Document ID: EPA-HQ-OAR-2009-0491-4513
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2011-07-12T04:00Z

Docket Number EPA - HQ - OAR - 2009 - 0491
Response to Comments on the Proposed Transport Rule: Federal Implementation Plans To Reduce Interstate Transport of Fine Particulate Matter and Ozone
                         (75 FR 45210; August 2, 2010)
                                       
                                       
                                       
                                       
                                  Transport Rule
                           Primary Response to Comments
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                                       
                     U.S. Environmental Protection Agency
                          Office of Air and Radiation
                                   June 2011
                                       
Table of Contents
Introduction	vii
I. General Comments in Support of Rule That Don't Fit Into Specific Topic Areas	1
II. General Comments in Opposition to Rule That Don't Fit Into Specific Topic Areas	57
III. [Reserved]	66
III.A. EPA's Authority for This Action	67
III.B. What Air Quality Problems and Which NAAQS Does This Proposal Address?	171
III.C. CAIR and NOx SIP Call Rulemaking History	192
III.D. Primary Goals and Key Guiding Principles of Proposal	193
III.E. Why Does This Proposed Rule Focus on the Eastern Half of the United States/ 37-State Region Analyzed	212
III.F. Anticipated Rules Affecting Power Sector	221
III.G. Setting a Precedent for How to Determine Upwind State Responsibilities in Future Transport Rulemakings	271
IV. Defining "Significant Contribution" and "Interference With Maintenance"	274
IV.A. Choice of Baseline Used for Cost, Emissions, and Air Quality Analyses	285
IV.B. Approach to Identify Contributing Upwind States and Approach to Identify Downwind Nonattainment/Maintenance Receptors	301
IV.B.1. Choice of Covered Pollutants (SO2 and NOx for PM2.5 and Ozone Season NOx for Ozone)	305
IV.B.2. Choice of Air Quality Thresholds (1% of Relevant NAAQS) and Rounding Convention	311
IV.B.3. Identification of Downwind Nonattainment and Maintenance Receptors	337
IV.C. Air Quality Modeling Approach and Results	384
IV.C.1. What Air Quality Modeling Platform Did EPA Use?	388
IV.C.2. How Did EPA Project Future Nonattainment and Maintenance for Annual PM2.5, 24-Hour PM2.5, and 8-Hour Ozone?	409
IV.C.3. How Did EPA Assess Interstate Contributions to Nonattainment and Maintenance?	420
IV.C.4. What Are Estimated Interstate Contributions to Annual PM2.5, 24-Hour PM2.5, and 8-Hour Ozone Nonattainment and Maintenance?	426
IV.C.5. Proposed Geographic Coverage (States Covered)	428
IV.D. Proposed Methodology to Quantify Emissions That Significantly Contribute or Interfere With Maintenance	437
IV.D.1. Overall Approach: Emissions Reduction Cost Curves	471
IV.D.2. Overall Approach: Air Quality Assessment - Use of Air Quality Assessment Tool (AQAT)	491
IV.D.3. Overall Approach: Identify Appropriate Cost Thresholds	508
IV.D.4. Specific Application of Overall Approach: Fine Particles (PM2.5)	514
IV.D.4.a. EGU Cost Curves/ Air Quality Assessment (AQAT)/Cost Thresholds	516
IV.D.4.b. Modeling Methods/ Air Quality Assessment Tool/Results of Evaluation With Detailed Air Quality Model (CAMx)	540
IV.D.4.c. Possible Emissions Increases in Non-covered States/ Should TX Be Included for PM2.5	548
IV.D.4.d. Other Comments On Application of Approach to Fine Particles (PM2.5)	566
IV.D.5. [Reserved]	568
IV.D.5.a. Specific Application of Overall Approach to Ozone: EGU Cost Curves/ Air Quality Assessment (AQAT)/ Cost Thresholds	569
IV.D.5.b. Specific Application of Overall Approach to Ozone: Modeling Methods/ Air Quality Assessment Tool/ Results of Evaluation With Detailed Air Quality Model (CAMx)/ New York City	577
IV.D.6. Non-EGU Emissions Sources and Control Costs	581
IV.D.6.a. Non-EGU SO2 Emissions Sources and Costs	599
IV.D.6.b. Non-EGU NOx Emissions Sources and Costs	601
IV.E. State Emissions Budgets (Before Accounting for Variability)	602
IV.E.1. SO2 and Annual NOx State Emissions Budgets for EGUs - Data and Methodology	645
IV.E.2. Ozone Season NOx State Emissions Budgets for EGUs - Data and Methodology	674
IV.F. Approach to Power Sector Emissions Variability	680
IV.F.1. General Comments on Variability Approach	682
IV.F.2. Estimating Year-to-Year Variability/Determination of 1-Year Variability Limits	708
IV.F.3. Alternative Calculation Methods	717
IV.F.4. Estimating Multi-Year Variability/Determination of 3-Year (and 2-Year) Variability Limits	719
IV.F.5. Proposed Variability Limits on SO2, NOx, and Ozone Season NOx	724
IV.F.6. Estimate of Effects of Emissions Variability on Downwind Air Quality	728
IV.G. How the Proposed Approach to Significant Contribution and Interference With Maintenance is Consistent With Judicial Opinions	730
IV.H. Alternative Approaches for Significant Contribution and Maintenance That EPA Evaluated	732
V.A. Covered Pollutants (SO2 and NOx for PM2.5 and Ozone Season NOx for Ozone)	734
V.B. [Reserved]	736
V.C. Timing of Proposed Emissions Reductions Requirements (Compliance Deadlines)	737
V.C.1. Coordination With NAAQS Deadlines/Addressing Court's Concern About Timing	756
V.C.2. Reductions as Expeditiously as Practicable/Feasibility of the 2012 and 2014 Compliance Deadlines	768
V.D. [Reserved]	849
V.D.1. General Comments on Remedies/ Remedy Options Overview/Trading Ratios Approach	850
V.D.2. State Budgets/Limited Trading Proposed Remedy	891
V.D.2.a. Applicability/ Opt-in Units	944
V.D.2.b. Allocations	1025
V.D.2.b.i. Comments on Allocations Data/Corrections to Allocations Data	1059
V.D.2.b.ii. Comments on Allocations Methodology	1172
V.D.2.c. Monitoring and Reporting	1428
V.D.2.d. Assurance Provisions/Emissions Limitation Provisions	1435
V.D.2.e. Should Assurance Provisions Start in 2012 Instead of 2014?	1482
V.D.2.f. Penalties	1493
V.D.2.g. Electric Reliability	1496
V.D.2.h. How Proposed Remedy is Consistent With Court's Opinions	1525
V.D.2.i. Other Comments on State Budgets/Limited Trading Proposed Remedy	1529
V.D.3. State Budgets/Intrastate Trading Remedy Option	1533
V.D.3.a. Auctions of Allowances	1541
V.D.3.b. Other Comments on State Budgets/Intrastate Trading Remedy Option	1546
V.D.4. Direct Control Remedy Option	1548
V.D.4.a. Emission Rate Limits - Data and Methodology	1556
V.D.4.b. [Reserved]	1558
V.D.4.c. Penalties	1559
V.D.4.d. How Direct Control Remedy is Consistent With Court's Opinions	1560
V.E. Projected Costs and Emissions for Each Remedy Option	1561
V.E.1. State Budgets/Limited Trading	1566
V.F. Transition from the CAIR Cap-and-Trade Programs to Proposed Programs	1577
V.F.1. Sunsetting of CAIR, CAIR SIPs, and CAIR FIPs	1582
V.F.2. [Reserved]	1590
V.F.3. Applicability, CAIR Opt-ins and NOx SIP Call Units	1591
V.F.4. Early Reduction Provisions	1598
V.F.4.a. SO2 Allowance Bank/Use of Title IV Allowances	1619
V.F.4.b. NOx Allowance Banks/Use of CAIR NOx Allowances	1636
V.G. [Reserved]	1668
V.G.1. Title IV Interactions	1669
V.G.2. NOx SIP Call Interactions	1671
VI. Stakeholder Outreach	1673
VII. State Implementation Plan Submissions	1677
VII.A. Section 110 (a)(2)(D)(i) SIPs for the 1997 Ozone and PM2.5 NAAQS	1686
VII.B. Section 110 (a)(2)(D)(i) SIPs for the 2006 PM2.5 NAAQS	1688
VII.C. Transport Rule SIPs	1690
VIII. Permitting	1732
VIII.A. Title V Permitting	1733
VIII.B. New Source Review (NSR)	1735
IX. What Benefits are Projected for the Proposed Rule?	1754
IX.A. [Reserved]	1757
IX.B. Human Health Benefit Analysis	1758
IX.C. Quantified and Monetized Visibility Benefits	1780
IX.D. [Reserved]	1781
IX.E. How Do the Benefits Compare to the Costs of This Proposed Rule?	1782
IX.F. What are the Unquantified and Unmonetized Benefits of the Transport Rule Emissions Reductions?	1788
IX.F.1. What are the Benefits of Reduced Deposition of Sulfur and Nitrogen to Aquatic, Forest, and Coastal Ecosystems?	1789
X. Economic Impacts	1790
XI. Incorporating End-use Energy Efficiency Into the Proposed Transport Rule	1819
XI.A. How Does Energy Efficiency Contribute to Cost-effective Reductions of Air Emissions from EGUs?	1821
XI.B. How Does the Proposed Rule Support Greater Investment in Energy Efficiency?	1828
XI.C. How EPA and States Have Previously Integrated Energy Efficiency Into Air Regulatory Programs?	1830
XI.D. Incorporating End-use Energy Efficiency Into the Transport Rule	1832
XI.D.1. Options That Could be Used to Incorporate Energy Efficiency Into Allowance Based Programs	1837
XI.D.2. Why EPA Did Not Propose These Options?	1843
XII. [Reserved]	1845
XII.A. Executive Order 12866: Regulatory Planning and Review	1846
XII.B. Regulatory Flexibility Act (RFA)	1849
XII.C. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments	1852
XII.D. Executive Order 13211: Actions That Significantly Affect Energy Supply, Distribution, or Use	1855
XII.E. Executive Order 12898: Federal Actions to Address Environmental Justice (EJ) in Minority Populations and Low-Income Populations	1860
XIII. Regulatory Impact Analysis	1871
XIV. Regulatory Text	1886
XIV.A. Part 97	1887
XV. Air Quality Modeling Technical Support Document (TSD)	1894
XVI. Other Comments	1898
XVII. Extension of the Comment Period	1927
XVIII. [Reserved]	1991
XVIII.A. [Reserved]	1992
XVIII.B. [Reserved]	1993
XVIII.C. Approach to Future EGU (Power Sector) Emission Projections	1994
XVIII.C.1. NPR: EGU Projections Using IPM/NEEDS V.3.02EISA	2132
XVIII.C.2. September 1, 2010 NODA: EGU Projections Using IPM/NEEDS V.4.10	2184
XIX. Transport Rule 2 and Other Future Transport Rulemakings	2420
XX. NODA on Allocations and Related Matters (January 7, 2011)	2459
XX.A. Alternative Allocations Approaches	2643
XX.A.1. General Comments on the Two Alternative Allocation Methodologies	2677
XX.A.1.a. Option 1	2769
XX.A.1.b. Option 2	2791
XX.A.2. Unit-level Comments on Data	2829
XX.A.3. Unit-level Comments on Applicability (e.g., Remove or Add Unit to Inventory of Potential Existing Units)	2861
XX.B. Calculating Assurance Provision Surrender Requirement on Designated Representative (DR) Basis	2890
XX.C. Whether Assurance Provision Approach Should Be Maintained if Allocation Approach is Changed	2928
XX.D. Allocations to New Units in Indian Country	2940
XX.E. Provisions for States to Submit Full or Abbreviated SIPs Providing for State Allowance Allocations	2950
XX.F. Other Comments on NODA 3	2990

Introduction

The following four documents respond to public comments received on the proposed Transport Rule:

   1. Transport Rule Primary Response to Comments (this document)
   2. Transport Rule Emissions Inventories Response to Comments  -  a supplemental document that responds to comments on non-EGU emissions inventories (available in the docket)
   3. Transport Rule IPM Assumptions Response to Comments  -  a supplemental document that responds to comments on the Integrated Planning Model (IPM) assumptions and EGU inventories (available in the docket)
   4. Transport Rule Engineering Feasibility Response to Comments  -  a supplemental document that responds to comments on engineering feasibility of the compliance deadlines (available in the docket)
   
EPA issued the following actions soliciting public comment on the proposed Transport Rule and on additional information relevant to the rulemaking:

   * Federal Implementation Plans To Reduce Interstate Transport of Fine Particulate Matter and Ozone (75 FR 45210; August 2, 2010).
   * Notice of Data Availability Supporting Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone (75 FR 53613; September 1, 2010).
         o This NODA provided an updated database of unit-level characteristics of EGUs included in EPA modeling, an updated version of the power sector modeling platform EPA used to support the final rule, and other input assumptions and data EPA provided for public review and comment.
   * Notice of Data Availability Supporting Federal Implementation Plans To Reduce Interstate Transport of Fine Particulate Matter and Ozone: Revisions to Emission Inventories (75 FR 66055; October 27, 2010).
         o This NODA provided additional information relevant to the rulemaking, including updated emission inventory data for 2005, 2012 and 2014 for several stationary and mobile source inventory components.
   * Notice of Data Availability for Federal Implementation Plans To Reduce Interstate Transport of Fine Particulate Matter and Ozone: Request for Comment on Alternative Allocations, Calculation of Assurance Provision Allowance Surrender Requirements, New-Unit Allocations in Indian Country, and Allocations by States (76 FR 1109; January 7, 2011).
         o This NODA provided additional information relevant to the rulemaking, including emissions allowance allocations for existing units calculated using two alternative methodologies, data supporting those calculations, information about an alternative approach to calculation of assurance provision allowance surrender requirements, allocations for new units locating in Indian country in Transport Rule states in the future, and provisions for states to submit SIPs providing for state allocation of allowances in the Transport Rule trading programs.
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I. General Comments in Support of Rule That Don't Fit Into Specific Topic Areas

Organization: Adirondack Mountain Club
Gomez, Rose
Comment: 
Adirondack Mountain Club
ADK appreciates the hard work and careful thought that the Agency put into this rule. Upwind air pollution must be regulated to protect New York's unique ecosystems that provide New Yorkers with clear air and water, and promote a strong tourism economy. Clean air contributes to a balanced and healthy environment. ADK is pleased that this rulemaking reflects the importance of upwind pollution management for this and future generations. [EPA-HQ-OAR-2009-0491-2761, p.2]
We have a critical stake in the proposed Clean Air Transport Rule (CATR). Emissions of NOx and SO2 from fossil-fueled electric power generating plants are harmful to human communities, aquatic life, and forest ecosystems in the Appalachians, Hudson Highlands, Catskills, Adirondacks, and White Mountains. We strongly feel that deep reductions in emissions of these pollutants are crucial, not only for New York State, but for the country as a whole. [EPA-HQ-OAR-2009-0491-2761, p.2]
Gomez, Rose
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.86.]
This is of course something that needs to happen as quickly as possible, and 2012, in no means, is very quickly by any standard as far as I'm concerned, and as far as 2014, when emissions would be reduced by 71 percent, that's fine. The more the better.
Why couldn't it be higher? The amount of benefits, like I said, far outweigh the costs.
Response: 
EPA thanks the commenters for their support of this Rule.  EPA is working as expeditiously as possible and within the full extent of its authority, under  Section 110(a)(2)(d) of the Clean Air Act, to ensure improved human health for all Americans through reductions in interstate transport of pollutants within the Transport Rule's 27 states.  EPA is under a timeframe to promulgate the Transport Rule as expeditiously as practicable, as per the remand of CAIR by the Court to the Agency for development of the current Transport Rule.
Organization: Edison Mission Energy (EME)
Comment: 
Edison Mission Energy (EME)
While EME supports the overall emission reduction goals set forth in the Transport Rule as consistent with ongoing progress to achieve important air quality goals under the Clean Air Act, EME has specific concerns with key components of the Proposed Rule that must be addressed before EPA finalizes the rule. Specifically: [EPA-HQ-OAR-2009-0491-2707.1, p.2]
If the issues above are not addressed, EME submits that the Transport Rule will impose emission reduction requirements on the power generation sector that: (i) are not technically feasible, and (ii) penalize sources that installed emissions controls before, in some cases well before, the first compliance phase of the Transport Rule. Due to these deficiencies, the compliance costs of the Rule likely significantly exceed EPA's estimate of $2,500 per ton for SO2 control and $500 per ton for NOX control. Therefore, EME requests that EPA make the changes outlined in the Sections below. [EPA-HQ-OAR-2009-0491-2707.1, p.4]
EME SUPPORTS THE OVERALL EMISSION REDUCTION OBJECTIVES OF THE PROPOSED RULE [EPA-HQ-OAR-2009-0491-2707.1, p.4]
At the outset, we note that EME commented in 2004 and 2006 in support of the Clean Air Interstate Rule ("CAIR"), 3 and went as far as to intervene in support of EPA in the lawsuit brought by the State of North Carolina and other parties challenging CAIR. Consistent with these prior positions, EME supports the emission reduction objectives of the Transport Rule. The Proposed Rule would reduce NOx and SO2 emissions from EGUs in affected states by 71%and 52%, respectively, relative to 2005 emissions to address downwind nonattainment issues. By 2014, the caps currently proposed by EPA, would result in emission reductions of over 6.3 million tons of SO2 per year and 1.4 million tons of NOx per year relative to 2005 emissions. [EPA-HQ-OAR-2009-0491-2707.1, p.4]
Like CAIR, the reductions contemplated by the Transport Rule from the EGU sector are massive, and will require considerable investments and impose billions of dollars in costs for the installation and operation of emission control technology such as FGD, SCR, SNCR, and low-NOx burners. Despite these costs, EME supports these emission reductions because they are generally consistent with ongoing progress toward the attainment of important air quality goals under the CAA. Moreover, given the substantial compliance costs that will have to be borne by the power generation sector generally, EME also supports the Agency's preferred approach of achieving the proposed emission reductions using a regional cap-and-trade mechanism. A cap and-trade mechanism is a critically important component of any final Transport Rule, as it will promote efficient emissions control and will provide affected sources with much-needed compliance flexibility. As such, cap-and-trade represents sound public policy. [EPA-HQ-OAR-2009-0491-2707.1, pp.4-5]

3 See Comments of Midwest Generation/Edison Mission Energy on EPA's Proposed Rule to Reduce Interstate Transport of Fine Particulate Matter and Ozone (Interstate Air Quality Rule), Docket Entry EPA-HQ-OAR-2003-0053-0751 (Mar. 30, 2004); Comments of Midwest Generation EME, LLC on EPA's Rule to Reduce Interstate Transport of Fine Particulate Matter and Ozone (Clean Air Interstate Rule): Reconsideration, Docket Entry EPA-HQ-OAR-2003-0053-2279 (Jan. 13, 2006).
Response: 
EPA thanks the commenter for their support of this Rule.  EPA is working as expeditiously as possible and within the full extent of its authority, under  Section 110(a)(2)(d) of the Clean Air Act, to ensure improved human health for all Americans through reductions in interstate transport of pollutants within the Transport Rule's 27 states.  For more detailed information, please see Sections III.A, III.F, IV.A, IV.E, IV.F.1, V.C, V.C.2, V.D.1, V.D.2.b, V.D.2.b.ii, VII, VII.C, XVIII.C, XVIII.C.1, and XIX within the Final Response to Comments Document.
Organization: Luminant
Comment: 
Luminant
In general, Luminant supports some aspects of the proposed rule, such as the appropriate exclusion of Texas from the annual SO2 and NOx programs, but Luminant believes that the timeline for implementation of all CATR programs are too short, and that it is inappropriate to conclude that Texas emissions will impact Baton Rouge. Luminant's specific comments are provided below. 2 [EPA-HQ-OAR-2009-0491-2729.1, p.4]

2. Further, Luminant is a member of and supports the comments filed by the Utility Air Regulatory Group, the Edison Electric Institute, the American Coalition for Clean Coal Electricity, the Association of Electric Companies of Texas and the Gulf Coast Lignite Council. [EPA-HQ-OAR-2009-0491-2729.1, p.4]
Response: 
EPA thanks the commenters for their support of this Rule.  EPA is working as expeditiously as possible and within the full extent of its authority, under  Section 110(a)(2)(d) of the Clean Air Act, to ensure improved human health for all Americans through reductions in interstate transport of pollutants within the Transport Rule's 27 states.  EPA is under a timeframe to promulgate the Transport Rule as expeditiously as practicable, as per the remand of CAIR by the Court to the Agency for development of the current Transport Rule.
Organization: Tennessee Department of Environment and Conservation, Division of Air Pollution Control
Citizens Campaign for the Environment (CCE)
Minnesota Pollution Control Agency (MPCA)
Province of Ontario, Canada
Green America
Mid-America Regional Council (MARC) Air Quality Forum
Metropolitan Washington Air Quality Committee
Iowa Department of Natural Resources (IDNR)
Clean Energy Group
Pennsylvania Department of Environmental Protection
National Association of Clean of Air Agencies (NACAA)
New York State Department of Environmental Conservation
Maryland Department of Environment (MDE)
Constellation Energy
State of Wisconsin, Department of Natural Resources
Consolidated Edison Company of New York, Inc, (CECONY)
Clean Air Task Force
Indiana Department of Environmental Management 
Republicans for Environmental Protection
Delaware Nature Society
Massachusetts Department of Environmental Protection
Pennsylvania Energy Alliance
NRG Energy
Exelon
PSEG Services Corporation
Xcel Energy Inc.
8-Hour Ozone State Implementation Plan (SIP) Coalition
American Petroleum Institute (API)
Calpine Corporation
Empire District Electric Company (Empire District)
Clean Air Council
Entergy Services, Inc.
Pew Environment Group
Sierra Club, Pennsylvania Chapter
Sierra Club
Adirondack Council
St. Louis University
International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers and Helpers (AFL-CIO Boilermakers Union)
NextEra Energy, Inc.
American Lung Association of the Upper Midwest
Respiratory Health Association of Metropolitan Chicago
Cool Joliet
Edison Electric Institute (EEI)
Greenpeace Chicago
Greenpeace Washington, DC
National Resources Defense Council (NRDC)
Pilsen Environmental Rights and Reform Organization (PERRO)
Ailey, John
Tampa Electric Company
American Lung Association
Stuckey, Richard
Mass Comment Campaign (38) (unknown organization)
Mass Comment Campaign (7,793) (Environmental Defense Fund)
Mass Comment Campaign (409) (unknown organization)
Mass Comment Campaign (679) (Greenpeace)
Environmental Law & Policy Center
DiMeo, Daniel
Mass Comment Campaign (20,795) (Sierra Club)
Mass Comment Campaign (600) (Sierra Club)
Mass Comment Campaign (1,817) (American Lung Association)
American Lung Association of Illinois
Peoria Families Against Toxic Waste
Heart of Illinois Group Sierra Club
Central Illinois Global Warming Solutions Group
Ringle, Weeks
Gifford, Casey
Fuller, Tony
Headington, Vincent
Northeast States for Coordinated Air Use Management (NESCAUM)
Parrish, Jr., Joseph
Rizzo, M.D., Albert A.
McCloskey, Natalie
American Lung Association of the Mid Atlantic
Doyle, Edward
Environmental Defense Fund (EDF)
Mothers and Others for Clean Air
Jones, Tiffini Eugene
Atlanta Faces of Homelessness Speakers Bureau
Southern Alliance for Clean Energy
Southeastern States Air Resource Managers (SESARM)
American Lung Association of Georgia
Geogians for Smart Energy Coalition
White, Dr. Yolanda
Mellinger-Birdsong, Anne
Layer, Harrison
Rennes, Beth
South Carolina Department of Health and Environmental Control 
Herbert, Natasha
Larson, Nancy
Glynn, Erin
Hanberry-Martin, Susan
Martin, Lee
Nederhand, Frank
Garland, Jenna
Feinberg, Stephen
Watzman, Talie
Black, Jim
Menkes, Larry
Rogers, Nick
New Jersey Business and Industry Association
Tsou, Walter
Ozone Transport Commission (OTC)
DelCore, Amanda
Public Interest Law Center of Philadelphia
Citizens for Pennsylvania's Future, or Penn Future
Schmoyer, Rebecca
Schmerling, Mark
Maryanski, Joseph
Adkins, Frederick
Conover, Barbara
Cummings, Katherine
Pryde, Coralie
Locker, Robert
Mills, Mary
Lillstrom, Aatis
Hodgin, Bradley
Taylor, Nancy
Pendleton, Mark
MacNeille, Jeanette
Stafford, Dr. Wesley & Jane
Stimpfel, Theresa
Waddle, Tolsun
Sierra Club, New Jersey Chapter
Gardner, Robert
Hage, Martin
Strand, Rev. Dr. Horace
Rust, Morgan
New Jersey Department of Environmental Protection (NJDEP)
Michetti, Susan
Oren, Craig N.
Hansen, Gordon
Ripple, Steven
Plumb, James
Ritz, Aaron
Cheung, Eric
Chung, Dr. Esther K.
Group Against Smog and Pollution (GASP)
Fallon, Myriam
Bucic, Sarah
Greater Philadelphia Chamber of Commerce
Smith, Iskar
Fiorentino, Robert
City of Philadelphia, Department of Public Health, Air Management Services
Maher, Jeff
Kravitz, Gregg
Pietrzak, Karl
McKinley, Brad
Comment: 
8-Hour Ozone State Implementation Plan (SIP) Coalition
The Coalition supports the overall goal of the transport rule -- reducing the transport of emissions to downwind nonattainment and maintenance areas.  Emissions from our member companies have been steadily decreasing for many years due to a suite of regulatory and voluntary actions that affect virtually every aspect of our operations.  We have also delivered several generations of cleaner gasoline and diesel, which have enabled significant reductions in the mobile source sector. [EPA-HQ-OAR-2009-0491-2736.1, p. 2]
Adirondack Council
We believe that the Environmental Protection Agency is taking appropriate actions to address shortcomings in CAIR that were outlined in 2008 by the U.S. Circuit Court of Appeals for the District of Columbia. We appreciate the efforts of the EPA to quickly respond to the Court's ruling and propose the Transport Rule. [EPA-HQ-OAR-2009-0491-2848.1, p.2]
We are also happy that several of our concerns from 2004 have been addressed, including further reducing the levels of pollution, shrinking the timelines for reductions and dealing with the glut of "banked" allowances that have accumulated over the last 15 years. [EPA-HQ-OAR-2009-0491-2848.1, p.2]
[These comments were also submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.61-62.]
In conclusion, the Adirondack Council strongly supports the Transport Rule and commends EPA for this action, but we believe more can and should be done to protect public health and the environment. We urge EPA to look for opportunities to implement the program with even deeper reductions in nitrogen oxides while keeping its aggressive compliance deadlines in place. [EPA-HQ-OAR-2009-0491-2848.1, p.5]
Adkins, Frederick
I am pleased that the EPA is acting to help states be good neighbors by reducing air pollution escaping across state lines. [EPA-HQ-OAR-2009-0491-0596, p.2]
Thank you for the opportunity to comment in support of the proposed rule for cutting air pollution from Pennsylvania's power plants. [EPA-HQ-OAR-2009-0491-0596, p.3]
This is a national problem that needs a national solution, and I urge the EPA to quickly finalize this common sense approach to protect public health and help states efficiently and cost-effectively clean up their air. [EPA-HQ-OAR-2009-0491-0596, p.3]
Ailey, John
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.50.]
I believe this is the consensus that the basic point is we do indeed support that these rules should be passed.
American Lung Association
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.57-62.]
We are pleased that the U.S. Environmental Protection Agency has moved ahead to help states like Illinois fight for healthy air by requiring the cleanup of pollution that blows into these states from outside.
States can't do this on their own. States need the Transport Rule to stop that pollution at the state line.
The American Lung Association calls on the EPA to not only adopt the framework of the Clean Air Transport Rule but to strengthen the limits on the emissions nationwide.
We at the American Lung Association call on the EPA to take this opportunity to do more to protect the air we breath and the lives of our families and friends.
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.45-46.]
First, The American Lung Association is pleased with EPA's decision to create a framework for setting emissions reductions under the 'good neighbor' provisions of the Clean Air Act. Such a framework allows EPA to follow a strong, logical pathway forward. Under this framework, EPA assesses in detail the contribution from sources in each upwind state to the pollution levels in downwind states. Such a careful analysis provides strong evidence that pollution from these 31 states and the District of Columbia harm and burden people living in these nonattainment and maintenance areas. The EPA analysis is compelling evidence that to have clean and healthy air here in Pennsylvania, we need clean and healthy air throughout the entire region.
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.9.]
We are pleased that the US Environmental Protection Agency has moved ahead to help states like Georgia have healthy air by requiring cleanup of pollution from coal-fired power plants. 
The American Lung Association calls on EPA to adopt the framework of the Clean Air Transport Rule, but to also set tighter limits on emissions. 
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p. 13.]
This tool gives us the framework to act, to stop pollution from blowing across our states. The American Lung Association supports the framework, but also urges EPA to set the right targets and limits. Thank you.
American Lung Association of Georgia
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.56.]
The American Lung Association calls on EPA to not only adopt the framework of the Clean Air Transport Rule, but to strengthen the limits on emissions nationwide to meet the requirement of protecting human health. 
These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010. See Docket Number EPA-HQ-OAR-0491-1939, pp.56-59.
This rule will save thousands of lives. We are committed to the prevention of lung disease and the promotion of lung health and this rule will further those goals.
I'll close by saying we at the American Lung Association call on EPA to take this opportunity to do more to protect the air we breathe and the lives of our family and friends.
American Lung Association of Illinois
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.97-98.]
That is why the American Lung Association urges the Environmental Protection Agency to adopt the Clean Air Transport Rule.
We want the air coming across our state line not to add to the burden of pollutants that we already have here in Illinois.
We urge EPA to quickly move to adopt and put in place this important tool for our air.
Controlling air pollution at its source will promote lung health now and in the future.
I rely on EPA to protect my patients to improve their lives and even to save them.
American Lung Association of the Mid Atlantic
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.25-26, 30, 34.]
The American Lung Association calls on EPA to not only adopt the framework of the Clean Air Transport Rule, but to strengthen the limits on emissions nationwide. We need to provide even basic protection for public health.
Passage of the Clean Air Transport Rule will mean fewer people will die and more will stay healthy.
We are here today to testify strongly in favor of the proposed Clean Air Transport Rule. To underscore the need for the rule, to confirm its benefits, and to call for certain safeguards and improvements.
The Clean Air Transport Rule is clearly the kind of major step in the right direction we have been waiting for and we applaud EPAs leadership in proposing this rule.
American Lung Association of the Upper Midwest
[These comments were submitted as testimony at the Chicago, Illinois hearing.  See Docket Number EPA-HQ-OAR-0491-1746, p.15.]
The American Lung Association of the Upper Midwest recommends that U.S. EPA works towards cleaner air by promulgating the Interstate Transport Rule.
American Petroleum Institute (API)
API supports the overall goal of the transport rule -- reducing the transport of emissions from large Electric Generating Units (EGUs) to downwind nonattainment areas. Emissions from our member companies have been steadily decreasing for many years due to a suite of regulatory and voluntary actions that affect virtually every aspect of our operations. We have also delivered several generations of cleaner gasoline and diesel, which have enabled significant reductions in the mobile source sector. [EPA-HQ-OAR-2009-0491-2649.1, p. 2]
Atlanta Faces of Homelessness Speakers Bureau
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.34-35.]
Reducing diesel emissions and smog in Georgia will make life better for school children, as well as for the rest of us who live and work here. Therefore, the Atlanta Faces of Homelessness Speakers Bureau supports a strong Transport Rule to reduce one of the main sources of air pollution causing harm to Georgia's children.
Black, Jim
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.87.]
Please, approve the new Transport Rule to reduce the pollution that is poisoning us all.
Bucic, Sarah
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.201.]
I am testifying today in favor of the EPA Transport Rule.
Calpine Corporation
In general Calpine enthusiastically supports the proposed rulemaking. [EPA-HQ-OAR-2009-0491-3614, p.2]
Central Illinois Global Warming Solutions Group
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.121-122.]
I'm here today in full support of the EPA's actions and the Surface Transport Rule.
I believe that it embodies three principles which need to be broad-based and underlay regulation of all pollutants in our society.
I believe it's a step forward and a move to a better energy future because it helps to place the true cost of using coal and fueling our nation on coal back on to the coal plants. I'm very happy to see that the public health impacts will no longer be absorbed by the public at large, but the cost of the pollution control technologies will be put on the plant so that the cost of coal reflects its true cost rather than allowing all of these socialized costs to go out to the general public and the benefits to remain privatized to the power generators.
I think that's an important principle, and I would hope that as the EPA moves forward on things like coal ash and regulations of other pollutants that the true cost, the true expense to society of dirty fossil fuels would become clear, and eventually they would go out of the market.
Cheung, Eric
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.183-184.]
Now, I need you to do your part and address what I cannot control. I need you to do all you can to reduce the pollution outside that I have no choice but to breathe. And if this means targeting ozone from neighboring states, then I fully support and applaud you actions.
Please act accordingly, and proceed with these regulations as well as future ones that will reduce air pollution.
Chung, Dr. Esther K.
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.185 & 190.]
The new rule would have a significant and favorable impact on health by one, reducing coal pollution and its associated diseases and two, lessening the threat of global warming and its predicted ill health effects.
I commend the EPA for the proposed Transport Rule and for all of its work to preserve and improve America's health.
Citizens Campaign for the Environment (CCE)
CCE is pleased that the EPA is moving ahead quickly with the new proposed Transport Rule, and offer the following comments. GENERAL COMMENTS In general, CCE strongly supports the EPA finalizing a strengthened Transport Rule as soon as possible. [EPA-HQ-OAR-2009-0491-1937.1, p. 1]
While New York State has taken significant action to reduce its emissions, power plants from upwind states continue to damage our environment, public health, economy, and building structures in NYS. The longer we wait, the worse the problem will get, and the more expensive the solutions will become. Finalizing a strengthened Transport Rule as soon as possible will help to protect our environment, health, economy, and building structures from additional harm. [EPA-HQ-OAR-2009-0491-1937.1, pp. 1-2]
Citizens for Pennsylvania's Future, or Penn Future
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.128-130.]
We support actions by EPA that address air pollution and protect the public health.
We commend EPA for proposing this rule. We encourage EPA to make it better, with steeper reductions that reflect already-available pollution controls.
City of Philadelphia, Department of Public Health, Air Management Services
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.216.]
The City of Philadelphia commends the EPA for its efforts to protect public health by proposing to regulate nitrogen oxide, NOX and sulfur dioxide, SO2, emissions from electric generating units, EGUs, within 31 states in the eastern U.S. and the District of Columbia.
Clean Air Council
I am a concerned citizen who is in support of the proposed 'Transport Rule'. This rule will require coal burning power plants to substantially reduce their emissions, limiting the amount of ozone and particulate matter pollution that goes into the air, thus protecting the environment and public health . Inhaling ozone and fine particulate matter has been linked to health problems such as heart disease, lung cancer, asthma, bronchitis and emphysema. By enacting this proposed rule more children would be able to grow up asthma-free, fewer adults would feel the crippling effects of heart disease and emphysema, and more people would be able to breathe clean air. [EPA-HQ-OAR-2009-0491-2876 p.2]
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.41-42.]
The purpose of my testimony today is to support EPA's proposed Clean Air Transport Rule and yet urge that it be even more stringent.
Pennsylvania is the poster child for the Transport Rule. Our western borders are invaded by air pollution from neighboring states, and yet we are also an exporter of pollution. Indeed, even under the proposed rule, Western Pennsylvania will not meet the federal health standards. It cannot do so unless EPA tightens the NOX standard.
Clean Air Task Force
I. Overview
Today, fossil fuel-fired power plants remain -- despite substantial regulatory focus and resultant emission reductions in recent years -- the largest source of industrial air pollution in the country. These emissions are harmful in their own right, but through atmospheric interactions they are also primary contributors to ozone smog and fine particles, both of which are extremely harmful to human health and the environment. Earlier this month, CATF released a report updating its earlier analysis of US power plant pollution, projecting that PM emissions from the nation's coal-fired power plant fleet will cut short the lives of about 13,000 people this year. [EPA-HQ-OAR-2009-0491-2738.1, p.2]
More than a decade ago, EPA promulgated the 1997 air quality standards for fine particulate matter and 8-hour ozone. A more protective PM standard was established in 2006. In 2008, EPA adopted a stronger 8-hour ozone standard. EPA recently determined that the 2008 ozone standard did not provide the protection required under the Clean Air Act and is currently considering strengthening that standard as well. Today, however, many areas throughout the East and Midwest continue to exceed these health-based standards. In order for many Eastern nonattainment areas to have a realistic chance of meeting those standards and improving the health of their citizens, steep reductions in transported power plant emissions of SO2 and NOx are absolutely necessary. Not only will steeper reductions allow states to attain the existing PM and ozone NAAQS, but they will also be necessary to help states achieve future air quality standards for PM and ozone, which are likely to be tightened in the next year or so. Furthermore, additional reductions will deliver substantial additional public health benefits resulting from lower ambient pollution levels, regardless of attainment status. [EPA-HQ-OAR-2009-0491-2738.1, pp.2-3]
The problem would be much worse if many power plants had not reduced their emissions of SO2 and NOx over the past few years. National power plant emissions of sulfur dioxide have fallen from 10.3 million tons per year in 2004 to 5.7 million tons last year, a drop of nearly 50 percent in five years. NOx emissions from power plants have also fallen by about half during this period. While these reductions may be attributed to a number of factors, including the 'NOx SIP Call,' New Source Review enforcement actions and a variety of state regulations, these air quality gains were consolidated and extended through EPA's 2005 Clean Air Interstate Rule ('CAIR').  [EPA-HQ-OAR-2009-0491-2738.1, p.3]
We generally support the basic structure of the TR, although the proposed SO2and NOx emission reductions are inadequate. We agree with EPA that the control of both regional and local reductions is a more cost-effective, balanced, and reasonable approach to addressing nonattainment than relying on local reductions alone. 22 We also generally support EPA's two-step approach to determining significant contribution, although we do have some concerns about its application, as well as its use of non-uniform cost thresholds to determine the level of required emission reductions. [EPA-HQ-OAR-2009-0491-2738.1, p.6]
In conclusion, we support the general approach and direction of EPA's TR proposal, but we submit that it is not sufficiently stringent to adequately protect public health or to provide adequate emission reductions to allow nonattainment areas to achieve attainment of the PM and ozone NAAQS as expeditiously as practicable. EPA must finalize a stronger rule as soon as possible. [EPA-HQ-OAR-2009-0491-2738.1, p.30]
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.105-106.]
Furthermore, even at todays pollution levels, the lives of tens of thousands of Americans will be cut short and there are still over 700 coal-fired power plants in the U.S. operating with no scrubber in place. At this point, every coal-fired power plant in the United States should be well-controlled. That is why it is so important for EPA to strengthen and finalize the proposed Transport Rule.
We believe that the Transport Rule is a good step towards requiring needed air pollution reductions in the electric power sector, and we commend the EPA for bringing the proposal forward. We are concerned, however, that the proposal falls short of requiring the amount of cost-effective reductions that are reasonably obtainable and necessary to protect human health and the environment.
Clean Energy Group
The Clean Energy Group supports the proposed Transport Rule. The proposed rule will achieve important air quality, health, and economic benefits utilizing EPA's current authority. It is critical that EPA implement the rule as expeditiously as practicable to ensure realization of these benefits. We are committed to working with EPA to ensure the Agency can implement the Transport Rule by January 1,2012, and to that end, we offer these comments. [EPA-HQ-OAR-2009-0491-2702.1, p. 1]
Conover, Barbara
Thank you for taking an important step forward in the fight against pollution by proposing the Good Neighbor Rule. As you are aware, millions of people are currently breathing air that does not meet clean air standards. Soot and smog from dirty coal plants travels downwind and affects neighboring states. This pollution causes heart attacks, asthma and lung disease. [EPA-HQ-OAR-2009-0491-0917, p.2]
The 2005 CAIR was a good step in EPA's regulation of interstate air pollution as directed by the Clean Air Act.. But the 2010 Good Neighbor Rule goes further -- and I encourage you to make it as strong as possible. [EPA-HQ-OAR-2009-0491-0917, p.2]
I also encourage you to include in the rule particular safeguards for states whose own 'state level EPAs' oversee the Clean Air Act regulation do not allow their enforcement to be lax. [EPA-HQ-OAR-2009-0491-0917, pp.2-3]
Consolidated Edison Company of New York, Inc, (CECONY)
CECONY supports the efforts of all levels of government to improve our common air quality, and has received numerous awards from the U.S. Environmental Protection Agency ('EPA'). Specifically, CECONY has been recognized for reducing fugitive SF6 and CH4 emissions through its participation in the EPA's SF6 Reduction Partnership Program and Natural Gas STAR program. In 2009, Con Edison was listed for the first time to the prestigious Dow Jones Sustainability Index, and was rated first globally among utilities for performance by the Carbon Disclosure Project. In 2010, the Company underwent a third party verification of its greenhouse gas emissions and became a Climate Registered company under The Climate Registry's voluntary reporting protocol. [EPA-HQ-OAR-2009-0491-2653.1, p.1]
Constellation Energy
Our primary comment is that EPA should move forward quickly with full implementation of the rule. [EPA-HQ-OAR-2009-0491-3613, p.1]
Cool Joliet
[These comments were submitted as testimony at the Chicago, Illinois hearing.  See Docket Number EPA-HQ-OAR-0491-1746, p.23.]
We also call on the U.S. EPA as part of the Transport Rule to not allow for cap and trade of these deadly pollutants.
All plants should be required to install pollution controls. Polluters shouldn't be allowed to pick what plants they clean up when the plants are a threat to public health.
Cummings, Katherine
I urge the EPA to adopt and enforce the Transport Rule to protect and improve the health of both urban and rural Americans. Coal-fired power plants are among the biggest polluters in our country. The risk of death and disease caused by coal-fired power plant pollution threatens the health of millions of Americans. The clean up of power plants is long overdue. Georgia stepped up to start cleaning up their own power plants, but Georgia cannot stop the pollution that blows into our state from other states. We need EPA to help us clean the air we breathe. [EPA-HQ-OAR-2009-0491-0968, p.2]
I encourage the proposed EPA Transport Rule because it will reduce sulfur dioxide and nitrogen oxide pollution that create ozone smog and particle pollution that blows into our state. This will improve the health of millions of people at risk from these pollutants, especially seniors, children and people with chronic lung diseases and cardiovascular diseases, and diabetes. We also need to cut pollution that our power plants are sending to other states, too. We need to have even greater reductions in the sulfur dioxide and nitrogen dioxide emissions that create deadly ozone and fine particle pollution. [EPA-HQ-OAR-2009-0491-0968, p.2]
This Transport Rule does what we cannot do: require power plants that are spewing toxic pollution into our state to clean up their act. Too many times pollution comes into our state. Air at the state line is already too polluted. Georgia has a strong power plant clean up rule. This would apply a similar rule to other states so that pollution from Illinois, Indiana, Pennsylvania, Ohio and even Florida won't spread into our state. [EPA-HQ-OAR-2009-0491-0968, p.2]
The EPA can contribute greatly to improved health status for millions of Americans by adopting and enforcing the Transport Rule. Please adopt and enforce it for the benefit of citizens of all ages. [EPA-HQ-OAR-2009-0491-0968, p.3]
Delaware Nature Society
The organization has been studying 'energy issues' broadly for many years and supports the EPA's efforts to limit sulfur dioxide (SO2) and nitrogen oxide (NOX) through the proposed 'Transport Rule.' [EPA-HQ-OAR-2009-0491-0204.1,p.1]
DelCore, Amanda
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.121.]
So, as a resident of Philadelphia, a resident of North America, I am asking you to please implement this plan to reduce interstate transport of fine particulate matter and ozone.
DiMeo, Daniel
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.90.]
Again, I would like to say that I believe it's a great step towards achieving the goal of the Clean Air Act, and I hope it is one of many steps in this direction.
Doyle, Edward
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.66.]
I am excited and really happy to see what the EPA is doing in limiting transportable pollutants, sulfur dioxide and nitrous oxide.
Edison Electric Institute (EEI)
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.23-25.]
Let me begin by saying that EEI shares a commitment with the Environmental Protection Agency to reduce emissions for power-generating facilities and is generally supportive of the policy objectives underlying EPA's proposed Transport Rule.
In fact, the electric power industry has already made significant progress in reducing emissions in sulfur dioxide, nitrogen oxide, even while the nation has consumed more energy and the economy has grown.
In particular, national SO2 emissions from power plants in 2009 were 64 percent lower than in 1990, and national power plant NOx emissions declined 70 percent over the same period.
Further, power generation of NOx emissions during the ozone season in the 20-state region covered by the NOx Budget Trading Program of Eastern U.S. have declined 81 percent since 1990.
In order to continue to effectively produce electricity and reduce emissions in the electric sector, we need clear, coordinated and flexible regulations that provide certainty for power companies to plan multibillion-dollar investments, many of which must serve decades into the future.
Only through carefully crafted regulations can EEI members continue to minimize costs to consumers and impacts on shareholders, avoid straining natural gas supply and prices, and continue efficient and reliable electric generation using diverse domestic energy resources.
Empire District Electric Company (Empire District)
Empire supports the EPA's remodeling of Kansas regarding inclusion for annual and ozone season NOx and for SO2.  [EPA-HQ-OAR-2009-0491-2659.1, p.1]
Entergy Services, Inc.
As it supported most elements of the Clean Interstate Air Rule ("CAIR"), Entergy supports the Proposed Clean Air Transport Rule (Transport Rule) as an effective way to reduce ozone and fine particulate levels in the eastern United States. [EPA-HQ-OAR-2009-0491-2847.1,p.1]
Environmental Defense Fund (EDF)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.74-75.]
The Proposed Rule is an important step in protecting public health and the environment.
Environmental Law & Policy Center
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.75.]
The LPC is supportive of the concept of the Clean Air Interstate Rule, and we support making it even stronger.
Therefore, we support the EPA in its rule-making and encourage EPA to go even further.
Exelon
Exelon Corporation ("Exelon") offers the following comments in support of the Environmental Protection Agency's ("EPA's") Clean Air Transport Rule ("Transport Rule"). 1 Exelon urges EPA to implement the rule largely as proposed and to do so as quickly as possible. Not only will the proposed Transport Rule generate significant human health and economic benefits, it will further promote the modernization of the electric generating industry and reduce the implicit "pollution charge" that stymies growth and economic development in Exelon's primary service areas. Exelon also suggests several potential improvements to the proposed rule. [EPA-HQ-OAR-2009-0491-2666.1, p.1]
Exelon is one of the nation's leading electricity suppliers. Exelon Corporation is comprised of three principal subsidiaries: two electric transmission and distribution subsidiaries, Commonwealth Edison Company ("ComEd") and PECO Energy Company ("PECO"), serving approximately 13 million people in the greater Chicago and Philadelphia regions, respectively; and Exelon Generation Company, LLC ("Exelon Generation"), which owns and operates over 25,000 MWs of nuclear, coal, wind, hydro, solar, gas and oil-fired generation  -  the fifth largest generation fleet in the United States. Although Exelon owns and operates facilities directly affected by the Transport Rule, Exelon strongly supports the policy objectives underlying EPA's proposal. [EPA-HQ-OAR-2009-0491-2666.1, p.1]
To be sure, some in our industry will argue that compliance is not feasible because EPA is acting too quickly, that electric reliability will suffer, or that the costs are too high at a time when the nation's economy is struggling. These arguments are myopic and wrong. The history of our industry proves that EPA's regulatory pace is appropriate and can be met by industry with little, or no, innovation. Moreover, the industry can easily tolerate the retirement of the oldest and dirtiest units without affecting reliability. And while the purported feasibility and reliability arguments against the Transport Rule are simply mistaken, the argument that EPA should delay the rule because of the nation's economic struggles is pure sophistry. The record is clear that the economic costs, and in particular the healthcare costs, associated with uncontrolled emissions dwarf the compliance costs of the proposed regulation. Moreover, as more fully set forth below, uncontrolled emissions from certain regions of the country are imposing enormous economic burdens on downwind economies. Against these hard facts, EPA must move quickly to control these emissions precisely because the American economy can no longer afford to pay the costs of failing to act. [EPA-HQ-OAR-2009-0491-2666.1, pp.1-2]
Indeed, the proposed Transport Rule could and should be strengthened significantly. In its comments below, Exelon suggests several modifications to the proposal that will improve Transport Rule by (1) expediting the elimination of upwind contribution to downwind nonattainment by increasing economic incentives to reduce emissions, (2) improving the functioning of pollutant allowance markets, (3) facilitating reductions in state budgets to meet revised National Ambient Air Quality Standards ("NAAQS"), and (4) making the rule both more fair and more defensible. As described in greater detail below, Exelon suggests: [EPA-HQ-OAR-2009-0491-2666.1, p.2]
Implementing the compliance assurance provisions beginning in 2012 rather than 2014 (Comment 5.2); [EPA-HQ-OAR-2009-0491-2666.1, p.2]
Reducing the proposed state budgets so that they do not exceed the least of actual historical state emissions, the Clean Air Interstate Rule ("CAIR") state budgets and the reduced state budgets that should result from the EPA's revisions to its modeling assumptions referenced in the Notice of Data Availability published on September 1, 2010 (Comment 6); [EPA-HQ-OAR-2009-0491-2666.1, p.2]
Reducing the proposed state budgets to assure compliance with revisions to the 2008 Ozone NAAQS expected to be adopted before the final Transport Rule is adopted (Comment 7); [EPA-HQ-OAR-2009-0491-2666.1, p.2]
Providing for the issuance of allowances that include state and vintage year identifiers, and modifying the compliance assurance provisions to be based upon the number of in-state, in-vintage year allowances surrendered by a source owner each year, rather than the initial allocation of allowances that the owner receives (Comment 5.3); [EPA-HQ-OAR-2009-0491-2666.1, p.2]
Revising the method for allocating allowances so that an increasing portion of allowances are auctioned and free allowances are awarded in a manner that does not create perverse operating incentives (Comment 8); and [EPA-HQ-OAR-2009-0491-2666.1, p.2]
Allowing certain additional units to opt in to the trading program (Comment 9). Although Exelon believes that these changes would improve the proposed Transport Rule, the proposed rule is legally defensible in its present form without these improvements. Exelon therefore urges EPA to adopt and implement the Transport Rule as so modified as soon as possible, so that downwind employees and customers can realize its benefits to health and the economy without further delay. [EPA-HQ-OAR-2009-0491-2666.1, p.2]
As an owner and operator of facilities directly affected by the Transport Rule, Exelon strongly supports the policy objectives underlying EPA's proposal. It is imperative that power plants in the Transport Rule states make significant and timely reductions in emissions of nitrogen oxides ("NOX") and sulfur dioxide ("SO2") to support the attainment and maintenance of NAAQS in downwind states. Pollution from plants that have not installed adequate control equipment imposes a heavy burden on businesses and families living in areas affected by these emissions, both those near the plants and those hundreds of miles downwind. [EPA-HQ-OAR-2009-0491-2666.1, p.3]
[This comment was also submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.35.]
THE TRANSPORT RULE REPRESENTS A REASONABLE, MEASURED AND APPROPRIATE SCHEME TARGETED TO PREVENT AIR POLLUTION SOURCES INUPWIND STATES FROM INTERFERING WITH THE MAINTENANCE OR ATTAINMENT OF NAAQS IN DOWNWIND STATES.
The Transport Rule will improve health and the environment and promote economic growth and equity without impairing electric system reliability. When Congress Enacted the CAA, Congress anticipated that older units would eventually be upgraded or retired and replaced with facilities employing Best Available Control Technology ("BACT"). 8 Instead, the New Source Review ("NSR") program created perverse incentives to keep uncontrolled, antiquated inefficient units alive and operating. Today, 59% of the coal-fired units in operation where in existence when the CAA was enacted in 1970, and of those very old units, 61.3% are still entirely uncontrolled. These units, however, produce only 33.5% of the total electricity supplied by the coal-fired fleet.9 Providing a signal that these antiquated, polluting units will need to pay for an increasing percentage of the pollutants they emit will restore appropriate incentives and encourage their replacement with state of the art efficient units. [EPA-HQ-OAR-2009-0491-2666.1, p.5]
As discussed in greater detail below, the proposed Transport Rule faithfully addresses the requirements of the CAA as interpreted by the Court of Appeals for the District of Columbia Circuit. EPA applied reasonable methodologies to develop state emission budgets and carefully assessed the costs and benefits of this proposal. The proposed Transport Rule would eliminate downwind contribution to nonattainment in almost all areas, and do so without any dislocation in the electric generation and distribution system. Nonetheless, Exelon believes that there are a few areas in which the Transport Rule could be improved, and requests that EPA consider the comments below. Exelon also urges EPA to adopt and to implement the rule on the schedule Exelon has proposed below, with full compliance commencing on January 1, 2012. [EPA-HQ-OAR-2009-0491-2666.1, p.6; for additional comments pertaining to THE TRANSPORT RULE REPRESENTS A REASONABLE, MEASURED AND APPROPRIATE SCHEME TARGETED TO PREVENT AIR POLLUTION SOURCES INUPWIND STATES FROM INTERFERING WITH THE MAINTENANCE OR ATTAINMENT OF NAAQS IN DOWNWIND STATES, see pp.5-6 of this comment summary]
Exelon respectfully requests that EPA modify the proposed Transport Rule to incorporate the changes proposed by Exelon in these comments, and that EPA adopt and implement the final Transport Rule as expeditiously as possible. Exelon offers its experience and support to EPA should the agency require additional information in connection with these comments or other issues regarding the Transport Rule. [EPA-HQ-OAR-2009-0491-2666.1, p.48]
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.38.]
The proposed Transport Rule is critical to leveling the playing field and ensuring that costs are appropriately borne by the plants that are causing the problem.

8 The Senate Report stated: "Therefore, the Committee determined that existing sources of pollutants either should meet the standard of the law or be closed down, and in addition that new sources should be controlled to the maximum extent possible to prevent atmospheric emissions." Clean Air Amendments of 1970, 91st Congress  -  Committee Reports: Senate Public Works Committee Report 91-1196, Reporting S. 4358, 91 Cong. Senate Report 1196 at 3; CAA, 70 Leg. Hist. 19, 103 (Sept. 17, 1970).
9 See Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability, M.J. Bradley & Associates LLC & the Analysis Group (2010), attached hereto as Exhibit 1, at Table 5 [See pp.Exh-pg.16. of this comment summary for Exhibit 1 table 5]
Fallon, Myriam
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.195-197.]
I believe this rule to be a big step in the right direction as far as the air quality goes, and across our country.
Feinberg, Stephen
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.133.]
I want to voice my support for the Clean Air Transport Rule.
Restrictions on the polluting outputs of coal plants will improve air quality and health and, in turn, leading to monetary savings and a better energy future. And we can't afford to spend time and energy on building new plants like the one we're currently doing in Georgia with plants like Plant Washington in Centerville, Georgia, nor should we have to worry about air pollution that we receive from other states. We should instead be focusing on the future of clean energy.
Fiorentino, Robert
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.210.]
I love the idea of making the air better, making the industry more secure and tighter. I really like what the EPA is doing.
I really can't see any reason to not go forward and have stricter standards. I am thinking selfishly for my own health and enjoyment, and also down the line when I have children, grandchildren, what have you. I really think that we're on the right track and EPA is on the right track.
Fuller, Tony
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.132.]
So I'm not a scientist, but I just wanted to say there are a lot of people out there suffering because of this, and I just wanted to come in and say that I support this effort to make strong reductions in these pollutants, and I believe that the costs involved are negligible compared to the benefits that it's going to make for people in the city, and, of course, around the country as well. I guess that's it.
Gardner, Robert
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.143-144.]
I would like to applaud the EPA for taking this positive step towards restricting dangerous Sulfur Dioxide and Nitrogen oxide.
The Environmental Protection Agency is right to restrict pollution of sulfur dioxide and nitrogen oxide from dirty old coal plants across the country. Americans should not be forced to wait for clean air. This is especially so, given the clear ability of electric power companies to utilize readily available pollution-control technologies, while simultaneously ensuring a reliable electric system.
Under authority of the Clean Air Act, a strong Transport Rule will put the onus back on industry for the pollution it has tried to send far away by building taller and taller smokestacks. Many of the worst offending coal plants do not even provide electricity to the communities they pollute.
Garland, Jenna
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.131 and 132.]
Because when I was doing my research and learning about what was proposed, I thought this is exactly what we need because we know that coal-fired power plants are dangerous. We know that the plants we have today are pumping pollutants into our air. We know that the proposed plants are only going to make things worse and we need to start taking steps now.
So I'm so pleased that Administrator Jackson is a strong leader in the US EPA and I want to ask you to please do even more. Please be more -- I don't want to say aggressive, but maybe active a little more. I don't know the right word, but you know what I'm trying to say. Even more excited and active about moving forward with having this rule implemented, having it as strong as possible.
So, once again, in summation, thank you for being here. Thank you for listening to our comments. And I hope that we will soon be able to move beyond coal entirely and towards an economy powered 100 percent by clean energy.
Geogians for Smart Energy Coalition
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.60 and pp.62-63.]
We support EPA's clean Transport Rule because it will reduce sulfer dioxide and nitrogen oxide pollution that create ozone smog and fine particulate pollution that blows into our state.
This regulation by our government which is specifically charged with protecting our health will improve the health of millions of people at risk from these pollutants, especially seniors and children, people with chronic lung disease and cardiovascular diseases and diabetes.
The Clean Air Transport Rule is an opportunity to speak out for our children and other sensitive groups that rely on our knowledge and action to protect them.
This Transport Rule does what we cannot do, which is require power plants that are spewing toxic pollution into our state to clean up their act and to require some of the plants here in Georgia that send our dirty coal plant pollution to neighboring states. And as has been mentioned, this rule would require Georgia, as other states, to cut the pollution. Although there has been a great reduction already, Georgia has some of the dirtiest coal plants here in the nation.
Gifford, Casey
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.130.]
So I encourage the EPA to pass this rule.
Glynn, Erin
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.111 and p.113.]
I'm here today to support  the Clean Air Transport Rule and ask that it be strengthened.
So I would just like to say thank you again for coming. I support the Transport Rule and energy efficiency and clean energy would be much greater opportunities to the utility representatives that are here today. 
Greater Philadelphia Chamber of Commerce
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.204.]
We are please to be here today to express our support for the proposed rules designed to help states implement the Good Neighbor provisions of the Clean Air Act which prohibits states from significantly contributing to the air quality problems of another state.
The EPA Transport Rule specifically is aimed at requiring stricter controls for air pollution that travels hundreds of miles and causes multiple health and environmental problems for surrounding regions. As a downwind state, Pennsylvania will benefit from the proposed rule changes being suggested by the EPA. These actions will have a significant impact on public health as well as on economic development and infrastructure needs within our region.
Green America
The members of Green America are deeply concerned about the environmental impacts of electric power generation in our country, and support the generation of electric power in the cleanest way possible. As we all know, ozone and fine particulate matter pose significant health risks to our citizens. The EPA has dealt with these problems diligently through the use and enforcement of the National Ambient Air Quality Standards. This summer the EPA proposed a new Transport Rule, which would help to strengthen the steps the EPA has already taken to control SOx, NOx, fine particulate matter, and ozone. The proposed 71 percent reduction of SO2 and 52 percent of NOx in covered states would create an enormous benefit for millions of Americans. [EPA-HQ-OAR-2009-0491-2611,p.2]
We at Green America wanted to send our thanks to the EPA for continuing your work in protecting our country from the significant environmental and health risks that are posed by fine particulate matter and ozone. We support the continued regulation of NAAQS pollutants and support the new Transport Rule. [EPA-HQ-OAR-2009-0491-2611,p.2]
Greenpeace Chicago
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.31-33.]
Today we show our solidarity with these communities in voicing our support for the Transport Rule as an initial step in the right direction.  
The Transport Rule helps put the burden back on the polluters for the damage they cause and places responsibility squarely where it belongs, not on the very people being victimized by big coal's corporate greed. 
By ending public health subsidies and a free lunch for filthy plants, we can ensure that energy efficiency and renewable energy also have a place at the table when discussing compliance with the Transport Rule. 
Greenpeace Washington, DC
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.34-35.]
Greenpeace firmly believes that no one should have to die to keep the lights on, so on behalf of families who suffer from coal-plant pollution day in and day out and thousands of our supporters across the midwest and U.S., Greenpeace expresses its support of the Transport Rule as a means to clean air across 31 states and the District of Columbia.
With a cost-to-benefit ratio of more than 100 to 1 even industry leaders from Exelon, PSEG and Constellation Energy can see that the Transport Rule provides cost-effective common-sense protection of public health.
Based on the Clean Air Act's 42-fold return on investment, it stands to reason that the Transport Rule promises to deliver many similar air quality and cost-of-protection benefits of care, and, indeed, go further as it should.
Group Against Smog and Pollution (GASP)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.191 & 199-200.]
We commend the agency for developing the Clean Air Transport Rule, and we welcome the reductions in PM 2.5 and ozone the rule will secure.
However, from the perspective of those of us living in southwestern Pennsylvania the proposed rule does not go far enough.
We applaud EPA for taking interstate action for an interstate problem. Knowing that our upwind pollution sources are being dealt with will allow GASP to hold our leaders in Pittsburgh more accountable for the pollution we produce ourselves.
But while we are pleased to see this rule go forward, we would like it to be even stronger.
Hage, Martin
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.148.]
I would like to put on the public record my support for the Transport Rule. I believe this rule will make the air I breathe less harmful to my body.
Hanberry-Martin, Susan
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.121-122.]
One of the most important functions of government is to protect the health and safety of the citizens. And because our state is not doing it, we look to the EPA to produce strict rules that will protect our health and safety. And I'm fully in support of everything that you're doing to this end. I can't thank you enough for getting the ball rolling on this. We truly, truly need some help.
Hansen, Gordon
I applaud EPA efforts to help states be good neighbors. [EPA-HQ-OAR-2009-0491-1955,p.1]
Headington, Vincent
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.134.]
I'm here to support the proposed rule.
So my main reason for supporting the rule is that I believe that it would, A, reduce healthcare costs and also save costs for small employers.
Heart of Illinois Group Sierra Club
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.117-120.]
We are in support of EPA and appreciate your leadership in moving forward for better air quality.
The time is now to move forward with stronger regulations, and this Transport Rule is an essential step.
We look to your rulings as a way to help our community be careful not to get out of attainment I should say, and, also, that we can improve air for us.
Herbert, Natasha
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.103.]
The Clean Air Transport Rule, if enacted, is an example of a primary method that would protect many people from developing diseases and conditions that are preventable.
I'm a supporter of this rule because it is time to clean up power plants and decrease the pollution that we are creating. Coal-fired power plants produce massive amounts of pollution which affect those living in close proximity, along with those afar due to the winds blowing particulate matter and other fine particles around.
The state of Georgia has been proactive in making steps to clean up the power plants here, but we are also affected by our neighboring states by pollution that blows in. We need EPA and the cooperation of all our neighbors to decrease pollution and prevent unnecessary asthma attacks and emergency room visits that Americans face every day due to the pollution produced by coal-fired power plants.
There are several laws at the national and state level that have been passed and enforced that save countless lives. Every time we put on our seat belts when we get in the car, we think click it or ticket. Or when we are able to breathe smokeless air on airplanes or in some indoor facilities, just think of the many individuals and lives that were saved because these laws were enacted to protect the greater population.
I support the Clean Air Transport Rule because I see it as another avenue to clean the air that we breathe and prevent unnecessary hospitalizations and the development of disease. As public health professionals, let us act in the best interests of the general public to clean up power plants so that we can all breathe cleaner air.
Hodgin, Bradley
I am 100% behind you and the E.P.A., and I'm sure most Americans are also in implementing a good neighbor rule, and regulating these dirty corporations. I believe that the public is being silenced by the right wing owned media, and the only points of view being allowed onto the airwaves are views from the far right. The only tool the public has now is the open internet, and that now is in jeopardy, so I encourage you to look at points of view from the public, and not from corporate America. [EPA-HQ-OAR-2009-0491-1274, p.1]
Indiana Department of Environmental Management 
Indiana feels that U.S. EPA has effectively addressed the court's ruling and fairly applied the applicable criteria. Furthermore, Indiana believes that the proposed rule adequately addresses obligations under Section 11 0(a)(2)(D) of the Clean Air Act for the states affected by this rulemaking. Additional emission reductions will be necessary at the local level for the few remaining nonattainment areas to comply with the 1997 National Ambient Air Quality Standards (NAAQS). [EPA-HQ-OAR-2009-0491-2645.1, p.1]
International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers and Helpers (AFL-CIO Boilermakers Union)
We applaud EPA's leadership in transitioning from the Clean Air Interstate Rule (CAIR) to a new framework to address interstate contributions to air quality degradation prohibited under Section 110(a)(2)(D)(i)(I) of the Clean Air Act (CAA). Improving air quality through cost-effective emissions reduction measures is crucial to protecting the public health and welfare and stimulating economic activity in this difficult recession. The capital that will be deployed by EGU owners to implement emissions control measures required under the proposed Transport Rule should create well-paying jobs for Boilermakers across the country. However, as described in detail below, the Boilermakers Union also has serious concerns about certain aspects of EPA's proposed implementation of the Transport Rule. We believe that changes are necessary to ensure the effective and efficient implementation of the emissions reduction requirements and achievement of the air quality goals of the Transport Rule. [EPA-HQ-OAR-2009-0491-2672.1, pp.1-2]
Although we have concerns about the timing of the proposed Transport Rule, the Boilermakers Union generally supports the proposed reduction requirements of the Transport Rule and believes that - if implemented on a realistic timetable - the rule would stimulate considerable new investment and job creation in the power sector. During the three years following the promulgation of CAIR, our members experienced a rapid increase in demand for labor as EGUs began installing FGD and SCR units to meet the new control requirements. We anticipate that the Transport Rule could precipitate a similar wave of construction, bringing jobs to areas of the country and to economic sectors that badly need them. [EPA-HQ-OAR-2009-0491-2672.1, p.2]
V. CONCLUSION
Despite the aforementioned concerns regarding the proposed Transport Rule, the Boilermakers Union believes that EPA has established, on balance, a strong and viable framework for reducing interstate pollution in the eastern United States. By equipping itself with more complete information about the economic impacts of the regulations it is proposing, and by ensuring that the manner in which these regulations are implemented along a feasible timeline, the Boilermakers Union is confident that EPA can maintain the environmental integrity of this program without unnecessarily imperiling American workers in this difficult economic period. [EPA-HQ-OAR-2009-0491-2672.1, p.11]
Iowa Department of Natural Resources (IDNR)
The IDNR supports EPA efforts to reduce emissions associated with interstate pollutant transport. We also commend EPA for considering the revised 2006 24-hour PM2.5 standard in addition to the 1997 O3 and PM2.5 standards in the proposed rule. Timely and effective regulations that generate adequate and equitable reductions in interstate pollutant transport are important components to protecting public health. Continued emphasis on reducing interstate pollutant transport will be needed to the extent the lowering of the National Ambient Air Quality Standards (NAAQS) exacerbates the degree to which out-of-state sources contribute to in-state air pollution.
Jones, Tiffini Eugene
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.24.]
And I'm here today to support the proposed Transport Rule.
I applaud EPA's proposed Transport Rule that will require 31 states and the District of Columbia to reduce power plant emissions. I want utilities in the eastern US, some of whose pollution reaches our state, to be required also to put pollution controls on their coal plants.
Kravitz, Gregg
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.221.]
This is not 50 or 100 years ago. We're at a time in our society right now where we know, we have the science to prove the damage that not passing the Transport Rule will do, what the consequences will mean.
Again, I don't think this is political. It's a global issue, simply, do you care about your family, your friends and future generations; and if you do, you very much need to support this.
Larson, Nancy
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.109, 110-111.]
I'm here today to express my support for the proposed Transport Rule as a concerned citizen and a parent.
So it's critical that the new Transport Rule be passed to protect our health and the health of our children.
The proposed rule has already shown to have significant health benefits as you mentioned and, like green building, this will save money and improve human health rather than harming human health.
Layer, Harrison
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.76.]
I am pleased with the EPA's mission to reduce pollution. I am here to advocate for cleaner air and some issues that intersect with this issue. 
Lillstrom, Aatis
Thank you for taking an important step forward in the fight against pollution by proposing the Good Neighbor Rule. As you are aware, millions of people are currently breathing air that does not meet clean air standards. Soot and smog from dirty coal plants travels downwind and affects neighboring states. This pollution causes heart attacks, asthma and lung disease. [EPA-HQ-OAR-2009-0491-1126, p.1]
Cleaning up the dirtiest plants will reduce pollution from state to state and make our air safe. I urge you to take a step further to protect the environment and public health by adopting this rule. [EPA-HQ-OAR-2009-0491-1126,p.1]
Locker, Robert
I am pleased that the EPA is acting to help states be good neighbors by reducing air pollution escaping across state lines. [EPA-HQ-OAR-2009-0491-1050, p.2]
MacNeille, Jeanette
You should put in a strong clean air transport law. I live in Pennsylvania. I saw a map once that indicated that the majority of the particulate pollution we breathe here comes from Texas. As a resident of PA, do you think I have any 'say' with -- or even access to -- legislators in Texas? I don't. We need you to put in a decent law that will protect everyone from the health effects of the old fashioned, non-innovative approaches we now use to energy production. [EPA-HQ-OAR-2009-0491-3138, p.1]
If you could walk an hour in my shoes you'd do it in a blink. Please put in strong clean air transport rule for me and for the millions like me, especially the kids. [EPA-HQ-OAR-2009-0491-3138, p.1]
Maher, Jeff
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.219-220.]
So I think it's a no brainer that this Transport Rule is a fantastic idea.
So I think this rule will do a lot by helping to regulate things that I think should have been regulated long ago. I wanted to come out and voice my support for it.
Martin, Lee
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.124.]
Please make your rules for the health of citizens and not for the bottom line of huge economic engines and coal-fired power plant companies.
Maryanski, Joseph
Thank you for taking an important step forward in the fight against pollution by proposing the Good Neighbor Rule. As you are aware, millions of people are currently breathing air that does not meet clean air standards. Soot and smog from dirty coal plants travels downwind and affects neighboring states. This pollution causes heart attacks, asthma and lung disease. [EPA-HQ-OAR-2009-0491-0505, p.2]
Cleaning up the dirtiest plants will reduce pollution from state to state and make our air safe. I urge you to take a step further to protect the environment and public health by adopting this rule. [EPA-HQ-OAR-2009-0491-0505, p.2]
Maryland Department of Environment (MDE)
The Maryland Department of Environment (MDE) appreciates the opportunity to comment on the Environmental Protection Agency's (EPA) proposed rule, "Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone (40 CFR Parts 51, 52, 72, 78 and 97)," also referred to as the "Transport Rule." Transported ozone and particulate matter pollution endanger the health of Maryland's citizens, particularly the very young and elderly, and causes lung damage, respiratory illness and premature mortality. Individuals with pre-existing heart and lung disease are particularly at risk, and in the United States as a whole in 2008, 42 million people had heart disease or asthma. [EPA-HQ-OAR-2009-0491-2639.1, p.1]
Maryland commends EPA on the Transport Rule, which, rather than being a regional cap and trade program, is a long-awaited confirmation by the EPA of the regional nature of the ozone and PM2.5 problem in the Eastern United States. Maryland has been in the forefront of conducting research and taking measurements of how long-range transport affects our state. Maryland is at the crossroads of ozone, PM2.5, and precursor transport. The prevailing westerly winds bring in air pollutants from the Midwest and the nocturnal low-level jet brings in air pollutants from the Southeastern states. We have adopted tough State measures like the Healthy Air Act to reduce local emissions that produce ozone and fine particulates, but it has not been enough. We have controlled both VOC and NOx generated in Maryland through a multitude of regulations, but continue to struggle with transported pollution at levels that are 50-75% of the current standards. To finish the job, we have lobbied tirelessly for control of emissions transported to Maryland by other states (e.g., cement kilns, ICI boilers, mobile sources, marine engines, locomotives and EGUs) to help level the playing field and achieve healthy air for our citizens. [EPA-HQ-OAR-2009-0491-2639.1, p.1]
EPA should move aggressively to require all major source categories of NOx, SO2 and mercury to, as quickly as possible, install state-of-the-art, multi-pollutant air pollution controls. In Maryland, ozone and fine particle levels drop dramatically as regional control programs for NOx and SO2 including the NOx SIP Call, early CAIR and the Acid Rain Program have been implemented. We know that regional NOx and SO2 reduction programs work and result in significantly cleaner air. [EPA-HQ-OAR-2009-0491-2639.2, p.1]
Maryland's comments address what is positive and what needs improvement in the proposed Transport Rule. Overall, Maryland agrees with the comments of NACAA and OTC. In addition, MDE agrees with EPA's timing for implementation of controls; encourages EPA to consider all transported and local pollution affecting an area on an equal cost per ton of control basis; and encourages the continued use of CAMx and CMAQ to verify Air Quality Assessment Tool (AQAT) results. Since Maryland has applied binding controls to its largest electric generating units (EGUs), we feel qualified to comment on the proposed definitions and methodology used in defining cost-effectiveness and identifying an appropriate cost threshold for controls. As a leader in transport research, we use our experience to comment on 'significant contribution' and 'interference with maintenance' by upwind states. [EPA-HQ-OAR-2009-0491-2639.1, pp.2-3]
States like Maryland that have moved ahead aggressively to control power plants and other sources are at a disadvantage for trying to clean the air when other States are not implementing the same measures. We are depending on EPA to use the Transport Rule and other authorities like the MACT requirements of the Clean Air Act to level the playing field. [EPA-HQ-OAR-2009-0491-2639.1, p.3]
Mass Comment Campaign (7,793) (Environmental Defense Fund)
I strongly support the proposed clean air plan to cut sulfur dioxide and oxides of nitrogen from eastern smokestacks. And I urge the EPA to strengthen its standards to secure greater health and environmental benefits. [EPA-HQ-OAR-2009-0491-3617_Mass, p.1]
I support these rules and urge the EPA to strengthen its standards even more to secure greater health and environmental benefits.[EPA-HQ-OAR-2009-0491-3617_Mass, p.1]
Your proposed rules to cut pollution from fossil fuel-fired power plants would reduce power plant sulfur dioxide (SO2) emissions by 71% from 2005 levels and nitrogen oxide (NOx) by 52% from 2005 levels. [EPA-HQ-OAR-2009-0491-3617_Mass, p.1]
EPA's plan to clean up this smokestack pollution would protect public health by avoiding: 14,000 to 36,000 premature deaths, 21,000 cases of acute bronchitis, 23,000 nonfatal heart attacks, 26,000 hospital and emergency room visits, 1.9 million days when people miss work or school, 240,000 cases of aggravated asthma, and 440,000 upper and lower respiratory symptoms. [EPA-HQ-OAR-2009-0491-3617_Mass, p.1]
And EPA's Rule would yield benefits of more than $120 to $290 billion annually in 2014, compared to the estimated annual costs of $2.8 billion. [EPA-HQ-OAR-2009-0491-3617_Mass, p.1]
Mass Comment Campaign (1,817) (American Lung Association)
Coal-fired power plants are among the nation's biggest polluters. The risk of death and disease a caused by coal-fired power plant pollution threatens millions of people across the country. [EPA-HQ-OAR-2009-0491-0955_Mass,p.1]
The clean-up of power plants is long overdue. I am urging EPA to strengthen the requirements on these power plants to improve air quality and protect public health. [EPA-HQ-OAR-2009-0491-0955_Mass,p.1]
Children, teenagers, senior citizens, and people with lung diseases like asthma, cardiovascular disease and diabetes are particularly vulnerable to the health effects of the ozone and particle pollution that these plants help to spread. By 2014, this rule will help to save the lives of 14,000 to 36,000 people each year. And it can prevent 26,000 hospital and emergency room visits each year. We cannot wait any longer. [EPA-HQ-OAR-2009-0491-0955_Mass,p.1]
I support the proposed EPA 'Transport Rule' which will reduce sulfur dioxide and nitrogen oxide pollution that contribute to ozone smog and particle pollution. This will save lives and improve the health of millions of people at risk from these pollutants, especially seniors, children and people with chronic lung diseases. [EPA-HQ-OAR-2009-0491-0955_Mass,p.1]
Mass Comment Campaign (20,795) (Sierra Club)
I am pleased that the EPA is acting to help states be good neighbors by reducing air pollution escaping across state lines. [EPA-HQ-OAR-2009-0491-3819_Mass,p.1]
The proposed rule will produce at least $100 billion, and possibly up to $290 billion, in public health savings, and it will prevent at least 23,000 heart attacks, 26,000 hospital visits and 240,000 asthma attacks, according to EPA estimates. In contrast, delaying action could result in up to 36,000 deaths related to dirty air. Like the highly successful acid rain program, the rule sets final clean air requirements but gives coal plants flexible options to achieve those requirements. The areas with the most cleanup to do will also realize significant benefits so that no state will bear an unfair burden. [EPA-HQ-OAR-2009-0491-3819_Mass,p.1]
This is a national problem that needs a national solution, and I urge the EPA to quickly finalize this common sense approach to protect public health and help states efficiently and cost-effectively clean up their air. [EPA-HQ-OAR-2009-0491-3819_Mass,p.1]
Mass Comment Campaign (38) (unknown organization)
I'm writing to express support for U.S. EPA's Clean Air Transport Rule and to urge the agency to do more to clean up dirty coal-fired power plant pollution by strengthening the rule. [EPA-HQ-OAR-2009-0491-3616_Mass, p.1]
EPA's proposal is a long overdue step for clean air. For decades, polluters have refused to invest in modern pollution controls. As a result, coal-fired power plants continue to be the single largest sources of air pollution in the Midwest, Illinois and Chicago. [EPA-HQ-OAR-2009-0491-3616_Mass, p.1]
On Chicago's West Side, Fisk and Crawford power plants spew well over 10,000 tons of fine particle pollution each year, causing asthma attacks, heart attacks and early deaths throughout the Midwest. A dozen coal-fired power plants, most of which still lack modern pollution controls, ring the tri-state metropolitan Chicago region. [EPA-HQ-OAR-2009-0491-3616_Mass, p.1]
Mass Comment Campaign (409) (unknown organization)
I am a concerned citizen who is in support of the proposed 'Transport Rule.' This rule will require coal burning power plants to substantially reduce their emissions, limiting the amount of ozone and particulate matter pollution that goes into the air, thus protecting the environment and health.  Inhaling ozone and fine particulate mater has been linked to health problems such as heart disease, lung cancer, asthma, bronchitis and emphysema.  By enacting this proposed rule more children would be able to grown up asthma-free, fewer adults would feel the crippling effects of heart disease and emphysema, and more people would be able to breathe clean air.
Mass Comment Campaign (600) (Sierra Club)
Thank you for taking an important step forward in the fight against pollution by proposing the Good Neighbor Rule. As you are aware, millions of people are currently breathing air that does not meet clean air standards. Soot and smog from dirty coal plants travels downwind and affects neighboring states. This pollution causes heart attacks, asthma and lung disease.[EPA-HQ-OAR-2009-0491-0135_Mass,p.1]
 Cleaning up the dirtiest plants will reduce pollution from state to state and make our air safe. I urge you to take a step further to protect the environment and public health by adopting this rule. [EPA-HQ-OAR-2009-0491-0135_Mass,p.1]
Mass Comment Campaign (679) (Greenpeace)
I am writing to support the Clean Air Transport Rule as an essential and cost-effective means of protecting public health and the climate. [EPA-HQ-OAR-2009-0491-1710_Mass, p.1]
By helping to sharply reduce emissions of sulfur dioxide and nitrogen oxides, the EPA can reduce the amount of heart attacks, asthma attacks and early deaths associated with pollution from coal-fired power plants. In the absence of a Federal cap-and-trade system, the Transport Rule represents the best chance of reducing harmful carbon dioxide emissions without an act of Congress. [EPA-HQ-OAR-2009-0491-1710_Mass, p.1]
I encourage you to resist the pressure of industry to water down this important and life-saving regulation, and applaud your leadership on this issue and your ongoing advocacy for public health and climate protection. [EPA-HQ-OAR-2009-0491-1710_Mass, p.1]
Thank you, EPA, for all you do to protect human/environmental health. [EPA-HQ-OAR-2009-0491-1710_Mass, p.1]
Massachusetts Department of Environmental Protection
We commend EPA for taking a significant step towards reducing the polluting emissions from large electric generating units (EGUs) that are transported across state boundaries. The ozone and particulate matter pollution that is formed from Nitrogen Dioxide (NOx) and Sulfur Dioxide (S02) emissions from these sources endangers the health of Massachusetts residents. Ail' pollution causes lung damage, respiratory illness and premature morbidity, with young children and the elderly at greatest risk from these health impacts. The EGU sector that EPA addresses in the proposed Transport Rule accounted for 18 percent of total nationwide NOx emissions and 66 percent of total nationwide S02 emissions in 2008. 1 Addressing emissions from this source category is essential to meeting the National Ambient Ail' Quality Standards (NAAQS) for ozone and fine particles (PM 2.5) and protecting the health of our citizens and we are gratified that EPA acknowledges this in its proposal.   [EPA-HQ-OAR-2009-0491-2787.2 p.1]
McCloskey, Natalie
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.24.]
Though we support the Clean Air Transport Rule, we would love to see stricter standards put in place. The technology is there. Utilizing only a portion of the technology is like letting us only have a portion of a breathing treatment.
McKinley, Brad
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.30-35.]
Reducing diesel emissions and smog in Georgia will make life better for school children, as well as for the rest of us who live and work here. Therefore, the Atlanta Faces of Homelessness Speakers Bureau supports a strong Transport Rule to reduce one of the main sources of air pollution causing harm to Georgia's children. Thank you.
Mellinger-Birdsong, Anne
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.72 and 75.]
I will start off by saying that I am speaking in support of the proposed rule on the transport of ozone and fine particle matter.
It is clear that the interstate transport of ozone and fine particulates and the precursors of nitrogen oxide and sulfer dioxide has public health impacts and that regulating and reducing interstate transport could have major public health benefits.
Therefore, I support this proposed rule and EPA's efforts to reduce interstate transport of both ozone and fine particulates.
Menkes, Larry
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.89-90.]
If we had the Clean Air Act Now, the air protected now, we would be up in arms that the EPA would allow this much pollution. But I do think it's necessary to get to this rule.
Metropolitan Washington Air Quality Committee
  MWAQC supports the proposal to provide a remedy to the challenges faced by states under Section 110 of the Clean Air Act in meeting requirements to limit emissions that impact downwind areas. Research conducted in this region continues to show that emissions transported into our region play a significant role in formation of air pollution in our metropolitan area, and unless abated will continue to hinder our efforts to meet National Ambient Air Quality Standards (NAAQS) now and into the future. [EPA-HQ-OAR-2009-0491-2618.1, p.1]
Michetti, Susan
I strongly support the proposed clean air plan to cut sulfur dioxide and oxides of nitrogen from eastern smokestacks. And I urge the EPA to strengthen its standards to secure greater health and environmental benefits. [EPA-HQ-OAR-2009-0491-3223, p.2]
Your proposed rules to cut pollution from fossil fuel-fired power plants would reduce power plant sulfur dioxide (SO2) emissions by 71% from 2005 levels and nitrogen oxide (NOx) by 52% from 2005 levels. [EPA-HQ-OAR-2009-0491-3223, p.2]
EPA's plan to clean up this smokestack pollution would protect public health by avoiding:
14,000 to 36,000 premature deaths,
21,000 cases of acute bronchitis,
23,000 nonfatal heart attacks,
26,000 hospital and emergency room visits,
1.9 million days when people miss work or school,
240,000 cases of aggravated asthma, and
440,000 upper and lower respiratory symptoms. [EPA-HQ-OAR-2009-0491-3223, p.2]
And EPA's Rule would yield benefits of more than $120 to $290 billion annually in 2014, compared to the estimated annual costs of $2.8 billion. [EPA-HQ-OAR-2009-0491-3223, p.2]
I support these rules and urge the EPA to strengthen its standards even more to secure greater health and environmental benefits. [EPA-HQ-OAR-2009-0491-3223, p.2]
Mid-America Regional Council (MARC) Air Quality Forum
  The Forum strongly supports the concept of regulating interstate transport of pollutants and agrees with the need to provide states with federal tools to deal with this issue. Interstate transport is a considerable source of ozone precursor emissions in the Kansas City area, which is itself a bi-state region. Based on local photochemical modeling, fully one-third of Kansas City's ozone precursor emissions are transported from other areas. [EPA-HQ-OAR-2009-0491-2613.1, p.1]
Mills, Mary
Thank you for taking an important step forward in the fight against pollution by proposing the Good Neighbor Rule. As you are aware, millions of people are currently breathing air that does not meet clean air standards. Soot and smog from dirty coal plants travels downwind and affects neighboring states. This pollution causes heart attacks, asthma and lung disease. [EPA-HQ-OAR-2009-0491-1088, p.1]
Cleaning up the dirtiest plants will reduce pollution from state to state and make our air safe. I urge you to take a step further to protect the environment and public health by adopting this rule. [EPA-HQ-OAR-2009-0491-1088, p.1]
Minnesota Pollution Control Agency (MPCA)
The MPCA would like to commend EPA for the way in which the proposed Transport Rule responds to the myriad concerns that the D.C. Circuit Court of Appeals raised over the Clean Air Interstate Rule (CAIR). The overall framework does an admirable job in ensuring that the rule will adequately address the specific state-to-state impacts of transported pollutants, so that covered states fulfill their obligations under 110(a)(2)(D), the Clean Air Act's 'good neighbor' provision. [EPA-HQ-OAR-2009-0491-2521.1, p.1]
Mothers and Others for Clean Air
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.18.]
We would like to commended EPA for its efforts to reevaluate clean air standards and develop new rules that will lead to reductions in harmful emissions. Georgia needs federal leadership to meet its clean air goals.
National Association of Clean of Air Agencies (NACAA)
Areas Where NACAA Generally Supports EPA's Approach in the Transport Rule
We appreciate EPA's efforts to thoughtfully address the court decision 1 that overturned the previous transport rule  -  the Clean Air Interstate Rule (CAIR)  -  and to quickly put in place a rule that limits NOx and SO2 emissions from power plants in the Northeast, Mid-Atlantic, Southeast and Midwest on a timeframe that helps states meet their attainment deadlines. We will highlight here several aspects of the proposed Transport Rule that we generally support:  [EPA-HQ-OAR-2009-0491-2771.1, p.2; For additional comments pertaining Areas Where NACAA Generally Supports EPA's Approach in the Transport Rule see page 2 of this comment]

Footnote:
1 North Carolina v. EPA 531 F.3d 896 (DC Cir. 2008) (court decision vacating CAIR) and North Carolina v. EPA, 550 F.3d 1176 (DC Cir. 2008) (court decision remanding CAIR in lieu of vacatur).
National Resources Defense Council (NRDC)
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.40.]
I am here today both to commend the EPA on its proposal to significantly reduce emissions of sulfur dioxide and nitrogen oxide for coal-fired power plants and also to encourage the EPA to go even further in reducing emissions in its final rule.
U.S. EPA's proposed regulations are both necessary and timely and should be strengthened in order to realize the enormous potential health benefits that will accrue from ensuring the nation's ambient air quality standards are achieved throughout the country.
Nederhand, Frank
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.126-127.]
We're pleased that EPA is acting to help states be good neighbors by reducing air pollution that crosses state lines. We applaud this common-sense approach by Lisa Jackson and the EPA to effectively protect public health and help states clean up their air efficiently and cost effectively. We support the Transport Rule and ask that it be strengthened.
New Jersey Business and Industry Association
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.95-96.]
As we're looking at this rule and having businesses in nonattainment areas, which are downwind, we basically see our businesses paying a pollution tax. As we're already at a disadvantage because of the fact that our companies are subject to state regulations, that other states are not, we're incurring more costs.
So we see this as a way that we can control emissions in other states and help our states businesses be able to reduce some of their costs as well.
New Jersey Department of Environmental Protection (NJDEP)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.156.]
I would like to first applaud USEPA for their effort to address the flaws in the Clean Air Interstate Rule, CAIR.
New York State Department of Environmental Conservation
This proposal makes many improvements over the Clean Air Interstate Rule (CAIR) that it is intended to replace. For example, we strongly support the retirement of allowance banks and EPA's decision to restrict interstate trading. In addition, we applaud EPA for its development of a framework for expeditiously addressing transport when EPA issues future NAAQS. [EPA-HQ-OAR-2009-0491-2730.1, p.1]
NextEra Energy, Inc.
Overall, NextEra Energy supports EPA's proposed Transport Rule because it will achieve important air quality and health benefits. In our view, it is critical that EPA implement the rule as expeditiously as practicable, and we are committed to supporting EPA's implementation of the Transport Rule by January 1, 2012. [EPA-HQ-OAR-2009-0491-2718.1, p.1]
The fundamental purpose of the Transport Rule is to address the Section 110(a)(2)(D)(i)(1) requirement that states do not contribute significantly to nonattainment in, 01' interfere with maintenance by, any other state with respect to any primary or secondary national ambient air quality standard (NAAQS). Several of NextEra Energy's power plants operate in downwind states where the transport of emissions from upwind states contribute significantly to nonattainment with the ozone and fine particulate (PM2.5) NAAQS. Our company has made substantial investments in clean energy technologies and advanced emission control technologies to improve the air quality in the areas in which we operate. Despite these efforts, however, transported pollution from upwind states prevents many of these areas from meeting air quality standards. [EPA-HQ-OAR-2009-0491-2718.1, pp.1-2]
Northeast States for Coordinated Air Use Management (NESCAUM)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.8-9.]
NESCAUM congratulates EPA on issuing the proposed Clean Air Transport Rule. We support establishing a framework to address transported air pollution that will assist states in meeting national ambient air quality standards, or NAAQS. Transported air pollution continues to have a significant impact on NESCAUM states, as we strive to achieve clean air. Thus, a framework to address it is important to us.
Today, in 2010, we're discussing a proposal to address the 1997 ozone and annual PM 2.5 NAAQS, and 2006 24-hour PM 2.5 NAAQS. This proposal is welcomed, but it is long in coming. States are already well into planning to further improve air quality and build upon past successes that have integrated regional approaches with state-based planning.
Based on our past experiences, we urge EPA to promulgate future transport rules concurrent with finalizing new national air quality standards. This would provide states with the critical information they need up front to develop and submit approvable plans within the required three years after an air quality standard is promulgated. The result will be timely, effective pollution reductions that produce cleaner air sooner for the public and the environment.
We applaud several aspects of the proposed framework.
NRG Energy
NRG supports EPA's efforts to improve air quality, address the legal inadequacies of the Clean Air Interstate Rule (CAIR) and offer a degree of flexibility for the electric generating units (EGUs). We offer these comments to provide NRG's insight on options discussed in the proposed rule, recommended changes that could improve implementation while maintaining legal defensibility, and provide corrections to assumptions in the EPA database for NRG plants. [EPA-HQ-OAR-2009-0491-2749.1, p. 1]
NRG commends EPA's effort to release a proposed Transport Rule. The Transport Rule addresses the legal requirements established by the D.C. Circuit's decision North Carolina v. EPA, provides health benefits to the public, and a sense of certainty to companies as they plan for the future. [EPA-HQ-OAR-2009-0491-2749.1, p. 3]
Oren, Craig N.
This is an important rulemaking, particularly since the Carper/Alexander legislation to reduce interstate air pollution has been delayed until at least 2011. The health consequence of transport are horrific, as the proposed rule document. [EPA-HQ-OAR-2009-0491-2644-cp, p.1]
Ozone Transport Commission (OTC)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.111 & 114.]
By controlling emissions from these sources under the Transport Rule, EPA is achieving badly needed public health benefits that are long overdue utilizing the most cost-effective reductions available.
We, therefore, urge EPA to strengthen this Transport Rule, particularly in the areas we will now discuss, to provide greater public health protection in a more timely manner.
Parrish, Jr., Joseph
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.14-15.]
Any additional EPA regulations to control SOX and ozone of carbon based power plants when finally put into effect will directly and immediately improve lung health on the eastside of Manhattan that I oversee and the westside of Queens.
Cleaning up power plants will save lives. EPA estimates that just the reductions in the proposed Transport Rule will save between 14,000 and 36,000 lives a year by the year 2014. I think that is a low-ball estimate. Particle pollution and ozone smog cause coughing and wheezing, trigger asthma attacks, send people to the emergency rooms and cause heart attacks and strokes, as well as premature death.
Pendleton, Mark
I encourage the EPA to reconsider the proposed rule related to the Interstate Transport of Fine Particulate Matter and Ozone. [EPA-HQ-OAR-2009-0491-1596, p.1]
I support the agency's efforts to reduce the amount of sulfur dioxide and nitrogen oxide in the atmosphere. [EPA-HQ-OAR-2009-0491-1596, p.1]
Pennsylvania Department of Environmental Protection
The Pennsylvania Department of Environmental Protection (DEP) appreciates the opportunity to submit comments on the U.S. Environmental Protection Agency's (EPA) proposed rule entitled the 'Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone, published in the Federal Register on August 2, 20I0, at 75 Fed. Reg. 45,210. The proposed rule, known as the 'Transport Rule' or 'TR,' requires electric generating units (EGUs) in 31 states including the Commonwealth of Pennsylvania and the District of Columbia to substantially improve air quality by reducing nitrogen oxide (NOx) and sulfur dioxide (SO2) emissions in downwind areas that contribute significantly to nonattainment or interfere with maintenance of the 1997 ozone and the annual fine particulate matter (PM2.5) national ambient air quality standards (NAAQS) and the revised 2006 24-hour PM2.5 NAAQS. EPA has proposed Federal Implementation Plans (FIPs) for the immediate implementation of the final Transport Rule. [EPA-HQ-OAR-2009-0491-2660, p.1]
According to EPA projections, 'the proposed TR and other state and EPA actions would reduce power plant SO2 emissions by 71 percent over 2005 levels. Power plant NOx emissions would drop by 52 percent.' The final TR will replace the 2005 Clean Air Interstate Rule ('CAIR') and FIPs promulgated by EPA on May 12,2005, and April 28, 2006, respectively. (70 Fed. Reg. 25,162; 71 Fed. Reg. 25,328). [EPA-HQ-OAR-2009-0491-2660, p.1]
The DEP commends EPA's efforts to remedy the flaws in the CAIR, vacated in its entirety (including the FIPs) by the U.S. Court of Appeals for the District of Columbia Circuit ('DC Circuit' or 'Court') on July 11, 2008.' The 'fundamentally flawed' CAIR was remanded to EPA on December 23, 2008, for revisions consistent with the DC Circuit's July 2008 opinion? Despite several major flaws in the CAIR, EPA approved the Commonwealth's CAIR as a revision to Pennsylvania's State Implementation Plan (SIP) on December 10, 2009 (74 Fed. Reg. 65,446). Under the CAIR, annual NOx emissions from EGUs in Pennsylvania decreased by approximately 64,000 tons in 2009. Prior to the 2010 compliance date, S02 emissions decreased by an estimated 249,000 tons. [EPA-HQ-OAR-2009-0491-2660, pp.1-2]
The DEP believes that the proposed Transport Rule, which establishes FIPs to reduce the transport of NOx and SO2 emissions, will allow the Commonwealth to continue to make great strides in protecting public health and the environment. The projected emission reductions are expected to result in significant annual health benefits in Pennsylvania and other states in the Transport Rule region. [EPA-HQ-OAR-2009-0491-2660, p.2]
[These comments were also submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.50.]
Pennsylvania Energy Alliance
Therefore, we strongly support the proposed Air Pollution Transport Rule requiring power plants to regulate the amount of harmful emissions released into the air. Doing so will help states like Pennsylvania meet their obligations to reduce transported pollution and maintain compliance with the national ambient air quality standards. Protecting Pennsylvania's environment and our citizens' public health from air pollution is of the utmost importance, and we believe the proposed improvements on the Clean Air Interstate Rule are necessary. The PA Energy Alliance urges the EPA to finalize and begin implementation of the Transport Rule. [EPA-HQ-OAR-2009-0491-0084,. p.2]
Peoria Families Against Toxic Waste
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.111.]
And I am in favor, strongly in favor of this rule but think it needs to be stronger.
Pew Environment Group
More than a decade ago, EPA promulgated the 1997 air quality standards for fine particulate matter and 8-hour ozone. A more protective PM standard was established in 2006. Today, however, many areas throughout the East and Midwest continue to exceed these health-based standards. The problem would be much worse if many power plants had not reduced their emissions of sulfur dioxide (SO2) and nitrogen oxides (NOx) over the past 5 years. In fact, national power plant emissions of sulfur dioxide were 10.3 million tons per year as recently as 2004. Last year, they had fallen to 5.7 million tons, a drop of nearly 50 percent in five years. This reduction is due to a number of factors, including New Source Review enforcement actions and state regulations, as well as EPA's 2005 Clean Air Interstate Rule. [EPA-HQ-OAR-2009-0491-2703.1 p.1]
While this success should be applauded, today's pollution levels still lead to over 13,000 premature deaths and there are still approximately 700 coal-fired units in the U.S. operating with no sulfur scrubber in place. At this point, every coal-fired plant in the U.S. should be well-controlled. That is why it is so important for EPA to strengthen and finalize the proposed Transport Rule. First, it will lock in the gains we have made in the last 5 years. Second, the Transport Rule goes farther than CAIR in 15 states and should allow many nonattainment areas in the East to reach attainment of federal air quality standards (mostly particulate matter, or PM). [EPA-HQ-OAR-2009-0491-2703.1 p.1]
The direct link between power plant emissions and human health has been documented extensively, and much of it has been reviewed and included in formal rulemakings and regulatory analysis by EPA. For the last decade, public health concerns have focused on very small airborne particles that have been found to cause or contribute to respiratory and cardiopulmonary diseases as well as the increased risk of premature death. Unfortunately, elevated levels of fine particles are persistently present and common across large portions of the country.  [EPA-HQ-OAR-2009-0491-2703.1 p.1]
Pietrzak, Karl
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.223.]
The only thing I want to say is I am supportive of the rule because it is not fair for different communities just to have the geographical disadvantage of shear existence.
Pilsen Environmental Rights and Reform Organization (PERRO)
[These comments were submitted as testimony at the Chicago, Illinois hearing.  See Docket Number EPA-HQ-OAR-0491-1746, pp.44 & 47.]
PERRO is our acronym, and we are here to support the Transport Rule as a first step in hopefully what will be a much more evolved process of reducing power plant pollution.
So, obviously, this Transport Rule is a good step in the overall process of dealing with these pollution sources.
Plumb, James
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.172-173.]
It's my responsibility as a physician to advocate for my patients and my students by strongly supporting the Clean Air Transport Rule. Without this rule, an immediate and direct threat to the children, elderly, the poor and vulnerable citizens of Philadelphia remains. Not to implement this rule is a socially irresponsible action and will lead to numerous missed days of work and school, preventable illness and deaths. 
Province of Ontario, Canada
We believe that the Transport Rule is sound environmental policy, and we commend the U.S. EPA for this proposed course of action.  [EPA-HQ-OAR-2009-0491-2610.1, p.1]
The Transport Rule will require significant reductions in the emission of nitrogen oxides (NOx) and sulphur dioxide (SO2) from electricity generating units (EGUs) in 31 states and the District of Columbia. The Transport Rule, intended to reduce the interstate transport of ozone and fine particulate matter in the eastern U.S., will also reduce the international transport of these pollutants to Ontario. Scientists at the Ontario Ministry of the Environment (MOE) believe that the reductions required by the Transport Rule will result in improved air quality in the Province of Ontario. The result will be better protection for human health and the environment on both sides of the border. [EPA-HQ-OAR-2009-0491-2610.1, p.1]
We fully support the u.s. EPA's proposed Transport Rule. The reductions required by the Transport Rule will reduce both the interstate transport of air pollution within the U.S. and the international transport of air pollution to Ontario. We urge the u.s. EPA to finalize and implement the Transport Rule as expeditiously as possible. If the U.S. EPA takes that action, citizens on both sides of the border will breathe a little easier. [EPA-HQ-OAR-2009-0491-2610.1, p.3]
Pryde, Coralie
The cost of installing equipment to reduce pollutants from smokestacks is very small compared to the vast cost of the health problems caused by ozone and particulate matter. But the owners of the coal-fired plants don't care because they don't pay for the health costs. They argue that the states shouldn't force them to 'clean up their act' because it will make their electricity uncompetitive with that from neighboring states. The only logical answer is to have federal regulation. I strongly support the Transport Rule. [EPA-HQ-OAR-2009-0491-0981, p.1]
PSEG Services Corporation
Overall, PSEG supports the proposed rule because it will achieve important air quality and health benefits. It is critical that EPA implement the rule as expeditiously as practicable, and we are committed to supporting EPA's implementation of the Transport Rule by January 1, 2012. [EPA-HQ-OAR-2009-0491-2726.1, p.2]
In conclusion, PSEG supports the implementation of this program and believes it can be accomplished by January 1, 2012 without negative impacts on electric system reliability. Although our preference would have been to incorporate the Acid Rain Title IV allowance system into this program, PSEG understands the constraints imposed. Thus, PSEG is supportive of the overall framework of preferred option for unlimited intra-state and limited interstate emission trading and the assurance provisions as proposed but strongly recommends that EPA modify the unit allocation methodology which in effect rewards higher emitting facilities at the expense of other companies, like PSEG, who have committed early investments to control emissions. [EPA-HQ-OAR-2009-0491-2726.1, pp.11-12]
Public Interest Law Center of Philadelphia
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.124.]
These reductions would represent significant progress toward finally achieving attainment standards for PM 2.5 standard. Although these cuts could and should be deeper, particularly with respect to nitrogen oxide, and could and should cover more sources, the welcome public health and environmental benefits from the proposed reductions in these dangerous pollutants are unmistakable, and will far outweigh the costs of compliance with the Transport Rule. 
Rennes, Beth
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.81.]
So I'm here to support the proposed Transport Rule.
Republicans for Environmental Protection
The job of securing cleaner air for America's families and communities, however, is not complete. A significant fraction of the coal-fired power plants that generate about half the electricity used in America lack equipment to control emissions of pollutants that create ozone smog and tiny particulates, which are known respiratory and cardiac health hazards. [EPA-HQ-OAR-2009-0491-1892.1, p. 1] The Environmental Protection Agency's proposed Clean Air Transport Rule, which would reduce emissions of sulfur dioxide and nitrogen oxides by 71 percent and 52 percent, respectively, in 31 states east of the Rocky Mountains and in the District of Columbia, would result in significant public health benefits. [EPA-HQ-OAR-2009-0491-1892.1, p. 1] The rule, scheduled to take effect in 2012, would deliver up to $290 billion worth of health and public welfare benefits in 2014 alone, including avoidance of 14,000 to 36,000 premature deaths. Compliance costs would total $2.8 billion annually, far less than the value of the benefits. [EPA-HQ-OAR-2009-0491-1892.1, p. 1]
The job of securing cleaner air for America's families and communities, however, is not complete. A significant fraction of the coal-fired power plants that generate about half the electricity used in America lack equipment to control emissions of pollutants that create ozone smog and tiny particulates, which are known respiratory and cardiac health hazards. [EPA-HQ-OAR-2009-0491-1892.1, p. 1] The Environmental Protection Agency's proposed Clean Air Transport Rule, which would reduce emissions of sulfur dioxide and nitrogen oxides by 71 percent and 52 percent, respectively, in 31 states east of the Rocky Mountains and in the District of Columbia, would result in significant public health benefits. [EPA-HQ-OAR-2009-0491-1892.1, p. 1] The rule, scheduled to take effect in 2012, would deliver up to $290 billion worth of health and public welfare benefits in 2014 alone, including avoidance of 14,000 to 36,000 premature deaths. Compliance costs would total $2.8 billion annually, far less than the value of the benefits. [EPA-HQ-OAR-2009-0491-1892.1, p. 1]
Respiratory Health Association of Metropolitan Chicago
[These comments were submitted as testimony at the Chicago, Illinois hearing.  See Docket Number EPA-HQ-OAR-0491-1746, pp.16-17.]
As an organization that represents people who have lung disease, we came here today to applaud EPA for their work and strongly encourage the agency to do more to clean up power plant pollution. 
To us, EPA's pollution rule isn't about scenic vistas and pretty skylines. To us, it's a matter of public health. 
To this end, while EPA's proposed Transport Rule is a significant step for clean air, we strongly urge the Agency to tighten its rule. 
Ringle, Weeks
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.128.]
I thank you for the measures you are considering and ask that you continue to push for the cleanest air possible.
Ripple, Steven
Thank you for taking an important step forward in the fight against pollution by proposing the Good Neighbor Rule. As you are aware, millions of people are currently breathing air that does not meet clean air standards. Soot and smog from dirty coal plants travels downwind and affects neighboring states. This pollution causes heart attacks, asthma and lung disease. [EPA-HQ-OAR-2009-0491-1611, p.2] 
I am not taking this situation and others like it lightly. Your time as EPA Administrator is limited, and if you don't put into effect many more rules, regulations, and standards like the Good Neighbor Rule, then you will have ensured a longstanding commitment to putting industry profits before the health of our planet and its every inhabitant. Not only will cleaning up the dirtiest plants reduce pollution from state to state and make our air safe, but implementing the Good Neighbor Rule specifically will take a step further to protect the environment and public health. If you are a true steward to this planet and its inhabitants, however, then you will recognize that we are operating without regard to the true costs of energy and this economy. [EPA-HQ-OAR-2009-0491-1611,p.2]
Ritz, Aaron
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.174.]
We're pleased that EPA is acting to help states be good neighbors by reducing air pollution escaping across state lines.
We applaud this common sense approach by Lisa Jackson and EPA to protect public health and help states clean up their air efficiently and cost-effectively.
Rizzo, M.D., Albert A.
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.16-20.]
It is that vulnerability why the American Lung Association urges the U.S. Environmental Protection Agency to adopt the Clean Air Transport Rule, and to make it stronger. 
That's why this proposed rule is so important. 
We need the help of this Clean Air Transport Rule to stop millions of tons of dangerous pollution from coming into Pennsylvania and Delaware. We need to clean up our own power plants so we are not spreading pollution to our neighbors.
In fact, we need to clean up millions more tons of these pollutants because even lower levels of pollution can mean even greater benefits. The American Lung Association urges EPA to adopt tighter limits on ozone than what are proposed in the the Rule, to reflect the tighter national air quality standards that are coming this year. 
We want the air coming across our state line to not add to the burden of these pollutants that we already have here in Pennsylvania and Delaware. We urge the Environmental Protection Agency to quickly move to adopt and put in place this important tool for our air. 
Rogers, Nick
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.90-93.]
I am a strong supporter of the proposed EPA Transport Rule
I am strongly urging the adoption of the Transport Rule. I fear that if it isn't adopted, my life might be one of those that could have been saved with the help of this reduced pollution.
I am strongly urging the adoption of the Transport Rule. I fear that if it isn't adopted, my life might be one of those that could have been saved with the help of this reduced pollution.
It is my request that the EPA please go forward with the proposed Transport Rule and protects everyone's health and air quality, especially those like myself with a higher risk of health problems.
Rust, Morgan
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.152-153.]
I want to show support for the Transport Rule to significantly reduce emissions from coal power plants for cleaner air. Clean air has to be a priority. During this crucial time showing its effects every day. As someone who bikes, runs and works outside, it directly affects me and my health.
Schmerling, Mark
Thank you for taking an important step forward in the fight against pollution by proposing the Good Neighbor Rule. As you are aware, millions of people are currently breathing air that does not meet clean air standards. Soot and smog from dirty coal plants travels downwind and affects neighboring states. This pollution causes heart attacks, asthma and lung disease. [EPA-HQ-OAR-2009-0491-0421, p.2]
Cleaning up the dirtiest plants will reduce pollution from state to state and make our air safe. I urge you to take a step further to protect the environment and public health by adopting this rule. [EPA-HQ-OAR-2009-0491-0421, p.2]
Schmoyer, Rebecca
Thank you for taking an important step forward in the fight against pollution by proposing the Good Neighbor Rule. As you are aware, millions of people are currently breathing air that does not meet clean air standards. Soot and smog from dirty coal plants travels downwind and affects neighboring states. This pollution causes heart attacks, asthma and lung disease.   [EPA-HQ-OAR-2009-0491-0330, p.2]
The Centers for Disease Control and Prevention reported that asthma rates have more than doubled since 1980. The center has explicitly stated that asthma can be reduced and sometimes eliminated by 'avoiding environmental triggers.' [EPA-HQ-OAR-2009-0491-0330, p.2]
In my opinion, dirty coal plants are the result of regulatory irresponsibility which should be treated as a serious crime. Nowhere in the United States should the air we breathe become a threat to someone's life or livelihood. No one in the United States should have to go through this, and yet it is still taking place as I write this. [EPA-HQ-OAR-2009-0491-0330, p.2]
Cleaning up the dirtiest plants will reduce pollution from state to state and make our air safer. I urge you to take a step further to protect the environment and public health by adopting this rule. [EPA-HQ-OAR-2009-0491-0330, p.2]
Sierra Club
The Sierra Club supports and incorporate by reference the substantive comments on the Rule submitted by the Clean Air Task Force, et aI., that seek further emission reductions and an expanded geographical coverage of the rule, as discussed in greater detail below. [EPA-HQ-OAR-2009-0491-2872.1 p.1]
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.84.]
I am grateful that the EPA is working on enforcing clean air designed to end regulatory enforcement too long exploited by big coal.
The Clear Air Transport Rule is one of those safeguards. I am very much in support of it.
Sierra Club, New Jersey Chapter
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.138-143.]
I just wanted to thank the EPA for taking a step with the interstate Transport Rule to reduce pollution and improve air quality. This Rule will help to clean up dirty coal plants that pollute their home states and downwind states throughout the region. We thank Lisa Jackson and the EPA for moving forward with the Good Neighbor Rule. The Agency has lived up to its name and reputation for protection of the environment and public health.
Coal plants pour millions of tons of Nitrogen Oxide and Sulfur Dioxide into the air every year. This pollution knows no borders. It doesn't know state boundaries or county lines. It travels downwind, affecting neighboring states like New Jersey, choking people with soot and smog.
The Good Neighbor Rule will hold these dirty coal plants accountable and put protections in place to limit harmful emissions. The Rule will protect downwind states like New Jersey and will greatly reduce pollution in upwind states as well.
This rule is essential for protecting the environment and the public health for the people of New Jersey, Pennsylvania and the nation.
I urge you as a citizen of New Jersey and the Sierra organizer to go forward with the rule. A delay in action could result in 36,000 deaths related to dirty air.
The interstate Transport Rule will save hundreds of millions of dollars in health savings, with economic benefit, by protecting people from pollution related illnesses.
As it has been said, it will costs very little in utility bills to support this. A dollar or two a month is a very small price to pay for the amount of lives that will be saved. This is a cost effective plan. I want to urge that to the EPA.
You have done an excellent job with this proposal to reduce soot and smog in 31 states. The people of New Jersey and all of the states affected by the rule will be able to breathe cleaner and healthier air.
To begin, as a member and representative of the New Jersey Chapter of the Sierra Club, I want to applaud the EPA's proposal 'to limit the interstate transport of emissions of nitrogen oxides (NOx) and sulfur dioxide (SO2)'. This proposal 'to both identify and limit emissions within 32 states in the eastern United States that affect the ability of downwind states to attain and maintain compliance with the 1997 and 2006 fine particulate matter (PM2.5) national ambient air quality standards (NAAQS) and the 1997 ozone NAAQS. The proposal 'to limit these emissions through Federal Implementation Plans (FIPs) that regulate electric generating units (EGUs) in the 32 states.' represents a major advance in the attempt to protect both public health and that of all animals, and the quality of all ecosystems in the affected areas. [EPA-HQ-OAR-2009-0491-3649, p.1]
Sierra Club, Pennsylvania Chapter
The Sierra Club, Pennsylvania Chapter - and it's over 24,000 members - supports the efforts of EPA to finally bring to our citizens a proposal that will help Pennsylvania protect our citizens from upwind power plant pollution and help prevent Pennsylvania from victimizing our citizens and our downwind neighbors with our dirty coal fired electric generation. The Sierra Club, Pennsylvania Chapter supports the Clean Air Transport Rule [TR]. [EPA-HQ-OAR-2009-0491-3482.1, p.1]
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.135-136 & pp.177-178.]
We are pleased that the Environmental Protection Agency is acting to help states be good neighbors. The rule will systematically envision and cut pollution from dozens of coal plants, and will otherwise spread across the country. We applaud this common sense approach by Lisa Jackson and the EPA to protect public health, and help states clean up their air efficiently and cost effectively.
On behalf of the Sierra Club and all my colleagues, I just want to say this is a real priority issue for us in this community and throughout the region. The coal industry is something we need to move beyond, both for greenhouse gases and for ozone pollution.
We thank the EPA for addressing this problem.
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.179-180.]
The Sierra Club and its Pennsylvania Chapter supports the proposed EPA proposal called the Good Neighbor Rule and Clean Air Transport Rule, because it will reduce sulfur dioxide and nitrogen oxide pollution that create acid precipitation, ozone smog and particle pollution that blows into our state. This will improve the health of millions of people at risk from these pollutants, especially vulnerable people, seniors, children and people with chronic lung disease and cardiovascular disease and diabetes. 
However, we call on EPA to strengthen this rule. We need to have even greater reductions in the airborne sulfur dioxide and nitrogen dioxide emissions that create deadly ozone and fine particle pollutions. 
Smith, Iskar
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.207-209.]
So, I'm an asthmatic, like many of you in this room. I am in favor of reducing the emissions for obvious reasons.
I feel that this rule needs to be passed and I strongly support the Transport Rule.
South Carolina Department of Health and Environmental Control 
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.83.]
We generally support the proposed Transport Rule and its important public health benefits, but we have some concerns about its implementation and the potential negative impact on air quality in South Carolina.
Southeastern States Air Resource Managers (SESARM)
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.44-45.]
We encourage EPA to finalize the Transport Rule consistent with the aforementioned principles.
Southern Alliance for Clean Energy
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.35-36]
The Southern Alliance for Clean Energy supports EPA's proposed Clean Air Transport Rule and believes that it's a good step toward requiring needed air pollution reductions in the electric power sector.
This rule will fill a wide and troublesome gap in the federal government's clean air regulatory scheme and will help relieve long-suffering states from the burden of out-of-state air pollution.
While air quality has improved in recent years, primarily through power plant retrofits, we see this new rule as an important step in cementing and then continuing the ongoing process of cleaning up our air.
The Transport Rule will lock in the gains we have made in the last five years, goes farther than CAIR would have in 15 states and should allow many non-attainment states in the east to reach attainment.
The proposed Transport Rule not only sets stringent standards for coal-fired units, it demonstrates that rigorous methods were used to derive those standards from state-specific emissions and transport data.
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.39.]
Ultimately, we support this rule and thank EPA for its work to rapidly finalize it because air pollution seriously threatens public health and quality of life for many southerners. We urge EPA to strengthen the rule as mentioned and we will be providing more in-depth written comments with our colleagues.
St. Louis University
I support these rules and urge the EPA to strengthen its standards even more to secure greater health and environmental benefits. [EPA-HQ-OAR-2009-0491-3604, p.1]
Stafford, Dr. Wesley & Jane
The clean-up of power plants is long overdue. I am urging EPA to strengthen the requirements on these power plants to improve air quality and protect public health. [EPA-HQ-OAR-2009-0491-3133, p.1]
Studies recently done at Driscoll Children's Hospital in Corpus Christi show that children in Corpus Christi Texas have a risk of asthma and respiratory disease that increases depending on how close they live to our refinery area. There is no question that we are seeing illness in our children related to pollution, yet the refineries in our community are all operating within the current EPA standards. We have to do more. [EPA-HQ-OAR-2009-0491-3133, p.1]
I support the proposed EPA 'Transport Rule' which will reduce sulfur dioxide and nitrogen oxide pollution that contribute to ozone smog and particle pollution. This will save lives and improve the health of millions of people at risk from these pollutants, especially seniors, children and people with chronic lung diseases. [EPA-HQ-OAR-2009-0491-3133, p.1]
State of Wisconsin, Department of Natural Resources
Wisconsin strongly supports EPA's efforts to address interstate transport of sulfur dioxide (SO2) and nitrogen oxides (NOx) emissions. We have long advocated for the ability to access and address the air quality impact contribution from upwind states on Wisconsin because a substantial portion of Wisconsin's ambient air problems are attributable to emissions from upwind states inside and outside the Lake Michigan airshed. Therefore, we have an inherent interest to ensure a phased implementation of equatable and efficient emission controls regionally. [EPA-HQ-OAR-2009-0491-2829.1, p.1] [EPA-HQ-OAR-2009-0491-3803.2_NODA, p.1]
Stimpfel, Theresa
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.130-133.]
I strongly support the proposed EPA rule and it's approach to interstate transport proposal and fine particle pollution. The EPA has done an excellent job in developing a well documented rule with great supporting materials for everyone to comment.
In summary I would like to say that my neighbors and I need the EPA to implement the Transport Rule so we can be healthier, to limit our consumption and to be able to use our financial resources wisely and to support the American economy, not simply support the power industry and their friends because they have the money, and to lobby strongly and to have limited improvement in air quality we need.
Strand, Rev. Dr. Horace
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.150-151.]
I want to applaud the EPA for taking the issue to change the regulation concerning our air. The Transport Act will give communities such as ours something to look forward to, something to hope for, for our children's well-being, as well as our own. 
Today we're sitting here talking about something that is paramount to the health and welfare of our all residents and all citizens of the United States. I applaud the EPA because they have demonstrated they are serious about change in this country. They are serious about the grass root organizations who are fighting, trying to protect the quality of life of the residents that have been bullied and taken advantage of by industries that their only concern is the almighty dollar. 
Stuckey, Richard
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.69.]
This alone should make it obvious that the changes proposed should be implemented vigorously in as short a possible timeframe as you can provide.
I encourage you to implement the tightest rules that you possibly can.
Tampa Electric Company
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.52.]
Tampa Electric generally supports EPA's proposal.
Taylor, Nancy
Please, please, please - I have been pleading for Clean Air Acts since 1976 and I'm running out of life....Help my grandson now! Help those with breathing problems to find a way to go to school, to work - to be active in the community - to live as productively as possible. [EPA-HQ-OAR-2009-0491-1594, p.2]
It's wrong to take the country's natural resources and life-sustaining elements away from all the people... Coal-burning, vehicle emissions, cigarettes....we've picked up some bad habits and it's time to REFORM!! [EPA-HQ-OAR-2009-0491-1594, p.2]
Thank you for your efforts on behalf of all suffering breathing patients, your own family members ---not to mention your own health! [EPA-HQ-OAR-2009-0491-1594, p.2]
Tennessee Department of Environment and Conservation, Division of Air Pollution Control
Tennessee supports EPA's efforts to identify and limit emissions of SO2 and NOX within the eastern United States. We note that the emissions reductions proposed by this rule, as well as the reductions that have been attained under the existing CAIR programs, are necessary for Tennessee and other States to attain and maintain compliance with the 1997 and 2006 ozone and PM2.5 NAAQS and to comply with the requirements of Tennessee's Regional Haze State Implementation Plan. We also recognize that significant changes to the existing CAIR programs were needed in order to address the issues raised by the DC Circuit Court of Appeals in North Carolina vs. EPA, and we appreciate EPA's efforts to develop a program that addresses the concerns of the Court, while preserving, to the extent possible, the flexibility allowed by an emissions trading program. [EPA-HQ-OAR-2009-0491-0553.1, p.2]
Tsou, Walter
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.96.]
I wish to offer my strong support for the proposed air pollution Transport Rule, otherwise known as the Good Neighbor Rule, which would restrict or limit power plant pollution.
Waddle, Tolsun
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.138.]
I applaud the EPA for taking this dramatic step. It's a tremendous step. I hope that consumers when they look at their energy bills go up a dollar or two a month realize that it's for the greater good.
Watzman, Talie
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.135.]
And I just -- I look forward to a future where runners don't have to carry around inhalers when they run and I think that this rule will be a step towards that in the future.
White, Dr. Yolanda
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.70-71.]
I'm requesting that the EPA set much tighter sulfer dioxide and nitrogen oxide emissions in support of this Transport Rule and require even greater cleanup. There's immediate need for an aggressive public awareness campaign and community outreach activities. Cleaning the air not only saves lives and money, but it keeps children in school and keeps people working, making it a win-win solution for everyone. 
Xcel Energy Inc.
Because of the company's efforts to reduce its emissions and prepare proactively for air quality, and other regulations applicable to the utility industry, we have a great interest in encouraging the Environmental Protection Agency ('EPA') to promulgate flexible regulations that minimize customer costs, maximize environmental benefits and reward early action, such as that already taken by Xcel Energy. For this reason, we appreciate the opportunity to comment on the Transport Rule. We support the efforts that EPA has made to respond to the D.C. Circuit's decision in North Carolina v. EPA while attempting to maintain the flexibility of a market-based trading program. We submit the comments below to provide constructive feedback to the Agency as it develops its final rule.
In summary, Xcel Energy offers comments recommending that (1) the EPA reward, rather than penalize, companies for making early emission reductions by creating an earl), reduction allowance pool to reward early movers; (2) we strongly support EPA's plan to utilize an interstate trading program, but encourage EPA to refine the allowance allocations; and (3) we strongly urge EPA to maintain the state groupings as proposed.
Our comments below address the following topics:
- Allowance trading provisions and allocations,
- Implementation timeline,
- States included and excluded from the proposed rule,
- EPA's analysis and justification for the proposed rule, and
- General comments. [EPA-HQ-OAR-2009-0491-2728.1, p.2]
Response: 
EPA thanks the commenters for their support of this Rule.  EPA is working as expeditiously as possible and within the full extent of its authority, under  Section 110(a)(2)(d) of the Clean Air Act, to ensure improved human health for all Americans through reductions in interstate transport of pollutants within the Transport Rule's 27 states.

II. General Comments in Opposition to Rule That Don't Fit Into Specific Topic Areas

Organization: Missouri Public Utilities Alliance (MPUA)
Comment: 
Missouri Public Utilities Alliance (MPUA)
We find it ironic that EPA is proposing rules through the air program that will encourage expanded use of natural gas at the same time the water division of the agency is critically reviewing the industry practice of "fracking" to create gas flow in previously nonproductive wells or strata.  It is this new practice which is a major reason that domestic natural gas inventory levels have swelled in recent year.  If EPA determines that injection of significant amounts of water and chemicals into underground geologic layers to release natural gas is not protective of the environment, the agency will be in a position of both requiring investments on one hand by the electric generation sector for fuel switching while at the same time escalating the price of the fuel on which those investments are predicated. [EPA-HQ-OAR-2009-0491-2785.1, pp.2-3]
Response: 
EPA thanks the commenter for their concern.  EPA's natural gas projections take into account the latest forecasts of resource availability, including natural gas supply, subject to all relevant costs and limitations on extraction.  Additionally, resources within each state will have the flexibility to adapt their compliance strategies to meet the state budgets at the lowest possible costs and are not required to pursue any particular strategy, such as choosing to combust natural gas.
Organization: Utility Air Regulatory Group (UARG)
West Window Corp.
Dayton Power and Light Company (DP&L)
Occidental Chemical Corporation (OCC)
Ameren Services Company
East Kentucky Power Cooperative
EquiPower Resources Corp.
Michigan Manufacturers Association (MMA)
ARIPPA
Holland Board of Public Works
Ohio Coal Association
Four Flags Area Chamber of Commerce
American Municipal Power, Inc. (AMP)
Michigan Chamber of Commerce
Mass Comment Campaign (245) (American Electric Power)
Jessee, Robert
DTE Energy
American Coalition for Clean Coal Electricity (ACCCE)
Indiana Municipal Power Agency
Comment: 
Ameren Services Company
The Proposed Transport Rule does contain some reasonable elements that Ameren can support; however it contains many that Ameren can not. The rule as proposed is seriously flawed on legal, policy and factual grounds. Considering the magnitude of these flaws EPA should withdraw the proposed rule and allow CAIR to continue. Then only after EPA has finalized the PM25 and 8-hour ozone standards currently under reconsideration replace it with a new proposed rule that addresses these new standards as well as remedies the specific deficiencies identified by the court in North Carolina v. EPA. In the development of this rule EPA should use the most recent emissions data, monitored air quality data and meteorological data available to allow for a creditable and relevant analysis. EPA should then, based on their analysis, develop a reasonable implementation and compliance schedule that allows adequate time for states to develop SIPs, rather than impose FIPs in the first instance. [EPA-HQ-OAR-2009-0491-2722.1, p.27]
American Coalition for Clean Coal Electricity (ACCCE)
COMPLIANCE ALTERNATIVES
Under the proposal, the alternatives to deferring the compliance deadlines would not adequately remedy the problem we have discussed above and would, in some cases, create complications. Below we discuss briefly the four most likely remedies if controls could not be installed by an EGU in time to meet the proposed deadlines. [EPA-HQ-OAR-2009-0491-2874.1 p.5]
Seek a Waiver from EPA
This solution is problematic because the standard for granting a waiver is unclear and, therefore, no owner of an uncontrolled EGU could be certain that EPA would approve such a waiver or how long the waiver would be valid. This alternative would create intolerable uncertainty. Further, it is not clear whether EGU operators seeking to obtain waivers would be deemed to be in violation of the Clean Air Act and, therefore, subject to civil penalties and allowance surrender requirements for circumstances beyond their control. [EPA-HQ-OAR-2009-0491-2874.1 p.6]
American Municipal Power, Inc. (AMP)
While AMP appreciates EPA's efforts to develop a replacement for the Clean Air Interstate Rule (CAIR), AMP is concerned that EPA's Transport Rule creates, rather than eliminates, regulatory and legal uncertainty and overlooks the time-consuming and costly nature of project development and unit control equipment retrofits. AMP encourages EPA to reconsider its current proposal and to enact a Transport Rule that realistically achieves environmental objectives but also accounts for the practical realities of building, replacing and retrofitting electric power plants. To that end, AMP requests that EPA consider the following specific comments. [EPA-HQ-OAR-2009-0491-2678.1, p.2]
Although AMP understands that EPA's primary goal in issuing the Transport Rule is to replace the CAIR Rule, the Transport Rule goes well beyond the scope of CAIR and creates significant, additional uncertainties for the power generation sector. [EPA-HQ-OAR-2009-0491-2678.1, p.2]
ARIPPA
As set forth above, ARIPPA objects to the Proposed Rule for a number of reasons. As an initial matter, ARIPPA contends that its member facilities should not be subject to the Proposed Rule, because EPA has not justified a finding of significant contribution as to these facilities. Specifically, EPA concludes that all affected units within the "category" of sources meeting EPA's somewhat arbitrary definition of EGU significantly contribute to downward nonattainment, without considering the substantial distinction in emission rates and characteristics among different types of EGUs, based upon boiler configuration and fuel type. In addition, EPA has concluded that the objectives of the Proposed Rule can most "cost effectively" be achieved by categorically regulating all EGUs? however, EPA does not consider the distinctions among types of EGUs dictated by emissions characteristics, fuel source, operational design, emissions control options, or any other criteria, in evaluating cost effectiveness in this context. [EPA-HQ-OAR-2009-0491-2794.1, pp.19-20]
Dayton Power and Light Company (DP&L)
DP&L appreciates the opportunity to comment on the proposed rule. Although the proposed Clean Air Transport Rule does contain some commendable elements, the proposed rule overall is seriously flawed on legal, policy, and factual grounds. These flaws are so substantial that EPA should withdraw the proposed rule and replace it with a new proposed rule that: [EPA-HQ-OAR-2009-0491-2637.1, p. 8]
:: Adopts a reasonable implementation and compliance schedule that allows adequate time for development of SIPs - rather than impose FIPs.
:: Does not impose emission reduction obligations on affected states that are more demanding than those in CAIR.
:: Does not withhold allowances from EGUs based upon unreasonably low estimates of current capabilities.
:: Takes into consideration the expected costs that will be incurred by the utilities to comply with unnecessary, over-stringent emission reductions. [EPA-HQ-OAR-2009-0491-2637.1, p. 8]
DTE Energy
As noted by UARG, ''The D.C Circuit's opinion in North Carolina v EPA did not require, or even suggest, that the overall levels of reductions required under CAIR were less than those necessary to comply with CAA section 110{a){2){D){i){I). Nor did the court include in its opinion any mandate that the replacement rule for CAIR must include a promulgation date in 2012 or within any period of time as short as six months after final rule promUlgation.' [EPA-HQ-OAR-2009-0491-2851.1,p.4]
East Kentucky Power Cooperative
Finally, EKPC adopts and incorporates here in the attached comments on the rule from the Utility Information Exchange of Kentucky. For all the above-stated reasons, EKPC urges EPA to delay the CATR until such time as all underlying data can be reviewed, reconciled and calculations can be transparent and understood. Time should be taken to analyze the emissions reductions previously achieved by the industry as well as to acknowledge the effects of the rule on the ability to generate power. [EPA-HQ-OAR-2009-0491-2776.1, p.5]
EquiPower Resources Corp.
Based on the foregoing, EquiPower submits that the Transport Rule, as currently proposed, is legally and technically deficient because: [EPA-HQ-OAR-2009-0491-2704.1, p.31]
EPA's state budget caps and assurance provisions stand in the way of an effective emissions trading market; [EPA-HQ-OAR-2009-0491-2704.1, p.32]
The Transport Rule has co-opted state authority and adopted a regulatory approach that is flawed and contrary to law; [EPA-HQ-OAR-2009-0491-2704.1, p.32]
The Proposed Rule relies on flawed data and assumptions resulting in significant errors in unit-level allocations and state emission budgets; and [EPA-HQ-OAR-2009-0491-2704.1, p.32]
The Transport rule unfairly penalizes certain electric generating units ("EGUs").  [EPA-HQ-OAR-2009-0491-2704.1, p.32]
Thus, while EquiPower applauds EPA's efforts to improve air quality, if the issues above are not addressed, EquiPower submits that the Transport Rule will impose requirements on the power generation sector that: (i) are technically infeasible, and (ii) penalize states and sources that have already taken action on NOX and SO2 emissions. As a result, the compliance costs of the Proposed Rule are likely to be significantly higher than EPA's estimates, and therefore could result in a substantial disruption in the power generation sector. [EPA-HQ-OAR-2009-0491-2704.1, p.32]
Four Flags Area Chamber of Commerce
We strongly urge the EPA to delay implementation of the Transport Rule as it is proposed. The current proposal has several shortcomings that will result in needless economic harm to my state. [EPA-HQ-OAR-2009-0491-3807, p.1]
Holland Board of Public Works
The HBPW encourages regulations that protect human health and the environment without sacrificing the reliability and the diversity that public power entities such as ourselves contribute to the national electric system and our local communities. We look forward to a fair and balanced final Clean Air Transport rule. This version is not it. [EPA-HQ-OAR-2009-0491-2861.1, p.2]
Indiana Municipal Power Agency
The Indiana Municipal Power Agency strongly urges the EPA to delay implementation of the Transport Rule as it is proposed. [EPA-HQ-OAR-2009-0491-3057.1, p.1]
Jessee, Robert
I am asking the EPA to reconsider the proposed Air Pollution Transport Rule. I have and will continue to support efforts to reduce the environmental impact of using coal to generate electricity, but these proposed regulations are not practical or feasible. [EPA-HQ-OAR-2009-0491-3288, p.1]
In its current proposed state these rules do not take into account the progress that was made recently with compliance to CAIR, nor how this compliance has affected air quality.  [EPA-HQ-OAR-2009-0491-3288, p.1]
Once again I support the agency's efforts to reduce the amount of sulfur dioxide and nitrogen oxide in the atmosphere, but I am terribly concerned about the impact of this proposed rule. [EPA-HQ-OAR-2009-0491-3288, p.1]
Mass Comment Campaign (245) (American Electric Power)
I encourage the EPA to reconsider the proposed rule related to the Interstate Transport of Fine Particulate Matter and Ozone.
Michigan Chamber of Commerce
On behalf of our over 6,800 members representing manufacturers, retailers, service providers and local chambers of commerce, the Michigan Chamber of Commerce would like to express our opposition to the proposed rule related to Fine Particulate Matter and Ozone (The Transport Rule) (75 Fed. Reg. 45210, August 2, 2010), Docket No. EPA-HQ-OAR-2009-0491. [EPA-HQ-OAR-2009-0491-2696.1, p.1]
At the Michigan Chamber of Commerce, we strongly urge the EPA to either retract and revise the rule or delay implementation of the Transport Rule as it is proposed. Michigan is currently challenged by some of the most difficult economic circumstances in the entire United States. Michigan businesses have responded with tremendous resilience to these difficult times. However, the current proposed Transport Rule will likely result in needless economic harm to job providers in Michigan. [EPA-HQ-OAR-2009-0491-2696.1, p.1]
At the Michigan Chamber of Commerce, we understand the responsibility that EPA has with respect to protecting human health and the environment. We know that tough choices need to be made. However, the EPA's proposed path forward does not make sense. We, therefore, respectfully request that the EPA retract and revise the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2696.1, p.2]
Michigan Manufacturers Association (MMA)
MMA strongly urge the EPA to either retract and revise the rule or delay implementation of the Transport Rule as it is proposed. The current proposal has several shortcomings that will result in needless economic harm to Michigan. [EPA-HQ-OAR-2009-0491-2762.1, p.1]
MMA believes the EPA's actions are premature and do not allow enough time for state participation or for industry compliance. Hasty action will have economic consequences for Michigan without any assurance that the rule will deliver the desired results any faster than the nation can achieve on its current path. I strongly urge the EPA to either retract and revise the rule or delay implementation of the Transport Rule as it is proposed. The current proposal has several shortcomings that will result in needless economic harm. Finally, the EPA should rethink its plans to alter the long standing and successful partnership between the states and the EPA, with regard to the state implementation planning process. [EPA-HQ-OAR-2009-0491-2762.1, p.4]
Occidental Chemical Corporation (OCC)
As discussed in detail in these comments, OCC has significant concerns with the proposed rule and the supporting technical basis that will require correction by EPA before the CATR is finalized. [EPA-HQ-OAR-2009-0491-2754.1, p. 1]
Ohio Coal Association
:: The Transport Rule relies on outdated and inaccurate technical information and inappropriate models. EPA, itself, admits that it continues to update data, both in the NODA and contemplated subsequent technical additions to the regulatory record. EPA should postpone any implementation of this rulemaking until it has completely and fully evaluated all necessary and appropriate data. [EPA-HQ-OAR-2009-0491-2743.1, p.2]
Utility Air Regulatory Group (UARG)
EPA's explanation of the elements of the PTR, and its information and calculations offered in support of the PTR, are opaque to the point of incomprehensibility. These points are explained further below. For these reasons, UARG believes that the PTR is inadequate as a proposed rule to replace CAIR. EPA should develop and offer for comment a new proposal that corrects the serious flaws in the PTR. [EPA-HQ-OAR-2009-0491-2756.1, pp.9-10]
West Window Corp.
I am writing to express my concerns regarding the proposed Transport Rule. I am a proponent of the Clear Air Interstate Rule, and I support legislation to monitor coal emissions and reduce the environmental impact of using coal as an energy source. However, I feel that we must find a balance between reasonable environmental limits and excessive governmental regulations that will force electric utilities to meet unreasonable emissions standards, which will drastically increase the cost of energy. I am opposed to the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2386, p.1]
In summary, I am opposed to the proposed Transport Rule and I ask you to repeal this Rule and allow the Clear Air Interstate Rule to remain in effect, or at least, to delay ruling on this Transport Rule to allow further studies to be completed. [EPA-HQ-OAR-2009-0491-2386, p.1]
Response: 
EPA would like to thank commenters for their feedback and suggestions.  Some comments were concerned with the Transport Rule's overall regulatory approach - including data assumptions, implementation and compliance schedule, unit-level and allocations.  Please see Section VII of the Preamble for further information on the design of the Agency's overall regulatory approach as well as how the above-mentioned issues are addressed, in order to achieve emission reductions under the Transport Rule.  Additionally, Section XII.A of the Preamble explains how the Transport Rule will impact the power generation sector (e.g., utility rate payers).
One commenter argued that EPA's state budget caps and assurance provisions stand in the way of an effective emissions trading market.  In fact, EPA believes its approach for setting state budgets and applying assurance provisions under the Transport Rule are directly responsive to the Court's opinion in North Carolina and its remand of the Clean Air Interstate Rule (CAIR).  Please see Section VII.E in the Preamble for more information.
Other commenters are seeking a waiver from EPA to delay compliance for uncontrolled EGUs.  EPA does not find any reasonable grounds to consider such waivers under the Transport Rule programs.  As discussed in section VII.C of the preamble, EPA believes the Transport Rule compliance deadlines allow enough time for sources to pursue the control strategies (including retrofit installations of pollution control technologies) that EPA projects to be cost-effective responses to the state budgets under the rule.  Furthermore, the Transport Rule does not impose any specific emission reduction requirement on any given unit subject to the rule, and owners and operators are free to obtain additional allowances in the market to cover their units' emissions under the programs.  With these important flexibilities in place, EPA disagrees with commenters that any "waivers" from compliance are warranted.
One commenter stated that the Transport Rule goes well beyond the scope of CAIR and creates significant and additional uncertainties for the power generation sector.  In fact, the Transport Rule does create certainty by the fact that it will be replacing CAIR, which the Court ruled as unlawful.  Although the Court did not specify a definitive date by which EPA should promulgate the Transport Rule, the Court did not give the Agency an infinite stay on CAIR and did, in fact, indicate that the Transport Rule was to be completed in a timely manner.
Other commenter concerns included the EPA's modeling of EGUs was not properly representing EGU control characteristics.  In fact, EPA has carefully considered such EGU pollution control technology characteristics in its projections for emission reductions under the Transport Rule.  Please refer to the Appendix for Final Transport Rule Response to Comment (RTC) - "Transport Rule IPM Assumptions Response to Comments" - for more detailed information.
Several commenters expressed concerns regarding the economic impacts (e.g., employment impacts, cost to utility rate payers) of the Transport Rule.  Please refer to Section VIII of the Preamble for a complete explanation of the emission reductions, impacts on concentrations of PM2.5 and Ozone of the final SO2 and NOX emission reduction strategy, overall benefits, and the employment impacts of the Transport Rule.  Section VIII.C of the Preamble specifically discusses, in detail, the benefits to be achieved by the Transport Rule.  The analysis in Section VIII.C of the Preamble demonstrates how the benefits far outweigh the costs.
Many commenters criticized EPA's timeframe for issuing and implementation of the Transport Rule.  Although the Court did not specify a definitive date by which EPA should promulgate the Transport Rule, it did not give the Agency an infinite stay on CAIR and did, in fact, indicate that the Transport Rule was to be completed in a timely manner.  Section 307(d)(5) of the CAA requires the Administrator to give an opportunity for written or oral comments.  The Act does not specify the length of time, other than the record must be open 30 days after holding public hearings - with which EPA complied.
EPA posted the signed version of the Proposed Transport Rule to the web when it was signed on July 6, 2010.  The proposal was published in the Federal Register on August 2, 2010, and the public comment period closed on October 1, 2010.  This provided a 60 day comment period (and also provided 90 days of public notice from the date posted to the web).
EPA posted the signed version of the first Transport Rule Notice of Data Availability (NODA) addressing its power sector model (IPM) to the web when it was signed on August 25, 2010.  The first NODA was published in the Federal Register on September 1, 2010, and the public comment period closed on October 15, 2010.  This provided a 45 day comment period (or 52 days from the date posted to the web).  EPA posted the signed version of the second Transport Rule NODA (addressing emissions inventories) to the web when it was published in the Federal Register on October 27, 2010.  The public comment period closed on November 26, 2010, which provided a 30 day comment period.  EPA posted the signed version of the third Transport Rule NODA (allocations and related matters) to the web when it was signed on December 30, 2010.  The third NODA was published in the Federal Register on January 7, 2011.  The public comment period closed on February 7, 2011, which  provided a 30 day comment period (or 38 days from the date posted to the web).
Given the timeframe EPA provided to the public for submission of comments, and indicative of the fact that the Agency received several hundred substantive comments, commenters did, in fact, have sufficient time to submit their comments for consideration. 
Organization: we energies
PowerSouth Energy Cooperative
Comment: 
PowerSouth Energy Cooperative
The Proposal, as written, fails to provide equitable treatment and the regulatory and economic certainty and flexibility that PowerSouth must have to meet our goal of providing reliable, affordable, low cost energy to our member owners.  As detailed in the comments below, the Proposal must be amended to address these issues. [EPA-HQ-OAR-2009-0491-2693.1 ,p.2]  
we energies
Unfortunately the proposed rule does not account for post-2005 emission reductions. We have also found the proposal to be based on factual errors in data inputs and on outdated modeling assumptions. These shortcomings result in inaccurate estimates of interstate transport and contribution to downwind nonattainment, and are ultimately reflected in flawed state emission budgets and electric generating unit (EGU) budget allocations. [EPA-HQ-OAR-2009-0491-2629.1, p.2]
Response: 
EPA would like to thank commenters for their feedback and suggestions.  Some comments were concerned with the Transport Rule's overall regulatory approach - including data assumptions, implementation and compliance schedule, unit-level and allocations.  Please see Section VII of the Preamble for further information on the design of the Agency's overall regulatory approach as well as how the above-mentioned issues are addressed, in order to achieve emission reductions under the Transport Rule.  Additionally, Section XII.A of the Preamble explains how the Transport Rule will impact the power generation sector (e.g., utility rate payers).
Other commenter concerns included the EPA's modeling of EGUs was not properly representing EGU control characteristics.  In fact, EPA has modeling characteristics that project the controls for which the Agency is accounting in EGUs.  Please refer to the IPM documentation located within the Transport Rule Docket for more information on EGU-specific characteristics considered in this rulemaking.
Several commenters expressed concerns regarding the economic impacts (e.g., employment impacts, cost to utility rate payers) of the Transport Rule.  Please refer to Section VIII of the Preamble for a complete explanation of the emission reductions, impacts on concentrations of PM2.5 and Ozone of the final SO2 and NOX emission reduction strategy, overall benefits, and the employment impacts of the Transport Rule.

III. [Reserved]

III.A. EPA's Authority for This Action

Organization: Alcoa Power Generating Inc. - Warrick Power Plant
Ameren Services Company
American Electric Power

Comment: 
Alcoa Power Generating Inc. - Warrick Power Plant
EPA has proposed a FIP rather than a SIP, followed by a FIP, as required by the CAA. Congress intended States to take the primary role in regulating stationary sources under Title I of the CAA. Title I unequivocally guarantees States the opportunity to establish a statewide program for achieving the NAAQS, and only where States fail to establish such programs does a FIP apply directly to the sources within the State. Here, EPA proposes to skip the SIP process and immediately and directly regulate power plants in States covered under this rule. Only once the FIP is in place, does EPA intend to allow States 'the option of replacing these Federal rules with state rules to achieve the required amount of emissions reductions from sources selected by the state.' [EPA-HQ-OAR-2009-0491-3648, p.5]
EPA lacks statutory authority to reverse the order of the NAAQS process designed by Congress and immediately impose its program for a State's achievement of the NAAQS, unless and until a State has failed to develop and obtain approval of its own State program. [EPA-HQ-OAR-2009-0491-3648, p.5]
Not only does a FIP-first approach violate the CAA, it also deprives States and sources the opportunity - intended by the statutory scheme - to selectively target reductions from among the many emissions sources and to find innovative, source-specific solutions to achieving emission reductions.  [EPA-HQ-OAR-2009-0491-3648, p.5]
EPA acknowledges this failing of its FIP-first approach: '[W]hen allowance based programs are implemented through SIPs, states may have significant flexibility to determine the methodology used to allocate or auction allowances in their budgets. Under the proposed FIPs, EPA would allocate allowances to sources in a manner consistent with the methodology used to determine each state's budget.' 75 FR 45353.  EPA believes this approach is appropriate because of the link between the allowance allocation methodology and the significant contribution determinations.' 75 FR 45353.  However, EPA has not taken into consideration in its selection of EGU's for inclusion in the CATR that some of these generators may produce electricity that is not sold, but is instead used for internal support purposes. Such generators would not be subject to the rule, because their produced electricity is not sold. States are in a better position to make this determination, and fashion their budget compliance mechanisms accordingly. [EPA-HQ-OAR-2009-0491-3648, p.5]
EPA's motivation for doing the FIP first, evident throughout the rulemaking, is to arrogate to the Agency the selection of which sources to regulate, thereby usurping the States' prerogative to select sources for NAAQS attainment as established by the CAA. For example, EPA notes that '[f]ossil-fuel-fired power plants contribute a large and substantial fraction of the emissions of several key air pollutants, and the agency has statutory or judicial obligations to make several regulatory determinations on power plant emissions.' 75 FR 45213/2. While this maybe a true statement, EPA is no less 'obligated' to follow other provisions of the statute, including those establishing a SIP process and thereby granting States the authority to the ability to identify the source reductions. [EPA-HQ-OAR-2009-0491-3648, p.5]
It is also noteworthy that EPA baldly asserts that because power plants contribute a  'substantial fraction' of key pollutants, EP A can therefore use a FIP to directly compel reductions from that sector. The statute an4 its longstanding regulatory interpretations do not support EPA's finding as a basis to regulate via a FIP. APGI opposes EPA's arbitrary interpretation of the CAA, in the context of this rule and any others for which this novel interpretation of the law could set a precedent. Further, EPA should provide supporting data for its finding, including the comparative contributions of other sources of emissions and key pollutants. EPA is clearly targeting the power sector, but a State in a SIP very well could conclude that attainment is more properly achieved through the regulation of other sources. APGI supports a straightforward application of clear CAA text, which EP A has abandoned in this proposed rule. [EPA-HQ-OAR-2009-0491-3648, p.6]
Ameren Services Company
States should be given time to develop SIPs instead of EPA immeadiately issuing a FIP
The proposed federal implementation plan (FIP) for the Transport Rule supplants the role that Congress granted states under the Clean Air Act (CAA). EPA has no authority to promulgate a FIP to replace CAIR without first giving the states the opportunity to develop their own SIPs and then finding such SIPs deficient or a failure to submit. Support for this is given under CAA § 101 (a)(3) [EPA-HQ-OAR-2009-0491-2722.1, p.3; For additional comments pertaining to, States should be given time to develop SIPs instead of EPA immediately issuing a FIP, see pp.3-5 of this comment summary]
American Electric Power
I understand, the U.S. EPA has proposed a new air emissions rule designed to reduce sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions in 31 states by 2014. My company(AEP) favors the continued reduction of air emissions, but believes that the EPA should delay this rule for several reasons:

:: The 2014 deadline does not provide enough time for emissions control equipment to be designed, permitted, fabricated and installed on power plants. 

:: The deadline does not provide enough time for states to develop their own implementation plans to comply with the rule. [[This comment can also be found in Section VII.C.]]

:: The data that the EPA used to develop the rules were outdated and based on inaccurate information. This has caused the EPA to underestimate the amount of work needed to comply as well as the cost.  [EPA-HQ-OAR-2009-0491-1120, p.1]
The EPA should delay the Transport Rule until it sees the latest modeling based on CAIR compliance. At the least, the EPA should extend the compliance deadline to allow companies time to install the needed retrofits and to allow states to develop their own implementation plans.  [EPA-HQ-OAR-2009-0491-1923, p.1] [[This comment can also be found in Section VII.C.]]
Under the Proposed Transport Rule, states would play a distinctly secondary (or even nonexistent) role in implementation. By framing its program as a FIP and setting deadlines that do not allow enough time for each state to develop its own state implementation plan (SIP) for addressing interstate transport, EPA is effectively preempting state discretion in determining how to meet at least the first (2012) phase of emission reduction obligations. EPA's legal theory for bypassing the states is that, in the Agency's view, they have defaulted on their CAA section 1l0(a)(2)(D)(i)(I) obligations with respect to the 1997 ozone and fine particulate matter (PM2.5) NAAQS and with respect to the 2006 PM2.5 NAAQS. But EPA has approved states' plans for meeting those obligations, and the flaws in the CAIR program identified by the D.C. Circuit in the North Carolina case were of EPA's making, not the states'. EPA has failed to provide current and specific notification to the states targeted by the proposed Transport Rule of how their current implementation plans fail to meet the requirements of section 11O(a)(2)(D)(i)(I). [EPA-HQ-OAR-2009-0491-2665.1, p.2]
Furthermore, the six to eight months is a fraction of the time needed for states to develop their own implementation plans and get them approved. State implementation plans are not only the primary and preferred approach under the Clean Air Act, but also especially vital given the huge financial implications and accompanying decisions that will result from these new regulations. [EPA-HQ-OAR-2009-0491-2665.1, p.5] [[This comment can also be found in Section VII.C.]]
Many states have in place CAIR SIPs that were approved by EPA. In the absence of regulatory actions by EPA to disapprove those SIPs and require further regulatory development, the states can continue to rely on those programs. EPA has recently begun the process of issuing proposed disapprovals of the CAIR portions of certain SIP submissions, claiming that the states have not submitted sufficient technical information to support a finding that the requirements of Section 1I0(a)(2)(D)(i)(I) are met. See e.g. 76 Fed. Reg. 6376 (February 4, 2011). However, the modeling analysis submitted by MOG does in fact show that any significant contribution to non-attainment has been eliminated through the reductions required by CAIR. [EPA-HQ-OAR-2009-0491-3934[1].1, p.3] 
Response: 
For the reasons explained in this section of the RTC, in section IV.C.2 of the preamble to the final rule, and in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs Final Rule TSD", EPA has a legal obligation to promulgate the FIPs in this final rule and need not provide states an additional period to submit SIPs that are overdue or have been disapproved.  This conclusion is based on the plain language of the Clean Air Act as applied to the specific circumstances of each state.  
Section 110(c)(1) of the Act requires EPA to promulgate FIPs within two years after finding that a state has failed to make a required SIP submission or disapproving a SIP.  Specifically, section 110(c)(1) states that the Administrator shall promulgate a Federal Implementation Plan within two years after the Administrator "(A) finds that a State has failed to make a required submission or finds that the plan or plan revision submitted by the State does not satisfy the minimum criteria established under subsection (k)(1)(A) of this section or (B) disapproves a State implementation plan submission in whole or in part."  42 U.S.C. § 7410 (c)(1)(A) & (B).  EPA is relieved of the obligation to promulgate a FIP only if the state corrects the deficiency and EPA approves the SIP before promulgating a FIP.  42 U.S.C. § 7410(c)(1).  The Act does not create any exceptions to this rule.
For each FIP in this final rule, EPA either has found that the state failed to submit a 110(a)(2)(D)(i)(I) SIP for the relevant NAAQS, or has disapproved the state's 110(a)(2)(D)(i)(I) SIP submission for the relevant NAAQS.  In 2005, EPA made findings of failure to submit 110(a)(2)(D)(i) SIPs with respect to the 1997 ozone and 1997 PM2.5 NAAQS for all states.  In June 2010, EPA found that the following states had failed to submit 110(a)(2)(D)(i)(I) SIPs with respect to the 2006 PM2.5 NAAQS:  DC, MD, PA, VA, WV, IL, MI, MN, WI, IA, and NE.  Subsequently, EPA found that Tennessee had also failed to submit a 110(a)(2)(D)(i)(I) SIP with respect to the 2006 PM2.5 NAAQS.  In addition, EPA has disapproved 110(a)(2)(D)(i)(I) SIPs for the 2006 PM2.5 NAAQS that had been submitted by the following states: NJ, NY, AL, GA, KY, NC, IN, OH, TX, MO, and KS.  Additional information regarding state specific actions taken by EPA appears in the TSD entitled "CAA 110(a)(2)(D)(i)(I) SIP submissions."
EPA thus has an obligation to promulgate FIPs to address the identified SIP deficiencies with respect to significant contribution to nonattainment and interference with maintenance unless two things happen: (1) the state corrects the deficiency; and (2) EPA approves the SIP before promulgating a FIP. 
EPA disagrees with the suggestion that EPA was relieved of its obligation and its authority to promulgate FIPs when it approved SIP submissions from certain states implementing the requirements of CAIR in those states.  EPA does not interpret the Clean Air Act as relieving it of this obligation in the circumstances presented here.   
In 2005, EPA found that all states had failed to make submissions that address the requirements of section 110(a)(2)(D)(i) related to interstate transport of pollution with respect to the 1997 ozone and 1997 PM2.5 NAAQS.  See 70 FR 21147 (April 25, 2005).  Also in 2005, EPA promulgated CAIR, which was intended to provide states covered by the rule with a mechanism to satisfy their section 110(a)(2)(D)(i)(I) obligations.  In CAIR, EPA concluded at that time that the states in the CAIR region would meet their section 110(a)(2)(D)(i) obligations to address "significant contribution" and "interference with maintenance" requirements for the 1997 ozone and 1997 PM2.5NAAQS by complying with CAIR requirements.  EPA also issued Federal Implementation Plans for all states covered by CAIR to implement the requirements of CAIR in a timely manner.  EPA also concluded then that these FIPs satisfied the requirements of 110(a)(2)(D)(i)(I).  EPA allowed states to remain subject the FIPs as promulgated, submit "abbreviated SIPs" to allocate allowances to sources in their states and make other slight modifications to the program while remaining subject to the FIPs, or to submit "full CAIR SIPs" to replace the FIP or FIPs for the state.  EPA also determined that states which received EPA approval of a full CAIR SIP did not need to submit a separate SIP revision to satisfy the section 110(a)(2)(D)(i) requirements.  Some states remained subject to the FIPs as promulgated, some states remained subject to the FIPs but received EPA approval of an abbreviated CAIR SIP, and other states received EPA approval of a full CAIR SIP.  Further not all states chose the same path for all pollutants covered by CAIR.
As an initial matter, EPA notes that the commenters' argument that approval of a CAIR SIP relieved EPA of the obligation to promulgate a FIP applies only to EPA's obligation to promulgate FIPs with respect to the 1997 PM2.5 and 1997 ozone NAAQS for those states which submitted and received EPA approval of a full CAIR SIP for the relevant NAAQS.  This argument does not address EPA's authority to promulgate FIPs for the 2006 PM2.5 NAAQS which was not addressed in CAIR.  It also does not apply to EPA's authority to promulgate FIPs for the 1997 ozone and 1997 PM2.5 NAAQS for states that remain subject to the CAIR FIPs, including those with approved "abbreviated SIPs". 
Further, the argument also fails in the limited circumstances where it applies  -  that is with respect to EPA's authority to promulgate FIPs for the 1997 PM2.5 and 1997 ozone NAAQS for those states which submitted and received EPA approval of a full CAIR SIP for the relevant NAAQS.  In 2008, CAIR and the CAIR FIPs were found unlawful and remanded to EPA.  Among other things, the court found that CAIR did not effectuate the statutory mandate of section 110(a)(2)(D)(i)(I) and that the reduction requirements were not tied to that statutory mandate.  Compliance with CAIR, it found, did not make measurable progress towards satisfying the statutory requirement to prohibit emissions that significantly contribute to nonattainment of or interfere with maintenance of the NAAQS in another state.  Thus, in light of the court decision, neither the CAIR FIPs nor the SIPs approved to replace those FIPs can be said to satisfy those requirements and thus remedy the state's 110(a)(2)(D)(i)(I) deficiency previously identified by EPA.  On rehearing, the court decided to remand CAIR without vacatur to temporarily preserve the environmental values covered by CAIR.  North Carolina, 550 F.3d 1176 (D.C. Cir. 2008).  The SIPs remained in force for the limited purpose allowed by the Court -- that is to achieve interim reductions until EPA promulgated a rule to replace CAIR.  The fact that CAIR remains in place temporarily does not disturb the court's conclusion that CAIR and the CAIR SIPs/FIPs do not satisfy the requirements of 110(a)(2)(D)(i)(I),  A CAIR SIP submittal, thus is not a submittal of a SIP that corrects the identified SIP deficiency, and EPA's approval of that submittal does not relieve it of the obligation to promulgate a FIP to address the SIP deficiency.
Nonetheless, to avoid any confusion, EPA is taking action in this notice under section 110(k)(6) to correct its prior CAIR SIP approvals to rescind any approval to the extent that it: (a) states or suggests that the SIP submissions either satisfied or relieved states from the obligation of submitting a SIP to demonstrate compliance with the requirements of section 110(a)(2)(D)(i)(I) with respect to the 1997 ozone and/or 1997 PM2.5 NAAQS; (b) states or suggests that the SIP approval affects EPA's authority to issue a FIP.  This action is based on EPA's determination that, in light of the court decision, the SIP approvals were in error to the extent they provided explicitly or implicitly that compliance with CAIR satisfies the requirements of 110(a)(2)(D)(i)(I) with respect to the 1997 ozone or the 1997 PM2.5 NAAQS or that the SIP submissions corrected the deficiency previously identified by EPA.
Finally, nothing in the Act requires EPA to give the states another opportunity, following promulgation of the Transport Rule, to promulgate a SIP before EPA promulgates a FIP.  Section 110(a)(2)(D)(i)(I) SIP submittals are due 3 years after promulgation or revision of a NAAQS.  See 42 U.S.C. § 7410(a)(1).  Section 110(a)(2)(D)(i)(I) SIPs for the 1997 ozone and PM2.5NAAQS were due in 2000 and 110(a)(2)(D)(i)(I) SIPs for the 2006 PM2.5 NAAQS were due in 2009.  While the statute gives EPA authority to prescribe a shorter period of time for states to make these SIP submissions, it does not give EPA authority to extend the 3-year deadline established by the Act.  See 42 U.S.C. § 7410(a)(1).  Moreover, there is no requirement that EPA promulgate a rule or issue guidance regarding the specific requirements of section 110(a)(2)(D)(i)(I) in advance of the SIP submittal deadline, much less a provision giving EPA authority to alter the statutory SIP submittal deadline so that it runs from the issuance of any such guidance. 
As explained above, in the Technical Support Document (TSD) entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs," and in section IV.C.2 of the preamble to the final rule, EPA is promulgating FIPs only in those circumstances where the Clean Air Act explicitly provides that it shall do so. 
EPA also disagrees with the commenters' characterization of EPA's approach as a "FIP first" approach and their suggestion that EPA is skipping the SIP process.  To the contrary, EPA has followed the Clean Air Act provisions which give states a specified amount of time to submit SIPs and requires EPA to take action in certain circumstances when SIP deficiencies remain.  EPA is not depriving States of the opportunity to target specific emission reduction opportunities.  If EPA receives state SIPs that satisfy the requirements of section 110(a)(2)(D)(i)(I), it will take action to approve those SIPs regardless of the regulatory mechanism used to satisfy the requirements.  For example, some states prior to promulgation of the Transport Rule, took steps to significantly reduce emissions or SO2 and NOX.  One such state, Delaware, submitted a 110(a)(2)(D)(i)(I) SIP to EPA and, since EPA's analysis (based on updated emissions inventories) now demonstrates that sources in Delaware do not significantly contribute to nonattainment or interfere with maintenance of the PM2.5 or ozone NAAQS, EPA is therefore not promulgating a FIP for Delaware.  Instead, it intends to move forward to approve the Delaware SIP submission.  (See 76 FR 2853, January 18, 2011).  EPA further notes that its decision to promulgate the FIPs in this action was not based simply on a determination that power plants contribute a substantial fraction of key pollutants.  As explained above, section 110 of the Clean Air Act gives EPA a legal obligation to promulgate the FIPs in this action, and EPA has concluded that one way for EPA to address this obligation is through regulation of power plants.  States have been free since the relevant NAAQS were promulgated (in 1997 and 2006 respectively) and remain free to address the transport obligations as they prefer and submit such SIP revisions to replace the Transport Rule FIPs. 
Further, pursuant to section 110(a)(1) the deadline for submitting infrastructure SIPs for a particular NAAQS runs from the date of promulgation or revision of that NAAQS.  The date on which EPA makes designations for the NAAQS has no impact on the SIP submittal deadline.  Thus, the structure of the statutory scheme demonstrates that Congress did not intend to require EPA to finalize attainment designations before requiring the submission of 110(a)(2)(D)(i)(I) SIPs.  As noted above, these SIPs are due within three years of promulgation of the NAAQS, and section 107(d)(1)(B)(i) of the Act allows EPA to take that same length of time in some instances to make designations with respect to the NAAQS.  The structure of the statutory scheme suggests that Congress intended states to have, within a few years of the promulgation or revision of a NAAQS, information regarding their designation status but also information regarding the steps to be taken by upwind states to address transported emissions.  This structure makes sense given the difficulties faced by downwind states which have significant amounts of pollution coming from out of state sources.  Without information regarding steps taken to address transported emissions, it is extremely difficult for such states to develop plans to bring nonattainment areas within the state into attainment.   This structure of the statute also suggests that the designation status of an area should not be considered relevant to the 110(a)(2)(D)(i)(I) analysis.
The fact that EPA continued approving CAIR SIPs and technical corrections to CAIR SIPs following the remand of the CAIR rule has no impact on EPA's authority to promulgate the FIPs in this rule.  These approvals were done for the limited purpose of implementing the D.C. Circuit's decision remanding the rule without vacatur to temporarily preserve environmental values covered by CAIR.  Given this mandate, EPA felt it was appropriate to continue implementing the CAIR program, including promulgating SIP approvals, until the program could be replaced.  Further the fact that a state was not covered by CAIR does not mean that EPA now lacks FIP authority for that state.  The analysis remains the same.  Where there is a finding of failure to submit or a SIP disapproval EPA has an obligation to promulgate a FIP within two years unless a SIP correcting the deficiency is approved by EPA before it promulgates a FIP.
Sections VI and VII of the preamble to the final rule explain EPA's decision to use the compliance dates in the final rule.  As explained therein and in other sections of this RTC, EPA has an obligation to align the compliance dates with the attainment deadlines for the relevant NAAQS, the 2012 deadline is reasonable and appropriate, and EPA made numerous updates and modifications to data inputs in response to comments.
EPA also disagrees with the commenter's statement that EPA is bypassing the states by promulgating the Transport Rule as a FIP.  As explained above, EPA has a legal obligation to promulgate all of the FIPs in this rule.  The commenter appears to suggest that "because the flaws in the CAIR program identified by the D.C Circuit in the North Carolina case were of EPA's making, not the states," and because EPA approved some CAIR SIPs submitted by the states, EPA has no remaining obligation pursuant to 110(c)(1).  The commenter assigns blame to EPA for the flaws in CAIR, yet argues that EPA action based on that flawed rule discharged its FIP obligation.  EPA does not think this line of reasoning is consistent with the requirements in section 110(c)(1) of the Clean Air Act.  Instead, as explained above, section 110(c)(1) requires EPA to promulgate a FIP within two years of finding that a state has failed to submit a required SIP submission, disapproving a SIP or finding a submission to be incomplete.  EPA must discharge this obligation unless two conditions are met: the state submits a SIP that corrects the deficiency and EPA approves the SIP.  The statute does not explicitly address the situation presented here where EPA approved a state SIP that EPA incorrectly believed at the time of its action corrected the deficiency.  However, since the statute explicitly requires EPA to  promulgate a FIP unless it has approved a SIP that corrects the deficiency, EPA does not believe the statutory language leaves room for it to argue that its FIP obligation has been discharged in these circumstances.  Further, to the extent the statute is ambiguous because it does not address the specific situation presented here, EPA interprets the statute as requiring approval of a SIP that, in fact, corrects the deficiency at issue.  This interpretation is consistent with the statutory objective of ensuring that the requirements of section 110 are met and is consistent with the requirements in 110(c)(1) which require EPA to act when a SIP deficiency has not been corrected.   The need for prompt action here is further supported by the fact that the statutory deadlines for compliance with the requirements of 110(a)(2)(D)(i)(I) passed in 2000 for the 1997 ozone and 1997 PM2.5 NAAQS and in 2009 for the 2006 PM2.5 NAAQS. 
Further, there is no support for commenters' assertion that the states must be given time, following the promulgation of the Transport Rule, to submit 110(a)(2)(D)(i)(I) SIPs.  Section 110(a)(1) of the Act requires states to adopt and submit SIPs meeting certain requirements including the requirements of section 110(a)(2)(D)(i)(I), "within 3 years (or such shorter period as the Administrator prescribe) after the promulgation of a national primary ambient air quality standard (or any revision thereof)."  42 U.S.C. § 7410(a)(1).   The submission deadline clearly runs from the date of promulgation of the NAAQS.  In addition, while the Administrator is given authority to prescribe a period shorter than three years for the states to adopt and submit such SIPs, the Act does not give the Administrator authority to lengthen the time allowed for submissions.  In addition, all states have been aware that their SIPs could no longer satisfy 110(a)(2)(D)(i)(I) since the North Carolina decision in July 2008, and thus had ample time to develop SIPs to satisfy those requirements in advance of the Transport Rule FIPs if they chose to do so.
Moreover, there is no requirement that EPA promulgate a rule or issue guidance regarding the specific requirements of section 110(a)(2)(D)(i)(I) in advance of the SIP submittal deadline, much less a provision giving EPA authority to alter the statutory SIP submittal deadline so that it runs from the issuance of any such guidance. 
Organization: American Public Power Association (APPA)
Comment: 
American Public Power Association (APPA)
Yet in other respects, EPA`s proposed approach is seriously misguided. The decision to impose FIPs rather than allow states time to develop state implementation plans ("SIPs") to implement section 110(a)(2)(D)(i)(I) obligations rests on an unlawful view of the CAA and the federal-state cooperative relationship under the Act. [EPA-HQ-OAR-2009-0491-2812.1, p.7]    
More importantly, APPA believes that the U. S. EPA in this proposed rule has arrogated to itself, in contravention of the law, the right and responsibility to determine how a state's emission reduction requirements must be accomplished, thereby assuming an exceptionally heavy burden to show that it has applied its unit allowance allocation methodology accurately and consistently. Review of the PTR`s supporting information, however, reveals that EPA`s approach on this score is anything but accurate and consistent. [EPA-HQ-OAR-2009-0491-2812.1, pp.7-8]  
In addition, the proposed rule -- and especially its 2012 first-phase compliance date -- is fundamentally inconsistent with the CAA because it effectively deprives states of the time they need to develop, submit, and receive EPA approval of SIPs before the program begins. See section VII infra. [EPA-HQ-OAR-2009-0491-2812.1, pp.16-17] [[This comment can also be found in Section VII.C.]]  
EPA should take the needed time necessary to correct the many errors in the proposed rule, and allow adequate time for states to develop SIPs and for sources to make the adjustments necessary to comply with the rule, rather than rushing to implementation as it proposes to do. [EPA-HQ-OAR-2009-0491-2812.1, p.20] [[This comment can also be found in Section VII.C.]]      
APPA is simply mystified at the willingness that the U.S. EPA has in proposing that it will utilize a rarely used FIP authority. EPA has unabashedly proposed the Transport Rule as a FIP rule. Indeed, promulgation and implementation of the Transport Rule pursuant to the schedule that EPA proposes would make it nearly impossible for states to develop, submit, and receive EPA approval of SIPs in time to use them for implementation of the first phase of the program. EPA`s assertion that promulgation of FIPs "would in no way affect the right of states to submit . . . a SIP that replaced the federal requirements of the FIP with a state requirement," 75 Fed. Reg. at 45342/2, misses the point. The opportunity to replace federal requirements with a state plan at some point in the future does not satisfy the requirement that EPA allow the opportunity for states to develop their own plans, at the outset of the program, to comply with the Transport Rule. EPA's proposal would effectively bypass the states, at least with respect to the first phase of the program. This is unsupported by anything in the proposed rule and is contrary to the Clean Air Act. In fact, this flies in the face of the legislative intend in 1990 when the Clean Air Act Amendments was passed by Congress to avoid the FIP issue in Southern California's South Coast Air Quality District (SCAQMD). APPA finds it extraordinary that the U. S. EPA would enthusiastically and with great ease suggest a FIP process when, historically, the EPA has been loath to accept this regulatory responsibility and usurp the role of the states. [EPA-HQ-OAR-2009-0491-2812.1, p.21]    
[For additional comments pertaining to 'EPA's Authority for This Action', see pages 21-27 of this comment.]    

12. The D.C. Circuit`s finding that the 2015 compliance deadline for the second phase of CAIR was unlawful because "EPA did not make any effort to harmonize CAIR`s Phase Two deadline for upwind contributors to eliminate their significant contribution with the attainment deadlines for downwind areas," 531 F.3d at 912, does not mandate a 2012 compliance deadline. In the preamble to the proposed rule, EPA attempts to justify its proposed 2012 compliance deadline in part by asserting that it is coordinated with the attainment deadline for the 8-hour ozone NAAQS. In doing so, EPA focuses on the June 2013 maximum deadline for areas designated "serious" for 8-hour ozone, but acknowledges that "[areas] that have not yet attained the [8-hour ozone] standard have maximum attainment dates ranging from 2010 . . . to 2018." 75 Fed. Reg. at 45301/1. EPA also relies heavily on the statement in CAA section 172(a)(2)(A) that the attainment date for nonattainment areas "shall be the date by which attainment can be achieved as expeditiously as practicable" to justify the proposed 2012 and 2014 compliance deadlines. See, e.g., id. at 45300/2 ("EPA chose these dates to coordinate with the NAAQS attainment deadlines and to assure that reductions are made as expeditiously as practicable"); id. at 45300/3 ("EPA believes that [the 2014] deadline is as expeditious as practicable for the installation of the controls needed for compliance"); id. at 45301/2 (in addition to being coordinated with the 2013 maximum attainment deadline for serious ozone nonattainment areas, the 2012 deadline "is also consistent with the requirement that states attain the NAAQS as expeditiously as practicable"). This requirement, that attainment be achieved as expeditiously as practicable, must be read in the context of the remainder of the Act. It does not give EPA the authority to impose a FIP before allowing states the opportunity to develop and submit SIPs. Neither the CAA nor the court`s opinion in North Carolina v. EPA requires EPA to accelerate the PTR`s compliance dates to the extent proposed. [EPA-HQ-OAR-2009-0491-2812.1, pp.18-19]  
Response: 
For the reasons explained in this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs Final Rule TSD", EPA has a legal obligation to promulgate the FIPs in this rule.  The commenter has cited to no authority which would allow EPA to further extend the statutory deadline for 110(a)(2)(D)(i)(I) SIP submissions or allow EPA to argue it has discharged its obligation to issue a FIP to correct certain identified SIP deficiencies which continue to exist, due in part to the court remand of CAIR.
Sections VI and VII of the preamble to the final rule explain EPA's decision to use the compliance deadlines in the final rule.  Among other things, EPA has an obligation to align the compliance dates with the attainment deadlines for the relevant NAAQS.
Organization: ARIPPA
Comment: 
ARIPPA
D. EPA should preserve to the states maximum flexibility to implement state-specific programs through SIPs to satisfy final emission budgets under the Transport Rule. [EPA-HQ-OAR-2009-0491-2794.1, p.15]
In the preamble to the Proposed Rule, EPA explains that "by promulgating these Transport Rule FIPs, EPA would in no way affect the right of states to submit, for review and approval, a SIP that replaces the federal requirements of the FIP with state requirements. . . . 75 Fed. Reg. 45342. EPA further recognizes that [i]n CAIR, EPA allowed the states to replace the CAIR FIP with SIPs and provided substantial flexibility. Again, EPA wants to offer states substantial flexibility for addressing the Section 110(a)(2)(D)(i)(I) transport issues though a SIP should they choose to do so. The EPA's intent is to provide states with substantial flexibility in implementing these requirements. Id. [EPA-HQ-OAR-2009-0491-2794.1, p.16]
EPA specifically requests comments on this objective. ARIPPA strongly endorses EPA's stated intention to ensure states substantial flexibility in implementing the requirements of the Transport Rule. Consistent with this approach, states should be permitted under the Proposed Rule to allocate allowances to affected EGUs in any manner, and on any basis, they deem appropriate to satisfy their established emissions budgets. States should not be constrained to allocate allowances among affected EGUs based on an individual source's relative contribution to the state's total emissions budget, in the manner used by EPA in allocating allowances under the proposed FIP. To that end, ARIPPA requests that EPA clarify in the final rule that states are afforded such flexibility in developing and implementing state-specific regulations and SIPs to replace the proposed FIP. [EPA-HQ-OAR-2009-0491-2794.1, p.16]
EPA must recognize that the inability of states to finalize state-specific SIP-based programs for implementing the Transport Rule would not merely postpone transition from a FIP-based to a SIP-based program. Instead, affected sources must pursue compliance options based upon the regulations that will be effective at the earliest time. Sources may not be able to develop and implement a temporary or transitional compliance approach, especially to the extent that the Proposed Rule is ultimately promulgated. Instead, the very restrictive proposed emission limitations that would be imposed upon the ARIPPA facilities through the Proposed Rule would require dramatic measures, if such reductions could even be achieved. These affected facilities would not likely have the option of implementing a transitional approach during the first phase of regulation that could simply be undone and replaced with a longer term strategy once the state SIP is promulgated and approved. For this reason, it is critical that states be afforded a reasonable opportunity to finalize and establish SIPs before affected sources would be subject to the promulgated standards. [EPA-HQ-OAR-2009-0491-2794.1, p.18] [[These comments can also be found in Section VII.C.]]
Response: 
For the reasons explained in this section of the RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs Final Rule TSD", EPA has a legal obligation to promulgate the FIPs in this rule.  EPA aims to both discharge its legal obligation to promulgate the FIPs and ensure the states have flexibility to replace the FIPs with SIPs that satisfy the requirements of section 110(a)(2)(D)(i)(I).  EPA has an obligation to promulgate the FIPs in this rule and is discharging its obligation to do so.  States have been free and remain free to submit SIPs, using any mechanism of their choosing, to satisfy the requirements of section 110(a)(2)(D)(i)(I).  EPA is not requiring a state to use any particular mechanism to satisfy the requirements of 110(a)(2)(D)(i)(I) in a SIP submission, and if the state chooses to use the Transport Rule trading programs to satisfy the requirements of section 110(a)(2)(D)(i)(I) with respect to any particular NAAQS, EPA is not requiring the state to use any particular methodology for allocating allowances to covered sources.
Organization: Arkansas Department of Environmental Quality
Comment: 
Arkansas Department of Environmental Quality
ADEQ is concerned about EPA's conclusion that states, including Arkansas, have failed to adequately address interstate transport of pollution pursuant to Clean Air Act ('CAN') section 11O(a)(2)(D)(i) for the 1997 ozone National Ambient Air Quality Standard ('NAAQS'). ADEQ acted in good faith to correct a finding of failure to submit a State Implementation Plan ('SIP') addressing the section 11 0(a)(2)(D)(i) requirements. ADEQ followed EPA guidance entitled 'SIP Guidance on Section 11 0(a)(2)(D)(i) Findings of Failure to Submit' and 'Guidance for SIP Submissions to Meet Current Obligations Under Section 11O(a)(2)(D)(i) for the 8-hour Ozone and PM2,S National Ambient Air Quality Standards' dated August 11, 2006, and August 15, 2006, which allowed for states to rely on CAIR to fulfill CAA section 1 IO(a)(2)(D)(i) requirements. [EPA-HQ-OAR-2009-0491-2676.2, p. 1]
ADEQ believes EPA is not justified in using the April 25, 2005, finding of failure to submit a SIP to start a FIP clock for states such as Arkansas that made a good faith effort to address EPA's finding of failure using EPA's own rules and guidance. EPA's use of the April 25, 2005, finding of failure to satisfy CAA section I lO(k) (1 )(5) that requires EPA to specify SIP deficiencies, circumvents the process by which the state is given up to I8-months to review and correct SIP deficiencies. [EPA-HQ-OAR-2009-0491-2676.2, p. 1]
ADEQ therefore requests that EPA reconsider the necessity to promulgate a Transport Rule FIP instead of allowing states any opportunity to implement the Transport Rule to address CAA section 11 0(a)(2)(D)(i) requirements. The D.C. Circuit Court of Appeals recognized the environmental benefit that would result from allowing CAIR to remain in effect while EPA formulated a replacement rule. Allowing CAIR to remain in effect while allowing states adequate opportunity to prepare and submit approvable SIPs would respect this Court's opinion. This would also provide a workable solution to allow for the continued control of interstate transported pollution, while continuing to recognize traditional due process and FIP clock procedures. EPA's tactic of reverting to the original finding of failure to submit, which does not identify specific deficiencies, leaves open the possibility that any required SIP submittal that is properly submitted and approved by EPA provides no protection from the EPA resetting SIP or FIP clocks, leaving states completely vulnerable to future FIPs without adequate time to develop SIPs. [EPA-HQ-OAR-2009-0491-2676.2, p. 1]
Response: 
For the reasons explained in this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs Final Rule TSD," EPA has a legal obligation to promulgate the FIPs in this rule. 
EPA recognizes that many states acted in good faith and aimed to correct the finding of failure to submit made in 2005 by submitting SIPs that were consistent with the requirements of CAIR.  However, nothing in the statutory language relieves EPA of an obligation to promulgate a FIP where the state has acted in good faith to try and correct a SIP deficiency.   Unfortunately the court overturned CAIR and concluded that it could not satisfy 110(a)(2)(D)(i)(I), with the result that EPA can no longer conclude that the SIPs meet that obligation despite the states' good faith submissions.  Further, EPA does not believe that the statute gives it authority to restart the "FIP clock" to give states additional time to submit SIPs in these circumstances. ("FIP clock" is a term used to describe EPA's responsibility found in CAA section 110(c)(1) to promulgate a FIP within 2 years after either: finding that a state has not submitted a required SIP revision; that a submitted SIP revision is found incomplete; or EPA has disapproved a SIP revision.)  The plain language of section 110(c)(1) of the Act provides that EPA shall promulgate a FIP at any time within 2 years after the Administrator finds that a state has failed to make a required submission or after disapproving a state implementation plan submission in whole or part, unless the state corrects the deficiency, and the Administrator approves the plan or plan revision, before the promulgation of a FIP. See 42 U.S.C. § 7410(c)(1).  Far more than 2 years has now elapsed since EPA first made these findings with respect to the 1997 ozone and 1997 PM2.5 NAAQS.  In addition, states could have attempted to develop SIPs that did satisfy 110(a)(2)(D)(i)(I) at any time since the court overturned CAIR if they chose not to wait for EPA to develop a replacement transport rule.
Organization: Associated Electric Cooperative, Inc. (AECI)
Comment: 
Associated Electric Cooperative, Inc. (AECI)
EPA's CATR FIP is unlawful and contrary to the plain language of CAA Section 110.
The proposed Transport Rule is aimed squarely at reducing interstate transport of air pollution with the ultimate goal of achieving attainment of the NAAQS for PM, NOx, SO2, and ozone in downwind states. Section 110 of the Act lays out the mechanism by which EPA may issue new rules and standards, how and when states must respond by amending their SIPs, and the timing by which EPA may issue a FIP on individual states that do not submit approvable SIP amendments in a timely fashion:  [EPA-HQ-OAR-2009-0491-2845.1 P.4]
CAA Section 110(a) of the Clean Air Act affords states up to three years to submit State Implementation Plans (SIPs) before EPA can enforce a Federal Implementation Plan (FIP) for a final rule. 
CAA Section 110(c) outlines the precursor to a FIP as a date that follows a finding of inadequacy by EPA on the part of a state to develop and approvable SIP: 
(Relevant excerpt) 110(c)(1) The Administrator shall promulgate a Federal implementation plan at any time within 2 years AFTER the Administrator -- 
(A) finds that a State has failed to make a required submission or finds that the plan or plan revision submitted by the State does not satisfy the minimum criteria established under section 110(k)(1)(A), or
(B) disapproves a State implementation plan submission in whole or in part, unless the State corrects the deficiency, and the Administrator approves the plan or plan revision, before the Administrator promulgates such Federal implementation plan. Only after the criteria of CAA 110(c) is met should EPA consider a FIP on individual states that do not meet the requirements of CAA 110(a)(2).   [EPA-HQ-OAR-2009-0491-2845.1 P.4]
CAA 110(k)
(5) CALLS FOR PLAN REVISIONS. -- Whenever the Administrator finds that the applicable implementation plan for any area is substantially inadequate to attain or maintain the relevant national ambient air quality standard, to mitigate adequately the interstate pollutant transport described in section 176A or section 184, or to otherwise comply with any requirement of this Act, the Administrator shall require the State to revise the plan as necessary to correct such inadequacies. The Administrator shall notify the State of the inadequacies, and may establish reasonable deadlines (not to exceed 18 months after the date of such notice) for the submission of such plan revisions.  [EPA-HQ-OAR-2009-0491-2845.1 P.5]
Request: Associated asks that EPA observe the statutory requirements of the Clean Air Act under section 110(k) to allow for a "reasonable deadline" of not less than eighteen (18) months for states to update their SIPs to address the requirements of a final Transport Rule. Further, and to allow for full and adequate time for states to carefully consider public comment and for electric utilities to fully consider the implications of new rules expected to be published between now and into 2012, Associated requests that EPA allow the full 3 years of CAA 110(a) for states to amend their SIPs. Finally, Associated comments that the CAA does grant EPA the authority to determine source or unit obligations, only to determine statewide reduction levels  -  again pointing to the states to develop implementation plans that meet the requirements of CAA 110(a)(2) and according to the plain timetables set forth in the Act.  [EPA-HQ-OAR-2009-0491-2845.1 P.5]
Response: 
As explained in this section of the RTC, in section IV of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs," EPA has a legal obligation to promulgate the FIPs in this final rule.  Nothing in CAA section 110 requires EPA to provide an additional three years for state to submit SIPs after it promulgates a federal requirement to address transport.  Further, EPA has an obligation when exercising its FIP authority to correct the existing SIP deficiency.  EPA has determined that setting unit allocations is a necessary part of the action needed to correct the existing 110(a)(2)(D)(i)(I) SIP deficiencies.  The preamble to the final rule explains the steps taken by EPA to make it easier for states that wish to do so to allocate allowances.   
Organization: Attorney General of North Carolina
Comment: 
Attorney General of North Carolina
[[2685.1 p.32]]
North Carolina appreciates the need to resolve the issue of interstate transport of SO2 and NOX expeditiously. However, this should not come at the cost of prejudicing States' prerogatives under the Clean Air Act.
Response: 
EPA agrees it is important to address this issue expeditiously.  Also, for the reasons explained in this RTC, in section IV.C.2 of the preamble to the final rule, and in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs Final Rule TSD", EPA has a legal obligation to promulgate the FIPs in this rule.
Organization: Buckeye Power, Inc.
Comment: 
Buckeye Power, Inc.
EPA proposes stringent statewide caps on SO2 and NOx using questionable methodology and modeling as its basis, then proposes to impose a federal implementation plan ('FIP') upon the states in contravention of the federal Clean Air Act. This approach is unlawful and unreasonable. EPA should allow the states, which have experience with their own utilities, the opportunity to develop state implementation plans ('SIP'). [EPA-HQ-OAR-2009-0491-2710.1, p.2]
4. EPA's proposal to issue a Federal Implementation Plan versus allowing the States the opportunity to implement the rule runs afoul of the Clean Air Act and constitutes ill-advised and arbitrary rulemaking.
EPA's proposed FIP is contrary to the Clean Air Act because it does not give states the opportunity to submit SIPs conforming to the proposed CATRs overall state reduction mandates. The Clean Air Act grants states up to 3 years to submit SIPs to remedy interstate transport, in this case to meet proposed CATR reduction mandates. 42 U.S.C. § 74l0(a). In light of the invalidation of CAIR, this period should begin to run when EPA issues a final CATR. The Clean Air Act does not authorize EPA to determine source or unit obligations, only to determine statewide reduction levels. [EPA-HQ-OAR-2009-0491-2710.1, p.7]
Moreover, by imposing a federal implementation plan, EPA takes away from the states, who are in the best position to determine the proper individual unit allocations for allowances, the ability to determine how best to meet overall state reduction levels. Indeed, in many cases, as explained elsewhere, meeting individual unit allowance limits under EPA's preferred CATR approach is difficult if not impossible. States may be able to meet the overall state reduction levels through properly tailored state implementation plans, which take into account differences between individual unit performance in the applicable state. States rather than the federal EPA are best able to take into account the characteristics of individual generating units within their states. Buckeye submits that imposition of a FIP is unreasonable, arbitrary, and contrary to law. [EPA-HQ-OAR-2009-0491-2710.1, p.7]
Response: 
For the reasons explained in this section of this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs," EPA has a legal obligation to promulgate all of the FIPs in this rule.  The commenter has not identified any provision that would give EPA authority to alter the deadlines established in the Clean Air Act.  Section 110(a) of the Act explicitly states that States are required to submit 110(a) SIPs "within 3 years (or such shorter period as the Administrator may prescribe) after the promulgation of a national primary ambient air quality standard (or any revision thereof)."  EPA does not have authority to alter that provision.  Further, the statute explicitly recognizes EPA's authority to include emission trading programs in a FIP and to establish enforceable emission limitations in a FIP.  Specifically, the term "Federal Implementation Plan" is defined in section 302 of the Clean Air Act as "a plan (or portion thereof) promulgated by the Administrator to fill all or a portion of a gap or otherwise correct all or a portion of an inadequacy in a State implementation plan, and which includes enforceable emission limitations or other control measures means or techniques (including economic incentives, such as marketable permits or auctions of emissions allowances) and provides for attainment of the relevant national ambient air quality standard."  42 U.S.C. § 7602  (emphasis added).  Any FIP that includes an economic incentive program based on marketable permits or allowances, must include a mechanism for distributing such allowances.  The grant of authority to EPA to include emission trading programs in a FIP thus necessarily includes the authority to distribute allowances for use in such programs. 
Organization: City of Springfield, Illinois, Office of Public Utilities
Comment: 
City of Springfield, Illinois, Office of Public Utilities
In addition, by selecting 2012 as a compliance target, without taking into account controls and reductions since 2005, USEPA has artificially boot-strapped its support for an expedited federal implementation plan ('FIP'). By proposing a FIP, rather than a schedule that allows for State Implementation Plans, USEPA is short-changing state environmental agencies, sources like CWLP regulated by those state agencies, and the process developed under the Clean Air Act which accommodates public comment on issues of traditionally local concern. [EPA-HQ-OAR-2009-0491-2635.1, p.3]
Response: 
EPA disagrees with the commenter's characterization of the 2012 base case modeling.  This modeling and the rational for the modeling approach selected are described in section V of the preamble to the final rule, which fully describes why after the court decision remanding CAIR EPA must treat the reductions compelled only by CAIR as not continuing to be compelled after replacement of CAIR for purposes of establishing the baselines reductions to be addressed in the Transport Rule.  In addition, for the reasons explained in this section of this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate all of the FIPs in this rule. 
Organization: City of Tallahasse
Comment: 
City of Tallahasse
EPA Must Provide Time for SIP Development/Approval Before FIP is Effective.
The aggressive schedule proposed by the Transport Rule will force the EPA to impose Federal Implementation Plans (FIPs) on affected states, including Florida, rather than permitting states to develop State Implementation Plans (SIPs).  Even if the state of Florida could act as soon as possible to implement program elements by the established deadline, it is doubtful that the procedures and requirements dictated by Florida's legislative system would allow for such a rapid integration of the program.  States are best suited to understand a state's needs in developing the lowest cost method to meeting the requirements of the Transport Rule.  Certainly, given the amount of data that is submitted by electric utilities to their respective states on an annual and semi-annual basis, states would best be able to determine EGU-specific emission rates that would reduce the impact of transported emissions on downwind states. [EPA-HQ-OAR-2009-0491-2669.1, p.2]
Response: 
For the reasons explained in this section of this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate all of the FIPs in this rule, and authority to set unit level allocations where appropriate to eliminate states' significant contribution. 
Organization: Clean Energy Group
Comment: 
Clean Energy Group
I. The Proposed Transport Rule is Within EPA's Clean Air Act Authority and Appropriately Addresses the Constraints Set Out in North Carolina v. EPA
EPA has determined that air pollutants emitted from EGUs 'contribute significantly to nonattainment' and 'interfere with maintenance' with respect to NAAQS for ozone and PM2.5 in the Eastern U.S. Subsequent modeling, including by EPA for the proposed rule as well as by affected states and other third parties, continues to confirm this finding. The D.C. Circuit invalidated EPA's most recent attempt to satisfy the requirements of Section 110 through the Clean Air Interstate Rule (CAIR). The court concluded that EPA could not satisfy the statutory requirement 'unless it is promulgating a rule that achieves something measureable toward the goal of prohibiting sources 'within the State' from contributing to nonattainment or interfering with maintenance' in any other state. '' The court further held that EPA must measure each state's 'significant contribution' to downwind nonattainment. The proposed Transport Rule satisfies these requirements and, in order to meet its statutory duty, EPA must proceed to promulgate the proposed rule as expeditiously as feasible. Section IIO(c)(I) of the Act requires EPA to promulgate a Federal Implementation Plan (FIP) to address transport as the deadlines for eliminating significant contribution and noninterference have long since passed, and neither the affected states' State Implementation Plans (SIPs) nor EPA in previous programs (e.g., CAIR) have succeeded in eliminating these emissions. EPA, therefore, has the legal authority to promulgate a FIP and to do so 'as soon as practicable.' [EPA-HQ-OAR-2009-0491-2702.1, p. 3]
Response: 
EPA agrees with the commenter that it has authority and a legal obligation to promulgate the FIPs in this action.  EPA also agrees that the Transport Rule addresses the issues raised by the court in North Carolina v. EPA.
Organization: Cleco Corporation
Comment: 
Cleco Corporation
EPA's proposal to promulgate a FIP is premature, illegal and ill-advised. Under the Clean Air Act, states have the primary role for implementing state rules to ensure compliance with the Act. EPA cannot and should not circumvent the states and must allow states an opportunity to develop SIPs that comply with the Clean Air Act in a manner tailored to the interests and circumstances unique to the individual state. [EPA-HQ-OAR-2009-0491-2859.1 p.3]
Under the Clean Air Act, EPA has the authority to impose a FIP two years after it finds that a state has failed to submit a SIP that satisfies the minimum requirements of the Act.2 Louisiana submitted SIPs for the CAIR SO2 and CAIR NOx trading programs, and EPA approved those SIPs as compliant with the Act's "good neighbor" provision on July 20, 2007 (SO2 SIP) and September 28, 2007 (NOx SIP).3 EPA has not revoked that approval and the Court's remand of CAIR does not equate to a retroactive disapproval of Louisiana's SIP by EPA. Accordingly, the FIP clock has not started to run against Louisiana. [EPA-HQ-OAR-2009-0491-2859.1 p.4]
Furthermore, this Transport rule is a new determination with an entirely different basis. For example, in CAIR EPA found that Louisiana significantly contributed to PM-2.5 nonattainment in Jefferson County, Alabama. In this proposed Transport Rule, EPA does not find that Louisiana significantly contributes to or interferes with maintenance of Alabama's PM-2.5 attainment. EPA's proposed new finding is that Louisiana interferes with maintenance of the 1997 annual PM-2.5 standard at one monitor in Harris County, Texas (commonly known as the "Clinton Drive" monitor). The Clean Air Act reserves to the states in the first instance authority to respond to such a finding. It specifically, provides that
Whenever the Administrator finds that the applicable implementation plan for any area is substantially inadequate to mitigate adequately interstate pollutant transport ...the Administrator... shall require the State to revise the plan as necessary to correct such inadequacies. [EPA-HQ-OAR-2009-0491-2859.1 p.4]
With respect to both the annual and ozone season programs, EPA's 2005 finding that Louisiana failed to submit a § 110(a)(2)(D)(i)-compliant SIP has been extinguished by the very terms of EPA's finding.6 EPA states that its "finding starts a 2-year clock for the promulgation by EPA of a FIP, unless each State submits a SIP to satisfy the section 110(a)(2)(D)(i) requirements, and EPA approves such submission prior to that time."7 As noted, Louisiana submitted CAIR SIPs in accordance with EPA's precise guidance, and EPA approved them. That EPA's guidance was found to be fundamentally flawed, is not something Louisiana could control and is not a basis for reversing congressional intent that states maintain the primary responsibility for controlling sources within their borders. [EPA-HQ-OAR-2009-0491-2859.1 p.4]
Response: 
As explained in this section of this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate all of the FIPs in this rule.  To the extent EPA previously approved any SIPs purporting to satisfy these requirements through adoption of CAIR requirements, EPA is also correcting its prior approvals to clarify that in light of the court decision EPA can no longer conclude that these SIPs adequately address the requirements of 110(a)(2)(D)(i)(I).  Further, EPA notes that the findings of failure to submit made with respect to the 1997 ozone and 1997 PM2.5 NAAQS were general findings of failure to submit 110(a)(2)(D)(i) SIPs, and the findings of failure to submit made with respect to the 2006 PM2.5 NAAQS were general findings of failure to submit 110(a)(2)(D)(i)(I) SIPs.  The findings were not findings of failure to submit SIPs in response to a specific SIP call, but rather findings of failure to submit, as an initial matter, SIPs addressing the requirements of those provisions of the Act.  
Organization: Cogen Technologies Linden Venture, LP
Comment: 
Cogen Technologies Linden Venture, LP
L. As an Alternative to Resolving the Errors in IPM or Basing Unit Allocations on Historical Heat Input Data, EPA Could Instead Provide Adequate Time for States to Develop Adequate SIP Revisions Prior to Imposing the Proposed FIPs
In the Proposed Transport Rule, EPA has proposed to take the unusual step of promulgating FIPs that would become effective before it has made the requisite finding that a state had failed to submit an adequate SIP or otherwise taken any action to rescind EPA's earlier approvals of states' CAIR SIP submittals. This would represent a significant departure from the Clean Air Act's clearly established process for addressing nonattainment of the National Ambient Air Quality Standards ('NAAQS'). If EPA does not either correct the serious problems with IPM or establish unit-specific allocations based on historic heat input, it could, as an altogether different approach, refrain from promulgation of the proposed FIPs, and instead support states' efforts to submit adequate SIP revisions within a reasonable amount of time. Linden Cogen has confidence that NJDEP could develop an allowance allocation methodology that would result in a fairer allocation of the State's budget, as it did under the CAIR. Accordingly, Linden Cogen believes that allowing the states the opportunity to propose allocations for individual facilities, prior to imposing such allocations through a FIP, would likely avoid many of its concerns regarding EPA's proposed NOx allocations for Linden Cogen. [EPA-HQ-OAR-2009-0491-2712.1, p.21]
While awaiting states' submission of SIP revisions might delay implementation of the CAIR's replacement program until after 2012, it would abide by Section 110 of the Clean Air Act's requirement that EPA provide reasonable deadlines for the submittal of necessary SIP revisions to address interstate pollution and also provide states with the opportunity to correct identified deficiencies, prior to promulgating a FIP. Moreover, given that the CAIR would remain in effect in the interim and EPA has recognized that most reductions in the 2012-2014 control periods will be achieved through implementation of emissions reductions that are already being achieved or planned for implementation, such a delay would not delay or interfere with attainment of the NAAQS. Further, any such delay would provide EPA and the states with the opportunity to establish an adequate replacement program for the CAIR that also addressed anticipated revisions of the NAAQS, avoiding an unnecessary and duplicative series of rulemakings and SIP revisions. [EPA-HQ-OAR-2009-0491-2712.1, pp.21-22]
Response: 
For the reasons explained in this section of this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate each of the FIPs in this final rule.  Sections VI and VII of the preamble to the final rule explain EPA's decision to use the compliance dates in the final rule.  Among other things, EPA has an obligation to align the compliance dates with the attainment deadlines for the relevant NAAQS.
Organization: Consumers Energy
Comment: 
Consumers Energy
C. EPA's Proposal Would Usurp the Role of the States in the Traditional State and Federal Partnership for the State Implementation Plan (SIP) Process, as Laid Out in the Clean Air Act
EPA has proposed the Transport Rule as a Federal Implementation Plan (FIP) based rule. Promulgation and implementation of the Transport Rule according to the proposed schedule would make it virtually impossible for states to develop, submit, and receive EPA approval of SIPs in time to use them for implementation of the first phase of the program. As proposed, EPA would first impose a FIP and then allow states to submit a SIP that replaced the federal requirements of the FIP with a state requirement. But the opportunity to replace federal requirements with a state plan at some point in the future does not satisfy the Clean Air Act (CAA) requirement that EPA allow the opportunity for states to develop their own plans, at the outset of the program, to comply with the Transport Rule. EPA's FIP-first proposal would effectively bypass the states, at least with respect to the first phase of the program. This is contrary to the CAA. [EPA-HQ-OAR-2009-0491-2837.1, p.6]
The CAA contemplates that states must be given a meaningful opportunity to develop SIPs and to submit them to EPA for review and approval before implementation of a new or revised NAAQS. Air pollution control at its source is the primary responsibility of States and local governments. Each State has the primary responsibility for assuring air quality within its entire geographic area and the State is required to submit an implementation plan that specifies the manner in which national primary and secondary ambient air quality standards will be achieved and maintained within the State. [EPA-HQ-OAR-2009-0491-2837.1, p.6]
With respect to interstate air pollution, section 110(a)(2) provides that each state shall, in the first instance, submit a SIP to EPA that 'contain[s] adequate provisions' prohibiting the emissions proscribed by section 110(a)(2)(D)(i). And section 110(k)(5) of the Act states that:
Whenever the Administrator finds that the [SIP] for any area is substantially inadequate to attain or maintain the relevant [NAAQS], to mitigate adequately the interstate pollutant transport described in [section 176A or section 184 of the Act], or to otherwise comply with any requirement of [the Act], the Administrator shall require the State to revise the plan as necessary to correct such inadequacies. The Administrator shall notify the State of the inadequacies, and may establish reasonable deadlines ... for the submission of such plan revisions. [EPA-HQ-OAR-2009-0491-2837.1, p.6]
While EPA has a role in implementation of NAAQS, including interstate transport requirements, that role is plainly secondary to that of the States. The D.C. Circuit has interpreted the 'partnership between EPA and the states for the attainment and maintenance of national air quality goals,' as set forth in the Act, as follows: 'The states are responsible in the first instance for meeting the NAAQS through state-designed plans that provide for attainment, maintenance and enforcement of the NAAQS.' The court noted further that the Act's SIP provisions give states 'authority to make the many sensitive technical and political choices that a pollution control regime demands.' The authority of states to develop SIPs and submit them to EPA for approval enables the States to determine, based on state-specific concerns and the specialized knowledge of state officials, how best to achieve the emission reductions that may be necessary to satisfy section 110(a)(2)(D) by allocating allowances to sources within the State. [EPA-HQ-OAR-2009-0491-2837.1, p.6]
The CAA specifies that EPA may promulgate a FIP within two years after the Administrator (i) finds that a State has failed to submit a SIP or has submitted a SIP that does not satisfy the minimum criteria set forth in section 110 of the Act, or (ii) disapproves a SIP in whole or in part, unless the state has corrected the deficiency and the Administrator has approved the SIP. [EPA-HQ-OAR-2009-0491-2837.1, p.7]
The State of Michigan has a proven track record of crafting SIP strategies that have resulted in attainment of National Ambient Air Quality Standards for all six criteria pollutants. There have been instances where the strategies utilized by the State have differed from the strategies recommended by EPA. Nevertheless, the result has been successful attainment of the standards, which remains the ultimate goal. [EPA-HQ-OAR-2009-0491-2837.1, p.7]
As proposed, the Transport Rule's FIP-first approach would violate this principle and must be changed. [EPA-HQ-OAR-2009-0491-2837.1, p.7]
:: EPA made a deliberate choice to isolate itself from the affected states and sources as the Agency crafted this rule. While EPA conducted 'listening sessions' EPA elected not to bounce its concepts off those who would bear the consequences - the affected states and sources.[EPA-HQ-OAR-2009-0491-2837.1, p.15]
:: EPA must continue to recognize the traditional partnership between the states and EPA, with regard to the SIP process. It is the responsibility of the states to make the many sensitive technical and political choices that a pollution control regime demands. This process is clearly laid out within the Clean Air Act and has been reaffirmed by the courts. Consequently, Consumers Energy recommends that EPA abandon the FIP-first strategy. [EPA-HQ-OAR-2009-0491-2837.1, p.16]
Response: 
For the reasons explained in this section of this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate all of the FIPs in this rule.  The commenter cites no provision that would give EPA authority to alter the statutory deadlines and requirements.  EPA made a concerted effort to get input, both prior to the proposal and during the comment period on the proposal, from all affected parties including states, utility source owners, tribes, and environmental groups. 
Organization: Council of Industrial Boiler Owners (CIBO)
Comment: 
Council of Industrial Boiler Owners (CIBO)
EPA has proposed a FIP rather than a SIP, followed by a FIP, as required by the CAA. Congress intended States to take the primary role in regulating stationary sources under Title I of the CAA. Title I unequivocally guarantees States the opportunity to establish a statewide program for achieving the NAAQS, and only where States fail to establish such programs does a FIP apply directly to the sources within the State. Here, EPA proposes to skip the SIP process and immediately and directly regulate power plants in States covered under this rule. Only once the FIP is in place, does EPA intend to allow States "the option of replacing these Federal rules with state rules to achieve the required amount of emissions reductions from sources selected by the state." 75 FR 45212.
EPA lacks statutory authority to reverse the order of the NAAQS process designed by Congress and immediately impose its program for a State's achievement of the NAAQS, unless and until a State has failed to develop and obtain approval of its own State program. CAA §110 establishes an order of mandatory acts: each state 'shall' submit a SIP to EPA; EPA 'shall' review each plan; and EPA 'shall' promulgate a FIP after EPA finds a plan does not meet the SIP criteria.
Not only does a FIP-first approach violate the CAA, it also deprives States and sources the opportunity  -  intended by the statutory scheme  -  to selectively target reductions from among the many emissions sources and to find innovative, source-specific solutions to achieving emission reductions. EPA acknowledges this failing of its FIP-first approach: "[W]hen allowance based programs are implemented through SIPs, states may have significant flexibility to determine the methodology used to allocate or auction allowances in their budgets. Under the proposed FIPs, EPA would allocate allowances to sources in a manner consistent with the methodology used to determine each state's budget." 75 FR 45353. EPA believes this approach is appropriate because of the link between the allowance allocation methodology and the significant contribution determinations." 75 FR 45353.
EPA's motivation for doing the FIP first, evident throughout the rulemaking, is to arrogate to the Agency the selection of which sources to regulate, thereby usurping the States' prerogative to select sources for NAAQS attainment as established by the CAA. For example, EPA notes that '[f]ossilfuel- fired power plants contribute a large and substantial fraction of the emissions of several key air pollutants, and the agency has statutory or judicial obligations to make several regulatory determinations on power plant emissions.' 75 FR 45213/2. While this may be a true statement, EPA is no less obligated to follow other provisions of the statute, including those establishing a SIP process and thereby granting States the authority to identify the source reductions.
EPA justifies going directly to a FIP by asserting that the DC Circuit found CAIR "inadequate to satisfy the requirements of 110(a)(2)(D)(i)(I), neither EPA's FIP implementing the requirements of CAIR nor any states SIPs that relied on CAIR to satisfy the requirements of this section, are adequate to meet the requirements of section 110(a)(2)(D)(i)(I). EPA's obligation to issue a FIP has therefore not yet been met. The requirements of the FIPs proposed in this rule are designed to address this obligation." 75 FR 45226. EPA misconstrues the DC Circuit decision in North Carolina v. EPA. 532 F.3d 896, modified on reh'g, 550 F.3d 1176 (D.C. Cir. 2008). What the DC Circuit found inadequate about CAIR was EPA's methodology for developing state-level pollutant emission reduction requirements. North Carolina v. EPA. The court made no findings, much less issue holdings, that could be construed to indicate that state implementation through the SIP process of emission reductions --properly calculated-- would not satisfy CAA 110(a)(2)(D)(i)(I). Had EPA used a proper methodology for assessing each state's contribution to downwind nonattainment, state SIPs could have accounted for emission reductions that fully satisfied that provision of the CAA. EPA now seizes on CAIR's inadequacies to go directly to a FIP. But EPA here proposes the Clean Air Transport Rule, a new very different rule, which the CAA requires States to first implement.  [EPA-HQ-OAR-2009-0491-2751.1 p.13]
Response: 
For the reasons explained in this section of this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate each of the FIPs in this final rule.
Organization: Dayton Power and Light Company (DP&L)
Comment: 
Dayton Power and Light Company (DP&L)
Because DP&L supports the comments of the EC-OUG, DP&L will not discuss in depth in these comments the valid concerns raised by the EC-OUG that the EPA's proposals impermissibly extend into areas that the Clean Air Act ('CAA') reserves for State environmental agencies and are not rationally based on solid data and validated assumptions. While the EPA appears to be taking this approach in an effort to get programs up and running quickly, this is an area where haste could be self-defeating. It does not help the environment or any interested party to have rules promulgated quickly if those rules go beyond EPA's lawful authority, are not rationally based, and are subsequently rejected by federal courts. [EPA-HQ-OAR-2009-0491-2637.1, p. 2]
DP&L supports the UARG comments, and would like to specifically note that DP&L agrees with UARG that the states should determine the allocation of the allowances through their State Implementation Plans ('SIPs') as provided by the CAA. Modeling projections show that a small number of areas may continue to experience non-attainment after significant reductions are made throughout the electric utility sector. The states are in a better position to take into account the contribution from local emissions sources and the use of alternative approaches to address the air quality in these areas. For example, the State of Ohio is in a much better position to develop an implementation plan that brings the Steubenville/Weirton area into NAAQS attainment than the EPA. [EPA-HQ-OAR-2009-0491-2637.1, p. 3]
Response: 
For the reasons explained in this section of this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate all of the FIPs in this rule. 
Organization: Dominion
E.ON U.S.
Comment: 
Dominion
The Proposed Rule in the Form of a FIP Supplants the Role of the States
EPA's proposal of this rule in the form of a federal implementation plan (FIP) is questionable and problematic. The Clean Air Act contemplates that states must be givena meaningful opportunity to develop state implementation plans (SIPs). EPA's proposal effectively bypasses the states, at least with respect to the initial phase of the program as the 2012 compliance deadline would make it virtually impossible for states to develop, submit and receive approval of SIPs in time to implement the program. Given the issues noted above with respect to the proposed 2012 and 2014 compliance deadlines as well as the assumptions used to establish the state budgets and unit allocations, EPA should withdraw this proposed FIP, address the technical issues noted and re-propose the rule (as an SNPR) in the form of a SIP Call that would appropriately allow the states to implement the requirements into their state implementation plans. [EPA-HQ-OAR-2009-0491-2715.1, p.15-16]
E.ON U.S.
EPA has precluded the states from playing their proper implementation role under the program.
Under the Clean Air Act (CAA) EPA is assigned the authority to set standards, while the states are generally assigned the role of implementing necessary reduction programs. By setting deadlines that do not allow enough time for the states to develop implementation plans and framing its program as a Federal Implementation Plan (FIP), EPA has effectively precluded the states from playing their proper role in implementing emissions reductions, particularly for the first phase of the program. Under EPA's proposed approach, state specific reduction determinations that are rightfully the responsibility of the states will be made by EPA. EPA's position that promulgation of FIPs "would in no way affect the right of states to submit . . . a SIP that replaced the federal requirements of the FIP with a SIP..." ignores the relevant provisions of the CAA and established precedent in implementing new requirements. The CAA allows the states the opportunity to develop SIPs and to submit them to EPA for review and approval before implementation of a new or revised NAAQS. Under the CAA, EPA may promulgate a FIP within two years after the Administrator finds that a state has failed to submit a SIP or has submitted a deficient SIP. In this instance, EPA has proposed an unlawful implementation process that precludes the states from assuming "primary responsibility" for air quality within their boundaries. See CAA, Section 101 (a)(3) and Section 107(a). [EPA-HQ-OAR-2009-0491-2797.1, pp.6-7]
Response: 
As explained in this section of the RTC, in section IV of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs," EPA has a legal obligation to promulgate the FIPs in this final rule. 
Further, in section VI of the preamble to the final rule, EPA explains the rationale behind the compliance dates in the final rule.  Section VII also explains the importance of aligning compliance dates with NAAQS attainment deadlines.
Organization: Duke Energy
Comment: 
Duke Energy
Footnote 9: The D.C. Circuit's finding that the 2015 compliance deadline for the second phase of CAIR was unlawful because "EPA did not make any effort to harmonize CAIR's Phase Two deadline for upwind contributors to eliminate their significant contribution with the attainment deadlines for downwind areas," 531 F.3d at 912, does not mandate a 2012 compliance deadline. In the preamble to the proposed rule, EPA attempts to justify its proposed 2012 compliance deadline in part by asserting that it is coordinated with the attainment deadline for the 8-hour ozone NAAQS. In doing so, EPA focuses on the June 2013 maximum deadline for areas designated "serious" for 8-hour ozone, but acknowledges that "[areas] that have not yet attained the [8-hour ozone] standard have maximum attainment dates ranging from 2010 . . . to 2018." 75 Fed. Reg. at 45301/1. EPA also relies heavily on the statement in CAA section 172(a)(2)(A) that the attainment date for nonattainment areas "shall be the date by which attainment can be achieved as expeditiously as practicable" to justify the proposed 2012 and 2014 compliance deadlines. See, e.g., id. at 45300/2 ("EPA chose these dates to coordinate with the NAAQS attainment deadlines and to assure that reductions are made as expeditiously as practicable"); id. at 45300/3 ("EPA believes that [the 2014] deadline is as expeditious as practicable for the installation of the controls needed for compliance"); id. at 45301/2 (in addition to being coordinated with the 2013 maximum attainment deadline for serious ozone nonattainment areas, the 2012 deadline "is also consistent with the requirement that states attain the NAAQS as expeditiously as practicable"). This requirement, that attainment be achieved as expeditiously as practicable, must be read in the context of the remainder of the Act. It does not give EPA the authority to impose a FIP before allowing states the opportunity to develop and submit SIPs. Neither the CAA nor the court's opinion in North Carolina v. EPA requires EPA to accelerate the PTR's compliance dates to the extent proposed. [EPA-HQ-OAR-2009-0491-2689.1, p.10]
Footnote 10: According to LADCO, a fundamental assumption for this state-by-state analysis was a July 2012 start date for the planning, engineering, and construction of any new NOx or SO2 controls, reflecting a January 2011 promulgation date for the final Transport Rule and another 18 months for adoption of SIPs. See id. at 1, attachment at 4. Thus, LADCO properly recognized that a substantial amount of time would be necessary after promulgation of EPA's final rule for states to develop SIPs and submit them to EPA for approval. [EPA-HQ-OAR-2009-0491-2689.1, p.11]
Response: 
As described in this section of the RTC, in section IV.C.2. of the preamble to the final rule and in the TSD entitled "Status of CAA 100(a)(2)(D)(i)(I) SIPs Final Rule TSD," EPA has the authority and legal obligation to promulgate all of the FIPs in this rule.
Further, Section VII of the preamble to the final rule contains a discussion of the need to align compliance dates with NAAQS attainment deadlines.
Organization: Dynegy, Inc.
Comment: 
Dynegy, Inc.
Finally. proposing the Transport Rule as a Federal Implementation Plan (FIP) that would take effect in 2012 effectively undercuts the role of states under Clean Air Act Section 110(a)(I) to develop their own State Implementation Plans (SIP). EPA's position that a FIP is the only way to implement this program in order to meet the Agency's arbitrarily self-imposed January 1, 2012 starting date fails due to its circular logic. Moreover, under the Clean Air Act, the FIP process is to be employed only when a state is provided adequate notice to develop a SIP but fails to submit a SIP in a timely manner. EPA's desire to create a new program by 2012 is not an adequate reason to ignore Section 110(a)(1) and push aside state primacy under the Clean Air Act. Beginning implementation of the Transport Rule 30 to 36 months after promulgation, instead of January 1, 2012, would provide states with sufficient time to develop and submit SIPs in accordance with the division of state and federal authority under the Clean Air Act. [EPA-HQ-OAR-2009-0491-2698.1,p.3]
Response: 
For the reasons explained in this section of the RTC, in section IV.C.2 of the preamble to the final rule, and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate the Federal Implementation Plans in this action. 
Section 110(a)(1) of the Clean Air Act requires states to submit, within three years of promulgation or revision of a NAAQS, a plan which provides for implementation, maintenance, and enforcement of the standard.  The deadline for submission clearly runs from promulgation or revision of the NAAQS, not as the commenter suggests, from the date on which EPA gives some sort of additional notice to the state.  Section 110(a)(2) then lays out in greater detail what such plans must contain.  Among other things, they must include provisions sufficient to satisfy section 110(a)(2)(D)(i)(I).  These implementation plans are commonly referred to as infrastructure SIPs.  They are distinct and separate from the nonattainment SIPs that states with designated nonattainment areas are required to submit.  
Organization: East Kentucky Power Cooperative
Comment: 
East Kentucky Power Cooperative
EKPC Concerns Regarding Rule Implementation
Given EPA's proposal to immediately implement the reductions required through a Federal Implementation Plan ('FIP'), EKPC requests clarification regarding implementation of the rule and its oversight. EKPC requests clarification as to whether EPA or the state will be responsible for developing and managing allowed intrastate trading programs. EKPC further requests clarification regarding enforcement of the emissions reductions and how units with allowance deficits will be addressed. The chart below provides examples of the allowance deficits that EKPC will face if the rule is finalized: [EPA-HQ-OAR-2009-0491-2667.1, p.4; See p.4 of this comment summary for a chart providing examples of the allowance deficits that EKPC will face if the rule is finalized]
Response: 
For the reasons explained in this section of this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate each of the FIPs in this final rule.  EPA will implement all FIPs finalized in this action.  Section X of the preamble to the final rule explains the steps taken by EPA to make it easier for states to replace the FIPs, in whole or in part, with SIPs.  The allowance allocation system used in the final FIPs is also explained in the preamble to the final rule.
Organization: Edison Electric Institute (EEI)
Comment: 
Edison Electric Institute (EEI)
EPA's Approach to the Transport Rules is at Variance with the CAA's Division of Federal and State Responsibilities
EPA states that the Transport Rule is designed to address interstate transport in relation to several existing NAAQS. EPA states that the upcoming revision to the ozone NAAQS, (scheduled for late October 2010), will require an additional rulemaking (i.e., Transport Rule II); this rule would be proposed in 2011 and finalized in mid-2012. [EPA-HQ-OAR-2009-0491-2697.1, pp.14-15]
A broader CAA question arises, however, regarding whether EPA should be constructing additional Transport Rules at all on the basis that it has proposed to do so. That is, EPA is proposing to determine significant contribution in Federal Implementation Plans (FIPs) prior to timeframes allowed for the development and submittal of SIPs. EEI member company opinions vary on the legality and value of the proposed FIP approach. Some companies would prefer earlier emission reductions. Other companies believe that EPA should not pursue this course, but instead follow CAA requirements and the Agency's historic implementation of the SIP/FIP process.  [EPA-HQ-OAR-2009-0491-2697.1, p.15]
EPA states that addressing transport through § 110(a)(2)(D)(i)(I) "before downwind state nonattainment SIPs are due . . . would aid downwind states in developing plans for attaining and maintaining the new NAAQS." This action, however, does not comport with the SIP planning process provided for in the CAA. CAA § 110(a)(2)(D) requires "each" implementation plan to contain adequate provisions to prohibit emissions that "contribute significantly to nonattainment . . or interfere with maintenance by, any other State . . ." By acting before states have the ability to develop and submit SIPs to EPA, the Agency is impermissibly attempting to define the actionable level of pollution transport without reference to whether states submit approvable SIPs and without reference to the independent analysis and action by states provided for in the CAA. This raises the question of whether EPA should provide guidance and tools to the states to assist in their SIP revisions as opposed to implementing proposed Transport Rule FIPs as in the Proposed Rule. [EPA-HQ-OAR-2009-0491-2697.1, p.15]
Response: 
EPA is promulgating the FIPs in this rule because, for the reasons explained in this section of the RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs," it has a legal obligation to do so.  Section 110(c) of the Clean Air Act describes the circumstances under which EPA is obligated to promulgate a FIP.
 Organization: Edison Mission Energy (EME)
Comment: 
Edison Mission Energy (EME)
EPA's aggressive emission reduction timelines are contrary to law. Title I of the Clean Air Act ("CAA") gives states, not EPA, primary responsibility for attaining air standards within their borders. Under Title I, the proper process for implementing measures to attain air quality standards, like the emission reduction contemplated by the Transport Rule, is for EPA to give the states an opportunity to propose a state implementation plan ("SIP") that achieves those goals. Title I does not permit EPA to skip the SIP development process and impose a federal implementation plan ("FIP") on the states first as it has done here, nor does the D.C. Circuit's opinion in North Carolina v. EPA remanding CAIR. By ignoring the cooperative federalism dictates of Title I, the Transport Rule fails to comply with the CAA. [EPA-HQ-OAR-2009-0491-2707.1, pp.2-3] [[These comments can also be found in Section VII.C.]]
EPA's Proposal To Impose Emission Reductions On States By Directly Implementing Federal Implementation Plans Is Contrary To The Cooperative Federalism Dictates Of Title I Of The CAA [EPA-HQ-OAR-2009-0491-2707.1, p.6]
While EME supports efforts to reduce emissions and has made enforceable commitment to aggressive and substantial emissions reductions, we are concerned that EPA's proposed approach does not comply with the CAA. Specifically, we believe that EPA's decision to forego SIP revisions for many states and proceed directly to the promulgation of FIPs is contrary to the cooperative federalism dictates of Title I and the case law interpreting the respective roles of EPA and the states in carrying out the CAA's requirements. [EPA-HQ-OAR-2009-0491-2707.1, pp.6-7]
Statutory Framework Underlying EPA's Authority to Promulgate Federal Implementation Plans [EPA-HQ-OAR-2009-0491-2707.1, p.7]
The CAA commits to the states "the primary responsibility for assuring air quality within [the state] . . . by submitting an implementation plan . . . which will specify the manner in which national primary and secondary ambient air quality standards will be achieved and maintained . .. ." However, EPA may determine that a state's SIP does not meet the requirements of the CAA. Section 110(k)(5) provides that if EPA finds that a SIP is "substantially inadequate to attain or maintain" the relevant NAAQS, to "mitigate adequately" interstate pollutant transport or otherwise fails to comply with requirements of the CAA, EPA "shall require the State to revise the plan as necessary to correct such inadequacies." The CAA requires that EPA notify the state of the inadequacies in the SIP and allows EPA to set "reasonable deadlines (not to exceed 18 months after the date of such notice)" to submit SIP revisions. [EPA-HQ-OAR-2009-0491-2707.1, p.7]
If and when a state submits a SIP revision, EPA must make a determination of completeness -- whether the revised SIP meets the minimum criteria established by EPA pursuant to § 110(k)(1)(A). The CAA directs EPA to make this determination within 60 days of receipt of the SIP revision, but the decision must be made no later than six months after receipt. If EPA makes no determination within six months after receipt, the SIP revision is deemed to meet the minimum requirements established under § 110(k)(1)(A) by operation of law. Following submission of a completed SIP revision, EPA must act within 12 months and either approve or disapprove the revision. (EPA may also partially approve or disapprove the submission, or 'conditionally' approve it.) [EPA-HQ-OAR-2009-0491-2707.1, p.7]
EPA Blurs the Issue of the Statutory Findings Required for Promulgating FIPs and is Mistaken in Its Conclusions [EPA-HQ-OAR-2009-0491-2707.1, p.8]
EPA acknowledges in the preamble to the Transport Rule that it cannot promulgate a FIP unless it finds that a state has failed to make a required SIP submission, that a SIP submission is incomplete, or it disapproves a SIP submission. EPA attempts to evade the issue by making generalized findings without specifying to which state they apply. Moreover, although EPA acknowledges that the findings required by § 110(c)(1) have not yet been made for some states, it never specifies which states fall into that category, obscuring the basis for the rule and undermining the public comment process. The Agency's approach is flatly contrary to the CAA. [EPA-HQ-OAR-2009-0491-2707.1, p.8]
EPA's Rationale Regarding 1997 Ozone and PM2.5 NAAQS is Flawed for States That Have EPA-Approved SIPs in Place [EPA-HQ-OAR-2009-0491-2707.1, p.8]
EPA notes in the Transport Rule's preamble that in 2005 it found certain states had failed to make submissions meeting the requirements of § 110(a)(2)(D)(i) regarding the interstate transport of pollution. EPA later promulgated CAIR and concluded that state SIP submissions satisfying CAIR would satisfy § 110(a)(2)(D)(i) requirements. Most states submitted SIP revisions complying with the CAIR requirements, and EPA approved most of those SIP revisions. Table 1 [See p.9 of this comment summary for Table 1 entitled, States with SIPs EPA Approved Under CAIR as Fully Complying with Section 110(d)(2)(a)(i)] details states included in CAIR that later submitted SIP revisions, whichEPA approved as fully complying with those states' obligations under § 110(d)(2)(a)(i). [EPA-HQ-OAR-2009-0491-2707.1, p.9]
The CAA is clear that it is EPA's action in disapproving a SIP (or finding it incomplete)that triggers the FIP process. EPA, however, inexplicably argues that the D.C. Circuit Court of Appeals' remand of CAIR in December 200822 somehow acts as a repeal of EPA's approvals of the CAIR-based SIP revisions and that the 2005 findings of failure to submit are now back into effect for the states in which EPA approved SIP revisions under CAIR.23 EPA states in the preamble that, in light of North Carolina v. EPA, "a CAIR SIP can no longer be considered an adequate section 110(a)(2)(D)(i)(I) SIP submission."24 The preamble does not provide any legal basis for this conclusion nor does EPA argue that it has made the required finding that a SIP is "substantially inadequate to attain or maintain" the relevant NAAQS or to "mitigate adequately" interstate pollutant transport under § 110(k)(5). The CAA does not support EPA's conclusion that it may implement a FIP for these states. [EPA-HQ-OAR-2009-0491-2707.1, p.10]
[See EPA-HQ-OAR-2009-0491-2707.1, pp.10-15 for additional comments pertaining to EPA's Rationale Regarding 1997 Ozone and PM2.5 NAAQS is Flawed for States That Have EPA-Approved SIPs in Place]
These cases  -  all of which address the interplay between state and federal authority under Title I  -  have all found that Congress intended to give the states great discretion in developing SIPs, so long as those SIPs meet the minimum requirements set forth in the CAA. By implementing FIPs without giving the states an opportunity to develop measures to meet the applicable air quality standards, the Transport Rule usurps the states' role, expressly provided for in the CAA and affirmed by the case law, as the entity Congress chose for deciding how air quality standards are to be met on a state-by-state basis. This is equally so with states currently operating under SIPs EPA approved as meeting § 110(a)(2)(D)(i) standards for 1997 8-hour ozone and PM2.5 NAAQS. [EPA-HQ-OAR-2009-0491-2707.1, p.15]
That said, EME submits that EPA should not be in the business of allocating Phase II allowances at all, but rather should leave that work to the states. As explained in Section IV.A, the regulatory approach in the Proposed Rule bypasses the authority Congress committed to the states -- "primary responsibility for assuring air quality within [the state] . . . by submitting an implementation plan" -- by directly implementing FIPs and making unit-level allocation determinations. In doing so, EPA has not only acted contrary to the cooperative federalism dictates of Title I of the CAA, as a practical matter it has established a regulatory structure that does not take advantage of state-level relationships and expertise in terms of understanding the challenges facing individual EGUs. As a result, EPA has sacrificed the potential efficiencies that could be achieved through state decision-making on unit-level allocations. [EPA-HQ-OAR-2009-0491-2707.1, p.34]
There are a large number of units covered by the Transport Rule, and presumably it was challenging for EPA to collect accurate individual information about all of the EGUs in 32different states. We understand from others, like UARG, that EPA has made inaccurate or ill found assumptions with respect to individual EGUs (e.g., making incorrect assumptions about control technology that will be online by 2012, and unrealistic assumptions about the control efficiency of existing equipment). Such errors are inevitable given the magnitude of the data EPA needed to collect. However, that such errors are inevitable does not mean they are unavoidable  -  or that they should not be corrected. [EPA-HQ-OAR-2009-0491-2707.1, p.34]
EPA could have avoided the massive data collection necessitated by its FIP approach if it had followed the dictates of Title I which required EPA to give the affected states an opportunity to implement the Transport Rule through the SIP process. Under such an approach the States, and not EPA, would have initial responsibility for allocating allowances. Moreover, allowing the States to handle allocations would have been more cost-effective because state regulators are uniquely situated to make the most effective and economical allocations of allowances to EGUs within their borders. This is because they have a detailed understanding about source mix in a state and circumstances surrounding individual EGUs, or groups of EGUs. They are best situated to make the trade-offs necessary to ensure that allowance allocations are fair, because the universe of affected sources in an individual state is much smaller then the total number of sources covered by the Rule. Moreover, if states are allowed to establish the allocations, they would likely select allocation approaches tailored to the specific circumstances in a given state, as opposed to the one-size-fits-all approach employed by EPA. [EPA-HQ-OAR-2009-0491-2707.1, p.34-35]
In contrast to the approach taken in the Transport Rule, EPA had previously given states the flexibility to determine unit-level NOx allocations under CAIR. Before that, EPA gave states the flexibility to determine unit-level NOx allocations under the NOx SIP call. These prior rulemakings confirmed the wisdom of giving the states a lead role in making unit-level allocation decisions. Nowhere does EPA explain why that same logic does not apply with equal force in the Transport Rule context. That said, to the extent EPA attempts to retain authority over the Phase II unit-level allocations, it should do so in a manner that does not penalize existing sources that have already obtained meaningful emissions reductions. [EPA-HQ-OAR-2009-0491-2707.1, p.35]
Response: 
As explained in this section of this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate all of the FIPs in this rule.  As explained in that TSD, for each FIP finalized in this rule, EPA has made specific findings with respect to the state and pollutant at issue, or taken specific action to disapprove a specific 110(a)(2)(D)(i)(I) SIP from the state with respect to the relevant pollutant.   In addition, the statute explicitly recognizes EPA's authority to include emission trading programs in a FIP and to establish enforceable emission limitations in a FIP.  See  42 U.S.C. § 7602(y).  Any FIP that includes an economic incentive program based on marketable permits or allowances, must include a mechanism for distributing such allowances.  The grant of authority to EPA to include emission trading programs in a FIP thus necessarily includes the authority to distribute allowances for use in such programs.  In response to comments and information obtained by EPA, EPA has also made numerous revisions and corrections to the data used to develop the proposal.  The revised and corrected data was used to develop the final rule.  Finally, section X of the preamble explains the steps taken by EPA to make it easier for states to replace the FIPs in whole or in part.
Organization: EquiPower Resources Corp.
Comment: 
EquiPower Resources Corp.
The Transport Rule has co-opted state authority and adopted a regulatory approach that is flawed and contrary to law. Under Title I of the Clean Air Act ("CAA"), states have the primary responsibility for attaining air quality standards through promulgation of State Implementation Plans ("SIPs"). Therefore, EPA does not have the authority to directly implement Federal Implementation Plans ("FIPs") as it proposes and is acting contrary to law. Setting aside EPA's lack of authority to implement FIPs, EPA's approach is also flawed in that it ignores significant distinctions in state regulatory regimes. EPA should allow states to promulgate SIPs to meet the air quality standards as Congress intended. [EPA-HQ-OAR-2009-0491-2704.1, p.2] 
THE TRANSPORT RULE'S APPROACH OF BYPASSING STATE AUTHORITY TO PROMULGATE SIPS IS FLAWED AND CONTRARY TO LAW [EPA-HQ-OAR-2009-0491-2704.1, p.12] 
EPA Does Not Have Authority to Directly Implement FIPs And Must First Give The Affected States An Opportunity To Propose SIPs [EPA-HQ-OAR-2009-0491-2704.1, p.12] 
In sum, if EPA has made a finding that these states' SIPs are "substantially inadequate to attain or maintain" the relevant NAAQS, to "mitigate adequately" interstate pollutant transport or otherwise fail to comply with requirements of the CAA, the CAA requires that EPA notify the states of the inadequacies in the SIPs and allows EPA to set "reasonable deadlines" for states to submit SIP revisions.42 It does not allow EPA to immediately propose FIPs for those states. Thus, EquiPower recommends that EPA comply with the procedural requirements of the CAA and: (1) issue a SIP call; (2) allow states reasonable time to propose SIPs; and (3) then determine whether the SIPs meet the requirements of the CAA. Only after it takes those actions would the Agency be in a position, if necessary, to implement FIPs in the 32 states covered by the Transport Rule. [EPA-HQ-OAR-2009-0491-2704.1, pp.15-16; for additional comments pertaining to EPA Does Not Have Authority to Directly Implement FIPs And Must First Give The Affected States An Opportunity To Propose SIPs see pp.12-16]
EPA'S PROPOSAL HAS SIGNIFICANT DATA QUALITY FLAWS THAT RESULTED IN SIGNIFICANT ERRORS IN STATE BUDGET AND UNIT-LEVEL ALLOCATION CALCULATIONS WHICH MUST BE CORRECTED [EPA-HQ-OAR-2009-0491-2704.1, p.17] 
If EPA Allowed States To Craft SIPs As Congress Intended, This Would Alleviate Data Quality Concerns [EPA-HQ-OAR-2009-0491-2704.1, p.17] 
As explained in Section IV.A. above, Congress recognized the wisdom of allowing states to decide the best mechanisms for ensuring that air quality standards are met by committing to the states  -- "primary responsibility for assuring air quality within [the state] . . . by submitting an implementation plan." In bypassing this authority by directly implementing FIPs and dictating unit-level allocations, EPA has not only acted contrary to the cooperative federalism dictates of Title I of the CAA, it has also made important unit-level decisions without the benefit of the detailed data needed to achieve accuracy in its allocations. The result is that there are a number of errors in EPA's data and assumptions, as described in more detail below. While it is inevitable that errors would be made with EPA collecting individual information about all of the EGUs in 32 different states, these errors could have been (and still can be) avoided if states are afforded their proper role under the CAA. [EPA-HQ-OAR-2009-0491-2704.1, pp.17-18] 
State regulators are in the best position to craft SIPs and decide unit-level allocations as they have a detailed understanding about the generation mix in their state, the status of controls on those EGUs, and the performance of individual EGUs or groups of EGUs. They are also best-situated to compile data and perform the necessary analysis because the universe of affected sources in an individual state is much smaller than the total number of sources covered by the Transport Rule. Additionally, in states with delegated air programs, individual EGUs are obligated to report data directly to them. More importantly, if states are allowed to establish the allocations, they would likely select allocation approaches tailored to the specific circumstances in a given state, as opposed to the one-size-fits-all approach employed by EPA under the Transport Rule's FIP. [EPA-HQ-OAR-2009-0491-2704.1, p.18] 
In contrast to the approach taken in the Transport Rule, EPA had previously given states the flexibility to determine unit-level NOx allocations under CAIR.49 Before that, EPA gave states the flexibility to determine unit-level NOx allocations under the NOx SIP call.50 These prior rulemakings confirmed the wisdom of giving the states a lead role in making unit-level allocation decisions. No where does EPA explain why that same logic does not apply with equal force in the Transport Rule context. [EPA-HQ-OAR-2009-0491-2704.1, p.18] 
EPA should follow the procedures established in the CAA and allow states to craft SIPs because this approach would take advantage of state-level relationships and expertise in understanding the challenges facing individual EGUs. Individual states are not likely to have the same errors in their underlying data, assumptions and analysis that EPA has made in the Transport Rule. If EPA were to proceed with a SIP-approach, as required by law, states would be able to correct the specific errors noted in the subsections that follow. [EPA-HQ-OAR-2009-0491-2704.1, p.18] 
o EPA does not have authority to directly implement FIPs because it has not made the statutorily-required findings and EPA's approach is contrary to the cooperative federalism dictates of Title I of the CAA.
o Therefore, EPA should issue a SIP call and allow states reasonable time to propose SIPs. [EPA-HQ-OAR-2009-0491-3928[1].1, pp.2-3]
Response: 
As explained in this section of this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate all of the FIPs in this rule.  In response to comments, EPA made numerous revisions and corrections to the data used to develop this final rule.  Finally, in section X of the preamble, EPA explains the steps taken to make it easier for States to either replace the FIPs in whole, or to take over allocation of allowances under the FIP.
Organization: Exelon
Comment: 
Exelon
THE TRANSPORT RULE IS REQUIRED BY SECTION 110(A) OF THE CAA.
Expeditious implementation of the proposed Transport Rule is not only an economic imperative, it is required by law. The rule is long overdue. It has been almost twelveyears since EPA made a finding that interstate transport of ozone significantly contributed to nonattainment and interfered with maintenance in downwind states and five years since it made the finding with respect to PM2.5. The pollution reductions required by the Transport Rule, and its deadlines for making these reductions, represent the minimum required by Section 110(a)(2)(D)(i)(I) of the CAA, 42 U.S.C. § 7410(a)(2)(D)(i)(I) (hereafter, "Section 110(a)"). Section 110(a) requires that states adopt and implement State Implementation Plans ("SIPs") containing adequate provisions to prohibit sources from within the state from emitting amounts of air pollutants that will "contribute significantly to nonattainment in, or interfere with maintenance by, any other State with respect to any such national primary or secondary ambient air quality standard." The deadlines for eliminating significant contribution to nonattainment have long since passed, and neither the Transport Rule states, through their SIPs nor EPA in its past attempts to promulgate a Federal Implementation Plan ("FIP"), has succeeded in eliminating these emissions and their health impacts. EPA is therefore legally required to promulgate a FIP and to do so "as soon as practicable." [EPA-HQ-OAR-2009-0491-2666.1, pp.7-8]
EPA has found, and the modeling that has been conducted in connection with the development of the Transport Rule confirms, that air pollutants from EGUs within each of the states covered by the Transport Rule "contribute significantly to nonattainment in" and "interfere with maintenance by" other states with respect to the NAAQS for ozone, NOX and particulate matter. Accordingly, the EPA is required by Section 110(c)(1) of the CAA, 42 U.S.C. § 7410(c)(1), to promulgate a FIP that will satisfy the requirements of Section 110(a). 14 In the proposed Transport Rule, like the EPA's prior attempt to promulgate a FIP to satisfy the requirements of Section 110(a) in the CAIR, EPA has mandated a cap and trade program requiring reductions in emissions of the pollutants significantly contributing to nonattainment or interfering with maintenance. The use of the cap and trade mechanisms is expressly authorized by Section 110(a)(2)(A) of the CAA, 42 U.S.C. § 7410(a)(2)(A), and the CAA's definition of FIP, id.§ 7602(y). [EPA-HQ-OAR-2009-0491-2666.1, p.8]
In North Carolina, the court invalidated EPA's first attempt to satisfy the requirements of Section 110(a)(1) through CAIR. The court held that the regional cap and trade program established in CAIR did not satisfy the requirements of Section 110(a) because it failed to prohibit sources from within a state from contributing to nonattainment in other states. The court reasoned that EPA would not satisfy the statutory requirement "unless it is promulgating a rule that achieves something measureable toward the goal of prohibiting sources `within the State' from contributing to nonattainment or interfering with maintenance `in any other state.'"15 The court specified that a complete remedy to Section 110(a) problems requires the elimination of emissions from sources that contribute significantly to downwind nonattainment and must measure each state's "significant contribution" to downwind nonattainment. The proposed Transport Rule satisfies these requirements and, in order to meet its statutory duty, EPA must proceed to promulgate the proposed rule as expeditiously as feasible. [EPA-HQ-OAR-2009-0491-2666.1, pp.8-9]
THE TRANSPORT RULE APPROPRIATELY ADDRESSES ALL OF THE DEFICIENCIES IN CAIR IDENTIFIED BY THE COURT IN NORTH CAROLINA.
The proposed Transport Rule would create a cap and trade program that fully remedies all of the deficiencies that led the court to invalidate CAIR in North Carolina, where it held that: (1) it was unlawful for EPA to allow for regionwide caps on emissions without making state specific quantitative contribution determinations or imposing state specific emissions requirements; (2) CAIR lacked a fixed date for upwind states to eliminate their "significant contribution" to downwind nonattainment; (3) the NOX caps established in CAIR unlawfully considered fuel factors rather than air quality factors; and (4) the CAIR trading program unlawfully related each states' SO2 reductions to their CAA Title IV allowances. Each of these deficiencies is corrected in the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2666.1, p.9; for additional comments pertaining to THE TRANSPORT RULE APPROPRIATELY ADDRESSES ALL OF THE DEFICIENCIES IN CAIR IDENTIFIED BY THE COURT IN NORTH CAROLINA, see pp.9-10 of this comment summary]
BOTH EPA'S PROPOSED ALLOCATION METHODOLOGY AND THE ALTERNATIVES SUGGESTED HERE ARE AUTHORIZED UNDER THE CAA, BUT EXELON'S PROPOSED ALTERNATIVES WILL BETTER PROMOTE THE LEGISLATIVE INTENT.
Thus, the statute specifically authorizes promulgation of a FIP that includes economic incentives, such as marketable permits and auctions of emissions allowances.
Courts have traditionally balanced the requirement of notice to affected parties against the public's interest in having the law established firmly and expeditiously. In general, courts have not required republication of a proposed rule as long as the final rule is the "logical outgrowth" of the proposed rule. Notice is the primary consideration used by the courts to determine whether a proposed rule requires republication. Under both the Administrative Procedure Act ("APA") and the CAA, a court will evaluate whether the changes to a proposed rule are so significant that the final regulations are not the "logical outgrowth" of the proposed rule. However, it is within EPA's authority to promulgate a final rule that differs in some aspects from the proposed rule. The D.C. Circuit Court explained that Congress contemplated administrative flexibility when creating the APA and the CAA. The court further clarified that the notice and comment process does not begin anew each time a proposed rule is changed in response to public comments on a proposed rule. Only in instances where the final rule deviates too sharply from the proposed rule may republication be necessary to avoid depriving affected parties of notice and an opportunity to respond. [EPA-HQ-OAR-2009-0491-2666.1, pp.45-46]
None of the modifications proposed by Exelon even approach the level that might require republication. Indeed, Exelon's comments primarily address issues on which EPA expressly solicited comment in the preamble to the proposed rule, including the allowance allocation methodology, the compliance assurance provisions and the implementation schedule. There is no party whose rights could be adversely affected by the Transport Rule, modified as proposed by Exelon, who can claim that it did not have notice and an opportunity to be heard based upon the proposed Transport Rule and all of the supporting documentation that EPA has made available during the comment period. [EPA-HQ-OAR-2009-0491-2666.1, p.46]

14 That section requires that "[t]he Administrator shall promulgate a Federal implementation plan at any time 2 years after the Administrator  -  (A) finds . . . the [state implementation] plan or plan revision submitted by the State does not satisfy the minimum criteria" for SIPs.
Response: 
EPA agrees with the commenter that it has a legal obligation to promulgate the FIPs in this action.  EPA also agrees that the Transport Rule address the deficiencies in CAIR identified by the court in the North Carolina decision.  The statute explicitly recognizes EPA's authority to include emission trading programs in a FIP and to establish enforceable emission limitations in a FIP.  Specifically, the term "Federal Implementation Plan" is defined in section 302 of the Clean Air Act as "a plan (or portion thereof) promulgated by the Administrator to fill all or a portion of a gap or otherwise correct all or a portion of an inadequacy in a State implementation plan, and which includes enforceable emission limitations or other control measures means or techniques (including economic incentives, such as marketable permits or auctions of emissions allowances) and provides for attainment of the relevant national ambient air quality standard."  42 U.S.C. § 7602  (emphasis added).  Any FIP that includes an economic incentive program based on marketable permits or allowances, must include a mechanism for distributing such allowances.  The grant of authority to EPA to include emission trading programs in a FIP thus necessarily includes the authority to distribute allowances for use in such programs.  To implement the emission trading programs established, EPA must select a methodology to be used for allocating allowances. For the reasons explained in section VII.D. of the preamble and in the TSD on allowance allocations, EPA believes the methodology selected for allocation of allowances under the FIP is within EPA's authority and consistent with the statutory mandate of section 110(a)(2)(D)(i)(I) as interpreted by the courts.   
Organization: Florida Electric Power Coordinating Group, Inc. (FCG)
Comment: 
Florida Electric Power Coordinating Group, Inc. (FCG)
Finally, EPA's unreasonable 2012 date does not allow states time to develop their own SIPs to address interstate transport issues, despite EPA's pledge that states are free to do so. This issue is discussed more fully below.  [EPA-HQ-OAR-2009-0491-2658.1, p.4] [[This comment can also be found in Section VII.C.]]
Accordingly, EPA should not include a compliance deadline of 2012, and take the time to develop a more accurate, complete and defensible rule. [EPA-HQ-OAR-2009-0491-2658.1, p.4]
Response: 
Sections VI and VII of the preamble explain the rationale for the compliance dates used in the final rule.
Organization: Florida Municipal Electric Association (FMEA)
Comment: 
Florida Municipal Electric Association (FMEA)
FMEA has serious concerns with the more aggressive implementation schedule and specific electric generating unit (EGU) reduction requirements proposed in the Clean Air Transport Rule (CATR), frequently called the Proposed Transport Rule. There appears to be no mandate by the U.S. District of Columbia Court of Appeals (Court) that would require the Proposed Transport Rule compliance schedule, which forces the Environmental Protection Agency (EPA) to impose Federal Implementation Plans (FIPs) on affected states, including Florida, rather than permitting states to develop State Implementation Plans (SIPs). States are best suited to understanding the state-specific circumstances and developing the lowest cost method of meeting requirements of the Transport Rule. [EPA-HQ-OAR-2009-0491-2731.1, p. 1]
EPA's proposed approach is seriously misguided. The decision to impose FIPs rather than allow states time to develop state implementation plans ("SIPs") to implement section 110(a)(2)(D)(i)(I) obligations rests on an unlawful view of the CAA and the federal-state cooperative relationship under the Act. The Proposed Transport Rule (PTR) compliance schedule is wholly unreasonable, particularly its imposition of a January 1, 2012 initial compliance deadline that will fall only a few months after EPA plans to take final action in this rulemaking. EPA has failed to propose a defensible methodology for determining statewide emission reduction obligations and has required additional emission reductions even where they have not been shown to be needed to meet the air quality objectives that EPA asserts. More importantly, APPA believes that the U.S. EPA in this proposed rule has arrogated to itself, in contravention of the law, the right and responsibility to determine how a state's emission reduction requirements must be accomplished, thereby assuming an exceptionally heavy burden to show that it has applied its unit allowance allocation methodology accurately and consistently. Review of the PTR's supporting information, however, reveals that EPA's approach on this score is anything but accurate and consistent. Moreover, in many respects, EPA's explanation of the elements of the PTR, and its information and calculations offered in support of the PTR, are opaque to the point of incomprehensibility. These points are explained further below. [EPA-HQ-OAR-2009-0491-2731.1, pp. 4-5]
For these reasons, APPA believes that the PTR is inadequate as a proposed rule to replace CAIR. EPA should develop and offer for comment a new proposal that corrects the serious flaws in the PTR. [EPA-HQ-OAR-2009-0491-2731.1, p. 5]
Response: 
As explained in this section of this RTC, in section IV.C.2 of the preamble to the final rule, and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate each of the FIPs in this final rule.
Organization: Gainesville Regional Utilities (GRU)
Comment: 
Gainesville Regional Utilities (GRU)
In its proposed Clean Air Transport Rule (CATR) the Environmental Protection Agency (EPA) has abandoned important provisions of CAIR that appear to have little to do with the Court remand of the rule. GRU has serious concerns with the more aggressive implementation schedule and specific electric generating unit (EGU) reduction requirements discussed in the proposed CATR. There appears to be no mandate by the United States District of Columbia Court of Appeals that would require the proposed CATR compliance schedule, which forces the EPA to impose Federal Implementation Plans (FIPs) on affected states, including Florida, rather than permitting states to develop State Implementation Plans (SIPs). States are best suited to understanding their own specific circumstances and developing the lowest cost method of meeting the requirements of the proposed CATR. [EPA-HQ-OAR-2009-0491-2674.1, p.1]
Response: 
As explained this section of the RTC, in section IV.C.2 the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs Final Rule TSD", EPA has the authority and legal obligation to promulgate all of the FIPs in this rule.
Further, sections VI and VII of the preamble to the final rule explain the rationale supporting EPA's decision to use the compliance deadlines in the final rule and the importance of aligning compliance dates with NAAQS attainment deadlines.
Organization: Golden Spread Electric Cooperative
Comment: 
Golden Spread Electric Cooperative
As proposed, overall the emission reductions required under both the 2012 and 2014 compliance deadlines are overly optimistic and otherwise unachievable.
Most of the major problems with this proposal, or action, begin with EPA eliminating requirements under CAIR and "proposing FIPs to immediately implement the emission reduction requirements identified and quantified by EPA in this action." The unreasonable and unnecessary proposed compliance deadlines in the proposed CATR present further complications for EPA as the agency attempts to circumnavigate its responsibilities under the Clean Air Act (CAA) Section 110 that clearly requires states be given opportunities to implement Section 110 obligations through the SIP process. EPA has not explained why it has chosen to accelerate this proposed CAIR replacement or why it finds it necessary to do so based on the courts' decisions in North Carolina v. EPA, 513 F.3d 896, (DC Cir 2008). GSEC recommends that CAIR remain in effect until each state has been given the opportunity to meet the requirements set forth in the CAA Section 110 (a) based on the timetable(s) set forth in Section 110(a)(1).  [EPA-HQ-OAR-2009-0491-2808.1 p.4] [[This comment can also be found in Section VII.C.]]
Response: 
For the reasons explained in this section of the RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs," EPA has a legal obligation to promulgate each of the FIPs in this final rule.
Organization: Holland Board of Public Works
Comment: 
Holland Board of Public Works
A compliance deadline of 2012 does not leave much time after the anticipated final rule is promulgated in 2011 to determine a cost-effective, cost-stable method of operating our affected unit. This deadline also does not allow our state to develop a State Implementation Plan (SIP) that could be crafted to take in mitigating factors for small municipalities that the EPA's modeling program cannot. [EPA-HQ-OAR-2009-0491-2861.1,p.1] [[This comment is also in Section VII.C.]]
Response: 
As explained in this section of the RTC, in section IV of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs," EPA has a legal obligation to promulgate the FIPs in this final rule.  Further, in section VI of the preamble to the final rule, EPA explains the rationale behind the compliance dates in the final rule.  Section VII also explains the importance of aligning compliance dates with NAAQS attainment deadlines.
Organization: Illinois Environmental Protection Agency
Comment: 
Illinois Environmental Protection Agency
The Illinois EPA recommends that the final Transport Rule allow for a State Implementation Plan (SIP)-based regulatory process with the initial budgets established for 2014, and subsequent budgets in 2016 or 2017. In Illinois, affected sources would continue to comply with CAIR and Illinois' multi-pollutant standards until the Transport Rule reductions become effective.
This approach is consistent with key recommendations made in a September 2, 2009 letter to U.S. EPA Administrator Jackson from a collaborative of 17 states in the eastern U.S. Those recommendations were based on in-depth technical evaluations of feasible control options and timing of implementation and a good-faith effort by the states to reach a consensus on the overall approach to reducing interstate transport consistent with the decision of the DC Circuit Court. Using a later date than 2012 for the initial budgets under the Transport Rule FIP allows states sufficient time to develop SIPs and would allow emission sources sufficient time to plan and optimize control measures. Allowing states sufficient time to develop SIPs may ultimately prove to be a more timely approach for reducing interstate transport than will U.S. EPA's FIP approach, due to the likelihood of further litigation.  [EPA-HQ-OAR-2009-0491-2781.1 p.1]
Response: 
For the reasons explained in this section of this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate all of the FIPs in this rule.  Sections VI and VII of the preamble to the final rule explain EPA's decision to use the compliance dates in the final rule.  Among other things, EPA has an obligation to align the compliance dates with the attainment deadlines for the relevant NAAQS.
Organization: Indiana Cast Metals Association (INCMA)
Indiana Manufacturers Association, Inc. (IMA)
Georgia Department of Natural Resources, Air Protection Branch
Comment: 
Georgia Department of Natural Resources, Air Protection Branch
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.94.]
Finally, EPA's approach to establishing federal implementation plans or FIPs in every state subject to this rule is unjustified and undermines the federal-state partnership the EPA administrator has said is important to successful implementation of the Clean Air Act.
Indiana Cast Metals Association (INCMA)
There is not enough time to develop a state implementation plan, forcing Indiana to rely on the federal implementation plan. This is counter to the spirit of the Clean Air Act and an unneeded and hasty short-circuit of an established regulatory process. [EPA-HQ-OAR-2009-0491-2178.1, p.1]
Indiana Manufacturers Association, Inc. (IMA)
Resons to delay include: Lack of time to develop a state implementation plan, forcing us to rely on the federal implementation plan. This is counter to the spirit of the Clean Air Act and an unneeded and hasty short-circuit of an established regulatory process. [EPA-HQ-OAR-2009-0491-1813.1, p. 1]
Response: 
As explained in this section of the RTC, in section IV of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs," EPA has a legal obligation to promulgate the FIPs in this final rule. 
Organization: International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers and Helpers (AFL-CIO Boilermakers Union)
Comment: 
International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers and Helpers (AFL-CIO Boilermakers Union)
An additional shortcoming of the Transport Rule's exceedingly ambitious deadlines is that it short-circuits the traditional prerogative of states under the Clean Air Act to take primary responsibility for addressing air pollution through SIPs. [EPA-HQ-OAR-2009-0491-2672.1, p.3]
Second, the proposed 2012 deadline runs contrary to the 'cooperative federalism' policy of the CAA by depriving states of the opportunity to first come into compliance with Section 110 by amending their SIPs. [EPA-HQ-OAR-2009-0491-2672.1, pp.3-4] [[This comment can also be found in Section VII.C.]]
2. Circumventing State Prerogatives to Develop SIPs. The 2012 deadline is also inconsistent with the CAA policy of 'cooperative federalism' because it will result in the imposition of a Federal Implementation Plan (FIP) without giving the states adequate opportunity to revise their SIPs to comply with Section 110. As EPA acknowledged in the NOx SIP Call, 'Congress' clear preference throughout Title I is that states are to decide and plan how they will control their sources of air pollution, and the mechanism for imposing those controls at the state level is SIPs. In previous rulemakings implementing Section 110(a)(2)(D)(I)(i), EPA has effectuated Congress' 'clear preference' by providing adequate time for states to submit revised SIPs addressing interstate transport before proceeding to implement a FIP. In CAIR, for example, EPA gave states the maximum statutory period of eighteen months to submit compliant SIPs before implementing a FIP (and gave states additional lead time to comply with emission requirements). The proposed Transport Rule, however, would be promulgated just six to nine months before emission requirements take effect - a timeframe that essentially guarantees that most states will become subject to a FIP. This circumvention of state prerogatives is inappropriate, inconsistent with the 'clear preference' of Congress, and contrary to EPA's past practice. [EPA-HQ-OAR-2009-0491-2672.1, p.5]
In further support of our recommended deferral, we note that EPA has extended deadlines in the CAA in the past where timely compliance was rendered impossible due to delays in issuing agency guidance. For example, in Natural Resources Defense Council v. EPA, the D.C. Circuit determined that states should be allowed to submit enhanced vehicle inspection and maintenance standards after a deadline provided in the CAA, because delays in issuing necessary EPA guidance had prevented states from meeting the statutory deadline. Here, states were not in a position to comply with the interstate transport requirements of Section 110(a)(2)(D)(i) in the absence of EPA's technical and policy analysis determining which states are contribution to downwind attainment problems and how much each upwind state is required to abate. These issues entailed statutory analysis and technical judgment that only EPA could provide. [EPA-HQ-OAR-2009-0491-2672.1, p.10]
Accordingly, the states should not be considered bound by the original three-year deadline provided for meeting the interstate transport requirements of the 1997 PM2.5 and Ozone NAAQS, and the 2006 PM2.5 NAAQS. Instead, EPA should provide a reasonable period from the publication of the final Transport Rule for revision of SIPs to address interstate transport issues. [EPA-HQ-OAR-2009-0491-2672.1, p.10] [[These comments can also be found in Section VII.C.]]
Response: 
For the reasons explained in this section of this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate all of the FIPs in this rule.  The commenter has not cited to any provision that would give EPA authority to alter the deadlines established in the Clean Air Act.  In NRDC v. EPA, the D.C. Circuit extended certain deadlines where the deadlines were intended to run from the date on which EPA issued certain statutorily required guidance.  In this case, however, the deadlines run from the date of promulgation of the NAAQS.  Further the statute does not direct or require EPA to issue guidance with respect to the requirements of section 110(a)(2)(D)(i)(I) and EPA lacks authority to alter the statutory deadline.
Organization: JEA
Comment: 
JEA
EPA did not allow sufficient participation by the state of Florida to promulgate a state-specific solution
Contrary to those previous interstate emission provisions of CAIR, the proposed Transport Rule would impose a FIP approximately six to nine months after promulgation - providing no meaningful opportunity to the states to first address their interstate emissions through the SIP process. As EPA acknowledges in the preamble to the Transport Rule, SIP revisions typically take on the order of three years to prepare and approximately six months to approve. Since the Transport Rule is likely to be finalized in mid-2011 and FIPs would take effect in 2012, there is almost no chance that states subject to the Transport Rule could revise and approve their SIPs in time to avoid the imposition of the FIP. EPA must respect the rights of individual states to develop and implement their own SIPs if they so choose. EPA does not have the authority to promulgate a FIP without first giving the states this opportunity. The ability to replace federal requirements at some point in the future does not satisfy the requirement that EPA allow states the opportunity to craft their own plans, at the outset of the program, to address interstate transport. [EPA-HQ-OAR-2009-0491-2713.1, pp.3-4]
EPA's Proposal, if Finalized, Would Violate N.C. v EPA, Constitute a Taking and Violate Due Process [EPA-HQ-OAR-2009-0491-2713.1, p.5]
Response: 
For the reasons explained in this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD discussing the status of CAA 110(a)(2)(D)(i)(I) SIPs, EPA has a legal obligation to promulgate all of the FIPs in this final rule.  This rule was developed to address the issues raised by the court in North Carolina v. EPA and is consistent with that opinion in all respects.  In no way does the rule constitute a taking.  The Clean Air Act and EPA's regulations explicitly provide that no allowance created by the Acid Rain Program or the Clean Air Interstate Rule constitute a property right.  The value of allowances issued under both programs are affected by the numerous factors including market expectations, cost of controlling emissions, and subsequently issued rules.  EPA is taking no action in this rule to terminate or limit allowances issued under Title IV.  Further, EPA is taking no action to limit the use of CAIR allowances for use in the CAIR trading programs which continue in force through the 2011 control periods.  EPA's responses to comments regarding whether it should permit banked CAIR allowances to be used for compliance with the new Transport Rule trading programs is addressed in section IV.C.2 of the preamble to the final rule and this RTC.
 Organization: Kansas City Board of Public Utilities (BPU)
Comment: 
Kansas City Board of Public Utilities (BPU)
THE RULE AS APPLIED TO KANSAS EXCEEDS EPA'S STATUTORY AUTHORITY
The CAA provides the authority for each state to have 'the primary responsibility for assuring air quality' within its borders. 42 U.S.C. § 7410(a). Individual states exercise this responsibility by adopting SIPs providing for the 'implementation, maintenance, and enforcement of' the NAAQS. 42 U.S.C. § 7410. See, e.g., Train v. Natural Resources Defense Council. 421 U.S. 60, 79 (1975) and Natural Resources Defense Council v. Browner, 57 F.3d 1122, 1123-24 (D.C. Cir. 1995)(explaining federal-state partnership under CAA). As the Rule recognizes, 'EPA has approved the 110(a)(2)(D)(i) submission [SIP] from the State of Kansas for the 1997 ozone and PM25 NAAQS.' 75 FR at 45342/1. To date Kansas has been expressly excluded from the NOx SIP Call and CAIR on the basis that Kansas does 'not significantly contribute to downwind nonattainment under the 1-hour or 8-hour ozone NAAQS, or interfere with maintenance under the 8-hour NAAQS.' NO, SIP Call at 63 Fed. Reg. 57398/3. Thus, Kansas has never been required to submit a revised SIP in response to the CAIR rule. 70 Fed. Reg. 25171/2 ('The final CAIR does not cover Kansas based on new analyses of its contribution to downwind PM25 nonattainment.'); see 72 Fed. Reg. 10608 (March 9, 2007) (order approving Kansas SIP on same basis). [EPA-HQ-OAR-2009-0491-2740.1, pp.8-9]
EPA may promulgate a FIP to replace the SIP in whole or in part only after finding that a SIP fails to meet minimum criteria established by regulation or by finding that a SIP is inadequate to attain or maintain the NAAQS at issue. Neither finding has been made with respect to the Kansas SIP. CAA § 7410(c)(l)(A) states:(c)(1) The Administrator shall promulgate a Federal implementation plan at anytime within 2 years after the Administrator-(A) finds that a State has failed to make a required submission or finds that the plan or plan revision submitted by the State does not satisfy the minimum criteria established under subsection (k)(1 )(A) of this section 2 [EPA-HQ-OAR-2009-0491-2740.1, p.9]
Alternatively, EPA may require a State to revise its currently effective SIP '[w]henever the Administrator finds that the applicable implementation plan for any area is substantially inadequate to attain or maintain the relevant national ambient air quality standard ... or to otherwise comply with any requirement of' the Clean Air Act. 42 U.S.C. § 7410(k)(5). However, such revision can occur only after the Administrator first publicly notifies the state of the SIP's inadequacies and sets a deadline (not to exceed 18 months) for the state to revise the SIP. Id. [EPA-HQ-OAR-2009-0491-2740.1, pp.9-10]
While the Rule states that the approved Kansas SIP is inadequate and must be replaced based on 'updated modeling done for this proposed rule,' 75 FR at 45342/1, this is not the requisite finding and does not follow the requisite procedure. EPA further states that it 'is proposing to finalize the FIP for Kansas for ozone only if the state fails to submit a complete and approvable SIP by the deadline established in any final SIP Call.' Id But in order to avoid subjecting Kansas EGUs to enforcement action and Kansas to adverse findings under any FIP that will result from the Rule, Kansas must immediately begin implementing the Rule and the EGUs subject to the Rule must commit many millions of dollars to attain compliance with the Kansas state air emission budget and individual EGU emissions allowances set forth in the Rule. In other words, the Rule's preemptive finding outside the requisite procedures does not give Kansas sufficient time to respond to a SIP disapproval and submit a revised SIP before the new emissions restrictions proposed in the Rule take effect. See 75 FR at 454286/3 ('a single SCR unit on average takes 21 months to install'). This presents the very real possibility that penalties could be assessed against the State of Kansas or any in-state EGU even though EPA's preemptive approach does not comport with the processes that Congress mandated for EPA SIP disapproval.[EPA-HQ-OAR-2009-0491-2740.1, p.10]
The CAA language allows EPA to replace a SIP only on the basis and after promulgation of final regulations establishing the applicable minimum criteria to be met by a SIP. Subsection 7410(c)(1)(A). EPA is in the process of promulgating, but has not yet finalized, the instant proposed rules. 75 FR at 45342/1. Consequently, the proposed rules do not yet constitute 'minimum criteria' with which Kansas' SIP must comply. [EPA-HQ-OAR-2009-0491-2740.1, p.10]
Quite the opposite, EPA has already determined under the currently effective minimum criteria that Kansas does 'not significantly contribute to downwind nonattainment under the 1-hour or 8-hour ozone NAAQS, or interfere with maintenance under the 8-hour NAAQS.' NOx SIP Call at 63 Fed. Reg. 57398/3; 72 Fed. Reg. 10608 (March 9, 2007)(same). Until the proposed rules are implemented as final regulations with the force of law, the already approved Kansas SIP will continue to meet the currently effective minimum criteria, and thus is not subject to replacement. [EPA-HQ-OAR-2009-0491-2740.1, p.11]
As the conditional language in the Rule acknowledges, the same result is reached by following the SIP Call process of § 7410(k)(5): 'That SIP Call, if finalized, would' find that Kansas' existing SIP is substantially inadequate and would 'establish a deadline for submission' of a new SIP. 75 FR at 45342/1 (emphasis added). The prerequisite for taking such action - a finalized SIP Call - has not yet happened, and therefore Kansas (and in-state EGU sources) cannot not yet be subjected to the proposed FIP as outlined in the Rule. By determining Kansas state air emission budgets and allowances for Kansas EGUs and including them in the Rule, EPA treats Kansas and its EGU sources as if they would be subject to and required to meet the 2012 emissions levels--this exceeds EPA's statutory authority. [EPA-HQ-OAR-2009-0491-2740.1, p.11] 
For the reasons stated herein, BPU requests alternative modifications to the proposed Rule by:
1. eliminating Kansas from the list of States identified as significantly contributing to or interfering with maintenance of 8-hour ozone levels; [EPA-HQ-OAR-2009-0491-2740.1, p.23]
3. reversing its ruling that Kansas' current SIP is not in compliance with the currently effective minimum criteria for significant contribution and interference with maintenance;  [EPA-HQ-OAR-2009-0491-2740.1, p.23]

2 Section 7410(k)(1)(A) provides that '[w]ithin 9 months after November 15, 1990, the Administrator shall promulgate minimum criteria that any plan submission must meet before the Administrator is required to act on such submission under this subsection. The criteria shall be limited to the information necessary to enable the Administrator to determine whether the plan submission complies with the provisions of this chapter.'
Response: 
For the reasons explained in this section of the RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," because EPA disapproved the SIP revision submitted by the state of Kansas to address the requirements of 110(a)(2)(D)(i)(I) with respect to 2006 PM2.5 NAAQS, EPA has a legal obligation to promulgate a FIP for the state of Kansas addressing the requirements of section 110(a)(2)(D)(i)(I) with respect to the 2006 PM2.5 NAAQS.  Further, the commenter mischaracterizes the requirements of subsection 7410(c)(1)(A).  This subsection does not, as the commenter asserts "allow EPA to replace a SIP only on the basis and after promulgation of final regulations establishing the applicable minimum criteria to be met by a SIP."  Section 110(c)(1) provides that the Administrator shall promulgate a Federal implementation plan at any time with two years after the Administrator takes one of three actions: (1) "finds that a State has failed to make a required submission"; (2) "finds that the plan or plan revision submitted by the State does not satisfy the minimum criteria established under subsection (k)(1)(A) of this section, or (3) "disapproves a State implementation plan submission in whole or in part."  42 U.S.C. § 7410(c)(1).
Section 110(k)(1)(A), which is entitled "completeness criteria" only discusses the issuance of criteria that a plan submission must meet "before the Administrator is required to act on such submission,"  in other words, criteria for determining whether a submission is complete, and not criteria for determining whether a submission is approvable.  Nothing in section 110(k)(1)(A) requires EPA to quantify the specific reductions a state must make for a particular 110(a)(2)(D)(i)(I) SIP submission to be approved as satisfying the requirements of that section.  EPA promulgated SIP completeness criteria in 1991.  See 56 FR 23826, 56 FR 42216.  EPA has no obligation to act on SIP submissions that do not satisfy the 110(k)(1)(A) completeness criteria.  A finding of completeness, however, is not a finding that the SIP submission satisfies any substantive statutory requirements. Section 110(k) explicitly provides that when EPA is obligated to act on a SIP submission it can approve, disapprove, or conditionally approve the submission.  EPA further notes that it can and has approved SIP submissions as meeting the requirements of section 110(a)(2)(D)(i)(I) of the Clean Air Act submitted by states prior to any determination by EPA quantifying or otherwise specifically identifying whether the state has emissions which significantly contribute to nonattainment or interfere with maintenance in another state.  See, e.g. 75 FR 33174, 75 FR 72688 (approving SIP submissions from New Mexico).  Finally, section 110(a)(1) explicitly requires the submission of 110(a) SIPs within 3 years of promulgation or revision of a NAAQS.  It does not suggest that the deadline for 110(a) SIP submissions for all NAAQS should be 3 years from the date EPA issues completeness criteria for plan submissions. 
Organization: Kansas City Power and Light Company (KCP&L)
Comment: 
Kansas City Power and Light Company (KCP&L)
5. Implementation of the Proposed Transport Rule pursuant to the schedule that EPA proposes would make it virtually impossible for states to implement SIPs prior to the first phase of the program. Issuing the PTR as a FIP would effectively bypass the states' rights to develop their own plans. This is contrary to the Act, in that the opportunity to replace federal requirements with a state plan at some time in the future does not satisfy the requirement that EPA allow the states an opportunity to develop their own plans at the outset of the program. [EPA-HQ-OAR-2009-0491-2709.1, p.4]
Response: 
For the reasons explained in this section of this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate each of the FIPs in this final rule.
Organization: Kentucky Division for Air Quality
Comment: 
Kentucky Division for Air Quality
Authority must be maintained to allow for states to implement additional programs necessary to address attainment and maintenance issues within their borders. [EPA-HQ-OAR-2009-0491-2805.1, p.1] Given Adequate Time Prefer a SIP to a FIP  
Pursuant to the proposed Transport Rule preamble Section III.A., Summary of Proposed Rule (75 FR 45214), the Division is concerned about the Federal Implementation Plan (FIP) proposal and the lack of specific State Implementation Plan guidance in the proposal. A FIP implies that a state has failed to meet its obligation and this is just not the case. The Kentucky CAIR SIP was approved in EPA in an October 4, 2007, Federal Register. The Division would prefer the opportunity to implement the proposed Transport Rule requirements through the SIP process; however, due to the lack of time this is not feasible. In addition, there is little specificity in this proposal on how states would develop an appropriate SIP to replace the Transport Rule FIP. EPA should provide additional SIP guidance to the states.  [EPA-HQ-OAR-2009-0491-2805.1, p.6]
Response: 
For the reasons explained in this section of this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate all of the FIPs in this rule.  This obligation arises from the Clean Air Act regardless of the reason for the deficiency in the state SIP.  Section X of the preamble to the final rule provides additional information regarding steps taken to make it easier for states to replace the FIPs, in whole or in part, with SIPs.  Finally, section 116 preserves the authority of states, in many circumstances, to promulgate emission limits at least as stringent as federal limits.   
Organization: Lansing Board of Water & Light
Comment: 
Lansing Board of Water & Light
States must be granted the opportunity to develop a SIP before proceeding to a FIP 
The Clean Air Act established an order that has been followed roughly since its inception in 1970: Congress delegates to EPA the authority to set National Ambient Air Quality Standards (NAAQS), and requires states to develop State Implementation Plans (SIP) to attain those standards. As explained in Cases and Materials on Environmental Law, 7th Edition (Farber, et al)
This division of responsibility affords the states the flexibility to mete out the pain of emissions reductions in a way that is sensitive to local conditions. These conditions are not just political but also geographical and cultural. Because of the variability among states in terms of their industrial base, geography, climate, and tolerance for difference kinds of regulation, state governments are thought to be in the best position to determine how to meet federal standards. [EPA-HQ-OAR-2009-0491-2752.1,pp.7-8]
This is not just some subjective commentary found in a case law textbook, it's a discussion of the Clean Air Act as found in 42 U.S.C. § 7410. Specifically, subsection (a) establishes that states must develop and submit a SIP, "after reasonable notice and public hearings...within 3 years". While subsection (c) grants the EPA authority to develop a FIP, its only after the EPA "finds that a State has failed to make a required submission or finds that the plan or plan revision submitted by the State does not satisfy the minimum criteria". [EPA-HQ-OAR-2009-0491-2752.1,p.8]
Response: 
For the reasons explained in this section of this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate each of the FIPs in this final rule.
Organization: Large Public Power Council (LPPC)
Comment: 
Large Public Power Council (LPPC)
Briefly stated, our principal recommendations to EPA are:
- Before imposing the proposed FIPs, allow states adequate time to prepare SIPs that are capable of addressing the interstate contributions of NOx and SO2 that are identified in the Transport Rule;[EPA-HQ-OAR-2009-0491-2667.1, p.2]
A. EPA Must Allow Sufficient Time for States to Prepare Adequate SIPs Before Proceeding to Implement FIPs Under the Transport Rule.
By almost immediately imposing Federal Implementation Plans (FIPs) before giving states an opportunity to craft SIPs that address interstate emissions of NOx and SO2, the proposed Transport Rule would usurp the responsibilities given to states under the Clean Air Act (CAA) and violate the "cooperative federalism" policy undergirding the statute. As EPA knows, Section 110 of the CAA gives states a default period of three years from the promulgation of a National Ambient Air Quality Standard (NAAQS) to submit a SIP that "provides for the implementation, maintenance, and enforcement" of the NAAQS, including "adequate provisions" to prohibit sources within the state from significantly contributing to nonattainment or interfering with the maintenance of attainment in any other state. 5 Only when EPA finds that a state has failed to submit an adequate SIP or disapproves a SIP may EPA impose a FIP that meets the requirements of the CAA. 6 [EPA-HQ-OAR-2009-0491-2667.1, p.3]
First, the proposal improperly circumvents the CAA-mandated, state-driven process for preparing and amending State Implementation Plans (SIPs). [EPA-HQ-OAR-2009-0491-2667.1, p.3]
LPPC believes that EPA has discretion under the CAA, and under the D.C. Circuit's opinion in North Carolina, to defer implementation of the Transport Rule for at least one to two years. Such a deferral would provide states adequate time to prepare SIPs that address the significant contributions and interference with maintenance identified in the Transport Rule.[EPA-HQ-OAR-2009-0491-2667.1, p.3] [[This comment can also be found in Section VII.C.]]
In decisions spanning over thirty years, the Federal courts of appeals have consistently recognized that this statutory scheme gives states primary responsibility for meeting air quality criteria under a policy of "cooperative federalism." 7 EPA itself acknowledged in the NOx SIP Call that "Congress' clear preference throughout Title I is that states are to decide and plan how they will control their sources of air pollution, and the mechanism for imposing those controls at the state level is SIPs." 8 Indeed, EPA relied on that principle in the NOx SIP Call when allowing states to first revise their SIPs to address interstate ozone transport before imposing direct federal emission controls under Section 126. 9 Similarly, EPA promulgated CAIR four years in advance of the starting date for emission reductions under the CAIR FIPs, a timeframe that gave each state ample notice as to the amount of interstate emissions it was required to abate under Section 110(a)(2)(D)(i)(I) and a fair opportunity to prepare a SIP achieving that reduction. 10 [EPA-HQ-OAR-2009-0491-2667.1, pp.3-4]
Unlike those previous interstate emission regulations, the proposed Transport Rule would impose a FIP approximately six to nine months after promulgation  -  providing no meaningful opportunity to the states to first address their interstate emissions through the SIP process. As EPA acknowledges in the preamble to the Transport Rule, SIP revisions typically take on the order of three years to prepare and approximately six months to approve. 11 Since EPA has stated that the Transport Rule is not planned to be finalized until mid-2011 and FIPs would take effect in 2012, there is almost no chance that states subject to the Transport Rule could revise and EPA could approve their SIPs in time to avoid the imposition of the FIP. 12 This result is inconsistent with past practice under the CAIR and the NOx SIP Call, and is also incompatible with EPA's recognition that it was the "clear preference" of Congress that states be given primary responsibility for crafting emission control requirements through the SIP process. LPPC notes that this concern has been expressed by state permitting authorities; the Director of the Ohio Environmental Protection Agency, for example, testified earlier this summer that that the "FIP first" approach of the Transport Rule is "not consistent with the spirit of cooperative federalism embedded in the essential structure of the Clean Air Act." 13  Similarly, the Chief of the Air Protection Branch of the Georgia Environmental Protection Division testified to EPA in September that "EPA's approach to establishing Federal Implementation Plans (FIPs) in every state is unjustified and undermines the Federal-State partnership the EPA administrator has said is important to successful implementation of the Clean Air Act." 14 [EPA-HQ-OAR-2009-0491-2667.1, p.4]
In defense of its legal authority to promulgate a FIP as part of the Transport Rule, EPA claims that many of the jurisdictions covered by the Transport Rule were already found in the CAIR to have deficient SIPs with respect to the 1997 NAAQS for ozone and PM2.5. For the 2006 NAAQS for PM2.5 (and for jurisdictions not covered by findings made in CAIR), EPA claims that the findings of inadequacy in the Transport Rule itself allow EPA to immediately proceed with implementation of a FIP. 15 EPA's reasoning overlooks the fact that the states have not submitted adequate SIPs because  -  unlike other aspects of a SIP  -  the CAA prohibition on significant interstate transport of emissions cannot be reasonably addressed in a SIP unless and until EPA undertakes the significant contribution and maintenance analysis that appears in the proposed Transport Rule. 16 Because EPA guidance is indispensable in order for states to comply with Section 110(a)(2)(D)(i)(I), the states must be afforded adequate time to craft responsive SIPs once EPA finally acts. [EPA-HQ-OAR-2009-0491-2667.1, p.5]
There are two reasons that states were powerless to act in the absence of EPA's latest analysis of significant contributions and interference with maintenance. First, the analysis of interstate emissions transport involves matters of technical judgment that fall to EPA to resolve. For the proposed Transport Rule, EPA substantially revised its methodology for determining which states contribute to downwind nonattainment and interference with maintenance  -  including the thresholds used to "screen out" states with minimal contributions to interstate transport of emissions, 17 the "relative contribution" technique used to project future ozone and PM2.5 concentrations, 18 and the modeling technique (source apportionment) used to determine the magnitude of upwind emissions on downwind air quality. 19 Once CAIR was remanded to EPA, no state was in a position to predict how EPA would exercise technical judgment on these issues. [EPA-HQ-OAR-2009-0491-2667.1, p.5]
Second, as EPA itself points out in the preamble to the Transport Rule, the prohibition against "significant contribution" to nonattainment and interference with maintenance in Section 110(a)(2)(D)(i)(I) requires a policy judgment as to how responsibility to abate emissions should be apportioned among downwind and upwind states. The preamble notes that regional air quality problems arise from a complex interaction of downwind and upwind sources. In some cases, a downwind jurisdiction has exhausted all cost-effective emission reduction opportunities and the burden of further air quality improvements must fall on the upwind state; conversely, it may be more reasonable for a downwind state to undertake additional measures in cases where an upwind state has already tightly controlled its emissions. Consequently, EPA notes that the interpretation of "significant contribution" and "interfere with maintenance" in the CAA "inherently involves a policy decision on how much emissions control responsibility should be assigned to upwind states, and how much responsibility should be left to downwind states." 20 Absent EPA's exercise of policy judgment on this issue, no state could determine how much it needs to revise its SIP. [EPA-HQ-OAR-2009-0491-2667.1, pp.5-6]
In order for the policy of "cooperative federalism" inherent in the CAA to have meaningful expression with respect to Section 110(a)(2)(D)(i)(I), states must be given adequate notice and opportunity to revise their SIPs after EPA has made the above technical and policy judgments. It is inconsistent with CAA requirements for EPA to deprive states of the opportunity to craft compliant SIPs when the agency has only now proposed definitive conclusions as to which states are responsible for abating upwind emissions, and how much each state needs to abate in order to address its significant contributions and interference with maintenance in downwind jurisdictions. For this reason, past decisions of the D.C. Circuit have held that EPA must "reset" CAA compliance deadlines where necessary EPA policy guidance is not released in a timely manner. In Natural Resources Defense Council v. EPA, for example, the D.C. Circuit determined that states should be allowed to submit enhanced vehicle inspection and maintenance standards after a deadline provided in the CAA, because delays in issuing necessary EPA guidance had prevented states from meeting the statutory deadline. 21 Here, it was impossible for any state to take meaningful action to craft a SIP that complies with Section 110(a)(2)(D)(i)(I) until EPA clarified the extent of significant contributions and interference with maintenance. Once EPA finalizes these determinations in the Transport Rule, it should therefore allow states at least eighteen months (the period provided in CAIR and the maximum period allowed under Section 110(k)(5)) to bring their SIPs into compliance before imposing a FIP. 22 This would necessitate deferring the proposed compliance deadlines for the Transport Rule by at least one year. [EPA-HQ-OAR-2009-0491-2667.1, pp.6-7]

7. See Virginia v. EPA, 108 F.3d 1397, 1409-10 (D.C. Cir. 1997) (affirming that states have primary responsibility for selecting the means of satisfying NAAQS under the CAA, and finding that EPA must defer to that prerogative when requiring SIPs to be revised to address interstate pollution); Bethlehem Steel v. Gorsuch, 742 F.2d 1028, 1036-37 (7th Cir. 1984) ("Congress has given the states the initiative and a broad responsibility regarding those means to achieve [NAAQS] through state implementation plans and timetables of compliance . . . . The Clean Air Act is an experiment in federalism, and the EPA may not run roughshod over the procedural prerogatives that the Act has reserved to the states."); Train v. Natural Resources Defense Council, 421 U.S. 60 (1975) (noting that states have primary responsibility for determining the means of meeting NAAQS under the CAA) [EPA-HQ-OAR-2009-0491-2667.1, p.4]
22. Indeed, the SIP Call is arguably the process intended by Congress in cases where EPA determines that an already-approved SIP is "substantially inadequate" because it fails to meet one of the requirements of the CAA. As EPA recently stated in a proposed SIP Call for Prevention of Significant Deterioration permitting of greenhouse gas sources, the CAA requires EPA to allow states to submit revised SIPs within a "reasonable deadline" before EPA can impose a FIP that addresses "substantial inadequacies" raised in a SIP Call. Action to Ensure Authority to Issue Permits under the Prevention of Significant Deterioration Program to Sources of Greenhouse Gas Emissions: Finding of Substantial Inadequacy and SIP Call at 26- 27 (Aug. 12, 2010). [EPA-HQ-OAR-2009-0491-2667.1, p.6]
Response: 
For the reasons explained in this section of the RTC, in section IV.C.2. of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs," EPA has a legal obligation to promulgate each FIP in this final rule.  The commenter does not identify any provision that would give EPA authority to alter the deadlines established in the statute or delay implementation of the Transport Rule as requested.  The commenter also incorrectly characterizes EPA's statements in the proposed Transport Rule regarding its authority to promulgate FIPs in this rule.  Further the statutory deadlines which the court found could be extended in the case cited by the commenter were deadlines that the court found were intended to run from the date on which EPA was required to issue guidance.  In contrast, in this case, the Act explicitly provides that the SIP submission deadline runs from the date of promulgation or revision of a NAAQS and the FIP clock starts when EPA finds that a state has failed to make a required SIP submission or EPA disapproves a SIP submission.
Finally, nothing in the Act requires EPA, where it has already made findings of failure to submit or disapproved SIP submissions, to promulgate a SIP Call to give the states another opportunity to promulgate a SIP before promulgating a FIP.  Section 110(a)(2)(D)(i)(I) SIP submittals are due 3 years after promulgation or revision of a NAAQS.  See 42 U.S.C. § 7410(a)(1).  Thus, 110(a)(2)(D)(i)(I) SIPs for the 1997 ozone and PM2.5 NAAQS were due in 2000 and 110(a)(2)(D)(i)(I) SIPs for the 2006 PM2.5 NAAQS were due in 2006.  While the statute gives EPA authority to prescribe a shorter period of time for states to make SIP submissions, it does not give EPA authority to extend the 3-year deadline established by statute.  See 42 U.S.C. § 7410(a)(1).  Moreover, there is no requirement that EPA promulgate a rule or issue guidance regarding the specific requirements of section 110(a)(2)(D)(i)(I) in advance of the SIP submittal deadline.  Thus, the cases cited by commenters for the proposition that EPA must establish a new SIP submittal deadline to give states time, following promulgation of the Transport Rule to submit SIP revisions, are inapposite.
Organization: Louisiana Chemical Association (LCA)
Comment: 
Louisiana Chemical Association (LCA)
EPA's Attempt to Adopt FIP In Lieu of Allowing Louisiana to Revise It's SIPs Violates the Clean Air Act.
The Clean Air Act Mandates that EPA Allow Louisiana to Address Potential Transport from Louisiana Sources Through a SIP.
The Clean Air Act was intended by Congress to establish a model of cooperative federalism wherein states have the primary responsibility for air pollution control and EPA is to act only in the clear absence of state action. Under CAA § 107(a), 42 USC 7407(a), the Act provides that "[e]ach State shall have the primary responsibility for assuring air quality within the entire geographic area comprising such State by submitting an implementation plan for such State which will specify the manner in which national primary and secondary ambient air quality standards will be achieved and maintained..." Under CAA §110(a)(1), 42 USC 7410(a), the Act provides that "[e]ach State shall ... adopt and submit to the Administrator, within 3 years (or such shorter period as the Administrator may prescribe) after the promulgation of a national primary ambient air quality standard ... a plan which provides for implementation, maintenance, and enforcement of such primary standard in each air quality control region (or portion thereof) within such State." [EPA-HQ-OAR-2009-0491-3527.1, p. 37; see pp. 37-38 for further discussion of this issue.]
Louisiana Adopted and EPA Approved a SIP to Address the Good Neighbor Requirements of the CAA for the 1997 Ozone and PM2.5 Standards.
On September 27, 2006, LDEQ submitted a SIP revision to EPA adopting the CAIR SO2 Trading Program to address its "good neighbor" obligations under CAA Section 110(a)(2)(D) with respect to the potential impact of Louisiana emissions on downwind PM2.5 receptors in the State of Alabama. EPA approved this SIP revision on July 20, 2007 at 72 Fed.Reg. 39741.101 On July 12, 2007, LDEQ submitted a SIP revision to EPA adopting a SIP for a CAIR NOx Trading Program to address both the 1997 8-hour ozone standard and the 1997 annual PM2.5 standard. EPA approved this SIP revision on September 28, 2007 at 72 Fed. Reg. 55064.102 LDEQ submitted amendments to its NOx CAIR SIP on July 1, 2009, which are pending before EPA for decision.  [EPA-HQ-OAR-2009-0491-3527.1, p. 38]
EPA has indicated under the proposed Transport Rule and that a CAIR SIP submission is no longer considered an adequate Section 110(a)(2)(D)(i)(I) SIP submission. 75 Fed. Reg. 45,341. EPA stated: The promulgation of this rule does not affect the right of the states to submit, for review and approval, a SIP that replaces the federal requirements of the FIP with state requirements. To replace the FIP in a state, the state's SIP must provide adequate provisions to prohibit NOx and SO2 emissions that contribute significantly to nonattainment or interfere with maintenance in another state or states. Transport Rule FIP would be in place in each covered state until a state's SIP was submitted and approved by EPA to replace a FIP. Id. EPA taking comment on all aspects of how a state could replace the Transport Rule FIP with a SIP and on what the SIP approval criteria should be.[EPA-HQ-OAR-2009-0491-3527.1, pp. 38-39]
Thus, the proposed Transport Rule purports to be a finding of insufficiency of the state SIP to the extent it is based on CAIR. This finding of insufficiency will not be final until the Transport Rule is final. Despite this, EPA proposes to enact the FIP BEFORE giving the states the full CAA mandated ability to submit their own SIPs to address the 1997 8-hour ozone NAAQS. LCA believes this is contrary to the CAA and asserts that EPA cannot enact a FIP to address any alleged impacts of Louisiana sources on the 8-hour ozone NAAQS in Texas without giving Louisiana 18 months from the final date of the Transport Rule/finding of insufficiency of its existing CAIR SIP. Note that EPA found that there was no impact from Louisiana sources with respect to the old 1997 PM2.5 NAAQS.[EPA-HQ-OAR-2009-0491-3527.1, p. 39]
Response: 
For the reasons explained in this section of this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate each of the FIPs in this final rule, including the FIPs for the state of Louisiana.  EPA disagrees with the commenter's characterization of the proposed Transport Rule.  The original findings of failure to submit 110(a)(2)(D)(i)(I) SIPs were made in 2005.  As explained above, EPA's obligation to promulgate a FIP in response to those findings can only be discharged by issuing a FIP unless certain prior conditions, which have not been met here, have been met.
Organization: Louisiana Energy and Power Authority (LEPA)
Comment: 
Louisiana Energy and Power Authority (LEPA)
In addition, the short time frame for compliance would make it impossible for states to develop, submit, and gain approval for SIPs before compliance with the FIP would be required. This violates the Clean Air Act's mandate that EPA allow Louisiana to address potential transport from Louisiana through a SIP. Section 107(a) of the Clean Air Act, 42 U.S.C. 2407(a) grants states a primary role in implementing the requirements of the law. The jurisprudence recognizes the states' primary role. See, e.g., Train v. Natural Resources Defense Council, Inc., 421 U.S. 60 (1975); Union Elec. Co. v. E.P.A., 427 U.S. 246 (1976). The EPA must allow Louisiana an adequate opportunity to adopt and submit a SIP. [EPA-HQ-OAR-2009-0491-2700.1, pp.18-19]
The state is in a better position to evaluate local electric power conditions and craft a remedy that would achieve the EPA's goals while protecting local interests. The EPA must and should extend the compliance deadline to permit Louisiana to develop a state implementation plan. [EPA-HQ-OAR-2009-0491-2700.1, p.19]
Response: 
For the reasons explained in this section of this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate all of the FIPs in this rule.
Organization: Mass Comment Campaign (221) (American Electric Power)
Comment: 
Mass Comment Campaign (221) (American Electric Power)
It also doesn't allow the states enough time to develop and put in place their own regulatory plans. Given the improvements in air quality that are already occurring, I believe the EPA can delay this rule and achieve the same environmental benefit at a much lower cost for utility ratepayers. [EPA-HQ-OAR-2009-0491-3528_Mass, p.1]
Please delay the Transport Rule and modify it with longer deadlines that won't increase costs needlessly and that allow states enough time to put in place common sense regulations. [EPA-HQ-OAR-2009-0491-3528_Mass, p.1]
Response: 
Sections VI and VII of the preamble to the final rule explain the rationale supporting EPA's decision to use the compliance deadlines in the final rule and the importance of aligning compliance dates with NAAQS attainment deadlines.  In addition, for the reasons explained in this section of this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate all of the FIPs in this rule. 
Organization: Michigan Manufacturers Association (MMA)
Indiana Builders Association 
Indiana Utility Shareholders Association
Four Flags Area Chamber of Commerce
Comment: 
Four Flags Area Chamber of Commerce
There is not enough time to develop a state implementation plan, forcing us to rely on the federal implementation plan . This is counter to the spirit of the Clean Air Act and an unneeded and hasty short-circuit of an established regulatory process. [EPA-HQ-OAR-2009-0491-3807, p.1]
Whether intentional or not, you must understand that the proposed Rule's deadlines virtually preclude the development of a state implementation plan. To formulate, post for comment, revise and finalize a credible implementation plan requires at least 12 months. The schedule EPA has proposed effectively federalizes an historical state responsibility. This short-circuits a long-standing compliance process for what appears to be little environmental benefit. The EPA should provide adequate time for affected states to create an implementation plan, post it for comment, review, and issue as final. Adequate time must then be given for power plant operators to develop plans to comply with the state rules and then implement those plans. [EPA-HQ-OAR-2009-0491-3807, p.2]
Indiana Builders Association 
The Indiana Builders Association strongly urges the EPA to delay implementation of the Transport Rule as it is proposed. [EPA-HQ-OAR-2009-0491-2871.1,p.1]
There is not enough time to develop a state implementation plan, forcing Indiana to rely on the federal implementation plan. This is counter to the spirit of the Clean Air Act and an unneeded and hasty short-circuit of an established regulatory process. [EPA-HQ-OAR-2009-0491-2871.1,p.1] [[These comments are also in Section VII.C.]]
Whether intentional or not, you must understand that the proposed Rule's deadlines virtually preclude the development of a state implementation plan. To formulate, post for comment, revise and finalize a credible implementation plan requires at least 12 months. The schedule EPA has proposed effectively federalizes an historical state responsibility. This short-circuits a long-standing compliance process for what appears to be little environmental benefit. The EPA should provide adequate time for affected states to create an implementation plan, post it for comment, review, and issue as final. Adequate time must then be given for power plant operators to develop plans to comply with the state rules and then implement those plans. [EPA-HQ-OAR-2009-0491-2871.1,p.2] [[These comments are also in Section VII.C.]]
We urge the EPA to delay the Transport Rule until there is a clear indication that comparable results cannot be achieved through CAIR. The EPA also should establish realistic deadlines that will not punish electricity consumers. [EPA-HQ-OAR-2009-0491-2871.1, p.3]
Indiana Utility Shareholders Association
Whether intentional or not, you must understand that the proposed Rule's deadlines virtually preclude the development of a state implementation plan. To formulate, post for comment, revise and finalize a credible implementation plan requires at least 12 months. The schedule EPA has proposed effectively federalizes an historical state responsibility. This short-circuits a long-standing compliance process for what appears to be little environmental benefit. The EPA should provide adequate time for affected states to create an implementation plan, post it for comment, review, and issue as final. Adequate time must then be given for power plant operators to develop plans to comply with the state rules and then implement those plans. [EPA-HQ-OAR-2009-0491-3845 p.2] [[These comments can also be found in Section VII.C.]]
Before the EPA imposes new reductions on sulfur dioxide and nitrogen oxide emissions, it should take into account the progress that the nation has made under CAIR. Though the Rule was remanded by the D.C. Circuit Court of Appeals in 2008, it remains in effect and generation companies have necessarily moved ahead with implementation of compliance measures. Before new rules are imposed on a still-weak economy, it makes more sense to determine what improvements in air quality have already occurred. To ignore the improvement the nation has made to date could impose needless substantial costs on my citizens with limited incremental environmental benefit. As we continue to climb out of recession, the last thing that government should do is create additional costs to the economy without substantiated reasons. [EPA-HQ-OAR-2009-0491-3845 p.3]
Michigan Manufacturers Association (MMA)
Whether intentional or not, the proposed Rule's deadlines virtually preclude the development of a state implementation plan. To formulate, post for comment, revise and finalize a credible implementation plan requires at least 12 months. The schedule EPA has proposed effectively federalizes a historical state responsibility. The Clean Air Act gives the states "authority to make the many sensitive technical and political choices that a pollution control regime demands." As the courts have upheld, it is the state that has primary responsibility for controlling pollution at the source. EPA's proposal short-circuits a long-standing compliance process for what appears to be little environmental benefit. The EPA should provide adequate time for affected states to create an implementation plan, post it for comment, review, and issue as final. Adequate time must then be given for power plant operators to develop plans to comply with the state rules and then implement those plans.
Michigan has used this process successfully to attain standard after standard. This is the long standing result of Michigan working to solve the problem in a way that makes both good scientific sense and sense for Michigan. [EPA-HQ-OAR-2009-0491-2762.1, p.2]
Response: 
For the reasons explained in this section of this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate all of the FIPs in this rule.  Further, sections VI and VII of the preamble to the final rule explain the rationale supporting EPA's decision to use the compliance deadlines in the final rule and the importance of aligning compliance dates with NAAQS attainment deadlines.  Also, EPA cannot leave CAIR in effect indefinitely.  It has an obligation pursuant to the D.C. Circuit opinions in the North Carolina case, to issue a rule to replace the CAIR.  This Transport Rule will replace the CAIR.  The requirements are necessary to ensure that the progress made under CAIR is sustained.
Organization: Midwest Ozone Group
Comment: 
Midwest Ozone Group
There are many legal and technical defects in the transport rule proposed by the agency, including, but not limited to, concerns over matters such as (1) the overly aggressive schedule for implementation of the CATR which is insufficient for states to develop and submit SIPs, (2) the arbitrary and unreasonable nature of the 2012 and 2014 compliance deadlines, (3) unlawfully ignoring the primary role of states in developing state implementation plans (SIPs), (4) arbitrary rejection of the monitored-plus-modeled approach used to determine downwind nonattainment areas in the CAIR and the NOx SIP Call in favor of modeling only, (5) arbitrary classification of some states as "Group 1" states and other states as "Group 2" states, (6) unreasonably stringent variability limits and assurance provisions, and (7) numerous significant errors in allowance allocations. We defer to organizations such as the Utility Air Regulatory Group and others to address these and other concerns about the rule. [EPA-HQ-OAR-2009-0491-2809.1, p.2] 
For all of the aforementioned reasons, MOG urges EPA not to finalize the proposed CATR rule and to reexamine the need for a new transport rule based on sound science. [EPA-HQ-OAR-2009-0491-2809.1, p.14]
Response: 
EPA explains the rationale for the compliance deadlines used in the final rule in sections VI and VII of the preamble to this final rule and in this RTC.  We explain the approach used to identify downwind nonattainment and maintenance areas in sections V.C. of the preamble and in this RTC.  The development of state specific emission reduction requirements and the variability limits and assurance provisions is discussed in section VI of the preamble and in this RTC.  And the allowance allocation methodology is discussed in section VII.D. of the preamble.  In addition, for the reasons explained in this section of this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate all of the FIPs in this rule.
Organization: Missouri Public Utilities Alliance (MPUA)
Comment: 
Missouri Public Utilities Alliance (MPUA)
6. EPA appears to be taking upon itself the authority to decide which local utilities will be winners and losers in the implementation of this rule by specifically identifying which units should be shut down.  For instance EPA has identified specific units owned by one of our member utilities, Independence Power and Light for zero emission allowances for a unit that is preparing to go back into service after significant refurbishment.  The legal role of EPA is to set the air pollution goals and allow the states working with local stakeholders to develop compliance plans.  The marketplace, not a governmental agency, should be making the decision based on business necessity to close down a unit. [EPA-HQ-OAR-2009-0491-2785.1, p.3]
Response: 
EPA is not, contrary to the commenter's assertion, taking action to decide which utility units should be shut down.  As explained in response to other comments in this section, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs," EPA has a legal obligation to promulgate all of the FIPs in this rule.  The statute explicitly recognizes EPA's authority to include emission trading programs in a FIP and to establish enforceable emission limitations in a FIP.  Specifically, the term "Federal Implementation Plan" is defined in section 302 of the Clean Air Act as "a plan (or portion thereof) promulgated by the Administrator to fill all or a portion of a gap or otherwise correct all or a portion of an inadequacy in a State implementation plan, and which includes enforceable emission limitations or other control measures, means or techniques (including economic incentives, such as marketable permits or auctions of emissions allowances) and provides for attainment of the relevant national ambient air quality standard."  42 U.S.C. § 7602  (emphasis added).  Any FIP that includes an economic incentive program based on marketable permits or allowances must include a mechanism for distributing such allowances.  The grant of authority to EPA to include emission trading programs in a FIP thus necessarily includes the authority to distribute allowances for use in such programs.  To implement the emission trading programs established, EPA must select a methodology to be used for allocating allowances.  EPA must determine the units which will receive allocations and how much each will receive.  Such allocation determinations affect the initial distribution of allowances but do not restrict unit owners or operators in any way from determining each unit's operation (and thus emissions) under market-based programs such as those in the Transport Rule FIPs.  The Transport Rule imposes no emission limitation on any specific unit's level of emissions aside from the requirement that sufficient allowances are held at the end of the compliance period to cover the emissions from that unit.  These allowances may be acquired either via initial allocations or they may be acquired subsequently in the marketplace.  Therefore, there is no basis for the commenter's argument that initial allocations determine a unit's ability to operate under the Transport Rule.  Indeed, as the commenter appears to prefer, the market-based programs under the Transport Rule will allow the marketplace to inform unit-level operational decisions made by unit owners and operators, who may choose their preferred operational strategies factoring in the market price of the allowances necessary to cover emissions under various operational scenarios.  Even if a unit was initially allocated a certain amount of allowances, the Transport Rule does not require those allowances to be used for that particular unit, and that unit's owner or operator can determine whether to use those allowances or sell them at their market value.  A decision to give a unit allowances would not require that unit to run.  Similarly, a decision that a particular unit should not receive an allocation of allowances would not require that the unit be shut down.  EPA believes the methodology selected for allocation of allowances under the FIP is within EPA's authority and consistent with the statutory mandate of section 110(a)(2)(D)(i)(I) as interpreted by the courts.  Furthermore, EPA believes that based on prior experience with interstate trading programs, the Transport Rule programs will offer robust allowance markets allowing unit owners and operators to determine a unit-level cost-effective emission reduction strategy that is easily compatible (via the programs' allowance trading flexibilities) with whatever initial allocations any given unit receives under the final rule's allowance allocation methodology.
Organization: National Environmental Development Association
Comment: 
National Environmental Development Association
2. EPA's Proposed CATR Rulemaking Raises Broad Administrative and Clean Air Act Procedural Concerns.  
NEDA/CAP's members are concerned about the proposed CATR rulemaking and whether EPA has followed or will follow fair procedures that meet Section 307(d) of the Clean Air Act and the Administrative Procedures Act. 42 U.S.C.§7607(d), 5 U.S.C. §§551 et seq.. First EPA has presented the proposal in such a multi-part fashion (Federal Register NPRM, supplemental information via a NODA, plus MANY pieces and parts of the rulemaking background, including critical model runs that can only be found via extensive internet searches and docket searches) that many of us have concluded that it is impossible to discern whether our review of the proposal has been comprehensive. The law requires that the public have notice of and the opportunity to comment on rulemaking proposal and provide "the factual data on which the proposed rule is based" and the methodology used in obtaining the data and in analyzing the data." Id., at §§307(d)(3)(B),(C). However, none have us believe that we have been able to complete a comprehensive review of the docket, in the time allotted. EPA has not only made several docket dumps of information following the date of proposal of the CATR rule, but two weeks ago, the Agency issued a Notice of Data Availability, extending the comment period exclusively for review of that data to October 15, 2010. 75 Fed. Reg. 53613 (Sept. 1, 2010). While we are sympathetic to the constraints under which EPA has been placed by a consent decree and court order with a schedule for reissuance of this rulemaking, NEDA/CAP believes that the Agency should provide an additional comment period for review of its proposal in order to be able to defend this rulemaking. We submit that EPA is obligated by law to provide a more orderly production of all the information on which it relies for its proposal and the opportunity for the public to review that data.  [EPA-HQ-OAR-2009-0491-2744.1 p.2]
For these reasons, NEDA/CAP asks EPA to confirm that if and when it includes industrial sources of these pollutants in proposed FIPs, affected industrial sources will be provided an opportunity to comment on the proposed modeling and methodology on which such future proposal is based. Not only would it be grossly unfair for EPA to claim that industries that might be affected in the future would be precluded from having the opportunity to critique the technical basis for this rulemaking for utilities, but we would maintain that it would be a violation of the Clean Air Act and otherwise unlawful for EPA to fail to provide procedural opportunities to comment on these issues in a future rulemaking that directly affects them. [EPA-HQ-OAR-2009-0491-2744.1 p.3]
Response: 
As explained in the preamble to the final rule, EPA has complied with the requirements of 307(d) including the applicable notice and comment requirements in that section.  EPA also made significant efforts to reach out to stakeholders both prior to and during the comment period on the proposal.  EPA placed all information and documents on which the proposed rule was based in the docket for this rulemaking prior to publication of the proposal.  Additional data and information was provided through three subsequent Notices of Data Availability.  All data and information related to the NODAs was placed in the docket prior to publication of the NODAs.  In addition to being available in the docket at www.regulations.gov, EPA placed many of the key documents on its website to make it easier for stakeholders to identify and find key documents.  EPA staff have been available to answer, and have answered numerous questions about the rulemaking.  EPA will also comply with all procedural requirements applicable to any future rulemakings relating to interstate transport issues.
Organization: National Mining Association (NMA)
Comment: 
National Mining Association (NMA)
EPA's 2012 and 2014 Deadlines Result in the Usurpation of State Authority under the Clean Air Act
The federalist nature of the Clean Air Act is well-established. EPA sets standards, and states implement those standards through SIPs. Only if states do not submit an adequate SIP may EPA step in and impose a Federal Implementation Plan (FIP). [EPA-HQ-OAR-2009-0491-2868.1,p.17]
Under Section 110(c)(1), EPA may impose a FIP within two years after EPA (a) finds that a state has failed to make a required SIP submission or finds that the SIP does not satisfy the minimum criteria under section 110 or (b) disapproves a SIP, unless the State corrects the deficiency. Under Section 110(k)(5), if EPA finds that a SIP fails "to mitigate adequately pollution transport" as may be found by EPA under Sections 176A or 184, "[t]he Administrator shall require the State to revise the plan as necessary to correct such inadequacies." Further, "[t]he Administrator shall notify the State of the inadequacies, and may establish reasonable deadlines ... for the submission of such plan revisions." [EPA-HQ-OAR-2009-0491-2868.1,p.17]
Thus, where as here, EPA has made findings that states are significantly contributing to the interstate transport of pollution, the required procedure is for EPA to so notify the states and to give them an adequate opportunity to submit a SIP revision. If those SIP submissions are inadequate, EPA may impose a FIP. Here, EPA has improperly reversed the procedure and skipped directly to imposition of a FIP. [EPA-HQ-OAR-2009-0491-2868.1, p.18]
EPA's reason for doing so, again, is its rush to begin phase one as of 2012. But EPA's policy interest does not permit it to ignore plain statutory language. Moreover, EPA's statement that imposition of FIPs "would in no way affect the rights of states to submit ... a SIP that replaced the federal requirements of the FIP with a state requirement"42 has it exactly backwards. The opportunity for a SIP precedes the FIP; it doesn't follow it. [EPA-HQ-OAR-2009-0491-2868.1,p.18]
EPA seeks to justify immediate imposition of FIPs on the ground that EPA, as a part of CAIR, found that states were significantly contributing to downwind NAAQS nonattainment and therefore already had been given more than the required amount of time to submit conforming SIPs. But, as EPA recognizes, the states fully complied with the requirements that EPA imposed. As EPA states, following EPA's interstate transport findings, EPA in CAIR called for states to cure their SIP deficiencies by submitting SIP revisions that complied with the standards set forth in CAIR. The states did so, and EPA approved their SIPs. The only reason why states could be said to be in violation of CAA interstate transport requirements is because CAIR was overturned in Court. But that was not the state's fault; it was EPA's. Case law supports a "resetting of the deadline clock" where, as here, states cannot meet their statutory obligations because of EPA's failure to carry out its CAA responsibilities. NRDC v. EPA, 22 F.3d 1125 (D.C. Cir. 1994). [EPA-HQ-OAR-2009-0491-2868.1,p.18]
In short, EPA's imposition of FIPs is improper. EPA should extend the time for compliance with its phase one and two requirements and allow states adequate time to formulate conforming SIPs. [EPA-HQ-OAR-2009-0491-2868.1,p.18]
Response: 
For the reasons explained in this section of this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate each of the FIPs in this final rule.  Sections VI and VII of the preamble to the final rule explain EPA's decision to use the compliance dates in the final rule.  Among other things, EPA has an obligation to align the compliance dates with the attainment deadlines for the relevant NAAQS.
Organization: National Rural Electric Cooperative Association (NRECA)
Michigan Municipal Electric Association (MMEA)
Nelson Industrial Steam Company (NISCO)
Luminant
Comment: 
Luminant
:: States will not be able to adequately prepare a State Implementation Plan for interstate transport based on the new timeline in the proposed rule, thus forcing them into accepting the Federal Implementation Plan program. That is an inappropriate outcome that usurps the states' role under the CAA. [EPA-HQ-OAR-2009-0491-2729.1, p.2]
V. The Timeline for Implementing CATR is Too Short for Any State.
EPA proposed to finalize the CATR Federal Implementation Plan (FIP) in mid-2011 with the program beginning in 2012. This schedule does not give states the opportunity to develop their own State Implementation Plan (SIP) for addressing significant contributions to nonattainment areas in downwind states. Luminant believes that EPA should give states the time to prepare SIP rules or rules to adopt the FIP by reference. [EPA-HQ-OAR-2009-0491-2729.1, p.7]
Michigan Municipal Electric Association (MMEA)
6.) Conform to the mandate and structure of the Clean Air Act by allowing meaningful time and opportunity for States to develop State Implementation Plans  -  and State administered unit-specific allowance allocation programs  -  to implement the Transport Rule. [EPA-HQ-OAR-2009-0491-2828.1, p.16]
National Rural Electric Cooperative Association (NRECA)
The Clean Air Act (CAA) mandates that states be given a reasonable opportunity to develop their own plans through the state implementation plan (SIP) process to address interstate transport. The proposal fails to do this and is, therefore, unlawful. [EPA-HQ-OAR-2009-0491-2723.1, p.1]
Nelson Industrial Steam Company (NISCO)
II. EPA Should Allow Louisiana Sufficient Time to Submit a SIP in Lieu of the Proposed FIP
The Clean Air Act was intended by Congress to establish a model of cooperative federalism wherein states have the primary responsibility for air pollution control and EPA is to act only in the clear absence of state action. This is not one of those cases. Louisiana has acted to prevent interstate transport of emissions that could affect attainment of NAAQS in downwind states and should be given a reasonable opportunity to submit any necessary SIP improvements. EPA's preemptive action of proposing this SIP does not provide Louisiana with the deference accorded to states under the Clean Air Act. [EPA-HQ-OAR-2009-0491-2813.1, pp.8-9]
[For additional comments pertaining to this topic, see pages 9-11 of this comment.]
Response: 
As explained in this section of the RTC, in section IV of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs," EPA has a legal obligation to promulgate the FIPs in this final rule.  Further, in section VI of the preamble to the final rule, EPA explains the rationale behind the compliance dates in the final rule.  Section VII also explains the importance of aligning compliance dates with NAAQS attainment deadlines.
Organization: NextEra Energy, Inc.
Comment: 
NextEra Energy, Inc.
The use of a Federal Implementation Plans (FIP) to implement the program is authorized under the Clean Air Act. While states have authority to, and may, submit State Implementation Plans (SIPs) to replace the FIP, we agree with EPA's assertion that due to time concerns, states are unlikely to be able to complete these plans before implementation of the Transport Rule on January 1, 2012. [EPA-HQ-OAR-2009-0491-2718.1, p.2]
Response: 
EPA agrees with the commenter that EPA has authority, under the Clean Air Act, to promulgate the FIPs included in this final action.
Organization: North Carolina Department of Environment and Natural Resources
Comment: 
North Carolina Department of Environment and Natural Resources
Further, NCDAQ appreciates EPA's attempts to expedite implementation of the FTR by proposing a Federal Implementation Plan (FlP), Due to the long delay since some of the interstate impacts to be addressed by the FIP were first identified, the needs of the impacted States are now uniquely pressing, But EPA must also recognize that under the Clean Air Act Congress has invested primary responsibility for air quality control with the States - both upwind and downwind States. Therefore, EPA should take care that the upwind States are permitted to exercise their right to tailor their own programs and should appropriate adequate resources to working constructively and expeditiously with States on their SIP submittals. While a FIP approach is satisfactory to NCDAQ for this FTR, it should not be construed as support for using this approach for the second FTR aimed at addressing the pending revision to the 8-hour ozone standard. NCDAQ suggests the simplest and most defensible way to effectuate the mandate in §110(a)(2)(D)(i)(I) is for EPA to determine each State's significant contribution level and then allow the State to determine how to reduce its emissions to a level below that. [EPA-HQ-OAR-2009-0491-2767.1, pp. 1-2]
Response: 
EPA appreciates NCDAQ's support.  As explained in section X of the preamble to the final rule, EPA seeks to make it easier for states to submit SIPs to replace the FIPS in whole or in part, and EPA intends to work with States and provide assistance with SIP submittals. 
Organization: Northwest Indiana Forum
Comment: 
Northwest Indiana Forum
The long standing regulatory process whereby individual states have the authority and opportunity to develop implementation rules and regulations by which compliance with federal rules can occur has been undermined by this proposed rulemaking. Historically as states proceed with their regulatory development process, state agencies are required to obtain stakeholder input on a process or rule. With this opportunity, local stakeholders are presented a clear understanding of the issue, the desired outcome, the environmental and economic impact of proposed rules and regulations as well as a responsibility to participate in the implementation and compliance activities. Whether it is air, water or solid waste related, the general public not only has an interest in the outcome but a responsibility to be part of the solution via personal habit alterations. Northwest Indiana residents have been supportive of ozone action days and had to comply with enhanced vehicle inspection and maintenance program requirements for many years. In partnership with industrial air pollution control implementation, Northwest Indiana has seen significant air quality improvements which have resulted in an attainment status for our counties. Without the opportunity for our state regulatory agency, Indiana Department ,of Environmental Management (IDEM), to develop a state implementation plan, IDEM will be forced to utilize a one size fits all approach developed without a true stakeholder involvement process which in general is not a successful approach. [EPA-HQ-OAR-2009-0491-3650 p.1]
Response: 
For the reasons explained in this section of this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate all of the FIPs in this rule.  EPA has made a concerted effort to solicit input, both prior to proposal and during the comment period on the proposed rule, from stakeholders including states, regulated industry, tribes, environmental groups, and the general public.  Further section X of the preamble to the final rule explains the steps taken to make it easier for states to replace the FIPs, in whole or in part, with SIPs.
Organization: Ohio Utility Group (OUG)
Comment: 
Ohio Utility Group (OUG)
The Proposed Transport Rule Unlawfully Expands EPA's Authority at the States' Expense
EPA's actions under the proposed Transport Rule are unlawful, arbitrary, and unreasonable. In its current form, the Transport Rule will have a negative impact on the electric utility industry in ways that are yet to be fully considered by EPA. [EPA-HQ-OAR-2009-0491-2679.1, p.1] 
EPA overstepped its bounds with respect to transport obligations and has attempted to federalize a state responsibility. The Clean Air Act ('CAA') requires that all states achieve attainment status of the National Ambient Air Quality Standards ('NAAQS') for the six criteria pollutants. While EPA has been assigned the responsibility to determine appropriate air quality standards, the CAA gives each state the primary authority to determine how it will meet the standards, and requires states to submit implementation plans detailing a particular state's approach. The Supreme Court addressed the federal-state relationship under the CAA and held that, in the context of implementing emissions limitations to achieve air quality standards, EPA's role is 'secondary' to that of the states. EPA's breach of this partnership is twofold. First, the timing requirements under the proposed Transport Rule effectively deny the states the opportunity to develop and submit a SIP for final approval. Second, the substance of the proposed rule impermissibly allows EPA to impose source-specific emissions controls. [EPA-HQ-OAR-2009-0491-2679.1, pp.1-2]
The Transport Rule impermissibly requires unit-specific emissions controls [EPA-HQ-OAR-2009-0491-2679.1, p.2]
Due to state-specific concerns and specialized knowledge required to impose emissions limitations at the source level, the CAA gives states the 'power to [initially] determine which sources would be burdened by regulation and to what extent.,,6 Again, EPA is limited to a secondary role in determining source-specific emissions limitations.7 EPA simply does not have the capabilities to acquire the amount of information necessary to make unit-by-unit emissions limitation decisions. Although the Utilities' objections to EPA's flawed methodology and inadequate data are analyzed in a subsequent section of the comments, a learned understanding of those issues is not necessary at this point. By merely conceptualizing the magnitude of the task, the pitfalls of EPA engaging in implementing emissions limitations at the source level  -  a responsibility appropriately delegated to the states - are readily apparent. [EPA-HQ-OAR-2009-0491-2679.1, pp.2-3]
OUG members have felt the effects of EPA's blind leap into the highly technical realm of state implementation. The Dayton Power and Light Company ('DP&L') is an Ohio public utility that owns generation units and provides electric distribution services to deliver electric energy to approximately 500,000 customers in west-central Ohio. Two of its largest facilities, the Stuart Station, comprised of four generating units with an aggregated capacity of approximately 2400 Megawatts (MW) and the Killen Station, comprised of one 600 MW generating unit, each face emissions limitations that are unachievable with their current Nox control equipment. [EPA-HQ-OAR-2009-0491-2679.1, p.3]
The Stuart Station is subject to a 2009 consent decree that sets NOx limits at 0.17Ibs/mmBtu with an expectation that additional control equipment would be installed and that NOx would be limited to 0.10 Ibs/mmBtu by January 2015. However, under the proposed Transport Rule, the Stuart Station is required to comply with an unrealistic emissions budget level of less than 0.06 Ibs/mmBtu by January 2012. The end result is equally unrealistic for the Killen Station. Killen had an SCR installed in 2003 that was designed to achieve 0.12IbNOx/mmBtu. The proposed rule provides Killen a budget allocation that assumes that it could operate at less than 0.06 Ib-NOx/mmBtu level, far below its current capability. [EPA-HQ-OAR-2009-0491-2679.1, p.3]
The Ohio Valley Electric Corporation ('OVEC') faces similar consequences. OVEC does not dispute the NOx controls EPA assumes for the five Kyger Creek units - each being equipped with SCRs and over fire air. However, the emissions limitations imposed on Kyger Creek under the proposed rule place the facility in a position of assured failure. Comparing estimated annual NOx emissions at historic heat inputs to proposed Transport Rule allocations illustrates the severity of the problem. For example, in 2009, Kyger Creek's estimated Nox emissions were .098 Ib/mmBtu, and 3,229.5 tons; under the proposed transport rule, Kyger Creek would have received allocations for only 2,939 tons, an equivalent of .089 Ib/mmBtu. [EPA-HQ-OAR-2009-0491-2679.1, p.3]
With respect to FGD controls, EPA defaulted to a 98% removal criteria. However, are view of the most recent data shows that 98% removal is ambitious even for the newest technology and would be nearly impossible for units with older FGD equipment. For example, members of the American Electric Power system ('AEP') have units equipped with FGD systems proven effective in reducing emissions, but simply cannot achieve the reductions in the required timeframe under the proposed rule. AEP suggests that the scrubber efficiency at Gavin Units 1 and 2 be reduced to 94.5%. Furthermore, the most recent information from Duke Energy at the co-owned Zimmer unit indicates a scrubber efficiency of 93%. The effectiveness of all equipment is subject to several variables such as vintage and design. As such, the Utilities object to the appropriateness of defaulting one all-encompassing removal criteria, especially one as high as 98%. [EPA-HQ-OAR-2009-0491-2679.1, p.3]
The precision and acute level of detail associated with regulating at the source level manifests itself in all aspects of EGU operations, and the importance of maintaining accuracy cannot be ignored. One faulty assumption can have a detrimental impact on the facility. Furthermore, a mistake at one unit creates a ripple effect for all units across the state. Ohio officials have familiarity with the operational tendencies of the EGUs operating within the state and, thus, are better positioned to negotiate the intricacies of unit-by-unit emissions limitations. [EPA-HQ-OAR-2009-0491-2679.1, pp.3-4]
The impact of this rule is far greater than EPA seems to appreciate. EPA has exceeded its authority under the CAA, attempting to federalize a state responsibility. Furthermore, EPA has made several incorrect assumptions which have a direct effect on a state's 'significant contribution,' cost thresholds, and budget allocations. EPA's faulty assumptions have also caused EPA to gloss over several practical implications. Most notably, recent modeling performed by MaG shows that less stringent emissions reductions are appropriate. To avoid any negative effects, EPA should revise the rule according to the Utilities' suggestions. [EPA-HQ-OAR-2009-0491-2679.1, p.8]
Response: 
For the reasons explained in this section of this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate all of the FIPs in this rule.  The statute also explicitly recognizes that a FIP promulgated by EPA may include emission trading programs and enforceable emission limitations.  See, 42 U.S.C. § 7602(y) (definition of a FIP).  Further, the final Transport Rule does not establish source specific emission limits, but instead establishes an interstate emissions trading program with assurance provisions to ensure the required reductions occur within each covered state.  The initial allocations of allowances to units in the trading programs do not determine the permissible level of operation or emissions for a particular unit as allowances may be acquired either via initial allocations or they may be acquired subsequently in the marketplace.  The specific allowance allocation methodology selected for use in the final rule is explained in section VII.D of the preamble to the final rule.
In response to comments regarding removal efficiency assumptions, EPA made some changes to the assumptions used in the modeling for the final rule.  These issues are discussed in the IPM v.4 documentation entitled "Documentation Supplement for EPA Base Case v. 4.10_FTransport-Updates for Final Transport Rule" and in the RTC appendix section entitled "Transport Rule IPM Assumptions Response to Comments."
Organization: Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
Comment: 
Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
The states that have not received a notice of deficiency must be given the opportunity afforded by the Act to revise their SIPs to correct the flaws in CAIR identified by the court in North Carolina v. EPA. EPA's NODA proposal regarding SIPs does not acknowledge this process. EPA must follow the process prescribed by law. [EPA-HQ-OAR-2009-0491-4010[1].1, p.7]
Legal Deficiencies in EPA's Proposed Transport Rule [EPA-HQ-OAR-2009-0491-2803.1, p.9]
In addition to the serious problems identified above in the application of the proposed rules to the Kyger Creek and Clifty Creek plants, the proposed rules are also substantially flawed in the following respects. [EPA-HQ-OAR-2009-0491-2803.1, p.9]
EPA May Not Proceed with a Federal Implementation Plan without First Finding that the State Implementation Plans are Deficient and Providing an Opportunity to the States to Address the Deficiencies [EPA-HQ-OAR-2009-0491-2803.1, p.9]
A fundamental legal flaw in the proposal is that it is presented as a federal implementation plan that will take immediate effect. That is directly contrary to Section 110(k)(5) of the Act, providing that when a state plan is inadequate with regard to interstate transport, the Administrator 'shall require the State to revise the plan as necessary to correct such inadequacies. The Administrator shall notify the State of the inadequacies, and may establish reasonable deadlines. .. for submission of such plan revisions.' (Emphasis added.) These procedures are mandatory, and may not be circumvented through immediate imposition of a federal plan. Indeed, a federal plan may not be imposed prior to two years after the Administrator finds that a state plan is deficient or disapproves a state plan that is submitted for approval, Section 110(c). Thus, this proposed federal plan may not be lawfully imposed on states that presently have approved plans that have not been subsequently found by the Administrator to be. deficient. [EPA-HQ-OAR-2009-0491-2803.1, pp.9-10]
Both Ohio (as to the Kyger Creek plant) and Indiana (as to the Clifty Creek plant) currently have approved interstate transport implementation plans for which there have been no subsequent notices of deficiency by the Administrator. Ohio recently received a 'full SIP' approval on September 25, 2009 for its rules that fully implement CAIR. 74 Fed. Reg. 48,857. This was preceded by approval of a partial ('abbreviated') SIP on February 1, 2008, consisting of state rules that implemented a portion of CAIR. 73 Fed.Reg. 6,034. Indiana received an abbreviated SIP approval of a portion of CAIR on October 22,2007. 72 Fed. Reg. 59,480. None of these approved transport SIPs have been found to be deficient by the Administrator. Accordingly, all remain in place and effective in these states, and still apply to the Kyger Creek and Clifty Creek plants. [EPA-HQ-OAR-2009-0491-2803.1, p.10]
As to the 2006 NAAQS establishing a 24-hour standard for fine particulates, both Ohio and Indiana submitted transport plans that are under review. On June 9, 2010, EPA published a notice to those states that had not submitted transport plans, which did not include Ohio or Indiana, and informed those states that the deficiency notice 'establishes a 2-year deadline for promulgation by EPA of a FIP, in accordance with Section 11 0(c)(1), for any state that either does not submit or EPA cannot approve a SIP.' 75 Fed. Reg. 32,673. Thus, in that notice, EPA clearly acknowledged the applicability of the process by which EPA must first find a state SIP to be deficient before it may proceed, after two years, to promulgate a federal plan. [EPA-HQ-OAR-2009-0491-2803.1, p.10]
EPA's proposal argues that the Administrator may dispense with the mandatory procedure of finding those plans to be deficient and providing Ohio and Indiana the opportunity to revise their SIPs to address the deficiencies before proceeding with a federal implementation plan, due to the court's decision in North Carolina v. EPA, 531F.3d 896 (D.C.Cir., 2008) that found CAIR to be unlawful. 75 Fed. Reg. 45,341,45,342. EPA reasons that this judicial disapproval of federal CAIR rules in effect also nullified the Administrator's approval of state SIPs that implemented CAIR, and restored the status quo ante of the Administrator's pre-CAIR notice of deficiency of state transport SIPs that were issued in 2005. But this reliance upon the court's decision in North Carolina to disregard language in the Act is wholly misplaced. Although the court's decision surely gave the Administrator grounds for finding deficient those state CAIR based SIPs that the Administrator had approved (including Ohio's and Indiana's), the decision did not authorize the Administrator to disregard her statutory duty to issue such notices of deficiency and allow the states to submit new plans prior to imposing a federal plan. Moreover, that mandated process is not an empty exercise. Ohio, Indiana, and all similarly-situated states, must be given the opportunity afforded by the Act to revise their SIPs to correct the flaws in CAIR identified by the court in its decision. The states should be allowed to fashion a plan that meets the requirements of law in a manner that, in the states' judgment (not EPA's), best conforms to the states' preferences and regulatory policies. EPA may not lawfully skip over that process and proceed immediately to a federal plan. [EPA-HQ-OAR-2009-0491-2803.1, pp.10-11]
Accordingly, EPA should withdraw this proposal and proceed with the process required by the Act. [EPA-HQ-OAR-2009-0491-2803.1, p.11]
The 2012/2014 Emission Reduction Deadlines Are Unattainable, Unreasonable, and Not Mandated by Law [EPA-HQ-OAR-2009-0491-2779.1, p.11]
As discussed above, the emission reduction deadlines cannot be met at the Kyger Creek and Clifty Creek plants. Moreover, they are not mandated by law. Section 110(c) provides no constraints on the Administrator in setting deadlines for achieving emission reductions mandated by a federal plan. Thus, the Administrator must choose deadlines that are practically achievable, and neither arbitrary nor capricious. The deadlines in this proposed plan must therefore be extended to provide a reasonable opportunity to affected facilities to install required emission reduction technology. [EPA-HQ-OAR-2009-0491-2779.1, p.11]
The rationale for the deadlines offered by EPA in the preamble is inadequate. EPA explains that the deadlines were selected so that emissions would be reduced on or before the dates for attaining the 1997 and 2006 ambient air quality standards in the areas affected by the upwind emissions. 75 Fed. Reg. 45,300, 45,301. However, the Act does not mandate that emission reductions in a federal plan that is imposed as a substitute for an inadequate state plan must be achieved on or before NMOS attainment dates. The Act could not rationally do so, since such dates may have passed before the Administrator finds a state plan to be deficient and imposes a federal plan to address the deficiency. In the present circumstance, the federal plan is proposed prior to the attainment dates, but so close to those dates that emission reductions cannot practically be achieved in advance of those dates. Importantly, any failure to meet attainment dates cannot be blamed on failure to mitigate interstate transport in accordance with federally approved transport plans in Ohio and Indiana. In such a circumstance, to require emission reductions on or before the NMOS attainment dates rather than when the reductions can be practically achieved is surely arbitrary and capricious. [EPA-HQ-OAR-2009-0491-2779.1, p.11]
Contrary to preamble, the court in North Carolina v. EPA did not hold that emission reduction deadlines in a federal plan must always precede applicable NMOS attainment dates. The court found that state plans must prevent significant contribution to downwind nonattainment by the NMOS attainment deadline, and faulted EPA for failing to 'make any effort to harmonize CAIR's Phase Two deadline' with the 2010 NMOS attainment date. North Carolina, 531 F.3d. at 912. However, the court did not hold that the NAAQS attainment date is an inflexible legally mandated deadline for all federal plans imposed as a substitute for deficient state plans. In the present situation, in which a federal plan is proposed too close to NAAQS attainment dates to allow emitters to reduce emission by those dates, surely the court would not demand the impossible and disapprove the federal plan. Congress could not possibly have intended that result, and the text of the Act does not require it. [EPA-HQ-OAR-2009-0491-2779.1, pp.11-12]
Accordingly, EPA should extend the emission reduction deadlines to provide adequate time to reduce emissions. [EPA-HQ-OAR-2009-0491-2779.1, p.12]
Response: 
As explained above, the question of whether EPA has authority to promulgate each FIP in this action must be evaluated on a FIP by FIP basis as the states covered by the Transport Rule are not similarly situated with respect to the 110(a)(2)(D)(i)(I) SIP requirements, and individual states are not always similarly situated with respect to the 110(a)(2)(D)(i)(I) SIP requirements for different pollutants.  EPA explains in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs" the reasons why EPA has a legal obligation to promulgate all of the FIPs in this rule, including the FIPs addressing the requirements of 110(a)(2)(D)(i)(I) with respect to the 1997 ozone NAAQS, the 1997 PM2.5 NAAQS and the 2006 PM2.5 NAAQS for Indiana, and the FIPs addressing the requirements of 110(a)(2)(D)(i)(I) with respect to the 1997 ozone NAAQS, the 1997 PM2.5 NAAQS and the 2006 PM2.5 NAAQS for Ohio.  Further, sections VI and VII of the preamble to the final rule explain the rationale supporting EPA's decision to use the compliance deadlines in the final rule and the importance of aligning compliance dates with NAAQS attainment deadlines.
Organization: Oklahoma Gas & Electric Company (OG&E)
Comment: 
Oklahoma Gas & Electric Company (OG&E)
OG&E hereby incorporates the comments submitted by The Class of ' 85 Regulatory Response Group on the Proposed Transport Rule. OG&E also submits these additional comments separately to emphasize its concern regarding the unique position that Oklahoma is in with respect to EPA's authority for this action. As discussed in more detail below, EPA cannot adopt the Proposed Rule for Oklahoma because the normal procedure set forth in the Clean Air Act ('CAA') for state implementation of minimum federal requirements have not been observed. [EPA-HQ-OAR-2009-0491-2708.1, p.1]
In the Transport Rule, EPA proposes to finalize a Federal Implementation Plan ('FIP') to address interstate transport for sources in the State of Oklahoma without ever providing the State a meaningful opportunity to develop a State Implementation Plan ('SIP') addressing interstate transport requirements under CAA section 110(a)(2)(D)(i)(II). EPA claims the promulgation of this FIP 'would in no way affect the right of states to submit ... a SIP that replaced the federal requirements of a FIP ... ' 75 Fed. Reg. at 45,342. EPA's reasoning, however, is plainly contrary to the background for this proposed rulemaking and the language of the CAA. [EPA-HQ-OAR-2009-0491-2708.1, p.2]
A basic tenet of the CAA is that EPA may promulgate FIPs only where states fail to develop and submit SIPs that meet minimum federal requirements. Among the minimum criteria a SIP must satisfy are the two 'good neighbor' provisions in section 110(a)(2)(D)(i) of the Act. First, a SIP must prohibit sources in the state from contributing significantly to nonattainment in, or interfering with maintenance by, any other state with the NAAQS. CAA § 110(a)(2)(D)(i)(I). Second, a SIP must prohibit sources from interfering with measures in any other state's SIP to prevent significant deterioration ('PSD') or protect visibility. CAA § 110(a)(2)(D)(i)(1I). [EPA-HQ-OAR-2009-0491-2708.1, p.2]
The Act contemplates that EPA may develop a FIP for these requirements only after states have been given a meaningful opportunity to develop and submit SIPs. In CAA section 110(a)(2), the Act vests states, not EPA, with primary responsibility for developing requirements for interstate transport. CAA 110(a)(2). Where a state initially fails to fulfill its responsibility, the Act directs EPA to 'require the State to revise the plan as necessary to correct such inadequacies.' CAA § 110(k)(5). EPA must 'notify the State of the inadequacies, and may establish reasonable deadlines . .. for the submission of such plan revisions' ld. (emphasis added). After undergoing these procedures, EPA has authority to promulgate a FIP two years after the Administrator (i) finds that a state has failed to submit a SIP or has submitted a SIP that does not satisfy the minimum criteria set forth in section 110 of the Act; or (ii) disapproves a SIP in whole or in part, unless the state has corrected the deficiency and the Administrator has approved the SIP. CAA § 110(c)(l). [EPA-HQ-OAR-2009-0491-2708.1, p.2]
On April 25, 2005, EPA issued a general finding that all 50 states, the District of Columbia, and three U.S. territories had failed to submit SIPs to satisfy the interstate transport requirements of CAA section 110(a)(2)(D)(i) for the 1997 ozone and PM2.5 National Ambient Air Quality Standards ('NAAQS'). 70 Fed. Reg. 21,147. The finding did not specify how each state failed to satisfy one or both of the good neighbor provisions in CAA section 110. Rather, EPA provided only general notice that no state had submitted any SIP revision to address interstate transport. [EPA-HQ-OAR-2009-0491-2708.1, p.2]
One month after issuing the SIP finding of deficiency, however, EPA provided a definitive finding on the first of the good neighbor provisions dealing with NAAQS compliance. The final Clean Air Interstate Rule ('CAIR'), issued May 12, 2005, identified those states which EPA found were required to submit a SIP revision to comply with the first of the CAA 'good neighbor' provisions in CAA section 110(a)(2)(D)(i)(I). See 70 Fed. Reg. 25,162, 25,319 ('the Administrator determines that each State identified in paragraph (c)(I) and (3) of this section must submit a SIP revision to comply with the requirements of section 110(a)(2)(D)(i)(I) of the CAA ....'). The State of Oklahoma was not included on the list and, as a result, never developed a CAIR SIP. The State fulfilled its responsibilities for the other 'good neighbor' provision, dealing with PSD and visibility, by submitting a SIP revision to EPA on May I, 2007. EPA issued a proposed rule to approve that SIP revision on September 17, 2010. 75 Fed. Reg. 56,923. [EPA-HQ-OAR-2009-0491-2708.1, p.2]
In the Proposed Transport Rule, EPA incorrectly claims that its general finding of SIP deficiency in 2005 'remain[s] in force' for states, like Oklahoma, that were not covered by CAIR. 75 Fed. Reg. at 45,342. EPA ignores the fact that the 2005 finding did not provide any state-specific information, whereas the final CAIR specifically identified which states were required to submit SIP revisions under CAA section 110(a)(2)(D)(i)(I). Oklahoma was not included on the list and, therefore, had no cause to develop an interstate transport SIP to implement section 110(a)(2)(D)(i)(I). The general finding of deficiency in 2005 also could not be used to support the adoption of the Transport Rule for Oklahoma under section 110(a)(2)(D)(i)(II) because EPA recently proposed approval of a SIP to address those requirements. [EPA-HQ-OAR-2009-0491-2708.1, p.3]
EPA may not promulgate a FIP for the State of Oklahoma under CAA section 110(a)(2)(D)(i)(II) where the State has never before been found to require a SIP revision for interference with NAAQS compliance in other states. The CAA does not allow EPA to leapfrog state authority in this fashion. Instead, Oklahoma must be given a meaningful opportunity to develop a SIP revision to comply with CAA section 110(a)(2)(D)(i)(1) before EPA may promulgate a FIP for the State. [EPA-HQ-OAR-2009-0491-2708.1, p.3]
Response: 
For the reasons explained in this section of this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate each of the FIPs in this final rule.  Further the commenter misrepresents the requirements of section 110(a)(2)(D)(i)(I) of the Clean Air Act.  This section requires all states to submit SIPs sufficient to prohibit all emissions within the state that significantly contribute to nonattainment or interfere with maintenance of the NAAQS in another state.  This requirement, like the findings of failure to submit made in 2005, applies equally to all states. 
Organization: Pfeiff, Mike
Comment: 
Pfeiff, Mike
8. Beyond Existing Statutory Authority - The EPA unlawfully derives it's authority to regulate SO2 emitted EGUs in the Proposed Transport Rule from section 110(a)(2)(D) of the CAA. 75 Fed. Reg. at 45,218. Section 100(a)(2)(D) requires State Implementation Plans ('SIPs') to ...
contain adequate provisions - (i) prohibiting, consistent with the provisions of this subchapter, any source or other type of emissions activity within the State from emitting any air pollutant in amounts which will - (I) contribute significantly to nonattainment in, or interfere with maintenance by, any other State with respect to any [National Ambient Air Quality Standards]. [EPA-HQ-OAR-2009-0491-2742.1, p.7]
[For additional comments pertaining to Beyond Existing Statutory Authority, see pages 7-8 of this comment.]
I request that the EPA provide the legal rational to regulate EGU S02 emissions under the Proposed Transport Rule without any evidence of SO2 NAAQS violations. I further request the EPA to provide legal rational for its contention that it has the authority to issue new regulations for EGU regulations when existing CAA statutes clearly set forth specific regulations for S02 for this source category. [EPA-HQ-OAR-2009-0491-2742.1, p.8]
9. Existing Statutory Solution to Interstate Transport Pollution - Section 126(b) of the CAA, provides the EPA with a mechanism for dealing with the interstate transport of pollution. Section 126(b) provides states or political subdivisions with the option to petition the Administrator of the EPA for relief from pollution transported into their jurisdiction. Under section l26(b) the EPA has the obligation to make a finding within 60 days. [EPA-HQ-OAR-2009-0491-2742.1, p.8]
I request that the EPA explain why it has the discretion to not fulfill its existing statutory obligation under section 126(b) and instead elect to establish a massive and complex new government program for emissions from a source for which the CAA provides clear language for the structure of regulations. [EPA-HQ-OAR-2009-0491-2742.1, p.8]
10. Provide Congress with a Legislative Solution - During multiple recent testimony before the United States Senate Clean Air and Nuclear Safety subcommittee hearings since CAIR was vacated by the DC Circuit Court of Appeals, various members of Congress have asked EPA officials what additional new statutory authorities the EPA needed to promulgate a replacement rule for CAIR in a way that preserves the spirit of the market oriented program previously established by Congress in Title IV of the CAA. In response to these queries from Congress, EPA officials gave the standard 'at this time we are continuing to do analysis so I don't know and will have to get back to you Senator' answer. Remarkably, to this date the EPA has completely disregarded, at least publicly, these inquire from Congress. While Congress' inquires are suggesting of the importance in preserving the spirit of the Title IV program, the EPA's Transport Rule seems to be purposely dismantling it despite Congress's expressed desire to consider granting authorities. The EPA has claimed that they have worked with Congress by providing analytical support by modeling various legislative solutions proposed by Senator Tom Carper but the EPA has not officially provided answers to Congress questions. [EPA-HQ-OAR-2009-0491-2742.1, p.8]
I request that the EPA answer Congresses repeated request to provide it with the required new authorities needed to promulgate a CAIR replacement rule that operated in harmony with the existing ARP established by Title IV of the CAA. [EPA-HQ-OAR-2009-0491-2742.1, p.8]
Response: 
EPA appreciates your interest in this rule and in protection of the environment.  For the reasons explained in this section of this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate all of the FIPs in this rule.  EPA has an obligation to implement the Clean Air Act as enacted by Congress.  EPA does not have authority to alter requirements in the Act.  EPA's obligation to promulgate FIPs must be discharged unless a state submits a SIP that cures the existing SIP deficiency and EPA approves such a SIP.  Finally, as explained in greater detail in section V.A. of the preamble to the final rule, EPA regulates SO2 in this action because it is a PM2.5 precursor. 
Organization: PPG Industries, Inc.
Comment: 
PPG Industries, Inc.
EPA Should Allow Louisiana Sufficient Time to Submit a SIP in Lieu of the Proposed FIP  The Clean Air Act was intended by Congress to establish a model of cooperative federalism wherein states have the primary responsibility for air pollution control and EPA is to act only in the clear absence of state action. This is not one of those cases. Louisiana has acted to prevent interstate transport of emissions that could affect attainment of NAAQS ind downwind states and should be given a reasonable opportunity to submit any necessary SIP improvements. EPA's preemptive action of proposing this SIP does not provide Louisiana with the deference accorded to states under the Clean Air Act.[EPA-HQ-OAR-2009-0491-2763.1, p. 8; see pp. 8-11 for extensive discussion of this issue.]
Response: 
This final rule is consistent with and implements the system of cooperative federalism established in the Clean Air Act.  For the reasons explained in this section of this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate all of the FIPs in this rule. 
Organization: Progress Energy Service Company
Comment: 
Progress Energy Service Company
A later initial compliance date also would allow sufficient time for states to develop State Implementation Plans (SIPs) for implementation of the Transport Rule and therefore avoid the need for EPA to promulgate the rule as a Federal Implementation Program (FIP). The opportunity to replace federal requirements with a state plan at some point in the future does not satisfy the requirement that EPA allow the opportunity for states to craft their own plans, at the outset of the program, to comply with the Transport Rule. EPA's proposal would effectively bypass the states, at least with respect to the first phase of the program. The following section elaborates further on the SIP/FIP process as set forth by Congress. [EPA-HQ-OAR-2009-0491-2831.1 p.3-4] [[These comments can also be found in Section VII.C.]]
The CAA contemplates that states will have the opportunity to develop SIPs and to submit them to EPA for review and approval before implementation of a new or revised NAAQS. According to the CAA, EPA may promulgate a FIP within two years after the Administrator (i) finds that a state has failed to submit a SIP or has submitted a SIP that does not satisfy the minimum criteria set forth in section 110 the Act, or (ii) disapproves a SIP in whole or in part, unless the state corrects the deficiency. CAA § 110(c)(l). Section 110 states that:
Whenever the Administrator finds that the [SIP] for any area is substantially inadequate to attain or maintain the relevant fNAAQS], to mitigate adequately the interstate pol/urion transport described in [section 176A or section 184 of the Act], or to otherwise comply with any requirement of [the Act], the Administrator shall require the State to revise the plan as necessary to correct such inadequacies. The Administrator shall notify the State of the inadequacies, and may establish reasonable deadlines ... for the submission of such plan revisions. [EPA-HQ-OAR-2009-0491-2831.1 p.4]
CAA § 11O(k)(S) (emphasis added). The CAA grants no authority to EPA to promulgate a FIP without first giving the states an opportunity to develop and submit SIPs. Thus, the Proposed Transport Rule FIPs are contrary to the tenns of the CAA and would abrogate the rights of the states that Congress established. [EPA-HQ-OAR-2009-0491-2831.1 p.4]
Response: 
For the reasons explained in this section of this RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate all of the FIPs in this rule.  Further, sections VI and VII of the preamble to the final rule explain the rationale supporting EPA's decision to use the compliance deadlines in the final rule and the importance of aligning compliance dates with NAAQS attainment deadlines.
Organization: PSEG Services Corporation
Comment: 
PSEG Services Corporation
PSEG believes the proposed Transport Rule appropriately addresses the legal requirements set out in the D.C. Circuit's decision vacating the Clean Air Interstate Rule ("CAIR"), North Carolina v. EPA. As noted above, the Clean Air Act requires states to ensure they do not significantly contribute to downwind states' nonattainment and interference with maintenance. The proposed rule satisfies that legal obligation and addresses the additional flaws identified by the D.C. Circuit. [EPA-HQ-OAR-2009-0491-2627.1, p.3]
The use of Federal Implementation Plans ("FIPs") to implement the program is authorized under the Clean Air Act. While states have authority to, and may, submit State Implementation Plans ("SIPs") to replace the FIPs, we agree with EPA's assertion that due to time concerns, states are unlikely to be able to complete these plans before implementation of the Transport Rule on January 1, 2012. We believe it is very important to engage the Transport Rule in 2012. [EPA-HQ-OAR-2009-0491-2627.1, p.3]
Response: 
EPA agrees with the commenter that EPA has authority, under the Clean Air Act, to promulgate the FIPs included in this final action.
Organization: San Miguel Electric Cooperative, Inc.
South Carolina Department of Health and Environmental Control 
Comment: 
San Miguel Electric Cooperative, Inc.
 The Clean Air Act (CAA) mandates that states be given a reasonable opportunity to develop their own plans through the state implementation plan (SIP) process to address interstate transport. The proposal implements an FIP with a possible SIP in the future. States should be given the opportunity to implement an SIP, using CAA guidelines, with an FIP as the back up for states not implementing an SIP.  [EPA-HQ-OAR-2009-0491-2641.1, p.6] 
South Carolina Department of Health and Environmental Control 
DHEC contends that a FIP is unnecessary, and it implies that a state has not met its Clean Air Act obligations. States are required to submit SIPs that address CAA section 110(a)(2) three years after the promulgation of a new NAAQS. If states fail to submit SIPs that address section 110(a)(2), then the EPA can issue a FIP. In the proposed Transport Rule, the EPA contends that SIP submittals that rely on the CAIR to address CAA section 110(a)(2), even SIPs that the EPA has approved, fail to meet the requirements of section 110(a)(2) because of the Court's remand of the CAIR.37 The EPA is proposing to usurp states' role in this important part of air quality management, not because of any failure by the states, but because of the Court's remand of an EPA rule. DHEC would rather address the Transport Rule through a SIP, as it did under the CAIR. Even though the EPA has indicated it will not impose any sanctions with this FIP,38 DHEC prefers the local control and flexibility that the SIP offers over a centralized FIP. DHEC recognizes that the EPA is concerned about the delay that Transport Rule SIPs would cause. If that concern over a delay is insurmountable and the EPA promulgates this final rule as a FIP, then DHEC requests that the EPA also allow states to use the SIP process to implement Transport Rule II, the rule that will incorporate the emissions reductions required to meet the 2010 Ozone Standard. [EPA-HQ-OAR-2009-0491-2677.1 p.17]
Response: 
As explained in this section of the RTC, in section IV of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs," EPA has a legal obligation to promulgate the FIPs in this final rule. 
Organization: Santee Cooper
Comment: 
Santee Cooper
EPA either should determine that the Transport Rule provides a basis for denying North Carolina's pending Section 126 petition, or explain why it does not. [EPA-HQ-OAR-2009-0491-2820.1, p.2]
EPA should give states sufficient opportunity to prepare State Implementation Plans (SIPs) before imposing Federal Implementation Plans (FIPs). [EPA-HQ-OAR-2009-0491-2820.1, p.11]
EPA EITHER SHOULD DETERMINE THAT THE TRANSPORT RULE PROVIDES A BASIS FOR DENYING NORTH CAROLINA'S SECTION 126 PETITION, OR EXPLAIN WHY IT DOES NOT. [EPA-HQ-OAR-2009-0491-2820.1, p.11]
In a 2006 rulemaking, EPA denied a section 126 petition from the State of North Carolina. The North Carolina petition had asserted that EGUs in several states were complicating North Carolina's attainment of the 1997 National Ambient Air Quality Standard (NAAQS) for fine particulate matter and the 1997 NAAQS for 8-hour ozone. EPA denied North Carolina's petition on the grounds that the CAIR would provide a complete remedy to North Carolina's transport concerns. The Agency explained: 'once EPA has taken action to eliminate the SIP deficiencies by approving SIPs which implement CAIR (i.e., which eliminate the significant contribution), or itself promulgates a CAIR FIP for states with SIP deficiencies, there is no longer a cause of action under section 126." EPA adopted a similar approach in the NOx SIP Call, denying eight section 126 petitions on the basis of promulgation of a SIP call that would remedy the alleged transport problems; the Agency further asserted that it was appropriate to defer direct federal action under Section 126 as long as states were on track with the process of revising SIPs to comply with requirements to address transport. [EPA-HQ-OAR-2009-0491-2820.1, p.13]
The State of North Carolina was one of the parties that petitioned for review of the CAIR, raising several objections to its legal validity. After the D.C. Circuit remanded the CAIR in the North Carolina decision, the court subsequently remanded for reconsideration the Agency's denial of North Carolina's section 126 petition. In its remand, the court observed that EPA had conceded that the invalidation of the CAIR had eliminated the legal basis of the agency's denial of the North Carolina petition. [EPA-HQ-OAR-2009-0491-2820.1, p.12]
The proposed Transport Rule purports to respond to the North Carolina decision, including the objections raised by the State of North Carolina itself. Among other things, the EPA proposal includes deeper reductions in SO2 and NOx emissions than were required under the CAIR, establishes a different approach to emissions trading, and addresses the requirement that State Implementation Plans ensure that sources do not 'interfere with maintenance' requirement in section 110 of the Act. In these respects, it appears to address all of North Carolina's claims regarding the invalidity and inadequacy of the CAIR as a transport remedy. Yet, the proposed Transport Rule is silent on North Carolina's section 126 petition. [EPA-HQ-OAR-2009-0491-2820.1, p.12]
As with the BART requirements, the proposed Transport Rule's silence regarding North Carolina's section 126 petition casts a shadow of uncertainty over compliance planning by states and utilities. The failure to address the petition also represents a missed opportunity for coordinating and rationalizing what EPA itself has acknowledged are a significant number of new environmental rules and obligations coming at the power sector in the next two years. [EPA-HQ-OAR-2009-0491-2820.1, p.12]
For these reasons, Santee Cooper urges the Agency either to determine that the Transport Rule provides a legal basis for denial of North Carolina's section 126 petition with respect to the 1997 fine particulate matter and 8-hour ozone NAAQS - or explain why it does not. [EPA-HQ-OAR-2009-0491-2820.1, p.12]
EPA SHOULD GIVE STATES SUFFICIENT OPPORTUNITY TO PREPARE SIPs BEFORE IMPOSING FIPs. [EPA-HQ-OAR-2009-0491-2820.1, p.12]
Under the proposed Transport Rule, EPA all but immediately imposes Federal Implementation Plans (FIPs) on the covered states, depriving them of an opportunity to develop State Implementation Plans (SIPs) that could address interstate transport. This arrangement violates the policy of 'cooperative federalism' that is a bedrock principle of the Act. In addition, the Agency fails to provide sufficient guidance for states to develop SIPs. Santee Cooper respectfully urges EPA to extend the compliance deadlines in the proposed Transport Rule to give states an opportunity to develop their own SIPs, and to offer the guidance needed for SIP development. [EPA-HQ-OAR-2009-0491-2820.1, p.13]
Section 110 of the CAA provides states with a default period of three years from the promulgation of a NAAQS to submit a SIP that 'provides for the implementation, maintenance, and enforcement' of the NAAQS, including 'adequate provisions' to prohibit sources within the state from significantly contributing to nonattainment or interfering with the maintenance of attainment in any other state. EPA's authority to impose a FIP exists only to the extent a state has failed to submit an adequate SIP. [EPA-HQ-OAR-2009-0491-2820.1, p.13]
The Federal courts have consistently held that the cooperative federalism structure of the Act gives states primary responsibility for determining how they will meet the NAAQS, including selecting the means of addressing interstate transport. SIP authority provides states with the opportunity to 'focus their reduction efforts on local needs or preferences,' thereby allowing for a fairer and more efficient regulatory program. [EPA-HQ-OAR-2009-0491-2820.1, p.13]
Indeed, in the NOx SIP Call, EPA itself acknowledged that 'Congress' clear preference throughout Title I is that states are to decide and plan how they will control their sources of air pollution, and the mechanism for imposing those controls at the state level is SIPS." Citing this principle, EPA first allowed states in the NOx SIP Call to revise their SIPs to address interstate ozone transport before imposing direct federal emission controls under Section 126. Furthermore, under the CAIR, EPA gave states a full 18 months to develop SIPs, and an overall lead time of four years before the start date for emission reductions. [EPA-HQ-OAR-2009-0491-2820.1, p.14]
The proposed Transport Rule represents a substantial and inappropriate departure from these previous interstate transport regulations and court decisions; it would impose a FIP approximately six to nine months after promulgation. EPA itself acknowledges that SIP revisions typically require three years to prepare and approximately six months to approve. Since the Transport Rule is likely to be finalized in mid-20l1 and FIPs would take effect in 2012, there is almost no chance that states subject to the Transport Rule could revise and approve their SIPs in time to avoid the imposition of the FIP. This result is inconsistent with past practice under the CAIR and the NOx SIP Call, and is also inconsistent with the 'clear preference' of Congress that states be given primary responsibility through the SIP process for fashioning emission control requirements. [EPA-HQ-OAR-2009-0491-2820.1, p.14]
EPA asserts, in defending its upending of state authority, that the Agency made findings of unsatisfactory SIPs with respect to the 1997 NAAQS for ozone and PM2.5 in the CAIR, and has made further findings with respect to the 2006 NAAQS for PM2.5 in the proposed Transport Rule itself. Yet, EPA fails to acknowledge that the states have not submitted satisfactory SIPs because, unlike other SIP elements, the section 110 prohibition on interstate transport cannot reasonably be addressed in a SIP without EPA's technical and policy analysis. [EPA-HQ-OAR-2009-0491-2820.1, pp.14-15]
After CAIR was remanded to EPA, states could not reasonably be expected to guess how the Agency would adjust its technical approaches to transport determinations under section 110(a)(2)(D). Indeed, in the proposed Transport Rule, EPA has made substantial modifications to its methodology for determining which states contribute to downwind nonattainment and interference with maintenance, including: (l) revised screening thresholds for states with minimal interstate emissions, (2) modifications to the process for projecting future ozone and PM2.5 concentrations, and (3) the modeling approach used to determine the magnitude of the impact of upwind emissions on air quality in downwind states. [EPA-HQ-OAR-2009-0491-2820.1, p.15]
Furthermore, as EPA itself recognizes in the preamble to the Transport Rule, the prohibition in Section 110(a)(2)(D) necessarily involves a policy determination about each state's relative responsibility to abate its share of many states' collective contribution. EPA observes that the interpretation of 'significant contribution' and 'interfere with maintenance' in the CAA 'inherently involves a policy decision on how much emissions control responsibility should be assigned to upwind states, and how much responsibility should be left to downwind states." Without EPA's policy judgment on this issue, no state could determine the extent to which it needs to revise its SIP. [EPA-HQ-OAR-2009-0491-2820.1, p.15]
Not only has EPA provided insufficient time for the covered states, it has also provided insufficient guidance. The proposed Transport Rule contains relatively little information states could use to develop their own SIPs. [EPA-HQ-OAR-2009-0491-2820.1, p.15]
Accordingly, in order to respect the principle of 'cooperative federalism' in the context of Section 110(a)(2)(D), EPA should give the states sufficient notice, opportunity, and guidance to revise their SIPs after EPA has made the threshold technical and policy judgments. To this end, Santee Cooper urges EPA first to finalize its analysis in the Transport Rule and then allow states a minimum of 18 months (the maximum period authorized under section 110(k)(5)) for states to submit satisfactory SIPs. [EPA-HQ-OAR-2009-0491-2820.1, p.16]
For the reasons outlined above, Santee Cooper respectfully requests that EPA provide more guidance and time for states to develop SIPs to address interstate transport, and also to extend the compliance deadlines for the proposed Transport Rule as necessary to accommodate SIP development. [EPA-HQ-OAR-2009-0491-2820.1, p.17]
STATES SHOULD BE ALLOWED TO REQUEST AN ALTERNATIVE ALLOWANCE ALLOCATION METHODOLOGY IN APPLICABLE FIPs [EPA-HQ-OAR-2009-0491-2820.1, p.30]
If EPA does not alter the compliance deadlines in the final Transport Rule, and thereby prevents states from submitting revised SIPs, EPAs in time to prevent the imposition of FIPs, Santee Cooper believes that EPA should create an informal process for incorporating state preferences on allowance allocations into FIPs. As noted above, EPA's proposed default method for allocating allowances among EGUs ensures that EGUs with the greatest demand for allowances (those with the highest NOx and S02 - 30- emissions) receive relatively more allowances. This method also disadvantages EGUs that have made significant investments in conversion to cleaner fuels and installations of pollution-control equipment. Allocation raises sensitive issues of equity that are best left to individual states to decide. [EPA-HQ-OAR-2009-0491-2820.1, pp.30-31]
Because states are in a superior position to decide how allowances should be allocated to EGUs within their jurisdictions, EPA should at least provide an informal avenue for states to submit their desired allowance allocation methodologies to EPA for inclusion in the Transport Rule FIPs. This mechanism would be akin to the process by which EPA has recently requested that states recommend a 'reasonable deadline' for submitting revised SIPs addressing authority to issue PSD permits that include greenhouse gas limitations. Such informal submissions would allow states to have voice in the allowance allocation process even if they are not able to revise their SIPs before the Transport Rule takes effect. [EPA-HQ-OAR-2009-0491-2820.1, p.31]
Response: 
EPA agrees with the commenter that the Transport Rule resolves the flaws in CAIR identified by the court in North Carolina v. EPA.  In addition, As explained in this section of the RTC, in section IV of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs," EPA has a legal obligation to promulgate the FIPs in this final rule.  EPA does not have a legal obligation to respond, in this particular rulemaking, to any petitions submitted pursuant to section 126 of the CAA.  Further, in section VI of the preamble to the final rule, EPA explains the rationale behind the compliance dates in the final rule.  Section VII also explains the importance of aligning compliance dates with NAAQS attainment deadlines. Also, in the final rule, EPA has created a process that would allow states to submit "abbreviated" SIPs to begin allocating allowances starting with vintage 2013 allowances. 
Organization: Southeastern States Air Resource Managers (SESARM)
Comment: 
Southeastern States Air Resource Managers (SESARM)
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.44.]
Number five, authority must be maintained to allow for states to implement additional programs necessary to address attainment and maintenance issues within their borders.
Number six, timely guidance from EPA is extremely critical to implementation of the final Transport Rule. This guidance should be issued concurrent with finalization of the rule.
Response: 
Section 116 of the Clean Air Act explicitly addresses retention of state authority and generally protects, in most instances, the authority of states to adopt or enforce emission standards or limitations at least as stringent as federal standards and limits.  EPA will work with states, industry and the public to facilitate smooth implementation of the Transport Rule. 
Organization: Southern California Edison Company
Comment: 
Southern California Edison Company
SCE recognizes that EPA has been seriously constrained in its options for addressing SO2 transport by the 2008 Court of Appeals decision on the Clean Air Interstate Rule (CAIR) in North Carolina v. EPA. However, it is ironic -- and appears of doubtful legality to SCE -- that CATR, EPA's response to the North Carolina decision, would essentially override Title IV (statutorily created by Congress) and would have an economic impact on the Title IV cap and trade program at least as dramatic as CAIR's adjustment of the Title IV SO2 allowance-to-emission ratio that the court held invalid in North Carolina as being beyond EPA's regulatory authority. [EPA-HQ-OAR-2009-0491-2852.1 p.2]
Response: 
As noted by the commenter, the D.C. Circuit held that EPA lacks authority to terminate or limit Title IV allowances through a trading program under section 110(a)(2)(D), North Carolina, 531 F.3d at 921, and that EPA does not have authority, under such a program, to remove Title IV allowances from circulation in the Title IV market,  id. at 922.  EPA sought to limit the value of certain Title IV allowances in CAIR, among other things, in order to ensure that Title IV allowances would retain value following promulgation of that rule.  In this rule, EPA is not taking any action to either terminate or limit any Title IV allowances.  While this rule (as well as other rules promulgated subsequent to passage of Title IV) may impact the value of Title IV allowances, the Title IV program, including the requirement for sources to hold Title IV allowances, continues in full force and effect and is not modified in any respects by this rule.
Organization: Southern Company
Comment: 
Southern Company
VIII. The Proposed Transport Rule Should Not be Structured as a FIP
As explained more fully in UARG's comments, the Clean Air Act does not give EPA the authority to promulgate a FIP before allowing the states to submit a SIP. The opportunity to replace a FIP with a SIP at some point in the future does not satisfy EPA's obligation to provide states an opportunity to craft their own plans at the outset of the program. EPA may issue a FIP, 'rescind[ing] state authority,' only after a state fails to develop and submit a complete SIP and receive Agency approval of it. The Act grants no authority to EPA to promulgate a FIP without first giving the states adequate time and a real opportunity to develop and submit SIPs that reflect each state's 'sensitive ... choices' on how to implement section 110 (a)(2)(D)(i)(I). EPA has no authority to leapfrog over the SIP process and impose its own choices on states and regulated parties. [EPA-HQ-OAR-2009-0491-2864.1, p. 22]
Response: 
As explained in this section of the RTC, in section IV of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs," EPA has a legal obligation to promulgate the FIPs in this final rule. 
Organization: Southern Environmental Law Center
Comment: 
Southern Environmental Law Center
Footnote 1. In these comments, we do not take a position on whether or to what extent the Transport Rule proposal would satisfy EPA's obligation to a downwind state seeking remedy under §126 of the Clean Air Act, 42 U.S.C. §7426, from the same interstate air pollution addressed in the Transport Rule. [EPA-HQ-OAR-2009-0491-2801.1, p.1]
Response: 
No response to this comment is necessary because the commenter is not taking a position on the issue.
Organization: Southern IL Power Cooperative
Comment: 
Southern IL Power Cooperative
EPA's proposed FIP is contrary to the Clean Air Act (CAA) because it does not give states the opportunity to submit SIPs conforming to the proposed CATR's overall state reduction mandates. States have up to 3 years to submit SIPs to remedy interstate transport, in this case to meet proposed CATR reduction mandates. (Section 110(a)) This period should begin to run when EPA issues a final CATR, since CAIR, the original transport rule, has been determined to be invalid by the court. The clean air act does not allow EPA to determine source or unit obligations, only to determine statewide reduction levels. [EPA-HQ-OAR-2009-0491-2863.1 p.4]
Response: 
As explained in this section of the RTC, in section IV of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs," EPA has a legal obligation to promulgate the FIPs in this final rule.  The commenter cites to no CAA authority for the proposition that the 3 year deadline for submitting SIPs should run from the date EPA issues this rule.  Section 110(a)(1) of the CAA explicitly provides that the SIPs are due within 3 years (or such shorter period as the Administrator may prescribe) after the promulgation of a national primary ambient air quality standard (or any revision thereof). 
Organization: State of Louisiana, Department of Environmental Quality
Comment: 
State of Louisiana, Department of Environmental Quality
LDEQ appreciates the time and effort extended by all parties to bring about federal control measures on nitrogen oxide (NOx) and sulfur dioxide (S02); however, the ultimate responsibility for attaining ambient air quality standards still rests with the state and local clean air agencies. Following this premise, LDEQ respectfully submits the following comments on this proposed rule. [EPA.HQ-OAR-2009-0491-2655.1, p.1]
Response: 
EPA thanks LDEQ for their support.  EPA believes the final rule is consistent with the requirements of the Clean Air Act including the system of cooperative federalism established therein. 
Organization: State of Missouri Department of Natural Resources
Comment: 
State of Missouri Department of Natural Resources
Also, Missouri requests that the implementation date after the rule becomes effective be extended to provide adequate time to work with Missouri utilities to develop state-specific elements such as allocations that are fair and reasonable. [EPA-HQ-OAR-2009-0491-3806, p.1]
Response: 
As explained in this section of the RTC, in section IV.C.2 of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)i)(I) SIPs," EPA has a legal obligation to promulgate all of the FIPs in this rule.  EPA explains in section X of the preamble to the final rule, the steps taken to make it easier for states to replace the FIPs, in whole or in part. 
Organization: State of Ohio Environmental Protection Agency (Ohio EPA)
Comment: 
State of Ohio Environmental Protection Agency (Ohio EPA)
0hio EPA also has concerns with the proposed Federal Implementation Plan (FIP) process. U.S. EPA must ensure states are able to address the transport of pollutants through Section 110 of the Clean Air Act, via a State Implementation Plan, and provide sufficient guidance to ensure approvability. [EPA-HQ-OAR-2009-0491-2793.2, p. 11]
Although we understand the need for emission reductions as soon as possible, this 'FIP first' approach usurps the fundamental right of the states to develop their own SIP. Section 110 of the Clean Air Act identifies the responsibility of states, as part of their implementation plan, to provide the provisions addressing the transport of pollutants that may contribute to nonattainment or interfere with maintenance. The U.S. EPA proposal goes into detail on how states are free to develop state plans as alternatives to the FIP, but also makes clear that U.S. EPA does not believe the proposed time line provides sufficient time for state plans to be developed and is also unsure about the appropriate criteria for approval of these state plans. In other words, states are free to start work on their own plans, but cannot be certain as to their approvability until U.S. EPA finalizes those criteria, which will undoubtedly take some time. In our view, this 'FIP first' approach is inconsistent with the structure of the Clean Air Act that places the responsibility of attaining ambient air quality standards with the states. For states that choose to develop a SIP, it is essential that U.S. EPA provide appropriate and timely guidance to ensure that approval of a SIP could occur by . 2012. It is also essential that U.S. EPA provide flexibility to states in developing a SIP. States should be free to implement an allowance structure that provides incentives, such as energy efficiency, provided state budgets remain intact and consistent with U.S. EPA's final rule. [EPA-HQ-OAR-2009-0491-2793.2, p. 11]
Response: 
As explained in this section of the RTC, in section IV of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs," EPA has a legal obligation to promulgate the FIPs in this final rule.  As explained in section X of the preamble, EPA has taken steps to make it easier for states to submit and get EPA approval of SIPs to replace the FIPs promulgated in this action, in whole or in part.
Organization: Tennessee Valley Authority (TVA)
Comment: 
Tennessee Valley Authority (TVA)
Equally important, this additional time provides states the opportunity to develop SIPs and have them approved using the three-year deadline for CAA § 110(a)(2)(D)(i)(I) interstate transport SIP submissions. [EPA-HQ-OAR-2009-0491-2782.1, pp. 4-5] [[This comment can also be found in Section VII.C.]]
Response: 
As explained in this section of the RTC, in section IV of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs," EPA has a legal obligation to promulgate the FIPs in this final rule.  As explained in section X of the preamble, EPA has taken steps to make it easier for states to submit and get EPA approval of SIPs to replace the FIPs promulgated in this action, in whole or in part.
Organization: Texas Commission on Environmental Quality
Comment: 
Texas Commission on Environmental Quality
The TCEQ is concerned with the EPA's efforts to usurp state responsibility and authority with regard to the issue of transport and Section 1l0(a)(2)(D)(i)(I) of the Federal Clean Air Act (FCAA). The TCEQ finds that the EPA's intent to address transport requirements for states for any revised National Ambient Air Quality Standards (NAAQS), prior to states themselves being afforded the opportunity to do so, is contrary to the intent of the FCAA.  [EPA-HQ-OAR-2009-0491-2857.1, p.1]
The EPA is usurping state responsibility and authority with regard to the issue oftransport and Section 11o(a)(2)(D)(i)(I) ofthe FCAA. As the EPA asserts, Section 1l0(a)(2)(D)(i)(I) of the FCAA obligates states to prohibit emissions that contribute significantly to nonattainment, or interfere with maintenance by, any other state with respect to the NAAQS. However, Section 1l0(a)(2)(D)(i)(I) is clearly a requirement for inclusion in the state implementation plans that states are required to submit under Section 1l0(a)(1). The writers of the FCAA clearly envisioned that states would be given the opportunity to implement local controls as necessary to address transport impacts to other states. While the EPA indicates that it has determined or proposed to determine that the 32 states covered by the proposed Transport Rule have not submitted SIP revisions adequate to meet the requirements of Section llo(a)(2)(D)(i)(I), the EPA does not plan to limit this approach to just the 1997 and 2006 PM2 .S NAAQS and the 1997 ozone NAAQS. The EPA has indicated (75 FR 45213) that future revisions to NAAQS may necessitate revisions to the Transport Rule with greater reductions from the sources covered under the proposed Transport Rule or possibly from states or different source categories not included in the current proposal. Based on this statement, the EPA has apparently predetermined that no states will ever be in compliance with Section 1l0(a)(2)(D)(i)(I) of the FCAA. Therefore, the EPA has apparently assumed sole responsibility and authority for Section llo(a)(2)(D)(i)(I). The TCEQ argues that such an action is contrary to the intent of the FCAA. [EPA-HQ-OAR-2009-0491-2857.2, p.2]
Response: 
For the reasons explained in this section of the RTC, in section IV.C.2 of the preamble to the final rule and in the TSD describing the status of CAA 110(a)(2)(D)(i)(I) SIPs, EPA has a legal obligation to promulgate the FIPs in this rule.  The question of whether EPA has authority for a specific FIP can only be determined by examining the status of the 110(a)(2)(D)(i)(I) SIP requirements for a particular state with respect to a particular NAAQS.  EPA has not taken any final action with regard to the transport requirements related to any future NAAQS or taken any position on the regulatory mechanism that would be used to address transport requirements related to any future NAAQS. 
Organization: TransCanada
Comment: 
TransCanada
Comment 5: EPA Should Consider Allowing States to Implement the Proposed Transport Rule Through SIPs Instead of FIPs
The proposed Transport Rule, instead of directing the states to prepare SIPs, if desired, to document how the requirements of the proposed Transport Rule will be implemented, requires that the proposed Transport Rule be implemented through FIPs established by EPA. CAIR and the NOx SIP calls, however, allowed the affected states to prepare SIPs to implement the programs. [EPA-HQ-OAR-2009-0491-2827.1, p.3]
EPA should consider providing states the opportunity to establish SIPs, if desired, to implement the requirements of the proposed Transport Rule. This would allow the states, including New York, to, among other things, allocate allowances among the units within the State. Giving states the opportunity to implement federal Clean Air Act ("CAA") requirements in a way that takes into account a state's particular situation, is a benefit of CAA regulation that should be considered by EPA. [EPA-HQ-OAR-2009-0491-2827.1, p.4]
Response: 
As explained in this section of the RTC, in section IV of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs," EPA has a legal obligation to promulgate the FIPs in this final rule.  As explained in section X of the preamble, EPA has taken steps to make it easier for states to submit and get EPA approval of SIPs to replace the FIPs promulgated in this action, in whole or in part.
Organization: Utility Air Regulatory Group (UARG)
Comment: 
Utility Air Regulatory Group (UARG)
The Proposed Transport Rule is intended to replace the Clean Air Interstate Rule, 70 Fed. Reg. 25162 (May 12, 2005) ("CAIR"), which EPA promulgated in 2005 and the U.S. Court of Appeals for the D.C. Circuit found to be "fundamentally flawed," initially vacated and remanded to the Agency in 2008, and then allowed to remain in place pending completion of EPA's remand rulemaking. See North Carolina v. EPA, 531 F.3d 896, 929 (D.C. Cir. 2008), modified on petitions for rehearing, 550 F.3d 1176 (D.C. Cir. 2008). Like CAIR, the Proposed Transport Rule primarily addresses EGUs and is based on EPA's interpretation and application of section 110(a)(2)(D)(i)(I) of the Act, which requires, in relevant part, each state's plan for attaining the national ambient air quality standards ("NAAQS") to "contain adequate provisions . . . prohibiting . . . any source or other type of emissions activity within the State from emitting any air pollutant in amounts which will . . . contribute significantly to nonattainment in, or interfere with maintenance by, any other State with respect to any [NAAQS]." [EPA-HQ-OAR-2009-0491-2756.1, pp.7-8]  
EPA's task in developing this proposed rule was to remedy the deficiencies identified by the court in North Carolina v. EPA. To an extent, EPA appears to have attempted to discharge that obligation. Indeed, as discussed in section II of these comments, UARG agrees with certain aspects of the proposal.[EPA-HQ-OAR-2009-0491-2756.1, p.9]  
Yet in other respects, EPA's proposed approach is seriously misguided. The decision to impose FIPs rather than allow states time to develop state implementation plans ("SIPs") to implement section 110(a)(2)(D)(i)(I) obligations rests on an unlawful view of the CAA and the federal-state cooperative relationship under the Act.[EPA-HQ-OAR-2009-0491-2756.1,p.9]  
And EPA in this proposed rule has arrogated to itself, in contravention of the law, the right and responsibility to determine how a state's emission reduction requirements must be accomplished, thereby assuming an exceptionally heavy burden to show that it has applied its unit allowance allocation methodology accurately and consistently. Review of the PTR's supporting information, however, reveals that EPA's approach on this score is anything but accurate and consistent. [EPA-HQ-OAR-2009-0491-2756.1, p.9]  
In addition, EPA states in the proposed rule that it intends to propose additional interstate transport determinations in the future as EPA revises the NAAQS for PM2.5 and ozone, and that these proposals "could require greater emissions reductions from states covered by [the Proposed Transport Rule] and/or require reductions from states not covered" by the current proposal. 75 Fed. Reg. at 45213/3. It would be very difficult for states and electric generating companies to plan for compliance with a rule under which the standards of compliance change along with the frequent changes to the ambient standards. EPA should keep state budgets (and allowance allocations, to the extent EPA sets allowance allocations) as constant as possible, revising them only when essential and in a way that provides ample time for compliance, rather than changing them sporadically each time EPA revises a NAAQS. [EPA-HQ-OAR-2009-0491-2756.1, p.19]  
Finally, the proposed rule -- and especially its 2012 first-phase compliance date -- is fundamentally inconsistent with the CAA because it effectively deprives states of the time they need to develop, submit, and receive EPA approval of SIPs before the program begins. See section IV infra. [EPA-HQ-OAR-2009-0491-2756.1, p.19]
EPA unabashedly proposes the Transport Rule as a FIP rule. Indeed, promulgation and implementation of the Transport Rule pursuant to the schedule that EPA proposes would make it nearly impossible for states to develop, submit, and receive EPA approval of SIPs in time to use them for implementation of the first phase of the program. EPA's assertion that promulgation of FIPs "would in no way affect the right of states to submit . . . a SIP that replaces the federal requirements of the FIP with state requirements," 75 Fed. Reg. at 45342/2, misses the point. The opportunity to replace federal requirements with a state plan at some point in the future does not satisfy the requirement that EPA allow the opportunity for states to develop their own plans, at the outset of the program, to comply with the Transport Rule. EPA's proposal would effectively bypass the states, at least with respect to the first phase of the program. This is unsupported by anything in the proposed rule and is contrary to the Act. [EPA-HQ-OAR-2009-0491-2756.1, p.24]  
The CAA contemplates that states must be given a meaningful opportunity to develop SIPs and to submit them to EPA for review and approval before implementation of a new or revised NAAQS. CAA § 110(a)(1). See also CAA § 101(a)(3) ("air pollution control at its source is the primary responsibility of States and local governments"); CAA § 107(a) ("Each State shall have the primary responsibility for assuring air quality within the entire geographic area comprising such State by submitting an implementation plan for such State which will specify the manner in which national primary and secondary ambient air quality standards will be achieved and maintained within each air quality control region in such State"). The CAA provides that EPA may promulgate a FIP within two years after the Administrator (i) finds that a state has failed to submit a SIP or has submitted a SIP that does not satisfy the minimum criteria set forth in section 110 of the Act, or (ii) disapproves a SIP in whole or in part, unless the state has corrected the deficiency and the Administrator has approved the SIP. CAA § 110(c)(1). With respect to interstate air pollution, section 110(a)(2) provides that each state shall, in the first instance, submit a SIP to EPA that "contain[s] adequate provisions" prohibiting the emissions proscribed by section 110(a)(2)(D)(i). And section 110(k)(5) of the Act states that:  
Whenever the Administrator finds that the [SIP] for any area is substantially inadequate to attain or maintain the relevant [NAAQS], to mitigate adequately the interstate pollutant transport described in [section 176A or section 184 of the Act], or to otherwise comply with any requirement of [the Act], the Administrator shall require the State to revise the plan as necessary to correct such inadequacies. The Administrator shall notify the State of the inadequacies, and may establish reasonable deadlines . . . for the submission of such plan revisions. CAA § 110(k)(5) (emphasis added). [EPA-HQ-OAR-2009-0491-2756.1, pp.24-25]  
Although EPA undoubtedly has a role in implementation of NAAQS, including interstate transport requirements, that role is plainly "secondary." Train v. Natural Res. Def. Council, 421 U.S. 60, 79 (1975). The D.C. Circuit has interpreted the "partnership between EPA and the states for the attainment and maintenance of national air quality goals," as set forth in the Act, as follows: "The states are responsible in the first instance for meeting the NAAQS through state-designed plans that provide for attainment, maintenance and enforcement of the NAAQS."  Natural Res. Def. Council v. Browner, 57 F.3d 1122, 1123 (D.C. Cir. 1995). The court noted further that the Act's SIP provisions give states "authority to make the many sensitive technical and political choices that a pollution control regime demands." Id. at 1124. Here, the authority of states to develop SIPs and submit them to EPA for approval would allow the states to determine, based on state-specific concerns and the specialized knowledge of state officials, how best to achieve the emission reductions that may be necessary to satisfy section 110(a)(2)(D) by allocating allowances to sources within the state. EPA lacks the knowledge of state-specific conditions that state agencies can bring to bear in developing implementation plans. For example, within a state, various agencies and regulatory bodies may have input to the process for setting policy for allocating allowances, to assure not only environmental protection but also effective energy policies and electric reliability.  [EPA-HQ-OAR-2009-0491-2756.1, pp.25-26]  
EPA may issue a FIP, "rescind[ing] state authority," id., only after a state fails to develop and submit a complete SIP and receive Agency approval of it. CAA § 110(c)(1). The Act grants no authority to EPA to promulgate a FIP without first giving the states adequate time and a real opportunity to develop and submit SIPs that reflect each state's "sensitive . . . choices" on how to implement section 110 (a)(2)(D)(i)(I). 57 F.3d at 1124. In other words, EPA has no "roving commission" to leapfrog over the SIP process and impose its own choices on states and regulated parties. Michigan v. EPA, 268 F.3d 1075, 1084 (D.C. Cir. 2001). [EPA-HQ-OAR-2009-0491-2756.1, p.26]  
As noted above, it is a bedrock principle that, under the CAA, EPA's role is a decidedly "secondary" one -- one that requires the Agency to give states room and time to act:  
[EPA] is relegated by the Act to a secondary role in the process of determining and enforcing the specific, source-by-source emission limitations which are necessary if the national standards it has set are to be met. Under [CAA] § 110(a)(2), the Agency is required to approve a state plan which provides for the timely attainment and subsequent maintenance of ambient air standards, and which also satisfies that section's other general requirements. The Act gives the Agency no authority to question the wisdom of a State's choices of emission limitations if they are part of a plan which satisfies the standards of § 110(a)(2), and the Agency may devise and promulgate a specific plan of its own only if a State fails to submit an implementation plan which satisfies those standards. § 110(c). Thus, so long as the ultimate effect of a State's choice of emission limitations is compliance with the national standards for ambient air, the State is at liberty to adopt whatever mix of emission limitations it deems best suited to its particular situation. [EPA-HQ-OAR-2009-0491-2756.1, pp.26-27]  
Train, 421 U.S. at 79 (emphases added) (footnote omitted); see id. at n.16 (listing exceptions to this principle, where specific CAA provisions authorize EPA to determine emission limitations; none of those provisions apply here). Indeed, the D.C. Circuit and other courts of appeals have recognized repeatedly and consistently the well-established relationship between the federal government and the states with respect to interstate pollution regulation -- and the limited scope of federal authority. As the D.C. Circuit explained,  
EPA determines the ends--the standards of air quality--but Congress has given the states the initiative and a broad responsibility regarding [the] means to achieve those ends through state implementation plans and timetables of compliance . . . . The Clean Air Act is an experiment in federalism, and the EPA may not run roughshod over the procedural prerogatives that the Act has reserved to the states. [EPA-HQ-OAR-2009-0491-2756.1, p.27]  
Virginia v. EPA, 108 F.3d 1397, 1408 (D.C. Cir. 1997) (quoting Bethlehem Steel Corp. v. Gorsuch, 742 F.2d 1028, 1037-38 (7th Cir. 1984)); see also Michigan v. EPA, 213 F.3d 663, 687 (D.C. Cir. 2000) (noting that the validity of the statewide emission budget program that was the central feature of EPA's NOx SIP Call rule depended on "whether the program constitutes an impermissible source-specific means rather than a permissible end goal"; the court affirmed that rule because it "merely provide[d] the levels to be achieved by state-determined compliance mechanisms" and allowed states "real choice with regard to the control measure options available to them to meet the budget requirements" (emphasis added)). The principle that it is the right and responsibility of the states to develop plans to implement the Act's requirements could not be more clear. [EPA-HQ-OAR-2009-0491-2756.1, pp.27-28]  
The Proposed Transport Rule makes equally clear, however, that EPA's proposal would violate this principle. The proposal's preamble articulates the view that EPA has broad responsibility to determine exactly what states, and sources in the states, must do to comply with section 110(a)(2)(D)(i)(I). EPA explains that its proposal "identifies emission reduction responsibilities of upwind states, and also proposes enforceable FIPs to achieve the required emissions reductions in each state through cost-effective and flexible requirements for power plants," and that "[e]ach state will have the option of replacing the [FIP with a SIP] to achieve the required amount of emissions reductions from sources selected by the state." 75 Fed. Reg. at 45212/3. In other words, under EPA's new approach, the states and their sources would be required to comply with the FIP unless and until -- after the prolonged period needed for SIP development -- SIPs are in fact developed, submitted, and approved by EPA (if and when EPA decides to approve them). This scheme is plainly contrary to the terms of the Act and the statesfirst principle recognized and enforced by the courts. EPA's passing reference to states' right to "replace[] the federal requirements of the FIP with state requirements," 75 Fed. Reg. at 45342/2, is not an acknowledgement of the right granted to states in section 110 of the Act. Congress gave the states the right to develop and submit SIPs implementing the Act's requirements in the first instance, based on state-specific considerations. No amount of expediency can justify violation of the terms of the Act and upsetting the balance that Congress struck between federal and state government. As the Supreme Court noted decades ago, "the Agency may devise and promulgate a specific plan of its own only if a State fails to submit an implementation plan which satisfies [the standards of § 110(a)(2)]." Train, 421 U.S. at 79 (emphasis added). [EPA-HQ-OAR-2009-0491-2756.1, pp.28-29]  
EPA claims that its findings regarding the pre-CAIR SIPs, see 75 Fed. Reg. at 45341/3- 45342/2, justify the Agency's proposal to supplant the role of the states under the Act. EPA's error is perhaps most starkly revealed by this attempt to assign blame to the states for faithfully implementing the underlying section 110(a)(2)(D)(i)(I) rule -- CAIR -- that EPA itself promulgated to guide the states' implementation of that CAA provision. In CAIR, EPA took it upon itself, much as it had done in the NOx SIP Call rule, to set broad parameters -- in the form of statewide emission budgets -- for the states' implementation of their section 110(a)(2)(D)(i)(I) obligations. That EPA rule was later held unlawful through no fault of the states that worked to implement it. Thus, EPA's justification in the proposed rule for not allowing states sufficient time to develop new SIPs, and to submit them to EPA for review and approval, before implementation of the program begins is contrary to the Act as construed by the Supreme Court and the D.C. Circuit. [EPA-HQ-OAR-2009-0491-2756.1, p.29]  
In particular, EPA's position that its 2005 findings that CAIR states had failed to submit SIPs satisfying their section 110(a)(2)(D)(i)(I) obligations for the 1997 PM2.5 and ozone NAAQS provide a legal basis for the Proposed Transport Rule FIPs, see 75 Fed. Reg. at 45341/3  - 45342/1, is without merit. 19 EPA attempts to justify this conclusion by explaining that, under CAIR:  
EPA concluded that the states in the CAIR region would meet their section 110(a)(2)(D)(i) obligations . . . by complying with the CAIR requirements. Consequently, states within the CAIR region did not need to submit a separate SIP revision to satisfy the section 110(a)(2)(D)(i) requirements provided they submitted a SIP revision to satisfy CAIR . . . . [T]he Court granted several petitions for the review of . . . CAIR and found . . . that EPA had not demonstrated that . . . CAIR effectuates the statutory mandate of section 110(a)(2)(D)(i)(I). The EPA approvals of the CAIR SIPs preceded the remand of . . . CAIR . . . . Therefore, because the D.C. Circuit found CAIR and the CAIR FIPs unlawful, EPA's approval of the provisions of a state's SIP submittal as addressing the requirements of . . . CAIR could not satisfy the state's section 110(a)(2)(D)(i)(I) obligation. [EPA-HQ-OAR-2009-0491-2756.1, pp.29-30]  
75 Fed. Reg. at 45341/3. This explanation -- that the states are in default of their SIP obligations because the D.C. Circuit held that EPA's promulgation of CAIR was unlawful -- is nonsensical. The states had no choice but to comply with CAIR or else to default on their EPA-determined SIP obligation. States cannot be penalized, or lose their right under the CAA to decide how to implement a CAIR replacement rule, because they complied with an EPA rule that, as later determined by the D.C. Circuit, violated the Act. [EPA-HQ-OAR-2009-0491-2756.1, p.30]  
The D.C. Circuit has held that, where states have been prevented from meeting their statutory obligations due to the failure of EPA to comply with applicable CAA provisions, the deadline clock for states to submit SIPs should be restarted. See, e.g., Natural Res. Def. Council v. EPA, 22 F.3d 1125, 1137 (D.C. Cir. 1994) ("we think it would be unfair to penalize states that reasonably relied on and complied with the EPA's [regulatory decision] . . . . [W]e direct that the sanction clock for . . . SIPs start, if necessary, from the time of SIP disapproval in accordance with the statutory scheme"); see also Natural Res. Def. Council v. Thomas, 805 F.2d 410, 435 (D.C. Cir. 1986) (holding that EPA was required to extend the deadline for compliance with automobile NOx emissions standards when EPA was a year late in promulgating the standards, and explaining that, "[a]lthough fully cognizant of the frustration the drafters would have felt, could they have foreseen the course of events, we nonetheless find that they enacted a four year leadtime requirement and we have no alternative but to enforce it, unless or until Congress decrees otherwise"). Thus, the three-year deadline for CAA section 110(a)(2)(D)(i)(I) interstate transport SIP submissions for the 1997 NAAQS should be restarted due to EPA's unlawful adoption of CAIR, and should begin to run upon EPA's promulgation of a valid final rule replacing CAIR. [EPA-HQ-OAR-2009-0491-2756.1, pp.30-31]  
Likewise, EPA's explanation that, with respect to the 2006 24-hour PM2.5 NAAQS, it will finalize FIPs for states that have not submitted SIPs and those for which EPA finds the previously-submitted SIPs to be incomplete or inadequate, 75 Fed. Reg. at 45342/2, lacks merit and is contradicted by EPA's own underlying justification for proposing the Transport Rule. In the proposed rule (as in CAIR), EPA plainly takes the position that it has the authority, if not the obligation, to set the overall terms for states' implementation of section 110(a)(2)(D)(i)(I) with respect to any new or revised NAAQS. Given this circumstance, therefore, the affected states' section 110(a)(2)(D)(i)(I) obligation with respect to the 2006 24-hour PM2.5 NAAQS should be deemed to begin to run only upon EPA's promulgation of a valid final rule setting guidelines (in the form of statewide emission budgets) for the states (e.g., a final CAIR replacement rule that is consistent with the CAA). [EPA-HQ-OAR-2009-0491-2756.1, p.31]As a Matter of CAA Procedural Requirements, the Proposed Rule's Unfounded Assumptions, Errors, and Apparent Anomalies -- and EPA's Failure To Explain Adequately Critical Aspects of the Proposal and To Include in the Docket Information that Would Enable Replication of EPA's Process -- Make the Proposed Rule Inadequate for Public Comment.  
Even apart from the fundamental legal deficiency in the Proposed Transport Rule -- i.e., EPA's use of a "FIP-first" approach that improperly bypasses the SIP process, as described above -- and other flaws in EPA's proposal related to that deficiency, such as an improperly accelerated compliance schedule, other elements of the proposed rule make it inadequate as a notice of proposed rulemaking for public comment. [EPA-HQ-OAR-2009-0491-2756.1 ,pp.101-102]  
First, the unfounded assumptions, errors, and anomalies in the Proposed Transport Rule, as described in these comments, make EPA's proposal inadequate for public comment. For example, the assumptions regarding individual units described in section VIII above affect the state budgets and allocations of allowances. These problems are serious, and some of them appear to be due to causes that are not readily discernible from EPA's proposed rule and TSDs. Such problems might have been avoided had EPA issued an advance notice of proposed rulemaking as UARG requested in April 2009, instead of developing the proposed rule without any meaningful opportunity for preliminary public review and input. Similarly, EPA's explanations of both its air quality assessment tool and the budgets and unit allocations are inadequate. Without additional explanation from EPA, it is impossible to replicate or validate EPA's significant contribution analysis and state budget and unit allocation calculations. See comments of Southern Company on the PTR (describing the lengths that it had to go to in order to try to replicate parts of EPA's analyses). [EPA-HQ-OAR-2009-0491-2756.1, p.102]  
EPA must now revise the Proposed Transport Rule to remove these errors and anomalies, correct its ill-founded assumptions and judgments, and provide the critical missing explanations, and must either withdraw the proposed rule and begin the rulemaking anew or issue a comprehensive supplemental notice of proposed rulemaking for public comment. [EPA-HQ-OAR-2009-0491-2756.1, p.102]  
The Proposed Transport Rule does contain some commendable elements, the proposed rule overall is seriously flawed on legal, policy, and factual grounds. These flaws are so substantial that EPA should withdraw the proposed rule and replace it with a new proposed rule that remedies the specific deficiencies identified by the court in North Carolina v. EPA, adopts a reasonable implementation and compliance schedule that allows adequate time for development of SIPs -- rather than impose FIPs in the first instance -- and does not impose emission reduction obligations on affected states that are more demanding than those imposed by CAIR. [EPA-HQ-OAR-2009-0491-2756.1, p.103]  

Footnote 19: Some states may have already satisfied any obligation that they have under section 110(a)(2)(D)(i)(I) for these NAAQS and the 2006 PM2.5 NAAQS. If a state were to have already implemented, under state law, the emission reductions necessary to satisfy the requirements of the Transport Rule, there would not even arguably be any basis for EPA to impose a FIP on that state.  
Response: 
As explained above, in the Technical Support Document (TSD) entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs," and in section IV.C.2 of the preamble to the final rule, EPA has a legal obligation to promulgate each Federal Implementation Plan (FIP) in this final rule.  This conclusion is based on the plain language of the Clean Air Act as applied to the specific circumstances of each state.  
Section 110(c)(1) of the Act requires EPA to promulgate FIPs within two years after finding that a state has failed to make a required SIP submission or disapproving a SIP.  Specifically, section 110(c)(1) states that the Administrator shall promulgate a Federal Implementation Plan within two years after the Administrator "(A) finds that a State has failed to make a required submission or finds that the plan or plan revision submitted by the State does not satisfy the minimum criteria established under subsection (k)(1)(A)  of this section or (B) disapproves a State implementation plan submission in whole or in part."  42 U.S.C. § 7410 (c)(1)(A) & (B).  EPA is relieved of the obligation to promulgate a FIP only if the state corrects the deficiency and EPA approves the SIP before promulgating a FIP.  42 U.S.C. § 7410(c)(1).  The Act does not create any exceptions to this rule.  For each FIP in this rule, EPA either has found that the state failed to submit a 110(a)(2)(D)(i)(I) SIP for the relevant NAAQS, or has disapproved the state's 110(a)(2)(D)(i)(I) SIP submission for the relevant NAAQS.  EPA is promulgating FIPs only in those circumstances where the Clean Air Act explicitly provides that it shall do so.  
EPA also disagrees with several of the more specific arguments presented by the commenter.  These are addressed in turn below.
The commenter's sweeping assertion that EPA should not be promulgating any of the FIPs in this rule fails to acknowledge or address the significantly different postures of the states covered by this rule with respect to the requirements of CAA section 110(a)(2)(D)(i)(I) for the relevant NAAQS.  In this action, EPA is issuing 59 FIPs.  EPA is issuing FIPs to 20 states to correct SIP deficiencies relating to the 110(a)(2)(D)(i)(I) requirements for the 1997 ozone NAAQS.  EPA is also issuing FIPs to 18 states to correct SIP deficiencies relating to the 1997 PM2.5 NAAQS.  Finally, EPA is issuing FIPs to 21 states to correct SIP deficiencies relating to the 2006 PM2.5 NAAQS.
The states covered by this rule are differently situated in several respects.  First, the states are differently situated with regard to the mechanism used to implement the Clean Air Interstate Rule (CAIR), which addressed the requirements of 110(a)(2)(D)(i)(I) with respect to the 1997 ozone and 1997 PM2.5 NAAQS in certain states.  Not all of the states covered by this rule were covered by CAIR.  In addition, CAIR was implemented differently in different states, with some states submitting SIPs and others remaining subject to the FIP (either with our without submitting an abbreviated SIP).  
Second, the states are differently situated with respect to the findings of failure to submit and SIP disapproval actions taken by EPA. In 2005, EPA made findings of failure to submit 110(a)(2)(D)(i) SIPs with respect to the 1997 NAAQS for all states.   EPA also has made findings of failure to submit 110(a)(2)(D)(i)(I) SIPs with respect to the 2006 PM2.5 NAAQS for a more limited number of states.  Additionally, EPA has acted to disapprove several SIPs that EPA concluded were not adequate to address CAA section 110(a)(2)(D)(i)(I) requirements for the 2006 PM2.5 NAAQS.  
Third, the states are differently situated with respect to individual SIP submissions.  For example, many states that submitted SIPs to address the requirements of 110(a)(2)(D)(i)(I) for the 2006 PM2.5 NAAQS relied on CAIR for all or a portion of their submittal.  EPA has disapproved such SIPs as CAIR did not purport to address the requirements of 110(a)(2)(D)(i)(I) with respect to the 2006 PM2.5 NAAQS.
EPA has considered the specific circumstances of each state in determining whether it has an obligation to promulgate a FIP for that state with respect to a particular NAAQS.  More detailed information regarding the state specific actions taken by EPA and the status of each covered states 110(a)(2)(D)(i)(I) SIPs appears in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs."
As explained below, the states are differently situated with regard to the mechanism used to implement the Clean Air Interstate Rule (CAIR).  The CAIR itself was intended to define the obligations of certain states with respect to the requirements of section 110(a)(2)(D)(i)(I) for these NAAQS.  The CAIR FIPs, in turn, were promulgated to ensure that the requirements of CAIR would be implemented in a timely manner.  Many states, however, chose to replace the CAIR FIPs, in whole or part, with SIPs.  Thus, some states are covered by the CAIR FIPs as promulgated by EPA, some are subject to the CAIR FIPs but have received EPA approval to allocate the allowances used in the CAIR FIP trading programs, and still other states have replaced the CAIR FIPs with SIPs that incorporated the CAIR trading programs into the SIPs. 
In addition, based on the conclusion in the CAIR that compliance with the budgets established in CAIR would satisfy a state's 110(a)(2)(D)(i)(I) obligations, EPA issued guidance stating that states covered by CAIR that submitted SIP revisions implementing the requirements of CAIR for a particular NAAQS did not need to submit separate SIP revisions demonstrating compliance with the requirements of 110(a)(2)(D)(i)(I) for the that NAAQS.  Thus, any state covered by CAIR for PM2.5, that received EPA approval of a CAIR SIP implementing the annual NOX and annual SO2 limits established in CAIR, was not required to submit a separate SIP demonstrating compliance with the requirements of 110(a)(2)(D)(i)(I) with respect to the 1997 PM2.5 NAAQS.  Similarly, any state covered by CAIR for ozone, that received EPA approval of a CAIR SIP implementing the ozone-season NOX limits established in CAIR, was not required to submit a separate SIP demonstrating compliance with the requirements of 110(a)(2)(D)(i)(I) with respect to the 1997 ozone NAAQS. 
Of the states covered by CAIR, only one state and the District of Columbia decided not to submit any SIP revisions to implement the requirements of CAIR or to allocate allowances under the FIP, but chose to remain subject to the FIP as promulgated by EPA.  Neither this state nor the District of Columbia, however, is covered by this rule because EPA determined that they (and some other states covered by CAIR) do not significantly contribute to nonattainment or interfere with maintenance of the 1997 ozone, 1997 PM2.5 or 2006 PM2.5 NAAQS in another state. 
Several other states covered by CAIR chose to submit abbreviated SIPs which allowed the state to allocate allowances to sources in the state while remaining subject to the FIPs.  These abbreviated SIP submissions did not purport to satisfy the requirements of section 110(a)(2)(D)(i)(I) and thus did not purport to cure the deficiency identified in the 2005 findings of failure to submit.  EPA approval of an abbreviated CAIR SIP did not replace the FIP.  Instead, the approved abbreviated SIPs only modified certain provisions of the CAIR FIPs.  Even after EPA approval of an abbreviated CAIR SIP for a state, the CAIR FIPs remained in place and continued to be the legal vehicle for implementing the requirements of CAIR in the state.  The CAIR FIPs were found unlawful by the D.C. Circuit in North Carolina v. EPA and were remanded to EPA.  The CAIR FIPs will be replaced, as appropriate, by the FIPs in this rule.  Neither the state's submission of nor EPA's approval of an abbreviated CAIR SIP has any impact on EPA's legal obligation to issue FIPs which was created by the 2005 findings of failure to submit.
Some states covered by CAIR (including some which had previously submitted abbreviated SIPs) chose to submit SIP revisions to replace the CAIR FIPs for the 1997 ozone NAAQS, for the 1997 PM2.5 NAAQS or for both.  To distinguish these from the abbreviated CAIR SIPs, EPA will refer to these as full CAIR SIPs.  Upon approval of a full CAIR SIP, the CAIR FIP which had previously served as the legal vehicle for implementing the requirements of CAIR was withdrawn to the extent it was replaced by the CAIR SIP.  EPA has approved full CAIR SIPs for several states.  In many of these approvals, EPA relied on the conclusion finalized in CAIR that compliance with CAIR satisfied the requirements of section 110(a)(2)(D)(i)(I) for the 1997 PM2.5 NAAQS for the states covered by CAIR for PM2.5 and that compliance with CAIR satisfied the requirements of section 110(a)(2)(D)(i)(I) for the 1997 ozone NAAQS for the states covered by CAIR for ozone.  In some instances, EPA stated in its approval that the SIP submission satisfied the requirements of section 110(a)(2)(D)(i)(I) with respect to a specific NAAQS.  In other instances, EPA cited to its own guidance stating that it was not necessary for states with approved CAIR SIPs to submit separate SIP revisions to satisfy the requirements of section 110(a)(2)(D)(i)(I).  The July 2008 decision of the D.C. Circuit in North Carolina v. EPA made it clear that both types of statements were in error.  In that decision, the court found CAIR unlawful because the state emission reduction requirements in the rule were not adequately related to the state's significant contribution to nonattainment or interference with maintenance.  The CAIR, the court concluded, did not make measurable progress towards the statutory mandate of 110(a)(2)(D)(i)(I).  In other words, compliance by a state with the requirements of CAIR would not make measurable progress towards satisfying that state's obligation to comply with the requirements of section 110(a)(2)(D)(i)(I).  For this reason the CAIR SIPs do not satisfy the requirements of 110(a)(2)(D)(i)(I) and do not correct the SIP deficiency identified by EPA in its 2005 findings of failure to submit.  EPA does not believe that its approval of a SIP that does not correct the SIP deficiency relieves the Agency of its obligation to promulgate a FIP to correct that deficiency. See 42 U.S.C. § 7410(c)(1).
Nonetheless, to avoid any confusion, EPA is taking action in this notice under section 110(k)(6) to correct its prior CAIR SIP approvals to rescind any approval to the extent that it: (a) states or suggests that the SIP submissions either satisfied or relieved states from the obligation of submitting a SIP to demonstrate compliance with the requirements of section 110(a)(2)(D)(i)(I) with respect to the 1997 ozone and/or 1997 PM2.5 NAAQS; (b) states or suggests that the SIP approval affects EPA's authority to issue a FIP.  This action is based on EPA's determination that, in light of the court decision, the SIP approvals were in error to the extent they provided explicitly or implicitly that compliance with CAIR satisfies the requirements of 110(a)(2)(D)(i)(I) with respect to the 1997 ozone or the 1997 PM2.5 NAAQS or that the SIP submissions corrected the deficiency previously identified by EPA.
Finally, as noted above, the Clean Air Act provides that EPA is not relieved of its obligation to promulgate FIPs unless the States submits a SIP that corrects the deficiency and EPA approves the SIP.  Nonetheless, in the preamble to the proposed rule, EPA indicated that for states not covered by CAIR which had 110(a)(2)(D)(i)(I) SIPs pending at the time of proposal, EPA would finalize the FIP only if EPA determined the submission was incomplete or disapproved the SIP submission.  75 FR 45342.  This statement on its face does not apply to states that were covered by CAIR, regardless of the extent to which they were covered by CAIR.  The only two states covered by this rule but not covered by CAIR are Kansas and Nebraska.  Both Kansas and Nebraska are covered by this rule based only on their significant contribution to nonattainment or interference with maintenance of the 2006 PM2.5 NAAQS.  EPA has not received a 110(a)(2)(D)(i)(I) submission from Nebraska with respect to the requirements of the 2006 PM2.5 NAAQS.  EPA disapproved a SIP submission from Kansas with respect to the requirements of 110(a)(2)(D)(i)(I) for the 2006 PM2.5 NAAQS. 
EPA disagrees with the commenter's argument that the rule is inconsistent with the CAA because it does not give states time, after promulgation of the Transport Rule, to develop, submit and receive EPA approval of SIPs before the FIPs go into effect.  First, as explained above, this argument is overbroad because it doesn't consider the unique circumstances in each state. Further, the commenter does not cite to any statutory authority which would allow EPA to alter the statutory deadline for SIP submissions.  Section 110(a)(2) provides that the deadline for states to adopt and submit SIPs runs from the date of promulgation or revision of the NAAQS, not from promulgation of the Transport Rule.  The Act does not give EPA authority to adjust the deadlines established in section 110(a)(1) in order to give states additional time, after promulgation of the Transport Rule, to submit SIPs that comply with section 110(a)(2)(D)(i)(I).  EPA also does not believe it has authority to alter the statutory requirement that it promulgate FIPs within two years of making a finding of failure to submit.  EPA sought to discharge this duty with respect to the states covered by CAIR for the 1997 ozone and PM2.5 NAAQS by promulgating the CAIR FIPs; however, the court vacated and remanded CAIR and the CAIR FIPs finding that they did not even make measurable progress toward meeting the statutory mandate of section 110(a)(2)(D)(i)(I).  EPA recognizes that deadline for promulgating the FIPs with respect to the 1997 standards now has passed, and it believes that it has an obligation to act expeditiously and that additional delay would not be justified in these circumstances.
Further, the cases cited by the commenter do not support the commenter's conclusion that it is improper for EPA to promulgate the FIPs in this rule.  The cases discussing the system of cooperative federalism established by the Clean Air Act explain both the primary role given to states with regard to the protection of air quality and EPA's obligation to promulgate federal plans "if a if a State fails to submit an implementation plan which satisfies [the standards of 110(a)(2)]".  Train, 421 U.S. at 79.  In addition, the two cases cited by the commenter for the proposition that EPA is required to adjust the SIP submittal deadline -- NRDC v. EPA, 22 F.3d 1125 (D.C. Cir. 1994) and  NRDC v. Thomas, 805 F.2d 410 (D.C. Cir. 1986) -- do not support that proposition.  In this case there is not a requirement for EPA to have taken some specific action in advance of the required state action.  Further, the statutory provisions at issue do not link the obligation of the parties to a required EPA action, much less provide that the obligation of the other parties (states in this case) does not arise until a specific period of time has elapsed following a required EPA action.  The fact that EPA stepped in to act where the states had not been able to act does not extend the statutory deadlines for states to submit SIPs or relieve EPA of the obligation and authority to promulgate FIPs. 

Further, pursuant the court's decisions, EPA believes it has an obligation to act expeditiously to replace the CAIR and CAIR FIPs, which the court found to be unlawful.  EPA does not believe it would be appropriate, in light of the Court's decision in North Carolina, to establish a lengthy transition period to the rule that will replace CAIR and the CAIR FIPs as some commenters have suggested.  In its December 2008 decision remanding CAIR without vacatur, the Court stressed its prior conclusion that CAIR was deeply flawed and emphasized EPA's obligation to remedy those flaws expeditiously.  North Carolina, 550 F.3d 1176.  Although the Court did not set a specific deadline for corrective action, the Court took care to note that the effect of its opinion would not be delayed "indefinitely."  Id.  Given the Court's emphasis on remedying CAIR's flaws expeditiously, EPA does not believe it would be appropriate to establish a lengthy transition period to the rule which is to replace CAIR.  In these circumstances, EPA does not believe it would be appropriate to delay implementation of the Transport Rule requirements, and leave the CAIR and CAIR FIPs undisturbed, for several years to give states additional time to submit 110(a)(2)(D)(i)(I) SIPs.  However, EPA has taken steps as explained in section X of the preamble to the final rule, to facilitate state submission of SIPs to replace the Transport Rule FIPs.  States can, through these SIPs tailor implementation of the TR requirements to the specific needs and concerns of that state. 
EPA has made every attempt to smooth the transition between the requirements of CAIR and those of the Transport Rule.  For future requirements, EPA will also make every effort to address transition issues.  However, EPA cannot ignore its statutory obligations and therefore cannot provide assurance, in this action, that no new requirements will be placed on the sources regulated by this action. 
Prior to this action, States had ample time under the provisions of the CAA to develop and submit SIPs to address the requirements of 110(a)(2)(D)(i)(I).  Finally, EPA has provided notice and opportunities for public comment throughout the rulemaking process.  In addition to the original proposal, EPA issued three Notices of Data Availability, providing additional opportunities for public comment on elements of the rulemaking that were critical to the final modeling and analysis.  EPA believes that these opportunities provided adequate information and access to the data upon which EPA has relied in issuing this final rule. 

[1] Section 110 (k)(1)(A) of the Act requires the Administrator to promulgate minimum criteria that a plan submission must meet before the Administrator is required to act on the submission.  This section does not require the Administrator to promulgate criteria for determining if a plan is approvable, but instead only criteria for determining if a submission is complete enough to require a substantive evaluation.  See 42 U.S.C.§ 7410(k)(1)(A).  A submittal that is incomplete is deemed not to have been made. See 42 U.S.C.§ 7410(k)(1)(C), see also NRDC v. EPA, 22 F.3d 1125, 1131 (D.C. Cir. 1994).
[2] States may also have received approval to expand the applicability of the CAIR NOX ozone season program to include all units subject to the NOX Budget Program, allow opt-ins, or provide for distribution of a Compliance Supplement Pool under the CAIR NOX (annual) program.
[3] The abbreviated SIP process was also used by some states to slightly modify the FIPs  by expanding the applicability of the CAIR NOX ozone season program to include all units subject to the NOX Budget Program, allowing opt-ins and/or providing for distribution of a Compliance Supplement Pool under the CAIR NOX (annual) program.
Organization: West Window Corp.
Comment: 
West Window Corp.
The deadline does not provide enough time for states to develop their own implementation plans to comply with the rule, which has previously been a cornerstone of EPA compliance. [EPA-HQ-OAR-2009-0491-2386, p.1] [[This comment can also be found in Section VII.C.]]
Response: 
As explained in this section of the RTC, in section IV of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs," EPA has a legal obligation to promulgate the FIPs in this final rule.  As explained in section X of the preamble, EPA has taken steps to make it easier for states to submit and get EPA approval of SIPs to replace the FIPs promulgated in this action, in whole or in part.
Organization: Westar Energy, Inc.
Comment: 
Westar Energy, Inc.
THE RULE AS APPLIED TO KANSAS EXCEEDS EPA'S STATUTORY AUTHORITY [EPA-HQ-OAR-2009-0491-2757.1, p.8]
The CAA provides the authority for each state to have 'the primary responsibility for assuring air quality' within its borders. 42 U.S.C. § 74l0(a). Individual states exercise this responsibility by adopting state implementation plans ('SIPs') providing for the 'implementation, maintenance, and enforcement of' the NAAQS. 42 U.S.C. § 7410. See, e.g., Train v. Natural Resources Defense Council, 421 U.S. 60, 79 (1975) and Natural Resources Defense Council v. Browner, 57 F.3d 1122, 1123-24 (D.C. Cir. 1995)(explaining federal-state partnership under CAA). As the Rule recognizes, 'EPA has approved the 110(a)(2)(D)(i)submission [SIP] from the State of Kansas for the 1997 ozone and PM2.5 NAAQS.' 75 FR at 45342/1. To date Kansas has been expressly excluded from the NOx SIP Call and CAIR on the basis that Kansas does 'not significantly contribute to downwind nonattainment under the I-hour or 8-hour ozone NAAQS, or interfere with maintenance under the 8-hour NAAQS.' NOx SIP Call at 63 Fed. Reg. 57398/3. Thus, Kansas has never been required to submit a revised SIP in response to the CAIR rule. 70 Fed. Reg. 25171/2 ('The final CAIR does not cover Kansas based on new analyses of its contribution to downwind PM2.5 nonattainment.'); see 72 Fed. Reg. 10608 (March 9,2007) (order approving Kansas SIP on same basis). [EPA-HQ-OAR-2009-0491-2757.1, pp.8-9]
EPA may promulgate a Federal Implementation Plan ('FIP') to replace the SIP in whole or in part only after finding that a SIP fails to meet minimum criteria established by regulation or by finding that a SIP is inadequate to attain or maintain the NAAQS at issue. Neither finding has been made with respect to the Kansas SIP. CAA § 7410(c)(1)(A) states: [EPA-HQ-OAR-2009-0491-2757.1, p.9]
(c)(1) The Administrator shall promulgate a Federal implementation plan at any time within 2 years after the Administrator - [EPA-HQ-OAR-2009-0491-2757.1, p.9]
(A) finds that a State has failed to make a required submission or finds that the plan or plan revision submitted by the State does not satisfy the minimum criteria established under subsection (k)(1)(A) of this section. [EPA-HQ-OAR-2009-0491-2757.1, p.9]
Alternatively, EPA may require a State to revise its currently effective SIP '[w]henever the Administrator finds that the applicable implementation plan for any area is substantially inadequate to attain or maintain the relevant national ambient air quality standard . . . or to otherwise comply with any requirement of' the Clean Air Act. 42 U.S.C. § 7410(k)(5). However, such revision can occur only after the Administrator first publicly notifies the state of the SIP's inadequacies and sets a deadline (not to exceed 18 months) for the state to revise the SIP. [EPA-HQ-OAR-2009-0491-2757.1, p.9]
While the Rule states that the approved Kansas SIP is inadequate and must be replaced based on 'updated modeling done for this proposed rule,' 75 FR at 45342/1, this is not the requisite finding and does not follow the requisite procedure. EPA further states that it 'is proposing to finalize the FIP for Kansas for ozone only if the state fails to submit a complete and approvable SIP by the deadline established in any final SIP Call.' Id. But in order to avoid subjecting Kansas EGUs to enforcement action and Kansas to adverse findings under any FIP that will result from the Rule, Kansas must immediately begin implementing the Rule and the EGUs subject to the Rule must commit millions of dollars to attain compliance with the Kansas state air emission budget and individual EGU emissions allowances set forth in the Rule. In other words, the Rule's preemptive finding outside the requisite procedures does not give Kansas sufficient time to respond to a SIP disapproval and submit a revised SIP before the new emissions restrictions proposed in the Rule take effect nor would the deadline set by the Rule allow potentially affected EGUs the necessary time to install equipment necessary to comply with emissions limits. See 75 FR at 454286/3 ('a single SCR unit on average takes 21 months to install'). This presents the very real possibility that penalties could be assessed against the State of Kansas or any in-state EGU even though EPA's preemptive approach does not comport with the processes that Congress mandated for EPA SIP disapproval. [EPA-HQ-OAR-2009-0491-2757.1, p.10]
The CAA language allows EPA to replace a SIP only on the basis and after promulgation of final regulations establishing the applicable minimum criteria to be met by a SIP. Subsection 7410(c)(1)(A). EPA is in the process of promulgating, but has not yet finalized, the instant proposed rules. 75 FR at 45342/1. Consequently, the proposed rules do not yet constitute 'minimum criteria' with which Kansas' SIP must comply. [EPA-HQ-OAR-2009-0491-2757.1, p.10]
Quite the opposite, EPA has already determined under the currently effective minimum criteria that Kansas does 'not significantly contribute to downwind nonattainment under the 1- hour or 8-hour ozone NAAQS, or interfere with maintenance under the 8-hour NAAQS.' NOx SIP Call at 63 Fed. Reg. 57398/3; 72 Fed. Reg. 10608 (March 9, 2007)(same). Until the proposed rules are implemented as final regulations with the force of law, the already approved Kansas SIP will continue to meet the currently effective minimum criteria, and thus is not subject to replacement. [EPA-HQ-OAR-2009-0491-2757.1, p.11]
As the conditional language in the Rule acknowledges, the same result is reached by following the SIP Call process of § 7410(k)(5): 'That SIP Call, if finalized, would' find that Kansas' existing SIP is substantially inadequate and would 'establish a deadline for submission' of a new SIP. 75 FR at 45342/1 (emphasis added). The prerequisite for taking such action - a finalized SIP Call - has not yet happened, and therefore Kansas (and in-state EOD sources) cannot not yet be subjected to the proposed FIP as outlined in the Rule. By determining Kansas state air emission budgets and allowances for Kansas EODs and including them in the Rule, EPA treats Kansas and its EOD sources as if they would be subject to and required to meet the 2012 and 2014 emissions levels - this exceeds EPA's statutory authority. [EPA-HQ-OAR-2009-0491-2757.1, p.11]
Response: 
As explained in this section of the RTC, in section IV of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs," EPA has a legal obligation to promulgate the FIPs in this final rule.  The requirements of section 110(a)(2)(D)(i)(I) apply to all states regardless of whether they have previously been found by EPA to significantly contribute to nonattainment or interfere with maintenance of a specific NAAQS in another state.  EPA's authority to identify emissions which significantly contribute to nonattainment of or interfere with maintenance of the NAAQS in another state is separate from its authority to promulgate a FIP to directly prohibit such emissions.  EPA has general authority under CAA sections 110(a)(2)(D) and 301(a)(1) to provide states with the results of analyses to identify the emissions that must be prohibited pursuant to section 110(a)(2)(D)(i)(I) and to provide optional remedies.  With respect to Kansas, EPA has disapproved a SIP submitted by the State to address the requirements of section 110(a)(2)(D)(i)(I) with respect to the 2006 PM2.5 NAAQS.  It thus has authority and a legal obligation to promulgate a FIP with addressing these requirements.  In addition, with respect to the requirements of section 110(a)(2)(D)(i)(I) for the 1997 ozone NAAQS, EPA is following the procedures in section (k)(5) of the Act which apply when EPA determines an approved SIP is deficient. 
Organization: Wolverine Power Supply Cooperative
Comment: 
Wolverine Power Supply Cooperative
EPA's implementation strategy that preempts the State Implementation Plan (SIP) process by immediate imposition of a Federal Implementation Plan (FIP) circumvents Section 110(a) of the Clean Air Act (CAA), and is neither legal nor advisable. Short-circuiting the SIP development process pre-empts State development of a workable allocation mechanism between subject sources within a state and other necessary control strategies to support attainment of the NAAQS. The CAA gives the states up to 3 years to submit SIPs to remedy interstate transport, which should follow the effective date of this rule. Further, the CAA does not allow EPA to determine individual source or unit obligations, which are the responsibilities of the states, but it does direct EPA to determine statewide reduction levels.  [EPA-HQ-OAR-2009-0491-2825.1 p.2]
Response: 
As explained in this section of the RTC, in section IV of the preamble to the final rule and in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs," EPA has a legal obligation to promulgate the FIPs in this final rule.  The commenter cites to no CAA authority for the proposition that the 3 years deadline for submitting SIPs should run from the effective date of this rule.  Section 110(a)(1) of the CAA explicitly provides that the SIPs are due within 3 years (or such shorter period as the Administrator may prescribe) after the promulgation of a national primary ambient air quality standard (or any revision thereof). 
III.B. What Air Quality Problems and Which NAAQS Does This Proposal Address?

Organization: Citizens Campaign for the Environment (CCE)
we energies
State of Delaware Department of Natural Resources & Environmental Control
Clean Air Task Force
Exelon
American Lung Association
American Lung Association of the Mid Atlantic
Ozone Transport Commission (OTC)
Oren, Craig N.
Edison Electric Institute (EEI)
Comment: 
American Lung Association
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.58-59.]
EPA needs to take the steps to provide even greater protection for public health.
Air pollution is coming into Cook today from ten different states, not just the neighboring states of Indiana, Wisconsin and Michigan, but states as far as away as Iowa, Kentucky, Minnesota, Missouri, Ohio and even Pennsylvania and West Virginia send ozone and particles into Cook County.
This rule would require that plants in 31 states, including Illinois, cut the pollution they send across state lines. That pollution is toxic.
Coal-fired power plants emit millions of tons of sulfur dioxide and nitrogen dioxide.
These two gasses are so dangerous that on their own EPA recently strengthened the limits on how much of each is safe.
More importantly, sulfur dioxide and nitrogen dioxide are also the raw ingredients that help form other, even deadlier pollutants which are ozone and fine particles.
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.63-66.]
Under this framework, EPA assesses in detail the contribution from sources in each upwind state to the pollution levels in downwind states.
Such a careful analysis provides strong evidence of pollution from these 31 states and the District of Columbia burdens people living in these nonattainment and maintenance areas.
EPA will need to move this framework forward soon. The standards that form the basis for these calculations are sadly out of date.
In particular, the 1997 standard that EPA used is now 13 years old, and was superceded by a tighter standard than 75 parts per billion.
Now that 75 parts per billion standard, also widely recognized as inadequate, is being reconsidered and should be replaced by the standard that will be coming out August 31st.
The 75-parts-per-billion standard which -- the 2006 PM 2.5 standards, which includes the ancient and woefully inadequate 15-parts-per-million standard for particles are also under review with proposals scheduled to come out soon.
So why not use, for example, the 75-parts-per-billion level for ozone in your calculation.
I suspect the simple answer is that there are no nonattainment areas or maintenance areas for that 75-parts-per-billion standard established.
However, the areas still in nonattainment for the 84 parts-per-billion standard are certainly in nonattainment for that 75-parts-per-billion level, and many areas in maintenance for 84 parts per billion also violate the 75 parts per billion.
We know adverse health effects occur at levels below 75 parts per billion. Should EPA at least not include that level in the assessment for a federal implementation plan.
In fact, EPA has design values and monitoring data for all counties with ozone monitors.
You can readily tell which counties failed to meet the 75-parts-per-billion level using that data.
EPA could assess the burden upwind states are placing on these downwind states just using the counties with monitors as reference points.
As it is, the Clean Air Transport Rule becomes weaker than is needed to address the significant interstate transport of ozone based on the 75-parts-per-billion standard.
Yet this rule is critical to helping states to protect public health.
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.46-48.]
EPA most move the framework forward expeditiously. Sadly, the standards that form the basis for the calculations are out of date. For PM, the proposal incorporates the 1997 and 2006 PM 2.5 standards, which fail to protect public health. EPA is considering new and compelling evidence that show those standards should be revised and tightened next year.
Most troubling is the use of the 1997 ozone standard as the basis of the proposal.
EPA can and should ameliorate some of the adverse consequence of the delay in the standard revision by moving forward with the most protective and strongest transport rule that maximizes pollution reductions. These reductions should ensure that no area is in nonattainment for 1997 standard and should maximize the number of areas meeting the 75 ppb level.
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.11]
We do need to do more because EPA's basing this rule on sadly out-of-date national air quality standards. This proposed rule uses standards adopted in 1997 for ozone and annual fine particles and 2006 for the 24-hour particle standards. 
Using out-of-date standards means that we are looking at the wrong target for cleanup. EPA should at least use the current ozone standard set in 2008 for their assessment of downwind impact. 
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.14-15.]
In this proposal, EPA chose to use the 1997 ozone standard that is now 13 years old. Two years ago, the Bush administration replaced that standard with a tighter one, setting 75 parts per billion. The medical and public health community considers 75 ppb far too much ozone for people to breathe. The Obama administration chose to reconsider the 2008 decision and is promising an answer in October. Before you finalize the Transport Rule next year, we will know that what new standard will be. 
The American Lung Association expressed our extreme disappointment last month as the EPA announced that the new ozone standard would be delayed until late October. The bottom line is that the current EPA national air quality standard for ozone is not 84 parts per billion used in its proposed rule. For the time being, it is 75 parts per billion. The Transport Rule should reflect the current standard.
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.15.]
EPA is proposing to review and revise the rule after the 2010 standard is adopted in 2011, but to wait until then to strengthen the rule is a mistake and unnecessary. The rule needs to begin by using the current ozone standard. Any county that gets a significant part of its ozone for an 84 ppb standard for transported pollution will also absolutely get a significant part of its ozone under a 75 ppb or a more protective standard. In fact, any county with current design values above 75 ppb should have the help this rule provides in solving their ozone problems.
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.17.]
Odds are good that the ozone standard announced this fall will require at least as much cleanup as the current standard and considerably more than the 1997 one. Requiring controls based on a 75 ppb provides a more realistic appraisal of what will be needed than the proposed rule does. We urge you to use the current ozone standard to develop the final rule.
EPA has design values and monitoring data for all counties with ozone monitors. You can readily tell which counties would fail to meet the 75 ppb ozone standard using that data. EPA could assess the burden upwind states are placing on these downwind states just using the counties with monitors as reference points.
American Lung Association of the Mid Atlantic
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.33.]
The EPA should be proactive and include the remanded 75 ppb ozone standard in its evaluation of the rules impacts.
Citizens Campaign for the Environment (CCE)
CCE believes that the proposed Transport Rule should be improved to provide maximum benefit to our environment, public health, economy, and building structures. Specifically, the final Transport Rule should:
Require deeper cuts in NOx emissions. The emissions reductions in the proposed Transport Rule are based on outdated 1997 National Ambient Air Quality Standard (NAAQS) data as the standard for which reductions will be based. This standard was updated and strengthened in 2008, and is being updated and expected to become even more stringent in late 2010. Utilizing the more stringent, up-to-date standard will help to ensure that the Transport Rule provides maximum emission reductions, thus providing maximum benefit to the environment, health, economy and building structures throughout NYS, CT, and the rest of the Northeast. Deeper cuts in emissions will also hasten the ecological recovery of places such as the Adirondack Park. The final Transport Rule should also utilize the new, up to date standards as they are developed in the future. [EPA-HQ-OAR-2009-0491-1937.1, p. 3]
CCE recommends that emissions reductions are based on National Ambient Air Quality Standard of 2008, and is updated accordingly as new, more stringent standards are developed, including the standards that are projected to be developed by late 2010. [EPA-HQ-OAR-2009-0491-1937.1, p. 3]
Clean Air Task Force
The TR should be based on the most recently adopted standard, even if nonattainment areas have not been designated. EPA does not need to wait for designations to employ the current NAAQS. Thanks to EPA's careful assessment of county-specific data, the evaluations can be based against the contributions to individual counties that currently have design values showing violations of the NAAQS. Even if the ultimate nonattainment areas are larger or smaller than the single county, at a minimum it is clear that county or that portion of the county is violating the standard and will need assessing against the impact of transported ozone. [EPA-HQ-OAR-2009-0491-2738.1, p.24]
In this proposal, EPA chose to use the 1997 8-hour ozone NAAQS to assess contributions to nonattainment areas. Since rounding is applied that standard was effectively 0.084 ppm. The 1997 standard is now 13 years old and is no longer the current NAAQS. In 2008, the EPA replaced that the 1997 standard with a tighter one, set at 0.075 ppm. As discussed earlier, the EPA has now proposed to strengthen that standard to between 0.060 ppm and 0.070 ppm, with the decision scheduled for announcement in late October. We applaud EPA's effort in this regard, and agree that a tighter standard is fully justified. However, the 2008 standard remains in effect, and unless and until it is superseded, EPA should determine and eliminate significant contribution to nonattainment and interference with maintenance of that standard. [EPA-HQ-OAR-2009-0491-2738.1, p.24; for additional comments pertaining to The proposed Rule Inappropriately Uses the 1997 Ozone NAAQS as the basis for Assessment of Contributions from Transported Ozone see p. 24-25]
We urge the Agency to issue a rule that includes that following adjustments to its August 2 proposal: uses the current NAAQS as the basis for assessment of the significant contributions, including the 2008 ozone NAAQS. [EPA-HQ-OAR-2009-0491-2738.1, p. 30]
Edison Electric Institute (EEI)
In response to suggestions by at least one state and one environmental group that the Proposed Rule be finalized based on the 2008 ozone standard, that standard, to be superseded in late fall 2010, will have no standing at the time of the final Transport Rule.[EPA-HQ-OAR-2009-0491-2697.1, p.13]
Exelon
EPA SHOULD ADJUST BUDGETS TO ASSURE COMPLIANCE WITH THE 2008 OZONE STANDARD AND DEVELOP AMECHANISM TO ALLOW IT TO RAPIDLY INCORPORATE OTHER NEW AND REVISED NAAQS.
Exelon agrees with other comments received by the agency that the Transport Rule should be modified to mitigate downwind nonattainment of the 2008 ozone NAAQS rather than the 1997 ozone NAAQS. Although the 2008 ozone NAAQS is under reconsideration by EPA, the agency is required by consent decree to promulgate a final standard before the end of 2010, likely before EPA publishes a final Transport Rule. EPA could address the 2008 ozone standard in the Transport Rule as a stepping stone between the 1997 and 2010 ozone NAAQS. Rather than implementing the 2008 ozone standard directly through the proposed FIPs, which may not be appropriate if the affected states have not had a chance to submit SIPs for that standard, EPA could promulgate Transport Rule SIP approval requirements with emissions reductions and state budgets that are modeled based on the 2008 ozone rule. Thus, trading under the FIP would be required based on the proposed Transport Rule state budgets, but states would be required to submit SIPs that would meet the lower budgets. [EPA-HQ-OAR-2009-0491-2666.1, p.29]
As some regions of the country continue to struggle to meet the 1997 attainment level, using the 2008 ozone standard for Transport Rule SIPs would assist states and the regulated community in advance planning to meet the further reductions anticipated for achieving the 2010 standard. Testimony from the PADEP illustrates why the more recent ozone standard should be used, notwithstanding EPA's ongoing reconsideration. According to that testimony, all areas with monitored data in Pennsylvania would be in nonattainment if the 2010 ozone standard drops to 60 or 65 parts per billion. In addition, there have been 145 exceedances of the 2008 ozone standard for the 2010 ozone season in Pennsylvania. If EPA were to base Transport Rule SIP approvals on the 2008 ozone NAAQS, it would facilitate compliance with the 2010 final ozone NAAQS that EPA ultimately adopts. Furthermore, while the reconsideration of the 2008 ozone NAAQS suggests that it is not as protective of public health as required by the CAA, it is certainly more protective than the 1997 standard that it was intended to replace. The Transport Rule should be based on the more protective standard established in the 2008 ozone NAAQS, rather than the 1997 ozone NAAQS that EPA has already determined to be inadequate to protect public health. [EPA-HQ-OAR-2009-0491-2666.1, p.30]
Exelon commends EPA's commitment to quickly implementing new and revised NAAQS where downwind nonattainment is projected to be problematic. Exelon understands from the Transport Rule preamble that EPA has already begun the complex and time-consuming calculations associated with connecting upwind emissions to downwind nonattainment with regard to the 2010 ozone standard. However, EPA also indicated that it will address the nonattainment issues under § 110(a)(2)(D)(i)(I) following publication of new NAAQS rather than simultaneously with the NAAQS. In lieu of this approach, Exelon urges EPA to concurrently publish both requirements. Concurrent publication would assist states in developing approvable SIPs. Ultimately, if states can promulgate appropriate SIPs expeditiously, the greater the likelihood that real emission reductions can be timely implemented with less administrative burden. If EPA cannot approve the states' SIPs, then it will have to develop FIPs to address the downwind nonattainment issues for the NAAQS, which may delay compliance with standards that are critical to protecting public health. [EPA-HQ-OAR-2009-0491-2666.1, p.30]
Oren, Craig N.
As the American Lung Association has testified, the proposed reductions are simply not sufficient to bring the northeast into attainment with the ozone standard, even assuming that the northeast undertake all reasonably available measures. The reductions should be based on what is needed to meet the 2007 ozone standard of 0.075. I understand that Sara Schneeburg has advanced the view that this is not legally possible because that standard was vacated. I have worked with Ms. Schneeburg and I have the greatest respect for her, but I think she is mistaken. I'm not sure that even technically the standard was vacated -- really, it was remanded by the court pursuant to a motion by EPA -- and I think it is arbitrary for EPA to use a weaker standard than 0.075 when it is clear to all that the standard will be no higher than 0.075. [EPA-HQ-OAR-2009-0491-2644-cp, p.1]
Ozone Transport Commission (OTC)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.113-115.]
To emphasize this point, there have been 53 separate exceedances of the 2008 ozone standard in the region so far during this ozone season and the season is far from over. And because the proposed Transport Rule purports to respond only to the inadequacies of CAIR, which addressed the 1997 ozone standard, it will not provide the NOX reductions necessary to meet the 2008 ozone standard nor its more stringent replacement expected in October.
It is troubling that the proposed Transport Rule does not completely address the significant contributions from upwind states in the context of the less protective 1997 ozone standards. Section 110(a)(2)(D) of the Clean Air Act mandates that states must include in their state implementation plans provisions that prohibit air pollutant emissions that significantly contribute to non-attainment or interfere with maintenance in any other state. And yet EPA asserts in the proposed Transport Rule (which is a federal implementation plan) that it will only "partially eliminate" the significant contributions of 25 states in relation to the 1997 annual and 2006 24-hour PM 2.5 NAAQS and will only "make measurable progress toward eliminating" the significant contributions of 10 states in relation to the 1997 ozone NAAQS. It is not acceptable to the OTC states that a federal implementation plan, which is intended to fulfill the obligations of a state implementation plan, does not meet the letter of the Clean Air Act transport requirements.
State of Delaware Department of Natural Resources & Environmental Control
The proposal does not offer necessary relief to downwind states. Delaware understands that the EPA is in this proposal segregating transport related to the 0.08ppm ozone NAAQS from the lower 75ppb ozone NAAQS promulgated last year, and from the new lower ozone NAAQS anticipated to be finalized by the EPA later this month. This does not seem reasonable to states like Delaware who, despite having already subjected its sources to advanced and costly emissions control requirements, continues to be impacted by unhealthy air from upwind states. And, Delaware will continue to be impacted by this unhealthy air long into the future. Given the low level of the new ozone NAAQSs relative to current air quality, and the overwhelming impact of transported emissions, further delay in installing and operating appropriate emission controls in upwind states is not warranted. [EPA-HQ-OAR-2009-0491-2980.1, pp.10-11]
we energies
EPA has also indicated that they are conducting the technical analysis to address interstate transport as related to a reconsidered ozone standard, and that a revised transport rule to address that standard will be issued as soon as possible. EPA is also in the process of reconsidering the annual PM2.5 standard. According to the Federal Register notice, EPA intends to revise the transport rule after each of these pending decisions, and presumably modify state budgets and EGU budget allocations. This creates enormous uncertainty for making investment and operations decisions for the whole of the electric generation system in the eastern half of the U.S. [EPA-HQ-OAR-2009-0491-2629.1, p.2]
For all of these reasons we request that EPA correct its technical data inputs and modeling assumptions, consider the pending National Ambient Air Quality Standards (NAAQS), revise the proposed rule, and republish it for additional public comment. [EPA-HQ-OAR-2009-0491-2629.1 ,p.2]
We ask, if the current CAIR rule (which remains in effect until it is replaced) addresses transport related to the existing ozone and PM2.5 NAAQS, and if EPA is intending to announce decisions regarding reconsideration of both of these standards, then should not the proposed transport rule instead focus on any residual non-attainment associated with the new NAAQS? Overall, there appears to be an opportunity for enormous administrative savings for both EPA and for all the affected state agencies, plus much more regulatory certainty for regulated sources - while at the same time achieving the 2014 attainment goals associated with the current NAAQS.[EPA-HQ-OAR-2009-0491-2629.1, p.2]
This completes We Energies detailed comments on the proposed transport rule. Overall, we have made substantial investments in emission controls, and have reduced our system emissions properly account for post-2005 emission reductions, correct data errors and modeling outputs, then re-propose the rules as also based on the outcome of the pending NAAQS reconsiderations. We Energies strongly believes that EPA should reconsider both its approach and schedule for the proposed transport rule. [EPA-HQ-OAR-2009-0491-2629.1, pp.7-8]
Response: 
See discussion in Preamble section IV.C.1 regarding EPA's use of the 1997 ozone standards as the basis for the proposed rule's ozone requirements.
Organization: Clean Air Council
Comment: 
Clean Air Council
EPA's Proposal, referred hereinafter as the Transport Rule, is a commendable step forward for air quality and public health-in several respects. the need to address the significant contribution to downwind state nonattainment of PM2.5 and Ozone NAAQS posed by power plants in upwind states in the Eastern U.S. could not be more clear. The promulgation of the Transport Rule is crucial if there is to be timely attainment of the 2006, PM2.5 NAAQS and the pending 2010 Ozone NAAQS. [EPA-HQ-OAR-2009-0491-2804.1, p.1]
Response: 
EPA agrees.  
Organization: Delaware Nature Society
Comment: 
Delaware Nature Society
While local area quality in Maryland, Delaware, Pennsylvania, and New Jersey have slowly improved, reductions from both the state of Delaware and the surrounding Delaware Valley has not succeeded in bringing these states into attainment. This is due mostly to heavy industry to the northwest and lax state air quality regulations in surrounding states. Since the 1970's Delaware has been considered a non-attainment state, meaning it does not meet the EPA's air quality standards for ozone and particulate matter. In the summer of 2010 alone, Delaware experienced more than 15 days exceeding the 8 hour National Ambient Air Quality levels (NAAQ). By requiring industry polluters across the Northeast, Midwest, and Southeast to reduce their SO2 and NOX, Delaware's air quality will drastically improve. [EPA-HQ-OAR-2009-0491-0204.1,p.1]
Response: 
EPA assumes that the summer 2010 exceedances are referring to exceedances of the 2008 ozone NAAQS of 75 ppb.    See preamble section IV.C.1 for discussion of EPA's use of the 1997 ozone standards as the basis for the rule's ozone requirements.
Organization: Florida Municipal Electric Association (FMEA)
Gainesville Regional Utilities (GRU)
Comment: 
Florida Municipal Electric Association (FMEA)
The Proposed Transport Rule is more complicated that necessary to correct the D.C. Court remand: The proposed rule is more complicated than necessary to correct the provisions remanded by the D.C. District Court. The Court remanded CAIR back to EPA with the objective to "preserve the environmental values covered by CAIR." The Transport Rule goes well beyond preserving those values and does so in very troubling manner. The increased SO2 and NOx emission reductions proposed by EPA were not required by the Court. This will create opportunities for additional court challenges that will add to the uncertainty faced by both state agencies and affected utilities. EPA's choice to address the 1997 ozone NAAQS as the basis for the transport rule reductions while ignoring the 2008 ozone NAAQS is curious. By attempting to address only selected NAAQS nonattainment issues, EPA has weakened the argument that the additional reductions required in the Proposed Transport Rule are in direct response to the Court finding. [EPA-HQ-OAR-2009-0491-2731.1, p.2]
Gainesville Regional Utilities (GRU)
The Proposed CATR is More Complicated than Necessary to Correct DC Court Remand
The proposed CATR is more complicated than necessary to correct the provisions remanded by the DC District Court. The Court remanded CAIR back to EPA with the objective to 'preserve the environmental values covered by CAIR'. The proposed CATR goes well beyond preserving those values and does so in very troubling manner. The increased SO2 and NOx emission reductions proposed by EPA were not required by the Court. This will create opportunities for additional court challenges that will add to the uncertainty faced by both state agencies and affected utilities. EPA's choice to address the 1997 ozone National Ambient Air Quality Standard (NAAQS) as the basis for the proposed CATR reductions while ignoring the 2008 ozone NAAQS is curious. By attempting to address only selected NAAQS nonattainment issues, EPA has weakened the argument that the additional reductions required in the proposed CATR are in direct response to the Court finding. [EPA-HQ-OAR-2009-0491-2674.1, p.4]
Response: 
EPA disagrees with the commenter's interpretation of the Court's opinion in North Carolina and notes that the Court referred to "the environmental values covered by CAIR" in its decision to allow the CAIR programs to remain in place, rather than vacating them, while EPA worked to issue a replacement rule.  The Court found a number of flaws with CAIR.   This Transport Rule is designed to be directly responsive to the concerns raised by the Court.
See preamble discussion in section IV.C.1 regarding EPA's rationale for establishing ozone requirements based on the 1997 ozone standard.
Organization: Kersting, John
State of Connecticut
Sierra Club, Arkansas, Little Rock Office
Sierra Club, Pennsylvania Chapter
Sierra Club, Oklahoma Chapter
Adirondack Mountain Club
Southern Environmental Law Center
Public Interest Law Center of Philadelphia
Respiratory Health Association of Metropolitan Chicago
Greenpeace Washington, DC
Illinois Student Environmental Coalition
Glynn, Erin
Gardner, Robert
Comment: 
Adirondack Mountain Club
Air pollution in eastern national parks and wilderness areas has reached alarming levels. This pollution has been linked to many serious health effects, and has been found to kill thousands of people each year. This pollution also causes the acid rain that weakens our forests, and it contributes to the regional haze that has reduced visibility by over fifty percent in these areas. Over 30 years ago, Congress directed the EPA to immediately improve air quality in the parks. Despite this Clean Air Act requirement, the air, soils and waters of our parks are badly polluted. Any effort to further delay and dilute anticipated park cleanup programs takes us in the wrong direction. [EPA-HQ-OAR-2009-0491-2761, p.3]
Human activity has clearly made an impact on New York's native species, as acknowledged by this rulemaking. ADK has long revered the Adirondacks, Catskills, and the Finger Lakes regions for their exceptional landscapes. As a hiking organization, we treasure healthy forests. As canoeing and kayaking become more popular and feasible for the passive recreationist, so does the State's requirement to maintain an exceptional aquatic environment. Healthy streams and lakes must contain many species that thrive within them. This rulemaking recognizes the importance of clean air for allowing important species to thrive within their native habitats, on land and in water. [EPA-HQ-OAR-2009-0491-2761, p.3]
Gardner, Robert
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.144-145.]
Industry can and should be required to adhere to stricter pollution limits than what is proposed by this rule, which would help clear the air in the Mid-Atlantic and the Northeast, where air quality worsened in 2010, yet another year that has proved to be the hottest on record.
Glynn, Erin
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.112.]
In addition, lowering air pollution by passing the Transport Rule will significantly improve visibility in our parks and our national monuments and our wild places that are integral to our American way of life. The improved views are worth the Sierra Club estimates $3.4 billion in increased tourism and recreational opportunities.
Greenpeace Washington, DC
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.35.]
Not only will the Rule help clear the air in the midwest, but, obviously, downstream in the northeast as well.
Illinois Student Environmental Coalition
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.74-75.]
This rule is an extremely important step in not only reducing the pollution from our power generation, but, really, taking significant steps to solve some of the things that contribute to health problems from these pollutants.
We'd also like to ask the EPA take the most stringent steps in reducing air pollution, and this isn't really a time for us sort of half-hearted measures. That is a long overdue step to reduce air pollution.
Kersting, John
I strongly urge you to take the strongest actions possible to reduce the levels of all emissions as quickly and effectively as possible.
Having seen the effects of out of control pollution in the United States during the 1960's and early 70's, in China recently and in Vietnam as well as numerous other countries, I am absolutely flabbergasted at the still huge levels of unfettered pollution being poured into our fragile and finite environment.
Having also lived in the Eastern United States and seeing the destroyed forests, I support the 'Transport Rule' to reduce the amount of ozone and fine particle pollution from power plants that drifts across the borders of every state proposed as long overdue. It is essential that all states in the eastern U.S. meet existing national air quality health standards.
The EPA reports ozone and fine particle pollution causes thousands of premature deaths and illnesses each year. Having deeply studied environmental issues and pollutants such as PCB's and Pentachloraphenal, I am dead certain that the pollutants this proposed rule addresses contribute to the high rate of special needs students that I am serving as a teacher today.
It is long overdue that the Transport Rule and other EPA actions reduce sulfur dioxide, nitrogen oxide and particulate matter as much as possible. I see that a new report funded by eight utility companies, show the new regulations will not hurt the reliability of the electric grid and I cannot understand why downwind pollution is allowed so freely.
The true costs and avoidable damage of this energy source MUST be addressed by full implementation. [EPA-HQ-OAR-2009-0491-0165, p.1]
It is long past due to reduce the horrible pollution that crosses from one state to kill or maim others just in the name of producing power and mostly profits for those who deserve none.  [EPA-HQ-OAR-2009-0491-0166, p.1]
Public Interest Law Center of Philadelphia
The Clean Air Act ("CAA") requires that all states do their fair share to prevent locally generated air pollution from traveling into other states and creating hazardous health and environmental conditions. It has been proven that in high concentrations, emissions commonly generated from power plants (including nitrogen oxides and sulfur dioxides) can give rise to negative health effects, including an increased risk of premature mortality. The EPA estimates that 1 in 20 premature deaths are caused by excess concentrations of fine particulate matter in the air. Effects on the pulmonary system commonly manifest as either acute bronchitis or aggravated asthma. Increased air pollution has also been linked to a number of cardiovascular side effects, including an increase in the number of non-fatal heart attacks. People with co-morbidities such as preexisting heart or lung diseases are the most vulnerable to this type of pollution. Children are also disproportionately vulnerable to effects of air pollution and the EPA predicts that decreasing emissions will have numerous benefits to children, including fewer cases of upper and lower respiratory illness, acute bronchitis, and asthma attack. [EPA-HQ-OAR-2009-0491-2817.1, p.2]
The EPA has also correlated increased air pollution to negative economic effects such as lost work and school days, and increased frequency of emergency department visits and hospital admissions. Emissions from energy plants also wreak havoc on the environment, resulting in increases in acidification of lakes and streams, mercury methylation, coastal eutrophication, and (indirectly) mercury deposition in soil. [EPA-HQ-OAR-2009-0491-2817.1, p.2]
Consistent with the Clean Air Act's objective to limit the amount of air pollution traveling between states, the EPA has proposed the Transport Rule to decrease existing emissions caps on nitrogen oxides (NOX) and sulfur dioxides (SO2), both of which are known to travel into neighboring "downwind" states and create air quality issues. These precursor chemicals lead to the formation of fine particulate matter (PM2.5) and ground level ozone (O3), both of which cause adverse human health effects and environmental damage. [EPA-HQ-OAR-2009-0491-2817.1, p.2]
Respiratory Health Association of Metropolitan Chicago
[These comments were submitted as testimony at the Chicago, Illinois hearing.  See Docket Number EPA-HQ-OAR-0491-1746, p.16.]
Coal-fired power plant emission is deadly and responsible for triggering tens of thousands of asthma attacks, heart attacks, strokes and missed school and workdays each year. 
EPA's proposal is a long and overdue step for clean air. 
Sierra Club, Arkansas, Little Rock Office
Every year coal plants pour millions of tons of harmful pollution into our air, worsening asthma, causing heart attacks, emergency room visits and missed work days. That pollution doesn't stop at county or even state lines and as a result people throughout the country are forced to breathe unhealthy air from neighboring states. I applaud the EPA for its action to help states be good neighbors by reducing air pollution escaping across state lines. I am pleased with this common sense approach by the EPA to protect public health and help states clean up their air efficiently and cost effectively. [EPA-HQ-OAR-2009-0491-2853, p.1]
Reducing air pollution will significantly improve visibility in our national parks and wilderness areas as well. According to a recent modeling study commissioned by the Sierra Club, significant visibility impacts have been predicted for Oklahoma's Wichita Mountains if the proposed coal plants in Texas are constructed in addition to the current visibility impairments connected to existing Texas coal plants. The tourism and recreational industry could be severely impacted if the increase in pollution occurs. The reduction in mercury contamination that this rule could provide would be greatly beneficial to Oklahoma as well. In July, the Oklahoma Department of Environmental Quality reported that sixteen lakes in Oklahoma have unsafe levels of mercury and issued consumption warnings for some fish from their waters. As the Oklahoma Department of Environmental Quality and the Attorney General for the State of Oklahoma have previously stated, there is reason for concern with the sheer number of proposed coal plants in Texas and the process being employed by the Texas Commission on Environmental Quality (TCEQ) for their approval. The TCEQ did not provide timely notice of facilities' permit applications and has not adequately addressed the potential impacts on air quality in Oklahoma. In addition to emissions from a large number of existing coal fired plants already in operation in Texas, there is great concern that emissions from new sources will adversely impact air quality, public health and economic growth in Oklahoma. The emissions will also contribute to nonattainment of the national ambient air quality standards (NAAQS) in Oklahoma. Some municipalities in Oklahoma are very close or are already exceeding some NAAQS. It is important that we take steps to cut down interstate pollution that interferes with attainment and maintenance of the NAAQS. [EPA-HQ-OAR-2009-0491-2853, p.2]
With new ozone rules bring finalized, more cities and counties in Oklahoma are at risk of going into nonattainment which would deter jobs and economic development in our cities, as well as an increase in health care bills. Oklahoma is doing all we can to meet attainment standards, and we implore you to use the Good Neighbor Rule to hold Texas accountable for their impacts on our air quality. [EPA-HQ-OAR-2009-0491-2853, p.2]
This is a national problem that needs a national solution, and I urge the EPA to quickly finalize this common sense approach to protect public health and help states efficiently and cost-effectively clean up their air. [EPA-HQ-OAR-2009-0491-2853, p.2]
Sierra Club, Oklahoma Chapter
On behalf of the Oklahoma Chapter of the Sierra Club, we applaud the EPA for its action to help states be good neighbors by reducing air pollution escaping across state lines. We are pleased with this common sense approach by the EPA to protect public health and help states clean up their air efficiently and cost effectively. [EPA-HQ-OAR-2009-0491-2792, p.1]
Reducing air pollution will significantly improve visibility in our national parks and wilderness areas as well. According to a recent modeling study commissioned by the Sierra Club, significant visibility impacts have been predicted for Oklahoma's Wichita Mountains if the proposed coal plants in Texas are constructed in addition to the current visibility impairments connected to existing Texas coal plants. The tourism and recreational industry could be severely impacted if the increase in pollution occurs. The reduction in mercury contamination that this rule could provide would be greatly beneficial to Oklahoma as well. In July, the Oklahoma Department of Environmental Quality reported that sixteen lakes in Oklahoma have unsafe levels of mercury and issued consumption warnings for some fish from their waters. [EPA-HQ-OAR-2009-0491-2792, p.1]
As the Oklahoma Department of Environmental Quality, Attorney General for the State of Oklahoma, and other leaders and elected officials have previously stated (see attached), there is reason for concern with the sheer number of proposed coal plants in Texas and the process being employed by the Texas Commission on Environmental Quality (TCEQ) for their approval. The TCEQ did not provide timely notice of facilities' permit applications and has not adequately addressed the potential impacts on air quality in Oklahoma. In addition to emissions from a large number of existing coal fired plants already in operation in Texas, there is great concern that emissions from new sources will adversely impact air quality, public health and economic growth in Oklahoma. The emissions will also contribute to nonattainment of the national ambient air quality standards (NAAQS) in Oklahoma. Some municipalities in Oklahoma are very close or are already exceeding some NAAQS. It is important that we take steps to cut down interstate pollution that interferes with attainment and maintenance of the NAAQS. [EPA-HQ-OAR-2009-0491-2792, p.2]
With new ozone rules being finalized, more cities and counties in Oklahoma are at risk of going into non-attainment which would deter jobs and economic development in our cities, as well as an increase in health care bills. Oklahoma is doing all we can to meet attainment standards, and we implore you to use the Good Neighbor Rule to hold Texas accountable for their impacts on our air quality. [EPA-HQ-OAR-2009-0491-2792, p.2]
This is a national problem that needs a national solution, and we urge the EPA to quickly finalize this common sense approach to protect public health and help states efficiently and cost-effectively clean up their air. [EPA-HQ-OAR-2009-0491-2792, p.2]
Sierra Club, Pennsylvania Chapter
After eight years of the Bush Administration obfuscation, backsliding, inaction and actual prevarication, these newly proposed safeguards work hard to put public health and welfare on top as our first consideration, just as Congress intended within the Clean Air Act. Among those safeguards are efforts such as:
- The Good Neighbor Rule, which could help avoid 36,000 premature deaths from dirty air; [EPA-HQ-OAR-2009-0491-3482.1, p.2]
- The ground level ozone smog rule which could prevent more than 5,000 heart attacks and up to 12,000 early deaths;
- The coal ash rule, which could keep known carcinogens from toxic coal leftovers out of our water. [EPA-HQ-OAR-2009-0491-3482.1, p.3]
We have long known that power plant pollutant emissions can be transported for hundreds of miles downwind. Coal-fired electricity generating power plants spew their pollution across the nation and into the Mid-Atlantic, and while we cannot stop the pollution that crosses borders into our state, we need EPA to help us clean the air we breathe. Air at the state line is already too polluted. Pollution comes into Pennsylvania from as far away as Missouri, Georgia, Tennessee, Illinois and Indiana and across the rest of the Ohio River Valley. Our prevailing winds are southwest to northeast, and we have several pollution gradients that are west to east across Pennsylvania for both acidic precipitation and ground level ozone smog. We need to make sure that pollution from the Midwest, South and the Southeast won't spread into our state in the future. [EPA-HQ-OAR-2009-0491-3482.1, p.3]
The Sierra Club and its Pennsylvania Chapter supports the proposed EPA regulation, called the "Good Neighbor Rule" and the "Clean Air Transport Rule", because it will significantly reduce sulfur dioxide and nitrogen oxide pollution that create acid precipitation, ozone smog and fine particle pollution that blows into our state. This will improve the health of millions of people at risk from these pollutants, especially vulnerable peoples: seniors, children and people with chronic lung and cardiovascular diseases, and diabetes. Particulate pollution alone has been linked to over 5300 premature deaths in Pennsylvania, and has now been linked to actual mortality from cardiovascular disease and chronic respiratory disease. [EPA-HQ-OAR-2009-0491-3482.1, p.4]
EPA has made a good start. It is requiring that 31 states and the District of Columbia [DC] reduce sulfur dioxide [SO2] and nitrogen oxide [NOx] pollution emitted from fossil fuel fired power plants. However, we call on EPA to strengthen this rule. We need to have even greater reductions in the sulfur dioxide and nitrogen dioxide emissions that create deadly ozone and fine particle pollution. [EPA-HQ-OAR-2009-0491-3482.1, p.4]
EPA in this Transport Rule does what we cannot do: require coal-fired power plants that are spewing toxic pollution into our state to clean up their act. EPA must do the maximum that it can do to stop these dangerous emissions now. Our citizens have already waited too long, in spite of the best efforts and Clean Air Act of 1977 and the Clean Air Act Amendments of 1990. [EPA-HQ-OAR-2009-0491-3482.1, p.4]
Southern Environmental Law Center
The Southeast is plagued with unacceptably-high levels of ozone and particulate matter pollution, and its environment and population are particularly vulnerable to the deleterious effects of such pollution. [EPA-HQ-OAR-2009-0491-2801.1, p.1]
While adoption of a strong rule on transported pollution will provide crucial protection throughout the United States, it will perhaps most dramatically affect the health of people and places in the Southeast. Not only are many of the Southeast's major urban areas still struggling with the 1997 annual PM2.5 National Ambient Air Quality Standard ("NAAQS"), almost every Southern metropolitan area of any size would currently be in nonattainment under the highest annual PM2.5 standard recommended by EPA staff in the on-going review of the particulate matter air quality standards. Likewise, the six-state region covered by SELC has long fought to meet healthy  air standards for ozone, and appears fated to continue that struggle well in to the future. 5 [EPA-HQ-OAR-2009-0491-2801.1, p.2]

5. For a map showing the existing and potential nonattainment areas for ozone, see SELC's website at:  http://www.southernenvironment.org/cases/southern_air_smog/maps/ [EPA-HQ-OAR-2009-0491-2801.1, p.2]
State of Connecticut
The State of Connecticut is pleased that EPA recognizes interstate air pollution transport is a significant environmental and public health problem and we support strong federal action to address this transport. Adequately addressing transport is critical to achieving Connecticut's air quality goals. Attaining the federal health-based air quality standards for ozone remains a challenge in Connecticut even though we have adopted a stringent regulatory framework. Connecticut has been aggressively pursuing NOx and SO2 emission reductions since the Clean Air Act was adopted in 1970 and partly as a result of these programs Connecticut citizens are paying some of the highest electricity costs in the country. Unfortunately, much of the air pollution in Connecticut is blowing in from upwind states whose emissions overwhelm our ability to attain the health based national ambient air quality standards (NAAQS). Many of these upwind states have not done their fair share to reduce transported air pollution. [EPA-HQ-OAR-2009-0491-2534.1, p.1]
Clearly more reductions are necessary, and it is time for the Federal government to act decisively to address the long-standing problem of transport. EPA's modeling shows that, on high ozone days, well over 90% of the peak ozone monitored in Southwestern Connecticut can be attributed to transport from upwind states. We simply cannot control this air pollution and we need EPA's help to level the playing field so that Connecticut residents are not unfaifly prevented from enjoying clean air. [EPA-HQ-OAR-2009-0491-2534.1, p.1]
The State of Connecticut understands that as a good neighbor, we must ensure that emissions from our state do not negatively impact downwind states. We understand that there is more to be done, especially as national ambient air quality standards are improved to reflect the latest and best science. The State of Connecticut is committed to continue to work in cooperation with EPA and our sister states to do our fair share. But Connecticut cannot afford and should not be expected to bear a disproportionate share of the impacts of air pollution transport. Transported pollution is burdening our residents with adverse health impacts and weighing down our economy. EPA must adopt transport controls that fully comport with the the protections from air pollution transport provided to Connecticut and other downwind states under the federal Clean Air Act. [EPA-HQ-OAR-2009-0491-2534.1, p.2]
Response: 
These comments offer general support to the rule, providing examples of air quality benefits directly and indirectly related to the emissions reductions required by the rule.    EPA agrees with these statements of general support and agrees that the rule has significant benefits. 
Organization: Mothers and Others for Clean Air
Comment: 
Mothers and Others for Clean Air
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.19, 21-22.]
We need to explore each and every tool available to reduce the pollutants threatening the health of Georgia citizens, particularly children and seniors. The Transport Rule is an 24 important tool in the regulatory toolbox.
EPA has proposed to finalize the Transport Rule based on the reductions needed to enable states to meet the 1997 ground-level ozone standard of 84 parts per billion. However, in just two short months, EPA is expected to announce a new standard for ozone in the range of 60 to 70 parts per billion. Given the very significant difference between the 1997 standard and the new standard coming this fall, we would ask that EPA finalize the proposed Transport Rule with nitrogen oxide budgets designed to meet the new standard not the 1997 standard.
While we applaud EPA's commitment to evaluate whether new emissions reductions would be required from upwind states each time National Ambient Air Quality Standards are modified, we do not want to see a two-year delay to revise theTransport Rule when the new ozone standard is so close to being finalized. Please revise the NOx limits in the proposed Transport Rule based on the 2010 ozone standards as soon as possible.
Response: 
EPA appreciates the need to address the new ozone standards as quickly as possible.    There is, however, substantial technical work that must be completed once these standards become final, and to revise the final rule based on the new NAAQS would result in a substantial delay.   See section IV.C.1 for further discussion of EPA's use of the 1997 NAAQS as the basis for the ozone transport requirements of the rule.
Organization: New Jersey Department of Environmental Protection (NJDEP)
Comment: 
New Jersey Department of Environmental Protection (NJDEP)
The proposal is not sufficient to prohibit upwind sources from contributing to attainment problems in downwind states. Source-specific standards are needed for each source, particularly facilities on state borders. [EPA-HQ-OAR-2009-0491-2684.1, p.2]
The proposal allows the amount of emissions emitted by each source to shift within a set boundary. This does not guarantee that a specific source that has significant impact on a downwind state will ever control its emissions. A real case-in-point is the Portland Generating Station ('Portland Plant') in Pennsylvania that has an adverse impact on New Jersey's air quality due to its significant, largely uncontrolled emissions, and its close proximity to New Jersey. Under the Transport Rule, not all power plants in a large state like Pennsylvania would have to control their emissions. For example, under the Transport Rule, the Portland Plant could remain uncontrolled through the purchase of allowances generated through the installation of control devices at other power plants in the state. Although on paper this could meet the Transport Rule, in reality the actual upwind emissions from the Portland Plant would not change, and New Jersey's air quality, and consequently its citizens and environment, would continue to suffer as a result of the plant's emissions. [EPA-HQ-OAR-2009-0491-2684.1, p.2]
On May 12, 2010, Commissioner Martin submitted a Section 126 petition to the USEP A Administrator Lisa Jackson, seeking reductions in emissions from the Portland Plant due to its significant contribution to nonattainment and interference with maintenance of sulfur dioxide ('SO2') and 24-hour fine particulate matter (PM2.5) National Ambient Air Quality Standards (NAAQS) in New Jersey. On September 13, 2010, the NJDEP submitted to USEPA a supplement to New Jersey's May 12, 2010 petition pursuant to Section 126 of the Clean Air Act. The units at the Portland Plant, built in the 1950's and 1960's, have no SO2 emission controls and outdated control technology for NOx and particulate emissions. This petition was based on the 24 hour SO2 standard. With EPA's promulgation of the new 1-hour SO2 standard, the Department predicts that Portland's impact on New Jersey's air quality is much worse and covers a larger area, as indicated in our supplement to the Section 126 petition. [EPA-HQ-OAR-2009-0491-2684.1, p.2]
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.161.]
The rule is not stringent enough to provide the necessary emission reductions to remove all significant contributions from upwind states. In the rules Preamble, the USEPA states that there are still several areas that will not attain the old 85 ppb ozone NAAQS and the annual and daily PM 2.5 NAAQS. This includes nonattainment areas in New Jersey. This problem is compounded when you consider the current 75 ppb ozone standard or an even lower standard.
Response: 
EPA is taking action under a separate rulemaking to address the concerns expressed in the section 126 petition related to the Portland facility.  
See preamble section IV.C.1 for discussion of EPA's use of the 1997 ozone standard as the basis for the rule's ozone requirements.
Organization: Northeast States for Coordinated Air Use Management (NESCAUM)
Comment: 
Northeast States for Coordinated Air Use Management (NESCAUM)
EPA has indicated that this rule may not fully satisfy the transport requirements of the Clean Air Act for a few states, including within the NESCAUM region. EPA further indicates that a second transport rule is planned that will complete that task for future NAAQS. While we appreciate EPA's acknowledgement of this shortcoming, we find it troubling in several ways. First, we are concerned with the postponement of public health protection resulting from the rule's inadequacies in addressing transport in full. Second, we are concerned that it sets a precedent in the proposed framework that could allow postponement, to an uncertain date, of the essential remedy that downwind areas with significant pollution contributions from upwind sources need in order to meet the NAAQS. There are no assurances that future transport rules will not also fall short of their goals. [EPA-HQ-OAR-2009-0491-2694.1 p.2]
Response: 
In contrast to the proposal, the final rule shows that the transport requirements for the covered NAAQS are fully addressed for the NESCAUM region.
EPA agrees with the commenter that full resolution of significant contribution and interference with maintenance is the right goal for EPA's rulemaking efforts under section 110(a)(2)(D)(i)(I).  However, EPA is requiring emission reductions that make "measurable progress" toward that goal as directed to in the Court's remand of CAIR, and EPA believes that finalizing the Transport Rule at this stage offers the greatest benefits and most progress toward that goal.  EPA did not find cause to further delay the Transport Rule as would be required to consider additional reductions that EPA may ultimately find necessary to make a full determination of the elimination of significant contribution and interference with maintenance from certain states with regard to the 1997 ozone NAAQS.  EPA has committed to considering such reductions in a subsequent rulemaking.
Organization: South Carolina Department of Health and Environmental Control 
Comment: 
South Carolina Department of Health and Environmental Control 
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.83-84 and p.88.]
First, the proposed Transport Rule offers further evidence that the current uncoordinated approach to setting the National Ambient Air Quality Standards or NAAQS is inefficient.
The EPA intends to revise the Transport Rule with each new revision of a relevant NAAQS. Presumably this means that the EPA will tighten the budgets with each NAAQS revision. Ozone does fall, PM 2.5 in 2011, and so forth.
South Carolina certainly welcomes the ultimate public health and environmental benefits that these new tightened budgets could bring, but revising the Transport Rule according to the underlying schedule of NAAQS revisions is unnecessarily complex and benefits to the public -- to public health and environment could be delayed as rules and regulations are litigated.
Our fourth comment concerns the 2010 ozone standard. We trust that even with the recently announced delay as it relates to the standard that EPA will adhere to its commitment to promulgate a proposed revision to the Transport Rule in 2011 to address the finalized 2010 ozone standard so that pollution from an upwind state does not significantly contribute to non-attainment or interference with maintenance downwind for this lower standard.
Response: 
EPA intends to address transport of ozone under revised standards as quickly as possible once these NAAQS are published.

III.C. CAIR and NOx SIP Call Rulemaking History

Organization: Calpine Corporation
Comment: 
Calpine Corporation
We commend EPA for responding largely to the court decision remanding the Clean Air Interstate Rule (CAIR). [EPA-HQ-OAR-2009-0491-3614, p.2]
Response: 
Thank you for your comments.
Organization: North Carolina Department of Environment and Natural Resources
Comment: 
North Carolina Department of Environment and Natural Resources
The NCDAQ appreciates EPA's efforts to thoughtfully address the court's concerns with the Clean Air Interstate Rule (CAIR), The NCDAQ is pleased that EPA has committed to quickly finalize a second FTR in recognition that much tighter NOx caps will be necessary to address the pending revision to the 8-hour ozone standard, NCDAQ strongly supports EPA's pledge to review the FTR each time it revises an air quality standard. [EPA-HQ-OAR-2009-0491-2767.1, p. 1]
Response: 
Thank you for your supportive comments.
Organization: Tennessee Valley Authority (TVA)
Comment: 
Tennessee Valley Authority (TVA)
TVA submitted supportive comments on EPA's original Clean Air Interstate Rule (CAIR), and continues to support cap and trade rulemaking to achieve required emission reductions in a cost effective manner. [EPA-HQ-OAR-2009-0491-2782.1, p. 1]
Response: 
Thank you for your continued support of cap and trade rulemaking to achieve required emission reductions in a cost effective manner.

III.D. Primary Goals and Key Guiding Principles of Proposal

Organization: American Public Power Association (APPA)
Comment: 
American Public Power Association (APPA)
EPA`s task in developing this proposed rule was to remedy the deficiencies identified by the court in North Carolina v. EPA. To an extent, EPA appears to have attempted to discharge that obligation. Indeed, as discussed in section V of these comments, APPA agrees with certain aspects of the proposal. [EPA-HQ-OAR-2009-0491-2812.1, p.7]
Moreover, in many respects, EPA`s explanation of the elements of the PTR, and its information and calculations offered in support of the PTR, are opaque to the point of incomprehensibility. [EPA-HQ-OAR-2009-0491-2812.1, p.8]
Response: 
EPA's approach in the Transport Rule to measure and address each state's significant contribution to downwind nonattainment and interference with maintenance is guided by and consistent with the Court's opinion in North Carolina and addresses the flaws in CAIR identified by the Court therein.  The final rule also responds to extensive public comments and stakeholder input received during the public comment periods in response to the proposal and subsequent Notices of Data Availability (NODAs). 
EPA issued a series of NODAs related to the Transport Rule that together with the proposal offered adequate opportunity for public comment on all of the detailed information used and relevant projections in the final rule.
Organization: Clean Air Task Force
Comment: 
Clean Air Task Force
We believe that EPA's TR proposal is a good step towards requiring needed air pollution reductions in the electric power sector, and we commend EPA for bringing the proposal forward. We are concerned, however, that the proposal falls short of requiring the amount of cost-effective reductions that are reasonably obtainable, necessary to protect human health and the environment, and necessary to eliminate significant contribution to downwind nonattainment and maintenance problems.
However, CAIR was invalidated by the DC Circuit Court of Appeals in 2008, 11 and much of the progress made over the past few years will be in jeopardy without a strong Transport Rule to replace CAIR. Flue gas desulfurization devices ("FGDs" or "scrubbers") and selective catalytic reduction ("SCR") are widely available and extremely effective, but they have an operation and maintenance cost, so many utilities [EPA-HQ-OAR-2009-0491-2738.1, p.3] will not operate them unless they are required to do so. Furthermore, although progress has been made, in 2009 almost two-thirds of coal-fired units in the U.S. (over 700) are still operating with no sulfur scrubber in place. 12 These uncontrolled units represent about half of total US coal-fired boiler capacity. 13 This is clearly not adequate -- at this point, every coal-fired power plant in the U.S. should be well-controlled. [EPA-HQ-OAR-2009-0491-2738.1, p.4]
Power Plant Emissions Seriously Endanger Public Health and Welfare
As stated above, power plants remain a major a source of NOx and SO2 emissions, which react in the atmosphere to form other unhealthful secondary pollutants such as ground-level ozone and fine particulate matter such as sulfate and nitrate. EPA's "base case" estimates that by 2014, power plants will be responsible for over 70% of the SO2 emissions and more than one-fifth of the NOx emissions in the region of the eastern and Midwestern US impacted by EPA proposed rulemaking. 37 [EPA-HQ-OAR-2009-0491-2738.1, p.8]

Footnote 30: 75 Fed. Reg. at 45283-84. The remaining problem counties are Jefferson, AL; Cook and Madison, IL; Lake, IN; Oakland, Wayne and Washtenaw, MI; Hudson, NJ; NY, Suffolk and Westchester, NY; Cuyahoga, OH; Allegheny and Lancaster, PA; Brooke, WV; and Milwaukee, WI. See EPA (July 2010), "Copy of TR Nonattainment County Table070110.xls."
Response: 
The Transport Rule requires substantial near-term emission reductions in every covered state to address each state's significant contribution to nonattainment and interference with maintenance downwind.  This rule achieves these reductions through FIPs that regulate the power sector using air quality-assured trading programs with assurance provisions to ensure that the necessary reductions will occur within every covered state.  The Transport Rule's air quality-assured trading approach will assure environmental results while providing some limited flexibility to covered sources.  
EPA's approach in the Transport Rule to measure and address each state's significant contribution to downwind nonattainment and interference with maintenance is guided by and consistent with the Court's opinion in North Carolina and addresses the flaws in CAIR identified by the Court therein.  This final rule also responds to extensive public comments and stakeholder input received during the public comment periods in response to the proposal and subsequent Notices of Data Availability 
EPA believes that the Transport Rule's approach of using air-quality thresholds to determine upwind-to-downwind-state linkages and using the cost- and air quality-based multi-factor approach to determine the quantity of emissions that each upwind state must eliminate, i.e., the state's significant contribution to nonattainment and interference with maintenance, could serve as a precedent for quantifying upwind state emission reduction responsibilities with respect to potential future NAAQS.  
Organization: Institute of Clean Air Companies (ICAC)
Comment: 
Institute of Clean Air Companies (ICAC)
Another source of flexibility for sources comes from the APC industry. As outlined above, the APC industry offers lower capitol cost equipment and compliance approaches that, in combination with the proposed trading programs, may allow sources to delay or avoid the installation of more-capital intensive solutions and plan their pollution control investments accordingly. Thus, ICAC fully supports EPA's statement that "EPA's experience shows that providing ... the flexibility to seek alternatives to less cost-effective controls provides for greater environmental protection at reduced cost." 75 FR 45227/2 [EPA-HQ-OAR-2009-0491-2695.1, p. 3]
Response: 
EPA agrees with the commenter, and there is significant evidence that EPA programs to reduce air pollution from the power sector have led to improvements in both the cost and performance of pollution control technologies while achieving emission reduction objectives and environmental improvement that EPA seeks.
Organization: National Rural Electric Cooperative Association (NRECA)
Comment: 
National Rural Electric Cooperative Association (NRECA)
A significant portion of cooperative fossil fuel electric generation is located within the 32 state regions addressed in the proposed CATR and would be affected by its mandates. The proposal is complex, utilizes several atmospheric and economic models and extensive, although many times erroneous, electric utility unit operational and emissions control information to produce four separate electric utility cap and limited trading programs. Utilizing this extensive modeling, the final rule dictates essentially permanent unit compliance obligations through limiting unit emissions allowances, while providing only extremely limited opportunities for any allowance reconciliations and no criteria for doing so. [EPA-HQ-OAR-2009-0491-2723.1,p.3]
Most assuredly this proposal is an enormous undertaking that involves constructing a complex proposal meeting technical and legal requirements including those set forth in the court decisions overturning the Clean Air Interstate rule (CAIR), the CATR predecessor. Nevertheless, EPA has a legal obligation to orchestrate a rational rulemaking process that provides interested parties all the information needed to understand the proposal's rationale and interworking. The present "black box" approach falls short. Accordingly, NRECA urges EPA to issue a supplemental CATR proposal that specifies in adequate detail how specific unit emissions were determined as well as incorporating our suggestions below. [EPA-HQ-OAR-2009-0491-2723.1, pp.3-4]
Response: 
EPA issued a series of NODAs related to the Transport Rule that together with the proposal offered adequate opportunity for public comment on all of the detailed information used to project "specific unit emissions" in the final rule.  Furthermore, EPA strongly disagrees with the commenter's assertion that unit-level allocations represent "permanent unit compliance obligations" - under the Transport Rule programs, units are only required to submit allowances for tons emitted, and owners and operators have the flexibility to acquire additional allowances from the market in addition to whatever initial allocations they receive.  Allowance allocation in no way "dictates" unit operations under market-based trading programs.  Please see section VII.D of the preamble for more information on allowance allocation under the final Transport Rule."
Organization: Respiratory Health Association of Metropolitan Chicago
Comment: 
Respiratory Health Association of Metropolitan Chicago
[These comments were submitted as testimony at the Chicago, Illinois hearing.  See Docket Number EPA-HQ-OAR-0491-1746, pp.17-19.]
First of all, we urge the EPA to support steeper cuts in sulfur dioxide and nitrogen oxide which form fine particulate and ground-level ozone pollution. 
New science has shown fine particulate and ozone pollution to be more harmful than previously thought, so it's imperative that the EPA takes further action to eliminate the formation of these deadly pollutants. 
Moreover, stronger cuts in sulfur dioxide and nitrogen oxides will be vital in helping the states meet tougher particulate matter and ozone rules your agency is currently seeking to revise.
Second, we urge the EPA to require modern pollution controls at all coal plants.
Under the proposed Transport Rule, there is no guarantee that individual plants will install pollution controls.
Allowing older plants in some communities to evade pollution controls is unacceptable and does nothing for the people who live near the plant.
Moreover, allowing some plants off the hook brings up serious environmental justice concerns which seems at odds with EPA's new initiative to address environmental justice disparities.
We applaud EPA for its work to reduce emissions through dirty coal plants, but more needs to be done to reduce emissions from power plants.
For people who suffer from lung disease, clean air is not a luxury. It's a requirement.
Therefore, we urge U.S. EPA to tighten the proposed Clean Air Transport Rule to ensure all people are protected.
Response: 
EPA's approach in the Transport Rule to measure and address each state's significant contribution to downwind nonattainment and interference with maintenance is guided by and consistent with the Court's opinion in North Carolina and addresses the flaws in CAIR identified by the Court therein.  The final rule also responds to extensive public comments and stakeholder input received during the public comment periods in response to the proposal and subsequent Notices of Data Availability (NODAs). 
The remedy in the final rule allows air quality-assured trading to account for variability in the electricity sector, but also includes assurance provisions to ensure that the necessary emission reductions occur within each covered state.  The assurance provisions restrict EGU emissions within each state to the state's budget with the variability limit and ensure that every state is making reductions to eliminate the significant contribution to nonattainment and interference with maintenance that EPA has identified.  The great majority of public comments supported the preferred remedy.
Organization: Ritz, Aaron
Comment: 
Ritz, Aaron
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.176.]
Like the highly successful acid rain program, the rule sets final clean air requirements but gives coal plants flexible options to achieve those requirements.
Those plants responsible for the most air pollution will have to make a second round of pollution reductions so that residents in all states can enjoy clean, healthy air.
EPA has concluded that this plan is the most cost-effective way to protect air quality in neighboring states.
Response: 
The Transport Rule was designed to be flexible and cost effective, while addressing important air quality concerns.  The rule identifies emission reduction responsibilities of upwind states, and also promulgates enforceable Federal Implementation Plans (FIPs) to achieve the required emission reductions in each state through cost-effective and flexible requirements for power plants.  Each state has the option of replacing these federal rules with state rules to achieve the required amount of emission reductions from sources selected by the state.  
Organization: Rochester Public Utilities (RPU)
Comment: 
Rochester Public Utilities (RPU)
Given the complexity and breadth of the proposed Transport Rule (accompanied by the vast amount of supporting technical data in the docket), the significant differences between the data on which EPA based the proposed rule and the data EPA released later pursuant to the NODA, and the lack of specificity with respect to the allocation methodology applied, RPU believes that EPA should withdraw the Proposed Transport Rule, revise it using quality-assured, representative data (with appropriate input from the affected facilities), and republish it for public comment with an adequate comment period. [EPA-HQ-OAR-2009-0491-2802.1,p.2]
Response: 
EPA's approach in the Transport Rule to measure and address each state's significant contribution to downwind nonattainment and interference with maintenance is guided by and consistent with the Court's opinion in North Carolina and addresses the flaws in CAIR identified by the Court therein.  The final rule also responds to extensive public comments and stakeholder input received during the public comment periods in response to the proposal and subsequent Notices of Data Availability (NODAs). 
EPA issued a series of NODAs related to the Transport Rule that together with the proposal offered adequate opportunity for public comment on all of the detailed information used and relevant projections in the final rule.
Organization: Sierra Club, Pennsylvania Chapter
Comment: 
Sierra Club, Pennsylvania Chapter
Every polluter pays: In particular, each power plant and/or major stationary source [MSS] must reduce its own pollution emissions by a guaranteed amount. That will provide a floor of pollution reductions which each community can basically count upon, both to guarantee local air pollution reductions and protection of public health. This requirement would reduce enforcement complexities and simplify the efforts of state agencies to promptly enforce pollution caps. Additionally, this would reduce the health care costs in heavily impacted communities, reducing both hospital emergency room visits and hospital admissions. Employers would benefit also, with employees maintaining better health. [EPA-HQ-OAR-2009-0491-3482.1, p.4]
1. This proposed regulation package fails to utilize cost-effective reductions that are reasonably available, obtainable and necessary to protect human health and the environment, and necessary to eliminate significant contribution to downwind nonattainment and maintenance problems in the future. [EPA-HQ-OAR-2009-0491-3482.1, p.7]
Response: 
See preamble Section III.
Organization: South Carolina Department of Health and Environmental Control 
Comment: 
South Carolina Department of Health and Environmental Control 
DHEC generally supports EPA action on interstate transport of air pollutants. However, as stated above and in our October 1,20 10, comments, we have significant concerns about the NODA and the proposed Transport Rule, particularly South Carolina's inclusion in the Transport Rule trading programs. [EPA-HQ-OAR-2009-0491-3718.1_NODA,p.2]
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.84-85.]
In addition, this approach could hamper the long-term planning on which the emission trading scheme depends. South Carolina supports making the necessary improvements to the air quality management process that will ultimately involve state and local air agencies, as well as other stakeholders, in developing a comprehensive approach to air quality management that provides an opportunity for integrated multi-pollutant planning.
Response: 
EPA's approach in the Transport Rule to measure and address each state's significant contribution to downwind nonattainment and interference with maintenance is guided by and consistent with the Court's opinion in North Carolina and addresses the flaws in CAIR identified by the Court therein.  The final rule also responds to extensive public comments and stakeholder input received during the public comment periods in response to the proposal and subsequent Notices of Data Availability (NODAs). 
The approach embodied within the rule is partly designed to improve the planning process for the NAAQS, is readily applicable to any current and future NAAQS, and would automatically adjust the stringency of the transport threshold to maintain a constant relationship with the stringency of the relevant NAAQS as they are revised.  EPA believes that the final Transport Rule demonstrates the value of this approach for addressing the role of interstate transport of air pollution in communities' ability to comply with current and future NAAQS.  EPA believes that the Transport Rule's approach of using air-quality thresholds to determine upwind-to-downwind-state linkages and using the cost- and air quality-based multi-factor approach to quantify significant contribution to nonattainment and interference with maintenance (i.e., to determine the specific amount of emissions that each upwind state must reduce) could serve as a precedent for quantifying upwind state emission reduction responsibilities with respect to potential future NAAQS.
Organization: Southern Alliance for Clean Energy
Comment: 
Southern Alliance for Clean Energy
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.37.]
Now with this proposal, the good-neighbor provisions of the Clean Air Act will finally provide some relief for North Carolina and many other states struggling with non-attainment and poor air quality from out-of-state pollution.
Response: 
The Transport Rule requires substantial near-term emission reductions in every covered state to address each state's significant contribution to nonattainment and interference with maintenance downwind.  This rule achieves these reductions through FIPs that regulate the power sector using air quality-assured trading programs with assurance provisions to ensure that the necessary reductions will occur within every covered state.  The Transport Rule's air quality-assured trading approach will assure environmental results while providing some limited flexibility to covered sources.  
Organization: State of Connecticut
Comment: 
State of Connecticut
EPA should adopt a final Transport Rule that fully addresses the needs ofthe greater New York City area. As acknowledged by EPA in the preamble, the proposed Transport Rule requires controls in 2012 that do not fully address significant contribution to the greater New York City nonanattainment area (including portions of Connecticut) under the existing ozone NAAQS. As proposed, the rule fails to meet the requirements of the federal Clean Air Act. [EPA-HQ-OAR-2009-0491-2534.1 p.2]
Response: 
      The final Transport Rule does make a full determination of the emission reductions necessary to fully eliminate significant contribution to and interference with maintenance of the 1997 ozone NAAQS in the New York City area.  That being said, EPA believes the Transport Rule is responsive to the Court's direction that a replacement rule for CAIR show at least "meaningful progress" toward the full elimination of significant contribution and interference with maintenance.  The Agency has committed to conduct further analysis and consider additional emission reductions in a subsequent rulemaking to address the states for which EPA is making a partial determination in the final Transport Rule with regard to the 1997 ozone NAAQS. 
Organization: State of Delaware Department of Natural Resources & Environmental Control
Comment: 
State of Delaware Department of Natural Resources & Environmental Control
The EPA proposal is unnecessarily complex. Delaware is supportive of EPA's efforts to propose a rule that effectively eliminates an upwind state's significant contribution or interference of maintenance with a NAAQS in downwind states. The EPA has provided much complex information and analysis in their proposal and technical support documents. Delaware has gleaned from the EPA documents that there are two main determinations being made: 1) a determination of whether a state significantly interferes with the attainment or maintenance of a NAAQS in a downwind state, and 2) a determination of the remedy for the states that do significantly interfere. Delaware has spent considerable time studying the EPA proposal, and participating on telephone calls and meetings with others discussing the proposal, and has concluded that both EPA's characterization of the problem and the proposed solution have been made unnecessarily complex and difficult to understand and evaluate. This is a very important proposal to downwind states like Delaware. The health and welfare of Delaware citizens has and continues to be negatively impacted by emissions from upwind states, and those emissions must be mitigated. This unnecessary complexity has required Delaware to expend significant resources to review and understand the proposal, but even after spending many man-hours reviewing it is not clear that the rule will result in emission reductions once it is fully implemented. [EPA-HQ-OAR-2009-0491-2980.1, p.10]
Response: 
See preamble Section III.
Organization: State of Wisconsin, Department of Natural Resources
Comment: 
State of Wisconsin, Department of Natural Resources
The main focus for these comments is to ensure that the Transport Rule adequately addresses significant contribution for the current existing air quality standards, at least on the Clean Air Interstate Rule's (CAIR) schedule, while meeting the basic requirements identified by the Court. These comments are based on the following tenets that EPA should strongly consider: [EPA-HQ-OAR-2009-0491-2829.2, p.1]
Ensure upwind S02 and NOx reductions are adequate to ensure continued maintenance of the National Ambient Air Quality Standards (NMQS). [EPA-HQ-OAR-2009-0491-2829.2, p.1; This comment can also be found at section IV. of this comment summary]
Provide a clear, achievable and reasonably equitable structure to ensure Wisconsin sources in the sector(s) addressed are able to plan, fund and install emission control equipment sufficient to address all likely [Sec 110] significant contributions to downwind states that originate from the sector in Wisconsin. [EPA-HQ-OAR-2009-0491-2829.2, p.1; This comment can also be found at section IV.D. of this comment summary]
Better inform Wisconsin facility/source decision-making regarding related emission controls coming on line in the near future, including those expected from additional Title 1 requirements, Title 3 requirements and evolving carbon control policies. [EPA-HQ-OAR-2009-0491-2829.2, p.1; This comment can also be found at section III.F. of this comment summary]
Ensure that the cost impacts on Wisconsin sources, industry and ratepayers from this program are not so large that it precludes the certainty of continued electric system reliability as well as maintenance of a competitive power rate structure. [EPA-HQ-OAR-2009-0491-2829.2, p.1; This comment can also be found at section IV.D.1 of this comment summary]
The scope of emission reductions and budgets in the proposed Transport Rule are too limited. Currently, it does not provide a full remedy for states needing the reductions to ensure timely attainment and maintenance for both 1997 and 2010 ozone and 1997 and 2006 PM2.5 NMQS. In structuring this program, EPA should set additional control levels and phases through a supplemental notice of proposed rulemaking (SNPR) to start addressing the expected new ozone standard and the residual unmet contribution reduction identified for upwind states. [EPA-HQ-OAR-2009-0491-2829.2, p.1]
Addressing current 1997 and 2006 Air Quality Standards - Significant contribution remains for some states under the proposed rule. EPA needs to consider further EGU emission reductions as part of this rule and also clearly identify any non-EGU control programs that may be needed. [EPA-HQ-OAR-2009-0491-2829.2, p.2]
EPA in this rule making is appropriately addressing components of significant contribution from upwind states on downwind states relative to the active ozone and PM-2.5 ail' quality standards. The interstate transport of nitrogen oxide and sulfur oxide precursor pollutants and their derivative species that help lead to elevated concentrations of ambient ozone and PM-2.5 formation in Wisconsin has been and will remain a major concern in our attainment efforts addressing these standards for the foreseeable future. [EPA-HQ-OAR-2009-0491-2829.2, p.2]
Wisconsin feels the transport rule as proposed does not, however, completely fulfill EPA's obligation to address contribution relative to the 1997 8-hour ozone and 2006 PM-2.5 24 hour standards. The air quality modeling and analysis EPA conducted in developing the proposed TR FIP indicates significant residual nonattaimnent and maintenance problems will remain after this FIP which necessitates some level of additional annual and seasonal NOx and S02 reductions. Additional reductions are available from the EGD sector and should be clearly considered for those states remaining as significant contributors (still> 1%) under the finalized Transport Rule. For example, EPA's proposed 2014 S02 emission budgets for the Group 1 states is based on controls costing $2,000 per ton as projected in EPA's IPM model. However, EPA's analysis showed minimal or no significant contribution remained only when implementing regional controls beyond a $2,400 per ton threshold. Further, deeper emission reductions from the EGD sector can be achieved as fast as or more quickly than from other sectors. Therefore, these EGD reductions should not be discounted within the scope of this rule. To reach a deeper average control level, added budget reduction years beyond 2014 may be needed to provide time for the added control installations. Other flexibilities may also need to be incorporated into the rule to provide a platform for achieving reductions that fully address contribution (see following comments on emission budgets and trading program elements). [EPA-HQ-OAR-2009-0491-2829.2, p.2]
If EPA is not able to address full emission reduction remedy for residual significant contribution on a timely basis, or exclusively through reductions in the EGD sector, it at least needs to provide the downwind recipient states strong assurances of additional and rapid program development to address the problem. In other words, to be fully defensible the finalization of this Transport Rule needs to demonstrate a 'whole' framework that addresses significant transport with formal outline of new programs or the delineation of further EGD reductions under added later phases of the rule. [EPA-HQ-OAR-2009-0491-2829.2, p.2]
During the Collaborative discussions (2008-20010), Wisconsin recommended that EPA identify states with residual significant contribution to specific attainment or maintenance sites as projected after implementing the proposed EOU program. If this is done, it establishes a formal process for linking such residual contributing states to attainment and maintenance plan participation liability. This would greatly strengthen the overall framework while addressing one of the major legal concerns. If certain or the identified upwind states refuse to formally participate in downwind SIP planning efforts and liabilities, such as a RACM style commitment, budgets for EOU emissions in those states should automatically and significantly drop in a next program phase to a level that demonstrates added progress. The Court has suggested, in its remand of the CAIR program that the scope of such added control would need to directly address the residual air quality improvement need of the downwind state and account for some large portion of progress beyond base programs in sectors beyond EGUs. [EPA-HQ-OAR-2009-0491-2829.2, p.4]
Beyond the concern with state-to-state variability in emission rate reduction targets (both slope of control installation and absolute emission rates), caused by an over-concern with equalizing the marginal control cost-effectiveness between contributing states, the proposed 2014 budgets for NOx and S02 still leave multiple residual areas with residual attainment and/or maintenance problems directly linked to transport impacts. [EPA-HQ-OAR-2009-0491-2829.2, p.7]
Response: 
EPA's approach in the Transport Rule to measure and address each state's significant contribution to downwind nonattainment and interference with maintenance is guided by and consistent with the Court's opinion in North Carolina and addresses the flaws in CAIR identified by the Court therein.  The final rule also responds to extensive public comments and stakeholder input received during the public comment periods in response to the proposal and subsequent Notices of Data Availability (NODAs).  EPA agrees with some elements of the comments, but disagrees with others.  For more detail on EPA's approach for the final Transport Rule and key differences from the proposal in response to comment, see preamble Section III and other sections of the preamble that cover specific issues in much greater detail.
Organization: U.S. Department of the Interior
Clean Energy Group
National Association of Clean of Air Agencies (NACAA)
Dayton Power and Light Company (DP&L)
Energy Future Coalition
Republicans for Environmental Protection
Edison Electric Institute (EEI)
New York State Department of Environmental Conservation
City of Springfield, Illinois, Office of Public Utilities
Ozone Transport Commission (OTC)
Capital Power Corporation
GE Energy Financial Services (GE EFS)
Kansas Department of Health and Environment
Calpine Corporation
American Chemistry Council
Clean Air Council
George Washington University Regulatory Study Center
American Clean Skies Foundation (ACSF)
NextEra Energy, Inc.
Greenpeace Washington, DC
American Lung Association
Central Illinois Global Warming Solutions Group
Environmental Markets Association (EMA)
Comment: 
American Chemistry Council
ACC urges EPA to provide affected states and sources with the maximum amount of flexibility allowed under the Clean Air Act to best ensure that the most cost-effective solutions will be developed to comply with the rule. [EPA-HQ-OAR-2009-0491-2716.1, p.1]
American Clean Skies Foundation (ACSF)
ACSF supports reducing NOx and SO2 emissions from power plants-emissions which are disproportionately attributable to coal-fired plants. These pollutants cause significant public health and environmental problems. EPA estimates that if CATR is not implemented, power plants will emit more than 70% of the SO2 and about 20% of the NOx within the states targeted by CATR. [EPA-HQ-OAR-2009-0491-2759.1, pp.1-2]
In contrast to coal-fired power plants, natural gas plants emit substantially lower NOx and very little SO2. Accordingly, switching from coal to natural gas and renewable energy generation can achieve substantial reductions in particulate matter emissions and ozone pollution. Moreover, numerous modern, low-emitting, high-efficiency natural gas combined cycle plants are available today, with significant unused capacity, to replace existing coal-fired generation. [EPA-HQ-OAR-2009-0491-2759.1, p.2]
The Proposed Rule notes that for "almost 40 years, Congress has focused major efforts on curbing ground-level ozone." Unfortunately, CATR does not do enough to reduce the emissions from coal-fired power plants that cause violations of ozone (i.e., smog) and particulate matter air quality standards. In fact, with its current allocation method, CATR rewards high emitters that have failed to install pollution control equipment. These issues are further discussed below. [EPA-HQ-OAR-2009-0491-2759.1, p.2]
American Lung Association
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.63.]
First, we are pleased with EPA's decision to create a framework for setting emissions reductions under the 'good neighbor' provisions of the Clean Air Act.
Such a framework allows EPA to follow a strong logical pathway forward.
Calpine Corporation
Calpine believes that the proposed rulemaking could better promote the goal of reducing SO2 and NOx emissions from the electricity sector and level the playing field for companies that have invested in air pollution controls.  [EPA-HQ-OAR-2009-0491-3614, p.2]
Capital Power Corporation
Overall, CPC agrees with and supports the intent, timing, and general structure of the proposed rule. The proposed emissions caps are stringent yet attainable; and we accept the methods EPA used to model emissions to determine which areas contribute significantly to downwind nonattainment and maintenance. While we support the overall methodology, that does not preclude CPC from questioning the values used in the modeling and noting possible errors in data and inputs. [EPA-HQ-OAR-2009-0491-2753.1, p.2]
Central Illinois Global Warming Solutions Group
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.122-124.]
Secondly, I think that this Surface Transport Rule does a great job in that it doesn't allow grandfathering.
As someone who has spent years fighting hazardous waste landfills, it's very frustrating to be told, 'Well, it was,' quote, 'grandfathered' in at the time that the regulations went into effect.'
I'm pleased to see that the EPA has not chosen to grandfather anything in. Even 60-plus-year-old coal plants will remain unexempt from this regulation.
Thirdly, I'm happy to see that this regulation embodies the 'good neighbor' policy.
As the EPA begins to roll out policies, and they put this 'good neighbor' into effect, and which they know everyone is being regulated, and they're being regulated not just for their effect in the immediate area, but for their contributions to other areas.
It removes that barrier, and I think it's important to move forward in that way.
My only comments would be that I would hope that as the EPA goes forward that this will be part of a larger effort that will take a more holistic approach to pollution.
City of Springfield, Illinois, Office of Public Utilities
While CWLP objects to the Transport Rule as proposed, CWLP agrees with USEPA's goals and objectives in improving air quality and reducing the transport of airborne emissions.  [EPA-HQ-OAR-2009-0491-2635.1, p.1]
CWLP strongly supports the goals of the Clean Air Act and USEPA's efforts to achieve cleaner air and to restrict the transport of airborne emissions, but cannot support the Transport Rule as proposed for the reasons stated. Thank you for the opportunity to comment. [EPA-HQ-OAR-2009-0491-2635.1, p.3]
Clean Air Council
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.43.]
The EPA has done a good job of figuring out how to remedy the problems identified in the Court's decision in North Carolina versus the EPA, which struck down the Clean Air Interstate Rule. While the Council is mindful of not unnecessarily creating financial burdens on industry and their attempts to comply with this rule, the EPA is wise to limit interstate trading. This will ensure that a substantial portion of state's assigned emissions reductions occur in that state.
Clean Energy Group
The framework proposed by the Transport Rule would take necessary and important steps toward improving the air quality in the Eastern U.S. As EPA notes in the preamble and supporting materials for the Transport Rule, EPA's air quality modeling demonstrates that the Transport Rule would help many areas in the Eastern U.S. attain the current NAAQS by reducing transported air pollution that is demonstrated to contribute significantly to nonattainment or interfering with maintenance. The proposal would also establish a framework that would allow EPA to address any transport problems associated with the attainment of future NAAQS revisions, such as revisions to the 8-hour ozone NAAQS expected later this year. EPA can readily utilize the mechanisms and models that it has used in developing the proposed Transport Rule's state budgets to develop reduced budgets to meet any lower ozone or PM2.5 standards. By using this final rulemaking to establish a reasonable and consistent threshold for significant contribution, EPA will establish a framework for a clear adjustment to reflect any revised NAAQS. After identifying states contributing to the nonattainment or interference with maintenance of future NAAQS, EPA should promulgate revised budgets as soon as reasonable and certainly within a time frame that would allow companies to consider future requirements in capital planning and positioning in the allowance and electricity markets. [EPA-HQ-OAR-2009-0491-2702.1, pl 2]
Dayton Power and Light Company (DP&L)
The comments of the Midwest Ozone Group ('MOG') filed in the docket of the proposed Clean Air Transport Rule on October 1,2010, are hereby incorporated by reference. The MOG comments offer the results of modeling and air quality analyses showing that the air quality objectives of the Clean Air Transport Rule can be achieved without the implementation of any controls beyond the Clean Air Interstate Rule ('CAIR') and other on-the-books controls. [EPA-HQ-OAR-2009-0491-2637.1, p. 3]
Edison Electric Institute (EEI)
EEI shares a commitment with the Environmental Protection Agency (EPA) to further reduce emissions from power generating facilities and supports the general policy objectives underlying EPA's proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2697.1, p.1] [These comments were also submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.99.]
Energy Future Coalition
By regulating power plant emissions, the CATR provides an important tool for facilitating this transformation in electricity; however, it does not go far enough. [EPA-HQ-OAR-2009-0491-2623.1, p.1]
Environmental Markets Association (EMA)
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.47.]
Environmental Markets Association recognizes EPA's efforts in the proposed Transport Rule to preserve a critical role for emissions trading in environmental regulation, while working within the bounds of the Court decision to guarantee that interstate transport pollutants does not interfere with attainment in downwind states.
GE Energy Financial Services (GE EFS)
GE EFS supports EPA's efforts to achieve significant additional reductions in emissions contributing to interstate pollution. GE EFS strongly believes that establishing a regional emissions trading program is the best way to assure that electric generators achieve the required reductions and thereby eliminate upwind states' contribution to nonattainment or interference with maintenance of ambient air quality standards in downwind states. After two years of significant uncertainty since the D.C. Circuit initially vacated and subsequently remanded the Clean Air Interstate Rule ('CAIR') in North Carolina v. EPA, GE EFS looks forward to EPA's development of a replacement to CAIR that will satisfy the requirements of the Clean Air Act. [EPA-HQ-OAR-2009-0491-2701.1,pp.1-2]
George Washington University Regulatory Study Center
While we accept the need to replace CAIR and applaud many elements of the EPA's approach, above all its decision to provide a role for emissions trading markets,6 we argue that the agency can and should make changes -- including some significant changes -- to the Rule before it is finalized. [EPA-HQ-OAR-2009-0491-2573.1,p.4]
We argue that taking these three steps in the final Transport Rule would result in a more effective, more robust, and more palatable rule, without any significant sacrifice in environmental benefits. The changes we recommend would also both reduce the likelihood of litigation over the Transport Rule and increase the EPA's chances of success in any litigation that does arise. They would further generate confidence in the EPA's management of emissions trading programs and conduct of cost-benefit analysis and would have important reputational impact extending beyond the Transport Rule. [EPA-HQ-OAR-2009-0491-2573.1, p.32]

 6 While discussion of the issue is beyond the scope of this comment, the EPA's decision to sharply limit interstate trading of allowances tempers our enthusiasm for the market-based elements of the Transport Rule.
Greenpeace Washington, DC
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.35.]
Given the history of backdoor deals, especially here in Illinois, with Fisk and Crawford, that allow polluters to pick and choose which plants to clean up, the Transport Rule and EPA should require statewide emissions and plant-specific reductions to minimize the influence of emissions trading and the fact that many of these people in communities from Joliet to Chicago are being left behind.
Kansas Department of Health and Environment
KDHE supports the efforts of EPA to have a multi-state rule that reduces transport of emissions that impact attainment of the NAAQS throughout the United States. As you are likely aware, Kansas emission sources, particularly electric generating units (EGU s), have made significant reductions in emissions over the last several years. These emissions reductions continue to occur now in 2010, and additional reductions will occur for several years to come as additional controls are put in place and utilized. [EPA-HQ-OAR-2009-0491-2606.1, p.1]
National Association of Clean of Air Agencies (NACAA)
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.106. Also as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.79-80.]
We applaud EPA for thoughtfully considering how to remedy the fatal flaws identified in court decisions striking down the CAIR rule. 
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.78-79.]
Controlling these sources is highly cost effective; EPAs own analysis shows a 40 to 1 and up to a 100 to 1 benefit-to-cost ratio for the power plant controls in the Transport Rule. Accordingly, this rule provides EPA with a tremendous opportunity to assist state and local air pollution control agencies throughout the eastern half of the United States with meeting their clean air obligations.
New York State Department of Environmental Conservation
The Department fully supports EPA in its mission to develop programs to remedy the transport of emissions, but it must be based on sound data and done with sound analyses to support its conclusions. It must also be done in manner that provides for a complete opportunity for public review of the data used in the analyses. [EPA-HQ-OAR-2009-0491-3763.1_NODA, p.2]
NextEra Energy, Inc.
With the possible exception of EPA's proposed allowance allocation approach (see discussion beginning on Page 3 of our comments), NextEra Energy believes that the proposed Transport Rule satisfactorily addresses the legal requirements set out in the D.C. Circuit's decision vacating the Clean Air Interstate Rule (CAIR), North Carolina v. EPA. As noted above, the Clean Air Act requires states to ensure they do not significantly contribute to downwind states' nonattainment and interference with maintenance. We believe that the proposed rule satisfies that legal obligation and addresses the additional flaws identified by the D.C. Circuit. [EPA-HQ-OAR-2009-0491-2718.1, p.2]
Ozone Transport Commission (OTC)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.112.]
We also commend EPA for addressing the Courts and the states concern with the relationship between emission reductions and downwind contributions, and important transport issue that caused the Court to reject and remand the 2005 Clean Air Interstate Rule (CAIR) back to EPA.
The proposed rule provides a strong, science-based methodology that can achieve significant reductions in air pollution from power plants transported from upwind states into and within the OTC region.
Republicans for Environmental Protection
The job of securing cleaner air for America's families and communities, however, is not complete. A significant fraction of the coal-fired power plants that generate about half the electricity used in America lack equipment to control emissions of pollutants that create ozone smog and tiny particulates, which are known respiratory and cardiac health hazards. [EPA-HQ-OAR-2009-0491-1892.1, p. 1] The Environmental Protection Agency's proposed Clean Air Transport Rule, which would reduce emissions of sulfur dioxide and nitrogen oxides by 71 percent and 52 percent, respectively, in 31 states east of the Rocky Mountains and in the District of Columbia, would result in significant public health benefits. [EPA-HQ-OAR-2009-0491-1892.1, p. 1] The rule, scheduled to take effect in 2012, would deliver up to $290 billion worth of health and public welfare benefits in 2014 alone, including avoidance of 14,000 to 36,000 premature deaths. Compliance costs would total $2.8 billion annually, far less than the value of the benefits. [EPA-HQ-OAR-2009-0491-1892.1, p. 1]
U.S. Department of the Interior
The Department supports EPA's proposal to require specific emissions limits for sulfur dioxide and nitrogen oxides for 32 eastern states to mitigate those states' contributions to nonattainment or their interference with maintenance ofnational ambient air quality standards in one or more downwind states. The required emissions limits are intended to eliminate the interstate contributions to the 1997 annual standard for fine particulate matter, the 2006 24-hour standard for fine particulate matter, and the 1997 8-hour standard for ozone. These primary standards were set to protect human health. EPA intends to revise the ozone and fine particulate matter standards in 2010 and 2011, and we encourage EPA to promptly propose additional emissions reductions to address interstate contributions under the revised standards. [EPA-HQ-OAR-2009-0491-2255.1, p.1]
EPA's proposed emissions reductions will also reduce fine particulate matter that contributes to visibility impairments in our national parks and wilderness areas. These emission reductions are necessary to ensure reasonable progress toward visibility improvement as required under the Regional Haze Rule. Several eastern states relied on the Clean Air Interstate Transport Rule (CAIR) to demonstrate progress in their State Implementation Plans for Regional Haze. Reductions equivalent to or greater than the CAIR reductions are necessary to comply with the Regional Haze Rule provisions for Best Available Retrofit Technology and to validate the state implementation plans for regional haze. Emissions reductions under the Transport Rule would also reduce ozone that adversely impacts vegetation and reduce deposition of sulfate and nitrate that impairs sensitive terrestrial and aquatic ecosystems. We encourage EPA to proceed expeditiously to finalize this rule.  [EPA-HQ-OAR-2009-0491-2255.1, pp. 1-2]
Response: 
See preamble Section III.
Organization: West Window Corp.
Comment: 
West Window Corp.
The data that the EPA used to develop the rules were outdated and based on inaccurate information, thus causing the EPA to underestimate the amount of work needed to comply, as well as the cost. [EPA-HQ-OAR-2009-0491-2386, p.1]
Response: 
EPA's approach in the Transport Rule to measure and address each state's significant contribution to downwind nonattainment and interference with maintenance is guided by and consistent with the Court's opinion in North Carolina and addresses the flaws in CAIR identified by the Court therein.  The final rule also responds to extensive public comments and stakeholder input received during the public comment periods in response to the proposal and subsequent Notices of Data Availability (NODAs). 
EPA issued a series of NODAs related to the Transport Rule that together with the proposal offered adequate opportunity for public comment on all of the detailed information used and relevant projections in the final rule.

III.E. Why Does This Proposed Rule Focus on the Eastern Half of the United States/ 37-State Region Analyzed

Organization: Midamerican Energy Holdings Company
Comment: 
Midamerican Energy Holdings Company
The Coverage of the Proposed Transport Rule Should Not be Extended
As the EPA has recognized, interstate transport made much smaller contributions to exceedances of the 1997 PM2.5 standards in the Western United States. (See p. 45227). MidAmerican agrees that Western states should not be included in the proposed is no widespread non-attainment of ozone and PM2.5 NAAQS in the West. Outside of California, western non-attainment is limited to urban areas and power plant emissions are not considered as major sources of such impairment. In the West, mobile sources are the dominant contributors (69%) of NOx emissions, a precursor to ozone formation, while power plants contribute only 15.5%. [EPA-HQ-OAR-2009-0491-2748.1 p.5-6]
The Grand Canyon Visibility Transport Commission Report and decades-long monitoring data in Class I areas by the National Park Service show that NOx emissions (from all sources) contribute less than 5% of the visibility impairment on the Colorado Plateau. Moreover, ongoing implementation of the "BART" reasonable progress provisions of the EPA Regional Haze Rule will further reduce utility NOx emissions during the next 5 years. [EPA-HQ-OAR-2009-0491-2748.1 p.6]
Existing Clean Air Act regulations pertaining to ozone and PM2.5, regional haze, and the permitting of new or modified sources adequately address NOx emissions from western fossil fuel-fired power plants. Source-specific Clean Air Act regulations will also not allow a robust NOx trading program in the West. The majority of western fossil plants employ SO2 scrubbers, on top of burning low sulfur coal. Requiring additional SO2 reductions may simply result in western sources buying allowances from Eastern sources. [EPA-HQ-OAR-2009-0491-2748.1 p.6]
Response: 
The final rule, as for the proposal, addresses transport in the eastern half of the United States.
Organization: Minnesota Pollution Control Agency (MPCA)
Comment: 
Minnesota Pollution Control Agency (MPCA)
As a state on the western edge of the covered area, Minnesota is particularly vulnerable to receiving  increased transport of pollutants due to leakage of emissions from covered to non-covered states. Minnesota is currently in attainment with the 1997 ozone and 2006 fine particulate matter National Ambient Air Quality Standards (NAAQS); however, as these NAAQS are revised and lowered, Minnesota's attainment status may be in jeopardy and the impact of transported pollutants will become more critical. The MPCA hopes that EPA will evaluate the necessity of having additional states covered  by a transport program as the rule is changed and updated to account for the revised NAAQS. [EPA-HQ-OAR-2009-0491-2521.1, p.1]
Response: 
EPA intends to re-evaluate transport to Minnesota in future rulemakings addressing transport under more stringent NAAQS. 
Organization: National Rural Electric Cooperative Association (NRECA)
Edison Electric Institute (EEI)
Xcel Energy Inc.
Arizona Public Service (APS)
WEST Associates
Comment: 
Arizona Public Service (APS)
APS is responding to EPA's request for comment on the assessment that western states should not be included in this rulemaking. APS agrees with the EPA's determination and concurs that the proposed Clean Air Transport Rule should not be extended to the western United States. [EPA-HQ-OAR-2009-0491-2824.1, p. 2]
Unlike in the East, there are no regional, widespread non-attainment areas of PM2.S or ozone in the West, outside of California (California has no coal-fired power plants). Isolated nonattainment areas of the annual and 24 hour PM2.5 and ozone NAAQS in the West are mainly found in urban areas. Coal-fired power plants in the West are located generally in rural areas, far away from those urban areas identified with non-attainment problems. A vast majority of western coal-fired power plants burn low sulfur-content coals and are already well-controlled for S02 emissions. With respect to NOx, emissions from EGUs represent only 17.3% of the total emissions in the west. In addition, most coal-fired power plants in the West are undergoing the 'Best Available Retrofit Technology' process, and consequently, it is assumed those emissions will be further reduced during the next few years. [EPA-HQ-OAR-2009-0491-2824.1. p. 2]
Even in western non-attainment areas (outside California), sulfates and nitrates resulting from coal-fired power generation are minor components of the PM2.5 concentration levels. In fact, organic and elemental carbon and crustal materials dominate PM2.5 A good example of this is the PM2.5 non-attainment designation submittal to EPA by the Arizona Department of Environmental Quality (ADEQ) for Pinal County. In the EPA Technical Analysis, ADEQ attributes the main causes of exceedances to agricultural activities, feedlots, and geological soil. The chemical components of emissions associated with these activities are primarily carbonaceous materials and soils/ crustal material. [EPA-HQ-OAR-2009-0491-2824.1, p. 2]
Ambient air quality data collected over the past decade from rural areas in the West under the IMPROVE Network for the National Park Service show that nitrates typically constitute less than a few percent of the PM2.5 on an annual average, and sulfate concentrations have been declining and do not form the largest fraction of the PM2.5 samples. Sampling and speciation analyses at the Grand Canyon and Mount Rainier IMPROVE sites show that nitrate mean concentration levels are 0.22 and 0.20 (ug/m\ and mean concentration levels for sulfates are 0.80 and 0.91 (ug/m3 ) respectively These values are significantly lower than the overall measured PM2.5 concentrations of 2.71 (ug/m3 ) at the Grand Canyon site and 3.92 (ug/m3 ) at the Mount Rainier site. Furthermore the overall mean concentrations of fine particulate matter at the two IMPROVE sites are well below the PM2.5NAAQS concentration level of 1 5 (ug/m3 ). [EPA-HQ-OAR-2009-0491-2824.1, p. 2]
APS supports EPA's determination that western states should not be included in the Clean Air Transport rulemaking and recommends that EPA not change its current position. APS believes there is substantial evidence showing the composition of fine particulate matter emissions in the West is different than in the East. Specifically, nitrate and sulfate emissions from fossil fuel fired power plants play a much smaller role in contributing or interfering with maintenance of nonattainment areas for the PM25 and ozone NAAQS. [EPA-HQ-OAR-2009-0491-2824.1, p. 3]
Edison Electric Institute (EEI)
In the Proposed Rule, EPA asks for comment on its assessment of why the Proposed Rule focuses on the eastern half of the United States and why the Western U.S. is not included. EPA notes that "in developing CAIR, EPA found that interstate transport (particularly for anthropogenic emissions) made much smaller contributions to exceedences of the 1997 PM2.5 standards in the Western United States." 75 Fed. Reg. 45227. EPA also notes that "Technical information developed for EPA's recently completed nonattainment designations suggest that interstate transport makes a relatively small contribution to exceedences in the western United States under the 2006 PM2.5 standards." EPA concludes that "A review of this information suggests to EPA that the Western nonattainment problems are relatively local in nature with limited interstate transport." Id. EEI concurs with this assessment and supports EPA's decision not to include Western states in the Proposed Rule.  [EPA-HQ-OAR-2009-0491-2697.1, p.14]
Several EEI member companies from the Western U.S. make additional observations supporting the continued exclusion of Western states from the Proposed Rule. First, unlike in the East, there is no widespread non-attainment of the ozone and PM2.5 NAAQS in the West. Second, outside of California, western non-attainment is limited to urban areas and power plant emissions are not considered as major sources of such impairment. In the West, mobile sources are the dominant contributors (69 percent) of NOx emissions, while power plants contribute only 15.5 percent. Regarding SO2, the majority of western fossil plants employ FGD, in spite of the fact that they burn low sulfur coals. Third, ongoing implementation of the Best Available Retrofit Technology (BART) reasonable progress provisions of EPA Regional Haze Rule will further reduce utility NOx emissions during the next 5 years. Further, existing CAA regulations pertaining to ozone and PM2.5 and the permitting of new or modified sources adequately address emissions from western fossil fuel-fired power plants. [EPA-HQ-OAR-2009-0491-2697.1, p.14]
National Rural Electric Cooperative Association (NRECA)
Western areas outside of the 32 state trading region are properly excluded from the proposal. [EPA-HQ-OAR-2009-0491-2723.1, p.2]
According to EPA, technical support for this proposal identified 37 states for interstate transport analysis. The proposal mandates requirements for only 32 states, because although analysis indicates that NAAQS exceedances for PM2.5 were identified in some Western areas outside of the CATR region, the problems were determined to be local in nature. EPA requests comment on this assessment. [EPA-HQ-OAR-2009-0491-2723.1, p.17]
NRECA agrees with EPA's assessment that NAAQS nonattainment problems outside of the proposed CATR 32 state region are local in nature and do not require interstate emissions reductions. Additional observations below support the approach in this rulemaking to exclude additional Western areas in the CATR.  [EPA-HQ-OAR-2009-0491-2723.1,p.17]
There are no widespread areas of ozone and PM2.5 NAAQS non-attainment in areas outside of the 32 state CATR region. The Outside of California, western non-attainment is limited to urban areas and power plant emissions are not major sources of this nonattainment. Further in the West, mobile sources are the dominant contributors (69percent) of NOx emissions, a precursor to ozone formation, while power plants contribute only 15.5 percent. [EPA-HQ-OAR-2009-0491-2723.1, p.17]
The Grand Canyon Visibility Transport Commission Report and decades-long monitoring data in Class I areas by the National Park Service show that NOx emissions (from all sources) contribute less than 5 percent of the visibility impairment on the Colorado Plateau. Moreover, ongoing implementation of the best available retrofit technology (BART) reasonable progress provisions of the EPA's Regional Haze Rule will further reduce utility NOx emissions during the next five years.  [EPA-HQ-OAR-2009-0491-2723.1, p.18]
Existing CAA regulations pertaining to ozone and PM2.5, regional haze, and the permitting of new or modified sources adequately address NOx emissions from western fossil fuel-fired units. The majority of these units also employ FGDs and burn low sulfur coal, thus mandating additional SO2 reductions from them would result in little air quality benefit. [EPA-HQ-OAR-2009-0491-2723.1, p.18]
WEST Associates
WEST understands that EPA's proposed Transport Rule to apply exclusively to the electric generating units (EGUs) in the 32 eastern states because that action may reduce the impact of transported emissions on downwind states in the eastern areas for ozone and PM2.5. Our view is that if this program were extended on a nationwide scale, this proposed EPA action would not yield the same result in the western United States for the following specific reasons: [EPA-HQ-OAR-2009-0491-2604.1,p.1]
   * Unlike in the East, there is no widespread non-attainment of ozone and PM2.5 NAAQS in the West. Outside of California, western non-attainment is limited to urban areas and power plant emissions are not considered major sources of such impairment. In the West, mobile sources are the dominant contributors (69%) of NOx emissions, a precursor to ozone formation, while western coal-fired power plants contribute only 15.5% (all EGUs, 17.3%). [EPA-HQ-OAR-2009-0491-2604.1, p.1]
   * Existing Clean Air Act (CAA) regulations pertaining to ozone, PM2.5, regional haze, and the permitting of new or modified sources adequately address NOx and SO2 emissions from western fossil fuel fired power plants.
   * The GCVTC Report and decades-long monitoring data in Class I areas by the National Park Service show that NOx emissions (from all sources) contribute less than 5% of the visibility impairment on the Colorado Plateau. Ongoing implementation of the "BART" determinations and reasonable progress provisions of the Environmental Protection Agency's (EPA) Regional Haze Rule will further reduce utility NOx emissions during the next 5 years.
   * The majority of western fossil plants employ SO2 scrubbers, in addition to burning low sulfur coal.
   * There are no PM2.5 nonattainment designations in the West attributable to high sulfate concentrations. Therefore, if additional SO2 reductions were extended to the West, it would penalize the local electricity consumers without providing measurable benefits in air quality.
   * Air Quality measurements made over the years in Class I Areas under the IMPROVE Network operated for the Federal Land Managers all over the West indicate PM2.5 concentrations well below NAAQS levels. Chemical compositions of those PM2.5 samples show the predominance of carbonaceous particles and crustal materials. [EPA-HQ-OAR-2009-0491-2604.1,p.2] 
Extending the Transport Rule on a nationwide basis would impose regulatory burdens in the western states without a commensurate benefit to resolving NAAQS nonattainment issues in the West. [EPA-HQ-OAR-2009-0491-2604.1,p.2]
Xcel Energy Inc.
IV. EPA'S ANALYSIS AND JUSTIFICATION FOR THE PROPOSED RULE
1. Xcel Energy supports EPA's assessment that western states should not be included in CATR.
Xcel Energy agrees with EPA's assessment of why this proposed rule focuses on the eastern half of the United States, found on page 45227. Xcel Energy also supports the comments offered by the Edison Electric Institute ('EEI') and WEST Associates regarding EPA's treatment of western states, specifically the comments supporting EPA's decision to exclude western states from CATR. [EPA-HQ-OAR-2009-0491-2728.1. p.8]
Response: 
EPA agrees as noted in the preamble to the proposed rule that transport issues in the western United States are analytically distinct from those in the eastern United States.    EPA notes that transport requirements for these states under the 1997 ozone standards, and under the 1997 and 2006 PM2.5 standards, must still be addressed in state SIPs, but this is appropriately accomplished separately from this Transport Rule.   
EPA and states are addressing visibility in western states through the implementation of EPA's regional haze rule and other visibility requirements.
 
Organization: State of New Mexico Environmental Department
Comment: 
State of New Mexico Environmental Department
The AQB does not agree with the Environmental Protection Agency's (EPA) finding in the proposed rule for interstate transport of PM2 5 and ozone that, by and large, nonattainment designations for ozone and PM2.5 in the western region of the United States are primarily due to localized contributions and not transport. The transport of air pollutants, particularly ozone, in the western United States is becoming an increasingly important issue. It is important that the role of transport in the west is evaluated carefully, especially as the level of the NAAQS for PM2.5 and ozone are reduced. [EPA-HQ-OAR-2009-0491-1927.1, p. 1]
Interstate and International Transport A detailed photochemical modeling analysis of current and potential future air quality conditions in the Four Comers region was carried out during 2007 - 2009 (Air Quality Modeling Study for the Four Comers Region, Stoeckenius et aI., 2009). The modeling study and associated documents are available online: http://www.nmenv.state.nm.us/aqb/4C/Modeling.html. Results from the study show that boundary conditions and western United States transport are both very significant to ozone levels in the Four Comers area of New Mexico. Boundary conditions representing the contributions of ozone and precursors transported into New Mexico from sources outside of the western U.S. were the single largest contributing source group to ozone formation. The modeling results estimated that boundary conditions contributed 0.040 ppm or more to certain 8-hour ozone peale levels in Northwestern New Mexico. The modeling results also predicted that transport of precursors and ozone into the Four Comers area from other parts of the western United States contributes significantly to ozone levels in the region. [EPA-HQ-OAR-2009-0491-1927.1, pp. 1-2]
New Mexico is also significantly affected by international transport. International transport from Mexico may be insignificant when analyzed on a national level, but it is a significant source of air pollution for the border region of the southern United States. Up to this point, the only area in New Mexico that has been designated nonattainment for ozone (I-hour) or has monitored high levels of PM25 is the small community of Sunland Park, New Mexico which is located adjacent to the City of EI Paso, Texas, and Ciudad Juarez, Mexico. This small community with a population of 13,000 contributes roughly three percent of the total ozone precursor emissions within this air shed, yet it may violate the reconsidered ozone NAAQS. Controlling local sources would have a negligible effect in reducing ozone concentrations in this instance. [EPA-HQ-OAR-2009-0491-1927.1, p. 2]
The AQB recently completed an analysis of monitoring data for the Sunland Park, EI Paso, and Ciudad Juarez region (the Paso del Norte air shed) regarding PM exceedances during periods of calm winds. A saturation network of thil1een PM25 monitors was deployed in the Paso del Norte air shed. The study investigated the spatial and temporal behavior of PM2 5 during low wind, stagnation episodes for the monitoring period of October 2008-April 2009. Using an air mass back-trajectory model for six episodes, a source area south of Sunland Park was identified. Based on this effort, the general locations of particulate emission sources contributing to low-wind exceedances are localized to an area three (3) to four (4) kilometers south of Sunland Park in Ciudad Juarez, Mexico. [EPA-HQ-OAR-2009-0491-1927.1, p. 2]
CAA 110(2 )(D )0)(1) Requirements The preamble to the proposed rule notes that although western states are not significantly affected by interstate transport, those states need to address the requirements of Clean Air Act (CAA) Section 11O(a)(2)(D)(i)(I). The rule does not discuss how western states should do so. While the AQB does not agree with EPA's conclusions regarding the role of transport in the west, as discussed above, we believe EPA should be consistent in its position on the meaning of its modeling. If in EPA's view modeling conducted for the proposed interstate transport rule indicates that nonattainment designations in the western region of the United States for PM25 and ozone are primarily due to localized sources, then EPA should not require additional modeling demonstrations from western states. Requiring modeling would place an unfair burden on western states to perform the sort of analysis provided by EPA for the eastern states. Instead, EPA should accept its own modeling results as demonstrating compliance with CAA 110(a)(2)(D)(i)(I) for those states not included under the proposed interstate transport rule. [EPA-HQ-OAR-2009-0491-1927.1, p. 2]
A better approach, however, would be for EPA to provide the western region of the United States with the same attention afforded to the eastern region, including modeling analyses, technical assistance and guidance needed for states to better understand and account for regional influences that are affecting air quality in order to comply with the requirements of CAA 110(a)(2)(D)(i)(I). The diversity of sources in the west, particularly for ozone precursor emissions, requires at least a similar type study as conducted by the Ozone Transport Commission for the east with equivalent or greater support from EPA. The AQB strongly encourages EPA to lead such an effort. [EPA-HQ-OAR-2009-0491-1927.1, pp. 2-3]
Response: 
As noted in the preamble to the proposed rule, EPA considers transport issues in the eastern United States to be analytically distinct and this rule focuses only on that subset of section 110(a)(2) issues.    Western states need to address the requirements of section 110(a)(2)(D)(i) of the CAA, as relates to the 1997 and 2006 PM2.5 and ozone standards, as a separate exercise.   
 
 
Organization: Tuscon Electric Power Company
Comment: 
Tuscon Electric Power Company
TEP owns and operates electric generation, transmission, and distribution assets and reliably serves more than 400,000 customers in Southern Arizona. TEP generates electricity both from firing fossil fuels as well as from use of renewable resources. TEP's operations are located entirely outside of the geographical reach of the Transport Rule. We submit these comments in anticipation that other stakeholders may suggest that EPA expand the program to States further west based on the incorrect assumption that interstate transport represents a significant contribution to National Ambient Air Quality Standard (NAAQS) non-attainment in the west. [EPA-HQ-OAR-2009-0491-2671.1, p.1]
EPA has analyzed data relating to interstate transport in the west and has concluded [75 FR 45227] that western NAAQS non-attainment is primarily a localized effect and not significantly affected by interstate transport. [EPA-HQ-OAR-2009-0491-2671.1, p.1]
Emissions of NAAQS pollutants and pre-cursors from electric generating units in the west are small in comparison to the emissions from other western sources. [EPA-HQ-OAR-2009-0491-2671.1, p.2]
Emissions of NOx from electric generating units has been and will continue to be reduced through implementation of other Clean Air Act programs, most significantly through the Regional Haze Rule provisions relating to Best Available Retrofit Technology and Reasonable Progress Goals. [EPA-HQ-OAR-2009-0491-2671.1, p.2]
EPA has stated [75 FR 45228] that it intends to initiate a separate rulemaking in 2011 (Transport Rule II) to address interstate transport relating to the upcoming 2010 NAAQS for ozone (expected in October 2010). Based on EPA projections of non-attainment during promulgation of the 2008 NAAQS for ozone, and the range of the standard that EPA has indicated is under consideration for the 2010 standard, it is likely that additional areas in the west will fall into non-attainment, including rural areas where local emissions of ozone precursors are not significant. If EPA considers addressing the west as part of Transport Rule II, they must consider all potential sources of ozone precursors, and limit regulation to those sources/sectors that are found to make a significant interstate transport contribution to the non-attainment. [EPA-HQ-OAR-2009-0491-2671.1, p.2]
Response: 
EPA intends to address interstate transport under updated NAAQS for ozone as noted by the commenter.    EPA intends to evaluate emission reduction opportunities from a broad array of sectors, including but not limited to EGUs, in this effort.

III.F. Anticipated Rules Affecting Power Sector

Organization: American Electric Power
Edison Electric Institute (EEI)
Clean Air Task Force
Clean Energy Group
City of Springfield, Illinois, Office of Public Utilities
Dayton Power and Light Company (DP&L)
Council of Industrial Boiler Owners (CIBO)
Maryland Department of Environment (MDE)
Exelon
Hoosier Rural Electric Cooperative
Florida Electric Power Coordinating Group, Inc. (FCG)
Dynegy, Inc.
Indiana Energy Association
Dominion
Midamerican Energy Holdings Company
Florida Municipal Electric Association (FMEA)
AES Corporation (AES)
MeadWestvaco Corporation (MWV)
First Energy
Cleco Corporation
Consumers Energy
Indiana Municipal Power Agency
Detroit Regional Chamber
American Public Power Association (APPA)
Luminant
American Municipal Power, Inc. (AMP)
Central Illinois Global Warming Solutions Group
American Chemistry Council
Comment: 
AES Corporation (AES)
The proposed Transport Rule does not provide the regulatory certainty required to make informed capital investment decisions. Capital investment decisions on pollution control retrofits are made more difficult by not knowing the emission targets and levels of planned and subsequent rulemakings. EPA mentions in the proposal that it will issue a separate proposal regarding NOx emissions related to the 1997 ozone standard. EPA also has indicated it will issue a "Transport Rule II" related to a tightened (October 2010) ozone standard, and it is almost certain that EPA will propose an additional major transport rule in 2012 to address a more stringent late-2011 NAAQS for particulate matter. These rules are all in addition to the power generator MACT rule, which will not be finalized until late-2011 and which will greatly influence decisions regarding SO2 and NOx control equipment. This lack of certainty will make for impractical project justifications and in many cases, impossible to determine short term regulatory requirements and thus jeopardizing businesses viability. [EPA-HQ-OAR-2009-0491-2791, pp.2-3]
The Transport Rule rulemaking must be coordinated with pending rulemakings on coal combustion products, Utility Maximum Achievable Control Technology ("MACT"), Industrial, Commercial, Institutional ("ICI") Boiler MACT, Phase II 316b, revisions to New Source Performance Standards ("NSPS") and revisions to the Clean Water Act Effluent Guidelines. EPA should provide for coordinated and flexible regulations that provide certainty for power companies to plan multi-billion dollar investments, many of which must serve decades into the future. Only through carefully crafted regulations can we continue to minimize costs to customers and impacts on shareholders, while maintaining a diverse supply of energy resources. [EPA-HQ-OAR-2009-0491-2791, p.5]
American Chemistry Council
EPA should evaluate the impact of the overlapping compliance deadlines on compliance with the Transport Rule, as well as the other upcoming rules. [EPA-HQ-OAR-2009-0491-2716.1, p.2]
American Electric Power
The Transport Rule Provides No Certainty Regarding Future Reduction Requirements for SO2 and NOx Under Currently Planned EPA Rules
EPA has noted in the proposed rule that it plans to further revise the rule and tighten the utility SO2 and NOx emissions caps in future rulemakings in order to meet its new fine particle and new ozone standards. Without knowing what levels of reductions will ultimately be required and by when, the investment planning process for the current Proposed Transport Rule is completely untenable. The risk of stranded or unnecessary pollution control costs increases dramatically. Such uncertainty also increases the probability that coal power plant units will be prematurely retired in order to avoid these investment and rate recovery risks. Given the equally effective transport mitigation resulting from the current CAIR program as compared to the Proposed Transport Rule, as demonstrated by the MOG modeling described above, EPA should not change the current CAIR program until after the transport constraints resulting from the upcoming ozone and PM-2.5 NAAQS revisions are determined by EPA. Units should be issued allowances in perpetuity to avoid reshuffling of 'deck' each time standards are tightened. [EPA-HQ-OAR-2009-0491-2665.1, pp.18-19]
Utility investments occur over time horizons of 20 to 60 years. Trying to plan in the wake of uncertain standards will quell economic investment and emissions reductions as well as drive up consumer electricity prices. Utilities need certainty that future policy will be based on past precedent to make sound investments. As such the Proposed Transport Rule should contain a concrete pathway as to how future NAAQS will be incorporated into this system. [EPA-HQ-OAR-2009-0491-2665.1, p.19]
EPA Should Consider Effects of Current and Future Multi-Pollutant Regulation
The combination of EPA's proposed transport rule and multiple other new air pollution regulations will likely result in a series of relatively inflexible and stringent air pollution regulations with inadequate timelines and high costs. As already noted, in addition to high costs borne by our electricity customers, these rules could also result in many premature plant retirements. This is tum would mean an attendant loss of skilled local jobs in some of the poorest rural counties in industrial states that are still reeling from the effects of the recession. [EPA-HQ-OAR-2009-0491-2665.1, p.19]
We expect this transformation of our coal fleet to continue in the coming decade. In addition to EPA's Proposed Transport Rule, we currently have requirements to reduce SO2 and NOx emissions further at units that are regulated under the Clean Air Visibility Rule. We are also moving forward with emissions reduction projects to meet our obligations under the consent decree that AEP entered into with EPA and other litigants related to the New Source Review provisions of the Clean Air Act. While considerable uncertainty exists over the timing and form of other future regulations, we know that EPA is actively pursuing additional programs to reduce emissions, including a new rule to address mercury and other hazardous air pollutants, and the establishment of more stringent national ambient air quality standards. Although we are committed to working with EPA in the development of future control requirements, we have concerns about the time frame for compliance with these multiple and overlapping programs, as well as the stringency and structure of the underlying regulatory requirements. Some of those concerns are: [EPA-HQ-OAR-2009-0491-2665.1, pp.19-20]
o The cumulative costs of multiple requirements and their impacts on our customers; o Immediate deadlines that do not take into account the need for economic recovery in our service territories;
o The risk of stranded investments that may result from installation of expensive pollution control equipment in order to meet near-term environmental regulations which are effectively overridden by future EPA standards;
o Lack of coordination of the control requirements imposed under future regulatory programs;
o Potential adverse impacts on grid reliability due to wide-scale unit outages required to install emission controls as well as a large number of unit retirements within a short compliance time frame;
o The significant new investments that may be required by non-air environmental programs including EPA's recently proposed rule for disposal of coal combustion by products, EPA's revisions to cooling water intake rules, and its initiative to update its steam-electric effluent guidelines; and
o The potential investments required to meet new EPA greenhouse gas regulations and/or potential new federal climate change legislation.
o This cumulative cost exposure is raising significant concerns about the economic viability of a large number of existing coal-fired units, as well as potential impacts to grid reliability and imposition of substantial increases in retail electricity prices on consumers.
o No evaluation of these potential cumulative costs and impacts has been undertaken. Instead, EPA has engaged in only piecemeal examination of individual rules, and ignored the sustained economic pressures created by these increasingly stringent requirements. [EPA-HQ-OAR-2009-0491-2665.1, p.20]
The series of rulemakings aimed at the same electric generating units subject to the Proposed Transport Rule creates an unreasonable and unnecessary moving target that increases costs to electric consumers and threatens very large stranded or misplaced investments at a time of tight capital markets and the recent recession. [EPA-HQ-OAR-2009-0491-2665.1, p.26]
American Municipal Power, Inc. (AMP)
Additionally, EPA has ignored the other significant federal rule mandates that will add to the complexity of compliance. For instance, EPA has not factored in considerations associated with new NAAQS and entirely new permit concepts tied to greenhouse gas emissions. EPA should be more reasonable in developing workable timeframes and, as such, AMP requests that EPA reconsider this issue and suspend the compliance deadlines of the Transport Rule for at least five years. [EPA-HQ-OAR-2009-0491-2678.1, p.3]
American Public Power Association (APPA)
2. Fundamentally, APPA remains confused by the decisions made by the U.S. EPA on deadlines forced in this re-proposal of the original CAIR rule. APPA finds it difficult to not conclude that the combination of the Proposed Transport Rule (PTR) and the many other U.S. EPA final, proposed, and forthcoming air, water, and waste regulations will result in fuel switching to natural gas and premature coal plant closures in many of the 31 states impacted by the PTR. [EPA-HQ-OAR-2009-0491-2812.1, p.2]
Central Illinois Global Warming Solutions Group
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.123.]
And I urge the EPA to stand strong and to adopt similar tough stances as other pollutants are regulated in the next cycle of looking everything over.
City of Springfield, Illinois, Office of Public Utilities
CWLP is also concerned that the proposed Transport Rule is both premature and potentially unnecessary. For example, it appears that USEPA has used 200S data as a starting point for its analysis, and has neither determined nor taken into account the impact on air quality as a result of recent actions to comply with the Clean Air Interstate Rule ('CAIR'). While USEPA's proposal to achieve maximum achievable control technology ('MACT') is not due until next spring and addresses pollutants not at issue here, the required MACT standard may require costly emission controls that could also reduce pollutants at issue in the Transport Rule. Similarly, guidance on greenhouse gases ('GHG') best available control technology ('BACT') is apparently now under review. Additionally, CWLP has agreed to lowered emission rates beginning in 2010 as part of a Best Available Retrofit Technology ('BART') agreement with Illinois EPA. By failing to recognize existing requirements and recent controls to comply with them, as well as impacts from the required MACT, GHG BACT standards and BART, US EPA's proposed Transport Rule lacks credibility, but wil also result in economic harm to the citizens of Springfield, without a correlative improvement to air quality. [EPA-HQ-OAR-2009-0491-2635.1, p.2]
Clean Air Task Force
Finally, we welcome EPA's stated intention to promulgate a number of rules in the future to require emission reductions from this sector beyond those in the Transport Rule proposal, including -- 
[These comments were also submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.109.]
Section 112(d) 'MACT' standards, to be proposed by March 2011;
revisions to the new source performance standards (NSPS) for coal and oil-fired power plants (including performance standards for GHG emissions);
and best available retrofit technology (BART) and regional haze programs to protect visibility. [EPA-HQ-OAR-2009-0491-2738.1, p.5]
We urge EPA to follow through expeditiously with these important regulatory efforts, which we fully support. [EPA-HQ-OAR-2009-0491-2738.1, p.5]
Clean Energy Group
The Clean Energy Group Encourages EPA to Coordinate the Proposed Rulemaking with Other Regulations Affecting the Electric Sector
The Transport Rule is one of several rules affecting the electric sector that EPA will be implementing over the next five to ten years. Each of these rules will affect the industry and alter companies' long-term planning decisions. To enable companies to make decisions consistent with EPA's long-term vision, the Clean Energy Group continues to encourage EPA to coordinate the upcoming regulations to the extent EPA has the legal authority to do so and so long as coordination does not delay implementation. As discussed in our comments on EPA's draft Strategic Plan, we also support the coordination of regulations among EPA's air, water, and solid waste offices in order to allow EPA and industry to assess the interrelated impacts of all regulations affecting the electric sector.8 This will ensure maximum co-benefits while avoiding potential unintended consequences and without delaying important environmental, public health, and economic benefits. [EPA-HQ-OAR-2009-0491-2702.1, p. 12]
Cleco Corporation
EPA should continue to keep CAIR in place and coordinate the timing and requirements of the Transport Rule with other EGU rules such as the EGU MACT, which is currently anticipated to require reductions as early as 2015. In fact, EPA's EGU MACT rule, with unit-by-unit emission limits, could convert the Transport Rule and its trading program into a meaningless paper exercise. At a minimum, coordinating regulatory deadlines is necessary to facilitate compliance planning, maximize investments and minimize costs. Absent this coordination and proper time for industry to develop compliance strategies, EPA may dramatically increase the cost of electric power by forcing the industry to hastily adapt to ever changing regulations. [EPA-HQ-OAR-2009-0491-2859.1 p.3]
Consumers Energy
We note, with interest, that EPA has gone to the D.C. Circuit Court in order to obtain permission to extend the comment period for the proposed Industrial Boiler MACT rule. In a similar a spirit, we believe that EPA should also be committed to 'ensuring that the final standards will reflect all of the relevant information received during the public comment period' and extend the comment period for the proposed Transport Rule. As EPA has neither a Court mandated or statutory date for completion of this rule, an extension is entirely at EPA's discretion. [EPA-HQ-OAR-2009-0491-2837.1, p.4]
As proposed, the rule would significantly affect the planning, spending and operations of Consumers Energy, as well as those for all utilities within the Transport Rule region. Our company's planning includes capital expenses and scheduling built around the final and still enforceable CAIR to create and maintain a balanced energy portfolio. As proposed, EPA's Transport Rule would force acceleration of spending and construction schedules (if even possible) and, in all likelihood, increase costs for capital expenditures that Consumers Energy currently projects to total in excess of one billion dollars The likely cost increases, coupled with accelerated retirements of units throughout the proposed Transport Rule region, including Michigan, have also caught the attention of the Michigan Public Service Commission (MPSC) which serves to protect the ratepayers in Michigan. [EPA-HQ-OAR-2009-0491-3795.1_NODA, p.3]
Council of Industrial Boiler Owners (CIBO)
The practical impact on regulated sources of the multiple, aggressively timed rulemakings is nowhere considered by EPA. One simple example demonstrates the uncertainty and complexity of the multiple overlapping rulemaking proceedings. ICI sources now face (based on this Proposed Rule) an expectation that in 2012 NOx and SO2 standards will be tightened through alimited market trading program. Yet given the pending and likely litigation-bound definition of 'solid waste' for boilers under the § 112 MACT vs. § 129 CISWI regulations, those sources will not have the certainty to know what types of materials they may burn as 'boilers' in order to meet the future more stringent NOx and SO2 standards.[EPA-HQ-OAR-2009-0491-2751.1]
Proposed Rule carries no semblance of certainty or the orderly administration of regulation.
The proposal makes clear that sources gain no certainty from this rulemaking. EPA projects 2012 and 2014 projections are already outdated, as they do not account for emission reductions required under new pending or soon-to-be-issued regulations. EPA's analysis of costs for sources to comply with this Proposed Rule reflect an expectation that sources will install scrubbers, SCR or implement other similar emission control upgrades. EPA indicates that its analysis assumes only rules in place as of December 2008. Since December 2008, EPA has proposed, finalized or will propose and finalize these regulations that mandate some or all of the very same emission reduction strategies that will be required by this rule: SO2 NAAQS, NO2 NAAQS, Ozone NAAQS, Boiler MACT, CISWI, Utility MACT, PM NAAQS, CO NAAQS as well as a host of MACT and NSPS standards under the Risk and Technology Review provisions.
Industry needs to know what controls will be required in total so that plans and costs can be optimized. It is very hard for business to plan and budget for control needs without clarification of what reductions will ultimately be required. Open-ended piece meal regulations are inconsistent with meeting environmental objectives and planning funding and resources to accomplish those objectives in a reasonable manner. This Proposed Rule carries no semblance of certainty or the orderly administration of regulation.
These other intervening rules also affect EPA's assumptions in this Proposed Rule. For example, EPA's planned rulemakings on NOx and utility MACT will impose additional costs and impacts on EGUs. These rules could provide different circumstances for determining whether or not a plant continues to run. In some cases, the plants that were modeled to decrease output may be the plants that are in a better position to operate under these potential new rules, but will not be able to do so because of the allocations received under the Transport Rule. [EPA-HQ-OAR-2009-0491-2751.1 p. 4]
Dayton Power and Light Company (DP&L)
Additional Time Is Necessary For a Coordinated Approach to Overcoming Technological Challenges
DP&L is uncertain how it will meet the challenges posed by decreasing emission budgets in the proposed rule, given the number of other initiatives that are underway within the EPA and the fact that these proposed rules themselves are likely to be superseded in the near-future. EPA mentions in the proposal that it will issue a separate proposal regarding NOx emissions related to the 1997 ozone standard. EPA also has indicated it will issue a 'Clean Air Transport Rule II' related to a tightened (October 2010) ozone standard, and it is almost certain that EPA will propose an additional major transport rule in 2012 to address a more stringent late-2011 NAAQS for particulate matter. These rules are all in addition to the utility MACT rule, which will not be finalized until late-2011 (about 6 months after the Clean Air Transport Rule is finalized) and which is likely to greatly influence company decisions regarding future control equipment. [EPA-HQ-OAR-2009-0491-2637.1, p. 5]
Other regulations are identified as coming in the next few years and DP&L joins many other companies in expressing concerns about planning for the cascade of unknown requirements. [EPA-HQ-OAR-2009-0491-2637.1, p. 5]
The need for better coordination among these regulatory projects is another reason that DP&L recommends that the EPA follow the CAA and provide time for the States to develop their own SIP. DP&L also supports the comments made by Chris Korleski (Director of the Ohio Environmental Protection Agency) testifying before the Senate Environment & Public Works Committee on July 22, 2010, requesting that, 'any budget U.S. EPA promulgates for an emissions sector would not change for at least ten years and then only ifU. S. EPA demonstrates that additional controls are technically achievable and cost effective.' [EPA-HQ-OAR-2009-0491-2637.1, p. 5]
Detroit Regional Chamber
Considering the economic consequences of increased energy prices, we believe that environmental regulations should look to maximize the environmental and public health benefit from dollars spent on compliance and on Agency staff. Review of the environmental benefits of other recent rules packages may help target where specific improvements can be made without overly burdening state and federal regulators with administering parallel regulations while achieving the targets outlined in the proposed Transport Rule. In cases where compliance with current standards can already be demonstrated, it would be more efficient to consider the effect of new National Ambient Air Quality Standards before moving forward with this proposal. [EPA-HQ-OAR-2009-0491-2720.1, p.2]
Dominion
Harmonization of the S02 and NOx Reductions of the Transport Rule with Future/Expected Air, Climate, Water and Waste Regulations is Crucial to the Electric Utility Industry
In addition to these rules, EPA is in the process of preparing and/or implementing a number of air (including greenhouse gases), water, and waste regulations that will focus heavily on the electric power industry's fossil-fuel generating plants. These new EPA rules will address mercury and other hazardous air pollutants (HAPs), greenhouse gases (GHG), cooling water structures and waste water discharge, and ash disposal from coal-based power plants with a possible cumulative cost of tens of billions of dollars per year. All of these rules have the potential to require new emissions controls. [EPA-HQ-OAR-2009-0491-2715.1, p.16]
As a result of EPA's numerous proposed regulations impacting coal- and oil-fired stations, companies may choose to retire them or convert them to another fuel. In order to determine, for each unit, what the most appropriate control strategy should be, it is necessary to evaluate the long-term viability of each unit. Companies should not be required to decide whether to invest hundreds of millions of dollars in SCR's and scrubbers for a unit before understanding the other air, water and waste requirements the unit will be subject to. The electric sector needs clear, coordinated and flexible regulations that provide certainty for power companies to plan multi-billion dollar investments, many of which must serve decades into the future. Only through carefully crafted regulations that harmonize reduction timelines can the industry continue to minimize costs to customers and impacts on shareholders, while maintaining a reliable and diverse supply of energy resources. EPA should allow CAIR to remain in place and implement a new Transport Rule on a timetable more compatible with other expected regulatory measures. At a minimum, EPA should synchronize this rule with the Utility MACT rule, which will greatly influence company decisions regarding S02 control equipment, with reductions required no earlier than 2015. [EPA-HQ-OAR-2009-0491-2715.1, p.17]
Dynegy, Inc.
Third, EGUs will be subject to several other EPA (or state) emission reduction rules in the next three to five years, some of which will supersede emission reductions required by the Transport Rule and/or overlap (and potentially conflict with) the emission control strategies and technologies needed to comply with the Transport Rule. For example, this includes EPA rulemakings regarding the 24-hour PM2.5 NAAQS, a more stringent ozone NAAQS (e.g., the second Transport Rule already envisioned by EPA), the So, I-hour NAAQS, and EGU hazardous air pollutant standards. All these rules are expected to affect the same group of EGUs, the same air pollutants, and/or interrelated pollution control technologies. Rather than proceed in piecemeal regulatory fashion by creating another interim step for emissions control requirements that further complicates planning and promotes compliance inefficiencies, EPA should defer the effective date of the Transport Rule until at least 30 to 36 months after the rule is finalized and provide the opportunity for integrated emission reduction strategy planning and implementation. [EPA-HQ-OAR-2009-0491-2698.1, p.2]
Edison Electric Institute (EEI)
The Proposed Rule Must Not Be Considered in Isolation From Other EPA Regulations on Air (Including Greenhouse Gases), Water and Solid Waste
The new EPA rules likely to be in effect within the next two years will address:
Air quality issues, including greenhouse gases -- In addition to this Proposed Rule, ongoing EPA air quality rulemakings address new National Ambient Air Quality Standards (NAAQS) for ozone, particulate matter, SO2 and nitrogen dioxide (including additional transport rules related to the soon-to-be-revised ozone and particulate matter standards); visibility; mercury and other hazardous air pollutants (HAPs); and greenhouse gases (GHGs). These rules combined have a possible cumulative compliance cost of over $100 billion per year; EPA has estimated the compliance cost of a 0.060 parts per million ozone NAAQS alone at $52-90 billion in the year 2020. [EPA-HQ-OAR-2009-0491-2697.1, p.4]
Cooling water intake structures and waste water discharge -- EPA is revising its remanded cooling water intake structure rule for existing steam-electric power plants, and appears likely to propose a revised rule that will require many existing "once-through" plants to retrofit cooling towers. Widespread retrofitting of cooling towers would affect almost 500 nuclear and fossil units, with a total capital cost in excess of $67 billion if all companies are required to install cooling towers.  [EPA-HQ-OAR-2009-0491-2697.1, p.4]
Ash disposal from coal-based power plants -- EPA has issued a proposal that includes both hazardous and non-hazardous waste regulatory approaches for coal-combustion products (CCPs). Annual compliance costs for a hazardous waste regulation could exceed $20 billion and would have a devastating impact on CCP beneficial uses, such as drywall and construction materials. Annual compliance costs for a non-hazardous waste regulatory approach could be approximately $2 billion. New installations of flue gas desulfurization (FGD) equipment (SO2 scrubbers) associated with the Proposed Rule will need to address ash disposal, including permitting of new and modified disposal sites.  [EPA-HQ-OAR-2009-0491-2697.1, pp.4-5]
Regarding the proposed Transport Rule, some companies have major concerns while others support the proposal and believe the requirements can be met without difficulty. However, when considering the universe of all air quality, including GHGs, water quality and solid waste regulations, virtually all electric power companies have concerns. The impact of these regulations will vary regionally and from company to company. Some companies will be affected more by air quality regulations, while others will be most affected by water quality regulations, especially requirements for cooling towers under Clean Water Act § 316(b). Because there are many concurrent and near-future new requirements, the impact to the industry and to individual companies can only be assessed by looking at the complete set of regulations over the next decade or longer. [EPA-HQ-OAR-2009-0491-2697.1, p.5]
In order to continue to efficiently produce electricity and reduce emissions, the electric sector needs clear, coordinated and flexible regulations that provide adequate certainty for power companies to plan multi-billion dollar investments, many of which must serve decades into the future. Only through carefully crafted regulations can the industry continue to minimize costs to customers and impacts on shareholders, while maintaining a diverse supply of energy resources. [EPA-HQ-OAR-2009-0491-2697.1, p.5]
The Proposed Rule, Especially in Concert With Other Upcoming Regulations, Provides Little Certainty for the Industry to Plan its Future Activities
The proposed Transport Rule provides little long-term certainty because, by its very terms, its requirements will be superseded in the near future. EPA indicates in the proposal that it will issue a separate, additional transport proposal regarding NOx emissions related to the 1997 ozone standard. More importantly, EPA also has indicated it will propose in 2011 a "Transport Rule II" related to a tightened (October 2010) ozone standard, and it appears almost certain that EPA will propose an additional major Transport Rule in 2012 to address a more stringent late-2011 NAAQS for particulate matter. These rules are in addition to the power generator HAPs maximum achievable control technology (MACT) rule, which will not be finalized until late-2011 (about 6 months after the final Transport Rule) and which will greatly influence company decisions regarding SO2 control equipment. Many companies have expressed concerns about planning for a series of regulations with yet unknown requirements. [EPA-HQ-OAR-2009-0491-2697.1, pp. 5-6]
[This comment was also submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.27-28.]
Describing this situation for Ohio companies, testifying before the Senate Environment & Public Works Committee on July 22, 2010, Chris Korleski (Director of the Ohio Environmental Protection Agency) stated 
Next, we are concerned with the concept that each time U.S. EPA promulgates a new (more restrictive) air quality standard, U.S. EPA intends to revise the Interstate Transport Rule by changing the emission budgets. We have two main concerns with this approach. First, we expect that at some point, it will be difficult or impossible to develop and implement technology that can achieve the new, more restrictive budgets. Second, the regulated community must have some degree of certainty to timely plan investments in controls, fuels, and operations at generating facilities in order to achieve necessary emission levels by the relevant deadline. [EPA-HQ-OAR-2009-0491-2697.1, p.6]
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.27.]
EEI has misgivings regarding the proposed Transport Rule providing little long term certainty because its requirements will be superceded in the very near future.
EPA mentions in the proposal that it is likely to alter this proposal to address wintertime emissions related to attaining the 24 hour PM2.5 standard.
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.54-55.  These comments were also submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.103.]
These rules are all in addition to the power generating sector MACT rule, which will not be finalized until late 2011, about six months after the final Transport Rule, and which will greatly influence company decisions regarding sulfer dioxide equipment.
These rules will force unknown additional control requirements for Georgia power plants in addition to in-state requirements related to ozone, particulate matter, sulfer dioxide and nitrogen oxide, National Ambient Air Quality Standards, and regional haze. In order for us to continue to effectively produce electricity and reduce emissions, the electric sector needs clear, coordinated and flexible regulations that provide certainty for power companies to plan multi-billion-dollar investments, many of which must serve decades into the future.
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.103.]
In order to continue to effectively produce electricity and reduce emissions, the electric sector needs clear, coordinated and flexible regulations that provide certainty for power companies to plan multi-billion dollar investments, many of which must serve decades into the future.
Only through carefully crafted regulations can EEI members continue to minimize costs to customers and impacts on shareholders, avoid straining natural gas supply and prices, and continue efficient and reliable electric generation using diverse, domestic energy resources.
Exelon
THE TRANSPORT RULE IS ONE OF A NUMBER OF MAJOR EPA RULEMAKINGS EXPECTED TO AFFECT FOSSIL FUEL EGUS IN THE NEAR FUTURE. TO THE EXTENT POSSIBLE, EPA SHOULD COORDINATE THE REQUIREMENTS AND IMPLEMENTATION SCHEDULES OF THESE RULEMAKINGS WITH OTHER GOVERNMENT AGENCIES WITHOUT DELAYING NEEDED ENVIRONMENTAL BENEFITS.
The Transport Rule is one of a number of rulemakings under way at EPA that will affect fossil fuel EGUs. EPA has adopted or plans to propose revisions to the NAAQS for NOX, Ozone and PM2.5. EPA is obliged to promulgate a NESHAP prescribing Maximum Achievable Control Technology ('MACT') for hazardous air pollutant emissions from EGUs in 2011. EPA has a number of rulemakings and guidance documents under preparation that address greenhouse gas emissions ('GHGs'). While EPA must consider these upcoming rulemakings, it is important to maintain issue separation. For example, some fossil fuel EGU owners may attempt in their comments to conflate the impact of the Transport Rule with the retirements that may occur as a result of the anticipated EGU MACT rule. EPA should disregard such comments, except to the extent that they relate appropriately to the regulatory scheme established in the Transport Rule. [EPA-HQ-OAR-2009-0491-2666.1, p.6]
Some energy companies have characterized the congruence of the Transport Rule and other pending EPA rules as a 'train wreck,' conjuring the three-headed specter of shuttered plants, skyrocketing electricity prices and potential blackouts. Such rhetoric is a transparent scare tactic. The Transport Rule will not result in the closure of fossil fuel EGUs. As long as the Transport Rule and EPA's other regulatory initiatives are properly managed, these efforts will clear the tracks for a clean and more reliable energy future by providing the market signals and incentives for companies such as Exelon to invest capital in clean and reliable renewable and nuclear generation technologies, technology to control emissions from natural gas generation, and technologies to promote energy efficiency and conservation. While these rules collectively may result in closure of some energy generation dinosaurs - these older cold-fired plants are the least efficient and most polluting. They are also the plants that Congress believed would have been phased out long ago when it enacted the CAA in 1970. [EPA-HQ-OAR-2009-0491-2666.1, pp.6-7]
Although some areas may see increases in generation costs, these rules will likely increase equity. Those whose costs may increase are located in areas of the country that have historically enjoyed lower electricity costs while the pollution and health impacts from that low cost electricity have fallen on downwind areas further burdened by higher electricity costs. As evidenced by Dr. Cicchetti's report, these rules will alleviate disincentives to investment in our nation's downwind urban centers and promote environmental justice by lightening the pollution burden imposed on disadvantaged urban populations. 10 [EPA-HQ-OAR-2009-0491-2666.1, p.7]
Exelon believes that, with adequate attention to coordination, EPA will be able to implement all of its forthcoming programs necessary to promote human health and the environment, without causing unnecessary dislocation in the electricity market. The CAA provides adequate flexibility both with respect to implementation deadlines and the availability of compliance extensions where certain conditions are met. The statutory risk management procedures available to EPA, the Department of Energy ('DOE') and the Federal Energy Regulatory Commission ('FERC'), as well as safeguards in the electricity markets, will assure that electric reliability is preserved throughout the implementation of all of the forthcoming regulatory actions. Nonetheless, EPA could ease the transition to a modernized, cleaner energy fleet by providing clear and early indications of emissions reductions that will be required by future rulemakings and revisions to NAAQS. Exelon proposes below several modifications to the Transport Rule that will allow fossil fuel owners to anticipate reductions in allowance allocations that might be necessary to implement future NAAQS revisions. EPA should attempt to incorporate similar transparency in other rulemakings. [EPA-HQ-OAR-2009-0491-2666.1, p.7]

10 Environmental justice is one of the EPA's highest priorities and one of the seven guiding principles in EPA's strategic plan. See Memorandum from Stephen L. Johnson, EPA Administrator, Reaffirming the U.S. Environmental Protection Agency's Commitment to Environmental Justice (Nov. 4, 2005).
First Energy
FE strongly suggests EPA follow through with coordination of the development and public comment and review of CATR and EGU MACT, at a minimum. [EPA-HQ-OAR-2009-0491-2657.1, p2]
EPA's own comments in the rulemaking at page 45227, Section E "Anticipated Rules Affecting the Power Sector," suggest that the Agency recognizes the need for this certainty and intends to coordinate the various rulemakings "with the goal of fostering investments in the most efficient and forward-looking expenditure of investor, shareholder and public funds...". It serves no ones interest to invest millions to comply with CATR and then strand that expenditure if the facility is retired due to the next EPA rulemaking. [EPA-HQ-OAR-2009-0491-2657.1, p.2]
Further, given the additional rulemakings pending on the EPA's calendar (EGU MACT, Coal Combustion Residuals, CWA Section 316, and others), EPA should coordinate the various timelines to allow the regulated community to make sound strategic decisions relative to EPA's regulatory programs. In particular, EGU MACT rules will also impose air emission reductions on the same subset of sources and are expected to be proposed in the second quarter of 2011 and require reductions of the same pollutants, in the same timeframe as CATR. [EPA-HQ-OAR-2009-0491-2657.1, p.2; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.2 10/15/2010]
Florida Electric Power Coordinating Group, Inc. (FCG)
EPA has provided a cursory assessment and explanation of the impacts of its proposed Transport Rule on the utility sector. But EPA has not attempted to analyze the combined impact of this proposal with other rules it has either recently promulgated, or is actively developing. Each of these rules individually will have a significant impact on the cost of electricity generation and transmission; combined, EPA's initiatives could have a crippling and irreparable impact. [EPA-HQ-OAR-2009-0491-2658.1, p.4]
Florida Municipal Electric Association (FMEA)
EPA Must Assess the Economic and Reliability Impact on Electric Utilities and its Customers of all Recently-Promulgated and Pending Regulations  A few key regulatory examples that EPA must incorporate into its economic and reliability analysis include the: (a) 2010 National Ambient Air Quality Standard for NO2; (b) 2010 National Ambient Air Quality Standard for SO2; (c) 2010 National Ambient Air Quality Standard for ozone; (d) 2011 National Ambient Air Quality Standard for PM2.5; (e) 2011 National Ambient Air Quality Standard CO; (f) 2011 revisions to the Transport Rule; (g) Regional haze rule; (h) Greenhouse gas regulations; (i) 2011 industrial boiler MACT; (j) 2011 utility MACT; (k) 2010 revisions to 40 CFR 63, Subpart ZZZZ (l) 316(b) cooling water intake structures; (m) Numeric nutrient criteria; and (n) Coal combustion residuals. [EPA-HQ-OAR-2009-0491-2731.1, pp. 6-7]
Any credible economic and reliability assessment must include the combined impact of all of these rules; to do otherwise would be negligent, an abuse of discretion, and arbitrary and capricious. EPA attempted to analyze the cost of its proposal, but has thus far kept blinders on when considering whether other regulations could be relevant to its overall impact assessment. As an example of a more holistic assessment, the North American Electric Reliability Corporation (NERC) is currently evaluating the combined impact of four of the above EPA rules on the retirement of specific electric generating units, planning reserve margins, and the need for additional generating units, as well as the magnitude of construction planning necessary for timely compliance. The specific rules NERC is evaluating are the Transport Rule, the utility MACT, 316(b) intake structures, and coal combustion residuals. Further, Electric utilities in Florida are required (annually) to plan on a 10-year horizon, and whenever they decide to make a prudent capital expenditure, it is made with a 20-30-40+ year vision considering all relevant and foreseeable regulatory initiatives. EPA must also consider the long-term consequences of its rules.[EPA-HQ-OAR-2009-0491-2731.1, p. 7]
Accordingly, EPA must conduct a holistic analysis of the impact of all of its regulatory initiatives. [EPA-HQ-OAR-2009-0491-2731.1, p. 7]
Hoosier Rural Electric Cooperative
It appears that CATR does not take into account the countless other EPA proposed rules and the affect that it has on affected companies. For example most utilities will be affected by the proposed EGD MACT rule, NOz and SOz NAAQS, Greenhouse Gas tailoring rule, Coal Combustion Residuals, and etc. [EPA-HQ-OAR-2009-0491-2724.1 p.2]
Indiana Energy Association
d. The Indiana Utility Group submits that there is no accommodation in the proposed CATR for the impact of the myriad of other new EPA proposed rules on the physical control installation process. The fact is that all of these new rules (e.g., proposed EGU MACT rule, GHG Tailoring rule, NO2 NAAQS, SO2 NAAQS, coal ash rule, and Clean Water Act 316) are related based on consumption of resources, overlapping planning and compliance periods and the modeling necessary to comply. The EPA analysis of the CATR in isolation will result in a significant administrative burden on companies having to spend resources to, prepare PSD permits and perform dispersion modeling, among other administrative requirements, concurrently with CATR compliance management. The Indiana Utility Group therefore urges EPA to reassess the CATR in conjunction with the myriad of new EPA rules affecting EGUs and consuming administrative resources. Failure to reassess the CATR in conjunction with the other new proposed rules results in an unrealistic Regulatory Impact Analysis that simply does not support the CATR as proposed. [EPA-HQ-OAR-2009-0491-3711 p.3]
Indiana Municipal Power Agency
The EPA has not determined the effect that recent actions to comply with the Clean Air Interstate Rule (CAIR) will have on ambient and downwind air quality. Because of actions already taken, the Transport Rule may not be necessary. [EPA-HQ-OAR-2009-0491-3057.1,p.1]
Before the EPA imposes new reductions on sulfur dioxide and nitrogen oxide emissions, it should take into account the progress that the nation has made under CAIR. Though the Rule was remanded by the D.C. Circuit Court of Appeals in 2008, it remains in effect and generation companies have necessarily moved ahead with implementation of compliance measures. Before new rules are imposed on a still-weak economy, it makes more sense to determine what improvements in air quality have already occurred. To ignore the improvement the nation has made to date could impose needless substantial costs on our members and region with limited incremental environmental benefit. As we continue to climb out of recession, the last thing that government should do is create additional costs to the economy without substantiated reasons. [EPA-HQ-OAR-2009-0491-3057.1,p.2]
We applaud the EPA's efforts to improve air quality for all Americans and to address downwind issues. However, we believe the EPA's actions are premature and do not allow enough time for state participation or flexibility for industry compliance. Hasty action will have economic consequences for our members without any assurance that the rule will deliver the desired results any faster than the nation can achieve on its current path. We urge the EPA to delay the Transport Rule until there is a clear indication that comparable results cannot be achieved through CAlR. The EPA also should establish realistic deadlines that will not punish electricity consumers. [EPA-HQ-OAR-2009-0491-3057.1,p.3]
Luminant
VI. EPA's Numerous, Concurrent Rulemakings Do Not Provide for Regulatory Certainty and Reasonable Implementation Planning.
EPA has recently proposed, promulgated, or is developing, rules that impact EGUs for the same pollutants that CATR covers. The one-hour SO2 National Ambient Air Quality Standard, the impending re-proposal of the 8-hour ozone NAAQS, the upcoming PM2.5 NAAQS and the 'Transport II' Rule, to name a few, may all have significant impacts on EGUs that would affect the targets and timelines for reduction of these emissions. [EPA-HQ-OAR-2009-0491-2729.1, p.7]
In addition, EPA is also developing Maximum Achievable Control Technology rules for hazardous air pollutants that could also have a significant impact on these emissions. It is imperative for the reliability of the electric system and the health of the US economy that the basis and structure behind this rulemaking be sound and result in realistic outcomes. [EPA-HQ-OAR-2009-0491-2729.1, p.7]
Maryland Department of Environment (MDE)
Larger, additional regional reductions of NOx will be needed for Maryland to attain the new ozone standard. We urge EPA to move ahead quickly with aggressive national rules for boilers, cement kilns, mobile sources, marine engines, locomotives and next round of EGU controls. These 6 source sectors represent about 75% of the NOx that is left to regulate. [EPA-HQ-OAR-2009-0491-2639.1, p.3]
We do recognize that EPA will need to use a suite of different authorities under the Clean Air Act, including Section 110, Section 112, NSR, NSPS and Title II and that the final state-of-the-art, multi-pollutant control program may be implemented in several steps using those different authorities. Transport Rule 1, followed quickly by Transport Rule 2, will be critical steps in this process. We urge EPA to move ahead aggressively to achieve this goal. [EPA-HQ-OAR-2009-0491-2639.2, p.1]
MDE supports the framework for quick updates to the Transport Rule. In the proposal, EPA recognizes the need for the Transport Rule to quickly adapt to the future revisions of the NAAQS for ozone and PM2.5. The proposal emphasizes the methodology for identifying and quantifying the section 110(a)(2)(D) "significant contributions," so that new standards can be issued concurrently with updates to the Transport Rule. While EPA elected to base this first Transport Rule on 1997 8-hour ozone and annual PM2.5 standards, and the 2006 24-hour PM2.5 standard, the modeling of state contributions to all monitor sites in the 37-state region puts all states on notice that lower standards will entail more encompassing and rigorous air pollution regulations. [EPA-HQ-OAR-2009-0491-2639.2, p.2]
MeadWestvaco Corporation (MWV)
MWV would also like to take the opportunity to point out that within this proposal and future proposals EPA should fully consider emission reductions that will be achieved over the next few years related to Boiler MACT and other regulatory programs. These standards will result in significant reductions of both PM and 802, which will result in improvements in air quality within non-attainment areas. [EPA-HQ-OAR-2009-0491-2650.1, p. 2]
Midamerican Energy Holdings Company
As EPA published data demonstrates, the electric power sector has made significant progress in reducing emissions of SO2 and NOx. Nationally, SO2 emissions from power plants were 67% lower in 2009 than in 1980 and NOx emissions were 72% lower during the same period. These emission reduction efforts took place over a number of years, through well-developed laws and regulations that achieved real emission reductions while allowing companies to plan for compliance with these requirements in a way that ensured that electricity consumers did not experience sudden, significant increases in electricity costs. One of the reasons that electricity consumers did not experience significant increases in costs of electricity associated with the installation of emission controls was that the requirements were implemented in a way that also provided assurance to utilities that they could appropriately depreciate the significant investment in emission controls over a 20-plus year equipment and plant life. [EPA-HQ-OAR-2009-0491-2748.1 p.1]
This environmental and economic regulatory paradigm has changed dramatically, and given the multitude of air quality issues1 facing utility companies in the near term, including, but not limited to, revised SO2, particulate matter, ozone and nitrogen dioxide National Ambient Air Quality Standards, the upcoming mercury and other hazardous air pollutant (HAPs) MACT, regional haze, and regulation of greenhouse gases, companies are being forced to make significant decisions on major capital investments in existing facilities that may ultimately not be fully utilized or fully depreciated. The EPA has made it clear that this is only the first step in reducing transport emissions and contemplates another potential emissions reduction as a result of the revised ozone standard even before the Transport Rule is finalized. [EPA-HQ-OAR-2009-0491-2748.1 p.1]
Utilities face at least three statutory requirements that must be reconciled; (1) state and federal requirements to maintain a reliable electric system capable of providing electric service in whatever amount customers demand; (2) state requirements to offer electric service at reasonable or least cost rates; and (3) federal and state environmental requirements, including restrictions on emissions. Reconciling these requirements is difficult under any conditions and is even more difficult given the likely adoption of various federal and state environmental requirements to reduce greenhouse gas emissions where the timing, amount and structure of the requirements cannot reliably be forecast. [EPA-HQ-OAR-2009-0491-2748.1 p.2]
It is difficult, if not impossible, for utilities to make sound, well-informed decisions that are in the best interests of their customers, the public and the environment to install expensive, long-life equipment while aiming at moving, short-term targets, particularly when the statutory requirements to be met by a utility may be in conflict. MidAmerican questions how a utility can make decisions that are in the best interests of its customers and the public, while, at the same time, ensuring reliable electric to meet customers' demand at reasonable or least cost rates if, in order to comply with the first phase of the Transport Rule in 2012, it balances the 50% greater water consumption aspects requirements of a wet scrubber with a 95% removal efficiency that will generate wet slurry that cannot be disposed of in a surface impoundment with the advantages of a dry scrubber having a 90% removal efficiency? And, to further complicate the balance, how can a company make a good decision on its Transport Rule compliance when EPA proposes the HAPs MACT in March 2011, finalizes the MACT in November 2011, and ultimately dictates a scrubber with a 98% removal efficiency to achieve the requisite acid gas removal criteria, with a compliance date in 2014? How can the utility, at the same time, ensure that it has a reliable supply of electricity that meets its statutory requirement of providing that electricity at reasonable or least cost rates when it is left in the untenable situation of having made a stranded investment in whatever control it chooses when it cannot meet the HAPs MACT or has to shut down to comply with greenhouse gas reduction requirements? [EPA-HQ-OAR-2009-0491-2748.1 p.2]
The Reopener Provision Fails to Provide Needed Certainty
While MidAmerican recognizes EPA's need to attempt to address interstate transport of emissions as they impact a state's ability to meet the NAAQS, due to the timing issues associated with the compliance dates specified in the Transport Rule and the revised NAAQS, facilities are put in a difficult position regarding installation of controls. Anticipating the next round of emission reductions, facilities can choose to install control equipment that will achieve the maximum possible emission reductions  -  at a higher cost  -  as a hedge that whatever those controls are will hopefully be sufficient to meet the next round of required reductions (effectively resulting in a false choice). However, installing the "gold-plated" version of controls may not be acceptable from a utility regulatory commission's perspective because compliance is not achieved through a least-cost program. Likewise, there is no guarantee that those controls will be sufficient to meet the yet-to-be-proposed HAPs MACT in the latter part of 2014 or other more stringent future requirements. MidAmerican believes that a better, more reasonable approach to regulating emissions reductions is that once a facility is retrofitted with state-of-the-art emission controls for a covered pollutant it will not be subject to further emission reduction requirements for that pollutant for the life of the unit while such emission controls are in place.  [EPA-HQ-OAR-2009-0491-2748.1, p.6]
Response: 
EPA's approach in the Transport Rule to measure and address each state's significant contribution to downwind nonattainment and interference with maintenance is guided by and consistent with the Court's opinion in North Carolina and addresses the flaws in CAIR identified by the Court therein.  The final rule also responds to extensive public comments and stakeholder input received during the public comment periods in response to the proposal and subsequent Notices of Data Availability (NODAs), and will provide greater certainty to affected sources and states.  The extensive analyses of this final rule indicate that there will be modest impacts on electricity prices, utilities, and consumers. 
As discussed in section III of the Preamble to this rule, EPA will provide full opportunity for notice and comment on each rule as they are proposed and finalized.  EPA will also include the final Transport Rule in its regulatory impact analyses of subsequent rulemakings. 
EPA will coordinate utility-related air pollution rules with each other and with other actions affecting the power sector including these rules from EPA's Office of Water and its Office of Resource Conservation and Recovery to the extent consistent with legal authority in order to provide timely information needed to support regulated sources in making informed decisions.  Use of a small number of air pollution control technologies, widely deployed, can assist with compliance for multiple rules.  EPA also notes that the flexibility inherent in the allowance-trading mechanism included in the Transport Rule affords utilities themselves a degree of latitude to determine how best to integrate compliance with the emissions reduction requirements of this rule and those of the other rules.  EPA will pursue energy efficiency improvements in the use of electricity throughout the economy, along with other federal agencies, states and other groups, which will contribute to additional environmental and public health improvements while lowering the costs of realizing those improvements. 
The approach embodied within the rule is partly designed to improve the planning process for the NAAQS, is readily applicable to any current and future NAAQS, and would automatically adjust the stringency of the transport threshold to maintain a constant relationship with the stringency of the relevant NAAQS as they are revised.  EPA believes that the final Transport Rule demonstrates the value of this approach for addressing the role of interstate transport of air pollution in communities' ability to comply with current and future NAAQS.  EPA believes that the Transport Rule's approach of using air-quality thresholds to determine upwind-to-downwind-state linkages and using the cost- and air quality-based multi-factor approach to quantify significant contribution to nonattainment and interference with maintenance (i.e., to determine the specific amount of emissions that each upwind state must reduce) could serve as a precedent for quantifying upwind state emission reduction responsibilities with respect to potential future NAAQS. 
With respect to the 1997 ozone NAAQS, the Transport Rule requires NOx reductions starting in 2012 to ensure that reductions are made as expeditiously as practicable to assist downwind state attainment and maintenance of the standard.  Sources must comply by May 1, 2012.  The Transport Rule's compliance schedule and alignment with downwind NAAQS attainment deadlines are discussed in detail in section VII of the preamble.
Organization: Associated Electric Cooperative, Inc. (AECI)
Comment: 
Associated Electric Cooperative, Inc. (AECI)
Request: AECI requests that EPA adjust the implementation of the Transport Rule to begin later while keeping CAIR in place in the interim. Since CAIR would remain in effect in the intervening year(s), the environmental consequences of allowing the Transport Rule to begin later would be nearly inconsequential. Further, granting this request would accomplish the following: 
:: Allow the states and regulated community to digest new NAAQS that will inform decisions on planning and permitting for existing and new facilities;  
:: Allow the proposal, comment, and finalization of the EGU MACT to take place in 2011 and provide utilities time to digest the impact to their generating system. As stated above,  compliance with the MACT will greatly impact how utilities plan for adding emission controls or unit retirements. Unit retirements will impact system reliability and will reduce options for utilities to comply with FERC capacity and transmission requirements;
:: Allow states time to develop approvable State Implementation Plans (SIPs) that include unit allocations that better fit the regulated community. The states already have mechanisms developed under the CAIR SIP development for distributing their state budgets to facilities within their borders; [EPA-HQ-OAR-2009-0491-2845.1 p.3] [[This comment is also found in Section VII.C.]]
Certain states were planning to demonstrate compliance with Regional Haze rules by citing emission reductions obtained through the CAIR. 
Request: AECI requests that EPA amend the rule to codify the emission reductions of the Transport Rule as equivalent to, or better than, Best Available Retrofit Technology (BART) for meeting Regional Haze requirements. [EPA-HQ-OAR-2009-0491-2845.1 p.8-9]
Response: 
EPA is taking no final action in this rule with respect to the relationship between the Transport Rule requirements and the visibility provisions of the CAA including the BART requirement.
EPA strongly disagrees with commenter's' suggestions that the Transport Rule deadlines should be delayed.  Please see section VII.C.1 of the preamble for discussion of why EPA selected 2012 and 2014 as important compliance deadlines for the Transport Rule programs.  EPA's analysis in this final rule shows substantial benefits from implementing this rule by the 2012 and 2014 deadlines, which represent the costs to public health and welfare that Americans would incur without successful implementation of this rule; the cost of delay is therefore of considerable consequence to the public.  EPA cannot rely on keeping CAIR in place in the interim, since the Court specifically found these programs to be illegal and only allowed them to remain in place on the basis that EPA would act as quickly as possible to replace them with programs consistent with its statutory authority under the Clean Air Act.  EPA believes it would be inappropriate to risk vacatur of these programs while delaying the promulgation of a replacement rule.
EPA appreciates that many EGUs will have compliance obligations under both the Transport Rule and the Mercury and Air Toxics Standards (MATS), and EPA included a representation of the proposed Transport Rule in its modeling projections of compliance behavior under the proposed MATS [EPA - HQ - OAR - 2011 - 0044].  EPA believes this analysis shows that compliance decisions are highly compatible under both programs, and EPA finds no reason to doubt that EGU owners and operators will be able to make sound investment and operational decisions on the basis of compliance with this final Transport Rule and the finalization of MATS later this year.  In fact, EPA believes that finalization of the Transport Rule today greatly increases regulatory certainty in the power sector and provides an additional "known" which will allow for better compliance planning in regard to other pending regulations the Agency has proposed. 
Finally, EPA has created rapid and flexible pathways for states to assume allocation responsibilities under the Transport Rule programs.  Please see section X of the preamble for more details.
Organization: Edison Mission Energy (EME)
Comment: 
Edison Mission Energy (EME)
EPA failed to indicate, as it had with respect to CAIR, that compliance with the Transport Rule would be sufficient to satisfy regional haze requirements. Given the magnitude of the reductions contemplated by the Transport Rule, EME was surprised that its preamble did not include a determination by EPA that compliance with the Rule satisfied Regional Haze Rule requirements. Based on the magnitude of the reductions contemplated by the Transport Rule, EME submits that EPA should make such a determination in the final rule. [EPA-HQ-OAR-2009-0491-2707.1, p.3]
EPA's Aggressive Timeline And Other Recently Promulgated Rules Increase The Probability That Shortages Of Materials And Labor Due To Increased Demand For Control Equipment Installation At Power Plants Will Make Compliance With The 2014 Cap Impracticable [EPA-HQ-OAR-2009-0491-2707.1, p.26]
Related to the emission control maintenance and installation timeframe issues discussed above, EME submits that the Agency should consider, when finalizing the Phase II cap deadline, the impact of the Transport Rule and other pending rules (including Boiler MACT and Utility MACT) with similar compliance dates on the availability of the raw materials, skilled labor and construction equipment needed to install the FGD, SCRs and SNCRs contemplated by the rule. Unlike other forms of construction where skill sets can be transferred across construction disciplines, adding emission controls to EGU and non-EGU boilers is a highly specialized endeavor requiring experienced engineers and craftsman; thus, having competing rules which require related types emission controls means that the entities that install those controls will necessarily face increased demand. [EPA-HQ-OAR-2009-0491-2707.1, p.26]
[See [EPA-HQ-OAR-2009-0491-2707.1, p.26-27 for additional comments pertaining to EPA's Aggressive Timeline And Other Recently Promulgated Rules Increase The Probability That Shortages Of Materials And Labor Due To Increased Demand For Control Equipment Installation At Power Plants Will Make Compliance With The 2014 Cap Impracticable]
The preceding suggests that EPA should endeavor to harmonize the Transport Rule's compliance deadlines with those created by other rules, such as the anticipated Utility MACT. The compliance deadline modifications in Section III.B.4 below, in addition to correcting the technical feasibility problems with EPA's currently proposed deadlines, achieve such a harmonization. [EPA-HQ-OAR-2009-0491-2707.1, p.27]
EME BELIEVES THAT COMPLIANCE WITH ANY TRANSPORT RULE THAT IS ULTIMATELY ADOPTED SHOULD BE SUFFICIENT TO SATISFY REGIONAL HAZE REQUIREMENTS [EPA-HQ-OAR-2009-0491-2707.1, pp.37]
Notably absent from the Agency's Transport Rule is any substantive discussion of its relationship to the Regional Haze Rule (CAA § 169A) and related Best Available Retrofit Technology requirement, unlike the CAIR proposal which expressly sought out comment on the relationship between these rules. EME had previously supported the Agency's determination that compliance by affected EGUs with the relevant CAIR standards would satisfy the Regional Haze Rule and BART requirements of the CAA. EME submits that EPA should adopt the same approach with respect to the Transport Rule given the magnitude of the NOx and SO2 emissions reductions contemplated by the Rule's Phase II cap and their relationship to the reductions EPA has predicted will be necessary to achieve Regional Haze goals. As such, EPA should recognize an EGU's compliance with the Transport Rule as satisfying Regional Haze emissions requirements through the first implementation period (which ends in 2018) as it did under CAIR, and it should further recognize that compliance with the Rule also satisfies emissions requirements through the second implementation period as well. [EPA-HQ-OAR-2009-0491-2707.1, p.37; for additional comments pertaining to EME Believes That Compliance With Any Transport Rule That is Ultimately Adopted Should be Sufficient to Satisfy Regional Haze Requirements see pp.37-42 of this comment summary]
Based on the foregoing, EME submits that states subject to the Transport Rule will achieve, and likely comfortably exceed, the Regional Haze Rule's reasonable progress requirements. Accordingly, EPA should formally determine in the final Transport Rule that states and EGUs in compliance with the Rule will have also satisfied all Regional Haze requirements, including BART and emissions standards, through 2018 and beyond. At a minimum, EPA should establish a strong presumption that affected states are in compliance with "reasonable progress" requirements and that compliance with the Transport Rule satisfies BART requirements and emissions limitations with respect to EGUs for which they are required. The basis for either of these positions is EPA's own modeling which shows that the emissions reductions predicted to result from that Proposed Rule in combination with regulations in force or pending are likely overwhelmingly sufficient for achievement of the Regional Haze Rule's objectives. [EPA-HQ-OAR-2009-0491-2707.1, pp.41-42]
Response: 
EPA's approach in the Transport Rule to measure and address each state's significant contribution to downwind nonattainment and interference with maintenance is guided by and consistent with the Court's opinion in North Carolina and addresses the flaws in CAIR identified by the Court therein.  The final rule also responds to extensive public comments and stakeholder input received during the public comment periods in response to the proposal and subsequent Notices of Data Availability (NODAs), and will provide greater certainty to affected sources and states.  The extensive analyses of this final rule indicate that there will be modest impacts on electricity prices, utilities, and consumers. 
As discussed in section III of the Preamble to this rule, EPA will provide full opportunity for notice and comment on each rule as they are proposed and finalized.  EPA will also include the final Transport Rule in its regulatory impact analyses of subsequent rulemakings. 
EPA will coordinate utility-related air pollution rules with each other and with other actions affecting the power sector including these rules from EPA's Office of Water and its Office of Resource Conservation and Recovery to the extent consistent with legal authority in order to provide timely information needed to support regulated sources in making informed decisions.  Use of a small number of air pollution control technologies, widely deployed, can assist with compliance for multiple rules.  EPA also notes that the flexibility inherent in the allowance-trading mechanism included in the Transport Rule affords utilities themselves a degree of latitude to determine how best to integrate compliance with the emissions reduction requirements of this rule and those of the other rules.  EPA will pursue energy efficiency improvements in the use of electricity throughout the economy, along with other federal agencies, states and other groups, which will contribute to additional environmental and public health improvements while lowering the costs of realizing those improvements. 
The approach embodied within the rule is partly designed to improve the planning process for the NAAQS, is readily applicable to any current and future NAAQS, and would automatically adjust the stringency of the transport threshold to maintain a constant relationship with the stringency of the relevant NAAQS as they are revised.  EPA believes that the final Transport Rule demonstrates the value of this approach for addressing the role of interstate transport of air pollution in communities' ability to comply with current and future NAAQS.  EPA believes that the Transport Rule's approach of using air-quality thresholds to determine upwind-to-downwind-state linkages and using the cost- and air quality-based multi-factor approach to quantify significant contribution to nonattainment and interference with maintenance (i.e., to determine the specific amount of emissions that each upwind state must reduce) could serve as a precedent for quantifying upwind state emission reduction responsibilities with respect to potential future NAAQS. 
With respect to the 1997 ozone NAAQS, the Transport Rule requires NOx reductions starting in 2012 to ensure that reductions are made as expeditiously as practicable to assist downwind state attainment and maintenance of the standard.  Sources must comply by May 1, 2012.  The Transport Rule's compliance schedule and alignment with downwind NAAQS attainment deadlines are discussed in detail in section VII of the preamble.
EPA is taking no final action in this rule with respect to the relationship between the Transport Rule requirements and the visibility provisions of the CAA including the BART requirement.
Organization: Empire District Electric Company (Empire District)
Comment: 
Empire District Electric Company (Empire District)
EPA has acknowledged that a CATR 2 is in development.  With the delay of CATR 1, timing to incorporate CATR 2 can be more adequately aligned with other developing regulations including MACT for electric generating units (EGU MACT).  The uncoordinated piecemeal approach to regulatory development has resulted in tremendous uncertainty for electric utilities.  The alignment of the initial compliance dates for CATR Phase II, CATR 2 and EGU MACT would provide for increased certainty. [EPA-HQ-OAR-2009-0491-2659.1, p.2]
In addition, we believe that EPA has avoided a critical issue in not determining that the Clean Air Transport Rule is `better than BART' as was defined in the final Best Achievable Retrofit Technology rule.  Given that CATR further restricts the transport of PM2.5 and ozone, in reality CATR is better than CAIR which was better than BART.  Empire District urges EPA to make such a determination.  Not only would such a determination provide clarity and certainty to the utility industry, it would be very beneficial to the states that have included CAIR in their SIPs for attaining the first reasonable progress goal for Regional Haze. [EPA-HQ-OAR-2009-0491-2659.1, p.3] 
Response: 
EPA is taking no final action in this rule with respect to the relationship between the Transport Rule requirements and the visibility provisions of the CAA including the BART requirement.
Please see section VII.C.1 of the preamble for discussion of why EPA selected 2012 and 2014 as important compliance deadlines for the Transport Rule programs.  EPA's analysis in this final rule shows substantial benefits from implementing this rule by the 2012 and 2014 deadlines, which represent the costs to public health and welfare that Americans would incur without successful implementation of this rule; the cost of delay is therefore of considerable consequence to the public.  EPA cannot rely on keeping CAIR in place in the interim, since the Court specifically found these programs to be illegal and only allowed them to remain in place on the basis that EPA would act as quickly as possible to replace them with programs consistent with its statutory authority under the Clean Air Act.  EPA believes it would be inappropriate to risk vacatur of these programs while delaying the promulgation of a replacement rule.
Organization: Florida Department of Environmental Protection
Mississippi Department of Environmental Quality
we energies
Indiana Department of Environmental Management 
Iowa Department of Natural Resources (IDNR)
Tennessee Valley Authority (TVA)
Minnesota Pollution Control Agency (MPCA)
State of Wisconsin, Department of Natural Resources
Michigan Department of Natural Resources and Environment
Xcel Energy Inc.
RRI Energy, Inc.
Wisconsin Power and Light Company
Santee Cooper
Class of '85 Regulatory Group
Comment: 
Class of '85 Regulatory Group
BART Compliance.
Sources subject to best available retrofit technology ('BART') requirements currently have the option of complying with CAIR as a mechanism for complying with BART (often referred to as CAIR = BART). The Proposal does not address whether CATR provides a similar compliance mechanism for BART units. State implementation plans for BART are due in January 2011. Accordingly, it is important that EPA confirm as soon as possible that compliance with CATR's reductions for SO2 and NOx meet compliance obligations for units subject BART. [EPA-HQ-OAR-2009-0491-2854.1,p.14]
Florida Department of Environmental Protection
Upon initial review, it was not clear how this rule impacts the Best Available Retrofit Technology (BART) program. As you may recall, under CAIR, electric utilities were not subject to BART for SO2 and NOx. [EPA-HQ-OAR-2009-0491-2624.1, p.1]
Indiana Department of Environmental Management 
In the future, further emission reductions from both regional and local sources may be needed in order to attain more stringent NAAQS. [EPA-HQ-OAR-2009-0491-2645.1, p.1]
Although not applying directly to ozone or fine particles, U.S. EPA needs to issue a Best Available Retrofit Technology (BART) equivalency determination for sources affected by the final Transport Rule, as was done in conjunction with the Clean Air Interstate Rule (CAIR). [EPA-HQ-OAR-2009-0491-2645.1, p.2]
Iowa Department of Natural Resources (IDNR)
A finding that participation in the Transport Rule would satisfy Best Available Retrofit Technology (BART) requirements should be incorporated into the Transport Rule. Participation in the Clean Air Interstate Rule served as an alternative solution to fulfill the BART obligations related to the July 1999, Regional Haze Rule. We recommend EPA similarly conclude that BART requirements would be satisfied if a BART eligible source participates in the Transport Rule under annual NOx and SO2 emissions caps. [EPA-HQ-OAR-2009-0491-2609.1, p.2]
Michigan Department of Natural Resources and Environment
The DNRE requests clarification about the EGUs and the BART requirements. In the Regional Haze regulations, a determination was made on BART requirements for subject EGUs. In 40 CFR 51.308(e)(4), the EPA determined that CAIR was better than BART. The EPA failed to address this previous determination when proposing the TR. The EPA has indicated that they would be providing a determination on the BART issues for EGUs with the first publication of a PM25 SIP approval. The DNRE believes the uncertainty this leaves for EGU BART obligations is unacceptable and requests that the EPA address the issue of BART for EGUs. This lack of guidance leaves uncertainty for the states and EGUs. [EPA-HQ-OAR-2009-0491-2774.1 p.7]
Minnesota Pollution Control Agency (MPCA)
Finally, the MPCA encourages EPA staff working on the Transport Rule to work closely with EPA staff working on Regional Haze in order to provide the necessary information for making a determination if the Transport Rule can be deemed to be better than Best Available Retrofit Technology (BART) under the Regional Haze program. [EPA-HQ-OAR-2009-0491-2521.1, p.2]
Mississippi Department of Environmental Quality
It was determined that the CAIR rule was sufficient to meet the BART and Reasonable Progress requirements of the Regional Haze rule, but no such provision is given for the Transport Rule. The Transport rule gives greater reductions than CAIR and the limitations on trading further assures that reductions will occur where they are needed. As such, we would encourage EPA to make the provision in this rule that the Transport Rule is sufficient to meet the BART and Reasonable Progress requirements of the Regional Haze Rule. [EPA-HQ-OAR-2009-0491-2634.1, p.2]
RRI Energy, Inc.
The CATR should be identified as an acceptable alternative for BART for Regional Haze as was done for CAIR. The emissions reductions mandated by the proposed CATR are in excess and earlier than those specified under CAIR which provide credibility for that situation. [EPA-HQ-OAR-2009-0491-2717.1 p.5]
Santee Cooper
EPA either should confirm that compliance with the Transport Rule is compliance with EGU requirements for Best Available Retrofit Technology (BART), or explain why it is not. [EPA-HQ-OAR-2009-0491-2820.1, p.2]
EPA EITHER SHOULD CONFIRM THAT COMPLIANCE WITH THE TRANSPORT RULE IS COMPLIANCE WITH THE BART REQUIREMENTS, OR EXPLAIN WHY IT IS NOT. [EPA-HQ-OAR-2009-0491-2820.1, p.10]
Santee Cooper urges EPA to clarify the interaction between the Transport Rule and the Regional Haze Rule. In particular, Santee Cooper requests that EPA determine whether compliance with the Proposed Rule constitutes compliance with BART requirements. [EPA-HQ-OAR-2009-0491-2820.1, p.10]
On July 6, 2005, EPA finalized revisions to the Regional Haze Rule, including guidelines for BART determinations. In its 2005 rulemaking, EPA determined that the CAIR made greater reasonable progress than would BART for SO2 and NOx at BART eligible EGUs in states covered by the CAIR. On this basis, EPA promulgated revisions to the Regional Haze regulations that provided that: [EPA-HQ-OAR-2009-0491-2820.1, p.10]
A State that opts to participate in the Clean Air Interstate Rule cap-and-trade and trade (sic) program under part 96 AAAEE need not require affected BART-eligible EGU's (sic) to install, operate, and maintain BART. [EPA-HQ-OAR-2009-0491-2820.1, p.10]
EPA intends the Transport Rule to supplant the CAIR. Furthermore, the Transport Rule would achieve deeper reductions of SO2 and NOx than the CAIR. Yet, the Transport Rule is silent as to whether the CATR will be 'better than BART,' and therefore whether states may rely on reductions resulting from the CATR as a compliance alternative for otherwise BART-eligible EGUs. [EPA-HQ-OAR-2009-0491-2820.1, p.10]
EPA's silence on the interaction of the Transport Rule and BART requirements frustrates compliance planning both for states and for the power sector. It also represents a missed opportunity to promote coordination and efficiency. In these respects, the Transport Rule is inconsistent with the Agency's commitment, made in the preamble, to 'promote and facilitate the most cost-effective and forward-looking compliance investments and strategies on the part of the power sector." [EPA-HQ-OAR-2009-0491-2820.1, pp.10-11]
For these reasons, Santee Cooper urges EPA to include in the final version of the Transport Rule a determination that the Transport Rule is better than BART and that covered states may rely on the CATR as an alternative means of compliance for BART eligible EGUs - or explain why such a determination is not possible. [EPA-HQ-OAR-2009-0491-2820.1, p.11]
State of Wisconsin, Department of Natural Resources
Better inform Wisconsin facility/source decision-making regarding related emission controls coming on line in the near future, including those expected from additional Title 1 requirements, Title 3 requirements and evolving carbon control policies. [EPA-HQ-OAR-2009-0491-2829.2, p.1; This comment can also be found at section III.D of this comment summary]
EPA needs to clarify the impact of the proposed Transport Rule on the BART program and Haze SIP requirements within the final rule Preamble specifically in regard to whether Transport Rule = BART as was the case with CAIR = BART. [EPA-HQ-OAR-2009-0491-2829.2, p.13]
Preferred Equivalency Approach - If EPA proposes such equivalency, it needs to demonstrate it on a state-by-state basis incremental to the projected 2012 budgets which include currently committed and under construction installations which are not part of the Clean Air Transpoort Rule. BART assessments for the upper Midwest should target 2015 - five years after the first anticipated Regional Haze SIP approval The assessment should compare air quality impact improvement from all EGU BART eligible facilities using presumptive controls as an increment to 2012 Budgets in the same fashion that IPM identifies incremental controls from the 2012 budgets needed to meet 2014 budgets. BART equivalency would be indicated by the approach that produces the visibility improvement as required under the Haze Rule. [EPA-HQ-OAR-2009-0491-2829.2, pp.13-14]
Without clarification, facilities remain uncertain regarding their scope of liabilities to address BART requirements as part of the Regional Visibility Improvement SIPs. [EPA-HQ-OAR-2009-0491-2829.2, p.14]
Tennessee Valley Authority (TVA)
A. Issue: In developing the CAIR rule, EPA took the position that States which adopt the CAIR cap and trade program for SO2 and NOx would be allowed to treat the participation of EGUs in this program as a substitute for the application of Regional Haze BART controls (i.e. the CAIR=BART presumption). This position was based on modeling done by EPA to demonstrate that CAIR emissions reductions as modeled produce significantly greater visibility improvements than source-specific BART. In the proposed Transport Rule, EPA does not create a similar presumption equating the Transport Rule to BART. [EPA-HQ-OAR-2009-0491-2782.1, pp. 15-16]
TVA Comment: EPA determined through modeling that CAIR controls are better than BART for EGUs, and that CAIR achieves greater progress than BART towards meeting the visibility goal. See 70 Fed. Reg. 25303-04 (May 12, 2005) Based on this determination, EPA created the CAIR-BART presumption. The legal principle in creating a CAIR-BART presumption was affirmed by D.C. Circuit in 2006. See Utility Air Regulatory Group v. EPA, 471 F.3d 1333 (D.C. Cir. 2006) Since the Transport rule will reduce SO2 and NOx emissions below CAIR levels, EPA should include in the Transport Rule a provision allowing States that adopt the Transport Rule requirements for SO2 and NOx to treat the participation of EGUs in the program as a substitute for the application of BART controls for these pollutants to affected EGUs. This will relieve needless regulatory burden on the states and regulated engities. [sic] [EPA-HQ-OAR-2009-0491-2782.1, p. 16]
we energies
The Clean Air Interstate Rule (CAIR) properly addressed the Best Available Retrofit Technology (BART) requirements of EPA's regional haze rule by establishing CAIR to be equivalent to BART for SO2 and NOx. EPA needs to clarify that the NOx and SO2 reductions in the transport rule satisfy utility BART requirements. EPA has already substantiated this through modeling associated with the CAIR, but should re-confirm transport rule coverage of utility BART obligations. We ask that EPA address this important issue in the current rule-making rather than deferring this to a future date, or as related to other regional haze rule activity. This regulatory certainty is very important to EGU's in order to optimize planning and installation of necessary control systems. [EPA-HQ-OAR-2009-0491-2629.1, p.7]
Wisconsin Power and Light Company
Given the increased stringency of the proposed CATR program compared to CAIR, WPL believes that these reductions address S02 and NOx reductions required for EGUs subject to Best Available Retrofit Technology (BART). Sources subject to BART currently have the option of complying with CAIR as a mechanism for complying with BART (often referred to as 'CAIR equals BART'). State implementation plans for BART are due in January 2011. WPL believes that EPA should confirm that CATR equals BART compliance for S02 and NOx as expeditiously as possible, but no later than by issuance of this final rule. [EPA-HQ-OAR-2009-0491-2844.1 p.4]
Xcel Energy Inc.
2. EPA should clearly state that CATR is BART.
EPA should clearly state that compliance with CATR requirements satisfies the Best Available Retrofit Technology (BART) requirements under the Regional Haze rule. In particular, EPA should inform the states that they are not obligated to undertake the 5-factor analysis for every BART affected unit in each state, if the state adopts the CATR regulations as a SIP or defers to EPA's proposed FIP. Under the CAIR role EPA clearly stated that a state's adoption of CAIR satisfied its BART obligations. As CATR is more stringent than CAIR, CATR should also be viewed as BART. [EPA-HQ-OAR-2009-0491-2728.1, pp.11-12]
Response: 
EPA appreciates the comments regarding the relationship of the transport rule to the BART requirement.  EPA recognizes that EPA's regional haze regulations provide for trading program alternatives to the BART requirement.  EPA's BART guidelines were published on July 6, 2005.  70 FR 39104.   In the final BART guidelines notice, EPA determined that CAIR achieved greater progress than BART and could be used by States as a substitute for BART at affected EGUs.  70 FR 39137.
Following promulgation of the Transport Rule, we intend to conduct a similar analysis of the transport rule to determine whether it would achieve greater reasonable progress toward the national visibility goal than BART.   We believe it is best to conduct this analysis once the transport rule requirements are final and certain.  If the analysis supports the conclusion that the transport rule achieves greater reasonable progress than BART, we intend to proceed with a notice and comment rulemaking that would provide that compliance with the Transport Rule satisfies BART requirements in certain states.    Because this analysis is not yet complete, we cannot make any representations in this rule regarding whether the Transport Rule achieves greater reasonable progress than BART.   We do, however, intend to complete this analysis as quickly as possible and hope to complete a rulemaking addressing the Transport Rule and BART by spring 2012.
Organization: Gulf Coast Lignite Coalition
Comment: 
Gulf Coast Lignite Coalition
I. EPA Should Extend the Transport Rule Compliance Dates to Accommodate Pending Federal Standards and State Emission Reduction Target Deadlines.
EPA proposes that the initial phase of emission reductions will begin in 2012 (less than one year after the rule is finalized), requiring sulfur dioxide (SO2) and nitrogen oxide (NOX) reductions in those 31 states covered for the 24-hour and/or annual PM2.5 National Ambient Air Quality Standards (NAAQS) as well as the 8-hour ozone NAAQS.1 A second round of additional SO2 reductions would be required for "Group 1" states in 2014 and EPA is considering additional NOX reductions in a future proposal for the ozone NAAQS (Transport Rule II). [EPA-HQ-OAR-2009-0491-2734.1 p.1]
The Transport Rule sets new emission budgets for each state and requires compliance with set emission reductions by 2012. With such a quick compliance deadline less than one year after the final rule is published, it is not clear how states will coordinate emission reduction mandates from the federal level with ongoing efforts at the state level.   [EPA-HQ-OAR-2009-0491-2734.1 p.2]
For example, Texas is in the middle of demonstrating attainment for several of their nonattainment regions for the 1997 8-hour ozone standard. Specifically, the Texas Commission on Environmental Quality (TCEQ) recently adopted the Houston Galveston Brazoria (HGB) Attainment Demonstration SIP Revision and the HGB Reasonable Further Progress SIP revision for the 1997 8-hour ozone standard. In this latest SIP revision, Texas will be demonstrating an 18% emission reductions, with 3% reductions between 2008, 2011, 2014, 2017, and 2018. Now, the EPA is proposing NOX emission reductions under the Transport Rule with a compliance date of 2012. Further complexity will be inserted by the planned adoption of a revised Ozone NAAQS, which will trigger a host of additional SIP Revision activities. Layering so many regulatory compliance timelines and developments on top of each other will cause confusion for state regulatory agencies, the regulated community, and the general public.  [EPA-HQ-OAR-2009-0491-2734.1 p.2]
Overly complicated compliance deadlines and little advance notice of changing regulatory requirements is a recipe for disaster given the current economic conditions. Put simply, the regulated community needs as much advance notice and flexibility as possible in times like these when capital is hard to come by and sensitivity to increased residential and industrial utility bills is at its highest. While it may be cumbersome to match compliance dates on a state and federal level, EPA should at a minimum extend the compliance deadlines beyond 2012. [EPA-HQ-OAR-2009-0491-2734.1 p.2]
EPA has set out a number of "Key Guiding Principles" in the preamble of the proposed Transport Rule, one of which is to "Provide [a] Workable Approach for EPA and States." Here, EPA is requesting compliance with the Transport Rule by 2012, a very short compliance timeframe considering the myriad of environmental regulations undergoing review and revision during the next few years, some of which form the basis of the Transport Rule (e.g., 1997 8-hour ozone NAAQS). EPA should consider the breadth of environmental regulations, including but not limited to regulations for hazardous air pollutants, new source performance standards, and greenhouse gas regulations. Failure to consider these ongoing emission reduction efforts by the states and pending regulations does not comport with the Key Guiding Principle to Provide a Workable Approach for EPA and the states. [EPA-HQ-OAR-2009-0491-2734.1 p.3]
Regulations with a short shelf life do not afford regulated entities sufficient time to request, acquire and implement the necessary control technology to meet the changing standards. The regulated community requires regulatory stability and certainty in order to properly plan and execute capital expenditures required for additional control technology.   [EPA-HQ-OAR-2009-0491-2734.1 p.4]
While GCLC understands the need to address the remanded Clean Air Interstate Rule (CAIR), the U.S. Court of Appeals did not set a specific timeline by which EPA should substitute CAIR with a new rule.1 GCLC requests that the EPA relax the compliance deadlines in the Transport Rule in order to acknowledge the complexity and burdens associated with the many standards that will be revised within the next year or two. [EPA-HQ-OAR-2009-0491-2734.1 p.4]
1 See State of North Carolina v. EPA, Case No. 05-1244 (D.C. Cir. December 23, 2008). "...Some Petitioners have suggested that this court impose a definitive deadline by which EPA must correct CAIR's flaws. Notwithstanding these requests, the court will refrain from doing so."
Response: 
EPA's approach in the Transport Rule to measure and address each state's significant contribution to downwind nonattainment and interference with maintenance is guided by and consistent with the Court's opinion in North Carolina and addresses the flaws in CAIR identified by the Court therein.  The final rule also responds to extensive public comments and stakeholder input received during the public comment periods in response to the proposal and subsequent Notices of Data Availability (NODAs), and will provide greater certainty to affected sources and states.  The extensive analyses of this final rule indicate that there will be modest impacts on electricity prices, utilities, and consumers. 
As discussed in section III of the Preamble to this rule, EPA will provide full opportunity for notice and comment on each rule as they are proposed and finalized.  EPA will also include the final Transport Rule in its regulatory impact analyses of subsequent rulemakings. 
EPA will coordinate utility-related air pollution rules with each other and with other actions affecting the power sector including these rules from EPA's Office of Water and its Office of Resource Conservation and Recovery to the extent consistent with legal authority in order to provide timely information needed to support regulated sources in making informed decisions.  Use of a small number of air pollution control technologies, widely deployed, can assist with compliance for multiple rules.  EPA also notes that the flexibility inherent in the allowance-trading mechanism included in the Transport Rule affords utilities themselves a degree of latitude to determine how best to integrate compliance with the emissions reduction requirements of this rule and those of the other rules.  EPA will pursue energy efficiency improvements in the use of electricity throughout the economy, along with other federal agencies, states and other groups, which will contribute to additional environmental and public health improvements while lowering the costs of realizing those improvements. 
The approach embodied within the rule is partly designed to improve the planning process for the NAAQS, is readily applicable to any current and future NAAQS, and would automatically adjust the stringency of the transport threshold to maintain a constant relationship with the stringency of the relevant NAAQS as they are revised.  EPA believes that the final Transport Rule demonstrates the value of this approach for addressing the role of interstate transport of air pollution in communities' ability to comply with current and future NAAQS.  EPA believes that the Transport Rule's approach of using air-quality thresholds to determine upwind-to-downwind-state linkages and using the cost- and air quality-based multi-factor approach to quantify significant contribution to nonattainment and interference with maintenance (i.e., to determine the specific amount of emissions that each upwind state must reduce) could serve as a precedent for quantifying upwind state emission reduction responsibilities with respect to potential future NAAQS. 
With respect to the 1997 ozone NAAQS, the Transport Rule requires NOx reductions starting in 2012 to ensure that reductions are made as expeditiously as practicable to assist downwind state attainment and maintenance of the standard.  Sources must comply by May 1, 2012.  The Transport Rule's compliance schedule and alignment with downwind NAAQS attainment deadlines are discussed in detail in section VII of the preamble.
Organization: Indiana Builders Association 
Comment: 
Indiana Builders Association 
This rule could cause the premature closure of some coal-based generation plants in my state, which will have severe economic consequences for our members, our communities and our local revenues. [EPA-HQ-OAR-2009-0491-2871.1, p.2]
In addition to the costs to comply, there is the economic harm my members will incur if some coal-fired power plants are forced to retire prematurely. Each plant supports hundreds of good paying jobs, at a time when there are few comparable employment opportunities. Closing these plants early will only lengthen the time needed for this nation to recover from the recession and will exacerbate a growing state and local budget problem through lost income tax revenues. [EPA-HQ-OAR-2009-0491-2871.1, p.3]
We applaud the EPA's efforts to improve air quality for all Americans and to address downwind issues. However, we believe the EPA's actions are premature and do not allow enough time for state participation or for industry compliance. Hasty action will have economic consequences for our members without any assurance that the rule will deliver the desired results any faster than the nation can achieve on its current path. [EPA-HQ-OAR-2009-0491-2871.1,p.3]
Response: 
As discussed in Section VII.C of the Preamble, EPA believes the 2012 and 2014 deadlines are feasible and the rule itself will not result in significant coal retirements or reliability challenges.  In addition, the rule is anticipated to have some positive employment impacts in the pollution control and construction industry as new environmental controls are needed to meet the requirements of the rule.
Organization: Kentucky Chamber of Commerce
Comment: 
Kentucky Chamber of Commerce
Coal plant emissions can continue to be reduced in a realistic, more cost-effective manner through multi-pollutant legislation that achieves equivalent environmental benefits without threatening the economic viability of our communities or the reliability of our power system.  [EPA-HQ-OAR-2009-0491-2760.1 p.2]
Response: 
EPA must follow existing law, as passed by Congress, and must follow direction from Courts where relevant.  EPA is promulgating the Transport Rule in response to the remand of the Clean Air Interstate Rule (CAIR) by the U.S. Court of Appeals for the District of Columbia Circuit ("Court") in 2008.  Opportunities to update existing law must be considered by Congress, and multi-pollutant legislation is one possible mechanism that could potentially achieve greater environmental benefits and lower cost.
Organization: Minnesota Power 
Comment: 
Minnesota Power 
Additionally, the Minnesota Pollution Control Agency had facilitated a Minnesota stakeholder process for addressing final Regional Haze (Clean Air Visibility Rule) requirements for targeted 2013 compliance with Reasonable Further Progress targets for Minnesota Class I Wilderness Areas.  The MPCA Northeast Regional Emissions Abatement Program called for about a 30% reduction in Northeast Minnesota utility emissions that, coupled with other regional emission reductions (e.g. MERP and AREA), would satisfy Minnesota regional haze, reasonable further progress requirements on schedule. It is not clear in EPA's Transport Rule, Technical Support Documents whether EPA gave consideration to Minnesota non-utility source emission reductions from this Minnesota visibility improvement initiative, but it does appear that EPA is incorrectly associating the Minnesota emission reduction measures with CAIR compliance action even though the CAIR has been stayed for Minnesota implementation pending this Transport Rule finalization.  [EPA-HQ-OAR-2009-0491-2750.1, p.4]   
The MPCA has submitted the Minnesota Regional Haze SIP to EPA for approval, but has not yet received confirmation that EPA has reviewed and approved the Northeast Minnesota emission reduction plan.  However, Minnesota utility sources have provided for the associated planned emission reductions at timing to meet the MPCA program regional haze targets, as cited in the Minnesota State Implementation Plan submitted to EPA.  Still, those Minnesota emission reduction measures appear to have been acknowledged by EPA when they suggest that States should be able to meet EPA's Transport Rule proposed 2012 SO2 and NOx budget emission limitations.  [EPA-HQ-OAR-2009-0491-2750.1, p.4]
Perform new formal rule makings and public comments before implementing any proposed new emission reductions.  Minnesota Power requests that EPA address any further measures that would impose additional reductions on Minnesota sources in a separate rule making that provides adequate time for public review and comments of EPA's justifying criteria for additional controls.  The current proposed Transport Rule does not provide adequate justification for further ratcheting down of budgets, since related control requirements may not meet reasonable criteria for emission reduction measures and cost effectiveness.  [EPA-HQ-OAR-2009-0491-2750.1, pp.6-7]   
Response: 
EPA's approach in the Transport Rule to measure and address each state's significant contribution to downwind nonattainment and interference with maintenance is guided by and consistent with the Court's opinion in North Carolina and addresses the flaws in CAIR identified by the Court therein.  The final rule also responds to extensive public comments and stakeholder input received during the public comment periods in response to the proposal and subsequent Notices of Data Availability (NODAs).  EPA has provided for adequate time for public comment.
As described in section VI of the preamble for the final Transport Rule, EPA reassessed SO2 and ozone season and annual NOx reductions for the final Transport Rule.  Please refer to this section for further details.  In addition, see preamble section V for more detail on analysis of air quality and upwind state emissions.
Minnesota's maximum contribution to nonattainment for daily PM NAAQS was 0.61 ug/m3, well above the threshold.  EPA included enforceable emission reduction agreements or targets in its analysis done in support of the significant contribution analysis, and the agreements mentioned by the commenter do not fall within this definition.  In addition, the commenter provides no details regarding the aforementioned emission reductions.
Organization: National Mining Association (NMA)
Comment: 
National Mining Association (NMA)
EPA's coordinated regulatory agenda to reduce coal usage
EPA has undertaken a far-reaching regulatory program that is apparently designed to reduce the use of coal throughout the American economy. The coordinated nature of this program is most evident in the electric power sector, which EPA has undertaken to transform. Upon taking office, EPA formulated seven priorities, one of which was to "develop a comprehensive strategy for a cleaner and more efficient power sector, with strong but achievable reduction goals for SO2, NO2, mercury and other air toxics." This goal was reiterated by EPA in the proposed Transport Rule, where the Agency said that "[i]n furtherance of this priority goal, and to respond to statutory and judicial mandates, EPA is undertaking a series of regulatory actions over the course of the next 2 years that will affect the power sector in particular."  [EPA-HQ-OAR-2009-0491-2868.1, p.3]
These EPA rulemakings include:
:: The recently completed National Ambient Air Quality Standards ("NAAQS") for sulfur dioxide ("SO2") and nitrogen dioxide ("NO2");
:: The currently proposed new ozone NAAQS and the soon-to-be proposed new PM2.5 NAAQS;
:: The proposed Transport Rule and expected additional transport rules for the 1997 ozone NAAQS, the currently proposed new ozone NAAQS, and the soon-to-be-proposed new PM2.5 NAAQS;
:: The soon-to-be-proposed MACT standards for electric generating units ("EGUs");
:: EPA's greenhouse gas ("GHG") regulation under the Prevention of Significant Deterioration ("PSD") program; [EPA-HQ-OAR-2009-0491-2868.1,p.3]
:: The soon-to-be-proposed New Source Performance Standards for EGUs (including GHG NSPS);
:: Best Available Retrofit Technology ("BART") standards for EGUs;
:: The proposed regulations for coal combustion residues; and
:: The soon-to-be-proposed water quality regulations for cooling intake structures and soon-to-be-proposed effluent guidelines for discharges from power plants.  [EPA-HQ-OAR-2009-0491-2868.1,p.4]
Recognizing that all of these regulations are implementing a single overall priority goal and constitute a "comprehensive set of requirements," EPA pledged in the proposed Transport Rule to coordinate at least its power sector air quality regulations and, to the extent it could under relevant statutory law, to coordinate these power sector air quality regulations with the coal combustion residue regulations and the two power sector water quality regulations. EPA further pledged to "engage with other federal, state and local authorities, as well as with stakeholders and the public at large, with the goal of fostering investments in compliance that represent the most efficient and forward-looking expenditure of investor, shareholder, and public funds, resulting, in turn, in the creation of a clean, efficient, and completely modern power sector." [EPA-HQ-OAR-2009-0491-2868.1,p.4]
EPA's regulatory agenda for the power sector will almost certainly significantly reduce the use of coal for electric generation. While EPA so far has not done any study of the cumulative impact of these regulations on coal use (or otherwise), the contractor EPA uses to model impacts of individual regulations recently produced its own analysis showing that just the EGU MACT standards alone will force major retirements of coal-fueled power-plants. [EPA-HQ-OAR-2009-0491-2868.1,p.4]
A recent report by Credit Suisse (copy attached) examined the effect of the Transport Rule and the upcoming EGU MACT rules and determined that:
:: About 60 GW of coal-fueled capacity will likely close between 2013 and 2017.
:: $70-$100 billion of capital expense in emission control equipment.
:: A 15-31% reduction in the use of coal for electric generation. [EPA-HQ-OAR-2009-0491-2868.1,p.4]
:: MISO, SERC, PJM-West, and SPP will see an "accelerating reversion to 15% reserve margins."
:: EPA's standards cannot be met unless compliance deadlines are extended to 2017. [EPA-HQ-OAR-2009-0491-2868.1,p.5]
Forced retirements will have substantial negative economic impacts nationally, but will also have severe impacts locally, as exemplified by the Arizona Hopi and the Navajo Generation Station:
Scott Canty, the Hopi Nation`s general counsel, explained to a panel of lawmakers on Nov. 2 that closure of the Navajo Generating Station would cripple the tribal government. The Hopi Nation relies heavily on coal revenues to fund its government, Canty said. About 88 percent of the tribal government`s budget comes from revenue generated by coal-fired energy production at the Navajo Generating Station, Canty said. . . . The EPA has proposed rules that would require the power plant to install expensive emissions equipment to address visibility impairment issues at the Grand Canyon. But the plant's owners and the tribes argue that the retrofit is too costly. [EPA-HQ-OAR-2009-0491-2868.1,p.5]
Moreover, news accounts recently reported that EPA is well aware that its regulatory efforts in the power sector will increase the costs to coal-fueled EGUs and make them less competitive with renewable resources. In an article entitled "Administration Eyes EPA Rules To Spur Shift From Coal To Renewables," it was reported that:
Rob Brenner of EPA's Office of Air & Radiation told a July 28 meeting of the agency's environmental justice advisers that pending rules to control emissions, waste and water discharges from utilities will not only protect public health but add costs to the industry that might make renewable energy a more viable alternative.
"We need to set health-based standards for power plants, and once we do that then they can compete with some of these renewable sources," Brenner said at the National Environmental Justice Advisory Committee (NEJAC) meeting in Washington, DC. He added later, "It's not really a fair competition because [coal-fired power plants] are cheaper than they should be because they're not controlling their pollutants" to their full extent because EPA is yet to issue key rules for the sector, including a mercury air rule and a plan to regulate coal combustion residue.8 [EPA-HQ-OAR-2009-0491-2868.1,pp.5-6]
The same article reported that the White House also understands that transforming the power sector will inevitably result in reduced use of coal and increased use of renewables. Referring to remarks of Nancy Sutley, Chair of the White House Council on Environmental Quality, the article reported that:
Sutley responded that she doubts the existence of so called clean coal. "Other people have labeled it `clean coal,'" she said. "I don't know if I would necessarily concede that that is real. . . . I think in the long run, not just for the [United States] but for the world, that developing and making sure that there is access to these inherently cleaner sources of energy is important. . . . . We need to use energy more efficiently and more cleanly." [EPA-HQ-OAR-2009-0491-2868.1,p.6]
Other EPA regulatory proposals are also part of an overall strategy to reduce the use of coal throughout the economy. This strategy includes the Boiler MACT and Area Source rule on which EPA recently took comment. In the regulatory preamble to the Boiler MACT rule proposal, EPA stated forthrightly that its reason for proposing strict MACT standards for coal boilers and process heaters but only work practice standards for natural gas boilers was to incent coal boilers to switch to natural gas and to disincent natural gas boilers from switching to coal. In discussing this issue, EPA made plain that it considers coal to be a "dirty" fuel whose use is inconsistent with the CAA and therefore should be discouraged. In contrast, EPA considers natural gas to be a "clean fuel" whose use should be encouraged at coal's expense. According to EPA: [EPA-HQ-OAR-2009-0491-2868.1,p.6]
In addition, emission limits on gas-fueled boilers and process heaters may have the negative effect of providing an incentive for a facility to switch from gas (considered a "clean" fuel) to a "dirtier" but cheaper fuel (i.e., coal). [EPA-HQ-OAR-2009-0491-2868.1,pp.6-7]
The coal industry also faces a panoply of prospective regulation of the process of producing coal. These regulations include potentially stricter NAAQS for PM10 which may make western surface mining untenable, new restrictions on coal mine permitting in Appalachia that could result in major reductions in surface and underground coal mining in that region, and potential imposition of NSPS standards on mining emissions of PM10, methane, volatile organic compounds, and nitrogen oxides. All of these regulations together -- EPA's power sector regulations, its regulations for the use of coal in the manufacturing and commercial sectors, and its regulations of coal mining -- all have the potential to combine to cumulatively and dramatically reduce coal usage. [EPA-HQ-OAR-2009-0491-2868.1,p.7]

8. Administration Eyes EPA Rules to Spur Shift from Coal to Renewables, InsideEPA.com (July 29, 2010), at http://insideepa.com/201007291915893/EPA-Daily-News/Daily-News/administration-eyesepa-rules-to-spur-shift-from-coal-to-renewables/menu-id-95.html.
Response: 
EPA's approach in the Transport Rule to measure and address each state's significant contribution to downwind nonattainment and interference with maintenance is guided by and consistent with the Court's opinion in North Carolina and addresses the flaws in CAIR identified by the Court therein.  The final rule also responds to extensive public comments and stakeholder input received during the public comment periods in response to the proposal and subsequent Notices of Data Availability (NODAs), and will provide greater certainty to affected sources and states.  The extensive analyses of this final rule indicate that there will be modest impacts on electricity prices, utilities, and consumers while providing significant health benefits to the public.
As discussed in section III of the Preamble to this rule, EPA will provide full opportunity for notice and comment on each rule as they are proposed and finalized.  EPA will also include the final Transport Rule in its regulatory impact analyses of subsequent rulemakings. 
EPA will coordinate utility-related air pollution rules with each other and with other actions affecting the power sector including these rules from EPA's Office of Water and its Office of Resource Conservation and Recovery to the extent consistent with legal authority in order to provide timely information needed to support regulated sources in making informed decisions.  Use of a small number of air pollution control technologies, widely deployed, can assist with compliance for multiple rules.  EPA also notes that the flexibility inherent in the allowance-trading mechanism included in the Transport Rule affords utilities themselves a degree of latitude to determine how best to integrate compliance with the emissions reduction requirements of this rule and those of the other rules.  EPA will pursue energy efficiency improvements in the use of electricity throughout the economy, along with other federal agencies, states and other groups, which will contribute to additional environmental and public health improvements while lowering the costs of realizing those improvements.
The approach embodied within the rule is partly designed to improve the planning process for the NAAQS, is readily applicable to any current and future NAAQS, and would automatically adjust the stringency of the transport threshold to maintain a constant relationship with the stringency of the relevant NAAQS as they are revised.  EPA believes that the final Transport Rule demonstrates the value of this approach for addressing the role of interstate transport of air pollution in communities' ability to comply with current and future NAAQS.  EPA believes that the Transport Rule's approach of using air-quality thresholds to determine upwind-to-downwind-state linkages and using the cost- and air quality-based multi-factor approach to quantify significant contribution to nonattainment and interference with maintenance (i.e., to determine the specific amount of emissions that each upwind state must reduce) could serve as a precedent for quantifying upwind state emission reduction responsibilities with respect to potential future NAAQS.
In addition, the commenter cites reports erroneously and attributes the reports findings to EPA regulatory actions, when in fact the reports were identifying many factors that are influencing power sector dynamics and costs (e.g., lower than expected electricity demand and natural gas supply/prices).  The reports also relied upon a misinformed interpretation of potential EPA regulatory actions since some of the aforementioned rules that were modeled had yet to be proposed and were assumed to be much more stringent than they actually were.  It is useful to cite analysis that makes sense, and it is not useful to misinterpret results from analyses.  There certainly will not be any "forced retirements," sources have many options for compliance and EPA has included flexible elements wherever possible.
The CAA, passed by Congress in 1970 and amended in 1990, sets forth a framework for the protection citizens from pollution, and EPA is responding to that framework (and Court direction) to ensure that standards are met cost-effectively and efficiently, while incorporating flexibility wherever possible.  In addition, EPA analysis indicate that impacts on coal will be modest and will not result in significant shifts away from coal.  In fact, much of the coal fleet will find it cost effective to install a variety of widely available pollution controls, many of which can remove multiple pollutants and will help meet more than one requirement.  
Organization: New Jersey Department of Environmental Protection (NJDEP)
Comment: 
New Jersey Department of Environmental Protection (NJDEP)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.158-159.]
New Jersey submitted on May 12, 2010, a Section 126 petition to the USEPA seeking reductions in emissions from the Portland Plant due to its significant contribution to nonattainment, and interference with maintenance, of the sulfur dioxide SO2 and 24-hour fine particulate matter PM 2.5 NAAQS in New Jersey.
The units at the Portland Plant, built in the 1950s and 1960s, have no SO2 emission controls and outdated control technology for NOX and particulate emissions. This petition was based on air quality modeling and the 24 hour SO2 standard.
Based on the new one-hour SO2 standard promulgated in June, the Department predicts that the Portland Plants sulfur dioxide impact on the air quality is much greater, causing nonattainment in a much larger area in New Jersey and Pennsylvania. While EPAs transport rule is a positive step, additional regulatory tools are needed to address plants like Portland.
Response: 
EPA's approach in the Transport Rule to measure and address each state's significant contribution to downwind nonattainment and interference with maintenance is guided by and consistent with the Court's opinion in North Carolina and addresses the flaws in CAIR identified by the Court therein.  The final rule also responds to extensive public comments and stakeholder input received during the public comment periods in response to the proposal and subsequent Notices of Data Availability (NODAs), and will provide greater certainty to affected sources and states.  The extensive analyses of this final rule indicate that there will be modest impacts on electricity prices, utilities, and consumers while providing significant health benefits to the public.  EPA anticipates that units at the Portland Plant would likely install pollution controls to reduce emissions SO2 and other harmful pollutants, in response to the requirements of the Transport Rule.
Organization: Owensboro Municipal Utilities (OMU)
Comment: 
Owensboro Municipal Utilities (OMU)
EPA Should Clearly State That the Final Transport Rule Satisfies the Requirements of BART and Defers Section 126 Findings.
In developing the CAIR rule, EPA took the position that States adopting the CAIR cap-and-trade program for SO2 and NOx would be allowed to consider the participation of EGUs in this program as equivalent to the application of best available retrofit technology (BART) controls (i.e., the CAIR-BART presumption) for those pollutants. This position was based on modeling done by EPA to demonstrate that CAIR emissions reductions as modeled produce significantly greater visibility improvements than source-specific BART. In the proposed Transport Rule, EPA does not create any such presumption equating the Transport Rule to BART. [EPA-HQ-OAR-2009-0491-2811.1,pp.3-4]
Since EPA appropriately determined that compliance with CAIR exceeded the visibility improvements that would result from BART, and since the Transport Rule will reduce SO2 and NOx emissions below CAIR levels, EPA should include in the Transport Rule a provision that treats EGU compliance with the Transport Rule as equivalent to the application of Regional Haze BART controls. [EPA-HQ-OAR-2009-0491-2811.1, p.4]
Additionally, in developing CAIR, EPA set forth its general view of the approach it expected to take in responding to any section 126 petition that might be submitted relying on the same record as CAIR. Under that approach, as long as an upwind state remained on track to comply with CAIR, EPA would defer making the Section 126 findings. In the proposed Transport Rule, EPA does not discuss how petitions under Section 126 will be handled. [EPA-HQ-OAR-2009-0491-2811.1,p.4]
EPA should set forth a position in the Transport Rule that, as long as an upwind state remains on track with compliance with the Transport Rule, EPA will defer making Section 126 findings. This would avoid a de novo review by EPA of petitions filed by states that would lead to uncertainty for the regulated community and consume EPA and state resources for no environmental benefit. [EPA-HQ-OAR-2009-0491-2811.1,p.4]
Response: 
EPA appreciates the comments regarding the relationship of the transport rule to the BART requirement.  EPA recognizes that EPA's regional haze regulations provide for trading program alternatives to the BART requirement.  EPA's BART guidelines were published on July 6, 2005.  70 FR 39104.   In the final BART guidelines notice, EPA determined that CAIR achieved greater progress than BART and could be used by States as a substitute for BART at affected EGUs.  70 FR 39137.
Following promulgation of the Transport Rule, we intend to conduct a similar analysis of the transport rule to determine whether it would achieve greater reasonable progress toward the national visibility goal than BART.   We believe it is best to conduct this analysis once the transport rule requirements are final and certain.  If the analysis supports the conclusion that the transport rule achieves greater reasonable progress than BART, we intend to proceed with a notice and comment rulemaking that would provide that compliance with the Transport Rule satisfies BART requirements in certain states.    Because this analysis is not yet complete, we cannot make any representations in this rule regarding whether the Transport Rule achieves greater reasonable progress than BART.   We do, however, intend to complete this analysis as quickly as possible, and we hope to complete a rulemaking addressing the Transport Rule and BART by spring 2012.
Organization: Ozone Transport Commission (OTC)
NRG Energy
NextEra Energy, Inc.
South Carolina Department of Health and Environmental Control 
Northern Indiana Public Service Company (NIPSCO)
Public Utilities Commission of Ohio
Northwest Indiana Forum
Sierra Club, Pennsylvania Chapter
Texas Mining and Reclamation Association
Sierra Club, New Jersey Chapter
Comment: 
NextEra Energy, Inc.
NextEra Energy encourages EPA to coordinate the proposed rulemaking with other regulations affecting the electric sector.
The Transport Rule is one of several rules affecting the electric sector that EPA will be implementing over the next five to ten years. Each of these rules will impact the industry and companies' long term planning decisions. To enable companies to make decisions consistent with EPA's long-term vhiotl, NextEra Energy encourages EPA to coordinate the upcoming regulations to the extent EPA has the legal authority to do so. We also support the coordination of regulations among EPA's air, water, and solid waste offices in order to allow EPA and industry to assess the interrelated impacts of all regulations affecting the electric sector. This will ensure maximum co-benefits while avoiding potential unintended consequences (e.g., stranded investments) and without delaying important environmental, public health, and economic benefits. [EPA-HQ-OAR-2009-0491-2718.1, p.10]
Northern Indiana Public Service Company (NIPSCO)
The preamble to the Transport Rule discusses upcoming EPA rules anticipated to affect the power sector in the next two years. EPA states that to the extent it has the legal authority to do so while fulfilling its obligations under the CAA, it will coordinate the utility related air pollution rules with the upcoming regulations for the power sector from EPA's Office of Water and its Office of Resource Conservation and Recovery in efforts to maximize reductions while maintaining cost-effective solutions. NIPSCO wholeheartedly agrees that coordination of rules will assist the power sector with planning and decision making and urges EPA to coordinate the Transport Rule with the replacement for the Clean Air Mercury Rule ('Utility MACT'). We urge EPA to consider the implications from the installation of control devices to meet the Transport Rule requirements on the other rules it mentions in the Transport Rule preamble concerning coordination efforts, specifically the coal combustion residue rule, the cooling water intake structures rule, and the effluent guidelines for wastewater discharges from power plants. The requirements of these rules should be set so the limits are achievable and not overly burdensome to the power sector while providing meaningful environmental benefit. Their provisions should be examined and set in a holistic manner that acknowledges the requirements and consequences of meeting the combined set of EGU rules.  [EPA-HQ-OAR-2009-0491-2747.1 p.2]
In order to coordinate other Utility rulemakings with the Transport Rule, NIPSCO recommends that EPA consider an approach that utilizes the entire Phase I period of the existing Clean Air Interstate Rule ('CAIR') and implements the Transport rule in 2015, the beginning of the CAIR Phase II period. NIPSCO will provide examples in these comments of how this approach improves the overall rule implementation process in a more holistic approach, and specifically addresses coordination with the Utility MACT and new ozone standard that will reportedly be the impetus for Transport Rule II. [EPA-HQ-OAR-2009-0491-2747.1 p.3]
Northwest Indiana Forum
Permitting certainty whereby a regulated facility fully understands the expectations and requirements of an environmental permit from either a state regulatory agency or the U. S. Environmental Protection Agency is critical to our nation's competitive status. As such, when new rules, policies and guidance documents are being proposed it is important that the regulators and the regulated community fully understands the interrelationship between air, water and solid waste permitting implications. The proposed Clean Air Transport Rule (CATR) has interdependency on other environmental rules that needs to be identified and provide clear direction. [EPA-HQ-OAR-2009-0491-3650 p.2]
NRG Energy
However, at the scale of the Transport Rule, it is important to provide an orderly, efficient transition to cleaner generation. It will take time to permit and construct new, cleaner facilities and back-end controls. Coal plants will have to make capital investment or retirement decisions based on the energy markets, the Transport Rule and the future demands of the Hazardous Air Pollutant MACT, 316(b) standards, and Coal Combustion Residue Rule. NRG recommends that EPA carefully consider the comprehensive impacts of the timing and implementation details of all these rules, including a 2015 or later implementation date for the Group 1 SO2 reductions. [EPA-HQ-OAR-2009-0491-2749.1, p. 2]
Ozone Transport Commission (OTC)
We also must point out that Section 110(a)(2)(D)(i)(I) of the Clean Air Act addresses transport "...with respect to any such national primary or secondary ambient air quality standard..." Because the 1997 ozone, 1997 PM2.5 and 2006 PM2.5 NAAQS all had identical primary and secondary standards, this has not previously been a concern. Transport 2, however, will have to account for the W-126 secondary standard under the ozone reconsideration, assuming it is part of the final NAAQS rule. OTC also notes that a transport analysis of the SO2 and NO2 secondary standards, scheduled to be finalized in early 2012, would also be appropriate. [EPA-HQ-OAR-2009-0491-2737.1, p. 19]
As a final point in this discussion, while EPA has committed to updating its interstate transport determinations for future ozone and PM2.5 NAAQS, the OTC feels it important for EPA to also assess transport impacts of SO2 and NO2 in regard to their specific 1-hour NAAQS. Section 110(a)(2)(D)(i) calls on states to prohibit the emission of any air pollutant which will contribute significantly to nonattainment or interfere with maintenance of a standard. The proposed Transport Rule notes that "EPA does not expect peak SO2 levels to be a long-range transport issue" (75 FR 45228) but does not allude to any study that yielded this finding. There is no mention of the recent NO2 NAAQS. A technical review should be completed to determine if any reduction in the SO2 or NOx budget would be required for these recently revised NAAQS. A review of the transport effects of each criteria pollutant upon review of the NAAQS is necessary for the protection of public health in downwind areas.
OTC notes that EPA needs to issue a firm timetable for the issuance of Transport 2 to allow states, industry stakeholders and all affected parties time to develop proper strategies to successfully implement the next rule and have a realistic shot at achieving measurable emissions reductions benchmarks. [EPA-HQ-OAR-2009-0491-2737.1, p. 19]
[[Please note commenter has extensive appendices and visual data attached]]
Public Utilities Commission of Ohio
Another extremely important consideration is the series of rules EPA has already proposed and/or implemented, as well as those it is scheduled to propose and finalize during the same timeframe when the Transport Rule will likely take effect. EPA issued its final "Tailoring Rule" for greenhouse gas emissions in May 2010. Beginning in January 2011, the rule will tailor permitting programs to limit the number of facilities that are required to obtain New Source Review and Title V operating permits based on their greenhouse gas emissions. The threshold will cover power plants, refineries, and other large industrial plants. EPA also issued its proposed rule on Coal Combustion Residuals in June 2010, which will seriously impact many utilities, and ultimately, ratepayers. [EPA-HQ-OAR-2009-0491-2855.1 p.14]
Further, in 2011, EPA is scheduled to propose and finalize a new utility MACT for hazardous air pollutants, as well as new utility new source performance standards (NSPS) for criteria pollutants, even while the 2006 utility NSPS are under reconsideration and subject to pending litigation. EPA is also schedule to issue the proposed Transport Rule for the 2010 reconsidered ozone NAAQS in 2011, with the final rule to be issued in 2012. EPA is additionally considering the substance and timing of its response to the remand of the utility NSPS for greenhouse gases. These are just a few of the EPA proposed regulations and issues that stand to impact utilities and ratepayers. In light of the upcoming changes due to new regulations, as well as changes in historical regulations, such as the replacement of CAIR with the proposed Transport Rule, it has become extremely difficult for companies to plan for compliance with the newest regulations. Achieving compliance has, in fact, become such a moving target that it is virtually impossible to comply with the latest-issued regulation before the next comes along, entirely changing expectations and compliance strategies, and creating stranded investments. We firmly believe that extending the timetable for implementation of the Transport Rule will help to alleviate this regulatory chaos, and allow utilities and regulatory bodies to regain their footing, so to speak, before the next round of proposed regulations is issued. We believe, in fact, that a comprehensive, multi-pollutant approach would be the best type of regulation to use in order to minimize confusion, in the minds of both regulatory bodies, as well as the regulated community, and reduce stranded investments. [EPA-HQ-OAR-2009-0491-2855.1 p.14]
Sierra Club, New Jersey Chapter
As regards the information provided in Section III. Summary of Proposed Rule and Background, and especially the statement that 'This proposed rule is the first of several EPA rules to be issued over the next 2 years that will yield substantial health and environmental benefits for the public through regulation of power plants. Fossil-fuel-fired power plants contribute a large and substantial fraction of the emissions of several key air pollutants'... It is even more reassuring to learn that 'The Administrator in January established improved air quality as an Agency priority and announced plans to promote a cleaner and more efficient power sector and have strong but achievable reduction goals for SO2, NOx, mercury and other air toxics.' [EPA-HQ-OAR-2009-0491-3649, p.1]
In addition to this rule, other anticipated actions include a section 111(d) for electric utilities to be proposed by March 2011, potential rules to address pollution transport under revised NAAQS, revisions to new source performance standards for coal and oil-fired utility electric generating units, and best available retrofit technology (BART) and regional haze program requirements to protect visibility. This too, is a good step forward in providing a healthier environment for the public when visiting many of our National and State Parks throughout the eastern United States. [EPA-HQ-OAR-2009-0491-3649, p.2]
Sierra Club, Pennsylvania Chapter
2. We would welcome and support EPA's intention to promulgate a number of additional rules in the near future to require emission reductions from the power plant sector beyond those in the Transport Rule proposal: [EPA-HQ-OAR-2009-0491-3482.1, p.7]
- address upwind transport with future revisions to the ozone or fine PM NAAQS, including a revised ozone NAAQS later this year and additional rulemakings resolving any needed reductions in transported NOx by 2012;
- Section 112(d) "MACT" standards, to be proposed by March 2011;
- revisions to the new source performance standards (NSPS) for coal and oil-fired power plants (including performance standards for GHG emissions); and
- best available retrofit technology (BART) and regional haze programs to protect visibility. [EPA-HQ-OAR-2009-0491-3482.1, p.8]
South Carolina Department of Health and Environmental Control 
The EPA will propose many new important regulations that affect utilities in the next two years, most notably, the Utility MACT and the Tailoring Rule. Because of South Carolina's large SO2 budget, DHEC predicts that these rules (which will restrict, among other things, mercury emissions and greenhouse gases) will likely have more bearing on utilities' decisions on which plants or controls to run than the proposed Transport Rule. Without considering these future rules, the EPA's Transport Rule modeling does not adequately capture the regulatory requirements governing EGU emissions, and may thus lead to flawed results. [EPA-HQ-OAR-2009-0491-2677.1 p.10]
The proposed Transport Rule offers further evidence that the current uncoordinated approach to setting the NAAQS is inefficient. If the EPA issues a new Transport Rule after each revision of the Ozone and PM NAAQS, or perhaps future SO2 NAAQS, budgets will likely change, which hampers long term planning on which the emissions trading program depends. DHEC certainly welcomes the ultimate public health benefits that these new tightened budgets could bring, but revising the Transport Rule according to the unaligned schedules of NAAQS revisions is unnecessarily complex. [EPA-HQ-OAR-2009-0491-2677.1 p.14]
In addition to future revisions to the Transport Rule, other EPA rules, such as the Utility MACT and the Tailoring Rule, affect utilities' decisions on which controls to build and run. The varying compliance dates and methods for these rules add unnecessary confusion to the air quality management process. [EPA-HQ-OAR-2009-0491-2677.1 p.14]
DHEC submits that this is also further evidence that Congress needs to amend the Clean Air Act to allow for a comprehensive, holistic multi-pollutant air quality planning process that aligns the NAAQS revisions and streamlines the SIP process. This is yet another example of where EPA could demonstrate its commitment to reforming the SIP process to focus limited resources on air quality improvement and not process for the sake of process. DHEC acknowledges the multi-pollutant pilot programs in North Carolina; St. Louis, Missouri; and Tacoma, Washington; as well as the Kaizen events in EPA Region 7; and Clean Air Performance Commitment (CAP-C) test cases; but these are no substitute for robust federal legislation that allows for true multi-pollutant planning and alignment of NAAQS compliance schedules. [EPA-HQ-OAR-2009-0491-2677.1 p.14]
For DHEC has been a leader in this reform effort. On September 11, 2009, nine southeastern states signed a resolution calling for, among other things, greater coordination among NAAQS, and a multipollutant strategy for addressing air quality. The resolution also noted that while states are responsible for achieving the NAAQS, the EPA is responsible for regulating pollutant-transport that affects attaining the NAAQS. DHEC appreciates that the EPA is addressing transport of pollutants across state lines, and we look forward to continuing the conversation with the EPA on SIP reform. Ten southeastern states continued this effort with a document entitled Improving the Current Air Quality Management and SIP Processes, sent to Assistant Administrator Gina McCarthy on September 9, 2010. DHEC supports making the necessary improvements to the Air Quality Management process that will ultimately involve state and local air agencies, as well as other stakeholders, in developing a comprehensive approach to air quality management that provides an opportunity for integrated multi-pollutant planning. [EPA-HQ-OAR-2009-0491-2677.1 p.14]
Texas Mining and Reclamation Association
While GCLC understands the need to address the remanded Clean Air Interstate Rule (CAIR), the U.S. Court of Appeals did not set a specific timeline by which EPA should substitute CAIR with a new rule.1 GCLC requests that the EPA relax the compliance deadlines in the Transport Rule in order to acknowledge the complexity and burdens associated with the many standards that will be revised within the next year or two. [EPA-HQ-OAR-2009-0491-2734.1 p.4]

1 See State of North Carolina v. EPA, Case No. 05-1244 (D.C. Cir. December 23, 2008). "...Some Petitioners have suggested that this court impose a definitive deadline by which EPA must correct CAIR's flaws. Notwithstanding these requests, the court will refrain from doing so."
Response: 
EPA's approach in the Transport Rule to measure and address each state's significant contribution to downwind nonattainment and interference with maintenance is guided by and consistent with the Court's opinion in North Carolina and addresses the flaws in CAIR identified by the Court therein.  The final rule also responds to extensive public comments and stakeholder input received during the public comment periods in response to the proposal and subsequent Notices of Data Availability (NODAs), and will provide greater certainty to affected sources and states.  The extensive analyses of this final rule indicate that there will be modest impacts on electricity prices, utilities, and consumers.
As discussed in section III of the Preamble to this rule, EPA will provide full opportunity for notice and comment on each rule as they are proposed and finalized.  EPA will also include the final Transport Rule in its regulatory impact analyses of subsequent rulemakings.
EPA will coordinate utility-related air pollution rules with each other and with other actions affecting the power sector including these rules from EPA's Office of Water and its Office of Resource Conservation and Recovery to the extent consistent with legal authority in order to provide timely information needed to support regulated sources in making informed decisions.  Use of a small number of air pollution control technologies, widely deployed, can assist with compliance for multiple rules.  EPA also notes that the flexibility inherent in the allowance-trading mechanism included in the Transport Rule affords utilities themselves a degree of latitude to determine how best to integrate compliance with the emissions reduction requirements of this rule and those of the other rules.  EPA will pursue energy efficiency improvements in the use of electricity throughout the economy, along with other federal agencies, states and other groups, which will contribute to additional environmental and public health improvements while lowering the costs of realizing those improvements.
The approach embodied within the rule is partly designed to improve the planning process for the NAAQS, is readily applicable to any current and future NAAQS, and would automatically adjust the stringency of the transport threshold to maintain a constant relationship with the stringency of the relevant NAAQS as they are revised.  EPA believes that the final Transport Rule demonstrates the value of this approach for addressing the role of interstate transport of air pollution in communities' ability to comply with current and future NAAQS.  EPA believes that the Transport Rule's approach of using air-quality thresholds to determine upwind-to-downwind-state linkages and using the cost- and air quality-based multi-factor approach to quantify significant contribution to nonattainment and interference with maintenance (i.e., to determine the specific amount of emissions that each upwind state must reduce) could serve as a precedent for quantifying upwind state emission reduction responsibilities with respect to potential future NAAQS.
With respect to the 1997 ozone NAAQS, the Transport Rule requires NOx reductions starting in 2012 to ensure that reductions are made as expeditiously as practicable to assist downwind state attainment and maintenance of the standard.  Sources must comply by May 1, 2012.  The Transport Rule's compliance schedule and alignment with downwind NAAQS attainment deadlines are discussed in detail in section VII of the preamble.
As discussed in Section VII.C of the Preamble, EPA believes the 2012 and 2014 deadlines are feasible, will not result in significant coal retirements, and will not result in any reliability issues.  In addition, the rule is anticipated to have some positive employment impacts in the pollution control and construction industry as new environmental controls are needed to meet the requirements of the rule.
Organization: Rennes, Beth
Michetti, Susan
Comment: 
Michetti, Susan
Industry and its corporations and businesses need to start paying 100% of their costs, including those that are now their cost externalities, including smokestack pollution and the health costs of victims of its polluting externalities. The Precautionary Principle needs to be instituted. The full costs of any process, any pollution, any waste, any adverse health effects to industrial exposure from cradle to grave needs to be treated in accounting and in liability responsibility as that company's full and true costs of doing business. The industry or corporation involved needs to be fully liable and to pay 100% of those costs of doing business,--many of which are currently externalities, being unfairly shifted to and paid by the public, the taxpayers, and by victims. If the corporation and the industry doesn't know a product or process is safe, then it shouldn't be doing that. [EPA-HQ-OAR-2009-0491-3223, p.2]
Rennes, Beth
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.81-82.]
I understand that this proposal would cost energy companies money and time to implement this, but I honestly feel like that's something they signed up for when they got in the business of providing people with energy. It's just an inherent risk and responsibility. And it's going to be paid for somewhere.
Right now I'm paying at least $30 a month for medications and that's with my insurance. And, fortunately, I haven't had to be hospitalized for it, but if I did, that's quite an additional cost for me and the healthcare system. So I don't think anyone's going to get out of paying for it. I guess it's just the question is who.
And personally if -- again, if they are in the business of providing energy, I feel like that's where it comes from. That's part of what they signed on for. And if that means that our rates go up a little bit, I'm happy to pay that if it mean that the children can enjoy recess.  
Response: 
The Transport Rule will result in further emission reductions from the power sector, and help eliminate the emissions across state borders that significantly contribute to nonattainment with air quality standards.
Organization: San Miguel Electric Cooperative, Inc.
Comment: 
San Miguel Electric Cooperative, Inc.
  San Miguel has a significant interest in the outcome of this rulemaking. San Miguel's lignite fired electric generating facility is a major source of electrical generation to our member cooperatives, under a long term wholesale power contracts for 100% of the generation of the San Miguel Generating Station. Being not-for-profit, San Miguel will be forced to pass along, to its consumer-owners, all costs of meeting any new requirements that may result from the implementation of CATR.  [EPA-HQ-OAR-2009-0491-2641.1,p.1]
As a member-owned electricity supplier, San Miguel understands that reliable, affordable electricity has been one of the key drivers of economic growth and prosperity in this country. This fact must not be forgotten as the EPA makes decisions on whether and how to regulate electric generating unit emissions under this and future potential rulemakings. [EPA-HQ-OAR-2009-0491-2641.1,p.1]
Response: 
EPA's approach in the Transport Rule to measure and address each state's significant contribution to downwind nonattainment and interference with maintenance is guided by and consistent with the Court's opinion in North Carolina and addresses the flaws in CAIR identified by the Court therein.  The final rule also responds to extensive public comments and stakeholder input received during the public comment periods in response to the proposal and subsequent Notices of Data Availability (NODAs), and will provide greater certainty to affected sources and states.  The extensive analyses of this final rule indicate that there will be modest impacts on electricity prices, utilities, and consumers while providing significant health benefits to the public.
Organization: Wholesale Markets Brokers' Association
Comment: 
Wholesale Markets Brokers' Association
IV. EPA's Unduly Restrictive Market Design Conflicts with Other Environmental Regulatory Priorities and Future Market Initiatives
A large number of current legislative proposals seek to use some form of cap and trade system in order to reduce GHG emissions in the U.S. and the EPA has mandated the monitoring and inventory of such emissions from many large sources during calendar year 2010. EPA's restrictive approach to trading SO2 and NOx emission allowances will make it more difficult to harmonize any eventual GHG cap and trade program with these efforts. From a market approach, the more value imputed to an emissions allowance, the more desirable it is to trade and the more efficient from an economic standpoint such trades are for the overall economy. Such "bundled" trading reduces transaction costs and recognizes the physical reality that reduced emissions from older, less efficient fossil-fuel fired plants cuts not only SO2 and NOx emissions, but also GHG emissions. EPA's geographic and temporal restrictions on the use of emission allowances conflict with these GHG realities and will make it harder, not easier for implementing a cap and trade system for GHG. [EPA-HQ-OAR-2009-0491-2799.1, p.5]
Second, we would point out that President Obama's October 5, 2009 Executive Order mandates that federal agencies seek to reduced emissions of GHGs and promote energy efficiency. EPA's CATR proposal potentially runs counter to this directive to the extent it fails to leave open to EGU owners the option of accomplishing emission reductions by use of alternative approaches to the installation of scrubbers, including more energy efficient means, such as retirement of older, less efficient units, and/or the substitution of lower sulfur fuels (e.g., natural gas, lower sulfur coal). [EPA-HQ-OAR-2009-0491-2799.1, p.5]
Response: 
EPA's approach in the Transport Rule to measure and address each state's significant contribution to downwind nonattainment and interference with maintenance is guided by and consistent with the Court's opinion in North Carolina and addresses the flaws in CAIR identified by the Court therein.  The final rule also responds to extensive public comments and stakeholder input received during the public comment periods in response to the proposal and subsequent Notices of Data Availability (NODAs), and will provide greater certainty to affected sources and states.  The extensive analyses of this final rule indicate that there will be modest impacts on electricity prices, utilities, and consumers while providing significant health benefits to the public.  EPA also notes that the flexibility inherent in the allowance-trading mechanism included in the Transport Rule affords utilities themselves a degree of latitude to determine how best to integrate compliance with the emissions reduction requirements of this rule and those of the other rules.  EPA will pursue energy efficiency improvements in the use of electricity throughout the economy, along with other federal agencies, states and other groups, which will contribute to additional environmental and public health improvements while lowering the costs of realizing those improvements.

III.G. Setting a Precedent for How to Determine Upwind State Responsibilities in Future Transport Rulemakings

Organization: Council of Industrial Boiler Owners (CIBO)
Comment: 
Council of Industrial Boiler Owners (CIBO)
In the rule, EPA indicates its plan to propose additional rounds that will cover sources other than EGUs. EPA makes this announcement, but provides no data to support an extension of the applicability of the rule. EPA offers lack of time as a reason not to base its plan now for future rulemaking: 'EPA believes that developing supplemental information to consider NOx sources beyond EGUs would substantially delay publication of a final rule beyond the anticipated publication of spring 2011.' 75 FR 45212-3.
EPA violates the CAA and APA rulemaking procedures by prejudging the outcome of a decision regarding how it will regulate sources in the future for certain pollutants. Such decisions can only legally be made based on data, analysis and the host of other considerations EPA must legally address as the basis of its decision. In addition, EPA foreshadows regulation of this sector, but does not spell out in enough detail how the expanded rule might work. Sources are therefore left without the opportunity to comment in any meaningful way on critical elements of this Proposed Rule as it might apply to them. [EPA-HQ-OAR-2009-0491-2751.1 p.7]
Response: 
EPA disagrees with the assertion that we are prejudging the outcome of future decisions.   Any future regulation of nonEGU sources would be accomplished with a transparent technical analysis and notice and comment rulemaking.  
Organization: Midamerican Energy Holdings Company
Comment: 
Midamerican Energy Holdings Company
The import of the proposed Transport Rule cannot be underestimated, particularly based on EPA's indication that the framework laid out in the proposal will be utilized as the basis for future emission transport assessments, including the near-term revised ozone standard assessments. EPA's intent to continuously take a "bite at the apple" to reduce transport emissions every time there is a change to the air quality standards dictates that sound science and good judgment be utilized in establishing the framework for analyzing the transport impacts. In other words, there is only one chance to get it right.  [EPA-HQ-OAR-2009-0491-2748.1 p.3]
Response: 
EPA agrees with the importance of this rulemaking in establishing the framework for future rulemakings.
Organization: National Environmental Development Association
Comment: 
National Environmental Development Association
NEDA/CAP's related concern has to do with the Agency's statements in the preamble of the NPRM which indicate that EPA intends to base future rulemaking on this rulemaking, including but not limited to emission limitations for additional sources including but not limited to industrial combustion units. 75 Fed. Reg. 45,300 - 301. EPA also indicates in the Notice that the Agency intends to rely on his rulemaking at the basis for promulgating future emission control requirements pursuant to future revisions of the National Ambient Air Quality Standards. Id., at 45,301  -  302. NEDA/CAP objects to relying on this rulemaking for future emission limitations or conditions created by EPA's tightening or other revisions to the form of a National Ambient Air Quality Standard. Not only are we objecting now to any future argument that EPA may make regarding our ability to comment on or attack the modeling or other methodologies on which the August 2, 2010 proposal or its state emission allocations are based, but we believe that EPA's intent to rely on this rulemaking based on future actions also violates Section 307(d)(3) and general notions of fairness. Industry needs to know what controls will be required in-total so that plans and costs can be optimized. It is very hard for business to plan and budget for control needs without clarification of what reductions will ultimately be required. Open-ended piece meal regulations are inconsistent with meeting environmental objectives and planning funding and resources to accomplish those objectives in a reasonable manner. [EPA-HQ-OAR-2009-0491-2744.1 p.3]
Response: 
EPA believes this rulemaking provides a framework for assessing significant contribution and interference with maintenance, a framework that would be applicable to future NAAQS.    EPA would, of course provide the opportunity for comment on data and air quality modeling conducted to support such future rulemakings.   
Organization: NextEra Energy, Inc.
Comment: 
NextEra Energy, Inc.
The framework proposed by the Transport Rule would take necessary and important steps toward improving air quality in the eastern U.S. As EPA notes in the preamble and supporting materials for the Transport Rule, the Agency's air quality modeling demonstrates that the Transport Rule would help many areas in the Eastern U.S. attain the current NAAQS. The proposal would also establish a framework that would allow EPA to address any transport problems associated with future NAAQS revisions (e.g., revisions to the 8-hour ozone NAAQS expected in October). [EPA-HQ-OAR-2009-0491-2718.1, p.2]
Response: 
EPA agrees.

IV. Defining "Significant Contribution" and "Interference With Maintenance"

Organization: Edison Electric Institute (EEI)
Comment: 
Edison Electric Institute (EEI)
The Proposed Rule does not bring all ozone and particulate matter non-attainment areas into attainment, a shortcoming claimed by some critics of the proposal. This perspective, however, misinterprets the legal basis of the rulemaking. Under the relevant section of the CAA, § 110(a)(2)(D), authorization of the Transport Rule is based on elimination of the "significant contribution" to nonattainment and interference with maintenance. The CAA does not hold upwind sources responsible for any or all contributions to downwind nonattainment or maintenance issues, only that portion which is considered significant. More broadly, the electric power sector, which emitted about 12 percent of national NOx emissions and 6 percent of ozone precursors in 2009, should not shoulder the entire regulatory burden related to attainment of the 1997 ozone NAAQS. Interstate transport, while very important, is not the sole source of emissions which determine whether a locality attains or does not attain a NAAQS. Additional emissions reductions must be made locally for some non-attainment areas to meet a NAAQS. Additional sources of significant interstate transport and local emission sources beyond EGUs should be considered in future Transport Rules and/or in traditional state implementation plan (SIP) revisions. [EPA-HQ-OAR-2009-0491-2697.1, p.13]  
Response: 
As described in the final Transport Rule preamble, EPA agrees that the objective of section 110(a)(2)(D)(i)(I) is to prohibit emissions that significantly contribute to nonattainment or interfere with maintenance of the NAAQS.  EPA also agrees that the full attainment of air quality standards is a responsibility that is shared by local and upwind sources.
Organization: Ozone Transport Commission (OTC)
Maryland Department of Environment (MDE)
State of Wisconsin, Department of Natural Resources
Pew Environment Group
Mass Comment Campaign (38) (unknown organization)
Sierra Club, Georgia Chapter
City of Philadelphia, Department of Public Health, Air Management Services
Northeast States for Coordinated Air Use Management (NESCAUM)
Pennsylvania Department of Environmental Protection
Clean Air Council
Clean Air Task Force
National Association of Clean of Air Agencies (NACAA)
New York State Department of Environmental Conservation
Comment: 
City of Philadelphia, Department of Public Health, Air Management Services
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.218-219.]
The Rule, in itself, is not a complete solution. There are many states that will need to do more to satisfy their Clean Air obligations to meet the Ozone and PM 2.5 standards.
Clean Air Council
Nevertheless, as the Council has previously indicated in testimony; the level of NOx reduction to be achieved by the Rule does not appear to be as stringent as warranted. The year round and ozone season NOx emissions are reduced by 2014 by only a small fraction above what would have been achieved by the 2005 Clean Air Interstate Rule (CAIR) vacated by the Court. Given the substantial new air quality goals set forth in revisions to the fine particulate, ozone and nitrogen oxide NAAQS which have been promulgated in the interim, the minor incremental improvement in the Transport Rule underwhelms. [EPA-HQ-OAR-2009-0491-2804.1, pp.1-2]
Clean Air Task Force
According to EPA's own statements and using its proposed approach to addressing transported air pollution under section 110(a)(2)(D), the TR proposal does not eliminate all of the projected contribution in upwind states to downwind nonattainment and maintenance problems. EPA's atmospheric modeling shows that even after the proposed rule is implemented:
[These comments were also submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.106-107.]
several downwind areas (Birmingham, Alabama and Allegheny County, Pennsylvania) will still experience nonattainment or maintenance problems under the 1997 annual PM2.5 NAQQS;
at least 14 downwind areas will continue to experience problems with nonattainment or maintenance of the 24-hour PM2.5 NAAQS; 30
and several downwind areas (Houston, Baton Rouge and New York City) will continue to experience ozone NAAQS attainment and maintenance problems.  [EPA-HQ-OAR-2009-0491-2738.1, p.7]
The $500/ton annual NOx marginal cost cut-off should be raised to at least $3200/ton.
The wintertime PM issue identified by EPA in the TR proposal is related not only to SO2 formation of sulfates, but also to NOx formation of nitrates. EPA states, "during the winter, PM2.5 contains a larger nitrate component than in summer months....Given this large contribution from nitrates in the winter, EPA is also taking comment on whether there should be a higher cost threshold for annual nitrogen oxides." 99 This larger nitrate contribution does indeed justify a higher cost threshold for NOx controls. [EPA-HQ-OAR-2009-0491-2738.1, p.17]
Maryland Department of Environment (MDE)
We similarly commend EPA for proposing a methodology for assessing transported air pollution that will provide a framework for quickly analyzing the impact of transport under future revised national ambient air quality standards (NAAQS). EPA must identify the reductions needed to eliminate significant contribution to nonattainment and interference with maintenance concurrent with the setting of new NAAQS for the states to have any chance of developing timely plans to address transport. In order to accomplish this, NOx caps and cost effectiveness thresholds need to be sufficiently strong to eliminate transport into nonattainment areas.  [EPA-HQ-OAR-2009-0491-2639.1, p.2]
Maryland also disagrees with EPA's statement on the responsibilities of downwind states under circumstances where all transport is not eliminated. EPA states in the preamble that a downwind state "must adopt controls to demonstrate timely attainment of the NAAQS despite any pollution transport from upwind states that is not eliminated under section 110(a)(2)(D)' (75 FR 45271 of the preamble). Based on recent discussions with EPA, Maryland and the other states of OTC understand that EPA interprets this statement to mean that section 110(a)(2)(D) has a limited goal of requiring upwind states to eliminate their significant contribution to nonattainment in downwind states, not to require upwind states to eliminate all transport. Even after significant contribution from upwind states is eliminated, downwind states might need to address their attainment needs by adopting controls to deal with local contributions to nonattainment or transport that EPA does not consider significant from upwind states. Maryland hopes that EPA will take the opportunity in issuing the final Transport Rule consistent with EPA's intent. [EPA-HQ-OAR-2009-0491-2639.2, p.8]
Mass Comment Campaign (38) (unknown organization)
The Clean Air Transport Rule will lead to significant public health and clean air benefits, but it needs to be strengthened. By 2014, sulfur dioxide emissions need to be limited to 1.5 million tons annually and nitrogen oxide emissions need to be capped at 900,000 tons. With the collected science clearly showing our health is being damaged by air pollution at even lower concentrations, EPA should restrict emissions as much as possible from older dirty power plants. [EPA-HQ-OAR-2009-0491-3616_Mass, p.1]
National Association of Clean of Air Agencies (NACAA)
The Transport Rule Fails to Completely Eliminate Transport
The proposed Transport Rule does not completely satisfy section 110(a)(2)(D)'s requirements to eliminate emissions that significantly contribute to downwind nonattainment [EPA-HQ-OAR-2009-0491-2771.1, p.3] or interfere with maintenance. As mentioned previously, there are dozens of states 5 that will need to do more in order to satisfy their Clean Air Act obligation to address transport, unless EPA reduces the NOx and SO2 emissions caps. We are disappointed that after spending a year-and-a-half to analyze interstate transport, EPA presents us with an incomplete solution. [EPA-HQ-OAR-2009-0491-2771.1, p.4]
For the remaining transport problems associated with the 2006 PM2.5 NAAQS, EPA says in the proposal that its air quality modeling shows that the "remaining component of nonattainment is almost entirely occurring in the winter months" and that the agency is "moving ahead with further efforts, before the final rule is published, to determine the extent to which this winter problem is caused by emissions transported from upwind states and, if this is the case, to identify the total amount of emissions that represents significant contribution and interference with maintenance. To the extent possible, EPA plans to finalize a rule that fully defines this amount." 6 We urge EPA to quickly complete this study in collaboration with the 15 states identified by EPA as still contributing to transport of PM2.5 precursor emissions, and we urge the agency to promulgate a final rule resolving the transport problem associated with the 2006 PM2.5 NAAQS. In this rule, EPA should clearly identify any additional requirements states must complete in order to fully satisfy their section 110(a)(2)(D) obligations. [EPA-HQ-OAR-2009-0491-2771.1, p.4]
New York State Department of Environmental Conservation
Notwithstanding our support for many aspects of the proposal, we are disappointed that the NOx reductions identified in the rule are inadequate to achieve full attainment of even the outdated 1997 ozone standard, let alone ozone levels that comply with the more restrictive 2008 standard. Because the proposed rule fails to completely address transport and maintenance, we urge EPA to improve the proposal to the extent practicable and quickly proceed to the second rulemaking phase referred to as Transport Rule II, which should be designed to enable full compliance with the new ozone standard that EPA will be announcing shortly. [EPA-HQ-OAR-2009-0491-2730.1, p.1]
Significant Contribution Not Completely Eliminated
EPA acknowledges that the proposed Transport Rule does not fully address SC/IM in all areas of the country as it pertains to the 1997 8-hour ozone and 2006 24-hour PM,., NAAQS. EPA should develop a definitive schedule for addressing the remaining SC/IM not addressed in the proposal. Where additional information gathering and analysis is needed to determine the extent to which further reductions from these states may be needed to fully eliminate SC/IM, this should be done in a manner that does not delay a remedy that addresses the statutory requirement to eliminate transport that causes SC/IM. [EPA-HQ-OAR-2009-0491-2730.1, p.5]
In the proposed Transport Rule, EPA acknowledges that the transport FIPs will not completely satisfy the emission reduction requirements of CAA section 110(a)(2)(D)(i)(I). Two areas Texas and Baton Rouge, Louisiana - are expected to still be in violation of the 1997 Houston, ozone NAAQS in 2014, while the New York City area is expected to have continued maintenance issues with this standard. In order to complete the task under section 110(a)(2)(D)(i) to eliminate all significant contribution and interference with maintenance, EPA should not only include additional reductions in the final rule that fully address the transport component of nonattainment with the 2008 ozone and 2006 PM2.5 NAAQS, but also address the transport components of the soon to be reconsidered NAAQS. [EPA-HQ-OAR-2009-0491-2730.1, p.15]
Northeast States for Coordinated Air Use Management (NESCAUM)
The NESCAUM states are dismayed that the NOx budgets are not set at levels stringent enough to fully address significant contribution. EPA indicates that it did not consider cost thresholds for NOx beyond $500/ton "because there are minimal additional NOx reductions until one considers cost levels higher than $2,400/ton" (75 FR 45281). EPA's conclusion can only be sustained if one first assumes that the only air pollution controls that can be installed prior to 2014 are those controls that are already required to be installed due to existing federal or state requirements. This approach severely limits the type and cost of controls that can be installed.
We do not agree with EPA's assumption that allowance prices reflect the actual marginal costs of installing air pollution control equipment. There are many factors that may cause significant fluctuations in allowance prices, which in turn make allowance prices a poor predictor of the actual marginal cost of installing air pollution controls. An example of the impact of one such factor, regulatory uncertainty, was demonstrated in the recent fluctuations in allowance prices caused by the vacatur and subsequent remand of CAIR. 
The NESCAUM states do not support EPA's proposed cost threshold for this phase of the transport rule, and are concerned that such a low threshold could create an unworkable regulatory hurdle especially for states that have already implemented successful programs at much greater per ton costs (some are even greater than $40,000/ton). EPA's own cost/benefit analysis shows that significantly higher costs are cost effective based on the public health and welfare benefits. We understand that EPA used a $2,500/ton threshold for CAIR. 
EPA should not be using the cost for operating SCRs as the basis for setting the cost threshold. EPA should use the same baseline it used for assessing the efficacy of the program (without CAIR) and the controls that were assumed, and apply the full cost of installing and operating controls in order to provide a level playing field. EPA's proposed methodology advantages the recalcitrant because under EPA's approach, sources/states that previously chose not to install controls under CAIR are now advantaged by not having to install controls under this rule. The burden then falls entirely onto the sources that opted to control under CAIR, as they are assigned an artificially low control cost that only accounts for operating their existing controls, and not the cost of installing them under the previous (and now illegal) CAIR. This appears to be a "Catch- 22" situation for those sources that acted in good faith to control emissions under CAIR, and a windfall for those sources that did not act at all. 
We urge EPA to adopt a more realistic cost threshold that reflects the cost of controls already in place in many areas and is more aligned with state efforts. Furthermore, these costs should also reflect EPA's use of additional available methods to determine cost effectiveness, such as EPA's CUECost model to analyze costs of installing NOx and SO2 controls on electric generating units (EGUs). For non-EGUs, these costs are more realistically reflected in the revised version of EPA's Control Strategy Tool (CoST). EPA should use CoST to analyze costs of NOx and SO2 controls for non-EGU stationary sources such as industrial, commercial, and institutional (ICI) boilers.   [EPA-HQ-OAR-2009-0491-2694.1 p.4-5]
Ozone Transport Commission (OTC)
OTC believes that the proposed Transport Rule does a more thorough job of dealing with thetransport of S02 emissions that contribute to PM2.S pollution than it does for NOx and OlOne, which isOTC's primary concern. For example, the proposed rule outlines a program that provides a 16 percentreduction in seasonal NOx emissions and a 36 percent reduction in annual NOx, while S02 is reduced by4S percent overall in the region, and some states' S02 emissions are reduced by as much as 68 percent.The proposed rule does not provide sufficient NOx controls that are feasible to implement by 2014 toeliminate significant contribution and interference with maintenance for the 1997 ozone standard,which will significantly and negatively impact the states of the Ozone Transport Region (OTR). [EPA-HQ-OAR-2009-0491-2737.1, p.2]
In order to complete the task under section 110(a)(2)(D) to eliminate all significant contribution and interference with maintenance, EPA needs to include additional reductions in the final Transport Rule that fully address the transport component of nonattainment with the 1997 ozone and 2006 PM2.5 NAAQS. EPA acknowledges in the proposed Transport Rule that the Transport FIPs will not completely satisfy the emission reduction requirements of Clean Air Act section 110(a)(2)(D)(i)(I). Two areas --  Houston, Texas and Baton Rouge, Louisiana -- are expected to still be in violation with the 1997 ozone NAAQS in 2014, while the New York City area is expected to have continued maintenance issues with this standard. [EPA-HQ-OAR-2009-0491-2737.1, p. 19]
Pennsylvania Department of Environmental Protection
The proposed Transport Rule does not provide a complete remedy to address transported pollution because, as EPA acknowledges, the proposal does not 'fully quantify all of the significant contribution and interference with maintenance.' 75 Fed. Reg. at p. 45,359. EPA has also indicated that there are 10 states for which the agency has 'only quantified a minimum amount of emissions reductions needed to make measurable progress towards eliminating their significant contribution and interference with maintenance with respect to' the 1997 ozone standard. 75 Fed. Reg. at p. 45,214, n. 2. [EPA-HQ-OAR-2009-0491-2660.1, p.6]
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.52-53.]
The proposed Transport Rule does not provide a complete remedy to address transported pollution because, as EPA acknowledges, the proposal does not, 'fully quantify all of the significant contribution and interference with maintenance'.
To date, we have recorded 28 exceedances of the 1997 ozone standard and 145 exceedances of the 2008 ozone standard during the 2010 ozone season. Failure to strengthen the final rule will adversely impact the ability of states to attain and maintain the ozone and PM 2.5 standards by the prescribed deadlines.
States cannot fully address transported pollution, EPA's failure to provide a complete remedy may result in the filing of additional 126 petitions, which are unduly burdensome for EPA and state agencies.
The DEP commends EPA for taking its responsibility very seriously 'to ensure that upwind reductions are made in a timely way so that downwind states can meet their attainment obligations' ... and for its acknowledgement ''that the proposal may not fully address the 24-hour PM2.5 standard.' EPA has indicated that the remaining component of nonattainment, which ' ... is almost entirely occurring during the winter months ... ' will be studied to determine the extent to which the ''winter problem' is caused by emissions transported from upwind slates.'. 75 Fed. Reg. 45,284. The DEP urges EPA to aggressively complete this study and, in collaboration with the states identify the additional amount of NOx and SO2 emission reductions needed to eliminate emissions that significantly contribute to or interfere with maintenance of the 24-hour PM2.5 NAAQS. [EPA-HQ-OAR-2009-0491-2660.1, p.6]
Therefore, DEP recommends that EPA identify the additional NOx and S02 reductions needed to eliminate significant contribution and interference with maintenance from upwind states contributing to any remaining areas that do not meet the current ozone and PM 2.5 NAAQS, and revise the final rule accordingly. Should EPA determine that a 'winter problem' continues to exist for residual 24-hour l'M2.5 sites, a supplemental rule should be promulgated expeditiously. This determination should be made in coordination with states with residual problem sites and the upwind states contributing to the transported pollution. [EPA-HQ-OAR-2009-0491-2660.1, p. 6]
Pew Environment Group
We believe that EPA's proposed transport rule is a good step towards requiring needed air pollution reductions in the electric power sector, and we commend EPA for bringing the proposal forward. We are concerned, however that the proposal falls short of requiring the amount of cost-effective reductions that are reasonably obtainable and necessary to protect human health and the environment. [EPA-HQ-OAR-2009-0491-2703.1 p.2]
EPA's modeling shows that even after the proposed rule is implemented: [EPA-HQ-OAR-2009-0491-2703.1 p.2]
several downwind areas (Birmingham, Alabama and Allegheny County, Pennsylvania) will still experience nonattainment problems under the 1997 annual PM2.5 National Ambient Air Quality Standards (NAAQS);
at least 14 downwind areas will continue to experience problems with nonattainment of the 24-hour PM2.5 NAAQS;
several downwind areas (Houston, Baton Rouge and New York City) will continue to experience ozone NAAQS attainment problems; and
A stronger rule could save many more lives and provide incremental benefits far in excess of costs. We therefore urge EPA to:
reduce the annual control region SO2 cap to 1.75 million tons and the NOx cap to 900,000 tons; and
include Texas, Arkansas, Mississippi and the Dakotas in the rule.
The Pew Charitable Trusts has also submitted comments on other aspects of this proposed rule jointly with the Alliance for Industrial Efficiency and other organizations. [EPA-HQ-OAR-2009-0491-2703.1 p.2]
Sierra Club, Georgia Chapter
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.97.]
However more reductions will be necessary when the newer, more protective standards are finalized and we're concerned that the Transport Rule does not go as far as fast as the Bush era CAIR would have required.
State of Wisconsin, Department of Natural Resources
Ensure upwind S02 and NOx reductions are adequate to ensure continued maintenance of the National Ambient Air Quality Standards (NMQS). [EPA-HQ-OAR-2009-0491-2829.2, p.1; This comment can also be found at section III.D of this comment summary]
LADCO has shared information with EPA regarding very current technical assessment of winter PM-2.S episodes in Wisconsin and the system sensitivity to ammonia, nitrate and sulfate. The current study suggests that as regional background levels of NOx and S02 drop relative to the ambient ammonia levels that the eastern Wisconsin sites will become more NOx and S02 limited, enhancing the PM-2.5 reduction potential of a combined NOx and S02 reduction strategy. Hence reduction of both pollutants from the proposed annual budget levels is a critical next step of the attainment strategy. [EPA-HQ-OAR-2009-0491-2829.2, p.6]
Response: 
Clean Air Act section 110(a)(2)(D)(i)(I)requires reductions in upwind states are sufficient to ensure that all significant contribution to nonattainment and interference with maintenance is eliminated.  Thus, the presence of residual nonattainment or maintenance areas does not, by itself, signify a failure to satisfy the requirements of 110(a)(2)(D)(i)(I).

As described in section VI of the preamble for the final Transport Rule, EPA reassessed SO2 and ozone season and annual NOX reductions for the final Transport Rule.  Please refer to this section for further details.

EPA finds that the final Transport Rule emission reductions of annual NOX and SO2 successfully eliminate significant contribution for the 1997 annual PM2.5 NAAQS and the 2006 24-hour PM2.5 NAAQS, respectively in the states covered by this rule for each NAAQS.  Regarding non-attainment of the ozone NAAQS, EPA believes it can best serve states with ozone non-attainment and maintenance problems by quickly finalizing this rule and seeking further ozone season NOX reductions, if necessary, in subsequent rulemakings.  This does not preclude EPA from future transport-related rulemakings to address new standards.  See final Transport Rule preamble section VI.D for a more detailed discussion of these issues.
Additionally, air quality modeling results provided in section VIII.B of the final rule's preamble indicate that the final transport rule will resolve non-attainment with all PM2.5 standards for all receptors with the exception of 1 receptor with remaining non-attainment problems for the 24-hour PM2.5 standard in the Liberty-Clairton area--which EPA has noted is heavily influenced by a local source of organic carbon (75 FR 45281).  This modeling also indicates that only 1 area (Houston, TX) is expected to have remaining non-attainment problems for the ozone standard and only 1 area (Baton Rouge, LA) is expected to have remaining maintenance problems for the ozone standard.
Organization: Pennsylvania Department of Environmental Protection
Comment: 
Pennsylvania Department of Environmental Protection
While we support EPA's decision to move forward with the final Transport Rule to provide for timely emission reductions and substantial human health and environmental benefits, failure to provide a complete remedy could set a flawed precedent for future transport analyses and remedies. Failure to strengthen the rule will adversely impact the ability of states to attain and maintain ozone and l'M2.5 NAAQS by prescribed deadlines. Additionally, if EPA fails to establish more stringent NOx emission budgets, reductions needed to satisfy the States' Section 110(a)(2)(D) obligations, improve visibility and reduce nitrogen deposition will not be achieved. States cannot fully address transported pollution-EPA's failure to provide a complete remedy to address transport may result in the filing of additional Section 126 petitions, which are unduly burdensome for EPA and state agencies. [EPA-HQ-OAR-2009-0491-2660.1, pp.6-7]
Response: 
EPA does not find the rule as adversely impacting Pennsylvania's ability to attain the PM and ozone NAAQS.   Additionally, the air quality impacts analysis for the final rule shows significant improvements in air quality, including improvements for Pennsylvania.   
EPA agrees that improving visibility and reducing nitrogen deposition are important air quality-related goals, and we believe that there will be indirect benefits to visibility and nitrogen deposition as a result of the rule.
Organization: Utility Air Regulatory Group (UARG)
National Mining Association (NMA)
Comment: 
National Mining Association (NMA)
No Need Exists to Enforce More Stringent Requirements than CAIR
Despite generating more and more electricity, the electric utility has made steady and continuous progress in reducing emissions. According to EPA data, SO2 emissions from power-plants declined by 67 percent from 1980 to 2009, and NOX emissions declined by 72 percent over the same period. Just in the East, NOX emissions during the ozone season declined by 80 percent. [EPA-HQ-OAR-2009-0491-2868.1,p.19]
This progress will continue at the CAIR level of reductions. CAIR was widely supported both by environmental groups and industry. It unraveled principally because of its interstate trading component. But the Court did not require EPA to produce more emission reductions than the CAIR amounts. CAIR was a reasonable program when promulgated, and nothing has happened since it was promulgated to justify further reductions. To the contrary, with the economic situation, load growth and the demand for electricity has flattened. The country has also undertaken a variety of new initiatives to foster renewable resource development. [EPA-HQ-OAR-2009-0491-2868.1,p.19]
Utility Air Regulatory Group (UARG)
Additionally, notwithstanding these assertions that the emission reductions required in 2012 would occur even without the Proposed Transport Rule, EPA indicated in a presentation given in July 2010, when it announced the proposed rule, that it projects that the proposed rule would reduce SO2 emissions by an additional one million tons per year ("TPY") in 2012 beyond what CAIR would have accomplished: from an emission level of 5.1 million TPY under CAIR to 4.1 million TPY under the proposed rule. In fact, during a meeting held shortly after EPA issued the proposed rule but before its publication in the Federal Register, EPA acknowledged that, according to the Agency's projections, the 2012 state budgets in the Proposed Transport Rule would reduce SO2 emissions by 1.2 million TPY, from 5.1 million TPY under CAIR to 3.9 million TPY under the Proposed Transport Rule. EPA failed to explain this apparently substantial discrepancy or how over a million additional tons of emissions would be eliminated in a phase of the program that is intended merely to replicate what would have occurred anyway. [EPA-HQ-OAR-2009-0491-2756.1, p.20]
Moreover, EPA has not shown that emission reductions beyond those required by CAIR are necessary. EPA's own data show that existing controls are working to reduce emissions; the result is that concentrations of SO2 and NOx in the ambient air have declined steadily in recent years. The D.C. Circuit's opinion in North Carolina v. EPA did not require, or even remotely suggest, that the overall degree of emission reductions required under CAIR was less than that necessary to comply with CAA section 110(a)(2)(D)(i)(I). [EPA-HQ-OAR-2009-0491-2756.1, pp.20-21]
Response: 
As described in preamble section VI.D of the final Transport Rule, the D.C. Court of Appeals rejected the state budgets in CAIR as arbitrary and capricious and not consistent with CAA section 110(a)(2)D)(i)(I)  (North Carolina, 531 F.3d  918 and 921) and remanded CAIR to EPA to promulgate a new rule (the Transport Rule) replacing CAIR and consistent with the Court's decision (North Carolina, 550 F.3d 1178).  On remand EPA developed new, final state budgets for the Transport Rule that address the Court's concerns and meet section 110(a)(2)(D)(i)(I) requirements.  Further, because the Court reversed and remanded CAIR with instructions to "remedy" the rule's "fundamental flaws" (including specifically the state budgets found to be unlawful (North Carolina, 550 F.3d 1178), it is difficult to see how a comparison between new state budgets meeting section 110(a)(2)(D)(i)(I) requirements and unlawful budgets could be viewed as informative.  
Section V of the preamble for the final Transport Rule discusses and explains the baseline used for the Transport Rule.
As described in section VI of the preamble for the final Transport Rule, EPA reassessed SO2 and ozone season and annual NOX reductions for the final Transport Rule.  Please refer to this section for further details.

IV.A. Choice of Baseline Used for Cost, Emissions, and Air Quality Analyses

Organization: American Electric Power
West Window Corp.
Metropolitan Washington Air Quality Committee
DoubleTree Hotel Roanoke and Conference Center
Indiana Manufacturers Association, Inc. (IMA)
Utility Air Regulatory Group (UARG)
Texas Commission on Environmental Quality
Southern Company
Duke Energy
Florida Electric Power Coordinating Group, Inc. (FCG)
Lansing Board of Water & Light
Ameren Services Company
Florida Municipal Electric Association (FMEA)
South Carolina Department of Health and Environmental Control 
Edison Mission Energy (EME)
City of Tallahasse
E.ON U.S.
Ohio Manufacturers Association (OMA)
First Energy
Progress Energy Service Company
Alcoa Power Generating Inc. - Warrick Power Plant
Ohio Utility Group (OUG)
Michigan Manufacturers Association (MMA)
Indiana Builders Association 
Commerce Lexington Inc.
Louisiana Chemical Association (LCA)
Gainesville Regional Utilities (GRU)
Four Flags Area Chamber of Commerce
Michigan Chamber of Commerce
DTE Energy
Tampa Electric Company
Midwest Ozone Group
State of Louisiana, Department of Environmental Quality
Exxon Mobil Corporation
Comment: 
Alcoa Power Generating Inc. - Warrick Power Plant
The Clean Air Transport Rule (CATR) fails to consider the extensive amounts of controls installed after 2005, resulting in a large and erroneous overestimation of emissions reductions necessary to eliminate the significant contribution to downwind nonattainment of many states.  EPA was well-aware when it proposed the CATR using only a 2005 EGU emissions inventory that significant new controls had been and were being installed on vast numbers of EGUs in response to CAIR and other requirements. Accordingly, EPA should re-analyze the CATR using the most up to date source inventory and air quality data. Because EPA's assumption that CAIR is not in effect lacks a 'rational relationship to the real world,' APGI suspects that the Agency's CATR cannot withstand judicial scrutiny. See, e.g., Appalachian Power Co. v. EPA. 249 F.3d 1032, 1053 (D.c. Cir. 2001) (citing Chemical Mfrs. Ass'n v. EPA, 28 F.3d 1259, 1265 (D.C. Cir.1994) ('While courts routinely defer to agency modeling of complex phenomena, model assumptions must have a 'rational relationship' to the real world'). [EPA-HQ-OAR-2009-0491-3648, p.1]
Ameren Services Company
EPA has assumed as part of its regulatory analysis that the CAIR program is not in place and that affected sources are not complying with the rules. This assumption is in error. By not including compliance with CAIR in its assumptions, the EPA analyses have over stated the impact of these sources prior to the imposition of the proposed transport rule considered here. This assumption completely invalidates EPA's analysis and the results produced. EPA should redo the analysis assuming that CAIR is fully in place and the affected sources are complying with the regulations. EPA should view CAIR as the valid control program that it is and allow sources to smoothly transition to the future rules to be promulgated, just as was done between the NOx SIP Call trading program and the CAIR. [EPA-HQ-OAR-2009-0491-2722.1, p.3]
American Electric Power
 The EPA's rule does not take into consideration recent improvements in air quality caused by compliance with the Clean Air Interstate Rule, which this rule replaces. [EPA-HQ-OAR-2009-0491-2665.1, p. 1]
States are now attempting to gather sufficient information to perfonn the technical analyses necessary to demonstrate attainment of additional NAAQS. The appropriate course under the current circumstances is not to require states to ignore CAIR and attempt to provide technical support for standards that continue to be revised by EPA. Instead, EPA should update its modeling and consider the impact of reductions already achieved and 'in the pipeline' as a result of CAIR, and provide states with rational targets and timetables. In the absence of clear targets, states should not be burdened with a requirement to perform successive modeling demonstrations that are not based in reality. EPA should allow states the time necessary to develop sound technical demonstrations that are based on real reductions, and that are targeted to achieve concrete air quality goals. [EPA-HQ-OAR-2009-0491-3934[1].1, p.3]
City of Tallahasse
In addition, EPA's proposal fails to properly account for post-2005 emission reductions and air quality improvements resulting from CAIR.  By excluding CAIR controls and reductions from the modeling, EPA ignored substantial federally-enforceable emission reductions, which could foreseeably change the modeling results.  Also, EPA must include CAIR in its base case because it remains binding law. [EPA-HQ-OAR-2009-0491-2669.1, pp.3-4]
Commerce Lexington Inc.
Companies have already taken steps to comply with CAIR and that makes the Transport Rule premature. The EPA should determine the full impact of CAIR compliance before proposing new rules. [EPA-HQ-OAR-2009-0491-2869.1 p.2]
DoubleTree Hotel Roanoke and Conference Center
Many improvements that have already been made as a result of compliance with CAIR need to be recognized by the EPA. [EPA-HQ-OAR-2009-0491-2142, p.1]
DTE Energy
EPA should have included CAIR in its base case modeling because it remains binding law until it is replaced by a valid rule. DTE and all other regulated EGUs operate under the current provisions of CAIR, and this should be reflected in EPA's analysis. [EPA-HQ-OAR-2009-0491-3714.1_NODA, p.3]
Duke Energy
EPA's Base Case Modeling Should Have Included CAIR.
The Proposed Transport Rule fails to account properly for post-2005 emission reductions and air quality improvements resulting from CAIR. See 75 Fed. Reg. at 45233/3. EPA's decision to assume that CAIR is not in effect for its analysis of the 2012 and 2014 base cases is contrary to law and has the effect of greatly overestimating EGU emissions during those periods. EPA should have included CAIR in its base case because it remains binding law pending the promulgation and effective date of a replacement rule. The D.C. Circuit granted EPA's petition to remand CAIR without vacatur, holding that "notwithstanding the relative flaws of CAIR, allowing CAIR to remain in effect until it is replaced by a rule consistent with our opinion would at least temporarily preserve the environmental values covered by CAIR." By the terms of the court's opinion on rehearing, CAIR will be in place until a replacement rule is implemented. Thus, there will be no time when neither CAIR nor a replacement rule will be in effect. In the proposed rule's preamble, EPA recognizes what it could hardly dispute -- that CAIR has yielded substantial emission reductions. There can be no dispute that CAIR, together with other programs, has had significant effects in reducing NAAQS design values. [EPA-HQ-OAR-2009-0491-2689.1, p.12]
In both the NOx SIP Call and CAIR rulemakings, EPA took account of other regulations in evaluating downwind air quality. It is therefore difficult to understand why EPA made the arbitrary decision to ignore CAIR for purposes of the Proposed Transport Rule. EPA's brief explanation of why it decided to ignore CAIR in modeling the base case for the proposed rule, which it characterizes as "a unique situation," id. at 45233/3, is baffling. PM2.5 and ozone concentrations have declined substantially in recent years, due not only to CAIR but a combination of other programs, and are expected to continue declining in the future. EPA should not pretend that these air quality improvements never occurred. While it may be true that some limited increases in emission levels could occur due to discontinuation of CAIR requirements in some states, it is far less realistic to assume that CAIR is no longer in effect than to assume that it remains in effect. EPA should recalculate the 2012 and 2014 base cases to take CAIR into account. [EPA-HQ-OAR-2009-0491-2689.1, pp.12-13]
E.ON U.S.
Air Quality improvements resulting from CAIR are not considered.
The Proposed Transport Rule fails to account properly for post-2005 emissions reductions and air quality improvements resulting from CAIR. EPA should have included CAIR in its base case because it remains binding law pending the promulgation and effective date of are placement rule. If EPA insists upon using 2005 as the baseline year, then the cost of all NOx and SO2 controls installed since 2005 should be included. [EPA-HQ-OAR-2009-0491-2797.1, p.4]
The proposed reduction targets are too stringent. [EPA-HQ-OAR-2009-0491-2797.1, p.4]
EPA's analysis fails to consider the air quality benefits of controls installed on the utility fleet since 2005 as a result of CAIR and other requirements. [EPA-HQ-OAR-2009-0491-2797.1, p. 4]
Edison Mission Energy (EME)
The Agency should not seek additional NOX reductions from EGUs beyond those already contemplated by the Transport Rule. NOX emissions from EGUs before the Transport Rule even takes effect have declined by over 70% since 1990 and currently account for only 12% of the national total. After the reductions required by Phase I and II of the Rule have occurred, these levels will be even lower. It is unreasonable for EPA to expect additional NOX reductions from EGUs, when they will account for such a small proportion of the total that remains. [EPA-HQ-OAR-2009-0491-2707.1, p.4]
Exxon Mobil Corporation
:: EPA's approach for projected emissions inventories eliminated the consideration of any reductions required by CAIR, due to the fact that the CAIR rule was overturned in North Carolina v. EPA, 531 F.3d 896, 901 (D.C. Cir. 2008). However, this results in overly conservative projections. The CAIR rule was remanded, but not vacated. Many regulated public utilities already invested in capital projects for reduction that were approved by their regulatory bodies and/or ratepayers. In most cases, legal obstacles would prevent the undoing of these projects. In addition, each physical project undertaken for purposes of CAIR reductions was of necessity permitted under an enforceable Title V permit. Those projects and permit limits cannot be relaxed without the facilities triggering Prevention of Significant Deterioration (PSD) rules. Triggering PSD would involve imposition of Best Available Control Technology, which, in most cases, would mean that the facilities would have to keep the pollution control equipment they installed for CAIR, or would have to meet even more stringent requirements. EP A should have undertaken a much more rigorous analysis for projecting what steps EGUs would take if CAIR were vacated completely, with no replacement. EPA has tools to easily accomplish this, such as a Clean Air Act Section 114 request for information. In short, EPA overestimated Base Case emissions for both 2012 and 2014 by eliminating all CAIR control requirements. [EPA-HQ-OAR-2009-0491-2841.1,pp.6-7]
First Energy
FE appreciates the use of sound modeling principles, model construction, and pre and post processing, but strongly believes the EPA's use of a 2005 base year is entirely unrepresentative. Using 2005 as a Base Year indeed captures a 'Pre-CAIR' world, as EPA stated, but is not representative of recent emissions and meteorological conditions. [EPA-HQ-OAR-2009-0491-2657.1, p.3]
To illustrate this point, Alpine Geophysics conducted air quality modeling using the latest version of CAM-x with a 2008 emissions and meteorology platform. Future years 2014 and 2018 were modeled using a "Business As Usual" approach (CAIR and enforceable federal, state, and local controls). The results showed that virtually ALL of the nonattainment areas for 8 hour Ozone (1997 NAAQS) and PM 2.5 (2006 NAAQS) come into attainment  -  except for two PM monitors (Allegheny County, PA and Brooke County, WV), which by EPA analysis are heavily influenced by local sources. Given the Court did not establish a deadline for EPA to revise CAIR and because revised standards for PM and Ozone are imminent and will result in the health benefits to be achieved by CATR, the CATR rule is actually not needed at this time. [EPA-HQ-OAR-2009-0491-2657.1, p.3; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.3 10/15/2010]
Florida Electric Power Coordinating Group, Inc. (FCG)
In addition, EPA's proposal fails to properly account for post-2005 emission reductions and air quality improvements resulting from CAIR. By excluding CAIR controls and reductions from the modeling, EPA ignored substantial federally-enforceable emission reductions, which could foreseeably change the modeling results. Also, EPA must include CAIR in its base case because it remains binding law. [EPA-HQ-OAR-2009-0491-2658.1, p.9]
Florida Municipal Electric Association (FMEA)
EPA is using the authority of section 110(c)(1) of the CAA to impose a FIP on Florida and the other states. The assumption is that the Florida SIP is deficient since it does not eliminate interstate transport of pollutants resulting in a significant impact to a downwind state's NAAQS compliance. However, this may not be the case. Many of the CAIR SO2 and NOx emission reductions for Florida in 2012 may be enforceable under Title V permits. We understand than the State of Florida will address this issue in their comments on the Transport Rule. It appears that EPA used 2005 SO2 and NOx emissions as opposed to the expected 2012 SO2 and NOx emissions baseline to evaluate the significance of Florida emissions on downwind states. Since the estimated 2012 CAIR rule required annual emissions reductions may be enforceable under Florida regulations, it is unreasonable to evaluate Florida's significance impacts based on a pre-CAIR emissions baseline.[EPA-HQ-OAR-2009-0491-2731.1, p. 3]
In addition, by using a 2005 emissions baseline, EPA exaggerates the projected benefits of the Proposed Transport Rule by failing to acknowledge that most of the benefits accrue from CAIR emission reductions. [EPA-HQ-OAR-2009-0491-2731.1, p. 3]
In addition, EPA's proposal fails to properly account for post-2005 emission reductions and air quality improvements resulting from CAIR. By excluding CAIR controls and reductions from the modeling, EPA ignored substantial federally-enforceable emission reductions, which could foreseeably change the modeling results. Also, EPA must include CAIR in its base case because it remains binding law.  [EPA-HQ-OAR-2009-0491-2731.1, p. 8]
Four Flags Area Chamber of Commerce
' The EPA has not determined the effect that recent actions to comply with the Clean Air Interstate Rule (CAIR) will have on ambient and downwind air quality. Because of actions already taken, the Transport Rule may not be necessary. [EPA-HQ-OAR-2009-0491-3807, p.2]
Before the EPA imposes new reductions on sulfur dioxide and nitrogen oxide emissions, it should take into account the progress that the nation has made under CAIR. Though the Rule was remanded by the D.C. Circuit Court of Appeals in 2008, it remains in effect and generation companies  have necessarily moved ahead with implementation of compliance measures. Before new rules are  imposed on a still-weak economy, it makes more sense to determine what improvements in air quality  have already occurred. To ignore the improvement the nation has made to date could impose  needless substantial costs on my citizens with limited incremental environmental benefit. As we  continue to climb out of recession, the last thing that government should do is create additional costs  to the economy without substantiated reasons. [EPA-HQ-OAR-2009-0491-3807, pp.2-3]
Gainesville Regional Utilities (GRU)
EPA is using the authority of section 110(c) (I) of the CAA to impose a FIP on Florida and the other states. The assumption is that the Florida SIP is deficient since it does not eliminate interstate transport of pollutants resulting in a significant impact to a downwind state's NAAQS compliance. However, this may not be the case. Many of the CAIR SO2 and NOx emission reductions for Florida in 2012 may be enforceable under Title V permits. We understand that the State of Florida will address this issue in their comments on the proposed CATR. It appears that EPA used 2005 SO2 and NOx emissions as opposed to the expected 2012 SO2 and NOx emissions baseline to evaluate the significance of Florida emissions on downwind states. Since the estimated 2012 CAIR required annual emissions reductions may be enforceable under Florida regulations, it is unreasonable to evaluate Florida's significance impacts based on a pre-CAIR emissions baseline. [EPA-HQ-OAR-2009-0491-2674.1, p.5]
In addition, by using a 2005 emissions baseline, EPA exaggerates the projected benefits of the proposed CATR by failing to acknowledge that most of the benefits accrue from CAIR emission reductions. [EPA-HQ-OAR-2009-0491-2674.1, p.5]
Indiana Builders Association 
The EPA has not determined the effect that recent actions to comply with the Clean Air Interstate Rule (CAIR) will have on ambient and downwind air quality. Because of actions already taken, the Transport Rule may not be necessary. [EPA-HQ-OAR-2009-0491-2871.1,p.2]
Before the EPA imposes new reductions on sulfur dioxide and nitrogen oxide emissions, it should take into account the progress that the nation has made under CAIR. Though the Rule was remanded by the D.C. Circuit Court of Appeals in 2008, it remains in effect and generation companies have necessarily moved ahead with implementation of compliance measures. Before new rules are imposed on a still-weak economy, it makes more sense to determine what improvements in air quality have already occurred. To ignore the improvement the nation has made to date could impose needless substantial costs on our members and region with limited incremental environmental benefit. As we continue to climb out of recession, the last thing that government should do is create additional costs to the economy without substantiated reasons. [EPA-HQ-OAR-2009-0491-2871.1 ,p.3]
Indiana Manufacturers Association, Inc. (IMA)
The IMA encourages the EPA to delay implementation of the Transport Rule as it is proposed. The current proposal has several shortcomings that will result in needless economic harm to Indiana. [EPA-HQ-OAR-2009-0491-1813.1, p.1]
Reasons to delay include: The EPA has not determined the effect that recent actions to comply with the Clean Air Interstate Rule (CAIR) will have on ambient and downwind air quality. Because of actions already taken, the Transport Rule may not be necessary. [EPA-HQ-OAR-2009-0491-1813.1, p. 1]
 Before the EPA imposes new reductions on sulfur dioxide and nitrogen oxide emissions, it should take into account the progress that the nation has made under CAIR. Though the Rule was remanded by the D.C. Circuit Court of Appeals in 2008, it remains in effect and generation companies have necessarily moved ahead with implementation of compliance measures. Before new rules are imposed on a still-weak economy, it makes more sense to determine what improvements in air quality have already occurred. To ignore the improvement the nation has made to date could impose needless substantial costs on my citizens with limited incremental environmental benefit. As we continue to climb out of recession, the last thing that government should do is create additional costs to the economy without substantiated reasons. [EPA-HQ-OAR-2009-0491-1813.1, pp. 2-3]
Lansing Board of Water & Light
Setting 2005 as the Base Case year for modeling undermines the significant investments utilities have made to reduce emissions throughout the last 5 years. EPA acknowledges this by stating "the baseline used in this analysis assumes no CAIR" which is ludicrous since the DC Court specifically remanded without vacating the rule, thus ensuring that emission reductions would continue to be enforceable through CAIR. By assuming the significant reductions of CAIR never happened, EPA modeling arbitrarily predicts higher impacts than can be expected in reality. [EPA-HQ-OAR-2009-0491-2752.1,p.6]
 
Louisiana Chemical Association (LCA)
EPA Overestimated Emissions in its 2012/2014 Projections by Completely Discounting Reductions Made Under CAIR EPA's approach for projected emissions inventories eliminated the consideration of any reductions required by CAIR, due to the fact that the CAIR rule was overturned in North Carolina v. EPA, 531 F.3d 896, 901 (D.C. Cir. 2008). However, this results in overly conservative projections. The CAIR rule was remanded, but not vacated. Many regulated public utilities already invested in capital projects for reduction that were approved by their regulatory bodies and/or ratepayers. In most cases, legal obstacles would prevent the undoing of these projects. In addition, each physical project undertaken for purposes of CAIR reductions was of necessity permitted under an enforceable Title V permit. Those projects and permit limits cannot be relaxed without the facilities triggering Prevention of Significant Deterioration (PSD) rules. Triggering PSD would involve imposition of Best Available Control Technology, which, in most cases, would mean that the facilities would have to keep the pollution control equipment they installed for CAIR, or would have to meet even more stringent requirements. EPA should have undertaken a much more rigorous analysis for projecting what steps EGUs would take if CAIR were vacated completely, with no replacement. EPA has tools to easily accomplish this, such as a Clean Air Act Section 114 request for information. In short, EPA overestimated TR Base Case emissions for both 2012 and 2014 by eliminating completely consideration of reductions made as a result of CAIR control requirements. [EPA-HQ-OAR-2009-0491-3527.1, p. 29]
Metropolitan Washington Air Quality Committee
  We applaud EPA for taking swift action to address the issues raised by the court in its ruling on the Clean Air Interstate Rule (CAIR). As you are aware, our recently submitted State Implementation Plans (SIPs) for ozone and fine particles include reductions from CAIR as a core component of our control strategy and attainment demonstration. Loss of such a key provision would have had serious implications for our ability to control sources in our region as well as count on reductions from upwind sources. Timely implementation of the Transport Rule will be an important step in securing necessary emission reductions included in our SIPs. [EPA-HQ-OAR-2009-0491-2618.1, p.1]
Michigan Chamber of Commerce
Before the EPA imposes new reductions on sulfur dioxide and nitrogen oxide emissions, it should acknowledge and account for the progress that the nation has made under CAIR and other emissions reductions on the books. Though the CAIR was remanded by the D.C. Circuit Court of Appeals in 2008, it remains in effect, and generation companies have necessarily moved ahead with implementation of compliance measures. Before new rules are imposed on a still-weak economy, it makes more sense to determine what improvements in air quality have already occurred. As Michigan continues to climb out of recession, the last thing government should do is create additional costs to the economy without substantiated reasons. [EPA-HQ-OAR-2009-0491-2696.1, p.2]
Michigan Manufacturers Association (MMA)
- The EPA has elected to use a 2005 base year emissions inventory. By doing so, EPA creates a modeling scenario that does not account for the real emissions reductions that have occurred through recent actions to comply with the Clean Air Interstate Rule (CAIR), as well as consent orders that are on the books, within the 32-state region. These emissions reductions have a demonstrated positive impact on ambient air quality, in Michigan and in downwind states. [EPA-HQ-OAR-2009-0491-2762.1, p.2]
- EPA's has deliberately chosen to only consider ambient air quality data through the year 2007. EPA currently posses quality assured data through 2009. That data shows that many of the nonattainment areas that EPA begins with and projects for future years, actually are currently meeting the standards that are the objectives of the proposed rules. EPA's choice disregards the efforts of states, like Michigan, and the affected sources to make real and demonstrable improvements to air quality. [EPA-HQ-OAR-2009-0491-2762.1, p.2]
Second, EPA's choice to only consider ambient air quality data collected through the year 2007 fails to look at the real world picture. EPA has quality assured data through 2009. The data show that many of the nonattainment areas that EPA begins with and projects for future years, actually are currently meeting the standards that are the objectives of the proposed rules. EPA's choice disregards the efforts of states, like Michigan, and the affected sources to make real and demonstrable improvements to air quality. [EPA-HQ-OAR-2009-0491-2762.1, p.3]
Before the EPA imposes new reductions on sulfur dioxide and nitrogen oxide emissions, it should take into acknowledge and account for the progress that the nation has made under CAIR and other on the books emissions reductions. Though the CAIR was remanded by the D.C. Circuit Court of Appeals in 2008, it remains in effect and generation companies have necessarily moved ahead with implementation of compliance measures. Before new rules are imposed on a still-weak economy, it makes more sense to determine what improvements in air quality have already occurred. To deliberately ignore the improvement the nation has made to date will impose needless substantial costs with limited incremental environmental benefit. As Michigan continue to climb out of recession, the last thing that government should do is create additional costs to the economy without substantiated reasons. [EPA-HQ-OAR-2009-0491-2762.1, pp.3-4]
Midwest Ozone Group
EPA arbitrarily assumes that the CAIR is not in effect in its 2005 base case. [EPA-HQ-OAR-2009-0491-2809.1, p.3]
The CAIR took effect in 2005 (70 Fed. Reg. 25,162, Mary 12, 2005). Although the D.C. Circuit initially vacated the CAIR in July 2008, the D.C. Circuit ultimately held following petitions for rehearing in December 2008 that vacatur was not required. North Carolina v. EPA, 531 F.3d 896 (D.C. Cir.), modified on rehearing, 550 F.3d 1176 (D.C. Cir. 2008). Thus, the CAIR remains in effect today and is legally enforceable today. Nonetheless, in analyzing existing emissions, EPA arbitrarily and capriciously "assumes that the CAIR is not in effect." 75 Fed. Reg. 45, 210, 45,233/3. Because EPA's assumption that the CAIR is not in effect lacks a "rational relationship to the real world," the Agency's proposed CATR cannot withstand judicial scrutiny. See, e.g., Appalachian Power Co. v. EPA, 249 F.3d 1032, 1053 (D.C. Cir. 2001) (citing Chemical Mfrs. Ass'n v. EPA, 28 F.3d 1259, 1265 (D.C. Cir.1994) ("While courts routinely defer to agency modeling of complex phenomena, model assumptions must have a `rational relationship' to the real world"). [EPA-HQ-OAR-2009-0491-2809.1, p.3]
EPA's decision to ignore the installation and operation of CAIR controls and emission reductions that have taken place since 2005 and that continue to take place is arbitrary and capricious. EPA attempts to explain its decision to ignore the CAIR first by arguing that it is premature to identify the states to be covered by the final CATR and second by arguing that the CAIR would not continue indefinitely. In EPA's own words: [EPA-HQ-OAR-2009-0491-2809.1, p.3; for additional comments pertaining to EPA arbitrarily assumes that the CAIR is not in effect in its 2005 base case, see pp.3-4]
EPA's arguments in support of its assumption of excluding no CAIR controls lacks support in the real world. First, EPA says that the new transport region may be smaller than the CAIR region. EPA's attempted justification ignores the D.C. Circuit's mandate to include the "interfere with maintenance" prong of CAA § 110(a)(2)(D)(i)(I) in its analysis. NC v. EPA, 531F.3d. 896, 908-11. As EPA itself has recognized, the result of this holding is for the number of covered states to increase, not decrease. Indeed, the proposed CATR covers thirty-one states plus the District of Columbia, whereas the CAIR covers twenty-eight states plus the District of Columbia. While EPA may still be considering whether certain states should be included in the CATR, EPA can and should analyze emissions reductions from those states whose status as a CAIR and CATR state is not uncertain. [EPA-HQ-OAR-2009-0491-2809.1, p.4]
Second, EPA says it cannot consistent with the D.C. Circuit's decision "assume that reductions from CAIR would continue indefinitely." The D.C. Circuit has allowed the CAIR to remain in place until it can be replaced. EPA fails to explain why its modeling does not assume the CAIR remains in place at least until the proposed CATR is finalized and takes effect, i.e., compliance and reductions are required. [EPA-HQ-OAR-2009-0491-2809.1, p.4]
EPA's erroneous assumption of no CAIR controls is critical because if EPA had taken into account control technology installations and emissions reductions resulting from the CAIR, then EPA's modeling projections would have shown even greater air quality improvement and would have eliminated monitored nonattainment at all but two locations. Except for these two locations, which are dominated by emissions from local sources, all monitored nonattainment is eliminated. EPA therefore does not need to address upwind and downwind state linkages or significant contribution. Because EPA's assumption of no CAIR controls in its base case ignores the "significant emissions reductions" from the CAIR that have and continue to take place in the real world, EPA must revise its proposed CATR to include CAIR controls. [EPA-HQ-OAR-2009-0491-2809.1, p.4]
Ohio Manufacturers Association (OMA)
EPA unnecessarily ignores the likely positive impacts already achieved by the Clean Air Interstate Rule (CAIR), which the Transport Rule will replace. Recent modeling performed by power generators indicates that the pollution reductions found in the Transport Rule could be substantially achieved over the same period of time by continuing CAIR and other emission requirements. Before proceeding with the Transport Rule, EPA should fully investigate the progress made thus far under CAIR and factor that analysis into the rulemaking process going forward. [EPA-HQ-OAR-2009-0491-2651.1, 2]
Ohio Utility Group (OUG)
Accurate data shows less stringent emissions reductions are appropriate [EPA-HQ-OAR-2009-0491-2679.1, p.7]
The most significant flaw of the proposed Transport Rule is EPA's failure to assume control technology and emissions reductions achieved with the advent of CAIR. The bottom-up modeling approach employed by EPA requires data and assumptions to be extremely accurate. Denying the existence and successes of the CAIR pro gram reduces the accuracy of EPA's information exponentially. EPA's response is that 'a state affected by CAIR may not be affected by the new rule and after the new rule goes into effect, the CAIR requirements will no longer apply ... and therefore an increase in emissions relative to present levels could occur in that state." However, EPA's position is irrational. [EPA-HQ-OAR-2009-0491-2679.1, p.7]
As an initial matter, the Utilities reiterate that states cannot be forced to accept federal emissions limitations. Section 110(a) of the CAA requires states to address downwind transport, and it is for the states to determine the unit-specific emissions limitations to ensure compliance. Moreover, the only way to rectify EPA's inconsistency with respect to aligning the Transport Rule deadlines with the NAAQS deadlines is to assume CAIR. [EPA-HQ-OAR-2009-0491-2679.1, p.7]
When modeling is performed with the most recent and accurate data - data that assumes CAIR - the Transport Rule's 2014 compliance deadline becomes much more realistic. In fact, the data shows that no (significant) additional reductions are necessary. OUG members participated in developing the comments submitted by the Midwest Ozone Group ('MOG') and adopt certain portions thereof. In these comments, the Utilities direct EPA's attention to MOG's modeling analysis demonstrating that Ohio NOx and S02 caps similar to the caps developed under CAIR, accounting for the control measures installed to comply with CAIR, are adequate to eliminate Ohio's 'significant contribution' to downwind non attainment in almost all areas by2014 - before the NAAQS attainment deadlines. MOG's data confirms what EPA already knew. 'EPA believes that a great deal of the improvement in PM2.5 and 24-hour concentrations in the eastern U.S. can be attributed to EGU reductions achieved due to the CAIR." [EPA-HQ-OAR-2009-0491-2679.1, p.7]
The billions of dollars spent and the resulting air quality improvements under CAIR cannot be arbitrarily ignored. Examining the rationale of the proposed Transport Rule in its entirety reveals that EPA bootstrapped its argument for excluding CAIR. First, EPA explains that CAIR cannot be assumed because some states that were covered under CAIR may not be covered under the Transport Rule, which EPA wrongfully seems to fear will result in carte blanche emissions practices in those 'lucky' states. Then, EPA establishes compliance deadlines for the Transport Rule that EPA previously determined to be infeasible for the CAIR program. This is where EPA's circular reasoning returns to the start. Now, those deadlines are feasible because of all the improvements made and anticipated to be made - under the CAIR program. EPA cannot forego CAIR in its formal rulemaking and, at the same time, assume CAIR to support that very decision. [EPA-HQ-OAR-2009-0491-2679.1, pp.7-8]
As discussed throughout these comments, state budget allocations - or, more precisely, the emissions control systems units will be required to install- are directly related to the data and modeling used by EPA. As MaG demonstrated, the use of inaccurate data results in as ubstantial overestimation of emissions, thereby creating a false depiction of the limitations needed to control those emissions. Without assuming the existence of CAIR, the proposed Transport Rule has Hobbesian potential- at great expense, many EGU's would purchase and install equipment that is not necessary; some units would be forced to shut down temporarily; jobs would be lost; and grid reliability would become questionable. [EPA-HQ-OAR-2009-0491-2679.1, p.8]
Progress Energy Service Company
EPA's Base Case Modeling Should Have Included CAIR
The Proposed Transport Rule fails to account properly for post-2005 emissions reductions and air quality improvements resulting from CAIR. Progress Energy recommends that EPA include CAIR in its base case because it remains binding law pending the promulgation and effective date of a replacement rule. [EPA-HQ-OAR-2009-0491-2831.1 p.5]
South Carolina Department of Health and Environmental Control 
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.86-87.]
This proposal to increase allowable emissions seems to contradict the spirit of anti-backsliding provisions in the Clean Air Act. Moreover, the EPA assumed a stationary source universe without an existing Clean Air Interstate Rule or CAIR controls in the Transport Rule model.
South Carolina contends that the EPA's model should recognize the limits and controls put in place to meet the requirements of the CAIR because utilities are not operating in a world without CAIR. South Carolina utilities and their rate payers commit considerable resources to install operating controls on several coal-fired units to meet the requirements of the CAIR and the EPA's transport modeling should take into account the operation of these CAIR-based controls.
To address these unintended consequences, South Carolina contends that the final Transport Rule should include provisions to require sources to maintain existing controls and start to comply with the CAIR.
Southern Company
XI. EPA's Method for Determining States' Significant Contribution to Nonattainment and Interference with Maintenance is Arbitrary and Unjustified and Results in Unnecessary Requirements for Emissions Controls
A. EPA's Base Case Modeling Should Have Included CAIR
The Proposed Transport Rule fails to account properly for post-2005 emission reductions and air quality improvements resulting from CAIR. EPA's decision to assume that CAIR is not in effect for its analysis of the 2012 and 2014 base cases has the effect of greatly overestimating EGU emissions during those periods. EPA should have included CAIR in its base case because it remains binding law pending the promulgation and effective date of a replacement rule. The D.C. Circuit granted EPA's petition to remand CAIR without vacatur, holding that 'notwithstanding the relative flaws of CAIR, allowing CAIR to remain in effect until it is replaced by a rule consistent with our opinion would at least temporarily preserve the environmental values covered by CAIR.' By the terms of the court's opinion on rehearing, CAIR will be in place until a replacement rule is implemented. Thus, there is no time during which neither CAIR nor a replacement rule will be effective. [EPA-HQ-OAR-2009-0491-2864.1, p. 27]
In the proposed rule's preamble itself, EPA recognizes what it could hardly dispute -- that CAIR has yielded substantial emission reductions. For example, according to the proposed rule, the most recent monitoring available (2006-2008) 'shows significant improvement[]' in PM2.5 ambient air quality, and 'EPA believes that a great deal of the improvement in PM2.5 annual and 24-hour concentrations in the eastern u.s. can be attributed to EGU S02 reductions achieved during CAIR.' There can be no dispute that CAIR, together with other programs, has had significant effects in reducing NAAQS design values. [EPA-HQ-OAR-2009-0491-2864.1, p. 27]
Additionally, in both the NOx SIP Call and CAIR rulemakings, EPA took account of other regulations in evaluating downwind air quality. See 63 Fed. Reg. at 57377/1 (NOx SIP Call) (EPA's 'analytical approach assumes that downwind areas implement all required controls and receive the benefit of reductions from Federal measures, and yet have a residual nonattainment problem.'); 69 Fed. Reg. at 4581/2-3 (CAIR proposed rule) ('In modeling the 2010 and 2015 'base cases,' we took into account adopted State and Federal regulations (e.g., mobile sources rules, the NOx SIP Call) as well as regulations that have been proposed and that we expect will be promulgated before [CAIR] is finalized.') Additionally, in the Proposed Transport Rule, EPA took into account all other federal rules promulgated as of December 2008, exceptfor CAIR. It is difficult to understand why EPA made the decision to ignore CAIR for purposes of the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2864.1, p. 27]
EPA's brief explanation of why it decided to ignore CAIR in modeling the base case for the proposed rule, which it characterizes as 'a unique situation,' is baffling. EPA acknowledges that 'EPA has been directed to replace the CAIR; yet the CAIR remains in place and has led to significant emissions reductions in many states.' Then, it says that 'EPA cannot prejudge at this stage which states will be affected by the rule,' and goes on to note that sources in states that are regulated under CAIR but not under the Transport Rule may increase their emissions once CAIR expires. Yet there are very few of those states, and the existence of a minority of such states hardly justifies wholesale disregard ofCAIR reductions. 25 In any event, many sources located in states that were regulated under CAIR but are not proposed to be regulated under the Transport Rule have gone to great expense to install controls to comply with CAIR. They are very unlikely to dismantle them or to discontinue use of them to the point that their emissions return to pre-CAIR levels. Finally, PM2.5 and ozone concentrations have declined substantially in recent years, due not only to CAIR but a combination of other programs, and are expected to continue declining in the future.  While it may be true that some limited increases in emission levels could occur due to discontinuation of CAIR requirements in some states, it is far less realistic to assume that CAIR is no longer in effect than to assume that it remains in effect. EPA should recalculate the 2012 and 2014 base cases to take CAIR into account. [EPA-HQ-OAR-2009-0491-2864.1, pp. 27-28]
State of Louisiana, Department of Environmental Quality
EPA must consider the emission reductions that have been achieved thru CAIR and other initiatives. [EPA-HQ-OAR-2009-0491-2655.1, p.1]
Tampa Electric Company
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.71-72.]
Tampa Electric urges EPA to include the benefits gained from the emission reductions already instituted as a result of the CAIR interim program.
Texas Commission on Environmental Quality
The TCEQ finds that the modeling conducted for Texas significantly over-predicts future ozone design values by ignoring actual monitoring and emissions data [EPA-HQ-OAR-2009-0491-2857.1, p.2]
Utility Air Regulatory Group (UARG)
EPA's Base Case Modeling Should Have Included CAIR
The Proposed Transport Rule fails to account properly for post-2005 emission reductions and air quality improvements resulting from CAIR. See 75 Fed. Reg. at 45233/3. EPA's decision to assume that CAIR is not in effect for its analysis of the 2012 and 2014 base cases has the effect of greatly overestimating EGU emissions during those periods. EPA should have included CAIR in its base case because it remains binding law pending the promulgation and effective date of a replacement rule. The D.C. Circuit granted EPA's petition to remand CAIR without vacatur, holding that "notwithstanding the relative flaws of CAIR, allowing CAIR to remain in effect until it is replaced by a rule consistent with our opinion would at least temporarily preserve the environmental values covered by CAIR." 550 F.3d at 1178. By the terms of the court's opinion on rehearing, CAIR will be in place until a replacement rule is implemented. Thus, there is no time during which neither CAIR nor a replacement rule will be effective. [EPA-HQ-OAR-2009-0491-2756.1, pp.55-56]
In the proposed rule's preamble itself, EPA recognizes what it could hardly dispute -- that CAIR has yielded substantial emission reductions. For example, according to the proposed rule, the most recent monitoring available (2006-2008) "shows significant improvement[]" in PM2.5 ambient air quality, and "EPA believes that a great deal of the improvement in PM2.5 annual and 24-hour concentrations in the eastern U.S. can be attributed to EGU SO2 reductions achieved due to the CAIR." 75 Fed. Reg. at 45219/3; see also id. at 45220/1-3 (noting that "EPA believes that there would be substantially more nonattainment counties for both the annual and 24-hour standards if the CAIR were not in effect," and crediting a variety of programs with improved ozone air quality in the years since EPA published CAIR). There can be no dispute that CAIR, together with other programs, has had significant effects in reducing NAAQS design values. [EPA-HQ-OAR-2009-0491-2756.1, p.56]
Additionally, in both the NOx SIP Call and CAIR rulemakings, EPA took account of other regulations in evaluating downwind air quality. See 63 Fed. Reg. at 57377/1 (NOx SIP Call) (EPA's "analytical approach assumes that downwind areas implement all required controls and receive the benefit of reductions from Federal measures, and yet have a residual nonattainment problem."); 69 Fed. Reg. at 4581/2-3 (CAIR proposed rule) ("In modeling the 2010 and 2015 `base cases,' we took into account adopted State and Federal regulations (e.g., mobile sources rules, the NOx SIP Call) as well as regulations that have been proposed and that we expect will be promulgated before [CAIR] is finalized.") In the Proposed Transport Rule, EPA purportedly took into account all other federal rules promulgated as of December 2008, except for CAIR.29 75 Fed. Reg. at 45233/3. It is difficult to understand why EPA made the decision to ignore CAIR for purposes of the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2756.1, pp.56-57]
EPA's brief explanation of why it decided to ignore CAIR in modeling the base case for the proposed rule, which it characterizes as "a unique situation," id. at 45233/3, is baffling. EPA acknowledges that "EPA has been directed to replace the CAIR; yet the CAIR remains in place and has led to significant emissions reductions in many states." Id. at 45233/3. Then, it says that "EPA cannot prejudge at this stage which states will be affected by the rule," and goes on to note that sources in states that are regulated under CAIR but not under the Transport Rule may increase their emissions once CAIR expires. Id. at 45233/3. Yet there are very few of those states, and the existence of a minority of such states hardly justifies wholesale disregard of CAIR reductions. Moreover, EPA has not shown that emission increases in these few states are likely, or indeed that such increases would even be permitted under state law. In any event, many sources located in states that were regulated under CAIR but are not proposed to be regulated under the Transport Rule have gone to great expense to install controls to comply with CAIR. They are very unlikely to dismantle them or to discontinue use of them to the point that their emissions return to pre-CAIR levels. Finally, PM2.5 and ozone concentrations have declined substantially in recent years, due not only to CAIR but also to a combination of other programs, and are expected to continue declining in the future. See EPA's Trends Report at 1-2. While it may be conceivable that some limited increases in emission levels could occur due to discontinuation of CAIR requirements in some states, it is far less realistic to assume that CAIR is no longer in effect than to assume that it remains in effect. EPA should recalculate the 2012 and 2014 base cases to take CAIR into account. [EPA-HQ-OAR-2009-0491-2756.1, pp.57-58]
West Window Corp.
The EPA's rule does not take into consideration recent improvements in air quality caused by compliance with the Clean Air Interstate Rule, which this rule would replace. [EPA-HQ-OAR-2009-0491-2386, p.1]
Response: 
See section V.B of the preamble.  EPA notes that the final Transport Rule does not set any precedent on what EPA may determine to be cost-effective reduction in future rulemakings, such as rulemakings concerning CAA section 110(a)(2)(D)(i)(I) requirements with regard to NAAQS than the NAAQS considered in the Transport Rule.  In future rulemakings, EPA intends to consider a broad array of source sectors, including but not limited to the electricity generation sector.

IV.B. Approach to Identify Contributing Upwind States and Approach to Identify Downwind Nonattainment/Maintenance Receptors

Organization: Fond du Lac Reservation
National Tribal Air Association (NTAA)
Comment: 
Fond du Lac Reservation
Technical Analysis  
First, the EPA takes too narrow of a view in applying the 'good neighbor' provision under section 110(a)(2)(D)(i)(1) of the Clean Air Act ('CAA') to advance the Transport Rule's purpose of bringing about positive NOx and SO2 emissions reductions, and as such, fails to adequately consider Indian tribes in any of its technical analysis. [EPA-HQ-OAR-2009-0491-3707, p.2]  
With respect to the 'good neighbor' provision which requires a state to ensure its jurisdiction's emission sources do not significantly contribute to air pollution in another state, and particularly to its nonattainment of designated national ambient air quality standards ('NAAQS'), the EPA fails to give any consideration to Indian tribes under the Transport Rule. Of course, the Agency could argue that it is following the letter of the law as the CAA makes specific reference to a. 'state,' but practically speaking, a downwind tribe is apt to suffer the same type of air-related impacts to its citizenry and land as a contiguous and/or nearby state covered under the Rule. In no way should such an Indian tribe be required to meet some burdensome bureaucratic process such as acquiring treatment-as-a-state (in accordance with the Act's section 301(d)) before the Agency will consider air-related impacts from an upwind state in accordance with the Rule. The Agency must avoid being shortsighted and instead consider the impacts of upwind states to all governmental jurisdictions including those of tribes. [EPA-HQ-OAR-2009-0491-3707, p.2]  
From what our Tribe understands about the Transport Rule, the EPA in fact stopped short of the mark by failing to consider Indian tribes in any of its technical analysis with respect to modeling, monitoring and emission inventories, 3 and may have actually gap-filled tribal data with that of states. As a result, the Agency fails to provide tribes with any assurances that they will achieve the particulate matter and/or Ozone NAAQS, or that their lands will not become 'hot spots' for NOx and SO2 as a result of the Rule's implementation. The Agency owes tribes much more, particularly based on the federal government's trust responsibility to them that requires the EPA to look out for the general welfare of such tribes and avoid taking actions that would compromise the Agency's ability to fulfill this responsibility, and given tribes' status as sovereign nations . But how are tribes to know if the federal government's trust responsibility has been met in the context of the Rule when the Agency has failed to account for anything related to these tribes in its technical analysis? [EPA-HQ-OAR-2009-0491-3707, pp.2-3]  
The Band recommends that the EPA redo its technical analysis to include Indian tribes and to gain a better understanding of the impacts and obligations truly associated with upwind states; technical analyses for any forthcoming Agency rule should consider Indian tribes as well. In support of this effort, particularly when an EPA rule is intended to affect the emissions of specific sources, the Agency should provide for an overlay of tribal lands so tribes can have a better understanding as to how they are being affected by such sources and how the proposed rule might improve their situation. [EPA-HQ-OAR-2009-0491-3707, p.3]   
3. A number of places in the Transport Rule reference how Canada and Mexico were considered in EPA's technical analysis while the Agency fails to consider Indian tribes altogether. [EPA-HQ-OAR-2009-0491-3707, p.2]  
National Tribal Air Association (NTAA)
Technical Analysis
First and foremost, the EPA takes too narrow of a view in applying the 'good neighbor' provision under section 110(a)(2)(D)(i)(l) of the Clean Air Act (CAA) to advance the Transport Rule's purpose of effectuating positive NOx and SO2 emissions reductions, and as such, fails to adequately consider Indian Tribes in any of its technical analysis. [EPA-HQ-OAR-2009-0491-2778.1, p.2]
With respect to the 'good neighbor' provision which requires a state to ensure its jurisdiction's emission sources do not significantly contribute to air pollution in another state, and particularly to its nonattainment of designated national ambient air quality standards (NAAQS), the EPA fails to give any consideration to Indian Tribes under the Transport Rule. Of course, the Agency could argue that it is following the letter of the law as the CAA makes specific reference to a 'state,' but practically speaking, a downwind Indian Tribe is apt to suffer the same type of air-related impacts to its citizenry and land as a contiguous and/or nearby state covered under the Rule. In no way should such an Indian Tribe be required to meet some burdensome bureaucratic process such as acquiring treatment-as-a-state (in accordance with the Act's section 301(d)) before the Agency will consider air-related impacts from an upwind state in accordance with the Rule. The Agency must avoid being shortsighted and instead consider the impacts of upwind states to all governmental jurisdictions including those of Tribes. [EPA-HQ-OAR-2009-0491-2778.1, p.2]
From what the NTAA understands about the Transport Rule, the EPA in fact did stop short by failing to consider Indian Tribes in any of its technical analysis with respect to modeling, monitoring and emission inventories, 3 and may have actually gap-filled Tribal data with that of states. As a result, the Agency fails to provide Tribes with any assurances that they will achieve the particulate matter and/or Ozone NAAQS, or that their lands will not become 'hot spots, for NOx and SO2 as a result of the Rule's implementation. The Agency owes Tribes much more, particularly based on the federal government's trust responsibility to them that requires the EPA to look out for the general welfare of such Tribes and avoid taking actions that would compromise the Agency's ability to fulfill this responsibility. But how are Tribes to know if the federal government's trust responsibility has been met in the context of the Rule when the Agency has failed to account for anything related to these Tribes in its technical analysis? [EPA-HQ-OAR-2009-0491-2778.1, pp.2-3]
The NTAA therefore recommends that the EPA redo its technical analysis to include Indian Tribes and to gain a better understanding of the impacts and obligations truly associated with upwind states; technical analyses for any forthcoming Agency rule should consider Indian Tribes as well. In support of this effort, particularly when an EPA rule is intended to affect the emissions of specific sources, the Agency should provide for an overlay of Tribal lands so Tribes can have a better understanding as to how they are being affected by such sources and how the proposed rule might improve their situation. [EPA-HQ-OAR-2009-0491-2778.1, p.3]

Footnote 3: A number of places in the Transport Rule reference how Canada and Mexico were considered in EPA's technical analysis while the Agency fails to consider Indian Tribes altogether. [EPA-HQ-OAR-2009-0491-2778.1, p.3]
Response: 
EPA's impacts and benefits analysis show that the emissions reductions required by the Transport Rule result in substantial decreases in transported PM2.5  and ozone concentrations throughout the eastern half of the United States.     EPA notes that the types and levels of reductions seen in states within this region will also be achieved in areas of Indian country that are encompassed within those states.  
With respect to the issue of "hot spots," EPA's air quality analysis for the Transport Rule did not show any resulting increases in ozone or PM2.5 anywhere in the Eastern United States as a result of this rule. 
Air quality in Indian country and health effects for tribal people were considered in the benefits analysis, even if they aren't mentioned specifically.  In addition, the distributional analysis, which examined the distribution of reductions in mortality risk due to reductions in PM2.5 exposure, does include specific analysis of changes in risk for Native American populations.
Organization: Ozone Transport Commission (OTC)
Comment: 
Ozone Transport Commission (OTC)
OTC suggests that the same weighted five-year average for both nonattainment and interference-with-maintenance projections be used. If that approach were used, it would seem reasonable to a) use different future years for the determination of attainment or interference with maintenance (maintenance should come after attainment), and/or b) use a different threshold for the determination of attainment (level of NAAQS) vs. the determination of interference with maintenance (e.g. 95% of level of NAAQS), making sure to reconcile these different thresholds with the "weight of evidence" concept described in the modeling guidance. [EPA-HQ-OAR-2009-0491-2737.1, p. 8]
Response: 
Regarding point (a), EPA recognizes as discussed in the preamble to the proposed rule that "maintenance" has two components.   First, provisions for maintenance assure that areas that are projected to attain, but given historic variability in air quality may have difficulty maintaining attainment.  Second, additional considerations may be needed if areas currently are projected to attain, but which could be in nonattainment later if emissions were to increase..  
Regarding point (b), EPA believes that its approach to identifying maintenance receptors is preferable to the approach suggested by the commenter, because it provides a method that is monitor-specific and makes use of local data in the assessment. 

IV.B.1. Choice of Covered Pollutants (SO2 and NOx for PM2.5 and Ozone Season NOx for Ozone)

Organization: Adirondack Council
Comment: 
Adirondack Council
We support strong nitrogen emission reductions on a year-round basis. In the Adirondacks, nitrogen builds up in the winter snow pack and with the spring snowmelt contributes heavily to the episodic acidification of our lakes and streams. There is substantial science that the saturation of nitrogen in soils has played a role in the depletion of essential minerals from forest soils in much of the northeastern United States. A study published by the Hubbard Brook Research Foundation in 2003 entitled, "Nitrogen Pollution: From the Sources to the Sea" provides details about the impact of nitrogen pollution. [EPA-HQ-OAR-2009-0491-2848.1, p.2]
Response: 
EPA agrees that the NOx control requirements have environmental co-benefits.
Organization: American Electric Power
Comment: 
American Electric Power
EPA Failed to Fully Analyze the Available Modeling Output to Determine the Effectiveness of the Transport Rule Remedy
In performing its analysis of the results of the CAMx modeling, EPA has failed to completely utilize the information in the output data. In analyzing the PM2.5 modeling data, EPA appears to have properly reconstructed the total mass from the constituent species. However, EPA appears to have then completely ignored the speciated concentrations to determine the potential effectiveness of the solution in the Proposed Transport Rule. EPA came to an erroneous conclusion that all downwind areas can significantly benefit from large utility reductions in all upwind areas where a given state triggers the I % impact threshold. There are many areas where the total benefit of the utility SO2 and NOx reductions will be much less than those that could be achieved from other source categories due to Organic Carbon being much larger contributors than are sulfate and nitrate species. AEP urges EPA to fully utilize the capabilities of the particulate Source Apportioning Technology (PSA T) algorithms in CAMx. In performing its analysis, EPA could easily develop a series of PSAT runs that would have examined a subset of states in each simulation. [EPA-HQ-OAR-2009-0491-2665.1, p.14]
This approach requires more simulations, but the benefits doing them far outweigh the cost of the extra CPU time involved. Such relevant simulations will identify relative contributions of particular sources and identify areas that need local controls to demonstrate attainment even if the out-of-state transported contribution was zero. [EPA-HQ-OAR-2009-0491-2665.1, p.14]
Response: 
See discussion in preamble section V.A regarding EPA's choice of regulated pollutants.   The final rule, as was the case for the proposed rule and for CAIR, focuses on SO2 and NOx reductions to address transported PM2.5.     EPA is not aware of any studies which specifically identify the mitigation measures and their effectiveness for organic carbon, or which compare the effect of mitigation measures for organic carbon with measures with measures for mitigation of SO2 and NOx for purposes of reducing PM2.5.   
Organization: Entergy Services, Inc.
Comment: 
Entergy Services, Inc.
In the Alternative, Louisiana Should Only Be In the Annual SO2 Program  
If EPA determines in the final Transport rule that Louisiana should be regulated under the annual program, then clearly Louisiana should be regulated under the annual program for SO2 only.  In the proposed rule, EPA has determined that Louisiana should be in the annual program of the Transport Rule because, according to EPA's analysis, Louisiana is interfering with the maintenance of attainment for the annual standard at the Clinton Drive monitor in Harris County, TX.  Further, EPA projected that the impact of Louisiana emissions on that monitor would be 0.34 ug/m3.  A review of the Annual PM Sulfate Contributions and Annual Nitrate Contributions contained in EPA's Air Quality Contributions Data, available at EPA's Technical Support Documents for the Proposed Transport Rule, reveals that the vast majority of the projected impact of Louisiana emissions on the Clinton Drive monitor was contributed by sulfate emissions (0.337 ug/m3) and only 0.004 ug/m3 was contributed by nitrate emissions.  Clearly, it makes no sense to include Louisiana in the annual program for NOx emissions in the transport rule with such a minimum impact on downwind compliance when the significance threshold in the proposed rule is 0.15 ug/m3. [EPA-HQ-OAR-2009-0491-2847.1, p.13]  
Response: 
See preamble section V.A for discussion of southern states NOx contribution to PM.  Additionally, EPA notes that in its analyses for the final Transport Rule, Louisiana is not found to have significant contribution or interference with maintenance with regards to the PM2.5 NAAQS considered in this rule, and is thus not subject to the annual SO2 and annual NOx programs under this rule.
Organization: Exxon Mobil Corporation
Comment: 
Exxon Mobil Corporation
:: As indicated above, the contribution of Louisiana nitrate emissions to PM2.5 annual design value concentrations in Harris County, Texas, are infinitesimal - only 0.004 ug/m3. Even without the corrections to the inventory above, it would be arbitrary and capricious, and an abuse of EPA discretion, to regulate annual NOx levels from Louisiana sources to address this projected contribution. If there is interference with attainment, which is denied, then control of SO2 alone should be all that EPA requires in a FIP. [EPA-HQ-OAR-2009-0491-2841.1, p.6]
Response: 
See preamble section V.A for discussion of southern states NOx contribution to PM.  Additionally, EPA notes that in its analyses for the final Transport Rule, Louisiana is not found to have significant contribution or interference with maintenance with regards to the PM2.5 NAAQS considered in this rule, and is thus not subject to the annual SO2 and annual NOx programs under this rule.
Organization: Southern Company
Alabama Department of Environmental Management
Georgia Department of Natural Resources, Air Protection Branch
Comment: 
Alabama Department of Environmental Management
The potency of fine particle precursors in the Southeast US has been investigated in the course of developing regional haze SIPs and the Birmingham annual fine particle attainment demonstration SIP. In each case, SO2 was clearly found to be more potent than NOx in the formation of fine particles in the Southeast US. A number of model sensitivities were performed which confirmed this. It is unclear why EPA, having acknowledged this in the proposed rule, still assumed equal potency in the contribution analyses. While this may not be the case across the entire eastern U.S., it seems that the modeling analyses could have accounted for this, perhaps in post-processing the results.  [EPA-HQ-OAR-2009-0491-2616, p.3]
Georgia Department of Natural Resources, Air Protection Branch
Insignificance of NOx Emissions to Annual and Daily PM2.5 
EPA combined the modeled contributions of nitrate and sulfate from each state for the purpose of evaluating the interstate contributions to annual and daily PM2.5. The combined contribution from nitrate and sulfate were compared against specific threshold criteria (0.35 _g/m3 for daily PM2.5 and 0.15 _g/m3 for annual PM2.5). In order to justify annual state budgets for both SO2 and NOx, it should be demonstrated that SO2 and NOx individually are significant contributors. In some parts of the country (i.e., the Southeast U.S.), the contributions from SO2 are 10 to 100 times higher than the contribution from NOx. In these cases, there is no justification for setting annual NOx budgets based solely on the finding that SO2 is a significant contributor. Instead, SO2 and NOx need to be compared individually against the significance threshold criteria so that only the significant pollutants are targeted for controls. Also, it has been documented that controlling NOx year-round in the Southeastern U.S. vs. controlling NOx in the ozone season only may lead to HIGHER annual PM2.5 concentrations. [EPA-HQ-OAR-2009-0491-2647.1, p.3]
Based on an analysis of the nitrate source apportionment contributions presented by EPA in the Transport Rule Air Quality Modeling Technical Support Document, Georgia EPD believes that Georgia NOx emissions do not significantly contribute to daily PM2.5 or annual PM2.5 in nonattainment and maintenance areas outside Georgia. Therefore, only ozone season NOx budgets (not annual NOx budgets) should be developed for the states in the Southeastern U.S. [EPA-HQ-OAR-2009-0491-2647.1, p.3]
Georgia EPD analyzed the impact from the combination of NOx and SO2 (EPA approach) as well as NOx and SO2 individually on nonattainment and maintenance areas outside Georgia. EPA identified 147 monitors with a 2012 maximum projected design value above the current daily PM2.5 NAAQS of 35 _g/m3. Of those 147 monitors, the maximum impact from Georgia NOx was 0.0364 _g/m3, which is approximately 0.1% of the NAAQS. The EPA approach combined the impacts of SO2 and NOx and compared the combined impacts to 1% of the NAAQS (0.35 _g/m3). If the combined impacts were above 0.35 _g/m3, the upwind state was linked to the downwind monitor and targeted for emission reductions. This approach results in 18 monitors being linked with emissions in Georgia (see Table 1). It should be noted that the majority of the impacts are coming from SO2 (sulfate) and less than 10% of the total impacts are coming from NOx (nitrate). [[See Docket Number EPA-HQ-OAR-2009-0491-2647.1, p.4 for Table 1]] [EPA-HQ-OAR-2009-0491-2647.1, p.3]
EPA identified 50 monitors with a 2012 maximum projected design value above the current annual PM2.5 NAAQS of 15 _g/m3. Of those 50 monitors, the maximum impact from Georgia NOx (not including impacts on Georgia monitors) was 0.0159 _g/m3, which is approximately 0.1% of the NAAQS. The EPA approach combined the impacts of SO2 and NOx and compared the combined impacts to 1% of the NAAQS (0.15 _g/m3). If the combined impacts were above 0.15 _g/m3, the upwind state was linked to the downwind monitor and targeted for emission reductions. This approach results in 8 monitors (not including Georgia monitors) being linked with emissions in Georgia (see Table 2). It should be noted that the majority of the impacts are coming from SO2 (sulfate) and less than 4% of the total impacts are coming from NOx (nitrate). [[See Docket Number EPA-HQ-OAR-2009-0491-2647.1, p.4 for Table 2]]. [EPA-HQ-OAR-2009-0491-2647.1, p.4]
This analysis clearly demonstrates that the impacts of Georgia NOx emissions individually on daily and annual PM2.5 in neighboring nonattainment and maintenance areas is insignificant and annual NOx emissions budgets are not justified. [EPA-HQ-OAR-2009-0491-2647.1, p.5]
[[The above comments can also be found in Section IV.D.4.b.]]
[The following comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.92-93.]
The Transport Rule air quality modeling technical support document talks about the state-by-state contribution assessment using PSAT source apportionment for SO2, NOx and direct PM 2.5. EPA combined the contributions of nitrate and sulfate in calculating the net contributions of PM 2.5 for the purpose of evaluating the interstate contributions against specific threshold criteria. In order to justify the annual state caps on both SO2 and NOx, it should be demonstrated that SO2 and NOx individually are significant contributors.
Southern Company
B. EPA Should Not Regulate Annual NOx Emissions from Southern States
EPA should exclude NOx emissions from the annual program, at least for Southeastern states for a number of reasons:
:: It is well known that particulate nitrate represents an exceedingly small fraction (~5%) of PM2.5 in the Southeastern US PM mass and speciation data collected at the SEARCH ambient monitoring sites over the last ten years illustrates the composition of PM-2.5 across Georgia, Florida, Alabama and Mississippi and confirm the findings of other studies (see figure XII-3 below). [See EPA-HQ-OAR-2009-0491-2864.1, p. 46 for the Figure]  [EPA-HQ-OAR-2009-0491-2864.1, p. 45]
:: Several studies have documented that changes in particulate nitrate in the Southeastern US are limited by available ammonia (e.g., Blanchard and Hidy, ISSN 1047-3289 J. Air & Waste Manage. Assoc. 53:283-290; Blanchard et. AI, ISSN:1047-3289 J. Air & Waste Manage. Assoc. 57:1337-1350), Much of the ammonia required to convert NOx reaction products to ammonium nitrate (PM2.5) is taken up by S02 and sulfates in the atmosphere, effectively limiting the role of NOx and nitrates in the formation of PM2.5 in the Southeast. Thus the response of ambient PM2.5 levels to NOx reductions is very limited (<< ~0.51ug/m3 even in the face of large S02 reductions.
:: EPA's own results from the modeling supporting the Transport Rule show exceedingly small benefits from NOx reductions (in stark contrast to EPA's assertion that 'these [southeastern] states can impact downwind states in cooler climates,' not only in the Southeast but also in terms of contributions to monitors in the north, from NOx emissions from Southeast states. The state contributions to downwind monitors calculated from the CAMx source apportionment modeling were provided in the technical information posted on EPA's website. Below is table XIII-3 [See EPA-HQ-OAR-2009-0491-2864.1, p. 47 for the Table] summarizing the maximum base case contributions to projected downwind nonattainment and maintenance monitors. Maximum values are shown for all downwind nonattainment and maintenance monitors and for only those to which each state is linked. For the linked monitors, the table also shows the nitrate fraction of total sulfate-plus-nitrate from anthropogenic sources, and the maximum nitrate contribution relative to the respective annual and 24-hr PM2.5 standards. The maximum statewide contribution from nitrate to any downwind nonattainment or maintenance monitor is 0.0193 Ilg/m3 from Alabama for the annual standard and 0.0364 ug/m3 from Georgia for the 24-hr standard. The maximum statewide contribution to a linked downwind nonattainment or maintenance monitor is 0.0193 ug/m3 (0.13% of the standard) from Alabama for the annual standard and 0.0332 ug/m3 (0.10% of the standard) from Georgia for the 24-hr standard. The maximum contributions from nitrate to linked monitors for these four states is approximately one tenth or less of the significant contribution threshold, and is generally much less than one tenth of the total sulfate-plus-nitrate contribution. Thus, statewide reductions in sulfate will be at least ten times more effective at eliminating downwind contributions than the same relative nitrate reductions. [EPA-HQ-OAR-2009-0491-2864.1, pp. 45-47]
C. EPA Should Not Regulate Annual NOx Emissions from Northern States for PM2.5
Although particulate nitrate can be an important fraction of PM2.5 during the winter in the northern states, EPA should not have included it in its remedy for several reasons:
:: EPA chose not to include ammonia emissions in this transport rule. The formation of particulate nitrate is an inherently non-linear process, is strongly thermodynamically driven, and is strongly associated with available ammonia. In fact, particulate nitrate is often driven by available ammonia, regardless of available nitric acid. Several studies have shown the effectiveness of ammonia emissions reductions over NOx reductions in reducing particulate nitrate in the Midwest. By excluding ammonia from consideration, EPA could not properly assess the role of NOx versus ammonia, especially using the linear assumptions in AQAT.
:: As demonstrated above, NOx reductions provide little additional benefits if S02 controls are applied first.
:: As stated above, lower NOx can increase SOA production thus there is a potential NOx disbenefit that EPAs methodology is incapable of assessing.
For all the reasons described above, EPA should not include NOx in the remedy for PM2.5. [EPA-HQ-OAR-2009-0491-2864.1, pp. 47-48]
Response: 
See preamble section V.A for discussion of the issue of southern states' NOx contributions to PM2.5.  EPA's response and analysis of this issue is presented in preamble section V.A. and the Technical Paper entitled "Technical Analyses in Support of the Need for Annual NOx Controls in the Final Transport Rule."
Organization: State of Missouri Department of Natural Resources
Comment: 
State of Missouri Department of Natural Resources
Missouri concurs with the pollutants used for identifying states to be included under the proposed rule. [EPA-HQ-OAR-2009-0491-3806, p.4]
Response: 
EPA appreciates the statement of support for the approach taken in the rule.

IV.B.2. Choice of Air Quality Thresholds (1% of Relevant NAAQS) and Rounding Convention

Organization: First Energy
Comment: 
First Energy
Further, EPA's approach for establishing significant contribution is flawed since there is a large discontinuity between the steps linking an upwind state to a downwind nonattainment area (1% test). Jumping directly from the test to using controllable emissions (via IPM-based cost curves) as the method to define and quantify significant contribution does not properly address the impact of these upwind sources on non-attainment. EPA should use source-apportionment as a second step in defining 'significant' contribution (use a percent-threshold -- upwind source vs. local sources contribution -- quantified via source apportionment to determine if the state significantly contributes to downwind nonattainment). [EPA-HQ-OAR-2009-0491-2657.1, p.3; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.3 10/15/2010]
Also EPA's simplified 'AQAT' test is based on linear assumptions which contradict the highly non-linear nature of meterology and chemestry in the atmosphere. [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.3]
FE requests additional information regarding the 1% "Significant Contribution" designation for upwind states impacting ambient air monitoring sites as an acceptable method for assigning and controlling upwind impacts. [EPA-HQ-OAR-2009-0491-2657.1,p.3]
Response: 
See discussion of EPA's choice of air quality thresholds in the final TR preamble section V.D.1.  EPA disagrees with the characterization that the 1 percent threshold defines a states "significant contribution."   See detailed discussion in the preamble on EPA's approach to quantifying each states' significant contribution. 
Organization: Utility Air Regulatory Group (UARG)
Southern Company
State of Connecticut
Arkansas Department of Environmental Quality
North Carolina Department of Environment and Natural Resources
Tennessee Valley Authority (TVA)
Maryland Department of Environment (MDE)
Council of Industrial Boiler Owners (CIBO)
State of Ohio Environmental Protection Agency (Ohio EPA)
State of Wisconsin, Department of Natural Resources
Pennsylvania Department of Environmental Protection
Clean Air Task Force
Texas Commission on Environmental Quality
West Virginia Department of Environmental Protection
Tennessee Department of Environment and Conservation, Division of Air Pollution Control
State of Missouri Department of Natural Resources
Exelon
South Carolina Department of Health and Environmental Control 
Ameren Services Company
Florida Municipal Electric Association (FMEA)
Minnesota Power 
Nebraska Public Power District
Sunbury Generation LP
Omaha Public Power District
ARIPPA
Entergy Services, Inc.
Sierra Club
Louisiana Chemical Association (LCA)
George Washington University Regulatory Study Center
Gainesville Regional Utilities (GRU)
Northeast States for Coordinated Air Use Management (NESCAUM)
Exxon Mobil Corporation
Comment: 
Ameren Services Company
Air quality significance levels used in determining a states contribution are unrealistically low and not within model precision/accuracy
EPA is using 1% of the applicable air quality standard as the significance threshold in its determination of whether a state significantly contributes to nonattainment or maintenance areas downwind of the state. That is for the 8 hour ozone standard EPA assumes that contributions of 0.8 ppb and larger constitute a significant downwind impact for a state. Like wise for annual and 24-hour PM25 EPA assumes impacts 0.15 ugm-3 and 0.35 ugm-3, respectively are significant. [EPA-HQ-OAR-2009-0491-2722.1, pp.24-25; for additional comments pertaining to Air quality significance levels used in determining a states contribution are unrealistically low and not within model precision/accuracy, see pp.24-26 of this comment summary] 
EPA should reevaluate its selection of the significance contribution levels and raise them to a level where regional air quality models can exhibit skill in predicting contributions. EPA should attempt to quantify the skill level of these regional air quality models. We would suggest that EPA consider ranges from 5 to 10 percent of the ambient standards as a starting point for this evaluation. [EPA-HQ-OAR-2009-0491-2722.1, p.26]
 
ARIPPA
Specifically, for purposes of determining which states significantly contribute to or interfere with maintenance of the NAAQS for PM2.5 or ozone in other states, EPA applies a threshold of 1% of the NAAQS. See 75 Fed. Reg. 45237. EPA attempts to justify the use of this extremely stringent threshold value by pointing to a finding of an "upwind `collective contribution' that is important to both PM2.5 and ozone", and "adverse health impacts associated with ambient PM2.5 and ozone even at low levels." Id. EPA then uses suspect modeling to translate this 1% threshold determination into an allowable emissions budget for each state. [EPA-HQ-OAR-2009-0491-2794.1, p.14]
EPA identifies no regulatory or statutory basis for determining that a projected impact of 1% of the relevant NAAQS qualifies as a "significant contribution" for purposes of Section 110 or Section 126 of the statute. Instead, EPA's determination is arbitrary and capricious, and substantially overstates the significance of the contribution from certain upwind states, including Pennsylvania. [EPA-HQ-OAR-2009-0491-2794.1, p.15]
For these reasons, EPA's reliance on a 1% threshold for determining significant contribution to or interference with maintenance of the NAAQS, and, in turn, the use of such threshold for determining a state's allowable emissions budget, is arbitrary, capricious, unsupported by the relevant provisions of the CAA, and inconsistent with the D.C. Circuit's findings in North Carolina. The use of this threshold effectively overstates the significance of contribution from upwind states, resulting in unwarranted requirements for emissions control from these areas. [EPA-HQ-OAR-2009-0491-2794.1, p.15]
Arkansas Department of Environmental Quality
Prior to this proposal, the lowest value used as a threshold indicating a significant contribution to downwind ozone was two parts per billion ('ppb'). EPA proposes to use modeled concentrations exceeding 1 % of the standard (in this instance, 0.8 ppb) as an indicator of significant contribution and proposes to use this same metric for future changes in the standard. In the proposed Transport Rule, EPA has not provided any technical justification for lowering the contribution threshold from two ppb to 0.8 ppb. The proposed contribution threshold is lower than the ability of current Federal Reference Method monitors to measure with precision and accuracy (approximately 1 ppb), and it is lower than regional-scale photochemical oxidant modeling can reliably predict. The contribution threshold should not be lowered to a level that can neither be monitored nor reliably modeled. Since EPA has not provided an explanation of how the lower threshold was determined to be appropriate, EPA should continue to use a two ppb contribution threshold for ozone. [EPA-HQ-OAR-2009-0491-2676.2 p.3-4]
Clean Air Task Force
Furthermore, power plants in five states that are in EPA's 37 state study region but outside of the proposed control region are projected to increase emissions following implementation of the rule, as they will be subject only to the much weaker Title IV acid rain restrictions. In fact, the increase in Texas is large enough to cause it to become a significant contributor (under the Agency's proposed 1% NAAQS threshold test) to downwind PM nonattainment and maintenance problems. [EPA-HQ-OAR-2009-0491-2738.1, p.7; this comment can also be found at III.D and IV.D.4.c of this comment summary.]
Finally, while we appreciate the simplicity of EPA's choice of a threshold for determining significant contribution for a state at 1% of the applicable NAAQS, we think that this level is too high. Rather, we think that any measurable level of contribution that can be eliminated cost-effectively is significant for purposes of section 110(a)(2)(D) of the Act. We suggest that, at a minimum, EPA should cut its proposed contribution threshold in half, i.e., to no more than 0.5% of the applicable NAAQS. Applying such a minimum threshold would bring Texas, Arkansas, New Hampshire, North Dakota and Oklahoma into the control region for SO2 and annual NOx purposes, and Massachusetts and Missouri into the control region for ozone season NOx purposes. 36 [EPA-HQ-OAR-2009-0491-2738.1, p.8]
Footnote:
36 See discussion infra in Section IV.A. We note that although we believe that our recommended lower threshold for determining significant contribution will require additional states to be included in the TR control regions, we have included only Texas emissions in our recommended emissions caps and the Alternate Control Scenario described in Section V infra. 
Council of Industrial Boiler Owners (CIBO)
EPA defines as "significant" any State emissions that are greater than 1% of the relevant NAAQS: 'States whose contributions to any downwind sites are greater than 1 percent of the relevant NAAQS are considered "linked" to those sites for the purpose of the second step in the analysis.' 75 FR 45233/2. EPA's definition of 1% as significant is arbitrary and has no defensible basis. If 1% of 100 is significant, how does EPA define "insignificant?" Statistical error is much higher than that, and rounding in analysis can easily equal amounts of 1% or more. [EPA-HQ-OAR-2009-0491-2751.1 p.4]
Entergy Services, Inc.
2.  The Projected Impact from Louisiana Emissions Is Less than a PSD Significant Impact Level
Entergy adopts comment I.D made by the Louisiana Chemical Association.  Entergy believes that EPA cannot set the level for "interference with maintenance" of a NAAQS lower than the EPA Significant Impact Level ("SIL") used under the Prevention of Significant Deterioration ("PSD") program.  Entergy intends this as a general comment on EPA's proposed methodology for determining when there is "interference with maintenance" within the meaning of CAA and as a specific comment with respect to the projected impact of Louisiana emissions on Harris County, Texas.  [EPA-HQ-OAR-2009-0491-2847.1,pp.7-8]
As part of the analysis of air quality impacts to determine compliance with the NAAQS and increment, the permit applicant and reviewing authority may compare the source's impacts for a pollutant with the corresponding SIL for that pollutant to show that a cumulative air quality impacts analysis is not necessary.  [EPA-HQ-OAR-2009-0491-2847.1,p.8]
Harris County is within a Class II air quality control district. On September 21, 2007, EPA proposed the following options for a SIL for the PM2.5 Annual NAAQS for a Class II area:
Option 1    1.0 ug/m3
Option 2    0.8 ug/m3
Option 3    0.3 ug/m3
The EPA projected value for Louisiana impacts to the Clinton Drive monitor in Harris County is 0.34 ug/m3.  Such value is well below the Option 1 and 2 proposed SILs and does not exceed the Option 3 SIL, with standard rounding conventions. While EPA has not yet finalized the proposed SILs pursuant to the 2007 notice, it is our understanding that EPA has reached a final decision, that decision has been reviewed by the Office of Management and Budget, and that a final rule adopting one of these 3 values will be published in the Federal Register in October 2010. [EPA-HQ-OAR-2009-0491-2847.1, p.8]
In the September 21, 2007 Federal Register notice proposing SILs for the PM2.5 annual NAAQS, EPA provided the following explanation of the concept and appropriate usage of a SIL:
Significant Impact Levels or SILs are numeric values derived by EPA that may be used to evaluate the impact a proposed major source or modification may have on the NAAQS or PSD increment. The SILs currently appear in EPA's regulations in 40 CFR 51.165(b), which are the provisions that require States to operate a preconstruction review permit program for major stationary sources that wish to locate in an attainment or unclassifiable area but would cause or contribute to a violation of the NAAQS. The SILs in that regulation are the level of ambient impact that is considered to represent a "significant contribution" to nonattainment.   [EPA-HQ-OAR-2009-0491-2847.1,p.8]
Although 40 CFR 51.165 is the regulation that establishes the minimum requirements for nonattainment NSR programs in SIPs, the provisions of 40 CFR 51.165(b) are actually applicable to sources located in attainment and unclassifiable areas. See 40 CFR 51.165(b)(4). Where a PSD source located in such areas may have an impact on an adjacent non-attainment area, the PSD source must still demonstrate that it will not cause or contribute to a violation of the NAAQS in the adjacent area. This demonstration may be made by showing that the emissions from the PSD source alone are below the significant impact levels set forth in 40 CFR 51.165(b)(2). However, where emissions from a proposed PSD source or modification would have an ambient impact in a non-attainment area that would exceed the SILs, the source is considered to cause or contribute to a violation of the NAAQS and may not be issued a PSD permit without obtaining emissions reductions to compensate for its impact. 40 CFR 51.165(b)(2)-(3).  [EPA-HQ-OAR-2009-0491-2847.1,p.8] 
The EPA has also applied SILs in other analogous circumstances under the PSD program. Based on EPA interpretations and guidance, SILs have also been widely used in the PSD program as a screening tool for determining when a new major source or major modification that wishes to locate in an attainment or unclassifiable area must conduct a more extensive air quality analysis to demonstrate that it will not cause or contribute to a violation of the NAAQS or PSD increment in the attainment or unclassifiable area. [EPA-HQ-OAR-2009-0491-2847.1 ,p.9]
***
Subsequently, in draft guidance for permit writers, EPA advised that SILs may be used to determine whether a source needs to conduct a cumulative or "full" impact analysis to demonstrate that in conjunction with all other increment consuming sources, it will not cause or contribute to violation of the NAAQS or PSD increment in an attainment or unclassifiable areas. New Source Review Workshop Manual, at C.24-C.25 (Draft 1990); See also 40 CFR 51.166(k); 40 CFR 52.21(k). Permitting authorities followed this guidance, and this approach remains an accepted aspect of PSD program implementation. If based on a preliminary impact analysis, a source can show that its emissions alone will not increase ambient concentrations by more than the SILs, EPA considers this to be a sufficient demonstration that a source will not cause or contribute to a violation of the NAAQS or increment.  [EPA-HQ-OAR-2009-0491-2847.1, p.9]
***
The concept of a significant impact level is grounded on the de minimis principles described by the court in Alabama Power Co. v. Costle, 636 F.2d 323, 360 (D.C. Cir. 1980). In this case reviewing EPA's 1978 PSD regulations, the court recognized that "there is likely a basis for an implication of de minimis authority to provide exemption when the burdens of regulation yield a gain of trivial or no value." 636 F.2d at 360.  [EPA-HQ-OAR-2009-0491-2847.1,p.9]
***
Similarly, significant impact levels are intended to identify a level of ambient impact on air quality concentrations that EPA regards as de minimis. The EPA considers a source whose individual impact falls below a SIL to have a de minimis impact on air quality concentrations. Thus, a source that demonstrates its impact does not exceed a SIL at the relevant location is not required to conduct more extensive air quality analysis or modeling to demonstrate that its emissions, in combination with the emissions of other sources in the vicinity, will not cause or contribute to a violation of the NAAQS at that location. [EPA-HQ-OAR-2009-0491-2847.1,p.9]
In other words, if a single point source within the Houston area had a project that triggers PSD for PM2.5, but the screening modeling indicates that the projected air quality impact for that project is below the SIL, in this case, at or below the level of one of EPA's proposed three options 1.0, 0.8 or 0.3 ug/m3, then that source would not be considered to have only a de minimis impact on air quality and would not be required to conduct modeling to demonstrate that its emissions, in combination with those of other sources, will not contribute to a NAAQS violation. If a single point source has emissions that are considered de minimis when at or below a SIL, then it would be arbitrary and capricious to require any regulation, let alone widespread controls on sources in another state, such as Louisiana, that cumulatively have an equivalent or lesser impact than would such individual source.  [EPA-HQ-OAR-2009-0491-2847.1,p.9]
For this reason, EPA should reverse its proposed finding that Louisiana emissions are likely to interfere with maintenance of the annual PM2.5 NAAQS in Harris Co., Texas. [EPA-HQ-OAR-2009-0491-2847.1, p.10]  
Exelon
THE TRANSPORT RULE PROVIDES A TEMPLATE FOR FUTURE REDUCTIONS TO STATE NOX AND SO2 BUDGETS THAT MAY BECOME NECESSARY TO PREVENT INTERFERENCE WITH MAINTENANCE AND ATTAINMENT OF NEW OR REVISED NAAQS IN THE FUTURE.
On January 19, 2010, EPA issued a notice of proposed rulemaking announcing its intent to strengthen the NAAQS for ozone. The proposed levels for the revised ozone standard are expected to be within the range of 0.060 to 0.070 parts per million ("ppm") ozone as an eight hour average, as compared to the current level of 0.080 ppm. EPA should readily be able to utilize the mechanisms and models that it has used in developing the proposed Transport Rule's state budgets for NOX to develop reduced state and unit budgets necessary to meet the new ozone standard. By setting a single bright line threshold for ozone at exactly 1% of the 1997 eight-hour ozone standard of 0.08 ppm, EPA is allowing for an easy adjustment to any future standard reductions below the current 0.08 ppm. As discussed in Comment 7 below, Exelon suggests that EPA promptly calculate the reduced budgets and either use the 2008 standard as a basis for the budget in the proposed Transport Rule or propose revised state budgets and unit budgets within a time frame that will allow companies to take account of this requirement in their planning. [EPA-HQ-OAR-2009-0491-2666.1, pp.12-13]
In October 2011, EPA is also planning to review, and possibly to modify, the PM2.5 NAAQS, and the methodology used in the proposed Transport Rule should allow EPA to propose reduced state emission budgets at the time of any NAAQS revision. As with ozone, EPA can utilize the threshold impact value at 1% of the NAAQS and utilize its existing data and models to adjust state budgets. Again, EPA should promulgate revised budgets within a time frame that will allow companies to take account of the upcoming requirements in their capital planning and market positioning. The benefits that will be achieved by implementation of the Transport Rule will far outweigh the costs. [EPA-HQ-OAR-2009-0491-2666.1, p.13]
Exxon Mobil Corporation
1. Any impact of Louisiana emissions on Harris County, Texas is less than any of the proposed EPA Significant Impact Levels ('SILs') for annual PM2.5 used under the Prevention of Significant Deterioration ('PSD') Program.5 By definition, any such impacts are de minimis. EPA would be arbitrary and capricious and/or abusing its discretion if it makes a finding of ''interference with maintenance' for a total projected Louisiana contribution that is less than one of these proposed SILs.  [EPA-HQ-OAR-2009-0491-2841.1,p.3]
4. Due to the inherent uncertainty in the IPM modeling, as unmistakably illustrated by the material differences between IPM v. 3.02 and v. 4.10 projections, a projected impact of less than 2 ppb based on modeling should never be used as a level indicating 'significant contribution' or 'interference with maintenance' from an upwind state to a downwind state under the ''good neighbor' provisions of the Clean Air Act, 42 U.S.C. 7410(a)(2)(D). The projected impact from Louisiana is well below 1 ppb. At most, the IPM should be used as a screening tool for making presumptions for 'significant contribution' or 'interference with maintenance' determinations. However, such presumptions should be always subject to a reasonable opportunity for rebuttal by empirical evidence. [EPA-HQ-OAR-2009-0491-2841.1, p.5]

Footnote 5: EPA proposed three options for an annual PM2.5 SIL for Class II areas, such as Harris Co., Texas, in 72 Fed.Reg. 54112, Sept. 21,2007. These options were 1.0 ug/m3, 0.8 ug/m3, and 0.3 ug/m3. With rounding conventions, the 0.34 ug/m3 projected as the Louisiana impact on Harris Co., Texas does not exceed any of these SILs. It is EM's understanding that the final SILs will be published in the Federal Register in October 2010 and thus, will be fmal prior to EPA's final decision on the proposed TR/FIP. [EPA-HQ-OAR-2009-0491-2841.1,p.3]
Florida Municipal Electric Association (FMEA)
Changing the criteria for determining a significant impact is not warranted: The DC District Court upheld the EPA methodology under CAIR for determining a significant impact due to the interstate transport of air pollutants. By lowering the significance threshold for upwind state impact on downwind states, EPA is expanding the number of states regulated under the transport rule beyond that of CAIR. This expansion was not required by the Court. By defining the significance level at 1% of the NAAQS as opposed to retaining the levels in the CAIR, EPA has established a criterion that will continually reduce the significance level without any future consideration of whether each decrease is justified. In the case of PM 2.5, this new method of determining significance lowered the CAIR threshold of 0.2 ug/m3 to 0.15 ug/m3, which is a 25% reduction. As currently proposed, EPA will create a continual series of Transport Rules in response to future NAAQS revisions starting in 2011. This will likely create a permanent Federal Implementation Planning (FIP) of the states and derailing Congressional intent on how the SIP program was designed to work under the Clean Air Act. [EPA-HQ-OAR-2009-0491-2731.1, p. 2]
Gainesville Regional Utilities (GRU)
Changing the Criteria for Determining a Significant Impact is Not Warranted
The DC District Court upheld the EPA methodology under CAIR for determining a significant impact due to the interstate transport of air pollutants. By lowering the significance threshold for upwind state impact on downwind states, EPA is expanding the number of states regulated under the proposed CATR beyond that of CAIR. This expansion was not required by the Court. By defining the significance level at 1% of the NAAQS as opposed to retaining the levels used in the CAIR, EPA has established a criterion that will continually reduce the significance level without any future consideration of whether each decrease is justified. In the case of PM2.5, this new method of determining significance lowered the CAIR threshold of 0.2 ug/m3 to 0.15 ug/m3, which is a 25% reduction. As currently proposed, EPA will create a continual series of 'Transport Rules' in response to future NAAQS revisions starting in 2011. This will likely create a permanent 'FIPing' of the states and derailing Congressional intent on how the SIP program was designed to work under the CAA. [EPA-HQ-OAR-2009-0491-2674.1, p.4]
George Washington University Regulatory Study Center
To identify eastern States whose contributions do not warrant transport requirements, EPA is proposing thresholds based on one percent of the NAAQS for ozone and PM. For the fine PM NAAQS, the contribution thresholds of 0.15 μg/m3 and 0.35 μg/m3 requires a high level of precision for the modeling approach used to determine significant contribution. This superficially technical detail has major implications -- whether states are included in the Rule or not depends on modeled differences as small as 0.001 μg/m3. [EPA-HQ-OAR-2009-0491-2573.1, p.19]
A. Defining Contribution and Interference in the Transport Rule
EPA proposes a two-step-process for determining that an upwind state makes a significant contribution to nonattainment or interferes with maintenance of attainment with NAAQS at downwind sites. In the first step, EPA uses air quality modeling to quantify the contribution of an upwind state to non-attainment and/or interference with maintenance at downwind sites. EPA proposes to find that states with a contribution greater than one percent of the relevant NAAQS are considered "linked" for purposes of the second step in making the determination. For the fine PM NAAQS, the relevant thresholds are a contribution of 0.15 μg/m3 of fine PM for the annual standard and a contribution of 0.35 μg/m3 for the 24-hour standard. In the second step, EPA identifies the SO2 and NOx emissions constituting a significant contribution and significant interference for each state identified as exceeding the thresholds in the first step. [EPA-HQ-OAR-2009-0491-2573.1, p.19]
In doing so, EPA adopts two alternative "maximum cost thresholds" -- cost thresholds reflecting alternative control levels and air quality considerations. EPA divides the significantly contributing/ interfering states into two groups. The first group consists of those states whose significant contribution can be eliminated at the lower cost threshold (essentially the cost of assuring the continued operation of installed control equipment). The second group consists of the remaining states: those that continue to contribute to (or interfere with) nonattainment even after region-wide control at the lower cost threshold. States in this second group are required to achieve additional reductions commensurate with control of SO2 at the higher cost threshold (i.e., the incremental cost at which EPA believes large additional reductions will occur with the widespread installation of additional scrubber control technology). [EPA-HQ-OAR-2009-0491-2573.1, p.19]
B. Measuring Contribution and Interference
Our focus in this discussion is on the first step and EPA's proposed selection of fine PM NAAQS thresholds of 0.15 μg/m3 for the annual standard and 0.35 μg/m3 for the 24-hour standard. In order to implement the first step in the significant contribution determination, EPA projects the emission levels for each state in 2012 and, using air quality modeling, estimates the ambient impact of these projected emissions on downwind nonattainment and maintenance receptors. States with an incremental contribution above the threshold are subject to the proposed Transport Rule. See Tables IV.C-13 and IV.C-16 in the proposal preamble for EPA's estimates of the largest incremental contribution to non-attainment for the PM NAAQS in each of the eastern States. [EPA-HQ-OAR-2009-0491-2573.1, p.20]
The adoption of a contribution threshold representing one percent of the annual fine PM standard -- i.e., 0.15 μg/m3 -- raises a question about the precision required (or at least implied) in using two figures to the right of the decimal. EPA first dealt with the issue in CAIR, where it proposed a threshold of 0.15 μg/m3. In the final CAIR rule, EPA agreed in response to comments with respect to the precision implied by a two-decimal-place threshold, "...that specification of a threshold value of 0.15 μg/m3 does suggest an overly precise test that might need to take into account modeled differences in PM2.5 values as low as 0.001 μg/m3." As a result, EPA adopted a single-digit value of 0.2 μg/m3 because it was consistent with EPA monitoring requirements in CFR Part 50, appendix N, section 4.3 stating that design values should be rounded to the nearest 0.1 μg/m3. This rationale, then, served as the basis for the fine PM thresholds for determining significant contribution in the 2005 CAIR rule.39
However, in this proposal, EPA argues the revised 24-hour fine PM NAAQS in 2006 of 35 μg/m3 raises a new difficulty. The rounding approach used in Appendix N for the 24-hour fine PM NAAQS (design values are to be rounded to the nearest 1 μg/m3) would yield a threshold of zero -- one percent of 35 μg/m3 is 0.35 μg/m3 which would round to zero. EPA believes that a threshold of zero would be counterintuitive and unworkable. Thus, EPA is proposing to decouple the precision of the air quality thresholds from its monitoring rules and instead to use 2-digit values representing one percent of the fine PM NAAQS. [EPA-HQ-OAR-2009-0491-2573.1, pp.20-21]
EPA does not provide any analysis to support the proposed approach of adopting contribution thresholds of 0.15 μg/m3 for the annual NAAQS and 0.35 μg/m3 for the 24-hour NAAQS. In particular, it does not provide analysis to show that its methodology will provide the precision necessary to support two-figure accuracy (two digits beyond the decimal place) in its estimates of the contribution by upwind states to the nonattainment or interference with maintenance at specific sites in downwind states. In particular, note that with the proposed thresholds of 0.15 μg/m3 for the annual NAAQS and 0.35 μg/m3 for the 24-hour NAAQS, EPA is attributing a greater precision to its modeling data than it provides for in its monitoring requirements.41 [EPA-HQ-OAR-2009-0491-2573.1, p.21]
Adoption of alternative single digit thresholds could have a significant effect on the number of states covered by the Transport Rule (see Table 1). With contribute/interfere thresholds of 0.2 ug/m3 for the annual NAAQS and 1 μg/m3 for the 24-hour NAAQS, for example, six states would no longer be covered by the Transport Rule.52 Given the uncertainty associated with its analysis, however, EPA may only be able to justify a threshold on the order of 1 μg/m3 for both the annual and 24-hour fine PM standards. With contribution/interfere thresholds of 1 μg/m3 for both the annual and 24-hour fine PM NAAQS, an additional 6 states, for a total of 12 states, would no longer be covered by the Transport Rule. [EPA-HQ-OAR-2009-0491-2573.1,p.24]
Since it is unclear whether the level of precision specified by the proposed contribution thresholds is appropriate and since that level has such important implications for states, the agency risks litigation by states or regulated entities that believe they should not be included in the rule. Litigation by state plaintiffs resulted in the DC Circuit's rejection of CAIR, and would be costly even if the EPA were to prevail. The agency could relatively easily and cheaply avoid or limit such litigation now by carefully studying and explaining its decisions regarding levels of precision. [EPA-HQ-OAR-2009-0491-2573.1,pp.24-25]
Second, we recommend that EPA undertake an expert elicitation study -- using independent experts -- to determine the appropriate level of precision for its thresholds for determining significant contribution and interference with maintenance in neighboring states. Doing so will ensure that the EPA has made rational and defensible decisions about how to determine the states covered by the Transport Rule. [EPA-HQ-OAR-2009-0491-2573.1, p.32]

 39 CAIR only used a contribution threshold for the annual fine PM standard in determining the States that were contributing significantly to non-attainment of the annual fine PM NAAQS in the downwind areas of neighboring States. At that time the 24-hour NAAQS for fine PM was 0.65 ug/m3. With this standard, EPA reported that that there were no non-attainment areas for the 24-hour NAAQS in Eastern areas of the U.S. Therefore, non-attainment of the annual NAAQS was the appropriate evaluative measure. 70 FR 25189.
41 Appendix N also includes as a part of the data handling provisions the following data reporting requirement: "The computed 24-hour average PM2.5 concentrations shall be reported to one decimal place (the additional digits to the right of the first decimal place are truncated), consistent with the data handling procedures for the reported data." (71 FR 61228.) Thus, a computed 24-hour average fine PM concentration of 0.35 ug/m3 would be reported as 0.4 ug/m3 under this provision of Appendix N. With the proposed thresholds of 0.15 ug/m3 for the annual NAAQS and 0.35 ug/m3 for the 24-hour NAAQS, EPA is attributing a greater precision to its modeling data than it provides for in its monitoring requirements. One possible approach for EPA is to use this rationale as the basis for adopting a 24-hour threshold of 0.4 μg/m3.
52 In addition, Texas would likely be below an annual contribution threshold of 0.2 ug/m3 threshold even with the substantial increase in SO2 emissions EPA projects for Texas under the proposed Transport rule. EPA requests comments in the proposal on the possibility of including Texas in the final Transport rule because the projected increase in SO2 emissions would result in a contribution that exceeds the proposed annual NAAQS threshold of 0.15 ug/m3. 75 FR 45284.
Louisiana Chemical Association (LCA)
The Projected Impact from Louisiana Emissions Is Less than a PSD Significant Impact Level.
LCA believes that EPA cannot set the level for either "significant contribution" or "interference with maintenance" of a NAAQS lower than the EPA Significant Impact Level ("SIL") used under the Prevention of Significant Deterioration ("PSD") program. LCA intends this as a general comment on EPA's proposed methodology for determining when there is "significant contribution" or "interference with maintenance" within the meaning of CAA Section 110(a)(2)(D) and as a specific comment with respect to the projected impact of Louisiana emissions on Harris County, Texas. [EPA-HQ-OAR-2009-0491-3527.1, pp. 7-8; see pp. 8-10 for extensive discussion of this issue.]
EPA's Should Revise It's Proposed Methodology for Determining Significant Contribution and Interference With Maintenance. LCA believes that EPA's proposed methodology for determining "significant contribution" and "interference with maintenance" should never be more than a screening tool. The upwind state should always be provided with the ability to submit objective evidence that there is no interference with maintenance that counteracts the modeled assumptions. For example, in this case, the fact that exceptional event data has been removed from the design value upon which EPA premised its projected 2012 design value should be allowed to controvert a proposed finding of interference. Further, the finding of interference should not be contradictory to objective evidence that local controls have eliminated the reasonable potential for the design value to rise to the level that EPA has projected. [EPA-HQ-OAR-2009-0491-3527.1, p. 30]
Further, for the reasons stated above, strictly as a legal matter, the threshold for a finding of reasonable interference should never be established below the PSD Significant Impact Level. LCA suggests that even a SIL would be entirely too conservative a value to use for making a finding of significant contribution or a finding of interference with maintenance under the CAA "good neighbor" clause. If a single source in the area is not required to perform an air quality impact analysis under a PSD permit review due to projected emissions being below a SIL, then the threshold for inclusion of cumulative emissions from an upwind state should be much more significant to justify detailed air quality analysis by the upwind state and, potentially adoption of a control program under a SIP. [EPA-HQ-OAR-2009-0491-3527.1, p. 30]
In no case should a threshold for a finding of reasonable interference with maintenance be less than 2 ppb when based upon projected, modeled data that has a significant uncertainty factor. The level of uncertainty in the IPM and the myriad of assumptions that form the submodels that are used by the IPM is too great to base decisions for sweeping, costly controls on a projected impact of less than 2 parts per billion of any pollutant. Literally hundreds of data points, some measured and some estimated are used in the IPM. The models just do not have the degree of certainty that they should form the only basis for such decisions. This is clearly illustrated by a simple comparison of the 2012 Base Case values from IPM v.3.02 to those from IPM v. 4.10. As noted above, the difference in projected SO2 levels between those two base case predictions for Louisiana EGUs was more than 20,000 tpy  -  a 20% difference just in EGU projections. Any decision to require an upstate to adopt SIP provisions for an impact of less than 2 ppb on a downwind state should require supplementation with objective, empirical data demonstrating a clear linkage from the upwind sources to the downwind receptor. [EPA-HQ-OAR-2009-0491-3527.1, p. 30]
Other Factors Providing a "Safety Net" for a Determination That Louisiana Emissions Do Not Interfere With Maintenance of the Annual PM2.5 NAAQS in Texas
LCA believes that the comments above clearly demonstrate that Louisiana emissions do not and will not interfere with maintenance of the annual PM2.5 NAAQS in Harris Co., Texas. In addition to these comments, as safety-factors supporting this conclusion are several recently adopted and anticipated regulations that EPA did not consider. [EPA-HQ-OAR-2009-0491-3527.1, p. 30; see pp. 31-32 for list of recently adopted and anticipated regulations.]
Maryland Department of Environment (MDE)
Significant Contribution and Interference with Maintenance
Maryland acknowledges that the current proposal including a strong assessment of significant contribution and interference with maintenance. Maryland supports the approach EPA used in quantifying significant contribution and interference with maintenance, and supports 1 percent of the NAAQS as an appropriate threshold for significant contribution for both the current proposed rule and any future rules to address transport pursuant to a future NAAQS. [EPA-HQ-OAR-2009-0491-2639.2, p.5]
The 1% significance threshold is consistent with the piecemeal nature of regional air pollution. The contribution modeling done for the Transport Rule confirms the fact that many small out-of-state contributions can add up to a big local ozone or PM2.5 problem. For Maryland, the average contribution per ozone monitor from Maryland itself is 26 ppb, but the sum of the average contribution of all other states in the modeling domain is 31 ppb. The top five states (Virginia, Pennsylvania, West Virginia, Ohio, and DC) contribute 21 of the 31 ppb while the remaining 10 ppb comes from 14 other states. The advantage of using a percentage of the NAAQS is that the threshold adjusts to the new standards. We believe the 1% threshold is a legitimate estimate of whether a contribution is considered "significant." [EPA-HQ-OAR-2009-0491-2639.2, p.5]
The approach in the proposed Transport Rule is an improvement to the absolute threshold of 2 ppb that EPA used previously in CAIR, because it sets a relative threshold as a function of the NAAQS for any pollutant. As long as the NAAQS remain unchanged, the threshold will remain constant. However, if the NAAQS are made more stringent, the threshold for the revised NAAQS will also become appropriately more stringent. [EPA-HQ-OAR-2009-0491-2639.2, pp.5-6]
The significance threshold should be amended to include "equal to" 1 percent. As previously noted, Maryland strongly agrees with EPA's definition of the significant contribution threshold as 1 percent of the NAAQS in the proposed Transport Rule. We further support the applicability of this definition for purposes of determining significant contribution in relation to any future NAAQS. However, we urge EPA to amend the definition in the proposed rule to also designate as "significantly contributing" those states whose significant contribution equals 1 percent of the NAAQS, in addition to those states whose contribution exceeds the 1 percent threshold. This is consistent with the recommendation made by the OTC and LADCO states in their letter dated September 2, 2009, to EPA on the replacement of CAIR (see Appendix D [See EPA-HQ-OAR-2009-0491-2639.2, p.35 for comments pertaining to Appendix D]). [EPA-HQ-OAR-2009-0491-2639.2, p.6]
EPA uses air quality modeling to quantify individual states' contributions to downwind nonattainment and maintenance sites (75 FR 45233). In the proposed rule, a state whose contributions to downwind sites are greater than 1 percent of the NAAQS are then considered "linked" to those downwind sites for purposes of further analyses. Our recommendation here is that a state whose contribution to any downwind site is "equal to or greater than" 1 percent of the NAAQS be included in the linkages. [EPA-HQ-OAR-2009-0491-2639.2, p.6]
Minnesota Power 
Minnesota Power (MP) has followed the EPA's release of the proposed Transport Rule with high interest for multiple reasons, including EPA's designation of the Transport Rule for impacting the status of the EPA Administrative Stay of the Clean Air Interstate Transport Rule (CAIR) in Minnesota.  In a 11/03/2009 Federal Register Notice, EPA acknowledged data error issues raised by the US DC Circuit Court of Appeals by establishing an Administrative Stay of CAIR and CAIR FIP implementation in Minnesota. Minnesota Power had provided EPA with modeling analysis prepared by Environ and Alpine Geophysics for Minnesota Power that reflected corrections in EPA's Minnesota emissions model inputs. The modeling analysis demonstrated that the Minnesota contribution to downwind nonattainment areas fell below EPA's CAIR significance level of 0.20 ug/m3 PM2.5 after correcting apparent errors in Minnesota source emissions. At the time, EPA was asserting that the Minnesota contribution to a downwind nonattainment area was right at the CAIR significance level, after application of EPA's truncation method.  The Minnesota Power CAIR analysis was indicating that the Minnesota signal was about 0.18 ug/m3 PM2.5 and that Minnesota should not be a CAIR affected state.   [EPA-HQ-OAR-2009-0491-2750.1, p.2]
Interestingly, EPA acknowledged in its Transport Rule discussion that their analysis now demonstrates the Minnesota contribution to downwind nonattainment is below the CAIR 0.20 ug/m3 PM2.5 significance level.  However, EPA proceeded to cite how Minnesota would be a Transport Rule, Group 2 affected State under a Transport Rule revision of EPA's significance level to 1% of the 15.0 ug/m3 annual average PM2.5 National Ambient Air Quality Standard (NAAQS) and by application of EPA's new cost effective control screening assessment.  EPA also cited reference to the new, 24 hour average PM2.5 standard that EPA had not considered under the 2005 CAIR.  Additionally, EPA indicated in the proposed Transport Rule its intention to revise the NAAQS for annual average PM2.5 to an undisclosed, prospectively more stringent value at a future time and that it was EPA's intent to continue to modify its standard for significant contribution to nonattainment or impediment to maintenance to a level that continues to represent 1% of any new PM2.5 annual NAAQS.  EPA proceeded in this proposed Transport Rule to inquire whether stakeholders considered it appropriate for Group 2 States (like Minnesota) to be designated as Group 1 Transport Rule states. EPA has noted that Group 1 States are subject to more stringent emissions reduction requirements. Group 1 States are more closely associated with States that currently contain PM2.5 standard nonattainment areas.  Group 1 States are described by EPA as having relatively lower cost per ton emission reduction costs than Group 2 States.   [EPA-HQ-OAR-2009-0491-2750.1, p.3]
In effect, EPA is indicating in the Proposed Transport Rule that, but for application of the more stringent measure of a significant contribution, Minnesota would have been excluded from the groups of Transport Rule affected states and that inclusion of Minnesota in the Transport Rule doesn't result in any additional Minnesota emission reductions to satisfy 2012 Group 2 Boiler budgets.  EPA's analysis affirms that Minnesota affected emission source owners and operators had a reasonable expectation that Minnesota would not be listed as an affected State in the Transport Rule, considering the Minnesota modeled contribution to PM2.5 nonattainment relative to EPA's 2005 CAIR significant contribution criteria.  This all begs the question of why EPA has chosen to place Minnesota in the Transport Rule at all and, if Minnesota is a Transport Rule affected State, why Minnesota should be expected to meet new SO2 and NOx Budget requirements only a year and a half after Minnesota learns that EPA is revising its significant contribution criteria in a manner that can draw Minnesota into the groups of Transport Rule affected States.  [EPA-HQ-OAR-2009-0491-2750.1, pp.4-5] 
Significance level changes, 2005 CAIR to proposed Transport Rule. EPA shifted the significance level to the more inclusive 0.15 ug/m3 for the Transport Rule, which becomes EPA's primary justification for now including Minnesota. EPA may make the criteria even tighter if it revises the PM2.5 NAAQS to below the annual average of 15 ug/m3. Yet, original comments Minnesota Power made in 2004 to EPA cited how a 0.15 ug/m3 significance level is not supported when compared to EPA's assessments of how well their modeling tools compare with actual ground level PM2.5 models used to determine nonattainment designations.  Air quality monitoring station limitations in discerning small changes in measured air quality separately from normal monitor measurement variability have not been demonstrated by EPA to have improved sufficiently to support such a large tightening of the Transport Rule significance level relative to the CAIR final rule significance level.   [EPA-HQ-OAR-2009-0491-2750.1, p.7]
Nebraska Public Power District
7) Setting Significance Thresholds. EPA has proposed extremely low levels of "significance" with respect to modeled impact contributions from upwind states, at 1% of the respective NAAQS for 24-hour PM2.5 (0.35 μg/m3), annual average PM2.5 (0.15 μg/m3), and 8-hour ozone (0.8 ppb). This means that some states, like Nebraska, with very minimal predicted contributions, will be targeted for controls that have a very high cost to benefit ratio. Instead of imposing cost inefficient controls (high $/μg/m3) on a state like Nebraska, it would make much more sense to spend similar levels of capital on more aggressive controls in states with predicted impact contributions that in some cases are estimated by EPA to be more than an order of magnitude higher than for Nebraska (see Table IV.C-16 of preamble). [EPA-HQ-OAR-2009-0491-2711.1, p.7]
12) Rounding Conventions. EPA's current TR proposal would alter past rounding conventions for annual and 24-hour PM2.5 inconsistently. On the one hand, for annual PM2.5, EPA proposes to deviate from the design value reporting requirement by only one decimal place -- rounding to the nearest 0.01 μg/m3 rather than the nearest 0.1 μg/m3 as it did under CAIR consistent with EPA monitoring requirements. In contrast, EPA proposes a two decimal place deviation from past practice for 24-hour PM2.5 -- rounding to the nearest 0.01 μg/m3 rather than the nearest whole μg/m3. In justifying its proposal, EPA lays out a false choice between adopting the CAIR approach, which would "yield air quality threshold of zero" and selecting a uniform 2 digit rounding convention for annual 24-hour PM2.5. We recommend that EPA use a rounding convention consistently with its earlier rule proposal for modeling of PM2.5 for demonstrating NAAQS compliance (see above comment), specifying the significance level to one decimal place. We believe this alternative rounding convention is a more defensible metric in setting an air quality threshold for assessing the significance of interstate contributions to downwind nonattainment. [EPA-HQ-OAR-2009-0491-2711.1, pp.8-9]
North Carolina Department of Environment and Natural Resources
The NCDAQ supports the 1% threshold and encourages EPA to be consistent in the rounding truncation conventions for all pollutants. [EPA-HQ-OAR-2009-0491-2767.1 p.6]
Northeast States for Coordinated Air Use Management (NESCAUM)
We support EPA's proposal to adopt 1% of a NAAQS level as the transport linkage criterion. This is a metric that the states of the OTC and the Lake Michigan Air Directors Consortium analyzed in great detail and collectively proposed to Administrator Jackson in September, 2009. It ensures public health and environmental protection into the future, with the likelihood of subsequent NAAQS revisions based on new science. We also agree with EPA's decision not to use its previous rounding convention to establish 1% of the NAAQS.   [EPA-HQ-OAR-2009-0491-2984.1, p.4]
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.9.]
We are pleased that EPA proposes to use 1% of a NAAQS concentration as the transport linkage criterion. We agree with EPA's decision not to use the rounding convention to establish 1% of the NAAQS.
Omaha Public Power District
EPA has proposed extremely low levels of 'significance' with respect to modeled impact contributions from upwind states, at 1% of the respective NAAQS for 24-hour PM2.5 (0.35 ug/m3), annual average PM2.5 (0.15 ug/m\ and 8-hour ozone (0.8 ppb). This means that some states, like Nebraska, with very minimal predicted contributions, will be targeted for controls that have a very high cost to benefit ratio. Instead of imposing cost inefficient controls (high $/ug/m3) on a state like Nebraska, it would make much more sense to spend similar levels of capital on more aggressive controls in states with predicted impact contributions that in some cases are estimated by EPA to be more than an order of magnitude higher than for Nebraska (see Table IV.C-16 of preamble). [EPA-HQ-OAR-2009-0491-2680.1, p. 4]
EPA's current TR proposal would alter past rounding conventions for annual and 24-hour PM2.5 inconsistently. On the one hand, for annual PM2.5, EPA proposes to deviate from the design value reporting requirement by only one decimal place-rounding to the nearest 0.01 ug/m3 rather than the nearest 0.1 ug/m3 as it did under CAIR consistent with EPA monitoring requirements. In contrast, EPA proposes a two decimal place deviation from past practice for 24-hour PM2.5-rounding to the nearest 0.01 ug/m3 rather than the nearest whole ug/m3. In justifying its proposal, EPA lays out a false choice between adopting the CAIR approach, which would 'yield air quality threshold of zero' and selecting a uniform 2 digit rounding convention for annual 24-hour PM2.5. We recommend that EPA use a rounding convention consistently with its earlier rule proposal for modeling of PM2.5 for demonstrating NAAQS compliance (see above comment), specifying the significance level to one decimal place. We believe this alternative rounding convention is a more defensible metric in setting an air quality threshold for assessing the significance of interstate contributions to downwind nonattainment.  [EPA-HQ-OAR-2009-0491-2680.1, p. 6]
Pennsylvania Department of Environmental Protection
In accordance with Section 110(a)(2)(D)(i)(T) of the CAA, EPA must ensure that SIPs for primary and secondary national ambient air quality standards 'contain adequate provisions' prohibiting sources within a state from emitting air pollutants in amounts which will 'contribute significantly to nonattainment in, or interfere with maintenance by, any other State with respect to any (NAAQSJ.' The DEP supports EPA's approach for determining each state's significant contribution to downwind areas-a threshold greater than or equal to 1 percent of the relevant NAAQS is an appropriate threshold for determining 'significant contribution.' This approach, which is consistent with the recommendation of the Ozone Transport Commission and Lake Michigan Air Directors Consortium (LADCO) submitted jointly to EPA in a September 2, 2009 letter on the replacement of CAIR, should ensure that emissions within a state that significantly contribute to nonattainment or interfere with maintenance in other states are eliminated. [EPA-HQ-OAR-2009-0491-2660.1, pp.3-4]
Sierra Club
Any rule intended to address the significant contribution of air pollution from neighboring states should include all states which are significantly contributing to NAAQS violations (and to interference with NAAQS maintenance) in downwind states. The Sierra Club contends that the contribution threshold that EPA proposes to use to determine whether a state will be included within the proposed Transport Rule, and thus whether it will have its interstate pollution transport reduced under the rule - a threshold which equates to one percent (l %) of the relevant NAAQS -- is too high. To fulfill the Clean Air Act's mandates for assuringtimely attainment and assurance of maintenance of NAAQS, 'significant contribution'within the meaning of section 11O(a)(2)(D) must include any discernable contributions(whether modeled or monitored) to non-attainment (or interference with maintenance) inanother state.. Contributions of less than 1% of the NAAQS (either alone, or in combination with contributions from other states) can still make the difference between an area being in attainment or non-attainment, so there is no rational basis for waiving control of such contributions - and indeed such waiver is contrary to the Act's central mandate of assuring timely attainment. [EPA-HQ-OAR-2009-0491-2872.1 p.2]
Indeed, the 1% contribution threshold EPA proposes as a cut off for including states in the Transport Rule is particularly concell1ing because the threshold excludes without valid reason certain states that are making discell1able contributions to ozone and fine particle levels in downwind states. For example, EPA's state-by-state modeling shows that Texas contributes 0.13 flg/m3 and 0.12 flg/m3 to annual PM2.5 nonattainment in two ites located in southell1 Illinoi (specifically, Madison and Saint Clair counties respectively),2 but because these contributions do not equal or exceed the 0.15 flg/m3 threshold, Texas will not be required to reduce its PM2.5 emis ions under the proposed Transport Rule. Such an outcome is not consistent with the clear mandate and purpose of the rranspOlt requirement, which i to prohibit states from emitting pollutants in a manner that will contribute to non-attainment or interfere with maintenance in other states, and can be avoided with the use of a lower contribution threshold. [EPA-HQ-OAR-2009-0491-2872.1 p.2]
Moreover, the Rule as proposed would allow emissions increases, the most egregious case being Texa . In this regard, when considering what effect, if any, the proposed Rule would have on non-regulated states, EPA's analysis reveals that Texas' 2012 S02 emissions will increase by 136,000 tons if the rule is in fact adopted.3 75 Fed. Reg. at 45284. This dramatic increase in S02 emissions, EPA notes, will push Texas' interstate contributions over the establi hed annual PM2.5 threshold in 2012, thus placing it within the group of states that require PM2.5 reductions under the temlS of the proposed rule. /d. In other words, implementation of the Rule will cause Texas to significantly contribute to non-attainment or interfere with maintenance in downwind states, thereby increasing -- rather than lessening -- the public health threat in those areas as well as within Texas. Given this outcome, which plainly contradicts the mandate of section 11O(a)(2)(D) and the purpose of the Clean Air Act and the Agency's proposed efforts, it is axiomatic that EPA must include Texas within its control program for annual PM2.5 reductions. [EPA-HQ-OAR-2009-0491-2872.1 p.3]
South Carolina Department of Health and Environmental Control 
The 1% contribution threshold in the proposed Transport Rule is too low. It captures insignificantly low levels of transported emissions. The EPA states that the threshold is low by design, because: ...PM2.5 nonattainment problems result from the combined impact of relatively small contributions from many upwind states, along with contributions from in-state sources, and, in some cases, substantially larger contributions from a subset of particular upwind states. [EPA-HQ-OAR-2009-0491-2677.1 p.7]
DHEC notes that the EPA does not elaborate on the mix for the downwind states in the Transport Rule. We cannot find a clearly articulated explanation of how the EPA determined the percentage of local contribution to nonattainment in the Transport Rule Technical Support Documents. Without that we cannot determine how South Carolina's contribution compares to local contributions for nonattainment, and cannot fully evaluate the rule. [EPA-HQ-OAR-2009-0491-2677.1 p.6]
In defending the low contribution threshold, the EPA continues: "A second reason that low threshold values are warranted, as EPA discussed in the notices for the CAIR, is that there are adverse health impacts associated with ambient PM2.5 and Ozone even at low levels."15 DHEC grants that this claim is related to the discussion, but we are unsure how to evaluate it since the studies that the EPA is referencing do not specifically study the health impacts of air pollutant at levels equal to 1% of the NAAQS.  [EPA-HQ-OAR-2009-0491-2677.1 p.7]
The CAIR and NOX SIP Call thresholds were more appropriate, and DHEC recommends that the EPA follow that precedent in the Transport Rule. The previous thresholds were tailored to each NAAQS, and not generalized across various standards. Also, the CAIR and NOX SIP Call thresholds linked the precision available in determining design values and the threshold. In other words, design values for monitors are reported to the nearest 0.1 μg/m3 and the EPA rounded the threshold to the tenths position so that the threshold is not more precise that the design value on which it is based. Federal regulations require states to submit design values for PM2.5 monitors only to one decimal place -- to the nearest 0.1 μg/m3.16 In the Transport Rule, the EPA is proposing to use thresholds rounded to two decimal places, based on design values that are only capable of capturing data to one decimal place. DHEC finds this illogical, and we cite this as a potential source of error in determining which states are subject to the Transport Rule. The EPA addresses the difference between the design value and the threshold in the proposal: For the proposed rule, EPA proposes to decouple the precision of the air quality thresholds with the monitoring reporting requirements, and to use 2-digit values representing 1% of the NAAQS, that is, 0.15 μg/m3 for the 24hr standard. 
The EPA defends this decision citing the ease of applying the threshold to future NAAQS. DHEC is concerned about the problems associated with rounding in converting between the more precise threshold values to the less precise design values. Additionally, if 1% of a lowered PM2.5 standard is less than 0.1 μg/m3, then converting that to a design value that only measures to the tenths would be problematic. The integers as thresholds in the CAIR and NOX SIP Call programs avoid this concern. [EPA-HQ-OAR-2009-0491-2677.1 p.7]
Based on these concerns, DHEC recommends against using thresholds with two decimal places, that is, numbers rounded to the hundredths position. For the annual standard, a threshold rounded to tenths position would be 0.2 μg/m3. For the 24-hour standard, a threshold rounded to the tenths position would be 0.4 μg/m3. But DHEC does not advocate using these thresholds. Because of the uncertainty and possible errors associated with IPM and other modeling assumptions in the proposal including the confounding local issues, we advocate a 1 μg/m3 threshold for determining significant contribution to downwind nonattainment and interference with maintenance. [EPA-HQ-OAR-2009-0491-2677.1 p.7]
Using this approach in the Transport Rule, South Carolina would not significantly contribute to nonattainment or interfere with maintenance downwind for the annual or 24-hour standards18 and would thus not be subject to the Transport Rule SO2 trading program. DHEC considers thμg/m3 threshold, rather than a threshold at the tenths of a microgram, reasonable for both the annual and the 24-hour standard because of the uncertainty and possible errors associated with IPM and other modeling assumptions in the proposal. [EPA-HQ-OAR-2009-0491-2677.1 p.8]
DHEC also finds the ozone threshold problematic. The proposed Transport Rule also uses the 1% threshold for the 1997 Ozone NAAQS, meaning the threshold is 0.8 ppb. The EPA proposes to include states that contribute more than this amount in the Transport Rule program. EPA monitoring regulations require states to submit ozone data to the third decimal place,19 which avoids the decimal place issue discussed above, but our concerns over uncertainty also apply to the ozone thresholds. Again, the uncertainty with IPM and possible local contributions to downwind monitors lead DHEC to request a 1 ppb threshold for ozone. With that threshold, South Carolina's largest contribution to downwind 8-hour ozone nonattainment and maintenance, 0.8 ppb, would fall below the 1 ppb threshold and South Carolina would not be subject to the NOX trading programs in the Trading Rule. [EPA-HQ-OAR-2009-0491-2677.1 p.8]
Southern Company
Additionally, Southern Company objects to EPA's proposal to use its percentage-based air quality contribution threshold approach in the current rulemaking -- or in any future interstate-transport rulemaking--in the absence of a robust technical justification that the resulting thresholds reflect meaningful, and truly measurable, air quality contributions, consistent with the D.C. Circuit's directive in Michigan v. EPA. [EPA-HQ-OAR-2009-0491-2864.1, p. 5]
F. EPA's Proposed Air Quality Contribution Threshold is Flawed
EPA proposes to use an air quality contribution threshold based on a percentage -- specifically, one percent -- of the NAAQS for annual PM2.5, 24-hour PM2.5, and 8-hour ozone to determine whether an upwind state should be included in the Transport Rule program with respect to each of those NAAQS. EPA explains in the preamble to the proposed rule that it chose to deviate from the approach it used in CAIR with respect to PM2.5 by using here a two-digit value rather than a single-digit value and 'decoupl[ing] the precision of the air quality thresholds [from] the monitoring reporting requirements.' [EPA-HQ-OAR-2009-0491-2864.1, pp. 33-34]
Although EPA properly proposes to avoid setting a zero contribution threshold for the current 24-hour PM2.5 NAAQS, and to avoid setting a precedent for a 0.1 u/m3 contribution threshold if the annual PM2.5 NAAQS in the future is reduced to some value lower than the current NAAQS but higher than 10 u/m3 (e.g., 14 u/m3), EPA's proposed approach ignores the limits of the capability of its air quality modeling techniques -- and of ambient monitoring -- to meaningfully detect and measure ambient-air contributions at the extremely low levels represented by one percent of current or possible future NAAQS. For example, the numerical values that result from application of EPA's one-percent contribution threshold approach to the current NAAQS -i. e., 0.15 u/m3 for annual PM2.5, 0.35 u/m3 for 24-hour PM2.5, and 0.8 ppb for 8-hour ozone -- are so low that they are likely below the detection capability of existing modeling and measurement tools. For that reason, it is far from clear that these thresholds could be deemed to reflect a 'measurable contribution' to downwind nonattainment and maintenance problems, as required by the D.C. Circuit. Interstate contributions cannot be assumed out of thin air.') (emphasis in original). At a minimum, EPA should provide, in a supplemental notice of proposed rulemaking, a technical justification for these very low thresholds as representing meaningfully measurable air quality contributions. [EPA-HQ-OAR-2009-0491-2864.1, p. 34]
Equally troubling is EPA's indication that it may be planning to use this same percentage-based approach in any future version of the Transport Rule to address possible future NAAQS. Application of this approach to potential future ambient standards that may be even lower than the current NAAQS would produce even less meaningful thresholds. It makes no sense for contribution thresholds to change based exclusively on changing NAAQS levels, irrespective of the capabilities of modeling and measurement technologies at the time the thresholds are established. [EPA-HQ-OAR-2009-0491-2864.1, p. 34]
Accordingly, Southern Company objects to EPA's proposal to use its percentage-based air quality contribution threshold approach in the current rulemaking -- or in any future interstate transport rulemaking -- in the absence of a robust technical justification that the resulting thresholds reflect meaningful, and truly measurable, air quality contributions, consistent with the D.C. Circuit's directive in Michigan v. EPA. [EPA-HQ-OAR-2009-0491-2864.1, p. 34]
State of Connecticut
The Transport Rule as proposed is an improvement to the Clean Air Interstate Rule of 2005 and there are provisions of the Transport Rule that Connecticut fully supports. For example, Connecticut is pleased that EPA adopted one percent of the NAAQS as the criterion for significant contribution, as recommended by Connecticut and other states. [EPA-HQ-OAR-2009-0491-2534.1, p.1]
State of Missouri Department of Natural Resources
Missouri concurs with the pollutants and air quality thresholds used for identifying states to be included under the proposed rule. Suggesting a higher threshold than one percent (1%) would put the burden of lowering emissions on fewer states. In addition, Missouri agrees with EPA's approach that does not use the rounding convention. [EPA-HQ-OAR-2009-0491-3806, p.4]
State of Ohio Environmental Protection Agency (Ohio EPA)
Ohio EPA has concerns regarding the 1% contribution threshold. U.S. EPA must take into consideration the impact of selecting such a small percent threshold as the NAAQS continue to be strengthened. [EPA-HQ-OAR-2009-0491-2793.2, p. 10]
Related to the continuous tightening of the rules, Ohio EPA has concerns regarding the 1% contribution threshold for identifying significant contributors to downwind states' air quality nonattainment and maintenance problems, which forms the basis of the Proposed Transport Rule. As ambient air quality standards continue to be revised and strengthened, the continued use of a 1% threshold will eventually become impractical and infeasibl~ because it continually rachets down state budgets and unit level allocations. [EPA-HQ-OAR-2009-0491-2793.2, pp. 1-11]
State of Wisconsin, Department of Natural Resources
Wisconsin supports the 1% contribution threshold, as proposed in the Transport Rule, for identifying states that are significant contributors to downwind state's air quality nonattainment and maintenance problems and therefore trigger obligations under Section 110a(2)(D) of the Clean Air Act (CM). [EPA-HQ-OAR-2009-0491-2829.2, p.1]
EPA has appropriately identified individual states that contribute significantly to Wisconsin criteria air quality nonattainment and maintenance problems. [EPA-HQ-OAR-2009-0491-2829.2, p.5]
EPA appears to address the Court concen regarding identification of specific state air quality impact contribution to both attainment and maintenance problems and setting a defensible timeframe for remedy under the current ambient standards. This first part ofsignificant contribution identification including thresholds comports with state recommendations under the OTC/LADCO States Collaborative effort. Wisconsin explicitly supports the 1% contribution threshold for nonattainment areas and some more conservative threshold regarding maintenance. Such thresholds have been upheld by the Court and Wisconsin agreed in the Collaborative process that such thresholds should have both designation period design value and attainment period context for the assessment of impacts relating to contribution. [EPA-HQ-OAR-2009-0491-2829.2, p.5]
Sunbury Generation LP
For purposes of determining which states significantly contribute to or interfere with maintenance of the NAAQS for PM2.5 or ozone in other states under the Proposed Rule, EPA applies a threshold of 1% of the NAAQS. See 75 Fed. Reg. 45237. EPA's reliance on this stringent 1% threshold for determining significant contribution results in an overstatement of the degree to which a state's emissions contribute to emissions impacts in downwind states. [EPA-HQ-OAR-2009-0491-3615,p .7]
Tennessee Department of Environment and Conservation, Division of Air Pollution Control
Comment on Contribution Threshold: EPA's 1% significance threshold for downwind contribution for annual PM2.5 (0.15 μg/m3) is more stringent than the threshold used with CAIR but is generally consistent with the CAIR methodology. 1 The use of similar 1% metrics may not be appropriate for ozone and daily PM2.5. Because the ozone and daily PM2.5 NAAQS employ much shorter averaging times than the annual PM2.5 standard, we are concerned that the use of a simple 1% significance threshold may overstate the downwind contribution for these pollutants, even if the contribution is averaged over multiple days. [EPA-HQ-OAR-2009-0491-0553.1, p.2]
EPA noted in the CAIR rulemaking that there are inherent differences between the PM2.5 and ozone NAAQS, and the thresholds necessarily differ in terms of specific metrics and threshold values. With respect to the 8- hour ozone NAAQS, if an upwind State's impact exceeded a maximum contribution of 2 ppb or an average contribution of 1%, then EPA used additional metrics to determine if downwind contribution from an upwind State was significant. EPA organized the outputs of two modeling techniques (zero-out and source apportionment) into a set of ``metrics.'' The metrics included:
-The magnitude of the contribution (actual amount of ozone contributed by emissions in the upwind State to nonattainment in the downwind area);
-The frequency of the contribution (how often contributions above certain thresholds occur); and
-The relative amount of the contribution (the total ozone contributed by the upwind State compared to the total amount of nonattainment ozone in the downwind area). [EPA-HQ-OAR-2009-0491-0553.1, p.2]
These metrics, which EPA used to assess downwind ozone contributions for CAIR, were also used in the NOX SIP Call. We believe that a methodology similar to the NOX SIP Call/CAIR approach would be preferable for ozone and daily PM2.5, since it would allow the Agency to use a measure of judgment in determining significance. [EPA-HQ-OAR-2009-0491-0553.1, p.2]
Tennessee Valley Authority (TVA)
Issue: EPA has proposed air quality thresholds to identify states with significant contributions that need to be addressed by the Transport Rule. These thresholds are based on 1 percent of the NAAQS: 0.15 ug/m3 for the annual PM-2.5 standard, 0.35 ug/m3 for the 24-hour PM-2.5 standard, and 0.8 ppb for the 8-hour ozone standard. (p. 45237) For CAIR, EPA used a threshold of 0.2 ug/m3 for the annual PM- 2.5 standard and 2 ppb for the 8-hour ozone standard. [p. 45270-83] [EPA-HQ-OAR-2009-0491-2782.1, p. 10]
TVA Comment: EPA should retain the air quality threshold of 0.2 ug/m3 that was used in CAIR for identifying significant contributions with respect to the annual PM-2.5 standard. TVA recommends that to the extent workable, the threshold value should be rounded to the same number of digits as specified in the reporting requirement for the design value of the applicable air quality standard. Thus, because the design value for the annual PM-2.5 standard must be reported to the nearest 0.1 ug/m3, one percent of 15 ug/m3 (i.e. 0.15 ug/m3) rounded to the nearest 0.1 ug/m3 becomes 0.2 ug/m3. Matching the number of digits in the threshold to the number of digits in the design value of the applicable standard imparts the appropriate degree of precision to the threshold. We therefore recommend against decoupling the precision of the air quality thresholds with the monitoring reporting requirements. In North Carolina v. EPA, the D.C. Circuit upheld EPA's decision to round the 0.15 ug/m3 threshold to 0.2 ug/m3. [EPA-HQ-OAR-2009-0491-2782.1, p. 10]
We understand that coupling the precision of the air quality threshold and the monitoring reporting requirement may not always be workable as is the case with the 24-hour PM-2.5 standard. One percent of the 24-hour standard is 0.35 ug/m3, and, as EPA points out, rounding to the nearest whole ug/m3 would yield an unworkable threshold of zero. In such circumstances, the air quality threshold should be rounded to the number digits that most closely approximate the monitoring reporting requirement without rendering the threshold unworkable. For the 24-hour standard, one percent of the standard (i.e. 0.35 ug/m3) should therefore be rounded to the nearest single digit, i.e. 0.4 ug/m3. [EPA-HQ-OAR-2009-0491-2782.1, p. 10]
Texas Commission on Environmental Quality
The TCEQ first objects to the EPA's proposed analysis regarding the determination of 'significant -contribution to nonattainment' by states, because the proposal does not adequately address why a threshold value of one percent of the relevant NAAQS is appropriate. The EPA notes only that 'low' threshold values are warranted due to the upwind 'collective contribution' being important to both PM2 .5 and ozone (75 FR 45237). Because the EPA has not clearly explained the rationale behind its one percent threshold (as opposed to any other 'low' percentage), the TCEQ is unable to determine the appropriateness of such a threshold, particularly given the inadequate comment period provided by the EPA. Given the numerous flaws in the technical analysis already identified, the TCEQ can only assume that such a value is unsupportable.[EPA-HQ-OAR-2009-0491-2857.2, pp.7-8]
Utility Air Regulatory Group (UARG)
EPA's Proposed Air Quality Contribution Threshold Is Flawed.
EPA proposes to use an air quality contribution threshold based on a percentage -- specifically, one percent -- of the NAAQS for annual PM2.5, 24-hour PM2.5, and 8-hour ozone to determine whether an upwind state should be included in the Transport Rule program with respect to each of those NAAQS. See 75 Fed. Reg. at 45237/1-45238/1. EPA explains in the preamble to the proposed rule that it chose to deviate from the approach it used in CAIR with respect to PM2.5 by using here a two-digit value rather than a single-digit value and "decoupl[ing] the precision of the air quality thresholds [from] the monitoring reporting requirements." Id. at 45237/3. [EPA-HQ-OAR-2009-0491-2756.1, p.60]
Although EPA properly proposes to avoid setting a zero contribution threshold for the current 24-hour PM2.5 NAAQS, see id., and to avoid setting a precedent for a 0.1 μ/m3 contribution threshold if the annual PM2.5 NAAQS in the future is reduced to some value lower than the current NAAQS but higher than 10 μ/m3 (e.g., 14 μ/m3), see id., EPA's proposed approach ignores the limits of the capability of its air quality modeling techniques -- and of ambient monitoring -- to meaningfully detect and measure ambient-air contributions at the extremely low levels represented by one percent of current or possible future NAAQS. For example, the numerical values that result from application of EPA's one-percent contribution threshold approach to the current NAAQS -- i.e., 0.15 μ/m3 for annual PM2.5, 0.35 μ/m3 for 24- hour PM2.5, and 0.8 ppb for 8-hour ozone -- are so low that they are likely below the detection capability of existing modeling and measurement tools. For that reason, it is far from clear that these thresholds could be deemed to reflect a "measurable contribution" to downwind nonattainment and maintenance problems, as required by the D.C. Circuit. Michigan v. EPA, 213 F.3d at 684 (" . . . EPA must first establish that there is a measurable [air quality] contribution. Interstate contributions cannot be assumed out of thin air.") (emphasis in original). At a minimum, EPA should provide, in a supplemental notice of proposed rulemaking, a technical justification for these very low thresholds as representing meaningfully measurable air quality contributions. [EPA-HQ-OAR-2009-0491-2756.1, pp.60-61]
Equally troubling is EPA's indication that it may be planning to use this same percentage-based approach in any future version of the Transport Rule to address possible future NAAQS. See 75 Fed. Reg. at 45237/3 (noting that one of the considerations favoring the one percent contribution threshold approach is that "the approach is readily applicable to any current and future NAAQS"). Application of this approach to potential future ambient standards that may be even lower than the current NAAQS would produce even less meaningful thresholds. It makes no sense for contribution thresholds to change based exclusively on changing NAAQS levels, irrespective of the capabilities of modeling and measurement technologies at the time the thresholds are established. [EPA-HQ-OAR-2009-0491-2756.1, p.61]
Accordingly, UARG objects to EPA's proposal to use its percentage-based air quality contribution threshold approach in the current rulemaking -- or in any future interstate-transport rulemaking -- in the absence of a robust technical justification that the resulting thresholds reflect meaningful, and truly measurable, air quality contributions, consistent with the D.C. Circuit's directive in Michigan v. EPA. [EPA-HQ-OAR-2009-0491-2756.1, pp.61-62]
West Virginia Department of Environmental Protection
Significant Contribution and Interference with Maintenance - EPA requested comment on the pollutants and air quality thresholds used for identifying states to be included under the Transport Rule. WVDAQ notes that the courts have been supportive of EPA's specific thresholds in the past. However, as the National Ambient Air Quality Standards become more stringent, a fixed one percent value may lead to inappropriate results, and could yield 'significance' thresholds that are practically unmeasurable. Just because a value can be modeled does not make it necessarily measurable or meaningful. WVDAQ believes that the significance threshold should consider both the percent of National Ambient Air Quality Standards and the reality of limited measurement precision. [EPA-HQ-OAR-2009-0491-2790.1, p. 3]
Rounding Convention - EPA also requested comment on whether the final Transport Rule should use the same rounding convention that was used in the final CAIR for the 15ug/m3 annual PM25 standard, or whether commenters agree with EPA's approach that does not use this rounding convention. WVDAQ believes that the rounding convention should directly consider the practicality of the rounding convention with respect to the precision of the applicable federal reference method monitors. [EPA-HQ-OAR-2009-0491-2790.1, p. 3]
Response: 
See preamble discussion of EPA's choice of air quality thresholds in section V.D.1 of the final Transport Rule.  

EPA notes that some of the commenters misinterpret the 1 percent threshold as identification of "significant contribution."   EPA describes in detail in the preamble EPA's approach to quantifying each state's significant contribution.

The comments by Minnesota Power related to contributions to annual PM2.5 levels.  EPA notes that Minnesota is covered by the Transport Rule based on its contribution to 24-hour PM2.5. 

Regarding comments from George Washington University, EPA disagrees with the commenter and finds that its analyses for the final rule are sufficiently detailed and precise enough to support the Agency's determinations of emission reduction responsibilities in each state.  EPA has followed all of its own modeling guidance to states and  has employed analytic methodologies (using peer-reviewed models) that have been upheld in prior regulatory actions under judicial review.  EPA believes that commenter's assertions ignore commonly practiced and widely accepted regulatory development procedures and demonstrate fundamental misunderstandings of the role of these analyses in Clean Air Act rulemakings. 

EPA disagrees with comments arguing that EPA cannot set the level for finding significant contribution to nonattainment or interference with maintenance of a NAAQS lower than the single source "significant impact levels" (SILs) used in the Prevention of Significant Deterioration (PSD) permitting program.  The SILs serve different purposes than the thresholds used in the Transport Rule analysis.  Thus, it does not follow that the two values should be made equivalent, or that the SILs establish a floor for identifying appropriate thresholds for use in the Transport Rule analysis of significant contribution and interference with maintenance under section 110(a)(2)(D)(i)(I) of the Clean Air Act.  Further, EPA's analysis for this rule only addresses the appropriate threshold to be used in the first step of the methodology used to identify and quantify emissions that must be prohibited pursuant to section 110(a)(2)(D)(i)(I).  This analysis does not address what SILs should be used in the PSD program. 
      
The SILs appear in EPA's regulations at 40 C.F.R. § 51.165(b)(2).  The SILs are used in the PSD program, among other things, to determine whether an individual source, seeking a preconstruction permit, must conduct cumulative ambient air quality modeling analyses to demonstrate that it will not cause, or contribute to, a violation of the NAAQS.  The SILs address source specific permitting requirements.  They address, furthermore, whether comprehensive, multi-source review is required of the source to make one of the showings required to obtain a permit to construct.  A major stationary source with estimated impacts below the applicable SIL is still subject to applicable control requirements, including best available control technology (BACT), designed to moderate the source's impact on air quality.  In other words, a determination that a source's emissions do not exceed the SIL does not excuse a source from controlling its emissions.

The thresholds in the Transport Rule, in contrast, are used to determine whether the total emissions from a state contribute so little to downwind nonattainment and maintenance receptors that further analysis is not warranted.  If the state's contribution is below the thresholds used in the Transport Rule, the state is deemed to have satisfied the requirements of section 110(a)(2)(D)(i)(I) with respect to the NAAQS in question and sources within the state are excused from making reductions to satisfy that requirement.  On the other hand, if emissions from the state exceed the applicable threshold at one or more nonattainment or maintenance receptors, EPA then conducts further analysis to determine if reductions are available in the state at the cost threshold identified as appropriate for use in that state for the pollutant in question. 
      
The two analyses serve distinct regulatory purposes.  The use of the word "significant" in both the term "significant impact level" and "significant contribution" is not sufficient to create an inference that the threshold used in this rule for determining if further analysis of a state's contribution to other downwind areas is warranted should be the same or higher than the "significant impact level" used in PSD permitting.

IV.B.3. Identification of Downwind Nonattainment and Maintenance Receptors

Organization: Attorney General of North Carolina
Comment: 
Attorney General of North Carolina
North Carolina's particulate matter ("PM2.5") and ozone receptors are not proposed to be "linked" to any upwind States under the Transport FIP because EPA proposes to conclude that North Carolina would have no nonattainment or maintenance areas under the 1997 National Ambient Air Quality Standards ("NAAQS") for PM2.5 and ozone or the 2006 PM2.5 NAAQS in the modeled year. This is in large measure due to programs undertaken by North Carolina, for example, the enactment of North Carolina's Clean Smokestacks Act ("CSA") in 2002. See 2002 N.C. Sess. L. 4. The CSA effected significant reductions in NOX and SO2 emissions from the State's fourteen largest coal-fired electric generating facilities. The reductions take effect in two stages. The first NOX tonnage limits began in 2007 and the final limit was reached in 2009. Facilities were required to meet the first phase of the SO2 limits in 2009 and the final limits are required in 2013. N.C. Gen. Stat. §143-215.107D(b)-(e).
At least partially through these efforts, North Carolina has been able to achieve compliance with the current PM2.5 standard. As EPA is aware, North Carolina has not yet attained the 85 ppb ozone standard. The remaining nonattainment area under that ozone standard is Charlotte  -  the State's largest metropolitan area.2 Air quality issues in Charlotte result from several factors, but certainly one is interstate NOX transport. See EPA, Technical Support Document for the Interstate Air Quality Rule Air Quality Modeling Analyses at Appx. G (Jan. 2004); see also North Carolina v. EPA, 587 F.3d 422 (D.C. Cir. 2009) (finding that North Carolina demonstrated sufficient "causation" regarding the effects of NOX emissions from Georgia on ozone levels in North Carolina). For this and other reasons, North Carolina has undertaken a significant program to effect emissions reductions throughout the region. See 2002 N.C. Sess. L. 4, §10; see also, e.g., North Carolina, 587 F.3d 422 (addressing NOX emissions from northern Georgia); Sierra Club v. EPA, No. 06-1221 (D.C. Cir. March 5, 2009) (addressing regional NOX and SO2 emissions); North Carolina, 531 F.3d 896 (same); North Carolina ex rel. Cooper v. TVA, 593 F. Supp. 2d 812, 821-25 (W.D.N.C. 2009) (addressing NOX and SO2 emissions from TVA), rev'd on other grounds, No. 09-1623, 2010 U.S. App. LEXIS 15286 (July 26, 2010), reh'g denied, No. 09-1623 (4th Cir. Sept. 21, 2010).
EPA projects that Charlotte will attain the 85 ppb ozone standard by 2012  -  the operative year for the Transport FIP. (This projection is discussed in more detail later.) Consequently, EPA has not included North Carolina as one of the downwind States that needs relief. Nevertheless, EPA's modeling demonstrates that North Carolina, like any State that is home to a nonattainment or maintenance area, would benefit from upwind reductions. This is significant for at least three reasons. First, reductions in ambient levels of PM2.5 and ozone even from levels below the NAAQS will result in public health and environmental benefits in North Carolina. E.g., TVA, 593 F. Supp. 2d at 821-25. Second, greater certainty regarding the locations of reductions will assist in future modeling and planning efforts. And third, North Carolina has areas that are currently not attaining the 75 ppb ozone standard and (if the PM2.5 standard is reduced in the near future, may have areas that do not attain that standard either). Although the 75 ppb standard is being reconsidered, it is likely that reconsideration will result in the standard being lowered and not remaining the same or increasing. National Ambient Air Quality Standards for Ozone, 75 Fed. Reg. 2938 (proposed Jan. 19, 2010). As EPA has indicated, whether an upwind area is violating the provisions of §110(a)(2)(D)(i)(I) does not depend on the formal attainment status of the downwind area, but instead on the air quality conditions in the downwind area. Finding of Significant Contribution & Rulemaking for Certain States in the Ozone Transport Assessment Group Region for Purposes of Reducing Regional Transport of Ozone, 63 Fed. Reg. 57,356, 57,370-72 (Oct. 27, 1998). As such, North Carolina is presently 6 entitled to relief from upwind NOX emissions under §110(a)(2)(D)(i)(I) regarding the 75 ppb ozone standard.
[EPA-HQ-OAR-2009-0491-2685.1 p.3]
Response: 
As the commenter notes, EPA did not identify any nonattainment or maintenance receptors in North Carolina for the 1997 ozone and PM2.5 NAAQS or the 2006 PM2.5 NAAQS. All of the potential receptors in North Carolina were projected to be below the NAAQS in 2012 (including the maximum design values used for determining maintenance receptors). Therefore EPA did not identify any linkages in the final rule for any upwind states to downwind areas in North Carolina.
Regarding analyses for the 75 ppb 2008 ozone NAAQS, please see preamble section IV.C.1. for a response. 
Organization: Clean Air Task Force
Comment: 
Clean Air Task Force
EPA's proposed TR assessment uses only the monitors in one or two counties in any nonattainment area. The assessments do not require calculations based on impacts to[EPA-HQ-OAR-2009-0491-2738.1, p.24] every county in a nonattainment area -- only those counties where transport contributes to that county's violation. Logically, that county's design value would at least equal the design value for the nonattainment area once designated. EPA can and should analyze counties with design values in violation of the standard and take action. [EPA-HQ-OAR-2009-0491-2738.1, p.25; for additional comments pertaing to The Proposed Rule Inappropriately Uses the 1997 Ozone NAAQS as the basis for Assesment of Contributions from Transported Ozone see p. 24-25]
Response: 
The primary attainment test contained in the ozone and PM2.5 SIP modeling guidance is a monitor based test.  We therefore project monitor values to determine nonattainment and maintenance receptors.  Although spatial fields of PM2.5 concentrations could be projected to cover all areas (grid cells), the values in unmonitored areas would be more uncertain.  Therefore we choose to limit the results to locations where EPA is certain of the ambient PM2.5 and ozone measurements.  And we only use monitors in the analysis if they have at least one complete design value period of data (3 years).  
EPA recognizes that official nonattainment areas often include additional counties which do not have monitors.   EPA's analysis focuses on identifying significant contribution to nonattainment and interference with maintenance to areas projected to have nonattainment or maintenance problems at a specific future date.  The designation status of an area is not directly relevant to this analysis.  Further, since this rule addresses transported pollutions, the benefits from the reductions required by this rule are widespread and not limited to the specific receptor areas identified. 
Organization: Cleco Corporation
Exxon Mobil Corporation
Lafayette Utilities System
Comment: 
Cleco Corporation
III. Louisiana Should Not Be Included In the PM-2.5 Programs.
In the proposed rule, EPA abandons its established approach to identifying downwind receptors in favor of one that relies exclusively on projected data  -  i.e., the Agency's guess work. This is completely inappropriate and leads to absurd results.9 Receptor identification is a fundamental component of the Agency's authority under the "good neighbor" provision, and must be based, to some extent, on actual monitored data. [EPA-HQ-OAR-2009-0491-2859.1 p.5]
EPA's departure from its modeled-plus-monitored approach significantly impacts Louisiana. It forces Louisiana into two annual trading programs because a single PM-2.5 monitor in Harris County, Texas (Clinton Drive) has a "future year maximum" annual PM-2.5 design value greater than 15.05μg/m3  -  based solely on EPA's modeling projections. EPA flatly ignores all of the actual data from the State of Texas, which has been submitted to the Agency, showing PM-2.5 levels decreasing at the Clinton Drive monitor following recent emission reduction efforts in Texas specifically designed to prevent potential future problems at that particular monitor. [EPA-HQ-OAR-2009-0491-2859.1 p.5]
Exxon Mobil Corporation
Louisiana Emissions Do Not Reasonably Interfere with the Ability of Harris County, Texas, to Stay in Attainment With the Annual PM2.5 NAAQS
Louisiana is included in the proposed Annual NOx trading program and the SO2 Group 1 Trading program due to projected impacts of Louisiana emission sources on the levels of fine particulate existing in Harris County, Texas. Actual monitored empirical data, however, show that Harris County is currently in attainment with the Annual National Ambient Air Quality Standard ('NAAQS') for PM2.5. Further, Harris County has never been designated as being in nonattainment with that standard. EPA has projected through modeling for the proposed CATR/FIP that Louisiana -emissions may interfere with maintenance of that NAAQS in 2012, by contributing only 0.34 ug/m3 to the annual PM2.5 values there. Of that total, EPA projects that 0.33 ug/m3 is from sulfate emissions and only 0.004 ug/m3 from nitrate emissions. Solely based upon these projections, EPA proposes to impose a FIP on Louisiana electrical generating units ('EGUs') to reduce their annual SO2 and annual NOx emissions. EM strongly objects to EPA's projections and proposed FIP for these reasons: [EPA-HQ-OAR-2009-0491-2841.1,pp.2-3]
5. Empirical evidence demonstrates that Louisiana emissions will not interfere with the ability of Harris County, Texas, to maintain compliance with the annual PM2.5 NAAQS. The last two years have seen annual average PM2.5 emissions below 14.0. The 2010 design value for Harris Co. is projected to be below 14.0. The Texas Commission on Environmental Quality, together with state and local partners, have undertaken a number of permanent measures to reduce PM2.5 levels to a point where interstate transport does not affect their ability to maintain attainment. [EPA-HQ-OAR-2009-0491-2841.1, p.5]
:: EPA included a significant quantity of S02 and NOx emissions from commercial marine vessels ('CMVs') in the Louisiana nonroad inventory that are actually from offshore, outside of the geographical jurisdiction for Louisiana and are thus not attributable to Louisiana under the Clean Air Act SIP requirements. EM also notes that the LDEQ does not have the authority to regulate these sources, even though they represent a growing percentage of the overall inventory. [EPA-HQ-OAR-2009-0491-2841.1,p.5]
:: For all Class 3 commercial marine vessels, including those that are properly within Louisiana jurisdiction, EPA failed to include projected reductions of SO2 and NOx emissions that will result from EPA marine engine regulations enacted in December 2009. In other words, not only are C3 commercial marine vessel emissions hundreds of miles offshore counted as being part of Louisiana's significance budget, even when not within Louisiana jurisdiction, they are overestimated because the full impact of the December 2009 rule were not included in the estimates. The same is true with respect to C3 CMV emissions that are within Louisiana jurisdiction. There are also additional clean fuel changes as agreed to by the US and others under the auspices of the IMO, as found at http://www.epa.gov/otag/oceanvessels.htm. It does not appear that the reductions in SO2 and NOx that will result were accounted for in the EPA's analysis. [EPA-HQ-OAR-2009-0491-2841.1,pp.5-6]
:: EPA failed to include enforceable reductions from non-EGU federal consent decrees in Louisiana even where these were entered prior to the date of the proposal and require at least a portion of the enforceable reductions before 2012. [EPA-HQ-OAR-2009-0491-2841.1,p.6]
:: EPA failed to include the Louisiana NOx Reasonably Available Control Technology rule in LAC 33:III.Ch. 22 reductions of NOx in the modeling used to project future impact. As part of its comments, EM hereby adopts and incorporates by reference those comments on the proposed CATR and FIP made by the Louisiana Chemical Association. EM supports such comments and urges EPA to carefully review such comments prior to final rulemaking. [EPA-HQ-OAR-2009-0491-2841.1,p.6]
Further, in support of the above principles and contentions, EM adopts and incorporates by reference the comments of the Louisiana Chemical Association and the Louisiana Department of Environrnental Quality, in support of the conclusion that Louisiana emissions inventories were overestimated and that Louisiana emissions do not reasonably interfere with maintenance of the annual PM2.5 NAAQS in Harris County, Texas. [EPA-HQ-OAR-2009-0491-2841.1,p.7]\
Louisiana Emissions Do Not Significantly Contribute to Nonattainment With Nor Interfere With Maintenance of the 1997 8-hour ozone standard in the Houston/Galveston/Brazoria Area or the Dallas/Ft. Worth Area.
EPA has projected that Louisiana emissions will significantly contribute to nonattainment with the 1997 8-hour ozone NAAQS at certain monitoring sites in the Houston-Galveston-Brazoria ('HGB') and the Dallas-Ft. Worth ('DFW') Areas of Texas in 2012. EPA has projected that Louisiana emissions will interfere with maintenance of that NAAQS at other monitoring sites in the HGB and the DFW Areas of Texas in 2012. EM disputes those projections for the following reasons. [EPA-HQ-OAR-2009-0491-2841.1, p.7]
1. All monitors in the HGB Area are currently in attainment with the 1997 8-hour ozone NAAQS and have been since 2008, based upon the 2006-2008 monitoring data. This is actual empirical data showing attainment. All of the DFW monitors that EPA projected were adversely impacted by Louisiana emissions, save one, are currently in attainment with that NAAQS. The design value at the one monitor at issue in DFW is 86 ppb, just 2 ppb above the standard. Under both versions of the IPM base case modeling, Louisiana ozone season NOx emissions are projected to decrease even without the CATR/FIP (or CAIR). Thus, there is no basis for presuming that actual conditions, as shown through empirical monitored data, will worsen due to Louisiana emissions. [EPA-HQ-OAR-2009-0491-2841.1,p.7]
Lafayette Utilities System
Louisiana Should Not Be Included Under the Transport Rule/FIP for Annual SO2 or NOx Reductions Because Louisiana Sources Do Not Interfere With Maintenance of the Annual PM2.5 NAAQS in Harris County, Texas.
Harris County, Texas, is currently in attainment with the annual National Ambient Air Quality Standard ('NAAQS') for PM2.5 and has never been designated as being in nonattainment with that standard. EPA has projected through modeling for the proposed Transport Rule/FIP that Louisiana emissions may interfere with maintenance of that NAAQS in 2012, by contributing only 0.34 ug/m3 to the annual PM2.5 values there. Of that total, EPA projects that 0.33 ug/m3 is from sulfate emissions and only 0.004 ug/m3 from nitrate emissions. Based solely upon these projections, EPA proposes to impose a FIP on Louisiana electrical generating units ('EGUs') to reduce their annual SO2 and annual NOx emissions. LUS strongly objects to EPA's projections and proposed FIP for the following reasons: [EPA-HQ-OAR-2009-0491-2983.1,p.2]
1. Any impact of Louisiana emissions on Harris County, Texas is less than any of the proposed EPA Significant Impact Levels ('SILs') for annual PM2.5 used under the Prevention of Significant Deterioration ('PSD') Program.4 By definition, any such impacts are de minimis. EPA would be arbitrary and capricious and/or abusing its discretion if it makes a finding of 'interference with maintenance' for a Louisiana contribution less than one of these proposed SILs. [EPA-HQ-OAR-2009-0491-2983.1,p.]
2. EPA's projection of reasonable interference was based on the IPM v. 3.02 Base Case modeling for 2012. On September 1,2010, EPA published a Notice of Data Availability for the IPM v. 4.10 modeling, including a revised TR Base Case 2012 scenario. Under the revised modeling, projected emissions of S02 are more than 20,000 tpy less than projected under the IPM v. 3.02 version. Based on this factor alone, it is believed that any revised air quality analysis based on the IPM v. 4.10 modeling will demonstrate no impact whatsoever on Harris County. PM2.5 levels that could conceivably interfere with maintenance of attainment of the annual PM2.5 NAAQS. While LUS has reservations about some of the other inputs to the IPM model, as discussed herein, LUS believes that the v. 4.10 estimates rely upon a more accurate forecasting of natural gas prices and that version should be used to determine, at least as a screening mechanism, the potential for significant contribution or interference with maintenance of a NAAQS. [EPA-HQ-OAR-2009-0491-2983.1,pp.2-3]
3. EPA's own modeling shows that the reductions in estimated Louisiana emissions from the Transport Rule Base Case v. 3.02 to the Base Case v. 4.10 are greater than what EPA stated was needed to remove 'interference with maintenance' in Harris County, Texas. EPA indicated that the difference between the TR Base Case 2012 v. 3.02 and TR Limited Trading Option case, or actually a reduction to the allocated state budget level, represents the amount necessary for a state to reduce emissions in order to remove significant interference or and interference with maintenance.5 EPA's revised IPM v. 4.10 Base Case 2012 modeling shows that even without implementation of the Transport RuielFIP (or the Clean Air Interstate Rule ('CAIR')), reductions from Louisiana are already greater than those required reductions. The following table demonstrates this finding: [EPA-HQ-OAR-2009-0491-2983.1,p.3] [[See Docket Number EPA-HQ-OAR-2009-0491-2983.1,p.3 for the table.]]
Because 'significant contribution' and 'interference witlt maintenance' Itave been removed as sltown by tltis revised IPM modeling, tltere is no basis for a Transport RulelFIP for annual SO2 or NOx control for Louisiana sources, as tlte level required to remove inteiference with maintenance will have already been achieved. [EPA-HQ-OAR-2009-0491-2983.1,p.4]
4. Due to the inherent uncertainty in the IPM modeling, as unmistakably illustrated by the material differences between IPM v. 3.02 and v. 4.10 projections, a projected impact of less than 2 ppb based on modeling should never be used as a level indicating 'significant contribution' or 'interference with maintenance' from an upwind to a downwind state under the 'good neighbor' provisions of the Clean Air Act, 42 U.S.C. 7410(a)(2)(D). The projected impact from Louisiana is well below 1 ppb. At most, the IPM should be used as a screening tool for making rebuttable presumptions for 'significant contribution' or 'interference with maintenance' determinations. However, such presumptions should be always subject to a reasonable opportunity for rebuttal by empirical evidence. [EPA-HQ-OAR-2009-0491-2983.1,p.4]
5. Empirical evidence demonstrates that Louisiana emissions will not interfere with the ability of Harris County, Texas, to maintain compliance with the annual PM2.5 NAAQS. The last two years have seen annual average PM2.5 emissions below 14.0 ug/m3. The 2010 design value for Harris County is projected to be below 14.0 ug/m3. The Texas Commission on Environmental Quality, together with state and local partners, have undertaken a number of permanent measures to reduce PM2. [EPA-HQ-OAR-2009-0491-2983.1,p.4]
6. EPA overestimated Louisiana emissions inventory used for making the projections, in both the IPM v. 3.02 and v. 4.10 models; thus, even the minimal contributions by Louisiana are likely grossly overstated. The primary reasons the inventories were overstated are:
:: EPA included a significant quantity of SO2 and NOx emissions from commercial marine vessels in the Louisiana nonroad inventory that are actually from offshore, outside of the geographical jurisdiction for Louisiana and are thus not attributable to Louisiana under the Clean Air Act SIP requirements. [EPA-HQ-OAR-2009-0491-2983.1,p.4]
:: For all Class 3 commercial marine vessels ('CMVs'), including those that are properly within Louisiana jurisdiction, EPA failed to include projected reductions of 802 and NOx emissions that will result from EPA marine engine regulations enacted in December 2009. In other words, not only are category 3 ('C3') commercial marine vessel emissions hundreds of miles offshore counted as being part of Louisiana's significance budget, even when not within Louisiana jurisdiction, they are overestimated because the full impact of the December 2009 rule were not included in the estimates. The same is true with respect to C3 CMV emissions that are within Louisiana jurisdiction.  [EPA-HQ-OAR-2009-0491-2983.1,pp.4-5]
:: EPA failed to include enforceable reductions from non-EGU federal consent decrees in Louisiana even where these were entered prior to the date of the proposal and require at least a portion of the enforceable reductions before 2012.  [EPA-HQ-OAR-2009-0491-2983.1,p.5]
:: EPA failed to include the Louisiana NOx Reasonably Available Control Technology rule, see LAC 33:III Ch. 22, reductions of NOx in the modeling used to project future impact. As part of its comments, L US hereby adopts and incorporates by reference those comments on the proposed Transport Rule and FIP made by the Louisiana Chemical Association ('LCA'). LUS supports such comments and urges EPA to carefully review such comments prior to final rulemaking. [EPA-HQ-OAR-2009-0491-2983.1,p.5]
Response: 
There are several related comments.
1) The final rule modeling included many emissions inventory updates in both Louisiana and Texas.  Details on these updates can be found in preamble section V.C.1 and the Transport Rule Emissions Inventories Response to Comments document.
2) The analysis for the final rule does not identify Harris County TX as a PM2.5 nonattainment or maintenance receptor in 2012, or identify Louisiana as a state with emissions that significantly contribute to nonattainment or interfere with maintenance of either PM2.5 NAAQS.  EPA does not agree with all of the arguments for why Harris County should not have been considered a receptor in the proposal. 
3) The final rule modeling identifies Louisiana as a state with emissions that contribute significantly to nonattainment and interfere with maintenance of the 8-hr ozone NAAQS in Houston, TX.  Since there are no nonattainment or maintenance receptors in Dallas in the final rule, Louisiana does not contribute to Dallas.  Commenters claim that due to more recent ozone data showing attainment in Houston, Louisiana should not be linked to Houston.  We disagree with this comment.  There are several reasons why recent monitoring data should not and cannot be used to determine the nonattainment and maintenance receptor status for consideration under the Transport Rule.  Please see preamble section V.C.2 for details.
Organization: Connecticut Department of Environmental Protection
Comment: 
Connecticut Department of Environmental Protection
Significant Impact Not Addressed Adequately for Connecticut
This issue is best illustrated with an example from Connecticut. Connecticut operates an ozone monitor in Greenwich (AQS ID 90010017), located at the extreme southwest edge of the state, on a peninsula jutting out into Long Island Sound2. During peak ozone events, southwest winds transport ozone and precursor emissions to the monitor from upwind states, with minimal impacts from Connecticut emissions due to the monitor's location. EPA's Transport Rule Air Quality Modeling Technical Support Document (TSD, page D-5) presents CAMx modeling indicating that Connecticut emissions contribute 2 ppb to 8-hour ozone levels at the Greenwich monitor in 2012 without the emission reductions from CAIR or the proposed Transport Rule. Total CAMx modeled impacts at the Greenwich monitor are 85 ppb (see page B-4 of the TSD), illustrating that overwhelming transport dominates the ambient concentrations measured at that monitor. [EPA-HQ-OAR-2009-0491-2780.1 p.13]
The measured 2009 8-hour ozone design value at the Greenwich monitor is 80 ppb, only 4 ppb below the effective 1997 8-hour-ozone NAAQS of 84 ppb. Given the potential increase in transport from upwind sources likely to occur during the eventual economic recovery, CTDEP cannot ensure its ability to maintain the current design value in Greenwich without an enhanced final Transport Rule. [EPA-HQ-OAR-2009-0491-2780.1 p.13]
Response: 
As described in preamble section V.C.2, EPA continues to identify maintenance receptors using the methodology described in the proposal.  And in fact, two monitors in Connecticut are identified as maintenance receptors in the final rule modeling (sites 090011123 and 090093002).  Instead of identifying a fixed value to determine if an area is "close to the NAAQS", EPA's maintenance methodology uses actual monitoring data at each site to evaluate the variability in measured ozone and PM2.5.  This leads to a monitor specific determination of maintenance that is based on actual data.  EPA continues to believe that this is a reasonable and appropriate approach to define maintenance receptors for the final transport rule. 
Organization: Consumers Energy
Comment: 
Consumers Energy
B. EPA's Proposal Relies Upon a Baseline that No Longer Exists Resulting in Conclusions that Contradict Current Reality and Ignore the Proven Efforts and Successes by the States and Affected Sources
In support of this proposal, EPA utilized a base year 2005 emission inventory. Future year emission inventories were then grown from that base year. Ambient air quality monitoring data, collected through 2007, were then combined with the emissions inventories and processed by EPA, with air quality models, to determine relative contributions to downwind nonattainment and to simulate changes in air quality as the result of control strategy implementation. [EPA-HQ-OAR-2009-0491-2837.1, p.5]
By the selection of a 2005 base year for emissions and the decision to limit ambient air quality monitoring data to 2007, EPA has begun a complicated rulemaking by going back in time to a world that no longer exists. This decision deliberately ignores the implementation of CAIR, which remains in effect, ignores the major regulatory strides made by the States in cooperation with affected sources from multiple source categories, and incredulously ignores the measured improvements in actual ambient air quality as shown in data collected, quality assured and reported through 2009. [EPA-HQ-OAR-2009-0491-2837.1, p.5]
As Consumers Energy commented during the April 17,2009, listening session, a 2005 emissions inventory has little relevance to states like Michigan. While EPA alluded to a 'temporary' economic downturn, we pointed out that we are looking at major source facilities that are not simply shutdown, they are gone - torn down and currently exist as brownfield sites. These facilities and their emissions are not coming back. This reality is in addition to the major control programs in place and being implemented in our State. [EPA-HQ-OAR-2009-0491-2837.1, p.5]
Actual ambient monitoring data, currently approved and in the hands of EPA, as evidenced by the recent 1997 ozone NAAQS attainment designation using 2007-2009 data, clearly demonstrates the folly of restricting model input to data collected through 2007. As the MDNRE points out in their comments, EPA begins with numerous areas in Michigan as nonattainment for the ozone and PM2.5 NAAQS. EPA's future projections conclude that numerous areas in Michigan will remain in nonattainment for those NAAQS unless the proposed rule is put in place. Yet the reality is that as of the end of 2009, all Michigan counties are designated as attainment for the 1997 ozone NAAQS that is a target of the proposed rule. As of the end of 2009, all Michigan monitors have 3 years of quality assured data demonstrating attainment of both the 1997 and 2006 PM2.5 NAAQS that are the targets of the proposed rule. As EPA is well aware, the MDNRE is currently preparing a redesignation request for EPA's approval. This scenario is repeated in numerous other states. [EPA-HQ-OAR-2009-0491-2837.1, p.5]
Computer modeling results rely heavily upon the input data used. Consumers Energy is confident that EPA's starting points were wrong, producing inaccurate results, resulting in a rule proposal that goes far beyond what is required for the world that exists, today. [EPA-HQ-OAR-2009-0491-2837.1, p.5]
:: The proposed rule has been developed using ambient air quality monitoring data that are not representative of air quality as it currently exists. EPA starts with out of date data and arrives at erroneous conclusions regarding attainment and nonattainment of the standards addressed by the proposed rule - conclusions that grossly conflict with air quality as it exists today. By doing so, EPA deliberately disregards the successes of the states in improving ambient air quality. [EPA-HQ-OAR-2009-0491-2837.1, p.15]
Response: 
See preamble section V.C.2.
Organization: Detroit Regional Chamber
Comment: 
Detroit Regional Chamber
While the overall approach of retaining limited interstate trading will result in cost savings for Michigan businesses and residents by giving our utilities some flexibility in managing their generating units, the use of old or misleading data could reverse any benefits derived from this trading and pile on significant costs at a time when Michigan's economy is still lagging behind any National recovery. For example, EPA has recently released monitoring data that show that 80% of monitoring sites projected by the EPA still to be out of attainment in 2012 for ozone and PM 2.5 were already in attainment as of 2009. This fits a pattern illustrated by some of the most up to date modeling of the Great Lakes region done by Alpine Geophysics, along with analysis by Environ Corp., that ozone and annual PM objectives of the Transport Rule can be achieved by 2014 through compliance with existing CAIR requirements and other current regulations. [EPA-HQ-OAR-2009-0491-2720.1, p.1]
Response: 
See preamble section V.C.2.
Organization: Dow Chemical Company
Comment: 
Dow Chemical Company
Dow believes that EPA's finding that Louisiana emission sources significantly contribute to nonattainment and/or interfere with maintenance of the 1997 8-hour ozone standard in the Houston-Galveston-Brazoria (HGB) area and the Dallas-Ft. Worth (DFW) area is erroneous, for the reasons stated in the comments of the Louisiana Chemical Association. Dow hereby adopts those comments by reference. The HGB Area is in attainment with the 1997 8-hr. ozone NAAQS and has been as of the 2006-2008 period. As EPA's own projections indicate that ozone season NOx emissions from Louisiana EGUs will decline by 2012 even without the Transport Rule/FIP, there is no legal basis for imposition of a FIP to control ozone season NOx with respect to the HGB Area.  [EPA-HQ-OAR-2009-0491-2775.1 p.2]
The DFW Area design value is currently 86 ppb, just 2 ppb in excess of the 1997 8-hr ozone standard. Moreover, there are only one or two monitors out of 12 monitors in the DFW area that have a design value above the standard and these two monitors are not substantially impacted by Louisiana emissions within the meaning of the ?good neighbor? clause of Section 110(A) of the Clean Air Act. The ozone design values have steadily dropped in the DFW area and that area is subject to additional state and federal controls that are projected to achieve attainment without the Transport Rule. As EPA's own projections indicate that ozone season NOx emissions from Louisiana EGUs will decline by 2012 even without the Transport Rule/FIP, there is no legal basis for imposition of a FIP. Dow requests that EPA delete the ozone season NOx requirements from the proposed rule and FIP for Louisiana EGUs with respect to the DFW area.  [EPA-HQ-OAR-2009-0491-2775.1 p.2]
Response: 
1) The final rule modeling included many emissions inventory updates in both Louisiana and Texas.  Details on these updates can be found in preamble section V.C.1 and the Transport Rule   Emissions Inventories RTC document.
2) The analysis for the final rule does not identify Harris County TX as a PM2.5 nonattainment or maintenance receptor in 2012, or identify Louisiana as a state with emissions that significantly contribute to nonattainment or interfere with maintenance of either PM2.5 NAAQS.  EPA does not agree with all of the arguments for why Harris County should not have been considered a receptor in the proposal. 
3) The final rule modeling identifies Louisiana as a state with emissions that contribute significantly to nonattainment and interfere with maintenance of the 8-hr ozone NAAQS in Houston, TX.  Since there are no nonattainment or maintenance receptors in Dallas in the final rule, Louisiana does not contribute to Dallas.  Commenters claim that due to more recent ozone data showing attainment in Houston, Louisiana should not be linked to Houston.  We disagree with this comment.  There are several reasons why recent monitoring data should not and cannot be used to determine the nonattainment and maintenance receptor status for consideration under the Transport Rule.  Please see preamble section V.C.2 for details.
Organization: Duke Energy
Comment: 
Duke Energy
The Method EPA Used To Determine "Interference With Maintenance" in the Proposed Rule Overestimates Actual Future Design Values
The method that EPA used in the Proposed Transport Rule to identify downwind monitors to be included in its "interference with maintenance" analysis overstates actual future design values, probably by a substantial amount. EPA explains in the preamble to the proposed rule that it determined maintenance sites based on the future-year maximum design values, and nonattainment sites based on future-year five-year weighted average annual design values. By using the future-year maximum PM2.5 design values as the basis for the "interference with maintenance" analysis, EPA fails to take account of the strong nationwide trend toward decreasing design values and improving air quality, which the Agency has said it expects to continue. This approach had a major effect on the design of the proposed rule. EPA should revisit its method for identifying downwind maintenance problems and revise its analysis to make it more representative of current and likely future air quality and to take account of the downward trend in design values. [EPA-HQ-OAR-2009-0491-2689.1, p.14]
Response: 
See preamble section V.C.2.
Organization: E.ON U.S.
Comment: 
E.ON U.S.
The Midwest Ozone Group (MOG) retained Alpine Geophysics to conduct CAMx modeling to predict the impact of these recently installed controls on ambient ozone and PM2.5 levels. This modeling is described in detail in the comments submitted by MOG. [EPA-HQ-OAR-2009-0491-2797.1, pp.4-5]
Response: 
See preamble section V.C.2.
Organization: Florida Electric Power Coordinating Group, Inc. (FCG)
Florida Municipal Electric Association (FMEA)
Comment: 
Florida Electric Power Coordinating Group, Inc. (FCG)
In the proposed rule, EPA includes Florida in the ozone portion of the rule, in part, due to its 'maintenance' impact on Harris County, Texas. Specifically, two receptors in this single county register contributions from Florida of 0.8000 and 2.1780. How can two different receptors in a single county show such dramatically different contributions? The FCG has not had time, due to the abbreviated and insufficient comment period, to understand the cause of these results, and whether it indicates a fundamental flaw or problem with EPA's modeling. At the very least, given the close proximity of the sites to each other and their similar distance relative to Florida, the difference in contribution results suggest that EPA's approach to calculating contributions is not very stable. The FCG requests that EPA explain and justify this result. [EPA-HQ-OAR-2009-0491-2658.1, p.11]
Florida Municipal Electric Association (FMEA)
In the proposed rule, EPA includes Florida in the ozone portion of the rule, in part, due to its "maintenance" impact on Harris County, Texas. Specifically, two receptors in this single county register contributions from Florida of 0.8000 and 2.1780. How can two different receptors in a single county show such dramatically different contributions? FMEA has not had time, due to the abbreviated and insufficient comment period, to understand the cause of these results, and whether it indicates a fundamental flaw or problem with EPA's modeling. At the very least, given the close proximity of the sites to each other and their similar distance relative to Florida, the difference in contribution results suggest that EPA's approach to calculating contributions is not very stable. The FMEA joins the FCG in requesting that EPA explain and justify this result. [EPA-HQ-OAR-2009-0491-2731.1, p. 10]
Response: 
The ozone (and PM2.5) contributions are calculated at each monitoring site individually.  For example, there are  3 ozone nonattainment and 2 ozone maintenance receptors identified in the Houston area in the 2012 base case.  The contributions from upwind states are calculated individually to each receptor.  Ozone contributions are calculated as the average contribution across all modeled days at the receptor (in 2012) that are above the 85 ppb NAAQS.  If there are no modeled days above the NAAQS, then we use the 5 highest modeled days.  
The commenters note that there is a large difference in the calculated contributions from Florida to two different receptors in Houston.  This is because the high modeled days at each receptor are different.  So the contributions are calculated across different sets of days.  The wind patterns were likely blowing from Florida to Houston on the particular set of high modeled days at the Houston receptor which had the larger contribution.  In most cases, upwind contributions to nearby receptors are similar.  But due to the unique set of high modeled days that exist at each receptor, the methodology can produce different contribution results even at nearby monitors.  EPA continues to believe that the contribution methodology is reasonable and appropriate, as applied in the final Transport Rule.
Organization: Louisiana Public Service Commission
Comment: 
Louisiana Public Service Commission
The LPSC Staff also questions the degree to which Louisiana is even eligible for the proposed CATR as the emissions data and emissions modeling utilized by EPA to arrive at this conclusion appears to be questionable. The LPSC Staff supports the comments and analyses provided by the LCA and LDEQ on this matter and recommends that the EPA remove Louisiana as one of the eligible states under the CATR. [EPA-HQ-OAR-2009-0491-2670.1, pp.6-7]
Response: 
In the final Transport Rule, Louisiana is found to contribute significantly to nonattainment and maintenance of the ozone NAAQS but not either PM2.5 NAAQS considered.  We received numerous comments and corrections regarding the Louisiana emissions inventories and have made updates as warranted.  Please see preamble section V.C.1 for more details. 
Organization: Maryland Department of Environment (MDE)
Comment: 
Maryland Department of Environment (MDE)
Maryland has spent years studying air pollution transport and found that it is an important driver in the development of unhealthy air in our state. Out of-state transport, much of it entrained into an elevated nighttime ozone reservoir from upwind areas, accounts for a notable proportion of ozone levels in Maryland. Our measured data shows that "incoming" ozone levels are routinely above 70 ppb. It is critical to have a strong Transport Rule so that air pollution carried into our state will be controlled and that reasonable local measures can achieve compliance with clean air standards. Despite past efforts of EPA and the OTC states, including Maryland, the only air pollution control options left in Maryland and the OTR are very difficult and highly expensive measures. Despite the difficulty and high costs, we have continued to adopt new local control measures. These decisions put Maryland and the region at a disadvantage with other regions of the country that are not required to institute similarly strong control measures. Therefore, it is essential that this Transport Rule fully achieves its primary mission and sets a sound precedent for future transport rules. [EPA-HQ-OAR-2009-0491-2639.1, p.2]
Further, Maryland also believes that the proposed transport rule does not anticipate and address the possibility that the federal remedy may not accomplish the elimination of significant contribution and interference with maintenance by the deadlines stipulated in the CAA. It is critical that the proposed rule provide a mechanism whereby an upwind state continues to engage with the downwind states it affects to pursue state remedies to fulfill its obligation under Section 110(a)(2)(D) of the CAA. In the September 2009 recommendation to EPA made by OTC, including Maryland, and the Lake Michigan Area Directors Consortium (LADCO), we outlined a process recommending that certain states contributing significantly to another state's nonattainment or interference with maintenance be involved in the SIP process of downwind states. [EPA-HQ-OAR-2009-0491-2639.2, p.3]
"Interference with maintenance" addresses historical variability in emissions. The proposed Transport Rule does a good job of addressing the impact of historical variability of air pollutant emissions on NAAQS attainment with its new definition of "maintenance sites." By calculating three design values based on five years of monitored data where the inventory year monitored data is given the most weight and using the maximum of these three to identify monitoring sites with maintenance problems, states that are barely in attainment can be aided by Transport Rule air pollutant reductions to stay in attainment. The number of maintenance sites identified for annual PM2.5, 24-hour PM2.5, and 8-hour ozone is generally a significant percentage of the number of nonattainment sites identified. This analysis highlights that a substantial number of areas are in danger of losing their attainment status, even under the 1997 (8-hour ozone and annual PM2.5) and 2006 (24-hour PM2.5) NAAQS. [EPA-HQ-OAR-2009-0491-2639.2, p.7]
Clarify that "Interference with Maintenance" methodology is different for upwind states' 110(a)(2)(D) obligations than downwind states' attainment designations. In the proposed Transport Rule EPA outlines an entirely new concept of modeling to identify areas projected to be in nonattainment or that may be at risk in their ability to maintain the standard due to contributions from upwind states. EPA uses a maximum design value based on a five-year period and the relative reduction factor (RRF) from model-based estimates of base and future year concentrations. We are concerned that the determinations using this method for purposes of identifying an upwind states' obligation under section 110(a)(2)(D) of the Clean Air Act (CAA) may cause confusion with the downwind site's attainment and maintenance determinations for its attainment SIP. Attainment determinations for areas in a state's SIP are calculated using a different methodology and EPA should clarify in the proposed Transport Rule that these are separate determinations with different purposes. We bring this to EPA's attention because MDE is concerned that the ozone and annual PM2.5 SIPs already submitted by the states to EPA could be in jeopardy since there are areas (monitors) that were shown to be in "model-based attainment" in those attainment SIPs that could potentially now be considered as areas at risk for interference with "model-based maintenance," per the methodology in the proposed Transport Rule. The implications of this are unknown at this time, but we are concerned that they could be severe. [EPA-HQ-OAR-2009-0491-2639.2, p.7]
Maryland urges that EPA revisit this issue and provide clarification in the proposed Transport Rule and/or propose guidance that addresses the issue of model-based maintenance as it is applied for section 110(a)(2)(D) purposes to avoid confusion with demonstration of model-based attainment for attainment SIPs. [EPA-HQ-OAR-2009-0491-2639.2, p.7]
Maryland encourages EPA to use the OTC-LADCO methodology regarding "areas of interest" as an alternative to EPA's proposed methodology. The September 2, 2009, OTC-LADCO recommendation offers a different method for determining areas of interest, which include areas projected not to meet the standard or struggling to maintain the standards. We urge EPA to revisit this recommended methodology as an alternative to that which is in the proposed Transport Rule. The OTC-LADCO recommendation proposes the use of both base monitored design values and future modeled design values above the applicable NAAQS as those that should be designated as areas of interest for purposes of addressing significant contribution and interference with maintenance. As noted in the OTC-LADCO letter, "the monitored design values are based on the maximum design value from the periods 2003-2005 through the most recent three-year period. Future modeled values are based on future year modeling which reflects legally enforceable control measures and a conservative model attainment test  -  i.e., use of maximum design values rather than average design values. The use of maximum design values and a conservative model attainment test are intended to account for historic variability, which is necessary to ensure maintenance. An alternative means of accounting for historic variability is to conduct a statistical analysis of the year-to-year variation in meteorology." [EPA-HQ-OAR-2009-0491-2639.2, p.8]
Maryland suggests that the same weighted five-year average be used for both nonattainment and interference-with-maintenance projections. If that approach is used, it would seem reasonable to proceed as follows: (a) use different future years for the determination of attainment or interference with maintenance (maintenance should come after attainment), and/or (b) use a different threshold for the determination of attainment (level of NAAQS) vs. the determination of interference with maintenance (e.g. 95% of level of NAAQS), making sure to reconcile these different thresholds with the "weight of evidence" concept described in the modeling guidance. [EPA-HQ-OAR-2009-0491-2639.2, p.17]
Finally there are several issues involved in the calculation of design values, including the potential disconnection between observed and modeled PM2.5 values, the lack of proposed alternatives to the use of the RRF factor, and the location of monitors excluded from the analysis. These questions need to be answered. [EPA-HQ-OAR-2009-0491-2639.2, p.17]
As mentioned above under "3. Significant Contribution and Interference with Maintenance," in the proposed Transport Rule EPA has outlined an entirely new concept of modeling to quantify interference to maintenance for an area by selecting the use of maximum design value based on a five year period and the RRF from model-based estimates of base and future year concentrations. [EPA-HQ-OAR-2009-0491-2639.2, p.17]
Response: 
There are several comments to address:
1) The final Transport Rule identifies states that contribute significantly to downwind nonattainment and/or maintenance of the 1997 ozone, 1997 PM2.5 and 2006 PM2.5 NAAQS and promulgates FIPs which prohibits all emissions identified as significantly contributing to nonattainment or interfering with maintenance of one or more of those NAAQS. There is no interactive process established by the statute for upwind and downwind states to engage which each other to inform the downwind states' SIP.  While discussion and cooperation between states are always encouraged, EPA is not at this time creating a formal process for discussion amongst states on section 110 SIP issues.
2) We agree that the methodology used in this rule to identify maintenance receptors and emissions that interfere with maintenance of a specific NAAQS in another state only applies within the scope of Section 110(a)(2)(D).  This rule is not intended to alter the obligations of downwind states with regard to  the attainment and maintenance determinations required for their attainment SIPs, or to alter the methodology to be used by EPA to evaluate whether attainment SIPs are approvable.
3) The identification of maintenance receptors in the final Transport Rule was based on projections of the maximum design value from the 2003-2007 base period.  This is a very similar approach to the technique recommended in the OTC/LADCO letter to EPA.  EPA determined that it was not appropriate to examine more recent air quality data to determine whether ambient data sites should or should not be nonattainment or maintenance receptors under the Transport Rule, as such data would inappropriately reflect emission reductions under the remanded Clean Air Interstate Rule that this rule must replace.  Please see preamble section V.B for explanation of EPA's baseline analyses for the Transport Rule, and please see preamble section V.C.2 for more details regarding recent air quality data.
4) EPA determined that the methodology used to define maintenance is reasonable and appropriate for the reasons explained in section V.C.2 of the preamble to the final rule. 
Organization: Midwest Ozone Group
Comment: 
Midwest Ozone Group
The principal focus of these comments is on air quality and modeling analyses that have been conducted on our behalf. These analyses demonstrate that the transport rule as currently proposed is not needed to address its stated air quality objectives. In these comments we will show that EPA has failed to account for the dramatic improvements that have occurred in air quality in recent years, and has failed to recognize how much air quality will improve in the future as the result of on-the-books [OTB] controls. Had EPA properly undertaken this analysis it would have learned that these existing controls applied to the areas we examined are more than sufficient not only to have eliminated "significant contribution," but also, with the exception of two monitors impacted by local sources, to have achieved attainment of both the ozone and PM national ambient air quality standards [NAAQS] that both this proposed rule and the original CAIR rule were intended to help achieve. [EPA-HQ-OAR-2009-0491-2809.1, p.2]
The most recent air quality data indicate substantially fewer nonattainment and maintenance areas than EPA's data. [EPA-HQ-OAR-2009-0491-2809.1, p.9]
At MOG's request ENVIRON examined EPA's list of nonattainment and maintenance monitoring sites for 2012 as defined in the proposed CATR to determine which of these sites were actually already in attainment of the NAAQS based on observations from 2006-2009. These results are set forth in an attachment to these comments. [See p.15 of this comment summary for the ENVIRON report] Sites already in attainment based on these most recent data represent locations where transport from upwind sources is not contributing to nonattainment or maintenance problems. In performing this comparison, ENVIRON used design values [DVs] calculated from annual summary statistics (e.g., annual fourth highest daily maximum 8-hour average ozone concentration) for 2006-2009. In some cases, insufficient data were available from which to compute the annual summary statistic. In these cases, ENVIRON used procedures for filling in missing data similar to those used by EPA for computing air quality trends. This is a conservative approach within the context of this analysis as DVs based on filled-in data may suggest a monitoring site is a nonattainment or maintenance site whereas MATS does not contain a DV for the monitoring site. [EPA-HQ-OAR-2009-0491-2809.1, p.9]
Total counts of nonattainment and maintenance monitoring sites based on EPA's 2012 projections in the proposed CATR versus nonattainment and maintenance sites determined from 2006-2009 data are provided in Table 1 [See p.22 of this comment summary for Table 1] of the attachment. These results show that over 80% of the sites predicted by EPA to be in nonattainment of the ozone or PM2.5 standards in 2012 are already in attainment as of 2009 based on an average of the 2006-2008 and 2007-2009 DVs. Furthermore, over 80% of the PM2.5 2012 maintenance sites and 1/3 of the ozone 2012 maintenance sites are no longer maintenance sites as of 2009. These results indicate that air quality has improved more rapidly than predicted by EPA's proposed CATR modeling. [EPA-HQ-OAR-2009-0491-2809.1, p.9]
Residual nonattainment in Allegheny County, PA and Brooke, WV cannot support a new or revised transport rule. [EPA-HQ-OAR-2009-0491-2809.1, p.12]
Only Allegheny PA and Brooke, WV remain in nonattainment with the 24-hr PMNAAQS in 2014 and only the Allegheny monitor is in nonattainment with the annual PMNAAQS in 2014. The fact that nonattainment has been eliminated at all other monitors in the 12km domain examined by Alpine Geophysics is enough to defeat the need for a 32 state transportrule. An examination of the details of the two monitors also fails to justify the implementation ofthe proposed transport rule. [EPA-HQ-OAR-2009-0491-2809.1, p.12]
It is apparent that the Liberty PM monitor is the focus of the Allegheny Countynonattainment and it is equally apparent that that monitor is not a regionally-representativemonitor. It appears that a combination of local sources and topographically-influencedmeteorology is the cause of the concern. Particularly telling are the timeline graphs in Figures13-1 and 13-2 on pages 71 and 72 of the Allegheny County SIP, in which the Liberty designvalues have been consistently, year after year, 3 to 6 ug/m3 greater than those at the surroundingsites. Table 13-1 on page 81 shows that this behavior continued into 2009. [EPA-HQ-OAR-2009-0491-2809.1, p.12]
EPA itself has recognized concerns about this monitor. For purposes of PM2.5 transport,the residual non-attainment in Allegheny County, PA is irrelevant because the air qualityproblem is local. See 75 Fed. Reg. at 45281/1 ("the monitor in Allegheny County that remains innonattainment is in an area where the air quality problem is primarily local"). AlleghenyCounty's air quality problems are due to emissions from a coke production facility and othernearby sources. See id. 45281/3 ("For this receptor monitor, EPA considered the localcircumstances in the Liberty-Clairton area in Allegheny County that were leading to continuednonattainment. [EPA-HQ-OAR-2009-0491-2809.1, p.12]
It is well-established that the Liberty-Clairton area is significantly affected by local emissions from a sizable coke production facility and other nearby sources. Seehttp://www.epa.gov/pmdesignations/2006standards/final/TSD/tsd_4.0_4.3_4.3.3_r03_PA_2.pdf. High concentrations of organic carbon indicate the unique local problem for this location."). Allegheny PM2.5 design values are very strongly dependent on organic carbonaceous matter (OMC) concentrations -- about 45% of the 2008 annual DV and 66% of the 2008 daily DV, and 51% of the 2018 annual DV and 70% of the 2018 daily DV are due to OMC. No other site comes close to these proportions of OMC making the Allegheny results unique. To show how important OMC is, if the Allegheny OMC values were replaced by the second highest OMC values in that we determined for any other monitor, Allegheny would be in both annual and daily attainment in 2018. If Allegheny had OMC levels at the average of all sites, it would be in attainment as early as 2008. [EPA-HQ-OAR-2009-0491-2809.1, p.12]
With regard to the Brooke County WV monitor, the residual non-attainment is related only to 24-hr PM. The Brooke County monitor presents a number of anomalies. For example, on the PM-2.5 Technical Support Document, CES values for Jefferson County were 100, for Hancock were 60 and for Brooke were 19. It is puzzling that the Brooke monitor would be so much slower to show air quality improvement compared with its neighbors when it theoretically should have been much closer to attainment in the first instance. In addition, it should be noted that the monitor sits on the border of Brooke and Hancock counties and should therefore be representative of Hancock County; however, there is also a Hancock monitor in the study and that is modeled to show attainment. [EPA-HQ-OAR-2009-0491-2809.1, p.13]
In Brooke County, all pollutants are dominated by a carbon manufacturing facility, an iron and steel mill and a ferroalloy manufacturing facility about 2 miles from the violating monitor. The location of the sampler relative to these local sources is an important consideration. The FRM sampler characterizes the impacts of that source. The monitor is therefore not likely to be representative of any larger geographic area. [EPA-HQ-OAR-2009-0491-2809.1, p.13]
Accordingly, while Allegheny PA and Brooke WV show residual PM nonattainment, it is apparent that such an isolated circumstance cannot be used to sustain the proposed 32 state transport rule particularly in absence of more widespread nonattainment. [EPA-HQ-OAR-2009-0491-2809.1, p.13]
By no later than 2014, all ozone nonattainment areas achieve attainment, all annual PM2.5 nonattainment areas except Allegheny County, PA, achieve attainment, and all 24-hour PM2.5 nonattainment areas except Allegheny County, PA, and Brooke County, WV achieve attainment,and by 2018, these areas remain in attainment. Plainly, the additional stringent emission reductions EPA is proposing are not needed to achieve attainment and maintenance of the applicable NAAQS. Because the nonattainment issue for Allegheny County, PA and Brooke County, WV is local and not transport-related, and because all other areas achieve attainment no later than 2014, the underlying rationale for a transport rule intended to prohibit significant contribution to nonattainment is soon to be a largely academic issue that no longer needs to be addressed for the 1997 ozone and PM NAAQS or the 2006 24-hour PM2.5 NAAQS. [EPA-HQ-OAR-2009-0491-2809.1, p.13]
Response: 
For responses related to the MOG modeling analysis and contention that emissions reductions beyond CAIR are not needed, see preamble section V.C.2.
With respect to residual nonattainment in Brooke, WV and Allegheny, PA, EPA's final rule modeling results differ from the MOG analysis.  In EPA's analysis of the final rule, Allegheny, PA remains a nonattainment and maintenance receptor throughout the analysis, but Brooke, WV comes into attainment in the EPA 2014 remedy modeling case.  See preamble section VI.C.3. for details on the analysis of receptors using the Air Quality Analysis Tool and preamble section VI.D.1. for the multi-factor analysis to determine the air quality and cost stopping point.  The analysis considered residual nonattainment and maintenance at each of the PM2.5 and ozone receptors.
With respect to the local contribution of PM2.5 at some receptors.  While some monitors may have relatively large local contributions of primary PM2.5, all of the nonattainment and maintenance receptors identified in this rule have important contributions from out-of-state PM2.5.  EPA examined the percentage of upwind vs. in-state sulfate plus nitrate that was estimated by CAMx source apportionment for each site in 2012.  The results of this analysis are contained in the air quality modeling technical support document. The upwind state contribution threshold in the Transport Rule is 1% of the NAAQS.  If an upwind state contributes more than 1% of sulfate plus nitrate to a downwind receptor, then they are evaluated further to determine whether they have emissions reductions available at specific cost thresholds.  As noted in preamble section VI.D.1, the Liberty/Clairton area in Allegheny, PA is the only monitoring site which EPA has singled out as having a uniquely large local PM2.5 contribution.  For the reasons explained in section V.C.2. of the preamble, the methodology used to identify nonattainment receptors is both reasonable and appropriate for use in this rule.  This methodology identifies the Liberty/Clairton monitor as a nonattainment receptor.
Organization: National Mining Association (NMA)
Comment: 
National Mining Association (NMA)
EPA Should Use the "Monitored-Plus-Modeled" Approach
Departing from its approach in the NOX SIP Call and CAIR, the proposed rule does not use a combination of monitored and modeled data to determine the downwind nonattainment areas that must be addressed under the rule. Instead, it uses only modeled data. This departure from the approach used in the two previous rules is not explained. The previous approach, however, was preferable because the purpose of the Transport Rule is to remedy real world nonattainment, not hypothetical nonattainment shown by a model. EPA should either return to its previous approach or explain its reasoning for the new approach. [EPA-HQ-OAR-2009-0491-2868.1,p.19]
Response: 
Please see preamble section V.C.2. for our response to comments on this issue.
Organization: Nebraska Public Power District
Omaha Public Power District
Comment: 
Nebraska Public Power District
8) Failure to Show Significant Contribution During Predicted Violation Episode. The basis for establishing a significant contribution by upwind states is seriously flawed. When conducting permit-related dispersion modeling, EPA's long-standing rules and guidance proscribe that for a given source to be considered to "contribute" to a modeled violation, the following conditions must be met. [EPA-HQ-OAR-2009-0491-2711.1, p.7]
a. There must be a predicted violation of the relevant NAAQS, considering the sum of all modeled sources' impacts, plus background (non-modeled sources).
b. The source of interest must contribute significantly during the episode(s) of predicted violation. [EPA-HQ-OAR-2009-0491-2711.1, p.7]
EPA's modeling analysis for the proposed TR apparently satisfies the first condition above, but not the second. Simply modeling the "source of interest" (State of Nebraska, for example) and determining its maximum 24-hour PM2.5 impact at receptors in the Milwaukee nonattainment area does not answer the question of whether the State (group of sources in that state) contributed significantly during the 24-hour episodes for which measured or modeled violations would occur. [EPA-HQ-OAR-2009-0491-2711.1, p.7]
In this case, Nebraska is analyzed by EPA to co ntribute significantly to 24-hour PM2.5 concentrations in only the Milwaukee PM2.5 nonattainment area. Inspection of maximum state-by-state contributions at the five receptors in Milwaukee indicates that the top three contributing states for total sulfate plus nitrate 24-hour PM concentrations were Illinois, Wisconsin, and Indiana, in that order. These three states contributed over half the total sulfate plus nitrate PM at Milwaukee receptors, according to EPA's analysis. Based on geographic location, it is obvious that meteorological conditions conducive to emissions transport from these states into Milwaukee would carry little or no emissions from Nebraska. Thus, controlling Nebraska's emissions to attempt to bring Milwaukee into attainment would be fruitless, and is inconsistent with EPA rules and policy in applying dispersion models for NAAQS attainment demonstrations. EPA should consider that states "contribute" to predicted NAAQS violations only if contributions are "significant" during periods of predicted 24-hour PM2.5 violations. [EPA-HQ-OAR-2009-0491-2711.1, pp.7-8]
Omaha Public Power District
The basis for establishing a significant contribution by upwind states is seriously flawed. When conducting permit-related dispersion modeling, EPA's long-standing rules and guidance proscribe that for a given source to be considered to 'contribute' to a modeled violation, the following conditions must be met. a. There must be a predicted violation of the relevant NAAQS, considering the sum of all modeled sources' impacts, plus background (non-modeled sources). b. The source of interest must contribute significantly during the episode(s) of predicted violation. [EPA-HQ-OAR-2009-0491-2680.1, p. 4]
EPA's modeling analysis for the proposed TR apparently satisfies the first condition above, but not the second. Simply modeling the 'source of interest' (State of Nebraska, for example) and determining its maximum 24-hour PM2.5 impact at receptors in the Milwaukee nonattainment area does not answer the question of whether the State (group of sources in that state) contributed significantly during the 24-hour episodes for which measured or modeled violations would occur. [EPA-HQ-OAR-2009-0491-2680.1, p. 4]
In this case, Nebraska is analyzed by EPA to contribute significantly to 24-hour PM2.5 concentrations in only the Milwaukee PM2.5 nonattainment area. Inspection of maximum state-by-state contributions at the five receptors in Milwaukee indicates that the top three contributing states for total sulfate plus nitrate 24-hour PM concentrations were Illinois, Wisconsin, and Indiana, in that order. These three states contributed over half the total sulfate plus nitrate PM at Milwaukee receptors, according to EPA's analysis. Based on geographic location, it is obvious that meteorological conditions conducive to emissions transport from these states into Milwaukee would carry little or no emissions from Nebraska. Thus, controlling Nebraska's emissions to attempt to bring Milwaukee into attainment would be fruitless, and is inconsistent with EPA rules and policy in applying dispersion models for NAAQS attainment demonstrations. [EPA-HQ-OAR-2009-0491-2680.1, pp. 4-5]
EPA should consider that states 'contribute' to predicted NAAQS violations only if contributions are 'significant' during periods of predicted 24-hour PM2.5 violations. [EPA-HQ-OAR-2009-0491-2680.1, p. 5]
Response: 
There are two aspects of the comment to address. 
1) We disagree that the contribution analysis for the Transport Rule must conform to guidance related to permit-related dispersion modeling.  This is not a permit application and therefore that guidance is not appropriate.    Existing permit related rules and guidance don't directly apply to the analysis of contribution under Section 110(a)(2)(D). 
2) The contribution analysis for the Transport Rule is not limited to days in which violations were observed in Milwaukee.  We evaluate the significant contribution on the high modeled PM2.5 days at each receptor.  Conceptually this is very similar to the type of analysis outlined in the comments.  Specifically, for the 24-hr PM2.5 NAAQs, EPA evaluated the contributions from upwind states to downwind nonattainment and maintenance receptors (such as Milwaukee) on the modeled 10% highest PM2.5 days in each quarter.  The contributions were calculated based on which quarter the projected 98th percentile day occurred.  For example, if the 98th percentile occurred in quarter 1 in the first year (of the 5 year period), then the contribution for quarter 1 was calculated from each upwind state to that downwind receptor.  This was repeated for each of the 5 years and then the contributions were averaged to get the final contribution.  In most cases, the 98th percentile values occurred in multiple quarters over the 5 year period.
Organization: New York State Department of Environmental Conservation
Comment: 
New York State Department of Environmental Conservation
EPA's Analysis of Significant Contribution to Maintenance of the 1997 8-Hour Ozone NAAQS
EPA has proposed through the rulemaking an entirely new concept of modeling interference to maintenance for an area by selecting the use of maximum design value over a five-year period and the RRF from model-based estimates of base and future year concentrations. [EPA-HQ-OAR-2009-0491-2730.1, p.11]
By adopting this method, an area or a monitor that is shown to be in attainment in the future could easily fall under 'maintenance' resulting in potential nonattainment status. It is unclear as to what an area has to do if it fans under these conditions - it is in attainment but it is also at the same time under 'maintenance'. EPA has not addressed how this 'interference with maintenance' is to be mitigated under this rule. [EPA-HQ-OAR-2009-0491-2730.1, p.11]
Furthermore, under this policy, the 03 and annual PM2.5 SIPs that were submitted to the EPA will be in jeopardy as there are areas (monitors) that are shown to be in 'model-based attainment' that will now fall under 'model-based maintenance'. [EPA-HQ-OAR-2009-0491-2730.1, p.11]
We urge that EPA should revisit this issue and propose guidance that addresses the issue of model-based maintenance and not use the transport rule to establish policy that is inconsistent with demonstration of model-based attainment. [EPA-HQ-OAR-2009-0491-2730.1, p.12]
Response: 
The methodology used in this rule to identify maintenance receptors and emissions that interfere with maintenance of a specific NAAQS in another state only applies within the scope of Section 110(a)(2)(D).  This rule is not intended to alter the obligations of downwind states with regard to  the attainment and maintenance determinations required for their attainment SIPs, or to alter the methodology to be used by EPA to evaluate whether attainment SIPs are approvable.
Organization: Shell Chemicals
Louisiana Chemical Association (LCA)
Occidental Chemical Corporation (OCC)
PPG Industries, Inc.
Nelson Industrial Steam Company (NISCO)
Comment: 
Louisiana Chemical Association (LCA)
1. EPA proposes to include Louisiana under the rule and FIP for annual S02 and NOx reductions solely due to EPA's modeled projection that Louisiana emissions have a potential to interfere with maintenance of the annual PM2.5 NAAQS at one monitor in Harris County, Texas (the Clinton Drive monitor). This conclusion is based on projections by EPA that Louisiana emissions will contribute an estimated 0.34 ug/m3 to the annual design value for PM2.5 in calendar year 2012 at that monitor. Considering the imprecision of the estimates and assumptions inherent to the modeled projections, this is an extreme basis for requiring controls on Louisiana EGUs with the attendant costs to the citizens of Louisiana. This is particularly extreme given that the Clinton Drive monitor is currently in attainment at a 2009 design value of only 12.36 ug/m3, well below the 15 ug/m3annual standard. Further, Harris county has never been in nonattainment. There is no evidence that Louisiana emissions to date have interfered with maintenance of attainment at that monitor and, because EPA predicts that Louisiana's inventory of S02 and NOx emissions will decrease even without the Transport Rule and FIP, there is little reason to anticipate that Louisiana emissions will interfere with maintenance in the future. [EPA-HQ-OAR-2009-0491-1925.1, pp. 1-2]
Louisiana Emissions Do Not Interfere With Annual PM2.5 NAAQS Attainment in Texas and Louisiana Should Not Be Included In the Transport Rule or Federal Implementation Plan for Reductions of Annual SO2 or Annual NOx [EPA-HQ-OAR-2009-0491-3527.1, p. 2; see pp. 2-7 for extensive discussion of the following issues: Background, EPA Proposed Findings of Interferrence with Maintence of Annual PM2.5 NAAQS, and The Clinton Drive monitor in Harris County Texas is in Attainment and Permanent Improvements There Make Nonattainment Unlikely.]
EPA modeling shows that virtually the entire impact on PM2.5 annual levels at the Clinton Drive monitor are due to sulfate emissions. The following data, taken from EPA Preamble Tables IV.C-1, IV.C-3 and IV.C-5, and based on the IPM v.3.02 modeling, demonstrate that SO2 emissions from Louisiana will significantly decline, without enactment of the Transport Rule or a FIP: [EPA-HQ-OAR-2009-0491-3527.1, p. 10; see p. 11 for Table 1. SO2 Emissions in TPY-EPA IPM v3.02 Base Case Modeling.]
In summary, EPA's own modeling shows that without the Transport Rule/FIP, overall emissions of SO2 in Louisiana will decrease by 12,758 tpy from 2005 levels by 2012 and by 26,618 tpy from 2005 levels by 2014. As discussed above, Harris County, Texas is currently in attainment with the annual PM2.5 NAAQS and has a strong downward trend of PM2.5 emissions over the past several years. If Louisiana SO2 emissions are not causing interference with maintenance now, and are projected to have this significant of a decrease of SO2 without the Transport Rule, then it is not reasonable for EPA to conclude that Louisiana will interfere with maintenance of the PM2.5 standard in Harris County or that the Transport Rule/FIP is justified. If greater emissions are not affecting maintenance, then how can lesser emissions affe.ct maintenance? LCA believes that it would be arbitrary and capricious for EPA to arrive at this as a final conclusion. [EPA-HQ-OAR-2009-0491-3527.1, p. 11; see pp 12-14 for extensive discussion of this issue.]
EPA Modeling Is Insufficient to Demonstrate that Louisiana Emissions Significantly Contribute to Nonattainment With the Ozone NAAQS or Interfere With Maintenance of the 1997 8-Hr. Ozone NAAQS in Texas.
EPA Projections.
EPA modeling projected that Louisiana emission sources and/or activities significantly contribute to nonattainment at 5 monitors in the Houston-Galveston-Brazoria area of Texas and interfere with maintenance at 4 additional monitors in the HGB area. There were 5 monitors in the HGB area (two in Harris Co., and one each in Brazoria, Galveston and Montgomery Counties) where attainment was projected and there was no interference with maintenance by Louisiana sources. [EPA-HQ-OAR-2009-0491-3527.1, p. 32]
EPA IPM v. 3.02 Base Case modeling projected that Louisiana emission sources and/or activities would significantly contribute to nonattainment at one monitor in the Dallas-Ft. Worth Area and would interfere with maintenance at 3 additional monitors in the DFW area without CAIR or the Transport Rule/FIP. [EPA-HQ-OAR-2009-0491-3527.1, p. 32]
However, as discussed below, all monitors in the HGB area showed design values in attainment of the 8-hour standard in 2008 and continue attainment in 2009. LCA asserts that EPA therefore cannot make a finding that Louisiana emissions significantly contribute to nonattainment with the 1997 8-hour ozone standard with respect to the HGB area. Further, LCA believes that Louisiana emissions do not interfere with maintenance of the standard in the HGB area now, and will not likely do so in the future. The monitor in DFW that was projected to receive "significant contribution" from Louisiana sources is also now in attainment, with a design value of only 78 ppb. Further, two of the monitors allegedly projected to receive emissions from Louisiana that would interfere with maintenance have projected 2008-2010 design value of 67 and 78 ppb, well below the standard. The remaining monitor has a design value of 86 ppb, but as noted below, Louisiana emissions are no longer projected to have interference with maintenance at any of these monitors. [EPA-HQ-OAR-2009-0491-3527.1, p. 32; see pp. 32-35 for extensive discussion of EPA Projections.]
Nelson Industrial Steam Company (NISCO)
I. Louisiana Should Not Be Included in the Proposed Transport Rule
A. Louisiana Emissions Do Not Reasonably Interfere with the Ability of Harris County, Texas, to Stay in Attainment With the Annual PM2.5 NAAQS
Actual monitored empirical data show that Harris County, Texas, is currently in attainment with the Annual National Ambient Air Quality Standard ('NAAQS') for PM2.5. Further, Harris County has never been designated as being in nonattainment with that standard. EPA has projected through modeling for the proposed CATR/FIP that Louisiana emissions may interfere with maintenance of that NAAQS in 2012, by contributing only 0.34 ug/m3 to the annual PM2.5 values there. Of that total, EPA projects that 0.33 ug/m3 is from sulfate emissions and only 0.004 ug/m3 from nitrate emissions. Solely based upon these projections, EPA proposes to impose a FIP on Louisiana electrical generating units ('EGUs') to reduce their annual S02 and annual NOx emissions. NISCO strongly objects to EPA's projections and proposed FIP for these reasons: [EPA-HQ-OAR-2009-0491-2813.1, pp.2-3]
1. Any impact of Louisiana emissions on Harris County, Texas is less than any of the proposed EPA Significant Impact Levels ('SILs') for annual PM2.5 used under the Prevention of Significant Deterioration ('PSD') Program. By definition, any such impacts are de minimis. EPA would be arbitrary and capricious and/or abusing its discretion if it makes a finding of 'interference with maintenance' for a total projected Louisiana contribution that is less than one of these proposed SILs. [EPA-HQ-OAR-2009-0491-2813.1, p.3]
2. EPA's projection of reasonable interference was based on the IPM v. 3.02 Base Case modeling for 2012. On September 1,2010, EPA published a Notice of Data Availability for the IPM v. 4.10 modeling, including a revised TR Base Case 2012 scenario. Under the revised modeling, projected emissions of S02 are more than 20,000 tpy less than projected under the IPM v. 3.02 version. Based on this factor alone, it is believed that any revised air quality analysis based on the IPM v. 4.10 modeling will demonstrate no impact whatsoever on Harris Co. PM2.5 levels that could conceivably interfere with maintenance of attainment of the annual PM2.5 NAAQS. While NISCO has reservations about some of the other inputs to the IPM model, as discussed herein, NISCO believes that the v. 4.10 estimates rely upon a slightly more accurate forecasting of natural gas prices. For that reason, the v. 4.10 should be used to determine, at least as a· screening mechanism, the potential for significant contribution or interference with maintenance of a NAAQS. [EPA-HQ-OAR-2009-0491-2813.1, p.3]
3. EPA's own modeling shows that the reductions in estimated Louisiana emissions from the Transport Rule Base Case v. 3.02 to the Base Case v. 4.10 are greater than what EPA stated was needed to remove 'interference with maintenance' in Harris County, Texas. Reductions greater than the difference between the TR Base Case 2012 v. 3.02 and TR Limited Trading Option case should represent the amount necessary for a state to reduce emissions in order to remove significant interference or and interference with maintenance. [EPA-HQ-OAR-2009-0491-2813.1, p.3]
In the Preamble to the CATR/FIP, EPA stated:
A state's emissions budget is the quantity of emissions that would remain in that state from covered sources after elimination of that portion of each state's significant contribution and interference with maintenance that EPA has identified in today's proposal, before accounting for the inherent variability in power system operations... .In other words, it provides a quantity of emissions to use in developing a remedy (e.g., the remedy should be designed to achieve the budget in an average year. Because the budget represents emissions that would remain without accounting for variability, it also represents the amount of emissions that would remain after significant contribution and interference with maintenance have been addressed, in an average year. [EPA-HQ-OAR-2009-0491-2813.1, pp.3-4]
Thus, when the Base Case v. 4.1 0 projection shows a value below the budget, and a greater reduction than the difference between the Base Case v. 3.02 and the TR SB Limited Trading Option v.3.02, it is clear that significant contribution and interference no longer exist. [EPA-HQ-OAR-2009-0491-2813.1, p.4]
EPA's revised IPM v. 4.10 Base Case 2012 modeling shows that even without implementation of the CATR/FIP (or CAIR), reductions from Louisiana are already greater than those required reductions. The following table demonstrates this finding: [EPA-HQ-OAR-2009-0491-2813.1, p.4]
[The comparison table can be found on page 4 of this comment.]
Because 'significant contribution' and 'interference with maintenance' have been removed as shown by this revised IPM modeling, there is no basis for a CATR/FIP for annual SO2 or NOx control for Louisiana sources, as the level required to remove interference with maintenance will have already been achieved. [EPA-HQ-OAR-2009-0491-2813.1, p.4]
4. Due to the inherent uncertainty in the IPM modeling, as unmistakably illustrated by the material differences between IPM v. 3.02 and v. 4.10 projections, a projected impact of less than 2 ppb based on modeling should never be used as a level indicating 'significant contribution' or 'interference with maintenance' from an upwind to a downwind state under the 'good neighbor' provisions of the Clean Air Act, 42 U.S.C. 7410(a)(2)(D). The projected impact from Louisiana is well below 1 ppb. At most, the IPM should be used as a screening tool for making rebuttable presumptions for 'significant contribution' or 'interference with maintenance' determinations. However, such presumptions should be always subject to a reasonable opportunity for rebuttal by empirical evidence. [EPA-HQ-OAR-2009-0491-2813.1, p.5]
5. Empirical evidence demonstrates that Louisiana emissions will not interfere with the ability of Harris County, Texas, to maintain compliance with the annual PM2.5 NAAQS. The last two years have seen annual average PM2.5 emissions below 14.0. The 2010 design value for Harris Co. is projected to be below 14.0. The Texas Commission on Environmental Quality, together with state and local partners, have undertaken a number of permanent measures to reduce PM2.5 levels to a point where interstate transport does not affect their ability to maintain attainment. [EPA-HQ-OAR-2009-0491-2813.1, p.5]
6. EPA overestimated Louisiana emissions inventory used for making the projections, in both the IPM v. 3.02 and v. 4.10 models; thus, even the minimal contributions by Louisiana are likely grossly overstated. The primary reasons the inventories were overstated are:
:: EPA included a significant quantity of S02 and NOx emissions from commercial marine vessels in the Louisiana nonroad inventory that are actually from offshore, outside of the geographical jurisdiction for Louisiana and are thus not attributable to Louisiana under the Clean Air Act SIP requirements.
:: For all Class 3 commercial marine vessels, including those that are properly within Louisiana jurisdiction, EPA failed to include projected reductions of S02 and NOx emissions that will result from EPA marine engine regulations enacted in December 2009. In other words, not only are C3 commercial marine vessel emissions hundreds of miles offshore counted as being part of Louisiana's significance budget, even when not within Louisiana jurisdiction, they are overestimated because the full impact of the December 2009 rule were not included in the estimates. The same is true with respect to C3 CMV emissions that are within Louisiana jurisdiction.
:: EPA failed to include enforceable reductions from non-EGU federal consent decrees in Louisiana even where these were entered prior to the date of the proposal and require at least a portion of the enforceable reductions before 2012. [EPA-HQ-OAR-2009-0491-2813.1, p.5]
:: EPA failed to include the Louisiana NOx Reasonably Available Control Technology rule in LAC 33:III.Ch. 22 reductions of NOx in the modeling used to project future impact. As part of its comments, NISCO hereby adopts and incorporates by reference those comments on the proposed CATR and FIP made by the Louisiana Chemical Association ('NISCO'). NISCO supports such comments and urges EPA to carefully review such comments· prior to final rulemaking.
:: As indicated above, the contribution of Louisiana nitrate emissions to PM2.5 annual design value concentrations in Harris County, Texas, are infinitesimal - only 0.004 ug/m3. Even without the corrections to the inventory above, it would be arbitrary and capricious, and an abuse of EPA discretion, to regulate annual NOx levels from Louisiana sources to address this projected contribution. If there is interference with attainment, which is denied, then control of S02 alone should be all that EPA requires in a FIP. [EPA-HQ-OAR-2009-0491-2813.1, p.6]
B. Louisiana Emissions Do Not Significantly Contribute to Nonattainment With Nor Interfere With Maintenance of the 1997 8-hour ozone standard in the Houston/Galveston/Brazoria Area or the Dallas/Ft. Worth Area.
EPA has projected that Louisiana emissions will significantly contribute to nonattainment with the 1997 8-hour ozone NAAQS at certain monitoring sites in the Houston-Galveston-Brazoria ('HGB') and the Dallas-Ft. Worth ('DFW') Areas of Texas in 2012. EPA has projected that Louisiana emissions will interfere with maintenance of that NAAQS at other monitoring sites in the HGB and the DFW Areas of Texas in 2012. NISCO disputes those projections for the following reasons. [EPA-HQ-OAR-2009-0491-2813.1, p.6]
1. All monitors in the HGB Area are currently in attainment with the 1997 8-hour ozone NAAQS and have been since 2008, based upon the 2006-2008 monitoring data. This is actual empirical data showing attainment. All of the DFW monitors that EPA projected were adversely impacted by Louisiana emissions, save one, are currently in attainment with that NAAQS. The design value at the one monitor at issue in DFW is 86 ppb, just 2 ppb above the standard. Under both versions of the IPM base case modeling, Louisiana ozone season NOx emissions are projected to decrease even without the CATR/FIP (or CAIR). Thus, there is no basis for presuming that actual conditions, as shown through empirical monitored data, will worsen due to Louisiana emissions. [EPA-HQ-OAR-2009-0491-2813.1, p.7]
2. EPA's projections of significant contribution and reasonable interference at the HGB and DFW monitors were based on the IPM v. 3.02 Base Case modeling for 2012. On September 1, 2010, EPA published a Notice of Data Availability for the IPM v. 4.10 modeling, including a revised TR Base Case 2012 scenario. Under the revised modeling, projected emissions of ozone season NOx are 6,061 tpy less than projected under the IPM v. 3.02 version. Based on this factor alone, it is believed that arty revised air quality analysis based on the IPM v. 4.10 modeling will demonstrate no impact whatsoever on ozone design values in the HGB or DFW areas. As noted, while NISCO has reservations about some of the other inputs to the IPM model, as discussed herein, NISCO believes that the v. 4.10 estimates rely upon a more accurate forecasting of natural gas prices and that version should be used to determine, at least as a screening mechanism, the potential for significant contribution or interference with maintenance of a NAAQS. [EPA-HQ-OAR-2009-0491-2813.1, p.7]
3. EPA's own modeling shows that the reductions in estimated Louisiana ozone season NOx emissions from the Transport Rule Base Case v. 3.02 to the Base Case v. 4.10 are greater than what is needed to remove 'significant contribution;' and 'interference with maintenance' in Texas. As indicated above, a reduction greater than the difference between the TR Base Case 2012 v. 3.02 and TR Limited Trading Option, or a reduction below the allocated state budget, represents the amount necessary for a state to reduce emissions in order to remove significant interference or and interference with maintenance. EPA's revised IPM v. 4.10 Base Case 2012 modeling shows that even without implementation of the CATR/FIP (or CAIR), reductions from Louisiana are already greater than those required reductions. The following table demonstrates this finding: [EPA-HQ-OAR-2009-0491-2813.1, p.7]
[The table and additional comment can be found on page 8 of this comment.]
4. Due to the inherent uncertainty in the IPM modeling, as unmistakably illustrated by the material differences between IPM v. 3.02 and v. 4.10 projections, a projected impact of less than 2 ppb based on modeling should never be used as a level indicating 'significant contribution' or 'interference with maintenance' from an upwind to a downwind state under the 'good neighbor' provisions of the Clean Air Act, 42 U.S.C. 7410(a)(2)(D). At most, the IPM should be used as a screening tool for making rebuttable presumptions for 'significant contribution' or 'interference with maintenance' determinations. However, such presumptions should be always subject to a reasonable opportunity for rebuttal by empirical evidence. [EPA-HQ-OAR-2009-0491-2813.1, p.8]
5. EPA overestimated Louisiana emissions inventory used for making the projections, in both the IPM v. 3.02 and v. 4.10 models for the reasons stated in Section II.A, above; thus, even the minimal contributions of ozone season NOx by Louisiana emissions to Texas are likely grossly overstated. [EPA-HQ-OAR-2009-0491-2813.1, p.8]
Further, in support of the above principles and contentions, NISCO adopts and incorporates by reference the comments of the Louisiana Chemical Association in support of the conclusion that Louisiana emissions will not significantly contribute to nonattainment with the 1997 8-hour ozone NAAQS in the HGB or DFW areas in 2012 and will not interfere with maintenance of that NAAQS in those areas of Texas. [EPA-HQ-OAR-2009-0491-2813.1, p.8]
In summary, NISCO respectfully requests EPA to eliminate Louisiana from the scope of the CATR. In the alternative, and only in the event that EPA does not do so, NISCO requests that at a minimum, EPA revise its methodology for determination of significant impact and interference with maintenance to make its methodologies into presumptive screening tools only, while providing states and potentially affected entities a reasonable opportunity to provide objective empirical evidence concerning whether an upwind state actually makes significant contribution to a downwind state's nonattainment or interferes with attainment in the downwind state. NISCO also requests that EPA allow Louisiana reasonable opportunity, consisting of a full 18 months following a final rulemaking in this docket, within which to submit a SIP in lieu of the proposed FIP. [EPA-HQ-OAR-2009-0491-2813.1, p.13]
Occidental Chemical Corporation (OCC)
Louisiana and Texas Should be Excluded from the Final Transport Rule Louisiana is targeted under the proposed rule to reduce annual NOx and SO2 emissions in order to help Texas meet and maintain compliance with the annual 1997 PM2.5 NAAQS. Specifically, EPA finds that Louisiana emissions will impact one monitor in Harris County, Texas  -  the Clinton Drive monitor. OCC disagrees with EPA's finding that Louisiana sources interfere with Texas' maintenance of the 1997 annual PM2.5 NAAQS (15.0 μg/m3), based on all of the reasons set forth in the comments on the proposed rule submitted by the Louisiana Chemical Association ("LCA"), and OCC hereby adopts LCA's comments by reference. EPA's analysis is flawed. In particular, EPA overestimated Louisiana's emissions inventory, failed to account for enforceable emissions reductions occurring after February 2009, and relied on outdated maximum design value data (years 2003  -  2007) to project a 2012 design value greater than 15.0 μg/m3. However, more recent data available to EPA demonstrate that the design value at the Clinton Drive monitor is dropping, particularly when data from exceptional events is excluded, and will be well below the standard in 2012. EPA must take into consideration the more recent monitoring data, all of the recent local measures implemented to reduce PM2.5, and the fact that as of February, 2010, Harris County is considered to be in attainment for the PM2.5 NAAQS, as approved by EPA in April 2010. Given that this monitor is currently in attainment and is expected to stay in attainment, it is nonsensical for EPA to include Louisiana in the CATR on the basis of alleged significant contributions to the PM2.5 NAAQS or interference with maintenance of the NAAQS. Furthermore, given that EPA's proposed methodology projects that Louisiana sources' sulfate emissions will contribute only 0.337 μg/m3 and the sources' nitrate emissions will contribute a mere 0.004 mg/m3 to PM2.5 at the Clinton Drive monitor, it is arbitrary and capricious and an abuse of discretion for EPA to impose a costly cap-and-trade program on Louisiana EGUs under the CATR. [EPA-HQ-OAR-2009-0491-2754.1, p. 4]
In addition, EPA erred in targeting Louisiana to reduce ozone season NOx emissions in order to help Texas meet and maintain the 1997 ozone NAAQS with respect to certain monitors in the HGB and DFW areas. However, given that the HGB area is in attainment with the 1997 8-hr ozone NAAQS, as of the 2006  -  2008 time period, it is unreasonable for EPA to impose a FIP on Louisiana EGUs with respect to the HGB area. Furthermore, in the DFW area, the design value is just 2 ppb above the 1997 8-hr ozone NAAQS. Yet ozone design values are steadily dropping and additional enforceable controls are projected to have the area in attainment without any additional benefits from CATR reductions. OCC requests that EPA recognize the recent data and ongoing controls, and remove Louisiana sources from any CATR requirements targeting significant contributions to, or interference with maintenance of, the 1997 ozone NAAQS in any downwind state. [EPA-HQ-OAR-2009-0491-2754.1, p. 4]
EPA also erred in targeting Texas to reduce ozone season NOx emissions in order to help the Baton Rouge, Louisiana area achieve compliance with the 1997 ozone NAAQS. EPA has already determined that the Baton Rouge area is in attainment with the 1997 Ozone NAAQS. This is based on monitored attainment for the 2006  -  2008 and the 2007 - 2009 monitoring periods. Furthermore, EPA believes that "preliminary data available for 2010 is consistent with continued attainment." 75 Fed. Reg. 54778 (Sept. 9, 2010). Given the Baton Rouge attainment status, and the emissions inventory database corrections that EPA must make in promulgating a final CATR, as discussed by the Louisiana Chemical Association, EPA has no justifiable basis for including Texas in the interstate program and should exclude all sources in Texas from the final rule. [EPA-HQ-OAR-2009-0491-2754.1, p. 5]
PPG Industries, Inc.
 I. Louisiana Should Not Be Included in the Proposed Transport Rule.
A. Louisiana Emissions Do Not Reasonably Interfere with the Ability of Harris County, Texas, to Stay in Attainment With the Annual PM2.5 NAAQS. Actual monitored empirical data show that Harris County, Texas, is currently in attainment with the Annual National Ambient Air Quality Standard ('NAAQS') for PM2.5. Further, Harris County has never been designated as being in nonattainment with that standard. EPA has projected through modeling for the proposed CATR/FIP that Louisiana emissions may interfere with maintenance of that NAAQS in 2012, by contributing only 0.34 ug/m3 to the annual PM2.5 values there. Of that total, EPA projects that 0.33 ug/m3 is from sulfate emissions and only 0.004 ug/m3 from nitrate emissions. Solely based upon these projections, EPA proposes to impose a FIP on Louisiana electrical generating units ('EGUs') to reduce their annual SO2 and annual NOx emissions. PPG strongly objects to EPA's projections and proposed FIP for these reasons: [EPA-HQ-OAR-2009-0491-2763.1, pp. 1-2; see pp. 2-6 for extensive discussion of this issue.]
B. Louisiana Emissions Do Not Significantly Contribute to Nonattainment With Nor Interfere With Maintenance of the 1997 8-hour ozone standard in the Houston/Galveston/Brazoria Area or the Dallas/Ft. Worth Area.  EPA has projected that Louisiana emissions will significantly contribute to nonattainment with the 1997 8-hour ozone NAAQS at certain monitoring sites in the Houston-Galveston-Brazoria ('HGB') and the Dallas-Ft. Worth ('DFW') Areas of Texas in 2012. EPA has projected that Louisiana emissions will interfere with maintenance of that NAAQS at other monitoring sites in the HGB and the DFW Areas of Texas in 2012. PPG disputes those projections for the following reasons. [EPA-HQ-OAR-2009-0491-2763.1, p. 6; see pp. 6-8 for extensive discussion of this issue.]
Shell Chemicals
Louisiana Should Not Be Included in the Proposed Transport Rule
Shell believes that EPA's finding that Louisiana emission sources interfere with maintenance of the annual PM2.5 standard in Harris Co., Texas is erroneous, for the reasons stated in the comments submitted by the Louisiana Chemical Association on the proposed Transport Rule and FIP. Shell hereby adopts those comments by reference. The one monitor in Harris County allegedly impacted by Louisiana emissions is in compliance with the annual PM2.5 NAAQS and annual average emissions for the past two years have been below 14.0 ug/m3. As EPA's own projections indicate that SO2 and NOx emissions from Louisiana EGUs will decline by 2012 even without the Transport Rule/FIP, there is no legal basis for imposition of a FIP. Shell requests that EPA delete the annual SO2 and NOx requirements from the proposed rule and FIP for Louisiana EGUs. [EPA-HQ-OAR-2009-0491-2614, p.2]
Shell believes that EPA's finding that Louisiana emission sources significantly contribute to nonattainment and/or interfere with maintenance of the 1997 8-hour ozone standard in the Houston Galveston- Brazoria ('HGB') area and the Dallas-Ft. Worth ('DFW') area is erroneous, for the reasons stated in the comments of the Louisiana Chemical Association. Shell hereby adopts those comments by reference. The HGB Area is in attainment with the 1997 8-hr. ozone NAAQS and has been as of the 2006-2008 period. As EPA's own projections indicate that ozone season NOx emissions from Louisiana EGUs will decline by 2012 even without the Transport Rule/FIP, there is no legal basis for imposition of a FIP to control ozone season NOx with respect to the HGB Area. [EPA-HQ-OAR-2009-0491-2614, p.3]
The DFW Area design value is currently 86 ppb, just 2 ppb in excess of the 1997 8-hr ozone standard. Moreover, there are only one or two monitors out of 12 monitors in the DFW area that have a design value above the standard and these two monitors are not substantially impacted by Louisiana emissions within the meaning of the 'good neighbor' clause of Section 110(A) of the Clean Air Act. The ozone design values have steadily dropped in the DFW area and that area is subject to additional state and federal controls that are projected to achieve attainment without the Transport Rule. As EPA's own projections indicate that ozone season NOx emissions from Louisiana EGUs will decline by 2012 even without the Transport Rule/FIP, there is no legal basis for imposition of a FIP. Shell requests that EPA delete the ozone season NOx requirements from the proposed rule and FIP for Louisiana EGUs with respect to the DFW area. [EPA-HQ-OAR-2009-0491-2614, p.3]
Response: 
There are several related comments.
1) The final rule modeling included many emissions inventory updates in both Louisiana and Texas.  Details on these updates can be found in preamble section V.C.1 and Transport Rule Emissions Inventories RTC document.
2) The analysis for the final rule does not identify Harris County TX as a PM2.5 nonattainment or maintenance receptor in 2012, or identify Louisiana as a state with emissions that significantly contribute to nonattainment or interfere with maintenance of either PM2.5 NAAQS.  EPA does not agree with all of the arguments for why Harris County should not have been considered a receptor in the proposal. 
3) The final rule modeling identifies Louisiana as a state with emissions that contribute significantly to nonattainment and interfere with maintenance of the 8-hr ozone NAAQS in Houston, TX.  Since there are no nonattainment or maintenance receptors in Dallas in the final rule, Louisiana does not contribute to Dallas.  Commenters claim that due to more recent ozone data showing attainment in Houston, Louisiana should not be linked to Houston.  We disagree with this comment.  There are several reasons why recent monitoring data should not and cannot be used to determine the nonattainment and maintenance receptor status for consideration under the Transport Rule.  Please see preamble section V.C.2 for details.
Organization: South Carolina Department of Health and Environmental Control 
Comment: 
South Carolina Department of Health and Environmental Control 
Our first general concern with modeling in the proposed Transport Rule is that the downwind receptors seem at first glance to be in nonattainment because of local contributions, and we note a few of these possible local issues. According to the proposal, South Carolina is an upwind contributor for the 1997 fine particulate matter ("PM2.5") National Ambient Air Quality Standard ("NAAQS") to nonattainment in Bibb, Clayton, and Fulton Counties in Georgia.12 The Macon-Allied Chemical monitor in Bibb County is within 2 miles of a paper mill, a rail yard, and a mineral wool plant, and 24 miles from Plant Scherer, the fifth largest electric plant in the U.S. by 2008 summer capacity.13 This plant is such a significant contributor to air quality in Bibb County that the EPA brought the plant into the Bibb County nonattainment area for the 1997 PM2.5 NAAQS even though the plant is in neighboring Monroe County. The violating monitor in Clayton County, the Georgia DOT monitor, is 1 mile downwind from the Hartsfield Jackson International Airport, and less than 1 mile downwind from a quarry. The Fulton County monitor that the EPA predicts will cause the county to not attain the 1997 PM2.5 NAAQS, the Fire Station #8 monitor, is within 1 mile of the CSX Tilford Yard. [EPA-HQ-OAR-2009-0491-2677.1 p.5]
2008 summer capacity.13 This plant is such a significant contributor to air quality in Bibb County that the EPA brought the plant into the Bibb County nonattainment area for the 1997 PM2.5 NAAQS even though the plant is in neighboring Monroe County. The violating monitor in Clayton County, the Georgia DOT monitor, is 1 mile downwind from the Hartsfield Jackson International Airport, and less than 1 mile downwind from a quarry. The Fulton County monitor that the EPA predicts will cause the county to not attain the 1997 PM2.5 NAAQS, the Fire Station #8 monitor, is within 1 mile of the CSX Tilford Yard. [EPA-HQ-OAR-2009-0491-2677.1 p.6]
DHEC is not denying the role of interstate transport in causing nonattainment with NAAQS. We simply note that the nonattainment areas to which South Carolina is found to contribute most likely have local air quality problems. We offer these local issues as examples that may suggest a potential flaw in the modeling approach. We elaborate on that potential flaw in our next comment. [EPA-HQ-OAR-2009-0491-2677.1 p.6]
The Air Quality Modeling Technical Support Document includes a discussion of how the EPA predicted 2012 nonattainment, specifically how the modeling predicted the design values that would allow a determination of 2012 attainment status. Many of South Carolina's exceptional events are wildfires, which, in some cases, are severe enough to affect the design value of a monitor. Based on a comparison with DHEC data, one of the design values listed was incorrect. The 2006-2008 Ozone Design Values spreadsheet28 included an incorrect value, 0.08 ppm, for the Cowpens Monitor in Cherokee County (AQS Site ID 45-021-0002) in the "y2008max4" column. The value should be 0.079 ppm. The EPA could have only produced the incorrect value by ignoring the February 20, 2008, prescribed burn at the monitoring site, which the EPA  approved as an exceptional event in a letter to DHEC dated May 8, 2009. By using this flawed data, the process by which the EPA modeled 2012 nonattainment does not comport with the actual designation process. [EPA-HQ-OAR-2009-0491-2677.1 p.13]
Response: 
In the final Transport Rule, South Carolina is found to contribute to Atlanta for the annual PM2.5 NAAQS.  All of the nonattainment and maintenance receptors identified in this rule have important contributions from out-of-state sulfate and nitrate.  EPA examined the percentage of upwind vs. in-state sulfate and nitrate that was estimated by CAMx source apportionment for each site in 2012.  The results of this analysis are contained in the air quality modeling technical support document. 
 With respect to the local contribution of PM2.5 at some receptors.  While some monitors may have relatively large local contributions of primary PM2.5, all of the nonattainment and maintenance receptors identified in this rule have important contributions from out-of-state PM2.5.  EPA examined the percentage of upwind vs. in-state sulfate plus nitrate that was estimated by CAMx source apportionment for each site in 2012.  The results of this analysis are contained in the air quality modeling technical support document. The upwind state contribution threshold in the Transport Rule is 1% of the NAAQS.  If an upwind state contributes more than 1% of sulfate plus nitrate to a downwind receptor, then they are evaluated further to determine whether they have emissions reductions available at specific cost thresholds.  As noted in preamble section VI.D.1, the Liberty/Clairton area in Allegheny, PA is the only monitoring site which EPA has singled out as having a uniquely large local PM2.5 contribution.  For the reasons explained in section V.C.2. of the preamble, the methodology used to identify nonattainment receptors is both reasonable and appropriate for use in this rule.  This methodology identifies the Liberty/Clairton monitor as a nonattainment receptor.
Regarding exceptional events and 2008 air quality data in South Carolina; first, 2008 ambient data was not used in any way in the Transport Rule analysis.  Ambient data from the 2003-2007 period was projected to the future years of 2012 and 2014.  The 2012 "no-CAIR" case projections were used to determine the nonattainment and maintenance receptors for the rule.  Second, exceptional events are removed from the ambient data only where data has been flagged by the state and the flag(s) has been concurred by the appropriate EPA Regional office.  If the flagged data is not concurred, then it is not removed from the design value calculation.  For the final Transport Rule analysis, EPA used the latest official design values (with concurred exceptional event data removed) for the 2003-2007 period.  
Organization: Southern Company
Comment: 
Southern Company
G. The Method EPA Used To Determine 'Interference With Maintenance' in the Proposed Rule Overestimates Actual Future Design Values
The method that EPA used in the Proposed Transport Rule to identify downwind monitors to be included in its 'interference with maintenance' analysis overstates actual future design values, probably by a substantial amount. EPA explains in the preamble to the proposed rule that it determined maintenance sites based on the future-year maximum design values, and nonattainment sites based on future-year five-year weighted average annual design values. (Thus, all nonattainment sites were, in effect, also maintenance sites because the maximum design value is always higher than the five-year weighted average.) However, EPA provides no justification for choosing this particular methodology to determine maintenance sites. By using the future-year maximum PMZ.5 design values as the basis for the 'interference with maintenance' analysis, EPA fails to take account of the strong nationwide trend toward decreasing design values and improving air quality, which the Agency has said it expects to continue. One can logically assume that EPA attributes the improving air quality to recent ongoing emissions declines and expects air quality to continue to improve as further emissions reductions are made. [EPA-HQ-OAR-2009-0491-2864.1, p. 35]
This approach had a major effect on the design of the proposed rule. For example, EPA proposed to require certain states (the 'group 1 states') to meet additional 80z emission reduction requirements beginning in 2014, beyond the reduction requirements for 2012, because of perceived maintenance problems at six specific downwind monitors. Plotted in Figure XI-1 below are the 98th percentile design values for PM2.5 from 2003 to 200837 based on EPA's 2006200838 Design Value spreadsheet for PM2.5, available at http://www.epa.gov/oaqpsOOl/airtrends/pdfs/dvyrn25_2006_2008rev102809.x1s. The downward trend in design values at these six monitors is clear: [See EPA-HQ-OAR-2009-0491-2864.1, p. 36 for Figure XI-1.]
It is easy to see that basing a determination of a maintenance problem at anyone of these six monitors on the future-year maximum PM2.5 design value would almost inevitably overstate the air quality design value at that monitor and, based on the strong downward trend in design values, would most likely result in a false determination. There is no reason to believe that the trend that is apparent in the design values at these six monitors is unusual. In fact, a similar trend is likely to exist at most of the downwind monitors evaluated in the proposed rule. It is especially important for EPA to come up with a justifiable methodology for determining maintenance issues since EPA has placed the burden in its significant contribution analysis upon all sites eliminating any and all maintenance issues. Therefore, EPA should revisit its method for identifying downwind maintenance problems, justify its reasoning for choosing a particular method and revise its analysis to make it more representative of current and likely future air quality and to take account of the downward trend in design values. [EPA-HQ-OAR-2009-0491-2864.1, p. 36]
A more reasonable approach that EPA could have taken to determine maintenance is to, first; remove the trend in the data where air quality is improving over the five-year period, prior to determining the maximum 3-year design value. Briefly, this method would first determine the linear fit to the 5-year (2003-2007) air quality data, calculate the residual values from the difference between the linear fit and the observed values, and then add the residuals to the average of all five years of data (2003-2007 values). The result is an adjusted five year time series with no trend, but has the same average and the same five-year weighted mean design value as the original observations. The result would still capture the inter-annual variability in air quality at sites with improving air quality without biasing the result high for areas where emissions reductions are already resulting in air quality improvement, and would better identify sites where maintenance may be an issue. The plot in figure XI-2  [See EPA-HQ-OAR-2009-0491-2864.1, p. 37 for the Figure] below shows the effect of applying this methodology to the data at the six monitors shown in the previous plot. [EPA-HQ-OAR-2009-0491-2864.1, p. 36]
As can be seen, the downward slope at all of these sites has been removed, but the inter-annual variability remains. Table XI-4 below  [See EPA-HQ-OAR-2009-0491-2864.1, p. 38 for Figure] shows the estimated effect of applying this methodology to the projected 2012 base case Design Values for these six sites. These results are a more reasonable estimate of the threshold that may be necessary to maintain attaining air quality in that it eliminates an inadvertent penalty for having made real improvements in air quality through emissions reductions. Furthermore, it leaves a better estimate of inter-annual variability that would be due to inter-annual meteorological and/or emissions variability. [EPA-HQ-OAR-2009-0491-2864.1, p. 37]
3. EPA's Methodology For Determining Maintenance Design Values Leads to Unnecessary Emissions Reduction Requirements
One of the six monitors that required larger upwind emission reductions to have their 24-Hour PM2.5 nonattainment and maintenance issues resolved was monitor number 245100040 in Baltimore City, Maryland. Out of the six, this was the one monitor that the state of Georgia was projected to contribute significantly to in the 2012 base case and was, therefore, the basis for Georgia's classification as a Group 1 state. In Figure XI-1 six years of annual 98th percentile daily PM2.5 values have been plotted for this monitor, among others. The plot shows a clear, steady downward trend in the data. As discussed in Section XI-G, EPA's proposed Transport Rule approach of using the maximum 3-year design value from the 2003-2007 period for calculating 'maintenance' design values in the proposed Transport Rule is unjustified. Had EPA used a justified methodology, such as the approach we proposed in Section XI-G that eliminates a penalty where early emissions reductions are already contributing to improved air quality, EPA should have found that the nonattainment and maintenance issues at the Baltimore City, Maryland, monitor will be resolved in 2014 at $0 per ton; therefore, Georgia should have been determined to have achieved the requirements for the 'off ramp' and should be classified as a Group 2 state. [EPA-HQ-OAR-2009-0491-2864.1, p. 41]
In fact, the refined modeling for the Birmingham PM2.5 SIP, which was conducted by the Alabama Department of Environmental Management in accordance with EPA guidance on PM2.5 attainment modeling and includes local emissions reductions that EPA failed to consider in the refined Transport Rule modeling,43 shows that the Birmingham area will actually attain the annual PM2.5standard in 2012. Indeed, current air quality is showing that Birmingham is already close to having attaining air quality (i.e., 2007-2009 DV of 15.1 ug m-3). In addition, the significant contribution assessment conducted for the Transport Rule shows that Florida only contributes 0.1519 ug m-3 to the nonattaining Birmingham monitor in the 2012 base case, a concentration increment which is only 0.0019 ug m-3 above the significant contribution threshold of 0.15 ug m-3. [EPA-HQ-OAR-2009-0491-2864.1, pp. 42-43]
Response: 
For responses related to the maintenance methodology and recent ambient data, see preamble section V.C.2. 
The commenter also mentions that the proposal modeling showed that Georgia had a significant PM2.5 contribution to Birmingham and Baltimore, and Florida significantly contributed to Birmingham.  Birmingham is a nonattainment and maintenance receptor in the final rule 2012 "no-CAIR" base case.   In the final Transport Rule modeling, Georgia contributes to Birmingham for both annual and daily PM2.5.  In the final Transport Rule, Georgia is a "group 2" state for SO2.  Florida is not in the Transport Rule region for PM2.5.
Organization: State of Louisiana, Department of Environmental Quality
Comment: 
State of Louisiana, Department of Environmental Quality
2005 BASE YEAR
Comment: Predictions of nonattainment status made by using the 2005 base year emissions inventory are flawed. EPA must use monitoring data that corresponds with the receptors' current attainment/nonattainment status. [EPA-HQ-OAR-2009-0491-2655.1, p.1]
The EPA has determined that Louisiana, specifically the Baton Rouge 5-Parish Nonattainment Area, is in attainment for the 1-hour ozone National Ambient Air Quality Standard (NAAQS) as well as the 1997 8 hour ozone NAAQS. In its modeling efforts, EPA indicates that the receptor monitor will 'remain' in nonattainment for both 2012 and 2014, regardless of the implementation of the Transport Rule control measures. This prediction is flawed; the monitored data from this receptor has shown attainment with the 1997 8-hour ozone NAAQS since December 31, 2008 and continues through today, September 30, 2010. This EPA quality assured and quality controlled data must hold more value than the predictions resulting from the model runs, therefore EPA must analyze input data more thoroughly as well as model results, consulting with the states when anomalies arise. [EPA-HQ-OAR-2009-0491-2655.1, p.2]
LDEQ has worked closely with area industries, utilities, local governments, and environmental communities to bring this area into attainment. Based on these determinations of attainment, LDEQ has significant difficulty following the modeling efforts for this rule proposal, especially those maps that show the area of East Baton Rouge Parish as nonattainment for the 1997 8-hour standard in future years. [EPA-HQ-OAR-2009-0491-2655.1, p.2]
PM 2.5/ GROUP 2 S02
Comment: Louisiana has been included in this proposed rulemaking based solely upon data errors and without consideration of existing air quality conditions. We request that EPA re-evaluate their methodology and the data going into their decisions regarding this aspect of the proposed rule, and once all corrections are made, that EPA re-propose this rule so that states and affected facilities can make informed decisions. [EPA-HQ-OAR-2009-0491-2655.1, p.2]
After reviewing the proposed rule, the Emissions Inventory Technical Support Document (EITSD), and the results of the Integrated Planning Model (IPM), Louisiana firmly believes that it has been erroneously included in this rulemaking under the Group 2 S02 reduction tier based on the following: [EPA-HQ-OAR-2009-0491-2655.1, p.2]
A. According to the source apportionment modeling performed by EPA, Louisiana contributes just 0.34 Ilg/m3 to the Harris County, TX, PM2.5 monitor (AQS 482011035). According to documentation and correspondence between the Texas Commission on Environmental Quality and the EPA, this monitor is and has historically been in attainment for PM2.5. [EPA-HQ-OAR-2009-0491-2655.1, p.2]
B. While Louisiana was included in this portion of the proposed transport rule, Texas was not. LDEQ finds this proposal contradictory to the attainment designations that these states obtained for both the 1997 and the 2006 PM2.5 NAAQS. See Attachment A.
The document 'Impacts of the Proposed Transport Rule on Counties with Monitors Projected to have Ozone and/or Fine Particle Air Quality Problems' shows the East Baton Rouge monitor as violating for 2003-2007. In 2012, without the transport rule, the monitor is listed as maintenance. Then in 2014, with or without the transport rule, the area is listed as violating the standard again. Since the Baton Rouge area has already attained the 1997 ozone NAAQS, it appears that the requirements of the transport rule will have a significant negative impact on Louisiana.  [EPA-HQ-OAR-2009-0491-2655.1, p.4] 
Response: 
There are several related comments.
1) The comment related to use of the most recent ambient data is addressed in preamble section V.C.2.
2) EPA's methodology for identifying nonattainment and maintenance receptors is based on measured air quality at specific monitors, not on the designation status of an area.  EPA believes this approach is appropriate for the reasons explained in section [INSERT] of the preamble.  EPA does not believe it would be appropriate to rely on the designation status of an area.  The statute does not require EPA to do so. In fact, the statutory requirement that 110(a)(2)(D)(i)(I) SIPs be submitted within 3 years of promulgation or revision of a NAAQS would make it difficult to do so, suggesting that Congress did not intend 110(a)(2)(D)(i)(I) SIPs to be linked in any way to designation status.  Further, even areas that have never been in attainment or have been redesignated to attainment (including those where the majority of pollution comes from out of state) continue to be at risk for falling into nonattainment due to the impact of emissions from upwind states.  In the final rule analysis, however, Harris County, TX was not identified as a PM2.5 nonattainment or maintenance receptor in 2012. 
3) In the proposal modeling East Baton Rouge was found to be a nonattainment receptor in the 2012 and 2014 base cases as well as in the 2014 Transport Rule remedy case.  Any listing of the East Baton Rouge monitor as a maintenance only receptor is an error. 
4) EPA continues to believe that measured concentrations during the period 2003 through 2007 provide an appropriate air quality starting point for projecting future nonattainment and maintenance for the purposes of the Transport Rule (see preamble section V..C.2).  EPA has updated the air quality modeling platform based on comments (see preamble section V.D.2) and the results of the updated modeling for the 2012 base case combined with measured ozone concentrations during 2003 through 2007 continue to show that Baton Rouge is projected to be nonattainment of the ozone NAAQS in 2012 without CAIR or a rule to replace CAIR.  The Transport Rule remedy case (the modeling showing air quality following implementation of the Transport Rule) projects that, with the TR in place, Baton Rouge will attain the ozone NAAQS.  The Transport Rule modeling shows no negative impact in any area of Louisiana.
Organization: State of Wisconsin, Department of Natural Resources
Comment: 
State of Wisconsin, Department of Natural Resources
While EPA tries to take an overall cautious approach in the framework to model an assessment of projected maintenance, it falls short in regard to the identification of areas potentially sensitive to maintenance for the 1997 ozone standard. An improvement to that effort would include an enhanced sensitivity analysis using both modeled projections and weight of evidence regarding contributions to areas with Clean Data findings for ozone based on 2007-2009 but where there are not formally approved attainment SIPs. Such evaluations appear necessary in order to exclude states from the Ozone Season control program for NOx where they are shown through modeling to have major contribution to downwind ozone concentrations but are not included in the control region using the old ozone standard as a threshold for sensitive site selection. EPA may need to consider including additional sensitive receptor sites - at least as part of a first cut geographic picture for significant ozone contribution. This is most important for areas where meteorology and/or economic performance in the 2008-2009 timeframe was extremely non-normal (producing very low relative ambient concentrations) and may result in some states being added to a summer NOx program. We feel this evaluation would provide a smoother transition to an area likely to be incorporated under a new ozone standard. Regional assessments now indicate many more states would need to be included within an updated EGU remedy program (see SNPR recommendation in comment #4 above). [See EPA-HQ-OAR-2009-0491-2829.2, p.5 for comments pertaining to SNPR recommendation in comment #4; EPA-HQ-OAR-2009-0491-2829.2, p.6]
Response: 
It is true that an upwind state can have a large contribution to a receptor which does not violate the 85 ppb NAAQS, but may violate a future lower NAAQS level.  This final rule is limited to findings based on the 1997 85 ppb NAAQS, but the source apportionment results are available for all potential receptors (where a monitor with valid data is located).  The full suite of ozone and PM2.5 contribution results are available in the rule docket.
Organization: Tennessee Valley Authority (TVA)
Comment: 
Tennessee Valley Authority (TVA)
C. Issue: Receptors indicating non-attainment or maintenance problems where air quality problems are primarily local. [EPA-HQ-OAR-2009-0491-2782.1, p. 12]
TVA Comment: EPA rightly identified one receptor (Monitor ID 420030064 in Allegheny County Pennsylvania) as "... in an area where the air quality problem is primarily local", and concluded that going to a higher SO2 cost breakpoint for the Transport Rule was not warranted due to this receptor's PM2.5 non-attainment. [P. 42881] A review of the design value and maximum design value PM2.5 concentrations produced at the eight receptor sites having potential nonattainment or maintenance issues at $300/ton for SO2 and $500/ton for NOx using the EPA's Air Quality Assessment Tool methodology, indicates many of these receptor sites have unusually high readings compared to receptors in the same counties (see attachment 4). This suggests many of these receptors are located in areas where the air quality problems may be primarily local. For example, the highest receptor in Lake County Indiana is 8.6 micrograms per cubic meter higher than the average of all of the receptors in that county. [EPA-HQ-OAR-2009-0491-2782.1, p. 12]
In addition, given that the purpose of the transport rule is to mitigate the impact of upwind emissions that become well mixed while being transported, we strongly recommend that the Design Values and Maximum Design Values for the receptor sites in each county be averaged and that the upwind states' contributions be based on these averages. This methodology would more accurately reflect the upwind states' actual contribution to downwind nonattainment and interference; and also eliminate unusual outliers created by local conditions while preserving the intent of the Transport Rule to ensure states equitably bear the burden for reducing emissions. [EPA-HQ-OAR-2009-0491-2782.1, p. 12]
TVA recommends the EPA thoroughly assess receptor sites with indicated PM2.5 or Ozone nonattainment or maintenance problems, and eliminate from the Transport Rule cost analysis those sites that are primarily impacted by local air quality problems. [EPA-HQ-OAR-2009-0491-2782.1, p. 12]
Response: 
While some monitors may have relatively large local contributions of primary PM2.5, all of the nonattainment and maintenance receptors identified in this rule have important contributions from out-of-state PM2.5.  EPA examined the percentage of upwind vs. in-state sulfate plus nitrate that was estimated by CAMx source apportionment for each site in 2012.  The results of this analysis are contained in the air quality modeling technical support document. The upwind state contribution threshold in the Transport Rule is 1% of the NAAQS.  If an upwind state contributes more than 1% of sulfate plus nitrate to a downwind receptor, then they are evaluated further to determine whether they have emissions reductions available at specific cost thresholds.  As noted in preamble section VI.D.1, the Liberty/Clairton area in Allegheny, PA is the only monitoring site which EPA has singled out as having a uniquely large local PM2.5 contribution.  For the reasons explained in section [INSERT] of the preamble, the methodology used to identify nonattainment receptors is both reasonable and appropriate for use in this rule.  This methodology identifies the Liberty/Clairton monitor as a nonattainment receptor.
Organization: Texas Commission on Environmental Quality
Comment: 
Texas Commission on Environmental Quality
The TCEQ objects to Texas' inclusion in the Transport Rule program, based on significant flaws in the EPA's technical analysis for the program, and the fact that the one area to which Texas is linked for significant contribution to nonattainment (East Baton Rouge, LA) has recently been determined in attainment of the 1997 eight-hour ozone NAAQS by the EPA. [EPA-HQ-OAR-2009-0491-2857.2, p.1]
The technical analysis used to support Texas' inclusion in the Transport Rule ozone-season NOx trading program relies on incomplete data, flawed modeling, and modeling calculations contrary to actual monitored values.[EPA-HQ-OAR-2009-0491-2857.2, p.2]
The TCEQ finds that the EPA's use of the maximum baseline design value in determining maintenance areas to be inappropriate, unjustified, and inconsistent with EPA's own guidance regarding the determination of compliance with the 1997 eight-hour ozone standard [EPA-HQ-OAR-2009-0491-2857.1, p.2]
Technical Analysis Flaws
Using the maximum baseline design value (DV) is unjustified and inconsistent with the EPA's own modeling guidance for the 1997 eight-hour ozone standard, and inappropriately penalizes areas where air quality improved during the baseline period. [EPA-HQ-OAR-2009-0491-2857.2, p.6]
In Section IV.C.2.b (3) of the Transport Rule (75 FR 45252), the EPA adopted an ad hoc definition for 'maintenance areas' based on using the highest of the three design values including the fourth-highest ozone concentration from the base year (2005). This definition was apparently designed to address year-to-year variability of the design values by focusing on a 'worst-worst-case' scenario, despite the EPA's 1997 guidance that states 'the average of the three design value periods best represents the baseline concentrations, while taking into account the variability of the meteorology and emissions (over a five-year period).' On page 22 of Guidance on the Use of Models and Other Analyses for Demonstrating Attainment of Air Quality Goals for Ozone, PM2 .S, and Regional Haze (EPA-454/B-07-002, April 2007), the EPA specifically lists four candidate methods for calculating a baseline design value for use in attainment demonstrations, including using the maximum design value from the three design value periods encompassing the base year of the simulation. This choice (along with two other candidates) was rejected in favor of the average of these three design values. In its previous guidance, the EPA specifically recommends use of the average of the three design values (alternatively described as a weighted five-year average of fourth-highest concentrations) in attainment demonstrations. [EPA-HQ-OAR-2009-0491-2857.2, p.6]
Regardless, the application of this worst-worst-case approach is not appropriate for areas like Texas whose design values have dropped since 2005 as a result of emissions reductions and not merely due to meteorological variability. In these cases using the highest of three design values negates actual improvements in air quality and bases decision-making on obsolete and incomplete information. Additionally, the EPA provides no support for why this departure from established guidance is appropriate in the context of the proposed rule. [EPA-HQ-OAR-2009-0491-2857.2, p.6]
The modeling conducted by the EPA in support of the proposed Transport Rule significantly over-predict future ozone DVs
In Section IV.C.2.b (3) of the Transport Rule (75 FR 45252), the modeling that the EPA is relying on to determine the linkages between source regions (states) and receptors (monitors) is demonstrably flawed, at least for Texas. Adequate performance of the model is impossible to discern because the technical support documentation does not present a detailed air quality model performance evaluation. Only a few basic statistics are presented, e.g., normalized mean bias and normalized mean error, averaged over the entire domain for the entire period. Model performance for Texas, or for the areas potentially affected by Texas, cannot be determined to satisfy the basic parameters when so little performance data is provided. The lack of transparency for the air quality modeling makes further review and analysis difficult. With such costly and crucial decisions based on this modeling, the EPA should, at a minimum, meet the same rigorous standards that states must meet when developing their state implementation plans and the modeling support for any control strategy. [EPA-HQ-OAR-2009-0491-2857.2, pp.6-7]
Based on the information provided and a comparison of actual air quality data, the Transport Rule future-case ozone modeling for sites in Texas is clearly biased and should not be used to establish linkages involving Texas as a source region. In 2009, only three regulatory monitors in the State of Texas - all in the Dallas/Fort Worth area had monitored ozone design values greater than 84 ppb. Because of emission limits on industrial sources and a vehicle fleet that grows cleaner every year, any reasonable modeling application would be expected to predict 2012 design values at or below the 2009 levels. However, the EPA's model showed 2012 predicted design values that exceeded the 2009 actual design values for every monitor but one. Of the fifteen predicted 2012 nonattainment or maintenance sites in Texas, the 2012 prediction exceeded the 2009 reality by more than 5 ppb in ten cases, by over 10 ppb in six cases, and by over 15 ppb in two cases. These discrepancies indicate a fundamental and serious disconnect between the EPA's modeling and the true state of air quality in Texas. The consequences of the EPA's reliance on flawed modeling extend beyond the borders of Texas; since the EPA cannot predict reasonable future design values within Texas, its assessment of Texas' influence on other states is likely also invalid. The proposed rule is notably silent regarding the extreme bias of the modeling assumptions and overpredictions and the EPA's rationale in choosing the proposed approach. This silence effectively prohibits the public from participating in a review of the EPA's proposed approach. [EPA-HQ-OAR-2009-0491-2857.2, p.7]
In general, assigning Transport Rule category labels of 'nonattainment' and 'maintenance' to sites currently monitoring attainment of the 1997 eight-hour ozone standard (or any other standard) strictly on the basis of modeling is questionable at best, especially when the model is showing a distinct propensity towards over-prediction in the future case. The TCEQ recommends assigning these labels based on the smaller of a) the modeled future design value or b) the actual design value observed in the most current three-year period. Using such a procedure would ground the assignments much more firmly in reality. [EPA-HQ-OAR-2009-0491-2857.2, p.8]
The TCEQ is particularly concerned with the technical analysis that requires Texas' inclusion in the Transport Rule, given the comment above regarding the overprediction of design values and comment provided later in this document regarding the failure to consider existing NOx controls. Of note, on September 9, 2010, the EPA published final notice in the Federal Register of a determination that the Baton Rouge, Louisiana 1997 eight-hour ozone nonattainment area has attained the 1997 eight-hour ozone NAAQS (75 FR 54778). The reality of Louisiana achieving this standard has been acknowledged by the finalized determination of attainment for Baton Rouge. The EPA cannot rationally ignore real world, actual measurements in favor of an inaccurate, incomplete, and unsupported computer modeling simulation of future air quality. Since the single monitor which links Texas to a nonattainment area is itself showing attainment of the 1997 8-hour ozone standard, Texas should not have been included in the list of states contributing significantly to nonattainment. [EPA-HQ-OAR-2009-0491-2857.2, p.8]
Further, in Section IV.C-4.b of the Transport Rule (75 FR 45267), Texas is 'linked' to a single monitor as contributing to its nonattainment in 2012, specifically a monitor in East Baton Rouge Parish in Louisiana (Site ID 220330003; misidentified as 261210008 in Table V-6 of the modeling TSD). The problem with this assessment is that as of 2009, none of the monitors in the entire state of Louisiana showed design values greater than 80 ppb, yet EPA's modeling shows a predicted 2012 DV for Baton Rouge of 87.8 ppb. It is simply not reasonable to expect the design value for Baton Rouge to increase by nearly 8 ppb in a three-year period when emissions nationwide are decreasing. [EPA-HQ-OAR-2009-0491-2857.2, p.8]
The EPA's modeling over-predicts design values both in Texas and in East Baton Rouge, LA (the one area to which Texas is linked in the proposed rule). Of particular concern is the fact that Baton Rouge is currently monitoring well below the 1997 eight-hour ozone standard: with a 2009 design value of 80 parts per billion (ppb), and the EPA has just finalized a determination of the attainment for the area under the 1997 eight-hour ozone standard. Please refer to further analysis in the 'Technical Analysis Flaws' portion of our comments below. [EPA-HQ-OAR-2009-0491-2857.2, p.2; Comments pertaining to Technical Analysis Flaws can be found at EPA-HQ-OAR-2009-0491-2857.2, p.12]
Response: 
There are several comments that are addressed in the following response:
1) Pursuant to the court's decision in North Carolina, EPA must give independent meaning to the term "interfere with maintenance" as used in CAA section 110(a)(2)(D).  The methodology used in this rule to identify maintenance receptors and emissions that interfere with maintenance of a specific NAAQS in another state only applies within the scope of Section 110(a)(2)(D).  This rule does not  alter the obligations of downwind states with regard to  the attainment and maintenance determinations required for their attainment SIPs, or alter the methodology to be used by EPA to evaluate whether attainment SIPs are approvable..  For the Transport Rule, EPA identified a methodology which projects the maximum design value from the 2003-2007 period to a future year (2012) to identify maintenance receptors.  EPA continues to believe that this maintenance methodology (used for the final rule) is both reasonable and appropriate.
2) EPA has completed an expanded model performance evaluation using the predictions from the updated 2005 base year CAMx simulation conducted for the final Transport Rule.   This evaluation provides additional spatial and temporal performance results in response to comments.  The model performance results can be found in Appendix A of the Final Transport Rule Air Quality Modeling Technical Support Document.
3) EPA continues to believe that measured concentrations during the period 2003 through 2007 provide the appropriate air quality starting point for projecting future nonattainment and maintenance for the purposes of the Transport Rule (see preamble section V.C.2 for more details).  EPA has updated the air quality modeling platform based on comments (see preamble section V.D.2 for more details) and the results of the updated modeling for the 2012 base case combined with measured ozone concentrations during 2003 through 2007 continue to show that Baton Rouge is projected to be nonattainment of the ozone NAAQS in 2012 without CAIR or a rule to replace CAIR.  The updated analysis continues to show that emissions from Texas contribute to ozone in Baton Rouge by an amount that exceeds the 1 percent of the NAAQS contribution threshold employed for the Transport Rule, and that significant emission reductions are available from sources in Texas as the cost thresholds identified.  Thus, Texas is identified as a state with emissions that significantly contributes to or interferes with maintenance of the 1997 ozone NAAQS in another state. 
Organization: Utility Air Regulatory Group (UARG)
Comment: 
Utility Air Regulatory Group (UARG)
The Method EPA Used To Determine "Interference With Maintenance" in the Proposed Rule Overestimates Actual Future Design Values.
The method that EPA used in the Proposed Transport Rule to identify downwind monitors to be included in its "interference with maintenance" analysis overstates actual future design values, probably by a substantial amount. EPA explains in the preamble to the proposed rule that it determined maintenance sites based on the future-year maximum design values, and nonattainment sites based on future-year five-year weighted average annual design values. (Thus, all nonattainment sites were, in effect, also maintenance sites because the maximum design value is always greater than or equal to the five-year weighted average.) 75 Fed. Reg. at 45247/2-3, 45249/3, 45252/2-3. By using the future-year maximum PM2.5 design values as the basis for the "interference with maintenance" analysis, EPA fails to take account of the strong nationwide trend toward decreasing design values and improving air quality, which the Agency has said it expects to continue. See EPA's Trends Report at 1-2. One can only assume that EPA's expectation is based on expected continuing declines in emission levels and that the recent improving air quality has been largely driven by recent declines in emission levels resulting from controls. [EPA-HQ-OAR-2009-0491-2756.1, p.62]
This approach had a major effect on the design of the proposed rule. For example, EPA proposed to require certain states (the "group 1 states") to meet additional SO2 emission reduction requirements beginning in 2014, beyond the reduction requirements for 2012, because of perceived maintenance problems at six specific downwind monitors. Southern Company, a UARG member, plotted the 98th percentile design values for 24-hour PM2.5 from 2003 to 2008 based on EPA's 2006-2008 Design Value spreadsheet for 24-hour PM2.5, available at http://www.epa.gov/oaqps001/airtrends/pdfs/dv_pm25_2006_2008rev102809.xls. The downward trend in design values at these six monitors is clear: [EPA-HQ-OAR-2009-0491-2756.1, pp.62-63] [[See Docket Number EPA-HQ-OAR-2009-0491-2756.1, p. 63 for a the graph.]]
It is easy to see that basing a determination of a maintenance problem at any one of these six monitors on the future-year maximum PM2.5 design value would almost inevitably overstate the air quality design value at that monitor and, based on the strong downward trend in design values, would most likely result in a false determination. There is no reason to believe that the trend that is apparent in the design values at these six monitors is unusual. In fact, a similar trend is likely to exist at most of the downwind monitors evaluated in the proposed rule. It is especially important for EPA to set forth a justifiable methodology for determining maintenance issues since EPA's proposal in effect establishes elimination of all interference with maintenance as the driving factor for the PTR's emission reduction requirements. Therefore, EPA should revisit its method for identifying downwind maintenance problems, justify its reasoning for choosing a particular method, and revise its analysis to make it more representative of current and likely future air quality and to take account of the downward trend in design values. [EPA-HQ-OAR-2009-0491-2756.1, pp.63-64]
One alternative approach that EPA could take to determine maintenance issues would be to remove the trend in the data where air quality is improving over the five-year period, prior to determining the maximum three-year design value. Briefly, this method would involve determining the linear fit to the five-year (i.e., the 2003-2007) air quality data, calculating the residual values from the difference between the linear fit and the observed values, and then adding the residual values to the average of all five years of data (2003-2007 values). The result would be an adjusted five-year time series with no trend, which would have the same average and the same five-year weighted mean design value as the original observations. This result would still capture the inter-annual variability in air quality at sites with improving air quality without biasing the projected "maintenance" value upward for areas where emission reductions are already resulting in air quality improvement, and would better identify sites where maintenance may genuinely be an issue. The plot below shows the effect of applying this methodology to the data at the six monitors shown in the plot above. [EPA-HQ-OAR-2009-0491-2756.1, p.64] [[See Docket Number EPA-HQ-OAR-2009-0491-2756.1, p.65 for the plot graph.]]
As this plot depicts, the downward slope at all of these sites has been removed, but the inter-annual variability remains. Table VII-1 below shows the estimated effect of applying this methodology to the projected 2012 base case design values for these six sites. This approach provides a more reasonable estimate of the threshold that may be necessary for maintenance of attaining air quality, in that it eliminates an inadvertent penalty for having made progressive improvements in air quality through emission reductions. Furthermore, it provides a better estimate of inter-annual variability that would be due to inter-annual meteorological and/or emissions variability.[EPA-HQ-OAR-2009-0491-2756.1, p.65] [See Docket Number EPA-HQ-OAR-2009-0491-2756.1, pp.66 for the Table VII-I.]
Response: 
See preamble section V.C.2. for responses.
Organization: we energies
Comment: 
we energies
In fact, as a supporting point, EPA has recently released monitoring data that reflects reductions in ozone and PM2.5 emission precursors showing that more than 80 percent of monitoring sites projected by the EPA still to be out of attainment in 2012 for ozone or PM2.5 were already in attainment as of 2009. And, more than 80 percent of the PM2.5 maintenance sites and one-third of the ozone maintenance sites are no longer maintenance sites based on 2006-2009 data. [EPA-HQ-OAR-2009-0491-2629.1, p.2]
Response: 
Please see preamble section V.C.2. for a response to these issues.

IV.C. Air Quality Modeling Approach and Results

Organization: City of Springfield, Illinois, Office of Public Utilities
Comment: 
City of Springfield, Illinois, Office of Public Utilities
As a member of the Midwest Ozone Group ('MOG'), CWLP has become aware of the results of MOG's modeling and air quality analysis showing that the air quality objectives of the Transport Rule can be achieved without the implementation of any controls beyond the (AIR rule and other controls already required. CWLP supports and adopts by reference MOG's comments. [EPA-HQ-OAR-2009-0491-2635.1, p.3]
Response: 
See section V.C.2 of the preamble.
Organization: Detroit Regional Chamber
Comment: 
Detroit Regional Chamber
We are appreciative of the Agency's proposal to maintain some degree of flexibility in compliance with the rule. Nonetheless, we are concerned that the use of inaccurate assumptions with respect to current and future emissions has led to largely flawed estimates for the transport of NOx and SO2. If left uncorrected, this mistake could prove costly to our region's economy without an associated environmental benefit beyond what current regulatory requirements, along with several pending new regulations, are likely to provide. [EPA-HQ-OAR-2009-0491-2720.1, p.1]
Response: 
EPA took comment on the current and future emissions used for the proposed rule.   The current and future emissions used for the final rule reflect updates made in response to comments.  The specific changes made to the non-EGU emissions inventories for the final rule can be found in the Emissions Inventory Response to Comment Document.  Changes made to the EGU emissions inventory can be found in section XVIII.C. of the Final Transport Rule Response to Comment Document.
Organization: DTE Energy
Comment: 
DTE Energy
Air Quality Benefits Targeted by EPA can be Achieved by Existing Emission Reductions Required by CAIR
Very recent modeling results by Alpine Geophysics and analyses by Environ Corp. show that the air quality and public health benefits that EPA is targeting can be achieved through existing emissions reductions required by CAIR and other emission reduction requirements. EPA, the state environmental agencies and the regulated power sector can determine an appropriate schedule for additional emissions reductions that are needed that allows for implementation at a more reasonable cost. This collaborative approach with the EPA would be based on modeling that we believe would corroborate results similar to those produced by Alpine and Environ in the materials submitted to the docket with the MOG comments. [EPA-HQ-OAR-2009-0491-2851.1,p.3]
Alpine and Environ conclude, based upon 12 km modeling accounting for the most current emissions reductions inventory available and design values, that
:: The ozone objectives of the proposed Transport Rule can be achieved within the 12 km modeling domain no later than 2014 with no additional controls beyond those already required by CAIR and other on-the-books regulations;
:: The annual PM objectives of the proposed Transport Rule can be achieved within the 12 km modeling domain no later than 2014 with no additional controls beyond those already required by CAIR and other on-the-books regulations, with the possible exception of local controls being necessary at one Allegheny County, Penn., site;
:: The 24-hr PM objectives of the proposed Transport Rule can be achieved within the 12 km modeling domain no later than 2014 with no additional controls beyond those already required under CAIR and other on-the-books regulations, with the possible exception of local controls at sites in Allegheny County, Penn., and Brooke County, W.Va.; [EPA-HQ-OAR-2009-0491-2851.1,p.3]
:: More than 80 percent of monitoring sites projected by the EPA still to be out of attainment in 2012 for ozone or PM2.5 were already in attainment as of 2009 .
:: More than 80 percent of the PM2.5 2012 maintenance sites and one-third of the ozone 2012 maintenance sites are no longer maintenance sites based on 2006-2009 data. [EPA-HQ-OAR-2009-0491-2851.1,p.4]
Response: 
See section V.C.2 of the preamble.
Organization: Northern Indiana Public Service Company (NIPSCO)
Comment: 
Northern Indiana Public Service Company (NIPSCO)
EPA states in the preamble that it used the CAM-x model for CAIR and the CAM-x and CMAQ for CAIR. We believe EPA may have intended to state which model was used for the Transport Rule and request EPA clarify which model(s) were used for analysis of air quality impacts for development of the Transport Rule.  [EPA-HQ-OAR-2009-0491-2747.1 p.8]
In the preamble discussion of the air quality modeling, EPA mentions various items that affect the accuracy of the air quality modeling and air quality related analyses. The results of these analyses subsequently are used by EPA to determine significant impacts from one state on another and form the basis for the conclusions to set state-, and consequently, unit-specific emission allocations. We are concerned about a number of items affecting the analyses and the resulting conclusions identified below. [EPA-HQ-OAR-2009-0491-2747.1 p.8]
EPA discusses the use the MM5 meteorological pre-processor for input to the CAM-x and indicates bias and error values were generally within the range of past meteorological modeling results that have been used for air quality applications. The discussion is not specific as to whether these prior modeling results are for PSD permitting, SIP or CAIR development and do not compare these values to any EPA criteria or guidance, if these even exist. We question how the MM5 bias and error would alter the significant contribution values determined from the CAM-x and, as a consequence, how these could change the state, and ultimately the unit-specific emission budgets. [EPA-HQ-OAR-2009-0491-2747.1 p.9]
Response: 
EPA used CAMx as the air quality model for simulating ozone and PM2.5 for the Transport Rule.
Model performance for the 2005 MM5 meteorological model simulation was found to be in the range of MM5 applications of similar spatial and temporal scales for the years 2002, 2003, and 2004.  These simulations are not related to PSD modeling.
There is no EPA guidance with quantitative criteria for judging model performance for regional/national scale meteorological models nor are there procedures for quantifying with any certainty how bias and error in particular components individually or collective affect downstream uses of the results. Rather, the approach to gaining confidence in meteorological modeling results involves (1) using a state-of-the-science model for purposes consistent with the design and capabilities of the model, (2) comparing the predictions to available observations recognizing that both the predictions and the observations contains uncertainties and potential biases, and (3) confirming that the results of the evaluation are generally within the range of what has been found by the modeling community for applications over similar temporal and spatial scales.
A description of the evaluation for the MM5 application performed by EPA for 2005 for the Eastern US can be found at http:/www.epa.gov/scram001/meteorology/metgridmodeling/met.2005.12EUS1.pdf. Overall, the results indicate minimal temperature bias. with an under-prediction bias for temperature in the Northeast and Great Lakes during the winter months. The wind speed bias is also minimal for the eastern United States with a very slight tendency toward under-prediction in the Midwest in the winter and Mid-Atlantic in the summer. Moisture is over-predicted in most regions of the eastern United States, in particular during the summer months. The observed spatial pattern of monthly total rainfall is matched well by model estimates. The magnitude of estimated rainfall is over-predicted in much of the eastern United States during the summer months.
Organization: Prairie State Generating Company, LLC
Comment: 
Prairie State Generating Company, LLC
14. MODELING
PSGC believes that the U.S. EPA should reevaluate the data used in the modeling relied upon to Support this proposal. By using 2005 base-year data instead of the most recent source inventory and air quality data, the U.S. EPA has failed to recognize the controls installed after 2005, thereby overestimating the amount of emissions reductions necessary to eliminate downwind impacts to other states. [EPA-HQ-OAR-2009-0491-2842.1, p.10]
Response: 
See section V.C.2. of the preamble.

IV.C.1. What Air Quality Modeling Platform Did EPA Use?

Organization: Alabama Department of Environmental Management
Comment: 
Alabama Department of Environmental Management
The model performance evaluation does not justify the use of the modeling system to be used as the basis for the transport rule. Such a model performance evaluation submitted by a state in support of a SIP revision would not be approved by EPA. [EPA-HQ-OAR-2009-0491-2616, p.3]
Response: 
EPA has completed an expanded model performance evaluation using the predictions from the updated 2005 base year CAMx simulation conducted for the final Transport Rule.   This evaluation provides additional spatial and temporal performance results in response to comments.  The model performance results can be found in Appendix A of the Final Transport Rule Air Quality Modeling Technical Support Document.
Organization: Ameren Services Company
Comment: 
Ameren Services Company
A. Utilization of a more recent base year than 2005 is more appropriate
EPA has used inventory and meteorological data that is not representative of current conditions. Inventories and meteorology are available for 2008. Currently the Lake Michican Air Directors Consortium (LADCO) is performing modeling with both 2007 and 2008 emissions and meteorological data. In addition the Midwest Ozone Group has performed modeling (see comments submitted by the Midwest Ozone Group, October I, 20 I0) that shows a totally different picture than that portrayed by EPA's modeling. EPA's reliance on noncurrent data produces results that are not reflective of todays environment and should not be relied upon as the basis of such a far-reaching rule. EPA should redo its analysis with more recent and relevant data. [EPA-HQ-OAR-2009-0491-2722.1, p.11]
Response: 
See section V.C.2 of the preamble.
Organization: American Electric Power
Comment: 
American Electric Power
EPA should utilize the most recent approved CAMx Model Version for its Proposed Ambient Air Quality impact analyses
EPA used version 5.01 of the Comprehensive Air Quality Model with Extensions (CAMx) as described in the Technical Support Document for the Proposed Transport Rule - Air Quality Modeling that discussed work performed starting in early 2009 and continuing until the spring of 2010. Version 5.01 of CAMx was the current version of the model at the time the exercise was initiated. Due to enhancements in the vertical transport algorithms that were implemented in version 5.20 of the model, differing results may exist when replication type studies are performed. AEP recommends that modeling relied upon in support of the proposed rule utilize the most current version of the CAMx Model. [EPA-HQ-OAR-2009-0491-2665.1, p.13]
Response: 
EPA has used CAMx version 5.3 for the air quality modeling for the Final Transport Rule.  CAMx v5.3 was the latest public release version of CAMx that was available when EPA began the Final Rule air quality modeling.
Organization: Duke Energy
Comment: 
Duke Energy
EPA Should Return to Its "Monitored-Plus-Modeled" Approach
EPA should not have abandoned use of the "monitored-plus-modeled" approach that it used in CAIR and the NOx SIP Call rule to determine downwind nonattainment areas to be addressed. EPA provides no justification in its proposal for its arbitrary decision to abandon this approach. The monitored-plus-modeled approach is preferable to the approach used in the Proposed Transport Rule because the inclusion of monitored data helps ground the rule in real-world air quality that is lost in EPA's new "modeling-only" approach. Moreover, the use of monitored data for this purpose was not challenged or criticized in North Carolina v. EPA. EPA's decision to abandon the monitored-plus-modeled approach is even more surprising given the rationale for the approach given in those previous rulemakings. [EPA-HQ-OAR-2009-0491-2689.1, p.13]
If EPA had considered current monitored data, it would have found that many of the areas that it projects, in the Proposed Transport Rule, to be downwind nonattainment areas in fact currently have air quality that is in attainment of the ozone and/or PM2.5 NAAQS.  [EPA-HQ-OAR-2009-0491-2689.1, p.14]
Additionally, Duke Energy understands that a number of monitors that EPA has included in its significant contribution analysis are in fact no longer operating. EPA needs to ensure that its significant contribution analysis is only looking at air quality impacts at active monitors.  EPA should return to its monitored-plus-modeled approach in this rulemaking, or at a minimum, should explain the basis for its departure from that approach, including how its reasoning has changed and why it believes that current monitored air quality data is not relevant to this rulemaking. [EPA-HQ-OAR-2009-0491-2689.1, p.14]
Response: 
See section V.C.2 of the preamble.
Organization: Empire District Electric Company (Empire District)
Trinity Consultants
Comment: 
Empire District Electric Company (Empire District)
We question the reliability of the CAMx model for distances greater than 300 miles from the source point and also some of the emission data used for the modeling as evidenced by the corrections listed below.  In support of remodeling Trinity Consultants was selected to review the EPA's CAMx modeling and perform CAMx modeling for Kansas using corrected data.  The results of the Trinity modeling show that Kansas should be excluded from the CATR for annual and ozone season NOx.  Their report is attached as Appendix A [See EPA-HQ-OAR-2009-0491-2659.3 for Trinity Consultants Report] .  Trinity Consultants has submitted the modeling data directly to EPA as referenced in their cover letter attached as Appendix B [See EPA-HQ-OAR-2009-0491-2659.2 for Trinity Consultants Cover Page]. [EPA-HQ-OAR-2009-0491-2659.1]
Trinity Consultants
The focus of this report is to review the EPA's determination that Kansas makes a significant contribution to the PM2.5 24-hr NAAQS nonattainment and maintenance status in Milwaukee, Wisconsin, the PM2.5 24-hr NAAQS maintenance status in Muscatine, Iowa, and the ozone 8-hr NAAQS maintenance status in the Dallas Ft-Worth (DFW) area. Specifically, the report reviews the emission rates that were included in the EPA modeling that formed the basis of the determination, presents revised emission rates based on this review, and summarizes modeling that was completed in support of the revised rates. Ultimately, based on the modeling with revised emission rates, the report concludes that EPA should not include Kansas in the final Transport Rule for 8-hr ozone. [EPA-HQ-OAR-2009-0491-3072.1, p.2-2] 
This report is in support of comments submitted (under separate record) by the following Kansas electric utility companies:  
:: Board of Public Utilities  
:: Empire District Electric Company  
:: Kansas City Power and Light  
:: Sunflower Electric Power Corporation  
:: Westar Energy   [EPA-HQ-OAR-2009-0491-3072,p.1]
Response: 
EPA disagrees with this comment.  The commenter describes distance limitations and accuracy of non-steady-state puff dispersion models from long-range transport from large point sources to distant Class I areas.  Such models are designed primarily for use in modeling the impacts of inert pollutants in support of analyses relevant to Prevention of Significant Deterioration (PSD) (See 40 CFR Part 51 Appendix W).   The commenter incorrectly assumes that the limitations and accuracy of non-steady-state long-range transport models are also applicable and relevant to photochemical grid models, like CAMx.   CAMx is specifically designed for simulation of ozone, PM2.5 and other pollutants over many spatial scales ranging from sub-urban to continental (Environ, 2010).  EPA has identified CAMx as one of several candidate models that are applicable for use by states in attainment demonstration modeling for ozone, PM2.5 and regional haze State Implementation Plans.  EPA has successfully used grid-based photochemical models for applications on regional and national scales in support of numerous rulemakings (placeholder for list/citations to dockets). 
The results of the modeling by Trinity referenced by the commenter indicates that Kansas contributes PM2.5 above the 1 percent of the NAAQS threshold to nonattainment of the 24-hour PM2.5 NAAQS in Milwaukee.  This finding is consistent with the results of EPA's updated air quality modeling for contributions of annual NOx and SO2 emissions from Kansas.  
The final transport rule analysis does not identify Dallas as a nonattainment or maintenance receptor.  This analysis, however, does identify Kansas as a state with emissions that interfere with maintenance in Allegan County, MI.  For reasons explained therein, EPA is issuing a Supplemental Notice of Proposed Rulemaking to propose that states (including Kansas) to take comment, among other things, on its conclusion that Kansas significantly contributes to or interferes with maintenance of the 1997 ozone NAAQS in another state.
 
Organization: Exelon
Comment: 
Exelon
Exelon has peer reviewed EPA's air modeling, using both internal and external experts, and has confirmed that the EPA's modeling approach in support of the proposed Transport Rule is state-of-the-art. This review included all modeling: that used to identify significant contributions and that used to project the impact of the state emissions budgets on downwind nonattainment. In particular, Exelon's review confirmed that the CAMx model and all other models used by EPA were appropriately selected, and that the modeling boundaries, grid spacing, initial and boundary conditions, meteorological data inputs, emissions inventory data inputs, and monitoring data inputs were all appropriate. While there is intrinsic uncertainty in any modeled prediction of future air quality conditions, EPA will continue to monitor air quality and will observe the empirical impact of the rule. EPA intends to modify state budgets as necessary to assure that significant contributions to downwind nonattainment are eliminated. This approach is reasonable and adequately addresses the court's concerns. [EPA-HQ-OAR-2009-0491-2666.1, pp.10-11]
Response: 
EPA agrees that the air quality modeling approach and models used for the Final Transport Rule are state-of-the-art and appropriate for use in this rule.
Organization: George Washington University Regulatory Study Center
Comment: 
George Washington University Regulatory Study Center
In addition, there is also likely to be substantial model uncertainty in EPA's air quality modeling. A 2002 NRC report (discussed in the next section) stated that it is difficult to know how much confidence to place in the predictions without evaluating the uncertainty in air quality modeling. In the few cases where there are "head-to-head" comparisons of air quality models, there are important differences in the estimates of ambient air concentrations. For example,  [EPA-HQ-OAR-2009-0491-2573.1,p.23]
Damage estimates in a 2009 NRC study, The Hidden Costs of Energy: Unpriced Consequences of Energy Production and Use", which used the Air Pollution Emission Experiments and Policy (APEEP) model in generating marginal damage estimates for fossil fuel-fired powerplants in the electricity sector are roughly a quarter those reported by EPA (using the Community Multiscale Air Quality Model [CMAQ]) for reductions in SO2 and NOx emissions from electricity generating units subject to EPA's CAIR rule.50 The NRC report attributes the difference in estimates to differences in air quality modeling.51 [EPA-HQ-OAR-2009-0491-2573.1,p.23]
In addition, Krupnick, et al. (2006) evaluated the effect of adopting alternative source-receptor models and reported over a 3-fold difference in the mean benefit estimates for the two air quality models used in the study. [EPA-HQ-OAR-2009-0491-2573.1,p.23]
Unfortunately, we are not aware of a similar comparison for the CAMx model. However, the various modeling platforms -- such as CMAQ -- are likely to yield different estimates of fine PM concentrations. Therefore, EPA should also consider the potential effect of model uncertainty in assessing the uncertainty in its estimates and in determining an appropriate contribution threshold. [EPA-HQ-OAR-2009-0491-2573.1,p.24]
In light of these several sources of uncertainty, EPA should develop a quantitative uncertainty analysis for its modeling of estimates of the interstate contributions of each of the eastern states to nonattainment and maintenance problems in neighboring states. EPA needs to do so in order to demonstrate that its methodology will provide the precision necessary to support the accuracy required by the fine PM thresholds of 0.15 μg/m3 for the annual standard and 0.35 μg/m3 for the 24-hour standard.  [EPA-HQ-OAR-2009-0491-2573.1,p.24]
Given the uncertainty in the several components underlying EPA's analysis, there are several alternative paths EPA should consider to address this issue. One possibility is to conduct an expert elicitation using independent modeling experts. This study could consider the information already available to EPA on the variability in the emissions from the power sector and the projected concentration levels (versus the actual observed levels). The objective of the study would be to develop a quantitative uncertainty analysis for the estimated contribution to downwind non-attainment based on the emissions projections and the air quality modeling used in the proposal and a recommendation of the appropriate precision embedded in the approach used to calculate contribution for each state. [EPA-HQ-OAR-2009-0491-2573.1, p.24]
E. Summary for EPA's Health Benefits Analysis  
Depending on model choice, then, health benefits estimates for the Transport Rule could be overstated by an order of magnitude. To the extent that EPA presents a quantitative treatment of uncertainty in its RIA, the analysis focuses on the concentration-response relationship and largely fails to address the uncertainty associated with other key elements in the benefits analysis, such as the estimated change in emissions and exposure, including air quality modeling. EPA should develop a more comprehensive quantitative uncertainty analysis that covers the major sources of uncertainty in its estimates. Doing so would provide a better characterization of the EPA estimates and their uncertainty and provide a greater confidence in EPA's benefits analysis. [EPA-HQ-OAR-2009-0491-2573.1,p.31]

50 CMAQ is an integrated assessment model developed by EPA. It is widely viewed as a "state-of-the-science" for air quality modeling. APEEP is a "reduced form" model that has been carefully calibrated to CMAQ in order to reflect the relationship between emissions and concentrations in CMAQ. APEEP is publicly available. The 2009 NRC report used APEEP because it focused on identifying the emissions from individual plants over the modeling domain; CMAQ is not structured to provide such estimates for individual plants. NRC (2009), 61.  
51 The NRC report noted that the version of CMAQ used for the CAIR rule overestimated sulfate PM concentrations (in summer months when sulfate concentrations are higher CMAQ overestimated ambient levels by as much as 14 percent. This estimation bias does not fully account, however, for the difference between the CMAQ and APEEP estimates, however. (NRC 2002, 73)
Response: 
EPA disagrees with this comment.  The 2002 NRC report acknowledges that there are uncertainties in air quality modeling systems (this includes the model construct, the scientific representation of complex physical and chemical processes, and model inputs such as weather and emissions).  However, the NRC report does not call for a quantitative assessment of these uncertainties.  Rather, the report states that the credibility of the modeling results is obtained by using state-of-the science air quality models that are appropriate for the particular application coupled with "a systematic process of model testing and evaluation".   Specifically, the report says that "the credibility of the model results is determined by the modeling process.  A good model application will use and evaluate the most appropriate model inputs, including emissions, meteorology, and topography."  In addition, the report states that "The one-atmosphere [modeling] approach is particularly useful because it allows integrated study of all pollutants that are important to a specific region." Regarding the evaluation, the report states that "Model accuracy should be determined empirically by comparing model estimates to actual observations in a recent period".   Moreover, the report indicates that the accuracy of modeling is increased when the model predictions  for a recent base period and a future time period are used in a relative sense as scaling (or response) factors to "calibrate" observed pollutant levels from the recent base period.  The report states that "This approach may help reduce the bias introduced by modeling errors and, therefore, may be more accurate than using model results directly (absolute values) to estimate future pollutant levels."
The EPA's air quality modeling approach for the Transport Rule is consistent with the recommendations in the 2002 NRC report.   Specifically, EPA used a state-of-the science "one atmosphere" photochemical model, CAMx, that is specifically designed to simulate the complex non-linear chemistry and physical processes that determine the formation and fate of ozone, PM2.5 and their precursor pollutant species across regional and national scales over short-term episodes and longer-term annual time periods (Comprehensive Air Quality Model with Extensions Version 5.3 User's Guide. Environ International Corporation. Novato, CA. December 2010).   CAMx is listed in EPA's modeling guidance as a candidate modeling tool for use by states as part of developing attainment demonstrations for ozone and PM2.5 (U.S. EPA, 2007: Guidance on the Use of Models and Other Analyses for Demonstrating Attainment of Air Quality Goals for Ozone, PM2.5, and Regional Haze; Office of Air Quality Planning and Standards, Research Triangle Park, NC. ).  EPA has evaluated CAMx predictions of ozone and PM2.5 through comparison of model predictions to the corresponding measured concentrations for the Transport Rule 2005 base year model simulation (the results of this evaluation can be found in the Transport Rule Air Quality Modeling Technical Support Document).   In addition, the impacts of biases that may be the result of model uncertainties are reduced since EPA is using the CAMx model predictions in a relative manner for both projecting future case concentrations of ozone and PM2.5 and for quantifying the contributions of emissions from individual states to ozone and PM2.5 nonattainment and maintenance in other downwind states. 
The models in the references cited by the commenter regarding head-to-head comparisons of predictions from multiple air quality models are not relevant to the modeling performed for the Transport Rule (see response above).  The modeling systems in these references include source-receptor models and statistical models that are based largely upon near-field dispersion models with simplified chemistry assumptions, climatological (not day-specific) weather conditions, and/or empirical extrapolation of the results beyond the location and/or time of the underlying data.   The cross-model comparisons in the cited references are based on the absolute predictions of the models, not the response to emissions changes.   Hogrefe et. al. (J. Air & Waste Manage. Assoc. 58:1086-1099, 2008) compared CAMx and CMAQ predictions of 8-hour daily maximum ozone in terms of (1) absolute predictions and (2) the relative response to emissions changes.   The results in this paper show that notable differences between these two models in terms of absolute concentrations appear to have only a "minor impact" on the simulated response to emissions reductions.   That is, despite differences in absolute predictions, and therefore differences in model performance, the relative response (as in the approach used by EPA in the Transport Rule for projecting concentrations and contributions) provides a robust determination of the expected effects of emissions perturbations.
EPA disagrees with the commenter and finds that its analyses for the final rule are sufficiently detailed and precise enough to support the Agency's determinations of emission reduction responsibilities in each state.  EPA has followed all of its own modeling guidance to states and has employed analytic methodologies (using peer-reviewed models) that have been upheld in prior regulatory actions under judicial review.  The commenter's assertions ignore commonly practiced and widely accepted regulatory development procedures and demonstrate fundamental misunderstandings of the role of these analyses in Clean Air Act rulemakings.  The interstate contributions to PM2.5 calculated for the Transport Rule are based on all anthropogenic emissions of SO2 and NOx, not just those emissions from the power sector.  Thus, considering the variability in power sector emissions alone, as suggested by the commenter, would not provide a meaningful approach to characterizing the uncertainty in the predicted contributions.  In addition, the approach suggested by the commenter of using expert elicitation is not workable in view of the construct of air quality modeling systems and the lack of data to gauge the uncertainty in individual components of this system.  As noted by the NRC, air quality modeling systems are quite complex.  They include hundreds of different emission sources, multiple, hourly spatially varying weather parameters (e.g., winds, mixing, clouds, precipitation, temperature, etc.), non-linear photochemical reactions, pollutant-specific, land-use and weather-dependent removal by deposition as well as other physical factors that affect the formation, transport, and ultimate fate of ozone and the individual component species of PM2.5 (e.g., sulfate, nitrate, organic carbon, etc.).   We are unaware of any expert or group of experts that would be able to provide a factual determination of the uncertainty in each and every component of the modeling system and then assimilate all of this disparate information in a physically and chemically consistent and sound manner that would provide a meaningful quantitative estimate of the overall uncertainty in the air quality modeling system.  For the final Transport Rule, EPA used a state-of-the science, "one atmosphere" air quality model, CAMx, with peer-reviewed source apportionment techniques coupled with input data that have undergone external review, and evaluation and analysis methods that are consistent with recommendations by the NRC.  Thus, EPA believes that the Transport Rule air quality modeling system is capable of fully supporting decisions made as part of this rule.
Organization: Iowa Department of Natural Resources (IDNR)
Comment: 
Iowa Department of Natural Resources (IDNR)
We commend EPA for using current state of the science tools for assessing interstate contributions such as the use of source apportionment technologies available in the CAMx photochemical grid model. Scientifically sound and technically supported methods are necessary components of the process to build the justification of any rule addressing intestate pollutant transport. Implementation of source apportionment methods can provide consistent, reproducible, and justifiable means through which source and receptor linkages can be evaluated. [EPA-HQ-OAR-2009-0491-2609.1, p.2]
Response: 
EPA agrees that the air quality modeling approach and models used for the Final Transport Rule are state-of-the-science and appropriate for use in this rule.
Organization: Kansas Department of Health and Environment
Comment: 
Kansas Department of Health and Environment
In our review of the proposal, we support many of the technical approaches EPA has used to determine contributions to nonattainment, specifically the use of 'best science' tools such as CAMx with source apportionment. KDHE believes tools such as CAMx can provide valuable insights into culpability assessments if proper inputs are used and correct interpretations are made. It appears EPA is making an attempt to utilize the latest available emissions and tools to inform policy decisions, and we commend EPA for this. [EPA-HQ-OAR-2009-0491-2606.1, p.2]
Response: 
EPA agrees that the air quality modeling approach and models used for the Final Transport Rule are state-of-the-science and appropriate for use in this rule.
Organization: Maryland Department of Environment (MDE)
Comment: 
Maryland Department of Environment (MDE)
Guidance on model performance for transport. EPA is now using photochemical modeling to determine significant contribution in the Transport Rule. Our research has shown that in the past, some of the photochemical models did not capture aloft transport from the west and low level jet transport from the south accurately. It is critical, with the models now being asked to play a critical role in addressing transport, that the model performance for transport be adequate. Maryland believes that EPA needs to address this issue in its modeling guidance. See Appendix A [See EPA-HQ-OAR-2009-0491-2639.2, p.22 for comments pertaining to Appendix A] for more information on the Maryland research program. [EPA-HQ-OAR-2009-0491-2639.2, p.6]
Response: 
EPA has completed an expanded model performance evaluation using the predictions from the updated 2005 base year CAMx simulation conducted for the final Transport Rule.   This evaluation provides additional spatial and temporal performance results in response to comments.  The model performance results can be found in Appendix A of the Final Transport Rule Air Quality Modeling Technical Support Document.  Including guidance on model performance for transport as part of EPA's modeling guidance for attainment demonstrations is outside the scope of this rulemaking.   The Final Transport Rule requires emissions reductions of annual NOx and/or ozone season NOx in 27 states in the East in addition to Maryland.  This includes states that are 700 miles to the south of Maryland and 1000 miles to the west of Maryland.  The emissions reductions within these upwind states will help Maryland attain and maintain the 1997 ozone NAAQS.
Organization: Midwest Ozone Group
Comment: 
Midwest Ozone Group
Modeling of existing CAIR requirements and other OTB controls indicate no needfor the nature and extent of controls as proposed in the CATR. [EPA-HQ-OAR-2009-0491-2809.1, p.9]
In support of its position that EPA's CATR analysis is flawed because it excludes benefits of controls installed on the EGU fleet since 2005, MOG and other entities have sponsored an analysis of the impact on predicted ozone and PM2.5 nonattainment resulting from emissions reductions that have occurred since 2005 as a result of the installation of additional controls, including controls that resulted from the CAIR. The studies, also included in the attachment to these comments, were performed using the CAMx model by Alpine Geophysics and included projections of predicted 2014 and 2018 air quality. They include modeling scenarios called "2014 Business As Usual (BAU)" and "2018 BAU." A disc with the input and output files related to these studies is being submitted under separate cover. [EPA-HQ-OAR-2009-0491-2809.1, p.9]
The project also involved use of updated inputs to the CAMx model, including a projected 2014 EGU inventory compiled by James Marchetti, J. Edward Cichanowicz and Michael Hein, and a projected non-EGU inventory compiled by Alpine Geophysics. [EPA-HQ-OAR-2009-0491-2809.1, p.9]
Alpine Geophysics conducted photochemical modeling analyses, including the EPA attainment test, for three key years: 2008, 2014, and 2018. The modeling for year 2008 served the important function of providing a recent `typical baseline' year for the purpose of calculating relative reduction factors (RRFs). Most importantly, moving to 2008 took direct advantage of recent reductions in 8-hr design values measured across the modeling region. Results of this work clarify when the effects of BAU state and federal control programs would begin to significantly lower the 8-hr ozone and annual and 24-hr PM2.5 design values at key monitors in the modeling domain. [EPA-HQ-OAR-2009-0491-2809.1, p.10]
The SO2 and NOx emission forecast for this analysis assumed compliance with the CAIR, as well as utility agreements with regard to consent decrees and state programs. The future regional electrical generation by fuel type and regional fuel forecasts that were incorporated into the model were from the Energy Information's Administration's Annual Energy Outlook 2009 (AEO2009) - Updated Reference Case. [EPA-HQ-OAR-2009-0491-2809.1, p.10]
Using EPA attainment test software and algorithms with the output from the BAU CAMx simulations for 2008, 2014 and 2018, Alpine Geophysics concludes that the ozone objectives of the proposed CATR can be achieved no later than 2014 within the 12 km modeling domain with no new controls beyond the existing CAIR and other BAU requirements. [EPA-HQ-OAR-2009-0491-2809.1, p.10]
Alpine Geophysics also concludes that the annual PM2.5 objectives of the proposed transport rule can be achieved no later than 2014 within the 12 km modeling domain with no new controls beyond the existing CAIR and other BAU requirements, with the possible exception of additional local controls at the Allegheny County, PA location, discussed later in these comments. [EPA-HQ-OAR-2009-0491-2809.1, p.10]
Finally, Alpine Geophysics concludes that the 24-hr PM2.5 objectives of the proposed CATR can be achieved within the 12 km modeling domain no later than 2014 with no new controls beyond the existing CAIR and other BAU requirements, with the possible exception of additional local controls at the Allegheny County, PA and Brooke County, WV locations, which are discussed later in these comments. [EPA-HQ-OAR-2009-0491-2809.1, p.10]
Accordingly, the additional stringent emission reductions EPA is proposing in the CATR are not needed to achieve the air quality objective EPA is targeting - attainment of the subject NAAQS requirements. [EPA-HQ-OAR-2009-0491-2809.1, p.10]
Response: 
See section V.C.2 of the preamble.
Organization: New York State Department of Environmental Conservation
Comment: 
New York State Department of Environmental Conservation
The evaluation of the CAMx base case performance presented in the Air Quality Modeling Technical Support Document (AQM-TSD) is limited to an operational evaluation of ozone and PM2.5 species using standard statistical comparisons. While these comparisons indicate model performance that is generally within the range of previous studies, they do not establish the modeling system's ability to capture the physical and chemical processes relevant to interstate transport of air pollution. In addition, these evaluations do not establish the modeling system's ability to correctly quantify the impact of emission reductions on ambient concentrations. For example, how did the model perform during high pollution events when interstate transport is considered to play a major role? Finally, the very high bias for the crustal/other component raises questions about the quality of the emission inventory for primary PM2.5 and/or the CAMx representation of its transport and removal. [EPA-HQ-OAR-2009-0491-2730.1, p.11]
Response: 
EPA has completed an expanded model performance evaluation using the predictions from the updated 2005 base year CAMx simulation conducted for the final Transport Rule.   This evaluation provides additional spatial and temporal performance results in response to comments.  The model performance results can be found in Appendix A of the Final Transport Rule Air Quality Modeling Technical Support Document.  
 
Organization: Progress Energy Service Company
Omaha Public Power District
Nebraska Public Power District
Comment: 
Nebraska Public Power District
10) Monitored-Plus-Modeled Approach. EPA should not have abandoned use of the "monitored-plus-modeled" approach that it used in CAIR to determine downwind nonattainment areas to be addressed. EPA provides no justification for its decision to jettison this approach. The monitored-plus-modeled approach helps provide grounding in real-world air quality that is lost in EPA's novel "modeling-only" approach. The use of monitored data was not challenged or criticized in North Carolina v. EPA. Hence, there is no need to alter this approach. [EPA-HQ-OAR-2009-0491-2711.1, p.8]
Omaha Public Power District
EPA should not have abandoned use of the 'monitored-plus-modeled' approach that it used in CAIR to determine downwind nonattainment areas to be addressed. EPA provides no justification for its decision to jettison this approach. The monitored-plus-modeled approach helps provide grounding in real-world air quality that is lost in EPA's novel 'modeling-only' approach. The use of monitored data was not challenged or criticized in North Carolina v. EPA. Hence, there is no need to alter this approach. [EPA-HQ-OAR-2009-0491-2680.1, p. 5]
Progress Energy Service Company
EPA should not have abandoned the use of the 'monitored-plus-modeled' approach that it used in developing the CAIR to determine downwind nonattainrnent areas be addressed. EPA provides no justification for its decision to jettison this approach. The monitored-plus-modeled approach is preferable to the approach used in the proposed Transport Rule because the inclusion of monitored data helps provide a basis in real-world air quality that is lost in EPA's 'modeling only' approach. Moreover, the use of monitored data was not challenged or criticized in North Carolina v. EPA. [EPA-HQ-OAR-2009-0491-2831.1 p.6]
Response: 
See section V.C.2 of the preamble.
Organization: Southern Company
Comment: 
Southern Company
EPA's method eliminated the monitored-plus-modeled test for identifying downwind (and now maintenance) monitors for assessment that was used in CAIR. This change removes an important constraint on the use of uncertain models. EPA's method ignored real emissions reductions from CAIR (still in place and operating) and local SIP-related controls, this omission leads to an overestimate of projected nonattainment/maintenance. EPA's method ignored its own regulatory modeling guidance by not properly projecting future air quality, especially for urban areas with strong local source contributions. For such situations, EPA guidance for evaluating air quality requires the use of refined models such as AERMOD joined with CMAQ for PM2.5, or a 4 km or less horizontal resolution receptor grid and/or plume-in-grid treatment for ozone. Collectively, the EPA approach results in over predictions of future air quality concentrations and over predictions of the number of significant air quality contribution linkages, thereby inflating the air quality burden to be 'resolved.' [EPA-HQ-OAR-2009-0491-2864.1, p. 30]
D. EPA's Refined Air Quality Modeling Fails to Follow its Own Guidance for Application and Performance Evaluation
EPA applied the CAMx model and its OSAT and PSAT source apportionment tools. There are serious problems with their application of these tools that begs the credibility of their analysis. [EPA-HQ-OAR-2009-0491-2864.1, p. 32]
First, EPA failed to apply their own guidance in modeling for PM2.5 in urban areas, especially where local sources have a significant short-range effect on the monitors (e.g., the North Birmingham and Wylam PM2.5 monitors in Birmingham both have significantly elevated concentrations compared to nearby urban monitors, largely due to local sources). EPA guidance recommends the use of AERMOD in conjunction with CMAQ (or CAMx) to obtain a more accurate projection of air quality. EPA did not do this nor otherwise try to account for effects of local sources in their projections. By ignoring this issue, EPA has likely overestimated future air quality concentrations, thereby increasing the air quality 'burden' that must be resolved, especially since EPA requires attainment and maintenance to be achieved through this rule, a criteria that is both overly burdensome and unlawful. [EPA-HQ-OAR-2009-0491-2864.1, p. 32]
Second, EPA's model performance evaluation is cursory at best. State SIP demonstrations require model performance evaluations that are far more rigorous. Further, EPA does not even use actual historical EGU emissions to assess how well the air quality model predicts actual historical monitored data. They use 'typical' EGU emissions. This process for model evaluation is totally unacceptable. In a model performance assessment, actual historical emissions must be used in the modeling or else the comparison of air quality modeling predictions to actual historical monitored data has no meaning. [EPA-HQ-OAR-2009-0491-2864.1, p. 32]
Third, given the importance of the PSAT and OSAT tools, EPA should have done much more to demonstrate that the tools give reliable answers, especially since they are being used to assess such small thresholds. A similar demonstration is needed for their use of the CAMx model itself. Can these models and source apportionment tools really give accurate results at differences of 0.15 ug/m3 of PM and 0.8 ppb of ozone? [EPA-HQ-OAR-2009-0491-2864.1, p. 32]
Finally, since EPA's approach is to rely solely on the model to determine if a monitor is in nonattainment or has a maintenance issue, getting the air quality projection correct is critical. EPA cannot reasonably argue that the use of coarse-scale modeling is acceptable for 'transport' but that 'local' effects are not relevant. The ultimate stringency of the proposed rule is critically dependent on getting projected air quality correct, and getting the local contribution correct is an essential element. [EPA-HQ-OAR-2009-0491-2864.1, p. 33]
The role of NOx in particulate matter formation is further complicated by recent discoveries demonstrating that the production of biogenic secondary organic aerosol (SOA) is heavily influenced by NOx levels. Specifically, this research shows that that biogenic SOA, particularly for isoprene, is enhanced with lower NOx levels due to changes in the fate of peroxy radicals. Thus, NOx reductions, particularly in the Southeast which has significant biogenic emissions, could actually result in increased PM2.5. Air quality models at present do not include this newly discovered chemistry and, therefore, EPA's analysis does not take into account these potential NOx disbenefits. In addition, the proper simulation of ammonium nitrate and other nitrate aerosol (e.g., organic nitrates) has confounded air quality scientists for many years. As such, the representation of the impacts NOx emission changes in PM levels in these models is incomplete, particularly when attempting to simulate relatively small signals such as interstate contributions to PM. [EPA-HQ-OAR-2009-0491-2864.1, p. 45]
Response: 
See preamble section V.C.2 for response to comments on (1) use of monitored-plus-modeled approach and (2) applicability of local scale modeling for determining future nonattainment as part of the Transport Rule. 
EPA has completed an expanded model performance evaluation using the predictions from the updated 2005 base year CAMx simulation conducted for the final Transport Rule.   The 2005 simulation used for the performance evaluation includes year-specific emissions from EGU and onroad and nonroad mobile sources.  The evaluation provides additional spatial and temporal performance results in response to comments.  The model performance results can be found in Appendix A of the Final Transport Rule Air Quality Modeling Technical Support Document.  
 The commenter says that EPA should have done much more to demonstrate that the PSAT and OSAT tools give reliable answers.  However, the commenter does not provide any suggestions on what might be included in such a demonstration.  EPA has subjected the PSAT and OSAT tools to an independent peer review.  Both OSAT and PSAT received favorable comments. "All reviewers agreed that OSAT in CAMx is a mature and well-evaluated methodology" and the "PSAT source apportionment technique has been extensively tested and evaluated against other source apportionment techniques". [Arunachalam, S. Peer Review of Source Apportionment Tools in CAMx and CMAQ, EP-D-07-102. University of North Carolina, Institute for the Environment, August 2009.] 
 The comments related to the current understanding of the impact of NOx on biogenic SOA and the simulation of ammonium nitrate do not reflect the state-of-the-science and noticeably lack supporting references.  While earlier studies (e.g., Kroll et al., 2006) reported increases in SOA associated with decreases in NOx from the isoprene-plus-OH pathway, recent work (e.g., Chan et al., 2010) suggests that SOA production from isoprene oxidation by OH can be similar for high- and low-NOx conditions at atmospherically relevant NO2-to-NO  ratios.  Additionally, a recent study (Ng et al., 2008) suggests that increases in biogenic SOA could be associated with increases in NOx via the isoprene-plus-NO3 radical pathway.  Furthermore, Ng et al. (2007) have reported increases in biogenic SOA associated with increases in NOx for the sesquiterpene-plus-OH pathway.  Therefore, even if a "dis-benefit" in biogenic SOA formation via the isoprene-plus-OH pathway occurred under reduced-NOx conditions, it could be compensated for by a potential "benefit" in biogenic SOA reduction via other pathways (e.g., sesquiterpenes-plus-OH, isoprene-plus-nitrate radical).  Indeed, a preliminary global modeling study that accounts for benefit and disbenefit pathways suggests that their impacts may largely cancel in the Southeast US (Pye et al., 2010).  While the dependence of biogenic SOA formation on NOx levels is an area of ongoing research, the current literature does not implicate a significant dis-benefit of biogenic SOA formation in the Southeast US associated with reductions in NOx concentration.     
 EPA disagrees with the comment that the simulation of ammonium nitrate aerosol confounds air quality scientists.  The thermodynamic and dynamic processes governing ammonium nitrate aerosol formation have been understood for many years (e.g., Bassett and Seinfeld, 1983; Wexler and Seinfeld, 1990, 1991).  The early challenge to representing ammonium nitrate formation in 3D photochemical models was related to the computationally intensive nature of the calculations rather than unknown chemical and physical processes.  However, thermodynamic modules were developed in the 1990s to efficiently solve the inorganic thermodynamic aerosol problem (e.g., ISORROPIA; Nenes et al., 1998).  Current state-of-the-science photochemical models, including CAMx, contain such thermodynamic modules. 
References: 
Bassett, ME, and Seinfeld, JH (1983) Atmospheric equilibrium model of sulphate and nitrate aerosols, Atmospheric Environment 17:2237 - 2252. 
Chan, AWH, Chan, MN, Surratt, JD, Chhabra, PS, Loza, CL, Crounse, JD, Yee, LD, Flagan, RC, Wennberg, PO, and Seinfeld, JH (2010) Role of aldehyde chemistry and NOx concentrations in secondary organic aerosol formation. Atmospheric Chemistry and Physics 10(15): 7169-7188. 
Foley, KM, Roselle, SJ, Appel, KW, Bhave, PV, Pleim, JE, Otte, TL, Mathur, R, Sarwar, G, Young, JO, Gilliam, RC, Nolte, CG, Kelly, JT, Gilliland, AB, and Bash, JO (2010) Incremental testing of the Community Multiscale Air Quality (CMAQ) modeling system version 4.7. Geoscientific Model Development 3:205 - 226. 
Kroll, JH, Ng, NL, Murphy, SM, Flagan, RC, and Seinfeld, JH (2006) Secondary organic aerosol formation from isoprene photooxidation. Environmental Science & Technology 40(6): 1869-1877. 
Nenes, A, Pandis, SN, and Pilinis, C, (1998) ISORROPIA: a new thermodynamic equilibrium model for multiphase multicomponent inorganic aerosols. Aquatic Geochemistry 4(1):123 - 152. 
Ng, NL, Chhabra, PS, Chan, AWH, Surratt, JD, Kroll, JH, Kwan, AJ, McCabe, DC, Wennberg, PO, Sorooshian, A, Murphy, SM, Dalleska, NF, Flagan, RC, and Seinfeld, JH (2007) Effect of NOx level on secondary organic aerosol (SOA) formation from the photooxidation of terpenes. Atmospheric Chemistry and Physics 7:5159 - 5174. 
Ng, NL, Kwan, AJ, Surratt, JD, Chan, AWH, Chhabra, PS, Sorooshian, A, Pye, HOT, Crounse, JD, Wennberg, PO, Flagan, RC, and Seinfeld, JH (2008) Secondary organic aerosol (SOA) formation from reaction of isoprene with nitrate radicals (NO3) Atmospherics Chemistry and Physics 8: 4117 - 4140. 
Pye, HOT, Chan, AWH, Barkley, MP, and Seinfeld, JH (2010) Global modeling of organic aerosol: the importance of reactive nitrogen (NOx and NO3) Atmospheric Chemistry and Physics 10(22): 11261-11276 
Wexler, AS, and Seinfeld, JH (1990) The distribution of ammonium salts among a size and composition dispersed aerosol. Atmospheric Environment 24A: 1231 -  1246. 
Wexler, AS, and Seinfeld JH (1991) 2nd-generation inorganic aerosol model.  Atmospheric Environment-Part A, 25:2731 -  2748. 
Organization: State of Missouri Department of Natural Resources
Comment: 
State of Missouri Department of Natural Resources
Missouri recommends that EPA use CAMx for ozone and Community Multi-scale Air Quality (CMAQ) modeling for 24-hour and annual PM2.5 given that previous modeling studies indicated that CMAQ performed better than CAMX in predicting PM2.5 concentrations: Output from CMAQ then can be converted to CAMX format in order to conduct source apportionment analysis. [EPA-HQ-OAR-2009-0491-3806, p.2]
Response: 
EPA selected CAMx as the air quality modeling tool for modeling both ozone and PM2.5 because (1) CAMx is a state-of-the-science photochemical model which is designed to simulate the formation, transport, and fate of ozone and PM2.5 and precursor species on regional and national spatial scales, (2) CAMx is instrumented with source apportionment tools which provide a means to quantify interstate contributions of ozone and PM2.5 component species, and (3) CAMx has been widely used by the modeling community for calculating ozone and PM2.5 concentrations and source culpability.  CMAQ is also a widely used state-of-the science photochemical model.  However, an independent peer review of the source apportionment tools in CAMx and CMAQ was more favorable in terms of the design and implementation of the tools in CAMx.  Using a single model for simulating both ozone and PM2.5 ensures physical and chemical consistency in the predictions for these pollutants that would not be possible using two different models.
Organization: Texas Commission on Environmental Quality
Comment: 
Texas Commission on Environmental Quality
Modeling for Texas, while challenging, is far from intractable. The TCEQ has conducted many successful modeling demonstrations during the past two decades, most recently the 2010 HGB Attainment Demonstration SIP revision adopted in March of this year. Using refined modeling techniques and up-to-date inventories, the TCEQ has demonstrated satisfactory base-case model performance and predicted credible future design values. The TCEQ's modeling is thoroughly documented, and all modeling input files are available upon request or have already been provided to the EPA for their review during the attainment demonstration review process. The EPA is invited to take advantage of the TCEQ's modeling successes to improve their efforts. [EPA-HQ-OAR-2009-0491-2857.2, p.7]
Response: 
EPA appreciates the offer by TCEQ of their modeling input files for use in the Transport Rule.
Organization: Utility Air Regulatory Group (UARG)
Comment: 
Utility Air Regulatory Group (UARG)
EPA Should Return to Its "Monitored-Plus-Modeled" Approach  
EPA should not have abandoned use of the "monitored-plus-modeled" approach that it used in CAIR and the NOx SIP Call rule to determine downwind nonattainment areas to be addressed. EPA provides no justification in its proposal for its decision to jettison this approach. The monitored-plus-modeled approach is preferable to the approach used in the Proposed Transport Rule because the inclusion of monitored data helps provide a grounding in real-world air quality that is lost in EPA's novel "modeling-only" approach that relies exclusively on IPM projections. It is by no means clear that IPM is even fit to be used in the manner in which EPA used it in developing the Proposed Transport Rule. IPM is a least-cost economic model that operates on a regional scale and is not designed to replicate real-world scenarios in specific locations. See section VIII infra for further discussion of IPM. Furthermore, LADCO specifically recommended that EPA continue to use the "monitored-plus-modeled" approach. LADCO Letter, attachment at 2. Equally important, the use of monitored data for this purpose was never challenged or criticized in North Carolina v. EPA. [EPA-HQ-OAR-2009-0491-2756.1 ,p. 58]  
If EPA had considered current monitored data, it would have found that many of the areas that it projects, in the Proposed Transport Rule, to be downwind nonattainment areas in fact currently have air quality that is in attainment of the ozone and/or PM2.5 NAAQS. For example, nearly 60 percent of the monitoring sites that EPA projects to be in nonattainment areas for the 24-hour PM2.5 NAAQS in 2012 in fact are in either currently designated attainment areas or areas that have air quality that is in attainment of that NAAQS, according to an EPA determination after notice-and-comment rulemaking. See Attachment III hereto at Table II for details. Likewise, EPA has determined or proposed to determine that approximately 20 percent of the monitoring sites that EPA projects to be in nonattainment areas for the annual PM2.5 NAAQS and approximately 10 percent of the sites that EPA projects to be in nonattainment areas for the 8-hour ozone NAAQS are in areas that currently have air quality that meets the relevant NAAQS. See id. at Tables I and III respectively for details. Given the prevailing downward trend in ambient concentrations, it is most unlikely that these areas should be viewed as downwind problem areas. [EPA-HQ-OAR-2009-0491-2756.1, pp.58-59] [[See Docket Number EPA-HQ-OAR-2009-0491-2756.1, pp.169-173 for Attachment III.]  
EPA should return to its monitored-plus-modeled approach in this rulemaking, or at a minimum, should explain the basis for its departure from that approach, including how its reasoning has changed and why it believes that current monitored air quality data is not relevant to this rulemaking. 34 [EPA-HQ-OAR-2009-0491-2756.1, pp.59-60]
The role of NOx in particulate matter formation is further complicated by recent research demonstrating that the production of biogenic secondary organic aerosol ("SOA") is heavily influenced by NOx levels. Specifically, this research shows that biogenic SOA, particularly isoprene, is enhanced with lower NOx levels due to changes in the fate of peroxy radicals. Air quality models at present do not include this newly discovered chemistry. In addition, the proper simulation of ammonium nitrate and other nitrate aerosol (e.g., organic nitrates) has confounded air quality scientists for many years. Thus, the representation of the impacts of NOx emission changes in particulate matter levels in these models is incomplete, particularly when attempting to simulate relatively small signals such as interstate contributions to ambient particulate matter concentrations. [EPA-HQ-OAR-2009-0491-2756.1, pp.77]
Footnote 34: EPA also must consider the results of air quality modeling and other analyses performed for the Midwest Ozone Group ("MOG") and reported in MOG's comments filed in this docket, dated October 1, 2010. MOG's comments show, among other things, that existing controls, including CAIR, are projected to resolve most of the downwind PM2.5 and ozone air quality problems in at least a large section of the PTR domain by no later than 2014. Moreover, MOG's comments demonstrate that, much as is shown in UARG's comments, there are substantially fewer existing nonattainment problems in the PTR domain than EPA's proposal suggests.  
Response: 
See preamble section V.C.2.
The comments related to the current understanding of the impact of NOx on biogenic SOA and the simulation of ammonium nitrate do not reflect the state-of-the-science and noticeably lack supporting references.  While earlier studies (e.g., Kroll et al., 2006) reported increases in SOA associated with decreases in NOx from the isoprene-plus-OH pathway, recent work (e.g., Chan et al., 2010) suggests that SOA production from isoprene oxidation by OH can be similar for high- and low-NOx conditions at atmospherically relevant NO2-to-NO  ratios.  Additionally, a recent study (Ng et al., 2008) suggests that increases in biogenic SOA could be associated with increases in NOx via the isoprene-plus-NO3 radical pathway.  Furthermore, Ng et al. (2007) have reported increases in biogenic SOA associated with increases in NOx for the sesquiterpene-plus-OH pathway.  Therefore, even if a "dis-benefit" in biogenic SOA formation via the isoprene-plus-OH pathway occurred under reduced-NOx conditions, it could be compensated for by a potential "benefit" in biogenic SOA reduction via other pathways (e.g., sesquiterpenes-plus-OH, isoprene-plus-nitrate radical).  Indeed, a preliminary global modeling study that accounts for benefit and disbenefit pathways suggests that their impacts may largely cancel in the Southeast US (Pye et al., 2010).  While the dependence of biogenic SOA formation on NOx levels is an area of ongoing research, the current literature does not implicate a significant dis-benefit of biogenic SOA formation in the Southeast US associated with reductions in NOx concentration.    
EPA disagrees with the comment that the simulation of ammonium nitrate aerosol confounds air quality scientists.  The thermodynamic and dynamic processes governing ammonium nitrate aerosol formation have been understood for many years (e.g., Bassett and Seinfeld, 1983; Wexler and Seinfeld, 1990, 1991).  The early challenge to representing ammonium nitrate formation in 3D photochemical models was related to the computationally intensive nature of the calculations rather than unknown chemical and physical processes.  However, thermodynamic modules were developed in the 1990s to efficiently solve the inorganic thermodynamic aerosol problem (e.g., ISORROPIA; Nenes et al., 1998).  Current state-of-the-science photochemical models, including CAMx, include such thermodynamic modules.
 References:
Bassett, ME, and Seinfeld, JH (1983) Atmospheric equilibrium model of sulphate and nitrate aerosols, Atmospheric Environment 17:2237 - 2252.
Chan, AWH, Chan, MN, Surratt, JD, Chhabra, PS, Loza, CL, Crounse, JD, Yee, LD, Flagan, RC, Wennberg, PO, and Seinfeld, JH (2010) Role of aldehyde chemistry and NOx concentrations in secondary organic aerosol formation. Atmospheric Chemistry and Physics 10(15): 7169-7188.
Foley, KM, Roselle, SJ, Appel, KW, Bhave, PV, Pleim, JE, Otte, TL, Mathur, R, Sarwar, G, Young, JO, Gilliam, RC, Nolte, CG, Kelly, JT, Gilliland, AB, and Bash, JO (2010) Incremental testing of the Community Multiscale Air Quality (CMAQ) modeling system version 4.7. Geoscientific Model Development 3:205 - 226.
Kroll, JH, Ng, NL, Murphy, SM, Flagan, RC, and Seinfeld, JH (2006) Secondary organic aerosol formation from isoprene photooxidation. Environmental Science & Technology 40(6): 1869-1877.
Nenes, A, Pandis, SN, and Pilinis, C, (1998) ISORROPIA: a new thermodynamic equilibrium model for multiphase multicomponent inorganic aerosols. Aquatic Geochemistry 4(1):123 - 152.
Ng, NL, Chhabra, PS, Chan, AWH, Surratt, JD, Kroll, JH, Kwan, AJ, McCabe, DC, Wennberg, PO, Sorooshian, A, Murphy, SM, Dalleska, NF, Flagan, RC, and Seinfeld, JH (2007) Effect of NOx level on secondary organic aerosol (SOA) formation from the photooxidation of terpenes. Atmospheric Chemistry and Physics 7:5159 - 5174.
Ng, NL, Kwan, AJ, Surratt, JD, Chan, AWH, Chhabra, PS, Sorooshian, A, Pye, HOT, Crounse, JD, Wennberg, PO, Flagan, RC, and Seinfeld, JH (2008) Secondary organic aerosol (SOA) formation from reaction of isoprene with nitrate radicals (NO3) Atmospherics Chemistry and Physics 8: 4117 - 4140.
Pye, HOT, Chan, AWH, Barkley, MP, and Seinfeld, JH (2010) Global modeling of organic aerosol: the importance of reactive nitrogen (NOx and NO3) Atmospheric Chemistry and Physics 10(22): 11261-11276
Wexler, AS, and Seinfeld, JH (1990) The distribution of ammonium salts among a size and composition dispersed aerosol. Atmospheric Environment 24A: 1231 -  1246.
Wexler, AS, and Seinfeld JH (1991) 2nd-generation inorganic aerosol model.  Atmospheric Environment-Part A, 25:2731 -  2748.
Organization: we energies
Comment: 
we energies
We would also like to comment on the availability of additional modeling conducted by Alpine Geophysics and analyses by Environ Corp. that was recently presented to the Lake Michigan Air Directors Consortium (LADCO). This modeling is based on updated baseline data and more recent ozone and PM2.5 design values. Importantly, the results of this modeling reach the conclusion that both the ozone and PM2.5 objectives of the proposed rule can be achieved by 2014 with no new controls (with the possible exception of local controls at two locations). [EPA-HQ-OAR-2009-0491-2629.1, p.2]
Response: 
See preamble section V.C.2.

IV.C.2. How Did EPA Project Future Nonattainment and Maintenance for Annual PM2.5, 24-Hour PM2.5, and 8-Hour Ozone?

Organization: George Washington University Regulatory Study Center
Comment: 
George Washington University Regulatory Study Center
The preamble only reports a select comparison of Comprehensive Air Quality Model with Extensions (CAMx) model predictions with actual measured concentrations of PM in 2005: [EPA-HQ-OAR-2009-0491-2573.1, p.22]
"The two PM2.5 species that are most relevant for this proposal are sulfate and nitrate. For the summer months of June through August, when observed sulfate concentrations are highest in the East, the model predictions of 24-hour average sulfate were lower than the corresponding measured values by 7 percent at urban sites and by 9 to 10 percent at rural sites in the IMPROVE and CASTNET monitoring networks, respectively. For the winter months of December through February, when observed nitrate concentrations are highest in the East, the model predictions of 24-hour average particulate nitrate were lower than the corresponding measured values by 12 percent at urban sites and by 4 percent at rural sites in the IMPROVE monitoring network." [EPA-HQ-OAR-2009-0491-2573.1, p.22]
But this kind of comparison only tells a part of the story and is of limited value in understanding the uncertainty in the CAMx modeling results. The comparisons reported in the preamble -- measures of "bias" in the predicted concentrations -- indicate that across the predicted-observed pairs in the sample the overestimates are roughly balanced by the underestimates. This could be a comforting statistic if one is using the results to provide some average estimate across all the sites in the sample. However, the issue is with the variability in the model estimates at specific sites -- the non-attainment areas in the eastern U.S. Appendix A provides a second set of "error" measures -- the normalized mean error and the mean fractional error -- that suggest there is a substantial variation in estimates around the observed levels.46 (See Error! Reference source not found.) For summertime sulfate levels, these error measures range from 40 to 50 percent. And, for wintertime nitrate levels, these errors range from 50 to 100 percent. While these measures suggest significant variation in projected versus observed concentrations, they do not provide adequate information on the underlying distributions. EPA should use the underlying data used to generate these measures of model performance in developing an analysis of the variation for its projections of contribution and interference for downwind nonattainment areas. [EPA-HQ-OAR-2009-0491-2573.1, pp.22-23]

 46 These measures are based on the sum of the absolute value of the error between projected levels and observed levels. The general practice is to represent the variability in a distribution by calculating the variance of a distribution which would be based, in this case, on the sum of squares of the errors in projected and observed levels. The variance places a greater weight on large errors than is the case for the error measures reported in Appendix A.
Response: 
EPA has completed an expanded model performance evaluation using the predictions from the updated 2005 base year CAMx simulation conducted for the final Transport Rule.   This evaluation provides additional spatial and temporal performance results in response to comments.  The model performance results can be found in Appendix A of the Final Transport Rule Air Quality Modeling Technical Support Document.
Organization: Kansas City Board of Public Utilities (BPU)
Independence Power & Light (IPL)
Comment: 
Independence Power & Light (IPL)
EPA PLACES GREATER RELIANCE ON THE CAMx MODELING FOR DOWNWIND EMISSIONS THAN CAN BE JUSTIFIED EPA PLACES GREATER RELIANCE ON THE CAMx MODELING FOR DOWNWIND EMISSIONS THAN CAN BE JUSTIFIED
Although the level of detail suggests a very high degree of precision, closer analysis reveals that the modeling cannot bear the evidentiary weight assigned it. In particular, as shown on the attached letter from Mr. Hoffnagle of TRC, the modeling cannot ascribe upwind contributions to downwind states at an acceptable degree of accuracy beyond 200 kilometers and the error ranges surrounding the predicted results are high and vary from positive to negative in differing seasons, thus suggesting a high degree of variance in the estimated results. Given these issues, attempting to pinpoint based on this modeling the emissions reductions purportedly necessary at individual EGUs, as Appendix A does, simply is more than can be justified. [EPA-HQ-OAR-2009-0491-2741.1, pp.8-9]
EPA previously found that long range transport models, albeit not including CAMx, do not reproduce measured data beyond 200 kilometers. See Hoffnagle letter, citing interagency Workgroup on Air Quality Models (EPA-454/R-98-019). The Rule does not identify, much less refute, this concern despite the fact that many of the downwind nonattainment and maintenance sites are located significantly more than 200 kilometers of the upwind EGU. For example, the closest downwind 24-hour PM25 nonattainment sites of the 17 Missouri sites (75 FR at 45257, Table IV.C-14) to IPL's Blue Valley Power Plant is St. Clair County, n, which is 386 kilometers from IPL's EGU. As this is nearly double the distance at which long range transport models lose accuracy (and, of course, the other 16 listed downwind sites for Missouri, id., are even farther away), it is highly questionable that the model has accurately predicted the Blue Valley plant's actual contribution in St. Clair or the other sites. [EPA-HQ-OAR-2009-0491-2741.1, pp.9-10]
This conclusion is further supported by the facts that the model does not measure PM2.5 at the downwind monitoring sites, but measures individual species of particulate at the upwind sources. Hoffnagle letter at ¶ 3; see 45 FR at 45253/1 ('CAMx employs enhanced source apportionment techniques which track the formation and transport of ozone and particulate matter from specific emission sources and calculates the contribution of sources and precursors to ozone and PM2 5 for individual receptor locations'). As a result, no error rates are available for PM2.5 projections at the sites, but only for sulfates and nitrates at the upwind sources. Jd. The sulfate and nitrate error rates shows the models under- and over-predict at different times of the year, which means a relatively wide confidence interval related to any prediction. Jd. Similar error rate problems are present for the ozone modeling. Hoffnagle letter at ¶ 20. [EPA-HQ-OAR-2009-0491-2741.1, p.10]
The practical effect of these error rates has been recognized in the SIP process where predicted results are calibrated to measured results for the purpose of eliminating model variance when applied to a specific area. Hoffnagle letter at ¶ 4. No such calibration was undertaken in connection with the predicted results used in development of the predicted upwind contributions at numerous downwind sites. Id. This omission opens the possibility that the predictions vary substantially from what actual measured emissions would be at any specific site. The Rule does not address this possibility, despite the fact eliminating such variances could dramatically affect the predicted estimates of upwind contributions. [EPA-HQ-OAR-2009-0491-2741.1, pp.10-11]
The need for calibration in light of the wide confidence intervals is heightened because the purported contributing emissions from any single source as tiny numbers. For example, Mr. Hoffnagle estimates that IPL's Blue Valley unit will represent 0.0075% of 2012 Missouri S02 emissions and 0.00092% of 2012 Missouri NOx emissions. Id. at ¶ 6. Absent some precise calibration that was not done, it seems highly likely the Blue Valley emissions are 'lost in the noise' surrounding the total Missouri level. Further, as the upwind 'contributions to downwind nonattainment and maintenance receptors for the Transport Rule were calculated using a relative approach,' 75 FR at 45254, it is evident that IPL's Blue Valley emissions will have a nearly imperceptible effect on the downwind sites. For example, Mr. Hoftnagle calculates that effect of completely eliminating IPL's Blue Valley NOx emissions would produce a 0.00093 ppb reduction in St. Clair, II's maximum ozone concentration, assuming Missouri were entirely responsible for all St. Clair's ozone concentration. Hoffnagle letter at ¶ 7. Similar results apply for PM2.5 concentrations and would also apply to other sites. Id. [EPA-HQ-OAR-2009-0491-2741.1, p.11]
These numbers on their own are well below what can be accurately measured, let alone what can be accurately estimated. And that is not even considering the high error rate and the long range inaccuracy of the modeling used in the Rule. The degree of precision that EPA proposes for the Rule and Appendix A in setting 2012 allowances for individual EGUs is unwarranted. This, in tum, means that the conclusions reached are not supported by the facts on which EPA relied, which indicates arbitrary and capricious decision-making. [EPA-HQ-OAR-2009-0491-2741.1, p.11]
Kansas City Board of Public Utilities (BPU)
EPA PLACES GREATER RELIANCE ON THE CAMx MODELING FOR DOWNWIND EMISSIONS THAN CAN BE JUSTIFIED EPA PLACES GREATER RELIANCE ON THE CAMx MODELING FORDOWNWIND EMISSIONS THAN CAN BE JUSTIFIED
Although the level of detail suggests a very high degree of precision, closer analysis reveals that the modeling cannot bear the evidentiary weight assigned it. In particular, as shown on the attached letter from Mr. Hoffnagle of TRC, the modeling cannot ascribe upwind contributions to downwind states at an acceptable degree of accuracy beyond 200 kilometers and the error ranges surrounding the predicted results are high and vary from positive to negative in differing seasons, thus suggesting a high degree of variance in the estimated results. Given these issues, attempting to pinpoint based on this modeling the emissions reductions purportedly necessary at individual EGUs, as Appendix A does, simply is more than can be justified. [EPA-HQ-OAR-2009-0491-2740.1, p.15]
EPA previously found that long range transport models, albeit not including CAMx, do not reproduce measured data beyond 200 kilometers. See Hoffnagle letter at  ¶ I, citing interagency Workgroup on Air Quality Models (EPA-454/R-98-019). The Rule does not identify, much less refute, this concern despite the fact that many of the downwind nonattainment and maintenance sites are located more than 200 kilometers of the upwind EGU. For example, the closest downwind 24-hour PM25 maintenance site of the two Kansas linked sites (75 FR at 45266, Table IV.C-18) or the single linked 8-hour ozone maintenance site to BPU's electric generating units is Muscatine IA, which is 400 kilometers away. As this is virtually double the distance at which long range transport models lose accuracy (and, of course, the other 2 sites for Kansas - Dallas TX and Milwaukee, WI - id., are even farther away), it is highly questionable that the model has accurately predicted the BPU units' actual contribution in Muscatine or the other two sites. [EPA-HQ-OAR-2009-0491-2740.1, p.15]
This conclusion is further supported by the facts that the model does not measure PM25 at the downwind monitoring sites, but measures individual species of particulate at the upwind sources. Hoffnagle letter at  ¶ 3; see 45 FR at 45253/1 ('CAMx employs enhanced source apportionment techniques which track the formation and transport of ozone and particulate matter from specific emission sources and calculates the contribution of sources and precursors to ozone and PM,s for individual receptor locations'). As a result, no error rates are available for PM25 projections at the sites, but only for sulfates and nitrates at the sources. Hoffnagle letter at  ¶ 3. The sulfate and nitrate error rates show the models under- and over-predict at different times of the year, which means a relatively wide confidence interval related to any prediction. Id. Similar error rate problems are present for the ozone modeling. Hoffnagle letter at ~ 2.  [EPA-HQ-OAR-2009-0491-2740.1, pp.15-16]
The practical effect of these error rates has been recognized in the SIP process where predicted results are calibrated to measured results for the purpose of eliminating model variance when applied to a specific area. Hoffnagle letter at  ¶ 4. No such calibration was undertaken in connection with the predicted results used in development of the predicted upwind contributions at numerous downwind sites. Id. This omission opens the possibility that the predictions vary substantially from what actual measured emissions would be at any specific site. The Rule does not address this possibility, despite the fact eliminating such variances could dramatically affect the predicted estimates of upwind contributions.  [EPA-HQ-OAR-2009-0491-2740.1, p.16]
The need for calibration in light of the wide confidence intervals is heightened because the purported contributing emissions from BPU is a relatively small fraction of the total Kansas number. For example, Mr. Hofnagle estimates that BPU's units will represent 9.5% of 2012 Kansas S02 emissions and 1.9% of 2012 Kansas NOx emissions. Id. at  ¶ 6. Mr. Hoffnagle calculates that BPU's units are responsible for 0.04 ppb reduction in Dallas' maximum ozone concentration, which is insufficient to have a serious effect on compliance there. Hoffnagle letter at  ¶ 7. BPU's portion of the Kansas total for PM2 5 concentrations at Milwaukee is even smaller, and thus would have a much lesser effect there. Id. at  ¶ 8.  [EPA-HQ-OAR-2009-0491-2740.1, p.16]
These numbers also must be considered in light of the high error rate and the long range inaccuracy of the modeling used in the Rule. When those considerations are factored into the analysis, they raise serious concerns about the degree of precision that EPA proposes for the Rule and Appendix A in setting 2012 allowances for individual EGUs. Failure to address those considerations is evidence of arbitrary and capricious decisionmaking. [EPA-HQ-OAR-2009-0491-2740.1, p.17]
Response: 
EPA disagrees with this comment.  The commenter describes distance limitations and accuracy of non-steady-state puff dispersion models from long-range transport from large point sources to distant Class I areas.  Such models are designed primarily for use in modeling the impacts of inert pollutants in support of analyses relevant to Prevention of Significant Deterioration (PSD) (See 40 CFR Part 51 Appendix W).   The commenter incorrectly assumes that the limitations and accuracy of non-steady-state long-range transport models are also applicable and relevant to photochemical grid models, like CAMx.   CAMx is specifically designed for simulation of ozone, PM2.5 and other pollutants over many spatial scales ranging from sub-urban to continental (Environ, 2010).  EPA has identified CAMx as one of several candidate models that are applicable for use by states in attainment demonstration modeling for ozone, PM2.5 and regional haze State Implemetation Plans.  EPA has successfully used grid-based photochemical models for applications on regional and national scales in support of numerous rulemakings (Light Duty Greenhouse Gas Rule: EPA-HQ-OAR-2009-0472; Heavy Duty Greenhouse Gas Rule: EPA-HQ-OAR-2010-0162; Reformulated Fuels-II: EPA-HQ-OAR-2005-0161; C-3 Commercial Marine Engine Rule:  EPA-HQ-OAR-2007-0121; and Locomotive/Marine Engine Rule: EPA-HQ-OAR-2003-0190).
EPA provides model performance results for sulfate and nitrate as well as other components of PM2.5 in Appendix A of the Air Quality Modeling Technical Support Document. 
Contrary to the assertion by the commenter, EPA does use measured data to provide the foundation for projection of PM2.5 concentrations.  The procedures used by EPA for coupling model predictions with measured data for use in projecting PM2.5 concentrations for the Transport Rule are described in the Air Quality Modeling Technical Support Document.  These procedures are consistent with recommendations in EPA's modeling guidance for ozone and PM2.5  attainment demonstrations (EPA-HQ-2009-0491-4361).
In interpreting the purported contributions from the individual sources cited, the commenter fails to recognize the importance of these contributions as part of the "collective contribution" that comprises transported ozone and PM2.5 (see preamble section V.D.1).  The commenter also fails to acknowledge that the relative contributions from individual sources on cumulative impacts depends on several factors in addition to emissions such as distance, meteorology, and chemical transformation.
Organization: Kentucky Division for Air Quality
Comment: 
Kentucky Division for Air Quality
More Recent Ambient Air Quality Data Should Have Been Utilized in EPA's Modeling
Pursuant to the proposed Transport Rule IV.C.2., How did EPA project future nonattainment and maintenance for the 1997 and 2006 air quality standards (75 FR 45246), EPA's approach for projecting future ozone and PM2.5 design values involved the use of 2003-2007 ambient air quality data. The Division finds that this approach to be somewhat lacking when more recent data for 2007-2009 was available. The use of more recent air quality data in EPA's modeling analysis for the proposed Transport Rule may have provided different final modeling results by more realistically capturing some of the air quality benefits and improvements provided by CAIR which began on January1, 2009. [EPA-HQ-OAR-0491-2805.1, p.6]
Response: 
See preamble section V.C.2.
Organization: New York State Department of Environmental Conservation
Comment: 
New York State Department of Environmental Conservation
Other factors are unknown as to how this analysis was conducted, such as whether alternate selection criteria for the RRF calculation (e.g., top 5 percent of modeled days in each quarter) were considered and if not, why not, what was the impact of alternative criteria, and why was the 10 percent criterion selected. For calculating quarterly ambient PM2.5 concentrations and species fractions, it is unclear if criteria other than the 'top 10 percent days' were considered and what the impact was of alternative criteria, These aspects of the analysis should be clarified. When calculating 8-hr ozone interstate contributions for the 2012 base case, no RRF and no interstate contributions were calculated at monitors where there are fewer than five days with modeled daily max 8-hr ozone concentrations less than 70 ppb in the 2012 base case simulations. However, EPA should clarify if there are any monitors where this criterion meant that no interstate contributions could be calculated and where they might be located, and what their 2012 base case design value / maximum design values were. [EPA-HQ-OAR-2009-0491-2730.1, p.11]
Response: 
EPA calculated the "high" ambient days and "high" modeled days based on the top 10% of measured or modeled days in each quarter.  While we could have used an alternative definition of high days, we believe the choice of 10% is reasonable and appropriate for the reasons explained below. 
Ambient PM2.5 FRM monitoring sites collect filter based samples on either a daily basis or once every 3 or 6 days.  For these sites, the top 10% of days varies between 1 and 9 days per quarter (depending of the sampling frequency).  The majority of sites operate on a 1 in 3 day schedule.  The top 10% of days at these sites (if data is complete for every schedule sampling day) is 3 days per quarter.  The CAMx model output contains data for every day of the year.  Therefore, from the model output, the top 10% of days per quarter is always 9 days. 
In the attainment test, we want to average a number of days together, so that the species fractions and/or relative response factors are relatively robust.  The goal is to represent the average conditions on high days.  At the same time, we do not want to average together too many days because the average of a large number of days will not adequately represent the "high" days or the 98[th] percentile.  Therefore we believe the choice of 10% (which in most cases is 3 to 9 days per quarter) is a good compromise between averaging too many days and too few days.  As such, use of the top 10% of days per quarter is the default recommendation in the updated 24-hour PM2.5 attainment test guidance. Therefore, EPA is using the top 10% of days per quarter in all of our future year 24-hr PM2.5 design value calculations and we have made the top 10% of ambient and modeled days the default setting in the MATS attainment test software.
In response to the comment related to the minimum number of days in the ozone attainment test and contribution test:  In the final rule modeling, there are at least 5 modeled days above 70 ppb at every ozone monitor with a base year 2003-2007 five year weighted average concentration of 80 ppb or greater.  Therefore, there is a projected 2012 design value for every monitor that has the potential to have a design value greater than or equal to 85 ppb in the future (2012).  On the contribution calculation side, in the final rule modeling there are 16 monitors which are projected as ozone nonattainment and/or maintenance sites in 2012.  Of those, contributions were not calculated at 6 sites because there were fewer than 5 modeled days above 70 ppb in 2012 at those sites.  All 6 of those monitoring sites are in Harris County Texas.  Of note, there are an additional 2 nonattainment and 2 maintenance sites in Harris County where contributions were calculated.    
Organization: Tampa Electric Company
Comment: 
Tampa Electric Company
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.71.]
We also find it curious the model finds that emissions generated in Florida have downwind effects in Georgia and Texas for ozone non-attainment, but does not have an effect on Louisiana or Alabama. This seems to be evidence of the need to use human judgment in interpreting the model. Don't just assume the output is wholly infallible.
Response: 
Based on the air quality modeling for the Final Transport Rule, Florida contributes to 8-hour ozone in amounts at or above the 0.8 ppb threshold to a total of 26 monitoring sites in 6 other States (i.e., Alabama, Georgia, Louisiana, Mississippi, South Carolina, and Texas).  However, only 2 of these sites, both in Harris county, Texas are projected to be nonattainment and/or have maintenance problems for the 1997 8-hour ozone NAAQS for 2012 base case and are, therefore, relevant receptors for the Transport Rule.
Organization: Westar Energy, Inc.
Comment: 
Westar Energy, Inc.
EPA PLACES GREATER RELIANCE ON THE CAMX MODELING FOR DOWNWIND EMISSIONS THAN CAN BE JUSTIFIED [EPA-HQ-OAR-2009-0491-2757.1, p.14]
To determine the impact of upwind emissions on downwind nonattainment and maintenance locations, EPA employed the 'CAMx photochemical apportionment modeling to quantify the impact of emissions in specific upwind states on projected downwind nonattainment and maintenance receptors for both PM2.5 and 8-hour ozone.' 75 FR at 4525311. The Rule states that this approach is 'particularly well-suited for quantifying interstate contributions' because it 'explicitly tracks the formation and transport of all ozone and PM 2.5 mass.' Id. at 45253/2. [EPA-HQ-OAR-2009-0491-2757.1, p.14]
For contribution modeling, EPA employed similar tagging approaches to track PM 2.5 and ozone source category, species, and precursor emissions. 75 FR at 4525411-2. EPA then determined 'those monitoring sites which are projected to exceed the NAAQS in the 2012 base case, and calculated that contribution to nonattainment and maintenance separately at those sites using the single largest contribution for each upwind State in 2012. Id at 45254-55 & Table IV.C-13. This modeling resulted in a list of downwind nonattainment and maintenance sites linked to upwind States. See 75 FR at 45258-67 (tables for PM2.5) and 45267-70 (tables for ozone). [EPA-HQ-OAR-2009-0491-2757.1, pp.14-15]
Although the level of detail suggests a very high degree of precision, closer analysis reveals that the modeling cannot bear the evidentiary weight assigned it. In particular, as shown on the attached letter from Mr. Glen Hoffnagle of TRC, the modeling cannot ascribe upwind contributions to downwind states at an acceptable degree of accuracy beyond 200 kilometers. The error ranges surrounding the predicted results are high and vary from positive to negative in differing seasons, thus suggesting a high degree of variance in the estimated results. Given these issues, attempting to pinpoint the emissions reductions purportedly necessary at individual EGUs, as Appendix A does, simply is more than can be justified. [EPA-HQ-OAR-2009-0491-2757.1, p.15]
EPA itself previously found that long range transport models, albeit not including CAMx, do not reproduce measured data beyond 200 kilometers. See Interagency Workgroup on Air Quality Models (EPA-454/R-98-019). The Rule does not identify, much less refute, this concern despite the fact that many of the downwind nonattainment and maintenance sites are located significantly more than 200 kilometers from the upwind EGD. For example, the closest downwind 24-hour PM2.5 maintenance site of the two Kansas linked sites (75 FR at 45266, Table IV.C-18) or the single linked 8-hour ozone maintenance site to Westar's electric generating units is Muscatine IA, which is 473 kilometers away. As this is more than double the distance at which long range transport models lose accuracy (and, of course, Dallas and Milwaukee, the other two Kansas downwind sites, id., are more than 700 kilometers from Westar's units), it is highly questionable that the model has accurately predicted Westar's actual contribution to those three sites. [EPA-HQ-OAR-2009-0491-2757.1, pp.15-16]
This conclusion is further supported by the facts that the model does not predict PM2.5 at the downwind monitoring sites, but predicts individual species of particulate at the upwind sources. Hoffnagle letter; see 45 FR at 45253/1 ('CAMx employs enhanced source apportionment techniques which track the formation and transport of ozone and particulate matter from specific emission sources and calculates the contribution of sources and precursors to ozone and PM2.5 for individual receptor locations'). As a result, no error rates are available for PM2.5 projections at the sites, but only for sulfates and nitrates at the sources. Id. The sulfate and nitrate error rates shows the models under- and over-predict at different times of the year, which means a relatively wide confidence interval related to any prediction. Id. Similar error rate problems are present for the ozone modeling. Hoffnagle letter. [EPA-HQ-OAR-2009-0491-2757.1, p.16]
The practical effect of these error rates has been recognized in the SIP process where predicted results are calibrated to measured results for the purpose of eliminating model variance when applied to a specific area. Hoffnagle letter. No such calibration was undertaken in connection with the predicted results used in development of the predicted upwind contributions at numerous downwind sites. Id. This omission opens the possibility that the predictions vary substantially from what actual measured emissions would be at any specific site. The Rule does not address this possibility, despite the fact that eliminating such variances could dramatically affect the predicted estimates of upwind contributions. [EPA-HQ-OAR-2009-0491-2757.1, p.16]
The import of these types of problems is reflected in the attached Trinity Report at p. 5-1 [See p.28 of this comment summary for the Trinity Report], which concludes that the proposed emissions reductions at Westar's units will have a very small impact on the linked downwind sites. For the Dallas downwind site, the effect of the 2012 NOx and S02 emission reductions from the Jeffrey Energy Center Units is estimated to be 0.043 ppb, or less than 0.05% of the original design value. This result occurs because other factors, specifically that the monitor is VOC-limited, affect whether the ozone concentration at the Dallas monitor is responsive to NOx emission changes. Id. Consequently, it is an open question how effective a NOx control at Westar's Jeffrey Units will be in alleviating ozone formation at the Dallas monitor. [EPA-HQ-OAR-2009-0491-2757.1, pp.16-17]
A similar disconnect between expectation and reality occurs with regard to the effects of NOx and S02 reductions at the Jeffrey Units. As adjusted by Trinity, the NOx and S02 reductions at the Jeffrey Units will account for approximately 13% and 4% reductions of each pollutant. But the effect of those reductions on the Milwaukee and Muscatine downwind sites linked to Kansas are much less impressive. The Milwaukee monitor would experience only a 0.04% proportionate reduction, while Muscatine's proportionate reduction of 0.3%. Trinity Report at 5-1. Again, the very low proportionate reduction at Milwaukee appears to be due to factors other than Jeffrey Units reduced emission. Specifically, because of the Milwaukee monitor's proximity to Lake Michigan, it, like other monitors near large bodies of water, has a low response to the NOx and the S02 reductions due to ambient conditions in those areas and the non-linear relationship between the formation of certain PM25 species and precursor emissions. Id. The point in all this comes down to the fact that these proceedings involve complicated matters that change under actual real world scenarios but the effects of those changes have not been factored into the current modeling. Thus, that modeling has only limited usefulness in determining what downwind reductions will result from what projected emissions restrictions at upwind sources, and does not provide the type of certainty that is suggested by the very specific EGU allowances set forth in Appendix A of the Rule.  [EPA-HQ-OAR-2009-0491-2757.1, p.17]
Response: 
EPA disagrees with this comment.  The commenter describes distance limitations and accuracy of gaussian long-range transport models that are designed primarily for use in modeling inert pollutants in support of analyses relevant to Prevention of Significant Deterioration (PSD) (See 40 CFR Part 51 Appendix W).   The commenter incorrectly assumes that the limitations and accuracy of gaussian long-range transport models are also applicable and relevant to photochemical grid models, like CAMx.   CAMx is specifically designed for simulation ozone, PM2.5 and other pollutants over many spatial scales ranging from sub-urban to continental (Environ, 2010).  EPA has identified CAMx as one of several candidate models that are applicable for use by states in attainment demonstration modeling for ozone, PM2.5 and regional haze State Implementation Plans.  EPA has successfully used grid-based photochemical models for applications on regional and national scales in support of numerous rulemakings (Light Duty Greenhouse Gas Rule: EPA-HQ-OAR-2009-0472; Heavy Duty Greenhouse Gas Rule: EPA-HQ-OAR-2010-0162; Reformulated Fuels-II: EPA-HQ-OAR-2005-0161; C-3 Commercial Marine Engine Rule:  EPA-HQ-OAR-2007-0121; and Locomotive/Marine Engine Rule: EPA-HQ-OAR-2003-0190).
EPA provides model performance results for sulfate and nitrate as well as other component of PM2.5 in Appendix A of the Air Quality Modeling Technical Support Document. 
Contrary to the assertion by the commenter, EPA does use measured data to provide the foundation for projection of PM2.5 concentrations.  The procedures used by EPA for coupling model predictions with measured data for use in projecting PM2.5 concentrations for the Transport Rule are described in the Air Quality Modeling Technical Support Document.  These procedures are consistent with recommendations in EPA's modeling guidance for ozone and PM2.5 attainment demonstrations ( EPA-HQ-2009-0491-4361).
In interpreting the purported contributions from the individual sources cited, the commenter fails to recognize the importance of these contributions as part of the "collective contribution" that comprises transported ozone and PM2.5 (see preamble section V.D.1)
The commenter provided no data to support the contention that monitoring locations near large bodies of water have a low response to emissions. 
The EGU allowances are not based on the air quality contributions from individual units (see preamble section VII for procedures used by EPA for emissions allocations).
IV.C.3. How Did EPA Assess Interstate Contributions to Nonattainment and Maintenance?

Organization: Calpine Corporation
Comment: 
Calpine Corporation
We agree with the methodology whereby EPA modeled emissions of fine particulate matter (PM2.5) and ozone precursors in order to determine which upwind areas contributed significantly to downwind state's nonattainment problems. [EPA-HQ-OAR-2009-0491-3614,p .2]
Response: 
We appreciate the commenter's support.
Organization: Entergy Services, Inc.
Louisiana Chemical Association (LCA)
Comment: 
Entergy Services, Inc.
The EPA Projection that Louisiana Emissions Sources Will Interfere With Maintenance in Harris County, Texas, Is Flawed.  EPA Has Projected Significant Reductions of SO2 and NOx Even Without the Transport Rule and FIP
Entergy adopts comment E.1 made by the Louisiana Chemical Association. In addition to the comments above, Entergy believes that EPA's projection that Louisiana emissions will interfere with maintenance of the annual PM2.5 NAAQS at the Clinton Drive monitor without further controls is flawed.   EPA modeling shows that virtually the entire impact on PM2.5 annual levels at the Clinton Drive monitor are due to sulfate emissions.  The following data, taken from EPA Preamble Tables IV.C-1, IV.C-3 and IV.C-5, and based on the IPM v.3.02 modeling, demonstrate that SO2 emissions from Louisiana will significantly decline, without enactment of the Transport Rule or a FIP: [EPA-HQ-OAR-2009-0491-2847.1,p.10] [[See Docket Number EPA-HQ-OAR-2009-0491-2847.1, p.10 for a table with the data.]]
Louisiana Chemical Association (LCA)
The EPA Projection that Louisiana Emissions Sources Will Interfere With Maintenance in Harris County, Texas, Is Flawed. EPA Has Projected Significant Reductions of SO2 and NOx Even Without the Transport Rule and FIP. [EPA-HQ-OAR-2009-0491-3527.1, p. 10]
In addition to the comments above, LCA believes that EPA's projection that Louisiana emissions will interfere with maintenance of the annual PM2.5 NAAQS at the Clinton Drive monitor without further controls is flawed because EPA overestimated Louisiana emissions in the emissions inventory, failed to account for reductions that will occur due to federal and state enforceable measures, and due to potential modeling errors. Each of these flaws is discussed in more detail below. However, even without correction of those errors, it is readily apparent that even using the flawed projections, it is not reasonable for EPA to conclude that Louisiana emissions will interfere with maintenance in Harris County. [EPA-HQ-OAR-2009-0491-3527.1, p. 10]
Response: 
EPA has conducted revised air quality modeling with updates based on comments on the modeling platform used for the proposed rule.  In the revised modeling there are no monitoring sites in Texas with projected 2012 base case nonattainment or maintenance problems for the annual PM2.5 NAAQS.   In addition, Louisiana is not identified in the final rule as a state with emissions that significantly contribute or interfere with maintenance of the 1997 or 2006 PM2.5 NAAQS.
Organization: Maryland Department of Environment (MDE)
Comment: 
Maryland Department of Environment (MDE)
The results of the significant contribution analysis are consistent with MDE scientific research. While all air quality model results are a source of considerable uncertainty, the linkages between upwind and downwind states identified in the CAMx source apportionment modeling verify that pollution transport occurs. Research by the University of Maryland - Baltimore County, Howard University, and University of Maryland - College Park has shown differences between long-range transport of ozone and long-range transport of fine particles. High ozone episodes in Maryland are most often accompanied by a westerly wind component and or the late night/early morning occurrence of the nocturnal low level jet (NLLJ). The westerly wind transports ozone, PM2.5 and precursors from the Midwest into Maryland. The NLLJ transports ozone and pollutant precursors from the south into Maryland. In general high fine particulate concentrations are most often accompanied by southwesterly flow. For further information on Maryland research regarding transport of ozone, please see Appendix A: Ozone Reservoir [See EPA-HQ-OAR-2009-0491-2639.2, p.22 for comments pertaining to Appendix A] . [EPA-HQ-OAR-2009-0491-2639.2, p.6]
EPA's Transport Rule analysis is consistent with these Maryland findings. The 24-hour PM2.5 nonattainment and maintenances sites located in Baltimore and Glen Burnie are linked to New Jersey, New York, Ohio, Pennsylvania, and West Virginia, as well as to southern states such as Virginia, North Carolina and Georgia (See Table IV.C-17, on preamble pages 75 FR 45262-45265, September 14, 2010). [EPA-HQ-OAR-2009-0491-2639.2, p.6]
The significant contribution analysis is strengthened by the use of relative response factors and monitor observations. The two federally-approved photochemical models, CMAQ and CAMx, have shown serious discrepancies when each models the same event. However, these models are more consistent when "relative" model results are evaluated instead of absolute results [Hogrefe, et al., Rethinking the assessment of photochemical modeling systems in air quality planning applications, J. Air & Waste Manage. Assoc., 58, 1086 - 1099 (2008)]. The EPA has addressed an important source of model uncertainty by using Relative Response Factors for both identifying nonattainment and maintenance sites and the source apportionment process. The use of real monitor data in these calculations adds an important "reality check" on the contribution amounts. In addition, the use of five years of monitor data instead of one year ensures that naturally variable annual meteorology does not bias the outcome. [EPA-HQ-OAR-2009-0491-2639.2, pp.6-7]
Response: 
EPA agrees that pollutants from certain upwind states contribute to air quality in other downwind states/  EPA has conducted revised air quality modeling with updates based on comments on the modeling platform used for the proposed rule.  
Organization: Minnesota Power 
Comment: 
Minnesota Power 
Remodel state contributions to nonattainment before rule finalization.  EPA should repeat their air quality modeling analysis, giving consideration to the most recent air quality data (2007 to 2009) and post 2005 emissions control reductions to confirm that the air quality nonattainment areas identified by EPA as significantly impacted by Minnesota and other evaluated state emissions will still be in nonattainment  in the 2012 to 2014 time frame.  Considering analysis performed on Proposed Transport Rule state nonattainment area impacts by Alpine Geophysics and Environ for the Midwest Ozone Group and submitted as comments to this Docket, there is good cause to expect that the annual and 24 hour average PM2.5 standards nonattainment areas cited by EPA as a basis for Minnesota inclusion in the Transport Rule will have reestablished attainment with the NAAQS around the timing EPA is proposing imposition of the 2012 state SO2 and NOx emissions budgets.  [EPA-HQ-OAR-2009-0491-2750.1, p.5]  
Transport Rule modeling cross-check findings.  Analysis of the Transport Rule modeling by the Midwest Ozone Group that was co-funded by MP indicates that the nonattainment areas identified by EPA as significantly impacted by Minnesota emissions are modeled to come into attainment with the ozone and PM2.5 daily and annual NAAQS with no further reductions beyond what is already being required for the current CAIR state reductions using the most recent ground level air quality data. EPA should remodel their Transport Rule determinations to use the more current data before assigning more control obligations i.e. to Minnesota, affirming that the nonattainment areas examined for the Transport Rule are still projected to be in nonattainment in 2012.  [EPA-HQ-OAR-2009-0491-2750.1, p.8]
Response: 
As part of the final rule EPA has remodeled state contributions to nonattainment and maintenance using a modeling platform with updates based on comments on the proposed rule.  The results of the updated contribution modeling are in section V.D.2 of the preamble. Response to comments on the use of most recent air quality data and on the modeling by the Midwest Ozone Group are in section V.C.2 of the preamble.
Organization: New York State Department of Environmental Conservation
Comment: 
New York State Department of Environmental Conservation
Methodology to Project Attainment/Interference with Maintenance Based on CAMx Modeling
For projecting future average/maximum design values for the daily PM2.5 standard, simulated concentrations of the 'other/crustal' component were excluded when determining top 10 percent 'high modeled PM2.5 days' for each quarter for relative response factor (RRF) calculations. This approach points to a disconnect between observed ''high days' and modeled 'high days' which may have implications for the determination of significant contribution and/or nonattainment/maintenance monitors, as well as determining if high observed sulfate/nitrate days correspond to high modeled sulfate/nitrate days. [EPA-HQ-OAR-2009-0491-2730.1, p.11]
Response: 
EPA found that the modeled concentrations of the other/crustal component far exceeded the corresponding measured concentrations (see the Air Quality Modeling Technical Support Document Appendix A).  In order to minimize any disconnect between the relative amounts of sulfate and nitrate on high modeled days with that on high measured days, EPA removed the concentrations of the other/crustal component in determining the modeled days to include in the calculation of relative response factors.  
Organization: Southern Company
Comment: 
Southern Company
EPA should re-run the CAMx model for the 2012 base case with appropriately corrected emissions to determine the corrected air quality contributions for each state to each appropriate (i.e., after considering monitored AND modeled attainment status) downwind monitor in 2012. [EPA-HQ-OAR-2009-0491-2864.1, p. 39]
Response: 
EPA has used CAMx to re-model the 2012 base case with the appropriately corrected emissions to determine the air quality contributions for each state to each downwind nonattainment and maintenance receptor in 2012.
Organization: State of Wisconsin, Department of Natural Resources
Comment: 
State of Wisconsin, Department of Natural Resources
The air quality modeling platform used by EPA in its assessment of interstate contribution to violating air quality mirrors that used by most regions in support of local attainment demonstrations and is therefore appropriate for assessing Section 110 impacts. In the application of the modeling platform EPA's modeling inventory and adjustments of assessment years and meteorology patterns also appear reasonable. Performance metrics are in line with similar evaluations pursued by states within their regional organizations. [EPA-HQ-OAR-2009-0491-2829.2, p.6]
Response: 
EPA agrees that the air quality modeling platform used in the Transport Rule to assess interstate contributions is appropriate for this purpose.
Organization: Sunflower Electric Power Corporation
Comment: 
Sunflower Electric Power Corporation
Unlike the reduction in significant contribution found to result from the control of pollutants as identified in Comment 3 above, a similar reduction in significant PM2.5 contribution modeled did not occur at the five Muscatine, IA and Milwaukee, WI receptors which EPA has concluded are significantly influenced by Kansas EGUs. We think, and our consultant alludes to this possibility in the aforementioned report, that the complexity of the atmospheric chemical reactions, at least at the distance from the sources that will result should Kansas sources be included, are not well enough understood to assure that the additional control of Kansas sources will have any significant reduction in air quality at those receptors. [EPA-HQ-OAR-2009-0491-2833.1 p.2]
Because the reductions at the Kansas EGUs referenced in the report will reduce the total SO2 loading from Kansas EGUs by 4%, and the total NOX loading by 44% at an improvement in PM2.5 concentrations of less than 0.34%, one might reasonably conclude that the complete elimination of the entire SO2 and NOX loading from EGUs in Kansas would result in an insignificant improvement in the PM2.5 concentrations in those distant cities. Thus the complete elimination of the EGU sources would still result in the Kansas EGUs as being judged to still have a significant impact on the air-sheds when the sources no longer exist. It seems to us at least that this is an absurd outcome brought about by the extension of incomplete information using modeling methods that have unknown algorithms and which on the surface produce more questions than have yet been answered. [EPA-HQ-OAR-2009-0491-2833.1 p.2]
We respectfully request that EPA reconsider the implications of outcomes such as those presented by our consultant and not rush to regulate where such questions still exist. At a minimum this information should lead to a further extension of the comment period to evaluate further the implications of the determinations thus far made by EPA. [EPA-HQ-OAR-2009-0491-2833.1 p.3]
Response: 
EPA has conducted revised air quality modeling with updates based on comments on the modeling platform used for the proposed rule including the EGU reductions referenced by the commenter (needs to be confirmed by CAMD).
The results of the modeling by Trinity referenced by the commenter indicates that Kansas contributes PM2.5 above the 1 percent of the NAAQS threshold to nonattainment of the 24-hour PM2.5 NAAQS in Milwaukee.  This finding is consistent with the results of EPA's updated air quality modeling for contributions of annual NOx and SO2 emissions from Kansas and that Kansas. 
Organization: West Virginia Department of Environmental Protection
Comment: 
West Virginia Department of Environmental Protection
WVDAQ finds it difficult to believe that EPA has determined that West Virginia significantly contributes to non-attainment St. Louis, Missouri. We believe that EPA needs to provide more explanation when model results are blatantly counter to expected outcomes. [EPA-HQ-OAR-2009-0491-2790.1, p. 7]
Response: 
EPA performed a back trajectory analysis to identify the 3-day upwind transport history of air parcels crossing the Madison county, Missouri (East St Louis) monitoring site on days with measured exceedances of the 24-hour PM2.5 NAAQS at this location during 2005 (the year of meteorology modeled for the Transport Rule) and in other years during the period 2003 through 2007 (see Air Quality Modeling Technical Support Document).  The results indicate that there are exceedance days in 2005 when the air arriving in Madison county is likely to have traversed portions of West Virginia within 3 days of arriving in this county.  The trajectory analysis provides qualitative evidence that corroborates the result of EPA's modeling which links emissions in West Virginia to nonattainment for 24-hour PM2.5 in Madison county, Missouri.

IV.C.4. What Are Estimated Interstate Contributions to Annual PM2.5, 24-Hour PM2.5, and 8-Hour Ozone Nonattainment and Maintenance?

Organization: Florida Municipal Electric Association (FMEA)
Comment: 
Florida Municipal Electric Association (FMEA)
In addition, the model projections of significant impacts appear to defy common sense. For example, it is hard to imagine that Florida emissions could result in a significant impact on non-attainment on Texas. [EPA-HQ-OAR-2009-0491-2731.1, p. 10]
Response: 
Based on the air quality modeling for the Final Transport Rule, Florida contributes to 8-hour ozone in amounts at or above the 0.8 ppb threshold to a total of 26 monitoring sites in 6 other States (i.e., Alabama, Georgia, Louisiana, Mississippi, South Carolina, and Texas).  However, only 2 of these sites, both in Harris county, Texas are projected to be nonattainment and/or have maintenance problems for the 1997 8-hour ozone NAAQS for 2012 base case and are, therefore, relevant receptors for the Transport Rule. 
EPA performed a back trajectory analysis to identify the 3-day upwind transport history of air parcels crossing the Harris county, Texas (Houston) 2012 nonattainment and/or maintenance monitoring sites on days with measured exceedances of the 8-hour ozone NAAQS at this location during 2005 (the year of meteorology modeled for the Transport Rule) and in other years during the period 2003 through 2007.  The results indicate that there are ozone exceedance days in 2005 when the air arriving in Harris county is likely to have traversed portions of Florida within 3 days of arriving in this county.  The trajectory analysis provides qualitative evidence that corroborates the results of EPA's modeling which link emissions in Florida to nonattainment/maintenance for 8-hour ozone in Texas.
Organization: Minnesota Power 
Comment: 
Minnesota Power 
Basis for EPA's change in their analysis of the Minnesota contribution to nonattainment.  When EPA's own analysis now posts the Minnesota nonattainment area contribution at 0.19 ug/m3, EPA does not clarify whether the shift from their earlier analysis is due to correction of EPA CMAQ modeling bias resulting from older model version mass stability errors or from EPA's revisiting and correction of CAIR modeled Minnesota unit emission rates.  Absent such information, Minnesota Power is hampered in doing an assessment of the technical support document for the Transport Rule and related review of the NODA. [EPA-HQ-OAR-2009-0491-2750.1, p.7]
Response: 
See section IX.A of the preamble for the major differences between the Transport Rule and CAIR.  There are numerous technical differences between the air quality analysis for CAIR and the Transport Rule.  The central technical components that differ between CAIR and the Transport Rule include changes to: (1) the modeling platform including the meteorology, base and future emissions, and air quality model. (2) the future analytic year, and (3) the metrics and thresholds for measuring and evaluating interstate contributions.

IV.C.5. Proposed Geographic Coverage (States Covered)

Organization: Clean Air Task Force
Comment: 
Clean Air Task Force
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.106.]
and to include Texas and several other states in the control region.
Response: 
The final rule identifies Texas as a state with emissions that significantly contribute to or interfere with maintenance of the 1997 ozone NAAQS and the 1997 and 2006 PM2.5 NAAQS.
Organization: Kansas City Power and Light Company (KCP&L)
Comment: 
Kansas City Power and Light Company (KCP&L)
1. The State of Kansas has been included in the PTR for ozone season NOx based on modeled emission rates projected using the Integrated Planning Model (IPM) v3.02.  Revised emission projections were developed and incorporated into CAMx by Trinity Consultants. A full copy of the final report is attached. It was concluded that, after the Jeffrey Energy Center emission rates were corrected, Kansas no longer makes a significant contribution to any ozone monitoring site included in the PTR and should not be included in the Transport Rule for ozone season NOx. [EPA-HQ-OAR-2009-0491-2709.1, p.3]
[The Attachment can be found at the end of this comment.]
Response: 
EPA has conducted revised air quality modeling with updates based on comments on the modeling platform used for the proposed rule including corrections to the emissions rates at the Jeffrey Energy Center (need someone from CAMD to confirm this).  
The final transport rule analysis does not identify Dallas as a nonattainment or maintenance receptor.  This analysis, however, does identify Kansas as a state with emissions that interfere with maintenance in Allegan County, MI.  For reasons explained therein, EPA is issuing a Supplemental Notice of Proposed Rulemaking to propose that states (including Kansas) to take comment, among other things, on its conclusion that Kansas significantly contributes to or interferes with maintenance of the 1997 ozone NAAQS in another state.
Organization: Louisiana Energy and Power Authority (LEPA)
Comment: 
Louisiana Energy and Power Authority (LEPA)
LEPA understands that other commenters, including the Louisiana Department of Environmental Quality and the Louisiana Chemical Association, have performed an analysis that demonstrates that the proposed Transport Rule should not apply to Louisiana because there is no proof that emissions in Louisiana contribute to non-attainment or maintenance of air quality standards in any neighboring state. LEPA has not conducted an independent analysis of this because it lacked the time and resources to do so in the very limited timeframe the EPA allowed for review and comment, but LEPA agrees with those comments and urges the EPA to revise its proposed Transport Rule to exclude Louisiana. [EPA-HQ-OAR-2009-0491-2700.1, p.2]
Response: 
For the Final Transport Rule EPA has conducted revised air quality modeling with updates based on comments on the modeling platform used for the proposed rule.  Based on the updated modeling, Louisiana is not identified in the final rule as a state with emissions that significantly contribute to or interfere with maintenance of the 1997 or 2006 PM2.5 NAAQS.  However, the updated modeling continues to show that emissions in Louisiana contribute to nonattainment and maintenance of the 1997 8-hour ozone NAAQS in Houston.   Thus, Louisiana continues to be included in the Transport Rule for ozone season NOx emissions reductions.
Organization: Luminant
Comment: 
Luminant
:: Luminant has concerns, however about the proposed area of impact under the NOx program for Texas. Baton Rouge has just demonstrated attainment for the 1997 ozone standard. Therefore, it is inappropriate to include Texas in the ozone season NOx program. [EPA-HQ-OAR-2009-0491-2729.1, p.2]
:: Furthermore, back trajectories of winds in Texas, generated by the National Oceanic and Atmospheric Administration (NOAA) and used in SIP planning, show that northwest winds are infrequent. Therefore, most of the EGUs in the state should have little impact on ozone in Baton Rouge, and it is inappropriate to conclude that Texas emissions have an impact on Baton Rouge attainment status. [EPA-HQ-OAR-2009-0491-2729.1, p.2]
IV. Texas Should Not Be Included in the Ozone Season NOx Program
EPA proposes to include Texas in the ozone season NOx program because the IPM model indicates that Texas will contribute significantly to the Baton Rouge ozone nonattainment area. However, on September 9, 2010, EPA published a final rule (75 Fed. Reg. 54778) determining that the Baton Rouge area had met the 1997 ozone standard and was in attainment. [EPA-HQ-OAR-2009-0491-2729.1, p.6]
Meteorological back trajectories of wind generated by NOAA and used in SIP planning for the Dallas-Fort Worth areas show that winds from the northwest are the least frequent, especially in ozone season. Logic would dictate that most power plants in Texas would have limited impact on Baton Rouge. In addition, EPA did not appear to include in the modeling all of the NOx and volatile organic compound (VOC) reductions that have been made in the Houston area. Thus, there is no logical basis for concluding that Texas emissions will impact Baton Rouge's attainment status. Thus, Texas should not be included in the ozone season NOx program. [EPA-HQ-OAR-2009-0491-2729.1, p.6]
Response: 
EPA continues to believe that measured concentrations during the period 2003 through 2007 provide the appropriate air quality starting point for projecting future nonattainment and maintenance for the purposes of the Transport Rule (see preamble section V.C.2).  EPA has updated the air quality modeling platform based on comments (see preamble section V.D.2) and the results of the updated modeling for the 2012 base case combined with measured ozone concentrations during 2003 through 2007 continue to show that Baton Rouge is projected to be nonattainment of the ozone NAAQS in 2012 without CAIR.   The updated contribution modeling continues to show that Texas contributes to ozone in Baton Rouge by an amount that exceeds the 1 percent of the NAAQS contribution threshold employed for the Transport Rule and that sources in Texas have emissions reductions available at the cost thresholds identified.  Thus, Texas continues to be included in the Transport Rule for an ozone season NOx budget.   In addition, EPA has  performed a back trajectory analysis to identify the 3-day upwind transport history of air parcels crossing Baton Rouge, Louisiana  on days with measured exceedances of the 8-hour ozone NAAQS at this location in 2005 (the year of meteorology modeled for the Transport Rule) and in other years during the period 2003 through 2007 (see Air Quality Modeling Technical Support Document).  The results of this analysis indicate that there are exceedance days in 2005 and in other years when the air arriving in Baton Rouge is likely to have traversed portions of Texas within 3 days of arriving in this parish.  The trajectory analysis provides qualitative evidence that corroborates the result of EPA's modeling which links emissions in Texas to nonattainment for the 8-hour ozone NAAQS in Baton Rouge.
Organization: PPG Industries, Inc.
Entergy Services, Inc.
Dow Chemical Company
Comment: 
Dow Chemical Company
Dow believes that EPA's finding that Louisiana emission sources interfere with maintenance of the annual PM2.5 standard in Harris Co., Texas is erroneous, for the reasons stated in the comments of the Louisiana Chemical Association on the proposed Transport Rule and FIP. Dow hereby adopts those comments by reference. The one monitor in Harris County allegedly impacted by Louisiana emissions is in compliance with the annual PM2.5 NAAQS and annual average emissions for the past two years have been below 14.0 ug/m3. As EPA's own projections indicate that SO2 and NOx emissions from Louisiana EGUs will decline by 2012 even without the Transport Rule/FIP, there is no legal basis for imposition of a FIP. Dow requests that EPA delete the annual SO2 and NOx requirements from the proposed rule and FIP for Louisiana EGUs.  [EPA-HQ-OAR-2009-0491-2775.1 p.2]
Entergy Services, Inc.
Applicability of Clean Air Transport Rule to Louisiana 
1. EPA Proposed Finding of Interference With Maintenance of Annual PM2.5 NAAQS
Entergy adopts comments I.B and I.C made by the Louisiana Chemical Association. Entergy does not believe that the state of Louisiana is interfering with the maintenance of PM2.5 attainment in downwind states.  Louisiana, therefore, should not be regulated in the annual program in the final rule.  In the proposed rule, Louisiana is in the annual program because of a 0.34 μg/m3 PM2.5 contribution to one monitor (Clinton Drive monitor) in Harris County, TX.  Since 2004, all PM2.5 monitors in the Houston area except the Clinton Drive monitor have recorded readings less than 15.0 μg/m3.  PM2.5 data for the Clinton Drive monitor showed a 2005 annual average of 15.9 μg/m3 and a three-year average of 15.0 μg/m3.  The Texas Commission on Environmental Quality (TCEQ) conducted an advanced analysis of the PM2.5 data, meteorological data, and the chemical speciation data to identify the cause (what portion and component of PM2.5), source types, and source areas contributing to the excessive particulate matter concentrations.  Daytime, weekday concentrations are the main cause of high PM2.5 levels at the Clinton Drive site.  Analysis of chemical speciation data shows the calculated mass of soil at Clinton Drive is approximately 1.5 to 2.0 μg/m3 higher than at any other speciation monitoring site in the Houston area.  The data indicates that the higher elevated PM2.5 concentrations at the Clinton Drive monitor represent a limited area that is impacted by local fugitive emissions, as the Clinton Drive monitor is located directly across from the entrance to the Port of Houston Authority (PHA) and unpaved ship yards along the Houston Ship Channel.  A railroad also runs parallel to this section of Clinton Drive. [EPA-HQ-OAR-2009-0491-2847.1, p.6]
Concurrently, the TCEQ began working with the PHA, the City of Houston, Harris County, and local industry to address this issue.  The combined efforts of the various organizations has improved particulate matter air quality to the point that the 2008 PM2.5 annual average at Clinton Drive was 14.0 μg/m3, even when exceptional event days are included. Without removing exceptional event days, the 2006 through 2008 design value for Clinton Drive was 15.2 μg/m3. After removing exceptional event days identified by TCEQ meteorologists, the 2006 through 2008 design value was 14.6 μg/m3.  Without removing exceptional event days, the 2007 through 2009 design value for Clinton Drive was 14.1 μg/m3.  The annual readings for the Clinton Drive monitor show a steady decline during the last 4 years.  [EPA-HQ-OAR-2009-0491-2847.1,p.7]    
2006  -  16.0 μg/m3     
2007  -  15.6 μg/m3     
2008  -  14.0 μg/m3      
2009  -  12.6 μg/m3 
This data demonstrates that the PM2.5 issue at the Clinton Drive monitor was caused by local conditions and that those local corrective actions had improved the air quality to an attainment status.   [EPA-HQ-OAR-2009-0491-2847.1, p.7]
Realizing that the PM2.5 issues at the Clinton Drive monitor are a local problem, and in anticipation of the strengthening of the NAAQS for PM2.5, a taskforce committee consisting of members from the TCEQ, Texas Department of Transportation (TxDOT), Harris County, the City of Houston, the PHA, and the Houston-Galveston Area Council was organized to address this issue. The taskforce committee established a scope for projects on Clinton Drive that prevent disturbing PM2.5 dust and will ensure these local issues are addressed.  See Attachments Clinton Drive 1, Clinton Drive 2, Clinton Drive 3, Clinton Drive 4.  [EPA-HQ-OAR-2009-0491-2847.1,p.7] [[See Docket Numbers [EPA-HQ-OAR-2009-0491-2847.3 thru EPA-HQ-OAR-2009-0491-2847.6 for Attachments.]]
Because the pollution causing the only purported Transport Rule related exceedences connected to Louisiana was caused by local conditions, these local conditions have been addressed,  these conditions will continue to be addressed in the future, and the monitor is now demonstrating attainment of the PM2.5 standard, Louisiana should not be in the annual program of the Clean Air Transport Rule.  [EPA-HQ-OAR-2009-0491-2847.1, p.7]
Furthermore, even if there were a downwind transport problem of NOx and SO2 from Louisiana, Table IV.C-1-2005 Base Case SO2 Emissions (Tons/Year) For Eastern States By Sector and Table IV.C-2-2005 Base Case NOx Emissions (Tons/Year) For Eastern States By Sector in the proposed rule, clearly indicate that the regulation of EGU's in Louisiana is not the solution to solving the problem, as EGU emissions for those pollutants in Louisiana are considerably less than non-EGU emissions of each pollutant. [EPA-HQ-OAR-2009-0491-2847.1, p.7] 
In summary, EPA's own modeling shows that without the Transport Rule/FIP, overall emissions of SO2 in Louisiana will decrease by 12,758 tpy from 2005 levels by 2012 and by 26,618 tpy from 2005 levels by 2014.  As discussed above, Harris County, Texas is currently in attainment with the annual PM2.5 NAAQS and has a strong downward trend of PM2.5 emissions over the past several years.   If Louisiana SO2 emissions are not causing interference with maintenance now, and are projected to have this significant of a decrease of SO2 without the Transport Rule, then how can EPA reasonably conclude that Louisiana is likely to interfere with maintenance of the PM2.5 standard in Harris County or that the Transport Rule is justified for Louisiana?  If greater emissions are not affecting maintenance, then how can lesser emissions affect maintenance? Entergy believes that it would be arbitrary and capricious for EPA to arrive at this as a final conclusion.  [EPA-HQ-OAR-2009-0491-2847.1,p.11]
As can be seen by this data, EPA also projects that these NOx emissions will decrease by 108,775 tpy (a 16% decrease), even without the Transport Rule/FIP.  As noted above, EPA's modeling demonstrates that Louisiana NOx emissions appear to have almost no impact on the resulting levels of PM2.5 in Harris County, Texas as the nitrate component of the Louisiana impact was only 0.004 ug/m3.  Thus, there is no reason to expect that NOx emissions will contribute to interference with attainment in Harris Co., Texas in the future as they are not causing interference now.  [EPA-HQ-OAR-2009-0491-2847.1, p.11] [[See Docket Number EPA-HQ-OAR-2009-0491-2847.1, p.11 for the data.]]
Moreover, actual certified SO2 and NOx data submitted to EPA's Clean Air Markets Division pursuant to the Acid Rain and CAIR programs confirms a significant decline in actual SO2 and NOx reductions statewide from Louisiana EGUs over the past five years:  [EPA-HQ-OAR-2009-0491-2847.1, p.12] [[See Docket Number EPA-HQ-OAR-2009-0491-2847.1,p.12 for a figure.]]
In fact, actual certified totals of SO2 and NOx in 2009 were already well below the values projected by EPA for the Base Case 2012 and 2014 levels for Louisiana EGUs, whether projected by TR Base Case v.3.02 or v.4.10.   
While Entergy has not been able to complete its review of the changes to the TR Base Case v. 4.10 compared to TR Base Case v. 3.02, nor of the evaluation of different Transport Rule FIP options using version 4.10, it is imperative for EPA to realize that the total SO2, annual NOx and ozone season NOx estimates under the TR Base Case v. 4.10 have dropped dramatically when compared to the TR Base Case v. 3.02.  The reduction in each case is greater than the difference between the TR Base Case v. 3.02 and the TR SB Limited Trading Values.  This difference is what EPA has stated to be the amount to be removed in order to prevent "significant contribution" or "interference with attainment."  In short, this means that EPA projects with the updated version of the IPM that by 2012, the total reduction required in order to prevent any significant contribution or interference with maintenance has already been achieved without the Transport Rule/FIP.  The following Table makes that comparison:  [EPA-HQ-OAR-2009-0491-2847.1, p.12] [[See Docket Number EPA-HQ-OAR-2009-0491-2847.1, pp.12-13 for the table.]]
Because "significant contribution" and "interference with maintenance" have been removed with this revised IPM modeling, there is no basis for a Transport Rule or FIP for Louisiana EGUs, as the levels required to remove significant contribution and interference with maintenance will have already been achieved.  In summary, EPA's IPM modeling provides no rational basis for the FIP proposed for Louisiana.  It supports a conclusion that any potential Louisiana impact on either annual PM2.5 or 8-hour ozone NAAQS in Texas will be removed through factors other than the Transport Rule and CAIR. [EPA-HQ-OAR-2009-0491-2847.1, p.13]
PPG Industries, Inc.
PPG believes that Louisiana should not be included within the proposed rule and FIP for annual SO2 and NOx reductions because Louisiana emission sources do not reasonably have the potential to interfere with the ability of Harris County, Texas, to maintain its current attainment with the annual PM2.5 NAAQS, contrary to EPA's proposal. PPG needs additional time to gather and present data to EPA on this critical issue. [EPA-HQ-OAR-2009-0491-1926.1, p.2]
Response: 
EPA has conducted revised air quality modeling with updates based on comments on the modeling platform used for the proposed rule.  In the revised modeling there are no monitoring sites in Texas with projected 2012 base case nonattainment or maintenance problems for the annual PM2.5 NAAQS.   In addition, Louisiana is not included in the final Transport Rule for reductions of annual SO2 and NOx emissions.
Organization: Sierra Club, Pennsylvania Chapter
Comment: 
Sierra Club, Pennsylvania Chapter
With this proposal, Pennsylvania can finally become a "Good Neighbor" to the states that surround it geographically in the Mid-Atlantic region, and in fact, states hundreds of miles down wind. We support the regional nature of these reductions and we believe that this regional focus should be expanded. [EPA-HQ-OAR-2009-0491-3482.1, p.2]
An EPA's analysis identifies 10 states that send pollution to Pennsylvania, using measured data captured in those state's own air monitors. Not only Indiana, Michigan and Wisconsin, but Illinois, Kentucky, Ohio, Georgia and Missouri send ozone and particles into Pennsylvania. This rule would require that plants in 31 states -- including Pennsylvania -- cut pollution they send across state lines. We believe that there are additional states that should be included in this process; please include Texas, Arkansas, New Hampshire, North Dakota and Oklahoma in the control region for SO2 and annual NOx reductions, and include Massachusetts and Missouri in the control region for ozone season NOx reductions. [EPA-HQ-OAR-2009-0491-3482.1, p.5]
- include Texas, Arkansas, New Hampshire, North Dakota and Oklahoma in the control region for SO2 and annual NOx purposes, and include Massachusetts and Missouri in the control region for ozone season NOx purposes. [EPA-HQ-OAR-2009-0491-3482.1, p.7]
Response: 
EPA conducted an objective, quantitative, air quality-based analysis to identify upwind states that contribute amounts of ozone and/or PM2.5 above threshold concentrations to projected 2012 base case downwind nonattainment and/or maintenance receptors.  The results of this analysis were part of the basis for identifying states included in the final Transport Rule for ozone season NOx reductions and/or annual NOx and SO2 emissions reductions.   Based in part on this analysis Texas is included for ozone season NOx reductions and annual NOx and SO2 emissions reductions and Arkansas is included for ozone season NOx reductions.  Missouri is included for annual NOx and SO2 emissions reductions.   Oklahoma and Missouri are proposed to be included for ozone season NOx reductions as part of a Supplemental Notice of Proposed Rulemaking.  Of the other states identified by the commenter, New Hampshire, North Dakota and Massachusetts are not included in the Transport Rule for ozone season NOx reductions or annual NOx and SO2 emissions reductions.
Organization: Texas Commission on Environmental Quality
Occidental Chemical Corporation (OCC)
Comment: 
Occidental Chemical Corporation (OCC)
Moreover, we seriously question why the state of Texas is included in this rulemaking, given that the downwind state (Louisiana) has improved ambient air quality such that it does not have any ozone non-attainment areas. As set forth in greater detail below, OCC strongly believes that neither Louisiana nor Texas should be included in the final CATR. [EPA-HQ-OAR-2009-0491-2754.1, p. 3]
Texas Commission on Environmental Quality
The TCEQ finds that Texas should not be identified as a significant contributor to any nonattainment areas for the 1997 eight-hour ozone standard. [EPA-HQ-OAR-2009-0491-2857.1, p.1]
Texas should not be identified as significantly contributing to any nonattainment areas for the 1997 eight-hour ozone standard.
Because the premises on which Texas' inclusion in the Transport Rule trading program is based are substantially flawed and rely on incorrect data, Texas should not be included in the Transport Rule program. [EPA-HQ-OAR-2009-0491-2857.2, p.3]
Finally, the TCEQ objects to the inclusion of Texas in the Transport Rule program, based on flaws in the EPA's technical analysis for the program and the fact that the only area to which Texas is linked for significant contribution to nonattainment (Baton Rouge, LA) has recently been determined in attainment of the 1997 eight-hour ozone NAAQS by the EPA. [EPA-HQ-OAR-2009-0491-2857.1, p.3]
Response: 
EPA continues to believe that measured concentrations during the period 2003 through 2007 provide the appropriate air quality starting point for projecting future nonattainment and maintenance for the purposes of the Transport Rule (see preamble section V.C.2).  EPA has updated the air quality modeling platform based on comments (see preamble section V.D.2) and the results of the updated modeling for the 2012 base case combined with measured ozone concentrations during 2003 through 2007 continue to show that Baton Rouge is projected to be nonattainment of the ozone NAAQS in 2012 without CAIR.   The updated contribution modeling continues to show that Texas contributes to ozone in Baton Rouge by an amount that exceeds the 1 percent of the NAAQS contribution threshold employed for the Transport Rule and that sources in Texas have emission reductions available at the cost thresholds identified..  Thus, Texas is identified as a state with emissions that significantly contribute to or interfere with maintenance of the 1997 ozone NAAQS. 
Organization: Western Farmers Electric Cooperative (WFEC)
Comment: 
Western Farmers Electric Cooperative (WFEC)
the State of Oklahoma was not included in the original CAIR program but has been included with CATR during Ozone season. Why did it change?  It is our understanding that the state of Oklahoma was only included because of one modeling day in which the Dallas - Fort Worth (DFW) area was affected by Oklahoma emissions.  Since southerly winds are predominately and Oklahoma is north of DFW, it seems unwarranted to place such a heavy financial burden on the electrical consumers in Oklahoma.  [EPA-HQ-OAR-2009-0491-2642.1, p.3]
Response: 
See section IX.A of the preamble for the major differences between the Transport Rule and CAIR.  The central technical components that differ between CAIR and the Transport Rule include changes to: (1) the modeling platform including the meteorology, base and future emissions, and air quality model. (2) the future analytic year, and (3) the metrics and thresholds for measuring and evaluating interstate contributions.
For reasons explained therein, EPA is issuing a Supplemental Notice of Proposed Rulemaking to take comment, among other things, on its conclusion that Oklahoma has emissions that significantly contribute to nonattainment or interfere with maintenance of the 1997 ozone NAAQS in another state.

IV.D. Proposed Methodology to Quantify Emissions That Significantly Contribute or Interfere With Maintenance

Organization: American Public Power Association (APPA)
Florida Electric Power Coordinating Group, Inc. (FCG)
Comment: 
American Public Power Association (APPA)
EPA has failed to propose a defensible methodology for determining statewide emission reduction obligations and has required additional emission reductions even where they have not been shown to be needed to meet the air quality objectives that EPA asserts. [EPA-HQ-OAR-2009-0491-2812.1, p.7]
EPA indicated in a presentation given in July 2010, when it announced the proposed rule, that it projects that the proposed rule would reduce SO2 emissions by an additional one million tons per year ("TPY") in 2012 beyond what CAIR would have accomplished: from an emission level of 5.1 million TPY under CAIR to 4.1 million TPY under the proposed rule. See Overview Presentation 7/26/10 at slide 33, available at http://www.epa.gov/airquality/transport/actions.html. [EPA-HQ-OAR-2009-0491-2812.1, p.17]
In fact, during a meeting held shortly after EPA issued the proposed rule but before its publication in the Federal Register, EPA acknowledged that, according to the Agency`s projections, the 2012 state budgets in the Proposed Transport Rule would reduce SO2 emissions by 1.2 million TPY, from 5.1 million TPY under CAIR to 3.9 million TPY under the Proposed Transport Rule. EPA failed to explain this apparently substantial discrepancy or how over a million additional tons of emissions would be eliminated in a phase of the program that is intended merely to replicate what would have occurred anyway. [EPA-HQ-OAR-2009-0491-2812.1, p.17]
EPA has not shown that emission reductions beyond those required by CAIR are necessary. EPA`s own data show that existing controls are working to reduce emissions; the result is that concentrations of SO2 and NOx in the ambient air have declined steadily in recent years. The D.C. Circuit`s opinion in North Carolina v. EPA did not require, or even imply that the overall degree of emission reductions required under CAIR was less than that necessary to comply with CAA section 110(a)(2)(D)(i)(I). Nor did the court include in its opinion any mandate that the replacement rule for CAIR must include a compliance date in 2012 or within any period of time as short as six months after final rule promulgation. 12 [EPA-HQ-OAR-2009-0491-2812.1, p.18]    
In light of this, EPA should decide not to call for the steep additional emission reductions demanded by the PTR because such reductions are not needed to reduce significant regional contributions to downwind nonattainment. [EPA-HQ-OAR-2009-0491-2812.1, p.32]
Florida Electric Power Coordinating Group, Inc. (FCG)
Notwithstanding EPA's assertion that the emission reductions required in 2012 would occur even without the Proposed Transport Rule, a presentation given by EPA in July indicated that the proposal would reduce S02 emissions by an additional one million tons per year ('TPY') in 2012 beyond what the Clean Air Interstate Rule (CAIR) would have accomplished: from a level of 5.1 million TPY under CAIR to 4.1 million TPY under the proposed rule. In fact, during a meeting held shortly after the proposed rule was issued, the Director of EPA's Clean Air Markets Division acknowledged that the 2012 state budgets in the Proposed Transport Rule would reduce S02 emissions by 1.2 million TPY, from 5.1 million TPY under CAIR to 3.9 million TPY under the Proposed Transport Rule. EPA must explain this apparent discrepancy and how over a million tons of emissions would be eliminated by relying on controls already in use. [EPA-HQ-OAR-2009-0491-2658.1, p.3]
Response: 
In EPA's assessment of significant contribution to non-attainment and inference with maintenance for the final Transport Rule, EPA utilized the most recently available information on emissions and existing controls.  This assessment is based on the best data available and reflects the current state of the electricity generation sector.  Regarding forecast emissions under CAIR, EPA finds that based on real world information, the electricity generation sector is doing more to reduce SO2 emissions (such as installing scrubbers, switching to lower sulfur coal, and fuel switching to gas) than was forecast at the time of CAIR's promulgation.  Additionally, when comparing projected emissions between the Clean Air Interstate Rule and the final Transport Rule, it is important to keep in mind that CAIR included a large bank of SO2 allowances carried over from the Acid Rain Program.  The Court in its decision in North Carolina found EPA's decision to base state budgets on existing ARP allowances to be unlawful and determined that EPA could not, through a 110(a)(2)(D)(i)(I) rule terminate or modify ARP allowances.
Organization: Attorney General of North Carolina
Comment: 
Attorney General of North Carolina
In CAIR, EPA declined to evaluate any attainment areas to determine if upwind emissions would interfere with maintenance of the National Ambient Air Quality Standards in those areas. The D.C. Circuit held that EPA cannot simply refuse to apply the "interfere with maintenance" prong of §110(a)(2)(D)(i)(I) and arbitrarily deny deserving downwind attainment areas protection from upwind sources that threaten their attainment of the NAAQS.
In response, EPA has developed a methodology to assess whether areas need assistance from upwind sources in order to maintain the NAAQS and has based certain reductions in the Transport FIP on its determination that certain areas require such assistance. North Carolina believes that EPA has adequately complied with the Court's mandate that it not read the "interfere with maintenance" language out of the statute.
In North Carolina, the Court declined to assess whether EPA's methodology for implementing the maintenance standard complied with the statute. North Carolina takes no position here on whether EPA's new methodology complies with the statute, except to submit that that EPA's implementation is incomplete.
In 2004, North Carolina filed a petition under §126 of the Clean Air Act. 42 U.S.C. §7426. The petition was based in part on North Carolina's conclusions that out-of-state sources were contributing significantly to nonattainment of the ozone NAAQS in North Carolina and were interfering with North Carolina's maintenance of that standard. EPA denied the petition regarding the ozone NAAQS because EPA projected that North Carolina would attain the ozone standard without the need for reductions in upwind States. Rulemaking on §126 Petition from N.C. to Reduce Interstate Transport of Fine Particulate Matter & Ozone, 71 Fed. Reg. 25,328, 25,337/1 (2006).
In 2006, North Carolina petitioned for judicial review of EPA's denial of the petition. See Sierra Club, No. 06-1221 (D.C. Cir.). By late 2008, EPA concluded that, contrary to its own projection that North Carolina would fully attain the ozone standard by the required attainment date of 2010, in the Charlotte area "attainment will not be achieved by the required moderate area deadline . . . ." Ltr. from J.I. Palmer, Reg'l Adm'r, EPA Region 4, to Sec'y W.G. Ross, N.C. Dept. of Envt. & Natural Resources at 1 (Nov. 17, 2008) [hereinafter "EPA Ltr."]; see also Ltr. from J.I. Palmer, Reg'l Adm'r, EPA Region 4, to Sec'y W.G. Ross, N.C. Dept. of Envt. & Natural Resources (Jan. 9, 2009). Based on this conclusion, EPA requested that the Court remand the matter to EPA for reconsideration in light of the changed facts. EPA, Supplemental Filing Requesting Remand, Sierra Club v. EPA, No. 06- 1221 (D.C. Cir. Feb. 23, 2009). On March 5, 2009, the Court issued its Judgment: EPA . . . concedes the factual predicate for denying North Carolina's petition as to ozone has fundamentally changed, and confirms that regardless of what this Court might decide based on the facts as then found by EPA, the Agency will reconsider its denial of North Carolina's petition in light of these new facts. Judgment, Sierra Club v. EPA, No. 06-1221, at 1-2 (D.C. Cir. March 5, 2009). Therefore, the Court remanded the matter to EPA for reconsideration. Despite the Court's admonishment that "this reconsideration should be expeditious" and the Court's reference to the sixty-day decisional deadline Congress included in §126, id. at 2, EPA has taken no formal action on the petition in over a year and a half.
The point here is that EPA recognized that the modeling in that case was "extremely complex and contain[ed] some uncertainty in the predictions." EPA Ltr. at 1. As the facts bore out, the modeling was incorrect and North Carolina was denied relief to which it was entitled.
Given this experience, North Carolina submits that EPA should build into the Transport FIP and CAIR's replacement safeguards to ensure that downwind areas are not inappropriately denied relief, as North Carolina was, based on projections that turn out to be incorrect and unfairly handicap downwind areas. North Carolina respects the need for regulatory certainty and administrative finality. However, the overriding concern is that established by Congress, which is to provide appropriate and timely upwind controls in order to alleviate unfair burdens on downwind States. In order to avoid regulatory delays that would prolong the deprivation of benefits to downwind areas, EPA should promulgate automatic triggers based on downwind air quality conditions or establish an expedited process to provide the necessary protections to downwind areas.
Therefore, North Carolina recommends that EPA provide for a "true up" of the air quality projections at such times as would be necessary and appropriate to fully implement Congress' mandate under §110(a)(2)(D)(i)(I) for timely elimination of upwind emissions that violate the twin test regarding nonattainment and maintenance.
This is not an idle request. The Charlotte area may very well attain the 85 ppb ozone standard in 2010. This would occur in no small measure due to the 2009 fourth-highest monitored value at the County Line monitor of 71 ppb, which would be part of the three-year average evaluated for attainment in 2010 and 2011. In the fifteen years prior to 2009, the fourth-highest value at this monitor exceeded 85 ppb every year except 2004, when it dipped a mere 2 ppb below the standard. In all but two of those fifteen years it recorded levels of 90 ppb or higher. Provisional data to date in 2010 yields a fourth-highest reading of 82 ppb. If this number holds it would be the second lowest ever recorded at the County Line monitor.
The 71 ppb recorded in 2009 is, historically speaking, an exceedingly low number and the current 2010 level would also be lower than normal. Although these recent data are undoubtedly beneficial from both a health and welfare perspective and in terms of regulatory compliance, whether these trends will continue is uncertain. NOX emissions across the southeast in 2009 fell considerably, but regional heat input levels also tumbled, suggesting that at least part of the regional NOX declines in both 2009 and 2010 were due to economic considerations and not NOX controls. The 2009 data will be included in the 2011 three-year average, but not in the three-year averages for 2012 or subsequent years. Accordingly, even though the Charlotte area may attain by the end of the 2011 ozone season, regional reductions may be necessary to assist Charlotte in maintaining the standard thereafter.7 EPA should consider this in its implementation of §110(a)(2)(D)(i)(I). [EPA-HQ-OAR-2009-0491-2685.1 p.12]
EPA does not appear to have considered retirement of coal units as a control option. Although "EPA projects that approximately 1.2 GW of coal-fired generation may be removed from operation by 2014" this seems to be more an unintended consequence of the proposed rule rather than a purposeful consideration. In fact, EPA notes that "[i]n practice, however" some of "the units . . . may be . . . kept in service . . . ." Id. at 45,357/1. [EPA-HQ-OAR-2009-0491-2685.1]
Consideration of coal unit retirement is necessary to be fair to downwind States. Long ago, in Union Elec. Co. v. EPA, 427 U.S. 246 (1976), the Supreme Court held that downwind States must meet the attainment deadlines regardless of perceived technical infeasibility because the Clean Air Act is a technology-forcing statute. Id. at 255-66 (The words "as expeditiously as practicable but . . . in no case later than three years" as used in the Clean Air Act regarding attainment of the 19 NAAQS leave no room for arguments regarding technological infeasibility); id. at 257 (The requirements of the Clean Air Act "are expressly designed to force regulated sources to develop pollution control devices that might at the time appear to be economically or technologically infeasible"). The Court also observed that no control scenario "is infeasible since offending sources always have the option of shutting down if they cannot otherwise comply with the standard of the law." Id. at 265 n.14. [EPA-HQ-OAR-2009-0491-2685.1]
EPA implements §110(a)(2)(D)(i)(I) by requiring only control s that are both technically and economically feasible. But the D.C. Circuit held that EPA is required to coordinate the upwind reductions with the downwind attainment deadlines. Attainment deadlines, of course, provided the framework for the Supreme Court's holding eschewing claims of technological infeasibility from the equation. Thus, under Union Electric and North Carolina, EPA has an obligation to consider solutions that may seem technologically infeasible. At the very least, EPA must consider unit retirements because, as the Supreme Court indicated, such a remedy is always technologically feasible. [EPA-HQ-OAR-2009-0491-2685.1]
The flaw in EPA's methodology becomes readily apparent when the situation is reduced to a single facility. If a single facility on the State X side of the border between States X and Y were in large part responsible for nonattainment in an area of State Y, yet the facility could not reduce its emissions at a cost level that 20 EPA deemed "highly cost effective," State Y would have no remedy under §110(a)(2)(D)(i)(I) according to EPA. Certainly, Congress would not have enacted a provision to address interstate issues yet leave a deserving State in such a helpless position  -  subject to health and welfare impacts and sanctions for a situation that was virtually entirely out of its control  -  without being clearer.8 The language Congress used in §110(a)(2)(D)(i)(I), on its face, appears to apply to exactly the situation of the hypothetical State Y. EPA's construct for implementing §110(a)(2)(D)(i)(I), which could result in no emissions reductions despite the presence of overwhelming interstate impacts, is at odds with Congress' direct efforts to provide a remedy. [EPA-HQ-OAR-2009-0491-2685.1]
Response: 
This comment does not object to, or otherwise raise issues concerning, EPA's identification of monitors or receptors used in the Transport Rule to determine which states significantly contribute or interfere with maintenance.   For example, the comment does not claim that the Charlotte, North Carolina monitor should be treated as a significant contribution or maintenance receptor in this rulemaking.  Additionally, the comment does not object to, or otherwise raise issues concerning, EPA's determination of the specific states covered under the Transport Rule or the methodology used by EPA in making that determination.  For example, the comment does not claim that any additional states should be covered by the Transport Rule because of the effect of their emissions on North Carolina.  In short, the comment does not raise any issues concerning the implementation of CAA section 110(a)(2)(D)(i)(I) in this rulemaking and the final Transport Rule.  Instead, the comment requests that EPA adopt regulations establishing new procedures for implementing that section of the CAA  in future rulemakings.  Specifically, the comment states that EPA should adopt regulations providing for future evaluation of status of monitors (such as the Charlotte monitor) based on data in subsequent years and for "automatic" or "expedited" response to the results of such future evaluation.  As such, this comment relates to possible future actions under CAA section 110((a)(2)(D)(i)(I)  and is outside the scope of this rulemaking and the Transport Rule.  Moreover, the comment merely suggests that EPA adopt, for the future, a "true-up" mechanism  that would be used when "necessary and appropriate" and that would provide an "automatic trigger" or "expedited process".  The comment did not provide any information on exactly how and when such a mechanism might be applied, what the trigger or expedited process might be, and what measures might be taken as a result. 
With respect to EPA's modeling of EGU retirements under the Transport Rule, EPA believes that its modeling appropriately takes into account retirement as a control strategy.  Details on emissions modeling can be found in section V and VI of the preamble for the final Transport Rule and in the Documentation Supplement for EPA Base Case v.4.10_FTransport  - Updates for Final Transport Rule.
Organization: Dayton Power and Light Company (DP&L)
Comment: 
Dayton Power and Light Company (DP&L)
Key Terms within the Proposed Rule Should Be More Precisely Defined
Two key terms that drive many of the policy decisions reflected in the proposed rule remain undefined or vaguely defined. The EPA should establish clear standards defining what is a 'significant contribution' and an 'interfering contribution.' The definitions should also include an understandable standard for when the level of contribution has declined to a point where it is no longer making a 'significant contribution.' In its currently undefined status, the definition of 'significant contribution' could vary from year-to-year or administration-to-administration depending on what year EPA looks at it and how often EPA chooses to ratchet down emissions budgets. [EPA-HQ-OAR-2009-0491-2637.1, pp. 6-7]
Response: 
EPA believes that the Transport Rule's approach of using air-quality thresholds to determine upwind-to-downwind-state linkages and using the cost- and air quality-based multi-factor approach to quantify significant contribution to nonattainment and interference with maintenance (i.e., to determine the specific amount of emissions that each upwind state must reduce) could serve as a precedent for quantifying upwind state emission reduction responsibilities with respect to potential future NAAQS.  For further discussion of this topic please refer to section VI.A of the final Transport Rule preamble.
Organization: Florida Municipal Electric Association (FMEA)
Gainesville Regional Utilities (GRU)
Comment: 
Florida Municipal Electric Association (FMEA)
Further, there appears to be no Court ordered requirement for the additional reductions of NOx and SO2 beyond those established in the CAIR Rule. EPA should only address the Court remand of CAIR and that complements the Court directive "to preserve the environmental benefits of the CAIR rule" by developing a Transport rule that achieves the original CAIR SO2 and NOX reductions within the CAIR timelines. EPA's new emission requirements and protocols for determining significance levels beyond those validated by the Washington, D.C. District Court are unjustified and will leave EPA unnecessarily open to potential lawsuits. [EPA-HQ-OAR-2009-0491-2731.1, p. 1]
Gainesville Regional Utilities (GRU)
Further, there appears to be no Court ordered requirement for the additional reductions of NOx and SO2 beyond those established in CAIR. GRU believes that EPA should only address the Court remand of CAIR and follow the Court directive 'to preserve the environmental benefits of the CAIR rule' by developing a Transport Rule that achieves the original CAIR SO2 and NOx reductions within the CAIR timelines. EPA's new emission requirements and protocols for determining significance levels beyond those validated by the DC District Court are unjustified and will leave EPA unnecessarily open to potential lawsuits. [EPA-HQ-OAR-2009-0491-2674.1, p.1]
Response: 
As described in preamble section VI.D of the final Transport Rule, the D.C. Court of Appeals rejected the state budgets in CAIR as arbitrary and capricious and not consistent with CAA section 110(a)(2)D)(i)(I)  (North Carolina, 531 F.3d  918 and 921) and remanded CAIR to EPA to promulgate a new rule (the Transport Rule) replacing CAIR and consistent with the Court's decision (North Carolina, 550 F.3d 1178).  On remand EPA developed new, final state budgets for the Transport Rule that address the Court's concerns and meet section 110(a)(2)(D)(i)(I) requirements.  Further, because the Court reversed and remanded CAIR with instructions to "remedy" the rule's "fundamental flaws" (including specifically the state budgets found to be unlawful (North Carolina, 550 F.3d 1178), it is difficult to see how a comparison between new state budgets meeting section 110(a)(2)(D)(i)(I) requirements and unlawful budgets could be viewed as informative.  
As described in section VI of the preamble for the final Transport Rule, EPA reassessed SO2 and ozone season and annual NOX reductions for the final Transport Rule.  Please refer to this section for further details.
Organization: Machaver, Bob
Comment: 
Machaver, Bob
Basic Approach: initial review of the proposed rule seems to indicate that EPA has an adopted an approach basically designed to require all EGUs in the states subject to this FIP to install control measures, by establishing a very low threshold for designating Interstate Impacts as "Significant". Therefore a state that is in compliance with the NAAQSs, and which contributes minimally to its neighbors could still be subject to a very onerous Budget Cap under this program. This type of approach could result in more onus being imposed on neighbors than on the state itself for achieving NAAQS compliance.  [EPA-HQ-OAR-2009-0491-2873.1, p.1]
It is understood that in some cases pollutant (or precursor) transport is major contributor to local impacts, and in such cases, requiring controls on upwind sources certainly makes sense. However  this concept should not be extended to the point that an unjustified burden is imposed on neighboring states to provide reductions to support the achievement of NAAQS compliance in a Non-Attainment state. [EPA-HQ-OAR-2009-0491-2873.1, pp.1-2]
Response: 
As described in section III and section VI.D of the preamble for the final Transport Rule, EPA believes that downwind states also have control responsibilities because, among other things, the Clean Air Act requires each state to adopt enforceable plans to attain and maintain air quality standards.  Indeed, states have put in place measures to reduce local emissions that contribute to nonattainment within their borders.  Section 110 (a)(2)(D)(i)(I) only requires the elimination of emissions that significantly contribute to nonattainment or interfere with maintenance of the NAAQS in other states; it does not shift to upwind states the responsibility for ensuring that all areas in other states attain the NAAQS.
Organization: Marquette Board of Light and Power
Comment: 
Marquette Board of Light and Power
Unfortunately, the EPA has unintentionally structured the proposed Transport rule to encourage facilities to run to the upper limit of the permitted emission rates and we believe this is a precedent that will set the future operating decisions for clean efficient boilers such as Shiras Unit 3. [EPA-HQ-OAR-2009-0491-2764.1, p.1]
We appreciate the opportunity to comment and feel that reducing ozone related pollutants is important but it must be done responsibly, provide the light incentives for current low emitters of oxides of nitrogen and sulfur dioxides, and use accurate background and projected data. [EPA-HQ-OAR-2009-0491-2764.1, p.1]
Response: 
EPA's final Transport Rule identifies state-level emission levels that will eliminate significant contribution to nonattainment and interference with maintenance and allows individual units, facilities, and entities to make their own decisions about how to meet these levels.  The final rule allows for air quality-assured trading while limiting the emissions from EGUs in each state. 
Organization: Ozone Transport Commission (OTC)
Comment: 
Ozone Transport Commission (OTC)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.113.]
For the states to have any chance of developing timely plans to adequately address transport, EPA must identify the reductions needed to eliminate significant contribution and interference with maintenance concurrent with the setting of air quality standards.
This proposed methodology should be quickly applied to identify the additional reductions in transport needed to meet the new ozone standard EPA expects to issue this fall.
Response: 
This comment appears to apply to federal, state, and local programs to address future revised in new National Ambient Air Quality Standards (NAAQS) set by EPA.  As such, it does not specifically apply to the final Transport Rule which is tied to existing NAAQS.
Organization: PPG Industries, Inc.
Comment: 
PPG Industries, Inc.
In summary, PPG respectfully requests EPA to eliminate Louisiana from the scope of the CATR. In the alternative, and only in the event that EPA does not do so, PPG requests that at a minimum, EPA revise its methodology for determination of significant impact and interference with maintenance to make its methodologies into presumptive screening tools only, while providing states and potentially affected entities a reasonable opportunity to provide objective empirical evidence concerning whether an upwind state actually makes significant contribution to a downwind state's nonattainment or interferes with attainment in the downwind state.  [EPA-HQ-OAR-2009-0491-2763.1, p. 19]
Response: 
EPA took comment on it's methodologies to determine which states are included in the final Transport Rule.  Details on this methodology for the final Transport Rule and a discussion of comments can be found in section V of the preamble for the final Rule.   Please see preamble sections V and VI for results related to Louisiana.
Organization: Southern Company
Comment: 
Southern Company
I. EPA Should Not Move Florida from a Group 2 S02 State to a Group 1 S02 State
For the annual PM2.5 standard, EPA's use of the air quality assessment tool projected that, after implementation of the proposed FIPs, the Birmingham, Alabama, annual PM2.5 monitors would not have a NAAQS air quality nonattainment or maintenance problem. However, the results of the refined air quality modeling, using the regional air quality model CAMx, projected that Birmingham, AL, would exceed the threshold for 'maintenance' by a slight amount (less than 0.1 ug/m-3 ). Based on these results of the refined modeling, EPA has requested comment on whether Florida should be moved from Group 2 to Group 1. We agree with EPA's conclusion that upwind reductions beyond those in the proposed FIPs are not required to address significant contribution and interference with maintenance of the annual PM2.5 NAAQS in Birmingham, AL. As EPA states, 'the refined air quality modeling projects that Birmingham, AL, will exceed the maintenance criteria by only an extremely slight amount.' [EPA-HQ-OAR-2009-0491-2864.1, p. 42]
Response: 

Based on EPA's modeling and assessments for the final Transport Rule, Florida is not identified as a state with emissions that significantly contribute to or interfere with maintenance of the annual or 24-hour PM2.5 NAAQS.
Organization: Southern IL Power Cooperative
Comment: 
Southern IL Power Cooperative
Southern Illinois Power Cooperative feels the deadlines and percentage of emission reductions are too stringent, and are unnecessary to meet National Ambient Air Quality Standards. [EPA-HQ-OAR-2009-0491-2863.1 p.2]
Response: 
EPA performed a new analysis for removal of significant contribution for the final Transport Rule based on best available data (updated to incorporate comments from the Transport Rule proposal and Notices of Data Availability for the Transport Rule) and modeling.  EPA determined that the emission reductions required under the final Transport Rule are necessary to meet the requirements of Clean Air Act section 110(a)(2)(D)(i)--elimination of significant contribution and interference with maintenance.  Please refer to section VI of the preamble for the final Transport Rule for more details on EPA's assessment of significant contribution and section VII of the preamble for the final Transport Rule for details about timing of implementation for the final Transport Rule.
Organization: State of Delaware Department of Natural Resources & Environmental Control
Connecticut Department of Environmental Protection
Comment: 
Connecticut Department of Environmental Protection
The procedure EPA proposed for determining upwind states' emissions that significantly contribute to nonattainment or interfere with maintenance downwind is overly influenced by cost considerations and inadequate emphasis is given to addressing air quality. EPA's current procedure will result in adoption of a remedy where some downwind states will remain subject to post-remedy transport levels that will prevent them from reaching attainment solely through adopting additional local emission control programs. [EPA-HQ-OAR-2009-0491-2780.1 p.13]
EPA's 4-step procedure to quantify significant contribution does not take into account the concerns illustrated by the Greenwich ozone monitor in the example presented above. That is, the procedure doesn't account for the magnitude of the affected downwind state's contribution to its own nonattainment/maintenance monitors or the downwind state's corresponding ability to address any remaining nonattainment/maintenance issues strictly through additional in-state controls. Furthermore, on page 45271 of the proposed rule's preamble, EPA seems to shift the remaining burden of any "residual" nonattainment/maintenance concerns entirely to the downwind state: [EPA-HQ-OAR-2009-0491-2780.1 p.14]
"The Act requires upwind states to eliminate significant interstate pollution transport under section 110(a)(2)(D). It also requires each state to assure attainment and maintenance of the NAAQS within its borders. Thus, a downwind state must adopt controls to demonstrate timely attainment of the NAAQS despite any pollution transport from upwind states that is not eliminated under section 110(a)(2)(D)." [EPA-HQ-OAR-2009-0491-2780.1 p.14]
The final Transport Rule must satisfy each upwind state's interference with maintenance or it will fail to satisfy EPA's obligation pursuant to the CAA. Some states will be left with "residual" [EPA-HQ-OAR-2009-0491-2780.1 p.14]
Nonattainment/maintenance issues that cannot be rectified with additional in-state emission reductions. EPA's failure to fully address transport will become even more pronounced as future, more stringent NAAQS are promulgated, and transport becomes an even larger portion of the air quality challenges faced by downwind states. [EPA-HQ-OAR-2009-0491-2780.1 p.14]
State of Delaware Department of Natural Resources & Environmental Control
State Contribution Thresholds. In Section III. A. of the preamble to the proposed rule, EPA discusses that the proposed methodology of the rule uses air quality analysis to determine whether a state's contribution to downwind air quality problems is above specific thresholds. EPA states, 'If a state's contribution exceeds those thresholds, EPA takes a second step that uses a multi-factor analysis that takes into account both air quality and cost considerations to identify the portion of a state's contribution that is significant or that interferes with maintenance.' This statement is troubling to Delaware. It is Delaware's opinion that an upwind state's emissions contribution is significant or interferes with maintenance in a downwind state based on the emissions and their effect on air quality, and is independent of cost considerations. It is Delaware's opinion that cost considerations are relevant when selecting the source category or population of sources that are to be targeted for control, not in determining if the emissions contribute to significant contribution or interference with maintenance in a downwind state. [EPA-HQ-OAR-2009-0491-2980.1, pp.6-7]
Response: 
See preamble section VI.A.2 for a discussion of appropriateness with respect to EPA's use of cost in determining significant contribution.  EPA believes that it is appropriate to consider both cost and air quality metrics when quantifying each state's significant contribution.  The use of cost is also supported by the D.C. Circuit Court's determination that EPA may consider cost when measuring significant contribution, Michigan, 213 F.3d at 679.
Regarding residual non-attainment and maintenance problems at receptors in Connecticut, EPA's final modeling of the Transport Rule (section VIII of the preamble for the final Transport Rule) shows that these issues will be resolved in 2014.
Organization: State of Missouri Department of Natural Resources
American Lung Association
National Association of Clean of Air Agencies (NACAA)
American Lung Association of the Mid Atlantic
Clean Air Council
Environmental Defense Fund (EDF)
Southern Alliance for Clean Energy
American Lung Association of Georgia
Geogians for Smart Energy Coalition
Clean Air Task Force
Comment: 
American Lung Association
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.61 & 67.]
EPA should set a much tighter national limit on sulfur dioxide and nitrogen dioxide emissions.
We call on EPA to set a nationwide limit on sulfur dioxide equivalent to 1.75 million tons by 2014.
Nitrogen oxide limits need to be lowered to 900,000 tons by 2014.
The control technology is widely available and effective. The investment in cleaning up even more means that we would see greater benefits including more lives saved each year.
We urge you today therefore to set stronger caps.
We urge that the limits should be 900,000 tons of nitrogen dioxide and 1.75 million tons of sulfur dioxide by 2014.
[This comment was also submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.48.]
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.10-11.]
The Lung Association recommends that EPA strengthen the limits by 2014 to no more than 90,000 tons of nitrogen oxide emissions and 1.75 million tons of sulfer dioxide emissions. These two pollutants are harmful as they pour out of the smokestack, but in the air, they convert toharmful fine particles and ground-level ozone. 
American Lung Association of Georgia
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.58-59.]
EPA can and should require even more reductions.
We support a nationwide limit on sulfer dioxide of no more than 1.75 million tons by 2014. Nitrogen dioxide limits should be no more than 900,000 tons by 2014. We support EPA reviewing the calculations using the 2008 national standard for ozone to determine what is really needed now. 
American Lung Association of the Mid Atlantic
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.28 & 33.]
As proposed, the rule will decrease sulfur dioxide pollution by 72 percent and nitrogen oxide pollution by 52 percent. Those aren't just measurements. These reductions will save 14,000 to 36,000 lives each year. They will prevent many heart attacks each year and eliminate many visits to the emergency room or the hospital.
EPA should require even more reductions. The benefits so far outweigh the costs that we can and should require tighter reductions.
We urge the Administrator to set even stronger caps than are currently proposed for 2014, for sulfur dioxide, an 80 percent reduction to 1.75 million tons per year, and for nitrogen oxides, a 68 percent reduction to 900,000 tons per year.
Clean Air Council
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.44.]
The Council's biggest concern is that the NOX reductions are not adequate to truly address the transport issue. EPA should revisit the proposed emission caps for NOX and make sure they are adequate to ensure that areas like Western Pennsylvania can meet the federal health standards.
Clean Air Task Force
The Clean Air Act ("CAA" or the "Act") requires state implementation plans ("SIPs") to include measures that adequately address transported pollution, and EPA has a duty to enforce these requirements, including but not limited to the promulgation Federal Implementation Plans ("FIPs") in the absence of compliant transport SIPs. EPA's proposed TR fulfills that duty only partially, not completely. In order to protect public health adequately, and to allow many areas around the country that will be in violation of the ozone and fine particulate ("PM2.5") National Ambient Air Quality Standards ("NAAQS") to attain those standards, EPA must tighten the emission caps and expeditiously finalize the proposed rule. Tighter emission caps are necessary to eliminate significant contribution to nonattainment and maintenance problems in several remaining downwind areas, and are therefore required under the Act and governing regulatory precedent and policy. Additional reductions of power plant emissions are also feasible, cost-effective, and will produce public benefits dramatically higher than the costs of controls. [EPA-HQ-OAR-2009-0491-2738.1, p.2]
We believe that EPA's TR proposal is a good step towards requiring needed air pollution reductions in the electric power sector, and we commend EPA for bringing the proposal forward. We are concerned, however, that the proposal falls short of requiring the amount of cost-effective reductions that are reasonably obtainable, necessary to protect human health and the environment, and necessary to eliminate significant contribution to downwind nonattainment and maintenance problems. [EPA-HQ-OAR-2009-0491-2738.1, p.4]
We therefore urge EPA to: reduce the 2014 aggregate state budgets in the annual control region (including Texas) for SO2 to 1.75 million tons (approximately equivalent to a 2 million ton nationwide cap); reduce the 2014 aggregate state budgets in the annual control region (including Texas) for NOx to 900,000 tons (approximately equivalent to a 1.25 million ton nationwide cap); and include Texas, Arkansas, New Hampshire, North Dakota and Oklahoma in the control region for SO2 and annual NOx purposes, and include Massachusetts and Missouri in the control region for ozone season NOx purposes. [EPA-HQ-OAR-2009-0491-2738.1, p.4; This comment can also be found at section IV.E.1 of this comment summary]
A. Basic Structure and Approach
The Clean Air Act requires states to include in their plans to implement the NAAQS 'adequate provisions...prohibiting...any source or other type of emissions activity within the State from emitting any air pollutant in amounts which will...contribute significantly to nonattainment in, or interfere with maintenance by, any other State with respect to any such national primary or secondary air quality standard....' Section 110(a)(2)(D)(i)(I). If a state does not meet that requirement on its own, EPA must require it to do so or impose a federal implementation plan (FIP). 18 Once EPA has determined that transported pollution significantly contributes to downwind nonattainment problems, it must require that pollution to be eliminated. The DC Circuit Court of Appeals stressed this requirement in its decision overturning CAIR.  [EPA-HQ-OAR-2009-0491-2738.1, p.5]
EPA has thoroughly documented in the TR and elsewhere the problem of transported air pollution and its extensive and harmful effect of on downwind public health and welfare and resulting NAAQS attainment problems.  In this case, EPA has shown that in the absence of regional reductions in NOx and SO2 emissions, widespread ozone and PM2.5 nonattainment will be experienced in the East, South and Midwest. [EPA-HQ-OAR-2009-0491-2738.1, p.5]
More specifically, EPA has found that NOx and SO2 emissions from 32 states (including) contribute significantly to nonattainment of the PM2.5 or ozone NAAQS in other states. However, as we will discuss in detail below, and as EPA acknowledges in the TR proposal, EPA's air quality modeling shows that some downwind areas will continue to have nonattainment or maintenance problems even after the proposed rule is implemented. [EPA-HQ-OAR-2009-0491-2738.1, p.6]
EPA also estimates that benefits from the rule will exceed costs by from 50 to over 120 times (an estimate which omits many substantial benefits that were not included because EPA could not reduce them to a fixed monetary value).  This enormous benefit-cost ratio not only provides ample support for the proposed reductions, but also makes clear that there is ample room for more stringent emissions limits in the TR. The incremental public health benefits that will flow from tighter rule will still exceed costs by an overwhelming margin. [EPA-HQ-OAR-2009-0491-2738.1, p.6]
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.106-107.]
Therefore, we urge EPA to reduce the annual control region SO2 cap to 1.75 million tons and the NOX cap to 900,000 tons;
EPA's atmospheric modeling shows that even after the proposed rule is implemented, many downwind areas will still experience nonattainment or maintenance problems under the 1997 annual PM 2.5 NAAQS; the 24-hour PM 2.5 NAAQS; and the ozone NAAQS.
At a minimum, these nonattainment areas should be brought into attainment by having appoint contribution.
Environmental Defense Fund (EDF)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.75 & 77.]
EDF respectfully requests that the EPA significantly strengthen the limits on sulfur dioxide and nitrogen oxide in order to further improve the health and lives of millions of Americans.
We respectfully request that the EPA establish substantially more rigorous limits on SO2 and NOX by 2014 in order to prevent more premature deaths, further reduce lost work days and protect the millions of Americans who suffer from asthma and respiratory symptoms.
Geogians for Smart Energy Coalition
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.64.]
EPA should endorse a higher, tighter national limit on sulfer dioxide and nitrogen oxide emissions. And this investment in cleaning up even more means that we will see even greater health benefits, including more lives saved each year and fewer children gasping for breath. The choice is either that coal plant operators invest in emission controls or our families pay for distress and the costs of expensive healthcare needed for their children's illnesses caused by dirty coal pollution.
I wanted to also mention that we believe that the regional standards wouldn't address needed state regulatory limits and while still wouldn't impair any market trading. I urge you to courageously step up to the challenge and set aggressive standards that will protect our families from pollution-induced asthma, heart attacks, and other health ailments that we know result from coal-fired power plants.
National Association of Clean of Air Agencies (NACAA)
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.105-108, 115.]
Nitrogen oxide and sulfur dioxide emissions contribute to fine particulate matter and ozone pollution which cause significant public health problems, including premature deaths, infant mortality, nonfatal heart attacks, hospital admissions for respiratory and cardiovascular issues and emergency room visits for asthma.
NACAA believes the NOx emission caps in the proposed Transport Rule are not stringent enough.
While EPA proposes to lower the SO2 cap in 2014, the Agency makes no such adjustment for NOx.
Instead, EPA proposes to keep the same overly generous NOx cap for 2014 that is proposed for 2012, which still leaves several areas vulnerable to interstate transport problem.
Although EPA says it will address the NOx reductions needed to meet the soon-to-be promulgated revised ozone standard in Transport Rule II, it is imperative that the Agency include in this Transport Rule a second, tighter NOx cap in 2014 to assist states in attaining the current ozone standard.
Well, obviously, modeling is a strong tool there to help us analyze that, and we did ask questions about the budgets, and even yesterday with our own calls tried to get a better understanding how the two models work together to set up the overall benefits versus the allocations and so forth. So we're still trying to understand, quite honestly, how it's coming together, but I think our general observations were that the NOx life seemed more lenient than what we needed to achieve.
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.82-83.]
For example, the NOX emissions caps in the proposed Transport Rule are not stringent enough. While EPA proposes to lower the SO2 cap in 2014, the agency makes no such adjustment for NOX. Instead, EPA proposes to keep the same overly-generous NOX cap for 2014 that is proposed for 2012. This is especially problematic because EPAs Transport Rule still leaves several areas vulnerable to interstate transport problems even under the ozone standard of 85 parts per billion, adopted in 1997, let alone the proposed 60-70 ppb EPA revised the ozone standard in 2008, lowering it to 75 ppb.
However, implementation of that standard was stayed while EPAA reconsiders the standard. EPA has proposed a range of 60-70 ppb. Since the 2008 standard was stayed, state and local air agencies are not developing range EPA is considering. Although EPA says it will address the NOX reductions needed to meet the soon-to-be promulgated revised ozone standard in Transport Rule ll, it is imperative that the agency include in this Transport Rule a second, tighter NOX cap in 2014 to assist states in attaining the 85 ppb ozone standard.
Southern Alliance for Clean Energy
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.36-37.]
We urge the EPA to reduce the annual control region sulfer dioxide cap to 1.75 million tons and the nitrogen oxide cap to 900,000 tons.
State of Missouri Department of Natural Resources
Additionally, the proposed rule does not fully satisfy the Clean Air Act (CAA) Section 110(a)(2)(D) mandate to eliminate.upwind emissions that prevent downwind attainment or maintenance. If CAMx modeling shows that several areas will continue to be nonattainment or not maintain the standard, the Transport Rule should be re-evaluated. Because emissions are likely to increase in noncontributing states over time, these states could become contributing upwind states in the future. At a minimum, the additional fourteen (14) nonattainment and maintenance areas should be addressed by the final rule. [EPA-HQ-OAR-2009-0491-3806, p.2]
Response: 
Clean Air Act section 110(a)(2)(D)(i)(I) addresses emissions that significantly contribute to nonattainment or interfere with maintenance of a NAAQS.  In this rule, therefore, EPA is only addressing such emissions.  
As described in section VI of the preamble for the final Transport Rule, EPA reassessed SO2 and ozone season and annual NOX reductions for the final Transport Rule.  Please refer to this section for further details.

EPA finds that the final Transport Rule emission reductions of annual NOX and SO2 successfully address all emissions that significantly contribute to nonattainment and/or interfere with maintenance of the 1997 annual PM2.5 NAAQS and the 2006 24-hour PM2.5 NAAQS in the states covered by this rule for those NAAQS.  Regarding non-attainment of the ozone NAAQS, EPA believes it can best serve states with ozone non-attainment problems by quickly finalizing this rule and seeking further ozone season NOX reductions, if necessary, in subsequent rulemakings.  This does not preclude EPA from future transport-related rulemakings to address new standards.  See final Transport Rule preamble section VI.D for more details about elimination of significant contribution.

Additionally, air quality modeling results provided in section VIII.B of the final rule's preamble indicate that the final Transport Rule will resolve non-attainment with all PM2.5 standards for all receptors with the exception of 1 receptor with remaining non-attainment problems for the 24-hour PM2.5 standard in the Liberty-Clairton area--which EPA has noted is heavily influenced by a local source of organic carbon (75 FR 45281).  This modeling also indicates that only 1 area (Houston, TX) is expected to have remaining non-attainment problems for the ozone standard and only 1 area (Baton Rouge, LA) is expected to have remaining maintenance problems for the ozone standard.
Organization: State of Wisconsin, Department of Natural Resources
Progress Energy Service Company
Duke Energy
Comment: 
Duke Energy
Last year, the Lake Michigan Air Directors Consortium ("LADCO") strongly recommended that any CAIR replacement rule include an initial compliance date no earlier than 2017 for any significant additional emission reduction requirements. LADCO explained in its recommendations to EPA that it had conducted a state-by-state analysis that indicated that installation of significant new NOx and SO2 controls -- specifically, installation of selective catalytic reduction systems ("SCRs") and flue gas desulfurization systems ("FGDs" or "scrubbers") -- would not be possible in LADCO states before 2017. Id. at 1, attachment at 4-5.10 [EPA-HQ-OAR-2009-0491-2689.1, p.1] On the other hand, the PTR's compliance schedule is wholly unreasonable; particularly its imposition of a January 1, 2012 initial compliance deadline that will fall only a few months after EPA plans to take final action in this rulemaking. [EPA-HQ-OAR-2009-0491-2689.1, p.1] 
In addition, EPA has required additional emission reductions even where they have not been shown to be needed to meet the air quality objectives that EPA asserts. [EPA-HQ-OAR-2009-0491-2689.1, pp.1-2]
The Proposed Transport Rule Should Not Include an Initial Compliance Deadline of 2012.
It is unreasonable and unrealistic to expect emission reductions required by the proposal to be achieved by January 1, 2012, barely six months after the date on which EPA expects to issue a final Transport Rule. [EPA-HQ-OAR-2009-0491-2689.1, p.6]
An Initial Compliance Deadline of 2012 Will Not Allow Enough Time for Sources to Make the Changes Necessary to Comply with the Transport Rule
A compliance deadline of 2012, following a mid-2011 date for final promulgation of the rule,5 would not allow enough time for sources to take actions that might be needed for compliance, such as installing or upgrading controls or switching to lower sulfur coal. [EPA-HQ-OAR-2009-0491-2689.1, p. 8]
Additionally, notwithstanding these assertions that the emission reductions required in 2012 would occur even without the Proposed Transport Rule, EPA indicated in a presentation given in July 2010, when it announced the proposed rule, that it projects that the proposed rule would reduce SO2 emissions by an additional one million tons per year ("TPY") in 2012 beyond what CAIR would have accomplished: from an emission level of 5.1 million TPY under CAIR to 4.1 million TPY under the PTR. See Overview Presentation 7/26/10 at slide 33, available at http://www.epa.gov/airquality/transport/actions.html. In fact, during a meeting held shortly after EPA issued the proposed rule but before its publication in the Federal Register, EPA acknowledged that, according to the Agency's projections, the 2012 state budgets in the Proposed Transport Rule would reduce SO2 emissions by 1.2 million TPY, from 5.1 million TPY under CAIR to 3.9 million TPY under the Proposed Transport Rule. EPA failed to explain this apparently substantial discrepancy or how over a million additional tons of emissions would be eliminated in a phase of the program that is intended merely to replicate what would have occurred anyway. [EPA-HQ-OAR-2009-0491-2689.1, p.9]
Furthermore, EPA has not shown that emission reductions beyond those required by CAIR are necessary. EPA's own data show that existing controls are working to reduce emissions; the result is that concentrations of SO2 and NOx in the ambient air have declined steadily in recent years.8 The D.C. Circuit's opinion in North Carolina v. EPA did not require, or even remotely suggest, that the overall degree of emission reductions required under CAIR was less than that necessary to comply with CAA section 110(a)(2)(D)(i)(I). Nor did the court include in its opinion any mandate that the replacement rule for CAIR must include a compliance date in 2012 or within any period of time as short as six months after final rule promulgation.9 [EPA-HQ-OAR-2009-0491-2689.1, pp.9-10]
EPA should not adopt the 2012 compliance deadline in the Proposed Transport Rule In the event that EPA promulgates a Transport Rule that, like the proposed rule, includes requirements more stringent than CAIR, the compliance deadline should reflect the degree of stringency of those requirements, when a final rule is promulgated, and a realistic assessment of the actual time it takes to retrofit controls on existing coal-fired power plants. [EPA-HQ-OAR-2009-0491-2689.1, p.10]
As economic activity picks up in the coming years, the implications of having to meet as a sector 2012 emissions cap that are based in large measure on less than representative base year periods and activity levels is unclear. It's critically important that if EPA finalizes the PTR with an unreasonable 2012 compliance period that the 2012 budgets be reasonably achievable for the sector because, as EPA acknowledges in the PTR, there will not be time between when EPA expects to finalize a rule (mid-2011) and January, 2012 for the addition of new emission controls or to upgrade existing controls. One possible result of extremely tight budgets in 2012 could be excessively high allowance prices. [EPA-HQ-OAR-2009-0491-2689.1, p.29]
EPA Underestimates the Complexity of Retrofitting FGD and SCR Systems.
In various prior rule makings, EPA has asserted what it believes to be appropriate times for the construction of additional controls. Unfortunately EPA has consistently and significantly underestimated the amount of time that it takes to implement these projects. On multiple occasions, Duke Energy and other entities have provided numerous comments in an attempt to correct EPA's understanding. Unfortunately in this rule making, EPA has continued to under estimate the time required for retrofit controls. This shortcoming is more egregious given the rush to regulate and impose additional controls upon the industry without giving sufficient time to construct those controls. Duke Energy once again requests that EPA defer to industry's estimates for the amount of time that it budgets for the installation of retrofit controls to allow for all phases of the project such as design engineering, financing, environmental permitting, as well as reasonable times for construction across the entire fleet. Duke Energy believes that the industry has earned this deference because of its extensive experience in adding retrofit controls over the last decade. [EPA-HQ-OAR-2009-0491-2689.1, pp.53-54]
EPA places all FGD and SCR installation activities into one of essentially three broad overlapping categories: (1) conducting an engineering review of the facility and awarding a procurement contract; (2) obtaining a construction permit; and (3) installing the control technology. EPA, "Engineering and Economic Factors Affecting the Installation of Control Technologies for Multipoint Strategies" (2002) at 7-8, 20, available at www.epa.gov/clearskies/pdfs/multi102902.pdf (hereinafter "2002 EPA Report").19 Categorizing the numerous activities involved in installing FGD and SCR systems in such a general way, however, masks the overall complexity of the numerous steps that are involved in the design, permitting, and construction of FGD and SCR retrofit systems at coal-fired power plants.  [EPA-HQ-OAR-2009-0491-2689.1, p.54]
FGD and SCR retrofits are complex projects requiring significant engineering, planning, permitting, construction, testing, and commissioning efforts. There are three major phases for a project of this type  -  engineering & permitting, construction, and commissioning. The timeframe required to begin and complete all of the required tasks in each phase is the relevant duration for how long it takes to complete and bring a FGD or SCR on line. Simply looking at the time it might take to actually construct a FGD or SCR is not appropriate and does not capture a significant amount of a given project's duration. None of the tasks preceding the actual construction of a FGD or SCR are optional and every phase is critical to the overall project completion. [EPA-HQ-OAR-2009-0491-2689.1, p.55]
1. Engineering and Permitting.  
What needs to occur during this phase of a project is considerably more than what EPA refers to as an engineering review. The engineering and permitting stage includes the development of the engineering drawings and specifications to support the bidding of the major equipment and construction contracts and the submission of permit applications to the various agencies from which we are required to obtain permits prior to construction and operation of these facilities. After an initial preliminary engineering phase during which the plant layout and process flows of the new systems are produced, the development of detailed engineering drawings and specifications are required to prepare the bid packages for the major contracts. The bid period for some of the contracts is 1 to 2 months because of the complexity of some of the systems required. The bid evaluation period by the owner can take 4 to 6 months in order to arrive at the lowest evaluated cost, as required by obligations to our customers and shareholders. Add to this the time required to negotiate contract terms and issuing the requisite contracts. [EPA-HQ-OAR-2009-0491-2689.1, p.55]
Some of the major equipment contracts will need to be in place so detailed information can be included in permit applications. [EPA-HQ-OAR-2009-0491-2689.1, p.56] 
Similarly, EPA seems to underestimate the complexity of permitting a FGD or SCR retrofit. For many projects permitting may take longer than actually fabricating the facility. Nearly all permitting aspects, which include more than simply air permitting, as explained below, require public notice, provide for public hearing and comment, and provide an opportunity for opponents to challenge the permit. It can take several years. Thus, it's far more complex than simply obtaining a construction permit. Rather than merely getting a single "construction permit" -- which may have been a relatively quick-and-easy process at the time of the writing of the 2002 EPA Report -- retrofitting FGD and SCR systems today requires numerous authorizations before construction can begin or before a unit can start operating the new systems, including authorizations and permits that were not required a decade ago or that did not take as long to get 10 years ago as they do now. [EPA-HQ-OAR-2009-0491-2689.1, p.56]
Permits must also be obtained to address the byproduct of a wet FGD systems including the benign byproducts of those systems, such as gypsum. In the past it has taken Duke Energy anywhere from 42 to 48 months to secure a land use management permit for scrubber byproducts when the landfill is located on the power plant property. This timeline includes locating and assessing the suitability of the site (18-22 months), securing the permit to construct (10-12 months), construction (12 months), and securing the operating permit (2 months). Duke Energy has no reason to believe that a future landfill permit would not take the same amount of time to obtain. In situations where property must be purchased for a new FGD landfill, the time it would take to obtain the permits necessary to construct and operate a landfill would be considerably longer than 42 to 48 months. Additionally, permitting and construction of a landfill will likely be much longer depending upon the classification of the FGD gypsum byproduct that may result from the proposed EPA Coal Combustion Residual rule now out for comment, should FGD gypsum be classified as a "special waste" under RCRA Subtitle C.  [EPA-HQ-OAR-2009-0491-2689.1,p.58]
In addition, unmentioned in the 2002 EPA Report is that in some states companies cannot proceed with the installation of new FGD or SCR systems unless and until they receive authorization from their public utility commissions to do so. Obtaining this approval can add to the overall project duration. [EPA-HQ-OAR-2009-0491-2689.1, p.58]
2. Construction.  
The construction phase includes grading of the site, foundations, superstructure, and erection of the mechanical systems and auxiliary power systems. As noted above, construction of permanent structures and foundations cannot be started until after the proper permits are received. During this phase, the materials and equipment ordered in the first phase will arrive on site and be set in place. Testing of the mechanical equipment and the power and control systems will occur. Tie-ins to existing plant equipment will occur during a unit outage during this phase. After tie-ins and the testing and check out of the new systems, the new FGD or SCR will be available for start-up.  [EPA-HQ-OAR-2009-0491-2689.1, p.59] 
Spanning the engineering and permitting and construction phases is the fabrication of the equipment required for the project. This phase of a project deserves special mention here due to the long lead times associated with some of the major equipment and systems associated with FGD and SCR systems. Typical lead times for the longer duration equipment are 18 to 20 months after receipt of the purchase order by the vendor. These durations reflect current durations in a slow market. These durations will increase significantly when many utilities begin installing these systems to meet EPA regulations due to limitations on vendor production capacity for this specialized equipment and for the raw materials, such as copper and special metals and steel alloys that are utilized in the manufacture of some of the components. This phenomenon occurred during the most recent flurry of FGD installations. [EPA-HQ-OAR-2009-0491-2689.1,p.59]
3. Commissioning.  
The commissioning phase begins as the unit outage is complete and the equipment is started up and operated for the first time. Although the unit is in operation at this time, critical tuning of the equipment and systems occurs during this phase in order to get the system to perform as designed. The duration of this phase is highly dependent on the individual system and a typical duration for a system without serious issues is 3 months. [EPA-HQ-OAR-2009-0491-2689.1, p.60]
Duke Energy's Experience Demonstrates that EPA Has Substantially Underestimated The Amount of Time it Takes to Retrofit FGD and SCR Systems at Coal-Fired Power Plants.
Apparently based in large part or entirely on a March 2005 report, EPA concludes that FGD retrofits can be completed in only 27 months and SCR retrofits can be completed in only 21 months. Based on these durations, EPA concludes that because there are approximately 30 months between mid-2011 (when EPA anticipates finalizing the PTR) and January 1, 2014 (the start of phase 2), there is sufficient time for sources to install the FGD and SCR systems projected by IPM to be retrofit to meet the PTR budgets.21 Based on its experience with retrofitting its coal-fired power plants with FGD and SCR systems, EPA has vastly underestimated the amount of time that it takes to design, permit, construct, and start up these systems. [EPA-HQ-OAR-2009-0491-2689.1, pp.60-61]
Duke Energy has retrofit many coal-fired electric generating units with FGD and/or SCR systems, and never has it been able to complete an FGD retrofit in 27 months or an SCR retrofit in 21 months. The following table provides information regarding the duration of some of Duke Energy's FGD and SCR completed retrofits. These projects clearly demonstrate that the 21 month and 27 month durations cited by EPA for SCR and FGD retrofits respectively are not achievable. [EPA-HQ-OAR-2009-0491-2689.1,p.61][[See Docket Number 
Duke Energy has retrofit many coal-fired electric generating units with FGD and/or SCR systems, and never has it been able to complete an FGD retrofit in 27 months or an SCR retrofit in 21 months. The following table provides information regarding the duration of some of Duke Energy's FGD and SCR completed retrofits. These projects clearly demonstrate that the 21 month and 27 month durations cited by EPA for SCR and FGD retrofits respectively are not achievable. [EPA-HQ-OAR-2009-0491-2689.1, p.61]  [[See Docket Number EPA-HQ-OAR-2009-0491-2689.1, p.61 for the table.]]
As further evidence that it takes far longer than 27 months to complete an FGD installation, a number of years ago Duke Energy contracted with Sargent and Lundy to develop a detailed project schedule for the possible installation of FGD systems on units 4, 5, and 6 of Duke Energy's W B Beckjord power plant in Ohio (W B Beckjord unit 6 is one of the units to which IPM adds an FGD in 2014). The schedule that Sargent and Lundy developed shows 52 month duration from project initiation to the date that the FGD for unit 6, the first of the 3 FGD retrofits to be completed based on the schedule, is available for service. As of today no work has been performed on this project so if Duke Energy were to proceed with this FGD retrofit, it would be anticipated to take the entire 52 months. It would not be possible to have this FGD operating by January 1, 2014 even if the project were to begin today, almost a year before EPA plans to finalize the PTR, which is the point in time when EPA believes (and Duke Energy agrees) it is appropriate to initiate any new emission control projects that are needed to meet the rule's requirements.  [EPA-HQ-OAR-2009-0491-2689.1, pp.61-62]
In summary, EPA has greatly underestimated the amount of time that it takes to design, permit, construct, and start up new retrofit FGD and SCR systems. It will take significantly longer than 30 months for affected EGUs to complete the retrofits of FGD and SCR units at coal-fired power plants. Thus, it will not be possible for affected EGUs to achieve all the SO2 and NOx emission reductions that -- under the terms of the PTR -- must be achieved by that rule's January 2014 deadline. [EPA-HQ-OAR-2009-0491-2689.1, p.62]
Footnote 19: The 2002 EPA Report also notes that source owners must obtain an operating permit for new control equipment but does not suggest that the process of getting such a permit will add months to the overall process of getting SCR and FGD equipment ready to operate. This step can in fact add many months to the timeline for pollution control retrofits. [EPA-HQ-OAR-2009-0491-2689.1, p.54]
Footnote 21: In presenting the schedule that affected source owners would face in making the additional emission reductions that the final Transport Rule will impose, EPA implies throughout the PTR preamble that the appropriate time for source owners to initiate work on any emission controls that are needed to meet the rule's requirements is when the Transport Rule is finalized. See, e.g., 75 Fed. Reg. at 45273/1, where EPA makes "mid-2011 (when the Agency anticipates finalizing this rule)" the start of the time period in which source owners are to design and construct additional FGD and SCR systems at their plants. EPA is correct in taking this approach. It would be entirely inappropriate for EPA either to require affected source owners to initiate serious work on additional control systems or to assume that source owners will voluntarily start such efforts before the Transport Rule is final. Indeed, it would be imprudent for regulated sources to start making major investments in the design and construction of controls that may or may not be needed dependent on the terms of the final Transport Rule and the terms of other emission control rules that are scheduled to be published by EPA in the near future and that could affect the control options faced by power plant owners. This is particularly so given the uncertainty as to the outcome of the present rulemaking that EPA has created by publishing the NODA and indicating that the emission budgets and allowance allocations in the final Transport Rule could be very different from those that EPA has proposed. [EPA-HQ-OAR-2009-0491-2689.1,p.60]
Progress Energy Service Company
Many of Progress Energy's concerns regarding the proposed Transport Rule, described in the sections that follow, could be resolved to a significant degree by eliminating the 2012 compliance date. Progress Energy believes that it is unreasonable and unrealistic to expect reductions - particularly the additional S02 reductions in Group I states - required in the proposal by January 2012, a mere six months after the date on which EPA proposes to issue a final Transport Rule. [EPA-HQ-OAR-2009-0491-2831.1 p.3]
According to EPA, the emission levels required in the 2012 phase generally reflect only the emission reductions that would occur even in the absence of the Transport Rule. However, in a number of cases, EPA has made incorrect assumptions regarding emission reductions that will occur at units by 2012. In addition, the approach set forth in the Proposed Transport Rule penalizes early emission reductions under the CAIR and seriously weakens market incentives.  [EPA-HQ-OAR-2009-0491-2831.1 p.3]
Notwithstanding EPA's assertion that the emission reductions required in 2012 would occur even without the proposed Transport Rule, a presentation given by EPA in July, when it announced the proposed rule, indicates that the proposed rule would reduce S02 emissions by an additional one million tons per year ('TPY') in 2012 beyond what CAIR would have accomplished: from a level of 5.1 million TPY under CAIR to 4.1 million TPY under the proposed rule. In fact, during a meeting held shortly after the proposed rule was issued, the Director of EPA's Clean Air Markets Division acknowledged that the 2012 state budgets in the Proposed Transport Rule would reduce S02 emissions by 1.2 million TPY, from 5.1 million TPY under CAIR to 3.9 million TPY under the Proposed Transport Rule. Progress Energy urges EPA to explain this apparent discrepancy and how over a million tons of emissions would be eliminated by using controls already available.  [EPA-HQ-OAR-2009-0491-2831.1 p.3]
Moreover, the Company believes that emissions reductions beyond those required by CAIR are not necessary. EPA's data show that existing controls are working to reduce emissions of SO2 and NOx have declined steadily in recent years. The D.C. Circuit's opinion in North Carolina v. EPA did not require that the overall levels of reductions required under CAIR be less than the levels necessary to comply with the section II0(a)(2)(D)(i)(J) of the Clean Air Act (CAA), nor did the court include in its opinion a mandate that the replacement rule for CAIR include a compliance date in 2012 or within any period of time as short as six months after final rule promulgation.  [EPA-HQ-OAR-2009-0491-2831.1 p.3]
Progress Energy urges EPA to eliminate the 2012 compliance deadline in the Proposed Transport Rule and instead establish an initial compliance date no earlier than January 1,2014. In the event that EPA promulgates a Transport Rule that includes requirements more stringent than CAIR, as EPA's July 2010 presentation on the proposal suggests, the initial compliance deadline should be later. Concern regarding the initial compliance date is not confined to utilities. Last year, the Lake Michigan Air Directors Consortium (·'LADCO') recommended that any CAIR replacement rule include an initial compliance date no earlier than 2017. See lener from LADCO to Administrator Jackson (Sept. 10, 2009). Phase I of CAIR would remain in place and continue to maintain emission reductions pending the initial compliance deadline for the Transport Rule. [EPA-HQ-OAR-2009-0491-2831.1 p.3-4]
2012 Deadline
EPA correctly recognizes that new FGD and SCR installations could not be added by January 2012 unless they are already under construction. However, EPA incorrectly claims that between final rule promulgation and January I, 2012, utilities could install 10w-NOx burners and switch to burning lower sulfur coal. [EPA-HQ-OAR-2009-0491-2831.1 p.4]
2014 Deadline
EPA claims that additional FaD and SCR systems can be permitted, designed and installed between June 2011 (the date EPA plans to issue the final Transport Rule) and the end of2013 because, EPA claims, it takes about 27 months to design, permit, and build FaDs and about 21 months to design, permit, and build SCRs. Progress Energy believes that EPA has not adequately justified these assumptions. Progress Energy's experience in installing nine FaD system retrofits as well as nine SCR system retrofits is that the actual time to construct the equipment is in the range oftime that EPA has assumed for the entire design, permitting, and construction process. However, the design and permitting parts of the process add approximately 18 months to the total time for installation, making EPA's estimates of27 months for FaD installation and 21 months for SCR installation much too short. Progress Energy urges the EPA to make these assumed timeframes more realistic at approximately 44 months for FGD installation and 38 months for SCR installation. In addition, EPA should take into account the additional workload on state permitting authorities to process additional pollution control projects. This likely will extend the pennitting portion of the project timelines and add to the total amount of time needed for project completion. [EPA-HQ-OAR-2009-0491-2831.1 p.5]
EPA's Determinations of 'Significant Contribution' and 'Interference with Maintenance' Presuppose EGU Emissions as the Primary Cause of Downwind Nonattainment Problems and Underestimate the Contribution of Local Sources
Section IV of the preamble to the Proposed Transport Rule explains the complicated process by which EPA defined 'significant contribution' and 'interference with maintenance.' Ultimately, EPA proposes that the amount of emissions each upwind contributing state can reduce at $2OO/ton for NOx and $2000/ton for S02 constitutes the upwind states' 'significant contribution.' Following this explanation, EPA states that only a few nonattainment and maintenance areas are projected to remain. Then, at the end of the process, EPA concludes that the few remaining nonattainment or maintenance problems are caused by and can be addressed by local controls. [EPA-HQ-OAR-2009-0491-2831.1 p.5]
Therefore, the proposed rule puts all or most of the emission reduction burden on sources located outside the local area. Proper accounting for local controls may well have resulted in different emission budgets. In addition, EPA may have failed to include binding state emission control requirements in its base case. [EPA-HQ-OAR-2009-0491-2831.1 p.6]
State of Wisconsin, Department of Natural Resources
Provide a clear, achievable and reasonably equitable structure to ensure Wisconsin sources in the sector(s) addressed are able to plan, fund and install emission control equipment sufficient to address all likely [Sec 110] significant contributions to downwind states that originate from the sector in Wisconsin. [EPA-HQ-OAR-2009-0491-2829.2, p.1; This comment can also be found at section III.D of this comment summary]
EPA needs to include within the current framework the capability to consider other sector emissions and additional EGU sectors emissions as being sufficiently cost effective to be addressed within any definition of 'significant contribution'. Midwest states suggested a two-step contribution assessment with two core components. A first step which EPA did pursue in this proposal identifies significant air quality impact and as a result, significant contribution. The second step would go beyond a core regional remedy specific to the power sector, identifying states with residual contribution and direct liability within state SIP planning processes to meet commit toward crafting viable SIPs. [EPA-HQ-OAR-2009-0491-2829.2, p.4]
Under EPA's proposed rule assessment, the following states were identified as contributing towards Wisconsin's non-attainment and/or maintenance concerns related to the 1997 and 2006 PM-2.S standards: [EPA-HQ-OAR-2009-0491-2829.2, p.5; See EPA-HQ-OAR-2009-0491-2829.2, p.5 for the table entitled: Significant Contribution for the 1996/ 1997/ 2006 air quality standards]
EPA's assessments also indicate that additional EGU sector reductions would cost relatively less per ton on average than equivalent non-EGU point source controls already acknowledged as necessary by EPA. Hence even a cost driven assessment of significant contribution relative to control levels achieved through RACT, BART and BACT would indicate a rationale for deeper post-2014 EGU control budgets in states with residual contribution demonstrated in years after the early program implementation period. [EPA-HQ-OAR-2009-0491-2829.2, p.8]
Response: 
Regarding installation of EGU controls and the timing of Transport Rule implementation (2012 and 2014), EPA received extensive comment and took these comments into consideration when designing the final Transport Rule.  For a detailed description of EPA's rationale for the final Transport Rule, please refer to section VII.C of the preamble for the final Transport Rule.
Organization: Utility Air Regulatory Group (UARG)
E.ON U.S.
First Energy
National Mining Association (NMA)
George Washington University Regulatory Study Center
National Resources Defense Council (NRDC)
Southeastern States Air Resource Managers (SESARM)
Group Against Smog and Pollution (GASP)
Northeast States for Coordinated Air Use Management (NESCAUM)
Cleco Corporation
Comment: 
Cleco Corporation
Under EPA's proposed rule, EPA identifies downwind receptors and then links upwind states to those receptors. With few exceptions, under this proposed rule, once a state is linked to a downwind area, EPA requires EGU controls necessary to bring that downwind area into full attainment and ensure that there are no projected maintenance issues. As a result, EPA's methodology essentially shifts the burden of air quality attainment out of state, and upwind EGUs effectively bear the full burden of resolving local nonattainment and maintenance problems in downwind states. The "good neighbor" provision was intended to supplement, not supplant, state and local efforts to attain and maintain the NAAQS. [EPA-HQ-OAR-2009-0491-2859.1 p.7]
The proposed rule's application with respect to the relationship between Louisiana and Harris County, Texas (Clinton Drive monitor) provides a prime example of how EPA improperly shifts the burden of air quality attainment to upwind state EGUs. As discussed above, Louisiana is in the PM-2.5 programs because the Clinton Drive monitor is projected to have maintenance problems under the 1997 annual PM-2.5 standard. EPA completely ignores the state and local efforts specifically designed to address potential maintenance problems at that monitor and instead proposes NOx and SO2 reductions and permanent emissions caps for all EGUs in Louisiana sufficient to eliminate the projected issues. Yet the record demonstrates that Texas and Harris County have been able to quickly improve air quality at the Clinton Drive monitor with costeffective local controls. This is how the Clean Air Act is designed to work. Each State has primary responsibility for its air quality. Louisiana's obligation as a good neighbor should be triggered only when those local controls have been implemented and have failed to produce results. This relationship between Louisiana EGU's and the Clinton Drive monitor clearly demonstrates the need for EPA to reconsider its assessment of local controls. [EPA-HQ-OAR-2009-0491-2859.1 p.7]
E.ON U.S.
Using EPA approved modeling protocols and updated inputs, Alpine Geophysics concluded that the ozone targets specified in the Proposed Transport Rule can be achieved no later than 2014 without any controls beyond the existing CAIR and other business as usual requirements. They determined that the same is true for 24-hour and annual PM 2.5 targets, with the possible exception of two locations that appear to be influenced by local sources. Consequently, it is unnecessary for EPA to adopt emission targets more stringent than CAIR to eliminate interstate transport interfering with downwind nonattainment with NAAQS requirements. EPA's proposedreduction targets in the Proposed Transport Rule are unjustified. [EPA-HQ-OAR-2009-0491-2797.1, pp.4-5]
Invalid assumptions on switching to lower sulfur coals.
EPA states that its analyses do not add capital or operations and maintenance costs for coal switching from higher to lower sulfur bituminous coals (Federal Register page 45273). This assumption is incorrect. All pulverized coal (PC) boilers are designed for a very specific coal specification; changes could invalidate manufacturer guarantees. Switching to lower sulfur coal can result in the boiler operating outside its design specification which will result in reduced efficiency (higher CO2 emissions per MW produced) or in many cases significant operational problems such as slagging. Overcoming these operational problems will requires significant boiler modifications which EPA has not considered in their implementation timeframe or cost analysis. Also, the use of lower sulfur fuels will likely require modifications to electrostatic precipitators and potentially for the coal handling equipment (mills, etc.). EPA states that "[e]astern bituminous coals used for power generation typically have more than sufficient sulfur content to facilitate highly efficient collection of fly ash in a cold-side electrostatic precipitator." Our operating experience shows that this is not the case and we have had to maintain minimum fuel sulfur content to avoid opacity issues. The additional cost and implementation time were not considered in EPA's cost analysis and implementation timeframes. [EPA-HQ-OAR-2009-0491-2797.1, pp.7-8]
First Energy
More fundamentally, EPA needs to revisit the level of emissions reductions required under CATR. Simply by using the most recent (2006-2009) monitoring data released by EPA, 80% of residual non-attainment areas identified by EPA in 2012 actually are already in attainment. [EPA-HQ-OAR-2009-0491-2657.1, p.1; This comment can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, pp.1-2 10/15/2010]
Further, all Ozone monitors and all but two PM 2.5 monitors come into attainment by 2014 for the 1997 and 2006 standards, respectively, without any additional controls requirements based on air quality modeling conducted by MOG, utilizing a more representative base year and accounting for enforceable federal, state, and local regulations. Because the Court did not assign a deadline for EPA to address a remedy to CAIR and because revised standards for PM and Ozone are imminent (which will still bring the EPA-sought after health benefits referenced in CATR), the additional emission reductions imposed by the CATR rule are simply not needed at this time. [EPA-HQ-OAR-2009-0491-2657.1, p.2; This comment can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.2 10/15/2010]
Please see Appendices A and C for details regarding the modeling completed by Alpine Geophysics on behalf of MOG. [EPA-HQ-OAR-2009-0491-2657.1, p.2] [[See Docket Number  EPA-HQ-OAR-2009-0491-2657.1, pp.15-26 for Appendix A and pp. 28-32 for Appendix C.]
Even modeling just using the most recent monitoring data (2006-2009), 80% of residual non-attainment areas identified by EPA in 2012 actually are already in attainment (see Appendix C for details) [EPA-HQ-OAR-2009-0491-2657.1, p.3; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.3 10/15/2010]
In developing the CATR rule, FE believes the EPA has a responsibility to confer with the regional coordinating agencies that manage the ambient program as an additional step to verify the "Significant Contribution" at a particular monitoring site. The EPA does specifically highlight a significant Coking Plant in Allegheny County, PA as the main driver in Allegheny County's non-attainment. Similarly, FE recommends the EPA list the significant monitoring site pollutant sources for all sectors. [EPA-HQ-OAR-2009-0491-2657.1, pp.3-4;; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.4 10/15/2010]
George Washington University Regulatory Study Center
The SO2 and NOx emissions reductions from the Transport Rule would result in corresponding reductions in fine particulate matter (PM) concentrations. Indeed, it is these PM concentrations in downwind areas that the Transport Rule is primarily designed to address. Many downwind areas are violating air quality standards (NAAQS) for PM, or might do so in the future if upwind emissions are not reduced. The extent to which upwind states' emissions produce either result -- in legal terms, the extent to which upwind emissions "significantly contribute" to a NAAQS violation or "interfere with maintenance" of the NAAQS -- determines whether and how the Transport Rule emissions restrictions will apply. The EPA therefore must define in the Transport Rule exactly what contribution of upwind emissions to downwind PM concentrations could be classified as either a significant contribution or interference with maintenance. The second section of these comments examines a potential problem with the high level of precision chosen by the EPA for the proposed thresholds for significant contribution and interference with maintenance. [EPA-HQ-OAR-2009-0491-2573.1, pp.5-6]
Group Against Smog and Pollution (GASP)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.191-194.]
Southwestern Pennsylvania is home to the Liberty-Clairton PM 2.5 nonattainment area, this is a tiny area made up of five municipalities just southeast of Pittsburgh along the Monongahela River.
The Liberty-Clairton area has quite possibly the most severe PM 2.5 problem in the nation. This area also has the unfortunate distinction of being the only place in the eastern half of the United States that will still fail to meet the annual PM 2.5 standard after the proposed transport rule is fully implemented. This is not acceptable.
Over 20,000 people live in the Liberty-Clairton area. So long as we fail to address the areas continued nonattainment, well se additional cases of childhood asthma, heart attacks, and premature deaths. These are very real and very grave consequences of our failure to act, and they are completely avoidable.
EPAs reasoning for not addressing the Liberty-Clairton problem in the transport rule is that the area is heavily influenced by local emissions from the nearby US Steel Clairton Coke Works. In other words, EPA is saying, it's a local problem, not a transport problem.
It's true that the coke works has a huge influence on local PM 2.5 concentrations. However, long-range transport also plays a significant role in the problem. Based on 2001-2003 data used to develop the 1997 PM 2.5 state implementation plan for the area roughly 14 ug/m3 of the annual PM 2.5 measured at the Liberty monitor was emitted by sources other than the coke works. Thats about two-thirds of the total annual measured PM 2.5 concentration. Nearly 12 ug/m3 originate from sources beyond the areas long range transport modeling domain-thats a 150 x150 kilometer area centered on Liberty-Clairton.
So even before accounting for emissions from the coke works, the Liberty monitor is nearly violating the PM 2.5 annual standard, and the bulk of those 14 micrograms are from sources nowhere near Liberty-Clairton.
EPA cannot use the emissions from the Clairton Coke Works to justify a transport rule that essentially pretends Liberty-Clairton doesn't exist. Liberty-Clairtons PM 2.5 problem is caused by a combination of local and distant sources, and it can only be addressed by achieving reductions from both local and distant sources.
The Clairton Coke Works must do its part, upwind sources must do theirs. If the transport rule is finalized in its current form, the local emission reductions currently being developed would not be sufficient to demonstrate attainment of the 1997 annual PM 2.5 standard until 2017-the absolute latest deadline the Clean air Act allows.
Maybe the transport rule cant fully resolve the Liberty-Clairton problem
National Mining Association (NMA)
The Proposed Rule Does not Assume Sufficient Emission Reductions from Local Controls
The premise behind the proposed rule is that, to cure nonattainment or preserve attainment, upwind sources should control first, then downwind sources should address any remaining problem. As EPA stated, "EPA continues to believe that a strategy based on adopting cost effective controls on sources of transported pollutants as a first step will produce a more reasonable, equitable, and optimal strategy than one beginning with local controls." In the court decision overturning CAIR, however, the court ruled that EPA's notions of what is "reasonable," "equitable," or "optimal" are irrelevant in applying the CAA. Congress determines what is the "reasonable," "equitable," and "optimal strategy for addressing nonattainment and interference with maintenance; EPA then carries out Congress' wishes. Section 107(a) of the CAA plainly states that "[e]ach State shall have the primary responsibility for assuring air quality within the entire geographic area comprising such State." EPA thus has it exactly backwards -- under the statute, the nonattaining state must first seek to achieve attainment through local controls, and the upwind states may then be required to address any remaining increment of nonattainment.[EPA-HQ-OAR-2009-0491-2868.1, pp.19-20]
 EPA's flawed legal analysis is reflected in its base case modeling. That modeling does not assume any further controls on local sources. Had new local controls been assumed, the burden on upwind sources would have been reduced. Moreover, EPA's Emission Inventory TSD states that modeling of the 2014 control case is indeed intended as a complete remedy for nonattainment ("The 2014 TR Control Case was intended to represent the implementation of NOX and SO2 reductions to attain the existing ozone and PM2.5 NAAQS in the eastern U.S."). [EPA-HQ-OAR-2009-0491-2868.1, p.20] 
EPA's policy requiring upwind states to go first is based on the Agency's conclusion that upwind controls are lower cost than local controls. Whether or not this is true, it is irrelevant under the CAA. The notion that (presumably) lower cost controls in upwind states should be installed before (presumably) higher cost local controls derives from the Agency's views of interstate equity, a concept that the North Carolina court specifically found to be beyond the scope of EPA's power to implement under the CAA. Thus, EPA should at least have modeled a reasonable level of local controls to achieve and maintain attainment, a level that cannot be determined with reference to the cost of upwind controls. [EPA-HQ-OAR-2009-0491-2868.1,p.20]
National Resources Defense Council (NRDC)
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.42-43.]
Second, EPA's regulation of coal-fired power plant is timely because reductions from these highly-polluting facilities are long overdue.
The vast majority of sulfur dioxide and nitrogen oxide pollution emitted by coal-fired power plants comes from the 50 percent of facilities that lack basic emission controls for these pollutants.
These plants are, for the most part, decades old and were initially grandfathered when the Clean Air Act was passed, and improperly continue to operate today much as they did when they were built in the 1950s and 60s.
Finally, on behalf of NRDC's hundreds of thousands of members living in areas adversely affected by out-of-state air pollution, I urge U.S. EPA to go further in the final version of the Transport Rule by requiring additional reductions in pollution from coal-fired power plants.
Northeast States for Coordinated Air Use Management (NESCAUM)
The record appears to show that the emissions used in the modeling to determine the levels for eliminating significant contribution and interference with maintenance are lower than the emissions budgets set for states. EPA should better explain the emissions used in the modeling to determine the level of reductions required for each individual state to eliminate significant contribution and interference with maintenance. EPA must also explain how these emissions compare to the emissions budgets proposed in the FIP. If the emissions used in analysis are indeed lower than the FIP budgets, then we need to understand how the budgets will eliminate significant contribution and interference with maintenance. Failure to limit state-level emissions at the level used in the analysis would seem to deviate from the court's mandate:
On remand, EPA must determine what level of emissions constitutes an upwind state's significant contribution to a downwind non attainment area "consistent with the provisions of [Title I]," which include the deadlines for attainment of NAAQS and set the emissions reduction levels accordingly."  [EPA-HQ-OAR-2009-0491-2694.1 p.5-7]
In the proposed rule, EPA states that "a downwind state must adopt controls to demonstrate timely attainment of the NAAQS despite any pollution transport from upwind states that is not eliminated under section 110(a)(2)(D)' (75 FR 45271). We understand that EPA's intent, with this statement, is to clarify a nonattainment area's obligation to adopt reasonable local controls, notwithstanding transport, to make progress towards attainment. It is not meant to imply that a downwind area is solely responsible for implementing all measures to attain the standard while being affected by significant contribution of transport. This is especially of concern if the final transport rule does not provide relief sufficient to address significant contribution to downwind nonattainment. We request that EPA clarify its intent in the final rule. [EPA-HQ-OAR-2009-0491-2694.1 pp.8-9]
Southeastern States Air Resource Managers (SESARM)
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.43-44.]
Two, levels of control should be based on sound air quality analysis using accepted evaluation tools.
Three, establishment of emission reduction mandates should be guided solely by what is needed to achieve and maintain attainment with national standards. Such analyses must give consideration to the impacts of emissions of local origin, as well as transported emissions.
However, the cost in relative air quality value 25 of local versus distant emission controls must be evaluated and final emission limits should be based on cost-effectiveness and proven technology.
Utility Air Regulatory Group (UARG)
EPA's Approach Places an Undue and Unlawful Burden on Sources in Upwind States To Reduce Emissions.
EPA's Proposed Transport Rule improperly puts all or most of the emission reduction burden on sources located outside the local nonattainment or maintenance area. Indeed, EPA admits as much. In the preamble to the proposed rule, EPA explains that "EPA continues to believe that a strategy based on adopting cost effective controls on sources of transported pollutants as a first step will produce a more reasonable, equitable, and optimal strategy than one beginning with local controls." 75 Fed. Reg. at 45226/3. EPA recites several reasons for its decision to assign "substantial responsibility" to upwind states to decrease their emissions in an effort to decrease or eliminate nonattainment in downwind states, 75 Fed. Reg. at 45272/1, but none can justify EPA's failure to adhere to the terms of the CAA. [EPA-HQ-OAR-2009-0491-2756.1, p.69]
Section 107(a) of the Act states that "[e]ach State shall have the primary responsibility for assuring air quality within the entire geographic area comprising such State." 42 U.S.C. § 7407(a) (emphasis added). EPA's proposal instead would impose on upwind states the "primary responsibility" for assuring air quality in the downwind states that contain the nonattainment and maintenance sites, in direct contradiction to this fundamental principle of the CAA. EPA is bound by the terms of the Act to recognize that the primary responsibility for attaining and maintaining air quality standards in a given state is to be borne by that state. [EPA-HQ-OAR-2009-0491-2756.1, pp.69-70]
One consequence of this principle is that EPA was required to account for local controls in the first instance. EPA did not comply with this requirement. For example, EPA states that in the development of the future year emission scenarios, "[f]or nonEGU point and nonpoint stationary sources, any local control programs that may be necessary for areas to attain the annual PM2.5 NAAQS and the ozone NAAQS are not included in the future base case projections." 75 Fed. Reg. at 45241/2. Proper accounting for local controls may well have resulted in different emission budgets. [EPA-HQ-OAR-2009-0491-2756.1, p.70]
EPA gave recognition to the terms of section 107(a) in the NOx SIP Call rule and CAIR, at least to a certain degree. Both the NOx SIP Call rule and CAIR were based on the concept of residual nonattainment -- that downwind states containing designated nonattainment areas would be unable to reach attainment in those areas through the use of local controls alone. See 63 Fed. Reg. at 57377/1-2 ("The fact that a nonattainment problem persists, notwithstanding fulfillment of CAA requirements by the downwind sources, is a factor suggesting that it is reasonable for the upwind sources to be part of the solution to the ongoing nonattainment problem."); 70 Fed. Reg. at 25184/3 (explaining that regional emission reductions are necessary because "it would be difficult if not impossible for many nonattainment areas to reach attainment through local measures alone"). In the final CAIR, for example, EPA explained that it evaluated emission control options to determine the average emission reductions that were possible in nonattainment areas using local controls, and then determined, based on this analysis, that reductions from sources in upwind states were necessary -- in addition to local controls -- in order for downwind states to reach attainment. 70 Fed. Reg. at 25194/1-2. As mentioned above, this reasoning gives at least a degree of recognition to the requirement of section 107(a), discussed above, that states bear the primary responsibility for assuring air quality within their borders. EPA's failure to do so here requires the Agency to revise and reissue the proposed rule based on a proper assessment of the -ole of local controls in NAAQS attainment strategies. [EPA-HQ-OAR-2009-0491-2756.1, pp.70-71]
Response: 

EPA made numerous updates and corrections to its significant contribution analysis for the final rule.  Among other things, EPA updated the modeling used to identify nonattainment and maintenance receptors, EPA's source apportionment modeling, and EPA's development and use of CAMx and AQAT for identifying significant contribution to non-attainment and interference with maintenance.  Details on these methods can be found in section V and VI of the preamble for the final Transport Rule.
These sections include a discussion of the appropriateness of EPA's baseline for the Transport Rule in comparison to alternative baselines (such as 2006-2009 monitoring data) which EPA determined to be inappropriate for use.
With respect to EPA's treatment of local sources for the final Transport Rule, see section V of the final Transport Rule preamble.  EPA recognizes the role that local controls play (as defined by the Clean Air Act) in attaining national air quality standards.  As such, EPA specifically requested comment on local control data as part of the proposal and the October 27 NODA, and incorporated any usable data that was provided into the final inventories.
Regarding inclusion of Louisiana for PM2.5, please see updated air quality analysis is section V of the final Transport Rule preamble.
With respect to air quality modeling conducted by MOG, EPA's evaluation of this modeling can be found in section V.C.2 of the preamble for the final Transport Rule.
A discussion of EPA's assessment regarding the Liberty-Clairton area can be found in section VI.D of the preamble for the final Transport Rule.
EPA modified the methods used to determine state emissions budgets for the final Transport Rule.  Details on the methods used for the final rule can be found in section VI.D of the preamble for the final Transport Rule and in the Significant Contribution and State Emissions Budgets Final Rule Technical Support Document.

IV.D.1. Overall Approach: Emissions Reduction Cost Curves

Organization: Connecticut Department of Environmental Protection
Comment: 
Connecticut Department of Environmental Protection
Transport cannot be considered completely addressed pursuant to CAA section 110(a)(2)(D) if the remedy, based solely on a cost threshold, leaves residual nonattainment. In the event that EPA persists with the use of cost thresholds to set the proposed remedy, EPA must identify thresholds necessary to level the playing field between Connecticut and upwind states. Based on the level and cost of controls already in place in Connecticut and other Northeast states, the proposed Transport Rule's $500/ton cost threshold (2006 dollars) for NOx is far below the costs already incurred by electric generating units in Connecticut. EPA must recognize the costs already incurred and the reductions already achieved by Connecticut and other states that are impacted by transport when devising this and future Transport Rules. Since EPA acknowledged (75 FR 45288) in the 2003-04 NOx SIP Call that highly cost-effective ozone season compliance costs of $3200/ton (in 2006 dollars) are reasonable, the Transport Rule would achieve much greater health benefits if EPA used a similar cost threshold. [EPA-HQ-OAR-2009-0491-2780.1 p.8]
Connecticut's increasingly stringent emission limits, coupled with market forces and CTDEP's efforts to encourage cleaner energy generation through participation in the New England Independent System Operator ( ISO-NE) and Connecticut Department of Public Utility Control (DPUC) processes, have resulted in installation of new electric generating facilities that are much lower emitting than in the past. In addition, at least 80 new units, many of which are small distributed generators that also utilize combined heat and power to increase efficiency, resulted in the net capacity of a 350MW base-loaded facility (representing almost 10% of total new capacity). Table A-1 summarizes emission limits for new facilities that are subject to the Transport Rule sited in Connecticut over the last 14 years, with all units permitted at NOx emission limits ranging from 0.008 to 0.09 lbs/MMBtu: [EPA-HQ-OAR-2009-0491-2780.1 p.8]
Table A-1. Emissions Limits of Connecticut's New Facilities [EPA-HQ-OAR-2009-0491-2780.1 p.8]
[[Data Table Here]]
These newer, cleaner installations have transformed the emission characteristics of Connecticut's EGU sector. Table A-2 displays the NOx emission rate of Connecticut's EGUs that report to EPA's Clean Air Markets Division (CAMD) compared to emission rates of similar EGUs in upwind states. [EPA-HQ-OAR-2009-0491-2780.1 p.9]
Table A-2. 2007 NOx Emissions Rates For Northeast States (CAMD)
Table A-2 shows that Connecticut's EGUs have an average NOx rate of 0.069 lbs/MMBtu, which is significantly lower than the average NOx rate of key upwind states such as Pennsylvania at 0.178 lbs/MMBtu and Ohio at 0.182 lbs/MMBtu. Furthermore, the average NOx rate for new capacity added in Connecticut since 1996 is 0.021 lbs/MMBtu. EPA should account for states with lower emitting, higher efficiency EGU infrastructure by ensuring that the final Transport Rule and future Transport Rules are structured to level the playing field with upwind states whose EGU sectors are higher emitting and less efficient. CTDEP recommends EPA adopt EGU performance standards by 2014. However, if EPA persists in using cost to establish the scope of the proposed remedy, EPA must use a more appropriate cost threshold, such as the cost per ton of actual EGU controls in downwind states most impacted by transport. [EPA-HQ-OAR-2009-0491-2780.1 p.9]
EPA requested comment on whether it should consider and analyze NOx reductions that could be achieved for greater than $500/ton in states linked to the New York area sites. EPA goes on to indicate that any future analysis deemed necessary would be conducted as part of a future notice that would also consider similar issues identified for the Houston and Baton Rouge areas. [EPA-HQ-OAR-2009-0491-2780.11 ]
CTDEP strongly urges EPA to strengthen the current proposal with appropriate additional control requirements to ensure that states fully meet CAA section 110(a)(2)(D) transport obligations as soon as possible for the 1997 8-hour ozone NAAQS. EPA should base all proposed and final decisions regarding appropriate transport control remedies on analyses conducted with the more refined CAMx model, which includes algorithms to simulate non-linear photochemistry and the spatial differences associated with emissions from the various source sectors. [EPA-HQ-OAR-2009-0491-2780.11 ]
Response: 

See Transport Rule preamble for an explanation of how the final Transport Rule implements the statutory mandate of CAA section 110(a)(2)(D) and a  discussion of residual nonattainment areas.  Section V.B of the preamble provides more information about the baseline used.  The final Transport Rule analysis did not identify Connecticut, in part because of the relatively low state wide emission rate, as a state with emissions that significant contribute to nonattainment or interfere with maintenance in another state.  Consequently, Connecticut is not subject to the final Transport Rule.
See section VI.B and D of the Transport Rule preamble for a discussion of the NOX cost thresholds used in the final Transport Rule
Organization: Council of Industrial Boiler Owners (CIBO)
Comment: 
Council of Industrial Boiler Owners (CIBO)
In addition, EPA arbitrarily adjusted costs, using "higher and lower cost thresholds, based on the downwind air quality impact of emissions from different groups of states.' 75 FR 45233/2. Based on the charts indicating cost per ton by State, it appears that States that still have fossil-fueled plants are targeted, whereas those that do not seem to escape this cost effective analysis. [EPA-HQ-OAR-2009-0491-2751.1]
Response: 
See section VI.B and VI.D of the Transport Rule preamble for a discussion of "cost curves" and how cost thresholds were applied to states.  The multi-factor analysis takes into account the downwind air quality benefit and the cost considerations when determining the levels of reductions in each state.  Even at the same cost threshold, states may have different emission reduction opportunities depending, among other things, on the control status of its EGU fleet.
Organization: Duke Energy
Comment: 
Duke Energy
IPM Has Improperly Switched Units from Bituminous to Subbituminous Coal  
In its proposal, EPA states that its "...analysis does not allow a unit designed for bituminous coal to switch to (very low sulfur) subbituminous coal unless the unit has demonstrated that capability in the past. EPA assumes units with that capability have already made any investments needed to handle a switch to subbituminous coals. EPA therefore assumes that any modeled coal switching from bituminous to subbituminous has no cost or schedule impact." (Emphasis added.) [EPA-HQ-OAR-2009-0491-2689.1, p.34]
EPA has provided no information about what in its view constitutes a demonstration of the capability to burn subbituminous coal. In cases where IPM has modeled a 100% fuel switch to subbituminous coal, it seems reasonable that having demonstrated the capability would mean that the unit IPM has switched has actually operated on 100% subbituminous coal in the past. Certainly units that have never burned subbituminous coal in any quantity would not be considered to have demonstrated the capability to burn such coal. Yet IPM has fuel-switched a number of Duke Energy units from bituminous to subbituminous coal where those units have never burned any amount of subbituminous coal in the past, not even a test burn. This is clearly an error that should be corrected. [EPA-HQ-OAR-2009-0491-2689.1, pp.34-35]
Response: 
See "Documentation Supplement for EPA Base Case v.4.10_FTransport  -  Updates for Final Transport Rule" for discussion on coal switching in the IPM model.  In particular, the section titled "Restriction on coal choice in 2012" discuss some modification EPA made to its IPM modeling in response to concerns expressed by commenters on coal switching in the proposed modeling.
Organization: First Energy
Comment: 
First Energy
FE understands, but does not support the EPA's assumption that utilities and their electric generating units (EGU's) are the lowest cost control option based on their cost curves. The EPA does not identify which sector has the greatest impact on each monitoring site. A better option for the EPA is to prioritize all source category impacts on a monitoring site and use that priority list as the first option used to bring a non-attainment site into attainment. This is in part the role the State has filled in the past, and EPA's strategy to issue a "FIP-first" focusing solely on EGU's is inappropriate, particularly in light of the fact that EPA is under no court ordered timeline to expedite this process. [EPA-HQ-OAR-2009-0491-2657.1, p.3; ; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, pp.3-4 10/15/2010]
Response: 

Section VI of the preamble discusses what sources categories are included and why.  Additionally, Section IV.C of the preamble and section III.A of this RTC explains EPA's FIP authority.
Organization: Independence Power & Light (IPL)
Comment: 
Independence Power & Light (IPL)
EPA Gave No Consideration to the Challenges Faced by Municipal Utilities
Finally, many municipal utilities own and operate a relatively small number of relatively small EGUs units. The ability to achieve emissions reductions on small units is not as postulated by the Rule due to simple economies of scale. The cost of controls on smaller units can be as much as three times the cost per MW that the Rule assigns in order to determine required reductions. This calls into question the assignment of costs per ton of reduction that forms the basis for regulation of many small municipal EGUs subject to the Rule.. [EPA-HQ-OAR-2009-0491-2741.1, pp.17-18] 
Response: 
EPA does consider the cost challenges faced by units less than 100 MW (smaller units) when developing its IPM modeling (see Documentation Supplement for EPA Base Case v.4.10_FTransport - Updates for Final Transport Rule).
Additionally, EPA conducts a Small Business Regulatory Enforcement Fairness Act (SBREFA) analysis that examines the impact on small EGUs covered by the Transport Rule.
Organization: Institute of Clean Air Companies (ICAC)
Comment: 
Institute of Clean Air Companies (ICAC)
EPA Should Consider Alternative Post-Combustion Cost-Effective Technologies for Reducing SO2 and NOx Emissions (75 FR 45273/1). EPA's analysis does not consider lower capital-cost options for SO2 capture, such as Dry Sorbent Injection (DSI) and upgrades to existing scrubbers that could be implemented much more quickly than installation of new scrubbers and could provide substantial reductions of SO2 well within the time frame considered for the new rule. [EPA-HQ-OAR-2009-0491-2695.1, p. 6]
DSI reduces SO2 through injection of trona, sodium bicarbonate or hydrated lime upstream of a particulate control device and has been proven to reduce SO2 by over 50% when an ESP is installed and over 80% when a fabric filter is used for particulate control. These technologies can be implemented very quickly  -  typically within one year.
It may be possible to improve the scrubber performance of many older scrubbers that were installed in the 1970's and 1980's. For example, limestone forced oxidation wet scrubber system upgrades at the Vectren Culley Station Units 2 & 3, E.On's Trimble County Unit 1, and Michigan South Central Power's Endicott Station resulted in removal efficiencies in the range of 98% being achieved for each of these units. 4, 5, 6 Upgrades such as these can also be implemented very quickly and inexpensively when compared to installation of a new scrubber.
These lower-cost approaches for SO2 control that can be implemented quickly lend themselves well to the flexibility envisioned in EPA's preferred approach. These methods do not require large commitments of capital. Utility companies can implement these methods and delay or avoid installation of more capital intensive technologies for SO2 control.
ICAC also requests that EPA include circulating dry scrubber technology (CDS) in the modeling for the proposed Transport Rule. As an example, the Greenidge Multi-Pollutant Control Project was conducted as part of the U.S. Department of Energy's Power Plant Improvement Initiative to demonstrate an innovative combination of air pollution control technologies that can cost effectively reduce emissions of SO2, NOx, Hg, acid gases (SO3, HCl, and HF), and particulate matter from smaller coal-fired electric generating units (EGUs).
CDS technology is an example of the improvements made by the APC industry to provide sources more flexibility in meeting their compliance requirements. The final project report can be accessed at http://www.netl.doe.gov/technologies/coalpower/cctc/PPII/bibliography/demonstration/environmental/bib_greenidge.html.

Footnotes:
4 Quatidamo, M., Erickson, C., Langone, J., "SO2 Removal Enhancement to the Vectren Culley Generating Station Units 2&3 Wet Flue Gas Desulfurization System", ICAC Forum '05, Baltimore, MD, March 7-10, 2005.
5 Erickson, C., Jasinski, M., VanGansbeke, L., "Wet Flue Gas Desulfurization (WFGD) Upgrade at the Trimble County Generation Station Unit 1", EPRI-DOE-EPA-AWMA Combined Power Plant Air Pollutant Control Mega Symposium, Baltimore, MD, August 28-31, 2006.
6 Silva, A., Williams, P., Balbo, J., "WFGD Case Study  -  Maximizing SO2 Removal by Retrofit with Dual Tray Technology", EPRI-DOE-EPA-AWMA Combined Power Plant Air Pollutant Control Mega Symposium, Baltimore, MD, August 28-31, 2006.
Response: 
EPA has updated its IPM modeling used in the Final Transport Rule analysis to reflect lower capital-cost options for SO2 capture - including Dry Sorbent Injection (DSI).  See IPMv.4.10 documentation for further explanation.
Organization: Midwest Ozone Group
Comment: 
Midwest Ozone Group
MOG recommends using 2018 as the year for eliminating significant contribution. [EPA-HQ-OAR-2009-0491-2809.1, p.10]
EPA requests comment on which year within 2012 to 2018 it should select for further analysis. See 75 Fed. Reg. at 45,286/1-2 ("EPA may select a year between 2012 and 2018 that is as expeditious as practicable as the appropriate year for eliminating significant contribution. Because, as explained later, further analysis is needed to quantify any additional reductions necessary to eliminate significant contribution to Houston, EPA requests comment on which year we should select within this 2012 to 2018 time period for this analysis."). MOG urges EPA to use 2018 as the year for determining significant contribution. [EPA-HQ-OAR-2009-0491-2809.1, p.10]
With respect to the ozone NAAQS, the year 2018 is the deadline for emissions reductions for the Houston severe ozone NAA, and Houston is an area that EPA has identified as a residual nonattainment area for ozone in 2014 even with the CATR. See 75 Fed. Reg. 45,210, 45,285-86.The year 2018 is also the deadline for emissions reductions for ozone NAAs classified as severe and above. See id. at 45,285. Further, if an area comes close to attainment, EPA may grant states two 1-year attainment date extensions provided certain criteria are met. See id. at 45,285/3. BAU control strategies will help improve air quality in areas with attainment deadlines after 2010. See id. at 45,301/1. [EPA-HQ-OAR-2009-0491-2809.1, p.11]
As for the PM2.5 NAAQS, designations for the 2006 24-hour PM2.5 NAAQS had not even been promulgated at the time of the D.C. Circuit's decision. Designations for the 2006 24-hour PM2.5 NAAQS were not published until November 13, 2009 (74 Fed. Reg. 58,688) and were not effective until December 14, 2009. The presumptive attainment deadline for nonattainment areas for the 2006 24-hour PM2.5 NAAQS is December 14, 2009, with a possible extension to December 14, 2019. All of the reasons that EPA relies upon for examining beyond 2012 to determine significant contribution (e.g., "unique situation created by the Court's remand of CAIR," missed deadline for transport SIPs, bump-up provisions, two 1-year extensions of attainment date provisions, long history of nonattainment areas failing to meet their nonattainment deadlines, and maintenance requirements) are equally applicable to looking beyond 2014 and to 2018 to determine source-receptor relationships and significant contribution. See Fed. Reg. at 45,285/2-3. Moreover, using 2018 for 24-hour PM2.5 does not rely on the two, one-year extensions beyond the additional ten years after the effective designations date allowed in the CAA. Using 2018 would harmonize implementation of the ozone and PM2.5 NAAQS programs while avoiding an arbitrary use of different years. [EPA-HQ-OAR-2009-0491-2809.1, p.11]
Using 2018 would be consistent with EPA's interpretation that reductions must occur in the year immediately preceding an area's attainment date. In any case, using the year 2018 does not create public health concerns because the most recent modeling data shows that, except for two areas influenced by local sources, all areas achieve attainment in 2014. Therefore, using 2018 is reasonable. [EPA-HQ-OAR-2009-0491-2809.1, p.11]
Further, using 2018 as the year for determining significant contribution gives states time to develop quality SIPs, submit them to EPA, and receive EPA approval. This approach is consistent with the provisions of the Clean Air Act (CAA) that states have the "primary responsibility" for air quality within the state. See CAA § 101(a)(3) & § 107(a). EPA's approach of proposing federal implementation plans puts the "cart before the horse". The CAA contemplates that EPA may promulgate a FIP within two years after the EPA Administrator makes a finding of failure to submit or incompleteness or disapproves a SIP. [EPA-HQ-OAR-2009-0491-2809.1, p.11]
Finally, 2018 is the appropriate year to use for determining maintenance of the NAAQS. See 75 Fed. Reg. 45,210, 45,285/3 ("Even if a downwind area attains on time, further upwind reductions may be important to assure continued maintenance of the standard."). As discussed above, these modeling results, which assume that CAIR requirements remain in place, demonstrate that with no new controls beyond CAIR and BAU controls, all ozone nonattainment areas, all annual PM2.5 nonattainment areas except Allegheny County, PA, and all 24-hour PM2.5 nonattainment areas except Allegheny County, PA and Brooke County, WV, will achieve attainment no later than 2014. [EPA-HQ-OAR-2009-0491-2809.1, pp.11-12]
Clearly, the additional stringent reductions EPA is proposing are not needed to achieve the air quality objective EPA is targeting  -  attainment and maintenance of the applicable ozone and PM 2.5 NAAQS. MOG urges EPA to reanalyze the CATR using 2018 as the year for projecting nonattainment and maintenance areas. [EPA-HQ-OAR-2009-0491-2809.1, p.12]
Response: 
See section VII.C of the Transport Rule preamble for an explanation of the compliance deadlines.  Also, EPA notes that the independent modeling referenced by the commenter assumes that CAIR stays in place, this is an assumption that EPA cannot make in its Transport Rule modeling for reasons explained in the both the proposed and final Transport Rule.
Organization: National Mining Association (NMA)
Comment: 
National Mining Association (NMA)
As with EPA's assumptions on coal-switching, if EPA is wrong about the amount of scrubbers that can be installed by 2014, the result will be the closing of coal plants or the ramping down of production at those plants. That result, which EPA has not analyzed, would completely change the basis for EPA's conclusion that its phase two emission reductions are cost-effective. [EPA-HQ-OAR-2009-0491-2868.1,p.17]
Response: 
As explained in Section VII.C of the Preamble, EPA believes the installation of approximately 6 GW of FGD by 2014 is feasible.  Additionally, EPA believes that while feasible, these controls are not necessary for compliance with Transport Rule emission limits in 2014.  The flexibility afforded through the trading component of the Final Transport Rule, allows sources to choose among an array of compliance options that include control retrofits, fuel switching, allowance purchase, etc.  EPA analyzed, and made available in the docket, a Transport Rule 2014 scenario where the FGD retrofit option was not available to sources in that time period.  The same Transport Rule state budget requirements were applied.  In this scenario, as discussed in Section VII.C, sources simply relied on additional DSI, subbituminous, and increased gas generation as a substitute for FGD retrofit.  By doing so, the modeling suggested they were still able to comply with the budget at reasonable cost and with no additional requirements. 
Organization: Nebraska Public Power District
Comment: 
Nebraska Public Power District
9) Better Significant Contribution Metric. EPA says it has defined "significant contributions" based on the cost of avoiding emissions from each given state or emissions source. EPA states in the preamble of the proposed TR:
"The methodology defines each state's significant contribution and interference with maintenance [of NAAQS] as the emissions that can be eliminated for a specific cost." [Federal Register, Aug. 2, 2010, Page 45271] [EPA-HQ-OAR-2009-0491-2711.1, p.8]
Controlling emissions most cost-effectively on a $/ton removed basis is an appropriate strategy in performing a Best Available Control Technology (BACT) analysis as part of a permitting action on a particular facility. We agree with bringing the cost element into consideration for the TR. However, because the purpose of the TR is to bring specific geographic areas into attainment with the NAAQS, the proper focus should be not on mass of emissions, but rather on the impacts. In other words, instead of using $/ton of pollutant emissions eliminated as a metric, the analysis should be looking primarily at a metric of $/μg/m3 of pollutant concentration reduced at each receptor of interest. [EPA-HQ-OAR-2009-0491-2711.1, p.8]
Response: 
As described in section VI of the final Transport Rule, EPA uses a multi-factor analysis that considers both cost and air quality when determining significant contribution at the state level.
Organization: New Jersey Department of Environmental Protection (NJDEP)
Clean Air Task Force
Comment: 
Clean Air Task Force
EPA solicits comment on several aspects of this issue, including whether: 
any Group 2 states should be moved to Group 1 for purposes of SO2 requirements; 
the $2000/ton SO2 marginal cost cut-off should be raised; and 
the $500/ton NOx marginal cost cut-off should be raised. 
We submit that the answer to all of these questions is clearly "yes." [EPA-HQ-OAR-2009-0491-2738.1, p.13]
New Jersey Department of Environmental Protection (NJDEP)
The USEPA used a very low cost threshold to exempt sources from addressing significant contribution. The cost level of $500 per ton of NOx removed, which was used by USEPA, is much too low, leaving reasonably achievable reductions unrealized. In the prior Clean Air Interstate Rule (CAIR), the rule that the Transport Rule is to replace, the USEP A cited $2,500 per ton reduced as highly cost effective for controlling NOx. Section 185 of the Clean Air Act specifies a penalty of over $8,000 per ton (in today's dollars) for exceeding attainment deadlines for the ozone NAAQS. States in the Ozone Transport Commission (OTC) have adopted rules that control NOx from smaller sources at well over $10,000 per ton. The USEPA needs to require NOx reductions that cost more than $500 per ton, to reflect the much greater public health and welfare benefits that result from better control air pollution control, as well as to address significant air quality impacts.   [EPA-HQ-OAR-2009-0491-2684.1 p.3]
Response: 
See section VI of the preamble for explanation and discussion of cost thresholds used in final Transport Rule and identification of "Group 1" and "Group 2" states
Organization: New York University School of Law, Institute for Policy Integrity
Comment: 
:: The determination of significant contribution should be based solely on the cost-effectiveness of emissions reductions; [EPA-HQ-OAR-2009-0491-2691.1, p.1]
2. Cost-Effectiveness and a Clear Methodology Should Determine Significant Contribution
EPA should modify the process by which it determines significant contribution to nonattainment and interference with maintenance by basing that determination solely on the cost-effectiveness of emissions reductions. Determining significant contribution to nonattainment and interference with maintenance based on cost-effectiveness represents the most efficient and rational approach to reducing interstate transport of air pollution, and comports with relevant judicial opinions -- including North Carolina v. EPA. [EPA-HQ-OAR-2009-0491-2691.1, p.8]
In its preferred approach, in order to determine significant contribution and interference with maintenance, EPA states that its "methodology defines each state's significant contribution and interference with maintenance as the emissions that can be eliminated for a specific cost." However, when determining the appropriate cost thresholds, EPA weighs air quality and cost considerations in a "multi-factor assessment" that includes identifying "cost breakpoints" on the relevant emissions reductions cost curves. While this represents a meaningful attempt by the Agency to address the complex set of circumstances surrounding the relationship between upwind and downwind emissions across various air quality districts, this approach is needlessly complicated and, ultimately, arbitrary. Cost breakpoints, which EPA defines as places where there are noticeable changes on emissions reductions cost curves, do not inherently correspond with the point on those cost curves that would provide the most efficient level of emissions reductions. In fact, cost breakpoints may simply reflect limitations in the data used to set the cost curve. [EPA-HQ-OAR-2009-0491-2691.1, pp.8-9]
The most appropriate approach to determining significant contribution to nonattainment or interference with maintenance would be based solely on the cost-effectiveness of state-specific emissions reductions. EPA should determine the distribution of emissions reduction burdens between upwind and downwind sources by comparing the cost of those reductions in linked upwind and downwind states. In other words, the Agency should identify the least expensive emissions reductions that would lead to attainment or maintenance of the NAAQS in a particular air quality district, whether or not those emissions reduction opportunities are located in the upwind or downwind state. The upwind state's share of those least-cost emissions reductions should then represent that upwind state's significant contribution to nonattainment in, or interference with maintenance by, the downwind state. This approach would ensure that attainment and maintenance of the NAAQS are achieved in the most cost-effective manner. [EPA-HQ-OAR-2009-0491-2691.1, p.9]
A Cost-Effectiveness Criterion Comports with Judicial Opinions
Section 110(a)(2)(D), as well as judicial opinions interpreting that provision of the Clean Air Act, give EPA discretion to determine significant contribution to nonattainment and interference with maintenance based on the cost-effectiveness of emissions reductions in upwind states and linked downwind air quality districts. In fact, interpreting section 110(a)(2)(d) in this way is the most rational approach to reducing interstate transport of air pollution. [EPA-HQ-OAR-2009-0491-2691.1, p.9]
Neither the text nor the legislative history of the Clean Air Act Amendments of 1990 provides a clear definition of "contribute significantly." In the congressional findings that introduce the Act, however, Congress provides an important guiding principle -- "A primary goal of this Act is to encourage or otherwise promote reasonable Federal, State, and local governmental actions, consistent with the provisions of this Act, for pollution prevention." This congressional objective should help elucidate the meaning of the section 110(a)(2)(D) statutory mandate. [EPA-HQ-OAR-2009-0491-2691.1, p.9]
Ultimately, "where Congress leaves a statutory term undefined, it makes an implicit `delegation of authority to the agency to elucidate a specific provision of the statute' through reasonable interpretation." While the word "significant" does not have a single dictionary definition, it generally operates to mean a measurable quantity. 40 According to a recent Supreme Court ruling, terms that "admit[] of degree" (such as "best," "minimize," "significant," or "reasonable") often give agencies discretion to consider both the costs and benefits of regulation -- "Whether it is reasonable to bear a particular cost may well depend on the resulting benefits." [EPA-HQ-OAR-2009-0491-2691.1, pp.9-10]
When a statute requires an agency to achieve a particular set of benefits -- in the case of section 110(a)(2)(D), attainment or maintenance of National Ambient Air Quality Standards -- the agency should pursue the most cost-effective regulatory option that meets those required benefits. OMB Circular A-4 recognizes that in those situations, cost-effectiveness analysis is a "rigorous way to identify options that achieve the most effective use of resources." [EPA-HQ-OAR-2009-0491-2691.1, p.10]
In Michigan v. EPA -- a case that also dealt with EPA's interpretation of section 110(a)(2)(D) -- the D.C. Circuit held that "[i]n some contexts, `significant' begs a consideration of costs," and that "the upshot of inserting the adjective `significant' was a consideration of which risks are worth the cost of elimination." The court has also noted that since the Benzene decision, OSHA has interpreted `"significant risk' to require `cost-effective protective measures.'" The Michigan court further concluded, "there is nothing in the text, structure, or history of § 110(a)(2)(D) that bars EPA from considering cost in its application." [EPA-HQ-OAR-2009-0491-2691.1, p.10]
The D.C. Circuit further addressed the permissibility of cost-effectiveness in North Carolina v. EPA. The North Carolina court stated, "EPA may require `termination of only a subset of each state's contribution,' by having states `cut [] back the amount that could be eliminated with `highly cost-effective controls.'" Relying on its holding in Michigan, the court in North Carolina stated, "we held that EPA may `after [a state's] reduction of all [it] could . . . cost-effectively eliminate[ ],' consider `any remaining "contribution"' insignificant." [EPA-HQ-OAR-2009-0491-2691.1, p.10]
While the court in North Carolina cautioned that "EPA can't just pick a cost for a region, and deem `significant' any emissions that sources can eliminate more cheaply," this is not the suggestion here. Instead, the cost of emissions reductions, and the share of emissions reductions required for each upwind state, should be evaluated at the state-specific level. This would satisfy the D.C. Circuit's requirement that significant contribution be determined at the state-specific level and would do so in the most efficient manner. [EPA-HQ-OAR-2009-0491-2691.1, p.10]
Methodology Must Be More Transparent
Ultimately, the description in the proposed rule fails to clearly explain the details of the decision-making process involved in determining significant contribution to nonattainment or interference with maintenance. It is unclear from the text of the rule just how much weight is given to each of the factors considered by the Agency. In fact, it appears that EPA intends to vary the importance of both air quality and cost considerations on a case-by-case basis. This ad hoc decision making and lack of transparency reduce the legitimacy and effectiveness of EPA's determinations. EPA acknowledges that a key guiding principle of its efforts to reduce interstate transport of air pollution is to "Provide for Cost-Effectiveness." EPA should embrace this principle, by determining significant contribution and interference with maintenance at the state-specific level based solely on a comparison of the cost-effectiveness of emissions reductions in linked states. [EPA-HQ-OAR-2009-0491-2691.1, p.11]
If EPA elects not to do so, the Agency should, at the very least, provide a clearer and more detailed description of the process by which significant contribution to nonattainment and interference with maintenance are determined. An explanation of the precise weight given to each factor in the analysis would at least increase the transparency and legitimacy of the Agency's determinations. [EPA-HQ-OAR-2009-0491-2691.1, p.11]
Response: 
In section VI of the preamble (as well as in other sections of the preamble), EPA describes the approach to define significant contribution and interference with maintenance.  In sections VI.A, VI.D and VI.G of the preamble, EPA describes its rationale for using both cost and air quality factors and its justification for using a uniform cost. 
EPA notes that in the proposed Transport Rule, EPA extensively discusses its assessment of two cost/air quality improvement methodologies in the Technical Support Document for the proposed Transport Rule, called "Alternative Significant Contribution Approaches Evaluated" that are directly relevant to this comment.  In stating that EPA should be utilizing only "cost-effectiveness"  emission reductions leading to attainment of the NAAQS, regardless of which upwind or downwind state the emission reductions are available in, the commenter is in fact utilizing an air quality and cost factor approach to defining significant contribution.  It specifically weighs the air quality impact and the cost of each upwind emission reduction.  EPA applied a similar approach in the final Transport Rule by analyzing specific cost and air quality impacts between specific upwind states and downwind monitoring sites.  EPA undertook the most detailed analysis of these linkages available at the time of promulgation.
Organization: Ohio Coal Association
Comment: 
Ohio Coal Association
:: The Transport Rule unlawfully forces fuel switching away from Eastern coals. In fact, EPA's expressly states a belief that unit compliance can be accomplished via additional controls along with fuel switching away from Eastern coals. 75 Fed. Reg. at 45273. Additionally, EPA unlawfully fails to provide any economic analysis of the devastating results on the economies in states like Ohio driven by EPA's forced fuel switching. Ohio Coal strongly opposes EPA's actions directing against the use of Ohio coal. [EPA-HQ-OAR-2009-0491-2743.1, p.2]
Response: 
The Transport Rule does not force coal switching at any sources.  It simply anticipates some coal switching as one mechanism sources may use to meet the applicable state caps and thus eliminate emissions within the state that significantly contribute to nonattainment or interfere with maintenance in another state. EPA action does not target coal supplies from certain states, it is an emission reduction program for SO2, NOX, and ozone season NOX, and consequently would provide an increased incentive for coals with lower emission rates for each of these pollutants.  However, TR covered states were already using a portfolio of coal types in 2010 that are similar to those forecasted under a least cost compliance scenario.
Organization: Omaha Public Power District
Comment: 
Omaha Public Power District
EPA says it has defined 'significant contributions' based on the cost of avoiding emissions from each given state or emissions source. EPA states in the preamble of the proposed TR:
'The methodology defines each state's significant contribution and interference with maintenance [of NAAQS] as the emissions that can be eliminated for a specific cost.' [Federal Register, Aug. 2, 2010, Page 45271]
Controlling emissions most cost-effectively on a $/ton removed basis is an appropriate strategy in performing a Best Available Control Technology (BACT) analysis as part of a permitting action on a particular facility. We agree with bringing the cost element into consideration for the. TR. However, because the purpose of the TR is to bring specific geographic areas into attainment with the NAAQS, the proper focus should be not on mass of emissions, but rather on the impacts. In other words, instead of using $/ton of pollutant emissions eliminated as a metric, the analysis should be looking primarily at a metric of $/ug/m3 of pollutant concentration reduced at each receptor of interest. [EPA-HQ-OAR-2009-0491-2680.1, p. 5]
Response: 
As described in section VI of the Transport Rule preamble, EPA used a multi-factor analysis that considered both cost and air quality when determining significant contribution at the state level.
Organization: Pfeiff, Mike
Comment: 
If finalized, the Proposed Transport Rule will result in unnecessary increases to the cost of producing energy. While I recognize that the cost of pollution abatement is not zero, an overarching goal of the EPA should be to promulgate regulations that minimize the cost of pollution reduction. In this regard, Proposed Transport Rule fails utterly. [EPA-HQ-OAR-2009-0491-2742.1, p.2]
19. Cost/Benefit Estimates - The EPA provides point estimates for the expected cost and benefits of the Proposal. 75 Fed. Reg. at 45354. With the exception of some limited undocumented estimates of ranges for the health benefit, the EPA's estimates are static. The fact that the EPA does not provide a distribution of estimates that reflect their estimate of the probability of each outcome indicates that the EPA's modeling and analytical techniques are grossly deficient. At the very minimum, for a proposal of this magnitude, the EPA should provide the public with sensitivities around the key assumptions.
I request the EPA to provide sensitivities of the cost of the Proposed Transport rule for key assumptions including but not limited to the price of Natural Gas, the price of Coal. [EPA-HQ-OAR-2009-0491-2742.1, p.14]
Response: 

As described in the preamble, the benefits (human health, environmental, etc.) of this rule greatly outweigh the costs.  However, this rule is intended to address section 110(a)(2)(D)(i)(I) of the Clean Air Act, which requires upwind states to eliminate significant contribution and interference with maintenance.  This rule helps the states to address that requirement, using market-based solutions and thereby minimizing costs to consumers.

As is documented throughout the preamble and this response to comments document, EPA utilized many comments on the price of natural gas, the price and availability of coal, control technologies, etc. in its power sector modeling and updated the emission inventories used for the air quality modeling.  In utilizing the cost curves (see section VI of the preamble), EPA is conducting a sensitivity test relating the cost and utilization of the emission control options suggested by the commenter.  These estimates, along with the corresponding air quality estimates using the Air Quality Assessment Tool, provide a range of emissions, costs, and air quality outcomes.  These were weighed using the multi-factor analysis presented in section VI.D.   Further sensitivity scenarios were examined (including air quality assessments using CAMx, and other electric generation and emissions modeling using IPM -- see the Air Quality Modeling Final Rule TSD, the Significant Contribution and Emissions Budgets Final Rule TSD).
Organization: Southern Environmental Law Center
Comment: 
Once EPA determined that a state was significantly contributing to nonattainment or interfering with maintenance of an area in another state, EPA set that upwind state's emission budget by calculating the amount of the state's electric generating unit ('EGU') emissions that could be eliminated for a specific cost. In the first of the four steps in its methodology for defining each state's significant contribution and interference with maintenance, EPA 'identifie[d] what emissions reductions are available at various costs, quantifying emissions reductions that would occur within each state at ascending costs per ton of emissions reductions.' In generating these 'cost curves,' EPA restricted its costs analysis to essentially one category of action: installing pollution control devices (or systems) on uncontrolled EGUs. Thus, EPA apparently failed to consider whether other types of actions that could be taken to reduce EGU emissions cost-effectively. [EPA-HQ-OAR-2009-0491-2801.1, p.4]
EPA itself touts one non-retrofit control option: end-use energy efficiency. As EPA notes in the Transport Rule preamble, but not within the discussion of how it arrived at each state's budget: 'Policies that will promote efficient use of electric power can be an integral, highly cost-effective component of power companies' compliance strategies.' Yet, EPA does not analyze, nor provide any justification for failing to analyze, the cost-effectiveness of reducing emissions through energy efficiency. [EPA-HQ-OAR-2009-0491-2801.1, p.4]
At least in some instances, EPA's failure to assess the cost of realizing energy efficiency potential in a state, and the associated emission reductions, renders the state emissions budgets suspect. For instance, a recent analysis of energy efficiency in the southern region includes s a supply curve that shows that there is a ready opportunity to save a tremendous amount of electric energy through efficiency at a cost between 1 and 3 cents/kwh, States across this region rely heavily on coal and therefore emit SO2, among other pollutants, at high rates, as exemplified by Georgia. According to EPA Clean Air Markets Division's Coal Unit Characteristics database, in 2009 coal-fired EGUs in Georgia emitted SO2 at a rate of 3.6 x 10-6 tons/kwh. Considering the cheap, available electricity efficiency resources in the region, coal-fired EGUs' high emissions rates (such as Georgia's SO2 rate), the fact that energy efficiency is simultaneously a control for NOx (and other air pollutants), and the many economic benefits of implementing energy efficiency measures, the cost-effectiveness of energy efficiency cannot be ignored by EPA. It must determine whether energy efficiency is a cost-effective control option in the contributing upwind states, and, if it is, tighten the budgets for those states. [EPA-HQ-OAR-2009-0491-2801.1, p.5]
In a similar vein, another example of a control strategy alternative that EPA failed to analyze for its cost-effectiveness is simply assessing the costs of retiring uncontrolled coal-fired EGUs. It may be that in a region, such as the South, with excess generating capacity, grid reliability will not be compromised by accelerating retirements of certain units and replacing them, as needed, with lower or non-emitting resources. [EPA-HQ-OAR-2009-0491-2801.1, p.5]
Response: 

EPA's power sector modeling uses a highly detailed electricity least-cost dispatch model (IPM) that incorporates a multitude of emission reduction control strategies extending beyond pollution control retrofit technologies.
Organization: State of Wisconsin, Department of Natural Resources
Comment: 
State of Wisconsin, Department of Natural Resources
Ensure that the cost impacts on Wisconsin sources, industry and ratepayers from this program are not so large that it precludes the certainty of continued electric system reliability as well as maintenance of a competitive power rate structure. [EPA-HQ-OAR-2009-0491-2829.2, p.1; This comment can also be found at section III.D of this comment summary]
In contrast to EPA's marginal cost-driven assessment of significant contribution, the Court seemed to indicate that aggregate electric system retrofit cost associated with investment in controls in the upwind state is important, but not limiting, until remedy becomes infeasible or at least impracticable. Further technical evaluation drives a recommendation here for a separate 2016 control phase for lowered NOx and S02 budgets within this first transport rule. [EPA-HQ-OAR-2009-0491-2829.2, p.4]
As background regarding relative regional contribution, Figures 1-5 attached at the end of these Technical Comments show surrounding states' past performance and projected budgets for NOx and S02 along with historic and rule projected total annual heat inputs to the EGU system. The comparisons include CAIR budgets for 2010 and 2015 in addition to the new Transport rule 2012 and 2014 proposed budgets. Figures 3 and 5 indicate the average annual EGU emission rates for NOx and SO2 for 8 of the 12 the states in close proximity found to contribute to Wisconsin's PM2.5 concentrations along with an estimate of projected emission rates needed to meet the new budget levels. [EPA-HQ-OAR-2009-0491-2829.2, p.4]
Response: 
EPA has updated its power sector and air quality modeling based on comments received during the TR proposal comment period.  The multi-factor analysis to determine "linkages", significant contribution, and state budgets was conducted with the updated modeling for the final Transport Rule. Section V and VI of the Transport Rule preamble describe the analytical approach.  As described in the TR preamble, EPA determined that the final Transport Rule fully quantifies emissions that constitute each covered state's significant contribution to nonattainment and interference with maintenance with respect to the 1997 annual PM2.5 and the 2006 24-hour PM2.5 NAAQS.  Therefore, an additional TR 2016 control phase for annual NOx and SO2 is not needed for these particular NAAQS under CAA section 110(a)(2)(D)(i)(I).
Organization: Tennessee Valley Authority (TVA)
Comment: 
Tennessee Valley Authority (TVA)
B. Issue: EPA assumes emission rates for low sulfur coal switches that are not achievable. EPA assumes reductions in SO2 for existing scrubbers by operating at their design removal efficiencies long term and for NOx for SCRs operating year-round up at their design removal efficiencies. EPA assumes emission rates for new controls that are not achievable long term. [EPA-HQ-OAR-2009-0491-2782.1, p. 6]
TVA Comment: EPA's assumed SO2 rates are not achievable long term for lower sulfur coals for TVA's units without FGD. Coal sulfur content is not homogenous even in the same seam, and coal suppliers will not guarantee sulfur contents that support EPA's assumed rates on TVA's uncontrolled units. For SO2 rates, TVA recommends that EPA use as a minimum, unit specific three year average annual SO2 rates from calendar years 2006-2008 with adjustments for controls added since 2006. Averaging emission rates over multiple years minimizes the distorting effects of SO2 fluctuations resulting from both the variations in coal deliveries over limited time periods and the variations due to operational problems at individual plants. [EPA-HQ-OAR-2009-0491-2782.1, p. 6]
For units with new SO2 scrubbers built after 2006, TVA recommends EPA assumed rates for SO2 be modified to be no less than 0.15 lb/MM-Btu for units expected to burn high or medium sulfur coal and 0.08 lb/MM-Btu for units burning low sulfur coal (PRB). SO2 rates on controlled units can be found lower than these stated rates, but considering normal equipment deterioration and reliability between maintenance opportunities and lack of equipment sparing typical for scrubbers designed for cap and trade programs, these rates are the most realistic annual average sustainable rates TVA can recommend for new SO2 controls. These rates allow for the following realistic scenarios: 1. Wet FGD for units burning high sulfur coal (approximately 5 lb SO2/MM-Btu) to be designed for 98% removal for short term performance tests, but to operate with a small degree of upsets with annual average SO2 removal down to 97% (achieving a 0.15 lb SO2/MM-Btu rate). 2. Wet or dry FGD for units burning medium sulfur coal (approximately 2.5 lb SO2/MM-Btu) to be designed for 95% removal for short term performance tests, but to operate with a small degree of upsets with annual average SO2 removal down to 94% (achieving a 0.15 lb SO2/MM-Btu rate). 3. Dry FGD for units already burning 100% PRB (with an SO2 rate around 0.80 lb SO2/MM-Btu) to be designed for 95% removal for short term performance tests, but to operate with a small degree of upsets with annual average SO2 removal down to 90% (achieving a 0.08 lb SO2/MM-Btu rate). Annual average 90% removal is typical of dry scrubber spray dryer designs requiring brief periods of time with no SO2 removal, while a unit's atomizer is pulled for maintenance. [EPA-HQ-OAR-2009-0491-2782.1, pp. 6-7]
For units with no post combustion NOx controls (no SCR, SNCR, etc.), TVA recommends EPA use unit specific three year average annual NOx rates from calendar years 2006-2008. Averaging emission rates over multiple years for units without SCR or SNCR minimizes the distorting effects of NOx fluctuations associated with operational boiler combustion or burner problems during specific time periods for individual plants. For units with post combustion NOx controls, TVA recommends using the average annual unit specific NOx rates for calendar year 2009, since annual NOx reductions were not achieved for most units until January 2009. For units where post combustion NOx controls are projected to be needed, TVA recommends nominal annual NOx rates no lower than 0.08 lb/MM-Btu, considering site specific issues, SCR inlet gas and ammonia injection distribution issues with changing loads, and startup/shutdown issues where units are not operating with gas temperatures high enough for ammonia injection into the SCRs. [EPA-HQ-OAR-2009-0491-2782.1, p. 7]
Control equipment is designed to meet guaranteed control efficiencies when new for steady state short term acceptance testing. Some equipment never meets design performance levels. Normal equipment deterioration between maintenance outages, and the process variability during startups, shutdowns, and load changes result in lower average removal efficiencies than the design level. Annual versus seasonal operation of SCRs results in lower removal rates due to less opportunity for maintenance and lower operating temperatures during cold weather. [EPA-HQ-OAR-2009-0491-2782.1, p. 7]
Attachment 3 indicates achievable yearly emission rates by 2014 for all of TVA's coal fired units. [Note that Attachment 3 was not available in the docket at the time of this summary.] [EPA-HQ-OAR-2009-0491-2782.1, p. 7]
A. Issue: EPA's methodology for determining cost curves does not consider the costs of controls installed for CAIR compliance, but nonetheless takes credit for emission reductions achieved by these controls. [EPA-HQ-OAR-2009-0491-2782.1, p. 8]
TVA Comment: Ignoring the cost of the controls for CAIR compliance while taking credit for the emission reductions those controls produce, results in significantly lower cost per ton projections that are inaccurate. EPA should include CAIR in the base case since CAIR remains binding law pending the promulgation and effective date of the Transport Rule. Accordingly, cost per ton curves for emission reductions should be recalculated based on the cost of emission reductions required beyond CAIR. Modeled downwind impacts without the Transport Rule should be based on CAIR level emissions. [EPA-HQ-OAR-2009-0491-2782.1, p. 8]
A. Issue: EPA recognizes that there are several limitations in its methodology to quantify emissions that significantly contribute or interfere with maintenance. EPA acknowledges these limitations but nonetheless justifies the use of the methodology on the basis that it strikes an appropriate balance between competing requirements of comprehensive analysis and timely action. [pp. 45270-83, summary of methodology on p. 45282] [EPA-HQ-OAR-2009-0491-2782.1, p. 10]
TVA Comment: The preamble to the proposed rule explains that EPA created an off-ramp for certain states that eliminate their significant contributions for less than $2000 per ton. [p. 45282] These states were placed in Group 2. For the remaining states (i.e. Group 1 states), EPA determined that SO2 emissions that could be reduced for $2000 per ton in 2014 should be considered that State's significant contribution. While TVA agrees that it would not be appropriate to assign the same cost per ton to Group 1 and Group 2 states, we cannot, on reviewing Figures IV-D-1 to IV-D-4, readily discern any guiding principle that EPA may have used for the grouping of states. For example, the cost curve for Tennessee is relatively flat (Figure IV-D-3), informing the reader that increasing the marginal cost per ton from $400 to $2000 does not increase the percent reduction to 2014 contribution in any significant way. Nevertheless, Tennessee is placed in Group 1. The same flat pattern of the cost curves is evident for other Group 1 states such as Kentucky and West Virginia, albeit to a slightly lesser degree. [EPA-HQ-OAR-2009-0491-2782.1, pp. 10-11]
Moreover, TVA believes that EPA should have included CAIR in the base case since CAIR will be binding law until replaced by the Transport Rule. With CAIR in the base case, the analysis of cost and air quality factors (marginal cost vs. percent reduction in 2014 contribution), as reflected in the nature of the cost curves, would be expected to significantly change. We urge EPA to redraw the cost curves with CAIR in the base case. [EPA-HQ-OAR-2009-0491-2782.1, p. 11]
Response: 
See EPA IPMv.4.10 documentation for information on sulfur content and control removal efficiencies.  EPA notes, that in response to significant public comment on control removal efficiency, it adjusted the unit level removal rates for both new and existing retrofits in its final Transport Rule modeling (described in further detail in documentation).  In regards to the cost curve analysis, EPA examined the air quality consequence of state level emissions at different cost levels, and found that Group 1 states did not eliminate their significant contribution and interference with maintenance for the 1997 annual PM2.5 and/or 2006 24-hour PM2.5 NAAQS until the $2300/threshold.  Tables in section VI.B of the Transport Rule preamble highlight the significant SO2 reductions available in Tennessee as the cost threshold is increased from $500/ton to $2300/ton.
Organization: Utility Air Regulatory Group (UARG)
Comment: 
Utility Air Regulatory Group (UARG)
In developing the Proposed Transport Rule, EPA used photochemical source apportionment modeling to identify the impact of emissions from specific upwind states on downwind areas projected to be in nonattainment or to have maintenance problems in 2012. 75 Fed. Reg. at 45253/1. Then, EPA determined each state's significant contribution to nonattainment and interference with maintenance based on the emissions that EPA projected could be eliminated from that state for a specific cost (in dollars per ton of reduced emissions), in conjunction with an analysis of air quality benefits at various cost levels, and set state budgets accordingly. 75 Fed. Reg. at 45271/1-2. Thus, although UARG disagrees with many aspects of the data and methodology that EPA used in this analysis, EPA's methodology does, as a general matter, attempt to address the EPA-projected contribution to nonattainment and interference with maintenance in downwind states from emissions from particular upwind states. At least in broad terms, the PTR's focus on state-specific data should align with the court's characterization of states' section 110(a)(2)(D)(i)(I) duties. [EPA-HQ-OAR-2009-0491-2756.1, pp.11-12]
EPA's Air Quality Assessment Improperly Overestimated the Marginal Benefit of Emission Reductions Above Relatively Low Dollar-Per-Ton Levels.
EPA's air quality assessment for the proposed rule did not properly consider the very limited nature of the reductions in the estimated number of projected nonattainment and maintenance sites that result from increasing the marginal cost per ton of EGU SO2 controls above comparatively low levels such as $300 or $400 per ton. See Tables IV.D-3 and IV.D-4, 75 Fed. Reg. at 45280, which are reproduced below. [EPA-HQ-OAR-2009-0491-2756.1, p.71]
EPA's Table IV.D-3 indicates that, with respect to the annual PM2.5 NAAQS, two nonattainment monitor sites would remain in 2014 at $200/ton and $300/ton and only one would remain at $400/ton, compared with 12 at $0/ton. EPA projects that the one remaining nonattainment monitor would reach attainment only at $1,800/ton. Similarly, EPA projects that only three nonattainment and maintenance monitors would remain in 2014 at $200/ton and $300/ton and two would remain at $400/ton, compared with 19 at $0/ton and six at $100/ton. [EPA-HQ-OAR-2009-0491-2756.1, p.72]
Table IV.D-4 indicates that, with respect to the 24-hour PM2.5 NAAQS, EPA projects that eight nonattainment and maintenance monitors would remain in 2014 at $300/ton and that six would remain at $400/ton, compared with 64 at $0/ton. EPA projects that those six monitors would remain nonattainment or maintenance until the $1,600/ton level, at which they would drop to five, and one would remain at $2,400/ton. [EPA-HQ-OAR-2009-0491-2756.1, p.73]
Analysis of these cost curves is complicated by the fact that, in EPA's analysis, few additional emission reductions are available at each additional cost increment. This drives the analysis upward in pursuit of the modest benefits available at each cost increment. Consideration of local controls would make this analysis far more realistic. 40 A proper analysis, particularly one conducted pursuant to an iterative process, likely would have produced very different and less stringent budgets. 41 EPA should conduct such an analysis and issue it for public comment in a supplemental notice of proposed rulemaking. [EPA-HQ-OAR-2009-0491-2756.1, p.73]

Footnote 40: UARG also notes that, by basing 2012 unit allocations on each unit's share of the lower of 2009 emissions or projected 2012 emissions for the state where the unit is located, 75 Fed. Reg. at 45309/3, EPA failed to take account of the additional overall cost of the program attributable to the de facto loss of the value of allowances that would have been generated as a result of early reductions under CAIR.
Footnote 41: Although the cost per ton levels that EPA selected are unreasonably high, UARG supports EPA's decisions not to select a NOx cost breakpoint above $500/ton and not to select an SO2 cost breakpoint above $2,000/ton. 75 Fed. Reg. at 45281/1-3. Although UARG believes that these breakpoints are also unreasonably high, they are more reasonable than other breakpoints that EPA considered or may have considered. However, as discussed in this section of the comments, had EPA considered the effects of reducing SO2 emissions before considering the effects of reducing NOx emissions, EPA would have concluded that annual NOx emission reduction obligations to address PM2.5 should not have been included in the proposed rule at all.
Response: 
EPA examined emission levels at different cost thresholds for EGU sources.  It did not examine non-EGU sources in its cost curve analysis for this rulemaking.  See section VI of the Transport Rule for further discussion of the cost curves and source categories considered.

IV.D.2. Overall Approach: Air Quality Assessment - Use of Air Quality Assessment Tool (AQAT)

Organization: ARIPPA
Comment: 
ARIPPA
Further, EPA relies upon a series of modeling assumptions, projections as to operating and emission rate, and unsupported control evaluations, including generic costs of control, in translating these ambient concentrations to state-specific budgets. EPA acknowledges the vulnerability of the assumptions and modeling approaches that it utilizes in this context, notwithstanding the critical significance that these projections and assumptions play in EPA's ultimate conclusions regarding significant contribution and source regulation. See, e.g., 75 Fed. Reg. 45274 ("EPA acknowledges that its "more refined air modeling of the proposed emissions budgets . . . suggest[s] that, in the case of daily PM2.5, the air quality assessment tool [used in the model] slightly over predicts the air quality benefit of the proposed reductions"). [EPA-HQ-OAR-2009-0491-2794.1, p.15]
In addition, by analyzing state baseline emissions in the aggregate for purposes of evaluating significant contribution, EPA's analysis is fatally flawed relative to the determination of source-specific contributions toward nonattainment. In particular, EPA does not evaluate source-specific emission characteristics to project ambient impacts, based not only on emission rates but stack configurations and exhaust flow characteristics. Given the inherent vulnerability of such modeling projections, especially in consideration of the uncertainty and relevant assumptions, EPA's determination to evaluate significant contribution based upon assumed aggregate emission conditions for an entire state substantially aggravates the inaccuracies of its modeled projections. [EPA-HQ-OAR-2009-0491-2794.1, p.15]
Therefore, EPA's assessment of the relative contribution of source-specific emissions to nonattainment or interference with maintenance in downwind states cannot be justified as consistent with the "good neighbor" provisions of Section 110(a)(2)(D), nor the mandate issued by the Court in North Carolina to ensure that the projected regulatory scheme is adequately tied to downwind impacts. [EPA-HQ-OAR-2009-0491-2794.1, p.15]
Response: 
With respect to the use of aggregate state-level emissions for the purposes of identifying contributing upwind states, EPA believes that its modeling assumptions are justified.  Please refer to section V of the preamble for the final Transport Rule for more information.  With respect to use of aggregate state-level CAMx source apportionment modeling an input to the method of identifying significant contribution to non-attainment and interference with maintenance, EPA again believes that its method is justified.  Please refer to section VI of the preamble for the final Transport Rule as well as the Significant Contribution and State Emissions Budgets Final Rule Technical Support Document for more information.
Organization: Iowa Department of Natural Resources (IDNR)
Comment: 
Iowa Department of Natural Resources (IDNR)
EPA's choice to couple a sophisticated source attribution technique with the questionable assumption that ozone and particulate nitrate reductions would respond linearly to upwind NOx reductions is not well supported. In their current modeling guidance EPA acknowledges the complex relationships between ozone concentrations and precursors emissions; on pages 18-19 it is stated:
"The NAAQS for ozone and PM2.5 requires ambient data to be averaged over three consecutive years. This presents difficulties using the resource-intensive Eulerian models we believe are necessary to capture spatially differing, complex non-linearities between ambient ozone and precursor emissions." (emphasis added) [EPA-HQ-OAR-2009-0491-2609.1, p.2]
Complex non-linearities also exist between ambient particulate nitrate concentrations and precursor emissions. We understand that EPA is seeking a balance between accuracy and resource efficiency to "analyze many more potential scenarios than the time and resource-intensive more refined air quality modeling would permit" (75 FR 45273). An alternative solution which avoids inappropriate oversimplification of atmospheric chemistry and also avoids some of the resource penalties associated with regional modeling, could include the use of metamodeling techniques. Metamodeling, as described by EPA in the Technical Support Document for the Proposed PM NAAQS Rule Response Surface Modeling, U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research Triangle Park, NC 27711, February 2006:
"aggregates numerous pre-specified individual air quality modeling simulations into a multidimensional air quality "response surface". Simply, this metamodeling technique is a "model of the model" and can be shown to reproduce the results from an individual modeling simulation with little bias or error." [EPA-HQ-OAR-2009-0491-2609.1, pp.2-3]
In this same document EPA describes a response surface model (RSM) built upon CMAQ as one means of preserving some of the sophistication of regional photochemical grid models within a method that allows time-efficient analyses. We suggest EPA investigate the use and application of any existing response surface models and avoid assuming ozone and particulate nitrate concentrations respond linearly to changes in NOx precursor emissions. [EPA-HQ-OAR-2009-0491-2609.1, p.3]
We recommend EPA expand the CAMx source apportionment methodology to include emissions source types in addition to the source regions (states) originally modeled. At a minimum, the addition of two source types would provide valuable information pertinent to the potential emissions reduction scenarios evaluated; a source type which includes only those source types which would be subject under this proposed rulemaking, and a remainder or `all other' (anthropogenic) source type. The additional information available through this technique would provide a means to generate a quantitative assessment of the downwind interstate contributions attributable to those sources for which additional regulations are proposed. [EPA-HQ-OAR-2009-0491-2609.1, p.3]
The inclusion of the additional CAMx source type source apportionment results would avoid the assumption made in the air quality assessment tool (AQAT) that all anthropogenic precursor NOx emissions in a given upwind state contribute equally to downwind particulate nitrate and ozone concentrations. The source apportionment methods also incorporate factors not considered by the AQAT, such as specific source locations and source characteristics (e.g. ground level versus elevated emissions releases). These factors are important components in the atmospheric mechanisms which determine how precursor emissions contribute to downwind ozone and particulate nitrate concentrations. The addition of the CAMx source type source apportionment methods would incorporate these factors, allowing for an improved accounting of how downwind pollutant concentrations may respond to upwind precursor emissions reductions. [EPA-HQ-OAR-2009-0491-2609.1, p.3]
The following discussion and illustration provides an example of how the air quality assessment would be improved by incorporating CAMx source type source apportionment data. The AQAT cannot differentiate between two scenarios, one in which all downwind contributions are associated with only mobile source emissions and the other in which contributions are associated with only electrical generating units (EGUs). Because the AQAT has no knowledge of how emissions from various source types actually affect downwind pollutant concentrations, the assessment tool concludes that a 10 percent reduction in a given state's precursor emissions, regardless of which sources actually reduce their NOx emissions, reduces ozone or particulate nitrate contributions by 10 percent in affected downwind areas. This assumption could easily be avoided by expanding the CAMx source apportionment methods to include just the two anthropogenic source types described above (sources subject to the proposed the Transport Rule, and `all-other' anthropogenic sources). [EPA-HQ-OAR-2009-0491-2609.1, p.3]
With the additional source type source apportionment information, it would be possible to at least proportion how precursor emissions reductions from those source types may impact downwind pollutant concentrations. The contribution assessments specifically for those source types can be adjusted rather than adjusting the contributions which are based upon a state's total anthropogenic contribution. For example, assume a state's contribution to particulate nitrate concentrations in a downwind nonattainment was determined to be 1 ug/m3. Also assume it was determined that a 66% reduction in total NOx emissions would satisfy this states' interstate pollutant transport abatement obligations. Per the proposal, the emissions reductions would come primarily from EGUs. Regardless of contributions from other source types, the AQAT would conclude that reducing EGU NOx emissions by 66 percent would reduce the contributing states' contributions to particulate nitrate in the downwind nonattainment area by 66% (or 0.66 ug/m3). [EPA-HQ-OAR-2009-0491-2609.1,  p.4]
This assumption would only be viable using two questionable assumptions. First, of all the anthropogenic emissions within the upwind state, only those from EGUs are contributing to particulate nitrate concentrations downwind. Second, particulate nitrate reductions respond linearly to NOx reductions. The recommendation to add source types to the CAMx source apportionment was provided above in order to address the first condition. Within the hypothetical example, if it was known (due to source type source apportionment techniques) that EGU NOx emissions contributed 50% of the state's total particulate nitrate contributions to the downwind nonattainment area, an entirely different answer would result from use of the assessment tool. In this case (ignoring the deficiencies in the linearity assumption), reducing the EGU NOx emissions would result in a downwind particulate nitrate concentration decrease of 0.33 ug/m3 instead of the 0.66 ug/m3 reduction predicted by the air quality assessment tool. [EPA-HQ-OAR-2009-0491-2609.1, p.4]
The implementation of source type source apportionment metrics could also be used to assess where adjustments to emissions budgets may be appropriate to alleviate deficiencies
"...for the 10 eastern states for which EPA has not completely quantified the total significant contribution or interference with maintenance with respect to the 1997 ozone NAAQS and the 15 states for which EPA has not completely quantified total significant contribution or interference with maintenance with respect to the 2006 PM2.5 NAAQS..." (75 FR 45214).  [EPA-HQ-OAR-2009-0491-2609.1, p.4]
Implementation of the CAMx source type source apportionment methods in combination with the response surface modeling would improve the technical analysis in support of the Transport Rule. EPA suggests the AQAT over predicts the reduction in daily PM2.5 concentrations associated with the proposed emissions reductions (75 FR 45274). These errors could be minimized or avoided by coupling the recommended source apportionment information with a proper response surface model. This analysis could be completed in a time efficient manner should an existing RSM be suitable. Any existing RSM may not be based on the most recent air quality models, but this is not necessarily a limiting factor. [EPA-HQ-OAR-2009-0491-2609.1, p.4]
The AQAT was deemed appropriate for use based on a simple qualitative comparison between average and maximum future year design values predicted in the 2014 base case and the 2014 control case (Technical Support Document (TSD) for the Transport Rule, Docket ID No. EPA-HQ-OAR-2009-0491, Analysis to Quantify Significant Contribution, U.S. EPA, July 2010, page 26). We could find little additional supporting evidence which demonstrates the air quality assessment tool is appropriate. Using this approach to adequacy determinations it would not appear difficult to assess the appropriateness of alternatively using an RSM (in combination with information from additional CAMx source apportionment techniques to supplement RSM results as appropriate) to quickly assess various emissions reductions scenarios. The CAMx source region source apportionment techniques are currently being used in support of the proposed Transport Rule. The source types apportionment methods are a justifiable extension of these capabilities. Response surface modeling techniques may not be as widespread, but if evaluated would likely surpass the measures used to determine that the proposed AQAT method is appropriate. [EPA-HQ-OAR-2009-0491-2609.1, pp.4-5]
Response: 
Regarding the relationship between NOX emissions and the formation of ozone and particulate nitrate concentrations, EPA updated certain modeling assumptions in response to comments on the proposal.  Please refer to section VI.C of the preamble for the final Transport Rule as well as the Significant Contribution and State Emissions Budgets Final Rule Technical Support Document for details.
Regarding the use of modeling and assessment tools for the final Transport Rule, EPA refined and improved AQAT for use in the final Transport Rule (please refer to section VI.C for details) and EPA believes that the best models available for the task at hand were used.  Specifically regarding EPA's response surface models (RSM), the models available at the time of analysis for the proposed and final Transport Rule are not sufficient to meet EPA's needs (for example, the RSMs do not allow independent evaluation of emissions by state).
With respect to the CAMx source apportionment modeling used, please refer to sections V and VI of the preamble for the final Transport Rule as well as the Air Quality Modeling Final Rule Technical Support Document for details of how this modeling was performed and it's appropriateness for use in developing the final Transport Rule.
Organization: Kentucky Division for Air Quality
Comment: 
Kentucky Division for Air Quality
Levels of control should be based on sound air quality analysis using accepted evaluation tools. [EPA-HQ-OAR-2009-0491-2805.1, p.1]
Establishment of emission reduction mandates should be guided solely by what is needed to achieve and maintain attainment with national standards. Such analyses must give consideration to the impacts of emissions of local origin as well as transported emissions. However, the cost and relative air quality value of local versus distant emission controls must be evaluated and final emission limits should be based on cost-effectiveness and proven technology. [EPA-HQ-OAR-2009-0491-2805.1, p.1]
Incomplete Flawed Model 
Pursuant to the proposed Transport Rule preamble Section III.A., Summary of Proposed Rule (75 FR 45214), EPA is proposing FIPs to immediately implement the emission reduction requirements identified and quantified by EPA in this action. For some covered states, these FIPs will completely satisfy the emissions reductions requirements of 110(a)(2)(D)(i)(I) with respect to the 1997 and 2006 PM2.5 NAAQS and the 1997 ozone NAAQS. The exception is for the 10 eastern states for which EPA has not completely quantified the total significant contribution or interference with maintenance with respect to the 1997 ozone NAAQS and the 15 states for which EPA has not completely quantified total significant contribution or interference with maintenance with respect to the 2006 PM2.5 NAAQS in which case the FIPs would achieve measurable progress towards implementing that requirement. [EPA-HQ-OAR-2009-0491-2805.1, p.6]
The Division is concerned that EPA's modeling results are incomplete and flawed since EPA admittedly has not completely quantified the total significant contribution or interference with maintenance with regards to all existing standards. The Division recommends that EPA properly complete its analysis. [EPA-HQ-OAR-2009-0491-2805.1, p.6]
Response: 
EPA believes that the analysis performed for the final Transport Rule appropriately accounts for emissions impacts from local sources (both in the baseline emissions inventories and in evaluation of EGU emissions at various cost thresholds).  For information about emissions used in modeling for the final Transport Rule please refer to section V and VI of the preamble for the final Transport rule as well as the Documentation Supplement for EPA Base Case v.4.10_FTransport  -  Updates for Final Transport Rule.  
EPA updated and refined its analysis for the final Transport Rule.  For details on the methods used and modeling and assessment performed please refer to section VI of the preamble for the final Transport Rule and the Significant Contribution and State Emissions Budgets Final Rule Technical Support Document.
Organization: North Carolina Department of Environment and Natural Resources
New York State Department of Environmental Conservation
Maryland Department of Environment (MDE)
State of Wisconsin, Department of Natural Resources
Clean Air Task Force
Ozone Transport Commission (OTC)
Environmental Energy Alliance of New York, LLC
Northern Indiana Public Service Company (NIPSCO)
Connecticut Department of Environmental Protection
First Energy
Progress Energy Service Company
Comment: 
Clean Air Task Force
Reasonable Determination of 'Significant Contribution' Requires Additional Reductions of Power Plant Emissions of SO2 and NOx.
EPA explains in the TR proposal that for reasons of administrative convenience it initially used a 'simplified air quality assessment tool, rather than actual air quality modeling, to identify air quality impacts of the options considered.' However, EPA did follow up this simplified approach with more rigorous and refined air quality modeling of the selected emission budgets. This modeling produced different results, which raises several issues upon which EPA seeks comment. In essence, the refined modeling (CAMx) projected that a number of downwind areas would continue to experience nonattainment or maintenance problems with either the PM or ozone NAAQS, or both, even after implementation of the proposed TR. EPA indicates that it intends to conduct further analysis to determine whether additional reductions are necessary, and notes that it is committed to providing downwind states full relief from upwind emissions. We support EPA's stated intention in this regard, and submit that the court's opinion in North Carolina v. EPA requires no less. [EPA-HQ-OAR-2009-0491-2738.1, p.13; This comment can also be found at section IV.D.4.b of this comment summary]
Connecticut Department of Environmental Protection
EPA used its air quality assessment tool (AQAT) in combination with IPM analyses of emission reductions anticipated at different marginal cost/ton levels to identify the proposed $500/ton NOx remedy for addressing significant impact/maintenance issues in downwind states. The AQAT assumes a linear relationship between the reduction in an upwind state's ozone season NOx reductions and the reduction in that state's contribution to downwind ozone levels. For example, if a given upwind state reduced its ozone season NOx emissions by 20 percent, AQAT estimates there would also be a 20 percent reduction in the state's contribution to downwind ozone. EPA explains that the linear AQAT tool was used to minimize the number of time-consuming and resource-intensive CAMx runs that would be needed to analyze the full suite of potential control-level scenarios with the more refined air quality model. The AQAT/IPM methodology is inaccurate and overstates the benefits achieved by the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2780.1 p.10]
EPA ran the CAMx model to identify monitor locations expected to have nonattainment or maintenance issues in 2012 and 2014 for a base case emissions scenario (not including either the proposed Transport Rule remedy or the CAIR Program it would replace). The 2012 base case run was also used to identify and quantify upwind state contributions to downwind monitors with nonattainment/maintenance issues. EPA employed these source apportionment results for 2012 to establish the AQAT linear relationship between emission reductions and upwind states' contributions. After EPA identified the proposed remedy with AQAT, the CAMx model was run one last time to provide a more thorough analysis of projected ambient impacts in the 2014 remedy case as a check on the AQAT result. [EPA-HQ-OAR-2009-0491-2780.1 p.11]
EPA's base case CAMx modeling identifies several monitors in the New York/New Jersey/Connecticut nonattainment area (including multiple monitors in southwest Connecticut) as having potential nonattainment or maintenance problems in 2012 and/or 2014 for the 1997 8-hour ozone NAAQS. When the simplified linear AQAT procedure is applied, EPA projects that the proposed $500/ton NOx marginal cost remedy will be sufficient to eliminate any potential problems by 2014. However, when EPA applies the more technically refined CAMx model (consistent with their modeling guidance), ozone levels at monitors in two (downstate) New York counties are projected to have continuing maintenance issues in 2014. [EPA-HQ-OAR-2009-0491-2780.1 p.11]
Environmental Energy Alliance of New York, LLC
In addition to the emissions modeling, the basis for the state-specific emission reduction projections is an air quality modeling analysis that projects the downwind impact of each state. While the Alliance acknowledges that air quality modeling is the appropriate tool for this analysis, EPA's use of an air quality assessment tool (AQAT) is likely no t an acceptable estimator for New York's significant impacts on downwind receptors in SE Connecticut. Simply put, the meteorological and air chemistry situation is very complex in this region so the generalization that AQAT is acceptable relative to CAMx modeling is inappropriate. Moreover given the complex meteorology associated with Long Island Sound, the Atlantic Ocean, and the Hudson River valley, even CAMx is a poor predictor of impacts of New York State in general and New York City in particular on the downwind monitors in Connecticut. It also is not clear if the AQAT approach can distinguish between the impacts downwind of New York City where the relative EGU contribution is different due to the large concentration of mobile source emissions compared to the rest of the state where the relative importance of EGU emissions is greater. As a result, we really don't know if the proposed emission reductions will be as effective or necessary at all. Therefore, in order to accurately project the impacts of New York on down-wind states more detailed air quality modeling is required. [EPA-HQ-OAR-2009-0491-2638.1, p[EPA-HQ-OAR-2009-0491-2638.1, p.4]
First Energy
Also EPA's simplified 'AQAT' test is based on linear assumptions which contradict the highly non-linear nature of meteorology and chemistry in the atmosphere. [EPA-HQ-OAR-2009-0491-2657.1, p.3]
Maryland Department of Environment (MDE)
Modeling and Technical Analysis
The Air Quality Assessment Tool should be used as a screening tool but the final determination of costs per ton should be evaluated by an air quality model.
While we appreciate the need for quick analyses, Maryland is concerned about the precedent set by EPA to short cut the technical process for a major national rule. Its use almost implies that EPA feels that this tool is sound enough for states to use in their ozone SIPs. Maryland believes that AQAT makes several over-simplifying assumptions: (1) regarding the direct proportionality between reductions of upwind emissions and downwind ambient concentrations, and (2) that emission reductions from all source sectors are equally effective in reducing downwind concentrations of pollutants. [EPA-HQ-OAR-2009-0491-2639.2, p.16]
Maryland urges EPA to adopt more detailed air quality modeling systems such as CAMx or CMAQ when determining the level of emission reductions needed to address interstate transport, especially in Transport Rule II. Also, given the nonlinearities associated with ozone and PM2.5, the final decision as to cost per ton for NOx and SO2 should depend on the CAMx relative response factors, between 2014 with no Transport Rule and 2014 with the Transport Rule. As EPA demonstrated in its proposal, the CAMx runs that were used to evaluate the AQAT showed that the CAMx winter nitrate reductions were not as high as predicted by AQAT. We do not want to slow down the Transport Rule implementation but we strongly recommend that all future final decisions as to cost per ton for NOX and SO2 should be evaluated by running the CAMx model and this modeling procedure should be acknowledged in the final rule since this methodology will be used in future Transport Rules. [EPA-HQ-OAR-2009-0491-2639.2, pp.16-17]
We further request that in the future EPA involve the state in the development of these modeling and technical analyses so that we can better understand the usefulness and workings of AQAT and the other tools EPA is employing and provide our perspective early in the process. [EPA-HQ-OAR-2009-0491-2639.2, p.17]
New York State Department of Environmental Conservation
Use of the Air Quality Assessment Tool (AQAT) to Examine the Impact of Emission Reductions at Specific Cost Levels
EPA indicates that 'While less rigorous than the air quality models used for attainment demonstrations, EPA believes this air quality assessment tool is acceptable for assessing the impact of numerous options on upwind reductions in the process of identifying upwind state significant contribution.' Given that SIP-quality modeling will be used in state-specific analyses, it is inappropriate to use a modeling approach not consistent with accepted practice. Also, the fact that the use of this approach did not demonstrate SC/IM in all areas and the more detailed CAMx approach found more areas potentially not addressed calls into question the use of AQAT to determine SC/IM. [EPA-HQ-OAR-2009-0491-2730.1, p.9]
In its analysis to quantify the impacts of emission reductions at various cost levels on air quality at downwind receptor sites, EPA relied heavily on the AQAT. This tool makes several simplifying assumptions such as the direct proportionality between reductions of upwind emissions and downwind ambient concentrations and the assumption that emission reductions from all source sectors are equally effective in reducing downwind concentrations. Analysis presented in the Preamble and the Significant Contribution Technical Support Document (SC-TSD) indicates that the AQAT overestimates the air quality benefits resulting from the 2014 remedy emission scenario in comparison to the analysis of the more detailed CAMx modeling for the case of daily PM2.5. The results presented in Table 4.2 of the SC-TSD indicate that AQAT and CAMx differ by an average of about six ug/m3 in their estimates of the air quality benefits resulting from the emission reductions occurring between the 2012 base case to the 2014 proposed remedy case. While CAMx modeling indicates an average air quality benefit of about 6 ug/m3 from the 2012 base case to the 2014 control case (reducing the average estimate design value from about 40 ug/m3 to about 34 ug/m3). AQAT analysis indicated about twice that amount (reducing the average estimate design value from about 40 ug/m3 to about 28 ug/m3 Since the assessment tool is over predicting the improvement of air quality as a result of the reductions in transported sulfate. EPA should address transport and assess which of the 14 areas identified by CAMx are, in fact, experiencing wintertime PM2.5issues caused by nitrates. For these areas, EPA must use CAMx to determine SC/IM and the level of reductions necessary to eliminate it. The SC-TSD does not present comparable quantitative information for the annual [EPA-HQ-OAR-2009-0491-2730.1, p.9] PM2.5 or ozone standard. Such information would be needed to gauge whether the use of AQAT is appropriate for those standards. The Preamble states that for the annual PM2.5 standard, there are only two monitors for which the AQAT analysis and the more detailed CAMx modeling differ in their attainment / maintenance status classification for the 2014 remedy case. [EPA-HQ-OAR-2009-0491-2730.1, p.10]
In addition, EPA acknowledges that the AQAT assumes a linear relationship between NOx reductions and ozone reductions. lt is well known that this relationship is not linear and, in fact, will almost universally over-predict the efficacy of the NOx reductions on ozone concentrations. Using AQAT in this manner can, therefore, yield skewed conclusions. EPA should use more refined CAMx modeling to assess ozone air quality benefits. [EPA-HQ-OAR-2009-0491-2730.1, p.10]
In summary, while in the particular case of the proposed transport rule the differences between AQAT and CAMx in terms of estimated air quality benefits resulting from emission reductions affect the attainment / maintenance status at only a few monitors, the magnitude of the daily PM2.5 differences presented in Table 4.2 of the SC-TSD raises serious concerns about the applicability of the AQAT to determine the emission reductions needed to address 110 (a)(2)(D) in reducing the significant contribution that contributes to the downwind attainment and maintenance for this rule and future rules. Instead, more detailed air quality modeling (as the EPA's modeling guideline) with systems such as CAMx should be performed when determining the level of emission reductions needed to address interstate transport. EPA should evaluate whether states belong in Group 1 or 2 based on the CAMx modeling and not the AQAT. In the currently proposed rule, a significant amount of effort was spent on performing numerous IPM simulations for different emission scenarios, but less effort was spent on characterizing the impact of these emission reductions on ambient air quality through detailed air quality modeling. [EPA-HQ-OAR-2009-0491-2730.1, p.10]
Still, a potential improvement to the AQAT would be to calculate and utilize CAMx PSAT contributions for specific source sectors such as EGU rather than working with PSAT contributions calculated for all source sectors and then assuming that emission reductions from all sectors are equally effective in reducing downwind concentrations. [EPA-HQ-OAR-2009-0491-2730.1, p.10]
North Carolina Department of Environment and Natural Resources
While the overall methodology seems reasonable, it is hard to make an informed assessment given the information provided and the time allocated to review the tool. [EPA-HQ-OAR-2009-0491-2767.1, p. 6]
As an alternative approach, NCDAQ suggests using the Assessment Tool as a screening tool to narrow down the suite of alternatives. Then, apply a refined tool, such as CAMx, to identify air quality impacts of these alternatives.[EPA-HQ-OAR-2009-0491-2767.1 p.6]
Northern Indiana Public Service Company (NIPSCO)
EPA indicates it used state-specific cost curves showing what level of emissions reductions could be achieved at different cost levels in 2012 and 2014 and then used the simplified air quality assessment tool to examine the impact of the reductions at specific cost levels on downwind nonattainment and maintenance sites. We request EPA provide clarification on the use of simplified air quality assessment tool and its limitations/biases as compared to use of a more refined air quality model (i.e., CAM-x). [EPA-HQ-OAR-2009-0491-2747.1 p.8]
We believe EPA's methodology that includes use of shortcut air quality assessment methods is inappropriate to assess the air quality impact of individual states on the other states and nonattainment areas. Given the complexity of what EPA is attempting to accomplish and the consequences of enacting a Transport Rule that could require overly stringent and unnecessary reductions, we fail to understand how EPA can rely primarily on a shortcut tool instead of utilizing full fledged, detailed, most recent state of the art version of the CAM-x source apportionment modeling tool to assess air quality impacts. Based on past ozone modeling for the NOx SIP Call and CAIR, we believe that EPA's conclusion that it is appropriate to utilize shortcuts to conduct evaluations where significance is established at such low concentrations (1 % of the NAAQS) is flawed and unreasonable. Further we do not understand how EPA contemplates using this procedure as a model upon which future analyses, at increasingly reduced levels (on a ug/m3 or ppm basis), as future NAAOS are made more stringent. We further question why EPA deviated from the CAIR approach of using monitored-plus-modeled results to assess impacts and future attainment and instead rely solely upon modeling and believe that the approach used in the Transport Rule is unreasonable and arbitrary. Given these concerns about the methodology and the representativeness of the conclusions obtained by use of this procedure, we believe the modeling needs to be redone with corrected inventories employing the full scale CAM-x model, in order to accurately establish and provide justification for appropriate state and unit-specific emission budgets in the Transport Rule. [EPA-HQ-OAR-2009-0491-2747.1 p. 9]
Ozone Transport Commission (OTC)
OTC believes that the Air Quality Assessment Tool (AQAT) makes several over-simplifying assumptions, the first in regards to the direct proportionality between reductions of upwind emissions and downwind ambient concentrations, and the second that emission reductions from all source sectors are equally effective in reducing downwind concentrations. The AQAT may be useful for quickly assessing numerous scenarios in attempting to identify and address significant contribution; however, it should not be seen as a substitute for more detailed air quality modeling to understand the impacts on air quality in greater detail and should be followed up with more accepted modeling techniques for application in the final rule. Air quality modeling systems such as the Comprehensive Air Quality Model with extensions (CAMx) or the Community Multiscale Air Quality model (CMAQ) are publicly reviewed and widely used models, and should be used to develop final budgets and emission reductions needed to address interstate transport, especially in Transport 2. We further request that if EPA is to use new screening tools like AQAT, that they involve the states in development of these analyses so that we can better understand their usefulness and workings prior to employing them. More detailed comments concerning AQAT, CAMx and CMAQ models are provided in Appendix 10. [EPA-HQ-OAR-2009-0491-2737.1, p. 7-8]
Progress Energy Service Company
EPA's limited explanation of both the Air Quality Assessment Tool and the Budget/Unit Allocations is incomplete and difficult to understand. Without additional explanation from EPA, it is impossible to replicate or validate EPA's significant contribution analysis and state budget/unit allocations. Progress Energy urges the EPA to provide a more complete description of the methodologies and data used and to provide additional time for comments on them. [EPA-HQ-OAR-2009-0491-2831.1 p.8]
State of Wisconsin, Department of Natural Resources
One approach that apparently leads to incomplete information is EPA's use of the Air Quality Assessment Tool (AQAT) as a short cut for assessing regional air quality impact of various emission reduction efforts. Better support is provided using a more comprehensive regional air quality model such as CAMX. We specifically urge EPA to rely on the CAMX modeling efforts where they indicate an area may be sensitive to winter nitrate episodes related to the ammonia-nitrogen oxides-sulfur oxides balance in portions of the Midwest. [EPA-HQ-OAR-2009-0491-2829.2, p.6]
Response: 
EPA received comment on the development and use of the Air Quality Assessment Tool (AQAT) as one component of defining significant contribution to non-attainment and interference with maintenance.  EPA refined and improved AQAT for use in the final Transport Rule.  It made significant improvements (including reliance on CAMx for modeling of NOX reductions and its effect on nitrate and ozone formation and improvements to AQAT's linearity assumptions with respect to the relationship between SO2 emissions and sulfate formation).  A detailed discussion of the improvements and results of AQAT as compared to CAMx can be found in section VI of the preamble for the final Transport Rule and the Significant Contribution and State Emissions Budgets Final Rule Technical Support Document.
With respect to the alignment of AQAT results with CAMx results (where CAMx results are available), alignment is greatly improved for the final Transport Rule due to updates to the inputs and methods used to develop and use AQAT.
With respect to clarity in describing the development and use of AQAT for the final Transport Rule, EPA believes that the information contained in section VI of the preamble for the final Transport Rule along with more detailed information in the Significant Contribution and State Emissions Budgets Final Rule Technical Support Document should provide enough information for any entity wishing to understand AQAT.
With respect to the use of AQAT versus CAMx to assess the number of cost thresholds that EPA processed, EPA continues to believe that AQAT (particularly as modified for the final Transport Rule) is an appropriate screening-level tool to quickly assess many emissions scenarios that would be prohibitive for CAMx.
Additionally, commenters questioned the use of CAMx to estimate air quality and noted the complexity of modeling ambient air quality.  EPA believes that CAMx is an appropriate tool for use in the final Transport Rule. For a detailed discussion of CAMx modeling for the final Transport Rule, please refer to section V of the preamble for the final Transport Rule and the Air Quality Modeling Final Rule Technical Support Document.
Organization: Southern Company
Utility Air Regulatory Group (UARG)
Georgia Department of Natural Resources, Air Protection Branch
Comment: 
Georgia Department of Natural Resources, Air Protection Branch
Georgia's SO2 emissions from electric generating units are significantly overestimated in the modeling to determine "significant contribution" and "interference with maintenance" for the annual and 24-hour PM2.5 NAAQS, resulting in an overestimation of Georgia's downwind impact. 
Table IV.C-3 of the proposed rule projects that the state of Georgia will emit 552,007 tons of SO2 from Electric Generating Units (EGUs) in 2012, a value that was used to model the States' "significant contribution" and "interference with maintenance" on downwind states. However, our analysis for SIP planning purposes demonstrates that Georgia is projected to emit only 232,952 tons of SO2 from EGUs in 2012. This value is based on controls and emission limits required by state rules that require specific equipment on specific units on specific dates as well as emission reduction requirements. EPA's emission estimate also includes two EGUs that are required by permit to cease operations prior to or during 2012. EPA states in the proposed rule that the base case was determined by not assuming reductions attributed to the Transport Rule or CAIR, and emissions were determined according to the most economic approach to operation of units without federal or state control requirements and under the existing Acid Rain Program. All major EGU emission units (93% of the coal-fired capacity) in the state of Georgia are required by state rule (Georgia Air Quality Control Rule 391-3-1-.02(2)(sss)) to have controls for SO2 (flue-gas desulfurization or scrubbers) and NOx (primarily selective catalytic reduction or SCR). Installation of these required controls is phased in so that about half will be in place by 2012 and most of the rest will be in place by the end of 2014. Therefore, EPA has significantly overestimated Georgia's SO2 emissions from electric generating units in the modeling to determine "significant contribution" and "interference with maintenance" for annual and 24-hour PM2.5 NAAQS, resulting in an overestimation of Georgia's downwind impact. EPD requests that EPA correct the emission estimates, re-run the model, and re-determine Georgia's downwind impact. [EPA-HQ-OAR-2009-0491-2647.1, p.2]
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.93-94.]
Georgia EPD has begun to examine the daily PM 2.5 and annual PM 2.5 source apportionment modeling results presented by EPA in the technical support document. Specifically, we looked at the impact from the combination of NOx and SO2, which was the EPA approach, as well as NOx and SO2 individually on non-attainment and maintenance areas outside of Georgia.
The EPA approach combined the impacts of SO2 and NOx and compared the combined impacts to one percent of the National Ambient Air Quality Standards, which are 0.35 micrograms per cubic meter for the daily PM 2.5 standard and 0.15 micrograms per cubic meter for the annual PM 2.5 standard.
If the combined impacts were above these levels, the upwind state was linked to the downwind monitor and targeted for use in reductions. However, the maximum impact from Georgia NOx on daily PM 2.5 levels was 0.0364 micrograms per cubic meter, and the maximum impact from Georgia NOx on annual PM 2.5 was 0.0159 micrograms per cubic meter, which is approximately 0.1 percent of the National Ambient Air Quality Standards.
In neither scenario did Georgia's NOx contribution to PM 2.5 levels downwind come close to the one percent of the NAAQS EPA has established as a threshold. Based on this analysis, using EPA's own results found in the technical support document, it makes no sense to control NOx emissions on an annual basis in the southeast to prevent attainment or maintenance of PM 2.5 levels in downwind states including those outside the southeast.
Southern Company
C. EPA's Overall Approach Results in a Highly Biased and Stringent Solution
By assessing NOx emissions first, the EPA approach incorrectly includes NOx emissions reductions in the Proposed Transport Rule. EPA's own justification for not evaluating emission reductions above $500/ton of NOx was that EPA found that 'S02 reductions are generally more effective than NOx reductions at reducing PM2.5'.29 This produced a high-cost look into S02 emissions. If S02 had been assessed first, additional NOx reductions would have been shown to add little additional benefit and therefore be unwarranted. Shown below in Tables XI-1 and XI-2 [See EPA-HQ-OAR-2009-0491-2864.1, p. 31 for Tables.] are results that illustrate this effect using Southern Company's 'replicated' version of EPA's AQAT. [EPA-HQ-OAR-2009-0491-2864.1, p. 30]
As it evaluated the effects of ever increasing reductions, the EPA approach assesses only benefits from transported and local EGU reductions and appears to set the criteria for 'stopping' as showing attainment/maintenance. This criterion places the entire burden for achieving and maintaining the NAAQS on transported air pollution. Furthermore, by ignoring the role of local controls, at least until the end of the assessment approach, the burden is placed ENTIRELY, and unlawfullly on transported and local EGU's. After correcting the errors in its data bases, EPA should redo the analysis and alter its approach by:
:: Including local controls in the 2012 baseline, as well as including CAIR in the 2012 baseline.
:: Constraining the modeling by requiring both monitoring and modeling in identifying downwind receptors.
:: Exploring alternative methods for modeling or post-modeling analysis that strive to obtain the projected air quality contributions from both local and transport, as accurately as possible.
:: Focus on S02 emission reductions first and then assess whether adding NOx emission reductions provides significant benefit. [EPA-HQ-OAR-2009-0491-2864.1, pp. 31-32]
XII. EPA Should Not Have Included Annual NOx Emissions Reductions as Part of the Remedy for PM2.5
A. If EPA Had Considered S02 Emissions First, It Would Have Shown Additional NOx Emission Reductions to Provide Little Benefit In one of the steps in its methodology for determining significant contribution, EPA assesses NOx emissions first, and then subsequently argues that since S02 is more effective, no further analysis of NOx emissions beyond $500 per ton would be pursued. Had EPA reversed the order of the assessment, it would have seen that adding NOx emissions reductions after first considering S02 provides essentially no further benefit. In the Tables XII-I and XII-2 below [See EPA-HQ-OAR-2009-0491-2864.1, p. 44 for the Tables.], we used our replicated version of the AQAT to estimate the benefit of emissions reductions as the number of monitors remaining in nonattainment or having maintenance issues after applying the emissions reductions at the specified cost level. These results illustrate that for both the daily and annual PM2.5 standards, there is little to no downwind benefit from requiring NOx emission reductions at the $500 per ton level. [EPA-HQ-OAR-2009-0491-2864.1, p. 43]
 Utility Air Regulatory Group (UARG)
Indeed, much of this work has already been done. Comments submitted by Southern Company include the results of an analysis conducted by replicating EPA's data and air quality assessment tool. That analysis shows that key indicators of air quality remain essentially unchanged under the Proposed Transport Rule despite differences in aggregate and statewide emission reduction amounts required under the proposed rule compared to those required under CAIR. This analysis provides a basis for concluding that the Proposed Transport Rule will produce a level of air quality that is substantially the same as that which would be produced by continued implementation of CAIR. Table VII-2 below, which was created by Southern Company, compares (i) the number of nonattainment and maintenance sites projected to remain after implementation of the emission reductions required beginning in 2012 under the PTR to (ii) the number of nonattainment and maintenance sites projected to remain after implementation of phase I of CAIR, and the number of nonattainment and maintenance areas projected to remain after implementation of the emission reductions required beginning in 2014 under the PTR to the number of nonattainment and maintenance areas projected to remain after implementation of phase II of CAIR. [EPA-HQ-OAR-2009-0491-2756.1, pp.73-74]  [[See Docket Number EPA-HQ-OAR-2009-0491-2756.1, p. 74 for Table VII-2]]
In almost every comparison, there are very few differences in the numbers of nonattainment and maintenance sites projected to remain following implementation of the Proposed Transport Rule and following implementation of CAIR. This indicates that no meaningful additional benefit is achieved by the emission reductions required under the Proposed Transport Rule beyond those required under CAIR, despite the increased cost and constraints that come along with the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2756.1, pp.74-75]
Additionally, in developing the Proposed Transport Rule, EPA assessed the effects of NOx emission reductions first, before considering the effects of SO2 emission reductions, despite EPA's acknowledgement that "SO2 reductions are generally more effective than NOx reductions at reducing PM2.5." 75 Fed. Reg. at 45281/1-2. This artificially inflates the projected contribution of NOx emissions to the formation of PM2.5. As EPA has acknowledged, for example, the contribution of NOx emissions to PM2.5 formation in southeastern states is considerably smaller than the contribution of SO2 emissions to PM2.5 formation. See 75 Fed. Reg. at 45237/1. In fact, it is minimal. See comments of Southern Company on the PTR (explaining, among other things, that particulate nitrate represents a very small fraction -- approximately five percent -- of PM2.5 in southeastern states). 42 Had EPA taken a more logical approach and assessed SO2 reductions first, it would have found that adding NOx reductions provides little additional improvement in key air quality indicators. Table VII-3 below, which was developed by Southern Company by replicating EPA's air quality assessment tool, illustrates the effect of assessing SO2 reductions before NOx reductions. [EPA-HQ-OAR-2009-0491-2756.1, p.75] [[See Docket Number EPA-HQ-OAR-2009-0491-2756.1, p.76 for Table VII-3.]]
This indicates that for both the annual and 24-hour PM2.5 NAAQS, the number of downwind nonattainment and maintenance monitors is driven primarily by reductions in SO2 emissions. There are only very slight changes in the numbers of downwind nonattainment and maintenance monitors when SO2 emissions are not reduced and NOx emissions are reduced using EGU NOx controls available at $500 per ton. By contrast, when SO2 emissions are reduced using EGU SO2 controls available at $100 per ton, there are significantly fewer downwind nonattainment or maintenance sites, and reducing NOx emissions using EGU NOx controls available at $500 per ton yields only a very slight difference. This same pattern holds true when SO2 emissions are reduced using EGU SO2 controls available at $200 per ton, $300 per ton, and $400 per ton -- although the additional incremental improvement even from the SO2 reductions that are achieved at $300 and $400 per ton is minimal. In each case, the difference between reducing NOx emissions using EGU NOx controls available at $500 per ton and not reducing EGU NOx emissions at all is very slight if there is any difference at all. [EPA-HQ-OAR-2009-0491-2756.1, pp.76-77]
EPA should reevaluate the marginal air quality benefits that are projected from incremental increases in cost for EGU SO2 controls above low levels, such as $300 to $400 per ton, and should reconsider the SO2 cost break-point in that light. Additionally, because of the very minimal benefit that is achieved from reducing EGU NOx emissions in addition to SO2 emissions, as well as the other issues discussed above, EPA should consider removing annual NOx reduction requirements from the proposed rule. [EPA-HQ-OAR-2009-0491-2756.1, p.78]

Footnote 42: Southern Company's comments also explain, among other things, that although particulate nitrate can represent an important fraction of PM2.5 during the winter in northern states, EPA should not have required annual NOx reductions in the PTR because EPA does not include consideration of ammonia emissions in the PTR. The formation of particulate nitrate is an inherently non-linear process, is strongly thermodynamically driven, and is strongly associated with available ammonia. Thus, by excluding ammonia from consideration, EPA cannot properly assess the role of NOx versus ammonia in particulate formation, especially using the linear assumptions in its air quality assessment tool. 
Response: 
With respect to SO2 and NOX emissions modeled for the purposes of the final Transport Rule, EPA took comment on emissions inventories and updated the inventories (including information provided on local controls) to reflect these comments as appropriate.  For details regarding emissions from electric generating units used in this assessment please refer to section V.C of the preamble for the final Transport Rule and the Documentation Supplement for EPA Base Case v.4.10_FTransport  -  Updates for Final Transport Rule.
With respect to EPA's decision to regulate emissions of SO2 and NOX due to their role in formation of downwind PM2.5, details regarding this decision can be found in section V.A of the preamble for the final Transport Rule.
EPA updated and refined its evaluation of NOX and SO2 emissions and their contribution to downwind PM2.5 for the final Transport Rule.  Please refer to section VI of the preamble for the final Transport Rule for details.
For the final Transport Rule, for reasons more fully described in Section VI of the preamble for the final Transport Rule, EPA was able to use CAMx modeling to evaluate ammonia emissions.
For details regarding EPA's multi-factor test for determination of elimination of significant contribution to non-attainment and interference with maintenance and the role that air quality plays in that test please refer to section VI of the preamble for the final Transport Rule.
IV.D.3. Overall Approach: Identify Appropriate Cost Thresholds 

Organization: Adirondack Council
Northeast States for Coordinated Air Use Management (NESCAUM)
Ozone Transport Commission (OTC)
New Jersey Department of Environmental Protection (NJDEP)
Comment: 
Adirondack Council
EPA is also taking comment on whether there should be a higher cost threshold for annual nitrogen oxides. (pp. 301-302) The Adirondack Council believes EPA should consider a higher cost threshold. As is mentioned earlier in our comments, "spring shock" and the nitrogen that builds up in the snowpack has a large impact on Adirondack ecosystems. We believe a threshold of $3,200/ton is reasonable and achievable for annual nitrogen oxides. [EPA-HQ-OAR-2009-0491-2848.1, p.3]
New Jersey Department of Environmental Protection (NJDEP)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.160-161.]
3. The cost level of $500/ton of NOX removed that the USEPA set for determining significant contribution is much too low to be reasonable. The USEPA cited $2,500/ton in CAIR as extremely cost effective for controlling NOX. Section 185 of the Clean Air Act specifies over $8,000 ton penalty for failure to attain the NAAQS. States in the Ozone Transport Commission (OTC) and elsewhere have adopted rules to control NOX from smaller sources that cost much more than $10,000 ton. Limiting costs to $500 ton in this transport rule is inappropriate because it does not reflect the much higher public health and welfare benefits that are available at higher control cost levels.
Northeast States for Coordinated Air Use Management (NESCAUM)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.10-11.]
Second, we do not agree with EPA's proposed cost threshold of $500 per ton of NOX, and are concerned that such a low threshold creates regulatory challenges for states, who have already implemented successful programs at much greater per ton costs. We urge EPA to incorporate a higher cost threshold more aligned with state efforts.
Ozone Transport Commission (OTC)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.116.]
We believe that cost-effective reductions from power plants are available at cost thresholds greater than EPAs proposed threshold of $500 per ton and we urge EPA to adopt a cost threshold that will result in tighter state NOX budgets.
Response: 
As described in section VI.D, EPA  refined and improved the analysis used to identify necessary ozone season and annual NOX reductions.  Please refer to section VI.D of the preamble for the final Transport Rule for further details. Regarding non-attainment of the 1997 ozone NAAQS, the 2008 standard, and future ozone standards, EPA believes it can best serve states with ozone non-attainment problems by quickly finalizing the ozone season NOX reductions under this rule and seeking further ozone season NOX reductions, if necessary, in subsequent rulemakings.

For the annual and 24-hour PM2.5 standards, EPA finds that, for the states covered by this rule for each NAAQS, the final Transport Rule emission reductions of annual NOX and SO2 emissions successfully address all emissions that significantly contribute to nonattainment or interfere with maintenance of the relevant NAAQS as required by Clean Air Act section 110(a)(2)(D)(i)(I).  

See final Transport Rule preamble section VI.D.1 for more details about elimination of significant contribution.
Organization: Cogentrix Energy, LLC
Westar Energy, Inc.
Sierra Club, Pennsylvania Chapter
Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
Indiana Utility Shareholders Association
Comment: 
Cogentrix Energy, LLC
Both Cogentrix sites operate dry scrubbers on all units which have exceeded the referenced cost-based required reductions of $1,800/ton-S02. Cogentrix has included cost tables that show cost-based reductions using actual installation and operating costs in Attachment 2 [See EPA-HQ-OAR-2009-0491-2772.1, p.7 of this comment summary for Attachment 2] of this letter. The cost-based reductions have been calculated using EPA's top-down Best Available Control Technology (BACT) guidance and EPA's pollution cost control manual. In addition, Cogentrix has uses enhanced over fire air combustion practices to meet its Title V permit's NOx requirements. As shown in Attachment 3, [See EPA-HQ-OAR-2009-0491-2772.1, p.9 of this comment summary for Attachment 3]  installation of additional NOx controls, such as SCR, would exceed the referenced value of $500/ton-NOx. [EPA-HQ-OAR-2009-0491-2772.1, p.3]
Indiana Utility Shareholders Association
The modeling the EPA used to determine the Rule's compliance requirements is out of date and/or inaccurate. The EPA based its assessments on equipment and capabilities that in some cases are not yet in place. In order for generation companies to comply with the emissions targets, they will have to install equipment that the EPA has mistakenly indicated is already operational or will be in service soon. This error underestimates the cost of compliance and exacerbates another inaccuracy in the EPA's compliance assumptions - the time and cost needed to design, permit, fabricate and install control equipment. [EPA-HQ-OAR-2009-0491-3845 p.2]
Power companies in my state inform me that the costs the EPA used as the basis for designing, permitting, fabricating and installing flue gas desulfurization units are less than half of market rates. Again, the cost of compliance is not accurately reflected in the EPA's estimates. The citizens in my state will have to bear a financial burden that may be unneeded. Now is not the time for expensive government mandates that will provide questionable benefits. [EPA-HQ-OAR-2009-0491-3845 p.2]
Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
F. Since EPA is Relying Upon Economics to Allocate Emission Budget Caps, EPA Must Use Accurate and Relevant Cost Estimates. EPA Did Not Fully and Fairly Consider the Direct and Indirect Costs of Compliance with the Proposed Transport Rule.
EPA claims that the cost per ton of emission reductions that it calculated render the reductions in the Proposed Transport Rule cost effective. Not only has EPA miscalculated and seriously underestimated the direct cost per ton of removal, but it has not considered the indirect costs in any meaningful way. First, on direct costs, EPA has not considered the direct effects of the Proposed Coal Combustion Residual Rule on the cost of FGD installation if utilities are forced to treat scrubber sludge as hazardous waste. For units required to install both SCR and FGD, EPA has failed to consider the cost of sulfur trioxide mitigation - equipment that is almost always necessary to avoid impermissible increases in the formation and emission of sulfuric acid mist that often occur when both SCR and FGD are installed on a coal-fired unit. EPA has also failed to account for the cost of coal handling projects that will be necessary for many units to burn or blend subbituminous coal. EPA has not considered the direct costs of unit output derating due to fuel switching or just to meet the proposed emission caps and deadlines, or because of the increased parasitic load for FGD and SCR operation. [EPA-HQ-OAR-2009-0491-2803.1, p.14]
Also, there are indirect costs that EPA does not address in the Proposed Transport Rule. The loss of jobs during horrible economic times because of early retirement of viable plants and units as a 'result of the aggressive and unjustified emissions caps and deadlines; the loss of Midwest and Eastern coal mining jobs as a result of forcing greater use of Western subbituminous coal; and the increased cost of electricity to consumers are just a few examples of the types of indirect costs that EPA ignores in the Proposed Transport Rule EPA does not even provide a comparison of what similar reductions would cost in the affected states. For example, if in-state emission reductions cost ten times as much as the same amount of reductions in upwind states, those in-state local reductions would be more cost-effective if they produced twenty times more peak ppb reductions in local nonattainment areas. The local in-state reductions would be even more cost-effective if they did not entail the same magnitude of indirect costs as the reductions from far-distant out-of-state sources. EPA should correct its direct costs to realistic levels, quantify all of the indirect costs of the extreme reductions it is proposing, and provide a comparison of the cost of in-state local control strategies relative to the control of far-distant out-of-state sources. EPA should at least identify and consider the most relevant metric of cost-effectiveness if it is to rely so heavily on economics in apportioning emission reduction burdens - the cost per unit of NAAQS attainment and maintenance benefit. [EPA-HQ-OAR-2009-0491-2803.1, p.15]
Sierra Club, Pennsylvania Chapter
3. EPA has demonstrated that without regional reductions in NOx and SO2 emissions, widespread ozone and PM2.5 nonattainment will be experienced in the East, South and Midwest, now and in the future. EPA has found that NOx and SO2 emissions from 31 states and DC contribute significantly to nonattainment of the PM2.5 or ozone NAAQS in other states. Even more importantly, EPA's air quality modeling shows that some downwind areas will continue to have nonattainment or maintenance problems even after the proposed rule is fully implemented. [EPA-HQ-OAR-2009-0491-3482.1, p.8]
4. While we generally feel that EPA must require coal-fired power plants to do whatever must be done to reduce emissions, previous experience has shown that industry can handle cost-effectively a cost per pollutant reduced threshold of at least $2600 per ton NOx pollutant removed, as was used by EPA in the 1998 NOx Budget Rule. [EPA-HQ-OAR-2009-0491-3482.1, p.8]
Westar Energy, Inc.
EPA'S ASSUMED COST PER TON OF EMISSIONS REDUCTIONS IS NOT CONSISTENT WITH CURRENT COSTS OF SCR TECHNOLOGY. [EPA-HQ-OAR-2009-0491-2757.1, p.26]
EPA conducted an analysis to determine cost-effective NOx emission reductions and ultimately selected $500/ton as a cost effective threshold. EPA then developed 2014 IPM runs that, among other things, projected units that could implement NOx controls for $500/ton. Specifically, IPM projected that Jeffrey Energy Center Units 1- 3 could retrofit SCRs in 2014 for this cost on the basis that Westar could reduce NOx emissions on Jeffrey Energy Center Units 1-3 using an SCR that cost only $500/ton. The support for this proposition is not clear. Westar has done recent work to develop pricing for SCRs on the units at Jeffrey Energy Center (following the installation of LNB low NOx burners and over-fired air on the units) and the cost effectiveness estimates approximate $15,000/ton based on a capital cost of $200 million developed, by the firm involved in assisting with SCR unit design. While Westar is not directly impacted in this proposed rulemaking by the 2014 emission projections, Westar's actual real world experience has been that SCR control equipment could not be installed on the units at Jeffrey Energy Center for anything remotely close to $500/ton. [EPA-HQ-OAR-2009-0491-2757.1, p.26]
Response: 
EPA requested comment on control costs and updated the modeling assumptions to reflect these comments where appropriate for the final Transport Rule.  For information regarding costs of controls for the final Transport Rule, please refer to the appropriate IPM documentation titled Documentation Supplement for EPA Base Case v.4.10_FTransport.  For information regarding the use of these control costs for the final Transport Rule, please refer to section VI of the preamble for the final Transport Rule.
EPA does not project any Transport Rule driven SCR installation in 2014 in the updated IPMv.4.10 used in the final rule analysis.  EPA's analysis for the final Transport Rule does show that existing SCRs would be cost effective to run at a NOX cost threshold of $500/ton.
EPA has updated both its unit level control assumptions regarding existing FGDs, as well as updated the cost assumptions for FGD retrofit installation between its IPMv3.02 used in the proposal and the updated IPMv.4.10 used in the final.  Of note, the Transport Rule modeling projects less than 6 GW of FGD retrofit in response to the rule by 2014.  In the proposal, the projection was 14 GW.
With respect to indirect costs, EPA quantifies these costs as practicable.  For a discussion of costs and employment impacts please refer to section VIII.D in the preamble for the final Transport Rule.  For a discussion of the indirect costs and impacts of higher electricity prices on the entire economy, please refer to the RIA for this final rule.
Organization: Group Against Smog and Pollution (GASP)
Comment: 
Group Against Smog and Pollution (GASP)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.194 & 200-201.]
it can better address the upwind contribution to nonattainment in Liberty-Clairton by adopting higher SO2 and NOX cost thresholds;
GASP supports raising the cost threshold from $2000/ton to at least $2500/ton for SO2, providing further reductions of hundreds of thousands of tons of pollutants per year.
Response: 
For a discussion of non-attainment in the Liberty-Clairton area and EPA's rationale for determining SO2 and NOx costs for the final Transport Rule, please refer to section VI.D of the preamble for the final rule.
Organization: Tennessee Department of Environment and Conservation, Division of Air Pollution Control
Comment: 
Tennessee Department of Environment and Conservation, Division of Air Pollution Control
Comment #1 on Available Reductions and Cost Thresholds: For each precursor pollutant linked to downwind nonattainment and maintenance sites, EPA identified the available reductions from EGUs in each upwind state at the appropriate maximum cost threshold. These emissions reductions represented the amount of the upwind state's significant contribution. A lower cost threshold should be considered for any State that can reduce their contribution below 1% significance using cost thresholds below the maximum values ($2,000/ton for SO2 and $500/ton for NOX), if applicable. [EPA-HQ-OAR-2009-0491-0553.1, p.2]
Comment #2 on Available Reductions and Cost Thresholds: We would like to see a summary for each State and pollutant that indicates, independently of cost, the amounts necessary to eliminate the significant contribution and interference with maintenance from upwind States. This could take the form of a simple table or statement, such as the following: "for [pollutant], the maximum contribution of [State] is _______________ ppb (or μg/m3), which would require _____________ tons/year of emission reductions to eliminate." [EPA-HQ-OAR-2009-0491-0553.1,p.2]
Response: 

EPA determined on a state by state basis, the reductions necessary for each state to eliminate those emissions, within the state, that significantly contribute to nonattainment or interfere with maintenance in another state.  EPA used state specific data and identified appropriate cost thresholds based on cost and air quality impacts to determine the reductions necessary in each state. For further discussion of this topic please refer to section VI of the final Transport Rule preamble.
As discussed in section VI of the preamble for the final Transport Rule, the methodology used to develop the final rule takes into account both the D.C. Circuit Court's determination that EPA may consider cost when measuring significant contribution, Michigan, 213 F.3d at 679, and its recognition that the Court accepted EPA's use of a single, uniform cost threshold to measure significant contribution.  Michigan, 213 F.3d at 679.  As such EPA uses uniform cost thresholds and does not identify the costs or emission reductions necessary to eliminate significant contribution for any individual state.

IV.D.4. Specific Application of Overall Approach: Fine Particles (PM2.5)

Organization: Southern Company
Comment: 
Southern Company
H. EPA Made a Number of Arbitrary Decisions an d Unjustified Assumptions in Their Methodology for Determining Significant Contribution that Result in Unnecessarily Stringent S02 Emissions Budgets
The methodology EPA uses to determine which states significantly contribute to nonattainment or interfere with maintenance is described previously in these comments. This section describes how the methodology and assumptions EPA makes in its significant contribution analysis (SCA) result in an overly and unnecessarily stringent SO2 emissions budget for the states of Georgia, Florida, and Alabama. [EPA-HQ-OAR-2009-0491-2864.1, p. 38]
In preparing to conduct the SCA, EPA developed emissions reduction cost curves by using IPM to project SO2 and NOx emissions in 2012 and 2014 at varying cost per ton increments, ranging from $0 (base case) to $2400 per ton for SO2and $0 to $2500 per ton for NOx. Based on the projected future design values and source apportionment results of the 2012 base case CAMx modeling using 2012 base case emissions, the states of Georgia, Florida and Alabama were determined to significantly contribute to downwind monitors with nonattainment and maintenance issues, making them subject to inclusion in the Transport Rule, at least as Group 2 states. EPA's further analysis using the AQAT to evaluate changes in air quality associated with potential emissions reductions found that in 2014 six monitors would require emissions reductions at significantly higher dollars per ton of SO2 from upwind states to resolve their 24hour PM2.5 nonattainment and maintenance issues. See Section XI-A for discussion of significant contribution analysis. The states that were determined to contribute above the 1% threshold to these six monitors in the 2012 base case were then designated Group 1 states and will be limited to statewide emissions budgets in 2014 that are approximately equivalent to the statewide emissions projected in the 2014 $2000/ton IPM model run. Since Georgia contributed above the 1% threshold to one of those monitors (Baltimore City, MD) in the 2012 base case, the state was classified as Group 1. [EPA-HQ-OAR-2009-0491-2864.1, p. 38]
Following is a list of issues demonstrating that the Transport Rule has no basis for requiring a) Georgia to make reductions beyond those that are required by state rule by 2014 and b) Florida and Alabama to make reductions beyond $100 and $200 per ton, respectively, in 2012.  [EPA-HQ-OAR-2009-0491-2864.1, p. 39]  [See EPA-HQ-OAR-2009-0491-2864.1, p. 39-42 for the list of issues. The issues are individually categorized under Comment Summary outline sections XIX.A., IV.C.3., IV.C.2., and IV.D.1.]
Response: 
EPA updated its IPM model and its emission inventories used in the analysis for the final Transport Rule.  Florida is not covered by the final Transport Rule.  Additionally, Georgia and Alabama are Group 2 SO2 states.  See section VI.D of the preamble for more discussion on cost thresholds examined.  The IPM base case modeling of EGU emissions does reflect the Georgia State Rule.  Georgia was covered under the Transport Rule because EPA's analysis, which reflects that rule, indicated that Georgia has emissions that significantly contribute to or interfere with maintenance of the 2006 24-hr PM2.5 NAAQs and the 1997 ozone NAAQS. 
IV.D.4.a. EGU Cost Curves/ Air Quality Assessment (AQAT)/Cost Thresholds

Organization: Clean Air Task Force
Comment: 
Clean Air Task Force
EPA can address these residual nonattainment and maintenance problems by requiring deeper reductions, even while keeping within the basic framework of the proposal. With respect to PM2.5, Group 2 states have minimal obligations under the current proposal, but there are clearly substantial additional reductions that can be obtained from those states at the $2000/ton cost threshold applicable under the proposal to Group 1 states. We urge EPA to require all states to meet the Group 1 state limits. In addition, there are also substantial additional SO2 reductions available at slightly higher [EPA-HQ-OAR-2009-0491-2738.1, p.7] costs than $2000/ton; according to EPA estimates, additional reductions of about 500,000 tons of SO2 could be obtained by increasing the proposal's SO2 cost threshold to $2400/ton. 34 [EPA-HQ-OAR-2009-0491-2738.1, p.8]
[These comments were also submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.107-108.]
All Covered States Should be Subject to Group 1 SO2 Requirements.
The thirteen states classified in 'Group 2' under the proposed TR are subject only to the first phase of SO2 emission requirements effective in 2012, 77 which are modest indeed, representing slightly less than a 30% reduction in aggregate SO2 emissions from the base case. 78 In reality, the 2012 emission limits (for both SO2 and NOx) are at best anti-backsliding provisions -- that is, they are intended to lock in emission reductions resulting from compliance with CAIR and other requirements. As EPA explained, "[k]eeping emissions of SO2 and NOx from increasing by 2012 in 27 states and DC assures that recent gains are maintained and that states that significantly contribute to downwind PM2.5 nonattainment and maintenance areas do not increase their contribution to those areas." 79 However, notwithstanding EPA's stated intent, the TR will actually allow some emissions to increase. In some cases the TR state budgets are higher than 2009 actual emissions, in many cases higher than the CAIR budgets, and in some cases, higher than both. 80 [EPA-HQ-OAR-2009-0491-2738.1, p.14]
In contrast, effective beginning in 2014, the fifteen Group 1 states are subject to additional and substantially more stringent SO2 reduction requirements, 81 representing an approximate 72% aggregate SO2 reduction from the 2014 base case. 82 As a result, power plants in some states are subject to significantly less stringent emission reduction requirements than those in neighboring states. We do not believe that such disparate treatment is either good policy or required by law, and we urge EPA to treat equally EGUs in all states found to be contributing significantly to nonattainment or maintenance problems in downwind states. [EPA-HQ-OAR-2009-0491-2738.1, p.14]
EPA's rationale for this proposed disparate treatment is that it projected that only 'modest' reductions would be needed in Group 2 states in order to eliminate the nonattainment or maintenance problems in downwind areas to which those states were 'linked.' 83 However, as mentioned previously, these projections were based on screening level analysis from EPA's simplified air quality assessment tool; in contrast, EPA's more refined and accurate CAMx modeling indicated that a significant number of nonattainment or maintenance areas to which a majority of Group 2 states were linked will continue to have problems following implementation of the proposed TR.[EPA-HQ-OAR-2009-0491-2738.1, p.14]
Initially, we note that EPA requests comment on whether it should use CAMx modeling in its determination of significant contribution and maintenance. 84 The answer to this question is clear. As a matter of policy (and perhaps of law), EPA should always use the best science and analytic tools that are available to it, within resource and time constraints. In this case, however, we do not need even to reach that issue, because here EPA has in fact performed analysis projecting residual significant contribution using the more detailed and accurate CAMx modeling as a follow-up to its initial screening analysis using its simplified air quality assessment tool (AQAT). 85 As EPA explains, AQAT assumes that the relationship between emission reductions and downwind pollutant contributions is linear, although the chemistry involved in the formation of PM from SO2 and NOx emissions is more complex, and in fact the emission/air quality relationship in many situations is nonlinear. CAMx modeling provides a more accurate representation of these chemical, nonlinear interactions, and thus is a better predictor of downwind pollutant contribution than is the AQAT. 86 Furthermore, the differences in the predicted results in this case are material and biased -- 'the air quality assessment tool nearly always overestimated total reductions in PM2.5 relative to the estimates from the CAMx modeling.' 87 Therefore, the question in this rulemaking is whether EPA can ignore more refined and accurate evidence of contribution in favor of a cruder screening analysis. As a matter of policy, and to avoid the legal prohibition against arbitrary agency action, EPA must, without some compelling justification (and the Agency offers none), base its rulemaking decisions on the best analysis that it in fact has performed. In this case the best evidence of downwind contribution is clearly provided by the CAMx modeling. [EPA-HQ-OAR-2009-0491-2738.1, p.15]
Group 2 states linked by CAMx to areas with continuing nonattainment and maintenance problems with respect to the 24-hour PM2.5 NAAQS are Connecticut, Kansas, Maryland, Massachusetts, Minnesota, Nebraska, and New Jersey. 88 In addition, EPA's modeling shows that Florida emissions are linked to continuing maintenance problems in Birmingham, Alabama. 89 EPA requests comment on whether these states should be moved from Group 2 to Group 1.90 We think not only that EPA should do so, but that it is required by law to do so, because otherwise these states will have not met their obligation under section 110(a)(2)(D) to eliminate their contribution to downwind nonattainment and maintenance problems. [EPA-HQ-OAR-2009-0491-2738.1, p.15]
As mentioned before, EPA should go farther, and simply do away with the distinction between Group 1 and Group 2 states, subjecting all contributing states to the same 2014 SO2 requirements. 91 EPA, in its extensive analysis of pollution transport over the last decade, has characterized the problem of widespread regional nonattainment as one of 'collective contribution' -- that is, the transport problem results from emission contributions from local sources combined with relatively small individual contributions from a large number of upwind sources typically spread out over many states. 92 We agree, and believe that the uniform approach to the collective contribution problem is best suited to address the transport problem. Most significantly, it treats all similar sources that are contributing to downwind nonattainment and maintenance problems in the same manner. 93 Because electric power moves across state borders, it is important to create as level a competitive regulatory 'playing field' as possible. A rule that creates significantly different reduction requirements could not only lead to competitive distortions within the eastern US power market, but this in turn could create a shift in power production (and emissions) from states with tighter emission requirements to those with less stringent requirements. These problems may be largely avoided by a rule that requires all contributing sources to eliminate emissions above a certain cost threshold. [EPA-HQ-OAR-2009-0491-2738.1, pp.15-16]
In fact, EPA has used this uniform reduction approach in its previous transport rules, and it has withstood direct legal challenge. In the case of Michigan v. EPA, which concerned the NOx SIP Call, several state and industry petitioners specifically challenged this approach as lacking a rational basis, complaining that 'where two states differ considerably in the amount of their respective NOx contributions to downwind nonattainment, under the EPA rule even the small contributors must make reductions equivalent to those achievable by highly cost-effective measures.' 94 The DC Circuit Court of Appeals rejected this claim, holding that EPA's uniform approach to emission reductions was lawful. 95 [EPA-HQ-OAR-2009-0491-2738.1, p.16]
Finally, as discussed earlier in note 80 [see EPA-HQ-OAR-2009-0491-2738.1, p.14 for footnote 80] and accompanying text and in note 91, [see EPA-HQ-OAR-2009-0491-2738.1, p.16 for footnote 91] actual SO2 emissions in 2009 from EGUs in five states that are presently proposed to be included in Group 2 for SO2 reduction purposes were already below their proposed TR SO2 state caps. In other words, the TR would allow these states to increase their SO2 emissions from current levels. Clearly, such increases will not help reduce transport or assist downwind areas in solving their attainment and maintenance problems and [EPA-HQ-OAR-2009-0491-2738.1, p.16] therefore should not be permitted. Such a problematic result could be rectified in several ways, including by moving these states from Group 2 to Group 1. [EPA-HQ-OAR-2009-0491-2738.1, p.17]
We urge the Agency to issue a rule that includes that following adjustments to its August 2 proposal: adopts a minimum threshold for state significant downwind contribution at 0.5% of the applicable NAAQS, rather than the proposed 1% NAAQS threshold, thereby slightly expanding the coverage of the emissions caps and the scope of the reductions [EPA-HQ-OAR-2009-0491-2738.1, p.30]
The $2000/ton SO2 marginal cost cut-off should be raised to $2400/ton.
EPA also seeks comment on whether the cost cutoff applied to SO2 reduction requirements should be raised. We think that it should. EPA notes that a $2000/ton control cost for SO2 is 'relatively low' compared to other potential SO2 control measures. 96 EPA analysis shows that about 500,000 additional tons of SO2 would be reduced in the TR region in 2014 using a slightly higher cut-off of $2400/ton of SO2 reduced. 97 Such a cost is still relatively low in comparison to SO2 controls on other potential sources that a state might regulate to meet its attainment and maintenance obligations, which EPA estimates go as high as $16,000/ton. 98 These additional reductions will not only be highly cost-effective on a relative basis, but will also save additional lives and provide other substantial human health and environmental benefits far in excess of incremental costs. [EPA-HQ-OAR-2009-0491-2738.1, p.17]
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.108.]
Our preliminary analysis shows that a 1.75 million ton regional SO2 cap could be achieved with a cost threshold of about $2600 a ton.

Footnotes:
78 EGU emissions in Group 2 states for the 2014 base case total 1,118,141 tons, while the 2014 budgets for those states total 776,582 tons.
79 75 Fed. Reg. at 45227.
80 For example, state EGU SO2 emissions in 2009 according to EPA acid rain data were already below the 2014 TR state budgets in CT, DC, KN, LA and SC. The problem is more pronounced for NOx, where actual 2009 emissions were lower than the proposed TR budgets in 16 states (AL, CT, DE, FL, GA, IN, IA, KN, LA, MN, MO, NJ, NC, SC, WV and WI).
81 Proposed Group 1 states are GA, IL, IN, IA, KY, MI, MO, NY, NC, OH, PA, TN, VA, WV and WI.
75 Fed. Reg. at 45216
82 EGU emissions in Group 1 states for the 2014 base case total 6,303,310 tons, while the 2014 budgets for those states total 1,723,421 tons.
83 75 Fed. Reg. at 45282. Under EPA's proposed significant contribution test, states are considered "linked" to downwind nonattainment or maintenance areas if they are projected to contribute at least 1% of the relevant NAAQS. 75 Fed. Reg. at 45233.
84 75 Fed. Reg. at 45284
85 See, e.g., 75 Fed. Reg. at 45283.
86 See EPA (July 2010), "Technical Support Document (TSD) for the Transport Rule -- Analysis to Quantify Significant Contribution" at pp 9, 25-27.
87 Id., at 27.
88 75 Fed. Reg. at 45283.
89 Id.90 This change appears to be part of a scenario that EPA evaluated as a "more stringent alternative" in the rulemaking process. See EPA (June 2010), "Regulatory Impact Analysis for the Proposed Transport Rule" at p10-11 (hereinafter "TR RIA").
91 The only remaining Group 2 states not found by CAMx to be linked to areas with continuing downwind attainment or maintenance problems are AL, DE, DC, LA and SC. DC was not modeled separately, but combined with MD. 75 Fed. Reg. at 45256, notes 50 and 51. And as stated in note 80, supra, three of these states (DC, LA and SC) already had actual SO2 emissions in 2009 that were actually lower than their proposed stated budgets for 2014.
92 See, e.g., 75 Fed. Reg. at 45236.
93 We note that once EPA departs from a uniform approach to reductions, it is hard to determine where to draw lines between states subject to lower standards and those subject to higher standards. This is similar to the problem the Agency noted in its discussion of the "binning" approach to significant contribution. See EPA (July 2010), "Technical Support Document (TSD) for the Transport Rule-- Alternative Significant Contribution Approaches Evaluated" at pp13-15. In this case, we do not think it reasonable to apply a $2000/ton SO2 cut-off for EGUs in 23 states and apply a much more lenient cut-off of $500/ton to EGUs in 5 states.
94 Michigan v. EPA, 213 F.3d 673, 679 (DC Cir. 2000), cert. denied, 532 US 904 (2001).
Response: 
Regarding differentiation between Group 1 and Group 2 states for SO2reductions under the final Transport Rule, as in the proposal, EPA determined that it would not be appropriate to assign the same cost threshold to Group 2 and Group 1 states because a significantly lower cost threshold was sufficient to resolve significant contribution to non-attainment and interference with maintenance for Group 2 states.  This decision, as well as the decision on emission reductions for Group 1 states, is based on EPA's authority under Clean Air Act section 110(a)(2)(D)(i)(I).  The authority provided under this section does not require that reductions in upwind states are sufficient to bring all downwind areas in to attainment; it is simply to ensure that all significant contribution to nonattainment and interference with maintenance is eliminated.  Thus, the presence of residual nonattainment or maintenance areas does not, by itself, signify a failure to satisfy the requirements of 110(a)(2)(D)(i)(I).  See Section VI.D for further discussion of this topic.
With respect to EPA's use of AQAT and CAMx for the final Transport Rule, EPA made significant improvements to the development and use of AQAT as well as the use of CAMx.  EPA's evaluation of AQAT against CAMx for the final rule showed that the changes made to AQAT brought AQAT predictions of ambient air quality into alignment with CAMx estimates.  Please refer to Section VI and the Significant Contribution and State Emissions Budgets Final Rule TSD for more details.
Regarding budgets under the Transport Rule, see section VI.D for updated state SO2 budgets and rationale for setting budgets at those levels.  SO2 budgets were set at levels at which significant contribution and interference with maintenance was eliminated for that state.  In this final Transport Rule, all covered states have 2012 budgets that are less than their 2012 base case emissions.  Budgets are not based or indexed to their 2009 emission levels in anyway.
Finally, with respect to the selection of a threshold for state significant downwind contribution, see preamble section V.D for a discussion of the threshold chosen for the final Transport Rule.
Organization: Cleco Corporation
Comment: 
Cleco Corporation
IV. EPA Has No Basis for Imposing an Annual NOx Program on Louisiana Because NOx Emissions Have an Insignificant Impact on Downwind PM-2.5 Attainment in the Southeastern United States.
If EPA insists on including Louisiana in the Transport Rule for purposes of PM-2.5, it cannot include Louisiana in the annual NOx program because there is absolutely no legal or technical basis for doing so based on EPA's own stated test and data. In the proposed rule, EPA includes Louisiana in the annual NOx program because, according to the Agency, the combined impact of SO2 and NOx emissions from Louisiana exceed 1% of the annual PM-2.5 standard. According to EPA's data, total anthropogenic SO2 and NOx emissions from Louisiana contribute 0.3411 μg/m3 to the Clinton Drive monitor in Harris County, Texas, which is not currently in nonattainment but which EPA projects may have a maintenance problem in the future. However, when EPA evaluates the impact of NOx and SO2 individually on that downwind monitor, EPA itself found that more than 98.7% of Louisiana's total impact is from sulfates, not nitrates. According to EPA, sulfates alone contribute 0.3368 μg/m3 to the alleged future maintenance problems at the Clinton Drive monitor. Nitrates contribute only 0.0044 μg/m3 to PM-2.5 levels at Clinton Drive. Thus, based on EPA's own data and analysis, total anthropogenic NOx emissions in Louisiana contribute less than 0.03% of the annual PM-2.5 standard at the Clinton Drive monitor in Harris County, Texas. [EPA-HQ-OAR-2009-0491-2859.1 p.6]
Including Louisiana in the annual NOx program based on this insignificant impact is truly arbitrary, capricious, and an abuse of discretion. It is well-established that NOx emissions, i.e. nitrates, are not significant contributors to fine particulate matter levels in the southeastern U.S.11 In fact, recognizing that sulfates and nitrates vary significantly in their contributions to PM-2.5 from one region to another, in the final PM-2.5 rules, EPA specifically authorized states to evaluate the relative impacts of these PM-2.5 precursors and exclude one or the other precursor based on a technical demonstration of insignificant impacts.12 Inclusion of Louisiana in the annual NOx program would not only ignore science and stated EPA policy, it would also ignore EPA's own modeling analyses and data underlying the proposed Transport Rule that show NOx and nitrates from Louisiana contribute less than 1.3% of Louisiana's total contribution to PM-2.5 levels at Clinton Drive (which again is just over 2% of the annual PM-2.5 standard). In addition, it would ignore EPA's own definition of significant impact under this proposed rule. EPA's estimated impacts for nitrates are also less than the significance levels established under CAIR (0.2 μg/m3). For all of the foregoing reasons, EPA has absolutely no legal or technical basis for including Louisiana in the annual NOx program. [EPA-HQ-OAR-2009-0491-2859.1 p.6]
Response: 
EPA's final Transport Rule modeling does not implicate Louisiana for significant contribution or interference with maintenance to PM2.5 standards.  See Section V and VI of the preamble for the final Transport Rule for more information.  For a more general discussion of NOX contributions to PM2.5 as it relates to southern states please refer to Section V.A of the preamble for the final Transport Rule.
Organization: Duke Energy
North Carolina Department of Environment and Natural Resources
Massachusetts Department of Environmental Protection
State of Wisconsin, Department of Natural Resources
Tennessee Valley Authority (TVA)
NextEra Energy, Inc.
Florida Electric Power Coordinating Group, Inc. (FCG)
Tampa Electric Company
Xcel Energy Inc.
Connecticut Department of Environmental Protection
Gulf Coast Lignite Coalition
Minnesota Power 
Progress Energy Service Company
Environmental Defense Fund (EDF)
Texas Mining and Reclamation Association
Pfeiff, Mike
Group Against Smog and Pollution (GASP)
Comment: 
Connecticut Department of Environmental Protection
EPA used its simplistic AQAT to identify the level of control needed in each upwind state to address significant contributions to downwind attainment or maintenance of the 24-hour PM2.5 NAAQS in downwind states. The AQAT results indicated that certain "Group 2" states (including Connecticut) could fully address their transport obligations through less costly controls in 2012, while other "Group 1" states would require additional, more costly reductions that could not be achieved until 2014 to satisfy their transport obligations. [EPA-HQ-OAR-2009-0491-2780.1 p.19]
Although the AQAT analysis was used to establish the proposed 2012 and 2014 annual SO2 budgets, EPA also followed up its AQAT analysis with a more thorough analysis using the CAMx model. In contrast to the AQAT results for the proposed remedy, the more refined CAMx air quality modeling results show a remaining 24-hour PM2.5 problem, with 10 nonattainment and 4 maintenance areas impacted. Connecticut is one of seven Group 2 states which are linked to one or more states with remaining nonattainment/maintenance problems, as identified by the CAMx modeling. As a result, EPA requests comments on whether any of the Group 2 states should be moved to Group 1 for SO2. [EPA-HQ-OAR-2009-0491-2780.1 p.19]
As EPA discusses in the preamble (pages 45283-45284), CAMx air quality modeling more accurately reflects the complex nature of the winter portion of the 24-hour PM2.5 problem than does the AQAT procedure. Sulfate typically is a lesser contributor to PM2.5 levels in the winter than the summer, likely making winter SO2 reductions less effective at reducing PM2.5 levels. EPA also notes that during the winter, PM2.5 contains a larger nitrate component than in summer months, partially due to the fact that some nitrates that are particles in cooler weather volatilize into the gaseous form during warmer weather. EPA acknowledges that more study of the winter portion of the problem is warranted to address the issues raised by the CAMx modeling. [EPA-HQ-OAR-2009-0491-2780.1 p.19]
Without further analysis to determine the relative benefit of additional SO2 and NOx reductions, it is not possible to determine whether the added SO2 reductions provided by moving Connecticut and other states from group 2 to group 1 would lower winter PM2.5. Therefore, CTDEP encourages EPA to do supplemental CAMx modeling to sufficiently quantify the level of additional SO2 and/or NOx emission reductions needed to fully address the remaining 24-hour PM2.5 transport and nonattainment issues that the modeling indicates will occur with the proposed 2012 and 2014 budgets. EPA should then modify the SO2 and/or NOx budgets accordingly and place states in the appropriate SO2 groups based on the more complete CAMx technical analysis. When making final Group 1/Group 2 determinations, EPA must take into account the level of reductions already achieved within states like Connecticut that have reduced power plant SO2 emissions by over 85% since 1995 and ensure that allowance allocations are correctly determined. [EPA-HQ-OAR-2009-0491-2780.1 p.19]
Duke Energy
EPA's Air Quality Assessment Overestimated the Marginal Benefit of Emission Reductions above Relatively Low Dollar-Per-Ton Levels.
It does not appear that EPA's air quality assessment for the proposed rule properly considered the very limited nature of the reductions in the projected numbers of nonattainment and maintenance sites that result from increasing the marginal cost per ton of EGU SO2 controls above comparatively low levels such as $300 or $400 per ton. See Tables IV.D-3 and IV.D-4, 75 Fed. Reg. at 45280. According to EPA, with respect to the annual PM2.5 NAAQS, two nonattainment monitor sites would remain in 2014 at $200/ton and $300/ ton and only one would remain at $400/ton, compared with 12 at $0/ton. EPA projects that the one remaining nonattainment monitor would reach attainment only at $1,800/ton. Similarly, EPA projects that only three nonattainment and maintenance monitors would remain in 2014 at $200/ton and $300/ton and two would remain at $400/ton, compared with 19 at $0/ton and six at $100/ton. See Table IV.D-3, 75 Fed. Reg. at 45280. With respect to the 24-hour PM2.5 NAAQS, EPA projects that eight nonattainment and maintenance monitors would remain in 2014 at $300/ton and that six would remain at $400/ton, compared with 64 at $0/ton. EPA projects that those six monitors would remain nonattainment or maintenance until the $1,600/ton level, at which they would drop to five, and one would remain even at $2,400/ton. See Table IV.D-4, 75 Fed. Reg. at 45280. A proper analysis, particularly one conducted pursuant to an iterative process, may well have produced very different and less stringent budgets.12 EPA should conduct such an analysis and issue it for public comment in a supplemental notice of proposed rulemaking. [EPA-HQ-OAR-2009-0491-2689.1, pp.15-16]
____________________________________________________________________________
Footnote 12: Although the cost per ton levels that EPA selected are unreasonably high, especially for SO2, Duke Energy supports EPA's decisions not to select a NOx cost breakpoint above $500/ton and not to select an SO2 cost breakpoint above $2,000/ton. 75 Fed. Reg. at 45281/1-3. Although Duke Energy believes that these breakpoints are also unreasonably high, they are more reasonable than other breakpoints that EPA considered or may have considered. [EPA-HQ-OAR-2009-0491-2689.1,p.16]
Environmental Defense Fund (EDF)
Eight states  --  Connecticut, Florida, Kansas, Maryland, Massachusetts, Minnesota, Nebraska, and New Jersey  --  should be included in Group 1 (the group with more aggressive SO2 emission reduction requirements) because CAMx modeling indicates that under the Proposed Rule these states continue to contribute to nonattainment and maintenance problems in linked downwind states. This recommendation reflects the general principle that results from the CAMx air quality model should be given precedence over the less reliable results from the simplified model. While the air quality assessment tool is a useful device for exploring potential regulations, there is no justification for using it as the basis for the actual rule given the contrary evidence from the more sophisticated modeling.  [EPA-HQ-OAR-2009-0491-2834.1 p.6]
Texas should be included under the regulations in Group 2 (the group of states with moderate SO2 emission reduction requirements) because modeling indicates that Texas SO2 emissions will exceed the 1 percent (0.15 μg/m3) contribution threshold for PM2.5, once the ancillary effects of the Proposed Rule (e.g., on the price of coals with different sulfur contents) are taken into account. Any reasonable regulation must be internally logically consistent. In studying whether the Proposed Rule will satisfy the statutory obligation to eliminate significant contribution and interference with maintenance, EPA must consider the predictable effects of the Rule in total, once implemented. Because EPA's modeling shows that emissions from Texas would make a significant contribution to downwind nonattainment under the Proposed Rule, it must include the State under the regulation.  [EPA-HQ-OAR-2009-0491-2834.1 p.7]
Florida Electric Power Coordinating Group, Inc. (FCG)
For the annual PM2.5 standard, EPA's use of the air quality assessment tool projected that, after implementation of the proposed FIPs, the Birmingham, Alabama, annual PM2.5 monitors would not have a NAAQS air quality nonattainment or maintenance problem. However, the results of EPA's refined air quality modeling, using the regional air quality model CAMx, projected that Birmingham, AL, would exceed the threshold for 'maintenance' by 'an extremely slight amount.' (less than 0.1 IJg/m-3 ). 75 Fed. Reg. 45283. Based on these results of the refined modeling, EPA has requested comment on whether Florida should be moved from Group 2 to Group 1. Based on more complete modeling by Alabama, and errors in EPA's data, we agree with EPA's conclusion that upwind reductions beyond those in the proposal are not needed to address significant contribution and interference with maintenance of the annual PM2.5 NAAQS in Birmingham, AL. The Alabama Department of Environmental Management recently conducted refined modeling for the Birmingham PM2.5 SIP, in accordance with EPA guidance on PM2.5 attainment modeling. This effort includes local emissions reductions that EPA failed to consider in the refined Transport Rule modeling (see, EPA Transport Rule Emissions Inventory TSD, p.11), and shows that the Birmingham area will actually attain the annual PM2.5 standard in 2012. These results also demonstrate that Birmingham should meet EPA's threshold for 'maintenance' of the annual PM2.5 standard in 2012. Indeed, current air quality data reveals that Birmingham is already close to attainment (i.e., 2007-2009 DV of 15.1 ug/m-3). In addition, EPA's significant contribution assessment conducted for the Transport Rule shows that Florida only contributes 0.1519 ug/m-3 to the non-attaining Birmingham monitor in the 2012 base case, a concentration increment which is only 0.0019 ug/m-3 above the significant contribution threshold of 0.15 ug/m-3. [EPA-HQ-OAR-2009-0491-2658.1, pp.7-8]
Furthermore, EPA erred in assuming that units 4, 5, 6 and 7 at Plant Crist in Escambia County, Florida, and units 4 and 5 at Plant Crystal River in Citrus County, Florida, have dispatchable wet FGDs that would not operate in the 2012 base case. In fact, the operation of these wet FGDs are required by permit (See, Crist: Permit No. 0330045- 023-AC; Crystal River: Permit No. 0170004-019-AC (PSD-FL-383A)) and would reduce the total combined Florida EGU (> 25 MW) S02 emissions by almost 40%. Had EPA properly accounted for (a) the reduction in local emissions in the Birmingham area and (b) emissions reductions from Florida sources in the base case, that analysis would almost certainly have found that Florida did not interfere with maintenance of the annual PM2.5 standard in Birmingham, AL. Therefore, Florida should not be considered for inclusion as a Group 1 state. [EPA-HQ-OAR-2009-0491-2658.1, p.8]
Finally, EPA must use the same criteria for assigning each state to Group 1 or 2, or its action would be arbitrary and capricious. Specifically, if EPA were to establish the significant contribution attributable to all states linked to Birmingham using the air quality assessment tool process, and then require Florida to make S02 reductions beyond the amount specified by the process, EPA's action could only be characterized as arbitrary and capricious. If significant contribution can only be established for a precursor pollutant using a detailed air quality model, then every state's significant contribution must be established using the same detailed air quality model. If EPA's internal timeline and resource limitations do not allow EPA to fully utilize the air quality model for this rulemaking, then EPA should focus solely on the assessment tool, or extend the period for its rulemaking. [EPA-HQ-OAR-2009-0491-2658.1, p.8]
Group Against Smog and Pollution (GASP)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.194.]
moving the eight candidate states EPA has identified from group 2 to group 1
Gulf Coast Lignite Coalition
 The proposed Transport Rule currently requires that Texas demonstrate NOX reductions with respect to the 8-hour ozone NAAQS. Texas is not currently held to the additional reductions for SO2 and NOX for the annual PM2.5 NAAQS or 24-hour PM2.5 NAAQS required for "Group 1" and "Group 2" states. EPA is now seeking comment on and considering, inclusion of Texas in the moderate SO2-controlled group, the "Group 2" states.   [EPA-HQ-OAR-2009-0491-2734.1 p.3]
 EPA's concern seems to be that the SO2-regulated states will switch to lower-sulfur coal, thereby creating a market for the higher-sulfur coal in the "unregulated states" such as Texas. EPA projects that Texas's new reliance on the higher-sulfur coal will result in SO2 increases over the base case and above 5,000 tons.1 In EPA's modeling, Texas' SO2 emissions would exceed the 0.15 ug/m3 threshold for annual PM2.5 in 2012. For this reason, EPA is considering including Texas as a Group 2 member subject to SO2 reductions by 2012.2 [EPA-HQ-OAR-2009-0491-2734.1 p.3]
1 75 Fed. Reg. at 45284.
2 As a Group 2 state, Texas would be required to make additional SO2 reductions through (1) operating existing scrubbers, (2) installing scrubbers by 2012, and (3) using coal with a lower sulfur content. 75 Fed. Reg. at 45290.
 Texas is currently demonstrating attainment for the 24-hour and annual PM2.5 NAAQS; there are no nonattainment areas for PM2.5 in Texas. To require additional reductions in SO2 based on the assumption that Texas may invest in coal with a higher sulfur content is speculative and unsubstantiated. Without a clear basis for this assumption, EPA should not include Texas into an additional regulatory program . [EPA-HQ-OAR-2009-0491-2734.1 p.3]
Massachusetts Department of Environmental Protection
Under the annual S02 Program framework, EPA has classified states that contribute to downwind PM nonattainment or maintenance problems into Group 1 or Group 2. EPA requests comment on whether some states, such as Massachusetts, which are in the Group 2 S02 annual program should be moved to Group 1. 15 EPA notes that states were included in Group 2 if the air quality assessment tool that EPA used to analyze downwind contribution indicated that the 2012 reductions will resolve the nonattainment or maintenance problems in downwind areas. Group 2 States, therefore, have a 2012 budget that remains the same in 2014 and future years. For Group 1 States, the analysis indicates that they are still contributing to downwind areas in 2014, therefore they are subject to a 2012 S02 budget and a lower 2014 S02 budget.
However, EPA notes that CAMx modeling, which is more detailed than the air quality assessment tool that EPA used, shows continuing downwind nonattainment or maintenance problems involving one or more states to which the Group 2 States contribute. 16 Massachusetts is identified as contributing to downwind nonattainment and maintenance for the New York City area, where significant contribution issues remain in 2014. MassDEP recommends that EPA determine which states to include in Group 1 in the final Transport Rule based on CAMx . modeling that is updated to incorporate data corrections submitted to EPA. If that modeling demonstrates that a state currently in Group 2 contributes to an area that has continuing downwind attainment or maintenance problems in 2014, the state should be included in Group 1 in the final rule.   [EPA-HQ-OAR-2009-0491-2787.2 p.7]
Minnesota Power 
Group 2 State.  Minnesota Power recommends that, if EPA decides to list Minnesota as a Transport Rule affected state, Minnesota remain a Group 2 Transport Rule state rather than being reassessed for inclusion as a Group 1 Transport Rule state. Minnesota Power notes that EPA's own dollar per ton emission reduction, cost effectiveness criteria shows it is not cost effective to deliver a significant amount of additional emission reductions in Minnesota relative to the cost per ton reduction for SO2 and NOx in EPA's Group 1 states. [EPA-HQ-OAR-2009-0491-2750.1, p.6]   
Cost effectiveness.  EPA's Group 2 status for Minnesota was justified by EPA's analysis that it was not cost effective for Minnesota sources to make Group 1 state reductions due to relatively low Minnesota baseline emission rates. The same cost effectiveness rationale used by EPA in their Group 1 vs. Group 2 determinations would suggest it is not cost effective to include states in the Transport Rule if EPA analysis shows that the reductions required to meet Group 2 emission budgets have already been implemented in a state.    [EPA-HQ-OAR-2009-0491-2750.1, pp.7-8]
NextEra Energy, Inc.
Florida should remain a Group 2 state for SO2 in the final rule based on EPA's multi-factor assessment using the air assessment tool
The methodology EPA proposes to use to quantify significant contribution in the Transport Rule is a multifactor approach that accounts for both cost and air quality improvement. In step one, EPA identifies what emissions reductions are available at various costs) quantifying emissions reductions that would occur within each state at ascending costs pet ton of emissions reductions. In step two, EPA uses a simplified air quality assessment tool to estimate the impact that the combined reductions available from upwind contributing states and the downwind state) at different cost-per-ton levels) would have on air quality at downwind air quality monitoring sites that had nonattainment and/or maintenance problems. While less rigorous than the air quality models used for attainment demonstrations) EPA believes that this air quality assessment tool is acceptable for assessing the impact of numerous options on upwind reductions in the process of identifying upwind state significant contribution. It allows the Agency to analyze many more potential scenarios in a shorter time frame than the time-and-resource-intensive more refined air quality modeling would permit (more refined air quality modeling can take several months) while multiple scenarios can be evaluated using the air quality assessment tool in a single day). [EPA-HQ-OAR-2009-0491-2718.1, p.7]
EPA did, however, conduct more refined air quality modeling of select emissions budgets to serve as a check on the appropriateness of the simplified method. This check confirmed the directional conclusions of the air quality assessment tool and largely confirmed the more detailed results of the air quality assessment tool, but there were some instances where EPA identified discrepancies between the results of the simplified air quality assessment tool and the more refined air quality modeling [EPA-HQ-OAR-2009-0491-2718.1, p.7]
For the annual PM, standard, the air quality assessment tool projected that, after implementation of the proposed FIP, only one area (Allegheny County, PA would have a continuing NAAQS air quality problem under the maintenance criteria. The results of the refined air quality modeling were very similar. This modeling projected similar annual PM reductions in downwind states and projected that Allegheny County, PA would remain in nonattainment and that Birmingham, AL would exceed the threshold for 'maintenance' by a slight amount less than 0.1 ug/m3). For this reason, EPA is taking comment on whether Florida, the one group 2 state that was identified as linked to Birmingham, should be moved from Group 2 to Group 1.[EPA-HQ-OAR-2009-0491-2718.1, p.7]
Since the refined air quality modeling projects that Birmingham, AL will exceed the maintenance criteria by only an extremely slight amount and because reductions from nearby point sources will reduce local emissions in the area, NextEra Energy does not believe the refined air quality modeling demonstrates that upwind reductions beyond those in the proposed FIP are required to address significant contribution and interference maintenance of the annual NAAQS in Birmingham. On this basis, supports EPA's proposal to include Florida as a Group 2 state for S02. [EPA-HQ-OAR-2009-0491-2718.1, p.7]
North Carolina Department of Environment and Natural Resources
The NCOAQ thinks that $2000/ton of 502 is reasonable. EPA should be consistent in the use of the tool to determine reductions needed. [EPA-HQ-OAR-2009-0491-2767.1 p.7]
Pfeiff, Mike
11. Preferred Approach Maximum Cost Threshold - The methodology the EPA uses to determine significant contribution (Federal Register page 45233) is unlawful. Specially, the EPA does not apply uniform cost standard across all states. Instead, the EPA, 'divides, for individual pollutants, the significant contributing states in to two groups: those with significant contribution that can be eliminated at a lower cost threshold; and those significant contribution is not eliminated' (Federal Register page 45233). A non uniform cost threshold definitions across states prejudices certain states. The Proposed Transport Rule does not provide the EPA the authority to determine cost thresholds that are not uniform.
I request the EPA to explain why the use of non uniform cost standards across all states in not arbitrary and capricious. [EPA-HQ-OAR-2009-0491-2742.1, p.9]
Progress Energy Service Company
Florida Should Remain a Group 2 State
EPA is taking comment on whether Florida, which is a Group 2 state for purposes of the S02 program, should instead be included as a Group I state. Treating Florida as a Group I state would result in little, if any, additional improvement to the air quality in surrounding states. [EPA-HQ-OAR-2009-0491-2831.1 p.9]
For the annual PM2.5 standard, EPA's use of the air quality assessment tool projected that, after implementation of the proposed rule, the Birmingham, Alabama, annual PM2.5 monitors would not have an air quality nonattainment or maintenance problem. However, the results of the refined air quality modeling, using the regional air quality model CAMx, projected that Birmingham would exceed the threshold for 'maintenance' by a slight amount (less than 0.1 uglm3 ). (75 FR 45283) Based on these results of the refined modeling, EPA has requested comment on whether Florida should be moved from Group 2 to Group 1. Progress Energy agrees with EPA's conclusion that upwind reductions beyond those in the proposed rule are not required to address significant contribution and interference with maintenance of the annual PM2.5 NAAQS in Birmingham. As EPA states, 'the refined air quality modeling projects that Birmingham, AL, will exceed the maintenance criteria by only an extremely slight amount.' [EPA-HQ-OAR-2009-0491-2831.1 p.9]
In addition, EPA erred in assuming that units 4, 5, 6 and 7 at Plant Crist in Escambia County, Florida, and units 4 and 5 at Crystal River in Citrus County, Florida, have dispatchable wet FGDs that would not operate in the 2012 base case. In fact, the operation of these wet FGDs is required by their permits, and together they reduce the total combined Florida electric sector S02 emissions by almost 40%. Had EPA fully accounted for the reductions from Florida sources in the base case, that analysis would almost certainly have found that Florida does not interfere with maintenance of the annual PM2.5 standard in Birmingham. Therefore, Florida should not be considered for inclusion as a Group I state, and Progress Energy urges the agency to maintain its Group 2 status. [EPA-HQ-OAR-2009-0491-2831.1 p.9]
State of Wisconsin, Department of Natural Resources
EPA needs to consider deeper control levels in identifying EGU responsibility for states with remaining significant contribution.
EPA's assessment for the proposed rule indicates a need to explore a broader range of EGU control cost effectiveness in this rule for both S02 and NOx controls in states directly impacting Wisconsin air quality. While identifying the core issue of insufficiency of remedy within the evaluated controls cost range, we also note a limiting system issue is one of controls installation feasibility in short timeframes. EPA's assessments showed a large drop in projected S02 emissions when going from $2000/ton to $2400/ton. This step function drop in residual emissions is probably due to a projected scrubber retrofit of a significant amount of installed baseload capacity that currently is configured to use sub-bituminous coal. Increasing the assessment to the same top level evaluated for NOx control (up to $5000/ton) would place all parts of the region into a more consistently and equitably controlled circumstance and would ensure that the major baseload portions of the utility fleet would no longer significantly contribute to ambient air quality problems downwind. While such control installation levels could not be achieved by 2014, much of the additional control need could be met in 2016 and later. [EPA-HQ-OAR-2009-0491-2829.2, pp.7-8]
Tampa Electric Company
EPA indicates in the proposal that Florida emissions have some impact on Birmingham's attainment status that may support including Florida as a Group 1 state. Although there is inadequate time to fully evaluate EPA's conclusions, Tampa Electric believes it would unnecessarily burdensome to impose an even stricter SO2 cap on Florida since EPA's modeling shows Birmingham "will exceed the maintenance criteria by only an extremely slight amount...." (75 FR at 45283, Col. 2). We understand that Alabama Department of Environmental Management recently conducted refined modeling for the Birmingham PM2.5 SIP, in accordance with EPA guidance on PM2.5 attainment modeling. This effort includes local emissions reductions that EPA failed to consider in the refined Transport Rule modeling (see, EPA Transport Rule Emissions Inventory TSD, p.11), and shows that the Birmingham area will actually attain the annual PM2.5 standard in 2012. We agree with EPA that reductions from local sources will have a more significant impact on reducing emissions in this area and that upwind reductions beyond those proposed are not necessary. [EPA-HQ-OAR-2009-0491-2745.1 p.7]
Tennessee Valley Authority (TVA)
B. Issue: EPA believes it is appropriate to use multiple cost thresholds where one group of states can, for a lower cost, eliminate non-attainment and maintenance for all downwind problem areas to which they are linked. (p. 45274)[EPA-HQ-OAR-2009-0491-2782.1, p. 11]
TVA Comment: As indicated in our earlier comment, TVA agrees that states in Group 1 and Group 2 should not be assigned the same cost per ton; however, it is hard to decipher EPA's rationale for grouping the states from reviewing Figures IV-D-1 to IV-D-4. It does not appear reasonable to place states such as Kentucky, Tennessee and West Virginia in Group 1 in view of the flat cost curves associated with SO2 reductions in these states. [EPA-HQ-OAR-2009-0491-2782.1, p. 11]
Further, EPA invites comment on whether certain states, while placed in Group 2 in the proposal, should be moved from Group 2 to Group 1 because refined air quality modeling predicts that the downwind states to which they are linked will continue to have nonattainment or maintenance problems. (p. 45283-84) TVA recommends that air quality significance thresholds, once established to identify states with significant contributions to downwind nonattainment or maintenance, should be rigorously applied. Section 110 would require nothing less. There are also a couple of policy reasons that make rigorous application of the threshold criteria necessary even in those states that may be on the cusp in creating downwind nonattainment or maintenance problems. First, the air quality standards that are being addressed in this Transport Rule are under reconsideration and likely to be further lowered. EPA recognizes that if more protective NAAQS are promulgated, further emission reductions would be needed in upwind states that significantly contribute to the air quality problems in another state. [p. 45228] Thus, states that are today on the cusp are very likely to become targeted for significant reductions in the near future. Second, the remedy proposed by EPA in the Transport Rule allows for limited interstate trading, providing EGUs the flexibility to implement controls in a cost-effective manner. Increasing the number of states in a group increases the opportunity for such interstate trading by increasing the size of the trading pool. Since Group 2 states must make deeper reductions than Group 1 states, the former group is likely to derive a greater benefit than the latter from having a larger trading pool. [EPA-HQ-OAR-2009-0491-2782.1, pp. 11-12]
Texas Mining and Reclamation Association
 The proposed Transport Rule currently requires that Texas demonstrate NOX reductions with respect to the 8-hour ozone NAAQS. Texas is not currently held to the additional reductions for SO2 and NOX for the annual PM2.5 NAAQS or 24-hour PM2.5 NAAQS required for "Group 1" and "Group 2" states. EPA is now seeking comment on and considering, inclusion of Texas in the moderate SO2-controlled group, the "Group 2" states.   [EPA-HQ-OAR-2009-0491-2734.1 p.3]
 EPA's concern seems to be that the SO2-regulated states will switch to lower-sulfur coal, thereby creating a market for the higher-sulfur coal in the "unregulated states" such as Texas. EPA projects that Texas's new reliance on the higher-sulfur coal will result in SO2 increases over the base case and above 5,000 tons.1 In EPA's modeling, Texas' SO2 emissions would exceed the 0.15 ug/m3 threshold for annual PM2.5 in 2012. For this reason, EPA is considering including Texas as a Group 2 member subject to SO2 reductions by 2012.2 [EPA-HQ-OAR-2009-0491-2734.1 p.3]
1 75 Fed. Reg. at 45284.
2 As a Group 2 state, Texas would be required to make additional SO2 reductions through (1) operating existing scrubbers, (2) installing scrubbers by 2012, and (3) using coal with a lower sulfur content. 75 Fed. Reg. at 45290.
  Texas is currently demonstrating attainment for the 24-hour and annual PM2.5 NAAQS; there are no nonattainment areas for PM2.5 in Texas. To require additional reductions in SO2 based on the assumption that Texas may invest in coal with a higher sulfur content is speculative and unsubstantiated. Without a clear basis for this assumption, EPA should not include Texas into an additional regulatory program . [EPA-HQ-OAR-2009-0491-2734.1 p.3]
Xcel Energy Inc.
2. EPA should leave Minnesota in the SO2 Group 2 trading program.
Xcel Energy opposes moving Minnesota from SO2 Group 2 to Group 1. EPA has performed a detailed analysis supporting Minnesota's inclusion in Group 2 using the air quality assessment tool. EPA's analysis placed Minnesota in Group 2 because the air quality assessment tool indicated that the 2012 reductions will resolve the nonattainment or maintenance problems at all areas to which they are linked. [EPA-HQ-OAR-2009-0491-2728.1, p.8]
EPA is considering moving Minnesota from the Group 2 to the Group 1 SO2 trading program because the CAMx model indicates that one or more of the states to which Minnesota is linked will have continuing nonattainment or maintenance problems after implementation of the 2012 reductions. We strongly oppose this approach, for the following reasons:[EPA-HQ-OAR-2009-0491-2728.1, p.8]
- EPA used the air quality assessment tool as the basis for the state designations under CATR.[EPA-HQ-OAR-2009-0491-2728.1, p.8]
- EPA has stated on page 45283 that it believes additional study of the winter portion of the problem is warranted to address the issues raised by the CAMx modeling. We agree that additional study of this issue should occur before EPA changes the SO2 trading group designation of Minnesota from Group 2 to Group 1 in the SO2 trading program.[EPA-HQ-OAR-2009-0491-2728.1, p.8]
For these reasons, EPA should not move Minnesota from the Group 2 to the Group 1 SO2 trading program.[EPA-HQ-OAR-2009-0491-2728.1, p.8]
Response: 
With respect to EPA's selection of receptors as having non-attainment and maintenance problems in the 2012 base case, EPA's source apportionment modeling, and EPA's identification of significant contribution to nonattainment and interference with maintenance, EPA updated and improved its analysis with respect to each of these steps for the final Transport Rule.
EPA updated the assumptions and inputs to the emissions inventories (based in part on public comment) for which details can be found in section V and VI of the preamble for the final Transport Rule and the Documentation Supplement for EPA Base Case v.4.10_FTransport  -  Updates for Final Transport Rule.
EPA modified and improved the Air Quality Assessment Tool (AQAT) for use in the final transport rule analysis.  Details can be found in section VI.C of the preamble for the final Transport Rule and the Significant Contribution and State Emissions Budgets Final Rule Technical Support Document.  These sections describe improvements to AQAT, demonstrate EPA's confidence that AQAT estimates of ambient air quality would align well with CAMx modeling for the assessed cost thresholds, and show that detailed CAMx modeling of the final Transport Rule supported AQAT's results.
Further, section VI.D of the preamble for the final Transport Rule and the Significant Contribution and State Emissions Budgets Final Rule Technical Support Document detail the methods used and rational for determination of significant contribution to non-attainment and interference with maintenance, including determination of Group 1 and Group 2 states for the final Transport Rule.
Organization: New York University School of Law, Institute for Policy Integrity
Wholesale Markets Brokers' Association
Comment: 
New York University School of Law, Institute for Policy Integrity
:: Trading should be allowed between SO2 group one states and SO2 group two states, with appropriate trading ratios. [EPA-HQ-OAR-2009-0491-2691.1, p.1]
5. Trading Between SO2 Groups
The Transport Rule divides states into two groups based on the significance of their SO2 emissions to downwind impacts. Under its preferred approach, EPA does not permit trading between the two separate groups. By limiting the size of the marketplace, this restriction will reduce the opportunities to take advantage of the lowest-cost abatement opportunities, without creating any measurable benefit to the environment or public health. Since EPA will already ensure that every state is taking reasonable measures to reduce its significant contribution (either through the current assurance provisions or the modifications recommended in these comments), the prohibition on intergroup trading is not necessary to comply with statutory mandates. To the extent the harms caused by SO2 emissions vary with geographic origin, trading ratios could be established to account for marginal damage differences, without interfering with a more open and efficient trading scheme. For example, firms operating in group one states might be required to submit two allowances for each ton of emissions, versus only one allowance required in group two states. [EPA-HQ-OAR-2009-0491-2691.1, p.13]
Because the prohibition on intergroup trading raises costs without providing benefits, EPA should remove it and allow trading among all states. EPA should also study the potential benefits of using trading ratios to govern trades between states in group one and group two. If trading ratios would increase net benefits at an acceptable administrative cost (because of significant disparity in marginal damages and/or wide variation in marginal abatement costs), EPA should adopt such an approach. [EPA-HQ-OAR-2009-0491-2691.1, p.13]
Wholesale Markets Brokers' Association
By restricting trading zones to arbitrary political boundaries, and not physical proximity, the CATR proposal would unduly limit the number and nature of market participants. In practical terms, this reality when coupled with the current electric utilities rate regulation strongly suggest that EPA take steps to broaden the number of potential market participants and increase the time period and geographic area within which allowances may be lawfully used for compliance purposes. Unfortunately, EPA's proposal, with its Group 1 and Group 2 states, goes in the opposite direction. By limiting potential trades to states within a group, EPA artificially reduces the number of potential market participants, and ignores the location of Group 1 and 2 states adjacent to each other. This artificial limitation on the size of the emissions trading market is further aggravated because the Group 2 states are not contiguous to each other in many cases. Because Group 2 states are scattered on the periphery of the Group 1 states, trading among Group 2 states is likely to be severely (and needlessly) limited. [EPA-HQ-OAR-2009-0491-2799.1, p.4]
To best improve air quality and public health, the Association suggest that EPA instead consider using a substantial fixed distance from electric generating units as the basis for trading. This will more closely reflect physical reality and facilitate trading on a predictable basis. Thus, this rule would be based on the physical aspects of particulates rather than the arbitrary political boundaries. While EPA may seek to use a standard distance around the country, it might also set a fixed distance applicable to each state, reflecting the average of weather conditions for that state. In that fashion, EPA would address the court's concern that emission reductions be tied to reductions of monitored air quality in downwind states. [EPA-HQ-OAR-2009-0491-2799.1, p.4]
Response: 
EPA's rationale for prohibiting trading between Group 1 and Group 2 SO2 states can be found in section VI.D of the preamble for the final Transport Rule.
Organization: Utility Air Regulatory Group (UARG)
Southern Company
Comment: 
Southern Company
B. EPA's Significant Contribution Analysis and Process to Classify Certain States as 'Group l' or 'Group 2' States is Inadequately Explained and Misguided
In the Proposed Transport Rule, EPA describes its process for classifying states as 'group 1' and 'group 2' states for PM2.5 as follows:
EPA used the air quality assessment tool to analyze the impact of requiring all states linked to the downwind state site with an air quality problem, as well as the downwind state, to reduce emissions consistent with the levels discussed for 2012 ... previously. The air quality assessment tool shows that those 2012 reductions will resolve the nonattainment and maintenance problems for all of the areas to which [certain] states [referred to as group 2 states] are linked . ... EPA also assessed whether, in 2014, the combination of this level of reduction from the group 2 states and the remaining states (referred to as group 1 states) continued to result in all downwind areas-except for Allegheny County, Pennsylvania-fully addressing their nonattainment [and/or] maintenance problems, and determined that it did. [EPA-HQ-OAR-2009-0491-2864.1, p. 28]
Conversations with EPA staff have revealed that, while not untrue, this description is incomplete and potentially misleading, especially with respect to the analysis that led to classification of the group 1 states. A representative of Southern Company contacted EPA's Clean Air Markets Division on September 3, 2010, and again on September 10, 2010, requesting clarification regarding how EPA classified individual states as group 1 or group 2 states. A representative of the Clean Air Markets Division explained the process as follows. [EPA-HQ-OAR-2009-0491-2864.1, p. 28]
EPA first determined which downwind monitors were classified as nonattainment and/or maintenance for PM2.5 based on the projected 2012 base case air quality, and then identified upwind states that were 'linked' to these monitors. This step in EPA's methodology determined which states were included in the Transport Rule for PM2.5, at least as group 2 states, based on their significant contribution to nonattainment or interference with maintenance. Next, EPA used its air quality assessment tool and the emission changes resulting from the 2014 cost curves to evaluate how air quality at the nonattainment and maintenance monitors would change in response to emission reductions from 'linked' upwind states, assuming a linear relationship between reductions in the upwind states' emissions and reductions in their respective contribution to projected ambient concentrations at the downwind monitors. EPA evaluated each monitor independently, considering only emission reductions from 'linked' upwind states and the state in which the monitor is situated. EPA found that the 24-hour PM2.5 NAAQS was controlling because most annual PM2.5 problems were resolved at relatively low dollars-per-ton thresholds, while 24-hour PM2.5 problems were more likely to persist at higher cost thresholds. EPA focused on the maintenance monitors and did not consider the nonattainment monitors separately because of the way that nonattainment and maintenance sites were determined. 28 [EPA-HQ-OAR-2009-0491-2864.1p. 29]
Using its air quality assessment tool, EPA determined that, in 2014, there were six monitors that still showed maintenance problems at approximately $300-400 per ton that, with the exception of one in Allegheny County, Pennsylvania, could be eliminated at $2,400 per ton or less. EPA then decided that the states linked to those six monitors that continued to have maintenance problems at higher dollar-per-ton levels should be required to make additional emission reductions and used the 2012 base case to determine which upwind states were 'linked' to those six remaining monitors. EPA classified upwind states linked to those six monitors as group 1 states and upwind states not linked to those six monitors as group 2 states. It appears that this was the sole determinant for classifying states as group 1. Strikingly, according to EPA's Clean Air Markets Division, in determining group 1 or group 2 status in 2014, EPA ignored the air quality benefits that would accrue in 2012 and 2013 from the emission reductions required by the Transport Rule in 2012 and from state rules and consent decrees that require emission reductions by 2014. [EPA-HQ-OAR-2009-0491-2864.1, p. 29]
This illogical decision not to consider the results of reductions required beginning in 2012 in projecting remaining maintenance problems in 2014 demonstrates a complete disconnect in the Agency's analysis. EPA characterizes its Proposed Transport Rule as having two 'phases.' 75 Fed. Reg. at 45215/3. It makes no sense to evaluate phase II of the proposal in isolation, ignoring the projected effects of phase I. EPA's approach is made worse by the Agency's decision to ignore the effects of CAIR for purposes of modeling. See section XI-A. Had EPA considered the emission reductions that would result from the 2012 CAIR compliance deadline, it is likely that the maintenance problems projected at most or all of these six monitors in 2014 would not have existed, even if the Agency had continued to ignore the effects of CAIR. Air quality has been improving steadily in recent years, and, consistent with that nationwide trend, 24-hour PM2.5 concentrations at all six of the monitors at issue show a strong downward trend. [EPA-HQ-OAR-2009-0491-2864.1, p. 29]
See Figure XI-1 [See EPA-HQ-OAR-2009-0491-2864.1, p. 36 for Figure.] showing the 98th percentile design values for 24-hour PM2.5 at these six monitors from 2003-2008 at Section XI-F. EPA should redo (as well as publish for public comment) its analysis of 2014 air quality by including consideration of the emission reductions required in 2012 under the proposed rule. A balanced analysis of this issue is likely to remove any justification for imposing more stringent S02 requirements on certain states in phase II of the program. [EPA-HQ-OAR-2009-0491-2864.1, p. 30] 
E. A Lower Cost Solution Appears Possible for PM2.5
It is unclear why EPA chose to drive to such a stringent 'remedy' when a lower cost solution appears possible for PM2.5. Using the AQAT, focusing on the 2012 cost curves, and assuming that local controls should bear some of the burden, it would appear that a similar air quality benefit could be achieved at between $200 and $400 per ton of S02. Table XI-3 below [See EPA-HQ-OAR-2009-0491-2864.1, p. 33 for the Table.] shows the results of these costs levels vs. the 2012 remedy. [EPA-HQ-OAR-2009-0491-2864.1, p. 33]
4. If EPA Deems It Necessary To Require 2012 Emissions Reductions Beyond CAIR, It Should Have Analyzed Air Quality Benefits Using the 2012 Emission Reduction Cost Curves
Once EPA established that nonattainment and maintenance could be achieved at all monitors in 2014 at $2000 per ton, it then considered what reductions could be achieved by 2012. EPA concluded that 'it is important to require all such reductions by 2012 to ensure that they are achieved as expeditiously as practicable.' CAIR was left in place by the Court and is achieving significant emissions reductions and air quality improvements (see Section XI-A). If EPA considered 2012 an important target date to achieve reductions beyond CAIR, it should have conducted an air quality analysis of air quality benefits that could be achieved by 2012 using the 2012 cost curves that were published in the Transport Rule. Using our replicated version of the AQAT, we found that, in 2012, Florida would have resolved all of its downwind PM2.5 linkages at $100 per ton, and Alabama would have resolved all of its downwind PM2.5 linkages at $200 per ton. This should have resulted in 2012 projected EGU budgets for these two states of 204,309 and 274,958 tons of S02, respectively. The proposed remedy budgets are 161,739 and 161,871 tons of S02 in 2012, which are overly and unnecessarily stringent to resolve the nonattainment and maintenance issues at the downwind receptors to which these two states are linked. [EPA-HQ-OAR-2009-0491-2864.1, p. 42]
 

Footnote 28:  As described above, EPA determined maintenance sites based on the future-year maximum PM2.5 design values, and nonattainment sites based on future-year five-year weighted average annual PM2.5 design values. Thus, all nonattainment sites were also maintenance sites. 75 Fed. Reg. at 45247. See Section XI-G for comments regarding the manner in which EPA determined maintenance sites.
 
 
 
 
 
 
Utility Air Regulatory Group (UARG)
The Process EPA Used To Classify Certain States as "Group 1" States Is Inadequately Explained and Misguided.
In the Proposed Transport Rule, EPA describes its process for classifying states as "group 1" and "group 2" states for PM2.5 as follows:
EPA used the air quality assessment tool to analyze the impact of requiring all states linked to the downwind state site with an air quality problem, as well as the downwind state, to reduce emissions consistent with the levels discussed for 2012 . . . previously. The air quality assessment tool shows that those 2012 reductions will resolve the nonattainment and maintenance problems for all of the areas to which [certain] states [referred to as group 2 states] are linked . . . . EPA also assessed whether, in 2014, the combination of this level of reduction from the group 2 states and the remaining states (referred to as group 1 states) continued to result in all downwind areas -- except for Allegheny County, Pennsylvania -- fully addressing their nonattainment [and/or] maintenance problems, and determined that it did. [EPA-HQ-OAR-2009-0491-2756.1, p.66]
75 Fed. Reg. at 45282/1-2. Conversations between UARG members and EPA staff have revealed that, while not untrue, this description is materially incomplete and potentially misleading, especially with respect to the analysis that led to classification of the group 1 states. A representative of Southern Company contacted EPA's Clean Air Markets Division on September 3, 2010, and again on September 10, 2010, requesting clarification regarding how EPA classified individual states as group 1 or group 2 states. A representative of the Clean Air Markets Division explained the process as follows. [EPA-HQ-OAR-2009-0491-2756.1, pp.66-67]
EPA first determined which downwind monitors were classified as nonattainment and/or maintenance for PM2.5 based on the projected 2012 base case air quality, and then identified upwind states that were "linked" to these monitors. This step in EPA's methodology determined which states were included in the Transport Rule for PM2.5, at least as group 2 states, based on their significant contribution to nonattainment or interference with maintenance. Next, EPA used its air quality assessment tool and the emission changes resulting from the 2014 cost curves to evaluate how air quality at the nonattainment and maintenance monitors would change in response to emission reductions from "linked" upwind states, assuming a linear relationship between reductions in the upwind states' emissions and reductions in their respective contribution to projected ambient concentrations at the downwind monitors. EPA evaluated each monitor independently, considering only emission reductions from "linked" upwind states and the state in which the monitor is situated. EPA found that the 24-hour PM2.5 NAAQS was controlling because most annual PM2.5 problems were resolved at relatively low dollars-per-ton thresholds, while 24-hour PM2.5 problems were more likely to persist at higher cost thresholds. EPA focused on the maintenance monitors and did not consider the nonattainment monitors separately because of the way that nonattainment and maintenance sites were determined. [EPA-HQ-OAR-2009-0491-2756.1, p.67]
Using its air quality assessment tool, EPA determined that, in 2014, there were six monitors that still showed maintenance problems at approximately $300-$400 per ton that, with the exception of one in Allegheny County, Pennsylvania, could be eliminated at $2,400 per ton or less. EPA then decided that the states linked to those six monitors that continued to have maintenance problems at higher dollar-per-ton levels should be required to make additional emission reductions, and EPA used the 2012 base case to determine which upwind states were "linked" to those six remaining monitors. EPA classified upwind states that, in the 2012 base case, were linked to those six monitors as group 1 states and classified upwind states not linked to those six monitors as group 2 states. It appears that this was the sole determinant for classifying states as group 1. Strikingly, according to EPA's Clean Air Markets Division, in determining group 1 or group 2 status in 2014, EPA ignored the air quality benefits that would accrue in 2012 and 2013 from the emission reductions required by the Transport Rule during those years and from state rules, consent decrees, and other requirements that will result in additional emission reductions by 2014. [EPA-HQ-OAR-2009-0491-2756.1, pp.67-68]
This illogical decision not to consider the results of reductions required beginning in 2012 in projecting remaining maintenance problems in 2014 demonstrates a complete disconnect in the Agency's analysis. EPA characterizes its Proposed Transport Rule as having two "phases." 75 Fed. Reg. at 45215/3. It makes no sense to evaluate phase II of the proposal in isolation, ignoring the projected effects of phase I (and other emission reduction requirements applicable in the period leading up to 2014). EPA's approach is made worse by the Agency's decision to ignore the effects of CAIR and local controls for purposes of modeling. See section VII.A supra and section VII.F infra. Had EPA considered the emission reductions that would result from the 2012 compliance deadline and other controls, it is likely that the supposed maintenance problems projected at most or all of these six monitors in 2014 would be shown not to exist, even if the Agency had continued to ignore the effects of CAIR. As these comments note above, air quality has been improving steadily in recent years, and, consistent with that nationwide trend, 24-hour PM2.5 concentrations at all six of the monitors at issue show a strong downward trend. See graph showing the 98th percentile design values for 24-hour PM2.5 at these six monitors from 2003-2008 at section VII.D supra. EPA should redo and publish for public comment its analysis of 2014 air quality by including consideration of the emission reductions required in 2012 and 2013 under the proposed rule and other applicable requirements. A balanced analysis of this issue is likely to remove any justification for imposing more stringent SO2 requirements on certain states in phase II of the program. [EPA-HQ-OAR-2009-0491-2756.1, pp.68-69]
Response: 
Section VI.D of the preamble for the final Transport Rule and the Significant Contribution and State Emissions Budgets Final Rule Technical Support Document detail the methods used and rational for determination of significant contribution to non-attainment and interference with maintenance, including determination of Group 1 and Group 2 states for the final Transport Rule.
Regarding the comment that "in determining group 1 or group 2 status in 2014, EPA ignored the air quality benefits that would accrue in 2012 and 2013 from the emission reductions required by the Transport Rule in 2012 and from state rules and consent decrees that require emission reductions by 2014" EPA does include emission reductions in 2014 from state rules and consent decrees that happened in 2012, 2013, and 2014.  EPA took comment on these emission reduction requirements and reflected them in the Air Quality modeling for the final Transport Rule and the application of AQAT for determining significant contribution.  Details on emissions inventories can be found in sections V and VI of the preamble for the final transport rule and in the Documentation Supplement for EPA Base Case v.4.10_FTransport  -  Updates for final Transport Rule.  Details on EPA's rationale and methods for determining Group 1 and Group 2 SO2 states can be found in section VI.D of the preamble for the final Transport Rule.
With respect to EPA's final determination of SO2 and NOX reductions under the final Transport Rule, details on the rationale and methods used can be found in sections V and VI of the preamble for the final Transport Rule.

IV.D.4.b. Modeling Methods/ Air Quality Assessment Tool/Results of Evaluation With Detailed Air Quality Model (CAMx)

Organization: American Forest & Paper Association (AF&PA)
Comment: 
American Forest & Paper Association (AF&PA)
Finally, we have concerns about the technical quality of the modeling used to support EPA's proposal, and in particular about EPA's decision to use AQAT rather than CAMX modeling. Those concerns are set out in more detail in a Technical Appendix. [EPA-HQ-OAR-2009-0491-2643.1, p.2]
D. AF&PA Supports CAMx Modeling as Superior to AQAT
For this rulemaking EPA has identified the Comprehensive Air Quality Model with Extension (CAMx) to assess ambient concentrations of ozone and PM2.5. CAMx, is among the 'one-atmosphere' Eulerian photochemical dispersion models that simulate regional to large-scale dispersion and the complex non-linear gas and particulate phase chemical and physical processes that govern the formation, transport and removal of secondary pollutants. In selecting CAMx for this assessment EPA recognizes that there is not a simple direct relationship between natural and anthropogenic emissions and these secondary pollutants. [EPA-HQ-OAR-2009-0491-2643.1, p.7]
Because this rulemaking required iterative simulations, EPA did not apply CAMx directly, citing the substantial level of effort, time and resources required for each CAMx simulation. Rather, the Air Quality Assessment Tool (AQAT) was developed with the objective of efficiently evaluating the effectiveness of multiple control strategies. In developing AQAT, CAMx was first applied to a base case in a source contribution mode to relate the contribution of EGU sources of NOx and SO2 in individual states to modeled ambient concentrations of ozone and PM2.5 at selected locations where ozone and PM2.5 NAAQS are presently exceeded. AQATs' formulation assumes that changes in emissions within a state will result in proportional changes in modeled concentrations according to the modeled relationships. Specifically, in AQAT:
:: A reduction in SO2 emissions leads to a proportional decrease in downwind PM2.5 sulfate contributions;
:: A reduction in NOx emissions leads to a proportional decrease in downwind PM2.5 nitrate contributions;
:: A reduction in NOx emissions leads to a proportional decrease in downwind ambient ozone concentrations [EPA-HQ-OAR-2009-0491-2643.1, p.7]
The chief limitations to AQAT is that it does not account for interactions that occur associated with the change in the mix of emissions and that the resolution of the interaction between emissions and ambient air quality are limited to the state level. Thus, AQAT incorporates an inherently incorrect assumption that the modeled ratio of a state's emissions to ambient concentrations is invariant even as the mix of emissions changes with each emissions control strategy evaluated. This type of simplified linear method can only be used to evaluate small perturbations in emissions necessary to evaluate the emissions reductions necessary to address very small margins of NAAQS non-compliance. If it is determined that PM2.5 and ozone concentrations will need to be reduced substantially, the magnitude of the projected necessary changes in emissions will result in complex non-linear pollutant interactions that will take effect such that the linearity assumptions inherent in AQAT are violated. [EPA-HQ-OAR-2009-0491-2643.1, p.8]
EPA's limited 2014 comparison of AQAT and CAMx simulations for 24-hour PM2.5 confirm the inaccuracy and bias in AQAT's estimation of the effectiveness of emission reductions. In an attempt to verify the viability of the AQAT application, EPA ran CAMx for the 2014 remedy scenario and compared results to the AQAT results for 24-hour PM2.5 concentrations at the nonattainment monitor locations. The comparison shows that AQAT at nearly all locations overestimated total reductions in PM2.5 concentrations relative to CAMx. The difference in the daily average design value between AQAT and CAMx was 5.7 μg/m3 or about 16% of the 35 μg/m3 NAAQS. [EPA-HQ-OAR-2009-0491-2643.1, p.8]
From this comparison it is apparent that AQATs assumption of linearity between changes in emissions and ambient concentrations of secondary pollutants is not well founded. CAMx explicitly accounts for interactions and nonlinearities in the atmospheric reactions. EPA conjectures that the degree to which AQAT overestimated the sensitivity of precursor emissions to ambient PM2.5 concentrations could be related in part to the seasonal differences in the response of sulfate concentrations to changes in SO2 emissions. It is also well-established that the NOx contribution to particulate nitrate is highly seasonally dependent and in competition with sulfate formation. Although EPA has not explicitly evaluated the adequacy of AQAT in developing the proposed rule, it is certain that AQATs assumption of linearity between NOx emissions has similar limitations. [EPA-HQ-OAR-2009-0491-2643.1, p.8]
It should be kept in mind that the noted deficiencies in AQAT are based not on observational evidence but on comparisons to CAMx, a model which itself has substantial, documented limitations in relating precursor emissions to secondary pollutant concentrations. The fact that AQAT substantially overestimates the improvement in daily average PM2.5 concentrations relative to CAMx indicates that EPA does not have an effective modeling tool upon which to develop national and regional emissions control strategies. The evidence provided by the CAMx-AQAT comparison is that AQAT as currently constituted is not sufficiently refined to provide accurate, unbiased projections of changes in secondary pollutant concentrations associated with various emission control strategies involving precursor emissions. [EPA-HQ-OAR-2009-0491-2643.1, p.8]
The inadequacy of the simplified AQAT approach makes it imperative that EPA develop a more refined approach to establish emission control strategies for this rulemaking. In Section IV.D.2. of the Rule, EPA requests comments on whether there are ways to use air quality modeling in conjunction with the air quality assessment tool to carry out the significant contribution analysis in a way that would not extend the time needed to complete this rulemaking and whether or not there are ways to improve the air quality assessment tool. There are a number of ways this may be accomplished. For instance, AQAT could be used as a starting point and then CAMx could then be applied directly to refine the strategies. Another approach would be to refine AQAT by developing a more robust multivariate tool based on a simplified parameterization developed based on CAMx sensitivity studies. While it is acknowledged that either approach will require additional time and resources, given that widespread emission reductions will be required under this rulemaking, it is mandatory that EPA apply the best available modeling technology. [EPA-HQ-OAR-2009-0491-2643.1, p.9]
Response: 
For the final Transport Rule, EPA made significant modifications and improvements to the development and use of AQAT.  Please refer to Section VI of the preamble for the final Transport Rule for more details.
Organization: Clean Air Task Force
Comment: 
Clean Air Task Force
Reasonable Determination of 'Significant Contribution' Requires Additional Reductions of Power Plant Emissions of SO2 and NOx.
EPA explains in the TR proposal that for reasons of administrative convenience it initially used a 'simplified air quality assessment tool, rather than actual air quality modeling, to identify air quality impacts of the options considered. However, EPA did follow up this simplified approach with more rigorous and refined air quality modeling of the selected emission budgets. This modeling produced different results, which raises several issues upon which EPA seeks comment. In essence, the refined modeling (CAMx) projected that a number of downwind areas would continue to experience nonattainment or maintenance problems with either the PM or ozone NAAQS, or both, even after implementation of the proposed TR. EPA indicates that it intends to conduct further analysis to determine whether additional reductions are necessary, and notes that it is committed to providing downwind states full relief from upwind emissions. We support EPA's stated intention in this regard, and submit that the court's opinion in North Carolina v. EPA requires no less. [EPA-HQ-OAR-2009-0491-2738.1, p.13; This comment can also be found at section IV.D.2 of this comment summary]
Response: 
For the final Transport Rule, EPA made significant improvements to the development and use of AQAT.  Please refer to Section VI of the preamble for the final Transport Rule for more details.  Additionally, as described in Section VI.D of the preamble for the final Rule, EPA finds that, for states covered by this rule for the 1997 annual PM2.5  NAAQS or the 2006 24-hr PM2.5 NAAQS, the annual NOX and SO2 reductions under the final Transport Rule successfully address significant contribution and interference with maintenance with respect to the NAAQS for which the state is covered.  Regarding the ozone standard, EPA believes it can best serve states with ozone non-attainment and maintenance problems by quickly finalizing this rule and seeking further ozone season NOX reductions as appropriate in subsequent rulemakings.  See final Transport Rule preamble section VI.D for more details about elimination of significant contribution.
Additionally, air quality modeling results provided in section VIII.B of the preamble for the final Transport Rule indicate that the final transport rule will resolve non-attainment with all PM2.5 standards for all receptors with the exception of 1 receptor with remaining non-attainment problems for the 24-hour PM2.5 standard in the Liberty-Clairton area--which EPA has noted is heavily influenced by a local source of organic carbon (75 FR 45281).  This modeling also indicates that only 1 area (Houston, TX) is expected to have remaining non-attainment problems for the ozone standard and only 1 area (Baton Rouge, LA) is expected to have remaining maintenance problems for the ozone standard.
Organization: Georgia Department of Natural Resources, Air Protection Branch
Comment: 
Georgia Department of Natural Resources, Air Protection Branch
Insignificance of NOx Emissions to Annual and Daily PM2.5 
EPA combined the modeled contributions of nitrate and sulfate from each state for the purpose of evaluating the interstate contributions to annual and daily PM2.5. The combined contribution from nitrate and sulfate were compared against specific threshold criteria (0.35 _g/m3 for daily PM2.5 and 0.15 _g/m3 for annual PM2.5). In order to justify annual state budgets for both SO2 and NOx, it should be demonstrated that SO2 and NOx individually are significant contributors. In some parts of the country (i.e., the Southeast U.S.), the contributions from SO2 are 10 to 100 times higher than the contribution from NOx. In these cases, there is no justification for setting annual NOx budgets based solely on the finding that SO2 is a significant contributor. Instead, SO2 and NOx need to be compared individually against the significance threshold criteria so that only the significant pollutants are targeted for controls. Also, it has been documented that controlling NOx year-round in the Southeastern U.S. vs. controlling NOx in the ozone season only may lead to HIGHER annual PM2.5 concentrations. [EPA-HQ-OAR-2009-0491-2647.1, p.3]
Based on an analysis of the nitrate source apportionment contributions presented by EPA in the Transport Rule Air Quality Modeling Technical Support Document, Georgia EPD believes that Georgia NOx emissions do not significantly contribute to daily PM2.5 or annual PM2.5 in nonattainment and maintenance areas outside Georgia. Therefore, only ozone season NOx budgets (not annual NOx budgets) should be developed for the states in the Southeastern U.S. [EPA-HQ-OAR-2009-0491-2647.1, p.3]
Georgia EPD analyzed the impact from the combination of NOx and SO2 (EPA approach) as well as NOx and SO2 individually on nonattainment and maintenance areas outside Georgia. EPA identified 147 monitors with a 2012 maximum projected design value above the current daily PM2.5 NAAQS of 35 _g/m3. Of those 147 monitors, the maximum impact from Georgia NOx was 0.0364 _g/m3, which is approximately 0.1% of the NAAQS. The EPA approach combined the impacts of SO2 and NOx and compared the combined impacts to 1% of the NAAQS (0.35 _g/m3). If the combined impacts were above 0.35 _g/m3, the upwind state was linked to the downwind monitor and targeted for emission reductions. This approach results in 18 monitors being linked with emissions in Georgia (see Table 1). It should be noted that the majority of the impacts are coming from SO2 (sulfate) and less than 10% of the total impacts are coming from NOx (nitrate). [[See Docket Number EPA-HQ-OAR-2009-0491-2647.1, p.4 for Table 1]] [EPA-HQ-OAR-2009-0491-2647.1, p.3]
EPA identified 50 monitors with a 2012 maximum projected design value above the current annual PM2.5 NAAQS of 15 _g/m3. Of those 50 monitors, the maximum impact from Georgia NOx (not including impacts on Georgia monitors) was 0.0159 _g/m3, which is approximately 0.1% of the NAAQS. The EPA approach combined the impacts of SO2 and NOx and compared the combined impacts to 1% of the NAAQS (0.15 _g/m3). If the combined impacts were above 0.15 _g/m3, the upwind state was linked to the downwind monitor and targeted for emission reductions. This approach results in 8 monitors (not including Georgia monitors) being linked with emissions in Georgia (see Table 2). It should be noted that the majority of the impacts are coming from SO2 (sulfate) and less than 4% of the total impacts are coming from NOx (nitrate). [[See Docket Number EPA-HQ-OAR-2009-0491-2647.1, p.4 for Table 2]]. [EPA-HQ-OAR-2009-0491-2647.1, p.4]
This analysis clearly demonstrates that the impacts of Georgia NOx emissions individually on daily and annual PM2.5 in neighboring nonattainment and maintenance areas is insignificant and annual NOx emissions budgets are not justified. [EPA-HQ-OAR-2009-0491-2647.1, p.5]
[[The above comments can also be found in Section IV.B.1.]]
Response: 
Please refer to Section V.A of the preamble for the final Transport Rule for a discussion about the topic of this comment.
Organization: Louisiana Chemical Association (LCA)
Comment: 
Louisiana Chemical Association (LCA)
EPA modeling shows that virtually the entire impact on PM2.5 annual levels at the Clinton Drive monitor are due to sulfate emissions. The following data, taken from EPA Preamble Tables IV.C-1, IV.C-3 and IV.C-5, and based on the IPM v.3.02 modeling, demonstrate that SO2 emissions from Louisiana will significantly decline, without enactment of the Transport Rule or a FIP: [EPA-HQ-OAR-2009-0491-3527.1, p. 10; see p. 11 for Table 1. SO2 Emissions in TPY-EPA IPM v3.02 Base Case Modeling.]
In summary, EPA's own modeling shows that without the Transport Rule/FIP, overall emissions of SO2 in Louisiana will decrease by 12,758 tpy from 2005 levels by 2012 and by 26,618 tpy from 2005 levels by 2014. As discussed above, Harris County, Texas is currently in attainment with the annual PM2.5 NAAQS and has a strong downward trend of PM2.5 emissions over the past several years. If Louisiana SO2 emissions are not causing interference with maintenance now, and are projected to have this significant of a decrease of SO2 without the Transport Rule, then it is not reasonable for EPA to conclude that Louisiana will interfere with maintenance of the PM2.5 standard in Harris County or that the Transport Rule/FIP is justified. If greater emissions are not affecting maintenance, then how can lesser emissions affe.ct maintenance? LCA believes that it would be arbitrary and capricious for EPA to arrive at this as a final conclusion. [EPA-HQ-OAR-2009-0491-3527.1, p. 11; see pp 12-14 for extensive discussion of this issue.]
Response: 
EPA's final Transport Rule modeling does not identify Louisiana as a state with emissions that for significantly contribute or interfere with maintenance of the 1997 annual or 2006 24-hour  PM2.5 standards.  See Section V and VI of the preamble for the final Transport Rule for more information.
Organization: Tennessee Department of Environment and Conservation, Division of Air Pollution Control
State of Missouri Department of Natural Resources
Northern Indiana Public Service Company (NIPSCO)
Group Against Smog and Pollution (GASP)
Comment: 
Group Against Smog and Pollution (GASP)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.200-201.]
CAMx modeling, which EPA admits is more accurate, shows that higher cost thresholds are needed for many regions to meet attainment for the 24-hour PM 2.5 standard.
We also support moving all states expected to have attainment issues under CAMx modeling from group two to group one, and adding Texas to group two. It makes little sense to have more accurate date from CAMx modeling not to use it.
Northern Indiana Public Service Company (NIPSCO)
In the proposed rule the EPA indicates the need to complete an analysis of wintertime particulate matter to appropriately address the wintertime 24-hr. PM 2.5 NMOS compliance issues. We recommend EPA complete its analysis of significant contribution and interference with maintenance for the 24-hour PM2.5 standard, and provide sufficient public notice and comment on the proposed remedy, for inclusion in the Transport Rule before finalizing the rule. This would further the ability of affected utilities to review the provisions and incorporate any additional or revised compliance requirements into system analysis and development of their overall compliance strategy. [EPA-HQ-OAR-2009-0491-2747.1 p.10]
State of Missouri Department of Natural Resources
In order for the Air Quality Assessment Tool (AQAT) to be convincing, it needs to show results for annual and 24-hour PM2.5 and ozone that are consistent with those of the refined modeling tools in the Comprehensive Air quality Model with extensions; (CAMX). The differing results for 24-hour PM2.5 from AQAT and CAMX calls into question the cost-per-ton analysis predictions. EPA should evaluate why AQAT gave inconsistent results as compared to CAMX before finalizing the rule. [EPA-HQ-OAR-2009-0491-3806, p.2]
EPA requests comments on whether the $2,000 per ton cost cutoff for SO2 should be raised, page 45283 . While all the reductions at $2,000 per ton may be achieved with the first Transport Rule, it would be appropriate to review a higher cost threshold with the second Transport Rule. Since the Integrated Planning Model analyses only allow for costs up to $2,500. per ton, EPA should find additional ways to analyze costs above that threshold. [EPA-HQ-OAR-2009-0491-3806, pp.2-3]
Tennessee Department of Environment and Conservation, Division of Air Pollution Control
Comment on Contributions to PM2.5 Nonattainment and Maintenance: EPA indicates that Tennessee's downwind contributions to PM2.5 nonattainment and maintenance are as follows: [See Docket Number OAR-2009-0591-0553.1, p.4 for the table]. We request that EPA review these values in light of our requested changes to the 2012 baseline. [EPA-HQ-OAR-2009-0491-0553.1, p.4]

 Footnote 1: Comments submitted by SESARM and supported by Tennessee noted that "EPA should incorporate into its revised CAIR rule the screening levels found in the original CAIR rule  -  2 parts per billion for ozone and 0.2 micrograms per cubic meter for PM2.5. These screening levels have been upheld by the Court and are practical to use.'
Response: 
For the final Transport Rule, EPA performed updated analyses using new CAMx modeling and significant improvements to AQAT.  Based on these new assessments, EPA identified states with emissions that significantly contribute to downwind non-attainment and maintenance problems and quantified the emission reductions necessary to address those contributions.  More information on these assessments can be found in Sections V and VI of the preamble for the final Transport Rule.
EPA updated the PM2.5 contribution modeling after incorporating a number of changes to the 2012 baseline.  These updates are discussed in Section V.C of the preamble for the final Transport Rule.
EPA made several improvements to AQAT for the final Transport Rule.  For details about AQAT and its ability to estimate similar air quality results to CAMx, please refer to section VI.C of the preamble for the final Transport Rule and the Significant Contribution and State Emissions Budgets Final Rule Technical Support Document.

With respect to the evaluation of SO2 costs for the final Transport Rule and EPA's determination of elimination of significant contribution, please refer to section VI of the preamble for the final rule.

EPA updated the methods used to assess significant contribution to non-attainment and interference with maintenance with respect to the 24-hour PM2.5 NAAQS.  For details on the methods used for the final Transport Rule, please refer to section VI of the preamble.
IV.D.4.c. Possible Emissions Increases in Non-covered States/ Should TX Be Included for PM2.5

Organization: Fond du Lac Reservation
National Tribal Air Association (NTAA)
Comment: 
Fond du Lac Reservation
Scope of the Transport Rule
Not only is the Band concerned with the potential impacts of the Transport Rule on Indian tribes in the eastern part of the nation, largely based on the incomplete technical and benefit analyses done by the EPA, we are equally concerned with how the Rule could impact tribes beyond the Eastern U.S. Our concern grows out of EPA's modeling, not as to how tribes were omitted, but how NOx and SO2 emissions could increase for those parts of the nation not covered by the Rule. [EPA-HQ-OAR-2009-0491-3707, p.3]
According to EPA's modeling, and as recently confirmed by Sam Napolitano, director of EPA's Clean Air Markets division, the demand for low sulfur coal will increase in the Eastern U.S. as sources in upwind states try to comply with their emission allocation budgets. As a result, higher sulfur coal will become more readily available and less expensive to purchase, likely encouraging sources in the Western and U.S. to retool their facilities so as to be able to use such coal at a lesser expense to them in the long run. This, in turn, could substantially and adversely impact the health and welfare of Indian tribes, many which occupy lands contiguous or close to a number of coal-fired power plants in the West. In fact, the EPA has already made it known that there could be an increase of more than 5,000 tons of SO2 emissions in North Dakota and South Dakota, states contiguous or near to a number of tribes, including Fond du Lac. [EPA-HQ-OAR-2009-0491-3707, p.4]
Because of this potential impact to Indian tribes beyond the region covered under the Transport Rule, the Band recommends that the EPA expand the scope of the Rule so as to cover the remainder of the nation as a means to prevent consequential increases in NOx and SO2 emissions due to the Rule's implementation. [EPA-HQ-OAR-2009-0491-3707, p.4]
National Tribal Air Association (NTAA)
Scope of the Transport Rule
Not only is the NTAA concerned with the potential impacts of the Transport Rule on Indian Tribes in the eastern part of the nation, largely based on the incomplete technical and benefit analyses done by the EPA, but our organization is equally concerned with how the Rule could impact Tribes beyond the Eastern U.S. Our concern grows out of EPA's modeling, not as to how Tribes were omitted, but how NOx and SO2 emissions could increase for those parts of the nation not covered by the Rule. [EPA-HQ-OAR-2009-0491-2778.1, p.4]
According to EPA's modeling, and as recently confirmed by Sam Napolitano, director of EPA's Clean Air Markets division, the demand for low sulfur coal will increase in the Eastern U.S. as sources in upwind states try to comply with their emission allocation budgets. As a result, higher sulfur coal will become more readily available and less expensive to purchase, likely encouraging sources in the Western U.S. to retool their facilities so as to be able to use such coal at a lesser expense to them in the long run. This, in turn, could substantially and adversely impact the health and welfare of Indian Tribes, many which occupy lands contiguous or close to a number of coal-fired power plants in the West. In fact, EPA has already made it known that there could be an increase of more than 5,000 tons of SO2 emissions in North Dakota and South Dakota, states also contiguous or near to a number of Tribes. [EPA-HQ-OAR-2009-0491-2778.1, p.4]
Because of this potential impact to Indian Tribes beyond the region covered under the Transport Rule, the NTAA recommends that the EPA expand the scope of the Rule so as to cover the remainder of the nation as a means to prevent consequential increases in NOx and SO2 emissions due to the Rule's implementation. [EPA-HQ-OAR-2009-0491-2778.1, p.4]
Response: 
See section XII.J of the preamble for a detailed discussion of potential emission changes in states not covered by the final Transport Rule based on EPA's updated modeling. The final modeling does not show the potential SO2 emissions increases in North Dakota and South Dakota that were seen in the modeling at proposal.
See sections V and VI of the preamble to the final rule for a detailed discussion of the analyses that determined the final rule's geographic coverage. Also see section III.E of this RTC document for a discussion of why the rule addresses the eastern portion of the United States.
See sections III and XII.J in the final rule's preamble, and sections III.F, XII.E, and XIX of this RTC document, for discussions of other regulatory actions that will impact power sector emissions.
See sections V and VI of the preamble to the final Transport Rule and section IV of this RTC document for discussion of EPA's technical analysis in developing this rule.  See section XIII of the preamble to the final rule, the Regulatory Impact Analysis (RIA), and sections IX and XX.D of this RTC for further information on benefits.
Organization: National Association of Clean of Air Agencies (NACAA)
Clean Air Task Force
Calpine Corporation
Group Against Smog and Pollution (GASP)
Pew Environment Group
Comment: 
Calpine Corporation
By not including Texas in the PM2.5 (annual) program the proposed rulemaking will significantly degrade air quality in that state. [EPA-HQ-OAR-2009-0491-3614, p.3]
EPA Should Include Texas in the Annual Program 
EPA predicts that SO2 emissions in Texas will increase by over 100,000 tons per year if the state is not included in the annual SO2 and NOx trading programs in the proposed rulemaking. Calpine is a significant generator of electricity in Texas (over 7,000 megawatts of capacity) and our corporate headquarters is in Houston, Texas. Calpine has invested in advanced air pollution controls at its Texas plants and we believe that EPA has a responsibility not to enact rules that would degrade air quality in Texas. Calpine urges EPA to include Texas in the annual program. [EPA-HQ-OAR-2009-0491-3614, pp.4-5]
Clean Air Task Force
Furthermore, power plants in five states 32 that are in EPA's 37 state study region but outside of the proposed control region are projected to increase emissions following implementation of the rule, as they will be subject only to the much weaker Title IV acid rain restrictions. In fact, the increase in Texas is large enough to cause it to become a significant contributor (under the Agency's proposed 1% NAAQS threshold test) to downwind PM nonattainment and maintenance problems. [EPA-HQ-OAR-2009-0491-2738.1, p.7; This comment can also be found at section III.D and IV.B.2 of this comment summary]
[These comments were also submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.107.]
Geographical Coverage of the Proposed Emission Caps.  
The geographical scope of the proposed TR must be expanded. There are two separate but inter-related problems with the current proposal.  First, EPA's choice of a 1.0% NAAQS threshold for determining significant contribution is too high, and should be reduced by at least half to 0.5%. Second, EPA's analysis of the air quality impacts of its TR proposal projects that EGUs in five states will increase their SO2 emissions. As a result, the amount of downwind contribution from Texas will exceed EPA's 1% NAAQS threshold for significant contribution, and that of Arkansas and North Dakota will also exceed our recommended reduced significant contribution threshold of no more than 0.5% of the applicable NAAQS. [EPA-HQ-OAR-2009-0491-2738.1, p.21; For additional comments pertaining to Geographical Coverage of the Proposed Emission Caps see pages 21-22 of this comment]  
The second problem with the geographical area proposed to be covered by the TR is that EGU emissions in five states not subject to the rule are projected by EPA to increase. For example, Texas SO2 emissions are expected to increase by over 130,000 tons, producing downwind air quality impacts that will exceed EPA's proposed 1% NAAQS threshold for significant contribution. Therefore, whether or not EPA lowers its proposed significant contribution threshold, Texas must be included in the TR control region for SO2 and NOx. [EPA-HQ-OAR-2009-0491-2738.1, p.22]
[These comments were also submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.109.]
We also note that EPA did not evaluate many states in the western US for their potential contribution to ozone and PM2.5 nonattainment problems, but that emissions in Colorado may also increase as a result of the TR. 130 We believe that, for all future transport rulemakings, EPA should analyze the contribution of all 48 states in the continental US, and require emission reductions from any state whose emissions are found to contribute to downwind nonattainment in excess of the minimum threshold. [EPA-HQ-OAR-2009-0491-2738.1, p.22]  

Footnote: 32 These five states are TX, AR, MS, ND and SD. 75 Fed. Reg. at 45284.  
Group Against Smog and Pollution (GASP)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.194.]
adding Texas to group 2.
National Association of Clean of Air Agencies (NACAA)
Inclusion of Texas in SO2 Control Program
NACAA recommends that Texas be included in the SO2 control program as a group 2 state. As EPA notes in the proposal, EPA's analysis shows that if Texas is not included in the SO2 control program, Texas' SO2 emissions would increase the state's contribution to an amount that would exceed the threshold for annual PM2.5 (thus exceeding the threshold for inclusion in the SO2 program). 10 Since implementation of the Transport Rule program changes Texas from a state whose contribution to annual PM2.5 does not exceed EPA's threshold to a state that does, EPA must proactively address the impacts that naturally flow from the Transport Rule and include Texas in the Transport Rule, so that the Transport Rule does not cause Texas to violate section 110(a)(2)(D) of the Act. [EPA-HQ-OAR-2009-0491-2771.1, p.6]
Pew Environment Group
EPA's modeling shows that even after the proposed rule is implemented: power plants in several states that are outside of the proposed control region will increase emissions following implementation of the rule, as they will be subject only to the much weaker Title IV acid rain restrictions; in fact, the increase in Texas is large enough to cause it to become a significant contributor to downwind nonattainment. [EPA-HQ-OAR-2009-0491-2703.1 p.2]
Response: 
EPA's analysis for the final rule identifies Texas as a state with emissions that significantly contribute to nonattainment or interfere with maintenance of the 1997 PM2.5, 2006 PM2.5, and 1997 ozone NAAQS in other states.  Texas is required, under the final rule, to reduce ozone season NOx emissions due to its significant contribution to nonattainment and interference with maintenance of the 1997 ozone NAAQS.  It is also required, under the final rule to reduce annual NOx and annual SO2 emissions due to its significant contribution to nonattainment and interference with maintenance of the 1997 PM2.5 NAAQS.
In further response to Clean Air Task Force, EPA's rationale for the choice of the air quality threshold is given in preamble section V.D.1.  EPA also notes the suggestion about evaluating the effects of future rulemakings in all of the continental states.
Organization: NRG Energy
Gulf Coast Lignite Coalition
Texas Mining and Reclamation Association
Comment: 
Gulf Coast Lignite Coalition
 GCLC also requests that EPA not include Texas in the Group 2 SO2 reductions program, based on an assumption that Texas will become reliant on a market of cheaper coal with a higher sulfur content. EPA should not require compliance with a new emission reduction program based on speculation instead of facts. [EPA-HQ-OAR-2009-0491-2734.1 p.4]
NRG Energy
The appropriate exclusion of Texas from the Transport Rule's SO2 Annual program EPA has requested comment on whether Texas should be included as a Group 2 state. EPA expresses concern regarding the potential increase in SO2 emissions in Texas if the state exclusion is in place. NRG understands that the majority of coal units in Texas utilize low sulfur coal, typically western sub-bituminous coal. In our experience, the use of a different, higher sulfur fuel would likely violate current operating permits and/or trigger both state and federal new source permitting requirements. Under this scenario, best available control technology requirements inherent with air quality permitting would preclude emission increases resulting from fuel switching. Consequently, NRG believes that EPA's projected modeled SO2 emission increase for Texas is not realistic and that EPA should not include Texas as a Group 2 state. [EPA-HQ-OAR-2009-0491-2749.1, p. 3]
Texas Mining and Reclamation Association
GCLC also requests that EPA not include Texas in the Group 2 SO2 reductions program, based on an assumption that Texas will become reliant on a market of cheaper coal with a higher sulfur content. EPA should not require compliance with a new emission reduction program based on speculation instead of facts. [EPA-HQ-OAR-2009-0491-2734.1 p.4]
Response: 
EPA considered all comments on and updated emission information, air quality information and modeling assumptions as appropriate in response to comments submitted on the proposed rule and subsequent NODAs, including assumptions about the use of coal as it was modeled in both the base case and in the remedy case.  The final modeling identified Texas as a state with emissions that significantly contribute to nonattainment or interfere with maintenance of the 1997 annual and the 2006 24-hr PM2.5 NAAQS in other states.  No states were shown to contribute above the threshold level in the remedy case modeling done for the final rule.
Organization: San Miguel Electric Cooperative, Inc.
Comment: 
San Miguel Electric Cooperative, Inc.
EPA has requested comment on whether Texas should be included in the SO2 controls program (75FR45284). 'Further analysis with the air quality assessment tool indicates that these projected increases in the Texas SO2 emissions would increase Texas's contribution to an amount that would exceed the 0.15 ug/m3 threshold for annual PM2.5. For this reason, EPA takes comment on whether Texas should be included in the program as a group 2 state.' [EPA-HQ-OAR-2009-0491-2641.1,p.5]
San Miguel believes that Texas should not be included in the SO2 controls program under the proposed rule. According to EPA data, the electric power industry in Texas already has made significant progress in reducing emissions in nitrogen oxides (NOx) and sulfur dioxide (SO2) even as Texas has consumed more energy and the economy has grown. Texas is already leading the way in clean electric generating units and should not be penalized for its successful emissions reductions. Inclusion of Texas in the SO2 controls program could force many EGUs to switch coals or from coal to some other type of fuel, jeopardizing fuel diversity. That in turn, would decrease the reliability of electricity, increase the cost of electricity, increase the frequency and intensity of natural gas shortages, and increase the price of natural gas. Another result is that it would produce severe, negative impacts on the economy of the State of Texas, and particularly in areas of the state (such as some locations of east and central Texas) whose primary economy is based on coal-fired electric generation and coal mining. [EPA-HQ-OAR-2009-0491-2641.1, p.5]
One of the concerns of the EPA is that units not in the SO2 control program will switch to a higher sulfur fuel. San Miguel as outlined in the introduction fires only lignite provided by the mine-mouth lignite mine. The unit was designed to burn this fuel and would require extensive modifications to switch to a sub-bituminous coal. Also San Miguel does not have a railroad coal delivery system. Thus a different fuel cannot be burned without significant modifications to the unit, at a cost estimated at over eighty million dollars. [EPA-HQ-OAR-2009-0491-2641.1,p.5]
San Miguel believes that Texas should not be included in the SO2 controls program. [EPA-HQ-OAR-2009-0491-2641.1, p.5]
Response: 
EPA considered all comments on and updated emission information, air quality information and modeling assumptions as appropriate in response to comments submitted on the proposed rule and subsequent NODAs, including assumptions about the use of coal as it was modeled in both the base case and in the remedy case.  The final modeling identified Texas as a state with base case emissions that significantly contribute to nonattainment or interfere with maintenance of the 1997 annual and the 2006 24-hr PM2.5 NAAQS in other states.  No states were shown to contribute above the threshold level in the remedy case modeling done for the final rule.
In EPA's emissions modeling for the final rule, the San Miguel unit has access only to lignite coal supply.  San Miguel burns 100% lignite coal in the final rule's base case 2012 and 2014 modeling, as shown in the IPM run titled "TR_Base_Case_Final" parsed for 2012 and 2014.  The unit also burns 100% lignite coal in the modeling of the final Transport Rule remedy, as shown in IPM run "TR_Remedy_Final" parsed for 2012 and 2014.  The IPM runs are available in the docket and on the Transport Rule website (epa.gov/airtransport).
See section VIII in the preamble to the final Transport Rule and the Regulatory Impact Analysis (RIA) for economic impacts of the rule.  See the Resource Adequacy and Reliability in the IPM Projections for the Transport Rule TSD in the docket for impacts to electric reliability.
EPA had requested comment at proposal on whether Texas should be included in the SO2 controls program (75FR45284). 'Further analysis with the air quality assessment tool indicates that these projected increases in the Texas SO2 emissions would increase Texas's contribution to an amount that would exceed the 0.15 ug/m3 threshold for annual PM2.5. For this reason, EPA takes comment on whether Texas should be included in the program as a group 2 state. [EPA-HQ-OAR-2009-0491-2641.1,p.5]
Organization: Texas Chemical Council
Comment: 
Texas Chemical Council
I. Texas Should Not Be Subject to the Transport Rule
TCC strongly maintains that Texas should not be subject to the Transport Rule because EPA's reasoning for including Texas in the rule proposal is fundamentally flawed. EPA states in the preamble that one of its key guiding principles in establishing the rule was to appropriately identify necessary upwind reductions. 75 Fed. Reg. at 45,226. Specifically, EPA states: [EPA-HQ-OAR-2009-0491-2815.1, p.1]
"Emissions from upwind states can, alone or in combination with local emissions, result in air quality levels that exceed the NAAQS and jeopardize the health of residents in downwind communities. Each upwind state is required by the "good neighbor provision" to eliminate its individual significant contribution to downwind state nonattainment and to eliminate emissions that interfere with downwind states" maintenance of air quality standards." 75 Fed. Reg. at 45,226. [EPA-HQ-OAR-2009-0491-2815.1, pp.1-2]
Texas emissions do not contribute to downwind nonattainment or maintenance interference for the 1997 8-hour ozone standard, the 2006 PM2.5 annual standard or the 2006 PM2.5 24-hour standard. In the proposal, EPA asserts that Texas should fall under the rule because emissions from Texas contribute to the downwind nonattainment of Baton Rouge, Louisiana under the 8-hour ozone standard. 75 Fed. Reg. at 45,269. EPA has made a fatally flawed linkage between Texas emissions and Louisiana air quality based on its own final determination on September 9, 2010 that Baton Rouge, Louisiana is in attainment with the 8-hour ozone standard. 75 Fed. Reg. 54,778  -  54,779 (Sept. 9, 2010). [EPA-HQ-OAR-2009-0491-2815.1, p.2]
In addition, EPA's 8-hour ozone contribution modeling in this instance unjustly assigned fault to Texas where Baton Rouge's air quality is concerned. Considering the dramatic improvements in air quality achieved by Texas in the last 15 years, Texas fits squarely within the "good neighbor provision," as evidenced by EPA's recent determination that Baton Rouge has reached attainment with the 8-hour ozone standard, and should be exempt from the rule proposal altogether. Texas' "good neighbor" status is also underscored by EPA's recent determination that the Beaumont-Port Arthur (BPA) area is in attainment in with the 1997 8-hour ozone standard and the state's request to EPA for a determination that the HGB area is also in attainment with the 1997 8-hour ozone standard. Accordingly, Texas should not be subject to the Transport Rule. [EPA-HQ-OAR-2009-0491-2815.1, p.2]
Response: 
See section V of the preamble to the final rule for a detailed discussion of EPA's conclusion that emissions from Texas significantly contribute to nonattainment or interfere with maintenance of the relevant NAAQS in other states.  Also see sections IV.C, IV.C.1 through IV.C.5, and XV of this RTC document for further information, including discussion of the modeling linking emissions from Texas to Baton Rouge, LA.
Organization: Texas Commission on Environmental Quality
Xcel Energy Inc.
Association of Electric Companies of Texas (AECT)
Luminant
Comment: 
Association of Electric Companies of Texas (AECT)
AECT does not see the need to include Texas in the SO2 controls program under the proposed rule and we support the exclusion of Texas from the SO2 controls program under the proposed rule. [EPA-HQ-OAR-2009-0491-3351.1, p.2]
Texas Should Not be Included in the SO2 Program as a Group 2 State
In the development of the proposed rule, EPA evaluated whether the rule could cause changes in the operation of EGUs not regulated under the proposal and whether such changes would cause emission increases resulting in downwind ambient air impacts above the 1 percent contribution threshold. EPA's modeling indicated that the proposed rule could affect the relative price of lower and higher sulfur coal. The modeling also projected that these fuel price effects could lead to greater use of higher sulfur coal in Texas, increasing annual SO2 emissions in Texas by 136,000 tons over the base case. EPA has requested comment on whether Texas should be included as a Group 2 state. [EPA-HQ-OAR-2009-0491-3351.1,p.2]
The majority of coal units in Texas utilize low sulfur coal, typically Powder River Basin (PRE) subbituminous coal. The use of a different, higher sulfur fuel would likely trigger both state and federal new source permitting requirements and the best available control technology requirements inherent with air quality permitting would preclude emission increases resulting from fuel switching. Consequently, AECT believes that EPA's projected modeled SO2 emission increase for Texas is not realistic and that EPA should not include Texas as a Group 2 state. [EPA-HQ-OAR-2009-0491-3351.1, p.2]
SO2 Emissions from Power Plants in Texas Have Declined and Air Ouality has Improved
Electric generating units (EGUs) in Texas have already achieved significant reductions in SO2 emissions over the past several years. According to the Acid Rain score-card data for 2009, the average SO2 emissions rate (in lb/mmBtu) for EGUs in Texas was only about two-thirds of the average SO2 emissions rate for EGUs in the rest of the country. [EPA-HQ-OAR-2009-0491-3351.1,p.2]
Effectiveness of Existing SO2 Control Programs
The entire state of Texas is currently in attainment with the existing SO2 and Particulate Matter 2.5 (PM2.5) standards. [EPA-HQ-OAR-2009-0491-3351.1, p.2]
EGUs in Texas have been making SO2 emission reductions for decades, all while meeting Texas' and the nation's ever-increasing demand for electricity. SO2 emissions control programs related to EPA's Acid Rain program and the state Senate Bill 7 program are examples of the SO2 emission reduction programs already in place and being implemented by EGUs. While these SO2 emission reductions have provided environmental benefits, they have cost electricity consumers billions of dollars. [EPA-HQ-OAR-2009-0491-3351.1,p.3]
Texas EGUs have one of the highest SO2 scrubbed capacities in the nation. Nearly half of the coal-fired generation capacity in Texas has flue gas desulfurization systems, and several companies that have completed or are constructing new units have made commitments to offset or more than offset the SO2 and NOx emissions from the new units. In addition, units in Texas consume over 62 million tons of low-sulfur PRB coal annually.[EPA-HQ-OAR-2009-0491-3351.1, p.3]
AECT is concerned that due to Texas EGUs' high current SO2 scrubbed capacity, and significant use of low- sulfur PRB, that inclusion of Texas in the SO2 controls program under the proposed rule would make it very difficult for Texas EGUs to be able to further reduce their S02 emissions and require controls at higher cost than other states for no commensurate environmental benefit. Texas is a competitive market for electricity. Prohibitively high cost of controls would lead to several significant problems, such as the forced retirement of viable and wellcontrolled EGUs and/or fuel switching from native Texas coal to more imported coal or natural gas. Such problems would negatively impact the electric reliability that is needed to meet Texas' large and ever increasing electricity demand. AECT is concerned that such problems would adversely affect Texas, while only providing little, if any, environmental or public health benefit. [EPA-HQ-OAR-2009-0491-3351.1,p.3]
Twelve percent of electricity that is generated in Texas is generated using native Texas coal, which is an amount equal to the electricity generation of the entire state of Wisconsin.  The total economic impact of coal-fired EGUs and coal mining in Texas (according to a 2004 report) is very significant - accounting for almost $10,500,000,000 in annual total expenditures and over 33,000 permanent jobs. [EPA-HQ-OAR-2009-0491-3351.1,p.3]
Texas is already leading the way in clean electric generating units and should not be penalized for its successful emissions reductions. Inclusion of Texas in the SO2 controls program would force many EGUs to switch from coal to some other type of fuel, jeopardizing fuel diversity. That, in turn, would decrease the reliability of electricity, increase the cost of electricity, increase the frequency and intensity of natural gas shortages, and significantly increase the price of natural gas. Another result is that it would produce severe, negative impacts on the economy of the State of Texas, and especially in part of the state (such as parts of East Texas) whose primary economy is based on coal-fired electric generation and coal mining. [EPA-HQ-OAR-2009-0491-3351.1,pp.3-4]
For the foregoing reasons, AECT strongly supports Texas exclusion from the SO2 controls program under the proposed rule. [EPA-HQ-OAR-2009-0491-3351.1,p.4]
Luminant
:: EPA correctly determined that Texas should not be included in the annual SO2 program.
o Seventy-two percent of Luminant coal-fired generation capacity has flue gas desulfurization systems, and approximately 50 percent of the coal-fired capacity in Texas has such systems. Other units are using low-sulfur subbituminous coal.
o Sulfur dioxide emissions from Electric Generating Units (EGUs) in Texas have already been reduced sixteen percent since the baseline modeling year used in the rule (2005) and will continue to decline. Several companies that have completed or are constructing new units have made commitments to offset or more than offset the sulfur dioxide and nitrogen oxides emissions from the new units. [EPA-HQ-OAR-2009-0491-2729.1, p.2]
II. Luminant Supports the Decision to Exclude Texas from the Annual SO2 and NOx Programs
The CATR Integrated Planning Model (lPM) base case shows that Texas will not significantly contribute to any PM2.5 nonattainment areas and thus, is not included in either the NOx or SO2 annual CATR programs. Luminant supports EPA's decision not to include Texas in the annual programs. Texas led the way in reductions of NOx in the United States, with a 2003 power plant average NOx rate of 0.142 lb/mmBtu. In 2009, this Texas average was 0.098 lb/mmBtu while the national average was 0.160 lb/mmBtu. [EPA-HQ-OAR-2009-0491-2729.1, p.5]
On page 45284 of the proposed rule, EPA expresses some concern that Texas' SO2 emissions will significantly increase if it is not included in the Group 2 SO2 program. Luminant believes that this concern is unfounded. Coal-fired units in Texas are of newer vintage than those in the CATR program region. Out of roughly 23,000 megawatts of coal-fired capacity in Texas, about half, or 11,500 megawatts, has flue gas desulfurization (FGD) systems. The other units combust subbituminous coal, or a blend of subbituminous coal and Gulf Coast lignite. Approximately 72% of Luminant's coal-fired generation capacity has FGD systems. Several of the companies constructing new coal-fired units have committed to offsetting the new emissions or even reducing emissions beyond previous fleet emissions. Since the modeling base case year of 2005, Texas coal-fired units have reduced their SO2 emissions by 16% and Luminant believes that this downward trend will continue because of these commitments, permit restrictions, and contracts for subbituminous coal. [EPA-HQ-OAR-2009-0491-2729.1, p.5]
Texas Commission on Environmental Quality
The TCEQ objects to the EPA proposing a rule that might apply to Texas at finalization (i.e. whether to include Texas in the Transport Rule FIP as a Sulfur Dioxide (S02) Group 2 State for fine particulate matter (PM2.5)) without providing adequate notice and information necessary for evaluation and comment. Further, the TCEQ disagrees with the EPA's conclusions that predict as likely a substantial increase in S02 emissions in Texas as support for such consideration. [EPA-HQ-OAR-2009-0491-2857.1, p.2]
Request for Comment on Including Texas in the Transport Rille FIP as an S02 Group 2 State for PM2.s (75 FR 45284)  
The TCEQ strongly objects to the EPA proposing a rule that might apply to Texas at finalization without providing adequate notice and information necessary for comment in the proposal.
The EPA's request for comment on this issue as well as other language in the preamble (75 FR 45359) indicates that Texas could be made subject to the S02 Group 2 Trading Program at finalization of the current proposal rather than at finalization of a future proposal. The current proposal of the Transport rule does not provided adequate information for the TCEQ and other affected entities to comment regarding whether or not Texas should be included in the rule for PM2.5. Annual S02 budgets, new unit set-aside, and variability limits for Texas are not provided in the proposal; therefore, the TCEQ and other affected entities cannot adequately comment as to the potential implications of including Texas under this portion of the proposed rule. If the EPA wanted to consider including Texas in the S02 Group 2 Trading Program because of assumed future concerns with PM2.5 then the EPA should have proposed the rule in that manner or proposed an alternative that included Texas so that affected entities would be given adequate notice to comment. Further, any inclusion of Texas in the PM2.5 program should be proposed with an adequate rationale and evidence supporting the need for this inclusion. If the final rule does include Texas in the S02 Group 2 Trading Program at adoption of this rulemaking, potentially regulated entities would have been denied the opportunity to comment on the adequacy of the S02 budgets, new unit set-aside, and variability limits. [EPA-HQ-OAR-2009-0491-2857.2, p.9]
While the TCEQ generally agrees that the implementation of environmental regulations might impact fuel costs, the TCEQ disagrees with the EPA's conclusion that the 802 emissions in Texas will substantially increase as predicted by the EPA's models.
The EPA's request for comment concerning whether. Texas should be included in the ru1e for PM2 .5 is based on the EPA's prediction that S02 emissions in Texas will increase by 136,000 tpy above the base case if the Transport Rule is implemented. This assumed spike in S02 emissions is based on the EPA's models projecting that the rule might increase the cost of low sulfur coal and decrease the cost of high sulfur coal, and that this projected cost shift might cause sources in states not covered in the rule for PM2 .5 to switch to high sulfur coal. However, the EPA's prediction appears to be based solely on a hypothetical market analysis and ignores factors that would restrict the use of high sulfur coal. [EPA-HQ-OAR-2009-0491-2857.2, pp.9-10]
Comparison of the base case and controlled case IPM data files indicates that the EPA is predicting that only certain coal-fired units, approximately 40 percent of the units in Texas, will experience this assumed shift to high sulfur coal. However, the TCEQ has not been able to identify any specific reason or logical pattern in the proposal as to why the EPA believes these particular units win switch to high sulfur coal. Because the EPA is considering including Texas in the S02 Group 2 Trading Program based on the predicted changes for these units, the EPA should provide clear and specific reasons for why these units are expected to change to high sulfur coal. [EPA-HQ-OAR-2009-0491-2857.2, p.10]
Many of the coal-fired utility units in Texas that the EPA assumes win have substantial S02 emission increases have permit provisions that set specific S02 pound per million British thermal unit (lb/MMBtu) emission specifications or low percent sulfur coal content limits that would prohibit the fuel switching to high sulfur coal that the EPA is predicting. One of the facilities that the EPA predicts to have more than a 15,000 tpy increase in S02 emissions will actually have a 27,547 tpy reduction in S02 emissions as a result of an enforceable site cap on S02 emissions that will go into effect in October 2012. The EPA should not ignore these other restricting factors when considering the possible future S02 emissions. [EPA-HQ-OAR-2009-0491-2857.2, p.10]
Given the recent finalization of the S02 NAAQS and the stringency of that standard, it is highly unlikely that any coal-fired power plant would pursue a permit modification that would result in a significant increase in S02 emissions. The rPM upon which this projected sulfur increase is based clearly does not even appropriately consider the EPA's own regulations. [EPA-HQ-OAR-2009-0491-2857.2, p.10] 
The TCEQ's quick review of the rPM parsed base case files indicates that the EPA has not properly characterized the current fuel mix for the coal-fired utility units in Texas or that the EPA is assuming a significant shift in coal fuel mix is going to occur in Texas prior to the predicted shift to high sulfur coals. Four of the facilities identified by EPA as being 100 percent subbituminous are lignite or lignite-blend units. This indicates that the base assumptions the EPA has used in its base case modeling are in error, and thus, any modeled predictions for future coal fuel use are questionable and cannot be used as a rational basis for decisionmaking. [EPA-HQ-OAR-2009-0491-2857.2, p.10]
Xcel Energy Inc.
III. STATES INCLUDED AND EXCLUDED FROM THE PROPOSED RULE
1. EPA should not include Texas in the SO2 trading program.
Xcel Energy opposes including Texas in SO2 Group 2 or Group 1. As EPA it self indicates in the CATR preamble, the modeling data does not support inclusion of Texas in the SO2 programs. Texas' emissions do not contribute to downwind nonattainment above the thresholds established in the proposed rule. [EPA-HQ-OAR-2009-0491-2728.1, p.7]
EPA is considering including Texas in the Group 1 or Group 2 SO2 trading program not because of its air quality impacts, but because its models show that, as a result of the Transport Rule, more eastern utilities would likely turn to lower sulfur western coal, causing Texas utilities to shift to coals with higher sulfur content. EPA apparently is considering including Texas in the SO2 trading program because it does not wish to see any SO2 emissions increase in Texas regardless of the impact on air quality. We strongly oppose this approach, for the following reasons: [EPA-HQ-OAR-2009-0491-2728.1, p.7]
- EPA's evidence for emissions increase - the results of an IPM model run - does not reflect the real world of utility operations. In fact, it is much more difficult to switch fuels than the model implies. The decision regarding which coal to use in a boiler is driven by a number of factors, including price, availability, transportation, boiler configuration, long-term contracts, and permit emission limits. The IPM model cannot account for these factors. In fact, most utilities have units designed for a specific fuel type supplied through long-term contracts for at least some of their' portfolio. They cannot and will not easily change to a higher sulfur fuel. [EPA-HQ-OAR-2009-0491-2728.1, p.7]
- The majority, of coal units in Texas utilize low sulfur coal, typically western subbituminous coal. The use of a different, higher sulfur fuel would likely trigger both state and federal new source permitting requirements and the best available control technology requirements inherent with air quality permitting would preclude emission increases resulting from fuel switching. Consequently, as indicated in its testimony, the Association of Electric Companies of Texas ('AECT') believes that EPA's projected modeled SO2 emission increase for Texas is not realistic and that EPA should not include Texas as a Group 2 state. We support AECT's position. [EPA-HQ-OAR-2009-0491-2728.1, p.7]
- EPA has no basis under this rule to cap SO2 emissions in Texas. As its name implies, the Transport Rule is designed to protect downwind air quality from pollution transported across state lines. EPA's own analysis shows that it has no basis for limiting SO2 from Texas for this purpose. [EPA-HQ-OAR-2009-0491-2728.1, p.7]
- EPA and Texas already have authority to limit SO2 emissions to address air quality within the state. If Texas emission limits are too high to protect air quality within cities like Dallas and Houston in the state, the state can impose new limits under Section 110 of the Clean Air Act without relying on the Transport Rule. [EPA-HQ-OAR-2009-0491-2728.1, p.7]
- EPA should not dictate fuel supply policy for companies. Speculative considerations of potential changes to coal contracts are not appropriate rationales for major expansions of air regulator), programs. EPA does not have the expertise or regulatory mandate to analyze coal markets, and should not engage in imposing pre-emptive regulation for problems that do not currently exist. [EPA-HQ-OAR-2009-0491-2728.1, pp.7-8]
For these reasons, EPA should not include Texas in the CATR SO2 program. [EPA-HQ-OAR-2009-0491-2728.1, p.8]
Response: 
As discussed in sections III, V, and VI of the preamble to the final Transport Rule, EPA has updated and improved the modeling inputs and platforms used to identify states with contributions to downwind nonattainment or maintenance receptors that meet or exceed the 1% air quality thresholds in the 2012 base case.  These updates -- which include a number of updates to the modeling inputs for Texas -- were made based on public comments received on the proposed rule and the subsequent notices of data availability (NODAs) and other standard updates.
In the proposed rule, EPA requested comment on whether Texas should be included in the Transport Rule for annual PM2.5.  EPA's analysis for the proposal showed that emissions in Texas would significantly contribute to nonattainment or interfere with maintenance of the annual PM2.5 NAAQS in a downwind state if Texas were not included in the rule for fine particles.  In contrast to the analysis at proposal, the updated modeling conducted for the final rule supports EPA's conclusion that in the base case, Texas significantly contributes to nonattainment or interferes with maintenance of the 1997 PM2.5 NAAQS in another state.  Thus, Texas is required in the final rule to reduce annual SO2 emissions (as a Group 2 state) and annual NOx emissions to eliminate its significant contribution to nonattainment and interference with maintenance, based on its emissions in the base case.
Certain commenters questioned EPA's determination in the proposal that projected SO2 emissions in Texas would increase enough to trigger the air quality threshold if the state is not covered by the Transport Rule SO2 program.  EPA notes that Texas is included in the final rule as a result of the state's contributions to downwind receptors in the updated base case modeling, thus, the comments on whether SO2 emissions in Texas might increase if the state were not covered (as was projected in the modeling for the proposal) are no longer relevant.
Based on a careful review of public comments  on the emissions inventories and modeling,  EPA updated input data and assumptions for Texas units in the final rule, including restricting the coal choice in 2012 where EPA received information indicating that short-term factors (e.g., coal contracts and boiler engineering considerations) limited a unit's choice to a particular assigned coal.  EPA imposed limits on the fuel assignments at four Texas coal steam plants (Big Brown, Limestone, Martin Lake, and Monticello) to increase consistency with reported fuel use at the plants.  For further information about these updates see section 9.3.11, "Short-term restrictions on coal choice and related issues" in the IPM documentation in the docket ("Documentation Supplement for EPA Base Case v.4.10_FTransport  -  Updates for Final Transport Rule").  Also see the IPM documentation for a summary of EPA's modeling of state EGU emission reduction requirements (including, e.g., Senate Bill 7, as referenced by an above commenter).
EPA has identified 10 facilities in Texas that were burning lignite fuels in 2010.  Of these, 6 were burning 100% lignite, and 4 were blending lignite and subbituminous.  EPA modeling shows the 6 lignite only units continue to burn 100% lignite in both base case and policy case modeling.  EPA models no coal switching at these facilities.  Additionally, of the 4 units that reported lignite and sub-bituminous blending to EIA for 2010, two units are projected to blend these types of coal in the EPA modeling of the Transport Rule policy scenario, and the other two units are projected to switch to 100 percent sub-bituminous to achieve cost-effective emission reductions.  EIA fuel use data reported by these two sources over the past 10 years demonstrates a steady increase in their subbituminous use, providing historic evidence that is consistent with the economic projections in EPA's modeling.
With respect to the comment about SO2 permit limits, EPA notes that its IPM modeling includes SO2 permit limits as inputs for the individual generating units (see "NEEDS v.4.10_FTransport" available in the docket).  
With respect to the comment about analyzing coal markets, EPA notes that the Agency conducts periodic independent formal peer review of IPM covering the model itself and key modeling input assumptions, including separate panels of independent experts who review the model's coal supply and transportation assumptions, natural gas assumptions, and model formulation.  In addition to formal peer review, the rulemaking process offers opportunities for expert review and comment by operators of the electricity sector that is represented in IPM, stakeholders affected by the policies being modeled, and developers of other models of the U.S. electricity sector.  This feedback provides a highly detailed public review of data inputs, assumptions, model representation, and model results.
With respect to the comment regarding SO2 emission reductions that have occurred in Texas "since the modeling base case year of 2005" EPA notes that we analyzed each state's contributions to downwind air quality problems based on a projected future 2012 base case (not a 2005 base case) that includes reductions since 2005.  As discussed in section V.C.2 of the final rule preamble, EPA used 2012 base case modeling to identify future nonattainment and maintenance locations and to quantify the contributions of emissions in upwind states to annual and 24-hour PM2.5 and 8-hour ozone in downwind states.  (For the reasons discussed in section V.B of the preamble, the 2012 base case does not include CAIR-specific emissions reductions.)  EPA agrees with the commenter that Texas EGUs have reduced their SO2 emissions since 2005.  According to EPA's Acid Rain Program (ARP) database, EGUs in Texas emitted about 535,000 tons of SO2 in 2005, while EPA's projected 2012 base case EGU emissions for Texas are about 446,000 tons (roughly 16% lower).  EPA also notes that its projected 2012 base case EGU SO2 emissions are lower than recent historical emissions in Texas as shown in the following table: 
                    Texas EGU SO2 Emissions (Thousand Tons)
                                2008 Emissions
                                2009 Emissions
                                2010 Emissions
                             2012 Final Base Case
                                      484
                                      454
                                      461
                                      446
The Transport Rule's interstate trading programs with assurance provisions provide regulatory flexibility that promotes the power sector's ability to operate as an integrated, interstate system and to provide electric reliability.  The final rule does not dictate the compliance choices of individual plants.  EPA performed a sensitivity analysis that shows that Texas can sustain the operation of lignite mines and the provision of lignite coal to Texas EGUs while still cost-effectively meeting the Transport Rule's emission reduction requirements (see section V.C.2 of the preamble for further discussion of this analysis).  Comments about potential impacts of the Transport Rule to electric reliability are addressed in section V.D.2.g in this RTC and the "Technical Support Document on Resource Adequacy and Reliability in the Transport Rule" in the docket.  Regarding the comment about benefits and economic impacts of the Transport Rule, see sections VIII and XII of the preamble and see the Regulatory Impact Analysis (RIA).
EPA provided a full opportunity for comment on whether Texas should be included in the annual NOX and annual SO2 programs in the Transport Rule based on its significant contribution to nonattainment or interference with maintenance of the 1997 annual PM2.5 NAAQS in other states.  Indeed, any argument that the parties could not have anticipated EPA's ultimate decision to include Texas in the rule based on its significant contribution with respect to the 1997 PM2.5 standards is refuted by the fact that EPA explicitly requested comment on this issue. See 75 FR 45284.
It is well established that a final rule need not be identical to the proposed rule.  It need only be a "logical outgrowth" of the proposed regulations.  See Small Refiner Lead Phase-Down Task Force v. EPA, 705 F.2d 506, 546-47 (D.C. Cir. 1983).  As the court has long recognized, a contrary approach would lead to the absurd result that "the agency can learn from the comments on its proposal only at the peril of starting a new procedural round of commentary," International Harvester Co. v. Ruckelshaus, 478 F.2d 615 (D.C. Cir 1973).  The notice and comment process does not begin anew each time a proposed rule is changed in response to public comments on a proposal.  Notice is the primary consideration used by the courts to determine whether a proposed rule requires a supplemental proposal. To determine if a final rule is a logical outgrowth of a proposal, courts look to whether "interested parties `should have anticipated' that the change was possible and thus reasonably should have filed their comments on the subject during the notice-and-comment period." CSX Transp. Inc. v. Surface Transportation Board, 584 F.3d 1076 (D.C. Cir 2009) (internal citations omitted).  "'[A] final rule represents a logical outgrowth where the NPRM expressly asked for comments on a particular issue or otherwise made clear that the agency was contemplating a particular change.'" International Union v. Mine Safety and Health Administration, 626 F.3d 84 (D.C. Cir 2010) (internal citations omitted).  

In this instance, EPA explicitly asked for comments on the issue in question.  EPA explicitly notified the public in the proposal that it was considering including Texas in the Transport Rule annual programs as a group 2 state, and requested comment on that issue.  Then, in the final rule, EPA decided to do what it had told the public, in the proposal, that it was considering.  Specifically, in the proposal, EPA noted that its analysis for the proposal indicated that projected increases in Texas SO2 emissions associated with implementation of the Transport Rule (e.g, as a result of fuel switching associated with changes in the price of low verses higher sulfur coal) would cause Texas's contribution to exceed the threshold for annual PM2.5.  It then explicitly requested comment on "whether Texas should be included in the program as a group 2 state."  75 FR 45284.  The analysis for the final rule, then demonstrated that emissions in Texas significantly contribute to nonattainment and interfere with maintenance in another state even in the base case.  In other words, even without any increases in Texas emissions associated with implementation of the Transport Rule in other states, emissions in Texas are significantly contributing to nonattainment and maintenance problems downwind.  For this reason, EPA decided to do what it requested comment on.  That is, it decided to include Texas in the annual programs as a group 2 state.  For these reasons, EPA's inclusion of Texas in the final rule based on its significant contribution and interference with maintenance with respect to the annual PM2.5 NAAQS is a logical outgrowth of the proposal.

The fact that the proposal did not include illustrative annual NOX and annual SO2 budgets for Texas does not change this conclusion.  In the proposal, EPA clearly identified and took comment on a methodology for identifying and quantifying emissions within a state that significantly contribute to nonattainment or interfere with maintenance downwind.  EPA also clearly identified the states for which it would be doing such analysis, and it identified and took comment on the data inputs to be used in the calculation.  EPA received numerous comments on the methodology, including comments from TCEQ and sources in Texas.  EPA also received numerous comments on and corrections to Texas-specific data.  EPA refined its methodology and data inputs in response to public comments.  The illustrative budgets provided in the proposal merely demonstrated the outcome of applying the proposed methodology to the data inputs used for the proposal.  Adjustments were made to all states budgets and the allowance allocations for all states between proposal and final.  EPA provided an ample opportunity to comment on the methodology and data inputs to be used to calculate states' significant contribution, and explicitly provided notice that it was considering including Texas in the final rule due to its impact on downwind nonattainment and maintenance problems with respect to the 1997 PM2.5 NAAQS.  For these reasons, EPA's determination that Texas must be included in the annual programs because of these impacts is a logical outgrowth of the proposal.

IV.D.4.d. Other Comments On Application of Approach to Fine Particles (PM2.5)

Organization: Nebraska Public Power District
Omaha Public Power District
Comment: 
Nebraska Public Power District
11) Significant Impact Levels. EPA's current TR proposal would set significant contribution levels for PM2.5 substantially lower than the "significant impact levels" (SILs) it has already proposed for modeling of individual sources (Federal Register, September 21, 2007). The prior rule proposal provides three options for an annual average PM2.5 SIL: 1.0, 0.8 or 0.3 μg/m3, and three options for a 24-hour average PM2.5 SIL: 5.0, 4.0, and 1.2 μg/m3. It is not reasonable to use a lower SIL for modeling impact contributions of entire states in the TR, than for individual sources in a permitting context. We recommend that EPA stay consistent with the prior rule proposal, and use a TR significance level for individual states no higher than the lowest proposed SILs (0.3 μg/m3 for annual averages and 1.2 μg/m3 for 24-hour averages). [EPA-HQ-OAR-2009-0491-2711.1, p.8]
Omaha Public Power District
EPA's current TR proposal would set significant contribution levels for PM2.5 substantially lower than the 'significant impact levels' (SILs) it has already proposed for modeling of individual sources (Federal Register, September 21,2007). The prior rule proposal provides three options for an annual average PM2.5 SIL: 1.0, 0.8 or 0.3 ug/m3, and three options for a 24-hour average PM2.5 SIL: 5.0, 4.0, and 1.2 ug/m3. It is not reasonable to use a lower SIL for modeling impact contributions of entire states in the TR, than for individual sources in a permitting context. We recommend that EPA stay consistent with the prior rule proposal, and use a TR significance level for individual states no higher than the lowest proposed SILs (0.3 ug/m3 for annual averages and 1.2 ug/m3 for 24-hour averages). [EPA-HQ-OAR-2009-0491-2680.1, pp. 5-6]
Response: 
As discussed in Section V.D of the preamble for the final Transport Rule, EPA determined that it is inappropriate to compare the thresholds for significant contribution under the final Transport Rule against "significant impact levels" which serve a different purpose.  EPA made this determination previously and it can be found in 70 FR 25101; May 12, 2005.
Organization: New York State Department of Environmental Conservation
Comment: 
New York State Department of Environmental Conservation
Furthermore, as noted in the proposal, the highest particulate nitrate concentrations in the East tend to occur in cooler months and regions. New York is concerned with EPA's inability to adequately determine the impact of NOx and ammonia on wintertime ambient PM levels as these represent a substantial amount of the PM2.5 found in the East in cooler months. A summertime-only focus could result in the failure to cost-effectively address wintertime based PM2.5 nonattainment caused by transport. [EPA-HQ-OAR-2009-0491-2730.1, p.7]
Response: 
For the final Transport Rule, for reasons more fully described in Section VI of the preamble for the final Transport Rule, EPA was able to use CAMx modeling to evaluate ammonia emissions, NOX reductions, and formation of the nitrate component of PM2.5.  Therefore, with respect to EPA's ability to adequately determine the impact of NOX and ammonia on wintertime ambient PM levels, EPA believes that it is employing the best modeling capabilities available for the final Transport Rule.  Additionally, as described in Section VI.C of the preamble for the final Transport Rule, EPA made substantial improvements to AQAT to specifically address the seasonality of PM2.5 non-attainment and maintenance.  Finally, as described in Section VI.D of the preamble for the final Transport Rule, EPA finds, for the states covered by this rule for the 1997 PM2.5  NAAQS or the 2006 PM2.5 NAAQS, that the annual NOX and SO2 reductions under the final Transport Rule successfully address significant contribution to nonattainment and interference with maintenance with respect to the NAAQS for which they are covered.
IV.D.5. [Reserved]

IV.D.5.a. Specific Application of Overall Approach to Ozone: EGU Cost Curves/ Air Quality Assessment (AQAT)/ Cost Thresholds

Organization: Environmental Defense Fund (EDF)
Comment: 
Environmental Defense Fund (EDF)
This recommendation reflects the general principle that results from the CAMx air quality model should be given precedence over the less reliable results from the simplified model. While the air quality assessment tool is a useful device for exploring potential regulations, there is no justification for using it as the basis for the actual rule given the contrary evidence from the more sophisticated modeling.  Moreover, EPA's estimated cost curves, developed using the IPM model, show that significant further reductions in SO2 emissions can be made at electric generating units at costs between $2,000 and $2,400 per ton. [EPA-HQ-OAR-2009-0491-2834.1 p.7]
Response: 
EPA made several improvements to AQAT for the final Transport Rule.  For details about AQAT and it's ability to estimate similar air quality results to CAMx, please refer to section VI.C of the preamble for the final Transport Rule and the Significant Contribution and State Emissions Budgets Final Rule Technical Support Document.
With respect to SO2 emission reductions available and various costs and how those reductions factored into EPA's determination of NOx and SO2 costs under the final Transport Rule, please refer to section VI of the preamble for the final rule.
Organization: Texas Commission on Environmental Quality
Clean Air Task Force
Maryland Department of Environment (MDE)
New York State Department of Environmental Conservation
Comment: 
Clean Air Task Force
With respect to ozone, EPA should raise the $500/ton minimum cost threshold in the Transport Rule proposal for requiring ozone season NOx reductions, keeping in mind that EPA found in the 1998 NOx SIP Call that a cost threshold of up to $2000/ton (in $1990; the equivalent of approximately $3200 in $2006) of NOx removed was highly cost-effective. 35 [EPA-HQ-OAR-2009-0491-2738.1, p.8]
[These comments were also submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.108-109.]
Over a decade ago, in the 1998 NOx SIP Call, EPA found that NOx reductions of up to an average cost of $2000/ton (in $1990) of NOx removed were highly cost-effective; this cost threshold is the equivalent of approximately $3200 in $2006. 100 EPA determined the $2000/ton average cost figure based on "NOx emissions controls that are available and of comparable cost to other recently undertaken or planned NOx measures." 101 However, EPA claims in the instant rulemaking that it will be difficult to require additional NOx reductions (i.e., reductions beyond those resulting from a $500/ton marginal cost threshold) without causing unacceptable delay in the finalization of the TR, noting that, unlike the case with SO2 controls, NOx controls for other source categories are available at costs between $500 and $3200/ton. 102 [EPA-HQ-OAR-2009-0491-2738.1, pp.17-18]
Furthermore, as discussed above in connection with SO2, 105 and in note 80 [See EPA-HQ-OAR-2009-0491-2738.1, p.14 for comments pertaining to footnote 80] and accompanying text, actual NOx emissions in 2009 from EGUs in sixteen states were already below their proposed TR NOx state caps. Here too, the TR would allow these states to increase their NOx emissions from current levels. This should not be permitted, and increasing the cost threshold for NOx reductions is one way to address this problem. [EPA-HQ-OAR-2009-0491-2738.1, p.18]    
In view of the foregoing, we urge EPA to raise the NOx cost threshold uniformly 106 to at least $3200/ton and to include, at minimum, EGUs, large boilers, large stationary combustion engines and cement kilns in the TR FIPs. [EPA-HQ-OAR-2009-0491-2738.1, p.18]     
Reductions in power plant NOx emissions in the 90% range are also feasible using selective catalytic reduction (SCR) technology. SCR technology for NOx control, although more recent than FGD control for SO2, is also in widespread use in the utility industry and is reliable and effective. EPA reports that "[o]perating data available from many plants indicate that the 90% NOx removal rate has been met or exceeded at these plants." And a 2001 report by the Northeast States for Coordinated Air Use Management (NESCAUM) stated: "Recent experience with actual SCR installations and vendor representations concerning expected system performance suggest that future SCR installation -- especially when coupled with advanced low-NOx burner technology -- can be expected to consistently deliver reductions in excess of 90 percent." [EPA-HQ-OAR-2009-0491-2738.1, p.19; For additional comments pertaining to Tighter Control on Regional Power Plant Emissions are Feasible and can be Implemented without Threatening the Economy or the Electric Power System see pages 19-21 of this comment]    
Specifically, EPA determined in the NOx SIP Call that "highly cost-effective" controls were those that "achieve the greatest feasible emissions reduction but still cost no more than $2000 per ton of ozone season NOx emissions removed (in 1990 dollars), on average." NOx SIP Call, 63 Fed. Reg. at 57399.     
We note that EPA primarily based its determination of "highly cost-effective" controls in the NOx SIP Call on average costs rather than incremental or marginal costs used by EPA in the proposed TR. Thus, the equivalent marginal cost in $2006 of those controls found highly cost effective in the NOx SIP Call would be significantly higher than $3200/ton.    
The $500/ton ozone season NOx marginal cost cut-off should also be raised to at least $3200/ton.    
For reasons similar to those discussed above in connection with annual NOx, the cost threshold for ozone season NOx reductions should also be raised. EPA's CAMx modeling shows not only that a number of downwind areas will continue to have nonattainment and maintenance problems with respect to the PM NAAQS, but also that several areas will have similar problems with the ozone NAAQS. Specifically, remaining ozone problem areas include Houston, Baton Rouge and New York City. 107 States linked to those problem areas include Alabama, Arkansas, Florida, Georgia, Illinois, Kentucky, Louisiana, Mississippi, Tennessee and Texas, as well as Connecticut, Delaware, Indiana, [EPA-HQ-OAR-2009-0491-2738.1, p.18] Maryland, New Jersey, North Carolina, Ohio, Pennsylvania, Virginia, West Virginia and Michigan -- that is, all but five of the states in the proposed TR. 108    
For the reasons stated above with respect to annual NOx, 109 EPA should adopt a cost threshold for determining ozone season NOx reductions at a level no lower than $3200/ton in $2006, and should require NOx reductions from EGUs, large boilers, large stationary combustion engines and cement kilns. EPA should also apply this higher cost threshold on a uniform basis for all covered sources in all contributing states in the TR, for the reasons stated earlier in connection with SO2 reductions. 110  [EPA-HQ-OAR-2009-0491-2738.1, p.19]    
Footnote:  

Specifically, EPA determined in the NOx SIP Call that "highly cost-effective" controls were those that "achieve the greatest feasible emissions reduction but still cost no more than $2000 per ton of ozone season NOx emissions removed (in 1990 dollars), on average." NOx SIP Call, 63 Fed. Reg. at 57399.   
We note that EPA primarily based its determination of "highly cost-effective" controls in the NOx SIP Call on average costs rather than incremental or marginal costs used by EPA in the proposed TR. Thus, the equivalent marginal cost in $2006 of those controls found highly cost effective in the NOx SIP Call would be significantly higher than $3200/ton.   
106 For the reasons stated earlier in connection with SO2 emissions, EPA should establish a single cost threshold for NOx, and not establish different "groups" of states with different reduction requirements.  
Maryland Department of Environment (MDE)
Cost Thresholds and Cost-Effectiveness  
In the proposed rule EPA suggests that a generic $500 per ton level represents the appropriate cost threshold for NOx reductions that can be achieved by 2012. Maryland sees at least two major problems with this presumption. First, using this cost threshold for NOx suggests that emission reductions above this level are not "cost effective" for the purposes of the proposed Transport Rule. Second, EPA uses this cost threshold in its rationale for foregoing the option of proposing a second phase of higher cost threshold NOx controls in 2014 in the proposed rule. Maryland urges EPA to revise its approach to determining the appropriate NOx controls in the proposed Transport Rule that are feasible to implement by 2014 and that will eliminate significant contribution and interference with maintenance for the 1997 ozone standard. [EPA-HQ-OAR-2009-0491-2639.2, p.4]
Maryland disagrees with EPA's assignment of a simple $500/ton cost-effectiveness threshold in the proposed Transport Rule, especially when our own state is already enacting NOx control measures at significantly higher costs. Further, EPA states in the proposed Transport Rule that the reductions achieved at this cost threshold will not eliminate significant contribution or interference with maintenance for eleven states linked to ozone air quality problems in New York City. This not only sets a dangerous precedent that the proposed Transport Rule does not have to fully achieve its primary mission, but it also leaves the downwind nonattainment area with the requirement to meet its attainment requirements with controls starting at over many times the cost per ton used in the proposed Transport Rule. Maryland believes that EPA's proposed dollar-per-ton cost thresholds are too low; they do not to capture all realizable cost effectiveness, and more importantly, they do not accurately reflect the cost associated with the emissions reductions required for each individual upwind state to eliminate its significant contribution and interference with maintenance. [EPA-HQ-OAR-2009-0491-2639.2, p.4]
Maryland encourages EPA to consider all transported and local pollution affecting an area on an equal cost per ton of control basis. Due to limited options for further reducing air pollution to meet the ozone and particulate matter NAAQS, Maryland and states across the OTR have been compelled to consider measures as high as $2,000 - $80,000 per ton of NOx controlled. [EPA-HQ-OAR-2009-0491-2639.2, pp.4-5]
Where significant contributions are not eliminated by the EPA proposal, Maryland believes that it is reasonable to require controls that reflect much higher costs than cited in EPA's proposed Transport Rule. This is especially true in the case of EGUs near the border of another state. Where a significantly contributing EGU is the primary cause of a violation of a NAAQS, the unit must reduce its emissions sufficiently to eliminate that violation. Maryland believes that the use of a dollar per ton cost threshold to determine emissions controls is inappropriate in this situation. The use of a dollar per ton threshold might be appropriate in order to call for more control than would otherwise be required to meet the receiving states emission limits, especially where a contributing state is not itself requiring available control technologies on its EGU sources.  [EPA-HQ-OAR-2009-0491-2639.2, p.5]
New York State Department of Environmental Conservation
To fully eliminate significant contribution and interference with maintenance by upwind states, EPA must require a second phase of ozone season NOx reductions from states that are linked to the New York, Houston, and Baton Rouge areas. EPA successfully used its authority to delineate a group of states from which further S02 emission reductions will be required in 2014 ('While we continue to believe that under certain circumstances it may be appropriate for us to use a single uniform cost per ton threshold to quantify significant contribution for all states, we believe it is also important to retain the flexibility to use multiple cost thresholds' (75 FR 4527)). A similar course of action is logical and necessary for ozone season NOx emissions. [EPA-HQ-OAR-2009-0491-2730.1, p.6]
EPA's Cost Effectiveness Thresholds
EPA states that it 'intends to proceed with additional rulemaking to address fully the residual significant contribution to nonattainment and interference with maintenance with the ozone standard as quickly as possible,' and that it is 'expeditiously conducting further analysis of NOx control costs, emissions reductions, air quality impacts, and the nature of the residual air quality issues' (75 FR 45213). New York believes that a greater cost threshold must be set for ozone-season NOx controls. While the $500 per ton value in the proposed rule was established only to maintain the operation of already installed SCR units, the large NOx emission reductions that will be required will necessitate the actual installation of new control equipment. Additionally, section 110(a)(2)(D) does not restrict EPA to regulation of the power sector alone; non-EGU stationary sources are some of the biggest emitters of NOx (and S02) in the region. These units would greatly benefit from emissions controls and such reductions would aid in solving the residual effects from upwind states. The cost effectiveness of combustion controls from non-EGUs is often in the range of $500 to $1,000 per ton of NOx removed and, therefore, would be cost effective for reducing and/or eliminating transported air pollution. It is certainly reasonable to require more effort from upwind states than the current $500/ton threshold requires, particularly when downwind states such as New York have required NOx emissions reductions at values up to ten times of this amount and more for purposes of attaining the NAAQS. EPA's statement that its methodology 'assumes controls at the same cost per ton level in the downwind state as in the upwind contributing states,' (75 FR 45272), is therefore not borne out in reality. [EPA-HQ-OAR-2009-0491-2730.1, p.12]
Enforcing a cut-off of only $500/ton is unfair to facilities that have already installed controls, which end up footing the burden for upwind reductions (however inadequate), while those that have gone uncontrolled in the past continue to have no control requirements under this low threshold. EPA's basis for costs, then, should not be limited to the operation of existing controls when additional controls can be put in place for costs that are very close to $500 per ton. This is especially important given that EPA has not set budgets in upwind states at levels that adequately address SC/IM for all areas, including New York City. [EPA-HQ-OAR-2009-0491-2730.1, p.12]
EPA also notes that 'a downwind state must adopt controls to demonstrate timely attainment of the NAAQS despite any pollution transport from upwind states that is not eliminated under section 110(a)(2)(D)' (75 FR 45271). EPA has introduced a qualifier into its section [EPA-HQ-OAR-2009-0491-2730.1, p.12] 110(a)(2)(D) responsibilities, however, in that only transported emissions that can be eliminated through 'cost-effective controls' are actually prohibited. In other words. NOx emissions that cost more than $500/ton to remove will still be allowed to impact downwind ozone nonattainment areas such as the New York metropolitan area. The downwind states cannot ignore these emissions simply because the cost of eliminating the emissions would exceed the costeffectiveness threshold determined by EPA. The downwind state has to account for local emissions in addition to these residual transported emissions, which can lead to inequities in allocating the responsibility for reaching attainment. [EPA-HQ-OAR-2009-0491-2730.1, p.13]
As further evidence of our concerns with EPA's budget and allocations. in examining the data in the tables in Section IV of the proposed Transport Rule, it is apparent that some states (AL. AR, GA, LA, MI, OK and TX) are allocated near their base case emissions and significantly over the emissions associated with a $500 per ton level-- while other states (CT, DE, DC, IL, MD, NJ, NY, NC, TN and VA) are allocated budgets that are lower than the emissions associated with a $5,000 per ton cost. Also, it should be noted that the $5,000 per ton level of emissions for Illinois is higher than those at the $500 per ton level (please explain this error). EPA states in the proposed Transport Rule that, for states linked to ozone air quality problems in Houston or Baton Rouge, EPA has not yet identified a final cost threshold for eliminating significant contribution. EPA does, however, propose to find that those states (AL, AR, FL, GA, IL, KY, LA, MS, TN, and TX) must make at least all of the NOx reductions that can be achieved for $500 per ton in 2012. The Department questions how the allocation of extra NOx allowances beyond the $500 per ton threshold to states whose significant contributions to those two cities have not been eliminated (in AL, AR, GA, LA and TX) fits with this statement. The Department also questions why many other states, including New York, are allocated fewer allowances. [EPA-HQ-OAR-2009-0491-2730.1, p.13]
Texas Commission on Environmental Quality
The TCEQ disagrees with the EPA's assumed $500 per ton cost effectiveness calculation for NOx reductions from EGUs in Texas and believes this amount to be based on an assumption of an uncontrolled baseline. Texas, however, has implemented substantial NOx controls on new and existing EGU facilities, and as a result, the TCEQ believes the EPA's cost assumptions to underestimate the true cost effectiveness of a control strategy. [EPA-HQ-OAR-2009-0491-2857.1, p.2]    
EGU NOx Controls    
The TCEQ disagrees with the EPA's assumed $500 per ton cost effectiveness for NOx reductions from EGUs in Texas. Despite the volume of discussion regarding cost that the EPA provided in the Technical Support Documents, the TCEQ has be unable to identify any substantive detail in the docket on how the EPA actually determined the threshold. The Technical Support Documents and preamble of the propose rule indicate that this control level is based on the installation of low NOx burners or similar NOx control techniques and not on the installation of new selective catalytic reduction (SCR) systems. The TCEQ agrees with the EPA that installation of new SCR systems could not be achieved by 2012. However, the TCEQ does not agree that significant ozone season NOx reductions, approximately 12,000 tons (75 FR 45268), can be achieved at the EPA's assumed $500 per ton cost effectiveness value. Based on prior experience with EPA cost effectiveness approaches, the TCEQ suspects this cost effectiveness threshold for low NOx burners is based on assuming an uncontrolled baseline and applying this cost effectiveness to any case that the technology is applied, regardless of the starting control level. The TCEQ has found this approach unreliable and typically underestimates the true cost effectiveness of a control strategy. The cost effectiveness on a cost per ton of pollution reduced basis for a control strategy should be based on actual costs and actual reductions to account for the incremental cost effectiveness of implementing reductions from one controlled level to another. While the EPA's assumption about a $500 per ton cost effectiveness might be valid for states that have implemented little or no EGU NOx control strategies in the past, it is certainly not valid for Texas. Texas has implemented substantial NOx controls on new and existing EGU facilities through legislative, rulemaking, and permitting actions. [EPA-HQ-OAR-2009-0491-2857.2,p.11]    
As discussed in other TCEQ comments, the assumed starting NOx control level for the EGUs in Texas in the EPA's base case parsed data files is not accurate. EPA's assumptions about potential NOx reductions and the cost effectiveness of those reductions are not reliable if the EPA does not have accurate information about the current NOx control level. [EPA-HQ-OAR-2009-0491-2857.2,p.11]  
Response: 
As described in section VI of the preamble, EPA updated its assessment of ozone season and annual NOX reductions for the final Transport Rule.  Details on EPA's analysis for the final Transport Rule with respect to costs of NOX controls, estimates of downwind air quality impacts, and determinations of NOX  budgets for elimination of significant contribution to non-attainment and interference with maintenance can be found in sections VI.B, VI.C, and VI.D of the preamble for the final Transport Rule respectively.
Regarding baseline emissions, EPA took comment and updated baseline emissions inventories and assumptions for the final Transport Rule.  Details on this topic can be found in Documentation Supplement for EPA Base Case v.4.10_FTransport  -  Updates for Final Transport Rule.
With respect to NOX emissions in Texas, the updates to emissions inventories and model assumptions between the proposed and final Transport Rule resulted in lower projected EGU base case emissions in the final rule compared to the proposal.  Specifically, 2012 base case ozone-season NOX emissions for fossil fuel-fired EGUs are projected to be about 13,000 tons lower and annual NOX  emissions about 23,000 tons lower, in the final rule compared to the proposal (see the IPM run titled "TR_Base_Case_Final" in the docket).  Regarding the magnitude of ozone-season NOx reductions available from Texas EGUs at $500 per ton, EPA's analysis for the final rule identified approximately 2,000 tons at that cost level (see section VI.B in the preamble; see also IPM run titled "TR_NOX_OS_500_Final" in the docket).         
With respect to elimination of significant contribution to nonattainment and interference with maintenance for the ozone standard, EPA believes it can best serve states with ozone non-attainment problems by quickly finalizing the ozone season NOX reductions under this rule and seeking further ozone season NOX reductions in subsequent rulemakings.  Additionally, air quality modeling results provided in section VIII.B indicate that only 1 area (Houston, TX) is expected to have remaining non-attainment problems for the ozone standard and only 1 area (Baton Rouge, LA) is expected to have remaining maintenance problems for the ozone standard.
For the annual and 24-hour PM2.5 standards, EPA finds, for the states covered by this rule for the 1997 PM2.5 NAAQS or the 2006 PM2.5 NAAQS, that the final Transport Rule emission reductions of annual NOX (coupled with SO2 reductions) successfully address significant contribution to nonattainment and interference with maintenance with respect to the NAAQS for which they are covered. Air quality modeling results provided in section VIII.B indicate that the final transport rule will resolve non-attainment with all PM2.5 standards for all receptors with the exception of 1 receptor with remaining nonattainment problems for the 24-hour PM2.5 standard in the Liberty-Clairton area--which EPA has noted is heavily influenced by a local source of organic carbon (75 FR 45281).
IV.D.5.b. Specific Application of Overall Approach to Ozone: Modeling Methods/ Air Quality Assessment Tool/ Results of Evaluation With Detailed Air Quality Model (CAMx)/ New York City

Organization: Adirondack Council
Comment: 
Adirondack Council
EPA is taking comment on whether it should consider and analyze the NOX reductions that can be achieved for greater than $500/ton in states that are linked to the New York area sites. (p. 324) The Adirondack Council believes that EPA should consider further reductions to NOX emissions that contribute to nonattainment in the New York City area. As mentioned above, EPA should consider reductions up to the $3,200/ton level to help New York meet National Ambient Air Quality Standards. [EPA-HQ-OAR-2009-0491-2848.1, p.3]
Response: 
EPA updated the analysis used to identify nonattainment and maintenance receptors in response to comments and to reflect updates to numerous modeling inputs including emissions inventories.  As indicated in section V.C of the preamble for the final Transport Rule, the final rule modeling demonstrates that New York area monitors are not projected to have non-attainment or maintenance problems with any of the evaluated standards in the 2012 base case under final Transport Rule modeling.
Organization: Kansas Department of Health and Environment
Comment: 
Kansas Department of Health and Environment
The approach EPA uses to assess the effect NOx reductions will have on downwind ozone is fundamentally flawed. The use of an assessment tool that assumes a linear relationship between the reduction in an upwind state's NOx emissions and that state's contribution to downwind ozone levels is flawed. The production of ozone is well understood to be a nonlinear process, thus the need to perform photochemical modeling that takes into account many of the nonlinear variables affecting ozone production. [EPA-HQ-OAR-2009-0491-2606.1, p.6]
This assessment tool, as described by EPA in the proposed rule and TSD, also does not differentiate between emissions reductions of low-level sources and elevated sources of NOx. For transport at large distances, the impacts of elevated sources versus low-level sources are likely different for varying reasons, including plume chemistry and physical location both in the vertical layer of the atmosphere and with the source-receptor relationship. Again, this is another nonlinear problem that should not be assumed to be linear in an assessment tool. While this flawed approach does not appear to directly impact the initial 'linkage' contribution assessment, it does potentially impact other conclusions drawn from this tool's use. [EPA-HQ-OAR-2009-0491-2606.1, pp.6-7]
KDHE understands the need for a tool that can conveniently be used for multiple scenarios; however, using a tool with fundamental flaws in the basic underlying assumption for the pollutants of concern is troublesome to KDHE. KDHE recommends a tool that can better account for a response to emissions changes, possibly even the same tool but modified to better account for a state's unique characteristics as identified by photochemical modeling. So, rather than assuming a linear response to all emissions reductions for all states, perhaps CAMx could be used to inform a tool that would have varying responses to emissions changes based on source receptor proximity, type of source reduction, etc., while retaining the needed benefits of speed in analysis.[EPA-HQ-OAR-2009-0491-2606.1, p.7]
Response: 
For the final Transport Rule, for reasons more fully described in Section VI of the preamble for the final Transport Rule, EPA was able to use CAMx modeling to evaluate NOx reductions for both ozone and the nitrate component of PM2.5.  The CAMx modeling accounts for any nonlinearity between NOx emissions and ozone formation as well as differential impacts between ground level and elevated sources of NOx emissions.
Organization: Louisiana Chemical Association (LCA)
Comment: 
Louisiana Chemical Association (LCA)
LCA also believes that EPA should reevaluate whether Louisiana sources are significantly contributing to nonattainment of the 1997 8-hour ozone NAAQS in the Dallas-Ft. Worth ('DFW') area and the Houston-Galveston-Brazoria ('HGB') area or interfering with maintenance in those areas. Again, we believe that Louisiana's emission inventory is overestimated by EPA and for that reason alone, new modeling should be performed. Further, the HGB area achieved attainment in 2009 with a design value of 84 ppb and that value has dropped to only 82 ppb year to date. I The DFW design values have dropped over the last several years to a present value of 86 ppb, just above the standard.2 The actual design values now are so much lower than EPA's projections for just two years from now, and with EPA projecting declining emissions of NOx and VOC even without the Transport Rule, there is significant question about the model procedures and inputs. EPA technical support documents also suggest that EPA may have modeled emissions from some large EGUs in Louisiana as the annual emissions from such units occurred only during ozone season. Thus, the projected impacts may be unrealistically high. However, further review of the underlying technical support documents and other data is necessary to confirm these concerns and to prepare comments for EP A's appropriate consideration. [EPA-HQ-OAR-2009-0491-1925.1, p. 2]
EPA's IPM v. 4.10 Has Projected That There Will Be No Significant Contribution or Interference With Maintenance of the 1997 8-Hr. Ozone NAAQS From Louisiana Sources. As noted above, LCA has not been able to complete its review of the changes to the TR Base Case v. 4.1094 compared to TR Base Case v. 3.02, nor to the evaluation of different Transport Rule FIP options using version 4.10, but a comparison of the IPM Base Case 2012 projections clearly shows that the total ozone season NOx estimates under the TR Base Case v. 4.10 have dropped significantly when compared to the TR Base Case v. 3.02. The reduction is greater than the difference between the TR Base Case v. 3.02 and the IPM v. 3.02 run for the TR SB Limited Trading Values and is below the stated budget allocation. [EPA-HQ-OAR-2009-0491-3527.1, p. 35]
In the Preamble to the CATR/FIP, EPA stated: A state's emissions budget is the quantity of emissions that would remain in that state from covered sources after elimination of that portion of each state's significant contribution and interference with maintenance that EPA has identified in today's proposal, before accounting for the inherent variability in power system operations....In other words, it provides a quantity of emissions to use in developing a remedy (e.g., the remedy should be designed to achieve the budget in an average year. Because the budget represents emissions that would remain without accounting for var1ability, it also represents the amount of emissions that would remain after significant contribution and interference with maintenance have been addressed, in an average year. [EPA-HQ-OAR-2009-0491-3527.1, p. 35]
Thus, when the Base Case v. 4.10 projection shows a value below the budget, it is clear that significant contribution and interference no longer exist. In short, this means that EPA projects with the updated version of the IPM v.4.10 that by 2012, the total reduction required in order to prevent any significant contribution or interference with maintenance with the 1997 ozone NAAQS has already been achieved without the Transport Rule/FIP. [EPA-HQ-OAR-2009-0491-3527.1, p. 36; see p. 36 for Table 6, Comparison of TR Base Case v. 3.02 to 4.10 for Louisiana EGUs.]
Because "significant contribution" and "interference with maintenance" have been removed with this revised IPM modeling, there is no basis for a Transport Rule or FIP for Louisiana EGUs, as the levels required to remove significant contribution and interference with maintenance will have already been achieved. In summary, EPA's IPM modeling provides no rational basis for the FIP proposed for Louisiana. It supports a conclusion that any potential Louisiana impact on either annual PM2.5 or 8-hour ozone NAAQS in Texas will be removed through factors other than the Transport Rule and CAIR. [EPA-HQ-OAR-2009-0491-3527.1, p. 36]
Response: 
EPA updated its significant contribution analysis for the final rule to take into account extensive comments and new data on emissions inventories.  This method and its results can be found in section V and VI of the preamble for the final Transport Rule.
With respect to "attainment" in 2009 of the Houston-Galveston-Brazoria ozone area, please refer to section V of the preamble for the final Transport Rule for a discussion of the appropriate air quality data on which EPA based the rule.
With respect to EPA's determination of elimination of significant contribution to non-attainment or interference with maintenance, EPA uses a multi-step process described in sections V and VI of the preamble for the final Transport Rule.  It is not sufficient to compare emission projections made under different iterations of IPM modeling (as the commenter does) without further taking into account revised air quality modeling of downwind impacts, which EPA proceeded to do using updated inputs for the final Transport Rule.  For a complete assessment of Louisiana and its role in the final Transport Rule, please refer to the preamble for the final rule.
Organization: New York State Department of Environmental Conservation
Comment: 
New York State Department of Environmental Conservation
Lastly, in the Air Quality Modeling Technical Support Document (Table F-5), EPA stated that it modeled using 585,584 tons of NOx for EGU emissions in the ozone season for the 26 states. This compares to the $500/ton level of 610,454 tons and the amount EPA allocated, 641,614 tons. If the latter allocated value was used in the modeling, it is very possible that more areas aside from Houston, Baton Rouge and New York City would continue to show SC/IM. Still, the use of the lower emissions in the modeling could invalidate EPA's conclusions regarding SC/IM. [EPA-HQ-OAR-2009-0491-2730.1, p.7] EPA should adjust its budgets to fit its analysis. [EPA-HQ-OAR-2009-0491-2730.1, p.8]
Response: 
EPA adopted a modified method for determining budgets under the final Transport Rule that EPA believes is more clear and easier to understand in connection with the Agency's modeling projections.  EPA believes the state budgets set under the final Transport Rule are an accurate reflection of its modeling of the removal of emissions identified as significant contribution and interference with maintenance from the states controlled.  For a discussion of this method and its results, please refer to section VI of the preamble for the final Transport Rule as well as the Significant Contribution and State Emissions Budgets Final Rule Technical Support Document.

IV.D.6. Non-EGU Emissions Sources and Control Costs

Organization: Central Illinois Global Warming Solutions Group
City of Philadelphia, Department of Public Health, Air Management Services
Comment: 
Central Illinois Global Warming Solutions Group
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.124-125.]
I also think that the Rule needs to look at all industries, not just power generation, and I hope that in future versions it can be expanded to do so.
City of Philadelphia, Department of Public Health, Air Management Services
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.219.]
EPA should include all categories in the proposed rule, not just EGUs that contribute significantly to interstate transport of NOX and SO2 in the jurisdictions covered.
Response: 
EPA intends to address the appropriateness of controls for additional industries in a separate rulemaking.  
Organization: Clean Air Task Force
Comment: 
Clean Air Task Force
In fact, the emission budgets in the NOx SIP Call were calculated on the basis of reductions not only from power plants, but also from large industrial, commercial and institutional boilers; cement kilns; and large stationary reciprocating internal combustion engines. 103 Notwithstanding EPA's assertion that including non-EGU reductions in this TR rulemaking would delay finalization of the TR beyond spring 2011, we do not believe that is necessarily so. NOx emissions from these additional source categories have been regulated in conjunction with the NOx SIP Call and other programs for over a decade, and EPA should by now have sufficient cost and other information available to analyze in a timely fashion the impact of regulation of these sources under the proposed TR. 104 [EPA-HQ-OAR-2009-0491-2738.1, p.18] 
Tighter Control on Regional Power Plant Emissions are Feasible and can be Implemented without Threatening the Economy or the Electric Power System.
As EPA found in conjunction with the CAIR rulemaking, emissions control technology for SO2 emissions is well demonstrated and well established, and has been commercially available for decades. 111 Wet and dry flue gas desulfurization (FGD) technologies have been available for over 30 years, and routinely achieve SO2 control efficiencies of 90 to 98+%. 112In conjunction with its 1999 regional haze rulemaking, EPA proposed in its 2001 BART Guidelines a presumption that 'an SO2-control level in the 90 -- 95% range is generally achievable' for uncontrolled boilers and thus should be considered to be best available retrofit technology for purposes of controlling visibility-impairing SO2 emissions. 113 [EPA-HQ-OAR-2009-0491-2738.1, p.19; For additional comments pertaining to Tighter Control on Regional Power Plant Emissions are Feasible and can be Implemented without Threatening the Economy or the Electric Power System see pages 19-21 of this comment.]

Footnotes:
104 For example, NESCAUM has published an in-depth report on emission controls for ICI boilers. See NESCAUM (2008, revised 2009), Application and Feasibility of NOx, SO2, and PM Emissions Control Technologies for Industrial, Commercial, and Institutional (ICI) Boilers, available at: http://www.nescaum.org/topics/air-pollution-control-technologies.
Response: 
EPA was mindful of the information developed in the NOx SIP call, and in the NESCAUM report in its evaluation of nonEGU controls for this rule, and in forming its conclusions regarding nonEGU reductions at cost per ton values for NOx and SO2.
While additional technically feasible reductions may be possible for EGUs, technical feasibility is not a sufficient grounds for imposing controls under this Transport Rule.  Under this rule, requirements for emissions reductions for EGUs must be justified based on a state's significant contribution to nonattainment or interference with maintenance.   
Organization: Council of Industrial Boiler Owners (CIBO)
MeadWestvaco Corporation (MWV)
American Forest & Paper Association (AF&PA)
American Chemistry Council
Comment: 
American Chemistry Council
We believe it is appropriate and necessary for EPA to continue to focus on the power sector (EGUs) to ensure that the largest contributors to NOX and SO2 emissions are reducing those emissions. Moreover, EGUs are able to do so in a more cost-effective manner than other industrial sectors. A continued focus on EGUs also keeps the number of covered sources to a manageable number. EPA has correctly assessed that it would not be cost-effective to extend the Transport Rule to non-EGUs. [EPA-HQ-OAR-2009-0491-2716.1, p.1]
ACC urges EPA to continue to exempt non-EGU emission sources from the Transport Rule. The exemption should extend to industrial boilers and turbines. Industrial boilers will be subject to a final National Emission Standard for Hazardous Air Pollutants (NESHAP) in January 2011, which will require a number of boilers to install additional control technologies in order to comply with strict emissions standards. Many non-EGU sources already have or will soon apply additional emission controls, and the next incremental step cost of controls significantly exceeds the $500/ton NOX and $2000/ton SO2 emission control measures that can be achieved by EGUs. [EPA-HQ-OAR-2009-0491-2716.1, p.1]
B. Particulate Matter
In the preamble, EPA states that it does not believe that other source categories beyond EGUs have emissions that are currently significantly contributing to non-attainment or interfering with maintenance of the 1997 and 2006 PM2.5 NAAQS. (75 Fed. Reg. at 45289.) [EPA-HQ-OAR-2009-0491-2716.1, p.2]
ACC agrees with EPA's assessment that, with respect to the 1997 and 2006 PM2.5 NAAQS, emissions reduction requirements should not be applicable to non-EGU sources. We do not believe that there are any < $500/ton PM2.5 emission reduction measures that can be implemented by 2012 for non-EGU point sources. [EPA-HQ-OAR-2009-0491-2716.1, p.2]
American Forest & Paper Association (AF&PA)
AF&PA supports EPA's decision to exempt emissions from non-EGU sources from Transport Rule regulation. We completely agree with EPA's conclusion that emissions from such sources cannot be cost-effectively controlled. Indeed, we think that EPA has underestimated the costs of such controls, although there is no need to address the issue in detail at present. [EPA-HQ-OAR-2009-0491-2643.1, pp.1-2]
II. EPA Properly Proposed to Exempt Non-EGUs from Transport Rule Coverage
The proposed Transport Rule concludes that EGUs (Electric Generating Units) can control their emissions cost-effectively, which results in achieving air quality goals with the least burden on society. [EPA-HQ-OAR-2009-0491-2643.1, p.2]
According to EPA's proposal the Agency "has not identified SO2 reductions for sources other than EGUs at $2000/ton or less" (75 Fed. Reg. 45289). The notice goes on to summarize the available data on non-EGU controls and to conclude that:
This information shows that few if any SO2 reductions are available from other source categories [besides EGUs] and [this], along with other information available to EPA, supports EPA's proposal not to include non-EGU SO2 reduction requirements ...for the proposed rule. (id.)  [EPA-HQ-OAR-2009-0491-2643.1, p.2]
For NOx, EPA concluded even more categorically that it "has not identified additional non-EGU controls that can be achieved at $500/ton or less" (75 Fed. Reg. 45290). In reaching this conclusion, EPA finds, categorically, that emission reductions from industrial sources cannot be achieved cost effectively within these thresholds. AF&PA fully supports EPA's analysis and conclusions. [EPA-HQ-OAR-2009-0491-2643.1, pp.2-3]
This conclusion is particularly important to manufacturing industry, which is exposed to constant and increasing international competition, and is less able to absorb the cost of pollution control programs than utility sources operating in an almost purely domestic market. Instead, increased costs can lead to reduced employment and reduced production. Utilities will likely pass their control costs on to their customers, including manufacturers, while non-EGUs would find such pass-through difficult in the highly competitive global marketplace. Further, EPA's analysis correctly identifies that the most significant emission sources are EGUs, which would also have a much greater impact on ambient air improvement if better controlled. These considerations further support EPA's proposed limitation of Transport Rule coverage to EGUs. [EPA-HQ-OAR-2009-0491-2643.1, p.3]
In closing, we support EPA's findings that non-EGU sources are not highly cost effective to control and should be excluded from the Transport Rule. Thank you for the opportunity to comment. [EPA-HQ-OAR-2009-0491-2643.1, p.9]
Council of Industrial Boiler Owners (CIBO)
EPA proposes to regulate EGUs under the rule, and as indicated in Footnote 77, does not define Industrial, Commercial, and Institutional (ICI) Boilers as covered sources in the Proposed Rule: "Certain non- EGUs and smaller EGUs were included in the CAIR NOx ozone season program in some CAIR states. EPA proposes that such units would not be covered by the Transport Rule requirements.' 75 FR 45299 at fn 77. However, EPA has requested comments on 'whether non- EGU emissions reductions should be required and on the specific control measures that would serve as the basis for those reductions.' 75 FR 45289-90.
CIBO supports the proposal to regulate only EGUs under this rule. As EPA concluded, non- EGUs would not be able to implement the emissions reductions mandated by this rule in an effective and cost efficient manner. As EPA points out in the Proposed Rule, ' EGUs can reduce SO2 and NOx emissions more cost-effectively than other source categories.' 75 FR 45299-300. EPA completed a study to this effect, which analyzed the 'costs of EGU and non-EGU controls [and] resulted in a conclusion that substantial SO2 and NOx reductions from EGUs are available at a cost per ton that is lower than the cost per ton of non-EGU controls.' 75 FR 45300. This fact is primarily driven by economies of scale (utility boilers typically 1 to 2 orders of magnitude larger than typical ICI boilers) and differences in operating characteristics such as capacity factor (many ICI boilers routinely operate with low annual capacity factors); both of these drive up the resultant cost per ton for emissions controls.
EPA also notes that compared to EGUs, ICI boilers are lower SO2 emitters, and that because of 'variability in operations, it is difficult to identify precise cost per ton estimates' for implementing control technologies. 75 FR 45289. EPA also has recognized that additional controls on NOx emissions from ICI boilers would be unjustifiably expensive and unnecessary for the purposes of the transport rule. 75 FR 45290. CIBO supports these conclusions regarding non- EGUs.[EPA-HQ-OAR-2009-0491-2751.1 p.6]
MeadWestvaco Corporation (MWV)
The proposed Transport Rule correctly concludes that EGUs (Electric Generating Units) can control their emissions cost-effectively, which results in achieving air quality goals with the least burden on society. In the proposal, EPA has determined that it is not cost effective to control emissions of nitrogen oxides (NOx) and sulfur dioxide (S02) from industrial sources. [EPA-HQ-OAR-2009-0491-2650.1, p. 2]
According to EPA's proposal, the Agency 'has not identified 802 reductions for sources other than EGUs at $2000/ton or less.' 75 Fed. Reg. 45289. For NOx, EPA concluded that it 'has not identified additional non-EGU controls that can be achieved at $500/ton or less.' 75 Fed. Reg. 45290. EPA finds, categorically, that emission reductions from industrial sources cannot be achieved cost effectively within these thresholds. MWV fully supports EPA's conclusions with respect to this issue. [EPA-HQ-OAR-2009-0491-2650.1, p. 2]
EPA's conclusion is particularly important to the manufacturing industry, which is exposed to constant and increasing international competition, and is less able to absorb the cost of pollution control programs than utility sources operating in an almost purely domestic market. Instead, increased costs can lead to reduced employment and reduced production. Utilities/EGUs will likely pass their control costs on to their customers, including manufacturers, while non-EGUs would find such pass-through difficult in the highly competitive global marketplace. Further, EPA's analysis correctly identifies that the most significant emission sources are EGUs, which would also have a much greater impact on ambient air improvement if better controlled. These considerations further support EPA's proposed limitation of Transport Rule coverage to EGUs.  [EPA-HQ-OAR-2009-0491-2650.1, p. 2]
Response: 
In the final rule, EPA retains its proposed conclusions regarding nonEGU source controls.
Organization: Eco Power Solutions (USA) Corp.
Comment: 
Eco Power Solutions (USA) Corp.
Because, according to the analyses EPA has relied upon, capital costs are a major element of costs in the non-EGU applications, EPA needs to reconsider its conclusion that for the non-EGU sector, control technology is not available below the cost-thresholds that EPA has identified (75 Federal Register No. 147 at 45289-90). [EPA-HQ-OAR-2009-0491-2692.1, p. 1]
EPA, however, did not consider innovative technology such as Eco Power's COMPLY 2000(R) units. The combination of higher cost thresholds and the dramatically lower capital costs for Eco Power's technology in non-EGU applications (due to heat recapture) would likely result in a reconsideration of the decision not to require compliance by non-EGUs as to SO2 and a potential reconsideration as to NOx, depending on the stringency of the final Ozone rule. The cost issues are discussed in more detail below. [EPA-HQ-OAR-2009-0491-2692.1, p. 3] [See 2692.1, pp. 2-7 for extensive discussion of Eco Power's technology.]
Response: 
EPA looks forward to additional information on this technology as further efforts proceed to demonstrate its effectiveness.  
Organization: Kentucky Division for Air Quality
Comment: 
Kentucky Division for Air Quality
Emissions of Other Sources Also Need to Be Reduced to Eliminate Transport  
Pursuant to the rule preamble Section V.B.2., Other Source Categories Are Not Included (75 FR 45300), the Transport Rule fails to include all sources that contribute significantly to transport. Given that EPA's new 8-hour ozone standard will be more stringent and a more difficult standard for states to attain and maintain, the Division requests that EPA obtain additional emission reductions from other relevant source categories especially from onroad mobile sources. Onroad mobile source emissions remain a significant source of ozone precursor emissions that have contributed to many areas' previous ozone nonattainment problems. EPA could assist state and local agencies by requiring additional emissions reductions from other source categories that are significant contributors of ozone and PM2.5 precursor emissions, such as onroad vehicles, locomotives, oceangoing marine engines, and nonroad vehicles. If EPA does not incorporate emission reductions for the aforementioned source categories in the proposed Transport Rule, then the Division requests that EPA consider these other source category emission reductions, especially for onroad mobile vehicles, when EPA proposes its Transport Rule II. [EPA-HQ-OAR-2009-0491-2805.1, p.5]
Response: 
This rule addresses the 1997 ozone standards, and does not address any newer ozone standards.   EPA agrees that additional efforts will be needed to necessary emissions reductions under newer standards.   EPA continues achieve substantial mobile source reductions from existing mobile source standards, and we will be continually evaluating ways to update those standards over time.
Organization: Maryland Department of Environment (MDE)
Comment: 
Maryland Department of Environment (MDE)
In working with other states and EPA we have identified 6 priority source categories which we believe should be targeted first for the state-of-the-art, multi-pollutant national controls. These are; EGUs, on- and off-road mobile sources, industrial, commercial and institutional boilers, cement kilns, marine engines and locomotives. These six categories represent about 85% of the SO2 that is left to regulate, 75% of the NOx that is left to regulate and 75% of the 2005 national Hg emissions. [EPA-HQ-OAR-2009-0491-2639.2, pp.1-2]
State-of-the-art, multi-pollutant controls on these six categories would move the Country far down the road to clean air and result in tens of thousands of lives being saved and huge additional health benefits linked to reduced respiratory illness. These controls would also dramatically help the states as they struggle to develop new SIPs for ozone, fine particles, NO2 and SO2 and new WIPs to address nitrogen and mercury related water quality problems. Maryland is one of the Co-Chairs for the EPA/NACAA retreat follow up workgroup on Multi-Pollutant, Sector-Based strategies. We look forward to working with EPA on this issue. [EPA-HQ-OAR-2009-0491-2639.2, p.2]
Maryland believes that the inclusion of non-EGU sources is a critical component of any pollution transport regulation promulgated by EPA. Maryland views emissions reductions from non-EGU sources as essential to the ability of the state to meet the upcoming EPA ozone and particulate matter NAAQS. Many non-EGUs contribute significantly to NOx emissions levels. Their inclusion would enable additional cost effective NOx emission reductions. [EPA-HQ-OAR-2009-0491-2639.2, p.9]
Maryland, working with NACAA, has identified six high priority categories as large contributors to NOx emissions. Based on EPA's projected 2020 emission inventory, the national emission inventory for NOx will no longer be dominated by power plants (see table below [See EPA-HQ-OAR-2009-0491-2639.2, p.9 for table]). [EPA-HQ-OAR-2009-0491-2639.2, p.9]
The inclusion of non-EGUs in the Transport Rule would provide a much needed boost in NOx reductions, especially in areas having difficulty attaining the NAAQS. Previous OTC modeling has shown that inclusion of non-EGU sources will help states come into attainment with air quality standards. The University of Maryland, College Park (UMD) completed a screening modeling simulation for OTC, to demonstrate the level of emission reductions needed to show compliance with the 8-hour ozone NAAQS of 75 ppb. The screening modeling simulation covered the time period of May 17  -  August 31, 2007, and was completed using the CMAQ model, 2007 meteorological data, and a 2007 proxy emissions inventory. The emissions reductions for the screening modeling simulation were based on OTC's recommendation for critical national reductions combined with local OTR measures. The emissions reductions included the following:  [EPA-HQ-OAR-2009-0491-2639.2, p.9]
Domain-Wide, including the OTR, Southeast, and Midwest
NOx
Point Sources: -65% (Represents reductions from ICI boilers, cement kilns, and a 900,000 ton regional trading cap on EGUs)
On-road Sources: -75% (Approximates a 2020 national Low-Emission-Vehicle (LEV) III Program)
Non-road Sources: -35% (Includes reductions from marine and locomotive engines)
VOCs
All Source Sectors: -30% OTR States
NOx
All Sectors: -5% (Additional reductions only in the OTR)  [EPA-HQ-OAR-2009-0491-2639.2, pp.9-10]
Results of the screening modeling simulation showed that targeted reductions among these source sectors were more effective at lowering ozone and particulate matter than deeper across-the-board cuts in NOx levels across all sectors. Only one monitor in the OTR had a future-year design value over the 8-hour ozone NAAQS of 75 ppb. Maryland believes that inclusion of non-EGUs is more cost effective than other measures that OTC states have already implemented to achieve the 85 ppb ozone NAAQS and current particulate matter standard. Therefore, Maryland recommends that EPA include non-EGU sources in the proposed Transport Rule.  [EPA-HQ-OAR-2009-0491-2639.2, p.10]
Maryland has experienced, with great pride, the dramatic improvements in ozone and fine particle air quality associated with the recent implementation of regional NOx and SO2 control programs. Our research (see Appendix F and G [See EPA-HQ-OAR-2009-0491-2639.2, p.49 for comments pertaining to Appendix F and p.50 for comments pertaining to Appendix G]) told us that the regional, elevated reservoir of ozone, created by regional emission sources, was contributing significantly to our ground level ozone problem. Our data shows that this elevated reservoir mixes down around 10:00 in the morning on bad ozone days and is responsible for up to two thirds of the daily maximums we record.  [EPA-HQ-OAR-2009-0491-2639.2, p.10]
The 2004 NOx SIP Call, the acid rain program and early CAIR provided us with a real world test case to see if reducing regional emissions would reduce the pollution in the elevated reservoir and ultimately lead to lower air pollution at ground level. The results have been dramatic. As emissions have gone down, the pollution measured in the reservoir has been reduced and ground level monitors have recorded much cleaner air. Our aloft measurements show an approximate 25% reduction in ozone in the elevated reservoir after 2004. Maryland is currently measuring ground level ozone and fine particle levels that are below the annual and daily fine particle standard and the old 1-hour ozone standard. 8-hour ozone levels have also dropped dramatically.  [EPA-HQ-OAR-2009-0491-2639.2, p.10]
Regional NOx and SO2 reductions have clearly worked.  [EPA-HQ-OAR-2009-0491-2639.2, p.10]
Maryland supports EPA's focus on reducing NOx and SO2 emissions from EGUs but we believe that EPA should also look into reductions from non-EGU sources as a means of controlling transported pollution. In the first of the three remedies, the "State Budgets/Limited Trading Proposed Remedy", sources would receive allocations based on state budgets alone (variability would not be included). There would be four trading groups established and banking of allowances would be permitted. EPA states that trading and banking "accounts for variability in the electricity sector". EPA is also proposing to impose assurance provisions starting in 2014. The assurance provisions will result in allowance surrender only if:
1. a state exceeds its budget plus variability in a given year or on average triennially AND
2. an owner's unit's emissions exceed the owner's share of the state budget PLUS variability limit [EPA-HQ-OAR-2009-0491-2639.2, pp.14-15; This comment can also be found at V.D.2.d. of this comment summary]
Response: 
EPA appreciates this information, and we look forward to continuing discussions on relevant information for evaluating the priorities for addressing newer air quality standards.   
Organization: National Association of Clean of Air Agencies (NACAA)
Comment: 
National Association of Clean of Air Agencies (NACAA)
Emissions of Other Sources Also Need to Be Reduced to Eliminate Transport
The Transport Rule fails to include all sources that contribute significantly to transport, such as industrial, commercial and institutional boilers, and cement kilns. These additional source categories represent a significant percentage of the states' NOx and SO2 emissions inventories and also contribute to interstate transport problems. We recognize that to include these sources, EPA believes it would need to repropose Transport Rule I, which, in the interest of time, we do not support. Thus, EPA must address these source categories as well when it proposes its Transport Rule II. In addition, EPA could assist state and local agencies by requiring substantial emissions reductions from other source categories that are significant contributors of ozone and PM2.5 precursor emissions, including, but not limited to, on-road light duty vehicles, locomotive and oceangoing marine engines, and nonroad vehicles. [EPA-HQ-OAR-2009-0491-2771.1, p.3]
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.105-109.  These comments were also submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.83.]
Like the power plants, the sources proposed to be controlled under the Transport Rule are significant contributors to ozone and PM2.5 pollution.
In addition, the Transport Rule fails to include all sources that contribute significantly to transport such as industrial, commercial and institutional boilers and cement kilns.
These additional source categories represent a significant percentage of the states' NOx and SO2 emissions inventories and also contribute to interstate transport problems.
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.83-84.]
We recognize that to include these sources, EPA would need to repropose Transport Rule l, which, in the interest of time, we do not support.
Response: 
EPA agrees with the need to evaluate these additional source categories in future efforts.
Organization: New York State Department of Environmental Conservation
Comment: 
New York State Department of Environmental Conservation
The second method by which to rectify residual transport issues is to require non-EGU and small EGU units to take part in the trading program as discussed on page 10 of these comments. [EPA-HQ-OAR-2009-0491-2730.1, p.6]
Omission of Non-EGU Sources and Small EGU Sources
In the development of this proposal, EPA indicated that non-EGU sources such as industrial, commercial and institutional boilers, and cement kilns were not included because of the likely delay in the release of the rule for such an evaluation. Additionally, EPA conducted an assessment of reductions available for source categories other than EGUs through which it determined that there likely would be large emissions reductions available from EGUs before costs reach the point for which non-EGU sources have available reductions. Based on the resulting cost curves, EPA determined that there were little or no reductions available from non-EGUs at costs lower than the thresholds that EPA had chosen. However, as discussed elsewhere in these comments, the use of the $500 is an inadequate approach to assessing the reasonability of control costs. Additionally, a number of non-EGUs and smaller EGUs were included in the CAIR NOx ozone season program in some states, indicating that EPA recognized the benefit of controlling non-EGU sources. The same should apply to the present proposal as well as to Transport Rule II. New York State recently revised its regulations to require greater reductions from boilers, glass plants and cement kilns. As the Department continues to require greater emissions reductions from sources within the state, it expects upwind sources to eliminate SC/IM. EPA must fully address the contribution of these sources in this rule making or in the very least when it proposes Transport Rule II. method by which to rectify residual transport issues is to require non-EGU and small EGU units to take part in the trading program as discussed on page 10 of these comments. [EPA-HQ-OAR-2009-0491-2730.1, p.14]
Another problem with failing to include non-EGU sources is the 'orphaning' of these sources in terms of meeting the requirements of the NOx SIP Call. The NOx SIP Call contained emission reduction requirements for industrial boilers, Portland cement kilns and internal combustion engines. Many states, including New York, met these requirements by including these sources with the requisite emission reduction requirements in their ozone season NOx budget trading programs. These sources and the emission reduction requirements were subsequently carried over to the CAIR ozone season NOx program. As EPA noted in the proposal, many of these sources did not choose to control, but instead opted to utilities the emission trading option to comply with the emission requirements. By not including these sources in the FIP, states will likely need to embark on specific rulemaking and SIP revisions to assure these sources are complying with the transport provisions of the NOx SIP Call individually. This is an additional administrative burden that EPA is imposing on states that can easily be avoided by continuing to include these sources in the new ozone season trading program. [EPA-HQ-OAR-2009-0491-2730.1, p.14]
In addition to not addressing non-EGU sources, this proposal does not address smaller EGUs (15 to 25 MW). New York and other Ozone Transport Commission (OTC) states have included these sources in their ozone season trading program since the beginning of the OTC NOx Budget trading Program in 1999. These sources are significant emission sources in the summer season and especially on high electricity demand days when the potential for ozone formation is greatest. Not including these sources in the ozone season program will remove an important tool towards reducing overall NOx emissions during the summer months. [EPA-HQ-OAR-2009-0491-2730.1, p.14]
Response: 
See discussion in preamble section VI related to the choice of dollar per ton thresholds for NOx. 
EPA notes that the $500/ton threshold does not establish a precedent for future rulemakings, which would need to evaluate the impacts of higher-cost control measures for NOx.   
See discussion in preamble IX.B related to SIP provisions for NOx SIP call sources not covered by this Transport Rule.
See discussion in preamble section VII.B on applicability related to the issue of including smaller EGUs below 25 MW in the program. 
Organization: Northeast States for Coordinated Air Use Management (NESCAUM)
Comment: 
Northeast States for Coordinated Air Use Management (NESCAUM)
EPA has indicated that it did not include non-EGU sources because it did not want to delay release of the rule for such an evaluation. While we appreciate EPA's efforts to release the rule as soon as possible, we are concerned that the omission of non-EGU sources compromises EPA's framework by proposing only a partial solution to transport. In addition, states in the NESCAUM region that opted non-EGUs into their CAIR programs now must develop separate and distinct regulatory programs for these sources, which no longer enjoy the advantages of inclusion in a trading program. We expect that, when EPA develops responses to fully address significant contribution, it will consider all cost-effective controls from upwind areas, and not just those from a single source sector.  [EPA-HQ-OAR-2009-0491-2694.1 p.8]
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.11-12]
Fourth, EPA has indicated that it did not include non-EGU sources because it did not want to delay release of the rule for such an evaluation. We appreciate the EPA's efforts to release the rule as soon as possible, but the omission of non-EGU sources results in only a partial solution to transport, which underlies our concerns in my previous comments. Going forward, we expect the EPA to consider all cost-effective controls from upwind areas, and not just those from a single source sector.
Response: 
In the analysis for the final Transport Rule, the rule provides a complete solution to transport for the northeast US.   This is in contrast to the analysis for the proposal, where it appeared that the proposed rule may not provide for a complete solution for some receptor locations in the New York City area.   
Organization: Ozone Transport Commission (OTC)
Comment: 
Ozone Transport Commission (OTC)
[[2737.1 p.3]]
Finally, OTC is disappointed that EPA chose to exclude non-EGU sources in the remedy outlined in the proposed rule. OTC provides analyses in the attached comments to support their inclusion in the final Transport Rule, based on work conducted jointly with the Lake Michigan Air Di rectors Consortium (LADCO) and the OTC states' own experiences in adopting controls from non-EGU sources. 1t is our expectation that non-EGU sources wi ll be included in Transport 2.
[[2737.1 p.17-18]]
OTC notes with concern that EPA has excluded non-EGU sources in the remedy outlined in the proposed rule, and urges EPA to consider including them in the final Transport Rule. OTC has long held the position that the inclusion of non-EGU sources is a critical component in any pollution transport regulation promulgated by EPA. OTC views reductions from non-EGU sources as a critical component to allowing OTC's member states the ability to meet the upcoming EPA ozone NAAQS, as well as a forthcoming PM standard. Inclusion of non-EGUs would add flexibility and allow for additional cost effective emission reductions. If non-EGU sources excluded in the final rule, OTC expects that they will be included in Transport 2 for the new ozone NAAQS when it is final, and any future transport rules designed for other future NAAQS.
Based on EPA's projected 2020 emission inventory, the national emission inventory for NOx will no longer be dominated by power plants. Emissions of NOx from EGUs will make up approximately 17 percent of the national emission inventory. On-road mobile emissions will make up about 22 percent of the national NOx emissions, and industrial, commercial and institutional (ICI) boilers and cement kilns will make up a combined 13 percent of the national inventory of NOx emissions. The inclusion of non- EGUs into the proposed Transport Rule will provide a much needed boost in NOx reductions, especially in critical locations. In a joint OTC-LADCO evaluation of emission controls for ICI boilers emissions from these sources are found to be significant. Therefore OTC and LADCO worked together to outline proposed levels of control that can be achieved through existing and reasonable technologies to reduce NOx and SO2 from this category of non-EGU sources (attached as Appendix 7).
The inclusion of non-EGU sources into a transport rule provides a needed boost in the reduction of air pollution transport into the hard-to-attain portions of the Northeast. In previous work, OTC modeling showed that inclusion of non-EGU source controls produced significantly more benefits and brought more downwind relief, and predicted attainment with air quality standards for many areas.
The University of Maryland College Park (UMD) completed a screening modeling simulation for OTC to illustratively demonstrate the necessary level of emission reductions needed to show compliance with the 8-hour ozone NAAQS in the potential range for the new ozone NAAQS (60 - 70 ppb). This screening modeling simulation covered a time period from May 17 through August 31, 2007, and used a 2007 proxy emissions inventory with the CMAQ model. The emissions reductions for the screening modeling simulation are based on OTC's recommendation for critical national reductions combined with local Ozone Transport Region (OTR) measures (see OTC Resolution dated 6/3/10, Appendix 8). The emissions reductions were applied across the full modeling domain and include emission reductions taken across entire source sectors as specified below:
Domain-Wide NOx Point Sources: -65% (Represents reductions from ICI boilers, cement kilns, and a 900,000 ton regional trading cap on EGUs) On-road Sources: -75% (Approximates a 2020 national LEV3) Non-road Sources: -35% (Includes reductions from marine and locomotive engines)
VOCs All Source Sectors: -30%
OTC States NOx All Sectors: -5% (Additional reductions only in the OTC states)
future year design value over the 2008 8-hour ozone NAAQS of 75 ppb (a summary of the OTC screening modeling analysis is attached as Appendix 9). OTC believes that inclusion of non-EGUs would be more cost effective than other measures that OTC states have already implemented to achieve the 85 ppb ozone NAAQS and current PM2.5 standard. OTC recommends that EPA seriously consider including non-EGU sources into the proposed Transport Rule.
Response: 
As noted in the preamble, this rule address transport under the 1997 ozone standards, and the 1997 and 2006 PM2.5 standards.    Additional future efforts will be needed to address transport under future NAAQS.   EPA appreciates the information on control measures, and we will be reviewing this an other information in those future efforts.
EPA notes that, in contrast to the proposal, EPA considers the final Transport Rule to be a complete solution to addressing ozone transport for the 1997 ozone standards for all of the states in the Ozone Transport Commission region.
Organization: Pennsylvania Department of Environmental Protection
Comment: 
Pennsylvania Department of Environmental Protection
Sources other than EGUs represent a significant percentage of the states' NOx and SO2 emissions and contribute to interstate transport problems. Industrial/commercial/institutional (ICT) boilers and cement kilns are the major stationary sources, while highway vehicles, marine engines, and locomotives also provide significant emissions and should be: addressed. EPA should examine all of its authority under the CAA to promulgate: national rules for these sources and any others for which controls at least as effective as those on EGUs can be identified. The OTC and the LADCO have provided an evaluation of potential emission limits and costs for ICT boilers. [EPA-HQ-OAR-2009-0491-2660.1, p.9]
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.54.]
EPA must also address emissions from non-EGU sources including glass melting furnaces, cement kilns and industrial, commercial, institutional boilers in the 2011 proposal.
We urge EPA to also adopt and implement additional measures to reduce emissions from on-road and off-road vehicles, which account for approximately 52 percent of the NOx emissions in Pennsylvania.
Response: 
EPA looks forward to further discussions on priorities for possible emissions reductions to address transport under newer air quality standards.
EPA continues to achieve substantial and continuing reductions from on the books mobile source standards, and EPA is also continually seeking ways to update those mobile source standards.
Organization: State of Delaware Department of Natural Resources & Environmental Control
Comment: 
State of Delaware Department of Natural Resources & Environmental Control
Non-EGU Emission Reductions. EPA has requested comments on whether non-EGU emissions reductions should be required and on the specific control measures that would serve as the basis for those reductions. It is Delaware's opinion that EPA should consider requiring emissions reductions for some non-EGU categories. Included in this view are fossil-fuel fired electric generating units with a nameplate rating between 15 MW and 25 MW, fossil -fuel fired co-generation units serving a generator with a nameplate rating of 15 MW or greater, and fossil-fuel fired industrial and commercial (ICI) boilers with a heat input capacity rating of 250 MMBTU/hr or greater. It appears that these categories of units can contribute to air quality excursions and impact a downwind state's ability to attain NAAQS. It is Delaware's experience that the small EGUs (<25MW nameplate) tend to operate most during periods of high electric demand which often coincide with ambient air quality excursions in downwind states. While co-generation units tend to operate with a more constant capacity, there is some data that indicates those units' loading may increase during periods of high electric demand to capitalize on opportunities for increased income from electric sales during high cost periods or to offset the purchase of additional electric at high relative cost. The large ICI boilers also tend to operate with a relatively constant capacity factor, which would also include operation during the periods of high electric demand that may coincide with air quality excursions in downwind states. [EPA-HQ-OAR-2009-0491-2980.1, pp.8-9]
It is Delaware's opinion that cost-effective emissions reduction technologies are proven and commercially available for these types of units. For boilers serving EGUs with nameplate ratings of 15 MW or larger (including co-generation units) or ICI applications, commercially available cost effective controls for retrofit include fuel switching in some cases for S02 and NOx reduction, low-NOx burners and SNCR and SCR for NOx control, and wet and dry scrubbers and sorbent injection for S02 controls. For combustion turbines driving generators with nameplate ratings greater than 15 MW, including both EGU and co-generation application, commercially available cost effective controls for retrofit include fuel switching in some cases for S02 and NOx control, and dry low-NOx burners, water injection, and SCR for NOx reduction. The March 2006 STAPPA/ALAPCO document 'Controlling Fine Particulate Matter under the Clean Air Act: A Menu of Options' provides considerable discussion regarding the applicability of emissions controls for these units.[EPA-HQ-OAR-2009-0491-2980.1, p.9]
Delaware has also experienced some considerable success with its state rulemakings that resulted in control installations similar to those discussed above. One such rulemaking resulted in the addition of water injection for NOx control on all fossil-fired combustion turbines driving electric generators with a nameplate rating greater than 15 MW (but less than 25 MW) that had not been previously controlled. The affected units tend to operate as peaking units and operate primarily during periods of high electric demand. Post installation testing indicated significant NOx emission rate reductions were achieved by all of the affected units. [EPA-HQ-OAR-2009-0491-2980.1, p.9]
Response: 
See discussion in preamble section VII.B regarding treatment of small EGUS (less than 25 MW) in revised applicability provisions.
Organization: State of Wisconsin, Department of Natural Resources
Comment: 
State of Wisconsin, Department of Natural Resources
While noting the strong need for additional transport remedy, Wisconsin agrees that the current proposed Transport Rule should only apply to the EGD sector. Although additional remedy affecting non-EGU sectors should be committed and scheduled within this federal plan, any such actions should be implemented separate from the EGU sector. This ensures that the proposed transport rule is finalized as expeditiously as practicable and that legal concerns, especially related to non-EGU programs, do not further delay the installation of EGU controls in upwind states. [EPA-HQ-OAR-2009-0491-2829.2, pp.2-3]
Response: 
EPA agrees. 
Organization: Texas Chemical Council
Comment: 
Texas Chemical Council
Furthermore, the EPA proposal states, "if a more protective ozone NAAQS is issued in August, EPA would plan to propose and interstate pollution transport rule for the NAAQS in 2011." 75 Fed. Reg. at 45,228. TCC believes there should not be a rush to promulgate a new Transport Rule for "other sources" because:
- The decision on a revised ozone NAAQS standard has been delayed until October/November 2010 time frame. A thorough analysis of the non-EGU sources in relation to a lower standard would need to be conducted before issuing a new Transport Rule that includes non-EGU sources.
- The same methodology applied to the EGU sources in this proposal will not work for "other sectors." The chemicals sector contains much more diverse emissions sources and emissions profiles than EGUs. [EPA-HQ-OAR-2009-0491-2815.1, p.5]
Response: 
EPA agrees that further analysis of non-EGU sources is needed.   Such analysis would be provided before any future rulemakings addressing these non-EGU sources. 
Organization: West Virginia Department of Environmental Protection
Comment: 
West Virginia Department of Environmental Protection
[[2790.1 p2-3]]
Non-EGU ICI Boilers - West Virginia's non-EGU industrial, commercial and institutional boilers have participated in a seasonal EPA market trading program since 2004. The ICI boiler sources in West Virginia have been good players under the NOx Budget Trading Program, and through their participation under CAlR. Under the proposed Transport Rule, non-EGU sources are not included, nor are EPA's plans to continue similar regulation for these significant sources. It is generally understood that non-EGU ICI boilers and perhaps other non-EGU sources will be addressed by EPA in Transport Rule II.
Because West Virginia repealed its NOx SIP Call rules when transitioning to CAIR (with the full knowledge and consent ofEPA's Region III and Clean Air Markets Division), there appears to be no mechanism that will ensure that seasonal NOx reductions from ICI boilers and continued reporting of NOx emissions under 40 CFR Part 75 will occur in 2012-2014. It should be noted that future emissions reductions from ICI boilers have been accounted for in West Virginia's submitted attainment demonstrations and SIP-approved maintenance plans. WVDAQ believes it is important that ICI boilers continue reporting NOx emissions under 40 CFR Part 75, and that the EPA prevent backsliding from the non- EGU sectors. Such a mechanism will also ensure continuity of data if EPA for some reason does not finalize Transport Rule II. WVDAQ does not consider the opt-in provisions of the proposed Transport Rule to be an appropriate mechanism to define a clear regulatory path or ensure continuity of Part 75 emissions data for non-EGU ICI boilers.
WVDAQ believes that EPA should squarely address the immediate need for guidance or rulemaking which provides a clear regulatory path for large ICI boilers, and their role in interstate transport and significant contribution mitigation issues. If CAIR provisions must cease in 2012, at a minimum, EPA should provide a mechanism to ensure that ICI boilers continue reporting their NOx emissions under Part 75.
Response: 
See discussion in preamble section IX.B related to nonEGU NOx SIP call sources that are not covered by this Transport Rule.

IV.D.6.a. Non-EGU SO2 Emissions Sources and Costs

Organization: Council of Industrial Boiler Owners (CIBO)
Comment: 
Council of Industrial Boiler Owners (CIBO)
EPA indicates that this Proposed Rule is round one for utilities, based on the 1997 ozone standard. There is currently a newer ozone standard, with another, more stringent standard expected imminently. EPA has stated that it plans for future rounds of emission reductions to meet these tighter standards. EPA announced in this rule that round 2 of the Transport Rule would be proposed in 2011, and finalized in 2012. Round 2 will increase reduction requirements, and unlike this rule, may mandate reductions for industrial boilers. [EPA-HQ-OAR-2009-0491-2751.1]
In this rule, EPA assumes that $500/ton of NOx and $2000/ton of SO2 for annualized costs is considered highly cost effective and should be met by sources. These numbers are already significantly higher than what sources consider to be appropriate costs, and creates a large amount of uncertainty as to what EPA will presume is highly cost effective in, not only round 2, but potential rounds beyond that. EPA has further said that it will use the same methodology used for utilities, when it determines appropriate levels for ICI boilers. This does not appropriately take into account the major differences between the purposes and uses of electric utilities versus ICI boilers. In addition, most utilities are much larger and can pass their costs through to customers, both features that are not shared by ICI boilers. [EPA-HQ-OAR-2009-0491-2751.1]
Response: 
EPA believes that these $/ton values are generally considered to be highly cost-effective.    However, any decision on the use of these or other cost cutoffs to evaluate non-utility sources would be accomplished in a separate notice-and-comment rulemaking. 
Organization: Massachusetts Department of Environmental Protection
Comment: 
Massachusetts Department of Environmental Protection
SO2 Emission Reductions
EPA also seeks comment on whether non-EGU S02 emissions reductions should be required and on the specific control measures that would serve as the basis for those reductions using the $2,000/ton removed cost threshold EPA has applied.5 EPA acknowledges that ICI boilers are among the highest emitting categories  non-EGU S02 emissions.6 However, it discounts the potential emissions reductions from residual or distillate oil-fired boilers, asserting variability in operations makes it difficult to 'identify precise cost per ton estimates for fuel switching.' Non-EGU S02 emissions rival EGU emissions in many states within the Transport Rule region. Residual oil-fired industrial boilers represent 16.5% of the entire 2012 anthropogenic S02 emissions inventory for Massachusetts. [EPA-HQ-OAR-2009-0491-2787.2]
Response: 
EPA continues to believe that additional information may be needed to identify precise cost estimates of cost per ton for fuel switching, including fuel switching options for distillate and residual oil-fired industrial boilers.   In addition, EPA notes that this issue for oil-fired boilers is most significant in northeast states such as Massachusetts which are no longer covered by this Transport Rule.  

IV.D.6.b. Non-EGU NOx Emissions Sources and Costs

Organization: Massachusetts Department of Environmental Protection
Comment: 
Massachusetts Department of Environmental Protection
NOx Emission Reductions For NOx,
EPA assess that it has not been able to identify significant reductions for Industrial, Commercial and Institutional (ICI) boilers and other non-EGU industrial point sources that can be achieved at the $500 per ton cost threshold it is proposing for EGU reductions. (45290) MassDEP believes that EPA has overlooked a significant opportunity to achieve additional emission reductions from ICI boilers and encourages EPA to reconsider the exclusion of these sources. [EPA-HQ-OAR-2009-0491-2787.2]
Response: 
EPA intends to evaluate the availability and appropriateness of additional NOx controls for non-EGU source categories in a separate rulemaking.
Organization: Texas Chemical Council
Comment: 
Texas Chemical Council
Additionally, the EPA proposal states, "for ozone, EPA determined that a number of states can eliminate their significant contribution and interference with maintenance by installing controls at this same $500/ton cost threshold." 75 Fed. Reg. at 45,290. TCC believes EPA has grossly underestimated the current cost of NOx controls. For example, in the proposal for the new ozone standard, EPA estimated that it could cost anywhere from between $15,000 to $30,000 a ton to make further NOx reductions to meet a lower standard. This is a huge discrepancy in EPA's estimates for NOx controls that needs to be addressed. [EPA-HQ-OAR-2009-0491-2815.1, p.5]
Response: 
EPA's conclusion was based upon contributions to the 1997 ozone standard, and did not addressed more recent or anticipated ozone standards.    EPA intends to evaluate NOx control costs and impacts for newer ozone standards in a separate notice and comment rulemaking.

IV.E. State Emissions Budgets (Before Accounting for Variability)

Organization: Adirondack Council
Comment: 
Adirondack Council
We believe that it is necessary and appropriate for EPA to adopt state-by-state budgets based upon each upwind state's significant contribution to nonattainment and interference with maintenance and that EPA has chosen the correct levels for determining these criteria. [EPA-HQ-OAR-2009-0491-2848.1, p.2]
Response: 
EPA final Transport Rule determines state budgets using a state-by-state analysis to determine each state's significant contribution.  
In the final Transport Rule, EPA does not use historic emissions data to set the Transport Rule state budgets, but instead relies on projected emissions data under the marginal cost thresholds selected to define significant contribution and interference with maintenance.  EPA uses the same budget-setting methodology in the final rule on all pollutants analyzed (including ozone-season NOx, annual NOx, and SO2).  EPA believes this budget-setting methodology is more clear and easier to understand in connection with the Agency's modeling projections.  EPA believes the state budgets set under the final Transport Rule are an accurate reflection of its modeling of the removal of emissions identified as significant contribution and interference with maintenance from the states controlled.  For a discussion of this method and its results, please refer to section VI of the preamble for the final Transport Rule as well as the Significant Contribution and State Emissions Budgets Final Rule Technical Support Document.
Organization: Alliance for Industrial Efficiency
Comment: 
Alliance for Industrial Efficiency
First, states should be allowed to receive credit under the Federal EPA plan for industrial energy efficiency measures that they take. We urge EPA to include output-based emissions standards in the Federal Plan. By setting pollution limits based on each unit of energy produced, rather than the amount of fuel consumed, such standards provide greater incentives for pollution prevention, energy efficiency, and emissions reduction.11 [EPA-HQ-OAR-2009-0491-2682.1 [EPA-HQ-OAR-2009-0491-2682.1 p.2]
Response: 
See section VII.D of the preamble for a description of why EPA finalized a historic heat input allocation methodology, and determined that such an approach was reasonable.  EPA also noted that there were certain data limitations that impeded the implementation of a generations based approach such as that described by the commenter.  Furthermore, EPA notes that the initial allocation under a heat input based approach closely tracks that which would be observed under a generation based approach.
Organization: American Clean Skies Foundation (ACSF)
Comment: 
American Clean Skies Foundation (ACSF)
EPA should consider the role of fuel-switching as a control technology, whether it is cost effective, and whether state budgets should be accordingly adjusted. The extent to which EPA has sufficiently assessed fuel switching from coal to gas is not clear from the record. For instance, EPA makes a vague reference to looking at control technology cost curves to see how reductions at various cost levels reflect changes in the generation mix, e.g., "dispatch changes, fuel use changes, or installation or operation of controls." [EPA-HQ-OAR-2009-0491-2759.1, p.7]
EPA should explicitly address the costs of fuel switching from coal to gas, which is a vital control technology. In particular, EPA should consider whether there are cost-effective emission reductions from fuel switching that are above the Proposed Rule cost cutoffs: e.g., $500 per ton for NOx. By comparison, EPA previously considered $2,000/ton to be cost-effective for NOx controls under the NOx SIP call. EPA should carefully assess the benefits and costs of fuel-switching from coal to gas, particularly for states that have significant downwind impacts. Tightened budgets in high-emitting states may incentivize cost-effective fuel switching by either increasing the dispatch of existing natural gas units, or removing a subsidy for existing coal units and allowing otherwise economical gas plants to be built. And by tailoring and tightening emission budgets in coal-heavy, high-polluting upwind states, EPA will better meet Congress' statutory directive to address upwind pollution. Such tiering of states by needed emission reductions is already done under CATR for SO2 (with 'Group 1' and 'Group 2' states), and EPA should fully take advantage of cost-effective fuel switching to reduce emissions from high emitting upwind states. [EPA-HQ-OAR-2009-0491-2759.1, p.7]
In the midst of this CATR comment period, EPA released new modeling with updated natural gas supply assumptions that reflect dramatic increases in domestically available natural gas. This new modeling shows that significantly reduced natural gas prices increase natural gas generation and reduce coal generation. EPA has not revised the emission budgets based on these modeling runs, despite the impact that lower gas prices may have on increased fuel-switching in states that have substantial coal-fired generation, particularly those states with old, low-efficiency coal plants that lack modern pollution controls and are the most likely candidates for retirement. With lower natural gas prices and a substantial natural gas resources base, more utilities are expected to switch from coal-fired generation to natural gas. This should lower CATR caps that are set by projecting emission levels and cost-effective emission reductions. [EPA-HQ-OAR-2009-0491-2759.1, p.9]
Response: 
EPA's IPM modeling has allowed generation to shift from coal to gas within a state or region to comply with budgets.  Additionally, it has updated its IPM model to reflect the coal to gas conversion at individual units as a compliance option.  See EPA IPMv.4.10 documentation for more discussion on this addition to the IPM modeling and the cost assumptions underlying it.  EPA also re-conducted is multi-factor analysis for final Transport Rule using the updated IPM modeling with the revised gas price assumptions.  The state budgets determined in the final Transport Rule reflect these updates to the modeling assumptions (see section VI.D of the Transport Rule preamble).
Organization: American Electric Power
Comment: 
American Electric Power
EPA has understated the direct costs of complying with the budgeted caps, ignoring some of the significant direct costs, including output capacity deratings, and landfill development. EPA has also ignored entirely the enormous indirect costs of its caps, including the indirect costs of fuel switching, unit retirements, and increased energy costs to consumers. [EPA-HQ-OAR-2009-0491-2665.1, p.26]
Response: 
EPA has updated its IPMv.4.10 modeling assumptions in response to comments.  Specifically, it has made changes which include cost adders to reflect output capacity deratings that may occur as a consequence of fuel switching.  See EPA IPM.v.4.10 documentation for a full description of the modeling assumptions and updates made in response to comments.  Additionally, see the final Transport Rule RIA for discussion of costs, including social cost, of the final rule.
Organization: ARIPPA
Comment: 
ARIPPA
B. EPA's stated basis for determining unit-specific allowance allocations under the Proposed FIP is inappropriate and inequitable as applied to the ARIPPA plants.
As explained above, ARIPPA believes that its facilities should not be subject to the Proposed Rule, on the basis that EPA has not adequately justified a finding of significant contribution as to these sources. Further, to the extent that EPA identifies a justifiable basis to regulate the ARIPPA facilities under the Proposed Rule, EPA's proposed basis for determining unit-specific allowance allocations under the proposed FIP is inappropriate and inequitable. [EPA-HQ-OAR-2009-0491-2794.1, p.7]
EPA has proposed that each state's emission budget would be constructed from a combination of reported data and projected emissions data for the EGUs in that state. See "State Budgets, Unit Allocations, and Unit Emissions Rates", Technical Support Document ("TSD") for the Transport Rule, Dkt. ID No. EPA-HQ-OAR-2009-0491, EPA, Office of Air and Radiation, July 2010, at *3. In turn, each EGU's contribution to the state's budget forms the basis of its specific allowance allocation. Id. [EPA-HQ-OAR-2009-0491-2794.1, p.7]
In determining the proposed allowance allocations for affected EGUs in Pennsylvania, EPA relied on several considerations, including projected emissions. EPA attempts to project emission rates based upon its own assessment, reflective of integration between different modeled projections, of anticipated generating rates in the future. EPA's projections for future generating rates are closely linked to its assumptions concerning the future cost of electricity generation, focusing principally on fuel cost. Relative to the ARIPPA facilities, EPA's consideration of fuel cost is flawed in two important respects. First, EPA incorrectly estimates the cost of coal refuse as a fuel, as reflected by current fuel costs incurred at the point of fuel production. For example, an evaluation of current actual fuel costs for five representative ARIPPA plants yields an average cost of $1.48/MMBtu. One of these plants reports a current actual fuel cost as low as $0.82/MMBtu. These fuel costs are somewhat inflated insofar as they include, in some cases, costs not directly attributable to the cost of fuel, including ash disposal. Nonetheless, these cost figures are still meaningfully lower than the cost estimates relied upon by EPA to project future fuel costs for waste coal. [EPA-HQ-OAR-2009-0491-2794.1, p.7]
Second, EPA's reliance on fuel cost as the primary basis for projecting future generating rates fails to adequately account for numerous other factors affecting generating rates. For example, in Pennsylvania, electricity distribution facilities and suppliers are required to supply a certain percentage of energy from Tier I or Tier II renewable energy sources, irrespective of electricity prices. Therefore, distribution of the generation of electricity will not strictly adhere to lowest cost of generation, as other operative criteria dictate distribution. Because waste coal-generated electricity qualifies as a renewable energy source, waste coal-fired sources will operate at a higher generating rate than cost alone would suggest. [EPA-HQ-OAR-2009-0491-2794.1, p.8]
Additionally, the ARIPPA facilities are subject to contractual agreements pursuant to PPAs and other legal vehicles which dictate minimum or required energy generation and purchase rates, as between these generating facilities and electricity supply and distribution utilities. Pursuant to these agreements, subject to certain allowances for maintenance and downtime, these waste coal-fired EGUs will operate at a certain rate and supply a certain baseload quantity of electricity to the grid, regardless of relative costs of generation. [EPA-HQ-OAR-2009-0491-2794.1, p.8]
These factors, among others, measurably affect generating rates. It does not appear that EPA adequately (if at all) considered these factors in its projections of future generating rates for purposes of determining allowance allocations under the Proposed Rule. [EPA-HQ-OAR-2009-0491-2794.1, p.8]
Further, EPA apparently "predicts" a substantial decline in operating rates for virtually all the ARIPPA facilities, and then uses these predictions to determine allowance allocations for the facilities. By contrast, EPA projects that many larger traditional coal-fired EGUs will increase generating rates in the future, in some cases, substantially. In all cases, these projections are directly inconsistent with the operating history for these plants. This disparity between actual operating rates and those projected by EPA are reflected in the following table: [EPA-HQ-OAR-2009-0491-2794.1, p.8]
[Table 1 can be found on pages 8-10 of this comment.]
Relative to the ARIPPA plants, for the reasons stated above, EPA's projected rates of generation clearly understate reasonable estimations of future operations based on consideration of all relevant factors. Indeed, in many cases, EPA's projections directly conflict with specific contractual obligations undertaken by the plants pursuant to PPAs to supply alternative energy to utility companies at a fixed price. In other words, operation at the rates projected by EPA for purposes of the Proposed Rule would cause certain ARIPPA facilities to breach their contractual obligations. [EPA-HQ-OAR-2009-0491-2794.1, p.10]
C. EPA's approach for determining state emissions budgets overstates the projected downwind impact of Pennsylvania's emissions.
In North Carolina v. EPA, 531 F.3d 896, modified on reh'g, 550 F.3d 1176 (2008), the D.C. Circuit Court of Appeals concluded that Title I of the Clean Air Act requires EPA to develop a regulation addressing the interstate transport of air pollution that is reasonably designed to eliminate significant contribution and interference with maintenance of the National Ambient Air Quality Standards ("NAAQS") from emissions generated in upwind states. See also 75 Fed. Reg. 45271 (EPA recognizes that "reductions required pursuant to section 110(a)(2)(D)(i)(I) must be related to the goal of eliminating upwind state emissions that significantly contribute to nonattainment or interfere with maintenance of the NAAQS in downwind areas"). Indeed, the Court determined to vacate CAIR, in significant part because the Court determined that EPA's proposed regulatory scheme was not reasonably related nor designed to eliminate emissions significantly contributing to downwind nonattainment with the NAAQS. EPA suggests that the Proposed Rule would remedy the deficiencies of CAIR enumerated by the Court. In fact, however, the Proposed Transport Rule is equally suspect when evaluated against the standard articulated by the North Carolina Court. [EPA-HQ-OAR-2009-0491-2794.1, p.14]
Response: 
EPA has modified its allocation methodology to existing units in the final Transport Rule to be based on unit-level historic data.  See section VII.D of the preamble for a detailed explanation of how EPA allocates allowances under the Federal Implementation Plans (FIPs) in the final rule.
In regards to concerns about overstating the impact of state budgets on downwind air quality (listed in comment section C), see section IV of the preamble for a discussion of EPA's legal authority for the Transport Rule and how it is responsive to the Court's decision on CAIR.
Organization: Clean Air Task Force
Calpine Corporation
Wisconsin Power and Light Company
Entergy Services, Inc.
Fond du Lac Reservation
Clean Air Board of Central Pennsylvania
National Tribal Air Association (NTAA)
Comment: 
Calpine Corporation
The proposed emissions caps are stringent yet attainable. [EPA-HQ-OAR-2009-0491-3614, p.2]
Regarding the individual state emissions caps, we consider it fair to base the individual state caps on historic and projected emissions as determined through dispatch modeling. [EPA-HQ-OAR-2009-0491-3614, p.2]
Clean Air Board of Central Pennsylvania
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.58-59.]
The proposed EPA rule aims to remedy the identified flaws. We hope this proposed rule, as administered, will set real emission reductions for each state.
In implementing this proposal, EPA must ensure that there are tangible emission reductions by electric generating units and reduced levels of ambient fine particulate and ozone.
Clean Air Task Force
EPA must tighten the stringency of the proposed state budgets. The Clean Air Act requires, and the record abundantly supports, more substantial SO2 and NOx reductions from the electric power sector.
We urge the Agency to issue a rule that includes that following adjustments to its August 2 proposal: :reduces the 2014 annual control region NOx cap in to about 900,000 tons (including Texas) [EPA-HQ-OAR-2009-0491-2738.1, p.30]
Entergy Services, Inc.
We support EPA's preferred approach that sets a pollution limit (or budget) for each of the 31 states and the District of Columbia.   [EPA-HQ-OAR-2009-0491-2847.1 ,p.1]
Fond du Lac Reservation
The Band agrees with the more stringent nitrogen oxides ('NOx') and sulfur dioxide ('SO2') standards proposed under the Transport Rule. However, rather than the 1.4 million ton cap on NOx emissions and 2.6 million ton cap on SO2 emissions that the rule currently requires (for the Eastern U.S only), the Band supports a 900,000 ton cap on NOx emissions and 1.75 million cap on SO2 emissions for the entire nation . The ability to limit emissions to these lower amounts exists and would further increase the Rule's benefits which already substantially outweigh its costs. The American Lung Association and Clean Air Task Force also support these tighter limits. [EPA-HQ-OAR-2009-0491-3707, p.1]
National Tribal Air Association (NTAA)
Generally speaking, the NTAA agrees with the calls by other organizations such as the American Lung Association and Clean Air Task Force to establish more stringent nitrogen oxides (NOx) and sulfur dioxide (SO2) standards under the Transport Rule.  Specifically, our organizatin supports a 900,000 ton cap on NOx emissions and 1.75 million cap on SO2 emissions for the entire nation versus what the rule currently requires -- i.e., a 1.4 million ton cap on NOx emissions and a 2.6 million ton cap on SO2 emission, but only for the Eastern U.S. The ability to limit emissions to the former amounts exists and would further increase the Rule's benefits which already substantially outweigh its costs by a substantial degree. [EPA-HQ-OAR-2009-0491-2688.1, p. 2]
Wisconsin Power and Light Company
WPL requests that EPA's final rule evaluation use the highest four consecutive quarters of actual emissions during the 2007-2009 time period, rather than the most recent emissions data. EPA's use of the most recent consecutive actual emissions does not consider EGU outages or extraordinary events that could have affected operation of electric generation units. [EPA-HQ-OAR-2009-0491-2844.1 p.4]
Response: 
The final Transport Rule reflects updates to EPA modeling analysis and emissions inventories.  These updates influenced both the final Transport Rule geography and the state budgets ultimately set.  The sum of the state budgets set in the final Transport Rule is less than (tighter) the sum of state budgets in the proposal (for states included in both the proposal and final rule geography.  See section VI of the preamble for how EPA used a multi-factor analysis to determine these budgets.
In the final Transport Rule, EPA does not use historic emissions data to set the Transport Rule state budgets, but instead relies on projected emissions data under the marginal cost thresholds selected to define significant contribution and interference with maintenance.  EPA uses the same budget-setting methodology in the final rule on all pollutants analyzed (including ozone-season NOx, annual NOx, and SO2).  EPA believes this budget-setting methodology is more clear and easier to understand in connection with the Agency's modeling projections.  EPA believes the state budgets set under the final Transport Rule are an accurate reflection of its modeling of the removal of emissions identified as significant contribution and interference with maintenance from the states controlled.  For a discussion of this method and its results, please refer to section VI of the preamble for the final Transport Rule as well as the Significant Contribution and State Emissions Budgets Final Rule Technical Support Document.
Organization: Cleco Corporation
Comment: 
Cleco Corporation
A. EPA Should Use Reported Data from a Typical Three Year Period to Establish State Budgets and Unit Allocations.
EPA defines state budgets as the quantity of emissions remaining in a state from covered sources after elimination of that state's significant contribution to nonattainment and maintenance problems in an "average" year. EPA's attempts to define this "average" year are fundamentally flawed.  [EPA-HQ-OAR-2009-0491-2859.1 p.8]
Under the proposed rule, EPA sets state budgets based on the lower of total adjusted reported emissions or total adjusted projected emissions from all covered sources in the state. With respect to reported data, EPA uses the most recent "non-null" data for each quarter (first through fourth quarter) from 2007 through third quarter 2009. Louisiana's "average" year for SO2 is essentially reported data from the fourth quarter 2008 to third quarter 2009.16 This period is far from an average year. Beginning in 2008 though 2009, energy demand was down due to the worst economic downturn since the great depression. Further, natural gas prices were extraordinarily low. These facts can dramatically impact fuel choice and dispatch and result in atypical operations. [EPA-HQ-OAR-2009-0491-2859.1 p.8]
Instead of selecting a single year to represent average operations and emissions, consistent with past practice, EPA should use a three year period. It is mathematically impossible to get an average year from a single year's worth of data. A three year period would provide more representative data and would incorporate two full operational cycles for a typical EGU. Given the severe recession which began in 2008 and continued through 2009, we recommend that EPA rely on reported data from 2005 thorough 2007. [EPA-HQ-OAR-2009-0491-2859.1 p.8]
Response: 
In the final Transport Rule, EPA does not use historic emissions data to set the Transport Rule state budgets, but instead relies on projected emissions data under the marginal cost thresholds selected to define significant contribution and interference with maintenance.  EPA uses the same budget-setting methodology in the final rule on all pollutants analyzed (including ozone-season NOx, annual NOx, and SO2).  EPA believes this budget-setting methodology is more clear and easier to understand in connection with the Agency's modeling projections.  EPA believes the state budgets set under the final Transport Rule are an accurate reflection of its modeling of the removal of emissions identified as significant contribution and interference with maintenance from the states controlled.  For a discussion of this method and its results, please refer to section VI of the preamble for the final Transport Rule as well as the Significant Contribution and State Emissions Budgets Final Rule Technical Support Document.
Organization: Dominion
Comment: 
Dominion
EPA's Justification for the 2012 Budgets is Ouestionable
In any event, EPA has not provided reasonable justification for a 2012 initial compliance date for the proposed rule. The emission levels required purportedly are intended to reflect the reductions that would occur anyway (and according to EPA's assertion, evenin the absence of CAIR), although as noted in Section III, serious inaccuracies in EPA assumptions have yielded state emission budgets and unit allocations that significantly overestimate expected reductions. This raises question as to why the 2012 budgets arenecessary since in actuality, CAIR currently remains in place. Furthermore, EPA has not shown that emission reductions beyond those already required by CAIR are necessary by 2012. As noted earlier, EPA's own air quality trend data show that existing controls are working to reduce emissions and improve air quality. In addition, the D.C. Circuit's remand of CAIR did not include or remotely suggest that the overall degree of emission reductions required under CAIR was less than necessary to comply with the requirements of Section 110(a)(2)(D)(i)(I) of the Clean Air Act. [EPA-HQ-OAR-2009-0491-2715.1, p.14-15]
Response: 
See preamble section VII.C for more detailed discussion on why EPA finalized budgets for 2012.  EPA disagrees with the commenter's interpretation of the Court's opinion in North Carolina and notes that the Court specifically found the state budgets under CAIR to be flawed, notwithstanding their ability to generally improve air quality.  EPA believes its analysis as presented in section VI of the preamble supports the determination of state budgets for 2012 under the final Transport Rule, and the discussion in preamble section VII.C clearly demonstrates the feasibility of meeting those state budgets by 2012.  Furthermore, EPA disagrees with the commenter that these reductions would occur "in the absence of CAIR."  Section V.B of the final rule's preamble explains why EPA cannot legally rely on CAIR-driven emission reductions when determining the emission reductions legally required by the Transport Rule.
Organization: Duke Energy
Comment: 
Duke Energy
EPA Has Failed To Explain Why It Did Not Use 2008 Heat Input Data in Calculating SO2 Emission Budgets.
EPA proposes to set state emission budgets for annual and ozone season NOx and for SO2 based on the quantity of emissions that remain after elimination of significant contribution to nonattainment and interference with maintenance, but before accounting for variability. 75 Fed. Reg. at 45290/2. In its TSD addressing state budgets, EPA explains that it calculated 2012 state budgets using a combination of emissions and heat input data reported to EPA as of 2009 and IPM projections for 2012, each adjusted to reflect emissions control equipment projected by EPA to be in place by 2012. See State Budgets TSD at 3, 5.  [EPA-HQ-OAR-2009-0491-2689.1, p.16]
In that TSD, EPA notes that in creating the state budgets for annual and ozone season NOx, it "rebased" annual and ozone season NOx emissions for units reporting emission data to EPA by using 2008 rather than 2009 heat input. Id. at 9. According to EPA, this adjustment was made "to account for unusually low utilization (or heat input) in 2009." Id. During a conference call on August 30, 2010, however, EPA staff offered a different explanation for this adjustment. EPA staff indicated that the reason EPA used 2008 data was that the IPM projection of how sources operated their NOx controls in 2012 did not align well with the 2009 data but aligned more closely with the 2008 data. [EPA-HQ-OAR-2009-0491-2689.1, p.16]
EPA proposes to set state emission budgets for annual and ozone season NOx and for SO2 based on the quantity of emissions that remain after elimination of significant contribution to nonattainment and interference with maintenance, but before accounting for variability. 75 Fed. Reg. at 45290/2. In its TSD addressing state budgets, EPA explains that it calculated 2012 state budgets using a combination of emissions and heat input data reported to EPA as of 200913 and IPM projections for 2012, each adjusted to reflect emissions control equipment projected by EPA to be in place by 2012. See State Budgets TSD at 3, 5.  [EPA-HQ-OAR-2009-0491-2689.1, p.16]
In that TSD, EPA notes that in creating the state budgets for annual and ozone season NOx, it "rebased" annual and ozone season NOx emissions for units reporting emission data to EPA by using 2008 rather than 2009 heat input. Id. at 9. According to EPA, this adjustment was made "to account for unusually low utilization (or heat input) in 2009." Id. During a conference call on August 30, 2010, however, EPA staff offered a different explanation for this adjustment. EPA staff indicated that the reason EPA used 2008 data was that the IPM projection of how sources operated their NOx controls in 2012 did not align well with the 2009 data but aligned more closely with the 2008 data.   [EPA-HQ-OAR-2009-0491-2689.1, p.16]
Whatever the reason or reasons EPA used 2008 instead of 2009 heat input data for NOx, EPA did not make a similar adjustment for unit-reported SO2 emissions. EPA does not provide any explanation for this differential treatment of the issue between the two pollutants. EPA does, however, state repeatedly in the preamble that it developed the state budgets based on projected emissions "in an average year." See, e.g., 75 Fed. Reg. at 45214/2 ("A state's emissions budget is the quantity of emissions that would remain after elimination of the part of significant contribution and interference with maintenance the EPA has identified in an average year."); id. at 45271/2 (A state's budget "represent[s] the remaining emissions for the state in an average year."); id. at 45292/1 ("EPA has . . . developed state budgets based on its projections of state emissions in an average year."). Both the explanation in the TSD and the explanation offered on the August 30 conference call seem to indicate that 2009 heat input was not an average year, at least for NOx budget purposes. It is far from apparent why, if 2009 heat input was not average for -- and therefore was not used for -- NOx budget purposes, there would be any reason to use it for SO2 budget purposes. Before it proceeds further with this rulemaking, therefore, EPA will need to clarify and provide an adequate explanation for its decision to use 2009 emissions data for SO2. Prior to taking any final action to promulgate a rule, EPA should provide an opportunity for the public to comment on this important matter in light of an adequate explanation by the Agency. [EPA-HQ-OAR-2009-0491-2689.1, p.17]
Duke Energy Recommends that EPA Increase All State Budgets by 3 Percent for the Initial Year of the Program to Offset the Effect of the New Source Set-Aside
If EPA retains the proposed accelerated compliance schedule and continues to overstate the ability of existing emission controls to reduce emissions, Duke Energy recommends that the Agency increase state budgets across the board for NOx and SO2 for 2012 by at least 3 percent. The initial year of any new market based program like the Transport Rule is always challenging as was demonstrated by the Acid Rain, NOx Budget and other programs. This rule will be no exception. The unreasonable compliance schedule and the fact that EPA is currently counting on more emission reductions from existing emission controls than they will be able to deliver will make 2012 exceedingly challenging. As has been demonstrated in the past, sources need to over comply in order to develop some compliance margin to guard against the penalties of non-compliance. This has been the case with Acid Rain, NOx Budget and CAIR. However in each of those programs, there has been a mechanism for sources to earn early reduction credits or some other mechanism to ease the transition into the new program. Because of the haste that it has drafted this rule, and the speed at which it intends to impose it, EPA has unfortunately not developed such an option in this rule making, making matters worse. The 3 percent new source set-aside will further contribute to the stringency of the program for existing sources. Increasing NOx and SO2 state budgets across the board for 2012 will offset the adverse impact of the new source set-aside on existing units. [EPA-HQ-OAR-2009-0491-2689.1, pp.23-24]
EPA Should Use the Average of 2006 - 2008 Reported Heat Input/Emissions on a Unit-By-Unit Basis For Determining Adjusted Reported Emissions.
As discussed in section III E of these comments, in determining adjusted reported emissions which EPA then compares at a state level to projected 2012 emissions to establish state budgets for annual and ozone season NOx and for SO2 for 2012 for all states, EPA utilized 2008 reported heat input and 2009 ozone season emission rates for NOx, and the most recent reported non-null quarter 1; quarter 2, quarter 3, and quarter 4 emissions for SO2 (the most recent reported non-null quarter 1; quarter 2, quarter 3, and quarter 4 emissions for SO2 emissions is typically the 4th quarter of 2008 and the first 3 quarters of 2009).  [EPA-HQ-OAR-2009-0491-2689.1, p.27]
As EPA acknowledges in its TSD addressing state budgets, 2009 was an unusually low utilization, or heat input year.  Duke Energy agrees and believes that the use of 2009 data for determining reported NOx emissions would not have been appropriate. Duke Energy also believes that EPA's use of the most recent non-null quarter 1; quarter 2, quarter 3, and quarter 4 2009 reported SO2 emissions data to determine adjusted reported emissions is not appropriate. Contrary to EPA statements in the preamble that it developed the state budgets based on projected emissions "in an average year," (See, e.g., 75 Fed. Reg. at 45214/2, 2012) state budgets based on the most recent non-null quarter 1, quarter 2, quarter 3, and quarter 4 of reported emissions are anything but average. If EPA's intent is to develop budgets that represent an average year, then it should truly use average reported emissions and heat input data to determine each unit's adjusted reported emissions. Duke Energy recommends that EPA do this by modifying its method of determining adjusted reported emissions for SO2 and for annual and ozone season NOx. [EPA-HQ-OAR-2009-0491-2689.1, p.27]
For purposes of establishing a unit's adjusted reported annual SO2 emissions and adjusted annual and ozone season NOx emissions, and therefore for establishing each state's adjusted reported emissions which are compared to projected emissions, Duke Energy recommends that EPA look across three years of reported data, 2006, 2007, and 2008, and select for each unit the average of the reported data across this period (average annual emissions for SO2 and average non ozone season and ozone season annual heat input for annual and ozone-season NOx). This approach would be much more representative of normal utility operation than the method EPA used to determine adjusted reported SO2 and NOx emissions and would be better described as average than using a single year's data, either 2008 or 2009.15  [EPA-HQ-OAR-2009-0491-2689.1, p.28]
In developing state budgets under the NOx SIP Call and CAIR rules, EPA looked at multiple historical years of reported heat input data. EPA clearly believed this to be appropriate, to minimize unusual operations in any one year. It is therefore confusing why for the PTR, EPA decided to base every unit's reported emissions, and therefore each state's adjusted reported SO2 and NOx emissions, on a single 12 months of data. Due to the severe limitations on trading in the PTR, it is even more important that the budgets and resulting allocations to units must be based on accurate and representative data. That is, the more trading is limited, the more similar the program becomes to a hard cap or command and control program, and improperly set budgets will have significant consequences on individual units that would be less significant under a robust trading program.  [EPA-HQ-OAR-2009-0491-2689.1, p.28]
Footnote 15: While the method of using reported 2008 heat input for NOx is preferable to EPA having used the most recent non-null quarter 1; quarter 2, quarter 3, and quarter 4 of reported emissions, the use of average heat input data over 2006-2008 would yield results more representative of typical operations than using only 2008 data. [EPA-HQ-OAR-2009-0491-2689.1, p.28]
Response: 
In the final Transport Rule, EPA does not use historic emissions data to set the Transport Rule state budgets, but instead relies on projected emissions data under the marginal cost thresholds selected to define significant contribution and interference with maintenance.  EPA uses the same budget-setting methodology in the final rule on all pollutants analyzed (including ozone-season NOx, annual NOx, and SO2).  EPA believes this budget-setting methodology is more clear and easier to understand in connection with the Agency's modeling projections.  EPA believes the state budgets set under the final Transport Rule are an accurate reflection of its modeling of the removal of emissions identified as significant contribution and interference with maintenance from the states controlled.  For a discussion of this method and its results, please refer to section VI of the preamble for the final Transport Rule as well as the Significant Contribution and State Emissions Budgets Final Rule Technical Support Document.
  Furthermore, any unused new source set-aside allowances will be reallocated to existing sources two weeks before the allowance transfer deadline.  Therefore, they will be available for compliance for their vintage year.  Additionally, as described in section VII.C of the preamble, EPA believes there are multiple ways in which states will be able to comply with their budgets.  EPA has also adjusted its control removal efficiencies which addresses concerns raised by commenter that they were overstated in the proposed modeling.
Organization: Dynegy, Inc.
Comment: 
Dynegy, Inc.
Second, by EPA's own admission, if the proposed Transport Rule is finalized in mid- 2011 , no new scrubbers or SCRs could be built and placed into service by 2012. Without the ability to install new controls, compliance options for affected EGUs are limited to unit shutdowns and allowance purchases. Further, while EPA states 'it takes approximately 27 months to build a flue gas desulfurization unit (FGD, or 'scrubber')' and 'approximately 21 months to construct a selective catalytic reduction (SCR) unit', 75 Fed. Reg. at 45273, Dynegy believes that material and skilled labor shortages and outage scheduling issues would significantly lengthen those estimates if dozens of FGDs and SCRs had to be constructed in the near term. A Transport Rule with a start date of no earlier than 30 to 36 months after the rule is finalized would provide affected sources a broader range of compliance options -- including the time needed to install scrubbers and/or SCRs -- and a better chance of achieving compliance in a cost effective manner. [EPA-HQ-OAR-2009-0491-2698.1,p.2]
Response: 
See section VII.C of the preamble for a discussion of the compliance options available in 2012 (which include, but are not limited to, those listed above by commenter).  This section of the preamble also discusses the feasibility of advanced pollution control installation for the 2014 compliance period.  Additionally, EPA notes that it does not project any SCR retrofits in response to the final Transport Rule.
Organization: Edison Electric Institute (EEI)
Comment: 
Edison Electric Institute (EEI)
The electric power industry already has made significant progress in reducing emissions in NOx and SO2, according to EPA data, even while the nation has consumed more energy and the economy has grown. In fact, national SO2 emissions from power plants in 2009 were 67 percent lower than in 1980, and NOx emissions declined 72 percent over the same time period. Even more impressive is the 80 percent reduction in ozone season NOx emissions in the East. The Proposed Rule will lead to SO2 in most states being reduced by 80-90 percent since 1980. What is truly remarkable is that as these emissions reductions were taking place, the demand for electricity grew 75 percent. [EPA-HQ-OAR-2009-0491-2697.1, pp.3-4]
Response: 
The final rule analysis relies on projected emissions data under the marginal cost thresholds selected to define significant contribution and interference with maintenance.  EPA uses the same budget-setting methodology in the final rule for all pollutants analyzed (ozone-season NOx, annual NOx, and SO2).  EPA believes this budget-setting methodology is preferable to the approach in the proposal which relied on a combination of adjusted historic emissions data and projected emission data.  It is preferable because it more directly links the air quality modeling used to determine at what point significant contribution is eliminated to the budget formation process that limits emissions to those precise levels that would remain following such eliminations.  By directly basing budgets on the emission levels from the final cost threshold arrived at through the multi-factor analysis, the elimination of significant contribution is more accurately reflected in state budgets as opposed to the budget formation method used at proposal.  Additionally, it is more clear and easier to understand and provides a more accurate reflection of the emissions that will remain in the state following the elimination of all emissions identified by EPA as significantly contributing to nonattainment or interfering with maintenance of the relevant NAAQS in another state.  EPA made significant updates to IPM between proposal and final which addressed the concerns expressed by EPA in the proposal regarding the use of projected data for setting the 2012 state budgets.   For a discussion of this method and its results, please refer to section VI of the preamble for the final Transport Rule as well as the Significant Contribution and State Emissions Budgets Final Rule Technical Support Document.
Organization: Edison Mission Energy (EME)
Comment: 
Edison Mission Energy (EME)
[See EPA-HQ-OAR-2009-0491-2707.1, pp.17-22 for additional comments pertaining to EPA's Phase I NOx and SO2 Caps Are Premised On Incorrect Assumptions About The Level Of Emissions Controls Actually Achieved By Existing Emission Controls]
Based on the time available from the start of the comment period, let alone the date EPA proposes to finalize the Transport Rule, there is plainly not enough time for sources to install such upgrade and/or retrofits by 2012, and therefore compliance with the 2012 deadline is not technically feasible. As explained in Section III.B.4 below, EME generally supports EPA's stated objective of establishing Phase I emissions caps that are obtainable using existing controls, but notes that despite its stated objective EPA's Phase I caps do not actually reflect what is attainable with existing controls, and therefore the Transport Rule's Phase I caps should be increased.
Response: 
In the final Transport Rule, EPA does not use historic emissions data to set the Transport Rule state budgets, but instead relies on projected emissions data under the marginal cost thresholds selected to define significant contribution and interference with maintenance.  EPA uses the same budget-setting methodology in the final rule on all pollutants analyzed (including ozone-season NOx, annual NOx, and SO2).  EPA believes this budget-setting methodology is more clear and easier to understand in connection with the Agency's modeling projections.  EPA believes the state budgets set under the final Transport Rule are an accurate reflection of its modeling of the removal of emissions identified as significant contribution and interference with maintenance from the states controlled.  For a discussion of this method and its results, please refer to section VI of the preamble for the final Transport Rule as well as the Significant Contribution and State Emissions Budgets Final Rule Technical Support Document.
Organization: Environmental Defense Fund (EDF)
Comment: 
Environmental Defense Fund (EDF)
e. EPA's Remedial Action under Section 110(a)(2)(D) Must Prohibit Interstate Air Pollution that Contributes Significantly to Nonattainment with or Interferes with Maintenance of the Ozone NAAQS Promulgated in March 2008 
EPA must prohibit interstate air pollution on the basis of the 8-hour ozone NAAQS adopted in March 2008. The plain language of section 110(a)(2)(D) is capacious, instructing the Agency to prohibit the covered interstate air pollution "with respect to any such national or secondary ambient air quality standard." 42 U.S.C. § 7410(a)(2)(D)(I) (emphasis added). The term "such" in turn refers to section 110(a)(1) which triggers delineated state planning obligations under section 110 "after the promulgation of a national primary ambient air quality standard (or any revision thereof) under section 7409 of this title for any air pollutant." 42 U.S.C. § 7410(a)(1). Accordingly, the promulgation or revision of a NAAQS under section 109 for any air pollutant brings into force the prohibitions on interstate spillovers with respect to any such NAAQS. See also New York v. EPA, 443 F.3d 880, 885-86 (D.C. Cir. 2006) (holding the customary usage of the word "any" is to give the terms it modifies expansive meaning). EPA may not, by contrast, strip away the basic human health protections associated with the March 2008 NAAQS by ignoring its force. EPA must also be prepared to take prompt action to carry out the prohibitions under section 110(a)(2)(D) based on any decision to strengthen or revise the March 2008 ozone NAAQS. [EPA-HQ-OAR-2009-0491-2834.1 p.9]
Though EPA has stayed the 2008 ozone NAAQS for the purpose of attainment and nonattainment area designations during the interim reconsideration period,25 EPA itself has determined that such designations are unnecessary for carrying out EPA's remedial authority pursuant to CAA § 110(a)(2)(D). The promulgation of the revised NAAQS alone triggers states' rights and responsibilities under these protections. [EPA-HQ-OAR-2009-0491-2834.1 p.9]
Both the language and purpose of the statute support this interpretation. First, § 110(a)(1) requires all states to adopt and submit SIPs "within 3 years (or such shorter period as the Administrator may prescribe) after the promulgation of a national primary ambient air quality standard (or any revision thereof)."26 Every SIP must conform to the requirements of § 110(a)(2),27 including § 110(a)(2)(D)(i)(I). Because sections 110(a)(1) and (a)(2) apply to all states, regardless of their designation status, states' duty to comply with § 110(a)(2)(D) must be triggered simply by the promulgation of a new or revised NAAQS rather than the process of attainment and nonattainment area designations. This interpretation of § 110(a)(2) is bolstered by the fact that those sections of the CAA that take effect only after nonattainment area designations have been made explicitly mention such designations as a necessary condition to their operation.28 [EPA-HQ-OAR-2009-0491-2834.1 p.10]
Additional textual support for this interpretation of § 110(a)(2)(D) can be found in the language of § 110(a)(2)(D)(i)(I). Under § 110(a)(2)(D)(i)(I), states are required to submit SIPs containing adequate provisions prohibiting emissions activity within the state that will "contribute significantly to nonattainment in . . . any other State."29 When Congress intended a particular provision of the CAA to apply only to areas that have been formally designated nonattainment under § 107, they used the term "nonattainment area."30 The use of the word "nonattainment" in § 110(a)(2)(D)(i)(I) rather than the term "nonattainment area" suggests that this section does not depend on an area's formal designation status, but rather the actual air quality of the area. [EPA-HQ-OAR-2009-0491-2834.1 p.10]
This understanding of § 110(a)(2)(D) comports with the underlying purpose of the provision, which is to ensure that downwind states are not unfairly burdened in their attempt to attain NAAQS by pollutants emitted by upwind states. The formal nonattainment designation process triggers SIP requirements under § 172(c) for the states in which those nonattainment areas are located. If these areas are unable to attain solely as a result of emissions from upwind states, their efforts to comply with § 172(c) will represent precisely the kind of unfair burden on downwind states that § 110(a)(2)(D) was meant to alleviate. [EPA-HQ-OAR-2009-0491-2834.1 p.10]
EPA itself recognized the expansive protections under § 110(a)(2)(D) in carrying out its defense of its actions under the NOx SIP Call Rule,31 noting that "no air quality purpose will be served (32) by waiting for nonattainment designations and that "taking action now is necessary to protect the public health."33 Accordingly, EPA must address the 2008 ozone NAAQS in determining the necessary emissions reductions under the Transport Rule and take expeditious action to address interstate air pollution upon the promulgation of any new or revised ozone NAAQS in the pending reconsideration proceeding. [EPA-HQ-OAR-2009-0491-2834.1 p.10]
Response: 
On January 19, 2010, EPA proposed revisions to the 8-hour ozone NAAQS that the Agency had issued March 12, 2008 (75 FR 2938); the Agency intends to finalize its reconsideration in the summer of 2011.  EPA intends to propose a rule to address transport with respect to the reconsidered 2008 ozone NAAQS as expeditiously as possible after reconsideration is completed. See section III of the preamble for additional discussion.
Organization: Environmental Law & Policy Center
Comment: 
Environmental Law & Policy Center
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.78.]
We also urge EPA to go even further. The Rule seems to lessen the pollution-control obligations of several states in the midwest as compared CAIR.
Iowa, Missouri and Wisconsin will have sulfur dioxide and annual nitrogen oxide reductions, not seasonal reductions, and this seems counterintuitive.
Response: 
See EPA response to commenter concern over potential backsliding in section VI.D of the preamble.
Organization: Exelon
Comment: 
Exelon
EPA SHOULD REDUCE ANY STATE BUDGET UNDER THE TRANSPORT RULE TO THE LEAST OF (1) HISTORICAL EMISSION LEVELS, (2) THE STATE'S EXISTING CAIR BUDGET, OR (3) THE LEVEL ACHIEVABLE BASED ON EPA'S RECENTLY REVISED IPM MODELING ASSUMPTIONS.
In some cases, the budgets under the proposed Transport Rule are less stringent than those established under the rule that is being replaced. At the Philadelphia public hearing on the Transport Rule proposal, a representative of the PADEP testified that the technical support document that sets forth state emissions budgets establishes budgets for Pennsylvania that exceed those established and currently in effect under CAIR for annual and ozone-season NOX and for 2012-2013 SO2. Indeed, a comparison of Transport Rule budgets with CAIR budgets shows that this is the case for many proposed state NOX and SO2 budgets. CAIR presently remains in effect, and fossil fuel EGU owners have certainly been planning to comply with its limitations. Therefore, it is presumably feasible and cost effective for each CAIR state to achieve emissions budgets under the Transport Rule that it is already committed to achieving under CAIR. [EPA-HQ-OAR-2009-0491-2666.1, pp.27-28]
As noted above, EPA is legally obliged to establish state budgets that will eliminate upwind contribution to downwind nonattainment "as soon as practicable." It is clearly practicable to achieve historical emission levels, which have, by definition, already been achieved. It is clearly practicable to achieve budgets established under CAIR, which has been the law for five years. It is clearly practicable to achieve lower emission budgets developed using EPA's most current set of modeling assumptions. Each of these budget options is practicable, but only the lowest budget will comply with the court's demand that EPA's program achieve attainment "as soon as practicable." 53 EPA should, therefore, reduce the 2012 and 2014 budgets where they exceed the lowest of these three options. [EPA-HQ-OAR-2009-0491-2666.1, p.29]
[For additional comments pertaining to EPA SHOULD REDUCE ANY STATE BUDGET UNDER THE TRANSPORT RULE TO THE LEAST OF (1) HISTORICAL EMISSION LEVELS, (2) THE STATE'S EXISTING CAIR BUDGET, OR (3) THE LEVEL ACHIEVABLE BASED ON EPA'S RECENTLY REVISED IPM MODELING ASSUMPTIONS, see pp.27-29 of this comment summary]

53 Individual unit allowance allocations should be reduced pro rata to reflect the additional reductions required. With the alternative compliance mechanism and the alternative allocation mechanism, these reductions can readily be implemented within the existing framework of the Transport Rule.
Response: 
EPA has revised its process for determining state budget.  As suggested by the commenter, EPA used its recently revised IPM model with updated assumptions for determining the final state emission budgets.  
In the final Transport Rule, EPA does not use historic emissions data to set the Transport Rule state budgets, but instead relies on projected emissions data under the marginal cost thresholds selected to define significant contribution and interference with maintenance.  EPA uses the same budget-setting methodology in the final rule on all pollutants analyzed (including ozone-season NOx, annual NOx, and SO2).  EPA believes this budget-setting methodology is more clear and easier to understand in connection with the Agency's modeling projections.  EPA believes the state budgets set under the final Transport Rule are an accurate reflection of its modeling of the removal of emissions identified as significant contribution and interference with maintenance from the states controlled.  For a discussion of this method and its results, please refer to section VI of the preamble for the final Transport Rule as well as the Significant Contribution and State Emissions Budgets Final Rule Technical Support Document.
Organization: Exxon Mobil Corporation
Comment: 
Exxon Mobil Corporation
In the Preamble to the CATR/FIP, EPA stated: A state's emissions budget is the quantity of emissions that would remain in that state from covered sources after elimination of that portion of each state's significant contribution and interference with maintenance that EPA has identified in today's proposal, before accounting for the inherent variability in power system operations ... In other words, it provides a quantity of emissions to use in developing a remedy (e.g., the remedy should be designed to achieve the budget in an average year. Because the budget represents emissions that would remain without accounting for variability, it also represents the amount of emissions that would remain after significant contribution and interference with maintenance have been addressed, in an average year.[EPA-HQ-OAR-2009-0491-2841.1,p.4]
Thus, when the Base Case v. 4.10 projection shows a value below the budget, it is clear that significant contribution and interference no longer exist. [EPA-HQ-OAR-2009-0491-2841.1,p.4]
EPA's revised IPM v. 4.10 Base Case 2012 modeling shows that even without implementation of the CATR/FIP (or CAIR), reductions from Louisiana are already greater than those required reductions. The following table demonstrates this finding: [EPA-HQ-OAR-2009-0491-2841.1,p.4] [[See Docket Number EPA-HQ-OAR-2009-0491-2841.1, p.4 for the table.]]
Because 'significant contribution' and 'interference with maintenance' have been removed as shown by this revised IPM modeling, there is no basis for a CATR/FIP for annual SO2 or NOx control for Louisiana sources, as the level required to remove interference with maintenance will have already been achieved. [EPA-HQ-OAR-2009-0491-2841.1, p.5]
3. EPA's own modeling shows that the reductions in estimated Louisiana ozone season NOx emissions from the Transport Rule Base Case v. 3.02 to the Base Case v. 4.10 are greater than what EPA stated was needed to remove 'significant contribution' and 'interference with maintenance' in Texas. EPA indicated that the difference between the TR Base Case 2012 v. 3.02 and TR Limited Trading Option case represents the amount necessary for a state to reduce emissions in order to remove significant interference or and interference with maintenance.  EPA's revised IPM v. 4.10 Base Case 2012 modeling shows that even without implementation of the CATRJFIP (or CAIR), reductions from Louisiana are already greater than those required reductions. The following table demonstrates this finding: [EPA-HQ-OAR-2009-0491-2841.1,pp.7-8] [[See Docket Number EPA-HQ-OAR-2009-0491-2841.1, p.8  for the table.]]
Because 'significant contribution' and 'inteiference with maintenance' have been removed as shown by this revised IPM modeling, there is no basis for a CATR/FIP for ozone season NOx control for Louisiana sources. [EPA-HQ-OAR-2009-0491-2841.1,p.8]
Response: 
There are five states for 2012 ozone season NOx that have budgets equal to their base case emissions.  See section VI.D of the preamble for an explanation of why budgets were set at baseline emissions levels for these states.  For all other covered TR states in all other TR programs, the state budget in 2012 and/or in 2014 is less than baseline emissions.
Organization: Florida Electric Power Coordinating Group, Inc. (FCG)
Comment: 
Florida Electric Power Coordinating Group, Inc. (FCG)
EPA proposes to set state emission budgets for annual and ozone season NOx and for S02 based on the quantity of emissions that remain after elimination of significant contribution to nonattainment and interference with maintenance, but before accounting for variability. In its technical support document (TSD) addressing state budgets, EPA explains that it calculated state budgets using a combination of emissions and heat input data reported to EPA as of 2009 and projections by the Integrated Planning Model ('I PM') for 2012, each adjusted to reflect emissions control equipment projected to be in place by 2012. See 'State Budgets, Unit Allocations, and Unit Emissions Rates' TSD at 3,5. [EPA-HQ-OAR-2009-0491-2658.1, p.7]
In that TSD, EPA notes that in creating the state budgets for annual and ozone season NOx, it 'rebased' annual and ozone season NOx emissions for units reporting emissions data to EPA by using 2008 rather than 2009 heat input. According to EPA, this adjustment was made 'to account for unusually low utilization in 2009.' However, EPA did not make a similar adjustment for reported S02 emissions. EPA does not provide an explanation for this differential treatment of the issue as between the two pollutants. EPA must clarify and explain more fully why it chose to use 2008 instead of 2009 data for NOx and explain why it did not do the same for S02 data reported to EPA. [EPA-HQ-OAR-2009-0491-2658.1,p.7]
Response: 
EPA has modified the proposed methodology for determining the state emission budgets.  The revised methodology obviates the need for any adjustments to account for unusually low utilization in 2009 as it relies on projected 2012 and 2014 state emission levels instead of adjusted historic data.
Organization: Louisiana Energy and Power Authority (LEPA)
PowerSouth Energy Cooperative
Comment: 
Louisiana Energy and Power Authority (LEPA)
If, however, Louisiana is not excluded, then EPA should revisit and revise the process and methodology by which state budgets and unit allocations were determined. That process was unsound, provided insufficient opportunity for public participation, failed to consider local reliability concerns, and denied states a feasible opportunity to develop state implementation plans ('SIPs') before the January 1, 2012 effective date. [EPA-HQ-OAR-2009-0491-2700.1, p.2]
PowerSouth Energy Cooperative
The emissions budgets in the Proposal are convoluted. The Integrated Planning Model (IPM) modeling and related assumptions EPA used to analyze interstate transport and arrive at state budgets is the basis for this regulatory action.  The underlying methodology and assumptions are convoluted and complex.  PowerSouth participates in a number of utility industry groups in a concerted effort to understand and participate in the rulemaking process.  Despite our best efforts, PowerSouth does not understand the IPM modeling and assumptions that EPA used to arrive at its proposed remedy.  EPA has failed to provide states and the regulated community the opportunity and resources necessary to review and comment on the very basis of this Proposal.  [EPA-HQ-OAR-2009-0491-2693.1,pp.2-3] 
Response: 
In the final Transport Rule, EPA has improved the process for determining state emission budgets.  The final approach used to determine state budgets is more transparent and less complex.  It is described in section VI of the preamble.  By relying on state level projected emissions to determine budgets, EPA does inherently consider reliability concerns.  The IPM model has regional reserve margin constraints that capture system reliability requirements by defining a minimum margin of reserve capacity (in megawatts) per year.  See EPA IPMv.4.10 documentation for additional details.
Organization: Massachusetts Department of Environmental Protection
National Association of Clean of Air Agencies (NACAA)
NextEra Energy, Inc.
PSEG Services Corporation
Mothers and Others for Clean Air
Comment: 
Massachusetts Department of Environmental Protection
While we are pleased with the proposed state annual S02 budgets, we believe that the NOx budgets EPA has proposed for the annual and ozone season trading programs are too high and will not result in the emissions reductions from upwind power plants that are needed to achieve clean ail' in Massachusetts. MassDEP supports a 900,000 ton annual NOx cap and a proportional  [EPA-HQ-OAR-2009-0491-2787.2 p.1]
Mothers and Others for Clean Air
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.23.]
We also ask that EPA work as quickly as possible to reevaluate emission budgets in the Transport Rule as the standard for fine particulate matter is reviewed and possibly strengthened in coming years.
National Association of Clean of Air Agencies (NACAA)
The 2014 NOx Emissions Cap Should Be Tightened
The NOx emissions caps in the proposed Transport Rule are not stringent enough. EPA admits that there are 10 states for which the agency has "only quantified a minimum amount of emissions reductions needed to make measurable progress towards eliminating their significant contribution and interference with maintenance with respect to" the 1997 ozone standard. 2 Furthermore, while EPA proposes to lower the SO2 cap in 2014, the agency makes no such adjustment for NOx. Although EPA says it will address the NOx reductions needed to meet the soon-to-be promulgated revised ozone standard in Transport Rule II, it is imperative that the agency include in this Transport Rule a second, tighter annual NOx cap in 2014 to assist states in attaining the 1997 ozone standard (85 parts per billion) and 2006 PM2.5 standards. 3 Analysis by NACAA and the Ozone Transport Commission suggests a 900,000 ton annual NOx cap in 2014 is technologically feasible and cost-effective, and EPA's analysis confirms the cost-effectiveness of additional NOx reductions. 4 [EPA-HQ-OAR-2009-0491-2771.1, p.3]
Emissions of Other Sources Also Need to Be Reduced to Eliminate Transport
The Transport Rule Fails to Completely Eliminate Transport The proposed Transport Rule does not completely satisfy section 110(a)(2)(D)'s requirements to eliminate emissions that significantly contribute to downwind nonattainment [EPA-HQ-OAR-2009-0491-2771.1, p.3] or interfere with maintenance. As mentioned previously, there are dozens of states 5 that will need to do more in order to satisfy their Clean Air Act obligation to address transport, unless EPA reduces the NOx and SO2 emissions caps. We are disappointed that after spending a year-and-a-half to analyze interstate transport, EPA presents us with an incomplete solution. [EPA-HQ-OAR-2009-0491-2771.1, p.4] The 2014 NOx Emissions Cap Should Be Tightened
The NOx emissions caps in the proposed Transport Rule are not stringent enough. EPA admits that there are 10 states for which the agency has "only quantified a minimum amount of emissions reductions needed to make measurable progress towards eliminating their significant contribution and interference with maintenance with respect to" the 1997 ozone standard. Furthermore, while EPA proposes to lower the SO2 cap in 2014, the agency makes no such adjustment for NOx. Although EPA says it will address the NOx reductions needed to meet the soon-to-be promulgated revised ozone standard in Transport Rule II, it is imperative that the agency include in this Transport Rule a second, tighter annual NOx cap in 2014 to assist states in attaining the 1997 ozone standard (85 parts per billion) and 2006 PM2.5 standards. Analysis by NACAA and the Ozone Transport Commission suggests a 900,000 ton annual NOx cap in 2014 is technologically feasible and cost-effective, and EPA's analysis confirms the cost-effectiveness of additional NOx reductions. [EPA-HQ-OAR-2009-0491-2771.1, p.3]
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.106-107.]
NACAA also supports the Agency's use of air quality factors and a health benefits assessment calculating states' emissions budgets, rather than basing the budget solely on the availability of cost-effective controls.
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.80.]
Furthermore, at this time the proposed SO2 caps especially the tightened 2014 cap appear to be sufficiently stringent to meet most states needs.

Footnote:
2 75 Federal Register 45214.
3 We believe a tighter annual NOx cap is called for because (1) ozone seasons vary in states, and states experience ozone problems outside the months covered by EPA's seasonal NOx program; and (2) research in the Midwest points to nitrates driving wintertime PM2.5 attainment problems. Jaemeen Beck, et al, "Episodic Air Pollution in Wisconsin (LADCO Winter Nitrate Study) and Georgia (SEARCH Network) During Jan-Mar 2009," (forthcoming 2010).
4 Senator Thomas Carper (D-DE) asked EPA to analyze the impacts of a 900,000 ton NOx cap in the East beginning in 2015 as a possible alternative to the 1.3 million ton cap in 2015 in his bill, the Clean Air Act Amendments of 2010 (S. 2995). The more stringent NOx caps provided between $3-10 billion in additional benefits each year at a cost of $1.5 billion. "EPA Analysis of Alternative NOx and SO2 Caps for Senator Carper" (July 16, 2010).
5 There are ten eastern states for which EPA has not completely quantified the total significant contribution or interference with maintenance with respect to the 1997 ozone NAAQS and 15 states for which EPA has not completely quantified total significant contribution or interference with maintenance with respect to the 2006 PM2.5 NAAQS. 75 Federal Register 45214.
While the ultimate responsibility for attaining the ozone and PM2.5 National Ambient Air Quality Standards (NAAQS) lies with state and local clean air agencies, federal control measures limiting emissions of NOx and SO2 are critical, due to the overwhelming transport problem in the Northeast, Mid- Atlantic, Southeast and Midwest (i.e., the region covered by the proposed Transport Rule). Accordingly, EPA needs to promulgate a strong timely Transport Rule. [EPA-HQ-OAR-2009-0491-2771.1, p.1]
NextEra Energy, Inc.
NextEra Ellergy supports EPA's preferred methodology for developing state budgets. From NextEra Energy's perspective, EPA appropriately uses a multi-step process that includes both air quality and cost modeling to calculate state contributions to downwind nonattainment and interference with maintenance. As EPA discusses in the preamble to the proposed Transport Rule, it is important to require that emission reductions are achieved as expeditiously as possible. Under EPA's preferred methodology for determining the 2012 state budgets, the Agency uses a mix of Integrated Planning Model (IPM) modeling,reported emissions, and adjustments to both modeled and reported emissions based on pollution control technologies installed or projected to be installed before 2012. By using this methodology, EPA intends to avoid backsliding from the progress made in response to CAIR in the control of emissions from units in the Transport Rule region. Under the unique circumstances resulting from the vacatur of CAIR, NextEra Energy supports this methodology for establishing initial state budgets for annual NOx, ozone season NOx, and2012 S02 in botll Group 1 and 2 states. In our view, this methodology would not be appropriate for future rule makings because it would not result in the most cost-effective emissions reductions. However, NextEra Energy understands that  vacatur of CAIR creates a unique situation for EPA and agrees that the proposed approach is appropriate for the initial state budgets. [EPA-HQ-OAR-2009-0491-0298.1 p.2]
NextEra Energy also supports EPA's exclusive use ofIPM runs to set state budgets for 2014 Group 1 S02emissions using pollution control cost thresholds. NextEra Energy understands and supports that this methodology would be the basis for establishing any revised state budgets in any of the four programs (e.g.,ozone season NOx, annual NOx, Groups 1 and 2 S02) as necessary to comply with future NAAQS revisions.[EPA-HQ-OAR-2009-0491-0298.1 p.2]
NextEra Energy supports EPA's preferred methodology for developing state budgets.
From NextEra Energy's perspective, EPA appropriately uses a multi-step process that includes both air quality and cost modeling to calculate state contributions to downwind nonattainment and interference with maintenance. As EPA discusses in the preamble to the proposed Transport Rule, it is important to require that emission reductions are achieved as expeditiously as possible. Under EPA's preferred methodology for determining the 2012 state budgets, the Agency uses a mix of Integrated Planning Model (IPM) modeling, reported emissions, and adjustments to both modeled and reported emissions based on pollution control technologies installed or projected to be installed before 2012. By using this methodology, EPA intends to avoid backsliding from the progress made in response to CAIR in the control of emissions from units in the Transport Rule region. Under the unique circumstances resulting from the vacatur of CAIR, NextEra Energy supports this methodology for establishing initial state budgets for annual NOx, ozone season NOx, and 2012 SO2 in both Group 1 and 2 states. In our view, this methodology would not be appropriate for future rulemakings because it would not result in the most cost-effective emissions reductions. However, NextEra Energy understands that the vacatur of CAIR creates a unique situation for EPA and agrees that the proposed approach is appropriate for the initial state budgets. [EPA-HQ-OAR-2009-0491-2718.1, p.2]
NextEra Energy also supports EPA's exclusive use of IPM runs to set state budgets for 2014 Group 1 SO2 emissions using pollution control cost thresholds. NextEra Energy understands and supports that this methodology would be the basis for establishing any revised state budgets in any of the four programs (e.g., ozone season NOx, annual NOx, Groups 1 and 2 SO2) as necessary to comply with future NAAQS revisions. [EPA-HQ-OAR-2009-0491-2718.1, p.2]
PSEG Services Corporation
PSEG supports EPA's preferred methodology for developing state budgets. [EPA-HQ-OAR-2009-0491-2726.1, p.2]
PSEG supports EPA's preferred methodology for developing state budgets. EPA appropriately uses a multi-step process that includes both air quality modeling and cost modeling to calculate state contributions to downwind nonattainment and interference with maintenance. As EPA discusses in the preamble to the proposed rule, it is important to require that emission reductions are achieved as expeditiously as possible. By using the preferred methodology for determining the 2012 state budgets, EPA avoids backsliding from CAIR in the control of emissions from units in the Transport Rule region. PSEG supports this methodology for establishing state budgets for annual NOx, ozone season NOx, and 2012 SO2 in proposed Group 1 and 2 states. [EPA-HQ-OAR-2009-0491-2726.1, p.5]
Response: 
In the final Transport Rule, EPA does not use historic emissions data to set the Transport Rule state budgets, but instead relies on projected emissions data under the marginal cost thresholds selected to define significant contribution and interference with maintenance.  EPA uses the same budget-setting methodology in the final rule on all pollutants analyzed (including ozone-season NOx, annual NOx, and SO2).  EPA believes this budget-setting methodology is more clear and easier to understand in connection with the Agency's modeling projections.  EPA believes the state budgets set under the final Transport Rule are an accurate reflection of its modeling of the removal of emissions identified as significant contribution and interference with maintenance from the states controlled.  For a discussion of this method and its results, please refer to section VI of the preamble for the final Transport Rule as well as the Significant Contribution and State Emissions Budgets Final Rule Technical Support Document.
Organization: Minnesota Power 
Comment: 
Minnesota emission reduction controls already in place. EPA projects that Minnesota has already provided for emission reductions sufficient to meet EPA's proposed 2012 Group 2 State SO2 and NOx emission budgets and concludes the 2012 compliance date for the Transport Rule is achievable.  Related EPA characterization that such emission reductions were implemented in anticipation of CAIR compliance ignores the record for the Minnesota Clean Air Visibility Rule, State Implementation Plan submitted to EPA for approval.  [EPA-HQ-OAR-2009-0491-2750.1, p.7]   
Response: 
EPA's modeling for the final Transport Rule captures any non-CAIR state and federal legal and enforceable emission limitations.  Therefore, the final rule air quality modeling that determined Minnesota's inclusion in the final Transport Rule for fine particles already accounted for any emission reductions achieved by "on-the-books" emission limitation requirements (except for CAIR, as explained in preamble section V.B).  EPA does not include proposed SIP emission control requirements that have not yet been formally approved and legally applied.  The IPM documentation has a list of state rules (and covered pollutants) that are captured in the final Transport Rule modeling.  Minnesota is included in this list and appears in the documentation.
Organization: New York State Department of Environmental Conservation
Comment: 
New York State Department of Environmental Conservation
Basis of Emission Budgets I Variability
State emissions budgets should reflect the emission reductions necessary to prevent SC/IM using the maximum design value rather than an average value based on a three-year period. This is the only way to assure that during any given year, a NAAQS violation will not occur due to transport. Also, emission budgets should reflect levels needed to eliminate SC/IM and not 'cost effective' controls in a given state, and must be designed to prohibit emissions that cause SC/IM. Any variability limit should be applied in a manner such that emissions causing SC/IM are prohibited, or at least mitigated. That is, the sum of a state's budget and the variability limit should be equal to or less than the emission reductions necessary to avoid SC/IM or EPA's trading program mitigation measures need to be applied once the budget is exceeded. Still, any variability limit that EPA might establish should start at the beginning of the program (for this case, 2012). [EPA-HQ-OAR-2009-0491-2730.1, p.7; This comment can also be found at section IV.F.1 of this comment summary]
Allowing an additional variable emission quantity over and above the state budget that is needed to achieve SC/IM may result in non-compliance with a NAAQS. For example, it is likely that plants in one state may have a higher than average cost of controls than the costs of another state due to higher costs of living or smaller power plants which generally have higher control costs than another state. It would be reasonable to expect that plants in the latter state would control more to offset their costs and sell allowances in the former. Without some mechanism to keep emissions in a particular state to a level at or below the budgets established to eliminate SC/IM, there can be no assurance that the transported emissions that significantly contribute to nonattainment or interfere with maintenance are eliminated. Another shortcoming is that the year to year variability treatment does not take into account that air pollution is generally episodic in nature. Higher emissions are more likely when the potential for ozone and PM2.5 formation is greatest. [EPA-HQ-OAR-2009-0491-2730.1, p.7; This comment can also be found at section IV.F.1 of this comment summary]
Response: 
State emission budgets reflect emissions in an average year after the elimination of "SC/IM" or, in the case of some states for ozone, it reflects progress towards this elimination.  EPA believes that state emissions after the elimination of "SC/IM" will have variability, and this is reflected in the variability limits.  See section VI.E of the preamble for further discussion.  Also, as suggested by commenter, EPA is finalizing variability limits to start at the beginning of the Transport Rule program.
Organization: Northeast States for Coordinated Air Use Management (NESCAUM)
Comment: 
Northeast States for Coordinated Air Use Management (NESCAUM)
Furthermore, we strongly recommend that EPA use a bottom-up approach to setting budgets. The approach would entail evaluating a specific strategy and starting out with those specific technologies, and applying the appropriate controls to each unit in the database. EPA could then calculate the emissions rates and then model the strategy using an air quality database. This analysis would be conducted on a state-specific, unit-specific basis, by fuel type. Once the emissions rates were determined, EPA could calculate the emissions and assess whether those emissions triggered the 1% significant contribution linkage criterion through CMAQ. The IPM model could then be used for assessing costs (not establishing the budgets), and an air quality model, such as CMAQ or CALGRID, could be used to assess air quality benefits. We understand that EPA has employed a similar, but not as comprehensive, approach in conducting assessments of other cap-and-trade programs (i.e., EPA did not analyze on the state-specific level nor employ air quality modeling). While this approach would entail multiple runs and take more time than EPA's current approach, it would produce results that we feel are more aligned with the intent of the program, and the July 11, 2008 decision of the U. S. Court of Appeals for the District of Columbia Circuit. [EPA-HQ-OAR-2009-0491-2694.1, pp.6-7]
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.12.]
Finally, we anticipate some issues with the proposed state budgets, and have identified some questionable assumptions used in the analysis. Our states will document these in our written comments.
Response: 
In the final Transport Rule, EPA does not use historic emissions data to set the Transport Rule state budgets, but instead relies on projected emissions data under the marginal cost thresholds selected to define significant contribution and interference with maintenance.  EPA uses the same budget-setting methodology in the final rule on all pollutants analyzed (including ozone-season NOx, annual NOx, and SO2).  This multi-factor approach described in section VI.D of the preamble takes into account air quality and cost considerations when determining state budgets.
Organization: Ohio Utility Group (OUG)
Comment: 
Ohio Utility Group (OUG)
C. The Proposed Transport Rule handcuffs the states, leaving no real choice for implementing emissions limitations 
The validity of EPA's budget system under the Transport Rule hinges on whether the states have any real choice in implementing Section 110 requirements. Under the proposed Transport Rule, the states are handcuffed with no choice other than implementing EPA's unit-specific emissions limitations. The proposed rule's timing requirements and EPA's use of 'default' limitations scattered throughout the proposed rule and the NODA deny the states their Section 110 authority to make unit-specific limitations. [EPA-HQ-OAR-2009-0491-3761.1_NODA, p.7]
The Supreme Court has defined 'emissions limitations' as 'regulations of the composition of substances emitted into the ambient air. .. They are the specific rules to which operators of pollution sources are subject.,,16 Ultimately the Court concluded that Section 110 of the CAA grants to each state primary authority 'to adopt whatever mix of emissions limitations it deems best suited to its particular situation.'  In light of Train, the validity of EPA's budget program under the proposed Transport Rule depends on 'whether the program in effect constitutes an EPA-imposed control measure or emission limitation.' The Michigan court explained that an EPA-imposed control measure is one where 'the program constitutes an impermissible means rather than a permissible end goal.' In other words, EPA exceeds its (secondary) Section 110 authority when a rulemaking, promulgated pursuant to Section 110, denies covered states choice with respect to implementing emissions limitations. [EPA-HQ-OAR-2009-0491-3761.1_NODA, p.7]
The proposed Transport Rule includes provisions effectively denying the states any real choice. In Michigan, EPA's budget program was upheld because: 1) EPA made clear that the states do not have to adopt the control scheme that EPA assumed for budget-setting. The proposed Transport Rule does not give states this option; 2) states remain free to implement other cost-effective measures in place of the ones identified by EPA, such as giving states the option to focus on mobile sources rather than stationary sources. EGUs, and only EGUs, bear the burden of the emissions limitations under the proposed Transport Rule; and 3) EPA gave the states full discretion in selecting controls, including participation in an interstate trading program. The proposed Transport Rule does not grant such latitude. [EPA-HQ-OAR-2009-0491-3761.1_NODA, p.7]
Furthermore, all of EPA's 'default' emissions limitations constitute the exact 'impermissible source-specific means' prohibited by the D.C. Circuit. Assigning a 'default' number for any emissions limitation is ill-advised. The effectiveness of control technology depends on numerous unit-specific operating variables. EPA's default to a 98% removal rate of S02 for new scrubber installations is one example of a faulty assumption. Achieving a 98% removal rate for a new scrubber may be obtained on an intermittent basis. However, achieving 98% removal on an annual basis could only be achieved in a vacuum where no operational variability could occur. Based on years of historical operating data and unit-specific knowledge, the Utilities recommend that, if EPA maintains its 'default' limitations, S02 removal rates for new scrubber systems be reduced to 95%. In addition, AEP requests that scrubber efficiency at Gavin Units 1 and 2 be revised to 94.5%. [EPA-HQ-OAR-2009-0491-3761.1_NODA, pp.7-8]
Establishing 'default' limitations is likely a direct result of EPA's lack of unit-specific knowledge and realization that EPA simply does not have the capability to acquire the detailed unit-specific knowledge required to make such decisions. Therefore, the Utilities caution EPA in setting 'default' limitations, especially at the upper-end of the spectrum. [EPA-HQ-OAR-2009-0491-3761.1_NODA, p.8]
Response: 
See section X of the preamble for discussion on State Implementation Plans.  In regards to commenters suggestions about adjusting SO2 removal efficiency, EPA updated its IPM modeling to reflect removal rates for existing FGDs that are based on historic removal efficiencies for the particular unit.  It also lowered its removal efficiency assumptions for new FGD retrofits.  The budgets set in the final Transport Rule were based on modeling that reflected these updated assumptions.
Organization: Ozone Transport Commission (OTC)
Comment: 
Ozone Transport Commission (OTC)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.115-116.]
A key reason that significant contribution is not eliminated by the proposed Transport Rule is that the NOX caps are not stringent enough. The proposed 2012 NOX caps are actually more generous than those that were required in CAIR phase 2, beginning in 2015.
We urge EPA to tighten the NOX caps in this rulemaking to a level that fully eliminates significant contribution.
Response: 
EPA has finalized different state emissions budgets for annual and ozone season NOx than those proposed.  
In the final Transport Rule, EPA does not use historic emissions data to set the Transport Rule state budgets, but instead relies on projected emissions data under the marginal cost thresholds selected to define significant contribution and interference with maintenance.  EPA uses the same budget-setting methodology in the final rule on all pollutants analyzed (including ozone-season NOx, annual NOx, and SO2).  EPA believes this budget-setting methodology is more clear and easier to understand in connection with the Agency's modeling projections.  EPA believes the state budgets set under the final Transport Rule are an accurate reflection of its modeling of the removal of emissions identified as significant contribution and interference with maintenance from the states controlled.  For a discussion of this method and its results, please refer to section VI of the preamble for the final Transport Rule as well as the Significant Contribution and State Emissions Budgets Final Rule Technical Support Document.
Organization: Prairie State Generating Company, LLC
Comment: 
Prairie State Generating Company, LLC
PSGC suggests in the case of new sources, all units at the source should be considered 'existing' units if construction is well underway and at least one unit has commenced commercial operation by January I, 2012. This expansion of the definition would likely affect very few sources; indeed, the U.S. EPA projects growth of coal-fired units at a level of only 3% in the entire region. PSGC's suggestion preserves the U.S. EPA's apparent intent to limit the number of units that would be 'existing' units. The PSD program requires that construction be continuous. Therefore, it is very likely that all units at any new sources under construction with at least one unit that has commenced commercial operation by January 1, 2012, or will have commenced commercial operation by January 1, 2014, the date demarcating Phase 2 of the proposed Transport Rule Program. [EPA-HQ-OAR-2009-0491-2842.1, p.2]
In the alternative, 'existing units' should be those that have been issued construction permits by January 1,2012, and have commenced commercial operation by January 1,2014. Unless the permit for new units are currently in the queue, it is highly unlikely that there would be a run on permitting authorities to issue new PSD permits and such permits would become final and effective before January 1,2012. Therefore, the universe of units which will commence commercial operation by January 1,2014, is small, should be known, 2 and will not adversely impact the U.S. EPA's analysis. [EPA-HQ-OAR-2009-0491-2842.1, p.2]
Moreover, for these few new sources, PSGC believes the applicable statewide budgets should be expanded to reflect these additional units. As discussed elsewhere in these comments, in the case of PSGC, it appears that the U.S. EPA's modeling included emissions attributable to PSGC as 'planned-committed' units. Therefore, expansion of the statewide budget to accommodate PSGC's allocation would not alter U.S. EPA's air quality analyses. [EPA-HQ-OAR-2009-0491-2842.1, p.2]

2 We recognize, however, that EPA is apparently not aware of all new units, since PSGC's units were not included on the list of allocations to 'existing' units, although a review of the data suggests that EPA may have included these units in the 'planned-committed' category. [EPA-HQ-OAR-2009-0491-2842.1, p.2]
Response: 
As explained in section VII.D of the preamble, units that commence commercial operation after January 1, 2010 are considered new units because EPA would not have one full year's worth of data on which to base these units' allocation if considered an existing unit.  However, EPA appreciates the commenters concern and has made modifications in the final Transport Rule in regards to the size of new source set-asides to address the issue raised by commenter.  Commenter correctly observed that some "planned-committed" units were reflected in EPA's modeling.  Because any "planned-committed" units that came online after 2009 are considered new units for Transport Rule purposes, the emission levels pertaining to those units under a Transport Rule scenario are reflected under the new source set-aside instead of the existing unit budget.  This has the impact of make the new source set-aside accounts larger in states where units are scheduled to come online, and consequently makes more allowances available to these units.
Organization: Rhode Island Department of Environmental Management
Comment: 
Rhode Island Department of Environmental Managment
[[2818.1 p.1-2]]
Rhode Island suggests that EPA give consideration to revising its proposed rule to include a system to allocate allowances to new units in those states that EPA evaluated for contribution to downwind nonattainment and maintenance and detennined their contributions were not significant.
The purpose of such a provision would be to mitigate 'leakage' i.e. increased emissions from sources outside ofthe budget/cap that offsets some ofthe anticipated reductions from the sources covered by the budget.
The current proposal does not a include mechanism for limiting this 'out-of-budget' growth in emissions. Two possible consequences of this shortfall in the rule are, if a new source locates in a non-contributing state and displaces an older source in a budget state, there is no commensurate reduction in the budget of that state under the current proposal, whereas if the new source was located in the budget state there would be the reduction. Additionally, if a non-contributing state was just marginally below the threshold for significant contribution, the current proposal has no mechanism to control growth in that state and therefore, unrestricted growth could allow that state to then significantly contribute to a downwind state's nonattainment.
One suggested approach would be to hold back a quantity of allowances from the total of all of the state budgets for a new unit set aside allowance pool for those states. Any unused allowances from the new unit .set aside allowance pool for a given compliance period could be allocated back to the individual state budgets.
Response: 
EPA analyzed the possibility of emissions increases in non-Transport Rule states.  However, EPA does not impose limits or require reductions from these states because its analysis suggested that no non-Transport Rule state's emissions would increase to the point where it tipped that state into a contributing on "linked" status as described in section V of the preamble.  See section V.C and VI and XII.J for further discussion.
Organization: RRI Energy, Inc.
Comment: 
RRI Energy, Inc.
Please note, though, that RRI's support for these aspects of the proposed CATR is tempered by our lack of a complete and comprehensive understanding of the inputs, programming logic and outputs from the Integrated Planning Model (IPM) and Comprehensive Air Quality Model with Extensions (CAMx), which are the primary tools used to establish the state emissions budgets. Concerns with the difficulty in accounting for IPM model results that appear to be contrary to the information available to various stakeholders and EPA's reluctance to fully disclose the IPM programming logic (presumably because of the proprietary nature of IPM) have been previously expressed to EPA by industry and other stakeholders. These developments have in fact resulted in recent actions undertaken by the Eastern Regional Technical Advisory Committee (ERTAC2) to develop an alternative to IPM for use by state and regional air quality planning entities to grow base hourly electric generating unit (EGU) inventories into future projection years for air quality impact assessments on both an annual and episodic peak basis. ERTAC's recent efforts have been shared with EPA, and ERTAC is awaiting EPA's response. RRI requests EPA to conduct IPM and CAMx training and outreach sessions during the upcoming months to allow stakeholders the opportunity to develop a greater understanding of IPM and CAMx with the ultimate goal of establishing a more transparent process used to determine the state emissions budgets. [EPA-HQ-OAR-2009-0491-2717.1 p.2]
RRI has reviewed the unit characteristics information for our units included in the budget allocation data file. All information is correct with the exception of the generating capacity data (defined as the net summer ratings). A comparison of the capacities presented in the CATR with the capacities determined by RRI (and in accordance with the test procedures specified by the local electrical grid operator) is presented in Attachment 1. If CATR applicability is defined as units with capacities greater than 25 MWe, then this comparison shows that the following RRI units have been incorrectly identified as being CATR-affected units:
Ohio: Niles CTA (ORIS 2861)
Pennsylvania: Hamilton 1 (ORIS 3109)
Mountain 31 and Mountain 32 (ORIS 3111)
Tolna 31 and Tolna 32 (ORIS 3116)
RRI requests that the unit characteristics information be updated to reflect the most current net summer capacity and CATR-applicability data. Supporting documentation for the net summer capacities can be provided upon request. [EPA-HQ-OAR-2009-0491-2717.1 p.6]
Response: 
In the final Transport Rule, EPA does not use historic emissions data to set the Transport Rule state budgets, but instead relies on projected emissions data under the marginal cost thresholds selected to define significant contribution and interference with maintenance.  EPA uses the same budget-setting methodology in the final rule on all pollutants analyzed (including ozone-season NOx, annual NOx, and SO2).  EPA believes this budget-setting methodology is more clear and easier to understand in connection with the Agency's modeling projections.  EPA believes the state budgets set under the final Transport Rule are an accurate reflection of its modeling of the removal of emissions identified as significant contribution and interference with maintenance from the states controlled.  For a discussion of this method and its results, please refer to section VI of the preamble for the final Transport Rule as well as the Significant Contribution and State Emissions Budgets Final Rule Technical Support Document.
Organization: Santee Cooper
Comment: 
Santee Cooper
While EPA's proposed approach for developing state emissions budgets is consistent with the statute and court decisions, EPA has failed to recognize the broad discretion conveyed with regard to the allocation of allowances to affected units under the Transport Rule. [EPA-HQ-OAR-2009-0491-2820.1, p.2]
EPA's PROPOSED APPROACH FOR DEVELOPING STATE EMISSIONS BUDGETS IS CONSISTENT WITH THE STATUTE AND THE NORTH CAROLINA DECISION. [EPA-HQ-OAR-2009-0491-2820.1, p.7]
Santee Cooper strongly supports the approach EPA has proposed for developing state budgets for NOx and S02 emissions. Basing budgets on state-specific contributions to downwind air quality problems addresses the concerns we raised in connection with state SO2 budgets under CAIR, and is most consistent with the language of the statute and the D.C. Circuit's opinion in North Carolina. As EPA is aware, the principal objection to the CAIR budgeting approach for SO2 was that it reflected considerations that were not grounded in the statute and unfairly balanced the burden of reducing interstate emissions among states. Basing state SO2 emission budgets on congressionally-mandated allocations of Title IV allowances, as CAIR did, had no logical connection to the purpose of Section II0(a)(2)(D), which is to eliminate 'significant contributions' to downwind nonattainrnent or 'interference with maintenance' of downwind attainment. [EPA-HQ-OAR-2009-0491-2820.1, pp.7-8]
The D.C. Circuit agreed in North Carolina that this was a fatal flaw in the CAIR SO2 budgets, finding that the Title IV allocations were based on data from the mid-1980's and designed to address acid rain - making them an inappropriate basis for allocations under Section 110. Further, North Carolina held that the fuel-factor-based NOx emission budgets established under CAIR were similarly arbitrary and contrary to the statute, because they did nothing to ensure that each state complied with the directive in Section 110 to prohibit significant contributions and interference with maintenance. Indeed, North Carolina concluded that the NOx budgeting methodology unfairly burdened states that had done the most to address interstate emissions (by installing pollution control equipment or relying on cleaner fuels) by depriving them of emission allowances. The clear message of North Carolina was that Section 110(a)(2)(D) requires state emission budgets to ensure that sources 'within each state' eliminate their significant contributions and interference with maintenance - no more and no less. [EPA-HQ-OAR-2009-0491-2820.1, p.8]
The revised state emissions budgeting approach for both S02 and NOx addresses these concerns and fulfills the statutory requirements of Section 110(a)(2)(D) as interpreted by North Carolina. EPA's new methodology correctly bases state emission budgets on the quantity of S02 and NOx emissions that would remain once sources within each state undertake emission control measures below a uniform marginal abatement cost. This approach ensures that each state addresses its significant contribution and interference with maintenance - no more and no less - and ensures that the costs of doing so are reasonably balanced between downwind and upwind states. We believe this is a rational methodology that implements the statutory mandate as faithfully as practicable, and urge EPA to preserve this approach in its final Transport Rule. [EPA-HQ-OAR-2009-0491-2820.1, pp.8-9]
Response: 
EPA finalizing an approach for determining state budgets that is consistent with what it proposed in regards to defining state emission budgets that reflect emissions subsequent to the elimination of significant contribution.
Organization: South Carolina Department of Health and Environmental Control 
Comment: 
South Carolina Department of Health and Environmental Control 
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.85-86.]
Our second comment centers on the increases in allowable sulfer dioxide and oxides of nitrogen, or SO2 and NOx respectively, budgets that some states are to receive under the proposed Transport Rule.
These possible increases in NOx and SO2 emissions are troubling given the recent lowering of the NOx and SO2 primary NAAQS, the current reconsideration of the 2000 ozone standard, and the end review of the fine particulate matter or PM 2.5 NAAQS. While we understand the technical reason for why this happened, it is hard to contemplate why the EPA is not taking this opportunity to address a more stringent NAAQS and bring about the public health and environmental benefits that the NAAQS are intended to address.
The budgeting process of the Transport Rule considered downwind non-attainment and interference with maintenance and the proposed budgets are the modeled amounts of NOx and SO2 that sources can emit without further contributing to non-attainment while interfering with maintenance downwind. However, the EPA did not account for the way a larger budget could potentially impact local air quality.
Response: 
See section VI.D of the preamble for a discussion on why EPA did not use CAIR state budget levels in its determination of Transport Rule State budget levels.  Furthermore, EPA notes that it did assess how projected emission patterns under the final Transport Rule budgets would impact air quality in each State (including South Carolina)
Organization: Southern Company
Comment: 
Southern Company
The graph below [See EPA-HQ-OAR-2009-0491-2864.1, p. 41 for the Figure] also shows that even if local controls are not considered, Georgia resolves all of its linkages at $300 - $400 per ton in 2014. This result should have left Georgia with a projected 2014 S02 budget of 133,563 tons per year. Furthermore, if local emission controls are appropriately considered early in the methodology, Georgia would have a projected budget in 2014 of no less than 173,257 tons per year. However, Georgia's budget in the proposed Transport Rule is 85,717 tons per year - less than half of what is necessary to resolve all of Georgia's downwind linkages to nonattainment and maintenance issues. [EPA-HQ-OAR-2009-0491-2864.1, p. 40]
XIII. EPA's State Budget and Unit Allocation Methodologies Are Fundamentally Flawed
To establish state budgets and unit allocations, EPA used a combination of reported data and projected data, both adjusted for controls. As mentioned earlier, EPA's methodology was not clearly defined and Southern Company spent  countless hours replicating EPA's approach. However, Southern Company has identified a number of fundamental flaws in EPA's methodologies for developing and adjusting this data for purposes of setting the state budgets and unit allocations. These flaws are described below. [EPA-HQ-OAR-2009-0491-2864.1, p. 48]
A. 2009 Was Not an 'Average Year'
To develop the reported emissions data for purposes of setting state budgets and unit allocations EPA took the most recent 'non-null' quarterly data (through the third quarter of 2009) for each quarter (quarter one through four). In most cases, this meant using data from the fourth quarter of 2008 through the third quarter of 2009 as a representative year (or 2009 ozone season data as a representative ozone season). This process is significantly flawed. EPA repeatedly claims that state budgets are based on emissions from an 'average year.' Yet its methods accomplish nothing of the sort. Put simply, EPA's selected representative year is anything but average. [EPA-HQ-OAR-2009-0491-2864.1, p. 48]
From 2008 through 2009, the nation was in the middle of the most significant economic downturn since the great depression. Electricity demand and heat input were unusually low. EPA appears to recognize this anomaly by adjusting reported NOx data based on 2008 heat input.4 But even that adjustment does not fully account for the unusually low demand for electricity beginning in the second half of 2008. In addition, in 2009 natural gas prices were at extraordinarily low resulting in highly unusual dispatch of the fossil fuel fired electric generating fleet. In some cases, large coal-fired units were idled while natural gas fired units - normally reserved for peaking power - ran at much higher capacity factors. Due to the combined forces of (i) decreased demand and (ii) low natural gas prices, 2009 is perhaps the least representative year in decades for determining average annual emissions. EPA should fully account for the economic downturn by selecting reporting years that were not impacted by the economic downturn. [EPA-HQ-OAR-2009-0491-2864.1, pp. 48-49]
Instead of attempting to select a single representative year, consistent with past practice, EPA should use a longer average period of time to develop reported emissions data. By selecting a longer period of time (e.g., three years as used in the Acid Rain Program, the NOx SIP Call and CAIR), EPA would capture data that is more representative. Selecting the three year period from 2005 to 2007 would fully account for the economic downturn, capture two full operational cycles for a typical unit, and would provide much more reliable data. [EPA-HQ-OAR-2009-0491-2864.1, p. 49]
[The above comments can also be found at section V.D.2.b.ii. of the comment summary.]
Response: 
In the final Transport Rule, EPA does not use historic emissions data to set the Transport Rule state budgets, but instead relies on projected emissions data under the marginal cost thresholds selected to define significant contribution and interference with maintenance.  EPA uses the same budget-setting methodology in the final rule on all pollutants analyzed (including ozone-season NOx, annual NOx, and SO2).  EPA believes this budget-setting methodology is more clear and easier to understand in connection with the Agency's modeling projections.  EPA believes the state budgets set under the final Transport Rule are an accurate reflection of its modeling of the removal of emissions identified as significant contribution and interference with maintenance from the states controlled.  For a discussion of this method and its results, please refer to section VI of the preamble for the final Transport Rule as well as the Significant Contribution and State Emissions Budgets Final Rule Technical Support Document.
Organization: State of Delaware Department of Natural Resources & Environmental Control
Comment: 
State of Delaware Department of Natural Resources & Environmental Control
Despite that EPA inventories for DE are inflated (see above and Attachment 1 [See comment EPA-HQ-OAR-2009-0491-2980.2, for Attachment 1] to this letter), EPA's inventories themselves indicate that it is not necessary to include Delaware in the transport rule, i.e.: [EPA-HQ-OAR-2009-0491-2980.1, p. 3]
Without variability limits, EPA proposes at 40 CFR 97.410 a 2012 Delaware NOx budget of 6,206 TPY, and at 40 CFR 97.710 a 2012 Delaware 802 budget of 7,784 TPY. EPA has indicted that a state's emissions budget ' ... is the quantity ofword~, it provides a quantity of emissions that would remain in that state from covered sources after elimination of that portion of each state's significant contribution and interference with maintenance that EPA has identified in today's proposal, before accounting for the inherent variability in power system operations ... The state emissions budget is a mechanism for converting the quantity of emissions that a state must reduce (i.e., the state's significant contribution and interference with maintenance) into enforceable control requirements. In other emissions to use in developing a remedy ... ' [EPA-HQ-OAR-2009-0491-2980.1, p. 3]
However, EPA's 2012 base case emissions for Delaware EGU's are 4,639 TPY for NOx and 7,841 TPY for S02, Since the EPA is establishing Delaware's EGU budgets at a level that is not less than its 2012 base case emissions 3, Delaware has already met its obligation to remedy downwind contributions for NOx and S02. [EPA-HQ-OAR-2009-0491-2980.1, p. 3]
 Given the above, Delaware should not be included in the final Transport Rule, since our current control strategies have already mitigated our significant contributions to downwind areas. [EPA-HQ-OAR-2009-0491-2980.1, p. 3] 

Footnote:
3 The difference between the EPA 2012 base case S02 inventory and the proposed budget for Delaware is 57 TPY. Once the EPA corrects the problems with the inventory 1) overall modeled contributions will be much less given that EPA's 2012 S02 projections are inflated on the order of 57%, and 2) Delaware's 2012 EGU projection will be less than the proposed budget. [EPA-HQ-OAR-2009-0491-2980.1, p. 3]
 
Response: 
Under the final Transport Rule air quality modeling, Delaware was not identified as a contributing upwind state and therefore not subject to the final Transport Rule.  However, EPA notes that under its revised budget determination methodology described in section VI of the preamble, states have budgets that are less than or equal to their base case emissions in 2012 for ozone season NOx to help meet with the June 2013 maximum attainment deadline.  For annual NOx and SO2, state have 2014 budgets that are less than their base case emissions to help meet the April 2015 deadline for the 1997 PM2.5 NAAQS.  The alignment with compliance deadlines is discussed in section VII.C, and section VI.D of the preamble discusses why some ozone states have budgets equal to, instead of less than, their state budgets
Organization: State of Wisconsin, Department of Natural Resources
Comment: 
State of Wisconsin, Department of Natural Resources
Wisconsin supports EPA's premise that 2012 emission budgets should reflect all existing and planned controls implemented by utilities in meeting initial 2010-2012 CAIR requirements. [EPA-HQ-OAR-2009-0491-2829.2, p.1]
Setting EGU emission budgets for allocations in multiple phases: 2012, 2014, 2016 - Given that the current proposal addressing an EGU emission control program is a partial, not full, remedy to current significant contribution reduction obligations, these EGU budgets (and reduction target levels) need to address, in order of importance - [EPA-HQ-OAR-2009-0491-2829.2, p.10]
existing installed controls
CAIR Budgets in 2010 and 2015 that have focused EGU controls planning and installation schedules to date
residual air quality improvement needs associated with significant contribution
standing SIP attainment deadlines
some metric of relative level of state average emission rates per unit power produced from fossil fuels
some metric for relative cost of incremental controls installation. [EPA-HQ-OAR-2009-0491-2829.2, p.10]
Following these criteria, budgets should be set for:
2012 - accurately reflect existing and committed (under construction) controls combined with normal operation levels. Since EPA's intent is to not backslide they should use CAIR 2010 NOx budgets for states where it is lower than the predicted IPM emission budget. The current aggregate state-level heat inputs projected in support of the 2012 budgets may need to be adjusted slightly upward to reflect an equivalency with the highest inputs by state during the period 2005-2009 in order to continue to account for variability. Appendix B [See EPA-HQ-OAR-2009-0491-2829.3, p.6 for comments pertaining to Appendix B] identifies critical issues and necessary unit fixes for input to the final lPM configuration being used in support of this rule. Noted base operating levels need to account for operational flexibility if being used to set budgets from a bottom-up approach. (A response by October 15 to the September 1, 2010 NODA will identify critical fixes to the Wisconsin facility IPM inputs along with necessary unit-specific corrections). [EPA-HQ-OAR-2009-0491-2829.2, p.10]
2014 - account for some continued variability within the system and target feasible control optimization and all new installations that can occur through typical installation timing. All reasonable control should be set within this budget to assure meeting of significant contribution obligation. The IPM model should be used in this case to determine time frames necessary for installing equipment while accounting for variability. The IPM assumptions for construction schedules should also consider regulatory approvals for equipment by state agencies such as Wisconsin's Public Service Commission. The current aggregate state-level heat inputs projected in support of the 2014 budgets may need to be adjusted slightly upward to reflect an equivalency with the highest inputs during the period 2005-2009 (on the order of 5% on average but different state-to-state) in order to continue to account for variability. [EPA-HQ-OAR-2009-0491-2829.2, p.10]
2016 - An SNPR needs to be proposed to address the new 2010 ozone standard. Once promulgated new proposed 2016 budgets should reflect the increased contribution reduction need associated with that new standard. A placeholder in the regulatory structure should also exist to address additional reduction targets associated with any PM2.5 standard revision. These budget levels could be established now as control program goals by state much as is the case with Regional Visibility program targets. While use of the IPM model for determining achievable state level emission budgets and average cost is acceptable to address one set of criterion, it is not appropriate for determining allocations (see comments below in the allocation discussion [See EPA-HQ-OAR-2009-0491-2829.2, p.11 for comments pertaining to allocation discussion; EPA-HQ-OAR-2009-0491-2829.2, p.11] ).
Response: 
In the final Transport Rule, EPA does not use historic emissions data to set the Transport Rule state budgets, but instead relies on projected emissions data under the marginal cost thresholds selected to define significant contribution and interference with maintenance.  EPA uses the same budget-setting methodology in the final rule on all pollutants analyzed (including ozone-season NOx, annual NOx, and SO2).  EPA believes this budget-setting methodology is more clear and easier to understand in connection with the Agency's modeling projections.  EPA believes the state budgets set under the final Transport Rule are an accurate reflection of its modeling of the removal of emissions identified as significant contribution and interference with maintenance from the states controlled.  For a discussion of this method and its results, please refer to section VI of the preamble for the final Transport Rule as well as the Significant Contribution and State Emissions Budgets Final Rule Technical Support Document.
Organization: Sunbury Generation LP
Comment: 
Sunbury Generation LP
Consequently, the states' emissions budgets are highly conservative and provide an ample safety net for eliminating significant contribution. [EPA-HQ-OAR-2009-0491-3615,p.7]
Response: 
In the final Transport Rule, EPA does not use historic emissions data to set the Transport Rule state budgets, but instead relies on projected emissions data under the marginal cost thresholds selected to define significant contribution and interference with maintenance.  EPA uses the same budget-setting methodology in the final rule on all pollutants analyzed (including ozone-season NOx, annual NOx, and SO2).  EPA believes this budget-setting methodology is more clear and easier to understand in connection with the Agency's modeling projections.  EPA believes the state budgets set under the final Transport Rule are an accurate reflection of its modeling of the removal of emissions identified as significant contribution and interference with maintenance from the states controlled.  For a discussion of this method and its results, please refer to section VI of the preamble for the final Transport Rule as well as the Significant Contribution and State Emissions Budgets Final Rule Technical Support Document.
Organization: TransCanada
Comment: 
TransCanada
Comment 1: EPA's Calculation of New York State's Emission Budget Fails to Provide Credit for Prior Emission Reductions Achieved
Unlike previous EPA rulemakings, the Transport Rule does not give full credit to New York State for the NOx and SO2 emission reductions that have already occurred through reductions from the Electric Generating Units in the state. TransCanada urges the Agency to continue its practice of giving credit to a state like New York that implemented its own program to reduce emissions of NOx and SO2 and to use this as a factor in the allowance allocation process. [EPA-HQ-OAR-2009-0491-2827.1, p.1]
As a result of the New York State Acid Reduction Program ("ADRP") and the Clean Air Interstate Rule ("CAIR"), New York State electric generating units ("EGU") reduction of NOx and SO2 emissions have be significant. New York State implemented 6 NYCRR Part 237 and Part 238, to reduce acid deposition in New York State by limiting emissions of NOx and SO2 starting on October 1, 2004 for NOx and January 1, 2005 for SO2. Three years before ADRP and CAIR were implemented, the average annual NOx emissions in New York State were 85,895 tons and the NOx emission rate was .207 pounds per million British thermal units ("mmbtu"). The average SO2 annual emissions during this period was 231,984 tons and the SO2 emission rate was .560 pounds/mmbtu. [EPA-HQ-OAR-2009-0491-2827.1, pp.1-2]
During the three years after implementation of ADRP, the average annual NOx emissions in New York State were reduced to 51,641 tons, and the NOx emission rate was reduced to .143 pounds/mmbtu. During the same period, the average annual SO2 emissions were reduced to 108,686 tons and the SO2 emission rate to .299 pounds/mmbtu. After the implementation of CAIR in 2009, the average NOx emissions in New York State were reduced to 39,239 tons and the NOx emission rate to .132 pounds/mmbtu. The average annual SO2 emissions in New York State were reduced to 53,110 tons and the SO2 emission rate was reduced to .178 pounds/mmbtu. [EPA-HQ-OAR-2009-0491-2827.1, p.2]
As can be seen from the amount of NOx and SO2 emissions that have been reduced, New York State's reductions in NOx and SO2 emissions from EGUs are momentous and should be considered by the Agency when calculating the NOx and SO2 emission budgets for New York State under the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2827.1, p.2]
Response: 
In the final Transport Rule, EPA uses an allowance allocation methodology that recognizes the early reductions made by units.  That is, if there are two identical units in the state, but one had installed advanced pollution control in recent years, and the other had not, they would still receive the same amount of allocations.  This allocation approach was made in response to commenters expressing concerns about the proposed allocation methodology penalizing early actors.
EPA notes that the recognition for previous emission reductions is reflected in the allocation methodology.  However, the commenter seems to suggest that similar recognition be made for state budgets.  While the commenter's intended mechanism for achieving this is unclear, EPA notes the important distinction between state budgets and allocations.  State budgets reflect the elimination of significant contribution, embody the environmental integrity of the program, and its responsiveness to CAA section 110(a)(2)(D)(i)(I).  The determination is described in section VI of the Transport Rule preamble.  Budgets are based on the amount of additional emission reductions that are necessary for the elimination of significant contribution and interference with maintenance.  Their determination is made independent of past reductions.  However, the burden imposed by a budget inherently reflects past reductions.  For example, if the state has already made significant reductions, then it will be starting from a lower base level of emissions and it will likely find it easier to meet its Transport Rule budget.  If the same state had not made the same previous reductions, than it would likely have more reductions to make in order to reach the point where its significant contribution had been eliminated.
To somehow index budgets to historic higher emission levels instead of the levels needed to achieve the elimination of significant contribution would fail to fulfill the mandate of CAA section 110(a)(2)(D)(i)(I), and potentially run counter to its goals by allowing for emission increases, rather than requiring reductions, within a state.
Organization: West Virginia Department of Environmental Protection
Comment: 
West Virginia Department of Environmental Protection
State Implementation Plans - WVDAQ is concerned that significant increases in some state budgets over CAIR may adversely affect the integrity of many attainment and Regional Haze SIPs. West Virginia relied on CAIR reductions for the Regional Haze SIP, as well as the 1997 PM25 SIPs, and the 8-hr Ozone Maintenance Plans. Therefore, the Transport Rule NOx budgets need to be at least as stringent as the SIP-approved CAIR NOx budgets. As previously noted, future emissions from ICI boilers have been accounted for in West Virginia's submitted attainment demonstrations. WVDAQ believes it is important that the final rule not contravene the anti-backsliding provisions of the Clean Air Act. [EPA-HQ-OAR-2009-0491-2790.1, p. 2-3]
In the final Transport Rule, WVDAQ requests a tabular summary by state and pollutant that demonstrates the reductions necessary for each state to eliminate significant contribution and interference with maintenance (without considering costs). [EPA-HQ-OAR-2009-0491-2790.1, p. 3]
Response: 
See Section VI.D of the Preamble for response to comments regarding backsliding concerns.
Organization: Wolverine Power Supply Cooperative
Comment: 
Wolverine Power Supply Cooperative
Although we do not take exception to EPA determining statewide reduction budgets, we understand from our agency and industry groups that EPA's methodology and allocations supporting the state budgets in this rulemaking are severely flawed, and in some cases inadequate information is available to evaluate the allocations. Michigan's state agency believes that the impacts attributable to Michigan are over-stated because emissions control assumptions are flawed, and thus the reduction requirements are excessive. We understand that additional modeling with more up-to-date data is being performed by both EPA and industry groups, and these results should be the basis of final budgets. It is particularly important that 2008 or later committed controls, rather than 2005 as EPA has used, be the basis of emission inventory assumptions. We understand that recent modeling has shown a future of attainment for both standards using current and committed EGU emission controls which are being installed under the CAIR that is still in effect. To state it differently, this proposed rule is not even necessary as the problem it purports to remedy has already been resolved. As the CAIR is still in place and driving reductions that lead to attainment, there is no reason why EPA cannot take the additional time necessary to develop a robust and current evaluation of states' contributions and necessary reduction targets.  [EPA-HQ-OAR-2009-0491-2825.1 p.3]
Response: 
EPA chose these dates to coordinate with the NAAQS attainment deadlines and to assure that reductions are made as expeditiously as practicable.  The Preamble discusses how the compliance deadlines address the Court's concern about timing.  See more in Section VII.C for more discussion on compliance deadline, and Section V.A and V.B for a description of the "no-CAIR" baseline that EPA used, and which further indicates that the Transport Rule is "necessary".

IV.E.1. SO2 and Annual NOx State Emissions Budgets for EGUs - Data and Methodology

Organization: Alcoa Power Generating Inc. - Warrick Power Plant
Comment: 
Alcoa Power Generating Inc. - Warrick Power Plant
Tables IV.E-1 and IV.E-2 (75FR45239) do not agree with tile total state budget allocations, as described in the Technical Support Document CTSD) Allocation Table. For Indiana, the allocation table indicates the following:
SO2 emissions for 2012: 388.361 tons/yr.
SO2 emissions for 2014; 195,367 tons/yr.
NOx emissions starting in 2012: 112,223 tons/yr.
Ozone Season NOx: 48,493 tons/yr. [EPA-HQ-OAR-2009-0491-3648, p.2]
Table IV.E-l indicates the following:
SO2 emissions for 2012: 400,378·tons/yr.
SO2 emissions for 2014: 201,412 tons/yr.
NOx emissions starting in 2012: 115,687 tons/yr.
Ozone Season NOx: 49,987 tons/yr. [EPA-HQ-OAR-2009-0491-3648, p.2]
It appears that the allocation table in the TSD reflects removal of 3% for the new unit setasides. To minimize confusion, APGI suggests that Tables IV.E-1 and IV.E-2 reflect the correction for 3% for the new unit set-asides. [EPA-HQ-OAR-2009-0491-3648, p.2]
Based on a comparison of Table IV.C-l for EGU's, which represent 2005 emissions, (75FR45239) and Table IV.E-1 (75 FR45239), EPA envisions a 61.8% reduction in SO2 emissions by 2012, and a 70.8% reduction by 2014 for Indiana to meet the proposed transport rule. For Warrick 4, the TSD allocation table indicates that allowances for SO2 will be allocated at 1,308 tons/yr. in 2012 and 2013, and 1,231 tons/yr. in 2012. Warrick 4 SO2 emissions in 2005 were 32,790 tons. This represents required 802 reduction efficiencies. of 96.01 % and 96.24%, respectively. Both efficiencies far exceed the reductions in the 2005 baseline envisioned by EPA to meet the Indiana reduction requirements for S02. i.e. 61.8% and 70.8% respectively. [EPA-HQ-OAR-2009-0491-3648, p.2]
Based on a comparison of Table IV.C-2 for EGU's, which represent 2005 emissions, (FR45239) and Table IV .E-1 (FR45239), EPA envisions a 51.9% reduction in NOx emissions by 2012 for Indiana to meet the proposed transport rule. For Warrick 4, the. TSD allocation table indicates that allowances for NOx will be allocated at 676 tons/yr. in 2012 and later years. Warrick 4 NOx emissions in 2005 were 4,093 tons. This represents a required NOx reduction efficiency of 83.48%. This efficiency requirement· far exceeds the reduction in the 2005 baseline envisioned to meet the Indiana reduction requirements for NOx, i.e. 51.9%. [EPA-HQ-OAR-2009-0491-3648,pp.2-3]
Response: 
See section VI.D for discussion on EPA final budget methodology and section VII.D for discussion on the allocation methodology used in the final Transport Rule.  The final allocation tables reflect unit-level allocations to existing units under the FIP methodology while reserving the allowances held in the new unit set-asides.  However, in the event that new unit set-aside allowances remain unallocated, then they will be allocated out to existing sources under the same existing unit allocation methodology as represented in the existing unit allocation tables.
The commenter mistakenly represents unit-level allowance allocations as conveying "reduction requirements" under the Transport Rule programs.  EPA also notes that there are no unit specific reduction requirements for the Transport Rule.  Reduction requirements are imposed at the state level.  Individual unit owners and operators may choose to obtain as many allowances as needed to cover their emissions under the Transport Rule programs, in line with whatever emission reduction strategy that the unit owner or operator deems to be most cost-effective for that given unit.
Organization: Algonquin Power Windsor Locks, LLC
Comment: 
Algonquin Power Windsor Locks, LLC
Connecticut is a small state with NOx emissions significantly lower than other states affected by the regulations. Over the years Connecticut has been pro-active in reducing the NOx emissions from Connecticut facilities by implementing some of the strictest emission limits in the country. It is well documented that the ambient NOx levels in Connecticut are significantely impacted by the NOx emissions from upwind states, many of which have less restrictive NOx emission limits. As a whole, the NOx emissions from Connecticut electric generating units are significantly lower than the NOx emissions from comparable units in other states. To achieve this, the Connecticut units have undertaken significant capital and operational expenditures and operate at the lowest emission levels that the current technologies of the units allow. Unfortunately, in the current open power market, the Connecticut units must compete with units with higher emissions rates in other states, which also adversely affect Connecticut air quality. Because of this, I fail to see the justification of requiring Connecticut generators to further reduce NOx emissions when significantly higher overall reduction at lower cost can be achieved by requiring the upwind states to meet the Connecticut emission limits. The Connecticut NOx budget should not be lowered from the Clean Air Interstate Rule levels. [EPA-HQ-OAR-2009-0491-2779.1, p.1]
Response: 
Connecticut is not subject to the final Transport Rule in light of EPA's final air quality modeling to identify contributing upwind states.
Organization: Clean Air Council
Comment: 
Clean Air Council
There is a local aspect to the inadequacy of the NOx reduction which is of particular concern. Upon examination of the state NOx emissions budget under the Transport Rule (Table IV.E.1), it appears that Pennsylvania has been allocated 113,903 tons of NOx on an annual basis. This number reflects a considerable increase from the Pennsylvania budget under CAIR, which allocated roughly 99,000 tons. NOx is a pre-cursor to PM2.5, and Pennsylvania faces serious challenges to attaining the NAAQS, especially in Lancaster and Allegheny County. Presenting Pennsylvania power plants with a bonus of nearly 14,000 tons of NOx will be detrimental to public health, contrary to public policy, and present an unjustified obstacle to attainment in portions of the Commonwealth struggling to meet air quality standards. As Phase I of CAIR remains effective upon power plants in Pennsylvania until the Transport Rule supercedes it, the specter of backsliding on air quality is very real. The Council does not believe that such a result would be consistent with the Clean Air Act. Therefore, we urge EPA to reassess the Pennsylvania budget to preclude this harmful anomaly before finalizing the Transport Rule. [EPA-HQ-OAR-2009-0491-2804.1, p.2]
Response: 
See Section VI.D of the Preamble for additional discussion on concerns over backsliding.
Some commenters expressed concern that, under the proposed Transport Rule, states had some state budgets that were higher than those under CAIR.  Commenters suggested that this would be inconsistent with requirements or spirit of certain CAA provisions aimed at preventing backsliding, i.e., sections 110(l), 172(e), and 193.   However, the D.C. Court of Appeals rejected the state budgets in CAIR as arbitrary and capricious and not consistent with CAA section 110(a)(2)D)(i)(I)  ( North Carolina, (531 F.3d  918 and 921) and remanded CAIR to EPA to promulgate a new rule replacing CAIR and consistent with the Court's decision ( North Carolina, 550 F.3d 1178 ).  As discussed elsewhere in this section, on remand EPA developed new, final state budgets that address the Court's concerns and meet section 110(a)(2)(D)(i)(I) requirements.   Although, for some states, some state budgets under the final rule are higher than those under CAIR, this does not violate either the letter nor the spirit of CAA provisions aimed at backsliding.   In particular, CAA section 110(l) provides that the Administrator may not approve  a plan revision  that would "interfere with any...applicable requirement" of the CAA.  42 U.S.C. 7410(l).   Because the Court reversed and remanded CAIR with instructions to "remedy" the rule's  "fundamental flaws"  (including specifically the state budgets found to be unlawful (North Carolina, (550 F.3d 1178 )), it is difficult to see how new state budgets replacing unlawful budgets and meeting section 110(a)(2)(D)(i)(I) requirements could be viewed as interfering with requirements of the CAA.   Indeed, the commenters' approach would severely limit  EPA's ability to meet the Court's mandate to develop a new rule consistent with section 110(a)(2)(D)(i)(I).  See North Carolina, 531 F.3d 921 (explaining that EPA may not require  "some states to exceed the mark" of eliminating their significant contribution).  Further, the other CAA sections cited by the commenters (section 172(e), addressing circumstances where the Administrator relaxes a NAAQS,  and section 193, addressing the treatment of requirements promulgated before the November 15, 1990, enactment date for the 1990 Amendments to the Clean Air Act) are not applicable here. 
Organization: Clean Air Task Force
Comment: 
Clean Air Task Force
We therefore urge EPA to reduce the 2014 aggregate state budgets in the annual control region (including Texas) for SO2 to 1.75 million tons (approximately equivalent to a 2 million ton nationwide cap); reduce the 2014 aggregate state budgets in the annual control region (including Texas) for NOx to 900,000 tons (approximately equivalent to a 1.25 million ton nationwide cap); and include Texas, Arkansas, New Hampshire, North Dakota and Oklahoma in the control region for SO2 and annual NOx purposes, and include Massachusetts and Missouri in the control region for ozone season NOx purposes. [EPA-HQ-OAR-2009-0491-2738.1, p.4; this comment can also be found at section IV.D. of this comment summary.]
EPA's Proposed Power Plant SO2 and NOx Emissions Budgets are Inadequate to Protect Public Health and Allow NAAQS Attainment and Must be Strengthened.
The severe harm to human health and the environment described above [See EPA-HQ-OAR-2009-0491-2738.1, p.8-12 for description of severe harm to health and the environment] demand the most substantial reductions in regional power plant emissions of SO2 and NOx that are feasible and cost-effective. EPA's proposal does not fully accomplish this -- tighter budgets for both pollutants are quite feasible and cost-effective, and EPA should require them. Specifically, as previously indicated, we urge EPA to limit regional (including Texas) SO2 emissions to 1.75 million tons annually and regional NOx emissions to 900,000 tons annually. 73 [EPA-HQ-OAR-2009-0491-2738.1, p.13]
We urge the Agency to issue a rule that includes that following adjustments to its August 2 proposal: reduces the 2014 annual control region SO2 cap to about 1.75 million tons (including Texas) [EPA-HQ-OAR-2009-0491-2738.1, p.30]
CATF Analysis of Alternate Control Scenario
In order to demonstrate that deeper reductions of NOx and SO2 emissions are feasible, cost-effective, and will provide substantial additional human health benefits, CATF, with the assistance of ICF Consulting and MSB Energy Associates, has evaluated the benefits and costs of tighter emission caps and schedules than proposed by EPA in the TR. This alternate scenario is a regional (EPA's proposed PM transport region plus Texas) annual EGU SO2 cap of 1.75 million tons, with a regional annual EGU NOx cap of 900,000 tons, each effective in 2014 ("Alternate Control Scenario"). [EPA-HQ-OAR-2009-0491-2738.1, p.26; For additional comments pertaining to CATF Analysis of Alternate Control Scenario, including: Alternate Control Scenario Analysis Methodology,Alternate Control Scenario Analysis Results, and tables V.1- V.7, see pages 26-28 & 32-33 of this comment]

73 As previously stated: supra at note 16, our recommended regional emission caps are the rough equivalent of national caps of 2 MT for SO2 and 1.25 MT for NOx, assuming equivalent out of region emission reductions; and supra at note 36, although we believe that our recommended lower threshold for determining significant contribution will require additional states to be included in the TR control regions, we have included only Texas emissions in our recommended emissions caps and the Alternate Control Scenario described in Section V infra. 
Response: 
The sum of final Transport Rule state budgets is tighter for both SO2 and NOx than those specified at proposal (for states covered in both proposal and final rule).  See section VI.D for description of the multi-factor analysis EPA used to determine appropriate stopping points for SO2 and NOx budgets.
Organization: Dayton Power and Light Company (DP&L)
Comment: 
Dayton Power and Light Company (DP&L)
The MOG modeling demonstrates that Ohio NOx and S02 caps similar to those developed for the CAIR rule are adequate to eliminate inappropriate transport from electric generating units ('EGUs') in Ohio. MOG modeling projections show that attainment for all existing standards can be achieved by 2018 without additional controls, with Ohio emissions estimated at 274,000 tons of SO2. This is significantly higher than the proposed CATR S02 emissions cap for Ohio of 178,307 in 2014. [EPA-HQ-OAR-2009-0491-2637.1, p. 3]
DP&L believes that lower CATR caps for Ohio are unnecessary to achieve overall attainment across the CAIR states. There may remain one or two monitoring sites facing nonattainment; however, these can be addressed though state SIPs and it is inappropriate to establish lower state caps through CATR to address these localized air quality problems. [EPA-HQ-OAR-2009-0491-2637.1, p. 3]
Response: 
See Section IV of the preamble for a discussion of the legal authority of the final Transport Rule, and Section VII.C for a discussion of the compliance deadlines.
Organization: Duke Energy
Comment: 
Duke Energy
EPA Should Modify Its Method of Adjusting a Unit's Reported NOx Annual Emission Rates to its Ozone Season Emission Rate.
Table 1 of the PTR State Budgets TSD indicates that for units with a pre-2009 SCR or SNCR, EPA is adjusting the reported annual NOx emissions rate to the unit's reported ozone-season emission rate. EPA has not explained why it believes it necessary to adjust the reported non-ozone season data in cases when a unit's reported data clearly reflects operation of the control. Such an adjustment might be appropriate if a unit's most recent non-null quarter 1; quarter 2, quarter 3, and quarter 4 of reported NOx emissions data with a pre-2009 SCR or SNCR only reflected operation of the control during the ozone season. When, however, a unit with a pre-2009 SCR or SNCR has the most recent non-null quarter 1, quarter 2, quarter 3, and quarter 4 of reported NOx emissions data that reflects the operation of the SCR or SNCR throughout the period, EPA should use the data as reported in determining a unit's NOx emission rates. For such a case, EPA should use two separate emission rates, an ozone season rate and a non-ozone season rate to calculate a unit's reported emissions. In other words, EPA should consider all reported data with a control in operation to be representative of the operation of the control during that period, and EPA should not adjust a unit's reported non-ozone season NOx rate to its reported ozone season NOx rate. Similarly, if a unit does not have the most recent non-null quarter 1, quarter 2, quarter 3, and quarter 4 of reported data that reflects the operation of the SCR or SNCR, EPA should adjust only the reported data for the period that does not reflect operation of the controls. For example, if a unit has reported NOx emissions data for the non-ozone season months of January through April of 2009 that reflect operation of controls and only the 4th quarter 2008 reported NOx emissions data does not reflect operation of controls, EPA should adjust only the 4th quarter 2008 data and not adjust the January through April data. In this case the reported 4th quarter data should be adjusted to the unit's January through April emissions rate, not its ozone season emission rate. [EPA-HQ-OAR-2009-0491-2689.1, pp.24-25]
By adjusting all reported NOx data to the ozone season emission rate, EPA is generally underestimating NOx emissions because ozone season NOx emission rates are typically lower than non-ozone season rates. This is due to many factors, including the following: 1) most units have the fewest number of outages during the ozone season which results in the most continuous period of SCR/SNCR operation, whereas outside of the ozone season, most units experience the bulk of planned and maintenance outage activity. This results in higher occurrences of unit start-up and shut-down when emission rates are higher than during continuous operation. 2) Lower ambient temperatures in the winter season generally result in a higher propensity for ammonium bisulfate formation in the air heaters and downstream ductwork on SCR/SNCR units, resulting in air heater and ductwork pluggage, and the need to reduce NOx removal to maintain unit output capacity. 3) Most units tend to have catalyst replacement outages in the spring outage season, resulting in peak SCR removal capability during the ozone season immediately following the outage. As the catalyst degrades, SCR removal capability decreases in the months following the ozone season. [EPA-HQ-OAR-2009-0491-2689.1, p.25]
If EPA does not modify its method by utilizing the average of 2006-2008 reported data, however, Duke Energy recommends that for SO2 EPA abandon its use of the most recent non-null quarter 1, quarter 2, quarter 3, and quarter 4 of reported emissions data and instead use reported 2008 emissions data as the basis for developing each state's adjusted reported SO2 emissions for 2012.  [EPA-HQ-OAR-2009-0491-2689.1, pp.28-29]
EPA Should Apply an Annual and Ozone Season Floor NOx Emission Rate of 0.060 lb/mmBtu to both New and Existing SCRs
EPA has made downward adjustments to reported NOx emission rates for units with an existing SCR that are unwarranted, unreasonable, and inaccurately described in the State Budgets TSD. The State Budgets TSD indicates that "NOx controls were assumed not to control beyond a floor of 0.060 lb/mmBtu." The way EPA has applied this rate to units with existing SCRs, however, the 0.060 lb/mmBtu rate would be more accurately described as a ceiling rather than a floor because of the downward adjustments EPA has made to NOx emission rates. If a unit had reported historical data that supported a NOx emission rate lower than 0.060 lb/mmBtu, EPA used that lower emission rate. Yet if a unit had reported historical data that demonstrated a NOx emission rate higher than 0.060 lb/mmBtu, EPA -- apparently arbitrarily -- made a downward adjustment of that rate to 0.060 lb/mmBtu. Such downward adjustments are unfair and unwarranted. Incentives exist in most cases to emit at the lowest reasonably achievable NOx emission rate whenever the SCR is in operation, and if a given unit reports NOx emissions at rates above 0.06 lbs/mmBtu, it is because that unit cannot physically and consistently operate at a lower rate. At a minimum, an across-the-board downward adjustment to 0.060 lb/mmBtu, without consideration of case-by-case factors, cannot be justified. Just because EPA thinks a unit should be able to emit at a 0.060 lb/mmBtu rate doesn't mean that it can actually achieve that rate. Under EPA's proposed approach, where an existing unit cannot in fact meet the 0.060 lb/mmBtu rate, that unit may well be forced to upgrade its pollution control device. Such an option was not anticipated in the PTR and the cost associated with such an option does not appear to have been accounted for in the PTR analysis. Certainly the $/ton removal cost for upgrades required to allow a unit to perform consistently at a 0.060 lb/mmBtu emission rate will exceed EPA's $500/ton cost breakpoint for NOx controls, and also could not be completed between the time EPA finalizes the PTR and January 1, 2012. EPA should therefore use the 0.060 lb/mmBtu rate as a floor rate for units with either a new or existing SCR. [EPA-HQ-OAR-2009-0491-2689.1,pp.42-43]
EPA's application of a 0.060 lb/mmBtu NOx emission rate without regard for the actual capability of existing SCRs to achieve that emissions rate resulted in EPA overestimating the amount of NOx emissions reduction available at $500/ton. The consequence is to make the annual and ozone season state budgets much more constraining that they should be based on actual SCR capabilities. Take for example a unit that is currently operating at an ozone season emission rate of 0.100 lb/mmBtu. When EPA models this unit's NOx emission rate at 0.060 or adjusts the unit's reported NOx emission rate to reflect a 0.060 lb/mmBtu emission rate for purposes of establishing a state's budget and allocating allowances, EPA has effectively reduced the emissions attributable to this unit by 40%. When this downward adjustment occurs at many units within a state and across the region, the result is a substantially reduced sector ozone season NOx cap beginning in 2012.  [EPA-HQ-OAR-2009-0491-2689.1,pp.43-44] 
EPA has stated correctly that additional controls cannot be brought on line by 2012 unless they are already under construction. So if EPA finalizes the PTR with the unreasonable 2012 compliance timeframe that reflects a ceiling 0.060 lb/mmBtu NOx emission rate for all units, and in 2012 when units for which EPA adjusted their NOx emission rates down to 0.060 are still operating at their reported 2009 emission rate because that's what the SCRs are capable of achieving, the result will be an exceedingly tight cap. Add to this the fact that while EPA is proposing not to apply variability limits in 2012 and 2013 (a proposal which Duke Energy supports), the ability of the trading program under the transport rule to serve as a cost-effective and reliable compliance alternative is uncertain at best. What is certain is if state budgets are based on a ceiling NOx emission rate of 0.060 lb/mmBtu, allowance prices in 2012 will likely be very high, much higher than they would be if EPA applies the 0.060 lb/mmBtu emission rate as a floor instead of a ceiling and used a unit's actual reported emission rate when it is above 0.060 lb/mmBtu.  [EPA-HQ-OAR-2009-0491-2689.1, p.44]
The $500/ton cost breakpoint EPA is using for NOx emissions is intended to ensure that all existing NOx controls are operated in 2012. This should mean operate at their current capability, not at some artificial level that EPA selects and that requires controls to be upgraded. As stated previously and reiterated here, the budgets that result from EPA modeling existing SCRs with a ceiling emission rate of 0.060 lb/mmBtu will certainly require emission reductions that cost more than $500/ton to achieve, and for which there is not enough time between when EPA plans to finalize the PTR (mid-2011) and January 1, 2012 to implement. [EPA-HQ-OAR-2009-0491-2689.1,p.44]
For Units with an Existing SCR, EPA Should Update Reported Unit NOx Emission Rates to Reflect 2009 Data and Use Separate Ozone Season and Non-Ozone Season Emission Rates in the PTR Analysis to Represent a Unit's NOx Emissions Over the Course of a Year.
As a general statement, EPA's use of a 0.060 lb/mmBtu NOx emissions rates ceiling for SCR controlled units is inconsistent with how SCR controlled units actually work. The key element of SCR performance is the condition and amount of catalyst used. SCR reactors are fixed in size at their time of construction and nits do not have the capability to add additional catalyst layers beyond what was included in their original design. In addition while in operation, catalyst ages as it is poisoned by materials in the flue gas and steadily degrades in its performance. Once its performance reaches an unacceptable level, it must be replaced. Catalyst replacement is expensive and can only be performed during a unit shutdown of sufficient length. Because of these factors, units will have significant differences in the levels of NOx removal performance when catalyst is new, and then just before it is replaced. An uninformed response to the issue of catalyst degradation would be to call for more frequent catalyst replacement. Clearly this is not an option because it would require frequent unit shutdowns, and scrapping expensive catalyst prematurely which would also increase the amount of waste materials. The marginal costs for the incremental reductions that would result would wildly exceed the $500 per ton cost breakpoint.  [EPA-HQ-OAR-2009-0491-2689.1, p.45]
For units with an existing SCR where the SCR has operated all of 2009 to comply with CAIR, consent decrees, state requirements, etc., Duke Energy recommends that EPA use two separate NOx emission rates, the ozone season rate and the non-ozone season rate, to calculate the annual NOx emissions from these units. Each of these emission rates should be set at the greater of the 0.060 lb/mmBtu floor that Duke Energy recommends for units with an existing SCR, and a unit's actual 2009 ozone season and non-ozone season NOx emission rates. [EPA-HQ-OAR-2009-0491-2689.1, p.45]
Duke Energy recommends that EPA use separate ozone season and non-ozone season NOx emission rates for units with an existing SCR instead of using a unit's ozone season emission rate to represent its emissions over the entire year because a unit's ozone season NOx emission rate is typically not completely representative of its non-ozone season emission rate, and therefore is not representative of a unit's capability over an entire year (a review of 2009 ozone season and non-ozone season NOx emission rates for units with SCRs operating year around shows that the ozone season NOx emission rates are typically lower than the non-ozone season rates). Therefore, applying a unit's ozone season NOx emission rate to the non-ozone season under predicts a unit's annual NOx emissions, the state budgets, and the unit allowance allocations. The fact that the ozone season NOx emission rate is not representative of the non-ozone season emission rate is due to many factors, including the following: 1) most units have the fewest number of outages during the ozone season which results in the most continuous period of SCR operation, whereas outside of the ozone season, most units experience the bulk of planned and maintenance outage activity. This results in higher occurrences of unit start-up and shut-down when emission rates are higher than during continuous operation. 2) Lower ambient temperatures in the winter season generally result in a higher propensity for ammonium bisulfate formation in the air heaters and downstream ductwork on SCR units, resulting in air heater and ductwork pluggage, and the need to reduce NOx removal to maintain unit output capacity. Generating units do this by reducing the level of ammonia feed and/or regulating the temperature of the gas entering the SCR. 3) Many units tend to have catalyst replacement outages in the spring outage season, resulting in peak SCR removal capability during the ozone season immediately following the outage. This "brand new" catalyst will show the best overall performance for the next several months immediately following the outage, and thus lower average ozone season emissions may be influenced by SCR catalyst outage schedules. [EPA-HQ-OAR-2009-0491-2689.1,pp.46-47]
The following presents unit level ozone season and non-ozone season NOx emission rates that Duke Energy recommends EPA use for each of the listed Duke Energy units. [EPA-HQ-OAR-2009-0491-2689.1,p.47]
East Bend (ORISPL 6018) Unit 2.  
This unit is being modeled at a 0.0520 lb/mmBtu annual and ozone season NOx emission rate. This unit cannot perform at or below a rate of 0.060 lb/mmBtu, as demonstrated by the actual 2009 performance which reflects year-round operation of the SCR for CAIR Annual and Ozone NOx compliance. The SCR was operated to the maximum extent possible, given the operating conditions of the unit. The 2009 ozone season and non-ozone season NOx emission rates for this unit were 0.0886 lb/mmBtu and 0.1249 lb/mmBtu respectively. These are the emission rates that Duke Energy recommends EPA use for this unit. It would require extensive upgrades to the SCR to get it to perform at or below 0.060 lb/mmBtu at a $/ton cost far in excess of $500/ton. In addition, it is not be possible to complete an upgrade by January 1, 2012. [EPA-HQ-OAR-2009-0491-2689.1, p.47]
Miami Fort (ORISPL 2832) Unit 7.
This unit is being modeled at a 0.0530 lb/mmBtu annual and ozone season NOx emission rate. This unit cannot perform at or below a rate of 0.060 lb/mmBtu, as demonstrated in the actual 2009 performance which reflects year-round operation of the SCR for CAIR Annual and Ozone NOx compliance. The SCR was operated to the maximum extent possible, given the operating conditions of the unit. The 2009 ozone season and non-ozone season NOx emission rates for this unit were 0.0650 lb/mmBtu and 0.0843 lb/mmBtu respectively. These are the emission rates that Duke Energy recommends EPA use for this unit. It would require extensive upgrades to the SCR to get it to perform at or below the floor level at a $/ton cost far in excess of $500/ton. In addition, it is not be possible to complete an upgrade by January 1, 2012. [EPA-HQ-OAR-2009-0491-2689.1,pp.47-48]
Miami Fort (ORISPL 2832) Unit 8.  
This unit is being modeled at a 0.0560 lb/mmBtu annual and ozone season NOx emission rate). This unit cannot perform on an annual basis at the floor rate of 0.060 lb/mmBtu or lower, as demonstrated in the actual 2009 performance which reflects year-round operation of the SCR for CAIR Annual and Ozone NOx compliance. The SCR was operated to the maximum extent possible, given the operating conditions of the unit. The 2009 ozone season and non-ozone season NOx emission rates for this unit were 0.0556 lb/mmBtu and 0.0993 lb/mmBtu respectively. Duke Energy recommends using 0.060 lb/mmBtu (Duke Energy's recommended floor emission rate) for the ozone season and 0.0993 lb/mmBtu for the non-ozone season for this unit. It would require extensive upgrades to the SCR to get it to perform at or below the floor level at a $/ton cost far in excess of $500/ton on an annual basis. In addition, it is not be possible to complete an upgrade by January 1, 2012. [EPA-HQ-OAR-2009-0491-2689.1, p.48]
W H Zimmer (ORISPL 6019) Unit 1.  
This unit is being modeled at a 0.0530 lb/mmBtu annual and ozone season NOx emission rate. This unit cannot perform at or below a rate of 0.060 lb/mmBtu, as demonstrated in the actual 2009 performance which reflects year-round operation of the SCR for CAIR Annual and Ozone NOx compliance. The SCR was operated to the maximum extent possible, given the operating conditions of the unit. The 2009 ozone season and non-ozone season NOx emission rates for this unit were 0.0852 lb/mmBtu and 0.1330 lb/mmBtu respectively. These are the emission rates that Duke Energy recommends EPA use for this unit. It would require extensive upgrades to the SCR to get it to perform at or below the floor level at a $/ton cost far in excess of $500/ton. In addition, it is not be possible to complete an upgrade by January 1, 2012. [EPA-HQ-OAR-2009-0491-2689.1, pp.49-50]
Gibson (ORISPL 6113) Unit 3.  
This unit is being modeled at a 0.060 lb/mmBtu annual and ozone season NOx emission rate. This unit cannot perform at or below a rate of 0.060 lb/mmBtu, as demonstrated in the actual 2009 performance which reflects year-round operation of the SCR for CAIR Annual and Ozone NOx compliance. The SCR was operated to the maximum extent possible, given the operating conditions of the unit. The 2009 ozone season and non-ozone season NOx emission rates for this unit were 0.1182 lb/mmBtu and 0.1400 lb/mmBtu respectively. These are the emission rates that Duke Energy recommends EPA use for this unit. It would require extensive upgrades to the SCR to get it to perform at or below the floor level at a $/ton cost far in excess of $500/ton. In addition, it is not be possible to complete an upgrade by January 1, 2012.  [EPA-HQ-OAR-2009-0491-2689.1, p.50] 
Gibson (ORISPL 6113) Unit 4.  
This unit is being modeled at a 0.060 lb/mmBtu annual and ozone season NOx emission rate. This unit cannot perform at or below a rate of 0.060 lb/mmBtu, as demonstrated in the actual 2009 performance which reflects year-round operation of the SCR for CAIR Annual and Ozone NOx compliance. The SCR was operated to the maximum extent possible, given the operating conditions of the unit. The 2009 ozone season and non-ozone season NOx emission rates for this unit were 0.0803 lb/mmBtu and 0.0915 lb/mmBtu respectively. These are the emission rates that Duke Energy recommends EPA use for this unit. It would require extensive upgrades to the SCR to get it to perform at or below the floor level at a $/ton cost far in excess of $500/ton. In addition, it is not be possible to complete an upgrade by January 1, 2012. [EPA-HQ-OAR-2009-0491-2689.1, p.50]
Gibson (ORISPL 6113) Unit 5.  
This unit is being modeled at a 0.060 lb/mmBtu annual and ozone season NOx emission rate. This unit cannot perform at or below a rate of 0.060 lb/mmBtu, as demonstrated in the actual 2009 performance which reflects year-round operation of the SCR for CAIR Annual and Ozone NOx compliance. The SCR was operated to the maximum extent possible, given the operating conditions of the unit. The 2009 ozone season and non-ozone season NOx emission rates for this unit were 0.1088 lb/mmBtu and 0.1105 lb/mmBtu respectively. These are the emission rates that Duke Energy recommends EPA use for this unit. It would require extensive upgrades to the SCR to get it to perform at or below the floor level at a $/ton cost far in excess of $500/ton. In addition, it would not be possible to complete an upgrade by January 1, 2012.  [EPA-HQ-OAR-2009-0491-2689.1, p.51]
Response: 
In the final Transport Rule, EPA does not use historic emissions data to set the Transport Rule state budgets, but instead relies on projected emissions data under the marginal cost thresholds selected to define significant contribution and interference with maintenance.  EPA uses the same budget-setting methodology in the final rule on all pollutants analyzed (including ozone-season NOx, annual NOx, and SO2).  This change obviates many of the concerns above regarding the selection and use of historic data in budget determination.  Additionally, EPA's final Transport Rule uses NOx rates that were updated from the proposal to reflect 2009 data.  See EPA IPMv.4.10 documentation for a description of how unit level NOx rates are modeled.  Finally, EPA notes that there are not unit level control requirements under the final Transport Rule, and individual sources are not required to operate in the same manner as reflected in any EPA modeling.
Organization: Edison Electric Institute (EEI)
Comment: 
Edison Electric Institute (EEI)
As for the particulate matter standard and the Proposed Rule's SO2 budgets, testifying on behalf of the National Association of Clean Air Agencies, Tad Aburn (Maryland Department of the Environment), at EPA's August 26 public hearing on the Proposed Rule in Philadelphia, stated that "Furthermore, at this time the proposed SO2 caps -- especially the tightened 2014 cap -- appears to be sufficiently stringent to meet most states' needs." [EPA-HQ-OAR-2009-0491-2697.1, p.13]
Response: 
See Section VI.D of final Transport Rule Preamble for discussion on final state emissions budgets and resulting air quality impact.
Organization: GE Energy Financial Services (GE EFS)
Comment: 
GE Energy Financial Services (GE EFS)
According to the preamble to the Proposed Transport Rule, 'instead of defining the budgets based on IPM projections of what will happen when [emissions controls] are turned on' (75 Fed. Reg. at 45291), EPA disregarded IPM's projections because 'EPA believes that the actual performance units achieved in 2009 is more representative of expected emissions than what EPA modeled using IPM. This is because real data takes into account actual unit by unit information that is represented at a more aggregate level in [PM.' 75 Fed. Reg. at 45290 (emphasis added). [EPA-HQ-OAR-2009-0491-2701.1, p.3]
Response: 
See Section VI of Preamble for discussion on why EPA relied on projected emissions for state budget in the final Transport Rule
Organization: Illinois Environmental Protection Agency
Comment: 
Illinois Environmental Protection Agency
Consistent with the recommendations ofthe state collaborative efforts, as contained in the September 2, 2009 letter to U.S. EPA Administrator Jackson mentioned above, Illinois EPA supports U.S. EPA's proposed approach for establishing initial budgets based on the optimization of existing controls. We believe that this approach provides the best means of providing timely emission reductions needed to address fast-approaching attaimnent deadlines for some nonattainment areas affected by interstate transport. It is important however that these initial budgets be replaced expeditiously with budgets based on a more equitable approach. Significantly, U.S. EPA's proposed NOx budgets for the second phase of emissions budgets continue to be based on optimization of existing controls which unfairly penalizes sources who have implemented controls prior to 2012. Illinois EPA recognizes and appreciates U.S. EPA's commitment to finalize a second Transport Rule quickly that may establish tighter NOx emission caps derived using a more equitable methodology. We believe that U.S. EPA should include revised Phase 2 NOx emission budgets in the present rulemaking to encourage further controls on high-emitting, under-controlled EGUs to level the playing field for EGUs that have already implemented controls.
Illinois EPA also believes that the initial 2012 budgets are based on unrealistic expectations for optimization of controls for some emission units. Review of the emissions data for Illinois sources shows that many of the units were assigned emissions allowances applying SCR emissions rates below 0.06 Ibs/mmBTU for NOx, and S02 removal rates greater than 95%. It may not be reasonably possible for some existing control systems to achieve these levels of emissions reductions. It is instructive to note that recent determinations of best achievable control technology (BACT) for new coal-fired utility boilers, as listed in the BACTILAER Clearinghouse, indicate that BACT for NOx controls using SCR varies from 0.07 to 0.1 Ibs/mmBTU. For S02 controls using FGD, BACT has been determined to be from 92 to 96% removal. Illinois EPA therefore recommends that U.S. EPA set a floor for the effectiveness of optimized controls at 0.07 Ibs/mmBTU for SCRs and 95% removal rate for FGD for NOx and S02 emissions, respectively.  [EPA-HQ-OAR-2009-0491-2781.1 p.2]
Response: 
See section VI of the preamble for a description of the final Transport Rule state budget determination. Also, the "Documentation Supplement for EPA Base Case v.4.10_FTransport - Updated for Final Transport Rule" describes changes made to removal efficiency of FGD.  Notably, EPA has adjusted its removal rate assumptions for both existing and new FGD based on comments of this nature.  Furthermore, EPA's modeling of EGU NOx emissions at each unit reflects emission rates that were reported by that specific unit.  EPA does not assign NOx emission rates below 0.06 lbs/mmbtu to any unit unless that unit had reported such a rate previously.
Organization: Kentucky Division for Air Quality
Comment: 
Proposed Transport Rule State SO2 Budgets for Kentucky
Pursuant to the proposed Transport rule Preamble Section IV.E., State Emissions Budgets (75 FR 45290-45292), the Division is concerned that the Transport Rule SO2 emission budgets being proposed by EPA for Kentucky, especially in 2014, represent a drastic SO2 emission reduction which may not be achievable by Kentucky sources. Based on the Division's review of 2009 actual SO2 emissions for Kentucky Electric Generating Units (EGUs) (an estimated 252,000 tpy per 2009 EPA CAMD data), the proposed Transport Rule SO2 budget in 2012 (219,549 tpy) will be difficult to meet and the proposed rule's SO2 budget for 2014 (113,844 tpy) will be much more difficult and problematic to achieve given that most large Kentucky EGUs already have flue gas desulfurization (FGD) scrubbers operational before 2012 (See below Figure 1 and see the attached Table 1 for Kentucky SO2 FGD controls and 2009 CAMD emissions [See EPA-HQ-2009-0491-2805.1, p.2 for Figure 1]). Kentucky has only one remaining large unit (800 MWe) that is not scrubbed. Per a consent decree, this unit will install a FGD scrubber by December 31, 2015. However, this alone cannot achieve the needed SO2 budget reduction proposed by EPA for 2014. [EPA-HQ-2009-0491-2805.1, pp.1-2]
As indicated by Figure 1 [See EPA-HQ-2009-0491-2805.1, p.2 for Figure 1], the Transport Rule as proposed would require Kentucky EGUs to reduce their 2009 SO2 emissions by an estimated 13% by 2012 and reduce their 2009 emissions by an additional 42% by 2014 resulting in a total EGU SO2 emission reduction of 55% from the Kentucky 2009 EGU SO2 emission level. In addition, the proposed 2014 Transport Rule SO2 budget reflects a 48% decrease from the proposed 2012 Transport Rule SO2 budget for Kentucky EGUs. Even if these drastic emissions reductions being proposed by the Transport Rule are technologically feasible, which is in question, they are unrealistic and not practicable given that achieving such reductions may: (1) lead to disruptions in a reliable power supply in the region; (2) cause certain economic hardships for industry sectors; and (3) drive up the cost of consumer electricity rates. The Division requests that EPA reconsider the SO2 emission reductions in light of these probable outcomes. [EPA-HQ-2009-0491-2805.1, p.2]
Proposed Transport Rule State NOx Budgets for Kentucky  
Pursuant to the rule preamble Section IV.E., State Emissions Budgets (75 FR 45290-45292), based on the Division's review of 2009 actual NOx emissions for Kentucky EGUs (an estimated 79,000 tpy per 2009 EPA CAMD data), the proposed Transport Rule NOx budget in 2012 and 2014 (74,117 tpy) will also be difficult for certain Kentucky EGUs to meet since most Kentucky EGUs already have some type of NOx controls in place (See below Figure 2 [See EPA-HQ-OAR-2009-0491-2805.1, p.3 for Figure 2] and see the attached Table 1 [See EPA-HQ-OAR-2009-0491-2805.1, p.2 for Figure 1] for Kentucky NOx controls and 2009 CAMD emissions). [EPA-HQ-OAR-2009-0491-2805.1, p.3]  
As indicated by Figure 2 [See EPA-HQ-OAR-2009-0491-2805.1, p.3 for Figure 2], the Transport Rule as proposed would require Kentucky EGUs to reduce their 2009 annual NOx emissions by an estimated 6% by 2012. Notwithstanding the difficulty in obtaining this reduction, the Division is perplexed that EPA has proposed such a drastic budget reduction for SO2 from 2012 to 2014 for Kentucky (See Figure 1), but has kept the 2012 and 2014 proposed Transport Rule NOx budgets the same (See Figure 2 [See EPA-HQ-OAR-2009-0491-2805.1, p.3 for Figure 2]). The Division requests that EPA provide its rationale for this decision. [EPA-HQ-OAR-2009-0491-2805.1, pp.3-4]  
Response: 
The Transport Rule 2012 budget does not assume the installation of any new controls in 2012, and Kentucky's 2012 budget is based on the operation of existing controls and other reductions available at $500/ton as described in the TR preamble.  EPA also notes that there are several consent decree requirements that impacted Kentucky sources between 2009 (the year for which SO2 emissions are quoted in comment) and 2012 (the first year of compliance).  Additionally, sources in the state had controls come online and become fully operational during this time period.  EPA believes that the 2012 SO2 budget for Kentucky is reasonable and can be met with no service disruptions. Additionally, as noted in the comment, there is one large unit that is not yet controlled in the state for SO2.  The 2012 SO2 emissions budget is premised on this unit not operating a control in 2012.

In regards to how EPA determined NOX and SO2 budgets, see the discussion in section VI of the Transport Rule preamble.  In regards to 2014 budget compliance, see section VII of the Transport Rule preamble.
Organization: Maryland Department of Environment (MDE)
Sierra Club, Pennsylvania Chapter
Comment: 
Maryland Department of Environment (MDE)
Despite our analysis of NOx reductions needed to decrease transport and our specific recommendations of appropriate NOx levels, EPA's proposed Transport Rule includes a NOx budget that is not tight enough to achieve healthy air. Maryland encourages EPA to adopt an annual NOx cap of 900,000 tons in 2014, consistent with National Association of Clean Air Agencies (NACAA) and Ozone Transport Commission (OTC) analyses suggesting this to be technologically feasible and cost effective. In addition, EPA's analysis confirms the cost effectiveness of additional NOx reductions.1 [EPA-HQ-OAR-2009-0491-2639.1, p.2]
 

Footnote:
1 Senator Thomas Carper (D-DE) asked EPA to analyze the impacts of a 900,000 ton NOx cap in the East beginning in 2015 as a possible alternative to the 1.3 million ton cap in 2015 in his bill, the Clean Air Act Amendments of 2010 (S. 2995). The more stringent NOx caps provided between $3-10 billion in additional benefits each year at a cost of $1.5 billion. See "EPA Analysis of Alternative NOx and SO2 Caps for Senator Carper," July 16, 2010, http://www.epa.gov/airmarkets/progsregs/epa-ipm/ Carper2010/Carper_Analysis.pdf, accessed September 27, 2010. [EPA-HQ-OAR-2009-0491-2639.1, p.2]
Sierra Club, Pennsylvania Chapter
- reduce the 2014 aggregate state budgets in the annual control region (including Texas) for SO2 to 1.75 million tons (approximately equivalent to a 2 million ton nationwide cap); 3
- reduce the 2014 aggregate state budgets in the annual control region (including Texas) for NOx to 900,000 tons (approximately equivalent to a 1.25 million ton nationwide cap); [EPA-HQ-OAR-2009-0491-3482.1, p.7]

3. Based on the relative percentage of national 2009 power plant NOx and SO2 emissions that were within the TR plus Texas, the recommended regional caps are approximately a 2.0 million ton national SO2 cap, and a 1.25 million ton national NOx cap. [EPA-HQ-OAR-2009-0491-3482.1, p.7]
Response: 
See section VI.D of the preamble for description of multi-factor analysis used to determine elimination of significant contribution and subsequent determination of state budgets.  EPA notes that the sum of annual state budgets for SO2 and NOx is tighter in this final rule than as originally proposed (for states included in both proposed and final geography).
Organization: National Association of Clean of Air Agencies (NACAA)
Massachusetts Department of Environmental Protection
State of Louisiana, Department of Environmental Quality
Adirondack Council
Comment: 
Adirondack Council
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.62-63.]
We urge the EPA to use a stronger baseline for NOX emissions than the 1997 NAAQS standard. At a minimum, EPA should use the more stringent 2008 standard, and update the Transport Rule when a new standard is put in place, hopefully later this year, although that is now uncertain.
Massachusetts Department of Environmental Protection
EPA acknowledges that the proposal does not adequately address the 'significant contribution' of a number of states for the ozone and fine particle (PM 2.5) air quality standards that EPA adopted in 1997 ('the 1997 NAAQS'). We urge EPA to adopt NOx budgets in the final rule that fully meet the Transport Rule's stated goal of addressing states' downwind contributions. We believe that EPA should require reductions that eliminate the significant contribution of any state based solely on downwind air quality impacts, irrespective of the cost per ton of reductions needed to eliminate the transported emissions. EPA has taken an approach that considers downwind air quality impacts combined with an assessment of the reductions achievable at $500 per ton or less. Massachusetts has aggressively addressed our own sources of ozone precursor emissions for years, and will continue to do so. Like other states in the Ozone Transport Region, in order to meet the 1997 ozone NAAQS on which the Transport Rule is based, as well as the prior I-hour ozone NAAQS, we have adopted ozone control measures at costs that are at least 2- 3 times higher than the $500 per ton threshold for NOx reductions on which EPA is basing the proposed Transport Rule. We strongly encourage EPA to base the final Transport Rule on a cost threshold that exceeds $500 per ton in order to realize additional reductions and to more equitably address the needed balance between upwind and local control measures in meeting air quality goals.   [EPA-HQ-OAR-2009-0491-2787.2 p.2]
National Association of Clean of Air Agencies (NACAA)
With respect to ozone, our preference is that EPA tighten the NOx caps in 2014 to resolve the remaining nonattainment problems. In addition, since EPA plans to quickly promulgate Transport Rule II to address the new tightened ozone standard, EPA also has an opportunity in that rulemaking to resolve any remaining ozone downwind issues, in collaboration with the 10 states identified as still contributing to transport of ozone precursor emissions. [EPA-HQ-OAR-2009-0491-2771.1, p.4]
State of Louisiana, Department of Environmental Quality
LDEQ suggests that the NOx emission caps identified in the proposed Transport Rule are sufficient to begin the control of this pollutant. With the forthcoming Ozone NAAQS Reconsideration decision, states will perform air quality modeling runs based on a smaller grid and will be able to better understand the air quality of each particular area. As an example, the last modeling performed in the Baton Rouge Nonattainment Area showed that the area was NOx limited; by allowing the cap to remain static, the area will be better suited to developing a control strategy that will continue the downward trend of emissions. [EPA-HQ-OAR-2009-0491-2655.1, pp.5-6]
Response: 
As discussed in section III of the preamble, EPA plans to finalize its reconsideration of the 2008 revised ozone NAAQS soon, and the reductions achieved through this final Transport Rule will also help areas make progress toward achieving those revised NAAQS.  EPA intends to finalize reconsideration of the March 2008 ozone NAAQS in the summer of 2011 and subsequently to propose a transport-related action to address any necessary upwind state control responsibilities with respect to that reconsidered NAAQS expeditiously.  Section VI or the preamble explains how EPA determined the final rule's selection of cost thresholds on each pollutant to define significant contribution and interference with maintenance in each state.
Organization: New York State Department of Environmental Conservation
Tennessee Valley Authority (TVA)
Clean Energy Group
JEA
Comment: 
Clean Energy Group
III. The Clean Energy Group Supports EPA's Preferred Methodology for Developing State Budgets
EPA appropriately uses a multi-step process that includes both air quality and cost modeling to calculate state contributions to downwind nonattainment and interference with maintenance. As EPA discusses in the preamble to the proposed rule, it is important to require that emission reductions are achieved as expeditiously as possible. Under the preferred methodology for determining the 2012 state budgets, EPA uses a mix of IPM modeling, adjusted reported emissions, and adjustments to both modeled and reported emissions based on pollution control technologies installed or projected to be installed before 2012. By using this methodology, EPA intends to avoid backsliding in the control of emissions from Transport Rule units' progress made in response to CAIR. Under the unique circumstances resulting from the vacatur and subsequent remand of CAIR, the Clean Energy Group supports this methodology for establishing initial state budgets for annual NOx, ozone season NOx, and 2012 S02 in both Group 1 and 2 states. This methodology would not be appropriate for future rulemakings because it would not drive the most cost-effective emissions reductions. However, the Clean Energy Group understands that the D.C. Circuit's decision creates a unique situation for EPA, and we agree that the proposed approach is appropriate for the initial state budgets. [EPA-HQ-OAR-2009-0491-2702.1, p. 4]
The Clean Energy Group also supports EPA's use of Integrated Planning Model (IPM) runs to set state budgets for 2014 Group 1 S02 emissions using pollution control cost thresholds. The Clean Energy Group understands and supports that this methodology would be the basis for establishing any revised state budgets in any of the four programs (e.g., ozone season NOx, annual NOx, Groups 1 and 2 S02) as necessary to comply with future NAAQS. [EPA-HQ-OAR-2009-0491-2702.1, p. 4]
JEA
EPA's Choice of 2008 and 2009 for the Baseline is Inappropriate
EPA has chosen 2008 and 2009 as baseline years for NOx and SO2 emissions, respectively. These two years do not represent normal operating conditions for JEA and many other EGUs regulated under this rulemaking. Therefore, EPA should allow for the selection of a more representative time period. The units regulated by this rulemaking are also regulated under the Clean Air Interstate Rule (CAIR). JEA did indeed have extended outages in 2008 and 2009 to install NOx control equipment at SJRPP. Additionally, in 2008 and further into 2009, the U.S. economy plunged into an economic 'crisis,' and electricity demand dropped significantly. Therefore, 2008 and 2009 are not representative years for JEA and many other EGUs regulated by this rulemaking. JEA suggests that EPA utilize an approach similar to CAIR, and use an average capacity of the past five years, or some other period that would more accurately represent past performance. [EPA-HQ-OAR-2009-0491-2713.1, p.3]
New York State Department of Environmental Conservation
The Department suggests two primary methods to rectify these residual transport issues. The first is a higher cost-per-ton threshold. This proposal defines cost-effective controls for ozone [EPA-HQ-OAR-2009-0491-2730.1, p.5] season NOx at $500 per ton. EPA reasons that SCR units would have already been installed under CAIR, and $500 per ton is the amount that would be required to keep these units operating. By not considering the cost of installing controls, EPA's cost threshold is held artificially low, which effectively eliminates installation of any controls from consideration. EPA should consider both the cost of installation and operation of controls and set the cost threshold accordingly. This would allow cost effective controls not yet in place to be considered in the analysis. [EPA-HQ-OAR-2009-0491-2730.1, p.6]
Tennessee Valley Authority (TVA)
B. Issue: EPA's technical support documents (TSD) indicate 2012 SO2 and NOx budgets are set at the lower of recent historical actual emissions or projected emissions at the state level. For NOx, EPA notes in the TSD ("State Budgets, Unit Allocations and Unit Emission Rates") that the reported annual and ozone season NOx data was adjusted for unusually low utilization rates in 2009. For SO2, however, EPA used the historical 12 month emission period comprising the last quarter of 2008 and the first three quarters of 2009, disregarding any low utilization during this period. EPA did not use historical emission rates with projected future heat input levels to determine SO2 and NOx budgets. [EPA-HQ-OAR-2009-0491-2782.1, p. 8]
TVA Comment: TVA coal fired generation and emissions were significantly depressed during the 2008- 2009 historical period due to economic recession, unusually low natural gas prices, and other factors. For example, two of TVA's fossil plants in Tennessee, Kingston and Bull Run, had units shutdown for significant periods in 2009, the former in the aftermath of the Kingston coal ash slide and the latter for high cost fuel supply and reduced demand. EPA should not use the 2008-09 time period to establish the emission budgets as this period is not representative of normal coal-fired generation levels for TVA. Instead, if EPA uses historical emissions to set budgets, EPA should use the average three year period spanning 2006-2008 as this period is representative of historical generation levels from the coal-fired plants in TVA's fleet. A better historical performance-based methodology would be to base future emission budgets on representative historical emission rates in conjunction with projected future heat input levels. [EPA-HQ-OAR-2009-0491-2782.1, p. 8]
Response: 
In the final Transport Rule, EPA does not use historic emissions data to set the Transport Rule state budgets, but instead relies on projected emissions data under the marginal cost thresholds selected to define significant contribution and interference with maintenance.  EPA uses the same budget-setting methodology in the final rule on all pollutants analyzed (including ozone-season NOx, annual NOx, and SO2).  Please see section VI.D of the preamble for a thorough explanation of this approach.
Organization: Pennsylvania Department of Environmental Protection
South Carolina Department of Health and Environmental Control 
Comment: 
Pennsylvania Department of Environmental Protection
Stringent Emission Budgets Needed to Prevent Backsliding
Pennsylvania is extremely concerned that the proposed Transport Rule may result in a relaxation of the CAIR emission budgets approved by EPA and incorporated in the Commonwealth's SIP on December 10,2009 (74 Fed. Reg. 65,446). [EPA-HQ-OAR-2009-0491-2660.1,p.5]
The CAIR SIP revision codified at 40 CFR 52.2020 established a federally enforceable CAIR annual NOx budget of 99,049 tons. However, under the proposed Transport Rule, the annual NOx budget for Pennsylvania is increased to 113,903 tons prior to variability. By 2014, DEP projects that the TR would allow up to a 4.2% increase in annual NOx emissions in the Commonwealth and as much as a 20% increase in ozone season NOx emissions from 2009 levels, depending on the remedy option promulgated in the final rule. It is imperative that the final rule establish more stringent NOx emission budgets to address transported pollution from upwind sources; otherwise, Pennsylvania and downwind areas would have to find other emission reductions to replace those lost due to EPA's lack of stringency. Additionally, Pennsylvania has recorded 28 exceedances of the 1997 ozone standard and 145 exceedances of the 2008 ozone NAAQS during the 2010 ozone season. The fact that ozone season actual reductions under CAIR Phase I and the proposed Transport Rule would be similar is further indication that a tighter ozone season NOx budget must be established to comply with Title I of the CAA. [EPA-HQ-OAR-2009-0491-2660.1, p.5]
Similarly, more stringent SO2 emission budgets must be established in the final Transport Rule. Pennsylvania's SIP-approved CAIR 2010 SO2 budget is 275,990 tons, whereas under the proposed rule, the 2012 SO2 budget for EGUs in the Commonwealth is increased to 388,612 tons. The SIP-approved CAIR annual 2015 SO2 budget for EGUs in Pennsylvania is 193,193 tons, whereas under the proposed Transport Rule, the annual 2014 SO2 budget is 141,693. [EPA-HQ-OAR-2009-0491-2660.1, pp.5-6]
The DEP is relying on the NOx and SO2 emission reductions achieved under the CAIR in Pennsylvania and other upwind states to support attainment demonstrations for the 1997 ozone and PM2.5 health-based standards. Therefore, the final Transport Rule must not violate the 'anti-backsliding' provisions in Sections 110 and 193 of the CAA, 42 D.S.C. §§ 7416 and 7515. Failure to address backsliding would require states with relaxed NOx and SO2 emissions budgets under the TR to insure 'equivalent or greater emission reductions of such air pollutant.' 42 U.S.C. § 7515. [EPA-HQ-OAR-2009-0491-2660.1, p.6]
The DEP urges EPA to establish stringent state-specific NOx and SO2 emissions budgets in the final Transport Rule that are at least equivalent to or greater than the SIP-approved CAIR budgets. EGU owners and operators must not be allowed to backslide on the NOx and SO2 emission reductions achieved in this Commonwealth and upwind areas. [EPA-HQ-OAR-2009-0491-2660.1, p.6]
[These comments were also submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.52.]
 
South Carolina Department of Health and Environmental Control 
DHEC notes that the proposed Transport Rule SO2 budget for South Carolina is greater than its SO2 budgets under CAIR and the Acid Rain Program. The proposed Transport Rule SO2 budget is 116,483 tons per year,43 while under CAIR the SO2 budget was 57,271 tons per year,44 and, under the Acid Rain Program, the SO2 budget was 111,342 tons per year.45 This 103% increase from CAIR in possible SO2 emissions is troubling, especially given the recently lowered SO2 NAAQS and the imminent review of the PM2.5 NAAQS. The proposed Transport Rule divides states controlled for PM2.5 into two groups, Group 1 and Group 2. Group 1 requires SO2 reductions in 2012 and 2014, and Group 2 requires SO2 reductions in 2012 only. Only two other Group 2 states, Louisiana and Alabama, experienced an increase in their SO2 budgets from CAIR to the Transport Rule. Louisiana's increase was only 51%, and Alabama's increase was only 2.6%. [EPA-HQ-OAR-2009-0491-2677.1 p.18]
DHEC understands that the proposed Transport Rule is designed to address downwind nonattainment and maintenance, not local air quality, as required by section 110(a)(2)(D)(i)(I).46 DHEC also acknowledges that the budgeting process considered downwind nonattainment and interference with maintenance. South Carolina's Transport Rule SO2 budget is the amount of SO2 that sources within the state can emit without significantly contributing to nonattainment or interfering with maintenance downwind.47 DHEC further understands that the Transport Rule budget is a firm cap, unlike the CAIR budgets, which states could exceed.48 CAIR sources within a state could emit more than a state's budget by purchasing allowances from sources inother states. Even in light of these acknowledgements, DHEC is concerned that sources within South Carolina subject to the Transport Rule would be given an increase in their allowableemissions cap under the Transport Rule. [EPA-HQ-OAR-2009-0491-2677.1 p.18]
DHEC could not find evidence in the modeling Technical Support Documents that the EPA accounted for the result of the economic incentive of a larger budget on future emissions. In the Budgets and Allocations Spreadsheet, DHEC notes that the EPA predicts SO2 emissions decreases for South Carolina sources.49 Without accounting for the incentive that a greater budget provides, this projection would be specious. [EPA-HQ-OAR-2009-0491-2677.1 p.19]
As noted above, the EPA states in the proposed Transport Rule that the Transport Rule is only designed to meet the requirements of section 110(a)(2)(D)(i)(I). That section of the Act, the EPA notes, "does not grant EPA authority to require emissions reductions solely because they provide large health and environmental benefits...."50 DHEC agrees with this reading of the section 110(a)(2)(D)(i)(I), but DHEC contends that in section 110(c)(1) of the CAA, the basis of the EPA's authority for the FIP,51 Congress did not intend for the EPA to enact programs that increase emissions locally, even if those programs reduce interstate transport. [EPA-HQ-OAR-2009-0491-2677.1 p.19]
DHEC further contends that an emissions increase resulting from the Transport Rule is not in line with the spirit of the anti-backsliding provisions of the CAA (sections 172(e) and 193). These provisions do not specifically address the current situation: The EPA is proposing a FIP based on section 110(c)(1) that could lead to emissions increases in a state which would likely contribute to nonattainment with a NAAQS. To be clear, DHEC is not arguing that the proposed  Transport Rule violates CAA sections 172(e) and 193. We are simply submitting our concern with the increased budget, and requesting clarification for how the EPA accounted for the impact of increased SO2 allowances available to South Carolina electricity-generating units under the proposed Transport Rule on SO2 emissions in South Carolina. [EPA-HQ-OAR-2009-0491-2677.1 p.19]
DHEC is also concerned that the anomaly of the 103% increase in the Transport Rule SO2 budget is further evidence of a flawed modeling process. More than 57,271 tons of SO2 per year from South Carolina under the CAIR would significantly contribute to downwind nonattainment, yet under the purportedly more stringent Transport Rule, South Carolina's sources can emit more than twice that amount without significantly contributing to nonattainment or interference with maintenance. Additionally, if the EPA were to include the FGD units on Santee Cooper's Cross Units 1, 2, and 3 in the IPM assumptions, then South Carolina's modeled SO2 emissions would be thousands of tons lower. We do not understand how the EPA can conclude in the CAIR that South Carolina sources could only emit 57,271 tons of SO2 per year, yet in the Transport Rule, even with the missing controls and over-estimated emissions, the EPA is proposing to allow South Carolina sources to emit 116,483 tons of SO2 per year. The intent of the Transport Rule is to correct the deficiencies in the CAIR. DHEC assumed that the Transport Rule was going to be more stringent than CAIR, and we note that such unexpected budgets call into question the fundamental assumptions of the modeling. [EPA-HQ-OAR-2009-0491-2677.1 p.20]
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.86.]
For example, there is a proposed 103 percent increase in South Carolina's SO2 budget from the CAIR to the Transport Rule. Under the CAIR, South Carolina sources were allowed a budget of 57,271 tons of SO2 per year. However, in the proposed Transport Rule, South Carolina sources would be given a budget of 111,342 tons of SO2 per year.
Response: 
See Section VI.D of the Preamble for additional discussion on concerns over backsliding.
Some commenters expressed concern that, under the proposed Transport Rule, states had some state budgets that were higher than those under CAIR.  Commenters suggested that this would be inconsistent with requirements or spirit of certain CAA provisions aimed at preventing backsliding, i.e., sections 110(l), 172(e), and 193.   However, the D.C. Court of Appeals rejected the state budgets in CAIR as arbitrary and capricious and not consistent with CAA section 110(a)(2)D)(i)(I)  ( North Carolina, (531 F.3d  918 and 921) and remanded CAIR to EPA to promulgate a new rule replacing CAIR and consistent with the Court's decision ( North Carolina, 550 F.3d 1178 ).  As discussed elsewhere in this section, on remand EPA developed new, final state budgets that address the Court's concerns and meet section 110(a)(2)(D)(i)(I) requirements.   Although, for some states, some state budgets under the final rule are higher than those under CAIR, this does not violate either the letter nor the spirit of CAA provisions aimed at backsliding.   In particular, CAA section 110(l) provides that the Administrator may not approve  a plan revision  that would "interfere with any...applicable requirement" of the CAA.  42 U.S.C. 7410(l).   Because the Court reversed and remanded CAIR with instructions to "remedy" the rule's  "fundamental flaws"  (including specifically the state budgets found to be unlawful (North Carolina, (550 F.3d 1178 )), it is difficult to see how new state budgets replacing unlawful budgets and meeting section 110(a)(2)(D)(i)(I) requirements could be viewed as interfering with requirements of the CAA.   Indeed, the commenters' approach would severely limit  EPA's ability to meet the Court's mandate to develop a new rule consistent with section 110(a)(2)(D)(i)(I).  See North Carolina, 531 F.3d 921 (explaining that EPA may not require  "some states to exceed the mark" of eliminating their significant contribution).  Further, the other CAA sections cited by the commenters (section 172(e), addressing circumstances where the Administrator relaxes a NAAQS,  and section 193, addressing the treatment of requirements promulgated before the November 15, 1990, enactment date for the 1990 Amendments to the Clean Air Act) are not applicable here. 
Organization: Sierra Club, Georgia Chapter
Comment: 
Sierra Club, Georgia Chapter
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.97-98.]
Whereas CAIR would have given Georgia an SO2 budget of 213,000 tons per year, the revised Transport Rule gives Georgia a bigger budget of 233,000 tons in 2012.
The construction schedules for the sulfer dioxide controls at Georgia power plants can achieve bigger reduction than the Transport Rule will require. We also need controls as fast as possible from our neighboring states, in particular Alabama and Tennessee.
Response: 
In the final Transport Rule, EPA accounts for emission reductions already occurring in the baseline (for example, due to Georgia's state rule) when setting emission budgets under the Transport Rule programs in 2012 and 2014.  In this manner, Georgia's 2014 SO2 budget accurately reflects the emission remaining after the identified cost-effective emission reductions have been made and all other legally binding emission requirements are in place.  Please see section VI.D in the preamble for more detail on this methodology.
Organization: Southern Alliance for Clean Energy
Comment: 
Southern Alliance for Clean Energy
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.38-39.]
While we're pleased to see that EPA has set strong and rigorously modeled budgets for upwind states, we are concerned about the confusing nature of group-one classification as it applies to the Tennessee Valley Authority.
EPA explains that certain states are categorized as group-one states and are tasked with sulfer dioxide reductions in 2012 and again in 2014. Tennessee is a group-one state and yet Tennessee's sulfer dioxide budget is 100,007 tons in 2012 and in 2014. In other words, it appears that Tennessee is not required to further reduce its sulfer dioxide emissions as other group-one states will be required to do.
We, therefore, ask that you please clarify why Tennessee as a group-one state has only one sulfer reduction goal set for 2012 and ask that you consider setting a more stringent budget for 2014.
Response: 
In the final Transport Rule, the 2014 budget for Tennessee is tighter than its 2012 budget.  The budget formation process is described in Section VI.D of the preamble and in the "Significant Contribution and State Emissions Budgets for the Final Transport Rule TSD"
Organization: State of Connecticut
Comment: 
State of Connecticut
Connecticut also generally supports the proposed sulfur dioxide emissions caps as they will lead to significant reductions in fine particulate matter throughout the eastern United States. However, EPA must improve the Transport Rule with respect to ozone in order to fully meet its responsibilities with respect to air pollution transport. [EPA-HQ-OAR-2009-0491-2534.1, pp. 1-2]
Response: 
See Sections III and VI of the final Transport Rule preamble for discussion of ozone season NOx budgets and elimination of significant contribution.
Organization: State of Ohio Environmental Protection Agency (Ohio EPA)
Comment: 
State of Ohio Environmental Protection Agency (Ohio EPA)
Ohio EPA believes the overall state NOx budgets are achievable. However, U.S. EPA must provide sufficient time for all units to meet the implementation deadline for their specific allocations and ensure that the allocations are determined in a fair and accurate manner. [EPA-HQ-OAR-2009-0491-2793.2, p. ]
The CAIR NOx budget for Ohio was 45,664 tons during the ozone season of 2009, dropping to 39,945 tons in 2015. The Proposed Transport Rule proposes a budget of 40,661 tons in 2012. In contrast, Ohio utilities emitted 36,076 tons in 2009 (due in part to a relatively cool summer and low demand). In short, the 2009 NOx emissions from Ohio utilities were less than the proposed 2012 NOx emissions budget. Although Ohio believes the overall state budget is achievable, there are inconsistent calculation methods and/or erroneous data that was used to establish the unit level allocations, which must be corrected before finalizing unit level allocations. [EPA-HQ-OAR-2009-0491-2793.2, p. 9]
Response: 
EPA has corrected unit level data based on comments (See Documentation Supplement for EPA Base Case v.4.10_FTransport - Updates for Final Transport Rule).  Furthermore, EPA has finalized an allocation methodology that relies on historic data, rather than projected data, to determine existing unit allocations under the Transport Rule FIPs.  The historic data is primarily based on reported data, which the sources' designated representatives have testified to its accuracy and completeness.
Organization: Tennessee Department of Environment and Conservation, Division of Air Pollution Control
Comment: 
Tennessee Department of Environment and Conservation, Division of Air Pollution Control
Comment #1 on Emissions Budgets: As noted above (Comment #2 on 2012 Baseline Emissions for Tennessee) EPA appears to have made certain assumptions for Tennessee based on the U. S. District Court decision in North Carolina vs. TVA. Specifically, we note that the 2012 SO2 and NOX budgets assume add-on controls at John Sevier fossil plants (control assumptions for John Sevier can be found in the parsed file for the 2012 IPM run). EPA should revise these assumptions, since the district court's decision was overturned by the court of appeals. [EPA-HQ-OAR-2009-0491-0553.1,p.4]
Comment #2 on Emissions Budgets: For both SO2 and NOX, EPA's technical support documents indicate that the 2012 budgets are the lower of the recent actual emissions or projected emissions at the state level. For NOX, EPA also notes that 2009 emissions were adjusted as necessary to account for low utilization during that year. EPA needs to make similar adjustments for SO2 if low utilization was not taken into consideration. [EPA-HQ-OAR-2009-0491-0553.1,p.4]
Response: 
In regards to comment #1: that modeling assumptions for the final rule did not include any constraints from the settlement that was overturned in that court case.
In regards to comment #2: In the final Transport Rule, EPA does not use historic emissions data to set the Transport Rule state budgets, but instead relies on projected emissions data under the marginal cost thresholds selected to define significant contribution and interference with maintenance.  
Organization: Utility Air Regulatory Group (UARG)
Comment: 
Utility Air Regulatory Group (UARG)
EPA Has Failed To Explain Why It Did Not Use 2008 Heat Input Data in Calculating SO2 Emission Budgets.
EPA proposes to set state emission budgets for annual and ozone season NOx and for SO2 based on the quantity of emissions that remain after elimination of significant contribution to nonattainment and interference with maintenance, but before accounting for variability. 75 Fed. Reg. at 45290/2. In its TSD addressing state budgets, EPA explains that it calculated 2012 state budgets using a combination of emissions and heat input data reported to EPA as of 2009 and IPM projections for 2012, each adjusted to reflect emissions control equipment projected by EPA to be in place by 2012. See State Budgets TSD at 3, 5.  [EPA-HQ-OAR-2009-0491-2756.1, p.78]
In that TSD, EPA notes that in creating the state budgets for annual and ozone season NOx, it "rebased" annual and ozone season NOx emissions for units reporting emission data to EPA by using 2008 rather than 2009 heat input. Id. at 9. According to EPA, this adjustment was made "to account for unusually low utilization [or heat input] in 2009." Id. During a conference call on August 30, 2010, however, EPA staff offered UARG members a different explanation for this adjustment. EPA staff indicated that the reason EPA used 2008 data was that the IPM projection of how sources would operate their NOx controls in 2012 did not align well with the 2009 data but aligned more closely with the 2008 data. [EPA-HQ-OAR-2009-0491-2756.1, p.79]
Whatever the reason or reasons EPA used 2008 instead of 2009 heat input data for NOx, EPA did not make a similar adjustment for unit-reported SO2 emissions. EPA does not provide any explanation for this differential treatment of the issue as between the two pollutants. EPA does, however, state repeatedly in the preamble that it developed the state budgets based on projected emissions "in an average year." See, e.g., 75 Fed. Reg. at 45214/2 ("A state's emissions budget is the quantity of emissions that would remain after elimination of the part of significant contribution and interference with maintenance the EPA has identified in an average year"); id. at 45271/2 (A state's budget "represent[s] the remaining emissions for the state in an average year"); id. at 45292/1 ("EPA has . . . developed state budgets based on its projections of state emissions in an average year"). Both the explanation in the TSD and the explanation offered on the August 30 conference call seem to indicate that EPA believes that 2009 heat input was not heat input for an average year, at least for NOx budget purposes.46 It is far from apparent why, if 2009 heat input was not average for -- and therefore was not used for -- NOx budget purposes, there would be any basis to use it for SO2 budget purposes. Before it proceeds further with this rulemaking, therefore, EPA will need to clarify and provide an adequate explanation for its decision to use 2009 heat input data for SO2. Prior to taking any final action to promulgate a rule, EPA should provide an opportunity for the public to comment on this important matter in light of an adequate explanation by the Agency. [EPA-HQ-OAR-2009-0491-2756.1, pp.79-80]

Footnote 46: UARG believes that EPA should have based state budgets on heat input in a higherthan- average year, at least for the first several years of the program, to allow for flexibility in the event that demand in those years requires higher-than-average generation.
Response: 
In the final Transport Rule, EPA does not use historic emissions data to set the Transport Rule state budgets, but instead relies on projected emissions data under the marginal cost thresholds selected to define significant contribution and interference with maintenance.  EPA uses the same budget-setting methodology in the final rule on all pollutants analyzed (including ozone-season NOx, annual NOx, and SO2).  Please see section VI.D of the preamble for a thorough explanation of this approach.
Organization: Vectren Corporation 
Comment: 
Vectren Corporation 
The proposed rule creates regional inequality.
The proposed Transport Rule creates regional inequality and further economic pressure for those thirteen states (including Indiana) that were singled out for even more stringent S02 reductions in 2014. The state emission caps for S02 in 2014 are significantly more stringent than those in 2012 for thirteen of the twenty-eight states covered under the Transport Rule. These states are the ones most reliant on coal and therefore shoulder the major portion of compliance burden for meeting these national goals. [EPA-HQ-OAR-2009-0491-2654.1, p. 5]
The extremely stringent S02 caps for states such as Indiana amount to an average rate of approximately 0.20 to 0.30 lbs S02 per million Btu, which can only just be attained by a scrubbed power plant using high sulfur coal meeting a 95% removal efficiency, 95% is the current maximum level of removal that most advanced retrofit scrubber designs can reliably achieve on an annual basis, Thus in order to achieve these stringent caps with a reasonable compliance cushion companies will face increasing pressure to move away from burning local high sulfur coal in favor of lower sulfur coal from Appalachia or the western states, This will further compound regional disparity if Indiana companies are unable to rely on local high sulfur coal mined in southern Indiana to meet the stringent state caps in the proposed rule, Indiana ratepayers will be faced not only with increases from higher fuel costs, but local southwestern Indiana economies will be further challenged by the loss of jobs in the coal-mining industry. [EPA-HQ-OAR-2009-0491-2654.1, p. 6]
Response: 
The incremental cost thresholds and corresponding multi-factor analysis examined in the Final Transport Rule was applied "equally" to all states that were contributing to downwind nonattainment or interference with maintenance.  Depending on the current control and fuel status of the generation within a state, the state budgets resulting from "multi-factor" analysis may suggest a greater reduction, relative to base case, in some states over other states.  However, while the resulting reductions and elimination of "significant contribution" that results from the multi-factor test may be different for certain states, the methodology for determining these budgets is not.
EPA does not find the commenter's calculated "average SO2 rate" metric to be a meaningful indicator of what individual units (including coal-fired units) will face under the Transport Rule programs.  The Transport Rule does not establish any specific emission rate requirements on any given units.  EPA analyzed the availability of cost-effective emission reductions in Indiana using the same methodology and modeling tools as it did for all other states, and it established a state-wide budget for covered units to meet collectively in Indiana.  This regulatory approach allows units with a wide spectrum of SO2 emission rates to flexibly comply with the Transport Rule programs as long as they hold an allowance for each ton emitted.
Organization: Wisconsin Power and Light Company
Comment: 
Wisconsin Power and Light Company
WPL is aware that EPA will be updating the final CATR in response to new and corrected information received in response to the Notice of Data Availability (NODA) published in the Federal Register on September I, 2010. EPA has developed the proposed CATR using a bottom-up approach that relies on modeled outcomes. EPA has stated that the modeled state budget levels are intended to be achieved by simply running existing or currently planned emission control equipment, or switching to lower sulfur coals where feasible. However, WPL believes that EPA has not sufficiently vetted this outcome and believes that many states, especially those subject to the tighter Group I S02 budget levels (that includes Wisconsin) will have significant difficulty achieving compliance. WPL's existing generation fleet is already predominantly burning low sulfur coal and the only further option to reduce S02 emissions is installation of new scrubber controls. The use of EPA models to develop air quality rules that require significant financial investments for compliance results in many uncertainties and potential implementation issues. Therefore, EPA must review final state budgets and associated EGU allocations to assure the models have not resulted in unreasonable or unintended controls by 2012. [EPA-HQ-OAR-2009-0491-2844.1 p.5]
Response: 
EPA's modeling of cost-effective emission reductions by 2012 specifically bars the installation of scrubbers or other post-combustion control installations in that timeframe, except for any specific post-combustion controls that are already scheduled to go online by 2012. 

IV.E.2. Ozone Season NOx State Emissions Budgets for EGUs - Data and Methodology

Organization: Connecticut Department of Environmental Protection
Comment: 
Connecticut Department of Environmental Protection
Set an ozone season emission budget in this proposed rule necessary to address interstate air pollution as measured against the 1997 8-hour ozone standard and include a tighter NOx budget for 2014 that will set a strong framework in advance of the anticipated reconsidered 2008 8- hour ozone standard and any subsequent Transport Rule. Doing so will provide regulatory certainty to the numerous sources subject to the Transport Rule both in Connecticut and throughout the Eastern United States. [EPA-HQ-OAR-2009-0491-2780.1 p.7]
Response: 
EPA is finalizing separate 2012 and 2014 state emission budgets for Ozone Season NOx.  As described in Section VI.D of the preamble, some states have tighter 2014 budget to capture potential reductions from non-Transport Rule state rules and consent decrees that come into effect between 2012 and 2014.  Also, the tighter 2014 budgets capture some of the co-benefit of tighter SO2 cost thresholds in 2014.
Organization: CPS Energy
Comment: 
CPS Energy
Another comment, the J K Spruce ORIS 7097 BLR1 (Spruce 1) Ozone Season NOx Rate is not achievable. Spruce 1 is equipped with Low NOx burners and a Separated Over-fired Air (SOFA) system which does reduce the NOx emission rate down to about 0.13 lb/mmbtu and sometimes slightly lower. The reported average NOx rate to the EPA was 0.13 lb/mmbtu for 2008 and 2009. Although, the 0.122 Ib/mmbtu rate was reported for 4th Quarter 2009, the unit cannot achieve a rate of 0.122 lb/mmbtu on a continuous basis. While operating all of the NOx reduction equipment using best practices, a rate of 0.13 lb/mmbtu is typically the rate achieved by the unit.  [EPA-HQ-OAR-2009-0491-2524.1, p.2]
Regarding our J K Spruce ORIS 7097 BLR2 (Spruce 2), the ozone season NOx rate is listed as 0.582 lb/mmbtu. That rate is actually too high for Spruce 2. Spruce 2 is our newest coal unit and was constructed with Low NOx burners, SOFA, and an SCR. Spruce 2 is a new unit and no emissions were reported for 2009, the first year that emissions will be reported will be for emissions year 2010. Our 12 month rolling permit limit is 0.05 lb/mmbtu, and we will operate the unit below our permit limits. [EPA-HQ-OAR-2009-0491-2524.1, p.2]
Response: 
See "Documentation Supplement for EPA Base Case v.4.10_FTransport-Updated for Final Transport Rule"  EPA made unit level updates to the units noted by commenter.
Organization: Georgia Department of Natural Resources, Air Protection Branch
Comment: 
Georgia Department of Natural Resources, Air Protection Branch
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.92.]
One area that we have begun to look very closely at and would like sufficient time to prepare our best justification for is why we believe that EPA should not include NOx controls outside of the ozone season in the southeast as part of this rule.
Response: 
Please see section V.A of the preamble for explanation of why EPA required annual NOx and SO2 reductions in all states linked for PM2.5 contribution to downwind states in the final Transport Rule.
Organization: Maryland Department of Environment (MDE)
Ozone Transport Commission (OTC)
Comment: 
Maryland Department of Environment (MDE)
Maryland agrees with OTC, which has been unable to determine exactly how EPA developed the ozone season NOx budgets. We request clarification on EPA's methodology. EPA's allocations do not match up with the process described in the preamble to the proposed rule. It appears that EPA applies three different methodologies in developing the state emission budgets for ozone season NOx. As a result, EPA provides three different values for the ozone season budgets for all 26 states in the proposed rule. In the Air Quality Modeling Technical Support Document, EPA cites an ozone season NOx budget of 585,584 tons as representing the remedy. At the same time, EPA used an ozone season NOx budget of 641,614 tons (page 75 FR 45296) before variability, and allocations of a budget of 610,454 tons to the states after netting out the 3 percent new source set-aside. (Note that the 610,454 tons allocation was calculated by summing the unit-level projected NOx ozone season mass, from the Transport Rule TSD "Budgets and Allocations  -  Detailed Unit-Level Data"). EPA explains that they used a combination of historical data and projected data to make adjustments to achieve the final allocated budget (75 FR 45290  -  45291) but the precise methodology for those adjustments is not provided. [EPA-HQ-OAR-2009-0491-2639.2, pp.11-12]
Ozone Transport Commission (OTC)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.115-116.]
The seasonal NOX budget for the identical states under EPAs proposed Transport Rule is 475,000 tons; the CAIR phase 2 NOX cap was 429,000 tons. EPA further exacerbates the situation by retaining the 2012 NOX cap in 2014, rather than ratcheting it down, as it did for the SO2 caps in the proposed rule. In a recent plant-by-plant analysis by OTC of potential future NOX caps, we determine that a 375,000 ton ozone season NOX cap by 2014 is technologically feasible and cost-effective based on an annual NOX cap of 900,000 tons in the eastern U.S.
Response: 
See Section VI of the Preamble for a comprehensive discussion of how EPA developed ozone season NOx budgets.  This section clarifies the step-by-step process for arriving at the final budgets.  Additionally, the "Significant Contribution and State Emissions Budgets for the Final Transport Rule Technical Support Document" provides a more detailed explanation on how the final state emissions budgets were determined.  EPA does include a separate 2014 ozone season cap budget in the final Transport Rule that is ratcheted down from 2012 levels for some states.  This is described in section VI.D.  In response to these comments, EPA also improved its budget formation process to improve its transparency and consistency with the air quality modeling.
Organization: New Jersey Department of Environmental Protection (NJDEP)
Comment: 
New Jersey Department of Environmental Protection (NJDEP)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.159-160.]
Two, perhaps most importantly, USEPAs proposal does not adequately address the daily nature of peak ozone. In order to states to attain and maintain the current 75 ppb and future ozone standards, it is necessary for the USEPA to additionally set short term (hourly to daily) performance standards that apply to each upwind source. New Jersey has adopted its own rules to address NOX and SO2 and particulate matter emissions on a 3 hour to daily basis. USEPA approved these RACT rules as a SIP revision on August 3, 2010. 75 Fed. Reg. 45483 (August 3, 2010) In an analysis NJDEP conducted for the northeast, it found that only a typical summer day in 2005, the NOX emissions were 551 tons per day, while on a high electric demand day, typically a hot summer day that corresponds with high ozone, the NOX emissions were 1,349 tons per day. Averaging emissions over the ozone season is insufficient to address high ozone days where the NOX emissions are almost three times the typical day. To properly address NOX emissions during high ozone days, the USEPA must adopt a rule with daily, or shorter time period, performance standards.
Response: 
See Section VI.D of the Preamble.
Organization: Texas Commission on Environmental Quality
Southern Company
Mississippi Department of Environmental Quality
North Carolina Department of Environment and Natural Resources
West Virginia Department of Environmental Protection
NRG Energy
Florida Electric Power Coordinating Group, Inc. (FCG)
Prairie State Generating Company, LLC
Entergy Services, Inc.
American Public Power Association (APPA)
Comment: 
American Public Power Association (APPA)
2. EPA requests comments on whether the ozone season should be longer than the five-month season used in the NOx SIP Call Rule, 63 Fed. Reg. 57356 (Oct 27, 2010), and CAIR (May 1 through September 30), perhaps to correspond to the ozone monitoring season for each state. 75 Fed. Reg. at 45292/1. If EPA expands the ozone season for some or all states, it would need to consider carefully how such an expansion would affect the proposed program, and at a minimum, would have to increase the NOx ozone season budgets in proportion to the extended season for affected states. Any such change should be addressed in a supplemental notice of proposed rulemaking. [EPA-HQ-OAR-2009-0491-2812.1, p.6]
Entergy Services, Inc.
Changing the Ozone Season Months   
Entergy does not support changing the Ozone Season Program dates from the current season of May  -  September to March  -  October as suggested in the proposed rule.  The Ozone season should remain consistent with the approach taken by the OTAG, the NOx SIP Call, and the CAIR. [EPA-HQ-OAR-2009-0491-2847.1, p.14]
Florida Electric Power Coordinating Group, Inc. (FCG)
The FCG supports EPA's approach of using/retaining the definition of the 'ozone season' as May through September.  [EPA-HQ-OAR-2009-0491-2658.1,p.12]
Mississippi Department of Environmental Quality
The proposed rule sets a five month Ozone Season Control Period of May through September but invites comments on making it longer, such as March through October. For Mississippi, a southern state, the proposed control period is sufficiently protective. We agree with the proposed control period of May 1 through September 30. [EPA-HQ-OAR-2009-0491-2634.1, p.2]
North Carolina Department of Environment and Natural Resources
As standards are lowered, the need for a longer ozone season should be reassessed. [EPA-HQ-OAR-2009-0491-2767.1, p. 7]
NRG Energy
Maintaining the current ozone season definition In the development of the Transport Rule, EPA presents the option of an expanded Ozone Season from May  -  October to a March  -  October period. Many state specific regulatory programs are based on the May  -  October definition for the Ozone Season. Historic state ambient air quality data identify very few, if any, exceedances of the ambient air ozone standards occur in March and/or April. The expansion of the regulatory Ozone Season would only add more compliance obligations to sources on a federal and state level without a significant air quality improvement. Therefore, NRG does not support an expansion of the Ozone Season budget. [EPA-HQ-OAR-2009-0491-2749.1, p. 4]
Prairie State Generating Company, LLC
12. LENGTH OF OZONE SEASON
The U.S. EPA requested comment on the proposed ozone control period, May 1 through September 30, rather than the program covering the entire ozone season that is April 1 through October 31, p. 45292. PSGC agrees that the proposed ozone control period of May 1 through September 30 is appropriate. Continuing with a control period covering these months provides continuity with the CAIR and addresses the peak period in most areas of the country. Where states have longer periods that require reductions, local controls should suffice. [EPA-HQ-OAR-2009-0491-2842.1, p.10]
Southern Company
XVI. Southern Company Supports Several of EPA's Decisions in the Proposed Transport Rule
As discussed throughout these comments, Southern Company has many concerns with the Proposed Transport Rule. However, we support several of EPA's decisions in the proposed rule including EPA's decision to retain the current ozone season. [EPA-HQ-OAR-2009-0491-2864.1, p. 52]
F. EPA's Decision to Retain the Current Ozone Season
Southern Company fully supports EPA's decision to retain the current ozone season (May 1 to September 30). EPA has consistently used this five month period to define the ozone season in prior interstate transport rulemakings - CAIR and the NOx SIP Call. Extending it would represent a significant break from this established approach and would call into question EPA's ozone season analyses underlying this rule, which are all based on a five month ozone season. An extension would therefore require EPA to revise its ozone season analyses and publish a supplemental proposal to address ozone transport. [EPA-HQ-OAR-2009-0491-2864.1, p. 54]
Texas Commission on Environmental Quality
Ozone Season Expansion
The EPA has not provided sufficient information for states to develop comments regarding its proposed consideration of expansion of the ozone season in the Transport Rule.  
The EPA has requested comments regarding whether the ozone season (May through September) should be extended in the proposed Transport Rule. However, the TCEQ cannot provide comment at this time, because the EPA has failed to provide sufficient information in the proposal, such as: the potential length of a proposed ozone season extension; how state budgets would be recalculated under an extended season; or how unit-level allocations would be recalculated under an extended season. The TCEQ requests additional information, with adequate notice and opportunity for comment, regarding a possible extended ozone season prior to inclusion in a finalized rule. [EPA-HQ-OAR-2009-0491-2857.2, p.9]
West Virginia Department of Environmental Protection
[[2790.1 p.7]]
EPA requested comment on whether the budgets for the final rule should be based on a longer ozone season, such as March through October. WVDAQ believes the current ozone season as defined under CAIR (May through September) is adequate for the final Transport Rule. However, EPA may reconsider the period of the ozone season for purposes of Transport Rule II and EPA's new secondary ozone standard.
Response: 
EPA is finalizing the same ozone season period as proposed (May 1 through September 30).  See additional discussion in Section VI.D of the Preamble.

IV.F. Approach to Power Sector Emissions Variability

Organization: Connecticut Department of Environmental Protection
Comment: 
Connecticut's electric distribution companies (EDCs) are required to develop an Integrated Resource Plan (IRP) through which adequate generation resources are identified and, if necessary, contractually secured to ensure the State of Connecticut will have sufficient electric generating capacity to meet its demand over a ten year planning horizon. In support of the IRP, the EDC's contractor ran an electric grid bid-stack model to better predict the future operation of EGUs in Connecticut. The IRP model shows that load following boilers (LFBs) in Connecticut are projected to continue to operate on High Electric Demand Days (HEDD). When Connecticut's LFBs operate on HEDD, daily NOx emissions increase by as much as 29 tons per day, which is a significant amount. [EPA-HQ-OAR-2009-0491-2780.1 p.9]
As currently proposed, EPA's framework for addressing significant contribution does not help states address the short-term (e.g., one-hour to 24-hour) public health effects of ozone, PM 2.5, NOx and SO2 exposures. It may, in fact, exacerbate this problem. Analyses indicate that, in the Northeast, NOx emissions are much higher, and in Connecticut can be as much as five times higher, on HEDD than during average summer days (see Table A-3):
[[Data Table Here]]
The proposed Transport Rule does not guarantee that a specific source that has a significant impact on a downwind area will control its emissions, and in such case those states will be in violation of Section 110(a)(2)(D) of the CAA. Therefore, any regulatory approach that sets standards, caps, or budgets that are based on annual or seasonal averaging will be insufficient to address peak ozone exposures that typically occur on HEDD. Consistent with Ozone Transport Commission (OTC) comments on the proposed Transport Rule, EPA should incorporate short term performance standards for electric generating units that apply to each upwind source. Furthermore, in order to address high electric demand days, performance standards should apply on a 24-hr basis. Such performance standards should be in addition to the proposed Transport Rule trading program and any subsequent trading program to ensure such emissions are addressed as required by North Carolina v. EPA. [EPA-HQ-OAR-2009-0491-2780.1 p.10]
Response: 
It is important to note that EPA's authority for this rule is limited to eliminating emissions from upwind states that "significantly contribute" to nonattainment or interfere with maintenance of the 1997 and 2006 fine particulate matter national ambient air quality standards (NAAQS) and the 1997 ozone NAAQS.  As described in section III and section VI.D of the preamble for the final Transport Rule, EPA believes that downwind states also have control responsibilities because, among other things, the Clean Air Act requires each state to adopt enforceable plans to attain and maintain air quality standards.  Indeed, states have put in place measures to reduce local emissions that contribute to nonattainment within their borders.  Section 110 (a)(2)(D)(i)(I) only requires the elimination of emissions that significantly contribute to nonattainment or interfere with maintenance of the NAAQS in other states; it does not shift to upwind states the responsibility for ensuring that all areas in other states attain the NAAQS.
Organization: Indiana Energy Association
Comment: 
Indiana Energy Association
c. To the extent that EPA continues to rely on limited baselines (one year of data) to establish budgets, the Indiana Utility Group generally supports the variability limits concept because it provides flexibility for compliance. [EPA-HQ-OAR-2009-0491-3711 p.5]
Response: 
EPA appreciates the commenters support.  See preamble section VI.E for more on variability limits. 

IV.F.1. General Comments on Variability Approach

Organization: Ameren Services Company
Oglethorpe Power
Comment: 
Ameren Services Company
Ameren also supports the concept of variability limits and the delay in implementation of these limits until 2014. However, EPA in the preamble has calculated 'maximum variability' among the covered states of 21% for NOx and 28% for S02. EPA should consider using these percentage rates instead of a flat 10% of a states budget along with the tonnage defaults. These rates are more supportable than the 10% rate EPA has chosen seemingly out of thin air. [EPA-HQ-OAR-2009-0491-2722.1, p.9]
Oglethorpe Power
IV. Variability
Oglethorpe Power believes that EPA should consider the basis for using a higher percentage than the 10% uniform variability chosen for the proposed Transport Rule. EPA's analysis for examining the effect of variability in upwind state emissions on air quality in downwind states - set forth in its TSD on Power Sector Variability 9 - does not appear to preclude a conclusion that a somewhat higher uniform percentage, such as 20% or greater, may be justified. In the Variability TSD, EPA's'worst case' variation (which assumes no more than the one year 10% variability in SO2 emissions in upwind states with the largest air quality impacts on downwind monitors) showed that the combined downwind air quality impacts were essentially negligible, and that the results of the worst case analysis indicated small resulting increases in air quality relative to other factors like weather. EPA should perform the analysis using higher variability limits, in the range of at least 20 to 30% of each state's budget, to see whether these analyses also indicate that the impact of upwind emissions variability on downwind air quality remains small. If so, then higher variability limits would appear justified. Higher variability levels would increase the potential of the program to produce efficient and cost-effective emission reductions in the Transport Rule regions, producing larger air quality benefits, likely at reduced costs to the rate-payers (which for Oglethorpe Power are its wholesale power EMC purchasers who, like it, provide power on a not-for-profit basis). [EPA-HQ-OAR-2009-0491-2732.1, pp.9-10]
Oglethorpe Power also supports EPA'sdecision not to apply variability limits in the first several years of the program, when state budgets are based on reductions EPA expects will occur with a 'high level of certainty.' 75 Fed. Reg. at 45306 col. l. Oglethorpe Power agrees and supports EPA's proposal that emissions from an owner's EGUsin excess of that owner's share of the state budget with the variability limit should not be a violation of the Transport Rule or the CAA. As EPA notes, the allowance surrender requirement (which is also supported, although we believe that the surrender ratio in this context should be less than 1-to-1) is significant and sufficient to ensure that Transport Rule state's emissions will not exceed its budget plus the variability limit. Oglethorpe Power also supports EPA'sproposal to define the ozone season as the 5-month period from May 1st to September 30th of each year, consistent with the approach taken by the Ozone Transport Assessment Group and by EPA in the NOx SIP Call and CAIR rulemakings.
 [EPA-HQ-OAR-2009-0491-2732.1, p.10]

9. TSD for the Transport Rule, 'Power Sector Variability,' U.S. EPA Office of Air and Radiation (July 2010) (the 'Variability TSD').
Response: 
As described in sections VI.E and VI.F of the preamble and in the Technical Support Document "Power Sector Variability Final Rule", based on historic data on variation in heat input, EPA is providing sufficient variability to accommodate the inherent fluctuations in emissions resulting from power sector operations.  Covered sources have operational and compliance flexibility in this rule, to the extent possible under EPA's authority and the court rulings.
As described in the "power sector variability final rule" TSD, EPA has done an assessment using the air quality assessment tool examining the air quality impacts of emissions from upwind states up to the variability limit, where it found the impacts are small.  As described in the preamble, this rule is focused on the removal of significant contribution and interference of maintenance resulting from the emissions of upwind states.
As seen in the "power sector variability final rule" TSD, EPA also assessed the air quality impacts of higher possible variability limits, again estimating the effects are small.  Preamble section VI.E and VI.F as well as the TSD also provide details about EPA's rationale that the basis of the variability limits is inherent variation in electric generation.  The air quality assessment confirms that the level selected is unlikely to compromise the air quality goals of the rule.
For the analysis with the final Transport Rule, in the Technical Support Document "Power Sector Variability Final Rule", EPA estimated the air quality impacts for variability limits up to 20%.  EPA finds that the air quality impacts are small, in all cases up to and including 20%.  However, it is the historically observed variation in state-level EGU emissions specifically tied to inherent power sector operation that inform EPA's determination of the appropriate variability limits in the final Transport Rule, in order to allow states to accommodate this year-to-year variability while achieving the required cost-effective emission reductions.
Section VII.A of the preamble to the final Transport Rule describes EPA's rationale for applying variability limits and assurance provisions beginning in 2012.
Organization: Arkansas Department of Environmental Quality
Comment: 
Arkansas Department of Environmental Quality
ADEQ supports the limited trading of allowances in order to ensure emission reductions happen where they are needed. ADEQ also understands the EPA's desire to allow for limited variability in emissions from affected sources due to market and other conditions. However, ADEQ is concerned that the wording in the Transport Rule is unclear. ADEQ would like further guidance in the final rule on how the variability provisions will affect attainment issues.  [EPA-HQ-OAR-2009-0491-2676.2 p.4]
Response: 
EPA assessed the potential downwind air quality impacts related specifically to year-to-year variability in upwind emissions under the Transport Rule program.  Please see this analysis in the Variability Final Rule TSD.
Organization: City of Dover, Delaware
Comment: 
City of Dover, Delaware
Central to the City's concerns with the Transport Rule is that EPA has not adequately accounted for the variability in emission levels that peaking units experience from year to year. [EPA-HQ-OAR-2009-0491-2636.1, p.1]
Response: 
Variability was analyzed on a state-by-state basis and variability limits are set for the state emissions, as a whole, in any single control period.  This variability takes into account variability in baseline emissions while ensuring that all necessary emission reductions occur in each upwind state as required by section 110(a)(2)(D)(i)(I).  EPA's variability analysis thus necessarily focuses on variability in state level emissions, not variability at the unit or facility level. See section VI.E of the preamble for more on variability limits and how they are applied.
Organization: Connecticut Department of Environmental Protection
Comment: 
CTDEP does not agree with EPA's proposed variability provisions, which are intended to cover a range of operational contingencies that may affect both electric reliability and resulting emissions of NOx and SO2. The concept of variability is critical to states like Connecticut that have very tight emission budgets coupled with a large percentage of electric generation capacity that is non-fossil based, but variability should not be applied to emissions that fluctuate based on changing electric demand due to weather. Variability provisions should be reserved for truly exceptional events such as natural disasters or the loss of significant generation resources that pose a threat to electric system reliability. In this event, states like Connecticut would require access to a substantially greater allowance pool than the proposed variability limits to ensure electric system reliability would not be compromised by a source's inability to access sufficient allowances to ensure lawful operation. Absent such access, electric load would likely shift to smaller higher emitting backup generators that are not subject to the Transport Rule. [EPA-HQ-OAR-2009-0491-2780.1 p.16]
By way of an example, in 1996, Millstone II and III nuclear powered EGUs were unexpectedly shut down by the Nuclear Regulatory Commission for an extended period of time (all of 1996 and 9 months in 1997). These shutdowns caused a serious capacity shortage in Connecticut. As a result, NOx emissions from all fossil-fuel generation capacity increased, and required emergency regulation by CTDEP to authorize the restart of previously retired EGUs as well as the use of emergency generators as a last line of reliability before voltage reductions and blackouts. If this scenario were to reoccur, approximately 25% of Connecticut's generation capacity would need to be replaced in short order (see Table A-5). [EPA-HQ-OAR-2009-0491-2780.1 p.16]
Connecticut has greatly improved both its generation fleet and transmission infrastructure since 1996- 97. Nearly 2,400 MW of clean new generating capacity is now operational and another 800 MW are expected to be available by the end of 2011. Additionally, the state has added approximately 350 MW of base-loaded distributed generation (see Table A-6). Regardless of these improvements and the fact that some displaced generation could be replaced by increasing power imports into Connecticut, internal transmission and distribution constraints would still require significant additional in-state generation in order to keep the lights on. [EPA-HQ-OAR-2009-0491-2780.1 p.17]
[[Data Table Here]]
During this same period Connecticut has only lost approximately 150 MW from the retirement of two older EGUs while seeing in state peak electric demand rise to 7367 MW up from 6030 MW in the 1996- 1997 timeframe.
Nonetheless, if Millstone II and III were to become unavailable today, CTDEP believes two scenarios highlight the range of impacts on Connecticut:
Scenario 1 All energy lost from nuclear shutdowns is replaced by new natural gas-fired combined cycle units with selective catalytic reduction:
o 2090 MW/h * 8760 hours/year * 0.95 capacity factor * 0.135 lbs/MWh/2000 lbs/ton = 1,174 additional tons per year NOx
Scenario 2 All energy lost from nuclear shutdowns is replaced by existing Connecticut load following boilers:
2090 MW/h * 8760 hours/year * 0.95 capacity factor * 1.5 lbs/MWh/2000 lbs/ton = 13,044 additional tons per year NOx
If Scenario 1 and 2 are bookends, the likely outcome in the event that electric capacity from Millstone II and III is lost for a year is that between 1,174 and 13,044 additional tons of NOx would be emitted. Using the average emission increase, this means that annual emissions of NOx in Connecticut would increase by 7,100 tons per year. EPA's proposed 1-year variability limit of 5,000 additional tons of NOx per year would be inadequate in this instance. [EPA-HQ-OAR-2009-0491-2780.1 p.18]
EPA should define an exceptional event as a natural disaster or mandated safety related shutdown that interrupts non-fossil based EGU operation for more than 30 days and requires the use of new EGUs or the increased use of existing EGUs to offset lost power generating capacity. EPA should establish a national set-aside allowance pool for exceptional events (e.g., 1-5% of the budgets) that EPA would administer and distribute only during an exceptional event. In order to determine the appropriate size of the set-aside, EPA should model the impact of exceptional, but reasonably foreseeable, events so as to establish a set aside of an appropriate size. [EPA-HQ-OAR-2009-0491-2780.1 p.19]
In the event that EPA chooses not to pursue CTDEP's initial recommendation and maintains the proposed variability provisions, CTDEP recommends that EPA adopt the proposed variability limits instead of the alternative variability limits set out in the proposed Transport Rule. However, EPA should recognize that this may jeopardize electric reliability in Connecticut should an exceptional event, such as the 1996-97 shutdown of Millstone Units II and III, occur again. [EPA-HQ-OAR-2009-0491-2780.1 p.19]
Response:
As described in sections VI.E and VI.F of the preamble to the final Transport Rule, and in the Technical Support Document "Power Sector Variability Final Rule", based on historic data on variation in heat input, EPA is providing sufficient variability to accommodate the inherent fluctuations in emissions resulting from power sector operations.  Covered sources have substantial operational and compliance flexibility in this rule due to the market-based structure of the air quality-assured trading programs.  
Organization: Edison Electric Institute (EEI)
Northeast States for Coordinated Air Use Management (NESCAUM)
Comment: 
Edison Electric Institute (EEI)
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.28.]
Apart from our concerns, EEI supports several aspects of the flexibility provisions EPA has proposed.
Northeast States for Coordinated Air Use Management (NESCAUM)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.9-10.]
We also support the concept of the variability provisions that limit interstate trading.
Response: 
EPA has finalized an assurance provisions approach similar to the one in the proposal, but with some small modifications and improvements.  See preamble section VII.E for more details on the final assurance provisions. 
Organization: Edison Mission Energy (EME)
Comment: 
Edison Mission Energy (EME)
The Proposed Rule's variability limits are too restrictive. EPA's proposed variability limits do not account for the emissions variability seen under real world conditions due to one-year anomalies (such as weather and unexpected unit outages) that are beyond the control of the power generation sector. [EPA-HQ-OAR-2009-0491-2707.1, p.3]
VI. EPA'S PROPOSED VARIABILITY LIMITS ARE TOO RESTRICTIVE
While EME agrees with EPA's proposal not to apply the variability limits during Phase I of the Transport Rule, EME has concerns that Phase II's variability limits are too restrictive.Under the current proposal, EPA establishes a one-year variability cap in all states equal to 10%of a state's emissions budget.71 Unfortunately, EME does not believe that a 10% cap is sufficient to cover all contingencies that might result in increased emissions in a given year. Based on its own experience, EME has observed circumstances where the EGUs in Illinois have approached the 10% limit under circumstances (e.g., weather and unit outages) that would not be considered anomalous. The fact that 10% has been approached under "normal conditions," suggests that a one-year 10% variability cap would not provide sufficient coverage to account for the range of like one-year anomalies. [EPA-HQ-OAR-2009-0491-2707.1, p.36]
For example, a significant percentage -- 48% of Illinois' generation capacity -- is provided by nuclear-power units.72 While these units are not typically down for extended periods, to the extent unexpected and prolonged outages occur (e.g., when unscheduled maintenance is required) fossil-fired generation would necessarily increase. Similarly, unusually hot summer weather and/or transmission line congestion can also result in unexpected increases in fossil-fire operations. Under the right circumstances these anomalies either individually or in aggregate could cause a given state to exceed a 10% variability limit. Since the common theme with respect to all of these anomalies is that they are, generally speaking, beyond either the State's or the individual EGU's control, penalizing individual sources within states for exceedences caused by such anomalies is unfair. Therefore, EPA should increase the one-year variability limit to ensure that it provides an adequate cushion to account for anomalies that are beyond a state's or a source's control. Based on this assessment, EME suggests that EPA increase the one-year variability limit to 15%, and that it use 10% to set the three-year variability limit. These adjustments will ensure that the Transport Rule's variability limits do not penalize sources for anomalies that they cannot control, but that nevertheless have the potential to result in emission increases that are material (at least relative to a 10% variability limit). [EPA-HQ-OAR-2009-0491-2707.1, pp.36-37]
Response: 
EPA has used a wider set of data from 2000 - 2010 for analyzing variability in the final rule. As explained in the preamble section VI.E, the resulting increased variability limit percentages provide sources with sufficient operational flexibility.
Organization: Environmental Defense Fund (EDF)
Comment: 
Environmental Defense Fund (EDF)
In addition, although EDF believes that the assurance provisions in the Proposed Rule in general provide ample confidence that individual states will eliminate their significant contributions to downwind nonattainment areas, for a few states in particular EPA's approach is unduly lax. In particular, the application of a uniform minimum variability limit (defined in tons) to all states, would allow far too much variability in small states. As EPA points out, a state like Connecticut would have a variability limit for SO2 equal to more than 55 percent of its emission budget  -- far greater than the maximum observed historical variability of 28 percent.17 EDF recommends that EPA follow the alternative approach of applying a maximum percentage of variability among covered states based on historical data  --  in this case, 21 and 28 percent of a state's budget for NOx and SO2, respectively. [EPA-HQ-OAR-2009-0491-2834.1 p.7]
In addition, although EDF believes that the assurance provisions in the Proposed Rule in general provide ample confidence that individual states will eliminate their significant contributions to downwind nonattainment areas, for a few states in particular EPA's approach is unduly lax. In particular, the application of a uniform minimum variability limit (defined in tons) to all states, would allow far too much variability in small states. As EPA points out, a state like Connecticut would have a variability limit for SO2 equal to more than 55 percent of its emission budget  -- far greater than the maximum observed historical variability of 28 percent.17 EDF recommends that EPA follow the alternative approach of applying a maximum percentage of variability among covered states based on historical data  --  in this case, 21 and 28 percent of a state's budget for NOx and SO2, respectively. [EPA-HQ-OAR-2009-0491-2834.1 p.7]
Response: 
EPA has modified the approach to variability limits in the final Transport Rule to align variability limits with historic heat input variability between  2000 - 2010 for all covered states.  In addition, Connecticut, Delaware, and DC are no longer in the Transport Rule region. For more on variability limits, see section VI.E of the preamble.
Organization: EquiPower Resources Corp.
Comment: 
EquiPower Resources Corp.
The Transport Rule's Variability And Assurance Provisions Are Flawed [EPA-HQ-OAR-2009-0491-2704.1, p.26]
The mechanism selected by the Transport Rule to provide assurance that upwind sources do not contribute to downwind nonattainment is to impose hard caps on statewide emissions. In recognition of the fact that some variability is inevitable, EPA created variability caps that allow the emissions cap to be exceeded in individual years so long as 1-year, and ultimately 3-year, variability limits are not exceeded. EPA argues that these variability limits provide flexibility by allowing one-time exceedances of a state's cap, and account for situations (e.g., weather) that might spike emissions in one year relative to another. EquiPower believes that EPA's approach is fundamentally flawed for four reasons. [EPA-HQ-OAR-2009-0491-2704.1, p.26]
First, EPA's proposed look-back reconciliation to determine whether a state cap plus variability limit has been exceeded is impracticable. In the later Phases of the Transport Rule, when states are subject to 3-year variability limits, EPA could potentially be looking back at data and imposing penalties on sources for emission exceedances the occurred several years earlier. This possibility makes it impossible for EGUs to manage their business with any sort of certainty, because they will never be certain that they will not be subject to a penalty in the future for past acts. [EPA-HQ-OAR-2009-0491-2704.1, p.26]
Second, as explained in Section III.B, this uncertainty will create an environment that encourages EGUs to retain allowances as opposed to trading them because sources will want to have allowances in reserve in case they are unexpectedly penalized. Allowance retention will deplete the supply of allowances available for trade, effectively eliminating any potential for an emissions market to be created. [EPA-HQ-OAR-2009-0491-2704.1, pp.26-27]
Third, these provisions are particularly unfair to natural gas units that did not receive any SO2 allowance allocations, even though they are presumed by EPA to have SO2 emissions. For example, if a state's emissions exceed its budget plus variability factor for SO2, then units who exceed their SO2 allocations would have to pay a penalty based on their proportional share of the SO2 exceedance. By not receiving any SO2 allowances, but being presumed to have SO2 emissions, natural gas units will always shave to pay a penalty for their full proportional share. This penalty will be particularly punitive because the Transport Rule will not create a robust emissions allowance market. So natural gas units will be forced to locate SO2 allowances for sale  -  no matter what the price  -  to pay a penalty that is entirely the result of EPA's unfair allocation methodology. [EPA-HQ-OAR-2009-0491-2704.1, p.27]
Finally, as explained in Section III.C above, EquiPower believes that there is an alternative to this approach that does not require the imposition of a rigid state cap or inflexible variability limits that effectively penalizes sources retroactively for actions that, at least in part, are out of an individual unit's control. The existence of an alternative approach that addresses the Court's concerns in North Carolina v. EPA while still allowing a robust emissions market renders EPA's approach unnecessary, rigid and punitive. EPA should revisit its approach in any Final Rule. [EPA-HQ-OAR-2009-0491-2704.1, p.27]
Response: 
For the final rule, only 1-year variability limits have been implemented for reasons provided in section VI.E of the preamble and the Power Sector Variability Final Rule TSD.  There are no 3-year variability limits in the final rule.  In addition, the allocation approach in the final rule has been modified and is now based on historic heat input.  See preamble section VII.D for more information on allowance allocations.  The final rule implements FIPs for all covered states and uses an approach to assurance provisions allows for air quality assured trading that gives sources compliance flexibility while at the same time meeting the requirements of CAA section 110(a)(2)(D).
Organization: First Energy
Comment: 
First Energy
State Variability Plan
FE does not believe the variability process should be included in the CATR rule. If the EPA truly expects to foster a competitive market and clone the success of the Acid Rain Program, placing a penalty stipulation on utilities because of an increase in plant generation would be counterproductive. [EPA-HQ-OAR-2009-0491-2657.1,p.12]
FE understands the EPA's concern that excessive interstate trading between states could contribute to ambient air quality concerns. One recommended solution would be to allow states within a regional area, similar to the size of Texas, to have unlimited trading. Limiting trading as strictly as EPA has proposed will significantly drive up the costs of the program and penalize companies like FE that have multi-state operations. [EPA-HQ-OAR-2009-0491-2657.1,p.12]
Response: 
The final variability limits are designed to give sources the operational flexibility they need, while comporting with the court's decision in North Carolina.  See preamble section VI.E for more on variability limits.
Organization: George Washington University Regulatory Study Center
Comment: 
There is good reason to believe that there is substantial uncertainty in the modeling estimates. 42 First, there is variability with EPA's projections of 2012 base case emissions projections. For example, EPA specifically recognizes variability in power sector emissions in developing state budgets as a part of this proposal and presents a calculation of that variability based on the standard deviation for state-level heat input over a 7 year period. EPA should incorporate information on emission variability from the power sector in an analysis of the uncertainty in its significant contribution approach. [EPA-HQ-OAR-2009-0491-2573.1, p.21]

 42 Throughout this discussion, the term "uncertainty" refers to both "variability" that reflects the statistical variation in estimates as well as to the uncertainty associated with a more fundamental lack of knowledge. Variability comes from the fact that there is variation within a population in terms of differences in exposure and in susceptibility. Variability cannot be reduced, but it can be better characterized with better data. Uncertainty results from a lack of knowledge about key elements or processes in the risk assessment. It can be represented by quantitative analysis -- and can be reduced with additional research -- but cannot be eliminated. One element of uncertainty is that which exists about the variability of a population estimate -- and thus the analyst often cannot be precise about the extent of variability. (For a more complete discussion, see NRC 2009a, 93-99.)
Response:

As described in the "power sector variability final rule" TSD, EPA has done an assessment using the air quality assessment tool examining the air quality impacts of emissions from upwind states up to the variability limit, where it found the impacts are small.  As described in the preamble, this rule is focused on the removal of significant contribution and interference of maintenance resulting from the emissions of upwind states.
Organization: Indiana Department of Environmental Management 
Comment: 
Indiana Department of Environmental Management 
The variability allowances proposed will help mitigate this situation and are important to the rule; however, a mechanism should be developed to provide some relief to affected sources that cannot meet these timeframes, despite their best efforts to do so. There are sources covered by consent decrees and other actions that have dates for installing controls beyond 2014 and many of these sources have planned accordingly. Perhaps an alternate five year variability allowance could accommodate these circumstances. [EPA-HQ-OAR-2009-0491-2645.1, p.2]
Response: 
Variability limits and assurance provisions are determined at the state level, not the individual unit or source level.  Sources that need more allowances to cover their emissions may use trading as a compliance mechanism.
Organization: Indiana Energy Association
City of Ames, Iowa
Comment: 
City of Ames, Iowa
7) The assumptions and analysis used by U.S. EPA to calculate 'power sector variability' falls way short of addressing the variability experienced here at the City of Ames, especially due to the impact of the current economic recession which started in the 1st quarter of 2008 and became severe by the 3rd quarter of 2008. This is in spite of the fact that Ames, Iowa is economically fairly healthy as compared to many other locations. We are fortunate to be a city with a major university, plus the headquarters for significant state and federal departments. [EPA-HQ-OAR-2009-0491-2769, p.2]
However, as you can see from the data in the table below, the current recession has had a dramatic and highly variable affect upon the electric utility of the City of Ames. For the period 2000 through 2007, the average annual growth in sales (in kilowatt-hours) was 3.58%, yet for 2008 and 2009, sales of electricity fell off trend 5.62 and 12.73 percent, respectively. For the same period, local generation was off dramatically, down 5.73% for 2008 and down 31.33% for 2009. This was due to the combination of reduced native load (kilowatt-hour sales), and the significant reduction in the average price of purchased power due to the supply-demand softness of the economy. As the third row in the table below shows, the City of Ames significantly increased its use of purchased power in 2009. During this period, 2008 and 2009 (and continuing presently), utilities with larger and multiple power plant resources had base load capacity to sell at base load pricing, as compared to the more historically normal purchased power pricing based upon cycling and peaking type units typically burning more expensive natural gas. As an example, the average price we paid for purchased power in 2008 was $53.65/megawatt-hour (mwh), however, in 2009 the power market had softened so much due to the recession that the average price for purchased power had dropped to $29.74/mwh. Another important factor contributing to the reduced electricity sales and the reduced prices for purchased power in 2009, was the very mild (cool) summer which significantly reduced the need for air conditioning in the upper Midwest, and certainly in Iowa. [EPA-HQ-OAR-2009-0491-2769, p.3]
[The table can be found on page 3 of this comment.]
As the economy recovers, we would expect that the supply and demand relationship for electricity to tighten, resulting in an increase in the price and the availability of power on the market, ultimately reducing the attractiveness of purchased power, thereby increasing the demand for electricity required of native generation. [EPA-HQ-OAR-2009-0491-2769, p.3]
Indiana Energy Association
h. The proposed energy variability limits are another issue of concern. The Indiana Utility Group believes that the proposed limits are insufficient to account for recent economic conditions and the potential need for significant additional generating capacity during the anticipated recovery. [EPA-HQ-OAR-2009-0491-3711 p.5]
Response: 
The assessment of variability was made at the state level on an annual basis.  This assessment incorporated substantial unit-to-unit and day-to-day variation in generation in the annual sum of heat input for each state. 
As described in preamble section VI.E and the "power sector variability final rule" TSD, heat input data from 2000 through 2010 were used in the assessment of inherent variability in power sector operation, thereby accounting for the long-run impacts of the business cycle (economic contractions and expansions) in the year-to-year variability of state-level EGU emissions.  EPA's power sector modeling, which provided the basis for establishing the Transport Rule emission budgets in each state, includes an electricity demand forecast that takes into account the expected trajectory of economic growth as modeled by the Energy Information Administration.  Therefore, the commenter's concerns about the near-term evolution of electricity demand (and the impact that has on EGU emissions) are already accommodated in the development of the Transport Rule state budgets.
Organization: JEA
Comment: 
JEA
JEA does not object to this general approach. However, JEA recognizes that variability limits inherently constrain cost-effective use of banking and trading, and could also have adverse impacts on reliability if not carefully designed - both key policy considerations for public power customers. Accordingly, JEA believes that the variability limits should be as flexible, generous, and straightforward as possible while remaining consistent with North Carolina. EPA's decision to establish two independent variability limits - an annual '1-year' limit and a '3-year' limit which restricts the average use of allowances over a rolling three-year period - fails these criteria. In particular, the 3-year limit will be impracticable, costly, and unnecessary. [EPA-HQ-OAR-2009-0491-2713.1, p.4]
Response: 
EPA is finalizing one-year variability limits only for the Transport Rule.  See preamble section VI.E in the final Transport Rule for more information about variability limits.
Organization: Lansing Board of Water & Light
Comment: 
Lansing Board of Water & Light
The entire concept of "variability limits" is unnecessarily complicated. If EPA is willing to allow a state to exceed a budget without penalty because the exceedances is not great enough to negatively impact a downwind area, then the budget should simply be raised. The artificial cap of the variability limit overly complicates the entire program. If a state is allowed to exceed its budget by up-to 10 percent, then the states budget should simply be raised by 10 percent and the concept of variability should be dropped. [EPA-HQ-OAR-2009-0491-2752.1, p.8]
Response: 
The variability limits, as explained in section VI.E of the preamble, are to acknowledge and allow for the inherent fluctuations in the power sector on a yearly basis.  They are not meant to be considered as part of the state budget, which is equal to the number of allowances allocated each year.  Increasing the state budgets would permanently decrease the stringency of the programs and therefore fail to achieve the cost-effective reductions identified as necessary to eliminate significant contribution to nonattainment and interference with maintenance in this rulemaking.  The variability limits maintain the stringency of the program (because they do not alter the total number of allowances issued under the programs, and thus the total emissions allowed) while accommodating the inherent year-to-year variability in state-level EGU emissions.   EPA believes that providing for a limited amount of variability offers flexibility and maintains reliability while meeting the agency's responsibilities under the CAA.
Organization: Large Public Power Council (LPPC)
Comment: 
Large Public Power Council (LPPC)
LPPC appreciates EPA's recognition that power sector emissions change from year to year because of factors including power demand, timing of maintenance activities, unexpected shutdown of units, extreme weather conditions, economic shocks, and other unpredictable events  -  and that EPA recognizes that proposed state budgets are based on average years or conditions. LPPC does not object to the general approach proposed by EPA to constrain total actual emissions from EGUs within states by means of variability limits. However, LPPC recognizes that variability limits inherently constrain cost-effective use of banking and trading, and could also have adverse impacts on reliability if not carefully designed  -  both key policy considerations four public power customers. Accordingly, LPPC believes that the variability limits should be as flexible, generous, and straightforward as possible while remaining consistent with North Carolina. EPA's decision to establish two independent variability limits  -  an annual "1-year" limit and a "3-year" limit which restricts the average use of allowances over a rolling three-year period  -  fails these criteria. In particular, the 3-year limit will be impracticable, costly, and unnecessary. [EPA-HQ-OAR-2009-0491-2667.1, p.11]
Response: 
EPA has used a wider set of data from 2000 - 2010 for analyzing variability in the final rule. As explained in the preamble section VI.E, the resulting increased variability limit percentages provide sources with sufficient operational flexibility.  In addition, the final rule only establishes 1-year variability limits.  There are no 3-year variability limits in the final rule for reasons explained in the preamble and Power Sector Variability Limits Final Rule TSD.
Organization: Maryland Department of Environment (MDE)
Comment: 
First, it does not appear that, in developing the variability concept, EPA considered which states export and which states import electricity and how that can affect emissions within groups of states such as when a large EGU shuts down. Likewise, EPA did not seem to take into account to degree to which a given state even needs the extra allowances provided by variability. Secondly, factors such as extended episodes of high temperature often affect large geographic areas and exacerbate ozone formation. While these emission surges may balance out over time, the actual extra emissions are likely to occur at the worst possible times, such as on hot, humid days that already have poor air quality. EPA claims that these assurances are not threatened because limited allowances will maintain the established emissions levels. However, this interpretation dismisses the fact that sources can have significant carryover allowances from year to year and in a short timeframe can accumulate enough allowances to increase overall emissions in any given year. As stated previously, Maryland believes that the NOx budgets are too lenient already and that the variability concept as proposed would not provide the necessary assurances that the current proposed NOx budgets would be met at even a minimum allowable level.  [EPA-HQ-OAR-2009-0491-2639.2, p.13; This comment can also be found at IV.F.2. of this comment summary]
Response:

See section IV.F.2 of the RTC for the response to this comment.
Organization: Morgan Stanly Capital Group
Comment: 
Morgan Stanly Capital Group
2. Variability Limit Set-Aside for Peaking Plants
As now designed, the Proposed Rule would not allow peaking plants much, if any, portion of a state's variability limits.20 Consequently, peaking plants will have to purchase all of the emissions allowances that they need to operate and still may violate the Proposed Rule if the state has exceeded its budgeted emissions and variability limit.21 As a practical matter, such plants would probably have to price their services on a "worst case" basis, under the assumption that they would incur very high costs to procure allowances  -  perhaps double allowances  -  if they run, and might also pay penalties. [EPA-HQ-OAR-2009-0491-2819.1 p.6]
The Administrator should consider a special set-aside of the relevant variability limit to ensure that peaking plant emissions are compliant with the limit. This in turn may mean that such plants receive more than their proportionate share of the state's variability limits. An alternative or supplemental provision could extend the extremely tight deadline for attaining compliance with the Proposed Rule, since these emission sources may have to find allowances in order to operate and may need additional operating experience after the Proposed Rule has become effective in order to achieve compliant operation. [EPA-HQ-OAR-2009-0491-2819.1 p.6]
Response: 
For the reasons explained above, variability limits are set at the state level, not the individual unit level, which accounts for and provides sufficient operational flexibility for all sources.  See preamble section VII.E for more information about assurance provisions and penalties. 
Organization: National Association of Clean of Air Agencies (NACAA)
Comment: 
EPA says it is including a variability factor to account for unplanned increased emissions in a state due to situations such as extreme weather events, unplanned outages or unexpected load demands because of an unusually hot summer. 9 We understand the need to account for variability in output due to unforeseen circumstances. We strongly suggest that EPA consider a different mechanism that accounts for variability in weather and possible unplanned outages of power plant units but that also preserves the environmental integrity of the Transport Rule. EPA should set aside an emergency reserve of allowances each year that can be used by plants that have to ramp up production because other plants out of state have experienced outages or that have to ramp up unexpectedly due to extreme weather events. These reserve allowances should be deducted proportionally from each state's budgets so that the overall caps remain intact. This approach still permits interstate trading  -  as long as purchases by in-state sources of out-of-state allowances matches out-of-state purchases of instate allowances. If there is an imbalance because of an unplanned outage or weather emergency, the emergency reserve of allowances is available to make up the difference in case of emergencies. This ensures the integrity of the cap while also accounting for variability. [EPA-HQ-OAR-2009-0491-2771.1, p.5]

Footnote:
9 In the case of an unusually hot summer, we note that these are precisely the circumstances where emissions reductions are needed the most, since increased temperatures can lead to higher ozone levels.
Response:
Thank you for your comments.  EPA notes that "the overall caps remain intact" already under the Transport Rule as finalized, because EPA will not issue any allowances beyond the state budgets.  The variability limits allow EPA to accommodate the inherent year-to-year variability in EGU emissions at the state level without reducing the stringency of the program's required cost-effective upwind emission reductions.
Organization: New York State Department of Environmental Conservation
Comment: 
Basis of Emission Budgets I Variability
State emissions budgets should reflect the emission reductions necessary to prevent SC/IM using the maximum design value rather than an average value based on a three-year period. This is the only way to assure that during any given year, a NAAQS violation will not occur due to transport. Also, emission budgets should reflect levels needed to eliminate SC/IM and not 'cost effective' controls in a given state, and must be designed to prohibit emissions that cause SC/IM. Any variability limit should be applied in a manner such that emissions causing SC/IM are prohibited, or at least mitigated. That is, the sum of a state's budget and the variability limit should be equal to or less than the emission reductions necessary to avoid SC/IM or EPA's trading program mitigation measures need to be applied once the budget is exceeded. Still, any variability limit that EPA might establish should start at the beginning of the program (for this case, 2012). [EPA-HQ-OAR-2009-0491-2730.1, p.7; This comment can also be found at section IV.E of this comment summary]
Allowing an additional variable emission quantity over and above the state budget that is needed to achieve SC/IM may result in non-compliance with a NAAQS. For example, it is likely that plants in one state may have a higher than average cost of controls than the costs of another state due to higher costs of living or smaller power plants which generally have higher control costs than another state. It would be reasonable to expect that plants in the latter state would control more to offset their costs and sell allowances in the former. Without some mechanism to keep emissions in a particular state to a level at or below the budgets established to eliminate SC/IM, there can be no assurance that the transported emissions that significantly contribute to nonattainment or interfere with maintenance are eliminated. Another shortcoming is that the year to year variability treatment does not take into account that air pollution is generally episodic in nature. Higher emissions are more likely when the potential for ozone and PM2.5 formation is greatest. [EPA-HQ-OAR-2009-0491-2730.1, p.7; This comment can also be found at section IV.E of this comment summary]
CAMx Modeling of Emission Variability
EPA has failed to examine air quality impacts arising from the variability in emissions which is assumed to be up to 10%. This variability is associated with year-to-year variability in meteorology to a major extent, since it is often assumed that there are no major or significant changes in anthropogenic activities during these years, unless there are regulatory requirements affecting changes in emissions. [EPA-HQ-OAR-2009-0491-2730.1, p.12]
Response:
Thank you for your comments.
Organization: New York University School of Law, Institute for Policy Integrity
Comment: 
New York University School of Law, Institute for Policy Integrity
:: The relationship between significant contribution and variability limits should be clarified; [EPA-HQ-OAR-2009-0491-2691.1, p.1]
3. Clarification of the Relationship Between Significant Contribution and Variability
EPA should clarify precisely what is meant by "significant contribution." It is unclear in EPA's preferred approach whether "significant contribution" encapsulates solely the state emissions budget, or whether it also includes variability limits. If it includes only the budget, then it appears that when a state emits more than the budget but still within the variability range, the state would exceed its significant contribution in violation of the statute. However, if EPA defines significant contribution to include the variability limit in addition to the budget, then it is unclear how EPA is authorized to mandate a budget that is lower than the state's significant contribution. [EPA-HQ-OAR-2009-0491-2691.1, p.11]
From the lengthy discussion of power sector variability, it appears as though EPA intends for significant contribution to vary in response to the inherent variability of the power sector. If so, it is appropriate for EPA to allocate state budgets that include such variability limits. Yet EPA must be clear about the relationship between a state's significant contribution and the state's budget and variability. Such an explanation is necessary to accurately evaluate whether EPA's preferred approach would satisfy the D.C. Circuit's interpretation of the section 110(a)(2)(D) mandate. [EPA-HQ-OAR-2009-0491-2691.1, p.11]
Response:
Thank you for your comments.
Organization: North Carolina Department of Environment and Natural Resources
Comment: 
EPA's decision to propose State budgets calculated on a state-by-state basis and to limit emissions to those budgets is a supported approach. Further, NCDAQ agrees in principle with EPA's attempts to address utility sector variability by allowing limited interstate trading. However, NCDAQ has concerns with the means EPA has chosen. Under EPA's proposed remedy, State X's relevant emissions may have been relatively low during the base year and State Y's may have been high. Theoretically, EPA's variability approach would allow for sources in State X to buy allowances from sources in State Y during a normal year in order to balance this variability. This presents two conceptual problems. First, it punishes sources in State X and provides a windfall for sources in State Y based solely on the variability of electricity production during the single year EPA chose as the base year (2005). That is, had EPA chosen 2006 instead of 2005 as the base year, sources in State X may have profited at the expense of sources in State Y instead of the other way around.
Second, and more significantly from an air quality perspective, sources in State Y could very well emit up to the maximum of their variability allowance for evcry one-year and three-year period, despite the fact that sources in State Y were already at the high end of their variability in the base year. Put another way, although the variability limits may have been calculated in a defensible manner - these Comments take no position on that technical issue - oncc the limits are allowed there is no legal assurance that the variability margins will be used by market participants to account for variability. The variability limits are simply a trading budget overage margin and are forever unmoored from their intended purpose. As such, the variability limits, although stemming from a defensible theory, are themselves not consistent with the Clean Air Act.
NCDAQ submits that if EPA is not able to resolve these issues with the variability limits, then interstate trading - as considered in the 'proposed remedy option' - cannot be permitted. Instead, NCDAQ would propose the 'first alternative remedy option' (option I throughout). It provides some flexibility while ensuring that a substantial portion of a state's assigned emissions reductions occur in that state. Option I most closely aligns with the CSA with respect to trading among only intrastate sources. Our experience with this type of approach shows that it is a feasible option. The CSA program has successfully reduced NOx and S02 emissions with minimal agency oversight. We do not support the 'second alternative remedy option' (option 2 throughout) and have concerns with its prescribed limits and feel that this offers sources little incentive to be more energy efficient and limits flexibility. [EPA-HQ-OAR-2009-0491-2767.1 p.2-3]
In the preamble, EPA states: 'If the state emissions exceeded both the state budget with the I-year and with the 3-year variability limit, then the 3-year variability limit would be used in determining the owner's share of the state budget.' 75 Fed. Reg. at 45,313/2. However, the proposed rules provide that 'the amount by which' the State's emissions during any control period 'exceeds the State assurance level shall be the greater of the amounts of the exceedance calculated under paragraph[s]' requiring calculation of the State's one-year and three-year exceedances. E.g., 75 Fed. Reg. at 45,374/2 (proposing §97.406(c) (2) (iii) (C>>. The relationship between these two statements is unclear, as is the manner in which EPA will treat emissions should a State's sources exceed both the one- and three-year assurance levels. NCDAQ requests clarification on this issue in the final rule and suggests assurance provisions be based on the maximum exceedance. [EPA-HQ-OAR-2009-0491-2767.1 p.3]
Response:
First, the budgets are developed based directly on IPM emission estimates for 2012 and 2014, based on the availability of emission reductions at or below specific cost thresholds under modeled average conditions; these cost thresholds are applied equivalently to all states within a particular Transport Rule program (see section VI.B of the preamble to the final Transport Rule).  Therefore, the Transport Rule budgets for each state within a common Transport Rule program are based on that state's emissions under the same cost-effective threshold for that pollutant; there is no "bias" among states in this programmatic structure, so the commenter's concerns about "windfalls" are unfounded.  The commenter is also mistaken in that 2005 "base year" emission inventories were not relevant to EPA's IPM power sector modeling projections of 2012 and 2014 EGU emissions that formed the basis for establishing Transport Rule state budgets at the appropriate cost thresholds (as described in section VI.D of the preamble).
Second, to implement the statutory mandate of section 110(a)(2)(D)(i)(I) EPA must ensure that this rule prohibits all emissions within a state that it has identified as significantly contributing to nonattainment or interfering with maintenance of the relevant NAAQS in other states.  The assurance provisions in the final rule provide assurance that the necessary reductions will occur, as required by statute, within each covered state.  As described in sections VI.E and VI.F of the preamble and in the Technical Support Document "Power Sector Variability Final Rule" the assurance provisions also provide variability to accommodate the inherent fluctuations in emissions resulting from power sector operations. For the analysis with the final Transport Rule, in the Technical Support Document "Power Sector Variability Final Rule", EPA estimated the air quality impacts for variability limits up to 20%.  EPA finds that the air quality impacts are small, in all cases up to and including 20%.  However, it is the variation in emissions resulting from inherent power sector operation that define the limits.
Since no additional allowances are allocated to cover the variability provisions, and since purchase of additional allowance includes a cost disincentive, and based, in part, on EPA's modeling of the remedy, EPA only anticipates that emissions will increase to up to the assurance  levels when the variability is needed.  EPA disagrees with the commenters assertion that utilities will operate as if the budgets themselves have been increased; sources cannot universally increase emissions because EPA will not issue more allowances than the sum of the state budgets; at the outset of the programs, any utilization of a variability limit in one state necessarily requires that sources reduce emissions below the budget in another state.  Rather, with the significant additional allowance surrender requirements for sources within a state that exceed the assurance level, and additional cost burden of purchasing additional allowances, it is not likely that sources will risk approaching the assurance level.  Furthermore, EPA's modeling of the Transport Rule suggests that additional pollution control hardware will be installed; thus, it is likely that emissions will be lower under nearly all circumstances, including during the extended episodes of high temperature leading to increased electric demand.
Organization: Ozone Transport Commission (OTC)
Comment: 	
Ozone Transport Commission (OTC)
[[2737.1 p.15]]
We urge EPA to strengthen the integrity of the intrastate trading program by including the variability component of the budget within, rather than on top of, the proposed emission budgets.
Response: 
Thank you for your comments.
Organization: Prairie State Generating Company, LLC
Comment: 
Prairie State Generating Company, LLC
8. VARIABILITY'S IN GENERATION CAPABILITIES AMONG THE STATES
The U.S. EPA's proposed state caps do not reflect the variabilities in generation capabilities among the states. Illinois has more nuclear generation than any other state. Nuclear generation is recognized as 'clean' generation, in that there are no emissions associated with nuclear generation. Nuclear generation provides base-load electricity for millions of users. However, there are times when Illinois' nuclear units are shut down for various reasons. That generation capacity must be made up. Because Illinois is a net exporter of electricity, it would likely be made up through increased fossil-fueled generation for the duration of the nuclear outage. [EPA-HQ-OAR-2009-0491-2842.1, p.7]
Although Illinois is also home to hundreds of acres of windmills, windmills cannot provide sufficient base-load generation to reliably make up for nuclear generation during outages or to replace base-load coal-fired generation. [EPA-HQ-OAR-2009-0491-2842.1, p.7]
Illinois' variability limit should be increased to account for this disparate amount of nuclear generation and the potential for increased fossil-fueled generation during outages at the nuclear units, at least during periods when any of the Illinois reactors are off-line for either planned or forced outages. [EPA-HQ-OAR-2009-0491-2842.1, p.7]
Response: 
EPA has used a wider set of data from 2000 - 2010 for analyzing variability in the final rule. As explained in the preamble section VI.E, the resulting increased variability limit percentages provide states and their sources with sufficient operational flexibility.
Organization: Progress Energy Service Company
Comment: 
Progress Energy Service Company
Progress Energy recommends that EPA increase the variability limit threshold of 10 percent of each state's budget to a higher threshold, such as 20 percent of each state's budget. This level provides additional flexibility while assuring that interstate trading will be limited in order to satisfy the court's decision. [EPA-HQ-OAR-2009-0491-2831.1 p.8]
Response: 
EPA believes that variability limits in the final rule are adequate to meet the states' operational needs. See preamble section VI.E for more details about variability limits.
Organization: Southern Company
Comment: 
V. EPA Should Assess the Air Quality Effects of a Less Restrictive Form of Interstate Trading
As EPA revises the rule and considers a compliance deadline no earlier than 2015, it should also assess the effect of a less restrictive form of interstate trading such as a higher than 10% variability limit as well as trading among group 1 and 2 states. Inherent in the examples in Section IV above comparing the CAIR and the Transport Rule remedies is the assumption that each state achieves the emissions reductions specified (i.e., no interstate trading). However, as shown above, while the overall emissions reductions are very similar across the Transport Rule affected states, the state-by-state differences in emissions between the two scenarios are highly variable, and yet they produce very similar results in terms of remaining nonattainment/maintenance monitors. These results, along with EPA's assessment of the effect of the 10% variability limit, are indicative of the fact that some level of interstate trading can be supported; possibly even unlimited trading (See Table IV-3 above). [See EPA-HQ-OAR-2009-0491-2864.1, p. 11 for Table IV-3] [EPA-HQ-OAR-2009-0491-2864.1, p. 12]
In reviewing EPA's variability analysis, we think the approach to variability (using HI from 2002-2008) is somewhat reasonable although not necessarily straightforward. While there are issues with how the EPA determined that 10% (or a tonnage in some cases) was a reasonable variability limit, EPA did evaluate the effect of emitting 10% above the cap on air quality. EPA evaluated two approaches to estimate the variation in downwind air quality at each monitor for daily PM2.5 allowed under the Transport Rule in 2014 due to the inherent variability in S02 emissions. The first approach examined the I-year variability effects on daily PM2.5 concentration when variations in emissions from different states are independent from each other. This is intended to represent 'typical' random variations in emissions and the resulting typical variations in air quality that might be seen under the Transport Rule. The second approach examined the 'worst' case I-year scenario for each monitor, when the upwind states with the largest impacts per ton emit at the upper end of the variability limit, while upwind states with the lowest impacts per ton emit below their budgets. This is intended to estimate an upper bound for the effects of emissions variability on air quality. [EPA-HQ-OAR-2009-0491-2864.1, p. 12]
EPA made the following conclusions about both approaches: [See TSD, pp, 44, 46, and 47 for EPA's conclusions.]
'For both approaches, the effects of the inherent variation III emissions on daily PM2.5 concentrations were estimated to be small.'  [EPA-HQ-OAR-2009-0491-2864.1, p. 12]
EPA's conclusion about Approach #1: 'In conclusion, we found that, even while allowing each state's emissions to randomly vary up to 10% of its budget (the 2-tailed 95% confidence variability level prescribed or many states in the Transport Rule), the combined downwind air quality impacts were essentially negligible.' [EPA-HQ-OAR-2009-0491-2864.1, p. 12]
EPA's conclusion about Approach #2: 'These results suggest that even under a 'worst case' scenario, where nearby states minimize reductions in emissions, while states far away maximize reduction, the resulting increases in air quality are small relative to other factors (i.e., weather).' [EPA-HQ-OAR-2009-0491-2864.1, p. 12]
As described above and to its credit, EPA did provide a limited assessment of variability on air quality. However, that analysis was too limited in at least two ways. First, EPA should have assessed the air quality effect of an 'unlimited' trading scenario. Second, EPA's analysis only looked at the 'worst-case' scenario of a state essentially emitting 10% above their budget. Under this scenario, EPA concluded that the increases in air quality were 'small'. What would a similar analysis of 15%, 20%, 25%, 50%, etc. above the state budget had shown on air quality? EPA has not justified why their criterion did not also look to see if higher variability, or unlimited trading, had an impact on air quality. In fact, our assessment suggests that a higher percentage may be supportable. [EPA-HQ-OAR-2009-0491-2864.1, p. 13]
Response:
Thank you for your comments.
Organization: Southern Environmental Law Center
Comment: 
Southern Environmental Law Center
EPA calculated state emissions budgets by applying the applicable cost thresholds to state-specific EGU data, before accounting for the 'inherent variability in power system operations.' EPA calls its proposed remedy for enforcing those budgets the 'state budgets/limited trading' option. While SELC does not express an opinion on the legality of the proposed variability adjustments, it does urge EPA, at a minimum, to not loosen those adjustments. [EPA-HQ-OAR-2009-0491-2801.1, p.5]
A state's basic emissions budget (without the variability adjustment) would still be used to determine how many emission allowances to allocate to EGUs in the state, so the variability adjustment would not increase the allocation to the EGUs in the state nor would it increase the total number of allowances available across the Transport Rule region. However, the variability adjustment would give a state breathing room to exceed its assigned basic budget. Moreover, if a state did so, because EPA proposes to allow interstate trading, each plant in that state would still be able to satisfy its fundamental requirement to possess an allowance for each ton of pollutant it emitted by purchasing allowances from plants in other states as necessary. [EPA-HQ-OAR-2009-0491-2801.1, pp.5-6]
This proposed flexibility would allow significant increases in emissions, and thus, the harmful downwind health and environmental impacts that the Transport Rule is designed to address. To provide an example from the Southeast region, Georgia's basic annual SO2 budget would be 85,717 tons per year ('tpy'). Its 1-year variability adjustment for that budget would be 8,572 tons and its 3-year average limit would be would 4,949 tons. In a single year, then, Georgia's EGUs could increase their collective SO2 emissions by 10% and still all be in compliance with the allowance holding requirement by purchasing as many as 8,572 allowances from power plants in Wisconsin, Illinois, or New York, among other states. While Georgia could not continue to overshoot its budget to this extent year after year because of the 3-year variability limitation, the 3-year adjustment would not prevent periodic, annual excess emissions that would have health impacts in Georgia and the downwind states it contributes to. [EPA-HQ-OAR-2009-0491-2801.1, p.6]
Response: 
As explained in the preamble, state-level emissions are likely to vary even after all significant contribution to nonattainment and interference with maintenance that EPA identified in this final rule are eliminated. EPA believes that the remedy uses variability limits in a way that both provides the flexibility of air quality-assured trading for dealing with real-world variability in the operation of the power system while providing assurance for downwind states that significant contribution to nonattainment and interference with maintenance by upwind states will be eliminated.  EPA's remedy is consistent with CAA requirements and the court's rulings.  Three-year variability limits are not part of the final rule.  See preamble section VI.E for more information about variability limits and required reductions.
Organization: State of Delaware Department of Natural Resources & Environmental Control
Comment: 
State of Delaware Department of Natural Resources & Environmental Control
Delaware is also concerned with EPA's concept of providing 1-year and 3-year average variability mass emission provisions that could serve to allow upwind states to increase their emissions above the limit that EPA has calculated to be required to fully eliminate that state's significant contribution or interfere with maintenance in a downwind state. It is Delaware's understanding that EPA has considered the use of this variability concept in order to help address concerns regarding the variability in electric demand and to prevent impact on electric grid reliability. While Delaware understands the need to maintain grid reliability, it is Delaware's concern that under this scenario any given upwind state, or group of upwind states, could potentially emit on a routine basis at levels that exceed the values calculated by the EPA as needed to eliminate significant contribution and interference with maintenance in a downwind state. It is Delaware's opinion that the proposed variability concept be eliminated or revised such that any revision would preclude the potential for and upwind state or group of upwind states to significantly contribute to a downwind state's inability to comply with applicable NAAQS, or interfere with maintenance of that NAAQS. [EPA-HQ-OAR-2009-0491-2980.1, pp.4-5; this comment can also be found at section IV.F.6 of this comment summary]
Response: 
As explained in the preamble, state-level emissions are likely to vary even after all significant contribution to nonattainment and interference with maintenance that EPA identified in this final rule are eliminated. EPA believes that the remedy uses variability limits in a way that both provides the flexibility for dealing with real-world variability in the operation of the power system while providing assurance for downwind states that significant contribution to nonattainment and interference with maintenance by upwind states will be eliminated.  In addition, there are no 3-year variability limits in the final rule. Delaware is no longer included in the Transport Rule region.  See preamble section VI.E for more information about variability limits and required reductions.
Organization: State of Ohio Environmental Protection Agency (Ohio EPA)
Comment: 
State of Ohio Environmental Protection Agency (Ohio EPA)
c. Ohio EPA believes it is imperative that U.S. EPA take the time to ensure that the appropriate historical emissions and assumptions are used when establishing allocations of the budgets as these allocations are not slated to be adjusted in the future. Ohio EPA believes it would be appropriate to use a similar methodology used when establishing the variability limits, i.e., averaging a series of years. The variability limit is based on the average heat input over several years, but starting budget allocations are based on emissions in one arbitrary year only, which, in this case, is a low demand year. A multi-year averaging approach should be used, continuing to account for controls put in place since such time, and making appropriate corrections and substitutions for periods of non (or very low) operation. [EPA-HQ-OAR-2009-0491-2793.2, p. 9]
Response: 
EPA is finalizing a historic heat input methodology for allocation of emissions allowances under the FIP.  See final rule preamble section VII.D for more information about the date range and calculation used.
Organization: State of Wisconsin, Department of Natural Resources
Comment: 
State of Wisconsin, Department of Natural Resources
Preferred Program Approach - Addressing year-to-year Variance - Within both its preferred inter-state trading/banking program and its alternate intra-state trading program, EPA has added a component of emissions they call variance to account for year-to-year meteorology and economic variability in the level of actual annual emissions from the power sector. This variance structure effectively increases the 'working' budget for states by 10% or more for anyone year. By allowing for variance, EPA has placed the burden of impact on downwind states rather than accounting for it within the state emission budgets and makes the EPA-recommended trading structures too complex. One consequence is any modeled benefit projected within an attainment demonstration must necessarily discount the enforceable emission reduction by the same 10% because modeling needs to reflect actual system response during ozone and 24 hour PM-2.5 episodes. [EPA-HQ-OAR-2009-0491-2829.2, p. 9; This comment can also be found at V.D.2.d. of this comment summary]
Wisconsin recommends that any variance in anticipated emission levels is addressed directly within the budget levels, thereby streamlining the trading and banking structure to avoid the potential air quality and legal problems associated with the proposed variance structure. A potential hybrid approach would be to combine a firmly limited inter-state trading program with a minimum rate-specified intra-state averaging program at a level that would reflect a slightly lower equivalent budget during typical periods. [EPA-HQ-OAR-2009-0491-2829.2, p. 9; This comment can also be found at V.D.2.d. of this comment summary]
A simple assessment of the level of heat input modeled to establish the 2012 and 2014 budgets indicated that EPA already includes some portion of variance within the proposed budget levels. Any alternate variance structure should provide a lower net buffer than proposed in the current rule which provides for significantly greater system fuel consumption than 2009 levels and also includes a separate variance component. Sensitivity analysis suggests the current system annual operation level based on heat input could be raised by 6% for a 2014 budget (on average) in order to reflect the maximum level of system operation by state for the period 2005-2009 (see Figure 1), thus precluding the need for a separate variance structure. [EPA-HQ-OAR-2009-0491-2829.2, pp. 9-10; This comment can also be found at V.D.2.d. of this comment summary]
Regardless of the final program structure adopted, EPA should retain some compliance flexibility, but focus that flexibility most in the early program years of 2012-2014 when it is most needed. 1t might make sense to start with a fairly open inter-state trading and banking program, but transition in later program phases (post-2014), to a structure that more reflects the Court's direction to meet state-by-state targets and to address the States' and Court's assurance concerns. [EPA-HQ-OAR-2009-0491-2829.2, p. 10; This comment can also be found at V.D.2.d. of this comment summary]
Response: 
See response in RTC section V.D.2.d.
Organization: West Virginia Department of Environmental Protection
Comment: 
West Virginia Department of Environmental Protection
EPA requested comment on the proposed variability limits and assurance provisions. With the inclusion of EPA's alternative calculation method for variability, WVDAQ generally supports the variability and assurance provisions in the proposed Transport Rule. We believe that when properly applied, variability limits help achieve good air quality while still allowing for real-world outages and weather events. However, in a few cases, the proposed variability is so large that it becomes dominant over the state's budget. For example, the proposed one-year S02 variability limits for the District of Columbia and Connecticut, are 504 percent and 56 percent of their respective budgets, and the threeyear variability limits are 291 percent and 32 percent ofthe respective S02 budgets. [EPA-HQ-OAR-2009-0491-2790.1, p. 6]
As proposed, the one-year annual NOx variability limit for the District of Columbia is 2941 percent of its proposed budget, and the proposed three-year variability limit is 1698 percent of the District's proposed budget. The seven areas that would be affected by the use of the alternative calculation methodology for variability for annual NOx, have proposed one-year variability limits ranging from 21 percent to 2941 percent of their budgets, with three-year variability limits ranging from 12 percent to 1698 percent oftheir annual NOx budgets. [EPA-HQ-OAR-2009-0491-2790.1, p. 6]
Response: 
EPA has modified the approach to variability limits in the final Transport Rule to align variability limits with historic heat input variability between 2000 - 2010 for all covered states.  In addition, Connecticut, Delaware, and DC are no longer in the Transport Rule region.  For more on variability limits, see section VI.E of the preamble to the final Transport Rule.

IV.F.2. Estimating Year-to-Year Variability/Determination of 1-Year Variability Limits

Organization: Boston Generating
Peabody Municipal Light Plant
Organization: Boston Generating
Comment: 
One year's worth of actual emissions data does not account for normal operating variability and therefore EPA should approximate baseline actual emissions using at least a three year look back period, similar to how the MassDEP allocates allowances under Mass CAIR and previous NO, Budget Programs.  [EPA-HQ-OAR-2009-0491-3804.1 p.1]
Response:
Thank you for your comment.
Organization: Peabody Municipal Light Plant
Comment: 
One year's worth of actual emissions data does not account for normal operating variability. Unit 2 dispatch is highly dependent on ambient temperatures and sometimes unit outages in the North Eastern Management Area (NEMA). For example, Unit 2 operated less than usual in 2009 because ambient temperatures were lower than normal. EPA should approximate baseline actual emissions using at least a three year period, similar to how the MassDEP allocates allowances under Mass CAIR and previous NOx Budget Programs. The following table summarizes actual NOx emissions for 2008, 2009 and 2010 (estimate through September 2010). [EPA-HQ-OAR-2009-0491-3730.1 p.1; see data table]
Response:
Thank you for your comment.

Organization: National Rural Electric Cooperative Association (NRECA)
Old Dominion Electric Cooperative
Organization: National Rural Electric Cooperative Association (NRECA)
Comment: 
Limitations on interstate allowance trading are too stringent. Both the annual and three-year rolling average limitations could be loosened while still meeting North Carolina legal mandates. [EPA-HQ-OAR-2009-0491-2723.1, p.1]
For interstate trading restrictions in the preferred remedy, EPA has proposed a yearly variability of 10 percent of the state budgets, or in the case of states with small budgets, numerical limits; and a three-year variability limit statistically derived by dividing the one year limit by the square root three. EPA requests comment on whether these proposed variances could be relaxed somewhat and still meet the requirements espoused by the court in North Carolina. As stated previously, NRECA believes trading is a vital element in the proposed CATR as a means of reducing costs, thus the more allowed the better so long as Section 110(a)(2)(D)(i) legal mandates are fulfilled. The underlying support for the proposed trading limits is based on statistical analysis of historic heat in-put variability on a state-by-state basis.  This analysis, however, reflects only variances in heat inputs and not emissions reductions. As EPA is well aware, the agency is implementing a "comprehensive strategy" over the next two years to further reduce electric utility air emissions, such as an electric utility hazardous air pollutant (HAPs) regulatory program that will cause emissions addressed in this proposed CATR to be reduced further. With the subsequent implementation of the utility HAPs program, SO2 and NOx emissions will be reduced to levels below that contemplated with the implementation of this proposed CATR alone. Thus, the heat in-put metric for limiting interstate trading will certainly not be as valuable a surrogate in the future as EPA assumes it to be in the present for predicting emissions reductions. Accordingly, NRECA suggests that the proposed variability limits be liberalized to reflect additional reductions that are imminent with the implementation of EPA's "comprehensive strategy." To this end, a 20 percent annual variability with resulting increase the three-year variability limit is appropriate. [EPA-HQ-OAR-2009-0491-2723.1, pp.11-12]
Organization: Old Dominion Electric Cooperative
Comment: 
For interstate trading restrictions in the preferred remedy, EPA has proposed a yearly variability of 10% of the state budgets, or in the case of states with small budgets, numerical limits; and a 3 year variability limit statistically derived by dividing the one year limit by the square root 3. EPA requests comment on whether the proposed variability could be relaxed somewhat and still meet the requirements espoused by the court in the North Carolina decisions, ld. a|45,305. As stated previously ODEC believes trading is a vital element in the proposed Transport Rule as a means of reducing costs, thus the more trading allowed the better so long as s 110(a)(2)(D)(i) legal mandates are fulfilled. The underlying support for the proposed trading limits is based on statistical analysis of historic heat in-put variability on a state by state basis. This analysis, however, reflects only variances in heat input and not emissions reductions. As EPA is well aware, the agency is implementing a 'comprehensive strategy' over the next 2 years to further reduce electric utility air emissions such as an electric utility hazardous air pollutant (HAPs) regulatory program that will cause emissions addressed in this proposed Transport Rule to be reduced further, id. at 45,227. With the subsequent implementation of the utility HAPs program SO2 and NOx emissions will be reduced to levels below that contemplated with the implementation of this proposed Transport Rule alone. Thus, the heat in-put metric for limiting interstate trading limits will certainly not be as valuable a surrogate in the future as EPA assumes it to be in the present. Accordingly, ODEC suggests that the proposed variability limits be liberalized to reflect additional reductions that are imminent with the implementation of EPA's 'comprehensive strategy.' To this end a 20% annual variability with a corresponding increase in the 3 year variability limit is appropriate. [EPA-HQ-OAR-2009-0491-2877.1,p.8]
Response:
EPA disagrees with the commenter's characterization of the purpose of the Transport Rule's variability limits.  The variability limits are not designed to accommodate variability in emission control stemming from specific imposition of other environmental requirements.  EPA does not see any technical basis for changing the requirements of the Transport Rule simply because covered units have other environmental obligations, especially where there is no evidence that compliance with those other obligations would impair the sector's ability to comply with the obligations of this rulemaking.  Furthermore, the commenter notes that EPA's "comprehensive strategy" would "further reduce electric utility air emissions."  Under such a scenario, states would find it even easier to meet their Transport Rule obligations; it does not logically follow that EPA should adjust the Transport Rule's variability limits to accommodate that potential lower-emission outcome.  Finally, the commenter incorrectly asserts that EPA is using historic heat input as a "surrogate... for predicting emission reductions," which the commenter then criticizes.  To develop the variability limits under the Transport Rule, EPA analyzed historic heat input as a surrogate for year-to-year variability in EGU emissions while holding emission controls constant.  This analysis is specifically designed to assess annual variability in emissions, not to predict future emission reductions.  See preamble section VI.E and VI.F for more details on variability limits in the final Transport Rule.
Organization: Maryland Department of Environment (MDE)
Comment: 
Variability
In the proposed Transport Rule EPA addresses electric reliability by establishing the concept of variability. In doing so, EPA guards against the possibility that specific emissions budgets assigned to individual states will impede a fluid and adequate supply of electricity among EGUs. EPA cites a number of factors that may contribute to difficulty in maintaining electric reliability: fluctuations in demand, maintenance, shutdowns, weather, economics and other unpredictable events. EPA asserts that these factors act independently state by state, and EPA develops a statistical method of creating a variability allowance of emissions additional to the state budgets established under significant contribution. EPA claims that this does not affect assurances that significant contribution to downwind nonattainment and interference with maintenance of NAAQS will be eliminated. EPA gives two reasons: 1) overall emissions will not increase because additional allowances will not be distributed, and 2) because the baseline emissions are variable, emissions after the elimination of all significant contribution and interference are also variable and thus it is appropriate to take this variability into account. EPA asks for comment on a number of aspects of the variability proposal. [EPA-HQ-OAR-2009-0491-2639.2, pp.12-13]
Maryland appreciates the need to address variability and agrees with its inclusion in the Transport Rule. However, we have significant concerns with EPA's proposed variability structure in the proposed rule. Many of the factors EPA cites as reasons for establishing variability do not independently affect the impacted states. Instead, groups of neighboring states may be affected simultaneously, a possibility that EPA does not seem to have properly analyzed when designing its variability concept. [EPA-HQ-OAR-2009-0491-2639.2, p.13]
First, it does not appear that, in developing the variability concept, EPA considered which states export and which states import electricity and how that can affect emissions within groups of states such as when a large EGU shuts down. Likewise, EPA did not seem to take into account to degree to which a given state even needs the extra allowances provided by variability. Secondly, factors such as extended episodes of high temperature often affect large geographic areas and exacerbate ozone formation. While these emission surges may balance out over time, the actual extra emissions are likely to occur at the worst possible times, such as on hot, humid days that already have poor air quality. EPA claims that these assurances are not threatened because limited allowances will maintain the established emissions levels. However, this interpretation dismisses the fact that sources can have significant carryover allowances from year to year and in a short timeframe can accumulate enough allowances to increase overall emissions in any given year. As stated previously, Maryland believes that the NOx budgets are too lenient already and that the variability concept as proposed would not provide the necessary assurances that the current proposed NOx budgets would be met at even a minimum allowable level. [EPA-HQ-OAR-2009-0491-2639.2, p.13; This comment can also be found at IV.F.1 of this comment summary]
Perhaps Maryland's greatest concerns with variability are that it is added on top of the budget that was supposedly determined to be the maximum acceptable emissions, and that it has not been proven acceptable with a photochemical model. Maryland believes that adding variability on top of the budgets is ripe for potential failures. Utilities may operate as if the 10% variability plus the budget level is the real budget and increase emissions up to the 10% limit. MDE believes that variability should be factored into the emissions budgets, not treated as a 10% add-on to a maximum acceptable emissions budget. [EPA-HQ-OAR-2009-0491-2639.2, p.13]
Maryland suggests that the variability concept be applied under the individual state budgets. We propose that, for instances of shutdowns and unexpected outages, EPA develop a process that would utilize allowances from the new source set asides to cover needed interim operations. For other factors, such as extreme weather and increasing demand, potential variability should drive stricter control levels or controls on additional EGU sources, and it should be absorbed under the budget. EPA's second reason for adopting variability states that as baseline emissions are variable, emissions after the elimination of all significant contribution and interference are also variable and thus it is appropriate to take this variability into account. On the other hand, EPA has maintained a strict emission level test, with no variability allowed, as the ultimate standard for approval under their re-designation and maintenance policies. This policy seems fundamentally at odds with EPA's variability concept as enumerated in the proposed rule, which holds that emissions can fluctuate and at the same time maintain assurance of eliminating significant contribution for downwind states. [EPA-HQ-OAR-2009-0491-2639.2, p.13]
Consequently, Maryland requests that EPA maintain assurance through the individual state budget structure proposed in the Transport Rule and address variability from within that construct; not as an add-on. Maryland would like to see EPA produce a modeling demonstration that verifies variability has been fully examined. [EPA-HQ-OAR-2009-0491-2639.2, p.14]
Response:
EPA's modeling of the final Transport Rule remedy directly incorporates the variability limits in each state.  Therefore, EPA's photochemical air quality modeling of the rule's impacts do in fact account for the application of variability limits on top of state budgets to form each state's assurance levels.  As a result, EPA's air quality projections for the impacts of this rule successfully incorporate emission projections including the variability limits allowed in each state.  EPA disagrees with the commenter's characterization of the Transport Rule emission budgets.  A state budget represents the emissions from covered units remaining in that state after the elimination of significant contribution and interference with maintenance in an average year.  This does not take into account the inherent year-to-year fluctuation in state-level EGU emissions that would occur in the future whether or not the Transport Rule was implemented.  Therefore, it is appropriate to apply the variability limits in addition to the state budget to allow for this year-to-year variation.  EPA acknowledges the concern expressed by the commenter regarding the impact of a single EGU failure to increased emissions from EGUs in multiple states, and EPA believes that the final Transport Rule successfully accommodates this potential outcome by applying the maximum historic year-to-year variability observed in any given state from the analyzed 2000-2010 period to all states in the programs.  As EPA explains in the final Transport Rule preamble section VI.E and the Variability Final Rule TSD, EPA observes several factors, including this factor identified by the commenter, that could lead multiple states in the future to experience up to the maximum state-level historic year-to-year variability observed in the data set analyzed from 2000-2010 for the final rule.
Organization: North Carolina Department of Environment and Natural Resources
Comment: 
NC beIieves that the 95% confidence interval seems appropriate. [EPA-HQ-OAR-2009-0491-2767.1 p.7]
Although the variability limits may have been calculated in a defensible manner, once the limits are allowed there is no legal assurance that the variability margins will be used by market participants to account for variability. The variability limits are simply a trading budget overage margin and are forever unmoored from their intended purpose. As such, the variability limits, although stemming from a defensible theory, are themselves not consistent with the Clean Air Act. [EPA-HQ-OAR-2009-0491-2767.1 p.7]
Response: 
With regard to the commenter's claim that the variability limits "are themselves not consistent with the Clean Air Act", see section VII.J of the preamble to the final Transport Rule. 

EPA appreciates North Carolina's support of the 95% confidence interval and has maintained that criteria in the final variability limit analysis.

See also section IV.F.1 of this RTC document.
Organization: Prairie State Generating Company, LLC
Comment: 
9. SIZE OF THE VARIABILITY LIMITS
The U.S. EPA requested comment on the size of the variability limits (10% for the 1-year variability limits and a level equal to the square root of the number of years covered by a look-back variability period). p. 45294. PSGC believes that the variability limits should be greater to account for emissions from new units who are not allocated allowances, to account for the variabilities in generation among the states discussed above, and to balance the data used to develop the base-years, i.e., 2009 emissions data when 2009 was an unusually low utilization year because of the economy and the lower than normal temperatures during the summer months in, at least, the Midwest. PSGC supports the U.S. EPA's suggestion that the variability limits should be based on historic heat input data (21% for annual NOx and 28% for SO2), p. 45294, as this level of variability is more representative of realistic conditions while still protecting the environment and would better accommodate new generation. [EPA-HQ-OAR-2009-0491-2842.1, p.7]
PSGC's concern with the proposed variability limit stems largely from the fact that the U.S. EPA did not determine on a state-by-state basis the likely new generation and then set the NUSA for each state consistent with those projections. If one state has a greater than 3% growth in generation, it is more likely that the total emissions in the state could exceed the state's variability limit because of the new generation while another state, even a neighboring state that has no new generation, will have NUSA allowances going unused. Because the assumption that the 3% growth in new generation region-wide is applied evenly in all states regardless of the prognosis for new generation in a state, the artificial constraints of that assumption carryover to the variability limits for each state. Increasing the size of the variability limits, at least in states with greater growth than others, would help to alleviate those unnecessary and unreasonable constraints. [EPA-HQ-OAR-2009-0491-2842.1, p.7]
As the U.S. EPA is aware, the energy from coal resources of states like Illinois is vast. New coal-fired power plants such as PSGC are highly controlled and are extremely efficient compared to the older coal-fired fleet. Arguably, the constraints inherent in the proposed Transport Rule extenuate reliance on older, less efficient plants and create unnecessary and unreasonable barriers to shifting generation to newer, more efficient units. Easing the ability of new plants to operate, rather than constraining them, by providing higher variability limits or excusing new units from compliance with the variability limits or, as suggested earlier, allowing them to become 'existing' units and thereby have a permanent allowance stream would enhance air quality while maintaining and increasing reliable electric service. [EPA-HQ-OAR-2009-0491-2842.1, p.8]
PSGC agrees that the variability limits should first apply in 2014, see pp. 45296, 45306, to provide for a reasonable transition period into the new program. [EPA-HQ-OAR-2009-0491-2842.1, p.8]
Response: 
EPA finalized a modified variability limit approach, which simplified the determination of limits by eliminating the tonnage limits and giving all states the same percentage. The percentage variability limits are higher than the 10% limits in the proposal.  See preamble section VI.E and VI.F of the final Transport Rule for more details on variability limits.
The new unit set-aside approach has also been modified in response to this and other similar comments.  See section VII.D.2 of the final Transport Rule preamble for more details on the new unit set aside.

Organization: State of Missouri Department of Natural Resources
Comment: 
State of Missouri Department of Natural Resources
EPA based the calculation for states' variability on heat input as a proxy for actual emissions. This seems appropriate as it factors out the effects on emissions of controls going online. The calculation was based on heat input from the Allowance Management System for years 2002 through 2008. A linear regression analysis was used to determine the regression line and coefficient of determination, r2. The difference was then noted between each annual observed heat input and the predicted heat input. The idea behind this was an attempt to quantify the changes to heat input over the study period due to growth or decline. The slope of the regression line would account for the increase or decrease. Limiting the discussion to just the coal-fired units, Missouri's data does not show this assumed linearity. The coefficient of determination was very low, 0.01, implying that the difference between actual and predicted values were due to factors other than heat input and random error. EPA continued with the linear regression in spite of the low r2 value. This leads to large differences between observed and predicted heat inputs, large standard deviation of the differences, and large ninety-five (95%) confidence level in the variability of heat input. EPA may want to consider using a regression method that yields the highest r2 value. As an example, a quadratic regression on Missouri's seven (7) data points yields an r2 value of 0.94. The difference between observed and predicted values is smaller, the standard deviation of the differences is smaller, and the ninety-five percent (95%) confidence level in the variability of heat input is smaller. Examining the regression line and regression quadratic versus the data confirms the data more closely follows the quadratic function and not the linear function. The ninety-five percent (95%) confidence level variability in heat input is combined with modeled emission rates to yield ninety-five (95%) confidence level in variability in emissions. The implication is that Missouri's 1-year variability in emissions, which serves as the basis for their 3-year variability, would be less if EPA used a more appropriate curve-fitting technique. [EPA-HQ-OAR-2009-0491-3806, p.4]
Response: 
Thank you for your comment.  You are correct that a quadratic equation is a better fit for Missouri's heat input data for the time period of 2002-2008, than the linear least-squares regression equation.  The r^2 value for the quadratic equation is large (0.942), indicating that the quadratic trend line can "explain" a substantial portion of the heat input pattern for Missouri.  However, it is not clear why there would be a parabolic pattern of heat input for the state, or whether we could expect to see such a quadratic pattern continue in the future.  When we apply a quadratic equation to Missouri's heat input for a larger time period 2000-2010, the r^2 value drops to 0.77.  Moreover, the estimate for 2010 using the quadratic equation for 2010 is going down (it would estimate 2011 as lower than 2010).  However, heat input in Missouri has increased from 2009 through 2010, and it does not seem likely for it to drop below 2009 levels in 2011.
The interpretation that we make for Missouri's heat input over the 2002-2008 time period is that there is substantial year-to-year variation, and essentially no trend over the time period as assessed over the entire time period.  The heat input value in 2002 is fairly close to the value in 2008.  When the regression line is essentially flat, there is no trend and the r^2 values will be very low (since the regression equation does not "explain" a trend).  When we assess the heat input over the 2000-2010 time period using the linear equation, the r^2 is about 0.33.  Given the large year to year variation and lack of consistent overall trend, EPA thinks that a linear equation is the most appropriate for gauging historical variability in heat input for Missouri.
Organization: Utility Air Regulatory Group (UARG)
Comment: 
Utility Air Regulatory Group (UARG)
1. Variability Limits.
EPA's explanation in the preamble to the proposed rule, and in the TSD on Power Sector Variability ("Variability TSD"), of its method for selecting the 10 percent uniform emission variability value is less than clear. At a minimum, it does not appear that EPA's analysis precludes a conclusion that a higher uniform percentage is justified. EPA should carefully consider the basis for adopting a higher percentage. [EPA-HQ-OAR-2009-0491-2756.1, p.92]
UARG strongly urges EPA to consider increasing the variability limit. A higher variability limit would encourage emission trading and increased emission reductions at sources where they are most cost-effective to achieve (thus lowering the overall cost of compliance with the program), while still ensuring that substantial emission control levels are maintained within each state. In fact, an analysis conducted by Southern Company and described in its comments on the Proposed Transport Rule indicates that even unrestricted interstate emission trading could yield air quality that is substantially the same as if trading were not allowed under the proposal. [EPA-HQ-OAR-2009-0491-2756.1, p.93, this comment can also be found at section IV.F.6. of the comment summary]
Response: 
EPA has used a wider set of data from 2000 - 2010 for analyzing variability in the final rule. As explained in the preamble section VI.E, the resulting  variability limit percentages provide sources with sufficient operational flexibility yet comport with the court ruling in North Carolina v. EPA that requires sources within each state to eliminate their significant contribution or interference with maintenance.  

IV.F.3. Alternative Calculation Methods

Organization: Adirondack Council
Comment: 
Adirondack Council
EPA also requests comment on an alternative calculation method for variability. The alternative method would use the results of the proposed method but add a ceiling based on the maximum percentage of variability among covered states as observed in the historic heat input data described previously. (p. 351) The Adirondack Council supports the alternative calculation with the ceiling as it would prevent higher levels for some states that may even allow for increases in emissions in some cases. We support the alternative approach as it will ensure all states make significant reductions. [EPA-HQ-OAR-2009-0491-2848.1, p.3]
Response: 
EPA has modified the approach to variability limits in the final rule making the alternative maximum percentage approach no longer applicable.  See preamble section VI.E for more details about the final variability limits approach.
Organization: West Virginia Department of Environmental Protection
Comment: 
West Virginia Department of Environmental Protection
[[2790.1 p.7]]
Alternative Calculation Method for Variability - EPA also requested comment on an alternative calculation method for variability. The alternative method would use the results of the proposed method, but add a ceiling on the maximum percentage of variability among covered states as observed in the historic heat input data. For both NOx annual and S02' the percentage limits calculated using this alternative methodology are 21 and 28 percent of a state's budget, respectively. Under this alternative calculation methodology, a state's variability limit would be no lower than 10 percent of its budget and no higher than 21 or 28 percent, for NOx and S02' respectively. Because no state varied by more than these percentages, they could serve as reasonable caps on variability limits. These limits would address the issue of small states receiving very large variability limits as a fraction of their budgets. The District of Columbia and Connecticut are the only areas that would be affected by the use of the alternative calculation methodology for S02 variability limits.
WVDAQ supports the use ofEP A's alternative calculation methodology for variability limits, and believes a ceiling on the maximum percentage of variability is appropriate. We also agree that the maximum percentage of variability among covered states as observed in the historic heat input data could serve as reasonable caps on variability limits.
Response: 
EPA has modified the approach to variability limits in the final rule making the alternative maximum percentage approach no longer applicable.  See preamble section VI.E for more details about the final variability limits approach.

IV.F.4. Estimating Multi-Year Variability/Determination of 3-Year (and 2-Year) Variability Limits

Organization: Adirondack Council
Comment: 
Adirondack Council
Table IV.F-1 shows proposed variability limits by states on SO2 emissions for 2014 and later. Table IV.F-2 shows proposed variability limits by state on NOX annual emissions for 2014 and later. EPA requests comment on the proposed variability limits. (p. 351) The Adirondack Council believes that the 3-year average limit is too high. While we understand the methodology for calculating this figure, we believe that using this type of mathematical formula creates some confusion. A simpler way to calculate the 3-year average would be to divide the 1- year limit by 2. [EPA-HQ-OAR-2009-0491-2848.1, p.3]
Response: 
EPA finalized one-year variability limits only in the Transport Rule for reasons explained in preamble section VI.E and in the Power Sector Variability Final Rule TSD.
Organization: Capital Power Corporation
Comment: 
Capital Power Corporation
CATR allocations and estimates of variability were made through EPA's use of the Integrated Planning Model (IPM) based on a run of 3-year emissions variability. CPC believes this period is inadequate to appropriately characterize an industry whose productions and emissions vary significantly with economic fluctuations. Given the economic downturn that has occurred over the past two years, CPC believes that EPA should consider modeling a five year period that would better account for the variability that may occur when the economy recovers. [EPA-HQ-OAR-2009-0491-2753.1, p.2]
Response: 
Variability limits were updated based on data from 2000 - 2010. This 11-year period includes both years in which heat input was above and below the average.  See preamble section VI.E and the Power Sector Variability Final Rule TSD for more on variability limits and the data used.
Organization: Illinois Environmental Protection Agency
State of Ohio Environmental Protection Agency (Ohio EPA)
Santee Cooper
Comment: 
Illinois Environmental Protection Agency
Almost half of Illinois' electric generating capacity is from nuclear power plants. In our opinion, the three-year variability averaging provisions proposed in the Transport Rule do not provide sufficient flexibility in the event of significant downtime of one or more nuclear generating stations. When such shutdowns occur, coal-fired generating stations necessarily ramp up electric generation, thereby causing an increase in S02 and NOx emissions for the duration of the shutdown. U.S. EPA's variability provisions could potentially be a risk to reliability in the event of a long-term shutdown of one or more nuclear power plants. The Illinois EPA recommends that U.S. EPA remove the three-year averaging requirement and provide the variability limit on a year-to-year basis.  [EPA-HQ-OAR-2009-0491-2781.1 p.3]
Santee Cooper
EPA should eliminate the 3-year variability limit on state NOx and S02 budgets because it would make the achievement of the Transport Rule's environmental objectives unnecessarily costly. [EPA-HQ-OAR-2009-0491-2820.1, p.2]
EPA SHOULD ELIMINATE THE 3-YEAR VARIABILITY LIMIT. [EPA-HQ-OAR-2009-0491-2820.1, p.6]
Santee Cooper believes EPA's proposal to impose a 3-year variability limit on state NOx and SO2 budgets is unworkable and would make the achievement of the Transport Rule's environmental objectives unnecessarily costly. EPA developed the concept of the variability limit in order to allow state budgets to accommodate changes in electricity demand, generation outages, and other common factors that influence year-to year emissions. However, EPA calculated the 3-year variability limits on the basis of statistical inference, not historical data. This method offers little protection for states that become subject to unusually large changes in demand for or supply of electricity. Moreover, compliance with the 3-year limit could force states to achieve unusual and abrupt changes in emissions. [EPA-HQ-OAR-2009-0491-2820.1, pp.6-7]
As an example, consider a state with an annual emissions budget of 100,000 tons of SO2 and a 1-year variability limit of 10,000 tons. Using EPA's formula, that state would have a 3-year variability limit of 5,800 tons. If sources within that state emitted 110,000 tons of SO2 in 2014 and 2015 (just within the 1-year variability limit), compliance with the 3-year limit would require the state to emit just 97,000 tons in 2016 - a reduction of approximately 13% relative to the previous two years. Such abrupt changes in emissions would be difficult to achieve, especially given that emissions data for 2015 would not become available until several months into 2016. Moreover, the prospect of such significant swings in emission budgets would create substantial business uncertainty and add to the cost and complexity of planning for compliance with the Transport Rule. [EPA-HQ-OAR-2009-0491-2820.1, p.7]
Santee Cooper believes that the 1-year variability limit is a sufficiently stringent limitation on interstate trading of allowances to comply with the D.C. Circuit's mandate in North Carolina that each state address its own significant contribution to nonattainment in downwind states. The 3-year variability limit is an unnecessary and impractical additional measure that should be discarded in the final version of the Transport Rule. [EPA-HQ-OAR-2009-0491-2820.1, p.7]
State of Ohio Environmental Protection Agency (Ohio EPA)
b. Furthermore, the framework established for the three-year variability limit also unnecessarily inhibits trading of allocations. Using a three-year variability limit that is lower than the sum of the one-year variability limits will create uncertainty, especially in that third year, as to whether enough allocations will be available. Owners will likely bank any left-over allocations to ensure they have sufficient allocations to cover the three-year variability. [EPA-HQ-OAR-2009-0491-2793.2, pp. 6-7]
Response: 
EPA is finalizing one-year variability limits only in the Transport Rule.  The three-year variability limits have not been included in the final rule for reasons discussed in the final Transport Rule preamble section VI.E and the Power Sector Variability Final Rule TSD.
Organization: Large Public Power Council (LPPC)
Comment: 
Large Public Power Council (LPPC)
A. The Three-Year Variability Limit is Impracticable, Increases the Cost of the Program, and Is Not Required by North Carolina  
LPPC urges EPA to eliminate the 3-year variability limit in the final Transport Rule. Unlike CAIR, the proposed Transport Rule sets individual state emission budgets that are based on each state's estimated significant contributions to nonattainment or interference with maintenance in downwind states. EGUs (or EGU owners) within the state would be permitted to submit allowances in excess of the annual budget (either by procuring them through interstate trading or by using banked allowances) only to the extent necessary to accommodate anticipated year-to-year variability in emissions within each state. EPA views these variability limits  -  which inherently restrict the volume of interstate emissions trading  -  as necessary to comply with North Carolina's holding that each state's emission reduction requirements must be tied to its actual level of significant contribution or interference with maintenance. [EPA-HQ-OAR-2009-0491-2667.1, p.11]  
1. Impracticability. The 3-year limit is impracticable because it forces emissions within each state to conform to statistically derived three-year averages regardless of actual conditions within the state (or face a penalty in the form of the assurance provisions). As EPA notes in the preamble, the underlying purpose of the variability limit is to allow states limited flexibility in their emissions budgets to accommodate fluctuations in electricity demand, generation outages, and other external factors that influence year-to-year emissions. Although variability averaged over a rolling 3-year period is historically smaller than variability in a single given year, EPA's method for deriving the 3-year variability limits is no more than a statistical prediction of the variability that "should" ordinarily be observed in a 3-year period. 39 This statistical method fails to accommodate actual variability that exceeds levels predicted by EPA's simple statistical estimates. If unusual circumstances  -  such as a surge in electricity demand stemming from unusually hot summer weather  -  nevertheless caused emissions to increase beyond the 3-year rolling average, sources within the state would be penalized for exceeding the 3-year variability limit. In order to avoid the assurance provisions, sources within the state would have to engineer abrupt reductions in emissions to conform to the 3-year limit. 40 [EPA-HQ-OAR-2009-0491-2667.1, pp.11-12]  
This hardship would be most acute in 2016, the first year that the proposed 3-year limit would become binding, because the amount of emissions allowable in 2016 in order for a state to remain within the 3-year limit could not be calculated until emissions data for both 2014 and 2015 are available. Since emissions data from 2015 would not likely be available until early 2016, sources within each state would have only a matter of months to curb their emissions to levels commensurate with the 3-year limit  -  a task that would likely be impossible. 41 [EPA-HQ-OAR-2009-0491-2667.1, p.12]  
2. Cost. The 3-year limit is also costly, for obvious reasons. A cap-and-trade system is most economically efficient when maximum flexibility is allowed as to the timing and location of emission reductions within the cap. Interstate trading, and banking of emission reductions, are the key mechanisms for ensuring this flexibility. Because the 3-year limit is about 42% lower than the annual variability limit in every state, 42 the effect of the 3-year limit is to significantly constrain the use of interstate and banked allowances even more than would occur with the 1-year limit alone. These constraints could, in many cases, prevent EGUs from minimizing the costs of meeting the environmental objectives of the Transport Rule through the efficient use of traded and banked allowances. [EPA-HQ-OAR-2009-0491-2667.1, p.12]  
3. Consistency With North Carolina. The 3-year limit is simply not required to satisfy the D.C. Circuit's instructions in North Carolina. In North Carolina, the D.C. Circuit faulted CAIR for allowing completely unrestricted emissions trading among sources in different states. Whatever its economic and environmental merits, the D.C. Circuit reasoned, such an approach could never ensure the achievement of "something measurable towards the goal of prohibiting sources `within the State' from contributing to nonattainment or interfering with maintenance in 'any other State,' 43 In the case of CAIR, which purported to provide a "complete" remedy to the problem of interstate transport of NOx and SO2, the D.C. Circuit required EPA to demonstrate that each state subject to the rule would effectively eliminate its significant contributions and interference with maintenance. [EPA-HQ-OAR-2009-0491-2667.1, pp.12-13]  
Nothing in the D.C. Circuit's opinion mandates that EPA adopt a 3-year limit or comparable approach. EPA's state emission budgets, combined with its proposed 1-year variability limits, satisfy the D.C. Circuit's mandate that the agency quantify and achieve "something measurable" toward eliminating each state's significant contribution to downwind air quality problems. As EPA notes in the preamble to the Transport Rule, the factors that would lead to variability under the Transport Rule are the same factors that would drive variability in a "baseline" scenario absent the Transport Rule. Accordingly, each state can be considered to have eliminated its significant contribution and interference with maintenance even if its emissions reach the 1-year variability limit. Moreover, the magnitude of the 1-year variability limits is small compared to the state emission budgets, and even smaller compared to the overall level of NOx and SO2 emissions from all sources within each state. The 3-year limit is an unnecessary appendage to the proposed rule, and  -  given its significant practical problems and cost impacts  -  should be discarded in the final rule. 44 [EPA-HQ-OAR-2009-0491-2667.1, p.13]  
4. Policy Rationale for 3-Year Limit. As a final comment on the 3-year limit, LPPC notes that EPA's stated policy rationale for the 3-year limit is unclear. According to EPA, the 3-year limit is necessary because air quality is assessed under the CAA on a rolling 3-year basis. However, EPA never explains why this method for assessing air quality must also drive variability limits, which are established for a completely distinct purpose: to accommodate natural fluctuations in regional electricity demand. The weak and arbitrary nature of EPA's stated policy rationale for the 3-year limit only adds to the case for eliminating the 3-year limit in the final rule. [EPA-HQ-OAR-2009-0491-2667.1, p.13]  

44. As EPA also acknowledges, the variability limits are designed to have no impact on the aggregate quantity of NOx and SO2 emitted among all upwind states. See 75 Fed. Reg. at 45,292. If one state exceeds its budget and reaches its 1-year variability limit, those excess emissions must necessarily be exactly offset by reduced emissions in another state (or in the case of banked allowances, emission reductions occurring in earlier years of the Transport Rule). Because the variability limits are relatively small and because their use is always offset by an emission reduction elsewhere or at a different point in time, the environmental impact of eliminating the 3-year variability limit is likely to be negligible. [EPA-HQ-OAR-2009-0491-2667.1, p.13]  
Response: 
EPA is finalizing one-year variability limits only in the Transport Rule.  The three-year variability limits have not been included in the final rule for reasons discussed in the preamble section VI.E and the Power Sector Variability Final Rule TSD, such as complexity and lack of air quality benefits.

IV.F.5. Proposed Variability Limits on SO2, NOx, and Ozone Season NOx

Organization: Duke Energy
Comment: 
It is not clear from EPA's explanation in the preamble to the PTR, and in the TSD on Power Sector Variability ("Variability TSD"), of its methodology for selecting a variability limit how or why EPA arrived at its proposed 10 percent uniform emission variability value. At a minimum, it does not appear that EPA's variability analysis would not support a higher uniform percentage, such as 20 percent. Duke Energy urges EPA to consider the basis for using a higher variability percentage. [EPA-HQ-OAR-2009-0491-2689.1, p.30]
The Variability TSD describes how EPA performed the variability analysis using two different approaches, each of which examined the effects of variations in SO2 emissions from upwind states on 24-hour PM2.5 concentrations at downwind nonattainment and maintenance monitors. Variability TSD at 43. In the first approach -- intended to replicate "typical" variation -- EPA projected that SO2 emissions in each upwind state in the proposed control region would vary randomly. Id. at 44. In the second approach -- intended to replicate "worst case" variation -- EPA projected, on a monitor-by-monitor basis, that SO2 emissions in the upwind states with the largest air quality impacts per ton on the downwind monitor increased to the maximum amount (up to each state's one year variability limit) and that SO2 emissions in all of the other upwind states decreased to compensate for the increased emissions from the high impact states (so that the region wide emissions in the proposed control region equaled the sum of all state budgets). Id. at 47. EPA reported that "[f]or both approaches, the effects of the inherent variation in emissions on daily PM2.5 concentrations were estimated to be small." Id. at 44. [EPA-HQ-OAR-2009-0491-2689.1, pp.29-30]
That a broader and more robust trading program would have little impact on where emission reductions occur is entirely consistent with what is expected for a well-designed trading program. There will typically be little overall difference in the units that will be controlled under a trading program that is set to meet specific targets. The reductions occur where the opportunities are greatest, and under a tight reduction program, there will be sufficient "opportunities" throughout the control region. What makes a difference is in the success of the trading program is the ability to pool the limited amount of available and unused allowances such that there will be sufficient volume of allowances to establish a viable market that is not subject to great volatility. The result of a limited market is that a viable market may not be established and controls may be added where they don't make sense  -  on smaller units or units that already have relatively low emission rates, and which are likely having less impact on downwind areas. [EPA-HQ-OAR-2009-0491-2689.1, p.30]
Duke Energy agrees generally that the analysis demonstrates that interstate trading does not adversely impact downwind air quality. However, Duke Energy encourages EPA to also perform this analysis using variability limits of 20 to 30 percent to determine if higher limits would also yield small impacts. [EPA-HQ-OAR-2009-0491-2689.1, p.31]
Response:

Thank you for your comments.
Organization: GE Energy Financial Services (GE EFS)
Comment: 
GE Energy Financial Services (GE EFS)
GE EFS would also suggest that EPA increase both the one-year and three-year variability limits to 15% and 10%, respectively, of a state's budget. [EPA-HQ-OAR-2009-0491-2701.1,p.6]
Response: 
EPA has modified the approach to variability limits in the final Transport Rule to align variability limits with historic heat input variability between  2000 - 2010 for all covered states.  For more on variability limits, see section VI.E of the preamble to the final Transport Rule.
Organization: JEA
Comment: 
JEA
However, JEA urges EPA to eliminate the 3-year variability limit in the final Transport Rule. Unlike CAIR, the proposed Transport Rule sets individual state emission budgets that are based on each state's estimated significant contributions to nonattainment or interference with maintenance in downwind states. Sources within the state would be permitted to submit allowances in excess of the annual budget (either by procuring them through interstate trading or by using banked allowances) only to the extent necessary to accommodate anticipated year-to-year variability in emissions within each state. EPA views these variability limits - which inherently restrict the volume of interstate emissions trading - as necessary to comply with North Carolina's holding that each state's emission reduction requirements must be tied to its actual level of significant contribution or interference with maintenance. [EPA-HQ-OAR-2009-0491-2713.1, p.4]
Response: 
EPA is finalizing one-year variability limits only in the Transport Rule.  The three-year variability limits have not been included in the final rule for reasons discussed in the preamble section VI.E and the Power Sector Variability Final Rule TSD.
Organization: New Jersey Department of Environmental Protection (NJDEP)
Comment: 
A seasonal limitation as proposed in the Transport Rule does not ensure enough reduction of the daily emissions of ozone precursors to prevent an ozone NAAQS violation. New Jersey has adopted its own rules to address NOx emissions on a daily basis. In an analysis the Department conducted for the northeast, we found that on a typical summer day in 2005, the NOx emissions were 551 tons per day, while on a high electric demand day, typically a high temperature day with high ozone, the NOx emissions were 1,349 tons per day. Averaging emissions over the ozone season is insufficient to address such days, where the NOx emissions can be two to three times the typical day. Although the USEP A offered a direct control alternative in the proposed Transport Rule, it is not sufficient to solve the peak ozone day problem because the alternative is an annual performance standard that allows averaging of all the units statewide under one owner and does not address daily emissions. To properly address NOx emissions during high electric delnand days, the USEP A must additionally adopt a rule with daily, or shorter period, performance standards.   [EPA-HQ-OAR-2009-0491-2684.1 p.3]
Response:
Thank you for your comments, EPA's modeling of the Transport Rule suggests that additional pollution control hardware will be installed; thus, it is likely that emissions will be lower under nearly all circumstances, including during the potential peak ozone days cited by the commenter.
Organization: State of Ohio Environmental Protection Agency (Ohio EPA)
Comment: 
State of Ohio Environmental Protection Agency (Ohio EPA)
5. Ohio EPA has concerns regarding the variability limit provisions. U.S. EPA should adjust the variability limits as they are not sufficient for some states, while for others they are excessive. [EPA-HQ-OAR-2009-0491-2793.2, p. 6]
a. Given the insufficient S02 emissions budget for Ohio and the fact that 3% is taken off the top for the new unit set aside, Ohio EPA believes it is necessary to provide a greater variability limit. [EPA-HQ-OAR-2009-0491-2793.2, p. 6]
b. Ohio EPA is also concerned, as pointed out by U.S. EPA, that some small states receive very large variability limits as a fraction of their budgets. [EPA-HQ-OAR-2009-0491-2793.2, p. 6]
c. Notwithstanding the fact that Ohio EPA believes the variability limits are insufficient, Ohio EPA disagrees with any approach that would implement those variability limits starting in 2012. Sufficient time is needed in order to allow sources to transition to this new system. [EPA-HQ-OAR-2009-0491-2793.2, p. 6]
Response: 
EPA has modified the approach to variability limits in the final rule and has addressed the concern raised in this comment regarding large variability limits for some states.  See preamble section VI.E in the final Transport Rule for more details about the final variability limits approach.
Organization: State of Wisconsin, Department of Natural Resources
Comment: 
By 2014, any variance provisions should not allow higher emission levels than the emission budgets that are determined necessary for meeting the determined significant contribution. [EPA-HQ-OAR-2009-0491-2829.2, p.1]
Response:
The commenter mischaracterizes the role of the Transport Rule state budgets, which EPA determined by identifying the cost-effective emission reductions required in an average year, before accounting for the inherent year-to-year variability in state-level EGU emissions.  EPA has determined that compliance with state assurance levels (state budget plus variability limit) under the Transport Rule programs meets the mandate of section 110(a)(2)(D) under the Transport Rule FIPs.
Organization: West Virginia Department of Environmental Protection
Comment: 
West Virginia Department of Environmental Protection
Similarly, the ozone season NOx ozone-year variability limit for the District of Columbia is 2000 percent of its proposed budget, and the three-year variability limit is 1154 percent of the proposed budget. The five areas that would be affected by the use of the alternative calculation methodology for ozone season variability limits have proposed one-year variability limits ranging from 29 percent to 2000 percent of the proposed budgets, and three-year variability limits ranging from 17 percent to 1154 percent of the proposed ozone season NOx budgets. WVDAQ believes that as proposed, the variability limits provisions are flawed. We therefore support EPA's alternative calculation method for variability, which contains a ceiling on the maximum percentage of variability. [EPA-HQ-OAR-2009-0491-2790.1, p. 6]
Response: 
EPA has modified the approach to variability limits in the final rule and has addressed the concern raised in this comment regarding large variability limits.  See preamble section VI.E for more details about the final variability limits approach.

IV.F.6. Estimate of Effects of Emissions Variability on Downwind Air Quality

Organization: Duke Energy
Utility Air Regulatory Group (UARG)
Comment: 
Duke Energy
Duke Energy encourages EPA to also assess the impact on downwind air quality assuming no variability limit. If one or more of these analyses also indicate that the impact of upwind emissions variability on downwind air quality remains small, higher variability limits, or no variability limits, would be justified. A higher variability limit would encourage greater emission trading and increased emission reductions at sources where they are most cost-effective to achieve, while still ensuring that substantial emission control levels are maintained within each state. Duke Energy urges EPA to give serious consideration to increasing the variability limit threshold. [EPA-HQ-OAR-2009-0491-2689.1, p.31]
Utility Air Regulatory Group (UARG)
The Variability Limits and Assurance Provisions Proposed by EPA Are Unduly Stringent and Should Be Adjusted.
The Variability TSD describes an analysis that EPA performed, using its air quality assessment tool, to evaluate the effect of variability in emissions in upwind states on air quality in downwind states. According to this TSD, EPA performed this analysis using two different approaches, each of which examined the effects of variations in SO2 emissions from upwind states on 24-hour PM2.5 concentrations at downwind nonattainment and maintenance monitors. Variability TSD at 43. In the first approach -- intended to replicate "typical" variation -- EPA projected that SO2 emissions in each upwind state in the proposed control region would vary randomly. Id. at 44. In the second approach -- intended to replicate "worst case" variation -- EPA projected, on a monitor-by monitor basis, that SO2 emissions in the upwind states with the largest air quality impacts per ton on the downwind monitor increased to the maximum amount (up to each state's one-year variability limit) and that SO2 emissions in all of the other upwind states decreased to compensate for the increased emissions from the high-impact states (so that the region-wide emissions in the proposed control region equaled the sum of all state budgets). Id. at 47. EPA reported that "[f]or both approaches, the effects of the inherent variation in emissions on daily PM2.5 concentrations were estimated to be small." Id. at 44; see also id. at 46 (reporting that the results of the analysis using the first ("typical" variation) approach indicated that "the combined downwind air quality impacts were essentially negligible"), 47 (reporting that the results of the analysis using the second ("worst case" variation) approach indicated that "the resulting increases in air quality are small relative to other factors (i.e., weather)"). [EPA-HQ-OAR-2009-0491-2756.1, pp.92-93]
UARG commends EPA for conducting this analysis and agrees in broad terms that this analysis demonstrates that interstate trading can play a valuable role in reducing emissions without decreasing downwind air quality. However, it is not apparent, and EPA does not explain, why it chose to perform this analysis using only a variability limit of 10 percent of the state budgets. EPA should perform the analysis using higher variability limits, in the range of at least 20 to 30 percent of each state's budget. If these analyses also indicate that the impact of upwind emissions variability on downwind air quality remains small, higher variability limits would be justified. [EPA-HQ-OAR-2009-0491-2756.1, p.93]
UARG strongly urges EPA to consider increasing the variability limit. A higher variability limit would encourage emission trading and increased emission reductions at sources where they are most cost-effective to achieve (thus lowering the overall cost of compliance with the program), while still ensuring that substantial emission control levels are maintained within each state. In fact, an analysis conducted by Southern Company and described in its comments on the Proposed Transport Rule indicates that even unrestricted interstate emission trading could yield air quality that is substantially the same as if trading were not allowed under the proposal. [EPA-HQ-OAR-2009-0491-2756.1, p.93, this comment can also be found at section IV.F.2. of the comment summary]
Response: 
Thank you for your comments.
Organization: State of Delaware Department of Natural Resources & Environmental Control
Comment: 
State of Delaware Department of Natural Resources & Environmental Control
Delaware is also concerned with EPA's concept of providing 1-year and 3-year average variability mass emission provisions that could serve to allow upwind states to increase their emissions above the limit that EPA has calculated to be required to fully eliminate that state's significant contribution or interfere with maintenance in a downwind state. It is Delaware's understanding that EPA has considered the use of this variability concept in order to help address concerns regarding the variability in electric demand and to prevent impact on electric grid reliability. While Delaware understands the need to maintain grid reliability, it is Delaware's concern that under this scenario any given upwind state, or group of upwind states, could potentially emit on a routine basis at levels that exceed the values calculated by the EPA as needed to eliminate significant contribution and interference with maintenance in a downwind state. It is Delaware's opinion that the proposed variability concept be eliminated or revised such that any revision would preclude the potential for and upwind state or group of upwind states to significantly contribute to a downwind state's inability to comply with applicable NAAQS, or interfere with maintenance of that NAAQS. [EPA-HQ-OAR-2009-0491-2980.1, pp.4-5; This comment can also be found at section IV.F.1 of this comment summary]
Response: 
Thank you for your comments.
IV.G. How the Proposed Approach to Significant Contribution and Interference With Maintenance is Consistent With Judicial Opinions

Organization: American Electric Power
Comment: 
American Electric Power
The Analyses Supporting the Transport Rule do not Meet the Requirements of the Court Decision Requiring a Full Impact Analysis
EPA has failed to fully examine the impacts of the utility sources in a given state on downwind nonattainment areas. This is important since the control program embodied in the Proposed Transport Rule is solely focused on utility sources while the impacts on downwind areas are based on all sources in the state. When EPA developed the NOx SIP Call Rule in the late 1990's, the analysis performed did take into account all source categories and the rule regulated emissions from all source categories. Further, the states were given some discretion in how the final budgets were distributed to sources, so long as the overall budget was met. [EPA-HQ-OAR-2009-0491-2665.1, pp.13-14]
In the Proposed Transport Rule, EPA assumes that a single source category is capable of resolving a state's contribution to downwind nonattaimnent and maintenance, and should exclusively bear the entire burden of mitigating that impact, even though it has used all source sectors to determine impacts. Making a single source category effectively responsible for resolving the downwind significant transport contribution is fundamentally unfair and technically flawed as shown using data developed by both EPA and the Midwest Ozone Group (as described above). In addition, MOG modeling also demonstrates that the trading program embodied in the existing CAIR program, with a complete and proper technical analysis, can cure the defects in the record found by the D.C. Circuit in the North Carolina case. [EPA-HQ-OAR-2009-0491-2665.1, p.14]
Response: 
EPA disagrees with the commenter's assertion that the analyses supporting the Transport Rule are inconsistent with the decision of the D.C. Circuit in North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008).  As explained in the preamble, EPA developed the Transport Rule to respond to and be consistent with the decision of the D.C. Circuit in North Carolina.  EPA believes that the Transport Rule and the analyses supporting it are fully consistent with the statutory mandate of section 110(a)(2)(D)(i)(I) as interpreted by the court. 
EPA also notes that the comment is premised on the incorrect assumption that, under the Transport Rule, a single source category is made responsible for resolving significant contribution to nonattainment and interference with maintenance that comes from other source categories.  This is not true.  As explained in detail in the preamble to the final rule, EPA's significant contribution analysis is a two part analysis.  In the first part, EPA looks to whether all emissions from a specific state contribute above a threshold amount to downwind nonattainment and maintenance receptors.  In this first step, EPA does consider emissions from all source categories.  However, a determination that the state's emissions exceed the thresholds identified in the rule at specific downwind receptors only means that the state is found "linked" to those receptors and therefore EPA must proceed to the second step to determine what portion, if any, of the state's total contribution is its significant contribution.  In this second step, EPA quantifies the emission reductions available from EGUs at specific cost thresholds.  EPA's analysis in this step only considers EGU emissions because, as explained in section VI of the preamble, EPA verified that there are little or no reductions available from non-EGUs at costs lower than the thresholds used in the final rule. Thus, when quantifying the state's significant contribution, EPA considers only emissions from the source category -- EGUs -- that offered broadly available cost-effective emission reductions at the cost thresholds at which EPA identified the necessary emission reductions in each state.  Further, EPA notes that states retain the discretion to submit to EPA a State Implementation Plan that may use a different regulatory mechanism or regulate different sources in order to prohibit emissions within the state that significantly contribute to nonattainment or interfere with maintenance of the relevant NAAQS in another state.
Finally, EPA disagrees with the commenter's assertion that the trading program as embodied in the existing CAIR program could, with no changes other than changes to the technical analysis supporting the program, cure the defects found by the D.C. Circuit in the North Carolina case.  EPA believes the Transport Rule as finalized is fully consistent with the statutory mandate of section 110(a)(2)(D)(i)(I) as interpreted by the D.C. Circuit.

IV.H. Alternative Approaches for Significant Contribution and Maintenance That EPA Evaluated

Organization: Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
Comment: 
Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
E. EPA Should have Evaluated Costs in Terms of the Cost per Unit of Reduction in Ambient Concentration in Nonattainment and Maintenance Areas, and not Cost per Ton of Reduced Emissions at the Source
EPA states, at 75 Fed. Reg. 45,299, that it considered, but rejected, a methodology for quantifying significant contributing emissions that would have assigned costs based upon cost per unit of air quality improvement (cost per ug/m3 or ppm) rather than cost per ton of emission reduction. No explanation is offered as to why this legally and logically preferable approach was not employed, even though it appears from the discussion of the cost/ton approach that EPA had available to it all modeling and analytical tools necessary to conduct such an analysis. EPA chose the units of the NAAQS when they are created, and this choice became the metric for attainment and maintenance required by SIPs or FIPs. If there was a direct correlation between the weight (tons) of emissions per 8 hours, or 24 hours, or per year (the time intervals relevant to the ozone and PM 2.5 NAAQS that the Transport Rule requirements are purportedly designed to attain and maintain), there would be no need for air quality models. EPA uses, and insists that the states use, air quality models to demonstrate the adequacy and appropriateness of their SIP or FIP attainment demonstration strategies. Having made the choice of units in setting the NAAQS, EPA cannot rationally or reasonably ignore those units in promulgating or approving implementation plans to achieve them. [EPA-HQ-OAR-2009-0491-2803.1, p.13]
Cost per ton of emission reduction is an approach that is ill-suited to development of a transport rule. The effect of removing a ton of emissions from a specific source on downwind air quality depends upon a number of factors, especially the distance of the source from the downwind nonattainment or maintenance area. Thus, for a distant source, far more tons of emissions must be removed to have the same effect of reducing the ambient air concentration of a pollutant as compared to a source closer to the impacted area, or, more importantly, sources located within the area. Thus, a more accurate and rational approach, consistent with the requirements of the Clean Air Act, is to determine the cost that a source must incur to produce a given unit of improvement of air quality in the impacted downwind area, rather than the cost per ton of removal, and to employ that cost in the determination of 'significance' for regulatory purposes. [EPA-HQ-OAR-2009-0491-2803.1, p.14]
Utilization of this preferable approach would allow EPA to more accurately assess the degree to which upwind sources are being required to incur high costs to achieve miniscule air quality improvement that sources located within the impacted area could achieve at far lesser cost, and thus avoid placing an unfair burden on distant upwind sources that is more equitably, and less expensively, borne by local sources. [EPA-HQ-OAR-2009-0491-2803.1, p.14]
Although the chosen methodology involves consideration of air quality impact of various emission scenarios, the use of cost/ton as an input into the evaluation rather than cost per ug/m3 (or cost per ppb) is a flawed approach. EPA should either employ the cost per ug/m3 in a reevaluation of the proposed rule, or solicit public comment on a detailed explanation of why that approach was not employed. [EPA-HQ-OAR-2009-0491-2803.1, p.14]
Response: 
In section VI of the preamble (as well as in other sections of the preamble), EPA describes the approach to define significant contribution and interference with maintenance.  In sections VI.A, VI.D and VI.G of the preamble, EPA describes its rationale for using both cost and air quality factors and its justification for using a uniform cost. 
EPA notes that in the proposed Transport Rule, EPA extensively discusses its assessment of two cost/air quality improvement methodologies in the Technical Support Document for the proposed Transport Rule, called "Alternative Significant Contribution Approaches Evaluated".  The commenter suggests an approach similar to the "first" approach EPA outlined.  In the comment, the commenter does not address the deficiencies EPA identified in the cost per air quality approach described by EPA (and repeated by the commenter).  These included, but were not limited to, requirements of "extremely high level of accuracy in both the emissions modeling...and the air quality modeling" and that "finer-scale emissions data from all sectors....and fine-scale air quality modeling could be needed to resolve differences in cost per air quality impact.." and that "these data and modeling techniques do not exist and/or are too computationally demanding to be operationally implemented".  A second challenge for this approach was to identify a single reduction requirement for a particular upwind state, since the reduction requirements relevant to different downwind receptors would vary significantly.  The commenter did not provide any suggestions as to how EPA would overcome these challenges that prevented the Agency from constructing a rulemaking on this basis.

V.A. Covered Pollutants (SO2 and NOx for PM2.5 and Ozone Season NOx for Ozone)

Organization: Adirondack Council
Comment: 
Adirondack Council
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.62.]
We support strong nitrogen emission reduction on a year-round basis.
Response: 
For states included for PM2.5 under the rule, year-round NOx emissions reductions are required.
Organization: Central Illinois Global Warming Solutions Group
Comment: 
Central Illinois Global Warming Solutions Group
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.124.]
That is the only fault I can find with the Rule. I think that you really need to factor in not just criteria, but all pollutants that are affecting the area to have an understanding in the modeling of the overall burden on communities.
Response: 
This rule is designed to address interstate transport of upwind state contributions to ozone and PM2.5 in other states.   Accordingly, it is not designed to assess the overall burden across the spectrum pollutants on communities.
Organization: Group Against Smog and Pollution (GASP)
Comment: 
Group Against Smog and Pollution (GASP)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.194.]
EPA should also explore the feasibility of establishing caps on ammonia and VOCs, or at least subset of the most reactive VOCs.
Response: 
See preamble discussion in section V.A.2 regarding EPA's choice of regulated pollutants. 
In addition, EPA extensively discussed its rationale for not including ammonia and VOCs in the CAIR rule.   See discussion of PM2.5 precursors for CAIR 70 FR 25181, May 12, 2005;   see discussion of ozone precursors for CAIR40 FR 25185, May 12, 2005.    This same rationale is appropriate for this Transport Rule.  
Organization: Southeastern States Air Resource Managers (SESARM)
Comment: 
Southeastern States Air Resource Managers (SESARM)
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.43.]
Number one, further control of NOx and SO2 emissions will be necessary for our region to meet federal standards and regulations issued under the authority of the Clean Air Act.
Response: 
EPA agrees.  

V.B. [Reserved]

V.C. Timing of Proposed Emissions Reductions Requirements (Compliance Deadlines)

Organization: Adirondack Mountain Club
Comment: 
Adirondack Mountain Club
While we do applaud any effort to reduce emissions of harmful pollutants, the Clean Air Interstate Rule significantly slowed the country's progress to bring all areas into attainment. Reduction requirements came too late and were not deep enough to meet existing Clean Air Act deadlines. Full-attainment may have been reached through the faithful implementation and enforcement of the existing Clean Air Act, which would allow an SO2 cap of 2 million tons by 2012 and NOX cap of 1.25 million tons by 2010. Thus, ADK is pleased to support CATR's rule which have a much larger reduction at a sooner date. [EPA-HQ-OAR-2009-0491-2761, p.3]
Response: 
EPA appreciates the support for the proposed rule.
Organization: American Clean Skies Foundation (ACSF)
Comment: 
American Clean Skies Foundation (ACSF)
In addition to supporting the overall goals of CATR, ACSF also supports the timing of CATR's emission caps, under which initial SO2 and NOx limits take effect in 2012, and SO2 caps are tightened in 2014 in certain states that have larger downwind impacts. These timelines allow the prompt achievement of this rule's important public health benefits. [EPA-HQ-OAR-2009-0491-2759.1, p.2]
Response: 
EPA agrees with these comments supporting the compliance period in the Transport Rule.
Organization: American Electric Power
Comment: 
American Electric Power
AEP believes it is particularly important for our company to comment on the relative merits and concerns with various portions of the Proposed Transport Rule. Unfortunately, EPA's Transport Rule as currently written does not appropriately balance environmental and economic objectives. While we commend EPA for retaining some of the flexibility of intrastate and regional emissions trading of SO2 and NOx, the timing of the reduction requirements, the relative inflexibility of other provisions of the rule, and the stringency of the emission reductions, particularly as it applies to SO2, would substantially increase the cost of compliance and could likely have significant adverse impacts on reliability and the regional economy. [EPA-HQ-OAR-2009-0491-2665.1, pp.2-3]
AEP does not believe that the timelines and stringent budgets within this Proposed Transport Rule are necessary. The modeling data developed by the Midwest Ozone Group (MOG) and its Industrial Modeling Coalition used in conjunction with ambient air quality data collected by USEP A show that not only are transport criteria met by the existing CAIR program, but full compliance with the NAAQS targeted by this rulemaking are satisfied for all be a few areas that have ambient concentrations driven by local sources. [EPA-HQ-OAR-2009-0491-2665.1, p.3]
We believe that EPA should address the specific issues identified by the D.C. Circuit in the North Carolina case, while keeping the timing and reductions the same as is defined in CAIR. [EPA-HQ-OAR-2009-0491-2665.1, p.3] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.9]
The 2012 program start date is a major issue for compliance entities as it is anticipated there will be only six to eight months after final rule promulgation until the start of the compliance period. This is not enough time to set up the requisite allowance trading system to accompany the rule. This will create considerable uncertainty as to how the allowance market will function for compliance purposes and lead to excessive speculation and turmoil. [EPA-HQ-OAR-2009-0491-2665.1, p.5]
The Proposed Transport Rule does not result in ozone or PM-2.5 NAAQS attainment and maintenance benefits by 2015 beyond those assured by the existing CAIR program. [EPA-HQ-OAR-2009-0491-2665.1, p.25]
For all of these reasons and the additional reasons detailed in the comments, EPA should limit the current rulemaking to providing enhanced technical support for the current CAIR provisions as amended to include narrow corrections specifically required by the North Carolina decision, and otherwise continue to rely upon the current CAIR program budgets, deadlines, trading, and banking until 2015. EPA should address the post-2015 period in a revised proposal that takes into account the states' primacy for SIP formulation, and that takes into account the transport implications of EPA's new ozone and PM-2.5 NAAQS revisions and utility HAP rules, at a minimum. [EPA-HQ-OAR-2009-0491-2665.1, p.26] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.9]
Response: 
See discussion in preamble section VI for EPA's methodology and technical approach to identifying the emissions reductions required by the Transport Rule.
See discussion in preamble section VII.C on EPA's rationale for the compliance deadlines.
Regarding suggestion to leave CAIR in place until 2015, see discussion in preamble section IV.C.2.
 
Organization: American Lung Association of the Upper Midwest
Comment: 
American Lung Association of the Upper Midwest
[These comments were submitted as testimony at the Chicago, Illinois hearing.  See Docket Number EPA-HQ-OAR-0491-1746, p.14.]
Secondly, we have some concern that the City of Chicago will not meet the fine particulate standards by 2014, even with the implementation of this proposed rule.
If the U.S. EPA's aware of this situation, and if expectations prove to be true, we urge U.S. EPA to take the proactive steps right now to address the air quality concerns rather than wait for 2014.
Response: 
See preamble section VII.C.1 for discussion of EPA's selection of the 2012 and 2014 deadlines, and the relationship to attainment deadlines for PM2.5 and ozone.   
    
Organization: Attorney General of North Carolina
Stuckey, Richard
Comment: 
Attorney General of North Carolina
EPA's concerns appear to be focused on emissions in 2010 and 2011. 75 Fed. Reg. at 45,339/1-3. 2010 is three months from completion, with the ozone season already having ended. The Transport FIP will not even be finalized until the spring of 2011 at the earliest. There is little or nothing that the proposed Transport FIP can do now to influence 2010 emissions. If EPA concludes that the law requires that emissions be limited during the period of 2011 that remains after the Transport FIP is finalized, it can promulgate and implement partial year budgets or directly require that sources continuously operate existing controls (SCRs, scrubbers, low NOX burners, low sulfur fuel, etc.) at covered units for the remainder of 2010 until the budget program begins. What EPA cannot do is allow States in 2012 or thereafter to avoid their statutory obligations. [EPA-HQ-OAR-2009-0491-2685.1]
Stuckey, Richard
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.69-70.]
And, also, the most aggressive schedule, which I think you've already heard, attempts to procrastinate and to delay the schedule. I think that is the wrong thing to do. We need to do this as fast as possible because the benefits are so huge and the population is growing older and much more susceptible to the dangers of pollution than it has been in the past.
The costs are going up every day we delay and procrastinate in implementing these rules. And, unfortunately, the power industry, with maybe some exceptions you heard today, has a long track record of procrastination and avoiding implementation of these Clean Air laws.
Response: 
These commenters both suggest accelerating the compliance deadlines in the proposed Transport Rule.   EPA believes that the 2012 and 2014 deadlines provide for emissions reductions as expeditiously as practicable.
Organization: Council of Industrial Boiler Owners (CIBO)
Comment: 
Council of Industrial Boiler Owners (CIBO)
While EGUs are not covered by the Industrial Boiler MACT, CIBO is concerned that the implementation timelines for both the Industrial Boiler MACT and the Clean Air Transport Rule will occur at approximately the same time (2011-2013). CIBO points out that in addition to these two rules, the new National Ambient Air Quality Standards for Ozone, NO2 and SO2; Regional Haze SIPs; and the forthcoming Utility Boiler MACT will all impact the marketplace at approximately the same time. The combined effects of these rules will dramatically increase the demand for engineering labor, construction labor and fabrication shop space. This will have the effect of dramatically tightening the pollution control market, which will most likely result in significant cost increases and lengthened delivery and installation schedules. These negative outcomes will impact both EGUs and non- EGUs alike. While many EGUs operate in regulated markets and can pass their costs on to consumers, CIBO member companies are not guaranteed a mechanism to recover escalating costs. This could have a significant negative impact on many CIBO member companies, and could force marginal plants to seriously consider shutting down operations. CIBO urges EPA to consider extending the compliance timeframe for the Transport Rule to at least 2017 to minimize the negative economic impact to non- EGUs. [EPA-HQ-OAR-2009-0491-2751.1, p. 12]
Response: 
Sections VI and VII of the preamble to the final rule explain the compliance deadlines used in the rule.  Further, this rule does not directly regulate industrial boilers. EPA is conducting a separate notice and comment rulemaking for the Industrial Boiler MACT. 
Organization: Entergy Services, Inc.
Comment: 
Entergy Services, Inc.
Entergy would also like to comment on the complications associated with the proposed compliance dates of January 1, 2012 for Phase I and January 2, 2014 for Phase II of the rule.  For the reasons stated below Entergy cannot support a compliance date of January 1, 2012 unless the inequities of the allowance allocations to Entergy units caused by the use of the Integrated Planning Model are corrected. [EPA-HQ-OAR-2009-0491-2847.1,p.6]
Response: 
See discussion in preamble section VII.C regarding compliance deadlines. 
EPA has revised the method for allowances allocations for the final Transport Rule, as is discussed in detail in preamble section VII.D.
Organization: EquiPower Resources Corp.
Comment: 
EquiPower Resources Corp.
First, EquiPower encourages EPA to establish Phase I budgets and unit-level allocations that reflect emissions reductions that can actually be achieved. The Transport Rule assumes that compliance with the 2012 cap will only require affected EGUs to (i) operate existing emissions controls year-round, and/or (ii) complete the installation of proposed controls that are scheduled to be online by 2012. But these assumptions are not technically feasible because as explained above, they are premised on the erroneous assumptions. As a result, EPA has overestimated the level of control that can actually be obtained by 2012, and therefore has imposed state-wide Phase I emissions caps, and by extension unit level allocations, that are too restrictive. [EPA-HQ-OAR-2009-0491-2704.1, p.27]
For example, by assuming that existing controls can achieve very low emission levels (levels that EquiPower is not even sure are obtainable on an operational basis using new equipment, let alone older equipment) and allocating allowances on that basis, the Transport Rule effectively penalizes facilities that installed emission controls early. If Transport Rule had in fact been structured such that compliance with the 2012 cap only required sources to operate existing controls, then state and unit level allocations would have been higher then currently proposed. Thus, EquiPower believes that EPA should increase the Phase I compliance caps based on more realistic assumptions about the level of control that can be achieved. At a minimum, all sources with existing controls should have sufficient allocations to cover their emissions. In the alternative, EPA should amend the Proposed Rule to permit affected sources to use previously banked CAIR emissions allowances to comply with Phase I emission caps. [EPA-HQ-OAR-2009-0491-2704.1, p.28]
Response: 
See discussion in preamble section VII.C regarding compliance deadlines. 
EPA has revised the method for allowances allocations for the final Transport Rule, as is discussed in detail in preamble section VII.D.
Organization: Indiana Manufacturers Association, Inc. (IMA)
Griffin Pipe Products, Inc.
Lakeland Electric
San Miguel Electric Cooperative, Inc.
Cleco Corporation
PPG Industries, Inc.
Old Dominion Electric Cooperative
Manitowoc Public Utilities (MPU)
National Mining Association (NMA)
Missouri Public Utilities Alliance (MPUA)
Midwest Ozone Group
American Municipal Power, Inc. (AMP)
ARIPPA
Consumers Energy
DTE Energy
American Public Power Association (APPA)
Edison Electric Institute (EEI)
Buckeye Power, Inc.
DoubleTree Hotel Roanoke and Conference Center
Ameren Services Company
Duke Energy
Empire District Electric Company (Empire District)
Florida Municipal Electric Association (FMEA)
International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers and Helpers (AFL-CIO Boilermakers Union)
Michigan Department of Natural Resources and Environment
PPL Corporation
Progress Energy Service Company
Santee Cooper
Southern IL Power Cooperative
Utility Air Regulatory Group (UARG)
National Rural Electric Cooperative Association (NRECA)
Pfeiff, Mike
Texas Mining and Reclamation Association
Edison Mission Energy (EME)
Tampa Electric Company
Comment: 
Ameren Services Company
EPA should abandon this rule making and allow CAIR to continue until a supportable rule can be developed [EPA-HQ-OAR-2009-0491-2722.1, p.11]
Under the D.C. Circuit court decision that ultimately remanded CAIR to EPA no deadline to replace CAIR was mandated. [EPA-HQ-OAR-2009-0491-2722.1, p.26] 
American Municipal Power, Inc. (AMP)
Additionally, EPA's expeditious timelines are unnecessary given the current effectiveness of the CAIR program. [EPA-HQ-OAR-2009-0491-2678.1, p.2]
American Public Power Association (APPA)
3. While APPA appreciates the many conference calls or webinars that were convened by the U.S. EPA, we do not believe that the deadlines are realistic. APPA believes that the PTR should not consider any compliance date earlier than 2015. [EPA-HQ-OAR-2009-0491-2812.1, p.3]
Moreover, despite EPA`s suggestions to the contrary, promulgation of compliance dates later than those that EPA proposes would not result in increased emissions. CAIR would remain in place and would continue to maintain a strong and effective program of emission reductions pending the initial compliance deadline for the Transport Rule. [EPA-HQ-OAR-2009-0491-2812.1, pp.19-20] 
ARIPPA
The states and EGUs affected by the Proposed Rule should not be penalized as a result of the delay in the regulatory development process associated with the Court's vacatur of CAIR. Further, the continued emission reductions mandated by CAIR would mitigate any adverse impacts associated with the postponement of the implementation of the Transport Rule. Indeed, the application of CAIR would result in greater NOx emission reductions than the Proposed Rule. [EPA-HQ-OAR-2009-0491-2794.1, p.19]
Buckeye Power, Inc.
For all of the foregoing reasons, Buckeye Power urges EPA to withdraw its proposed CATR program. If it does proceed, EPA should (8) extend the timeline for implementation of CATR. [EPA-HQ-OAR-2009-0491-2710.1, p.13]
Cleco Corporation
There is no reason for EPA to require a 2012 compliance deadline. The D.C. Circuit did not mandate any particular compliance schedule and certainly did not mandate a compliance schedule so compressed that there are few if any compliance options. In fact, EPA requested and received reconsideration by the D.C. Circuit to keep CAIR in place to ensure continued emission reductions under that program while EPA took the time needed to address CAIR's flaws. EPA has taken two years to develop this proposed rule and proposes to take another nine months to finalize it. At the same time, it eliminates time for public comment and time on the back end for state SIP development and compliance planning. Based on a comparison of the CAIR budgets to the proposed 2012 emission budgets under the Transport Rule, CAIR would achieve very similar emission reductions in the near term and enable EPA to take the additional time required for implementation and compliance. Put simply, because EPA prevailed on reconsideration, CAIR is in place, and EPA can take the time needed to implement its replacement. [EPA-HQ-OAR-2009-0491-2859.1 p.3] [[The comment on the state SIP development can also be found in Section VII.C.]]
Consumers Energy
EPA has neither a statutory nor court ordered deadline to complete this specific rulemaking. Yet EPA proposes a schedule that is much more ambitious than the schedule for CAIR, which remains in effect, and serves as the basis for planning by the electric utility industry and the states. [EPA-HQ-OAR-2009-0491-2837.1, p.3]
DoubleTree Hotel Roanoke and Conference Center
As a commercial customer of American Electric Power in Roanoke Valley of VA. I would like to express my sincere concern with the proposed Transport Rule. As a representative of the Hotel Roanoke and Conference Center and a concerned citizen of the communities of Va., I have serious concerns and objections with this upcoming proposal! The rule does not provide enough time for the states to develop their own implementation plans and there is not adequate time built in to the proposal to install new and improved equipment, as necessary, to meet the 2014 emission deadlines without huge financial impacts for customers. [EPA-HQ-OAR-2009-0491-2142, p.1]
DTE Energy
The proposed Transport Rule establishes new reduction requirements that must be met only 6- 12 and 30 months after the final Transport Rule is issued. By contrast, the Phase 1 deadlines for the Clean Air Interstate Rule (CAIR) allowed almost 5 years from promulgation of the final rule until the first compliance year for 502 and almost 4 years for NOx. Last year, the Lake Michigan Air Directors Consortium (LADCO) recommended that any CAIR replacement rule include an initial compliance date no earlier than 2017. [EPA-HQ-OAR-2009-0491-2851.1,p.5]
Duke Energy
Moreover, despite EPA's suggestions to the contrary, promulgation of compliance dates later than those that EPA proposes would not result in increased emissions. CAIR could remain in place and would continue to maintain a strong and effective program of emission reductions pending the initial compliance deadline for the Transport Rule. [EPA-HQ-OAR-2009-0491-2689.1, p.1]
The compliance dates required by whatever rule EPA finalizes should be informed by the stringency of the emission reduction requirements, the date of EPA's promulgation of the rule, and a realistic assessment of the amount of time required to retrofit controls on coal-fired power plants. [EPA-HQ-OAR-2009-0491-2689.1, p.62]
Edison Electric Institute (EEI)
The proposed Transport Rule establishes new reduction requirements that must be met in two phases, 6-12 and 30 months after the final Transport Rule is scheduled to be issued. By contrast, the Phase 1 deadlines for the Clean Air Interstate Rule (CAIR) allowed almost 5 years from promulgation of the final rule until the first compliance year for SO2 and almost 4 years for NOx. Under CAIR, Phase 2 requirements were not imposed until 10 years after promulgation of the final rule. [EPA-HQ-OAR-2009-0491-2697.1, p.8]
The Lake Michigan Air Directors Consortium (LADCO) in a September 10, 2009 letter to EPA, recommended that any CAIR replacement rule include an initial compliance date via regional emission caps no earlier than 2017, and stated that further selective catalytic reduction (SCR) and FGD installations (beyond CAIR Phase 1 controls) could not feasibly be required before 2017. In contrast, a September 10, 2009 letter to EPA from the (Northeast) Ozone Transport Commission (OTC) suggested earlier emission control actions, including "low capital cost NOx controls" to be required by 2015, including selective non-catalytic reduction (SNCR), and that "EPA analyze and determine the state-by-state reductions needed prior to 2017" to address transport. The OTC letter also supported implementing regional trading for SO2 and NOx "as early as possible" (by 2014) to "drive deeper...reductions" than those from statewide caps. [EPA-HQ-OAR-2009-0491-2697.1, pp.8-9]
Edison Mission Energy (EME)
Footnote 50: Increasing the Phase I cap would not be inconsistent with the Agency's overall approach because the Phase I compliance period was never intended to fully meet the § 110(a)(2)(D) goals. 75 Fed. Reg. at 45215. [EPA-HQ-OAR-2009-0491-2707.1, p.22]
Empire District Electric Company (Empire District)
We also recommend that a solution to this problem would be for EPA retain phase 1 of CAIR until 2014 or 2015 and replace CAIR with CATR at that time.  For the years 2012 and 2013, EPA can amend CAIR to meet the requirements of the remand from the US Court of Appeals for the District of Columbia Circuit on 12/23/2008. [EPA-HQ-OAR-2009-0491-2659.1, p.2]
Florida Municipal Electric Association (FMEA)
Accordingly, EPA should leave CAIR in place through Phase I, which should allow sufficient time to develop a more accurate, complete and defensible rule. [EPA-HQ-OAR-2009-0491-2731.1, p. 6]
Griffin Pipe Products, Inc.
The EPA should delay the Transport Rule until it sees the latest modeling based on CAIR compliance. At the least, the EPA should extend the compliance deadline to allow companies time to install the needed retrofits and to allow states to develop their own implementation plans. [EPA-HQ-OAR-2009-0491-2600, p.1] [[These comments can also be found in Section VII.C.]]
Indiana Manufacturers Association, Inc. (IMA)
This error underestimates the cost of compliance and exacerbates another inaccuracy in the EPA's compliance assumptions  -  the time and cost needed to design, permit, fabricate and install control equipment. [EPA-HQ-OAR-2009-0491-1813.1, p. 1]
Under the existing proposal, there is not enough time for power generators to design, permit, fabricate and install pollution control equipment to comply with the new emissions levels established in the rule's second phase. [EPA-HQ-OAR-2009-0491-1813.1, p. 1]
The most significant reductions under the current proposal occur in 2014  -  only two-and-a-half years after the Rule is expected to become effective. Two-and-a-half years are not enough to design, permit, fabricate and install the necessary equipment. This unrealistic deadline could affect grid reliability if power companies are forced to prematurely close generation units to comply. If new scrubber byproduct storage facilities are needed in addition to emissions control equipment, the time line becomes much longer. [EPA-HQ-OAR-2009-0491-1813.1, p. 2]
We applaud the EPA's efforts to improve air quality for all Americans and to address downwind issues. However, we believe the EPA's actions are premature and do not allow enough time for state participation or for industry compliance. Hasty action will have economic consequences for my citizens without any assurance that the rule will deliver the desired results any faster than the nation can achieve on its current path. We urge the EPA to delay the Transport Rule until there is a clear indication that comparable results cannot be achieved through CAIR. The EPA also should establish realistic deadlines that will not punish electricity consumers. [EPA-HQ-OAR-2009-0491-1813.1, p. 3]
International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers and Helpers (AFL-CIO Boilermakers Union)
A. EPA's proposed 2012 annual SO2 and NO, emissions reduction deadline is unrealistic and unnecessary to meet the objectives of the Clean Air Act. [EPA-HQ-OAR-2009-0491-2672.1, pp.3-4]
As noted above, EPA's 2015 deadline for CAIR was rejected in North Carolina because it was established without any regard for CAA attainment deadlines (or other substantive requirements of Title I of the CAA). If EPA allowed EGUs to prepare for compliance and state permitting authorities the opportunity to revise and submit compliant SIPs (as is Congress' clear preference) the Transport Rule could still achieve 'something measurable" towards assisting downwind states in meeting the earlier attainment deadlines, and would probably have no impact on the achievement of the later attainment deadlines. Our recommended deferral period is therefore consistent with North Carolina while striking an appropriate balance between the attainment deadlines of the CAA, feasibility considerations, and the policy of cooperative federalism. [EPA-HQ-OAR-2009-0491-2672.1, p.10] [[These comments can also be found in Section VII.C.]]
Lakeland Electric
EPA's Transport Rule as proposed has an effective compliance start date of January 1, 2012. The Transport Rule may not be final until Summer 2011, leaving regulated entities approximately six months from final rule publication until the effective date. During the rule development process EPA will embark on over the next year, EPA plans on proposing a new Ozone NAAQS somewhere between 60-70 ppb. Once this new Ozone NAAQS has been proposed, EPA is planning on updating the Transport Rule with a sequential rule which has been labeled "CAIR III" which will incorporate the new Ozone NAAQS. [EPA-HQ-OAR-2009-0491-2630.1,p.5]
EPA, by postponing implementation of the Transport Rule until at least 2014, will provide many benefits. This postponement will allow EPA the time which is needed in order to incorporate the new Ozone NAAQS. It will also give regulated CAIR I entities time to utilize their banked allowances, and will help avoid any Constitutional "Takings" arguments made by utilities which have experienced an economic loss by means of the Transport Rule. This additional time will also allow for additional review and comment periods by regulated industry to assist EPA in developing a more accurate regulation. As EPA is aware, EPA is not under any court order to finalize a rule by 2012, and so Lakeland Electric finds this time extension proposal a logical appeal. Therefore, EPA should postpone any compliance measures required under the Transport Rule until 2014. [EPA-HQ-OAR-2009-0491-2630.1,pp.5-6]
Manitowoc Public Utilities (MPU)
 The Proposed Transport Rule should not include an initial compliance deadline of 2012. CAIR could remain in place and would continue to maintain a strong and effective program of emission reductions while allowing the initial compliance deadline for the Proposed Transport Rule to have a reasonable compliance implementation schedule.  [EPA-HQ-OAR-2009-0491-2860.1, p.2] 
2012 Compliance Deadline  
The Proposed Transport Rule should not include an initial compliance deadline of 2012. It is unreasonable and unrealistic to expect emission reductions required by the Proposed Transport Rule to be achieved by January 1, 2012, barely six months after the date on which EPA expects to issue the final rule. Utilities are currently facing a number of new/revised EPA rules that interact with each other and final implications are not known at this time. Municipal utilities have very limited financial and manpower resources and must make decisions to address all of these issues that are protective of our rate payers and feasible to implement with our very limited resources. CAIR could remain in place and would continue to maintain a strong and effective program of emission reductions pending the initial compliance deadline for the Transport Rule. [EPA-HQ-OAR-2009-0491-2860.1, p.4]
Michigan Department of Natural Resources and Environment
Under CAIR, Michigan and most other states implemented rules that created a tiered or phased approach to the reductions. CAIR Phase One began in 2009 and Phase Two begins in 2015. To avoid unnecessary confusion, the timing of the first phase of the TR should at least coincide with the original CAIR Phase Two, I.e., 2015 versus 2014. [EPA-HQ-OAR-2009-0491-2774.1 p.3]
Midwest Ozone Group
Reliance on existing controls is not inconsistent with the D.C. Circuit's decision in NC v. EPA. [EPA-HQ-OAR-2009-0491-2809.1, p.13]
The continuation of CAIR controls is not inconsistent with the D.C. Circuit's decision in NC v. EPA. Indeed, the D.C. Circuit expressly allowed for the continuation of CAIR control spending EPA's replacement of the CAIR. NC v. EPA, 550 F.3d 1176, 1178 (D.C. Cir. 2008)("Here, we are convinced that, notwithstanding the relative flaws of CAIR, allowing CAIR to remain in effect until it is replaced by a rule consistent with our opinion would at least temporarily preserve the environmental values covered by CAIR. Accordingly, a remand without vacatur is appropriate in this case."). Further, it is undisputed that the 2010 attainment date that the D.C. Circuit focused on in its 2008 decisions has passed, and recent air quality data demonstrates that the transport issue that the CAIR sought to address is fast becoming moot. [EPA-HQ-OAR-2009-0491-2809.1, p.13]
Missouri Public Utilities Alliance (MPUA)
EPA has failed throughout the rule to verbalize or justify the necessity of implementing the rule at the outset of 2012. The deadline, coupled with the prohibition on use of previously issued emission allowances fails to allow some utilities to fully amortize the investments they had made in current pollution control equipment that was to have been paid for with credits to have been issued in the future.  We request that the deadlines be shifted to at least 2015 to allow the federal and state regulatory agencies the time necessary to make the administrative and regulatory changes, including guidance documents, necessary to administer this rule in a consistent manner. [EPA-HQ-OAR-2009-0491-2785.1, p.2]
In the alternative one solution may be to initiate the rule in 2012, but provide for less stringent controls for the first 3-5 years to give industry the time to develop strategies and financing to make the necessary investment. [EPA-HQ-OAR-2009-0491-2785.1, p.2]
3. Because of the short time span on which the current rule is predicated, electric utilities will be forced to seriously consider fuel switching as one option, especially if their generators were constructed to operate on dual fuel (coal and natural gas).  This modification can be done more quickly than installation of other control systems and in a way that significantly reduces emissions during a transition period.  Additionally as utilities evaluate the cost/benefits of various upgrades to meet the necessary emission limits, a switch from coal to natural gas which may require lower investments in control technology would be considered by utility managers. [EPA-HQ-OAR-2009-0491-2785.1, p.2]
The challenge is that studies in which MJMEUC has participated, demonstrate that widespread fuel switching can create additional complications both for electric utilities and for those individuals and industries using natural gas for process heat or as raw product materials.  Additionally MJMEUC cities have anecdotal experience of inability to acquire natural gas for supplemental power production during periods of extreme winter cold because of pipeline capacity is not available.  The study can be accessed at: http://www.appanet.org/files/PDFs/ImplicationsOfGreaterRelianceOnNGforElectricityGeneration.pdf [EPA-HQ-OAR-2009-0491-2785.1, p.2]
National Mining Association (NMA)
As discussed above, the feasibility of the 2012 and 2014 emission reductions required by the proposed rule are assumption and model driven -- if the assumptions are wrong, the feasibility of the whole program is in doubt and the economic cost the program will rise dramatically. EPA has left the public very little time to challenge (or even understand) these assumptions, and it has left almost no time between finalization of the rule and the 2012 compliance deadline for reconsideration of the rule if the assumptions prove to be faulty. Yet EPA already has in place a program that will lead to an acceleration of the emission reductions that the country has made in the last three decades. [EPA-HQ-OAR-2009-0491-2868.1,p.19]
National Rural Electric Cooperative Association (NRECA)
EPA, by postponing implementation of the Transport Rule until at least 2014, will provide many benefits. This postponement will allow EPA the time which is needed in order to incorporate the new Ozone NAAQS. It will also give regulated CAIR I entities time to utilize their banked allowances, and will help avoid any Constitutional "Takings" arguments made by utilities which have experienced an economic loss by means of the Transport Rule. This additional time will also allow for additional review and comment periods by regulated industry to assist EPA in developing a more accurate regulation. As EPA is aware, EPA is not under any court order to finalize a rule by 2012, and so Lakeland Electric finds this time extension proposal a logical appeal. Therefore, EPA should postpone any compliance measures required under the Transport Rule until 2014. [EPA-HQ-OAR-2009-0491-2630.1, pp.5-6]
Old Dominion Electric Cooperative
We find no reason that EPA needs to accelerate the processing of this rule. Further, there were no requirements in the North Carolina decisions to abolish CAIR and expedite this rule. EPA needs to justify why there is a need to accelerate this process. CAIR remains in place until this replacement rule is promulgated; therefore, this approach allows time to ensure this replacement rule addresses the courts comments and provides adequate time for the utilities to comply with the conditions of the rule. At a minimum ODEC recommends that CAIR remain in effect at least until 2013 to allow a reasonable time for utilities to meet requirements focused on demonstrating measurable or reasonable progress towards meeting Clean Air Act S 110(a)(2)(D)(i)(I) goals. [EPA-HQ-OAR-2009-0491-2877.1, p.3]
Pfeiff, Mike
However, as an actual market participant who has studied the EPA's process surrounding the development of this rule I can attest to the fact that from an administrative standpoint the implementation period is unrealistic. From an administrative perspective, I need only offer one example of why the implementation time line is unrealistic: CAIR was vacated by the DC Circuit Court of Appeals on July 11, 2008 and the quickest the EPA was able to officially offer a proposed replacement was August 2, 2010 and remarkably that replacement rule was predicated on base case data from 2005. [EPA-HQ-OAR-2009-0491-2742.1, pp.12-13]
Fortunately, when the DC Circuit Court remanded of its July 11, 2008 vacatur of CAIR, it did not order a firm deadline for which the EPA is obligated to promulgate a replacement rule. With emissions currently very low by all historical standards (likely due to ongoing fuel substitution from coal to natural gas) there is no practical reason to strive for a January 1, 2012 implementation. Instead of racing to implement a rule that is laden with opportunities for further judicial review, the EPA should take additional time to develop a rule that will be operational successful and preserves the values laid out by Congress in Title IV of the CAA. Even if an entity petitions the DC Circuit Court of Appeals to set a deadline, the EPA has a strong argument to justify the additional time since it can provide tangible evidence of measured progress. Further, many other commenter's have seemingly raised very good issues surrounding the assumptions in the EPA's modeling, that if sincerely addressed, would ultimately produce a better rule. Even though the EPA had previously indicated to the Court and Congress that it expected a replacement rule to take two years, the agency should not feel compelled to lock into this self prescribed timeline since there is a reasonable justification extending its implementation. [EPA-HQ-OAR-2009-0491-2742.1, p.13]
I request that the EPA delay the first compliance obligation period by a full year to January 1, 2013. [EPA-HQ-OAR-2009-0491-2742.1, p.13]
PPG Industries, Inc.
EPA has indicated a need for acting quickly on this rulemaking citing the courts desire to replace CAIR. PPG would like to remind EPA that there is not a court ordered deadline to finalize this rulemaking. EPA's reason for not allowing extensions, as posted on the website, cites the need to ?develop a final rule in time to obtain needed emissions reductions?. EPA does not need to rush this rule at the expense of defensibility in order to obtain needed emissions reductions. The court remand of the CAIR rule leaves CAIR and its associated emission reductions in place through the year 2014 while EPA is doing rulemaking on CATR. If EPA insists on forcing the CATR, PPG is concerned subsequent litigation will add further uncertainty to an already stressed business climate. This uncertainty could result in facilities postponing projects, therefore stifling economic and job growth. [EPA-HQ-OAR-2009-0491-2763.1, p. 18]
PPL Corporation
Since the rule will not be finalized until 2011, under the proposed schedule there would be less than a year for sources to make the necessary operational adjustments. This seems to be impractical; PPL recommends that the 2012 date be extended to 2013. This does not postpone addressing interstate transport because the Clean Air Interstate Rule (CAIR) is already place and will stay in place until replaced by the Transport Rule. [EPA-HQ-OAR-2009-0491-2739.1, p.9]
Progress Energy Service Company
EPA has not explained adequately why it proposes to require compliance beginning in 2012, particularly because the CAIR will remain in effect until the Transport Rule or similar program replaces it at an appropriate time. [EPA-HQ-OAR-2009-0491-2831.1 p.3]
San Miguel Electric Cooperative, Inc.
The 2012 deadline is in itself unnecessary and the 2014 deadline is premature.   [EPA-HQ-OAR-2009-0491-2641.1, p.6]
Santee Cooper
This implies extending the proposed Transport Rule's compliance deadlines from 2012 and 2014, to at least 2013 and 2015 respectively. Such a compliance deadline extension is consistent with past D.C. Circuit decisions, which have held that EPA must 'reset' deadlines in the Act in the event that necessary EPA policy guidance has not been provided in a timely manner. In Natural Resources Defense Council v. EPA, for example, the D.C. Circuit held that states should be permitted to submit vehicle inspection and maintenance standards after a deadline in the statute provided in the CAA, on the grounds that EPA delays in issuing necessary guidance had prevented states from meeting the statutory deadline. [EPA-HQ-OAR-2009-0491-2820.1, p.16]
In addition, nothing in the North Carolina decision bars an outer compliance deadline to 2015. Rather, the court held that EPA 'must decide what date, whether 2015 or earlier, is as expeditious as practicable for states to eliminate their significant contributions to downwind nonattaimnent.' For the reasons discussed above, the Agency should detennine that 2015 is the date that is 'as expeditions as practicable.' [EPA-HQ-OAR-2009-0491-2820.1, p.16]
Southern IL Power Cooperative
CAIR need not be replaced by 2012. There are no legal mandates to replace CAIR by a date certain, thus making the proposed 2012 CATR deadline unnecessary. [EPA-HQ-OAR-2009-0491-2863.1 p.2]
Tampa Electric Company
Although EPA proposes 2012 as the first year of the program, Tampa Electric encourages continuing the current Clean Air Interstate Rule through 2015. [EPA-HQ-OAR-2009-0491-2745.1 p.2]
Texas Mining and Reclamation Association
Overly complicated compliance deadlines and little advance notice of changing regulatory requirements is a recipe for disaster given the current economic conditions. Put simply, the regulated community needs as much advance notice and flexibility as possible in times like these when capital is hard to come by and sensitivity to increased residential and industrial utility bills is at its highest. While it may be cumbersome to match compliance dates on a state and federal level, EPA should at a minimum extend the compliance deadlines beyond 2012. [EPA-HQ-OAR-2009-0491-2734.1 p.2]
Utility Air Regulatory Group (UARG)
Nor did the court include in its opinion any mandate that the replacement rule for CAIR must include a compliance date in 2012 or within any period of time as short as six months after final rule promulgation. [EPA-HQ-OAR-2009-0491-2756.1, pp.20-21]
EPA should not adopt the 2012 compliance deadline in the Proposed Transport Rule and should not in any event consider any compliance date earlier than 2015. 15 In any event, if EPA promulgates a Transport Rule that, like the proposed rule, includes requirements more stringent than CAIR, the compliance deadline must reflect the degree of stringency of those requirements. [EPA-HQ-OAR-2009-0491-2756.1, p.22]
Despite EPA's suggestions to the contrary, promulgation of compliance dates later than those that EPA proposes would not result in increased emissions. CAIR could remain in place and would continue to maintain a strong and effective program of emission reductions pending the initial compliance deadline for the Transport Rule. In fact, electric generating companies will continue to have an obligation to achieve CAIR emission reduction requirements, including the phase II requirements, pending implementation of the Transport Rule. [EPA-HQ-OAR-2009-0491-2756.1, p.23]
EPA should take the time necessary to correct the many errors in the proposed rule, as described in these comments, and allow adequate time for states to develop SIPs and for sources to make the adjustments necessary to comply with the rule, rather than rushing to implementation as it proposes to do. [EPA-HQ-OAR-2009-0491-2756.1, p.24] [[These comments can also be found in Section VII.C.]]
In light of this, EPA should decide not to call for the steep additional emission reductions demanded by the PTR because, as discussed elsewhere in these comments, such additional reductions are not needed to reduce significant regional contributions to downwind nonattainment and interference with maintenance. In the alternative, EPA should extend the PTR's emission reduction deadlines by at least a two-year period beyond the proposed 2014 compliance date (plus an additional interval of time that reflects (i) any additional time that EPA takes to complete this rulemaking beyond mid-2011 and (ii) the reasonable period of time needed by states to implement emission budgets through SIP revisions after final promulgation of EPA's rule). The following subsections of this part of UARG's comments provide more detailed information on the unreasonableness of the emission reduction requirements that EPA has proposed. [EPA-HQ-OAR-2009-0491-2756.1, pp.35-36] [[These comments can also be found in Section VII.C.]]
Response: 
See discussion of EPA's rationale for compliance deadlines in preamble section VII.C.
Regarding the comments from MPUA regarding fuel switching, as discussed in preamble section VII.C.2, the flexibility of the rule provides for a wide range of compliance options.
Organization: Southeastern States Air Resource Managers (SESARM)
Comment: 
Southeastern States Air Resource Managers (SESARM)
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.44.]
Number four, deadlines for achieving mandated emission reductions should be designed to support the attainment deadlines prescribed for the standards. At the same time, the regulated community must be granted the required time to design and implement control equipment and operational changes necessary to meet the emission limits.
Response: 
EPA agrees, and we believe the Transport rule accomplishes these objectives.
Organization: Southern Company
Comment: 
Southern Company
EPA's rush to develop the Transport Rule and its failure to obtain stakeholder input has resulted in a proposed rule that suffers from numerous errors in methodologies and numerous incorrect assumptions. These flaws impact every aspect of this rule: the determination of which states are included in which programs; individual state budgets; unit allocations; timing of emission controls; etc. Although the court did not grant an 'indefinite stay' of its CAIR decision, it also expressly declined to impose a schedule on remand. EPA's forsaking quality for purported timeliness is unjustified in light of the fact that CAIR is still in place and the emission reductions mandated by CAIR are providing the intended environmental benefits, as well as helping states attain the NAAQS. For example, Birmingham, Alabama is now attainment for both the ozone and daily PM2.5 NAAQS and very close to attaining the annual PM2.5 NAAQS. [EPA-HQ-OAR-2009-0491-2864.1, p. 5]
For these reasons and the reasons explained below, EPA must issue a corrected supplemental proposal with adequate time for public comment. The compliance date should be no earlier than 2015, with CAIR remaining in place until the compliance date. Further information on the compliance timing, as well as other important issues that must be resolved before issuance of the final Transport Rule, are discussed in the comments below. [EPA-HQ-OAR-2009-0491-2864.1, p. 6]
A. EPA Should Discard the 2012 Compliance Date
The January 1, 2012 compliance date is only a mere 6 months after the anticipated issuance of the final Transport Rule. Most states, if not all, will not have time to develop a SIP to replace the PIP proposed by this rule; utilities will be faced with the extremely difficult task of developing and implementing several entirely new allowance strategies in unknown new allowance markets  [EPA-HQ-OAR-2009-0491-2864.1, pp. 8-9] [[These comments can also be found in Section VII.C.]]
It will also allow new allowance markets to develop and allow utilities to properly evaluate and implement possible compliance options. Further, allowing additional implementation time for the Transport Rule will not significantly alter or delay expected environmental benefits, as CAIR is still achieving important emission reductions and the absence of any court-ordered remand schedule enables EPA to exercise its discretion to set reasonable compliance dates. Finally, a compliance date any earlier than 2015 (the CAIR Phase II compliance date) is not justified since CAIR Phase I is achieving virtually the same benefit as the proposed under the Transport Rule (see Section IV). [EPA-HQ-OAR-2009-0491-2864.1, p. 9]
Response: 
EPA issued a NODA which requested and received comments on input data used in our analysis.   Based on this review EPA made a number of corrections for the analysis used for the final rule.  
See discussion in preamble section VII.C related to compliance deadlines. 
See discussion in preamble section X related to State Implementation Plans. 
 
Organization: Xcel Energy Inc.
Comment: 
Xcel Energy Inc.
The responsible regulatory agency needs to issue these permits in an expeditious manner to allow for installation of equipment to satisfy CATR. Otherwise, companies will be unable to meet CATR's aggressive compliance schedule. We encourage EPA to work cooperatively with the state permitting agencies to prepare a plan that will allow companies to meet the CATR deadlines and to provide compliance extensions for facilities that experience permitting delays beyond the owner's control. [EPA-HQ-OAR-2009-0491-2728.1, p.6]
Response: 
See discussion of permitting issues in preamble section VII.I.

V.C.1. Coordination With NAAQS Deadlines/Addressing Court's Concern About Timing

Organization: Edison Electric Institute (EEI)
Comment: 
Edison Electric Institute (EEI)
Many companies consider the compliance timeline to be the one of, if not the most, important factor(s) in complying with new regulations. For example, the proposed Transport Rule and MACT rule will not be finalized until mid- and late-2011, respectively. These rules both will influence company decisions regarding SO2, NOx, particulate matter and other controls. Final compliance with the Transport Rule is required by 2014 (30 months after a final rule), while MACT controls are expected to be required starting in 2015 (36 months after a final rule). Many companies believe that both compliance windows are too short, and that it would be more efficient for power companies to plan for compliance if both rules were to be finalized contemporaneously. [EPA-HQ-OAR-2009-0491-2697.1, p.6]
Finally, there is some uncertainty regarding whether the Agency reasonably established the dates for emission reductions in relation to Clean Air Act (CAA) deadlines for attaining and maintaining the 1997 annual PM2.5 NAAQS and the 2006 24-hour fine particulate matter (PM2.5), as well as the 1997 ozone NAAQS. 3 [EPA-HQ-OAR-2009-0491-2697.1, p.10]

Footnote 3: Regarding the PM2.5 NAAQS, EPA appears to have merged consideration of these two separate NAAQS into a justification for the 2012 and 2014 compliance deadlines. EPA's legal theory appears to be that 2012 and 2014 reductions will "help" such areas and, by virtue of this assistance, can be broadly justified under CAA § 110(a)(2)(D)(i)(I). However, such a standard of "help" provides no guidepost for the acceptable range of action under the CAA; almost any action to reduce air pollution could potentially "help" some area reach attainment. The CAA scheme enshrined within CAA § 110 directs EPA to base additional state controls on "significant contribution" and "interference" with maintenance which will occur over many years. With regard to the ozone NAAQS, nonattainment areas for the 1997 standard, areas not attaining the standard have maximum attainment dates ranging from 2010 to 2018. As a result of other decisions by the D.C. Circuit (vacating EPA's implementation rules for the 1997 standard) EPA proposed to classify 8-hour ozone nonattainment areas in accordance with Subpart II. 74 Fed. Reg. 2946. In this rule, EPA indicates that the 2012 compliance date is based on CAA requirements to attain "as expeditiously as practicable." However, since EPA has failed to finalize the 2009 proposed rule and to classify certain ozone nonattainment areas (i.e., areas formerly classified under Subpart I), EPA has not determined a date for attainment for such areas or whether such date is "as expeditious as practicable" under CAA § 172(a)(2), or responded to potential state requests for deadline extensions. Otherwise, EPA has indicated that the 2012 Proposed Rule deadline is coordinated with the June 2013 maximum attainment deadline for serious ozone nonattainment areas. Thus, control period dates in the proposed Transport Rule do not directly correspond to the Agency's assessment of what attainment dates should apply to certain areas in nonattainment of the 1997 ozone standard.
Response: 
See discussion in preamble section VII.C.1
Organization: Maryland Department of Environment (MDE)
Comment: 
Maryland Department of Environment (MDE)
In the future Maryland urges EPA to propose a Transport SIP Call and FIP concurrently with any future NAAQS proposals. This would result in the transport SIP being due 3 years after NAAQS promulgation, or the FIP would become final. Maryland recommends the following changes to EPA's proposed timetable below, with changes and additions in bold/italics: [EPA-HQ-OAR-2009-0491-2639.2, p.2]
Response: 
EPA will consider this recommendation.   Given that certain technical analyses are dependent on the selected level of the NAAQS, it may be difficult to provide transport requirements concurrently.   EPA intends, however, to address transport requirements as quickly as possible to assist states in developing their transport SIPs by the statutory deadline 3 years after the NAAQS are promulgated.
Organization: Michigan Municipal Electric Association (MMEA)
Comment: 
Michigan Municipal Electric Association (MMEA)
4.) EPA's Transport Rule Could Impose Pollution Control Requirements and Deadlines That Could Become Almost Immediately Outdated
For the Michigan public power units commenting here, the 2012 Transport limits and allocations will require almost immediate installation of pollution controls, followed by other, more stringent actions to meet 2014 Transport obligations. This may shortly be followed by additional NOx SIP calls or FIPs from EPA to implement revised ozone NAAQS standards. Requiring municipal utilities to stutter-step through these ongoing NOx regulations will not be feasible to achieve. The following, oft-cited charge shows the difficulties facing municipal electric utilities with respect to pending EPA compliance obligations: [EPA-HQ-OAR-2009-0491-2828.1, p.10]
[See page 10 of this comment for the figure that follows the above text.]
MMEA urges EPA to harmonize these pending NOx, SO2 and PM compliance obligations in a way that allows public power utilities to plan to meet these rules, by dropping the fast-approaching 2012 deadline and harmonizing the deadline with the SIP Call obligations that may result from the adoption of more stringent primary and secondary ozone NAAQS, projected by EPA beginning in 2014 (although EPA has already missed its projected deadline for finalization of that ozone NAAQS). [EPA-HQ-OAR-2009-0491-2828.1, p.10]
Response: 
See discussion in preamble section VII.C regarding EPA's rationale for the 2012 compliance deadline.   
EPA notes that there is a long-overdue obligation regarding CAA requirements to address significant contribution to ozone nonattainment and interference with maintenance under the 1997 standards.     Dropping the 2012 deadline in order to harmonize the deadline with future ozone NAAQS would lead to an unacceptable delay in meeting current obligations. 
Organization: National Rural Electric Cooperative Association (NRECA)
Pennsylvania Department of Environmental Protection
National Association of Clean of Air Agencies (NACAA)
State of Ohio Environmental Protection Agency (Ohio EPA)
Northeast States for Coordinated Air Use Management (NESCAUM)
Attorney General of North Carolina
Exelon
E.ON U.S.
Alcoa Power Generating Inc. - Warrick Power Plant
Large Public Power Council (LPPC)
Ohio Utility Group (OUG)
Associated Electric Cooperative, Inc. (AECI)
Environmental Defense Fund (EDF)
International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers and Helpers (AFL-CIO Boilermakers Union)
Southern Company
Comment: 
Alcoa Power Generating Inc. - Warrick Power Plant
The 2010 attainment date that the D.C. Circuit focused on in its 2008 decisions with respect to CAIR has passed, and recent air quality data demonstrates that the transport issue that CAIR sought to address is fast becoming moot. By no later than 2014, all ozone nonattainment areas achieve attainment, all annual PM2.5 nonattainment areas except Allegheny County, PA. achieve attainment, and all 24-hour PM2.5 nonattainment areas except Allegheny County, PA, and Brooke County, WV (both of which are local and not transport related) achieve attainment. Plainly, the additional stringent emission reductions EPA is proposing are not needed to achieve attainment and maintenance of the NAAQS. The underlying rationale for a transport rule of prohibiting significant contribution to nonattainment is soon to be a largely academic issue that no longer needs to be addressed for the 1997 ozone and PM NAAQS or the 2006 24-hour PM2.5 NAAQS. [EPA-HQ-OAR-2009-0491-3648, p.2]
Associated Electric Cooperative, Inc. (AECI)
EPA has proposed an overly aggressive timeline to implement the Transport Rule at a time of uncertainty. A near term final Transport Rule will likely be superseded in the near-future due to developments in new NAAQS. The implementation of new standards for PM2.5, PM10, NOx, and ozone will fall squarely in the middle of when EPA would implement the CATR. Consider: [EPA-HQ-OAR-2009-0491-2845.1 p.2]
:: PM2.5 - EPA commented that the final Transport Rule will need to be amended to address wintertime emissions related to attaining the existing 24-hour PM2.5 standard;
:: PM2.5, PM10  -  New, more stringent NAAQS coming in late 2011; :: NOx - EPA will issue a proposal to address NOx emissions related to the 1997 ozone standard;
:: The forthcoming ozone standard due out in October 2010 may cause EPA to issue a "Transport Rule II";
:: These rules are in addition to the electric utility MACT rule, which is set to be finalized in late-2011  -  just six months after the final Transport Rule is scheduled to be issued. The MACT rule will significantly influence how utility companies invest in scrubber equipment to control emissions of hazardous air pollutants as well as SO2.  
CAIR need not be replaced by 2012. There are no legal mandates to replace CAIR by a date certain, thus making the proposed 2012 CATR deadline unnecessary. Extending CAIR would allow CATR implementation to be postponed and the reduction goals more realistically obtainable .[EPA-HQ-OAR-2009-0491-2845.1 p.2]
Request: Associated requests that EPA delay the implementation of the Transport Rule until such time as these forthcoming standards are finalized, and allow states to develop SIPs. Again, nothing in the court mandate requires or compels EPA to abruptly end the CAIR program in favor of a Transport Rule FIP. Issuing the FIP with a 2012 compliance date leaves EPA vulnerable to legal challenges that would likely delay implementation of the rule beyond 2012. Associated strongly urges EPA to observe the orderly process and statutory timelines of Clean Air Act Section 110 for development of State Implementation Plans (see discussion/comments below). [EPA-HQ-OAR-2009-0491-2845.1 p.2]
Attorney General of North Carolina
In North Carolina, the D.C. Circuit held that EPA failed to properly implement the phrase in §110(a)(2)(D)(i)(I) requiring controls for interstate pollutants to be "consistent with the provisions of [Title I]." In the Court's view, this phrase requires EPA to coordinate the timing of controls on upwind sources with the attainment deadlines for downwind areas affected by those sources. 531 F.3d at 911-12. In CAIR, the deadlines for implementing controls were several years removed from the downwind attainment dates, virtually guaranteeing that the downwind areas would not get the full help from upwind sources in the time that Congress had commanded. [EPA-HQ-OAR-2009-0491-2685.1]
In the proposed Transport FIP, EPA has tacitly recognized that for some areas that are in need of assistance from upwind reductions the controls under the Transport FIP will come too late to help them attain in a timely manner. See 75 Fed. Reg. at 45,300/3-01/1. However, EPA argues that the controls are being implemented as expeditiously as practicable. EPA also contends that the 2012 and 2014 implementation dates are coordinated with the extended attainment deadlines for those areas that have already missed their attainment dates and with the deadlines for other nonattainment areas whose attainment dates have not yet arrived. Id. at 45,300/3-01/2. [EPA-HQ-OAR-2009-0491-2685.1]
E.ON U.S.
Further, it is unclear whether EPA has established reasonable dates for emission reductions in relation to Clean Air Act deadlines for attaining NAAQS. EPA appears to have combined the 1997 annual PM2.5 NAAQS and the 2006 24-hr PM2.5 NAAQS as justification for the 2012 and 2014 deadlines under Section 110(a)(2)(D)(i)(I). However, this section does not provide specific guidelines for deadlines. [EPA-HQ-OAR-2009-0491-2797.1, p.3]
Environmental Defense Fund (EDF)
d. The Statute Calls for EPA to Ensure That Downwind States Attain the NAAQS "As Expeditiously As Practicable" 
The agency's failure to establish a compliance schedule to ameliorate the "significant contribution" of upwind emissions to downwind nonattainment consonant with the NAAQS attainment deadline for downwind states was one of the central defects with CAIR identified by the D.C. Circuit in North Carolina v. EPA.18 To comply with the statutory mandate, EPA has a responsibility to carry out the prohibition on interstate air pollution under section 110(a)(2)(D) of the Clean Air Act not only by the outermost statutory deadlines for NAAQS attainment but "as expeditiously as practicable." The duty to attain the NAAQS "as expeditiously as practicable" and no later than the timetables delineated by law is an enduring framework of the statute.19 EPA has recognized that this rigorous, normative standard  -- to attain the NAAQS "as expeditiously as practicable"  -- is plainly intended to operate as the "overarching requirement for attainment."20  [EPA-HQ-OAR-2009-0491-2834.1 p.8]
Consistent with the natural, ordinary meaning of "expeditious," EPA must determine whether the emission reductions under the Transport Rule can be advanced to ensure speedy attainment of the NAAQS. Reviewing courts have interpreted the statutory admonition "as expeditiously as practicable" under the CAA to require compliance at the earliest possible date. By requiring compliance as expeditiously as practicable, "Congress made it clear that the states were to embark on the task of improving air quality as quickly as they could."21 [EPA-HQ-OAR-2009-0491-2834.1 p.8]
Further, courts have consistently recognized that the statute calls for expeditious attainment to fulfill the congressional imperative to protect human health, even when the phrase is coupled with an explicit deadline that sets an outer limit on compliance. [EPA-HQ-OAR-2009-0491-2834.1 p.8]
The Act's requirements with respect to SIPs emphasize that this purpose -- healthy air -- is to be attained "as expeditiously as practicable," but, in any event, no later than the attainment deadlines. Although [the defendants] focus[] on Congress' extension of the deadlines, the legislative history underscores that Congress regarded them as outside limits. 22 [EPA-HQ-OAR-2009-0491-2834.1 p.8]
In the NAAQS context these outer limit compliance deadlines are "certainly not a license for [a] state to take its time in complying with the NAAQS. The new attainment date is simply an outside date, and the CAA [amendment] explicitly reaffirms the Act's primary legislative purpose of attaining NAAQS `as expeditiously as practicable.'"23 [EPA-HQ-OAR-2009-0491-2834.1 p.9]
The proposed Transport Rule fails to meet the statutory exhortation to ensure attainment "as expeditiously as practicable." According to the agency's own projections, several downwind areas will fail to achieve or maintain the 1997 annual PM2.5 NAQQS, at least 14 downwind areas will fail to achieve or maintain the 2006 24-hour PM2.5 NAAQS, and several downwind areas will fail to achieve or maintain the admittedly inadequate 1997 ozone NAAQS.24 To demonstrate that the Transport Rule will prohibit interstate air pollution in accordance with the congressional mandate to restore healthy air expeditiously, EPA must show, on the administrative record, that the pace of reductions under the final rule will in fact sufficiently limit pollution to achieve the NAAQS "as expeditiously as practicable" and in no instance beyond the outermost statutory deadlines. [EPA-HQ-OAR-2009-0491-2834.1 p.9]
Exelon
The court in North Carolina also ruled that the 2015 deadline set by CAIR for upwind states to eliminate their "significant contribution" to downwind nonattainment ignore the plain language of CAA Section 110(a) requiring that attainment be achieved as expeditiously as practicable, but no later than five years from the date that the area was designated as nonattainment. The court ruled CAIR's 2015 compliance deadline was unlawful, because it resulted in downwind areas being required to attain NAAQS for ozone and PM2.5 without requiring upwind states to eliminate their significant contributions to downwind nonattainment. As a result, downwind states were forced to make reductions that exceeded the requirements of Section 110(a) solely to account for the additional pollutants that interfere with maintenance form upwind states. With the proposed Transport Rule, EPA addressed the issue of the CAA's compliance deadlines by coordinating the Transport Rule's deadlines for emissions reduction with the attainment deadlines for the relevant NAAQS. Considering the 2010 deadline will have passed prior to the proposed Transport Rule's adoption, EPA aligned the deadline for eliminating"significant contribution" under the proposed Transport Rule with respect to the 1997 PM2.5 NAAQS with the April 2015 deadline that is applicable to areas that will require an extension to the 2010 deadline. For areas designated as nonattainment with respect to the 2006 24-hour PM2.5 NAAQS, the attainment deadline must be met as expeditiously as practicable, but not later than December 2014. This 2014 deadline is consistent with the December 2014 attainment deadline for areas designated nonattainment for the 2006 PM2.5 NAAQS. The proposed Transport Rule Requires compliance with the limits on ozone-season NOX emissions by setting a 2012 deadline for compliance in coordination with the June 2013 maximum attainment deadline for serious ozone nonattainment areas. [EPA-HQ-OAR-2009-0491-2666.1, p.11]
International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers and Helpers (AFL-CIO Boilermakers Union)
Third, EPA errs in arguing that reductions in 2012 and 2014 are necessary to coordinate with NAAQS attainment deadlines under the D.C. Circuit's opinion in North Carolina. [EPA-HQ-OAR-2009-0491-2672.1, pp.3-4]
3. Attainment Deadlines and North Carolina. Contrary to EPA's stated belief in the proposed Transport Rule, Section 110 of the CAA and the D.C. Circuit's opinion in North Carolina do not require the establishment of a 2012 deadline for the Transport Rule. Read carefully, North Carolina rejected EPA's position that only the procedural provisions of Title I of the CAA apply to interstate transport; specifically, the D.C. Circuit faulted EPA for not 'mak[ing] any effort to harmonize CAIR's Phase Two deadline ... with the attainment deadlines for downwind areas.' North Carolina did not, however, explicitly hold that all substantial contributions and interference with maintenance must be eliminated by the attainment deadlines in the CAA. Indeed, such a goal would be impossible to achieve given that the 1997 Ozone NAAQS attainment deadlines began to expire this year. North Carolina should instead be interpreted to require EPA to balance attainment deadlines along with other Title I priorities and considerations - such as feasibility and state preparation of SIPs - in crafting rules for interstate emissions transport. We believe these considerations favor eliminating the 2012 deadline and preserving CAIR for an additional one year period. Such a deferral would be more feasible to meet and more consistent with the cooperative federalism policy of the CAA, and would not seriously imperil compliance with the CAA attainment deadlines. [EPA-HQ-OAR-2009-0491-2672.1, p.5]
Even under EPA's apparent reading of North Carolina, a 2012 deadline is only necessary to meet attainment deadlines for the 1997 Ozone NAAQS. As EPA notes in the preamble to the Transport Rule, the maximum attainment deadlines for the 1997 and 2006 PM2.5 NAAQS are 2015 and 2019, respectively - meaning that the trading programs for annual NOx and for Group 1 and Group 2 annual SO2 need not take effect until 2015. Thus, EPA has flexibility to postpone the implementation of at least the non-ozone portions of the Transport Rule. [EPA-HQ-OAR-2009-0491-2672.1, pp.5-6]
Large Public Power Council (LPPC)
C. North Carolina Does Not Require the Proposed Timetable for Implementing the Transport Rule
EPA justifies the timing for implementation of the Transport Rule in part on language in North Carolina regarding the original 2015 compliance deadline for CAIR. Contrary to EPA's suggestion, LPPC believes that North Carolina affords EPA latitude to defer implementation of the Transport Rule for one to two more years in order to ensure that the Transport Rule is feasible and does not impinge on state prerogatives under the CAA. [EPA-HQ-OAR-2009-0491-2725.1, p.9]
North Carolina interpreted Section 110 to require significant contributions to downwind air quality to be prohibited "consistent with" both the substantive and procedural requirements of Title I, including the deadlines for achieving attainment with NAAQS. LPPC notes, however, that the court rejected EPA's 2015 deadline because it was established without any regard for CAA attainment deadlines (or other substantive requirements of Title I of the CAA). North Carolina does not explicitly require CAIR (or its replacements) to take effect before the attainment deadlines. Indeed, such a mandate would be impossible to fulfill: some of the earlier attainment dates for the 1997 Ozone NAAQS will have already elapsed by the time the Transport Rule is promulgated. Although LPPC understands that EPA must take attainment deadlines into account when setting implementation timetables for the Transport Rule, LPPC does not believe North Carolina requires the Transport Rule to take full effect before the earliest attainment deadline.[EPA-HQ-OAR-2009-0491-2725.1, p.9]
In addition, North Carolina does not instruct EPA to impose requirements that are infeasible to meet or to do so at the expense of other important CAA provisions and policies. Section 110 instructs states to ensure that interstate emissions are controlled "consistent with" all provisions of Title I, including the "clear preference" expressed therein that states take the initiative to address pollution control problems through SIPs prior to the imposition of a FIP. Moreover, nothing in the language of Section 110(a)(2)(D)(i)(I) suggests that Congress wished for states to become subject to requirements that are infeasible to meet, even if an overly aggressive timetable is necessary to meet attainment deadlines. [EPA-HQ-OAR-2009-0491-2725.1, p.9]
In administering the CAA, EPA is responsible for  giving effect to all of its provisions and striking a reasonable balance among them where necessary. 36 Here, it is clear that there is some flexibility as to the timing of compliance with Section 110; as EPA notes in the preamble, the attainment deadlines for the 1997 NAAQS and 2006 NAAQS for PM2.5 are as late as 2015 and 2019, respectively, and the attainment deadlines for the 1997 NAAQS for ozone range from 2010 to 2018. Allowing states an additional one to two years to submit compliant SIPs and prepare EGUs for compliance would still achieve progress towards assisting downwind states in meeting the earlier attainment deadlines, and would probably have no impact on the achievement of the later attainment deadlines. Moreover, this deferral period would give effect to other equally important policies of the CAA. [EPA-HQ-OAR-2009-0491-2725.1, p.10]
Even if EPA disagrees with this analysis and determines that North Carolina requires the Transport Rule to take effect before the applicable attainment deadlines, there is no need for EPA to establish a 2012 compliance date for annual NOx and SO2 emissions. As noted above and in the preamble, the 1997 PM2.5 NAAQS and 2006 PM2.5 NAAQS have maximum attainment deadlines of April 2015 and December 2019, respectively. Although the 1997 Ozone NAAQS attainment deadlines arrive as early as 2013, EPA could postpone implementation of the Transport Rule requirements for PM2.5 without imperiling compliance with those attainment deadlines. [EPA-HQ-OAR-2009-0491-2725.1, p.10]
National Association of Clean of Air Agencies (NACAA)
Lead-In Time for Sources 
As noted previously, we support alignment of compliance dates with states' attainment deadlines, so that controls are installed and operational and reduce air pollutant emissions on a timeframe consistent with states' attainment deadlines. 11 We do note, however, that requiring compliance one year (2012) and three years (2014) after the rule's effective date will be technically challenging for a number of sources. We recognize the particular circumstances of this rule  -  the agency's need to act quickly to ensure reductions achieved by CAIR remained in place and to quickly propose a rule that met the court's dictates  -  influenced this schedule. [EPA-HQ-OAR-2009-0491-2771.1, p.6] 

Footnote: 
11 Not only does this make sense, the court decision requires such an alignment. 
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.106.] 
We are also pleased that EPA has attempted to align the Rule's compliance deadlines with attainment deadlines for the ozone and PM2.5 air quality standards. 
National Rural Electric Cooperative Association (NRECA)
Most of the major problems with this proposal, or action, begin with EPA eliminating requirements under CAIR and "proposing FIPs to immediately implement the emission reduction requirements identified and quantified by EPA in this action." NRECA can find no language in the North Carolina decisions that require CAIR abolishment and untimely substitute of its replacement. EPA has not explained why it has chosen to accelerate this proposed CAIR replacement or why it finds it necessary to do so based on the courts' decisions in the North Carolina cases. At a minimum, NRECA recommends that CAIR remain in effect at least until 2013 to allow a reasonable time for utilities to meet requirements keyed to demonstrating measureable or reasonable progress toward meeting Clean Air Act Section 110(a)(2)(D)(i)(I) goals. [EPA-HQ-OAR-2009-0491-2723.1, pp.4-5]
Northeast States for Coordinated Air Use Management (NESCAUM)
We greatly appreciate EPA's efforts to bring the timing of the transport rule's reductions in line with NAAQS attainment dates. This is a vast improvement from the Clean Air Interstate Rule (CAIR), and will greatly assist states in meeting Clean Air Act obligations to reduce emissions as expeditiously as possible.
[This comment was also submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.9.]
Ohio Utility Group (OUG)
Implementation deadlines under the Transport Rule deny the states the opportunity to submit SIPs [EPA-HQ-OAR-2009-0491-2679.1, p.2]
EPA anticipates that the Transport Rule will be finalized in mid-to-late 2011. The first phase of emissions reductions is set for January 1, 2012, leaving substantially less time than necessary for the states to figure out how to comply. Section 11O(a)(2)(D)(i) provides that each state shall submit a SIP that 'contain[s] adequate provisions prohibiting emissions that will contribute significantly to nonattainment in, or interfere with maintenance by, any other State.' This responsibility clearly contemplates that states be given adequate time to develop SIPs and submit them for EPA approval before being handcuffed by federally-imposed requirements. [EPA-HQ-OAR-2009-0491-2679.1, p.2]
EPA may require a state to abide by a FIP only after a state has failed to timely submit a SIP, or when a state's SIP has been denied.4 Developing a SIP, submitting it for comments, making appropriate revisions, and submitting the SIP to EPA for final approval can take a year or longer. Chris Korleski, Director of the Ohio Environmental Protection Agency, testified that 'achieving the substantial S02 reductions to meet the proposed S02 limit will be a difficult task in the timeframe proposed and additional time may be needed.' Comparatively, the time frame in which the states must complete the SIP process under the proposed Transport Rule is absurd. The NOx SIP Call program allowed states an entire year to submit SIPs. Moreover, the deadlines for CAIR - the program being replaced by the Transport Rule - provided a four-year gap between final promulgation and the first compliance deadline. However, the timing requirements under the proposed Transport Rule ignore the mandates of the CAA, ultimately requiring Ohio to accept the terms of the FIP until it has had time to properly develop its SIP. [EPA-HQ-OAR-2009-0491-2679.1, p.2]
Pennsylvania Department of Environmental Protection
Section 110(a)(2)(D)(i)(I) of the CAA mandates that SIPs must contain adequate provisions prohibiting significant contributions to nonattainment consistent with the Title I provisions of Act 42 U.S.C. § 7410(a)(2)(D)(i)(I). Therefore, EPA's final Transport Rule should attempt to harmonize the 'deadline for upwind contributors to eliminate their significant contribution with the attainment deadlines for downwind areas.' North Carolina v. EPA, 531 F.3d at 912 (D.C. Cir. 2008). [EPA-HQ-OAR-2009-0491-2660.1, p.4]
In accordance with Section 172(a)(2)(A) of the CAA, the PM2.5 NAAQS must be attained 'as expeditiously as practicable, but no later than 5 years from the date such area was designated nonattainment ... except that the Administrator may extend the attainment date ... for a period no greater than 10 years from the date of designation as nonattainment .... ' 42 U.S.C. § 7502(a)(2)(A). The CAA further provides in Section 181(a)(l) that' ... the primary standard attainment date for ozone shall be as expeditiously as practicable but no later,than the date provided in table 1.' 42 U.S.C. § 7511(a)(1). Therefore, as directed by the Court, EPA must harmonize the compliance dates with the statutorily prescribed ozone and PM2.5 attainment deadlines for the 1997 ozone, 1997 PM2.5, and 2006 PM2.5 NAAQS. [EPA-HQ-OAR-2009-0491-2660.1, p.4]
The DEP fully supports EPA's efforts to harmonize the compliance deadlines with the statutorily prescribed deadlines. While we recognize that industry has raised concerns regarding the TR compliance dates, NOx and SO2 emission reductions must be achieved expeditiously to ensure attainment and maintenance of the ozone and PM2.5 standards. Failure to retain the proposed compliance deadlines would make it difficult for states to satisfy their obligations - human health, environmental, and societal benefits would also be delayed. [EPA-HQ-OAR-2009-0491-2660.1, p.4]
[These comments were also submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.53.]
Southern Company
Southern Company strongly recommends that EPA discard the 2012 and 2014 compliance dates since among things, CAIR is still achieving important emission reductions and the absence of any court-ordered remand schedule enables EPA to exercise its discretion to set reasonable compliance dates. Additionally, Southern Company's analysis of the data shows that CAIR achieves virtually the same benefit as the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2864.1, p. 6]
State of Ohio Environmental Protection Agency (Ohio EPA)
U.S. EPA's 2012 compliance deadlines are intended to be aligned with the June 2013 deadline for serious ozone nonattainment areas under the 1997 Ozone NAAQS. Yet none of the 'downwind' states affected by this proposal are designated 'serious' ozone nonattainment areas. This approach would have been workable when CAIR was being developed but due to the remand of CAIR and the time necessary to develop the current proposal, this alignment is flawed. Essentially, reductions resulting from the Transport Rule will not further attainment of the 1997 ozone standard, but rather the soon-to-be-finalized revised 2008 ozone standard. In addition, if U.S. EPA did not implement the Transport Rule until 2014, or a later more appropriate date, U.S. EPA could allow states time to develop and implement a State Implementation Plan (SIP) in accordance with the Clean Air Act. [EPA-HQ-OAR-2009-0491-2793.2, p. 2]
Response: 
See discussion in preamble section VII.C.1 regarding EPA's rationale for compliance deadlines.
See discussion in preamble section  IV.C.2  and RTC section III.A related to EPA's imposition of FIPs.  
Organization: State of Louisiana, Department of Environmental Quality
Comment: 
State of Louisiana, Department of Environmental Quality
EPA's compliance schedule for this rule was written such that the compliance deadlines would coincide with the 1997 8-hour ozone NAAQS; however, many of those areas have met this attainment deadline and EPA has determined that these areas are indeed in attainment. Other areas are currently working on attainment demonstrations that will produce control measures to cure their individual ozone issues. LDEQ believes that it would be easier for states to include this proposed rule's control measures in the future attainment demonstration modeling that will take place once the Reconsideration of the 2008 Ozone NAAQS is final. [EPA-HQ-OAR-2009-0491-2655.1, p.5]
Response: 
See discussion in preamble section VII.C.1. on rationale for the compliance deadlines for ozone.
EPA is unclear on what commenter is referring to when suggesting that "it would be easier to include this proposed rule's control measures in the future attainment demonstration modeling."   If the commenter is suggesting that we defer any action with respect to transport of ozone until the ozone NAAQS are reconsidered, EPA would not be meeting our obligations under current standards.   If the commenter is suggesting that under a revised standard, there could be further support for achieving emission reductions from upwind states affecting ozone in Louisiana, EPA would agree and plans to address these issues further in a future rulemaking.

V.C.2. Reductions as Expeditiously as Practicable/Feasibility of the 2012 and 2014 Compliance Deadlines

Organization: Citizens Campaign for the Environment (CCE)
Clean Air Task Force
Maryland Department of Environment (MDE)
Constellation Energy
Attorney General of North Carolina
Exelon
PSEG Services Corporation
Institute of Clean Air Companies (ICAC)
NextEra Energy, Inc.
National Resources Defense Council (NRDC)
American Lung Association of the Mid Atlantic
Adirondack Council
Comment: 
Adirondack Council
The timetable proposed for implementation of the new Rule is aggressive, but capable of being met. We strongly recommend against extending these timelines. Many companies have already installed scrubbers or other pollution control equipment in order to meet the requirements of the first phase of CAIR. As the second phase of CAIR was scheduled to go into effect in 2015, moving the new deadline up by only one year will not cause any undue hardships to the energy companies, but will have an environmental benefit by speeding up the recovery in sensitive places like the Adirondack Park. [EPA-HQ-OAR-2009-0491-2848.1, p.2]
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.63.]
The timetable proposed for implementation of the new rule is aggressive, but capable of being met. We strongly recommend against extending these timelines. Many companies have already installed scrubbers or other pollution control equipment in order to meet the requirements of the first phase of CAIR. As the second phase of CAIR was scheduled to go into effect in 2015, moving up the deadline by only one year will not cause undue hardships to the energy companies, but will have an environmental benefit by speeding up the recovery in sensitive places like the Adirondack Park.
American Lung Association of the Mid Atlantic
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.29.]
We have already begun to hear that this schedule cannot be met or its too expensive. But I'm here to tell you that that is simply not true. The control technology is widely available and effective. The investment in cleaning up even more means that we should see even greater benefits, including more lives saved each year.
Attorney General of North Carolina
EPA's interpretation of "as expeditiously as practicable" appears to be based on the timing of the installation of control technologies on, and the implementation of control methodologies at, presently uncontrolled or insufficiently controlled facilities. These controls primarily are scrubbers, SCRs, low NOX burners and fuel switching. EPA has also solicited comment on other post combustion controls and advanced coal preparation. See 75 Fed. Reg. at 45,272-73 [EPA-HQ-OAR-2009-0491-2685.1]
Citizens Campaign for the Environment (CCE)
Important elements of the proposed Transport Rule that CCE recommends should be maintained in the finalized rule include:
1) Maintain current timelines. The Transport Rule would go into effect in 2012 with three programs, one for SO2, one for annual NOX and another for ozone-season NOX reductions. In addition, a second phase of SO2 reductions for 15 states that significantly impact the air quality of neighboring states will go into effect in 2014. CCE believes that the deadlines for emissions reductions in 2012 and 2014 are both reasonable and necessary, and recommends they be maintained in the final Transport Rule. Any changes to extend the deadlines would adversely impact our ability to protect our land, air and water from the impacts of acid rain. [EPA-HQ-OAR-2009-0491-1937.1, p. 3]
Clean Air Task Force
We urge EPA to strengthen and finalize the proposed Transport Rule as soon as possible. First of all, this will lock in many of the emission reductions achieved by US power plants in the last five years. Second, the Transport Rule goes farther than CAIR in a number of states and is projected to allow many nonattainment areas in the East to reach attainment, at least for PM. Third, as we discuss below, substantial reductions in power sector emissions beyond those required by the proposed TR are achievable and cost-effective, and the TR should be strengthened to capture those reductions. [EPA-HQ-OAR-2009-0491-2738.1, p.1]
Constellation Energy
Constellation Energy supports full implementation of the rule by January 1, 20121. Constellation Energy's primary interest is that a prompt and stable rule be put in place to achieve the emissions reductions we need to ensure public health with ensuing economic benefits. The rule as proposed would achieve this goal and would establish emission standards throughout the 31-state regicln that are similar to those already being met in our headquarters region. The rules will appropriately level the regulatory playing field and provide the sector with the certainty necessary to plan future operations. Likewise, once the ozone NAAQS is established, EPA should move quickly to promulgate revised budgets to allow companies maximum time to take them into account in capital planning and positioning in the allowance and electricity markets. [EPA-HQ-OAR-2009-0491-3613,p.2]
These comments are intended to guide timely implementation without litigation delays. None of our recommended modifications to the proposed rule are intended to delay implementation of the ru~e by January 1, 2012. [EPA-HQ-OAR-2009-0491-3613, p.3]
Exelon
THE COST OF IMPLEMENTING THE TRANSPORT RULE APPROPRIATELY FALLS PRIMARILY ON THOSE FOSSIL FUEL EGU OWNERS IN UPWIND STATES WHO HAVE AVOIDED THE COST OF INSTALLING CONTROLS IN THE PAST, TO THE DETRIMENT OF THOSE IN DOWNWIND NONATTAINMENT AREAS.
Many coal-fired power plant owners have already invested in upgrades to reduce harmful air pollutants. According to the Reliability Report, "[o]f the 310 [gigawatt ("GW")] of coal capacity in the United States, 150 GW have installed [flue gas desulfurization ("FGD")]systems and another 55 GW have FGD controls planned, representing 65 percent of the existing coal fleet." It has been, and would continue to be, poor public policy to allow upwind fossil fuel EGU owners to continue to operate uncontrolled units while imposing the burden of their emissions on downwind fossil fuel EGU owners that have modernized their fleets. [EPA-HQ-OAR-2009-0491-2666.1, p.14]
The owners of coal-fired power plants have had ample time to retrofit units. Those who previously chose not to make those investments cannot now complain that doing so is too costly or that more time is needed. Given the enormous public benefits of the Transport Rule and the damages being caused to downwind economies, no credible claims can be made that emissions technology upgrades are too costly. Moreover, for years it has been widely known in the electric power industry that upwind fossil fuel EGUs contributed to downwind nonattainment. As noted elsewhere herein, EPA made this finding more than twelve years ago, beginning with the NOX SIP Call. CAIR was proposed over seven years ago and the schedule and likelihood of additional downward revisions to NAAQS standards are also well known. In fact, CAIR remains in effect until the Transport Rule is adopted, and CAIR establishes lower state emission budgets for some states than the proposed Transport Rule. The data in the Reliability Report suggests that most EGU operators long ago realized that operating with lower emissions was a sound business strategy, essential to remaining competitive in the future, as environmental controls became increasingly stringent. Having promised to address the problem for more than a decade, EPA should not now disappoint the reasonable commercial expectations of plant owners who willingly invested in pollution controls in order to remain competitive when the promised regulatory initiatives were implemented. Law and equity require that EPA implement the Transport Rule as soon as practicable, and reject the pleas of some fossil fuel EGU owners for additional time or regulatory leniency because they failed to plan to equip their plants to meet new regulatory requirements designed to protect public health and downwind economies. [EPA-HQ-OAR-2009-0491-2666.1, pp.14-15]
THE TRANSPORT RULE CAN BE IMPLEMENTED WITHOUT ANY NEGATIVE IMPACT ON THE RELIABILITY OF THE ELECTRICITY GRID.
THE IMPLEMENTATION TIMELINE ESTABLISHED BY EPA IS REASONABLE AND ACHIEVABLE.
The implementation timeline established by EPA can readily be achieved by the electric generating industry. The contention by opponents of the proposed Transport Rule that the budgets are too strict to be met within the proposed timeframe is demonstrably incorrect. The proposed budgets are not significantly out of line with the budgets of other SO2 and NOx programs or with recent historical emission levels. The proposed Transport Rule SO2 budget falls within about 5% of the total CAIR SO2 budget. Furthermore, the proposed 2012 SO2 budgets are only 20% less than the actual 2009 emissions in these states. The proposed 2012 budgets are only 6% lower than projected 2010 emissions. [For additional comments pertaining to THE IMPLEMENTATION TIMELINE ESTABLISHED BY EPA IS REASONABLE AND ACHIEVABLE, see pp.15-18 of this comment summary; EPA-HQ-OAR-2009-0491-2666.1, p.15]
[See p.18 of this comment summary for Table 4.1: Impact of Increasing CC Generation in 2014 in Group 1 SO2 States on SO2 Emissions and Table 4.2: Impact of Increasing CC Generation in 2014 in Annual NOx States on NOx Emissions 28]
THERE IS NO REASON TO DELAY OR TO WEAKEN THE PROPOSED TRANSPORT RULE, AS SUGGESTED BY CERTAIN COMMENTORS.
Some industry commentors have suggested in Congressional testimony and elsewhere, that the effective date of the proposed Transport Rule should be delayed, citing an adverse impact on electric reliability and adverse impacts on jobs and economic growth. In support of these assertions, the commentors have submitted an improperly designed and rudimentary analysis prepared on behalf of the DOE, National Environmental Testing Laboratory, Lisa Phares, GDP Impacts of Energy Costs (October 5, 2009) ("NETL Study"). These comments are founded upon a misunderstanding of the Transport Rule and its implications. They should be rejected because, as discussed in Exelon's comments: (1) EPA is under a legal obligation to implement reductions in interstate transport as soon as practicable; (2) there is currently adequate capacity such that implementation of the Transport Rule and its compliance assurance mechanisms starting in 2012 can be accomplished with no adverse impacts on electric reliability; and (3) delay will allow additional impacts on health, additional premature deaths and continued impediments to economic development in non-attainment areas, while producing no corresponding benefits other than allowing companies that have resisted installation of pollution controls or low pollution technology to continue to operate antiquated coal fired plants and generate profits off of these fully depreciated assets. In fact, contrary to the NETL Study, as reflected in Dr. Cicchetti's report, implementation of these requirements will promote economic growth and delay will delay those benefits. [EPA-HQ-OAR-2009-0491-2666.1, p.46]
The NETL Study, submitted by critics of the Transport Rule, develops a simplistic model in which it projects increased electricity costs, draws a relationship between economic growth and electricity costs and projects decreased growth and job losses based on these increased costs. This is overly simplistic and contrary to the empirical evidence.71 Requirements such as those in the proposed Transport Rule will generate increased capital investments in both pollution control technology and modern, low or zero pollution generation technology. As discussed above, outmoded high pollution control plants whose capital costs are entirely depreciated depress investment in new technology and, to the extent these plants are retired, those retirements will spur investment in new technology which will generate more and better jobs and economic returns. In addition, increased energy prices will spur investment in energy conservation and efficiency measures as well as modern generation technology, and these investments will create both construction and manufacturing jobs. Moreover, these older, higher polluting plants have significant adverse impacts on health that result in higher health care costs.72 Because health care costs in the United States are borne disproportionately by private industry, higher health care costs reduce industry competiveness, as well as reducing worker productivity. This is restated in Dr. Cicchetti's analysis. These impacts are further confirmed by analyses of states' respective economic growth rates as compared to "carbon intensity," which show that the states with the lowest carbon intensity tend to enjoy higher rates of economic growth and prosperity. In short, the NETL Study changes one variable  --  electricity cost  --  and fails to consider the positive economic effects of increased efficiency, technological development and above all, improvements to human health and the environment. [EPA-HQ-OAR-2009-0491-2666.1, pp.46-47]
In recent testimony to Congress, one utility with heavy investments in old, uncontrolled coal plants contended that it would not be able to comply with the proposed Transport Rule limits for 2012 and urged Congress to enact legislation delaying those limits. EPA's modeling is based on what can be achieved in 2012 based on existing control equipment or control equipment that is already in place. In fact, at the time, the company admitted that it had "not yet had a chance to do a detailed analysis of our likely compliance options and choices to meet the budget targets," suggesting that the conclusion had been made without reading or understanding the proposal that had just been released. The company also assumes that the only compliance option is to retrofit old, inefficient coal fired plants, rather than to switch dispatch to cleaner natural gas EGUs or invest in new, cleaner plants. The company further indicated its fear that closure of coal plants would interfere with the electric grid and eliminate good rural jobs. As discussed above, there is plenty of modern, clean, efficient generation technology to secure a reliable electricity supply and older coal plants put a damper on investment in modern technologies. The real intent of these protestations is to allow companies to continue to operate older, fully depreciated facilities with no controls and to let downstream economies and individuals to continue to bear the costs. [EPA-HQ-OAR-2009-0491-2666.1, p.47]
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.38-39.]
Exelon urges EPA to require Transport Rule compliance on the 2012 and 2014 dates that the agency has proposed. Based on EPA's analysis, approximately 14 gigawatts of SO2 scrubbers and less than one gigawatt of SCR will be required for industry to comply with the 2014 date. This amount of new pollution control retrofits is much less than has been implemented in past construction cycles on similar timelines.

28 Tables 4.1 and 4.2 show the impact of directly substituting coal generation with gas-fired generation from existing CCs on emissions levels. The first line of each table shows the most recent historical CC capacity factor, and the following lines show the impact of increasing that CC capacity factor at different increments and reducing coal-fired generation by a commensurate amount.
Institute of Clean Air Companies (ICAC)
ICAC would like to emphasize that the competition in the air pollution control (APC) industry spurred by demand in the last decade has matured and diversified the industry and has led to the innovation and the development of many emission reduction technologies, including a broader suite of control technologies such as less capital-intensive options. Typically these less capital-intensive ttechnologies can be installed relatively quickly compared with SCR, FGD and baghouses. [EPA-HQ-OAR-2009-0491-2695.1, pp. 1-2]
Many of these technologies may be especially appropriate for sources complying with proposed Transport Rule requirements, as explained below, in order to meet the proposed reduction schedule as these lower capitol cost options that can be implemented quickly and lend themselves well to the flexibility envisioned in EPA's preferred remedy. The bottom line is that the end-user has access to a broader range of available technology options now offered by a mature and competitive industry and, resulting in unprecedented options for complying with regulatory deadlines. [EPA-HQ-OAR-2009-0491-2695.1, p. 2]
ICAC supports the statements in the proposed rule "EPA believes that 2014 provides sources sufficient lead time to install emissions controls or take other actions necessary to achieve the required reductions." (75 FR 45275/1) and "...a deadline of January 1, 2014 also provides adequate and reasonable time for sources to plan for compliance with the Transport Rule and install any necessary controls." 75 FR 45300/3 [EPA-HQ-OAR-2009-0491-2695.1, p. 3]
d. Capacity of the APC Industry to Respond to the Proposed Transport Rule and Other EPA Regulations. ICAC acknowledges EPA's statements in the proposed rule concerning the APC industry's capacity for retrofitting the expected 14 GW of FGD and the 1 GW of SCR as a result of the proposed rule in the 30 months between mid-2011 (when EPA anticipates finalizing the rule) and January 2014 (the proposed Phase 2 compliance deadline). In particular, ICAC supports the statement in the proposed rule that "This is significantly less than the capacity that was retrofit in the same length of time after CAIR was finalized. EPA is not aware of problems or issues with sources meeting the CAIR compliance deadlines, either in equipment deliveries or labor availability. EPA believes the proposed Transport Rule compliance deadlines are reasonable, and will result in emissions reductions as quickly as practicable, delivering health benefits to the public and aiding states with NAAQS attainment deadlines." 75 FR 45273/1  [EPA-HQ-OAR-2009-0491-2695.1, p. 4]
The APC industry is well-positioned to meet the requirements of the final Transport Rule, the next round of SO2 and NOx reductions from the "fully quantified" Transport rule, subsequent transport obligations from future National Ambient Air Quality Standards (NAAQS), and recently finalized, proposed, and upcoming Maximum Achievable Control Technology (MACT) standards. The industry is coming off finishing a wave of FGD installations and is poised and ready to meet all of our customers' needs in the next 4-5 year timeframe. Many variables and market conditions affect customer demand and the ability of the APC industry to meet that demand, and ICAC is confident that the market, in combination with the above-mentioned flexibilities, will sort out and prioritize the compliance requirements of all sources. [EPA-HQ-OAR-2009-0491-2695.1, p. 4]
Historically, the APC industry has always met the compliance requirements of our customers during the NOx SIP Call and CAIR Phase 1. In the proposal stage of each of these rules, concern had been expressed about the APC industry's ability to respond. Yet, in each case after rule finalization, the APC industry surpassed expectations. For example, in 2007 EPA modified their 2005 estimate for the FGD retrofits anticipated to be installed by 2010 for CAIR compliance based upon projects that had been announced and committed to, and it was significantly higher than previous estimates. In 2005, EPA estimated 36 GW of new FGD installations by 2010 and 72 GW by 2015. However, in early 2007 EPA's revised estimate was that at least 55 GW of new FGD capacity would be in place in 2009 and about 80 GW of new FGD by 2010. In other words, with real project information, EPA recognized that more FGD would be installed by 2010 than they previously expected to be installed by 2015.1 The 2005 estimate that proved to be low was demonstrated to be a result of overly conservative assumptions by US EPA regarding the demand for and availability of labor to execute these projects. [EPA-HQ-OAR-2009-0491-2695.1, p. 4]
Moreover, with the flexibility of EPA's preferred approach, it is not necessary to install every piece of equipment by the compliance date of 2014. As Figure 1 shows, over half of SCR installations were being placed into service for NOx SIP Call compliance well after the initial compliance date of May 1, 2003. [EPA-HQ-OAR-2009-0491-2695.1, p. 5; see p. 5 for Figure 1]
Most importantly, even with SCR installations after the compliance date, sources used the flexibility of cap-and-trade such that, according to EPA in the proposed Transport Rule preamble "[C]ompliance remained virtually 100 percent throughout the program's 6 years." 75 FR 45223/3 [EPA-HQ-OAR-2009-0491-2695.1, p. 5]
Finally, states have statutory provisions in the CAA available to them that allow them to request extensions to attainment dates for NAAQS. Two one-year extensions of ozone attainment are available under section 181, and a five-year extension of PM2.5 attainment is available under section 172. Further, sources can request that states allow them a one-year extension for MACT compliance under section 112(3)(B) "if such additional period is necessary for the installation of controls." ICAC believes that this additional flexibility afforded by the CAA in conjunction with EPA's analyses of labor and equipment availability should alleviate sources' concerns that the APC industry will not be able to comply with the suite of upcoming EPA regulations. [EPA-HQ-OAR-2009-0491-2695.1, p. 5]
Maryland Department of Environment (MDE)
Multiple FGDs, SCRs and other pollution controls equipment at EGUs can be installed in a relatively short, 2 to 3 year time frame. In a period ofjust under 3 years, Maryland's 9 coal fired power plant units installed 6 FGDs, 2 baghouses, 2 hydrated lime injection systems, 3 SCRs, 6 SNCRs and 6 powder activated carbon injection systems.  [EPA-HQ-OAR-2009-0491-2639.1, p.3]
Finally, Maryland finds that EPA's timing for implementation of controls, as discussed in the Transport Rule proposal, is very reasonable. Maryland's experience in implementing the Healthy Air Act substantiates the time frames that EPA names, and Maryland is opposed to any increase in the timing. More detailed supporting documentation for this comment is found in Appendix C: Case Study: Maryland Healthy Air Act: Deadlines and the Installation of Control Equipment [See EPA-HQ-OAR-2009-0491-2639.2, p.31 for comments pertaining to Appendix C]. [EPA-HQ-OAR-2009-0491-2639.2, p.4]
National Resources Defense Council (NRDC)
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.42-43.]
The means to achieve lower emissions of SO2 and NOx have long been available. Between fuel switching and readily implemented control technologies for reducing emissions of these pollutants, there is no question that EPA's proposed emission reduction and be quickly and affordably achieved.
NextEra Energy, Inc.
NextEra Energy believes that the industry is fully capable of installing the emission control technologies in the timeframes necessary to comply with the rule.
In determining the initial phase of SO2 emission reductions required under the Transport Rule, EPA only took into account emission reductions that could be made through (1) the operation of existing scrubbers, (2) scrubbers that are expected to be built by 2012 and (3) the use of low sulfur coal. With respect to determining the 2012 annual and ozone season NOx budgets, EPA used the same general methodology. EPA assumed only reductions achievable from the year-round operation of existing selective catalytic reduction (SCR) units and SCR units expected to be installed by 2012 in establishing the 2012 NOx budgets. [EPA-HQ-OAR-2009-0491-2718.1, p.8]
In the preamble to the proposed rule, EPA estimates that approximately 14 gigawatts (GW) of SO2 scrubbers and less than 1 GW of SCR for NOx control will be required for the electric sector to comply with the proposed 2014 emission caps. This amount of retrofits is significantly less than the industry has added in recent construction cycles. For example, according to the NEEDS database, approximately 56 GW of scrubbers was installed between 2006 and 2009, including 15 GW across 50 to 60 sites in 2009. EPA projects that an additional 19 GW of scrubbers will come online in 2010. [EPA-HQ-OAR-2009-0491-2718.1, p.8]
Moreover, the industry's past successful installation of pollution controls on numerous units underscores its ability to schedule and sequence any required unit outages in an efficient and reliable manner. 'To help ensure reliability, generators and transmission owners provide reasonable advance notice of any planned outages to the respective transmission authorities. In turn, the transmission authorities develop a coordinated outage schedule to prevent any deliverability problems. This illustrates a key benefit of a fully integrated national transmission system. [EPA-HQ-OAR-2009-0491-2718.1, p.8]
PSEG Services Corporation
PSEG supports the implementation timing of the Transport Rule  -  the industry can comply with the proposal without causing negative impacts on electric system reliability. [EPA-HQ-OAR-2009-0491-2726.1, p.1]
Response: 
EPA acknowledges and appreciates the above comments supporting the Transport Rule.
Organization: Southern Company
Georgia Department of Natural Resources, Air Protection Branch
Indiana Cast Metals Association (INCMA)
West Window Corp.
Energy Future Coalition
Indiana Department of Environmental Management 
Edison Electric Institute (EEI)
North Carolina Department of Environment and Natural Resources
we energies
Allegheny Energy
Kentucky Division for Air Quality
State of Ohio Environmental Protection Agency (Ohio EPA)
Dayton Power and Light Company (DP&L)
State of Delaware Department of Natural Resources & Environmental Control
Council of Industrial Boiler Owners (CIBO)
Electric Energy, Inc. 
City of Springfield, Illinois, Office of Public Utilities
National Rural Electric Cooperative Association (NRECA)
Oklahoma Department of Environmental Quality
Ameren Services Company
Occidental Chemical Corporation (OCC)
Kansas City Board of Public Utilities (BPU)
Independence Power & Light (IPL)
NRG Energy
Hoosier Rural Electric Cooperative
Peabody Municipal Light Plant
Florida Electric Power Coordinating Group, Inc. (FCG)
City Utilities of Springfield
Kansas Department of Health and Environment
Dynegy, Inc.
Lansing Board of Water & Light
Michigan Department of Natural Resources and Environment
Northern Indiana Public Service Company (NIPSCO)
Xcel Energy Inc.
Midamerican Energy Holdings Company
Minnesota Power 
Wolverine Power Supply Cooperative
RRI Energy, Inc.
Edison Mission Energy (EME)
PPL Corporation
City of Tallahasse
Great River Energy
Louisiana Energy and Power Authority (LEPA)
Buckeye Power, Inc.
East Kentucky Power Cooperative
E.ON U.S.
AES Corporation (AES)
Ohio Manufacturers Association (OMA)
Calpine Corporation
Wisconsin Power and Light Company
U.S. Congressman Pete Hoekstra
Large Public Power Council (LPPC)
EquiPower Resources Corp.
Big Rivers Electric Corporation
Empire District Electric Company (Empire District)
Ohio Utility Group (OUG)
Associated Electric Cooperative, Inc. (AECI)
Southern IL Power Cooperative
Public Utilities Commission of Ohio
Kansas City Power and Light Company (KCP&L)
PPG Industries, Inc.
Michigan Manufacturers Association (MMA)
Marquette Board of Light and Power
City of Ames, Iowa
ARIPPA
Entergy Services, Inc.
DTE Energy
Owensboro Municipal Utilities (OMU)
Old Dominion Electric Cooperative
Indiana Municipal Power Agency
Manitowoc Public Utilities (MPU)
Indiana Builders Association 
American Coalition for Clean Coal Electricity (ACCCE)
Exxon Mobil Corporation
National Mining Association (NMA)
Class of '85 Regulatory Group
Algonquin Power Windsor Locks, LLC
Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
Michigan Municipal Electric Association (MMEA)
American Chemistry Council
Texas Mining and Reclamation Association
Kentucky Chamber of Commerce
Nelson Industrial Steam Company (NISCO)
Indiana Utility Shareholders Association
Ohio Coal Association
Luminant
Four Flags Area Chamber of Commerce
International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers and Helpers (AFL-CIO Boilermakers Union)
American Municipal Power, Inc. (AMP)
Michigan Chamber of Commerce
Pfeiff, Mike
Mass Comment Campaign (245) (American Electric Power)
Pendleton, Mark
Crouch, Diane
Jessee, Robert
Environmental Defense Fund (EDF)
Holland Board of Public Works
Mass Comment Campaign (221) (American Electric Power)
San Miguel Electric Cooperative, Inc.
State of Louisiana, Department of Environmental Quality
Consumers Energy
American Electric Power
Comment: 
AES Corporation (AES)
The proposed Transport Rule does not provide sufficient time to permit and retrofit existing units. It does not appear that the proposed revisions will be finalized until June 2011 at the earliest. It will be extremely difficult for an owner of multiple generating units to complete all of the required analyses, permit applications, hearings and air quality modeling between June 2011 and the January 1, 2012 expected program start date. In addition, Investments and balance of plant modifications for SCR technology could exceed $50 million per boiler. Retrofitting existing boilers is typically a five to six year process, including budgeting, capital planning, permitting, engineering, procurement, construction, equipment shakeout, and performance testing. EPA must establish a realistic compliance date for installation of the emissions control technology. [EPA-HQ-OAR-2009-0491-2791, p.3]
Algonquin Power Windsor Locks, LLC
The proposed regulations do not allow adequate time for equipment modifications where such may be needed. If a unit is required to install a new emission control system, it takes more than two and a half years to allow for proper design and implementation of such a system. [EPA-HQ-OAR-2009-0491-2779.1, p.1]
Allegheny Energy
AE believes that the short implementation period in the proposed rule will make compliance unnecessarily challenging, if not impossible. Add to this the numerous upcoming regulations poised to be implemented in essentially the same time frame as this proposed rule and some generators will be left with limited options that could compromise the nation's electric reliability standard. At a very minimum compliance with the required NOx and first phase S02 reductions of this proposed rule should be delayed by one year to January 1, 2013. The second phase of S02 reductions should then be delayed, at a very minimum, by a year and a half to two years to late 2015 or January 1, 2016. Even these time extensions may prove inadequate to accomplish all the permitting, design, construction and startup necessary to add emissions control equipment. As an example, permitting alone for the 2009 installation of scrubbers at AE's Hatfield's Ferry power station took two years to secure before any construction could begin. Even if design is conducted concurrently with permitting, under EPA's proposal, that still leaves only one year for construction, tie-in, and start up of the equipment. This is an unrealistic schedule for one project let alone a multitude of projects by all the affected companies vying for the same equipment manufacturers and installation labor. [EPA-HQ-OAR-2009-0491-2605.1, p.2]
Ameren Services Company
The aggressive 1-2 year implementation of the requirement is also very concerning (2012) since it takes about 3-5 years to plan, finance, procure & erect / commission a scrubber at a coal fired power plant. Its even worse during this present economic downturn where budgets have been slashed due to low electricity market prices (especially in deregulated power states such as IL) & reduced demand for electricity. It would seem to me that most plants that have not already planned to install a scrubber and have that plan implemented at some stage will not be able to meet this 2012 deadline. Is the EPA prepared therefore to force the shut down of operations at such plants (which may become the best economic alternative on the part of a utility) and if so, what is it's plan for how it will go about replacing lost base load megawatts from such discontinued power plant operations? [EPA-HQ-OAR-2009-0491-0083, p.2]
Timeframes assumed for installation SCRs and FGDs are unrealistic [EPA-HQ-OAR-2009-0491-2722.1, p.5]
EPA claims that SCRs and FGDs can be installed between June 2011 (the date EPA plans to finalize the Transport Rule) and January 2014. EPA assumes that it takes about 27 months to design, permit, and build FGDs and about 21 months to design, permit, and build SCRs. EPA has not adequately justified these assumptions. EPA admits in the Preamble to this proposal that these assumptions are based upon data gleaned from boilermakers when the CAIR was developed, which was over six years ago. Based on Ameren's experience this assumption is incorrect. [EPA-HQ-OAR-2009-0491-2722.1, p.5]
Ameren has permitted and built 5 FGD systems over the last 6 years. Our experience is that a 6 to 12 month period is required for design prior to any air quality permits being submitted to the reviewing agency. For example Ameren's Coffeen plant submitted the application for an air construction permit on September 11, 2006 and was issued the permit by the permitting agency on December 15, 2006. Unit I FGD came on line in November 2009 and Unit 2 in February 2010. Without even considering the design time involved before the permit application was submitted to the agency, the time from permit application submittal to the first unit startup was 38 months. Adding a minimum of 6 month design time this is 17 months longer than EPA's claim of 27 months to plan, permit, build, and begin operation of an FGD system. Similarly for Sioux plant the permit application for a FGD was submitted in July 2006. Operation will begin in November 2010 approximately 52 months after application submittal. This does not include the initial design time. [EPA-HQ-OAR-2009-0491-2722.1, p.5; for additional comments pertaining to, Timeframes assumed for installation SCRs and FGDs are unrealistic, see pp.5-6 of this comment summary]
EPA needs to reevaluate its assumptions regarding the timing for installation of FGDs and SCRs. There will not be enough time to install these control systems between June 2011 and January 2014 to ensure compliance with the caps, particularly considering the proposed constraints on emissions trading. [EPA-HQ-OAR-2009-0491-2722.1, p.6]
Availability of a quality work force for design and permitting is of concern considering the accelerated implementation of this rule EPA in its selection of representative installations has chosen units that were retrofitted with FGDs and SCRs that were installed before 2005. Prior to 2005 there was only modest workforce demand and thus highly experienced and productive staffs were more readily available. Typically early in the adoption process of control technologies (usually at larger utility systems) higher productivity labor is usually available, but increasing demand could compromise this productivity as the need for multiple installations is realized. [EPA-HQ-OAR-2009-0491-2722.1, p.6]
An increased demand for competent process design, engineering and equipment suppliers will lengthen schedules. The cases EPA selected prior to 2005, when less than 5% of the existing inventory of FGDs and SCRs was installed, may not be representative of current availability. In fact having access to an abundant pool may have allowed construction schedules to compress during this period and therefore is not representative. At present there is much greater demand for competent process design, engineering, and equipment suppliers. [EPA-HQ-OAR-2009-0491-2722.1, p.6]
Typically when engineering a control system the design is done in two phases 4. The first phase establishes the design basis (i.e. gas flow rates, composition, reagent composition, etc), standard absorber design, equipment layout, basic balance-of-plant needs and preliminary cost. The second phase entails a detailed balance-of-plant including auxiliary equipment and the development of detailed contracts for fabrication, and construction schedules for the general and subcontractors. Each phase reportedly required 6 months to complete. These actions are required for each installation to assure proper engineering, procurement and construction to avoid prudency challenges from local Public Service Commissions as well as other governing bodies. [EPA-HQ-OAR-2009-0491-2722.1, p.7]
Considering the above issues Ameren is concerned that given the accelerated implementation of this rule that adequate time has not been given to complete required installations. [EPA-HQ-OAR-2009-0491-2722.1, p.7]
Considering the information presented in Section III above and the comments submitted by UARG it will be impossible to design, permit and construct these FGDs in time to meet the January 2014 deadline. If EPA promulgates this Transport Rule in June 2011 that would give these plants only 30 months to design, permit and construct the required FGDs; well short of the time necessary to perform this task. Additionally, Ameren as part of its long term planning process has no plans to install FGDs on the units at these plants. [EPA-HQ-OAR-2009-0491-2722.1, p.9]
American Chemistry Council
A. Technology and Labor Availability May Impact Project Completion
In the preamble, EPA invited comments on the schedule for scrubber and selective catalytic reduction (SCR) installations, the availability of boilermaker labor, and on alternative post-combustion cost-effective technologies. In addition, EPA seeks comment on whether other factors, such as other EPA regulatory actions, will create an increase in boilermaker demand earlier than today's proposal, in 2010 and beyond. (75 Fed. Reg. at 45273.) [EPA-HQ-OAR-2009-0491-2716.1, p.2]
While EGUs are exempt from the industrial boiler NESHAP, the implementation timelines for that rule, the boiler area source rule, CISWI rule and the Transport Rule will occur in the 2011-2013 timeframe. In addition, the upcoming final ozone and PM NAAQS, regional haze SIPs, and utility MACT rule are all expected within the next few years. This confluence of emissions controls installations will likely result in a great increase in demand for certain technologies, with a tight turnaround schedule and a great increase in compliance costs. [EPA-HQ-OAR-2009-0491-2716.1, p.2]
American Coalition for Clean Coal Electricity (ACCCE)
ACCCE supports reasonable efforts to reduce interstate transport of air pollution. Improving air quality through cost-effective emission reduction measures is crucial to achieving the air quality goals of the Clean Air Act, while protecting the U.S.economy and American workers. [EPA-HQ-OAR-2009-0491-2874.1 p.2]
However, the proposed compliance deadlines for the Transport Rule do not provide adequate time for EGUs to implement measures, especially the retrofit of pollution controls, necessary to meet the Transport Rule emission budgets.Moreover, if controls cannot be installed in time, we do not believe that purchasing allowances or other potential compliance strategies are feasible or desirable ways to address this timing problem. [EPA-HQ-OAR-2009-0491-2874.1 p.2]
Therefore, we urge EPA to adjust the compliance deadlines to take into account the time that is most likely to be necessary to retrofit S02 and NOx controls:
:: Defer the proposed January 1, 2012 date by at least 12 months, which would shift the date for initial NOx and S02 reductions to January 1, 2013 or later.
:: Defer the proposed January 1, 2014 date by at least 18 months, which would shift the compliance date for EGUs in Group 1 states to July 1,2015 or later.
Deferring both deadlines would be consistent with the D.C. Circuit's opinion in North Carolina v. EPA. Our comments are explained in further detail below.
[EPA-HQ-OAR-2009-0491-2874.1 p.2]
The compliance deadlines for S02 and NOx reductions in the proposed rule are based on out of date information about the length of time necessary to implement pollution control measures for EGUs. For that reason, it is likely to be infeasible for many EGUs to install controls in time to comply with the proposed 2012 and 2014 deadlines.  [EPA-HQ-OAR-2009-0491-2874.1 p.2]
Under the proposed rule, state emission budgets for S02 and NOx emissions would first become binding on January 1, 2012, with a more stringent round of S02 emission reductions required from a smaller number of Group 1 states beginning on January 1, 2014. The proposed timetable would leave only six months between the expected promulgation of the Transport Rule in June 2011 and the initial date the requirements take effect on January 1, 2012. EGUs in Group 1 states would have only 30 months to come into compliance with the more stringent S021imits that take effect on January 1,2014.  [EPA-HQ-OAR-2009-0491-2874.1 p.2]
PROPOSED 2012 DEADLINE
EPA's initial compliance deadline of 2012 is based on an assessment that low- NOx burners or other NOx controls can be installed in a relatively short time and that coal-fueled EGU scan switch almost immediately to low-sulfur coal.  [EPA-HQ-OAR-2009-0491-2874.1 p.3]
NOx reductions
Based on recent experience, the installation of 10w-NOx burners can be completed within approximately 12 to 18 months.? Therefore, it seems very unlikely - if not impossible - that the 30 EGUs that EPA indicates will require low-NOx burner retrofits- would be able to complete design work, order equipment, secure construction permits, schedule outages and install the burners - all during the last half of 2011 to meet the proposed January 1,2012 deadline. [EPA-HQ-OAR-2009-0491-2874.1 p.3]
The preamble to the Transport Rule cites a very brief (only two pages of text) Technical Support Document (TSD) in arguing that 10w-NOx burners can be installed by 2012. However, the document offers only two anecdotal instances of 10w-NOx burner installations to support this claim, and the document does not explain why these isolated cases are a reliable basis for extrapolating future installation schedules for 10w-NOx burners for 30 EGUs. The TSD also cites a conversation with a representative of an association of pollution control equipment manufacturers - a self-interested source - as sole support for concluding that selective non-catalytic reduction units and burner upgrades can be installed 'quickly.'4 However, the TSD does not provide any factual support for this statement. [EPA-HQ-OAR-2009-0491-2874.1 p.3]
S02 reductions
The 2012 deadline does not provide enough time for EGUs to switch to low-sulfur coals, which EPA suggests as a compliance strategy. Our members' experience is that EGUs need more than six months to switch coal supplies and, in many cases, make changes to the plant that are necessary to burn lower sulfur subbituminous coals. Moreover, these changes may raise permitting issues that have to be addressed, leading to further delays in switching coal. [EPA-HQ-OAR-2009-0491-2874.1 p.3]
PROPOSED 2014 DEADLINE
The January 1, 2014 deadline for meeting the second round of S02 reductions is based, in part, on a 2005 analysis - Boilermaker Labor Analysis and Installation Timing.5 EPA cites this study as support for its conclusion that a single scrubber takes 27 months to install. However, the 2005 Boilermaker Study is based, in turn, on a 2002 study which provides an estimate of 27 months. The 2002 study is out of line with industry experience since 20066 and inadequate to support the conclusion that scrubbers to comply with the proposed Transport Rule can be installed and brought on line within a period of 27 months.'  [EPA-HQ-OAR-2009-0491-2874.1 p.4]
Over 50 GW of scrubbing capacity has been installed since 2006, and industry experience is that approximately 40 to 65 months is the length of time it has typically taken to install a single scrubber,' Exhibit 2 lists the major steps required to install a scrubber. Summing the average time for each of the steps shows that an average scrubber installation takes approximately 45 to 50 months to complete. This timeframe is considerably longer than the 30 months the proposed rule would allow to retrofit 14 gigawatts (GW) of FGD capacity (according to EPA) on EGUs in Group 1 states.  [EPA-HQ-OAR-2009-0491-2874.1 p.4]
LIKELIHOOD OF PERMITTING DELAYS
Even if NSR is not triggered for a particular pollutant, states and localities often require construction permits and other approvals before EGUs can commence work on a pollution control project. EPA's proposed timetables implicitly assume there will be no delays in obtaining these permits and approvals.  [EPA-HQ-OAR-2009-0491-2874.1 p.4]
Several of our members report that obtaining construction permits for pollution control equipment takes well over a year. In fact, according to one of our members, obtaining a permit for a single pollution control project recently took some 36 months. For that reason, some companies are hesitant to commit to a design until all permits are obtained, likely resulting in an FGD installation schedule at the upper end of the 40 to 65-month range for a typical installation.  [EPA-HQ-OAR-2009-0491-2874.1 p.5]
Further, we question EPA's conclusion that pollution control projects required by the Transport Rule are not likely to cause an increase in greenhouse gas (GHG) emissions that exceed the thresholds in the Agency's June 2010 GHG Tailoring Rule.10 Without a pollution control project exclusion, a scrubber project is a non-routine change for which a detailed technical assessment could be required to demonstrate there is no significant GHG emissions increase. The use of limestone wet FGD systems, for example, will increase carbon dioxide (C02) emissions because C02 is released during the conversion of lime or limestone to calcium sulfate or calcium sulfite. For example, a hypothetical 1000 MW EGU operating at an 80% capacity factor using 2.5% sulfur coal with a 95% efficient scrubber would have a potential C02 emissions increase of over 90,000 tons per year. Such emissions would exceed the 75,000-ton threshold in EPA's tailoring rule. In addition, parasitic load requirements associated with the FGD operation (approximately 1.5% of output}' could theoretically cause an increase in C02 emissions.  [EPA-HQ-OAR-2009-0491-2874.1 p.5]
In summary, the time required to complete the permitting process for new FGD installations is likely to be considerably longer than EPA's 'estimate' and delay the installation of controls far past 27 months.
American Electric Power
Unrealistic Deadlines - The compliance deadlines of 2012 for Phase I and 2014 for Phase II will make it impossible for utilities to comply on time. There is simply not enough time to permit, construct and install Flue Gas Desulphurization (FGD or scrubbers) and Selective Catalytic Reduction (SCR) control equipment or to build replacement capacity (if units are retired) by these deadlines. This is not a matter of conjecture regarding the time needed, as AEP has lengthy experience in the last decade of actual time frames exceeding 3 years to install scrubbers and/or SCRs. EPA needs to provide adequate time for utilities to comply with the rules as well as for states to implement the rules. [EPA-HQ-OAR-2009-0491-2665.1, p.4]
The SO2 budget levels in 2014 are significantly more stringent than those in 2012 for about half of the States covered under the Proposed Transport Rule. These States are ones most reliant on coal and that face the major portion of the compliance burden for limiting SO2 emissions. In particular, the S02 budgets in Eastern states which have AEP coal-fired power plants (i.e., Virginia, West Virginia, Ohio, Kentucky and Indiana) are very stringent. The SO2 tonnages in these states amount to an average emission rate of approximately 0.20 to 0.30 Ibs SO2 per million Btu, which can only be just attained by installing a scrubber. 96.5% is the current maximum level of removal that most retrofit scrubber designs for existing units can reliably and consistently achieve on an annual basis. [EPA-HQ-OAR-2009-0491-2665.1, p.5]
Phase I SO2 and NOx Requirements in 2012 are Too Soon and Infeasible
One of our greatest concerns with EPA's proposed Transport Rule is that the schedule for implementing the new program's more stringent emission caps is too fast. Under the proposal, the Phase I caps apply at the beginning of 2012 and the even more stringent Phase II caps apply at the beginning of 20 14. [EPA-HQ-OAR-2009-0491-2665.1, p.5]
While the EPA claims that the Phase I will require little investment in the way of new controls, its assumption is counterfactual and predicated upon high level modeling and not the actual physical, contractual and financial constraints at these facilities during such a short time frame. This very short time frame is made worse by the constraints placed on emissions trading, assuming that this recommended option is adopted for implementing the reduction requirements. [EPA-HQ-OAR-2009-0491-2665.1, p.5]
Additionally, EPA has assumed in setting the 2012 compliance deadline that coal switching could occur by that date and thus drive some emission reductions. While some coal switching may occur, AEP and other large utilities generally procure much of their coal through contracts several years in advance. By the time of final rule promulgation, almost all of AEP's 2012 coal supply will be procured. Fuel switching is therefore an unrealistic model option in 2012, and any post-2012 fuel switching assumed or expected by EPA should take into account existing long term contracts and the full direct and indirect costs of such fuel switching. [EPA-HQ-OAR-2009-0491-2665.1, p.5]
Timing of Phase II SO2 Caps is Too Soon and the Caps are Very Stringent
The proposed Phase II budget levels would require most of AEP' s coal-fired power plant units in these states to install FGD, switch to natural gas, or retire early in order to comply. A 2014 deadline for a second phase of SO2 reductions further complicates the planning and logistical challenges for compliance. [EPA-HQ-OAR-2009-0491-2665.1, pp.5-6]
Retrofitting additional scrubbers by the beginning of 2014 throughout the Phase II states is infeasible given that, in our experience, the typical time frame to design, permit, fabricate, and install such major pollution control equipment has taken more than three years. AEP has extensive experience in the retrofit application of FGD technology on coal-fired boilers, having managed the overall engineering, design, permitting, procurement, construction and commissioning of scrubbers on over 10,000 megawatts of capacity. Similarly, AEP has managed the installation of SCRs on approximately 14,600 megawatts of generation, which when combined, provides us a wealth of knowledge related to schedules and resource requirements to implement environmental controls. Couple this with our management of past and current landfill construction programs and we become a uniquely qualified source of experience and expertise in these areas. [EPA-HQ-OAR-2009-0491-2665.1,p.6]
EPA assumed that it takes approximately 27 months to build FGD equipment and approximately 21 months to build SCR equipment. Based on these timelines, EPA assumed additional FGD controls could be installed by 2014 and thus SO2 emissions could be further reduced in 2014 due to the technology. AEP's experience outlined below does not support an assumed 21 and 27-month construction duration for a typical SCR and FGD installation project, respectively. In order to more accurately represent the overall required FGD project duration, one must consider a minimum of three separate and distinct components that influence the time required for the overall project: I) the FGD construction; 2) landfill construction; and 3) stack construction. Each of these three separate components is discussed below. [EPA-HQ-OAR-2009-0491-2665.1,p.6]
Engineering and Construction of the FGD System takes up to 52 months to complete
The complexity of the 'construction' of an FGD System is very site-specific which strongly influences the time required for installation. The Front End Engineering & Design (FEED) work required to determine the feasibility of the project, to support the technology selection, and to establish the high level cost estimates requires a 6 to 8 month effort. Following the completion of the FEED effort, and assuming the decision is made to proceed with the project, an additional 6 to 8 months of preliminary engineering is required to advance the maturity of the design to the point that long lead time major equipment orders can be placed and the initial site preparation and underground relocation work ('construction') can commence. Based upon our experience to date and our analyses of the current resources, the subsequent continuation of the detailed engineering for the project, performed in parallel with the site FGD construction effort, including startup and commissioning of the new FGD System, will take 28 to 40 months. This results in an overall project duration from initiation to 'first gas' through the new FGD system of 42 to 52 months. The shakedown, debugging, and optimization process after 'first gas' through the new system can take up to 6 months. The below chart depicts 6,200 megawatts of our most recent retrofit experience: Mountaineer and Amos Unit 3 (1,300 megawatts each), Mitchell I &2 and Conesville 4 (800 megawatts each) and Cardinal 1&2 (600 megawatts each). [EPA-HQ-OAR-2009-0491-2665.1, pp.6-7]
Engineering and Construction of the Landfill takes on average 54 months to complete
Assuming no land acquisition is required, a nominal 20-25 acre landfill, typical of those required for a new FGD system, requires 54 months to complete. (Land acquisition could add 6-12 months to the overall duration.) The first 19 months are utilized to generate the conceptual layout of the proposed landfill, to then perform a detailed site investigation including soil borings, monitoring wells) installation and barrow area determinations and then to perform the landfill engineering and design in sufficient detail to support the permit application process requirements. Following the submittal of the applications, the review and subsequent approval cycle for the Air Permit, the Corp of Engineers 401 and 404 permits, and the Solid Waste Permit required to commence landfill construction consumes the next 17 months. The next 18 months is spent actually constructing the haul roads, barrow areas and landfill cells to the point of being available for first disposal use. [EPA-HQ-OAR-2009-0491-2665.1, p.7] 
A nominal 20 to 25 acre landfill is typical in size of those required for 5 years of capacity for the disposal of an FGD system byproduct. When a new landfill can be sited adjacent to an existing landfill, the time required to generate the conceptual layout of the proposed new landfill, to then perform a detailed site investigation including soil borings, monitoring wells and barrow area determinations and then to perform the landfill engineering and design in sufficient detail to support the permit application process requirements is 10 to 12 months. Following the submittal of the applications, the review and subsequent approval cycle for the Air Permit, the COE 401 and 404 permits and the Solid Waste permit required to commence landfill construction can consume the next 6 to 10 months. This cycle duration is highly dependent upon the number of simultaneous applications within the agencies and their staffing levels, and the unpredictable extent of third party opposition. Actual construction of haul roads, barrow areas and landfill cells to the point of being available for first waste disposal results in an overall duration of 40 to 42 months, as shown below from our actual construction of the Mountaineer Plant and Cardinal Plant Landfill projects. [EPA-HQ-OAR-2009-0491-2665.1, p.7]
When a new landfill must be located remote to any existing landfill, the overall project schedule is extended by an additional 10 to 20 months, as shown below from our actual construction of the Amos Plant, Clinch River Plant, Kyger Creek Plant and Clifty Creek Plant Landfills. The time required for landfill engineering, permitting, and construction could be lengthened substantially by EPA's coal combustion residuals rule proposed on June 21,2010 (75 Fed. Reg. 35128). [EPA-HQ-OAR-2009-0491-2665.1, pp.7-8]
Engineering and Construction of the Stack takes on average 46 months to complete 
In addition to the FOD and Landfill construction durations, it should be noted that a typical wet-FOD concrete stack with a single FRP liner, built to OEP height, can take 44- 48 months to construct, dependent upon State permitting requirements. (Certain States allow construction of the stack foundation prior to receipt of the air permit.) The first 8 months are consumed performing the air modeling to determine stack location and height. Along with the stack information, additional engineering information needed to support the air permit application is compiled. Review and final approval of the air permit typically takes the 12 months. Upon receipt of the air permit, the stack foundation installation can be accomplished in 4 months (absent severe weather conditions) followed by 24 months required to slip form/pour the concrete shell and install the stack liner. These durations are based upon our actual construction of eight such stacks over the past SIX years. [EPA-HQ-OAR-2009-0491-2665.1, p.8]
Engineering and Construction of the SCR takes up to 42 months to complete 
Very similar to an FOD project, the complexity of the construction of an SCR System is also very site-specific, which can significantly effect the time required for installation. The Front End Engineering & Design (FEED) required to determine the feasibility of the project, to support the technology selection, and to establish the high level cost estimates requires a 4 to 6 month effort. Following the completion of the FEED effort, an additional 4 to 6 months of preliminary engineering is required to advance the maturity of the design to the point that long lead time major equipment orders can be placed and the initial site preparation and underground relocation work can commence. In some instances, the analyses and final determination of steam generator pressure part modifications to facilitate SCR operation can extend this engineering effort up to an 18 month duration. Again, based upon our experience to date, the subsequent continuation of the detailed engineering for the project, performed in parallel with the site SCR construction effort, including startup and commissioning of the new SCR System, will take 24 to 36 months. This results in an overall project duration from initiation to 'first gas' through the new SCR system of 32 to 42 months. The below chart depicts approximately 8,000 megawatts of our most recent retrofit experience: Cardinal 1 &2 (600 megawatts each), Cardinal 3 (635 megawatts), Kyger Creek 1-5 (215 megawatts each), Clifty Creek 1-5 (215 megawatts each), Mitchell 1&2 (800 megawatts each), Amos 1&2 (800 megawatts each) and Conesville 4 (800 megawatts). [EPA-HQ-OAR-2009-0491-2665.1, pp.8-9]
Other factors affecting the engineering and constrnction schedules
In addition to the front end permitting schedule constraints, several other factors strongly influence the overall schedule of work and project durations. During these challenging economic times and the inherent downturn in the number of large, capital intensive projects, domestic suppliers of environmental equipment, materials and services have scaled back production and skilled resources in an attempt to maintain their long term viability. Contrary to the belief of some that this situation would make major components and material more readily available, economic stagnation and uncertainty lead suppliers to scale back, which results in longer lead times for critical system components. As examples, the lead time after receipt of order for limestone ball mills for FGD systems has increased from 70 weeks in 2006 to 90 weeks in 2011. Major electrical transformers are currently quoted at a 40-48 week delivery. Specialty alloy metals necessary for wet FGD vessel fabrication currently require a minimum of 32 weeks for delivery of the raw materials to the fabricators so that they can begin their manufacturing work. When numerous Utilities are forced to move to market simultaneously seeking the same components in a severely constrained timeframe, lead times for practically all significant system components will be further exacerbated. [EPA-HQ-OAR-2009-0491-2665.1, p.9]
With today's era of high unemployment, one could surmise that labor availability should not and will not be a constraint to the timely execution of FGD and SCR projects. However, it should be understood that highly skilled labor in specific areas of expertise are required to construct these complex systems. Not every Union Boilermaker can weld exotic metals. In fact, only slightly more than half, approximately 55%, of the union members are currently certified to perform this task. Similarly, FGD systems utilize a significant quantity of Fiberglass Reinforced Plastic (FRP) piping within the processes, which requires unique skills to perform section-to-section joining. Only 15% of the total available union pipe-fitters are currently certified to perform this task. Numerous other highly specialized skills are required of other individual crafts, and similar availability statistics are valid. [EPA-HQ-OAR-2009-0491-2665.1, pp.9-10]
Furthermore, this schedule does not take into account the need for all controls to be permitted, engineered, contracted and constructed simultaneously. AEP acknowledges the total amount of retrofits is likely to be on a scale similar to what was achieved in preparation for compliance with CAIR. Unlike CAIR, the Proposed Transport Rule does not provide the timing for a phased approach to construction given the inability to utilize an existing allowance bank and the proposed tighter timeline for compliance. This means that every uuit undergoing a retrofit would have the same timeline for engineering, procurement, construction and operation and thus be concurrently relying on the same specialized segments of the required labor force and material suppliers, greatly straining resources. [EPA-HQ-OAR-2009-0491-2665.1, p.10]
In addition to any PSD or state air quality permitting, some state regulations require obtaining public utility commission approval in the form of a certificate of need. These are issued for projects required by regulation and in some instances (i.e. Kentucky), must be issued prior to initiating construction. The process to obtain the approval includes approximately 6-months to prepare the application then an additional 4 to 12 months (depending on the jurisdiction) for the Commission to evaluate the application, obtain public comment and process the order. The application includes detailed cost estimates that are only available after engineering is complete. Where the certificate is needed prior to initiating construction, an additional 4 to 12 months will be added to the engineering time estimates above. [EPA-HQ-OAR-2009-0491-2665.1, p.10]
 Simply put, EPA needs to provide more time for the full implementation of the Proposed Transport Rule. AEP recommends EPA keep in place for at least several more years the existing CAIR program. The SO2 and NOx reduction levels of the CAIR program were set at levels that EPA determined were appropriate to remedy interstate transport problems for both the ozone and fine particulate matter standards. Under this approach, Phase I of the Proposed Transport Rule would not begin until 2015. This schedule would provide additional time for companies to install the new control equipment to meet additional reduction requirements of the Proposed Transport Rule and for States to adopt and begin to implement this new control program. It would also allow EPA time to consolidate and coordinate the several active rulemakings affecting the decision to retire versus investing more in existing generating units for which the costs of the Proposed Transport Rule are most difficult to absorb. [EPA-HQ-OAR-2009-0491-2665.1, p.10]
Furthermore, the proposed time line for implementation is inconsistent with past multi-pollutant reduction programs. Congress, for example, provided almost a decade to implement in two phases the SO2 and NOx reductions mandated under the Acid Rain program. Similarly, EPA established a two-phase program for achieving the reduction obligations under the CAIR program. The Phase I deadlines for CAIR allowed almost five years from promulgation of the final rule until the first compliance year for S02 and almost four years for NOx. Similarly, EPA adopted the NOx SIP-Call program in September 1998, allowed States a full year until September 1999 to submit implementation plans, and did not apply the NOx control requirements until May 2003, over 4-1/2 years after EPA promulgation of the final rule. [EPA-HQ-OAR-2009-0491-2665.1, pp.10-11]
American Municipal Power, Inc. (AMP)
The Proposed Timelines are Unreasonable
The Transport Rule sets forth implementation and compliance timelines that are unrealistic and unworkable. EPA's proposed accelerated timelines will force the power industry to choose among several losing propositions: retire existing, cost-effective base load generation assets before replacement of such generation can be feasibly achieved; hastily attempt to retrofit existing plants with equipment that is either cost-prohibitive or commercially immature; or decrease overall electricity production in order to meet overly restrictive state emission budgets. The results of these choices will have severe cascading impacts on the power industry as well as other industry sectors and consumers. [EPA-HQ-OAR-2009-0491-2678.1, p.2]
EPA proposes emissions reductions and caps which take effect very quickly - in 2012 - with additional reductions occurring in 2014. While EPA believes that this phased approach allows adequate time for fossil fuel-fired generator owners to install pollution control equipment, it simply does not. It takes significant time to plan, design, permit, and install pollution control equipment at a power plant. [EPA-HQ-OAR-2009-0491-2678.1, p.2]
ARIPPA
Similarly, the January 2012 compliance deadline does not afford affected EGUs adequate time to develop compliance plans to achieve the emissions reductions necessary to meet the applicable standards in the Proposed Rule. In the Preamble to the Proposed Rule, EPA identifies and discusses its "Guiding Principles" for implementing the Proposed Rule. Among these Guiding Principles are consideration of cost effectiveness, providing the regulated community with incentives to achieve cost effective reductions and the flexibility to seek alternatives to less cost effective controls, and ensuring a reliable power supply. See 75 Fed. Reg. 45227. The imposition of an unduly stringent initial compliance deadline is inconsistent with these objectives. To the extent that affected EGUs are even able, from a technical feasibility standpoint, to comply with the requirements in the Proposed Rule, such sources would not be able to explore cost effective alternative controls, while still demonstrating initial compliance by the deadline in the Proposed Rule. [EPA-HQ-OAR-2009-0491-2794.1, p.19]
The imposition of this near-term compliance deadline would be particularly challenging for certain EGUs, like the ARIPPA plants, whose only options for reducing emissions would necessarily require drastic changes to technology and operations (to the extent that any such changes are even feasible). ARIPPA facilities and other similar plants cannot simply make relatively minor technological or operational changes through the addition of traditional add-on controls or fuel switching. Therefore, any compliance plan designed to meet the stringent emissions reductions required under the Proposed Rue would necessitate a substantial period of time to implement. [EPA-HQ-OAR-2009-0491-2794.1, p.19]
The imposition of a short-term compliance deadline would be especially challenging for the ARIPPA plants, who cannot simply reduce emissions through relatively minor technological or operational changes, such as adding backend controls or switching fuels. Instead, these facilities' only options for reducing emissions would necessarily involve drastic changes to technology or operational parameters (to the extent that any such changes are even possible). [EPA-HQ-OAR-2009-0491-2794.1, pp.21-22]
For these reasons, EPA should extend the initial compliance deadline in the Proposed Rule until January 1, 2015, to allow affected states and EGUs within those states sufficient time to develop and implement approved SIPs and compliance plans, respectively. [EPA-HQ-OAR-2009-0491-2794.1, pp.21-22] [[These comments can also be found in Section VII.C.]]
Associated Electric Cooperative, Inc. (AECI)
:: Utilities cannot engineer and construct scrubbers in a window of twenty-seven (27) months as EPA assumes. Allowing for additional time would provide some utilities an opportunity to add scrubbers in time to comply with the lower emission caps of the Transport Rule.  [EPA-HQ-OAR-2009-0491-2845.1 p.3]
A 2012 FIP deadline is not only unlawful as described above, it is also unrealistic. EPA's presumption that facilities can switch to lower sulfur coals or install low NOx burners (by 2012) if not already planning to do so is plainly wrong and the proposal offers inadequate support to justify these contentions. Even if coal switching were instantly placed on a fast track, the following project components would consume more time than afforded between now and 2012. These are mainly: Project scoping, engineering/design, permitting, coal contract negotiations, rail transport negotiations, bidding equipment and installation, material procurement, rail modifications, additions or modifications of coal unloading and conveying, and addition of new particulate controls to accommodate most (dustier) low sulfur coals. [EPA-HQ-OAR-2009-0491-2845.1 p.5]
Similar factors will impact the installation of Low NOx Burners or Over-fire Air for front end NOx reductions. These are mainly: Project scoping, combustion modeling, engineering/design, permitting, bidding equipment and installation, equipment procurement, and outage planning. Combined, these necessary steps will consume too much time to allow for systems to be installed and commissioned ahead of January 2012. [EPA-HQ-OAR-2009-0491-2845.1 p.5]
In summary, besides being unlawful and baseless, a 2012 CATR FIP is too aggressive given the realities of making necessary physical and operational changes necessary to comply. [EPA-HQ-OAR-2009-0491-2845.1 p.5]
Big Rivers Electric Corporation
The date certain for compliance beginning in 2012 does not take into account the need for final requirements of the rule to be in-place to specify the needs of engineering services.  Based upon the outcome of the engineering services, physical changes to existing control equipment or installation of new control equipment can take three or more years to complete when considerations of shop time to construct equipment, work force availability for construction and impacts to unit outage schedules for installation of equipment are factored into the time estimate. [EPA-HQ-OAR-2009-0491-2661.1, p.2]
In many cases, EPA has assumed a fuel switch to low sulfur coal without consideration of the process and timeframe required to do such.   Boiler design considerations must first be addressed when switching to a lower sulfur fuel to meet compliance which may limit the availability of low sulfur fuel.   Current contracts must be negated and new contracts established including transportation   Additional equipment or modifications to existing equipment are needed to abate increases in emissions from fuel handling modifications. In addition to the expense of changing to a low sulfur fuel, EPA's cost analysis of pollutant reductions does not include the penalties typically associated with ending fuel contracts early. [EPA-HQ-OAR-2009-0491-2661.1, p.2]
EPA's assumption that existing NOx control equipment can be operated at a greater efficiency than is currently operated is false.  Our units are currently reducing NOx at the highest efficiency capable in order to meet CAIR.  With consideration that the allotted timeframe of the proposal does not allow for installation of new control equipment or modification to existing equipment, in order to meet the proposed allocations our company will be forced to reduce generation significantly below our estimates beginning in 2012. [EPA-HQ-OAR-2009-0491-2661.1, p.3]
In closing BREC has realistically only one option to comply with the proposed compliance date of 2012 to meet the SO2 and NOx requirements and that is to reduce generation until control equipment can be installed.  The reduction in generation will not only be a financial burden for BREC, but will likely impact both our residential and industrial customers significantly.  The control equipment needed for compliance with the proposed rule cannot be designed, installed and operational until the regulation is finalized due to possible substantial changes that could be between the proposed and the final rule, which could affect both the design and cost of the control equipment.   BREC is asking EPA to follow previous rule making proposals and provide three years for the regulated community to install compliance measures after the rule is final. [EPA-HQ-OAR-2009-0491-2661.1, p.4]
Buckeye Power, Inc.
6. EPA has incorrectly assumed an overly aggressive and impossible installation schedule, rendering the rulemaking arbitrary.
Besides being unlawful, EPA's proposed rule is also unrealistic. The overall timeline for emission reductions across the industry is unreasonable and unrealistic. The assumption that FGDs and SCRs can be installed between the effective date of CATR and 2014 (27 months as proposed) is farfetched. Although Buckeye has already installed SCRs on its Cardinal Units and is in the process of placing a scrubber on the last of its Cardinal Units, forcing the industry to meet too tight a timeframe will necessarily increase costs of construction, affecting all utilities, including Buckeye as it works to complete its Cardinal Unit No. 3 scrubber by the end of 2012. [EPA-HQ-OAR-2009-0491-2710.1, p.12]
Calpine Corporation
Calpine supports the timing of the proposed rulemaking. Based on our experience with power plant construction we believe that there are ample supplies of materials and labor available to support power plant retrofits of pollution control systems that will need to occur by 2014. [EPA-HQ-OAR-2009-0491-3614, p.2]
City of Ames, Iowa
1) The timeframes that U.S. EPA assumes are adequate to budget, specify, bid, evaluate, contract, and install SO2 and NOx emissions reducing equipment are not realistic. They are too short! (See 75 FR 45273) If the 'Transport Rule' is not finalized until mid-year 2011, it is totally unrealistic for the City of Ames, for example, to source and install low NOx burners and overfire air systems at our two steam generating units by the proposed compliance date of January 1, 2012. The amount of time it would take to specify, bid, public notice, evaluate, award, and then fabricate, deliver, and install equipment is not possible in a six month period of time. Our experience bidding 'public improvement' projects as defined by Iowa Code 26.2, would contradict the statement made by Mr. Sam Napolitano during a webinar put on by U. S. EPA on July 26, 2010, where he stated that U.S. EPA assumed that a low NOx burner and an overfire air system (LNB-OFA) project could be sourced and installed in a six months. [EPA-HQ-OAR-2009-0491-2769, p.2]
5) The compressed compliance timelines of 2012 and 2014 (as previously discussed in Item 1) above, represent a great economic hardship for smaller utilities and the ratepayers of the smaller communities they serve. [EPA-HQ-OAR-2009-0491-2769, p.2]
City of Springfield, Illinois, Office of Public Utilities
For these same reasons, CWLP is concerned that in choosing 2012 and 2014 as the targeted compliance dates, USEPA's compliance schedule appears to be unreasonable and unrealistic, as well as potentially harmful to an already weakened economy. [EPA-HQ-OAR-2009-0491-2635.1, p.3]
City of Tallahasse
Compliance Deadline of 2012 is Unrealistic.
To implement a 2012 compliance obligation by a rule that is as far-reaching as the Transport Rule is unrealistic and problematic.  Generally, the EPA has insisted that emission levels required in 2012 would occur even in the absence of the Transport Rule, primarily relying on the emission reductions that have resulted from compliance with CAIR.  In order to meet our emission obligations under the currently proposed amount of allocations in CAIR, the City would be forced to perform either upgrades to existing control equipment, new SCR installation on one of our larger units, increased ammonia use in existing SCR control equipment, and quite possibly suspend the retirement of a more inefficient unit (Purdom 7 ORIS 689) while such work was done.  There are a number of concerns with this: permitting obligations that would have to be met; the process of obtaining bids and awarding contracts; and negotiating new ammonia slip limits in current permits, may also be an issue.  All of these require a fair amount of time and investment that is aggravated by the fact that other utilities will be doing the same, therefore inflating costs.  Also, the resolution of other environmental issues takes time, including water use and discharge permitting, and ash and gypsum management.  A recent control project in Florida was installed, and yet delayed several months to address such issues.  None of these factors appear to have been considered by EPA.  EPA must correct its control-installation timeline assumptions to match reality. [EPA-HQ-OAR-2009-0491-2669.1, p.2]
City Utilities of Springfield
The compliance time line is too short for practical implementation and will result in substantial cost overruns and waste.
Issue: As proposed, certain Group 2 SO2 units would be required to demonstrate compliance with reduced SO2 emission limits on or before January 1, 2014. Given that the final rule containing the mystery Appendix A allocation table will not be published before mid-2011, this allows less than 30 months to develop a compliance strategy, secure budget and rate authority, design, procure, erect, and performance-test a flue gas desulfurization unit. We, along with many others in our industry, would strenuously suggest that this is far too little time to perform these tasks in a reasonable and cost-effective manner. CU speaks from experience in this regard. When the CAIR rule was promulgated in mid- 2005 we immediately set about to design and install a selective catalytic reactor for our Southwest Unit 1. Still, we were unable to bring the new SCR into commercial operation prior to the annual CAIR NOx deadline of January 1, 2009. Given the inability to install a relatively passive SCR in forty-three months, we would be less than sanguine about the prospects of implementing a more mechanically complex FGD in less than thirty months. Moreover, the SCR project commanded a premium price to effect installation in calendar year 2008 at all. The SCR that was originally estimated to cost $33 million actually cost us $61 million. The cost differential stemmed entirely from the fact that all CAIR-affected units were competing for the same design, material, and labor pools. We would expect exactly the same phenomenon, if not worse, to occur in the FGD market over the next thirty-six months. In calculating the costeffectiveness of SO2 removal, we doubt that EPA has considered the artificial inflationary costs introduced by the compressed compliance timeline. The compliance timing problem is exacerbated by the concurrent EPA Boiler MACT rulemaking, which is expected to be finalized in late 2011. Many sources will find themselves caught in a regulatory Neverland between the promulgation of these two rules. In effect, utilities with multiple affected Transport Rule sources would not  -  or at least should not  -  develop a corporate compliance strategy until the MACT standard is finalized. To do otherwise would require TR compliance strategies to be changed midstream following MACT promulgation. This represents not only a waste of resources but also another source of delay in meeting the compressed TR schedule. [EPA-HQ-OAR-2009-0491-2721.1 p.5-6]
Recommendation: EPA should delay Group 2 Phase 2 compliance dates to somewhere between 2015 and 2017. This would come closer to harmonizing the Transport Rule and Boiler MACT, allow adequate time for the prudent planning required by utility regulatory commissions, and mitigate price spikes that have the effect of overturning EPA's economic assumptions.  [EPA-HQ-OAR-2009-0491-2721.1 p.6]
Class of '85 Regulatory Group
EPA Incorrectly Assumes that any Coal Fired Unit Can Burn Low-Sulfur Coal without Physical Modifications or Triggering Permitting Requirements.
EPA's conclusion that 'significant reductions' can be achieved by 2012 from the use of lower sulfur coals is based on the incorrect assumption that all coal-fired units can switch coal types without physical modifications to the boiler and associated equipment and without triggering pre construction permitting requirements. EPA's assumption is contrary to the position taken by its Office of Enforcement and Compliance Assurance ('OECA'), some states, and various environmental groups. [EPA-HQ-OAR-2009-0491-2854.1,p.8]
A considerable amount of changes to existing equipment, along with the installation of new or redesigned equipment, is required to convert most coal-fired EGUs designed for bituminous coal to 100% sub-bituminous coal, or even to a coal blend with some percentage of sub-bituminous coal. One Group member estimates that it will have to make the following changes to its facility before it can operate on sub-bituminous coal: [EPA-HQ-OAR-2009-0491-2854.1,p.8]
:: changes to coal mills to add water or steam inerting for explosion prevention;
:: changes to the boiler to add additional sootblowers due to the increased reflectivity of sub-bituminous coal ash;
:: changes to dust collection and suppression systems, including: upgrading electrical switchgear, junction boxes and lighting fixtures to dust tight and explosion proof standards, and changes to coal chutes, liners, and conveyor belt skirting to contain and eliminate coal and coal dust leakage;
:: the installation of methane gas detectors in coal conveying reclaim areas and other potential areas where coal may reside;
:: upgrades to fire sprinklers and detection systems in the coal handling areas;
:: installation of wash-down facilities inside coal conveying tunnels and along side coal-conveyor enclosures; :: upgrades to wastewater sumps to remove the waste wash water;
:: changes to wastewater processing facilities; and
:: additional changes, as necessary, in response to a new OSHA directive on general housekeeping practices in enclosed areas to minimize the accumulation of combustible coal dust. [EPA-HQ-OAR-2009-0491-2854.1,p.8]
EPA Underestimates the Time Necessary to Install Controls on an EGU.
EPA is proposing a second compliance deadline in 2014 based on the assumption that 'it takes about 27 months to install a scrubber and 21 months to install an SCR.' While the Class of '85 agrees that it is possible to install a scrubber or SCR within these timeframes, EPA should allot adequate time for sources to obtain any required construction and/or operation permits, go through the bid process, and obtain other required regulatory approvals (such as authorization from a public utility commission or similar state agency). [EPA-HQ-OAR-2009-0491-2854.1,pp.9-10]
Additionally, many EGUs are public entities that must comply with a lengthy and complex bidding process that involves the development of performance specifications; solicitation and response to bids; evaluation and selection of vendors; and, ultimately, negotiation and engagement of a contract. It is not unusual for this process to take three months to complete. [EPA-HQ-OAR-2009-0491-2854.1,p.10]
 EPA estimates that there are 30 months between the expected promulgation of the final rule and January 2014. There is a very real possibility that sources may not be able to obtain the necessary permits, engage the appropriate vendors, and complete installation and testing of controls within that timeframe. [EPA-HQ-OAR-2009-0491-2854.1, p.10]
Consumers Energy
EPA must recognize that the affected sources have been making substantial plans and progress towards the implementation of controls, in accordance with CAIR, which remains final and enforceable. Any changes to CAIR must take these plans into account.   [EPA-HQ-OAR-2009-0491-3795.1_NODA, p.5]
The changes to the schedule contained in the proposed Transport Rule are not attainable. Any attempt to meet them will result in limited success, substantial noncompliance across the region, with substantial cost penalties.  [EPA-HQ-OAR-2009-0491-3795.1_NODA, p.5]
Council of Industrial Boiler Owners (CIBO)
Large engineering projects to retrofit engineered equipment, such as SCRs or SO2 scrubbers to large boilers, take a considerable amount of time to execute. Before equipment may be purchased, detailed engineering is required to define the specific scope of work and develop a technical specification for the purchased equipment. Some CIBO member companies that operate large industrial boilers have recent experience that indicates the up-front engineering will take at least 12 months, and could reasonably be expected to take longer than that. Once the engineered equipment is ordered, lead times typically range from six to 24 months, depending on how much demand exists for the equipment. Thus, it is reasonable to expect that the installation would not even start until 2013 for many EGUs. [EPA-HQ-OAR-2009-0491-2751.1, p. 12] 
Crouch, Diane
The Transport Rule does not allow enough time for power companies to install the equipment needed to reduce emissions by the 2014 deadline. [EPA-HQ-OAR-2009-0491-3284, p.1]
Dayton Power and Light Company (DP&L)
Compliance Deadlines Are Overly Aggressive and May Be Impossible to Meet
The proposed rule establishes new reduction requirements that must be met within six, twelve, and thirty months after the final rule is issued. By contrast, the Phase 1 deadlines for the CAIR allowed almost five years from promulgation of the final rule until the first compliance year for S02 and almost four years for NOx:: Last year, the Lake Michigan Air Directors Consortium (LADCO) recommended that any CAIR replacement rule include an initial compliance date no earlier than 2017. [EPA-HQ-OAR-2009-0491-2637.1, pp. 5-6]
The need for additional time to comply is further demonstrated by past pronouncements by the EPA. The latest of EPA's emissions reductions deadlines under the proposed rule - May 1,2014 - are set to precede the NAAQS attainment deadlines - the earliest being April 2015. The CAIR rule implemented reductions in two phases, with the second more stringent phase beginning in 2015. The EPA based its implementation schedule on 'its analysis of engineering, financial, and other factors that affect the timing for installing the emission controls that would be the most cost-effective ....' The proposed emissions caps are more stringent than what was proposed for CAIR Phase II, and the EPA has not explained why it has proposed an accelerated schedule in light of its previous analysis. [EPA-HQ-OAR-2009-0491-2637.1, p. 6]
Similarly, DP&L respectfully suggests that the EPA has grossly underestimated the time required to install emissions control equipment. EPA determined that a flue gas desulfurization unit takes approximately 27 months to build, and a selective catalytic reduction unit takes only 21 months. Such a timeline is unrealistic, particularly if large numbers of utilities are trying to undertake similar projects at the same time throughout much of the country. The result of an overly aggressive set of compliance deadlines will likely result in backlogs and bottlenecks for key components of equipment and in being able to hire and bring to the projects the relatively few firms available to provide the engineering, design and construction expertise that is necessary for such programs. [EPA-HQ-OAR-2009-0491-2637.1, p. 6]
An additional factor warranting a reconsideration of the compliance deadlines is the implicit assumption that many coal-fired units can make a fuel switch to lower sulfur western coals at virtually the same time. Many units have fuel restrictions in their permits and are technologically incapable of combusting western coal without major modifications. Switching coal may also require major modifications to auxiliary operations such as coal handling waste treatment, etc., as well as the consideration of contractual obligations, transportation restrictions, and costs. [EPA-HQ-OAR-2009-0491-2637.1, p. 6]
Extending implementation deadlines is a necessity considering the substantial costs and additional time required to comply. [EPA-HQ-OAR-2009-0491-2637.1, p. 6]
DTE Energy
Compliance Deadlines
2012 Deadline
It is unreasonable and unrealistic to expect the emission reductions required in the proposed rule by January 2012, merely six months after EPA expects to issue the final Transport Rule. [EPA-HQ-OAR-2009-0491-2851.1,p.4]
Boilers designed for firing higher BTU bituminous coal cannot make seamless switches to subbituminous coals, even if the coals and their transportation capacity were somehow instantly more available. The ability to make quick, low cost emission retrofits is significantly overestimated by EPA in determining 2012 compliance limits are appropriate. [EPA-HQ-OAR-2009-0491-2851.1, p.4]
2014 Deadline
EPA claims that additional FGD and SCR systems can be permitted, designed and installed between June 2011 (expected date to issue the final Transport Rule) and the end of 2013. EPA claims this can be accomplished because they have determined it takes 27 months to design, permit, and build FGDs and 21 months to design, permit, and build SCRs. Based on DTE's experience, EPA's assumptions are incorrect.[EPA-HQ-OAR-2009-0491-2851.1, p.5]
 DTE has built and commenced operation on approximately 1,600 MW of FGD and 2,400 MW of SCRs. These projects required a full 36 months for FGD construction and 30 months for SCR construction. This is in addition to the time required to permit these major projects. In United States v. Xcel Energy, EPA recently suggested ' ... a permit application must be submitted prior to construction, and permit approvals take, at a minimum, eighteen months to two years.' [emphasis added] This is consistent with DTE experience permitting major projects, and is consistent with UARG's analysis of implementation schedules. [EPA-HQ-OAR-2009-0491-2851.1,p.5]
There is simply not enough time for EGUs to deSign, permit, build and install new equipment, if necessary, to meet the 2014 emission reduction deadlines. [EPA-HQ-OAR-2009-0491-2851.1,p.5]
Dynegy, Inc.
EPA Should Defer the Effective Date of the Transport Rule Until 30 to 36 Months After Promulgation
As proposed, the Transport Rule would take effect in 2012, less than one year after the rule is finalized, with a second phase of SO2 reductions to begin in 2014. These dates are contrary to the recommendations of the Lake Michigan Air Directors Consortium that recommended any CAIR replacement rule include an initial compliance date no earlier than 2017. Dynegy believes EPA should defer implementation of the Transport Rule until 30 to 36 months after the rule is finalized for several reasons. [EPA-HQ-OAR-2009-0491-2698.1, pp.1-2]
E.ON U.S.
The timeframe for installation of control technologies is too short.  [EPA-HQ-OAR-2009-0491-2797.1, p.5]

EPA assumes that FGD's and SCR's can be retrofitted in time for 2014 compliance (specifically, estimated deployment times of 27 months for an FGD and 21 months for anSCR). EPA has advised that these timeframes are based on historical construction periods. However, EPA's projections for required time for installation are inconsistent with the recent experience of LG&E/KU in implementing four FGD and six SCR projects. EPA overlooks the fact that regulated utilities are required to obtain approvals from their state utility commissions before undertaking major projects such as installation of FGD or SCR controls. [EPA-HQ-OAR-2009-0491-2797.1, p.5]

The timeframes assumed by EPA are also unrealistic and unworkable because they do not consider lead times prior to the beginning of actual construction. Our experience suggests four to six months for conceptual design, six months for bidding and contracting with an engineering, procurement and construction firms, 12 to 18 months for engineering and equipment lead times, six months for regulatory approvals, six months for internal design and preparation of regulatory approvals, and six months for financing. Aggregated, a major project takes some 4.5 to 6.5 years to implement from project initiation to commencement of operation. This timeframe does not account for time necessary to evaluate different control technologies and the bidding of the technologies, which can take an additional year. From 2007 to 2010, LG&E/KU brought four FGD's on line (Ghent Unit 3, Ghent Unit 4, Ghent Unit 1, and Brown Unit 3). Those FGD projects have taken on average 54.5 months from project initiation to commencement of operation. Other utilities have advised that their experience indicates that an FGD retrofit project, from project initiation to commencement of operation can take up to 60 months.  [EPA-HQ-OAR-2009-0491-2797.1, pp.5-6]
East Kentucky Power Cooperative
EKPC Concerns Regarding Compliance Deadlines [EPA-HQ-OAR-2009-0491-2776.1, p.1]
In drafting the proposed rule, EPA assumed that utilities such as EKPC could install all necessary equipment to meet the new requirements by the 2012 and 2014 deadlines established in the rule. EKPC is concerned that the practical constraints of financing, purchasing and permitting new equipment to comply with the rule will make compliance in a timely manner challenging if not impossible. EKPC would request that EPA recognize these practical constraints and allow for either a waiver of permitting requirements or allow the regulated community to request extensions when necessary to achieve compliance. [EPA-HQ-OAR-2009-0491-2776.1, p.1]
Edison Electric Institute (EEI)
The lead time for both building new, efficient fossil-fuel plants or retrofitting existing plants vary but in many cases is extensive due not only to engineering complexity, but also to the difficulty of obtaining the required pre-construction environmental permits. Permits for all types of new generation are subject to challenges that can lead to lengthy and costly construction delays. Many companies also must gain approval from financial regulators and/or an Independent System Operator (ISO) or Regional Transmission Organization (RTO), which operate a region's electricity grid, administer the region's wholesale electricity markets, and provide reliability planning for the region's bulk electricity system. [EPA-HQ-OAR-2009-0491-2697.1, p.6]
Other companies support the Transport Rule deadlines as proposed and believe that the Transport Rule can be met as scheduled through a variety of measures, including existing controls, controls under construction and fuel switching (either permanent or as a temporary bridge). Exelon Corporation states that there is over 45,000 megawatts of combined cycle gas generation in Group 1 SO2 states that had an average capacity factor of 19 percent in 2009, leaving significant margin for additional generation from existing natural gas facilities if needed during a transition period.  [EPA-HQ-OAR-2009-0491-2697.1, p.7]
EEI believes that it is imperative that EPA, the Federal Energy Regulatory Commission (FERC), the Department of Energy (DOE), ISOs/RTOs, and states work together to utilize all tools available to consider compliance targets and their timing for all upcoming EPA regulatory actions. [EPA-HQ-OAR-2009-0491-2697.1, p.7]
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.25-26.]
While some of our member companies have stated that they are able to meet the requirements of the proposed rule due to some combination of individual company approaches to addressing environmental issues, state requirements, settlement agreements, fuel mix or other factors, other EI members have concerns regarding the proposed Transport Rule.
One concern is the proposed Transport Rule establishes new reduction requirements that must be met only 6 and 30 months after the final Transport Rule is issued.
Some of our member companies have expressed concern that EPA's assumptions regarding their current control technology projects may be inaccurate and that they will have difficulty in achieving the initial 2012 compliance deadlines.
[This comment was also submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010. See Docket Number EPA-HQ-OAR-0491-1746, pp.26-27.]
The Proposed Rule Will Adversely Affect Some EEI Member Companies  
Some of EEI's member companies have stated that they are able to meet the requirements of the proposed rule -- due to some combination of individual company approaches to addressing environmental issues, state requirements, settlement agreements, fuel mix or other factors. Some companies believe that compliance with the Transport Rule and even other air regulations will be achievable given factors such as the industry having existing power system capacity in excess of minimum reserve levels, relatively modest projections of load growth, proposed new generation facilities, and load management practices. Some companies support the 2012 and 2014 deadlines of the Proposed Rule and the need to expeditiously reduce interstate transport of SO2 and NOx emissions. [EPA-HQ-OAR-2009-0491-2697.1, pp.7-8]
[These comments were also submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.100-101.]
Other EEI members have concerns regarding the proposed Transport Rule.
Concerns with the 2012 and 2014 implementation schedule   
Companies in nine states would need to reduce their SO2 emissions by at least 50 percent from 2009 to 2014. Even the Ohio Environmental Protection Agency recognizes this challenge for the state's power companies, as stated in testimony before the Senate Environment & Public Works Committee on July 22, 2010 by Chris Korleski:
[These comments were also submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.26.]
[These comments were also submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.101.]
There is concern by some companies that simultaneously adding controls at many units can stress labor, materials, and state and local regulatory agencies, and that completing control installation, especially in cases with multiple simultaneous projects, by the end of 2013 to meet the 2014 compliance deadline is unrealistic. Some EEI member companies believe that the full schedule, from conceptualization to regulatory approvals by financial regulators and air quality permitting agencies, through construction and operation of a SO2 scrubber, can take up to 60 months. This assumption stands in stark contrast to EPA's estimate that a new scrubber can be installed in 27 months, which appears to be based upon a limited sample of company experiences.  [EPA-HQ-OAR-2009-0491-2697.1, p.9]
[These comments were also submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.26.]
Consumers Energy describes a further complicating factor. In Michigan, before shutting down or restricting the operation of units, approval must be granted by both the Michigan Public Service Commission (MPSC) and the Midwest Independent Transmission System Operator (MISO). Furthermore, notification to EPA is required. Retiring units or placing units into long term cold storage earlier than planned will increase customer rates, which the MPSC is resistant to do, especially in today's economy. A notification must be provided at least 26 weeks prior to engaging in such an activity and then MISO will evaluate whether or not the generation resource is necessary for system reliability. [EPA-HQ-OAR-2009-0491-2697.1, p.9]
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.52-53.]
One concern is that the proposed Transport Rule establishes new reduction requirements that must be met only six and 30 months after the final Transport Rule is issued.
Some of our member companies have expressed concern that EPA's assumptions regarding their current control technology projects may be inaccurate and that they will have difficulty in achieving the initial 2012 compliance deadlines.
There also is concern by some companies that simultaneously adding controls at many units can stress labor, materials, and state and local regulatory agencies, and that completing simultaneous control installations by the end of 2013 to meet the 2014 compliance deadline is unrealistic. This maybe especially true in nine states where electric generating units would need to reduce their sulfer dioxide emissions by at least 50 percent from 2009 to 2014.
Some EEI member companies believe that the full schedule, from conceptualization to regulatory approvals by financial regulators and air quality permitting agencies, through construction and operation of an SO2 scrubber, can take up to 60 months. This assumption stands in stark contrast to EPA's estimate that a new scrubber can be installed in 27 months.
EEI believes that it's imperative that the EPA, the Federal Energy Regulatory Commission, FERC, and the Department of Energy and states work together to utilize all tools available to meet compliance targets while maintaining electric system reliability.
[These comments were also submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.102.]
Edison Mission Energy (EME)
Similarly, EPA mistakenly assumes that the 14 gigawatts ("GW") of SO2 controls and 1 GW of NOX controls that will be required for Phase II compliance can actually be installed in the 30 months between when EPA intends to finalize the rule (mid-2011) and Phase II's start date in 2014, even though industry experience suggests that roughly twice as much time will be required to install those controls. [EPA-HQ-OAR-2009-0491-2707.1, p.3]
The Aggressive Emissions Reductions Proposed By EPA For SO2 and Nox During Phase I and II Of The Proposed Rule Are Also Technologically Infeasible [EPA-HQ-OAR-2009-0491-2707.1, p.17]
EME also believes that the compliance deadlines contemplated by EPA for imposition of the SO2 and NOx caps in 2012 and 2014 are technologically infeasible because they are based on inaccurate assumptions about: (i) the level of control efficiency provided by existing SO2 and NOX controls; and (ii) the amount of time it will take to install the emission controls that EPA admits will be required by Phase II of the Transport Rule. [EPA-HQ-OAR-2009-0491-2707.1, p.17]
With respect to the second assumption, EPA readily admits that compliance with Phase II's 2014 deadline will require 14 GW of coal-fired capacity to be retrofit with flue gas desulfurization ("FGD") units (for SO2 control) and 1 GW of capacity to be retrofit with selective catalytic reduction ("SCR") units (for NOx control), 46 yet assumes that they can be installed during the time period between when the Transport Rule is finalized (assumed to bemid-2011 by EPA) and 2014. Even assuming no delays, EME does not believe that such installations are possible in the timeframe contemplated by the Proposed Rule based on industries' experience installing such systems over the preceding decade (see Section III.B.2).Further complicating the ability of affected sources to comply with the Phase I and Phase II caps are the labor shortages created by the demand for skilled labor necessary to install and maintain all of the emissions controls required by the Proposed Rule (see Section III.B.3). As explained in Section III.B.4, based on the foregoing EME respectfully submits that EPA should: (1) modify the 2012 state-wide emission caps so that they actually reflect the level of emissions controls that can be obtained for either existing or pending (i.e., those that will be available by 2012) emission control systems; and (2) push the Phase II deadline out to 2016 to allow sources sufficient time to install the controls that will be required by the Phase II cap. (Note: EME's recommendation with respect to 2016 is based on EPA's assumption that it will finalize the Transport Rule by mid-2011.) [EPA-HQ-OAR-2009-0491-2707.1, pp.17-18]
EPA's Phase II SO2 Cap Is Premised On Assumptions About The Time It Will Take To Install Additional Emissions Controls That Are Inconsistent With Real World Experience Installing Such Equipment [EPA-HQ-OAR-2009-0491-2707.1, p.22]
EPA's assertion that additional emissions controls can be installed by 2014 is premised on its assumption that it only "takes approximately 27 months" to install an FGD and "21 months" to install an SCR. EME understands that EPA's estimates are taken from a 2002 document in which TECO estimated it could install controls within those timelines. In fact, however, it appears that this utility's SCRs and FGDs did not become operational until approximately 5 years later  -  suggesting that the estimated timelines were overly optimistic. Moreover, based on industry's experience installing such systems, EME believes that EPA's installation timelines are plainly inadequate. [EPA-HQ-OAR-2009-0491-2707.1, pp.22-23]
[See [EPA-HQ-OAR-2009-0491-2707.1, pp.22-25 for additional comments pertaining to EPA's Phase II SO2 Cap Is Premised On Assumptions About The Time It Will Take To Install Additional Emissions Controls That Are Inconsistent With Real World Experience Installing Such Equipment]
Together these considerations  -  the need for 14 GW of new FGD; 1 GW of new SCR; the fact that most plants cannot begin design and construction until the rule is finalized; the need for permits to install and operate these controls; and the need for staggered outages to complete installations, which outages can only occur in the fall and spring and can only occur after construction is complete  -  make it abundantly clear that EPA's proposed 2014 deadline is utterly unrealistic. 56 [EPA-HQ-OAR-2009-0491-2707.1, p.25]
Based On The Technological Infeasibility Of EPA Proposed Emissions Caps EPA Should Amend Its Phase I and Phase II Compliance Deadlines [EPA-HQ-OAR-2009-0491-2707.1, p.27]
With respect to Phase II, EPA claims to have set those caps based on emissions reductions that are obtainable after the installation of additional controls. Specifically, EPA estimates that 14 GWs of FGDs and 1 GW of SCR will be required by 2014; although, as we note above, other sources have projected that the Transport Rule will require the installation ofSO2 scrubbers at 6% of U.S. coal fired power plants that generate 118 million MWh or approximately 40 GW of scrubbers in order to comply with both the Transport Rule and HAP MACT caps. EPA's assertion with respect to the feasibility of the 2014 deadline relies exclusively on its assumptions about the time it takes to install these additional controls. EPA simply asserts that the necessary FGD and SCRs can be installed all at once in the 30 months between when the Agency hopes to finalize the rule (mid-June 2011) and January 1, 2014.Setting aside the Agency's ability to issue the rule by mid-June 2011 given the volume of comments it is likely to receive, EME has concluded, as explained above, that EPA relied on unrealistic and overly optimistic assumptions about the construction timeline for the additional controls that will be required by the rule. Based on industry experiences, the availability of skilled labor, and electrical system reliability consideration, EME believes that it takes between40 and 60 months to install the controls that EPA believes are required, and therefore the Agency should not start the Phase II compliance deadline until January 1, 2016 to give EGUs the time they need to install additional controls. A 2016 deadline would have the added advantage of better aligning the Transport Rule's requirements with Utility MACT, thus allowing sources to identify the most cost-effective alternatives to complying with both rules.  [EPA-HQ-OAR-2009-0491-2707.1, pp.28-29]
The Phase II Unit-Level Allocations Should Not Penalize Early Adopters, But Rather Should Incentivize Early Action [EPA-HQ-OAR-2009-0491-2707.1, p.33]
Footnote 56: Additionally, the practical limitations on trading created by the state-by-state assurance provisions in the Proposed Rule will exacerbate this problem. [EPA-HQ-OAR-2009-0491-2707.1,  p. 25]
Electric Energy, Inc. 
I. The timeframe for installation of an FGD is unrealistic.
The Joppa Steam Generating Plant is subject to the USEPA CAIR rule and Illinois rules that were based on the USEPA CAIR rule. Both of these rules limit emissions of SO2 and NOx. In addition Joppa is subject to NOx and SO2 emission limits under Illinois rule 35 IAC Part 225, Subpart B, Section 225.233 Multi Pollutant Standard (MPS). [EPA-HQ-OAR-2009-0491-2628.1, p.1]
 To comply with the current USEPA CAIR Rule, the Illinois CAIR Rule, and the Illinois MPS rule, Joppa will need to reduce S02 emissions approximately 50% from current levels. EEl is currently evaluating technologies that will cost effectively achieve this level of S02 reduction. EEl is planning to use banked allowances and to purchase additional SO2 allowances to cover emissions reductions needed, which is an allowed method of compliance. [EPA-HQ-OAR-2009-0491-2628.1, p.1]
The timeframes assumed in the Transport rule for installation of pollution control equipment is unrealistic. The Transport rule is expected to be issued as final in June 2011, with SO2 compliance by January 1, 2014. It is not reasonable to engineer, permit, procure, and construct a scrubber beginning in June 2011 and have it operational by 1/1/2014, a period of less than thirty months. Based on experience obtained from other Utilities, it would take approximately 48 months to install an FGD. In addition, adding an FGD to a plant involves more than the FGD itself. The disposition of the gypsum that is generated requires construction of a landfill. Permitting a landfill in Illinois takes 3-5 years. Also wastewater treatment and water discharge permitting have to be addressed for an FGD, which can take 3-5 years. [EPA-HQ-OAR-2009-0491-2628.1, p.2]
Empire District Electric Company (Empire District)
Empire District recommends that 2016 or later should be considered as the initial compliance date to allow for the efficient planning, budgeting, permitting, financing and construction of the required pollution controls. [EPA-HQ-OAR-2009-0491-2659.1, p.2]
Empire District began a study of our Asbury facility in early 2010 to determine the needed Air Quality Control Systems (ACQS) to equip the facility for the future.  We have expedited this study as quickly as feasible and practicable. Initial draft results indicate that installation of AQCS that includes a scrubber will be difficult to accomplish before sometime in 2015.  Meeting the 1/1/2014 date is impossible.  The actual projected timeline from the planning process to the construction completion process is approximately 60 months, not the 27 months stated in the CATR. [EPA-HQ-OAR-2009-0491-2659.1, pp.2-3]
EPA stated in the proposed CATR that a scrubber could be installed in 27 months.  As explained previously, this is not possible and 60 months is a much more realistic time frame for the planning, budgeting, permitting, financing, outage scheduling within the utility and the regional control authority, and installation of a scrubber.  Therefore, Empire District urges EPA to delay the effective date of Phase II of the CATR to the 1/1/2016 time period.  This would provide marginal time for scrubber installation and would more closely align CATR with other developing regulations.  In addition, we question EPA's statement that Low NOx Burners (LNB) can be installed in 6 months.  The permit for LNB can take 6 month to a year.  Planning and budgeting must occur before the beginning of the permitting period.  An outage must be scheduled for installation.  This outage must be coordinated not only within the local utility, but also with the regional control authority.  From planning to completion of installation for LNB a more realistic time period is 24 to 36 months.  In order to provide for an adequate period for AQCS installation, EPA should reconsider revising phase 2 date of 2014 to 2016 or later and the proposed dates of 2014 for one-year variability and 2016 three-year variability. [EPA-HQ-OAR-2009-0491-2659.1, p.7]
Energy Future Coalition
The Energy Future Coalition appreciates EPA's interest in the rapid implementation of the CATR. [EPA-HQ-OAR-2009-0491-2623.1, p.2]
Entergy Services, Inc.
Proposed Compliance Date  
If a final rule is not issued until the middle of 2011, as suggested by EPA, it is unreasonable to assume that a utility can develop a compliance strategy based on short allowance budgets for each State's fleet, schedule outages, install controls, and train operators to operate these controls efficiently by January 1, 2012.  Even after the most cost effective compliance strategy is developed, it has been Entergy's experience that this will take a minimum of 2 years to evaluate, finance, award a bid, schedule outages, permit, construct, train, and have fully operational pollution control equipment.  Entergy has reviewed EPA's technical document, EPA-HQ-OAR-2009-0491  -  Installation Timing for Low NOx Burners, and disagrees that utilities can complete "engineering, fabrication, delivery and installation" of pollution control equipment in a 6 month time frame, much less at a time when pollution controls will be offered at a premium and contractor availability throughout the country may be limited. [EPA-HQ-OAR-2009-0491-2847.1,p.6]
Environmental Defense Fund (EDF)
Emissions Reductions are Achievable and Forward-thinking Investment Can Help Industry Comply with Future Regulations  
a. Background on the Clean Air Interstate Rule Process and Timeline
EPA first proposed the Clean Air Interstate Rule (CAIR) in December 2003. After a comment period and lengthy review, EPA finalized CAIR in March 2005. NOx reductions were scheduled to begin in 2009 and SO2 reductions in 2010. In response to petitions for judicial review filed by the state of North Carolina and numerous power companies, the U.S. Circuit Court of Appeals for the District of Columbia vacated CAIR in July 2008. In December 2008, the Court reinstated CAIR until EPA adopted a replacement. The Phase I NOx program under CAIR began in 2009 and regulated entities were required to begin meeting the emission reductions requirements as promulgated under CAIR. In response to the Court's decisions, EPA proposed the Transport Rule in July 2010. [EPA-HQ-OAR-2009-0491-2834.1 p.13]
It has been more than seven years since EPA proposed to address the interstate transport of SO2 and NOx emissions from EGUs in the Eastern US. Many regulated entities have already taken steps to reduce their emissions to comply with Phase I of CAIR and many others are in the process of retrofitting their plants with emissions control technology. There has been a significant amount of time for industries to prepare for the proposed Transport Rule and the first compliance deadline of 2012 provides adequate time for industry to meet the new standards. [EPA-HQ-OAR-2009-0491-2834.1 p.14]
b. Emission controls are affordable and widely available, can be installed in a timely manner, and will not negatively impact electricity reliability
An analysis by M.J. Bradley & Associates demonstrates that emission controls are affordable and widely available, have been installed in a short period of time, and will not negatively impact electricity reliability with proper planning by industry officials.39 Sixty-five percent of existing coal-fired power plants have already installed or plan to install flue gas desulfurization systems (i.e. scrubbers) to control SO2 emissions and 50 percent have installed or will install NOx controls. The analysis noted that from 2008 - 2010, 60 gigawatts (GW) of coal capacity was retrofitted with scrubbers, indicating that industry can make substantial retrofits in a short timeframe. Scrubbers can reduce SO2 emissions substantially (by at least 95 percent) and selective catalytic reduction can reduce NOx emissions by 90 percent or more. The analysis also concluded that electricity reliability will not be impacted by the timely implementation of the proposed Transport Rule in any of the NERC regions. All NERC regions are expected to have between 22 - 42 percent reserve generating capacity in 2013. [EPA-HQ-OAR-2009-0491-2834.1 p.14]
EPA notes in its Regulatory Impact Analysis that only about 1.2 GW of coal-fired capacity, or 0.3 percent of the nation's coal-fired generating capacity, will be uneconomic to maintain under the proposed Transport Rule and will be retired or maintained as back-up generation for reliability purposes only. Under EPA's proposed remedy, only an additional 14 GW of coal-fired capacity will need to be retrofit with scrubbers for Phase II, which is less than one-fourth the 60 GW of retrofits that occurred between 2008 and 2010. Additionally, EPA projects that less than 1 GW of SCR controls will be installed for Phase II. [EPA-HQ-OAR-2009-0491-2834.1 p.14]
EquiPower Resources Corp.
Second, with respect to the Phase II unit-level emission allocations, which, unlike Phase I, expressly contemplate the installation of additional controls to obtain additional SO2 reductions, EquiPower believes that the Phase II compliance caps are infeasible. EPA presumes that the 14 gigawatts ("GW") of coal-fired capacity to be retrofit with FGD units (for SO2 control) and 1 GW of capacity to be retrofit with SCR units (for NOx control), can occur during the brief time window between when the Transport Rule is finalized (assumed to be mid-2011 by EPA) and 2014. EPA based its conclusion on its assumption that it only "takes approximately 27 months" to install an FGD and "21 months" to install an SCR. EquiPower understands that EPA's estimates are taken from a 2002 document in which TECO estimated it could install controls within those timelines. In fact, however, it appears that this utility's SCRs and FGDs did not become operational until approximately 5 years later  -  suggesting that the estimated timelines were overly optimistic. Moreover, based on industry's experience installing such systems, EquiPower believes that EPA's installation timelines are plainly inadequate. [EPA-HQ-OAR-2009-0491-2704.1, p.28]
For example, the Utility Air Regulatory Group ("UARG") has indicated that it actually takes between 40 and 60 months to install an FGD system and make it fully operational. Installation of an FGD requires a number of steps  -  (i) permitting, (ii) design and engineering, and (iii) actual construction and operation, all of which are time consuming. We would note that the preceding time estimates assume only one FGD and would have to be extended if multiple units at the same facility were all receiving FGDs.  PSD review, if it were determined to apply, would obviously further delay the installation of these controls. EquiPower notes that there are similar problems with respect to EPA's assumptions about the time it takes to install additional Nox controls. Again, the Agency has made assumptions with respect to the time it takes to design, engineer, permit and install an SCR that are unrealistic, and which face the same potential installation delays as an FGD. UARG has indicated that it takes approximately 32 to 46 months to install an SCR from start to finish. And to the extent a facility needs to install both an SCR and an FGD, the timelines for the individual installations would necessarily be extended even further, as it is not always possible to conduct these installations in parallel; more typically they are installed serially. Given the large numbers of scrubbers and SCRs that must be constructed to comply with the 2014 caps, the two and a half year control equipment installation window to satisfy the 2014 caps currently contemplated by the Transport Rule (from mid-2011 through 2014) is plainly insufficient. [EPA-HQ-OAR-2009-0491-2704.1, pp.28-29]
Put simply, the Transport Rule does not allow sufficient time for affected EGUs to install all of the necessary emission controls at all of its units. Further complicating the timeline, we would also note that some EGUs would not be in a position to even start work on addition controls until the Proposed Rule is finalized because of various regulatory and practical constraints. As noted above, waiting to begin the FGD or SCR installation process until the Transport Rule is finalized simply does not provide enough time to finish the installation before 2014. As such, EPA's rule places companies in a truly impossible position: They cannot obtain the financing or regulatory approvals necessary to begin design and construction until the Proposed Rule is final, but if they wait until that happens they will not be in a position to install the controls in the time that remains. Similarly, compliance with the Phase I and Phase II caps are likely to result in shortages of the skilled labor necessary to install and maintain all of the emissions controls required by the Transport Rule. Finally, implicit in EPA's timing is an assumption that all EGUs in need of control equipment can install it at the same time. This also ignores the fact that the outages required to complete installation and bring an FGD or SCR online cannot occur simultaneously. The outages have to be coordinated or electricity system reliability will be negatively impacted. Regulators typically only allow the tie-in period for a new piece of control equipment during periods of off-peak demand (i.e., fall and spring), and even then the outages would have to be staggered to ensure that they do not interrupt the electricity supply. These limitations can all materially impact the feasibility of the Transport Rule's compliance deadlines and suggest that they are unrealistic. [EPA-HQ-OAR-2009-0491-2704.1, pp.29-30]
Exxon Mobil Corporation
EM is concerned with the nearly immediate effective date of the rule. EPA has suggested they will promulgate a final rule in late spring 2011 and it will become effective January 1,2012. This is obviously unreasonable considering the costly impact to affected facilities. It is beyond reason to expect a facility to engineer, procure, and install controls in six months or even budget for purchasing additional allocations. [EPA-HQ-OAR-2009-0491-2841.1, p.16]
Florida Electric Power Coordinating Group, Inc. (FCG)
EPA has also substantially underestimated the time required for facilities to install emission controls, meaning that additional emission reductions will take much longer to achieve than EPA has assumed. EPA's erroneous assumption is that it takes 27 months to design, permit and build an FGD system, and 21 months to design, permit and build an SCR. EPA's timeline apparently only considered the time needed to actually build the system, and disregarded the critical time necessary to design and permit the equipment. Substantial recent experience reveals the actual time needed. Specifically, the Southern Company recently installed 15 FGD systems and 15 SCRs. The average time needed for an FGD system was 54 months (the range was 40 - 69 months), and for an SCR was 36 months (the range was from 28 - 42 months). Progress Energy recently installed nine FGD systems and nine SCRs, and it took approximately 44 months for an FGD system, and 38 months for an SCR. In addition, utilities typically put emission control projects out for competitive bid, which adds several months to the process to help ensure that the most cost-effective expenditure is being made. Also, the resolution of other environmental issues takes time, including water use and discharge permitting, and ash and gypsum management. A recent control project in Florida was installed, and yet delayed several months to address such issues. None of these factors appear to have been considered by EPA. EPA must correct its control-installation timeline assumptions to match reality. [EPA-HQ-OAR-2009-0491-2658.1,p.3]
Four Flags Area Chamber of Commerce
Under the existing proposal, there is not enough time for power generators to design, permit, fabricate and install pollution control equipment to comply with the new emissions levels established in the rule's second phase. [EPA-HQ-OAR-2009-0491-3807, p.1]
Georgia Department of Natural Resources, Air Protection Branch
In determining the base case emissions for 2014, EPA moved controls and emissions for modeling from 2015 to 2014.
As stated previously, Georgia has a multipollutant rule that requires SCRs and SO2 scrubbers to be installed on 22 large coal-fired units by July 1, 2015. The State rule includes a timetable that specifies equipment and dates of installation for each unit. The dates in the rule were negotiated with the owners of the affected units to install the equipment as expeditiously as practicable while taking into consideration the limited construction resources and to accommodate the CAIR and the State's extensive nonattainment planning requirements for fine particulate matter and ozone. Additionally, this control schedule was negotiated around power outage schedules to accommodate this construction while still meeting the demands of the electrical grid. Ten (10) units have already been retrofitted and are in operation. Based on real experience at these 10 units, the time required to retrofit a unit with an SCR and scrubber is approximately 48 months for each unit, not the 27 months assumed in the Transport Rule. Moving the date from 2015 to 2014 affects the dates of 6 units that are currently scheduled for retrofit between June 2014 and June 2015. EPA must reconsider their assumptions on how quickly these controls can be constructed and provide adequate support for those assumptions in the record. This is especially true if the final rule is issued later than currently reported by EPA. [EPA-HQ-OAR-2009-0491-2647.1, p.2]
Great River Energy
Great River Energy appreciates EPA's efforts to address non-attainment and interstate transport of pollution, especially as it can be achieved through both flexible and highly cost effective means. Unfortunately, for several reasons, as discussed throughout these comments, Great River Energy finds neither a cost effective nor flexible compliance program for our Minnesota combustion turbines.
EPA must realize several facts about our peaking turbines, which may not have been reflected in the IPM modeling and associated conclusions. Great River Energy has seven peaking plants, with a nominal capacity of approximately 1700 MW. With limited allowances, as currently proposed by EPA, GRE will effectively have two non-flexible compliance options. Our preferred option is to purchase allowances through intrastate or interstate trading. As discussed elsewhere, we have strong reservations regarding the viability of both intrastate and, to a lesser extent, interstate trading. This presents significant compliance and operational risks.
Failing our preferred' allowance purchasing' option, GRE must consider installation of pollution controls, namely selective catalytic reduction ('SCR'), on our already controlled and, in certain instances, annually limited to synthetic minor thresholds per plant Title V permits. Our combustion turbines have been using Ultra Low Sulfur Diesel (15ppm) since 2006. Therefore, we cannot expect to reduce S02 emissions any further. With respect to NOx emissions, all of our units have dry low NOx (DLN) burners and water injection for oil combustion. These peaking plants are already controlled for Transport Rule pollutants, yet will not be able to meet EPA's proposed NOx allowance allocations. While simple cycle SCR installations may have been completed in California and other non-attainment areas, these controls fall well outside of EPA's cost thresholds for the Transport Rule.
Even if GRE could justify the cost of these controls, EPA's control installation timelines are overly optimistic. There are numerous reasons, including detailed engineering design, permitting, construction, labor, financing, and resource availability, which call into question the industry's collective ability to bring SCR NOx controls on-line in 20 months, or FGD S02 controls on-line in 27 months. A single source with a detailed engineering design and associated construction documents could potentially issue for bid and optimistically complete a control proj ect as proposed by EPA's timeline, but it should not be the basis for a regional compliance program. In short, EPA has failed to provide a flexible and cost effective compliance program for peaking plants located in Minnesota. [EPA-HQ-OAR-2009-0491-2758.1 p.5]
Holland Board of Public Works
A compliance deadline of 2012 does not leave much time after the anticipated final rule is promulgated in 2011 to determine a cost-effective, cost-stable method of operating our affected unit.  [EPA-HQ-OAR-2009-0491-2861.1,p.1]
Hoosier Rural Electric Cooperative
The control efficiencies seem to be across the board limits and not indicative of technology and age of the units. [EPA-HQ-OAR-2009-0491-3758.1_NODA, p.2]
Independence Power & Light (IPL)
EPA failed to consider the constraints on the financial means and timetable for capital expenditures and the lack of economies of scale for controls called for by the Rule as to municipal EGUs. In addition, it is unlikely that municipal utilities, given their relatively small size, would be able to obtain a favorable queue position in what will undoubted by a long line of utilities seeking to fabricate the necessary controls. These problems place municipal utilities, like IPL, in a most difficult position because under certain circumstances they will be obliged to run units that will not have timely met the Rule's requirements to serve their customers' load, as they are obligated to do by statute. [EPA-HQ-OAR-2009-0491-2741.1, p.17]
Many municipal utilities such as IPL must undergo a series of prescribed steps in order to fund capital expenditures for the controls such as those assumed to be installed under the Rule. For capital expenditures of the order called for by the Rule IPL must first engage in cost of service studies to support subsequent ratemaking proceedings to raise electric rates to then establish the basis for bond issuance. This process alone requires at least one year of time and assumes that the bond capability of the utility at the time is sufficient for the amount of capital expenditure needed. At each step lies the potential for failure of achieving the ability to make the capital expenditure. The Rule finds that SCRs can be installed to meet enforceable allocations effective January 1, 2014 allocation requirements. See, e.g., 75 FR at 454286/3 ('a single SCR unit on average takes 21 months to install'). It is apparent from the length of time needed to accomplish the steps described above that this assumption is flawed. [EPA-HQ-OAR-2009-0491-2741.1, p.17]
For the reasons stated herein, IPL requests that EPA modify the proposed Rule by: 2 considering the time and burden on municipal utilities of obtaining the necessary capital for the controls mandated by the rules and the other obstacles that they face in meeting the rules in a timely manner. [EPA-HQ-OAR-2009-0491-2741.1, p.18] 
Indiana Builders Association 
Under the existing proposal, there is not enough time for power generators to design, permit, fabricate and install pollution control equipment to comply with the new emissions levels established in the rule's second phase. [EPA-HQ-OAR-2009-0491-2871.1,p.1]
The most significant reductions under the current proposal occur in 2014  -  only twoand- a-half years after the Rule is expected to become effective. Two-and-a-half years are not enough to design, permit, fabricate and install the necessary equipment. This unrealistic deadline could affect grid reliability if power companies are forced to prematurely close generation units to comply. If new scrubber byproduct storage facilities are needed in addition to emissions control equipment, the time line becomes much longer. [EPA-HQ-OAR-2009-0491-2871.1, p.2]
Indiana Cast Metals Association (INCMA)
The Indiana Cast Metals Association is one of the largest energy dependent sectors in Indiana and we strongly urge the EPA to delay implementation of the Transport Rule as it is proposed. The current proposal has several shortcomings that will result in needless economic harm to our members and the State of Indiana. [EPA-HQ-OAR-2009-0491-2178.1, p.1]
The most significant reductions under the current proposal occur in 2014  -  only two-and-a-half years after the Rule is expected to become effective. Two-and-a-half years are not enough to design, permit, fabricate and install the necessary equipment. This unrealistic deadline could affect grid reliability if power companies are forced to prematurely close generation units to comply. If new scrubber byproduct storage facilities are needed in addition to emissions control equipment, the time line becomes much longer. [EPA-HQ-OAR-2009-0491-2178.1, p.2]
Indiana Department of Environmental Management 
While Indiana welcomes the aggressive implementation schedule in the proposed rule, it is unlikely that all control systems can be built in the amount of time provided by the proposed rule. [EPA-HQ-OAR-2009-0491-2645.1, p.2]
Indiana Municipal Power Agency
Under the existing proposal, there is not enough time for power generators to design, permit, fabricate and install pollution control equipment to comply with the new emissions levels established in the rule's second phase. [EPA-HQ-OAR-2009-0491-3057.1,p.1]
IMP A questions whether the modeling the EPA used to determine the Rule's compliance requirements is up to date and accurate. The EPA based its assessments on equipment and capabilities that in some cases are not yet in place. In order for generation companies to comply with the emissions targets, they will have to install equipment that the EPA has mistakenly indicated is already operational or will be in service soon. This error underestimates the cost of compliance and exacerbates another inaccuracy in the EPA's compliance assumptions - the time and cost needed to design, permit, fabricate and install control equipment. [EPA-HQ-OAR-2009-0491-3057.1,p.2]
The most significant reductions under the current proposal occur in 2014 - only two-anda- half years after the Rule is expected to become effective. Two-and-a-half years are not enough to design, permit, fabricate and install the necessary equipment. This unrealistic deadline could affect grid reliability if power companies are forced to prematurely close generation units to comply. If new scrubber byproduct storage facilities are needed in addition to emissions control equipment, the time line becomes much longer. [EPA-HQ-OAR-2009-0491-3057.1,p.2]
Indiana Utility Shareholders Association
The most significant reductions under the current proposal occur in 2014- only two-and-a-half years after the Rule is expected to become effective. Two and- a-half years are not enough to design, permit, fabricate and install the necessary equipment. If new scrubber byproduct storage facilities are needed in addition to emissions control equipment, the time line becomes much longer. [EPA-HQ-OAR-2009-0491-3845 p.2]
International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers and Helpers (AFL-CIO Boilermakers Union)
Although the Boilermakers Union supports aggressive action to regulate interstate transport of SO2 and NOx emissions within a 32-state region the proposed form of the Transport Rule sets deadlines that are based on inaccurate or outdated assumptions regarding the feasibility of installing pollution control measures. [EPA-HQ-OAR-2009-0491-2672.1, p.3]
Neither the Clean Air Act itself nor the D.C. Circuit's opinions in North Carolina v. EPA require these outcomes. To address our concerns, the Boilermakers Union urges EPA to defer implementation of the Transport Rule for one year. Such a deferral would give utilities an opportunity to make the necessary investments in their EGUs and allow states to develop SIPs that address interstate emissions transport. In addition, the Boilermakers Union urges a one-year extension of the second phase of SO2 reductions that would apply in 2014. Providing such extra time would address major concerns with the tight timeframes to permit, design, fabricate and install the FGD units at existing coal-fired generating units, while ensuring that meaningful steps are taken towards achieving attainment in downwind states by 2015. [EPA-HQ-OAR-2009-0491-2672.1, p.3]
EPA's proposal to impose Transport Rule emission budgets beginning in 2012 is based on three major errors. First, EPA unrealistically assumes that many EGUs can install low-NOx burners and or switch to burning lower sulfur coal by January 1, 2012. [EPA-HQ-OAR-2009-0491-2672.1, pp.3-4]
1. Feasibility of Controlling Pollution by 2012. There is little evidence in the record to support EPA's assertion that Transport Rule requirements can be met by 2012. EPA's two-page Technical Support Document (TSD) regarding the availability of NOx control technology provides just two anecdotal cases to support the claim that low-NOx burners can be installed by 2012. Absent from the TSD is any broader analysis showing that those two cases are comparable to the thirty facilities that would have to be retrofit with low-NOx burners under the proposed Transport Rule. Neither does the TSD assess whether SNCR and burner upgrades would be adequate to meet the 2012 emission budgets. [EPA-HQ-OAR-2009-0491-2672.1, p.4]
Our own assessment is that the 2012 deadline would give utilities little time approximately six months from the expected promulgation of the Transport Rule - to switch coal supplies and, in many cases and make the boiler modifications that are necessary to burn the lower sulfur subbituminous coals. Similarly, six months is not enough time to schedule outages and install necessary NO, controls at existing EGUs. 5 EPA's timetable may not be achievable for all facilities, and leaves no room for inevitable construction delays that often result from ordinary material shortages or regulatory complications. [EPA-HQ-OAR-2009-0491-2672.1, p.4]
Finally, EPA fails to account for the additional time that it will take to complete permit reviews and obtain the necessary construction permits for going forward with these projects. [EPA-HQ-OAR-2009-0491-2672.1, p.4]
B. The deep S02 reductions required by 2014 are infeasible.
The 2014 deadline for achieving additional SO2 reductions in 'Group 1' states is likely to be just as infeasible to meet as the initial 2012 deadline for SO2 and NOx reductions. First, EPA bases the 2014 deadline in part on a 2005 analysis (Boilermaker Labor Analysis and Installation Timing) indicating that a FGD unit takes 27 months to install. However, this estimate of construction time is actually drawn from a considerably more dated EPA analysis published in 2002.8 It is not clear whether this eight-year old analysis remains applicable to EGUs now being retrofitted. Even accepting the timetables in the 2005 study as valid, those timetables also show that 27 months is required to install FGD on a single generating unit. A multi-unit facility that seeks to avoid a complete shutdown would, necessarily, have to engage in successive retrofits of generating units that would take considerably longer than 27 months. For example, the 2005 study relied upon by EPA indicates that a four-unit facility would require almost 37 months to complete the installation of FGD equipment. If this timetable is correct, many facilities in Group 1 states would not have sufficient time to install additional SO2 controls by 2014. [EPA-HQ-OAR-2009-0491-2672.1, p.6]
EPA also says that the 2014 deadline is feasible because the amount of electric capacity anticipated to be retrofitted with FGD is less than was ultimately retrofitted under CAIR. This argument implicitly assumes that those EGUs remaining to be retrofitted can undertake modifications on a timetable comparable to units that have already installed pollution control equipment. The Boilermakers Union believes that this assumption is likely to be incorrect. In general, the population of EGUs that have already been retrofitted with FGD equipment includes a significant proportion of newer and larger generating units located away from urban areas. These EGUs were the first to be retrofitted under CAIR and similar programs because they offered the most straightforward and cost-effective emission reduction opportunities. By contrast, the population of EGUs that remains to be retrofitted is dominated by older, less-efficient facilities where modifications will be relatively more complex and difficult. EPA's analysis fails to take this phenomenon into account, assuming instead - without any support - that future retrofits will proceed as quickly as past retrofits. This assumption is arbitrary and has led EPA to an unjustifiably optimistic projection as to the amount of time it will take to meet the Group 1 SO2 requirements. [EPA-HQ-OAR-2009-0491-2672.1, p.7]
EPA's analysis of the feasibility of meeting the 2014 deadline is also flawed because it omits any consideration of the cumulative effects of impending rulemakings namely, Maximum Achievable Control Technology (MACT) standards for boilers and standards for cooling water intake structures on demand for boilermakers and equipment. These rulemakings, which are expected to be completed over the next two years, will also likely require EGUs to undertake extensive modifications. It is inappropriate to neglect the impact of these rulemakings on the availability of resources to complete retrofits required under the Transport Rule. [EPA-HQ-OAR-2009-0491-2672.1, p.7]
In light of the above-described problems with EPA's basis for the implementation timetable of the Transport Rule, the Boilermakers Union urges EPA to defer implementation of the Transport Rule for one year. Such a deferral would enhance the feasibility of the Transport Rule, enable the submission of SIPs that are compliant with Section 110, and avoid unnecessary elimination of jobs or missed employment opportunities. [EPA-HQ-OAR-2009-0491-2672.1, pp.9-10]

5. Through internal inquiries among our members, we have learned that a typical installation of a low-NOx burner at a 750 MW generating unit requires the plant to be out of service for approximately ten weeks (not including time required for design and manufacturing of the equipment, and acquisition of necessary permits). It may not be possible for many EGUs to arrange for such a long closure of facilities, and complete all necessary preparation for installation, in the time between the promulgation of the Transport Rule and the proposed 2012 deadline. [EPA-HQ-OAR-2009-0491-2672.1, p.4]
10. EPA's estimates also entail potentially heroic assumptions about the ability of electric utilities to obtain the other permits necessary for installing FGD systems. Such permits are not limited to air quality construction permits, but also include general construction permits, solid waste disposal permits, revisions to water use/discharge permits, etc. Such permits can take months and, in some cases, years to obtain. In addition, EGUs will have to arrange for funding - in the case of public power entities, this could involve the sale of bonds. Finally, it will be necessary to coordinate the construction work, including the scheduling of outages in order to ensure system reliability. [EPA-HQ-OAR-2009-0491-2672.1, p.7]
Jessee, Robert
I am also concerned about the timing required in the rule. The time frame from the proposed rule_s effective date until the second phase of required reductions is to be obtained is right at 2.5 years. The expectation to have installed the necessary equipment and have it fully functional within this short time frame is not obtainable. [EPA-HQ-OAR-2009-0491-3288, p.1]
Kansas City Board of Public Utilities (BPU)
EPA Gave No Consideration to the Unique Challenges Faced by Municipal Utilities
EPA failed to consider the constraints on the financial means and timetables for securing capital and the lack of economies of scale for air emission controls called for by the Rule in regards to municipally-owned EGUs like BPU. [EPA-HQ-OAR-0491-2009-0491-2740.1, p.22]
Many municipal utilities such as BPU must undergo a series of prescribed steps before they can fund capital expenditures for the controls such as those assumed to be installed under the Rule. For capital expenditures of the order called for by the Rule, BPU must first engage in cost of service studies as support for subsequent ratemaking proceedings to raise electric rates that will establish a basis for the issuance of municipal bonds. This process alone requires at least one year and assumes that the bond capability of the utility at the time is sufficient for the amount of capital needed. The potential for failure to achieve bond capital is very real. [EPA-HQ-OAR-0491-2009-0491-2740.1, p.22]
The Rule finds that SCRs can be installed to meet enforceable allocations effective January 1, 2014 allocation requirements. See. e.g., 75 FR at 454286/3 ('a single SCR unit on average takes 21 months to install'). It is apparent from the length of time needed to accomplish the steps described above, this assumption is flawed because it does include the time needed to raise the necessary capital. [EPA-HQ-OAR-0491-2009-0491-2740.1, p.22]
Finally, many municipal utilities own and operate a relatively small number of relatively small EGUs units. The ability to achieve the required emissions reductions on small units is not reflected in the Rule. Due to simple lack of economies of scale, the cost of controls on smaller units can be as much as three times the cost per MW that the Rule assigns meet required air emission reductions. See, e.g., 75 FR at 45277-79 (cost curves). This calls into question the validity of costs per ton needed to reach the reductions postulated that forms the basis for regulation of many small municipal EGUs subject to the Rule. [EPA-HQ-OAR-0491-2009-0491-2740.1, p.23]
For the reasons stated herein, BPU requests alternative modifications to the proposed Rule by:
7. considering the unique circumstances regarding time and burden on municipal utilities of obtaining the necessary capital for the controls mandated by the rules;  [EPA-HQ-OAR-2009-0491-2740.1, p.23]  
Kansas City Power and Light Company (KCP&L)
3. EPA underestimates the amount of time necessary to bring new controls online. For example, EPA estimates that a new scrubber can be installed in 27 months, from conceptualization to regulatory approvals by financial regulators and air quality permitting agencies, to operation. Engineering and permitting for KCP&L's Iatan Unit 1 controls began in early 2005 and the controls were installed, operational, and compliant by the end of 2009 or nearly 60 months. [EPA-HQ-OAR-2009-0491-2709.1, p.3]
Kansas Department of Health and Environment
Kansas is in the unique situation that several of our EGUs are slated for installation of low NOx burners (LNBs) as part of the proposed Transport Rule to meet statewide budgets. The timing for these installations as laid out in the rule is very aggressive, and KDHE believes likely unattainable without disruption of service. In the TSD discussing installation timing, EPA provides several examples where engineering analyses and retrofits are completed in a short time window (see http://www.epa.gov/airquality/transport/pdfs/TSD Installation timing for LNBs 07-6-10.pdf). Unfortunately, not all EGU units are the same and each brings its own unique challenges in design, engineering, and retrofitting controls. Making the assumption that all units required to install LNBs in the state could perform the retrofit in a six-month time window because it has been done at several sources elsewhere is not real-world reality, and in fact it is likely the exception rather than the rule that LNB retrofits are completed in this timeframe. Several of the Kansas units that would be looking at retrofits are co-located or operated by the same company, and could not be retrofitted at the same time for demand reliability reasons even if the design and engineering could be performed in this timeframe. In reality it is also unlikely LNB retrofits for these units can be designed and installed in a six-month window if all the variables unique to Kansas generators are factored in. KDHE strongly believes this portion of the rule is unattainable for Kansas sources. KDHE recommends language requiring LNB controls be installed as expeditiously as practicable, allowing for a more reasonable timeframe beyond the beginning of 2012. [EPA-HQ-OAR-2009-0491-2606.1, p.6]
Kentucky Chamber of Commerce
The Kentucky Chamber feels strongly the proposed Transport Rule is based on outdated and inaccurate data, proposes unrealistic time frames for achieving reductions and ignores significant constraints on how reductions can be achieved. The Kentucky Chamber feels it is simply not possible to design, permit, fabricate and install the equipment necessary to meet the new requirements within the timelines in the proposal, particularly considering how long it will take to finalize the rule and the limited amount of emissions trading that will be permitted. [EPA-HQ-OAR-2009-0491-2760.1 p.1]
The deadlines in the Transport Rule provide no practical way for power companies to install any needed pollution control equipment or for the states to develop their own state implementation plans (SIPs). SIPs have always been a cornerstone for compliance and enforcement of the Clean Air Act.  [EPA-HQ-OAR-2009-0491-2760.1 p.2] [[These comments can also be found in Section VII.C.]]
Kentucky Division for Air Quality
Deadlines for achieving mandated emission reductions should be designed to support the attainment deadlines prescribed for the standards. At the same time, the regulated community must be granted the required time to design and implement control equipment and operational changes necessary to meet new emissions limits. [EPA-HQ-OAR-2009-0491-2805.1, p.1]
More Time Needed to Install Controls  
Pursuant to the rule preamble Section IV.D., Emissions Reductions Cost Curves (75 FR 45273), the time available for affected units to install new SO2 and NOx controls by the 2012 and 2014 timeframes is not sufficient, especially for NOx, which has less flexibility in the emission reduction options available. Therefore, the Division requests EPA to take this comment into consideration when finalizing the Transport Rule. [EPA-HQ-OAR-2009-0491-2805.1, p.6]  
Lansing Board of Water & Light
BWL strongly disagrees with EPAs statement that low NOx burners could be installed by 2012 to meet this rule. EPA cannot expect any entity to spend exorbitant amounts of money to meet proposed restrictions in a proposed rule. By EPAs own admission, the Transport Rule is not expected to be finalized until Summer 2011. An expected date for pollution control installation of January 1, 2012 is completely preposterous. Permitting alone can take up to 12 months (see Michigan Permit to Install 390-08 which took more than 12 months to approve for the installation of two LNB systems on two boilers) and that is not including the time to design, fabricate and actually install the equipment. [EPA-HQ-OAR-2009-0491-2752.1,p.4]
Timing of the proposed rule and installation schedule
There is simply not enough time for electrical generators to design, permit, fabricate and install pollution control equipment to comply with the new emissions levels established by this proposed rule. BWL has begun preliminary discussions with various consultants and determined that the minimum time to design, fabricate, and install a selective non-catalytic reduction (SNCR) system is 24 months. With all of the uncertainty regarding regulatory applicability, the permitting phase will likely require additional 9-12 months to complete. Thus, an SNCR (which is relatively easy compared to scrubbers or SCR) will need three years to become operational. [EPA-HQ-OAR-2009-0491-2752.1,p.7]
To add to the uncertainty, EPA has already proposed to revise the proposed rule in regards to emissions of NOx, based upon the forthcoming Ozone NAAQS Reconsideration. The level of uncertainty this creates throughout the electrical generation industry is beyond fathom. Pollution control equipment for this industry is not something that can be bought at a local supermarket, only to be discarded when a new one is needed. This equipment takes years to design and install requiring investments of several million dollars. The utility industry is being asked to comply with a rule that is still just a proposal when there is already a proposal to revise the proposed rule! [EPA-HQ-OAR-2009-0491-2752.1,p.7]
EPA should not adopt the proposed 2012 compliance deadline and should not consider any compliance date earlier than 2015. This would give the utility a clear emissions reduction target and allow proper time to design, permit, fabricate and install the necessary control equipment. Furthermore, with CAIR remaining in place through 2015, emissions would continue to be reduced until the Transport rule would be fully implemented. [EPA-HQ-OAR-2009-0491-2752.1,p.7]
Large Public Power Council (LPPC)
LPPC understands EPA's desire to craft a Transport Rule that effectively addresses interstate transport of ozone and particulate matter (PM), complies with the D.C. Circuit's 2008 opinion in North Carolina v. EPA, 2 and achieves an orderly EPA's decision to propose a limited interstate trading program instead of a program that prohibits interstate trading or requires "direct control" of emissions on a source-by-source basis. [EPA-HQ-OAR-2009-0491-2667.1, pp.1-2]
However, LPPC believes that the proposed Transport Rule exceeds the D.C. Circuit's instructions in North Carolinpa, and creates a potentially disruptive break with CAIR, by imposing an unrealistically aggressive timetable that bypasses the traditional prerogatives of states to develop implementation plans that address interstate emissions. [EPA-HQ-OAR-2009-0491-2667.1, p.2]
Briefly stated, our principal recommendations to EPA are:
- Adjust the 2012 and 2014 compliance deadlines to reflect a more realistic assessment of the time required to implement SO2 and NOx controls; [EPA-HQ-OAR-2009-0491-2667.1, p.2]
EPA has proposed an extremely aggressive timetable for implementing the Transport Rule and enforcing compliance with its emissions limitations. As proposed, the Transport Rule would take effect and state emissions budgets would become binding in 2012  -  less than one year after the Transport Rule is expected to become final. So called "Group 1" states that are required to undertake additional SO2 reductions would have until 2014 to comply with these subsequent emission limitations. 4 LPPC believes the proposed implementation timetable and compliance deadlines raise two concerns. [EPA-HQ-OAR-2009-0491-2667.1, p.3]
Second, the aggressive compliance deadlines overlook legitimate concerns over the ability of the power sector to implement the requisite pollution controls within the contemplated timeframe. [EPA-HQ-OAR-2009-0491-2667.1, p.3] [[This comment can also be found in Section VII.C.]]
In addition, a one to two-year deferral would provide a realistic window for the installation of necessary pollution control technology. [EPA-HQ-OAR-2009-0491-2667.1, p.3]
B. The Proposed Compliance Deadlines Are Infeasible to Meet
The ambitious compliance deadlines in the proposed Transport Rule rest on unrealistic assumptions about the feasibility of implementing pollution control measures. EPA's initial compliance deadline of 2012 is based on its assessment that low-NOx burners or other NOx control strategies can be installed in a relatively short time frame, and that coal-burning EGUs can switch to low-sulfur coal without extensive retrofits. EPA bases its 2014 compliance deadline for further SO2 reductions in "Group 1" states on a 2005 analysis indicating that a flue gas desulfurization (FGD) system takes 27 months to install, and claims that the amount of electric capacity anticipated to be retrofitted with FGD is less than was ultimately retrofitted under CAIR. 23 [EPA-HQ-OAR-2009-0491-2725.1, p.7]
EPA has marshaled scant and questionable evidence to support these claims. First, EPA's two-page Technical Support Document (TSD) on the availability of NOx control technology is woefully inadequate. The TSD presents only anecdotal evidence from two EGUs to support EPA's claim that low-NOx burners can be installed by 2012, without showing that those two cases are comparable to or representative of the thirty facilities that EPA claims would have to be retrofitted with low-NOx burners under the proposed Transport Rule. The TSD also asserts that selective non-catalytic reduction (SNCR) and upgrades to existing burners can be implemented "quickly" (without indicating a particular timeframe), citing as sole support for this statement a conversation with an official representing an association of pollution control equipment manufacturers; 24 the TSD does not provide a factual basis for this statement or otherwise attempt to bolster the credibility of this assertion. Neither does the TSD assess whether SNCR and burner upgrades alone would be adequate to meet the 2012 emission budgets. [EPA-HQ-OAR-2009-0491-2725.1, p.7]
Second, EPA's reliance on the 2005 study entitled Boilermaker Labor Analysis and Installation Timing is misplaced. 25 EPA's claim that a FGD unit requires only 27 months to install appears to be based on the project timetables displayed on pages 14 and 15 of that report. Those timetables are themselves drawn from a considerably older EPA analysis completed in 2002. 26 EPA does not explain whether this eight-year old analysis remains applicable to EGUs now being retrofitted. Even setting aside this concern, the project timetables themselves show that 27 months is the expected time for installation of FGD equipment on a single generating unit. A multi-unit facility that seeks to avoid a complete shutdown would, necessarily, have to engage in successive retrofits of generating units that would take considerably longer than 27 months. Indeed, the timetables in the 2005 study indicate that a four-unit facility would require almost 37 months to complete installation of FGD equipment. 27 Similarly, a separate 2010 study commissioned by the electric power industry concluded that a typical installation of a single FGD unit would require 36 months. [EPA-HQ-OAR-2009-0491-2725.1, pp.7-8]
By noting that the amount of capacity expected to be retrofitted under the Transport Rule is no greater than under CAIR, EPA also implicitly assumes that those EGUs remaining to be retrofitted can undertake these modifications on a timetable comparable to units that have already installed pollution control equipment. LPPC believes that this assumption is incorrect. In general, utilities have installed existing FGD and SCR systems on larger and newer EGUs where those systems could be most cost effectively implemented. EGUs that remain to be retrofitted are, on the average, older, smaller, and less-efficient facilities where modifications will be relatively more complex and difficult. According to a recent study conducted by ICF International, approximately 92 GW of the total coal-fired generating fleet will lack both SO2 and NOx controls; of that amount, approximately 50 GW are units that are more than 40 years old and have heat rates greater than 10,000 BTU/kWh. 28 EPA's analysis fails to take this trend into account, assuming instead that future retrofits will proceed as quickly as past retrofits  -  an assumption that is inappropriate for many facilities. [EPA-HQ-OAR-2009-0491-2725.1, p.8]
Further, EPA's analysis of resource availability neglects to consider the cumulative effects of impending rulemakings  -  namely, Maximum Achievable Control Technology (MACT) standards for boilers and standards for cooling water intake structures  -  on demand for boilermakers and equipment. These rulemakings, which are expected to be completed over the next two years, will also likely require EGUs to undertake extensive modifications. Although it may be difficult to precisely quantify the resource demands associated with these still-pending rules, it is inappropriate to entirely overlook the impact of these rulemakings on the availability of personnel and funding to complete retrofits required under the Transport Rule. [EPA-HQ-OAR-2009-0491-2725.1, p.8]
Louisiana Energy and Power Authority (LEPA)
THE PROPOSED TRANSPORT RULE WOULD IMPOSE AN INAPPROPRIATELY SHORT INITIAL COMPLIANCE DEADLINE OFJANUARY 1, 2012. [EPA-HQ-OAR-2009-0491-2700.1, p.17]
LEPA's critical units are 40-year old simple cycle gas units. LEPA does not know if pollution control technology is available to eliminate the NOx emissions from those generators. Even if such technology is available, LEPA would have great difficulty securing the capital to install that equipment on its 40-year-old units. [EPA-HQ-OAR-2009-0491-2700.1, p.17-18]
Luminant
:: In addition, EPA anticipates the need for retrofitting existing generation with pollution control equipment or fuel switching however, EPA's compliance dates for pollution control equipment does not allow enough time for permitting, design, procurement, installation and testing of this pollution control equipment. Thus, the timeline is unacceptably short. [EPA-HQ-OAR-2009-0491-2729.1, p.3]
Based on the experiences of two plants in the first decade of the 21st  century, EPA believes that a selective catalytic reduction (SCR) system can be designed, permitted and installed in 21 months, and a flue gas desulfurization (FGD) system, in 27 months. Those timelines are not adequate for all necessary activities, especially if many sources are vying for design, materials, equipment, and construction resources concurrently. Furthermore, permitting can be a real unknown variable, particularly in states that have the public participation feature of a contested case hearing. For example, in Texas it can easily take 2 years or more to complete the air permitting process. Thus, EPA's proposed compliance timeline does not give a reasonable amount of time for compliance and should be extended. [EPA-HQ-OAR-2009-0491-2729.1, p.7]
Manitowoc Public Utilities (MPU)
 MPU believes that the EPA should consider the implications of fuel switching for the many States where budgets will be inadequate for SO2 and NOx.   [EPA-HQ-OAR-2009-0491-2860.1,p.2]
 MPU believes that EPA has vastly underestimated the amount of time that it takes utilities to design, permit, construct, and start up new FGD and SCR units. The SO2 and NOx emission reductions expected under the terms of the Proposed Transport Rule will be difficult to achieve with out additional control equipment.   [EPA-HQ-OAR-2009-0491-2860.1, p.2]
EPA Fuel Switching Expectations  
MPU believes that the EPA should consider the implications of fuel switching for the many states where budgets will be inadequate for SO2 and NOx. Utilities have long-term contracts for the supply of fuels that need to be honored to avoid significant penalties. Fuel contracts take time to develop and rapid changes are not practical and often times have operating permit issues that may need to be addressed. Expectations of significant switching to natural gas are also not reasonable due to operating permit issues, gas infrastructure shortfalls, and the time to design, install, and fund the installation of new gas burners to accommodate fuel switching to natural gas. [EPA-HQ-OAR-2009-0491-2860.1,p.4]
Installation of New Emission Control Systems  
MPU believes that EPA has vastly underestimated the amount of time that it takes utilities to design, permit, construct, and start up new FGD and SCR units. It will take longer than 30 months, in some cases significantly longer than 30 months, for affected EGUs to retrofit FGD and SCR units at existing EGUs. Thus, it will not be possible for affected EGUs to achieve all the SO2 and NOx emission reductions that must be achieved by the January 2012 and 2014 deadlines under the terms of the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2860.1,p.5]
Marquette Board of Light and Power
Inadequate Time for Implementation
The Agency has announced that it anticipates taking final action in the rulemaking in June 2011 and imposing an initial compliance date of January 1, 2012. There will not be sufficient time to evaluate the best control option, budget, permit, order, and install within the six month time frame that the Agency is proposing. Control options cannot be evaluated until allowances are allocated in a final rule. Budgeting is contingent on the control option selected. A permit application packet must be prepared, submitted, and obtained for the selected control option prior to making the equipment purchase. [EPA-HQ-OAR-2009-0491-2764.1, p.2]
Negotiating performance guarantees and manufacturer availability will restrict time of delivery. Installation time will vary depending on the control option selected. Marquette is located in the Wisconsin and Upper Michigan System (WUMS) subregion of the Midwest Impendent Transmission System Operator (MISO). Scheduling routine maintenance outages of a few days has proven difficult; scheduling an extended outage in such a short time frame will be challenging. [EPA-HQ-OAR-2009-0491-2764.1, p.3]
Mass Comment Campaign (221) (American Electric Power)
The Transport Rule does not allow enough time for power companies to install the equipment needed to reduce emissions by the 2014 deadline.  [EPA-HQ-OAR-2009-0491-3528_Mass, p.1]
Mass Comment Campaign (245) (American Electric Power)
I support the agency's efforts to reduce the amount of sulfur dioxide and nitrogen oxide in the atmosphere, but I am concerned about the the timing required in the rule. From the time the rule would become effective until the second phase of reductions are to begin is barely two-and-a-half years -- hardly enough time for power companies to install the needed equipment.
Michigan Chamber of Commerce
Under the existing proposal, there is not enough time for power generators to design, permit, fabricate and install pollution-control equipment to comply with the new emissions levels established in the rule's first and second phases. [EPA-HQ-OAR-2009-0491-2696.1, p.1]
Michigan Department of Natural Resources and Environment
One of most critical concerns of the Michigan Department of Natural Resources and Environment (DNRE) is the implementation timing for the proposed Interstate Transport Rules (TR), where Phase One begins in 2012 and Phase Two in 2014. The DNRE believes the shortened timeline for implementation of the TR has adverse impacts on the sources affected. [EPA-HQ-OAR-2009-0491-2774.1 p.3
In September 2009, states of the Lake Michigan Air Directors Consortium (LADCO) offered recommendations to the Environmental Protection Agency (EPA) regarding a framework for addressing transport (see attached letter, Appendix A). Along with other LADCO states, we were involved in the state-by-state analysis of what levels of electric generating unit (EGU) controls are achievable over the next several years. Per the letter from the LADCO states to the EPA, a fundamental assumption made was a JUly 2012 start date for planning, engineering, and construction of any new oxides of nitrogen (NOx) and sulfur dioxide (502) controls. This date reflects a January 2011 promulgation date for the replacement rule and approximately 18 months for adoption of state rules. Based on the analysis completed, the DNRE believes that the following three layers of controls can be completed by 2015 at the earliest:
:: All NOx and 502 controls installed to comply with original Clean Air Interstate Rule (CAIR) Phase I program;
:: Optimization of existing NOx and 502 controls by 2014; and
:: Application of low capital cost NOx controls by 2015.
As a result, the DNRE believes that the earliest installation of new major NOx and 502 controls to sources within Michigan can be achieved is 2017. [EPA-HQ-OAR-2009-0491-2774.1 p.3
Michigan Manufacturers Association (MMA)
- Under the existing proposal, there is not enough time for power generators to design, permit, fabricate and install pollution control equipment to comply with the new emissions levels established in the rule's first and second phases. In September 2009, the Lake Michigan Air Directors Consortium (LADCO), which includes Michigan, conducted a state-by-state analysis and informed EPA that significant additions of new controls would not be possible before 2017. [EPA-HQ-OAR-2009-0491-2762.1, p.1]
If new scrubber byproduct storage facilities are needed in addition to emissions control equipment, the time line becomes much longer. [EPA-HQ-OAR-2009-0491-2762.1, p.3]
Michigan Municipal Electric Association (MMEA)
the timeline for compliance with the Transport Rule is unachievable; [EPA-HQ-OAR-2009-0491-2828.1, p.2]
3.) EPA's Transport Rule Has Unrealistic and Unachievable Compliance Deadlines
Michigan's public power communities do not have the ability to reach EPA's proposed 2012 and 2014 compliance timelines, even if the drastic impacts on our units could be justified. Given that these utilities are relying on hardship allowances provided by the State of Michigan and affirmed by EPA in its approvals of Michigan's SIPs, these further pollution controls for NOx (such as SNCR or SCR) and SO2 (such as FGD or fuel switching) have not been planned and are not feasible now, let alone after the EPA finalizes this Transport Rule. As the Manager of Utility Compliance in Marquette states about the Transport Rule's impact on the Shiras unit, "I will not be able to obtain funds, conduct studies comparing the best control options, decide on a control option, pick a manufacturer, get it permitted, schedule, and have it installed by 2012. The time table is impossible to meet." [EPA-HQ-OAR-2009-0491-2828.1, p.9]
Regarding the compliance deadlines proposed for the Transport Rule, MMEA supports the comments filed by the Michigan Department of Natural Resources and Environment, which states that the earliest that additional NOx and SO2 controls could be installed in Michigan is 2017. We also support MMEA's national trade group the American Public Power Association, which comments extensively on why the proposed 2012 / 2014 compliance deadlines are not feasible and not necessary, and which requests later a later compliance deadline of no earlier than 2015. [EPA-HQ-OAR-2009-0491-2828.1, pp.9-10]
5.) Extend Transport Rule compliance deadlines to at least 2015, preferably the 2017 timeframe suggested by the Michigan Department of Natural Resources and Environment.[EPA-HQ-OAR-2009-0491-2828.1, p.16]
Midamerican Energy Holdings Company
It has taken EPA two years to propose the Transport Rule in response to the D.C. Circuit Court of Appeals decision determining that the Clean Air Interstate Rule was fatally flawed and it will take another six months  -  mid-2011  -  to finalize the Transport Rule. EPA will have had 30 months to draft and finalize a rule while sources with compliance obligations during the initial phase of reductions have a maximum of 15 months to comply with the rule beginning January 1, 2012. Even if sources in states covered by the initial phase of emission reductions started installing controls today, they could not comply with this aggressive deadline. Only if a facility has already engineered and designed the necessary control system, purchased equipment, negotiated a contract, retained a vendor, contractor and skilled labor to install the controls, obtained an air quality construction permit, obtained other necessary regulatory approvals2, and scheduled an outage to tie in equipment, can it have any hope of meeting these aggressive deadlines. Given current economic conditions and the potential rate impacts on customers associated with large capital expenditures, companies are not likely to fully engage in negotiations and enter into contractual commitments until the final rules are known -- particularly since EPA has proposed three different compliance scenarios that will influence a company's control suite. At the same time, given the aggressive compliance dates of 2012 and 2014, companies cannot wait until the outcome of the final rule to initiate their emission reduction projects. [EPA-HQ-OAR-2009-0491-2748.1 p.3-4]
EPA's optimistic estimates regarding the length of time necessary for the installation of controls are unrealistic and unachievable. At the outset, companies in states affected in the first phase of the SO2 reductions have approximately 15 months, not 27 months, to install controls. Given the gravity of the penalties associated with noncompliance, companies cannot afford contractor delays, labor strikes, or the myriad of other unanticipated circumstances that arise in projects of this nature. Taken in isolation, and without consideration of other regulatory requirements, a 27 month equipment installation (after, of course, a contract is negotiated  -  which alone frequently takes approximately six months, particularly when the equipment suppliers and contractors are in high demand) may be achievable. However, not only are the facilities in the 31 affected states competing for resources and equipment to reduce SO2 and NOx emissions between 2012 and 2014, but those states are also competing with skilled labor, equipment and other services with companies in the Western states that are required to install controls beginning in the same time frame to implement their BART determinations and Regional Haze State Implementation Plans. [EPA-HQ-OAR-2009-0491-2748.1 p.3-4]
Minnesota Power 
Similarly, it is questionable as to why EPA would expect Transport Rule budget compliance only about six months after the Transport Rule might be finalized and specific provisions for 2012 compliance have been identified and publically noticed, unless EPA expects such sources to be able to comply with 2012 requirements with controls already in place without the Proposed Transport Rule.   [EPA-HQ-OAR-2009-0491-2750.1, p.5]  
National Mining Association (NMA)
2012 Is Too Soon to Begin Phase One Regulation, and 2014 Is Too Soon to Begin Phase Two Regulation
1. 2012
The phase one emission reduction obligations are significant. EPA indicates that the 2012 SO2 emission reductions required under the rule will be 4.1 million tons per year, as compared with 5.1 million tons that would be expected otherwise. EPA evidently believes that this significant amount of emission reductions is feasible by the beginning of 2012 because, in EPA's analysis, sources will not be required to install new pollution control equipment, beyond those already planned and in development, to meet the requirements of the rule. Instead, EPA believes that the rule's NOX requirements can be met by operating NOX control equipment year round, and the rule's SO2 requirements can be met principally through coal-switching from high sulfur to low sulfur coal and from low sulfur coal to very low sulfur coal. [EPA-HQ-OAR-2009-0491-2868.1,pp.15-16]
Moreover, NMA is unable to find any documentation in the record of whether EPA considered whether utilities are constrained by coal supply or rail contracts from switching coal suppliers or coal sources. Many coal and rail contracts extend for a period of years, in many cases for five or ten years or longer. Certainly, as of mid- 2011 when the Transport Rule is final, many utilities will be contractually locked into their sources of coal for the 2012-14 period and will therefore be unable to switch coal as EPA anticipates. If they are unable to do so, the 2012 budgets will be unattainable, except by closing coal-fueled units or ramping back production, which in turn will produce different impacts than those that the Agency has analyzed. EPA must at least produce some form of analysis taking into account coal supply and rail contract constraints. [EPA-HQ-OAR-2009-0491-2868.1,p.16]
Similarly, NMA is unable to find any documentation in the record of whether EPA considered any physical constraints on substitution of one type of coal for another, except where the switch would entail substitution of very low sulfur subbituminous coal for bituminous coal. But many other types of coal characteristics affect whether coal can be burned in a particular unit even for coal within a single coal region. Unless EPA produces a unit-by-unit analysis demonstrating that coal can be substituted in the manner that EPA anticipates, there will be no certainty that utilities can meet the 2012 compliance deadline through coal-switching and that unit closures or reductions in operations will not be required. [EPA-HQ-OAR-2009-0491-2868.1,p.16]
2. 2014
For compliance with the 2014 SO2 budgets, EPA projects the installation of scrubbers on 14 GW of generation, in addition to the very substantial amount otherwise planned for that period. For NOX compliance in 2014, EPA projects the addition of SCRs on 51 GW of capacity. EPA expresses confidence that utilities can install scrubbers on 14 GW of capacity during the three year period between 2011 when the Transport Rule goes into effect and 2014 because utilities installed more than that amount of scrubbers in past three-year periods in response to CAIR. But that statement ignores the fact that EPA expects utilities to install scrubbers on an additional 26 GW of capacity by 2014 under what EPA calls other requirements. [EPA-HQ-OAR-2009-0491-2868.1,pp.16-17]
This is a great deal of construction activity in a very limited amount of time. In the first place, since EPA has overstated the number of scrubbers that will be brought on line by the beginning of 2012, it has underestimated the number that must be brought on line between 2012 and 2014. Based on comments that will be submitted by utility industry entities, industry estimates show that approximately 25 GW of new scrubbers will be required by 2014, not the 14 GW assumed by EPA. [EPA-HQ-OAR-2009-0491-2868.1,p.17]
Moreover, NMA understands that utility industry commenters will also be providing information showing that EPA has severely underestimated the time it takes to plan for, design and engineer, and construct scrubbers and SCRs. For example, EPA's estimate that a scrubber can be brought on line in 30 months is based on general industry information taken from a period that did not experience the extremely high volume of scrubber construction that EPA projects in the 2012-14 time period, and the even higher volume of construction that will likely take place in actuality. Furthermore, using general figures masks difficulties that may arise at individual locations. Yet EPA's ambitious schedule requires that every scrubber project be completed by 2014, not just a hypothetical "average" project. [EPA-HQ-OAR-2009-0491-2868.1,p.17]
National Rural Electric Cooperative Association (NRECA)
For example, EPA modeled that units are capable of higher to lower sulfur bituminous coal switching by the 2012 compliance deadline. Presuming, as EPA does, CATR rule finalization in mid-2011, units would have about six months to switch coals, alter transportation contracts, and potentially upgrade ESPs. EPA has failed to provide any actual data to support these presumptions. No information is available in the docket regarding actual capabilities to break existing contracts including financially absorbing resulting penalties for contract breaches, to acquire new coal transportation from the low sulfur bituminous mining regions, or to evaluate actual necessary time to study and install any needed ESP upgrades. Further, EPA assumes unit coal switching from high to very low sulfur subbituminous coal is viable if the unit has demonstrated that capability in the past. Again, EPA has provided no information to this supposition or to explain what it determines is adequate for demonstration. Is a onetime burn at the unit adequate demonstration? Is a burn with coal blending adequate demonstration? What information has EPA utilized regarding transportation contracts and availability? What about costs? [EPA-HQ-OAR-2009-0491-2723.1, p.6]
Similar problems are inherent in many of EPA presumptions regarding installation of FGDs and SCRs in a time to meet 2014 deadline mandates. For example, EPA believes that 14 gigawatts (GWs) of FGDs can be planned and installed is 30 months from CATR finalization to the 2014 compliance date. The proposal provides no background or indication that EPA has considered relative increased difficulties inherent in this next round of FDG retrofits, i.e. the more retrofits within the existing coal-fired generating fleet the harder, more time consuming and less cost effective they are. [EPA-HQ-OAR-2009-0491-2723.1, p.7]
Additionally, EPA has apparently not analyzed the additional material resources and skilled labor required in connection with other regulations the agency has proposed or may soon finalize that will compete with CATR resource and labor needs, thereby quite probably affecting timely installation of the approximately 28 additional FGDs by 2014.8 For example, EPA has recently proposed the Industrial Boiler maximum achievable control technology (MACT) Rule less than 60 days before the proposed CATR publication. According to that proposal, more than 1,000 coal and biomass units among other types will be affected by a final MACT Rule requiring similar emissions control technologies as required with the CATR. Relying on statutory timetables for MACT implementation, affected units under a final Industrial Boiler MACT Rule would be retrofitting units with required controls during time periods that coincide with those associated with CATR emissions control installation, thus competing with demands for similar resources required for CATR compliance. EPA needs to evaluate MACT and other rulemaking requirements on abilities of affected CATR units to meet their obligations within the proposed compliance periods. [EPA-HQ-OAR-2009-0491-2723.1, pp.7-8]
NRECA's concerns with the 2014 deadline and associated modeled emission reductions presumptions are similar to those outlined above for the 2012 deadline. Many units modeled by EPA to undertake and complete necessary retrofits by the 2014 deadline will not be able to accomplish the task. Accordingly, at a minimum EPA should extend the 2014 compliance deadline by at least one year to rationally accommodate emissions reduction requirements. [EPA-HQ-OAR-2009-0491-2723.1, p.8]
Footnote 8: The proposal assumes an additional 14 GWs of FGDs. Assuming an average commercial-sized affected coal-fueled unit at 500 MWs, the proposal would require 28 separate FGD installations. [EPA-HQ-OAR-2009-0491-2723.1, p. 7]
As a matter of substance, the NODA appears to be incorporating the same compressed 2012 and 2014 timelines that, as pointed out in our CATR comments, are unrealistic given the proposed emissions reduction goals. [EPA-HQ-OAR-2009-0491-3756.1_NODA, p.1]
Nelson Industrial Steam Company (NISCO)
IV. Comments on Effective Date of the Rule
NISCO is concerned with the nearly immediate effective date of the rule. EPA has suggested it will promulgate a final rule in late spring 2011 and it will become effective January 1, 2012. This is obviously unreasonable considering the costly impact to affected facilities. It is unreasonable to expect a facility to engineer, procure, and install controls in six months or even budget for purchasing additional allocations. [EPA-HQ-OAR-2009-0491-2813.1, p.12]
North Carolina Department of Environment and Natural Resources
Vendors and contractors specialized in the design and construction of 502 scrubbers and SCRs can more appropriately comment on and provide inputs on this issue. But, empirically, it can be said that it would be hard for the suppliers to provide their services (design and construction) at the same time to every owner/operator of power plant for installation of scrubbers and SCRs. For example, it is hard to imagine if many scrubbers are required to be Installed to comply with January 1, 2014 date in Group 1 States, whether there are enough qualified  suppliers available to design and construct this kind of scrubbers to meet this deadline. [EPA-HQ-OAR-2009-0491-2767.1 p.6]
Northern Indiana Public Service Company (NIPSCO)
NIPSCO agrees with EPA's acknowledgement in the preamble that the 2012 and 2013 timeframe does not allow companies enough time to install pollution control technologies. The 2014 timeframe does not allow enough time to complete projects needed to achieve required reductions, and is limited to projects that are already well in the planning cycle. [EPA-HQ-OAR-2009-0491-2747.1 p.10]
NRG Energy
An extension of the Group 1 second compliance deadline EPA is proposing a second compliance deadline in 2014 based on the assumption that "it takes about 27 months to install a scrubber and 21 months to install an SCR." While it may be possible to install a scrubber or SCR within these timeframes, it is not enough time to conduct engineering, obtain any required construction and/or operation permits, and go through the bid process. This is further complicated by the scheduling challenges of multiple controls at a single plant or multiple facilities in a single region and the construction of replacement generation to supplant coal retirements. In addition, NRG recommends that EPA carefully consider not only the challenges of multiple retrofits, but also the timing and implementation of the impending suite of rules that will impact EGUs. In short, an extension is warranted to maintain an orderly and efficient transition to new and cleaner generation. [EPA-HQ-OAR-2009-0491-2749.1, P. 5]
Occidental Chemical Corporation (OCC)
Compliance Deadline The scope of the proposal and required compliance activities are complex and may require the development of projects and capital expenditures. If the final rule is issued in 2011 and emission reductions are required in 2012, there is not sufficient time for a regulated entity to assess and plan future production, identify projects for compliance, and implement compliance activities. Respectfully, a 3-year compliance schedule should be provided in the final rule.[EPA-HQ-OAR-2009-0491-2754.1, p. 28]
Ohio Coal Association
:: The compliance deadlines are not reasonable and do not take into account the significant lead time necessary for electric power generators to consider, plan, design and construct necessary control equipment. Additionally, it is unreasonable for EPA to move towards a 2012 implementation deadline while EPA continues to contemplate changes to the Transport Rule and additions to the NODA. [EPA-HQ-OAR-2009-0491-2743.1, p.2]
Ohio Manufacturers Association (OMA)
The short timeline also makes it virtually impossible for power generators to design, permit, build and install new equipment that will likely be needed to satisfy the 2014 pollution reduction benchmarks. [EPA-HQ-OAR-2009-0491-2651.1, p. 1]
Ohio Utility Group (OUG)
The compliance deadlines are infeasible [EPA-HQ-OAR-2009-0491-2679.1, p.5]
EPA maintains that the Transport Rule's two phases of emissions reductions will help there remaining nonattainment areas reach attainment by their assigned deadline. 13 As such, EPA's emissions reductions deadlines under the Transport Rule - the latest being May 1, 2014 - are set to precede the NAAQS attainment deadlines - the earliest being April 2015. The unreasonableness of EPA's proposal is highlighted by the fact that EPA previously declared such a timeline unfeasible 'based on engineering and financial factors." What was impracticable then cannot be practicable now. [EPA-HQ-OAR-2009-0491-2679.1, p.5]
EPA attempts to rectify the discrepancy illustrated above by determining that a flue gas desulfurization unit takes approximately 27 months to build, while a selective catalytic reduction unit takes only 21 months. IS The Utilities assert that such a timeline is unrealistic. If state budgets are not reevaluated, the Utilities suggest that extending implementation deadlines is a necessity. [EPA-HQ-OAR-2009-0491-2679.1, pp.5-6]
In their own comments, AEP went into great detail about how long it takes to engineer, construct, and install the control technology that will be necessary to comply with the proposed Transport Rule. The OUG wishes to highlight some of AEP's real-world experiences and conclusions: [EPA-HQ-OAR-2009-0491-2679.1, p.6]
:: Engineering and construction of the FGD system takes up to 52 months to complete [EPA-HQ-OAR-2009-0491-2679.1, p.6]
:: The FGD-corresponding landfill takes 54 months on average to complete [EPA-HQ-OAR-2009-0491-2679.1, p.6]
:: Engineering and construction of the SCR systems takes up to 42 months to complete [EPA-HQ-OAR-2009-0491-2679.1, p.6]
Switching coal is not a viable option [EPA-HQ-OAR-2009-0491-2679.1, p.6]
EPA's response to curbing emissions in a timely manner is for sources to switch to low sulfur coal by 2012. The Utilities assert a two-prong objection to the fuel switch. First, the Transport Rule is to be based on technological feasibility and development. Switching coal is not a technology-based rationale. [EPA-HQ-OAR-2009-0491-2679.1, p.6]
In addition to engineering complications, switching coal raises permitting issues. For example, combustion of sub-bituminous coal would violate the Title V permits for DP&L's Stuart and Killen Stations, which specify the use of bituminous coal. Furthermore, these stations have a 25+ year history of burning only bituminous coal, DP&L has no operating experience with sub-bituminous coal, and DP&L has no plans to bum sub-bituminous coal. [EPA-HQ-OAR-2009-0491-2679.1, p.6]
Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
On May 11, 2006, OVEC announced its plan to retrofit its entire fleet with FGD. See May 11, 2006 Press Release, attached. At that time, the estimated cost of the retrofit was approximately $820 million, and the expected efficiency 'as much as 98%.' Id.The FGD system selected was a Chiyoda Jet Bubbling Reactor - a technology that to the best of OVEC's knowledge has only recently been installed on a very limited number of coal-fired utility units in the United States. The original target dates for completion of the FGD systems were 2009 for Kyger Creek and 2010 for Clifty Creek. [EPA-HQ-OAR-2009-0491-2803.1, p.3]
In December 2008, OVEC announced an indefinite delay in the construction of the FGD at Clifty Creek due to the severe downturn in the national economy and the uncertainty of obtaining the capital funding necessary to complete the project. See December 17, 2008 Press Release, attached. At the time, the Clifty Creek project was approximately 35% complete. It should be noted, however, that most of the parts and prefabricated equipment to complete the FGD project had already been purchased and continued to be delivered to the site and placed in storage. In addition, work on the landfill upgrade and other material handling facilities associated with the Clifty Creek FGD project was never halted and is currently continuing. However, given the continued harsh economic circumstances and scrubber design problems (explained below), Clifty Creek will not have FGD installed by January 1, 2012. The current estimated completion date for Clifty Creek to be fully retrofitted is mid-2013. [EPA-HQ-OAR-2009-0491-2803.1, p.4]
While construction continued on the FGD at Kyger Creek, very serious problems surfaced with the scrubber design and the materials being used. If not effectively addressed, the problems would severely impact the reliability and 802 removal efficiency of the scrubbers. See March 17, 2009 Press Release, attached. OVEC delayed the tie-in of the FGD system until a full engineering analysis could be performed and a solution to the problems could be found. OVEC is still working on these issues, and the current estimated completion date for Kyger Creek to be fully retrofitted is mid-2012. [EPA-HQ-OAR-2009-0491-2803.1, p.4]
It is important to note that, while OVEC is diligently working on all of the issues surrounding the delay of the FGD retrofit, all of the projected installation dates are subject to change due to the uncertainty with the scrubber design deficiencies. OVEC also does not know how long it will take for the operation of the FGDs to be optimized and achieve expected operating performance, particularly given the lack of industry experience with the Chiyoda Jet Bubbling Reactors. While the initial press release stated that the scrubbers could achieve 'as much as 98%' removal, that number is not a continuous, everyday, lifetime average expected removal efficiency. [EPA-HQ-OAR-2009-0491-2803.1, p.4]
Oklahoma Department of Environmental Quality
This rule may prove difficult to comply with both financially and with regard to physical/engineering constraints. From a financial standpoint, some companies may not have the capital to pay for the installation of controls in the short time frame allowed. Physically, while the installation of some controls may be possible within the time constraints, some units may not be able to physically accommodate the control equipment without major modifications. Additionally, the installation of controls will require that units be shut down. To install the controls likely to be required to ensure compliance on all of the units needed to generate sufficient excess allowances in all of the covered states, multiple units are likely to have outages at the same time, and rolling blackouts could result. Outages will mean that companies will be forced to purchase power over the grid to provide to their customers, at a substantial cost to the company, which cost will be passed on to the customers. That said, we are supportive of the public health benefits that will occur if this rule is implemented. However, we would urge EPA to reconsider the implementation timetable and consider a more phased in approach that will garner the public health benefits with a less burdensome financial impact to the public.[EPA-HQ-OAR-2009-0491-2662.1, p. 1]
Old Dominion Electric Cooperative
For example, EPA modeled that units are capable of switching from higher to lower sulfur bituminous coal by the 2012 compliance deadline , ld. at 45,273. Presuming, as EPA does, the Transport Rule fìnalization in mid 2011, units would only have approximately six (6) months to switch coals, alter transportation contracts, and potentially upgrade particulate controls. This approaches physical impossibility and leaves absolutely no room for any sort of contingency planning on the part of the utilities. EPA has failed to provide any actual data to support these presumptions. No information is available in the docket regarding actual ability (1) to break existing contracts including resulting penalties for contract breaches, (2) to acquire new coal transportation from the low sulfur bituminous mining regions, or (3) to evaluate actual necessary time to study and install any needed particulate controls upgrades. Further, EPA assumes unit coal switching from high to very low sulfur subbituminous coal is viable if the unit has demonstrated that capability in the past, Id. Again, EPA has provided no information to this supposition or to explain what it considers as adequate for demonstration. Adequacy should never be contingent upon a single test point. ODEC requests that EPA outline the specific information used with regard to transportation contracts, supply availability, and costs. [EPA-HQ-OAR-2009-0491-2877.1,p.4]
Similar problems are inherent in many of EPA's presumptions regarding installation of flue gas desulfurization units (FGDs) and selective catalytic reduction units (SCRs) in time to meet 2014 deadline mandates. For example, EPA believes that 14 GWs of FGD's can be planned and installed in 30 months from the Transport Rule finalization to the 2014 compliance date, Id. at 45,273. The proposal provides no background or indication that EPA has considered relative increased difficulties inherent in this next round of FGD retrofits, i.e. the more retrofits within the existing coal-fìred generating fleet, the harder and more time consuming and less cost effective the process becomes. Additionally, EPA has apparently not analyzed the additional material resources and skilled labor required in connection with other regulations the agency has proposed or may soon finalize. This will no doubt create competition for these additional resource and labor needs, thereby likely affecting timely installation of the pollution control equipment. [EPA-HQ-OAR-2009-0491-2877.1,p.5]
EPA should also consider that the pollution control vendors will be working with the utilities with the largest number of facilities needing upgrades. This will significantly reduce the ability to procure materials and acquire skilled trade labor for the smaller utilities (cooperatives and municipalities) that own fewer power stations. These smaller utilities may be put at an even greater disadvantage in meeting the 2012 and 2014 deadlines. [EPA-HQ-OAR-2009-0491-2877.1,p.5]
ODEC's concerns with the 2014 deadline and the associated modeled emission reductions presumptions are similar to those outlined above for the 2012 deadline. Many units modeled by EPA to undertake and complete necessary retrofits by the 2014 deadline will not be able to accomplish the task. Accordingly, at a minimum, EPA should extend the 2014 compliance deadline at least one year to rationally accommodate emissions reduction requirements. [EPA-HQ-OAR-2009-0491-2877.1,pp.5-6]
Owensboro Municipal Utilities (OMU)
The Schedule for Meeting Phase I Emission Caps Beginning In 2012 is Unreasonable.
Assuming the final Transport Rule is promulgated less than a year from now (EPA's current schedule is Spring of 20 II), Phase I of the program would allow only about 6-9 months to implement the new emission budgets, establish emission trading programs and make the needed investments to comply with the new emission caps. Having these new emission caps, state budgets and allowance allocations in 2012 creates major logistical challenges for the electric power sector and for the states that must implement the programs. [EPA-HQ-OAR-2009-0491-2811.1,p.2]
While the EPA claims that Phase I will require little investment in the way of new controls, its assumption is predicated upon high-level modeling and not the actual physical, contractual and financial constraints at electric generating facilities during such a short time frame. In reality, implementation of further reductions by a utility will require an engineering analysis for each generating unit, and any analysis must be based on promulgated targets. Until a final rule is in hand, a utility can only establish the framework for securing funding and procurement of the project. [EPA-HQ-OAR-2009-0491-2811.1,p.2]
Peabody Municipal Light Plant
The unit could and has continued to profitably operate on pipeline natural gas with a mix of some diesel oil. The facility intends to operate Unit 2 each year for the foreseeable future (at least through 2012) and at a similar capacity factor as has been observed in recent years. Unit 2 uses water injection for NOx control and a catalytic oxidizer to control CO. It is not reasonable to expect the unit to install additional NOx controls by the year 2012 and therefore emissions should not be adjusted downward to reflect such additional NOx control. [EPA-HQ-OAR-2009-0491-3730.1 p.1]
Pendleton, Mark
I am concerned about the the timing required in the rule. From the time the rule would become effective until the second phase of reductions are to begin is barely two-and-a-half years -- not nearly enough time for power companies to install the needed equipment. [EPA-HQ-OAR-2009-0491-1596, p.1]
Pfeiff, Mike
16. Unrealistic Implementation Schedule - Requiring affected sources to be in compliance by January 1, 2012 is nothing short of a fantasy. Not only is the proposed implementation period unrealistic from a technical standpoint but it is also unrealistic from an administrative standpoint. Many other commenters' have already provided comments on the technical limitations of the implementation schedule so I will not regurgitate those reasons here. [EPA-HQ-OAR-2009-0491-2742.1, p.12]
PPG Industries, Inc.
Comments on Effective Date of the Rule. Additionally, PPG is concerned with the nearly immediate effective date of the rule. EPA has suggested they will promulgate a final rule in late spring 2011 and it will become effective January 1, 2012. This is obviously very unreasonable considering the costly impact to affected facilities. It is beyond reason to expect a facility to engineer, procure, and install controls in six months or even budget for purchasing additional allocations. [EPA-HQ-OAR-2009-0491-2763.1, pp. 18-19]
PPL Corporation
7. Implementation Schedule
The proposed rule's implementation schedule of 2012 is very optimistic and not practical. [EPA-HQ-OAR-2009-0491-2739.1, p.9]
Public Utilities Commission of Ohio
While we applaud the efforts of EPA to create and support a model that provides the states and the regulated community with flexibility, we believe that the implementation schedule and regulatory framework proposed is unfortunately unworkable. EPA states in the proposed rule that in a best case scenario it takes about 27 months to install a flue-gas desulfurization scrubber and 21 months to install a selective catalytic reduction system to control NOx emissions. However, historically, in situations other than the best case scenarios the proposed rule assumes, three and a half to four years are necessary to build a scrubber. Given this situation, the time frame proposed in the rule is unreasonable for even the construction phase of the project. Potential delay due to complicating circumstances on the front end of any project, combined with the potential for complications during implementation phases, neither which have been contemplated by the proposed rule, also create a significant risk of delay for even the best managed projects. The PUCO feels that it is prudent and necessary to take these potential circumstances into account when developing any hard and fast timetable for implementation of a proposed rule. Accordingly, we ask EPA to reconsider its time frame for implementation of the Transport Rule. [EPA-HQ-OAR-2009-0491-2855.1 p.13]
In addition to the circumstances already set forth, other situations arise when pollution control equipment is being developed and assembled. Special stack liners typically need to be made "on-site." They are usually made of fiberglass. The impact of this is that a maximum achievable control technology (MACT) applies to the process, and Ohio can only enforce this MACT standard via a permitting process. [EPA-HQ-OAR-2009-0491-2855.1 p.14]
The proposed rule allows no time for companies or the states to develop implementation plans. Further, other regulatory steps, such as public utility commission approvals and environmental permitting, unfortunately seem to have been brushed aside in the development of the timetable for implementation of the rule. We urge EPA to take these routine, yet sometimes time-consuming matters into account when revisiting the implementation timeframe. [EPA-HQ-OAR-2009-0491-2855.1 p.14] [[These comments can also be found in Section VII.C.]]
RRI Energy, Inc.
The proposed Phase 2 implementation date (reduction in SO2 emissions budgets for the Group 1 states) must be changed from January 1, 2014 to January 1, 2015.
RRI understands that one of EPA's primary goals of the proposed CATR is to provide for a smooth transition from the existing programs, and RRI fully supports this goal. However, a Phase 2 implementation date of January 1, 2014 is not in accordance with this goal, and consequently the Phase 2 implementation date needs to be changed from January 1, 2014 to January 1, 2015 as outlined below. [EPA-HQ-OAR-2009-0491-2717.1 p.2]
Existing EGUs with a nameplate generating capacity greater than 25 MWe are currently subject to the requirements of the Clean Air Interstate Rule (CAIR), and these units will be subject to the final CATR beginning January 1, 2012. CAIR Phase 1 NOx and SO2 emission reductions were implemented beginning January 1, 2009 and January 1, 2010, respectively. Additional SO2 emissions reductions under CAIR Phase 2 were due to become effective on January 1, 2015. Planning and construction of emissions control devices such as a flue gas desulphurization (FGD) system require several years to complete the required activities (i.e., engineering design, bidding, budgeting, final engineering design, project approvals, financing, permitting / licensing, scheduling, construction and initiation of operations). Existing EGUs subject to CAIR have been planning future (nominally five year projections) operations in part in accordance with the requirements and implementation schedule under CAIR Phases 1 and 2. An acceleration of the Phase 2 SO2 emissions reductions simply can not be accommodated without subjecting the applicable EGU to substantial disruptions in the financial and operational plans. Note that EPA has identified that there are approximately 30 months between mid-2011 (expected promulgation of the final CATR) and January 2014 (implementation of proposed CATR Phase 2), which EPA believes is sufficient period of time to construct an FGD system (nominally 27 months based on EPA's analysis). However, even if all of the engineering design work is completed by mid-2011, EPA's analysis inexplicably omits the time required to obtain a permit from the local regulatory agency to construct such an FGD system. It is RRI's recent experience that regulatory agencies require at least six months and more typically one year to complete their review of FGD construction permit applications and issue the permits required (likely longer now because of the increased burden of applications and requests upon the agencies and decrease in available resources within the agencies). Consequently, EPA must change the implementation schedule for the proposed CATR Phase 2 SO2 emissions reductions from January 1, 2014 to January 1, 2015 to allow sufficient time to complete all activities associated with the planning and construction of emissions control devices such as an FGD system.[EPA-HQ-OAR-2009-0491-2717.1 p.3]
A January 1, 2015 CATR Phase 2 implementation date would allow applicable EGUs to synchronize their SO2 emission reductions with reductions in emissions of hazardous air pollutants (HAPs) expected through the promulgation of the MACT standards for coal and oilfired EGU boilers. Compliance with the MACT standards is currently projected to be due by November 2014. It is expected that installation and operation of emission control systems for acid gas HAPs will also yield co-beneficial reductions in SO2 emissions. Lastly, because of the logistical constraints associated with the expected installation of acid gas / SO2 emission control devices in the upcoming years, it is likely that these control devices will become operational over an extended period of time (e.g., mid-2013 through November 2014). Consequently, SO2 emissions reductions will also occur during that time period, which should result in decreases in ambient PM2.5 concentrations sufficient to demonstrate attainment with the (i) 1997 PM2.5 NAAQS (annual standard) by the April 2015 maximum attainment deadline and (ii) 2006 PM2.5 NAAQS (24-hour standard) by the December 2014 deadline. Areas unable to meet the December 2014 deadline may seek a maximum 5-year extension to 2019. [EPA-HQ-OAR-2009-0491-2717.1 p.3]
San Miguel Electric Cooperative, Inc.
 The proposed 2012 and 2014 compliance deadlines and associated emissions reductions are unrealistic and are not supported by real world assumptions.  [EPA-HQ-OAR-2009-0491-2641.1, p.6]
Southern Company
In addition to the methodological flaws, Southern Company believes that the Proposed Transport Rule compliance dates of 2012 and 2014 are unreasonable and unjustified. EPA should not seek a compliance date any earlier than 2015. [EPA-HQ-OAR-2009-0491-2864.1, p. 6]
The proposed compliance schedule is problematic since most states, if not all, will not have time to develop a SIP alternative to replace the FIP proposed by this rule; utilities will be faced with the extremely difficult task of developing and implementing several entirely new allowance strategies from unknown new allowance markets; implementation of fuel switching or the installation of new emission controls will be difficult if not impossible; and the compliance dates are uncoordinated with expected EPA regulations and are disruptive to compliance planning. [EPA-HQ-OAR-2009-0491-2864.1, p. 6] [[The SIP comment can also be found in Section VII.C.]]
III. The Proposed Compliance Deadlines are Unreasonable, Unnecessary, and Disruptive to Compliance Planning
even implementing fuel switching or installing low NOx burners at a facility will be virtually impossible. Furthermore, coal procurement strategies, fuel inventory levels, and the system dispatch procedures, which are carefully planned over the long term, may be negatively impacted and may not be able to be adjusted in such a short time frame. [EPA-HQ-OAR-2009-0491-2864.1, pp. 8-9] [[These comments can also be found in Section VII.C.]]
A later compliance date (no earlier than 2015) will allow states to exercise their right to develop their own SIP, something many states, including Alabama, Mississippi, and Georgia have expressed a desire to do. [EPA-HQ-OAR-2009-0491-2864.1, p. 9] [[This comment can also be found in Section VII.C.]]
B. EPA Should Discard the 2014 Compliance Date
The January 1, 2014 compliance deadline is only about 30 months after the expected final Transport Rule, which is an insufficient amount of time to install Selective Catalytic Reduction (SCR) for NOx control or Flue Gas Desulfurization (FGD) for S02 control. Even if these controls could be built by 2014, in some states, large investment decisions must be approved through the state Public Service Commission (PSC) processes. [EPA-HQ-OAR-2009-0491-2864.1, p. 9]
Furthermore, the 2014 compliance date does not represent a coordinated approach with the numerous other upcoming environmental regulations affecting the power sector such as future Transport Rules, Clean Air Act Section 112(d) standards (i.e., IB and EGU MACT), New Source Performance Standards (NSPS), Best Available Retrofit Technology (BART) requirements, Greenhouse Gas (GHG) regulations, as water and ash regulations. Indeed, EPA has acknowledged the numerous upcoming regulations in the Proposed Transport Rule and EPA has stated its intent to coordinate these rules with the 'goal of fostering investments in compliance that represent the most efficient and forward-looking expenditure of investor, shareholder, and public funds.' Despite EPA's stated intent, the proposed Transport Rule compliance deadlines are not being coordinated with the other upcoming regulations and fail to accommodate the need for coordinating important compliance planning and investment decisions. In the midst of all the uncertainty of the upcoming environmental regulations and the impacts of those rules on the investment decisions, it is difficult for the utilities and the PSCs to determine the best path forward from both a customer and business perspective. [EPA-HQ-OAR-2009-0491-2864.1, p. 9]
In fact, the 2014 compliance deadline is disruptive to the compliance planning of companies, which were planning for a CAIR Phase II deadline of 2015 and adds costs for little if any overall environmental benefit beyond what CAIR would have accomplished in either Phase I as discussed above or in Phase II (2015) (see Section N). Because no additional controls can be built before 2014, the proposed Transport Rule requirements in 2014 will greatly increase the compliance cost for utilities (in terms of allowances) over CAIR and the 'hard' caps may present a reliability concern. Therefore, EPA should not require a compliance date sooner than that of CAIR Phase II (2015). [EPA-HQ-OAR-2009-0491-2864.1, p. 9]
A compliance date any sooner than 2015 is unreasonable since: 1) new emission controls cannot be built in 30 months; 2) companies cannot make important compliance planning and investment decisions without regulatory certainty and coordination; and 3) the existing CAIR program is achieving and expected to achieve the similar benefits to the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2864.1, p. 10]
VI. EPA's Control Installation Assumptions are Flawed
In the proposed Transport Rule EPA states that it takes approximately 27 months to install a single Flue Gas Desulfurization (FGD) system and 21 months to install a single Selective Catalytic Reduction (SCR) system. 9 The agency further believes that 30 months between the final rule and compliance is sufficient time to install such controls. 10 In developing its timelines, EPA used only two facilities as the basis for its FGD timeline (2 Units at Big Bend Station and 2 Units at Centralia) and two facilities for its SCR timeline (1 unit at Somerset Station and 2 units at Keystone))). As discussed below, EPA's examples and assumptions about FGD and SCR time frames are neither representative nor common. Southern Company's historical experience has shown that it takes an average of 54 months to install an FGD and 36 months to install an SCR. These timelines include all of the steps necessary to plan, design, construct and start up an FGD or SCR system on an existing unit. Although our individual project schedules vary depending on site-specific factors and requirements, none of our FGD or SCR installations have occurred in the timeframes that EPA suggests. Further, none of our FGD or SCR installations were completed within the 30 months that EPA proposes to allow before the 2014 Transport Rule compliance date. [EPA-HQ-OAR-2009-0491-2864.1, p. 13]
In summary, EPA has greatly underestimated the amount of time that it takes to design, permit, construct, and start up new FGDs and SCRs. It will take longer than 30 months -- in some cases significantly longer than 30 months -- to complete the retrofits of FGD and SCR units at existing EGUs. While considering a compliance date no earlier than 2015, EPA must also update its control installation assumptions taking into account 1) a larger and more recent representation of installations-taking into consideration that quick installations can result in post-commercial problems; and 2) changes in the regulatory landscape since the adoption of CAIR and pending regulations for water and ash management that increase the likelihood of control installations requiring permitting; and 3) schedules that represent the installation of multiple controls at a facility at the same time. [EPA-HQ-OAR-2009-0491-2864.1, p. 20]
[See EPA-HQ-OAR-2009-0491-2864.1, pp. 13-20 for extensive discussion of control installation and schedules.]
VII. EPA's Fuel Switch Assumptions Are Flawed
EPA made the assumption that coal switching within the bituminous coal grades will have relatively little cost or schedule impact on most units and has requested comment on this issue. EPA's assumption is flawed because coal switching occurs over a longer timeframe than EPA has assumed; this is due to how coal purchases are layered in over time, the time it takes for plants to tune operations to the new fuel as well as the ability of the coal market to accommodate such a large switch as has been assumed. Currently, about two-thirds of Southern Company's required coal supply for 2012 is under contract; and this percent will likely increase prior to issuance of the final Transport Rule. Because of the layering approach that is common in the industry, new long-term contracts are negotiated well before existing contracts expire. Southern Company's coal procurement evaluations and decisions factor in the current and/or projected value of sulfur, which will necessarily change after the final Transport Rule is issued and new SO2 allowances enter the market. Because the allowance price discovery for SO2 will not be possible until the second half of 2011 at the earliest, the lead time to assess true costs of procurement decisions for 2012 and beyond will be severely limited. (A spring 2011 Long Term purchase may include purchases not only for 2012 but potentially for 2013,2014, and 2015, etc). Although coal contracts typically include clauses allowing us to be released from our contractual obligations in the event of a significant regulatory change, these clauses are narrow in nature and could not be relied on to release the Company from the obligation to purchase a large number of contracted tons. Exercising such a clause could be costly, time consuming, and potentially detrimental to coal producers. Of additional concern are rail and barge transportation contracts which are negotiated independently from coal contracts and would have to be revised or terminated on an extremely short time frame if the coal supply associated with those agreements is reduced or eliminated. This could also prove to be a costly and inefficient process. Furthermore, cancelling contracts of this magnitude invites protracted and expensive litigation. [EPA-HQ-OAR-2009-0491-2864.1, p. 21]
Even the most straightforward coal switches can take well over a year to implement. A typical timeline for a 'simple' coal switch would follow the steps below:
1. 4 - 6 months to procure test fuel; (4 - 6 months cumulative) 2. 1 - 4 months test bum; (5 - 10 months cumulative) 3. 2 - 3 months data evaluation; (7 - 13 months cumulative) 4. 2 - 6 months to procure first production fuel; (9 - 19 months cumulative) 5. 2 - 6 months for delivery of production fuel; (11 - 25 months cumulative) 6. 3 to 5 years for existing contracts to expire and achieve 100% switch (47 - 85 months cumulative) [EPA-HQ-OAR-2009-0491-2864.1, p. 21]
Furthermore, EPA's assumption that national coal markets can shift large volumes of production from higher sulfur grades to lower sulfur grades by 2012 is unreasonable and impractical. First, mine operators are currently reeling from the recession, and many cannot absorb additional costs associated with shutting-in existing production sites and opening new sites or expanding existing sites. Second, lead times, costs and regulatory challenges associated with permitting and starting operations at new mines or increasing production at existing mines may be insurmountable by 2012. And lastly, the ability for transportation infrastructure and capacity to absorb large volume swings in such a short time frame is uncertain. EPA's assumptions indicate that it believes the power, transportation, and coal industries can stop and tum their operations on a dime. These assumptions reveal EPA's complete lack of appreciation for the scale of these operations and the complex, long-term planning these industries must employ. [EPA-HQ-OAR-2009-0491-2864.1, pp. 21-22]
Southern IL Power Cooperative
Requiring coal-fired power plants to construct additional pollution control equipment and have it operational by 2012 to 2014 is not feasible. Manufacturing lead times for much of this equipment would be eight to twelve months within a normal business time, but for such a volume of equipment that would be required to meet the demands of the proposed rule, lead times would certainly be extended. Similarly, sufficient quantities of skilled labor to install such equipment would be difficult to obtain and still meet the 2012 to 2014 deadlines. [EPA-HQ-OAR-2009-0491-2863.1 p.2]
State of Delaware Department of Natural Resources & Environmental Control
An EGU Cap-and-Trade Program alone is not sufficient to mitigate a states impact on downwind states. Delaware understands the bottom line of the EPA proposal is that the control of EGUs is all that is needed in order for a state to mitigate its significant impact on downwind states. This conclusion is inconsistent with much of the information Delaware has learned in its efforts to address the ozone problem over the past 40 years, and the more recent fine particulate matter problems. The installation of all reasonably available control technology (RACT) on all volatile organic, nitrogen oxide, and sulfur dioxide emitting sources is needed. In addition, advanced best available control technology (BACT) level controls on EGUs and other large sources stationary sources is needed. And, based on Delaware's experience the timing associated with the design, permitting and construction of advanced emission controls on EGUs is relatively short; on the order of 24-months. If upwind states were to implement these measures (i.e., RACT on all sources, and BACT on all large stationary sources), as Delaware already has, attainment of the current and upcoming ozone and PM2.5 NAAQSs would be in reach. Delaware believes these measures must be added as required elements of this proposal. [EPA-HQ-OAR-2009-0491-2980.1, p.10]
State of Louisiana, Department of Environmental Quality
EPA has based compliance deadlines on the basis of 'time necessary for installation' of control technology. While LDEQ agrees that the equipment necessary to achieve emission reductions can indeed be installed within this time frame, LDEQ disagrees that the compliance deadlines are achievable. These facilities schedule major 'outages' on a rolling 5-year basis and cannot arbitrarily shut a unit down to install control technology without having back-up power sources. Additionally, it is infeasible for all units to shut down simultaneously so that controls can be installed prior to the unreasonable compliance dates imposed by the rule. Further, owners or operators must apply for and secure any necessary authorizations from their respective permitting authorities before modification of affected sources may commence. [EPA-HQ-OAR-2009-0491-2655.1, p.5]
State of Ohio Environmental Protection Agency (Ohio EPA)
b. Ohio EPA is concerned with the 'one size fits all' approach by which U.S. EPA assumes all sources can install controls or perform fuel switching. U.S. EPA must provide an implementation schedule that is reasonably achievable considering the ramifications for not complying. [EPA-HQ-OAR-2009-0491-2793.2, p. 2]
U.S. EPA believes that sources have sufficient time to install the advanced emissions controls that will be necessary to meet the proposed allocations. However, Ohio EPA believes this will be quite challenging if not impossible for a number of Ohio sources. For example, U.S. EPA assumes that Beckjord Unit #6 will install a scrubber by 2014. However, this unit's location lacks available surrounding land for a scrubber installation, which thereby would necessitate a 'custom fit'. While three years (from final rule effective date) may be plausible for an ideal situation, in the Beckjord situation three years will not provide enough time for the necessary planning and installation. As another example, the unit at the Zimmer plant already has a scrubber (installed in 1991) with an original design efficiency of approximately 91 %. Improvements have increased the efficiency of this unit but not to the 98% level assumed in this proposal, and for which the basis of allocations will be made. If a requirement for 98% is still assumed for this unit in the final rule, there would likely be no choice but to dismantle the current scrubber to make room for a new scrubber in exactly the same location. This would not be a 'typical' retrofit and will certainly necessitate more time than this proposal allows, and would be extremely costly in light of the pollution control investment already made at the plant. [EPA-HQ-OAR-2009-0491-2793.2, pp. 2-3]
With respect to the fuel switching which is assumed for some sources, Ohio EPA also believes there may be cases where the 'one size fits all' approach is not appropriate. For example, some sources are contractually bound to yertain fuels which will make fuel SWitching by the deadline impossible. Also, natural gas may not be available at all locations, making fuel switching an impractical control option. [EPA-HQ-OAR-2009-0491-2793.2, p. 3]
Because of the compliance with emissions limitation provisions and assurance provisions, units that can't meet this 'one size fits all' deadline of 2014 may face serious consequences. Therefore, Ohio EPA believes U.S. EPA should reconsider the 2014 deadline''or, alternatively provide additional flexibility, without legal consequences, for sources that are simply unable to install required controls by the deadline. Certainly, due to the limited trading opportunities provided for in the proposed rule, U.S. EPA cannot assume that an owner can just 'trade' to obtain the needed allowances. [EPA-HQ-OAR-2009-0491-2793.2, p. 3]
This proposal requires significant reductions in Ohio of S02 between 2012 and 2014. Ohio's 802 emissions have been declining significantly over the past eight years. In 2002 emissions of 802 were over 1,132,000 tons while in 2009 they were at 600,686 tons. This proposal budgets S02 emissions at 464,964 tons in 2012 and 189,583 tons in 2014, while CAIR had provided for an estimated 2015 budget of 233,464 tons. While many sources are already in the planning and/or construction stages of implementing the installation of scrubbers to address CAIR, this proposal will require significantly more sources to install scrubbers over the next several years. Small emissions budget allocations to a number of smaller units will necessitate retirement or retrofitting with controls. We fully support the comments of the Public Utilities Commission of Ohio (PUCO) regarding reliability concerns and the inability. to install controls in the time frames provided under this proposed rule. [EPA-HQ-OAR-2009-0491-2793.2, p. 3-4]
Texas Mining and Reclamation Association
I. EPA Should Extend the Transport Rule Compliance Dates to Accommodate Pending Federal Standards and State Emission Reduction Target Deadlines.
EPA proposes that the initial phase of emission reductions will begin in 2012 (less than one year after the rule is finalized), requiring sulfur dioxide (SO2) and nitrogen oxide (NOX) reductions in those 31 states covered for the 24-hour and/or annual PM2.5 National Ambient Air Quality Standards (NAAQS) as well as the 8-hour ozone NAAQS.1 A second round of additional SO2 reductions would be required for "Group 1" states in 2014 and EPA is considering additional NOX reductions in a future proposal for the ozone NAAQS (Transport Rule II). [EPA-HQ-OAR-2009-0491-2734.1 p.1]
EPA has set out a number of "Key Guiding Principles" in the preamble of the proposed Transport Rule, one of which is to "Provide [a] Workable Approach for EPA and States." Here, EPA is requesting compliance with the Transport Rule by 2012, a very short compliance timeframe considering the myriad of environmental regulations undergoing review and revision during the next few years, some of which form the basis of the Transport Rule (e.g., 1997 8-hour ozone NAAQS). EPA should consider the breadth of environmental regulations, including but not limited to regulations for hazardous air pollutants, new source performance standards, and greenhouse gas regulations. Failure to consider these ongoing emission reduction efforts by the states and pending regulations does not comport with the Key Guiding Principle to Provide a Workable Approach for EPA and the states. [EPA-HQ-OAR-2009-0491-2734.1 p.3]
 Regulations with a short shelf life do not afford regulated entities sufficient time to request, acquire and implement the necessary control technology to meet the changing standards. The regulated community requires regulatory stability and certainty in order to properly plan and execute capital expenditures required for additional control technology.   [EPA-HQ-OAR-2009-0491-2734.1 p.4]
Tennessee Valley Authority (TVA)
B. Issue: EPA's projection that utilities can meet 2012 NOx caps by installing low NOx burners (LNBs) is unrealistic.  [EPA-HQ-OAR-2009-0491-2782.1, p. 2]
TVA Comment: With the final Transport Rule expected in mid 2011, utilities will have only 6 months to design, permit, procure, and install LNBs or LNB upgrades. Such a short schedule is unreasonable for the installation of LNBs on even a single unit. LNB addition or upgrades require a minimum of a year from project initiation to completion, and can take several years when the work must be aligned with boiler outage schedules. [EPA-HQ-OAR-2009-0491-2782.1, p. 3]
C. Issue: EPA takes the position that it takes approximately 27 months to build a FGD unit and approximately 21 months to construct an SCR unit. [p. 45273] TVA Comment: TVA has extensive experience constructing FGDs and SCRs and has studied this timing issue in depth. TVA's fossil generation system currently operates FGDs on 17 units and SCRs on 21 units. The enclosed report (Attachment 1) [Note that Attachment 1 was not available in the docket at the time of this summary.] entitled Issues Associated with the Acceleration of Tennessee Valley Authority's Clean Air Program, prepared by a TVA expert in conjunction with the nuisance lawsuit (North Carolina v. TVA), sheds light on scheduling issues relating to the construction of FGDs and SCRs. The report states in pertinent part: A typical FGD project installation duration from conceptual design to commercial operation averages 5 years. A typical SCR project installation duration from conceptual design to commercial operation averages 3 to 4 years depending on the size of the unit and complexity with the retrofit installation. There are also schedule implications of the SNCR and SO3 mitigation projects that must be worked in conjunction with the new installation of FGDs and SCRs. TVA is confident in our projections for the time needed to complete FGD and SCR projects, which are based on TVA's actual experience to install FGDs and SCRs on several units, input from Advatech (TVA's FGD partner), benchmarking with other utilities and an extensive program review on cost and schedule conducted by Bechtel Power Corporation. (Executive Summary, p. 5) [EPA-HQ-OAR-2009-0491-2782.1, p. 3]
he above expert report was prepared in February 2007, a period when CAIR was being implemented. The report explains that the scheduling pressures placed on utilities by CAIR have stretched the market capacity for many critical resources. The rigorous schedules of the proposed Transport Rule would place even greater demands since the rule seeks deeper reductions in SO2 and NOx emissions on an accelerated schedule. The schedules assumed by the Transport Rule for construction of SCRs and FGDs are in fact impractical and unachievable. [EPA-HQ-OAR-2009-0491-2782.1, p. 4]
As an example, TVA completed the installation of the FGD on Paradise Fossil Plant Unit 3 in approximately 5 years, considering the time from conceptual design to commercial operations. The actual project schedule for the Paradise FGD is shown as Figure 3 in the attached expert report (Attachment 1, p. 16). Even this schedule may not be achievable at some sites due to space and other site specific constraints. For plants requiring installation of both FGD and SCR, physical site constraints commonly result in sequencing the installations and lengthening schedules approximately 2 years. [EPA-HQ-OAR-2009-0491-2782.1, p. 4]
TVA estimates that it would take 9 to 12 months (and possibly longer) to develop a permit application and obtain a permit for an air pollution control project that has the potential for significant emission increases. The permitting process would add several months to the overall project schedule. [EPA-HQ-OAR-2009-0491-2782.1, p. 4]
Further, permitting and construction of scrubber by-product disposal areas is required for most FGD projects, and for virtually all where the FGD is the first FGD for a particular facility. Typically this work can be completed concurrently with the normal 5 year period for FGD design and construction. If EPA determines, as identified as an option in EPA's proposed Coal Combustion Residuals Rule, that scrubber by-product must be disposed of as hazardous waste in landfills permitted under subtitle C requirements, more time will be required. Subtitle C landfills have often required 6 to 8 years for permitting and construction. Moreover, schedules must also be adjusted to accommodate the permitting process for any modifications to the facility's NPDES permit for the wastewater discharge from the scrubber. [EPA-HQ-OAR-2009-0491-2782.1, pp. 4-5]
s a federal agency, TVA must also comply with the environmental review requirements under the National Environmental Policy Act, Endangered Species Act, National Historic Preservation Act and other environmental statutes prior to undertaking these projects, often resulting in additional time necessary to complete the projects. [EPA-HQ-OAR-2009-0491-2782.1, p. 5]
TVA and other utilities have many older, smaller coal fired units, some of which may not be economical to control and operate in the future in light of anticipated air, water, and waste regulatory regulations. As a result, TVA is evaluating plans to idle a portion of its coal fleet. Additional gas-fired and nuclear generating units on the TVA system or elsewhere will be required to replace much of this idled capacity. These new cleaner units would in effect be constructed in lieu of constructing controls on some of the idled units. For example, TVA is currently constructing two new gas fired units at its existing Lagoon Creek Plant in Tennessee. For such natural gas units at an existing site, the project duration from air permitting to commercial operation is approximately three years. Gas fired units at greenfield sites would take significantly longer to complete. The overly stringent schedule in the proposed Transport Rule does not allow for such conversions from coal to cleaner fuel. [EPA-HQ-OAR-2009-0491-2782.1, p. 5]
The controls and new capacity required over a 31 state region to comply with the proposed Transport Rule will require a significant increase in skilled labor, manufacturing, and material resources for the construction of pollution control equipment and will cost billions of dollars. We anticipate schedule impacts and cost increases due to resource constraints. Unit outages for controls installations must be staggered and avoid peak demand seasons to ensure reliability. With the final Transport Rule expected in mid 2011, the earliest that construction of the required FGDs, SCRs, and new gas fired units could be achieved is 2016. The resource and schedule constraints described above, including permitting and environmental review, may result in even later completion dates for many pollution control projects. [EPA-HQ-OAR-2009-0491-2782.1, p. 5]
D. Issue: The compliance deadlines in the proposed Transport Rule are unreasonable and unrealistic. [EPA-HQ-OAR-2009-0491-2782.1, p. 5]
In the event that EPA promulgates a Transport Rule that requires the level of emission reductions set out in the proposal, the compliance date should be no earlier than 2016. As indicated in our other comments, utilities will need time at least until 2016 to install the controls necessary to achieve these reductions. [EPA-HQ-OAR-2009-0491-2782.1, pp. 4-5] [[This comment can also be found in Section VII.C.]]
U.S. Congressman Pete Hoekstra
The over-riding concern of 'why push this rule through so fasf is paramount. A compliance deadline of 2012 does not leave much time after the anticipated final rule is promulgated in 2011 to determine a cost effective, cost stable method of operating our affected unit. [EPA-HQ-OAR-2009-0491-3662, p.2]
we energies
Schedules for the construction of selective catalytic reduction (SCR) and flue gas desulfurization (FGD) units are assumed by EPA to be 21 and 27 months, respectively. These are unrealistic schedules and do not reflect the reality exhibited by combined SCR and FGD installations at two plants owned by We Energies. It is unclear if EPA's proposed schedules included the up front planning and regulatory approval time frames for such projects. This timeframe alone can be in excess of 12 months. [EPA-HQ-OAR-2009-0491-2629.1, p.4]
At We Energies' 1,200 MW Pleasant Prairie Power Plant the actual in-the-field construction period required 34 months. However, when front-end engineering and regulatory approvals are added, along with back end plant tie-ins and startup, the total time period for this project was 57 months as illustrated in the diagram in Attachment B. [EPA-HQ-OAR-2009-0491-2629.1, p.5] [[See Docket Number EPA-HQ-OAR-2009-0491-2629.1, pp.14-15 for Attachment B.]]
A more contemporary example is the on-going installation of combined SCR and FGD installations at We Energies 1,135 MW South Oak Creek Power Plant. This project is anticipated to require a total of 41 months of in-field construction time, and the total project period starting with engineering and ending with in-service operation is currently expected to entail 77 months. Attachment C illustrates the South Oak Creek schedule. This second plant is located adjacent to Lake Michigan and is representative of many existing coal plants that are located in close proximity to water bodies. Because of the nature of these types of sites, there are substantial space limitations for adding new controls. These engineering and construction constraints add to the cost and time required for major retrofit projects. [EPA-HQ-OAR-2009-0491-2629.1,p.5] [[See Docket Number EPA-HQ-OAR-2009-0491-2629.1, pp.16-17 for Attachment C.]]
EPA's proposed schedules do not recognize either the timing or regulatory impact of permitting issues associated with meeting the requirements of this rule. Many, if not most utility projects are required to obtain Public Utility Commission approval before embarking on any major construction project. [EPA-HQ-OAR-2009-0491-2629.1, p.5]
Timelines for construction authorization and rate recovery authorization vary, but for the South Oak Creek project, a project application was submitted to the Public Service Commission of Wisconsin in June 2007 and a final approval was received approximately one year later. Construction dockets are increasingly contested case proceedings, and in this case there were several intervening parties and project opponents including environmental groups, ratepayer advocacy organizations, and representation from large commercial and industrial customers. [EPA-HQ-OAR-2009-0491-2629.1,p.5]
Additionally, the Wisconsin Department of Natural Resources or the Michigan Department of Natural Resources and Environment may also have to issue construction permits, even for pollution control projects mandated by the EPA. The proposed schedules in the rule do not allow adequate time for agency review, public comment, and permit approval when coupled with engineering planning and construction. [EPA-HQ-OAR-2009-0491-2629.1, p.5]
In addition to not reflecting actual total project time requirements, EPA's mandatory schedule will impose artificial market factors into what should otherwise be a competitive bidding process. There are a limited number of equipment providers and qualified construction firms capable of both providing the necessary equipment and expertise for timely and proper installation. Even during the current economic downturn, the availability of skilled craft labor capable of constructing complex piping, process and instrumentation systems is limited. We Energies has experienced this skilled labor limitation during the current construction of the South Oak Creek Power Plant air quality control system cited above, as well as the construction of the new Elm Road Generating Station. [EPA-HQ-OAR-2009-0491-2629.1, p.5]
Coal Switching 
EPA assumes that switching from a bituminous to a sub-bituminous coal can be achieved by 2012. This assumption does not take into consideration three key factors. The first is the availability of sub-bituminous mining capacity, particularly production centered in the Power River Basin. Power River Basin is the closest source of sub-bituminous coal to the states identified in the proposed rule containing facilities that may consider such a fuel switch. [EPA-HQ-OAR-2009-0491-2629.1, p.6]
The second factor is more critical and involves the necessary railroad capacity between the Powder River Basin and the transport rule affected utilities in Midwestern states. We Energies and other utilities have documented evidence of having to limit generation due to limited rail capacity and the resulting decrease in receipt of contracted coal shipments. [EPA-HQ-OAR-2009-0491-2629.1, p.6]
The third factor is the potential influence that this regulatory requirement and its short-term deadline has on the market costs for sub-bituminous coals. Again, this regulatory-induced market impact will be most critical for those facilities seeking contracts for coal from the Powder River Basin. A 2014 or longer transition schedule for coal switching is more realistic and should be considered by EPA. [EPA-HQ-OAR-2009-0491-2629.1,p.6]
EPA has also not fully considered whether specific EGUs are capable of switching coals. A switch to sub-bituminous coal (for a unit designed to burn bituminous coal) brings multiple and significant issues to an existing generating unit. First, sub-bituminous coal is generally dustier and presents material handling and storage issues. Switching to this coal may require specific actions to address health and safety issues, including the design and installation of dust suppression and collection systems. Depending on the specific design and operation of any dust collection systems, state air quality construction permits may be required. Second, switching to sub-bituminous coal usually results in either a load decrease or significant capital investments and upgrades to attempt to maintain the design capacity of the unit. It is not as simple as burning a different coal. [EPA-HQ-OAR-2009-0491-2629.1, p.6]
Reliability 
Based on our current system outage schedule for the five units operating at the facility, emission control installations necessary to meet the current budget allocations could not be completed until spring 2014, under a best case scenario. Allocation shortages during the first years of the program (2012-2014) would have to be met through allowance trading with other states in the pool. We expect that pressure for allowance trading would be most severe in the early years of the program and are concerned about both allowance availability and costs during this time. [EPA-HQ-OAR-2009-0491-2629.1, p.6]
West Window Corp.
The 2014 deadline does not provide enough time for emissions control equipment to be designed and necessary regulatory permits to be obtained, nor for the equipment to be fabricated and installed on power plants. [EPA-HQ-OAR-2009-0491-2386, p.1]
Wisconsin Power and Light Company
EPA's final CATR must factor in the required regulatory approvals for construction authorization from public service commissions/state utility boards to install controls at regulated utilities. It does not appear that the EPA basis has taken this into account by projecting that flue gas desulfurization (FGD) installations can be built within 27 months and selective catalytic reduction (SCR) installations within 2 I months. WPL recently broke ground for the installation of an SCR at the Edgewater Generation Station to comply with the Wisconsin NR428 Reasonably Available Control Technology (RACT) Rule requirements for NOx. Approval of the Edgewater SCR Construction Authorization from the Wisconsin Public Service Commission took 19 months and it is currently estimated to take another 30-35 months to finish construction of this project. EPA's final rule must consider all required phases of this work, which encompasses regulatory approvals, environmental permits, equipment procurement, site preparation, construction and installation of air pollution equipment plus initial start-up and shakedown. In addition, retrofit of air pollution controls at existing EGUs may require additional engineering and design to address location or physical constraints. Therefore, WPL believes that EPA's models should assume a lead time of four to five years for FGDs and three to four years for SCRs. [EPA-HQ-OAR-2009-0491-2844.1 p.4]
Wolverine Power Supply Cooperative
Besides being unlawful, the tight implementation schedule of 2012 and 2014 provides nowhere near enough time to design and construct major pollution control projects, and thus potentially reduces available generation during the early years with possible electric reliability impacts. We would propose to begin Phase I in 2014 and Phase II in 2016, which will also be commensurate with the Electric Generating Unit MACT standard implementation. This would also provide adequate time for EPA to incorporate the corrected modeling results into the state budgets and unit allocations described above. [EPA-HQ-OAR-2009-0491-2825.1 p.3]
The full permitting, financing, design and construction schedule for major pollution control retrofits is in the range of four to six years. [EPA-HQ-OAR-2009-0491-2825.1 p.3]
Ownership of coal-fired units in Michigan is concentrated within a handful of utilities. These utilities cannot be expected to be capable of installing within the near-term controls necessary to control emissions below their proposed allowance allocations under the proposed rule. As a consequence, Wolverine must anticipate a short-fall in the available intrastate allowances which it would need to operate its Sumpter facility in a manner consistent with its operation this past summer. [EPA-HQ-OAR-2009-0491-2825.1 p.3]
Xcel Energy Inc.
II. IMPLEMENTATION TIMELINE
1. Permitting activities associated with control equipment installations could extend emission control project schedules and these potential delays are not built into EPA's CATR compliance projections.
Xcel Energy has first hand experience with how air emissions control technology projects can be delayed by air emission permitting issues. In Texas, a seemingly noncontroversial project, the installation of low-NOx burner technology on one of our existing coal fired utility boilers, was delayed by nine months due to air permitting issues. The outage to complete this installation was postponed by nine months while minor permitting issues between the State and EPA Region 6 were resolved. In situations where a permit or permit amendment is required to complete the installation of air emissions control technology, a very small part of that process timeline in under the control of the regulated part),. If the individual regulator is unable to process a permit in a timely manner, the project can be delayed. Under CATR's 30 month schedule (mid-2011 final rule issuance to the January 1, 2014 compliance date), it is unclear how much time has been allowed for air emission permitting. [EPA-HQ-OAR-2009-0491-2728.1, p.6]
Response: 
For EPA responses to the above comments on feasibility, please see the final Transport Rule preamble section VII.C.2 and the "Transport Rule Engineering Feasibility Response to Comments" document in the docket to this rulemaking.

V.D. [Reserved]

V.D.1. General Comments on Remedies/ Remedy Options Overview/Trading Ratios Approach

Organization: ARIPPA
Comment: 
ARIPPA
Based on its analysis of the D.C. Circuit Court's decision in North Carolina, ARIPPA does not interpret the Court's decision as prohibiting interstate trading under any circumstances. EPA has previously promulgated and continues to implement successful emission control programs under Title I which rely in significant part on the availability of interstate trading for their effectiveness. Consistent with EPA's evaluation of "significant contribution" toward nonattainment in downwind states, especially with respect to the cost effectiveness component of such analysis, the allowance for interstate trading among affected sources has contributed to the cost effective implementation of these emission reduction programs. By all accounts, these programs have reduced emissions to levels below the emission caps established by EPA for purposes of preventing significant contribution. [EPA-HQ-OAR-2009-0491-2794.1, p.16]
Not only have such programs been successful in achieving emissions reductions through the use of such systems, the Courts have confirmed the legislation of this interstate trading approach under Title I. Most notably, in State of Michigan v. EPA, 213, F.3d 663 (2000), the D.C. Circuit Court of Appeals affirmatively upheld EPA's right to authorize interstate allowance trading. [EPA-HQ-OAR-2009-0491-2794.1, pp.16-17]
As discussed above, EPA's use of the stringent 1% threshold for determining significant contribution results in an overstatement of the degree to which a state's emissions contribute to emissions impacts in downwind states. As a result, the states' emissions budgets are highly conservative, providing an ample "safety net" for eliminating significant contribution. For this reason, EPA could both refine the conservatism inherent in this analysis, and still eliminate the restrictions on interstate trading in the Proposed Rule, while still meeting its objectives for addressing interstate transport. More specifically, EPA could authorize an allowance trading program that allows maximum flexibility in interstate trading while providing a "backdrop" for ensuring that emissions from any individual state do not exceed those rates that actually contribute to nonattainment or interfere with maintenance of NAAQS in downwind states. [EPA-HQ-OAR-2009-0491-2794.1, p.17]
It is also critical that EPA's emission and trading schemes are reliable and dependable from the perspective of regulated sources. Specifically, an affected source must be able to rely upon allowances secured through interstate trading as its compliance strategy, without concern that, because of circumstances beyond its control, those allowances may lose their emission value or must be surrendered by the facility because of overall emission rates for the state. Facilities must be able to develop and implement a compliance plan based upon certainty regarding the reliability of allowances secured from trading, to the same extent as reliance on any other control option under the Transport Rule. Thus, once a facility appropriately and lawfully secures allowances through trading from other sources, such allowances must remain fully available to that source for use in compliance demonstrations under the Transport Rule, without any potential that such allowances must be surrendered because of their relation to the overall state allowance budget. [EPA-HQ-OAR-2009-0491-2794.1, p.17]
As stated above, the opportunity to engage in a flexible interstate trading program is particularly critical for facilities, including the ARIPPA plants, which would not receive an adequate allowance allocation under the Proposed Rule and, therefore, would be forced to rely on allowance trading to secure sufficient allowances to offset their emissions. Because allowance trading would be critical to these facilities' ability to demonstrate compliance with the Transport Rule, the final rule should authorize an interstate trading program that is both flexible and allows for cost-effective trading. Further, the authorization of a flexible interstate trading program would be consistent with EPA's stated "key guiding principles" for development of the Proposed Rule, including cost effectiveness, providing incentives and flexibility to the regulated community, and ensuring a reliable power supply. 75 Fed. Reg. 45226227. [EPA-HQ-OAR-2009-0491-2794.1, p.17]
For these reasons, ARIPPA believes that the limited use of interstate trading proposed by EPA under the Proposed Rule is unduly stringent, unsupported by any applicable statutory or regulatory standard, and unnecessary to achieve necessary emissions reductions. ARIPPA supports the promulgation of a final rule that maximizes the use of interstate trading for affected EGUs, irrespective of the state in which such sources are located. None of the three proposed allowance trading programs identified in the Proposed Rule meet this standard. [EPA-HQ-OAR-2009-0491-2794.1, pp.17-18]
To the extent that EPA nonetheless proceeds with implementation of one of the three options discussed in the Proposed Rule, ARIPPA endorses the use of the remedy option proposed by EPA through the Proposed Rule (i.e., the State Budgets/Limited Trading option). [EPA-HQ-OAR-2009-0491-2794.1, p.18]
Response: 
Thank you for your comment.  EPA has reviewed the 2008 Court decisions thoroughly and believes we have proposed a reasonable rule that addresses the Court's concerns. 
EPA believes that the preferred remedy it proposed and is finalizing provides flexibility for sources through trading, while also assuring that emission reductions take place in specific states to eliminate their downwind contribution to nonattainment and interference with maintenance.   EPA received numerous comments on the proposed allocation methodology.  Based on those comments, we put forth in January a Notice of Data Availability that proposed several alternatives that were more fuel neutral and control neutral.  As a result, in this final rule, EPA finalized a heat input based allocation methodology.
Organization: Associated Electric Cooperative, Inc. (AECI)
Comment: 
Associated Electric Cooperative, Inc. (AECI)
EPA proposes three "remedies" to satisfy the court mandate:
1- Proposed Remedy: State Budgets/Limited Trading
2- Alternative Remedy: State Budgets/Intrastate Trading
3- Alternative Remedy: Direct Control
As written, all three options are too restrictive. However, Associated could support option 1 (the "Proposed Remedy") as a model rule with the improvements listed in this document. EPA should withdraw the idea of a FIP and allow the states update their SIPs to meet the goals of the Transport Rule. [EPA-HQ-OAR-2009-0491-2845.1 p.12]
Response: 
As explained in section III C of the preamble, the proposal responds to the remand of CAIR by the Court.  The FIPs replace the remanded CAIR FIPs to eliminate emissions of SO2 and NOx that significantly contribute to or interfere with maintenance of the 1997 Ozone NAAQS and 1997 and 2006 PM2.5 NAAQS in the eastern half of the country (see 75 FR 45225-45226, August 2, 2010).  Note that, as EPA further explained in the preamble to the proposal, a covered state may submit for review and approval a state implementation plan that replaces the federal requirements with state requirements that would achieve the required reductions.  A state's SIP submission to replace the Transport Rule FIP might propose to use any remedy of the state's choosing that contains adequate provisions that prohibit any source or type of emission activity within the state that significantly contributes to nonattainment or interferes with maintenance downwind.  Additionally, the final rule discusses SIP submissions further in section X of the preamble.
Organization: Citizens Campaign for the Environment (CCE)
Comment: 
Citizens Campaign for the Environment (CCE)
Important elements of the proposed Transport Rule that CCE recommends should be maintained in the finalized rule include:
2) Limit interstate trading. Limiting interstate trading of emissions credits will help ensure that all states will be required to clean up their act, rather than allowing plants to purchase pollution credits from neighboring states that have invested in cleaning up their plants and reducing emissions. CCE recommends that EPA maintains limits on interstate trading in the final Transport Rule. [EPA-HQ-OAR-2009-0491-1937.1, p. 3]
Response: 
Thank you for your comment.  EPA is finalizing the air quality-assured trading remedy with the assurance provisions.
Organization: City of Dover, Delaware
Comment: 
City of Dover, Delaware
The City prefers a less restrictive interstate trading system than what is proposed in any of the three methods contemplated in the proposed Transport Rule. While recognizing the need to remain within the confines of the D.C. Circuit Court's decision in the State of North Carolina v. Environmental Protection Agency, the City believes that a trading system that allows for greater flexibility for trading emission allowances between states is preferable. The City supports an allowance trading system more akin to that which would be established under Senator Carper's proposed legislation for regulating SO2 and NOx emissions. [EPA-HQ-OAR-2009-0491-2636.1, p.3]
Response: 
Thank you for your comment.  EPA has worked within its authority and the 2008 Court decisions to replace the Clean Air Interstate Rule and maintain flexibility for EGUs with an air quality-assured trading remedy, while ensuring that reductions to eliminate a state's downwind contribution to significant contribution and interference with maintenance occur.
Organization: City of Springfield, Illinois, Office of Public Utilities
Comment: 
City of Springfield, Illinois, Office of Public Utilities
As to options under the proposed Transport Rule that US EPA invites comment, CWLP supports the interstate allowance trading option, so as to provide greater flexibility to sources, while still restricting the transport of certain emissions consistent with the Clean Air Act's provisions. CWLP also supports the proposal that allocates allowances to units six (6) years after shutdown. [EPA-HQ-OAR-2009-0491-2635.1, p.3]
Response: 
Thank you for your comments.  For a discussion of the continued allocation to units after shutdown, please see Section VII.D.2 of the preamble to the final Transport Rule.
Organization: City Utilities of Springfield
Comment: 
City Utilities of Springfield
City Utilities supports a regional trading platform that affords the highest degree of flexibility and market based compliance opportunities. Issue: As the owner of relatively small units with low emissions profiles, City Utilities necessarily encounters higher than average compliance costs. This was strikingly demonstrated over two decades ago by studies performed by Energy Ventures Analysis on behalf of USEPA (copy available on request). Accordingly, emissions trading can be an important compliance mechanism, if even for the short term, for CU and similarly situated utilities. The proposal outlines three different emissions market options for compliance trading  -  a preferred program and two optional programs - each of which is restrictive to at least some degree. CU would prefer an option that allows open trading throughout the control region with no artificial restrictions on an affected source's ability to use purchased allowances for compliance. CU recognizes EPA's dilemma in reconciling the cost efficiency of emissions trading with the clean air strictures imposed by the D.C. Circuit's CAIR remand. However, we would hope the Agency could craft a more open trading platform that still maintains the benefits of open trading for units severely impacted by the rules. [EPA-HQ-OAR-2009-0491-2721.1 p.2]

Recommendation: CU could not support any trading program more restrictive than the preferred option described in the proposal and certainly would be opposed to unit-specific emission limits. Ideally, the final rule should allow unrestricted regional trading. In addition, some provision should be available for the use of Acid Rain allowances for compliance during the initial transition period. [EPA-HQ-OAR-2009-0491-2721.1 p.2]
Response: 
Thank you for your comment.  EPA has tried to maintain as much flexibility for sources as allowed under the Clean Air Act and the 2008 Court Decisions by proposing and finalizing air quality-assured trading programs.  As stated in the proposal, the Court rejected EPA's effort to harmonize the CAIR SO2 trading program with the existing requirements of Title IV of the CAA, holding that section 110(a)(2)(D)(i)(I) did not give EPA authority to terminate or limit Title IV allowances.
Therefore, EPA proposed that the Transport Rule provisions not allow the use of Title IV allowances either as the basis for allocating Transport Rule SO2 allowances or directly for compliance with allowance-holding requirements.  As finalized, the Transport Rule will not carryover Title IV SO2 allowances into the new SO2 program for the reasons given in section IX of the preamble for the final Transport Rule.  Title IV allowances continue, of course, to be used for compliance with the Acid Rain Program.
Organization: Clean Air Board of Central Pennsylvania
Comment: 
Clean Air Board of Central Pennsylvania
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.59.]
Within this framework, we hope that trading allowances do not interfere with downwind attainment. We understand that it is a complex task to process the data and resulting ambient concentrations of fine particulate and ozone.
Response: 
Thank you for your comments.  EPA believes that the air quality-assured trading remedy will provide some flexibility to sources while still ensuring that states eliminate those emissions that contribute to downwind nonattainment and interference with maintenance.
Organization: Clean Air Task Force
Comment: 
Clean Air Task Force
We take no position on EPA's proposed choice of the 'state budgets/limited trading' remedy over the two alternative remedies under consideration, although we believe that any emission trading scheme that could reasonably result in the exceedance of a state's budget plus variability limit would be inconsistent with the court's decision in [EPA-HQ-OAR-2009-0491-2738.1, p.6] North Carolina v. EPA.  Thus, we completely agree that EPA may not allow unrestricted interstate allowance trading, may not permit any use of Title IV acid rain allowances as a means of TR compliance, and may not permit allowances that may have been 'banked' under another emission trading program to be used for TR compliance. [EPA-HQ-OAR-2009-0491-2738.1, p.7] 
Selection of Remedy [EPA-HQ-OAR-2009-0491-2738.1, p.22]
The Court in North Carolina v. EPA stated that whatever method EPA uses to determine significant contribution to downwind nonattainment or maintenance problems for section 110(a)(2)(D) purposes, emissions from any state so determined to be significantly contributing must be eliminated.  This requirement was central to the Court's reasoning in striking down the interstate trading provisions in CAIR. Therefore, any emissions trading scheme proposed in the TR must be able to demonstrate compliance with this core statutory requirement; that is, any trading scheme must ensure that emissions from each individual state that have been found to be significantly contributing to downwind nonattainment are eliminated. [EPA-HQ-OAR-2009-0491-2738.1, p.23] 
EPA has proposed an approach to implementing the emission reduction requirement in the TR that it asserts meets this test, and also has described two alternative approaches which for various policy reasons it does not prefer.  We believe that the two alternate remedy options -- called 'state budgets/intrastate trading' and 'direct control' -- would each be consistent with the Court's opinion, because each would require that EGU emissions in a covered state would remain below the state budget (plus variability limit, in the case of the direct control option).  Although EPA's preferred option, called the 'state budgets/limited trading' remedy, would allow interstate trading of allowances, EPA has proposed 'assurance provisions' that it asserts will 'ensure that every state is making reductions to eliminate the portion of significant contribution and interference with maintenance that EPA has indentified....'  [EPA-HQ-OAR-2009-0491-2738.1, p.23; for additional comments pertaining to Selection of Remedy see p. 22-24 of this comment]
EPA requests comment on the use of opt-in provisions. We do not favor allowing sources that are not subject to the emission reduction requirements to be issued allowances that would increase the overall state emission budgets. Due to the uncertainty that any reductions made by such units would be surplus, verifiable, permanent and enforceable, we are concerned that such opt-in provisions could compromise the integrity of the EGU emission reductions requirements of the TR, and jeopardize assurance that a state's significant contribution would be eliminated, as required by the Court in North Carolina v. EPA.  [EPA-HQ-OAR-2009-0491-2738.1, p.26]  
Response: 
Thank you for your comments.  Please see section VII.A of the preamble to the final rule for a full discussion of the air quality-assured trading program and why EPA chose not to finalize either of the alternative options, intrastate trading and direct control.  In order to ensure that each Transport Rule region state eliminates significant contribution to nonattainment and interference with maintenance, EPA has developed state-specific budgets as discussed in section VI.D of the preamble.  In addition, EPA has implemented assurance provisions starting in 2012, rather than 2014 as proposed.  See section VII.E of the preamble to the final rule.  EPA is not finalizing the opt in provisions for the reasons addressed in section VII.B. of the preamble to the final rule.
Organization: Commerce Lexington Inc.
Comment: 
Commerce Lexington Inc.
Coal plant emissions can continue to be reduced in a realistic, more cost-effective manner through multi-pollutant legislation that achieves equivalent environmental benefits without threatening the economic viability of our communities or the reliability of our power system. [EPA-HQ-OAR-2009-0491-2869.1 p.2]
Response: 
Thank you for your comment.  Absent finalized multipollutant legislation from Congress, EPA has acted within its authority and the 2008 Court decisions to replace the Clean Air Interstate Rule while providing flexibility to EGUs and still ensuring that states eliminate emissions that significantly contribute or interfere with maintenance downwind.
Organization: Connecticut Department of Environmental Protection
Comment: 
Connecticut Department of Environmental Protection
Structure the Transport Rule so that it reflects how all electric power is generated for the grid; specifically, EPA should adopt performance standards for sources subject to the Transport Rule because state-wide emission caps do not ensure that emission reductions occur where they are needed. For example, emission reductions in upstate New York State do little to address transport from the greater New York City metro area into southwest Connecticut. As such, careful examination of the operation and emissions from EGUs and other sources, such as diesel generators, that operate in close proximity to Connecticut on high electric demand days (HEDDs) will show that performance standards are necessary to protect Connecticut's air quality. [EPA-HQ-OAR-2009-0491-2780.1 p.7]
Response: 
Thank you for your comment. At this time EPA has not proposed performance standards as a remedy for upwind transport of emissions in the Transport Rule.  However, the Transport Rule assures downwind states that they will receive relief from upwind reductions that will help them achieve the NAAQS. EPA is committed to fulfilling its obligation to assure the downwind states that they receive the full relief they are entitled to under section 110(a)(2)(D).
Organization: Consumers Energy
Comment: 
Consumers Energy
:: Consumers Energy does not support a program whereby EPA would set unit or plant-specific emission rates. We believe that UARG's legal arguments fully support our position. [EPA-HQ-OAR-2009-0491-2837.1, p.16]
Response: 
Thank you for your comments.  EPA is finalizing the air quality-assured trading remedy.
Organization: Environmental Markets Association (EMA)
Comment: 
Environmental Markets Association (EMA)
The Environmental Markets Association recognizes EPA's efforts in the proposed Transport Rule to have emissions trading play a central role in the next stage of SO2 and NOx regulation, while working within the bounds of the D.C. Circuit's earlier decision in North Carolina vs. EPA. We know that EPA recognizes that it is critical to maintain the integrity of allowances as they represent the return on emission reduction investments which underwrite the improvements in human health and air quality. [EPA-HQ-OAR-2009-0491-2727.1, p.1]
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.47-48.]
To fulfill our national compliance targets 18 by undertaking significant financial commitments, we feel it is essential for EPA to restore confidence in trading programs when companies can both receive a fair shot at a return on investment and reduce emissions.
We at EMA appreciate the need for additional emission reductions. Without the environmental certainty of a cap, none of us can be assured that desired improvements in human health and air quality will be achieved. At the same time, without the regulatory certainty needed to support trade, risk premiums for emission reduction projects go up, along with the cost of allowances, something that does not benefit either the environment or consumers.
Cap and trade should be about attracting capital to the highest returned projects. The higher the cost of capital, the higher the cost of the projects that get completed, and the greater the resistance to further reductions.
Emission allowances represent the return on emission reduction investments which underwrite these improvements in human health and air quality.
We know that EPA realizes that it is critical to maintain the integrity of allowance markets, even as it becomes necessary to tighten or expand environmental programs.
Response: 
Thank you for your comments.  Section VII of the preamble discusses EPA's decisions regarding the remedy for the final rule.  Section IX of the preamble describes the differences between CAIR and the Transport Rule.  Section IX.C describes EPA's reasons for not carrying forward the SO2 or NOx allowance banks from CAIR. EPA believes that allowing such allowance carryover in the Transport Rule is inconsistent with North Carolina.  We believe that the remedy finalized in the rule permits trading that provides covered source's flexibility while ensuring the state-specific reductions required by the statute under CAA section 110(a)(2)(D)(i)(I).
Organization: EquiPower Resources Corp.
Comment: 
EquiPower Resources Corp.
THE TRANSPORT RULE'S STATE BUDGET CAPS AND ASSURANCE PROVISIONS PRECLUDE THE DEVELOPMENT OF AN EFFECTIVE EMISSIONS TRADING MARKET AND EQUIPOWER URGES AN ALTERNATIVE APPROACH [EPA-HQ-OAR-2009-0491-2704.1, p.3]
The Transport Rule seeks to reduce NOX and SO2 emissions from EGUs in the 32 states covered by the rule by 71% and 52%, respectively, relative to 2005 emissions to address downwind nonattainment issues. Those reductions mean that Phase II of the Rule, which goes in to effect in 2014, would result in emission reductions of over 6.3 million tons of SO2 per year and 1.4 million tons of NOX per year relative to 2005 levels. Given the magnitude of the contemplated reductions, it is critically important that the Transport Rule contain provisions to obtain those reductions in the most cost-effective manner possible. A cap-and-trade mechanism is the only way to provide flexibility to sources attempting to comply with the Rule, and thus represents the only vehicle to obtain those reductions in a cost-effective manner. [EPA-HQ-OAR-2009-0491-2704.1, p.3]
While the Proposed Rule attempts to capture some of these benefits by including some intra- and inter-state trading provisions, as explained below, EquiPower does not believe that the trading provisions of the Transport Rule will result in any sort of meaningful or effective emissions trading market, and therefore the Rule will not produce cost-effective emission reductions. Indeed, EPA concedes that even its preferred option ("State Budgets/Limited Trading"  -  the option with the greatest flexibility) will only provide "some limited flexibility to covered sources" because the provisions as drafted only provide for "limited interstate trading." EquiPower submits that EPA has overstated the effect of the Proposed Rule's trading provisions. Rather, the practical effect of the Transport Rule is to impose a system on affected EGUs that ultimately will be even more burdensome than a command-and-control option. EquiPower believes this result is not mandated by the D.C. Circuit's decision in North Carolina v. EPA and does not represent sound policy, and that as a result, the Agency should consider alternate approaches to achieve the Transport Rule's emission reduction goals. See Section III.C. below [See p.9 of this comment summary for Section III.C]. [EPA-HQ-OAR-2009-0491-2704.1, p.3]
[See EPA-HQ-OAR-2009-0491-2704.1, p.3-4 for comments pertaining to Benefits of Cap-and-Trade]
Eliminates The Advantages Associated With A Cap-And-Trade Program Because They Preclude The Development Of A Robust Emissions Credit Market [EPA-HQ-OAR-2009-0491-2704.1, p.5]
EquiPower believes that the Transport Rule will not create a true cap-and-trade program given the inherent limitations on such trading imposed by the Rule. Indeed, the Proposed Rule is, in essence, a command-and-control program with a capped overlay that eliminates even the limited flexibility that is provided through command-and-control (i.e., the ability to operate unconstrained so long as the targeted emissions rate is met or the required control technology is used). [EPA-HQ-OAR-2009-0491-2704.1, p.5]
EPA Should Adopt An Alternative Approach To Ensuring That Upwind Emissions Do Not Contribute To Downwind Nonattainment That Addresses The D.C. Circuit's Holding In North Carolina v. EPA While Enabling A Robust Emissions Trading Market To Develop [EPA-HQ-OAR-2009-0491-2704.1, p.9]
As described above, although the Transport Rule purports to establish a cap-and-trade program, the Transport Rule's limitation on trading will hamper any potential for a viable emissions trading market. While EPA's initial attempt to achieve emission reductions through a regional cap-and-trade program in the CAIR was ultimately struck down in North Carolina v. EPA, EPA should not abandon the many advantages that are provided by a robust emissions trading market. As discussed below, EPA should consider an alternative framework that would achieve emission reductions through a true cap-and-trade program while also ensuring the results required under the CAA § 110(a)(2)(D)(i)(l) are met. [EPA-HQ-OAR-2009-0491-2704.1, p.9]
In North Carolina v. EPA, the D.C. Circuit concluded that EPA's CAIR framework was flawed in not compelling upwind states to prohibit emissions from sources that "contribute significantly to nonattainment" and "interfere with maintenance" in downwind states as required by CAA §110(a)(2)(D)(i)(I). The court reasoned that sources in a state could purchase allowances from a noncontributing source outside of the state, and the result would be that any given state could emit beyond its cap  -  and potentially far beyond its cap. Additionally, because EPA had not measured each state's" significant contribution" to downwind nonattainment, the court found that it was unclear how EPA determined that the SIPs approved under CAIR would achieve the goals of § 110(a)(2)(D)(i)(I) without knowing each state's contribution. [EPA-HQ-OAR-2009-0491-2704.1, p.9]
Thus, the challenge for EPA is to craft a regulation that: (1) ensures that all states prohibit emissions contributing significantly to nonattainment in downwind states for the 1997 ozone and PM2.5 and 2006 PM2.5 NAAQS (collectively "the Transport Rule NAAQS"); (2) allows sources to reduce emissions through a combination of both control technology and the purchase of allowances in a balance that promotes desired results and economic efficiency; (3) allows states flexibility to require emissions reductions from non-EGU sources where preferable; and (4) provides regulatory certainty by confirming the full extent of control technology EGUs must adopt while providing EGUs access to a robust trading market to meet their remaining emission reductions targets. CAIR fell short of these goals, and the Transport Rule fares no better. The following proposal would achieve all of these goals, and is within EPA's statutory authority as described below. [EPA-HQ-OAR-2009-0491-2704.1, p.9]
The Proposed Alternative [EPA-HQ-OAR-2009-0491-2704.1, p.10]
The alternative approach would begin with familiar elements: (1) the establishment of state budgets, so that states will target a certain average emission reduction; and (2) an allowance trading system that does not limit interstate trading, and, thus, encourages EGUs to determine the most efficient and cost effective way to achieve significant emission reductions. EPA's CAIR modeling showed that CAIR would go far to achieve attainment in most areas. However, as the D.C. Circuit noted, CAIR did not necessarily compel upwind states to prohibit emissions from sources contributing significantly to nonattainment in downwind states. Thus, an additional step is required for the few remaining instances when nonattainment will persist after implementation of regional controls. [EPA-HQ-OAR-2009-0491-2704.1, p.10]
Additional modeling, conducted either by the states or Air Quality Management Districts, would be used to identify the impact of EGUs in that state on areas projected to be in nonattainment with Transport Rule NAAQS after implementation of regional controls. In some (perhaps many) instances, that residual nonattainment will be the result of mobile source pollution, and would not be improved by installation of controls on specific EGUs. If, however, NOx emissions from an EGU within a state have a substantial impact on nonattainment with the ozone or PM2.5 NAAQS, then the state SIP would need to require the EGU to install SCR or another control technology that will reduce NOx emissions at the source by 85% or more from uncontrolled levels. Similarly, where modeling shows that SO2 emissions from a specific EGU (or EGUs) in the state have a substantial impact on nonattainment with the PM2.5NAAQS, then the SIP would need to require that EGU to install FGD or another control technology that will reduce SO2 emissions at the source by 90% or more from uncontrolled levels. Consistent with the federalism principles embodied in CAA § 110 described in Section IV.A below, the State would have the option of controlling other sources of SO2 or NOx emissions (including, potentially, mobile sources and/or other industrial sources), so long as those control measures achieve equal or greater emission reductions within the same general geographic area. This element of the proposal is key since the cause of residual nonattainment in some instances will be mobile source pollution or other emissions sources, and states will be best positioned to determine the most effective  -  and cost-effective  -  source of reductions. [EPA-HQ-OAR-2009-0491-2704.1, p.10]
A comparable approach could be used where modeling predicts an area to be in nonattainment after implementation of regional controls and an EGU (or EGUs) located outside of the state is projected to have a substantial impact on such nonattainment. In that case, the state in which the EGU is located would need to require the EGU to install emissions controls, as discussed above. If the State declines to do so, EPA would look favorably upon a CAA § 126 petition from the downwind State that specifically identifies the EGU (or EGUs) as contributing to local nonattainment within its borders and asks EPA to impose emission control requirements directly on that EGU through a § 126 rulemaking. [EPA-HQ-OAR-2009-0491-2704.1, pp.10-11]
Importantly, these mandated controls would not change a state's emissions budget nor would they change the source's allowance allocation. Thus, although the source may incur additional expense in installing controls rather than using allowances to cover its emissions, the EGU could transfer unused allowances to another co-owned unit or sell the allowances on the market. [EPA-HQ-OAR-2009-0491-2704.1, p.11]
The Benefits of This Alternative Approach This proposal is superior to the Transport Rule's assurance provisions for four reasons. [EPA-HQ-OAR-2009-0491-2704.1, p.11]
First, in ensuring that the regulatory framework compels the prohibition of emissions from sources contributing significantly to nonattainment in downwind states, this alternative would address the D.C. Circuit's main objection to CAIR in North Carolina v. EPA, while providing vastly more flexibility to sources subject to CAIR. [EPA-HQ-OAR-2009-0491-2704.1, p.11]
Second, this alternative is well within EPA's legal authority because CAA § 110(k)(5) allows EPA to require SIP revisions to ensure that the SIP will result in attainment of the NAAQS, CAA § 110(a)(2)(A) requires the states to ensure that the SIP includes enforceable emissions limitations that result in attainment of the NAAQS, and CAA § 126 authorizes the Agency to require, in response to a petition from a downwind state, emissions reductions from sources that significantly contribute to nonattainment in downwind states. This approach also avoids the legal issues associated with the Transport Rule (and discussed below at Section IV.A.). [EPA-HQ-OAR-2009-0491-2704.1, p.11]
Third, this approach would produce a much better return on control investments because investments would be targeted to either those EGUs where additional reductions are most cost-effective or to those EGUs that are proven to be contributing significantly to downwind nonattainment. [EPA-HQ-OAR-2009-0491-2704.1, p.11]
Finally, this approach would enable a robust, interstate trading market; would eliminate the potential for allowance hoarding that is likely to result from the limited allowance trading contemplated under the Transport Rule; and would allow sources that have installed controls to run at maximum capacity, benefitting the environment and maximizing the cost effectiveness of the rule. [EPA-HQ-OAR-2009-0491-2704.1, p.11]
The net result would be the same or better environmental protection as compared to the Transport Rule, at a far lower cost. [EPA-HQ-OAR-2009-0491-2704.1, p.11]
Response: 
Thank you for your comments.  EPA disagrees with the commenter that the preferred trading remedy approach in the proposal is a command-and-control program.  Rather, for the reasons described in section VII.A of the final rule preamble, EPA believes that the air quality-assured trading program we are finalizing addresses the North Carolina court decision through both cost-effectiveness and reductions that address our statutory mandate under the Clean Air Act section 110(a)(2)(D), while providing covered units with flexible options to meet the required reductions.  The vast majority of public comments supported the remedy EPA is finalizing. 
EPA is not addressing reductions from non-EGUs in this rule as discussed in the preamble to the final rule because EPA believes that there are little or no emission reductions available by non-EGUs at the cost thresholds used in the final rule and so no basis for developing non-EGU state budgets reflecting the elimination of significant contribution to nonattainment and interference with maintenance.
EPA appreciates the commenters' thoughtfulness in proposing an alternative remedy to consider.  We have given your proposal due consideration but do not find that it improved our ability to address interstate transport under CAA section 110(a)(2)(D)(i)(I), in line with the Court decision, in an administratively practical way.
Organization: Headington, Maureen
Comment: 
Headington, Maureen
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.138.]
Pollution trading credits deem some communities unfortunate by receiving the lion's share of the pollutants and the toxins.
These games do little to benefit the whole of society, and I find it appalling.
Response: 
Thank you for your comments and for taking the time to attend the public hearing in Chicago.  EPA values and benefits from public participation.  In the final rule EPA retains the trading option that we proposed.  However, the assurance provisions that were also proposed will now begin in 2012 instead of 2014.  EPA makes the assurance provisions effective starting in 2012 because this approach provides even further assurance, consistent with the North Carolina court decision, that each state's prohibited emissions will be eliminated from the start of the Transport Rule trading programs.
Since the proposed Transport Rule, EPA has conducted additional analysis of the effects of the Transport Rule on environmental justice and other vulnerable communities.  We concluded that, similar to our experience with the Acid Rain Program,[1]many environmental justice communities are expected to see large health benefits, and, based on our analysis, none are expected to experience any disbenefits from implementing the air quality-assured trading program.  The results of this analysis are presented in section XII of the final rule preamble and Chapter 5 of the Regulatory Impact Assessment which is available in the docket for this rule.  In addition, the Clean Air Act provides flexibility for state and local authorities to impose stricter limits on sources to address specific local air quality concerns.  Such limits are independent of the requirements in this rule, and compliance with Transport Rule requirements in no way excuses a source from complying with other Clean Air Act or state law requirements.

[1] See http://www.epa.gov/airmarkets/resource/docs/ejanalysis.pdfand  Ringquist, Evan J. 2011. "Trading Equity for Efficiency in Environmental Protection? Environmental Justice Effects from the SO2 Allowance Trading Program."  Social Science Quarterly 92(2):297-323
Organization: Kentucky Division for Air Quality
Southeastern States Air Resource Managers (SESARM)
Comment: 
Kentucky Division for Air Quality
Emissions trading should be allowed to the extent authorized under the Clean Air Act. Any such trading program in the final Transport Rule should be operated at no cost to the local and state agencies. [EPA-HQ-OAR-2009-0491-2805.1, p.1]
Southeastern States Air Resource Managers (SESARM)
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.44.]
Number seven, emissions trading should be allowed to the extent authorized under the Clean Air Act and any such trading program in the final Transport Rule should be operated at no cost to the local and state agencies.
Response: 
The Transport Rule will be implemented as a Federal Implementation Plan (FIP) resulting from the failure of the affected states to adequately address section 110(a)(2)(D)(i)(I) of the Clean Air Act with respect to the 1997 and 2006 PM NAAQS and the 1997 ozone NAAQS.  See section IV. of the preamble to the final Transport Rule for a  discussion of EPA's legal responsibility and authority.
Regional air programs such as the NOx Budget Trading Program (under the NOx SIP call) and the CAIR ozone-season NOx trading program, developed by EPA to enable states to comply more cost-effectively with the "good neighbor" requirements of CAA section 110(a) (2)(D)(i) pertaining to the interstate transport of pollution, do not have their own funding source.  (The Acid Rain program, in contrast, was authorized and funded by the Clean Air Act Amendments of 1990.)  Accordingly, for regional air programs, EPA has asked covered states that participate in interstate emission allowance trading programs that satisfy the CAA section 110(a)(2)(D)(i) requirements to contribute a portion of their Section 105 funds towards the implementation and operation of the centralized allowance trading and emissions tracking system administered and jointly supported by EPA resources. 
Since the Transport Rule programs will provide covered states with a more cost-effective approach to satisfying the CAA 110(a)(2)(D)(i) requirements with respect to the 1997 and 2006 PM NAAQS and the 1997 ozone NAAQS than otherwise would be available to them, EPA plans to use a portion of the covered states' Section 105 funding  to supplement the EPA resources used to directly implement this regional air program.  EPA will provide staff for program operations, system maintenance, compliance  and accountability assessment and plans to absorb any difference in required contract resources above the current, CAIR-based funding.
Organization: Maryland Department of Environment (MDE)
Comment: 
Maryland Department of Environment (MDE)
Maryland also commends EPA for addressing the Court's and the states' concern about the relationship between emission reductions and downwind contributions, an important transport issue that caused the Court to reject and remand the 2005 Clean Air Interstate Rule (CAIR) back to EPA. By restricting interstate trading and the use of banked allowances, EPA has taken a major step towards addressing the court's finding and the Clean Air Act (CAA) requirement that each state must reduce its share of transported pollution. [EPA-HQ-OAR-2009-0491-2639.1, p.2]
Ratios Trading Option
As described in the preamble to the Transport Rule (see 75 FR 45304), the Ratios Trading Option would penalize sources based on the degree of their impact on downwind air quality. Sources having greater impacts would need more allowances in a trade than sources having less of an impact. While this seems like it would be advantageous, in reality it would not be. Maryland does not support this option for the following reasons. [EPA-HQ-OAR-2009-0491-2639.2, pp.15-16]
First, a ratios trading option would discourage the greatest polluters from trading since they would need more allowances than their trading partners. This would limit the value of their allowances, put them at a market disadvantage, and discourage the disadvantaged sources from making any meaningful emission reductions. Additionally as stated in the preamble to the Transport Rule, a ratios trading option would "assure a cumulative downwind air quality result, not ...assure specific upwind reductions." This would not be consistent with the section 110(a)(2)(D) requirements that reductions in emissions occur in particular geographic locations. [EPA-HQ-OAR-2009-0491-2639.2, p.16]
The complexity of the meteorology is another reason the ratios option would be difficult to implement. Upwind states impact various downwind receptors, and the impact on the receptors varies according to meteorological conditions. Also, each downwind receptor is affected by a different set of upwind states, and it would be very difficult to manage a system based on each individual receptor in each downwind state. [EPA-HQ-OAR-2009-0491-2639.2, p.16]
EPA states that the ratios trading option originally was considered for the NOx SIP Call but dismissed because, "it took close to a year to perform the underlying analysis to develop ratios for one pollutant (NOx) and one downwind air quality problem (ozone)...there are three pollutants (annual NOx, annual SO2 and ozone season NOx) and two downwind air quality problems (ozone and PM2.5) to consider" with the proposed Transport Rule. It would take a considerable amount of time to perform the analysis if this remedy were included in the proposed Transport Rule and subsequent rules. This would delay the rulemaking process and put us further behind in our attainment goals.
Maryland does not support the ratios trading option as a remedy for the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2639.2, p.16]
Response: 
Thank you for your comments. EPA generally agrees with the commenter and is not finalizing the ratios trading option.  EPA is finalizing the air quality-assured trading remedy, with assurance provisions beginning in 2012 instead of 2014, to hew to the North Carolina opinion.
Organization: Mid-America Regional Council (MARC) Air Quality Forum
Comment: 
Mid-America Regional Council (MARC) Air Quality Forum
However, due to the bi-state nature of the area, issues may arise with the proposed rule in unintended ways. The proposed rule should include some mechanism to allow emission credit trading across state lines or across groups. [EPA-HQ-OAR-2009-0491-2613.1, p.1]
Response: 
Thank you for your comment.  For clarification on your issue regarding trading, please note that there is no restriction on trading, per se.  Anyone may buy, sell, or bank an allowance in any of the Transport Rule trading programs.  However, in the SO2 trading program, there are two groups of states.  A source in a Group 1 state can only use SO2 allowances allocated to Group 1 states for compliance with the SO2 trading program.  A source in a Group 2 state can only use SO2 allowances allocated to Group 2 states for compliance with the SO2 trading program.  For compliance in the annual NOX and ozone-season trading programs, respectively, sources may use annual NOX and ozone-season allowances allocated for any state, even if that state is in a different group for SO2 than the source's state.  See section VI.D.2.b.in the preamble for the final rule.
Organization: New Jersey Department of Environmental Protection (NJDEP)
Comment: 
New Jersey Department of Environmental Protection (NJDEP)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.157-158.]
Transport Rule as proposed does not guarantee that a specific source that has significant impact to a downwind state will ever control its emissions. A real world example for New Jersey is the Portland Generating Station Portland Plant in Pennsylvania.
This source is adversely impacting New Jerseys air quality due to its significant, largely uncontrolled emissions and its close proximity to New Jersey. Under the Transport Rule, not all power plants in a large state like Pennsylvania will need to control their emissions. Thus, the Portland Plant might remain poorly controlled through the purchase of allowances under the Transport Rule.
If little or no reductions in the actual emissions from the Portland Plant occur, New Jersey's air quality, and the public health and welfare, will continue to suffer as a result of the plants emissions. Therefore, it is necessary to implement emission performance standards, similar to those already adopted by New Jersey, for electric generating units.
Response: 
Please see section VII. A and VII.J of the final rule preamble.
Organization: New Orleans City Council
Comment: 
New Orleans City Council
The Council has concerns regarding the Proposed Rule insofar as it may increase the costs of electricity to retail customers by restricting trading and devaluing emissions credits banked under the Clean Air Interstate Rule ("CAIR") and insofar as it fails to consider transmission constraints in its allocation of emissions allowances to specific units. [EPA-HQ-OAR-2009-0491-2719.1, p.2]
Response: 
Thank you for your comment.  Please note that EPA's modeling does in fact consider transmission constraints between regions in the country.  More information on this may be found in the TSD in the docket to this rulemaking called, Documentation Supplement for EPA Base Case v. 4.10_FTransport--Updates for the Final Transport Rule.
EPA has not projected a significant increase in the cost of electricity to retail customers.  Please see the Regulatory Impact Analysis in the docket to this rulemaking and section XII.H. of the preamble to this final rule.  EPA is not allowing the carryover of CAIR allowances for the reasons explained in section IX.A. of the final rule preamble.
EPA believes that the air quality-assured trading approach we are finalizing is the most cost-effective and practical way to comply with the Court decision in North Carolina to ensure that all emissions in a given state that EPA has identified as significantly contributing to downwind nonattainment or interfering with maintenance are eliminated.  The vast majority of public commenters agree.  In addition, this approach provides the most flexibility for sources while meeting the Clean Air Act requirements and protecting public health.
Organization: Old Dominion Electric Cooperative
Comment: 
Old Dominion Electric Cooperative
ODEC supports allowance trading as a preferred means of achieving a given emissions reduction goal because past programs demonstrated emissions trading reduces overall compliance costs. A primary goal of ODEC is the support of policies that keep electric cooperative consumer rates affordable. ODEC does not support allowance auctions that increase program costs while serving no environmental benefit. Moreover, depending on design, an auction process can increase price and allowance availability uncertainty.  Investment into new generation sources requires certainty. New baseload generation which, in some cases would cost billions of dollars, cannot obtain financing or be guaranteed it will operate if allowances are not available. [EPA-HQ-OAR-2009-0491-2877.1,p.3]
ODEC is concerned that the limited amount of interstate allowance trading allowed in the Transport Rule will promote a monopoly market to companies that own the majority of the power stations within a state. A monopoly market has the potential to drive the prices of allowances up and also may limit the amount of allowances traded. EPA needs to ensure there will be a favorable market for all sources and that there will be adequate allowances available to new sources through the new source set-aside and in the market. It is imperative that allowances be available so newer more efficient power stations can be built. [EPA-HQ-OAR-2009-0491-2877.1,p.3]
In the context of this rulemaking ODEC supports unlimited trading as proposed during the first compliance period beginning in 2012. [EPA-HQ-OAR-2009-0491-2877.1,p.3]
Response: 
Thank you for your comments.  EPA is finalizing an air quality-assured trading remedy which allows interstate trading.  EPA is also finalizing a new unit set aside in each state that makes allowances available to new units.
Organization: Ozone Transport Commission (OTC)
Comment: 
Ozone Transport Commission (OTC)
[[2737.1 p.15]]
Regarding EPA's preferred State Budgets/Limited Trading Option, we recognize the similarity of some elements in that option to the remedy recommended in the September 2, 2009 joint OTC-LADCO State Collaborative letter to EPA. We strongly support the direction EPA is taking to limit interstate trading to mitigate the movement of pollutant emissions across state borders.  We also strongly recommend that EPA combine the State Budgets/Limited Trading Option with the Direct Control Option by including minimum performance standards in a later timeframe, as OTC recommended in the supplemental letter we submitted to EPA on September 10, 2009 (attached as Appendix 6).
Response: 
Thank you for your comment and for your support. EPA is finalizing the air quality-assured trading remedy similar to what we proposed with some changes.  One significant change is that the assurance provisions will begin in 2012 instead of 2014, as proposed.  EPA believes that this approach comports with the court opinion in the North Carolina decision.  For reasons stated in section VII.A of the final preamble, EPA is not finalizing a direct control option in the timeframe of this rule.
Organization: Pennsylvania Department of Environmental Protection
Comment: 
Pennsylvania Department of Environmental Protection
In the TR, EPA proposed a 'preferred approach' in FIPs for reducing SO2 and NOx emissions from EGUs and two 'alternative' approaches for comment. EPA's preferred approach would establish state-specific emission budgets and would allow for intrastate trading, and limited interstate trading with assurance provisions to ensure that the majority of EGUs in each state control their own emissions. The first of EPA's proposed alternatives would use state-specific emissions budgets, but would prohibit interstate trading. The second proposed alternative would use state-specific emission budgets and emissions rate limits.
The DEP supports the 'preferred approach' proposed in the Transport Rule, which limits the degree to which EGU owners and operators can engage in interstate trading of emissions. With the elimination of the existing NOx and SO2 allowance banks and the creation of more stringent 2012 and 2014 NOx budgets and tighter SO2 emission budgets in 2012, the Commonwealth could satisfy its 'good neighbor' obligations under Section 110(a)(2)(D) of the Clean Air Act ('CAA'). By restricting interstate trading and the use of allowances banked under the CATR and the Acid Rain Program, EPA has taken a major step toward complying with the CAA and the Court's holding that each state must eliminate its own share of transported pollution and that EGD owners and operators in all states make actual emission reductions to mitigate transported pollution. By preserving intrastate trading with limited interstate trading, EPA has developed a market-based proposal that would still provide for cost effective emission reductions in a manner consistent with the Court's July 11, 2008, decision. [EPA-HQ-OAR-2009-0491-2660.1, p.3]
Response: 
Thank you for your comments supporting EPA's approach.
Organization: Pfeiff, Mike
Comment: 
Pfeiff, Mike
The Proposed Transport Rule offers a preferred and two alternatives Federal Implementation Plans ('FIPs'). The FIP which is ultimately finalized would establish the rules that determine how the environmental objectives of the Proposed Transport Rule will be achieved. The EPA characterizes its preferred and first alternative FIP as market oriented approaches (i.e. 'cap-and-trade') and its third alternative as a direct control (i.e. 'command-and-control') approach. In reality, because of the highly restrictive features embedded in the first two proposed FIPs, they are both cap-and-trade in name only. [EPA-HQ-OAR-2009-0491-2742.1, p.1]
The EPA solicits comments on a dismal set of alternatives, which are in effect, a false choice since they fail consider alternative and more pragmatic solutions to achieve the desired goals without dismantling existing market oriented programs established by act of Congress. [EPA-HQ-OAR-2009-0491-2742.1, p.1]
Response: 
EPA believes it is finalizing a remedy that addresses the Court's opinion in the North Carolina decision for the reasons cited in section VII.A and VII. J. of the final rule preamble.  Section IX explains the Transport Rule's interaction with other programs the commenter mentions, including CAIR, the Acid Rain Program, and the SIP Call.
Organization: PowerSouth Energy Cooperative
Comment: 
PowerSouth Energy Cooperative
A well-reasoned Cap and Trade regulatory scheme for NOx and SO2 should be developed.  Cap and Trade is a sound, proven regulatory mechanism that provides compliance flexibility for NOx and SO2 emissions.  However, this Proposal's implementation of Cap and Trade is unfair, arbitrary, and constrained.  The Proposal yields complex trading scenarios, including relatively small pools of trading partners, price and availability uncertainties and no way of analyzing state emissions prior to the end of the compliance year.   Consequently, PowerSouth must assume that no trading options are available when assessing compliance options under the Proposal as written.  The Proposal's Cap and Trade mechanism should be re-designed to promote allowance trading certainty and robust market trading.[EPA-HQ-OAR-2009-0491-2693.1,p.2]
Response: 
EPA has finalized a regulatory remedy which it believes comports with the Court's opinion in the North Carolina decision.  Please see Section VII.A. for an explanation of why EPA finalized the air quality-assured trading approach, and Section VII.J. on how the remedy's structure is consistent with the Court decision.
Organization: Public Interest Law Center of Philadelphia
Comment: 
Public Interest Law Center of Philadelphia
The EPA has also proposed two alternative implementation plans for the Transport Rule, each of which includes a more limited emissions trading program than the Agency's preferred approach. [EPA-HQ-OAR-2009-0491-2817.1, pp.2-3]
The alternative implementation approaches are the Intrastate Trading Option, and the Direct Control Option. The Intrastate Trading Option creates a pollution limit for each state and allows trading of emissions allowances only among regulated sources within a state. The second alternative, the Direct Control Option, provides a command and control approach. This implementation strategy would create a specific allowable emissions limit for each power plant, but also allows for limited averaging at the company-level basis within each state. [EPA-HQ-OAR-2009-0491-2817.1, p.3]
The EPA defines "Cap and Trade" as an environmental policy tool that delivers results with a mandatory cap on emissions while proving pollution sources flexibility in how they comply. Cap and trade programs, according to the EPA, seek to reward innovation, efficiency and early action, all while providing strict environmental accountability and without inhibiting economic growth. The Transport Rule's cap and trade programs, as proposed, would allow two options for individual power plants that produce less pollution than their predetermined allotment. These plants could either "bank" their additional allotments for a future occasion when they exceed their emissions quota, or sell the leftover pollution allowance to another plant. [EPA-HQ-OAR-2009-0491-2817.1, p.3]
III. If an Emissions Trading Program Must Be Part of the Transport Rule, the EPA Needs to Strictly Regulate Trading Which Will Negatively Affect EJ Communities.
The EPA suggests that emissions trading under the Transport Rule will offer a viable means to achieve compliance on a national level. By lowering the amount of overall emissions generated by any individual state, the amount of pollutants that travel to "downwind" states will likewise be reduced, and therefore should improve air quality in distant areas. [EPA-HQ-OAR-2009-0491-2817.1, p.4]
Response: 
EPA describes the remedy finalized in the Transport Rule preamble in section VII.A and how it comports with the Court decisions in North Carolina in Section VII.J.  For a discussion of EPA's analysis regarding the rule's impact on environmental justice communities, please see section XII.J.
Organization: Public Utilities Commission of Ohio
Comment: 
Public Utilities Commission of Ohio
We recognize that providing a workable approach for EPA and the States, as well as providing incentives and flexibility to the regulated community, were important overarching goals for EPA when developing the proposed Transport Rule. Even so, we would like to express our concern that the successful SO2 trading model of the Clean Air Act (CAA) has been abandoned in the context of the proposed rule. In our view, this omission will have the effect of penalizing industry generally, as well as ratepayers. One part of a trading scheme that is essential to the creation of a fluid market, one that stands to contain ratepayer costs, is the banking of allowances, including credits for early actions. The CAA has proven that a market-driven environmental program can be successful. SO2 prices during the onset of the regulation (CAA) were predicted to be in the $2,000 per ton range. The model employed was based on the ability to bank and the recognition of early action credits. The result of the use of this model was early implementation and lower-than-expected ratepayer impacts. Accordingly, we wish to encourage EPA to revisit its position on banking and credits for early action. [EPA-HQ-OAR-2009-0491-2855.1 p.16-17]
Response: 
Thank you for your comment.  As explained in section VII.A of the final rule preamble, EPA does permit banking of allowances in the remedy that is being finalized, air quality-assured trading.  In section VII.J, EPA explains how the program structure is consistent with the Court's opinion in the North Carolina decision.  In section IX of the preamble to the final rule, EPA explains why we cannot carryover allowances from other programs.  In section VII.D of the preamble to the final Transport Rule, EPA explains the allowance allocation methodology, which does not penalize units for past reductions.  In fact, cleaner units may get a higher portion of allowances since the allocation methodology EPA is finalizing is control-neutral.  That is, putting on controls does not reduce your allocation.  In this sense, EPA's allocation system does provide some reward for early reductions.
Organization: Rodman, Margaret
Comment: 
Rodman, Margaret
Please do keep the current higher sulfur dioxide and nitrogen oxide limits in place. It is imperative that the EPA not tread backwards on the limits. Please do not allow Intrastate Cap and Trade because it does nothing to reduce mercury, arsenic, nickel, chromium, cadmium, acid gases and dioxin, which is the crux of the matter before us. The technology is available to the energy industries, but their fight against its use is illogical and obscene. Why do they persist in our continued poisoning? [EPA-HQ-OAR-2009-0491-2594, p.2]
[Enclosures can be found on pages 3-13 of this comment.]
Response: 
Thank you for your comment.  EPA is doing everything we can with the authority that we have to regulate pollution sources.  In the case of the Transport Rule, EPA is addressing emissions of sulfur dioxide and nitrogen oxides from power plants that contribute to nonattainment or interfere with maintenance of the National Ambient Air Quality Standards for particulate matter and ozone.  Other rules addressing mercury and other hazardous air pollutants have been proposed or are being developed.
Organization: Sierra Club
Comment: 
Sierra Club
See e.g., Clean Air Ta k Force, Comments on Proposed Federal Implementation Plans To Reduce Interstate Transport of Fine Particulate Matter and Ozone, October 1,20 I.O ('CATF Comment '). The Sierra Club continues to contend that the simplest and most assured mean of nitrogen oxide ('NOx') and sulfur dioxide ('SOx') emissions reductions is through regulations that direct actual emission reductions of Ox and SOx from the sources emitting them via command and control style regulations (demand reduction opportunities, energy efficiency measures and clean energy options abound in the affected industry sectors, as well as available control technologies). However, should the EPA proceed with the trade mechanism in the proposed Transport Rule, it is critical that the emission allowance system, including the issuance, banking and use of allowances, be clearly established at the inception of the system, transparent in operation and enforceable. Moreover, it is imperative that the EPA incorporate into the Rule enhanced emissions reduction requirements and an expanded geographic range of states that are included within the Rule's ambit. [EPA-HQ-OAR-2009-0491-2872.1 p.2]
Response: 
Thank you for your comment.  EPA explains in Section VII.A and Section VII. J. why we chose to finalize the remedy approach for air quality-assured trading and why we think it comports with the Court decision in North Carolina.  Explanations of the allocation methodology may be found in section VII.D.  EPA has used its authority under CAA section 110(a)(2)(D)(i)(I) to develop as robust a rule as feasible to eliminate significant contribution and interference with maintenance from upwind states.
Organization: Sierra Club, New York
Comment: 
Sierra Club, New York
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.168]
As it relates to the proposed training, the three systems that have been outlined, could I suggest that there has to be some kind of incorporation of the local pollution issues, and that an intrastate training program or interstate training program or even some kind of allowable average as referred to in the third case scenario might not necessarily address the local pollution issues as in this situation on East 14th Street. 
Response: 
Thank you for your comments and taking the time to come to the public hearing to express your views.  EPA benefits from public participation in the regulatory process.  In section XII.J of the preamble to the final Transport Rule, EPA describes the analysis we've done for environmental justice and disadvantaged communities.  Section XII.J.2.d of the preamble to the final Transport Rule describes the distribution of health benefits among different populations.  As you point out, local and state governments are often helpful with controlling emissions from specific local sources.
Organization: South Carolina Department of Health and Environmental Control 
Comment: 
South Carolina Department of Health and Environmental Control 
DHEC supports the EPA's conclusion that the State Budgets/Limited Interstate Trading Option is the least costly of the three proposed remedies. DHEC agrees that the two proposed alternatives are more costly and may not provide significant public health and environmental benefits. [EPA-HQ-OAR-2009-0491-2677.1 p.21] 
Market-based environmental solutions depend on regulatory certainty, particularly in the energy sector where large capital investments are made on long timeframes. Regulatory uncertainty leads to reductions in the costs of allowances. For example, the July 2008 vacatur of the CAIR54 led to a precipitous drop in the price of NOX and SO2 allowances.55 The EPA expects litigation following promulgation of the final Transport Rule.56 Such projected litigation may decrease confidence in trading markets, decreasing the cost of allowances. When the cost of allowances drops, facilities can afford to emit more, threatening the important public health and environmental benefits of the program.  [EPA-HQ-OAR-2009-0491-2677.1 p.21]
One way to address this uncertainty is through amending the Clean Air Act. DHEC would support statutory backing for a trading system to control NOX and SO2. Legislative backing for an emissions trading program would provide the certainty that a regulatory approach could not. [EPA-HQ-OAR-2009-0491-2677.1 p.22] 
DHEC supports a legislative solution only if it will set up a simple, understandable trading program. A labyrinthine trading regime as is proposed in the Transport Rule may be too convoluted to offer the flexibility and openness that an emissions trading program should have to attain its intended benefits. The constant revisions needed to address future NAAQS only adds confusion and uncertainty. It would seem that a strategy based on straightforward emissions limits, such as through New Source Performance Standards (NSPS) regulations, would make a reasonable alternative. These regulations have the advantage of consistency and predictability over transient emissions trading programs and would address transport as well as local air quality concerns. [EPA-HQ-OAR-2009-0491-2677.1 p.22] 
Response: 
Thank you for your comments.  Section VII.A of the final rule preamble describes the air quality-assured trading remedy that EPA is finalizing.  Section VII.J explains why we think this remedy comports with the Court's opinion in the North Carolina decision, remanding the CAIR rule to EPA.  Section IV describes EPA's legal authority under the Clean Air Act for the Transport Rule.
Organization: Southern Company
Comment: 
Southern Company
IV. EPA's 'Remedies' Increase Cost with No Demonstrable Benefit Over CAIR
As part of Southern Company's effort to review the Transport Rule, we attempted to recreate EPA's methodology (see Section II above) and then explore alternative approaches. We used the underlying data sets and AQAT procedures to estimate the air quality improvements that would result from each of the Transport Rule's 'preferred' remedies and CAIR Phase I and Phase II emissions levels. To do so we used the emissions for each of the states provided by EPA for 2012 and 2014 under the 'preferred' remedy and created similar state-by-state emissions totals representing CAIR Phases I and II. On September 23, 2010, EPA staff provided by email to Southern Company a spreadsheet that contained projected emissions for the 2012 and 2014 'remedies' for all 38 states considered in the proposed Transport Rule. To compare the air quality benefits achieved by the CAIR budgets versus the Transport Rule budgets using our version of AQAT, it was necessary to supplement the documented budgets available from the CAIR final rule to include states that were not considered in CAIR. For those states, we used the baseline EGU emissions from Table 2-5 of the Significant Contribution Analysis TSD for the relevant year. [EPA-HQ-OAR-2009-0491-2864.1, p. 10]
We used as our criteria the number of monitors that are projected to remain nonattainment or have a maintenance issue after achieving the reductions in each scenario. We assessed the benefit of the emission reductions from all states affected by the proposed Transport Rule (i.e., unlike EPAs method of considering the benefits from emissions reductions from the linked states only). We show that the two programs actually provide similar results (see Tables IV-l and IV-2 below for both 2012 (vs. CAIR Phase I) and 2014 (vs. CAIR Phase II)) [See docket number EPA-HQ-OAR-2009-0491-2864.1, pp. 10-11 for Tables IV-1 and 2.] [EPA-HQ-OAR-2009-0491-2864.1, pp. 10-11]
Note that these similar air quality benefits are obtained from similar emission totals across the affected states and despite significant state by state differences in emissions. See the table IV-3 below for a summary of the emissions comparisons. [See docket number EPA-HQ-OAR-2009-0491-2864.1, p. 11 for Table IV-3] [EPA-HQ-OAR-2009-0491-2864.1, p. 11]
As explained elsewhere, the replacement of CAIR with the Transport Rule will increase our costs, create volatility in the allowance markets, and potentially limit our operational flexibility. However, these results indicate that the replacement would provide essentially no difference in the desired air quality result. [EPA-HQ-OAR-2009-0491-2864.1, p. 11]
XIV. EPA Should Adopt an Interstate Trading Program and Abandon the Alternatives Offered for Comment
EPA's proposed limited interstate trading option provides a limited amount of flexibility and allows more cost-effective compliance options. EPA has historically allowed interstate trading in transport rules and should do so in this case. The intrastate trading option (Alternative 1) is completely unworkable and cumbersome. And EPA has no authority for the direct control option (Alternative 2), which provides for little to no flexibility. As stated, Southern Company strongly supports a flexible interstate trading program. Although EPA's interstate trading option is preferable to either of the two proposed alternatives, as explained in Section V, EPA should evaluate whether less stringent limits on trading can be adopted without compromising the anticipated air quality benefits of the Transport Rule. [EPA-HQ-OAR-2009-0491-2864.1, p. 50] This comment can also be found at section V.D.2, V.D.3. and V.D.4 of this comment summary.]
Response: 
Thank you for your comments.  EPA is finalizing the air quality-assured trading remedy for the reasons explained in section VII.A of the preamble to the final Transport Rule.  In section VII.J of the preamble to the final Transport Rule EPA explains why this remedy structure comports with the Court's opinion in the North Carolina decision.  Section IV also describes in detail the legal authority and environmental basis for the Transport Rule.
Organization: State of Delaware Department of Natural Resources & Environmental Control
Comment: 
State of Delaware Department of Natural Resources & Environmental Control
The establishment or annual and/or seasonal EGU cap-and-trade programs and mass emissions budgets alone is insufficient. In the proposed rule, EPA has proposed to establish a cap-and-trade program for annual S02, annual NOx, and seasonal NOx for the purpose of mitigating the transport of fine particulate matter and ozone. A centerpiece of this proposal is the establishment of cap- and- trade programs: a S02 cap-and-trade program with annual state-by-state S02 mass emissions caps and provisions for unlimited intrastate trading and limited regional trading; a NOx cap-and-trade program with annual state-by-state NOx mass emissions caps and unlimited intrastate and regional trading; and a NOx cap-and-trade program with ozone season NOx mass emissions caps and unlimited intrastate and regional trading. In the preamble to the proposed rule the EPA also indicated that it was soliciting comments on two alternatives. The first alternative is the implementation of a program similar to proposed cap-and-trade program that excludes the regional trading aspects of the proposed program but still permits intrastate trading. The second alternative is a program based on establishing unit-specific emission rate limits based on historic emission rates and installation of controls, while maintaining state-specific mass emission caps similar to the proposed option. This second alternative also requests comment on including averaging for units owned by a common company in that state. EPA-HQ-OAR-2009-0491-2980.1, p.4]
It is Delaware's opinion that establishment of annual and/or seasonal EGU cap-and-trade programs and mass emissions budgets alone is insufficient to mitigate transport and assure the elimination of contribution of upwind states to downwind state noncompliance with short term NAAQS. Delaware believes that instead of allowing a cap and- trade program's market forces to determine which EGUs are controlled, well controlled, or not controlled, all EGUs should be subject to compliance with both short term emission rate limits/performance standards (that are supportive of applicable short term NAAQS) and longer term annual and seasonal mass emissions caps. Short term emission rate limits/performance standards should be established on the basis of technical and economic feasibility, on a unit-by-unit basis, such that the limits/standards are supportive of the short term NAAQS. These short term emission rate limits/performance standards would also be expected to help alleviate episodic air quality excursions. Given this opinion, Delaware is generally supportive of the EPA further developing and implementing its second alternative, as discussed in the preamble to the proposed rule, (i.e., a program based on establishing unit-specific emission rate limits and installation of controls) as the focus of this rulemaking effort. EPA-HQ-OAR-2009-0491-2980.1, p.4]
Response: 
Thank you for your comment.  EPA is finalizing the air quality-assured trading remedy for the reasons explained and section VII.A.  The reasons why EPA decided not to finalize either alternative are also presented in this section.  Section VII.J of the preamble to the final Transport Rule describes why EPA believes the remedy structure comports with the Court's opinion in the North Carolina decision.
Organization: State of Ohio Environmental Protection Agency (Ohio EPA)
Comment: 
State of Ohio Environmental Protection Agency (Ohio EPA)
Ohio EPA agrees with the importance of addressing Clean Air Act Section 11 0(a)(2)(D) regarding the transport of pollutants that may contribute to nonattainment or interfere with maintenance of the national ambient air quality standards (NAAQS). However, none of the options proposed by U.S. EPA provides the type of trading needed to significantly reduce emissions and, at the same time, minimize costs. [EPA-HQ-OAR-2009-0491-2793.2, p. 1]
Given the serious consequences that will face sources not meeting their allocated budgets, it is imperative that U.S. EPA provide a workable approach within the Transport Rule. However, the preferred proposal is deeply flawed and simply not practical. [EPA-HQ-OAR-2009-0491-2793.2, pp. 1-2]
Response: 
Thank you for your comment.  EPA is finalizing the air quality-assured trading remedy for the reasons explained in section VII.A of the preamble to the final Transport Rule.  Section VII. J explains the reasons why EPA believes the remedy approach comports with the Court's opinion in the North Carolina decision.  Section VII.D explains EPA's decision to use a heat input methodology for allowance allocation.  Section VI.D discusses development of the state-specific emission budgets.
Organization: State of Wisconsin, Department of Natural Resources
Comment: 
State of Wisconsin, Department of Natural Resources
Wisconsin believes that EPA should not define 'remedy' in the terms of emission budgets exclusively based on cost-effectiveness of marginal controls. Additional criteria, such as equalization of effort, achievability and air quality impacts are critical components that should be considered. [EPA-HQ-OAR-2009-0491-2829.2, p.1]
Preferred Program Approach - Compliance Approach - While it appears all three programs can efficiently address the meeting of contribution reduction budgets and the associated air quality improvement, the preferred program does provide greater early compliance year flexibility and appears to be supported by Wisconsin utilities. Conversely, an intra-state only trading structure would necessitate out-of-system allowance purchases in the early period for one or more Wisconsin utilities. This occurs because of stranded cross-border generation facilities. For this reason supports a more open trading approach in the early years (2012-2013). [EPA-HQ-OAR-2009-0491-2829.2, p.9]
A potential hybrid program might allow for close proximity trades as well as intra-state trades in a program that doesn't otherwise allow for trading out-of-state. Such a program would impose an added but not insurmountable tracking effort. Utilities would need to petition for specific exclusions to allow for intra-system but cross-state facility trades where a showing can be made for better ambient air quality results in the sensitive areas impacted. A second hybrid would just more strongly constrain the allowed scope of individual system interstate banking by tightening the proposed limits to trades between units controlled by the same operator. [EPA-HQ-OAR-2009-0491-2829.2, p.9] 
Response: 
Thank you for your comment.  Section VI.D of the preamble to the final Transport Rule explains the multi-factor cost and air quality analysis EPA used to establish state-specific budgets.  EPA is finalizing the limited interstate trading remedy for the reasons explained in section VII.A of the preamble to the final Transport Rule.  In this section, EPA also explains the reasons we decided not to finalize alternative options.  Section VII.J of the preamble to the final Transport Rule explains why EPA believes the remedy we are finalizing comports with the Court's opinion in the North Carolina decision.
Organization: Sunbury Generation LP
Comment: 
Sunbury Generation LP
The Proposed Rule identifies three potential allowance trading programs for implementation of the multi-state allowance program. EPA's proposed remedy option, referred to in the Proposed Rule as the 'State Budgets/Limited Trading' option, would allow unlimited intrastate trading and limited interstate trading. The two alternative remedy options identified in the Proposed Rule would allow intrastate trading, and company-wide emissions averaging, respectively, but would prohibit any interstate trading. [EPA-HQ-OAR-2009-0491-3615,p.7]
Based on its analysis of the decision of the D.C. Circuit Court in North Carolina v. EPA, Sunbury does not interpret the Court's decision as prohibiting interstate trading under any circumstances. EPA has previously promulgated, and is currently implementing, successful emission control programs under Title I. For their effectiveness, these programs rely, in large part, on the availability of interstate trading. Consistent with EPA's evaluation of `significant contribution' toward nonattainment in downwind states, and, in particular, with respect to the cost effectiveness component of this analysis, the allowance for interstate trading among affected sources has contributed to the cost effective implementation of these emission reduction regimes. In all regards, these programs have been effective in reducing emissions to levels below the emission caps established by EPA for purposes of preventing significant contribution. [EPA-HQ-OAR-2009-0491-3615,p.7]
In addition to these programs' successfully achieving emissions reductions through the use of such interstate trading systems, the Courts have confirmed the legislation of this interstate trading approach under Title 1. Notably, the D.C. Circuit Court of Appeals affirmatively upheld EPA's right to authorize interstate allowance trading in State of Michigan v. EPA, 213 F.3d 663 (2000). [EPA-HQ-OAR-2009-0491-3615,p.7]
On this basis, EPA could both refine the conservatism inherent in their significant contribution analysis, and still remove the restrictions on interstate trading in the Proposed Rule, while still meeting its objectives for addressing interstate transport. In particular, EPA could authorize an allowance trading program that allows maximum flexibility in interstate trading while providing a backdrop for ensuring that emissions from any individual state do not exceed those rates that actually contribute to nonattainment or interfere with maintenance of NAAQS in downwind states. [EPA-HQ-OAR-2009-0491-3615, p.7]
It is also important for EPA's emission and trading schemes to be reliable and dependable from the perspective of regulated sources. That is, affected sources must be able to rely on allowances secured through interstate trading as their compliance strategy, without being concerned that, because of circumstances outside their control, those allowances may lose their emission value or must be surrendered by the facility because of overall emission rates for the state, Moreover, facilities must be able to develop and implement compliance plans that are based upon certainty regarding the reliability of allowances secured from trading, to the same extent as reliance on any other control option under the Transport Rule. For these reasons, once a facility appropriately and lawfully secures allowances through trading from other sources, such allowances must remain fully available to that source for use in compliance demonstrations under the Transport Rule, without any possibility that such allowances must be surrendered because of their relationship to the overall state budget. [EPA-HQ-OAR-2009-0491-3615, pp.7-8]
Based on the foregoing, Sunbury believes that the limited use of interstate trading proposed by EPA under the Proposed Rule is unduly stringent, unsupported by any applicable statutory or regulatory standard, and unnecessary to achieve necessary emissions reductions. Sunbury supports the promulgation of a final rule that maximizes the use of interstate trading for affected EGUs (regardless of the state in which such sources are located). The three proposed allowance trading programs identified in the Proposed Rule fail to meet this standard. [EPA-HQ-OAR-2009-0491-3615,p.8]
Response: 
Thank you for your comments.  EPA is finalizing the air quality-assured trading remedy for the Transport Rule for the reasons cited in section VII of the preamble to the final Transport Rule.  Section VII.J. explains how we think this remedy is consistent with the Court's opinion in the North Carolina decision.  Section IV of the preamble to the final Transport Rule explains EPA's legal authority and environmental basis for the rule.  EPA discusses its decision not to carry-over CAIR allowances in the Transport Rule program in section IX. Based on these and other sections of the preamble, EPA believes we have finalized a rule that addresses the Court's concerns and still affords sources the flexibility to comply with a market-based program that delivers the reductions necessary to meet the statutory requirements under section 110(a)(2)(D)(i)(I) of the Clean Air Act.
Organization: Tampa Electric Company
Comment: 
Tampa Electric Company
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.55.]
But we request EPA give strong consideration to employing allocation methods that avoid disenfranchising early action in the future.
Response: 
Thank you for your comment.  EPA is finalizing a heat input methodology for allowance allocation that we believe to be fuel- and control-neutral, as explained in section VI. D of the preamble to the final Transport Rule.
Organization: Tennessee Department of Environment and Conservation, Division of Air Pollution Control
National Rural Electric Cooperative Association (NRECA)
Alabama Department of Environmental Management
Indiana Department of Environmental Management 
Edison Electric Institute (EEI)
Illinois Environmental Protection Agency
West Virginia Department of Environmental Protection
we energies
Massachusetts Department of Environmental Protection
Oklahoma Department of Environmental Quality
Virginia Independent Power Producers
PSEG Services Corporation
Edison Mission Energy (EME)
Louisiana Energy and Power Authority (LEPA)
Birchwood Power Partners, L.P.
Large Public Power Council (LPPC)
Santee Cooper
Northwest Indiana Forum
Adirondack Council
Ohio Coal Association
International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers and Helpers (AFL-CIO Boilermakers Union)
American Municipal Power, Inc. (AMP)
Sierra Club, Georgia Chapter
Comment: 
Adirondack Council
Further, we support EPA's proposal to allow intrastate trading and very limited interstate trading. [EPA-HQ-OAR-2009-0491-2848.1, p.2]
Alabama Department of Environmental Management
EPA's preferred approach is to allow unlimited intrastate trading and limited interstate trading among power plants. The preferred approach is to assure that each state will meet its pollution control obligations with assurance provisions to restrict EGU emissions within each state to the state's budget plus a variability factor. EPA also proposed two additional alternatives. ADEM supports an option that provides the maximum possible flexibility in intrastate and interstate trading to the extent allowed by the Clean Air Act (CAA) and the court ruling. [EPA-HQ-OAR-2009-0491-2616, p.2]
American Municipal Power, Inc. (AMP)
Interstate Trading Should Be Supported
AMP has been a long-term proponent of pollutant trading concepts and encourages continuation of market-based approaches. As such, AMP supports options that allows for both intrastate and interstate allowance trading. Trading gives operators, especially smaller generators and municipal power organizations, needed flexibility and allows for more cost-effective compliance. [EPA-HQ-OAR-2009-0491-2678.1, p.3]
Birchwood Power Partners, L.P.
Birchwood Power supports the proposed remedy of using state-specific control budgets and allowing for intrastate and limited interstate trading of emission allowances. Birchwood Power encourages EPA to adopt the broadest and most flexible trading program that can be implemented in accordance with the principles articulated by the court in North Carolina v. EPA Birchwood Power does not support EPA's proposed alternative of a 'direct control' program that does not allow for emissions trading. [EPA-HQ-OAR-2009-0491-2706.1, p.2]
Edison Electric Institute (EEI)
EEI supports EPA's preferred approach, the "State Budget/Limited Trading" remedy   
EEI supports, among EPA's stated options, the Agency's preferred approach that would allow limited interstate trading and unlimited intrastate trading. EPA's preferred approach will provide some flexibility and therefore permit more cost-effective compliance. The alternative approaches discussed by EPA in the rulemaking would provide much less flexibility and unnecessarily increase costs of emission reductions. [EPA-HQ-OAR-2009-0491-2697.1, p.16]
Edison Mission Energy (EME)
Cap-and-trade offers four important benefits over traditional command-and-control programs. First, cap-and-trade mechanisms provide for the efficient deployment of capital to achieve emission reductions. Rather than imposing specific control technologies upon EGUs in a command-and-control regime without thought to efficiencies, cap-and-trade programs allow EGUs to take into account individual factors in determining how best and most cost-effectively to achieve the greatest emission reductions. [EPA-HQ-OAR-2009-0491-2707.1, p.5]
Second, cap-and-trade mechanisms incent emission reductions; that is they encourage affected sources to develop innovative pollution control technology and strategies in the hopes of freeing up additional allowances for sale. They also reduce the risks associated with such innovation because sources that invest in untried reduction methods do not risk being in violation of the rule, even if the new technology fails, because they have an ability to purchase allowances from other market participants. Third, cap-and-trade systems provide a safety net that enables sources to cover for unexpected emissions by purchasing allowances from other parties with a surplus. Fourth, a cap-and-trade mechanism gives affected sources the incentive to operate as cleanly as possible to enable new sources to be brought online without causing an exceedance of the cap. In addition to these benefits, EPA has recognized that cap-and-trade programs achieve significant environmental benefits at a far lower (and more reasonable) cost than under a command-and-control regime. 8 One ancillary benefit to reduced cost is an increase in compliance (e.g., EPA has reported virtually total compliance with Title IV). [EPA-HQ-OAR-2009-0491-2707.1, p.5][EPA-HQ-OAR-2009-0491-2707.1, pp.5-6]

8 See id. (citing two advantages of market-based systems, "lower cost of compliance for individual sources and the regulated community as a whole" and "flexibility for the regulated community . . . .") 
EPA's experience with Title IV's Acid Rain Trading suggests that it achieved significant SO2 emissions reductions at substantially reduced costs relative to a command and control approach that would have required a fixed emission rate. See EPA, Acid Rain Program: 2009 Progress Reports-2009 Emission, Compliance, and Market Analyses (Sept. 2010), at http://www.epa.gov/airmarkt/progress/ARP09_2.html ("2009 Progress Report"). For example, EPA estimates that the Title IV program achieved reduction of 10.2 million tons (41% lower than 1980) at two-thirds the cost of achieving the same reductions under a command-and-control system  -  a 33% savings. See e.g., 69 Fed. Reg. at 4702.
Illinois Environmental Protection Agency
Of the options provided, Illinois EPA supports U.S. EPA's proposed preferred approach that provides the most flexibility for intrastate and interstate trading. We believe that U.S. EPA's proposed preferred approach more thoughtfully balances the conflicting goals of reducing compliance costs through trading and reducing overwhelming transport from culpable states. U.S. EPA's approach provides assurance that each state achieves emissions reductions within its borders, while allowing a limited ability to balance costs between affected sources. [EPA-HQ-OAR-2009-0491-2781.1 p.2]
Indiana Department of Environmental Management 
Of the three alternatives outlined by U.S. EPA in the proposed rule, the alternative that provides for intrastate and limited interstate trading is preferred to the other proposed alternatives. [EPA-HQ-OAR-2009-0491-2645.1, p.2]
International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers and Helpers (AFL-CIO Boilermakers Union)
In addition, the Boilermakers Union supports EPA's decision not to propose a purely intrastate emissions trading program or a 'command-and-control' system of source-specific emission controls. As EPA's own analysis in Table V.E-l of the preamble illustrates, both alternative remedies would be substantially more costly than the proposed Transport Rule while yielding equivalent environmental results. This result is to be expected, because both options forego the benefits in efficiency that can be derived from interstate trading of allowances. The Boilermakers Union is very concerned that the additional costs associated with complying with these alternative remedies could force plant retirements or harm investment in the power sector, to the detriment of our membership. Given that the alternative remedies have no discernible policy advantages, we urge EPA to retain the basic structure of a limited interstate trading remedy in the final rule. [EPA-HQ-OAR-2009-0491-2672.1, p.3]
Large Public Power Council (LPPC)
LPPC believes EPA correctly rejected the two alternative remedies described in the preamble to the proposed Transport Rule. The State Budgets/Intrastate Trading option has no discernible environmental advantage over the proposed Transport Rule, yet would carry a substantially higher compliance cost because it would completely foreclose the possibility of trading among states. States that face relatively higher abatement costs would, under the Intrastate Trading option, have no ability to mitigate those costs by purchasing allowances from states that are able to reduce emissions more cost effectively. In addition, the Intrastate Trading option does not create variability limits for each state (presumably because without interstate trading, there would be no way to ensure that the states' individual usage of variability limits offset each other). The lack of variability limits would leave states with precious little flexibility to accommodate unanticipated changes in demand for electricity or other developments that influence emissions; furthermore, LPPC is concerned that reliability of service in certain states could be impaired if some allowance for variability is not made. Because LPPC believes that the Intrastate Trading option has serious flaws and features no policy advantages relative to a system of limited interstate trading, LPPC supports EPA's decision not to propose the Intrastate Trading option. [EPA-HQ-OAR-2009-0491-2667.1, p.18]
EPA also correctly decided not to propose the "Direct Control" option described in the preamble. Except for the limited use of "averaging" emission rates among EGUs under common ownership, the Direct Control option would completely forfeit the efficiency benefits of emissions trading among EGUs. Moreover, the combination of unit-specific emission rate limits and annual emissions limitations would make compliance extremely complex for EGUs. LPPC was unsurprised to see that the Direct Control option was estimated to be the most costly of the three "remedy" proposals evaluated by EPA. 54 Given the lack of compensating advantages associated with this option, LPPC strongly supports EPA's decision to instead propose the State Budgets/Limited Trading option. [EPA-HQ-OAR-2009-0491-2667.1, p.18]
Louisiana Energy and Power Authority (LEPA)
LEPA OPPOSES BOTH ALTERNATIVE REMEDY OPTIONS TO THE PROPOSED TRANSPORT RULE BECAUSE THOSE ALTERNATIVES FURTHER RESTRICT OR ELIMINATE ALLOWANCE TRADING. [EPA-HQ-OAR-2009-0491-2700.1, p.17]
LEPA is already at a serious disadvantage under the proposed Transport Rule because its critical must-run units receive no emission allowances. Trading increases the opportunity for LEPA to obtain the allowances necessary to permit its critical units to run. LEPA therefore strenuously opposes any alternative that would further restrict trading. The first alternative remedy option would allow intrastate trading but would prohibit interstate trading. The second alternative remedy option would use emission rate limits with no trading. Both of those alternative remedy options would restrict trading more than the proposed Transport Rule, thus LEPA opposes both of those alternative remedy options. [EPA-HQ-OAR-2009-0491-2700.1, p.17]
Massachusetts Department of Environmental Protection
We support EPA's preferred remedy to address emissions from states that significantly contribute to air pollution in downwind states by proposing annual and seasonal cap and trade programs. Cap and trade programs allow for cost-effective reductions and have been successfully implemented under the Acid Rain Program and the NOx Budget and Clean Ail' Interstate Rule (CAIR) programs. We commend EPA for proposing to allow only limited interstate trading, thereby taking a major step towards addressing the D.C. Circuit Court's decision and the Clean Ail' Act requirement that each state must reduce its share of transported pollution. We also support the proposed framework of separate annual NOx and annual S02 cap and trade programs to address PM 2.5 issues and a seasonal NOx program to address ozone levels during the ozone season.  [EPA-HQ-OAR-2009-0491-2787.2 p.1]
National Rural Electric Cooperative Association (NRECA)
In the context of this rulemaking, NRECA supports unlimited trading as proposed during the first compliance period beginning in 2012. NRECA also supports the proposal's remedy option and the intrastate trading option in the second compliance period to the extent that both allow allowance trading, because program costs would be reduced without jeopardizing emission reduction goals. [EPA-HQ-OAR-2009-0491-2723.1, p.4]
Northwest Indiana Forum
As a membership organization, we must balance the diverse corporate positions on environmental matters. A concern regarding the limitations to emissions trading has been raised by multiple members. Members are in agreement that emissions trading should not be limited. [EPA-HQ-OAR-2009-0491-3650 p.2]
Ohio Coal Association
:: The Transport Rule should maintain fair and robust allowance trading provisions in order to provide flexibility to affected sources. [EPA-HQ-OAR-2009-0491-2743.1, p.2]
Oklahoma Department of Environmental Quality
While ODEQ agrees with the efforts being made to eliminate upwind states' impacts on the air quality in downwind states, we also believe that the modeling should not be afforded quite so much weight and that the states should have been given much more time to review the copious amounts of information associated with this rule as well as the rule itself. That being stated, Oklahoma would also like to express its preference for EPA's "preferred method" of implementation, giving each state a budget and allowing limited interstate trading. Not only does the preferred option offer the most benefits from a cost standpoint, but it also offers the most flexibility. With the promulgation of several new Federal rules in the near future, electric utilities will benefit from having as many options as practicable to allow them to achieve compliance at the lowest cost and with the greatest likelihood of success.
PSEG Services Corporation
PSEG does not support Alternative 1 or Alternative 2 outlined in the proposed rule. The first alternative would use state-specific control budgets and allow intrastate trading of emissions allowances allocated to EGUs, but it would not allow interstate trading. The second alternative would be a direct command and control program in combination with state-specific control budgets and also would prohibit trading. Both options would be inefficient, more costly, and would unnecessarily limit the flexibility of interstate trading available under the preferred option. While PSEG has consistently supported market-based programs because they can result in the most cost effective reductions, we recognize that the D.C. Circuit court's opinion constrains EPA's authority to allow unlimited interstate trading. The preferred approach is structured to allow trading while also addressing the court's concerns. We would strongly oppose any alternative that prohibits all interstate trading. [EPA-HQ-Oar-2009-0491-2627.1, p.10]
Santee Cooper
EPA's own discussion in the preamble makes clear that the State Budgets/Intrastate Trading option would have no environmental advantages relative to limited interstate trading, but would cost considerably more. According to the tables in Section V.E of the preamble, the Intrastate Trading option would achieve marginally greater reductions in SO2 emissions in 2012 than the proposed Transport Rule (a difference of 4%), slightly fewer reductions in SO2 emissions in 2014 (a difference of 2%), and virtually identical reductions in annual and ozone season NOx emissions in2012. Yet the cost of the Intrastate Trading option would be 13.5% greater than the proposed Transport Rule in 2012, and 10% greater in 2020 and 2025. The unfavorable performance of the Intrastate Trading option is unsurprising, given that this option would prevent states that face relatively high abatement costs from purchasing allowances from states that are able to reduce emissions more cost-effectively. Incidentally, prohibiting interstate trading would also reduce the ability of states to accommodate natural fluctuations in demand for electricity (and resulting air pollution) - raising reliability concerns for publicly-owned utilities such as Santee Cooper, which are obligated to provide service to retail customers. [EPA-HQ-OAR-2009-0491-2820.1, p.4]
Santee Cooper also supports EPA's decision not to propose 'direct control' of EGU emissions. According to Table V.E-l, the costs of the Direct Control option relative to the proposed Transport Rule are even higher than the Intrastate Trading option, even though the Direct Control option would yield 8% less SO2 emission reductions by 2012. More critically, the Direct Control option appears fundamentally unworkable to Santee Cooper, given its unwieldy combination of unit-specific emission rate limits and annual emissions limitations. For these reasons, the Direct Control option is Santee Cooper's least preferred remedy of the three alternatives considered in the Transport Rule. [EPA-HQ-OAR-2009-0491-2820.1, pp.4-5]
Sierra Club, Georgia Chapter
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.98.]
We do support the limits of the trading of pollution allowances.
Tennessee Department of Environment and Conservation, Division of Air Pollution Control
Comment on In-State-Only Trading Option: We agree with EPA that limited interstate trading is preferable to in-State-only trading for the reasons stated in the proposed rule. [EPA-HQ-OAR-2009-0491-0553.1, p.4]
Comment on Trading Ratios: EPA requests comment on the use of trading ratios to limit interstate trading. As EPA indicated in the proposed rule, development of trading is likely to be time consuming and fraught with legal uncertainty. Use of trading ratios is a good idea in theory, but the practical problems are likely to be insurmountable. [EPA-HQ-OAR-2009-0491-0553.1, p.4]
Virginia Independent Power Producers
Both Interstate and intrastate Trading Should Be Allowed and Encouraged by the Transport Rule.
The free trading of emissions allocations is a proven and effective market-based mechanism that benefits the environment generally and regional air quality in particular, while minimizing to the extent possible the economic harm caused consumers by higher energy prices. Unrestricted free trading of emissions allocations has been historically proven to provide the maximum environmental benefit at the lowest societal cost, by providing financial incentives to install newer, more efficient environmental controls at facilities with the greatest need and obligation to reduce air emissions. This mechanism, which matches financial resources with facilities having the greatest environmental improvement potential has worked exceedingly well in the past greatly to the public benefit. [EPA-HQ-OAR-2009-0491-2640.1, p.2]
To accomplish the important public policy goals of improved air quality and reduced adverse economic impacts, the transport rule should be structured to permit and encourage the free trading of emissions allocations among Electric Generating Units (EGUs) located in the 31 affected States and the District of Columbia to the maximum extent possible. [EPA-HQ-OAR-2009-0491-2640.1, p.2]
The design of the Transport Rule should avoid a strict 'command and control' structure and should instead allow and encourage operational and regulatory flexibility. [EPA-HQ-OAR-2009-0491-2640.1, p.3]
The large number of EGUs operating in the 31 states and District of Columbia transport region vary greatly in their size, fuel types, operating characteristics and customer obligations. Successful operation of each EGU to attain maximum environmental benefit and minimal financial disruption cannot be achieved with a 'one size fits all' regulatory regime. Again, a market-based approach that provides operational and regulatory flexibility - while achieving overall emissions reductions goals - is the better approach as it provides financial and regulatory incentives to improve operations and reduce emissions. The public interest would be better served 'with a less rigid, more flexible approach. [EPA-HQ-OAR-2009-0491-2640.1, p.3]
we energies
Overall, not withstanding this fundamental question, we generally agree with the format of EPA's preferred approach, which allows limited interstate trading and unlimited intrastate trading. This is especially important to We Energies since our generation system is located in two contiguous states. Having the opportunity for intra- and interstate trading provides compliance flexibility and economic savings for our customers. [EPA-HQ-OAR-2009-0491-2629.1, pp.2-3]
West Virginia Department of Environmental Protection
[[2790.1 p.1]]
Under the Acid Rain Program, the NOx Budget Trading Program and the CAIR, West Virginia electric generating sources have made significant reductions in S02 and NOx emissions, thereby helping to reduce or eliminate nonattainment problems related to interstate transport. WVDAQ generally supports the provisions limiting interstate trading in the proposed Transport Rule. The limited trading provisions will discourage the practice of sources, in some states, of purchasing allowances to cover uncontrolled emissions (renting compliance), rather than obtaining emission reductions from the installation of scrubbers and catalytic reduction devices. Because of the reduction in flexibility for applicable sources, WVDAQ does not support the intrastate trading or direct control alternatives in the proposed Transport Rule.
Response: 
EPA thanks you for your comments.  As discussed in the proposal, EPA has a long history of successful implementation of national and regional trading programs.  EPA has put forth a rule that we believe comports with the 2008 Court decisions while providing compliance flexibility for sources to ensure cost-effective state-specific reductions that eliminate downwind impacts.
Organization: Virginia Department of Environmental Quality (VDEQ)
Comment: 
Virginia Department of Environmental Quality (VDEQ)
Trading programs provide regulatory flexibility while protecting the environment, and VDEQ supports the concept of trading. Regulations requiring facilities to participate in trading programs, however, do not provide definitive emissions limitations in future years at individual units. This fact causes the planning process, which is heavily dependent on emissions reductions within nonattainment and maintenance areas, to rely on a variety of tools to 'guess' where units might be retired or modified to use different fuels; where controls might be installed; and what types of controls might be used. These tools can not only be very expensive to use, they also tend to be inaccurate. [EPA-HQ-OAR-2009-0491-2595.1, p.2]
 Rather than guessing how a trading program will affect future year emissions, VDEQ suggests that EPA include in the Transport Rule requirements for owners of subject units to share their plans for compliance with States where units are located, similar to the requirements of the North Carolina Clean Smokestacks Act. The information required to be provided; over a reasonable planning horizon, should be best available projections of where controls are going, what type of controls are being expected, which units will be shut down, and which units may be subject to a fuel switch. This information would be used to better inform the planning process for current and future National Ambient Air Quality Standards (NAAQS) rather than relying on inaccurate assumptions from computer models. The planning process is too important, and the penalties for failing to improve air quality or otherwise comply with Reasonable Further Progress, Rate of Progress, Reasonable Available Control Technology, attainment year caps, mobile vehicle emissions budgets, Section 110(a)(2)(D) and other requirements are too severe, to simply guess at where major control devices mayor may not be installed, where units may be shut down, and where units may use different fuels. Requiring the communication of known plans would greatly improve the planning process. [EPA-HQ-OAR-2009-0491-2595.1, p.2]
The draft Transport Rule offered three options for comment. VDEQ supports the use of a limited trading scheme, as proposed in the preferred option in the draft regulation. The draft regulation will achieve significant reductions while preserving the flexibility and least cost alternative that are the hallmarks of a trading program. [EPA-HQ-OAR-2009-0491-2595.1, p.1]
Response: 
Thank you for your comments.  Section IV of the preamble to the final Transport Rule discusses EPA's authority and environmental basis for the rule.  Section V describes the updated emission inventories and modeling platforms used for analysis in the final Transport Rule.  Section VIIA. explains EPA's reasons for finalizing the air quality-assured trading remedy and section VII.J describes the reasons EPA believes the program structure comports with the Court's opinion in the North Carolina decision.
Organization: Western Farmers Electric Cooperative (WFEC)
Comment: 
Western Farmers Electric Cooperative (WFEC)
The proposal from EPA is complex, utilizes several atmospheric and economic models and extensive electric utility operational and emission control information to produce four separate electric utility and limited trading programs.  Utilizing this extensive modeling, the final rule dictates essentially permanent unit compliance obligations through limiting unit emissions allowances, while providing only extremely limited opportunities for any allowance reconciliation and no criteria for doing so. [EPA-HQ-OAR-2009-0491-2642.1, p.2] 
Response: 
Thank you for your comment.  As with EPA's other cap and trade programs (first started in 1995), a unit must hold one allowance, for each ton of controlled pollutant emitted, in its account at the end of the compliance period.  Under the Transport Rule, EPA has developed state-specific budgets that address the Clean Air Act requirements in section 110(a)(2)(D)(i)(I) to eliminate a state's significant contribution and interference with maintenance to another state's air quality.  These budgets are allocated among the covered units in the state under the Federal Implementation Plans in the final Transport Rule and as described in section VII.D.  Section VI.D describes how the state budgets were developed.  Section VII of the preamble to the final Transport Rule describes the trading structure of the programs.  In order to make the final FIP trading program rules as simple and consistent as possible, EPA designed them so that the final rules (like the proposed rules) for each of the trading programs are parallel in structure and contain the same basic elements. The key elements of the final Transport Rule trading program rules are summarized in Section XI of the preamble to the final Transport Rule.
Organization: Wolverine Power Supply Cooperative
Comment: 
Wolverine Power Supply Cooperative
We are supportive of a "cap and trade" approach as the remedy to the interstate transport contribution of Electric Utility Generators (EGUs) to fine particulate and ozone nonattainment in downwind states. We have guarded support for EPA's preferred remedy, that is "limited interstate trading," to maximize flexibility and minimize control costs, but we believe that the proposed rule is severely flawed as described in the following comments. [EPA-HQ-OAR-2009-0491-2825.1 p.2]
Response: 
Thank you for your comment.  EPA is finalizing the air quality-assured trading remedy for the reasons explained in section VII.A of the preamble to the final Transport Rule.  In section VII.J EPA explains why we believe the program structure comports with the Court's opinion in the North Carolina decision.

V.D.2. State Budgets/Limited Trading Proposed Remedy

Organization: 8-Hour Ozone State Implementation Plan (SIP) Coalition
American Petroleum Institute (API)
American Chemistry Council
Adirondack Council
American Lung Association of the Upper Midwest
American Lung Association of the Mid Atlantic
Comment: 
8-Hour Ozone State Implementation Plan (SIP) Coalition
The Coalition also supports the use of a trading program within the rule to facilitate the most cost-effective reductions possible.  The Coalition supports the option EPA has proposed for the Federal Implementation Plans (FIPs), which would use state-specific emissions budgets and allow for intrastate and limited interstate trading. This approach would assure environmental results while providing some limited flexibility to covered sources. The approach would also facilitate the transition from CAIR to the Transport Rule for implementing agencies and covered sources. [EPA-HQ-OAR-2009-0491-2736.1, p. 2]
Adirondack Council
We applaud EPA's efforts to limit interstate trading as well. Since 2000, the Adirondack Council has advocated for action to limit New York's unused allowances from being sold to upwind utilities and sent back to us in the form of acid rain. By limiting interstate trading and giving each state its own budget for pollution reductions based on its contribution to nonattainment in downwind areas, EPA has adequately addressed New York's concern which has been a problem for over a decade. [EPA-HQ-OAR-2009-0491-2848.1, p.2]
[These comments were also submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.63.]

[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.63-66.]
In 2000, the Adirondack Council distributed the chart on the screen that depicts data from a GAO report on which states were buying and selling SO2 allowances. Green states like New York were selling extra allowances, while red states like Ohio and Indiana were purchasers of the excess credits from other states.
In 2000, we persuaded the New York State Legislature to pass a law that created a financial disincentive for cleaner New York utilities when they sold their leftover SO2 allowances to upwind states.
State Senator Carl Marcellino, Environmental Conservation Committee Chair at the time had a memorable quote when discussing this legislation. The state law was eventually over-turned, but it demonstrated a need to do something about upwind states.
By limiting interstate trading and giving each state its own budget for pollution reductions based on its contribution to nonattainment in downwind areas, EPA has adequately addressed New York's concern which has been a problem for over a decade.
American Chemistry Council
III. Approach to Emissions Control
Of the three alternatives presented in this proposal, ACC supports EPA's preferred approach as providing the most flexibility for covered sources. By setting a pollution budget for the impacted states for NOx and SO2, EPA is allowing for some interstate trading while also ensuring that the states meet emission limits. Allowing for maximum flexibility will result in sources being able to achieve the required emission reductions in the most cost-effective way. [EPA-HQ-OAR-2009-0491-2716.1, p.4]
American Lung Association of the Mid Atlantic
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.32.]
We support the essence  of EPAs preferred approach for setting  pollution budgets
American Lung Association of the Upper Midwest
[These comments were submitted as testimony at the Chicago, Illinois hearing.  See Docket Number EPA-HQ-OAR-0491-1746, p.14.]
I would recommended U.S. EPA's  preferred approach of setting a pollution budget  for each of the states, which allows for limited interstate trading, but assures that each state  meet its pollution control technology.
American Petroleum Institute (API)
API also supports the use of a trading program within the rule to facilitate the most cost-effective reductions possible. API supports the option EPA has proposed for the Federal Implementation Plans (FIPs), which would use state-specific emissions budgets and allow for intrastate and limited interstate trading. This approach would assure environmental results while providing some limited flexibility to covered sources. The approach would also facilitate the transition from CAIR to the Transport Rule for implementing agencies and covered sources. [EPA-HQ-OAR-2009-0491-2649.1, p. 2]
Response: 
Thank you for your comments and for your support.
Organization: Adirondack Mountain Club
Comment: 
Adirondack Mountain Club
EPA's preferred alternative, which would allow for interstate trading among power plants, does not address the New York's problem with pollution hotspots. EPA acknowledges in this rulemaking that particular plants have very significant affects on very specific downwind regions. The preferred alternative, along with the first alternative to allow for unlimited trading within States and no interstate trading, do not address the regional pollution problems associated with upwind polluters. [EPA-HQ-OAR-2009-0491-2761, p.2]
While the cap and trade system for NOx and SO2 may indeed achieve reductions on a national scale, it may also provide no relief at all in locations where pollution credits are used in lieu of real controls. New York's Adirondacks and Catskills are downwind of 70 large coal-burning plants in the Midwest. These plants burn coal without scrubbers or other pollution controls and produce as much as 80 to 90 percent of the air pollutants impacting the Northeast. A strong state emissions budget must be maintained and EPA must not allow trading to increase a State's budget. More importantly, trading restrictions must be put in place for specific regions where strong linkages, as evidenced in the proposed rule, cause a significant increase in downwind air pollution and restrict counties' abilities to achieve attainment and maintenance. [EPA-HQ-OAR-2009-0491-2761, p.3]
Response: 
Thank you for your comment.  In the preamble to the final Transport Rule, EPA is finalizing the air quality-assured trading program for the reasons discussed in section VII.  Section VII.J. describes why EPA believes this remedy comports with the Court's opinion in the North Carolina decision.  EPA also describes in section IV its legal authority and the environmental basis for this rulemaking.  In addition, EPA discusses in section XII.J the environmental justice analyses we have done and the results. 
Organization: Attorney General of North Carolina
Comment: 
Attorney General of North Carolina
[[2685.1 p.6]]
a. Lawfulness of Trading In North Carolina, the D.C. Circuit discussed the lawfulness of the interstate trading of pollution allowances under §110(a)(2)(D)(i)(I):
Section 110(a)(2)(D)(i)(I) prohibits sources "within the State" from "contribut[ing] significantly to nonattainment in . . . any other State . . ." (emphasis added). Yet under CAIR, sources in Alabama, which contribute to nonattainment of PM2.5 NAAQS in Davidson County, North Carolina, would not need to reduce their emissions at all. See CAIR, 70 Fed. Reg. at 25,247 tbl. VI-8. Theoretically, sources in Alabama could purchase enough NOX and SO2 allowances to cover all their current emissions, resulting in no change in Alabama's contribution to Davidson County, North Carolina's nonattainment. CAIR only assures that the entire region's significant contribution will be eliminated. It is possible that CAIR would achieve section 110(a)(2)(D)(i)(I)'s goals. EPA's modeling shows that sources contributing to North Carolina's nonattainment areas will at least reduce their emissions even after opting into CAIR's trading programs. 71 Fed. Reg. at 25,344-45.
531 F.3d at 907. The Court then concluded that although EPA need not measure each State's "significant contribution" solely according to the State's sources' impact on a downwind area, once EPA determines a State's "significant contribution," EPA "must actually require elimination of emissions from sources that contribute significantly and interfere with maintenance in downwind nonattainment areas." Id. at 908; see also 75 Fed. Reg. at 45,303/1-3.
EPA proposes to meet this requirement by calculating each State's budget, on a state-by-state basis and not on a regional basis. EPA proposes to allow interstate trading so long as the State's total emissions do not exceed the budget. However, due to the "unavoidable variability in baseline emissions" that "result[s] from the inherent variability in power plant operations," 75 Fed. Reg. at 45,292/1, EPA proposes that each State's sources may, during any given year, exceed the State's budget by a State-specific amount that would be established in the FIP.
EPA's decision to propose State budgets calculated on a state-by-state basis and to limit emissions to those budgets is sound under North Carolina. Further, as a legal matter, North Carolina does not disagree in principle with EPA's attempts to address utility sector emissions variability by allowing limited interstate trading. However, North Carolina disagrees with the means EPA has chosen. Under EPA's proposed remedy, State X's relevant emissions may have been relatively low during the base year and State Y's may have been high. Theoretically, EPA's variability construct would allow for sources in State X to buy allowances from sources in State Y during a normal year in order to balance this variability. This presents two conceptual problems. First, it punishes sources in State X and provides a windfall for sources in State Y based solely on the variability of electricity production during the single year EPA chose as the base year (2005). That is, had EPA chosen 2006 instead of 2005 as the base year, sources in State X may have profited at the expense of sources in State Y instead of the other way around.
Second, and more significantly from an air quality perspective, sources in State Y could very well emit up to the maximum of their variability allowance for every one-year and three-year period, despite the fact that sources in State Y were already at the high end of their variability in the base year and therefore their budget  -  without the variability limits  -  already reflects the needed variability. Put another way, although the variability limits may have been calculated in a defensible manner  -  these Comments take no position on that technical issue  -  once the limits are allowed, there is no legal assurance that the variability margins will be used by market participants to account for variability. The variability limits are simply a trading budget overage and are forever unmoored from their intended purpose. For example, if sources in State X choose or are required by state law, state rule or a consent decree to reduce emissions to a level below that State's budget, the remaining allowances may be purchased year after year by sources in State Y not because the sources in State Y need the allowances to account for variability but only because they desire them for economic reasons to avoid having to reduce emissions, i.e., to avoid eliminating their "significant contribution" from  "within the State." 531 F.3d at 907. As such, the variability limits, although stemming from a defensible theory, are themselves not consistent with the Clean Air Act.
Response: 
Thank you for your comments.  Please see section V.B for a discussion on the base year.  Please see sections VI.E and F for a discussion on the variability limits and assurance, and section VII.E for a discussion on the assurance provisions.  Please see section IV of the preamble to the final Transport Rule for a discussion of EPA's legal authority and the environmental basis of this rulemaking.  Please see section VII J of the preamble to the final Transport Rule for a discussion of how the remedy EPA is finalizing is consistent with the Court's opinion in the North Carolina decision.  Based on these and other sections of the preamble, EPA believes we have finalized a rule that addresses the Court's concerns and meets the statutory requirements under section 110(a)(2)(D)(i)(I) of the Clean Air Act.
Organization: Calpine Corporation
Comment: 
Calpine Corporation
The limitations on interstate trading in the proposed rulemaking, while potentially creating issues regarding market liquidity, responds to the D.C. Circuit Court of Appeals (Court) decision that unlimited interstate trading cannot guarantee the necessary reductions in all the upwind states. Further, creating new allowance currencies solves the problem of directly affecting the Title IV SO2 program. With the exception of the unit specific allocation method, Calpine supports EPA's preferred option in the proposed rulemaking. [EPA-HQ-OAR-2009-0491-3614, p.2]
Response: 
Please see section VII of the Preamble regarding the allocation method used in the final rule.
Organization: City of Tallahassee
Comment: 
City of Tallahassee
Preferred Options for Implementing the Transport Rule.
EPA has asked for comments on the three options for implementing the Transport Rule reductions, among which it has its preferred choice.  The City prefers any option which allows specific emission limits that are technology driven and allows enough flexibility for a utility to make timely, cost-conscious, environmentally beneficial decisions that will not overwhelmingly, negatively impact its customers.  In lieu of this, the EPA's preferred option (state budgets with limited interstate trading) is the lesser of three evils, in that it would allow limited interstate trading of allowances and banking of allowances. The direct control remedy, where pollution limits are set for each state and an allowable emission rate limit is determined for each EGU, with some emissions averaging amongst an entity's generating fleet is also preferred, provided that the State would make determinations of emissions rates.  However, it would appear that under the EPA's direct control remedy, a company could meet all of its obligations under this alternative and meet all of its individual emission reduction requirements, yet be penalized by the failure of other companies within its state to meet theirs.  As one can imagine, this is an untenable situation. [EPA-HQ-OAR-2009-0491-2669.1, p.4]
Response: 
Thank you for your comment.  EPA is not finalizing the direct control alternative, but is finalizing the air quality-assured trading remedy.  As EPA explained in the proposal, a state's SIP submission to replace the Transport Rule FIP might propose to use any remedy of the state's choosing that actually eliminates the emissions that significantly contribute to nonattainment or interfere with maintenance downwind. Additional information on the SIP process may be found in section X of the preamble to the final Transport Rule.
Organization: Class of '85 Regulatory Group
Comment: 
Class of '85 Regulatory Group
The Class of '85 appreciates EPA's efforts to develop the Proposal. The Group supports EPA's preferred option for implementing the requirements of CAA § 110(a)(2)(D), subject to the comments provided herein. The preferred option provides the most environmental benefit of any proposed option while offering important flexibility for EGUs, which provide a vital service to society by producing a reliable supply of electricity. However, the Class of '85 believes that EPA can improve its preferred option by making several changes to the proposed program, including refinements to trading and variability provisions, and clarifications to opt-in, penalty, and other provisions. These changes will ensure a smooth transition from the Clean Air Interstate Rule ('CAIR') and increase the overall effectiveness of CATR. [EPA-HQ-OAR-2009-0491-2854.1,p.1]
The Preferred Option's Interstate Trading Mechanism Provides the Most Efficient Mechanism for Reducing Emissions.
Any interstate emissions reduction program implemented by EPA must contain flexibility mechanisms to help assure highly cost-effective emissions reductions and address real-world fluctuations in electricity demand. [EPA-HQ-OAR-2009-0491-2854.1,p.2]
Response: 
Thank you for your comment.  EPA is finalizing the air quality-assured trading remedy in the preamble to the final Transport Rule for the reasons cited in section VII.  EPA describes the transition from CAIR to the Transport Rule is section IX.  Based on these and other sections of the preamble, EPA believes we have finalized a rule that addresses the Court's concerns and still affords sources the flexibility to comply with a market-based program that delivers the reductions necessary to meet the statutory requirements under section 110(a)(2)(D)(i)(I) of the Clean Air Act.
Organization: Cogentrix Energy, LLC
Comment: 
Cogentrix Energy, LLC
Cogentrix supports the Preferred Option for a number of valid and proven reasons. First, Cogentrix has opted in to EPA's successful Acid Rain program at both the Hopewell and Portsmouth sites. The Acid Rain program allowed for interstate trading, and yet it has proven highly successful in its goal to reduce acid deposition in Northeastern states. Second, the Preferred Option allows for the most economical reductions among affected facilities through a 'cap and trade' approach. The economic efficiency of the First Alternative is significantly reduced from the Preferred Option because covered sources in different states, even within close proximity would be precluded from trading with each other. To bar trading among proximate sources based on arbitrary state lines that have no influence on air transport of emissions would be economically inefficient. The Second Alternative Option is not a 'cap and trade' program at all and provides none of the economic efficiency of a trading program. Rather. it merely dictates emissions reductions similar to EPA's less successful Reasonably Available Control Technology (RACT) programs. By allowing for trading among affected facilities the likelihood for excessive control costs and the use of unproven control technologies is reduced. [EPA-HQ-OAR-2009-0491-2772.1, p.4]
Further, Cogentrix believes that the Preferred Option also adequately addresses the identified issues of the Clean Air Interstate Rule (CAIR) since it uses geographical boundaries on trading of allocations. [EPA-HQ-OAR-2009-0491-2772.1, p.4]
Response: 
Thank you for your comment.  EPA is finalizing the air quality-assured trading option, known as the preferred option in the proposal,  for the reasons discussed in section VII.A of the preamble to the final Transport Rule.
Organization: Consumers Energy
Comment: 
Consumers Energy
:: Consumers Energy is an advocate of the use of emissions trading to arrive at cost effective solutions to air quality issues. Consequently, we support an approach similar to EPA's preferred methodology. We believe that the collaborative approach described above will enable EPA to craft an allowance allocation scheme that will be more robust, yet still in accordance with the rulings of the D.C. Circuit Court. [EPA-HQ-OAR-2009-0491-2837.1, p.16]
:: EPA must recognize that the affected sources have been making substantial plans and progress towards the implementation of controls, in accordance with CAIR, which remains final and enforceable. Any changes to CAIR must take these plans into account. The changes to the schedule contained in the proposed Transport Rule are not attainable. Any attempt to meet them will result in limited success, substantial noncompliance across the region, with substantial cost penalties. [EPA-HQ-OAR-2009-0491-2837.1, p.16]
Response: 
Thank you for your comments.  Please see section VII.D. in the preamble to the final rule for a discussion of the allocation methodology.  Please see section VII.C for a discussion of compliance with the programs.
Organization: DiMeo, Daniel
Comment: 
DiMeo, Daniel
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.89-90.]
And as far as EPA's preferred approach to the trading of pollution limits, it's my vision that the more trading that's allowed generally the less pollution control you can expect, and when the costs are, again, shown to be so significantly less than the benefits overall, I believe that the best option, like the EPA's second or third alternative, especially in terms of eliminating interstate trade, it's very easy for companies to see those pollution limits as more allowances that they have, and that it's a budget that they must spend as much of as possible in order to cut down the cost.
And so we need to make sure that those budgets are as low as possible for the sake of the rest of us as it were.
Response: 
Thank you for your comment and participation in the Chicago public hearing.  EPA benefits from public involvement in the rulemaking process.
EPA is finalizing the air quality-assured trading remedy for the reasons discussed in section VII.A in the preamble to this final Transport Rule.  EPA discusses how we developed budgets for this rule in section VI.D.  EPA has also included assurance provisions beginning in 2012, the start of the program, to ensure that each state eliminates its significant contribution and interference with maintenance as required under Clean Air Act section 110(a)(2)(D)(i)(I).  You can read about the assurance provisions in section VII. E of the preamble to the final Transport Rule.
Organization: DTE Energy
Comment: 
DTE Energy
We support EPA's preferred option proposing to permit some degree of interstate allowance trading. This option will provide very restricted flexibility within the constraints of Michigan's proposed budget, but at least provides some flexibility for more cost-effective compliance than the alternative approaches. While DTE supports the preferred proposal over the alternatives, trading of emission allowances for compliance purposes under this proposal will be at best limited. The preferred option creates significant risk with EPA's after-the-fact variability analysis. This concern could be moderated to a degree if the variability limits were such that the company would not be unexpectedly found in a noncompliance situation. [EPA-HQ-OAR-2009-0491-2851.1, p.2]
Response: 
Thank you for your comment. EPA is finalizing the air quality-assured trading remedy in the final Transport Rule.  EPA notes that there are no limits on trading in the Transport Rule.  For SO2 compliance purposes, however, a source in a group 1 state (such as Michigan) must surrender for compliance a group 1 allowance for each ton of emissions.  For compliance in the annual NOX and ozone-season trading programs respectively, sources may use annual NOX and ozone-season allowances allocated for any state, even if that state is in a different group for SO2 than the source's state.  For a discussion on the interstate trading programs, see section VII.A of the preamble to the final Transport Rule.  Variability limits are discussed in the preamble to the final Transport Rule in section VI.E and F.  Further detail is provided on state variability limits in the Technical Support Document called Power Sector Variability Final Rule. 
Organization: Duke Energy
Comment: 
Duke Energy
As explained in the following comments, Duke Energy agrees with certain aspects of the PTR, including EPA's preferred limited interstate trading remedy that allows some degree of allowance trading, EPA's proposal not to auction allowances under this approach, the ability to bank allowances from the beginning of the program, and not applying the assurance limits at the start of the program. [EPA-HQ-OAR-2009-0491-2689.1, p.1]
Duke Energy Supports EPA's Proposed Limited Interstate Trading Remedy.
Duke Energy supports EPA's proposed limited interstate trading remedy over the intrastate trading and direct control remedy alternatives. The fact that this option permits at least some degree of allowance trading provides more potential compliance flexibility and will provide for more cost-effective compliance options than the alternative remedies. This flexibility will be especially important in the early years of the program, especially if EPA does not alter the unreasonable proposed compliance schedule and continues to overstate the ability of existing emission controls to reduce emissions. [EPA-HQ-OAR-2009-0491-2689.1, pp.2-3]
Response: 
EPA is finalizing the air quality-assured trading remedy for the reasons discussed in section VII.A of the preamble to the final Transport Rule.  For information on the compliance deadlines, see section VII.C of the preamble to the final Transport Rule.
Organization: E.ON U.S.
Comment: 
E.ON U.S.
We support EPA's preferred option allowing limited interstate allowance trading, as opposed to the alternative options under consideration. [EPA-HQ-OAR-2009-0491-2797.1, p.8]
EPA's preferred trading option that allows unlimited intrastate trading and limited interstate trading is the best of the three allowance trading options identified by EPA. EPA's proposal to allow at least some degree of allowance trading in order to provide flexibility is the most cost-effective option among those being considered by EPA. In addition, we support EPA's proposal to delay the variability limits until 2014. However, even with the delay until 2014, Kentucky and many other states will face a significant allowance shortfall which simply cannot be avoided by installation of additional controls or costly fuel switches or boiler modifications. Therefore EPA should not begin the variability limits until 2014 and then they should be phased in over a six-year period perhaps starting with 25% then stepping down to 10%. [EPA-HQ-OAR-2009-0491-2797.1, p.8]
Response: 
Thank you for your comment.  EPA is finalizing the air quality-assured remedy for the reasons discussed in section VIIA of the preamble to the final Transport Rule.  For reasons discussed in section VII E, EPA has decided to begin the variability limits and assurance provisions in 2012.  Discussions on the variability limits may be found in section VI.E.2 of the preamble to the final Transport Rule.  More details on variability are also available in the Power Sector Variability Technical Support Document in the docket for this rulemaking.  EPA is finalizing a different allowance allocation methodology from what was proposed in the Transport Rule proposal that bases allocations on historic heat input.  For reasons discussed in section VII J of the preamble to the final Transport Rule, EPA believes we are finalizing a rule that comports with the Court's decision in North Carolina while still providing sources the flexibility they need to comply with the regulatory programs.
Organization: Edison Electric Institute (EEI)
Comment: 
Edison Electric Institute (EEI)
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.28-29.]
EEI supports, among EPA's stated options, the Agency's preferred approach that would allow limited interstate trading.
However, even with EPA's preferred approach for limiting emissions trading, EEI is concerned that some of the companies may choose to avoid emissions trading because they would seek to avoid the risk that EPA's after-the-fact variability analysis brings to the compliance demonstration process.
Response: 
Thank you for your comments.  EPA is finalizing the air quality-assured trading remedy for the reasons discussed in section VII A of the preamble to the final Transport Rule.  For a discussion of the variability limits and assurance provisions, please see sections VIE, VIF, and VII E of the preamble to the final Transport Rule.  An example of how compliance works is found in Table VII.E-1 of section VII E of the preamble to the final Transport Rule.  Section VII.J discusses why EPA believes we are finalizing a remedy that comports with the Court's decision in North Carolina while still providing flexibility to sources to comply with the regulatory requirements of the program.
Organization: Environmental Defense Fund (EDF)
Comment: 
Environmental Defense Fund (EDF)
EDF strongly supports the preferred remedy, State Budgets/Limited Interstate Trading, over the two alternatives identified in the Proposed Rule. At the same time, EDF recommends that EPA strengthen and streamline the assurance provisions to align them even more closely with the Agency's statutory obligation while simultaneously enhancing flexibility and cost-effectiveness. EDF also urges EPA to consider ways of allowing even more robust interstate trading to secure expansive emissions reductions and public health protections while hewing its statutory obligations.
In the proposed Transport Rule, EPA considered three alternative remedies that varied in the scope of trading allowed: one with limited interstate trading, one with only intrastate trading, and one with no trading at all. EDF strongly supports utilizing EPA's preferred Limited Interstate Trading approach to secure expansive emissions reductions and greater human health protections than provided for under the proposed Transport Rule. As EPA recognizes in the proposed Transport Rule, there is strong theoretical and empirical support for flexible regulatory mechanisms such as emissions trading. Trading is widely recognized to be cost-effective, i.e., achieve reductions at the lowest total cost.40 Furthermore, the United States and EPA in particular have substantial practical experience with trading programs that have been resounding successes, including the Acid Rain Program under Title IV of the 1990 Clean Air Act Amendments and the NOx Budget Program that would be superseded by the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2834.1 p.15]
Indeed, EPA's own analysis shows that the preferred approach will offer greater net benefits than the two alternatives, which would limit trading to differing degrees. The Direct Control alternative applies controls directly to affected units with no trading at all, while the Intrastate Trading alternative allows for intrastate trading, but prohibits interstate trading. The EPA's RIA finds that the net estimated benefits of the Limited Interstate Trading remedy exceed those of both the Direct Control and Intrastate Trading alternatives by billions of dollars a year.41 [EPA-HQ-OAR-2009-0491-2834.1 p.16]
Moreover, these additional economic benefits come at no cost in terms of the effectiveness of the policy or its alignment with the goals and requirements of Section 110(a)(2)(D)(i)(I). Indeed, there are strong statutory grounds for using the preferred approach. To carry out the Agency's statutory mandate to prohibit interstate air pollution consistent with Section 110(a)(2)(D), EPA must address the emissions that significantly contribute to downwind nonattainment and interfere with maintenance. As we have already argued, this can be effectively achieved with greater emissions reductions and tighter variability limits. With an appropriate increase in the stringency of emissions reductions, the mechanisms that EPA proposes  -- the combination of carefully constructed state emissions budgets and assurance provisions tied to the variability limits  --  will ensure that the remedy satisfies the requirement of Section 110(a)(2)(D)(i) [EPA-HQ-OAR-2009-0491-2834.1 p.16](I).
First, EPA has painstakingly and carefully constructed state emission budgets that are tied directly to the significant contribution and interference with maintenance attributable to individual upwind states. These budgets, which were developed using state-of-the-art modeling of air quality impacts and abatement costs, establish a clear connection between the proposed trading system and EPA's statutory responsibility. [EPA-HQ-OAR-2009-0491-2834.1 p.16]
Second, the assurance provisions in the Proposed Rule play a crucial role. By requiring facilities to submit additional allowances for every ton in excess of state-specific variability limits, the Proposed Rule creates a strong economic disincentive to emit above those limits. The result is a very high degree of confidence that emissions from upwind states will remain within the defined variability limits, helping to align the proposed remedy with the objectives of Section 110(a)(2)(D). [EPA-HQ-OAR-2009-0491-2834.1 p.16]
Nonetheless, EDF believes that an even better approach is possible  --  one that would provide increased flexibility to regulated facilities and encourage a more robust emissions market (thereby lowering the costs of compliance with the program even further) while simultaneously aligning the rule even more closely with the statutory language in Section 110(a)(2)(D)(i)(I). We recommend that EPA consider two improvements to its preferred approach  -- the first streamlining and strengthening the assurance provisions, the second allowing trade between States in different groups. We emphasize that these two changes are independent, so that one could be adopted without the other. [EPA-HQ-OAR-2009-0491-2834.1 p.17]
a. Streamline and strengthen the assurance provisions. As noted above, the Proposed Rule includes assurance provisions that, when combined with appropriately stringent emissions budgets and variability limits, ensure that emissions from individual States will not make significant contributions to downwind nonattainment. [EPA-HQ-OAR-2009-0491-2834.1 p.17]
While the assurance provisions clearly satisfy the legal test, the specific way in which they would be implemented is unnecessarily complicated and puts undue weight on the specific mechanism used to allocate emission allowances to individual facilities. In the event that emissions in a state exceed the variability limit, the proposed approach lacks a clear or automatic means of allocating responsibility for that excess among sources within the state. EPA's proposed solution to this problem relies heavily on the initial facility-level budgets and introduces unnecessary uncertainty. As a result, the proposed approach might have the unintended effect of limiting banking and trading of allowances. [EPA-HQ-OAR-2009-0491-2834.1 p.17]
EDF recommends an alternative approach that would be even more closely aligned with EPA's statutory obligation, while improving and strengthening the performance of the assurance provisions from an economic point of view.42 [EPA-HQ-OAR-2009-0491-2834.1 p.17]
i. Facilities would be required to hold two distinct types of permits, or allowances, emission allowances and assurance allowances. The approach would work as follows:
ii. Emission allowances would function just as in the Proposed Rule, with each allowance authorizing the emission of one ton of SO2 or NOx. At the end of each annual compliance period, facilities would be required to submit one emission allowance for each ton of pollution emitted. [EPA-HQ-OAR-2009-0491-2834.1 p.17]
iii. As in the Proposed Rule, each state would be allocated a quantity of emission allowances equal to its State budget as determined by EPA. The total number of emission allowances available in a given year would be the sum of all the state budgets. Emission allowances would be fully tradeable and bankable. [EPA-HQ-OAR-2009-0491-2834.1 p.18]
iv. Assurance allowances would be a novel aspect of this approach. At the end of each annual compliance period, facilities would also be required to submit one assurance allowance for each ton of pollution emitted.43
v. Each State would be allocated a quantity of assurance allowances equal to the State budget plus the variability limit as determined by EPA. As in the case of emission allowances, there would be distinct assurance allowances for each pollutant. [EPA-HQ-OAR-2009-0491-2834.1 p.18]
vi. Importantly, assurance allowances would be State-specific: that is, they would only be valid in the state of issuance. As a result, assurance allowances could not be traded across State lines. Moreover, assurance allowances would not be bankable. In this way, the assurance allowances would guarantee that emissions in a state could not exceed the state emissions budget plus variability limit.44 [EPA-HQ-OAR-2009-0491-2834.1 p.18]
vii. EPA would administer an emissions market for each pollutant and an assurance market for each pollutant in each state.45 [EPA-HQ-OAR-2009-0491-2834.1 p.18]
This approach has a number of important advantages over the EPA's proposed approach:
:: While setting up separate assurance and emission markets might appear complicated at first, in fact it is a much simpler and more streamlined approach over all. The existence of a separate assurance market completely obviates the need for any method of allocating responsibility for excess emissions among facilities within a State. Each facility must submit an emission allowance and an assurance allowance for each ton of pollution: that is it. No further formulas or computation is needed. [EPA-HQ-OAR-2009-0491-2834.1 p.18]
Under the EPA's proposed approach, in contrast, facilities have no inherent or distinct responsibility to account for their contribution to a State's emissions in excess of the budget plus variability limit. As a result, EPA must propose a complicated scheme to apportion responsibility based on each EGU's "proportional share of the amount by which state emissions exceed the state budget with the variability limit."  [EPA-HQ-OAR-2009-0491-2834.1 p.18]
:: For the same reason, the approach proposed here is also much more flexible in that it would be compatible with any method of allocating emission allowances. For a range of reasons, individual States may want to propose alternative methods of initial allowance allocations. For example, there are strong economic reasons to support auctioning emission allowances (as in the Regional Greenhouse Gas Initiative already underway in the Northeastern U.S.) Alternatively, States might reasonably prefer simpler allocation rules that are directly tied to heat rates, or that reward facilities that have already made significant emissions reductions in the past and/or built up large banks of allowances under the pre-existing Acid Rain Program. [EPA-HQ-OAR-2009-0491-2834.1 p.19]
EPA's proposed approach for allocating responsibility for excess emissions among facilities within a State is entirely dependent on the proposed approach for allocating emission allowances among facilities, since the definition of an EGU's "proportional share" of excess emissions is based on the EGU's initial allocation. In effect, the EPA's proposed approach "locks in" a potentially suboptimal allocation approach, and would not allow individual States the flexibility to institute their own approaches to allowance allocation.[EPA-HQ-OAR-2009-0491-2834.1 p.19]
Response: 
Thank you for your comments and your thoughtful alternative proposal.  EPA gave it thorough consideration and decided to finalize the air quality-assured trading remedy for the reasons discussed in section VII.A of the preamble to the final Transport Rule.  Regarding your proposal for assurance allowances, we have given your proposal due consideration but do not find that it improved our ability to address interstate transport under CAA section 110(a)(2)(D)(i)(I), in line with the Court decision, in an administratively practical way.  In addition, EPA analyzed the degrees of power sector market concentration in each state using the Herfindahl-Hirschman index, that indicates only 6 Transport Rule states have power markets sufficiently diffuse to assure fair access to intrastate allowances.  The remaining states have highly concentrated power markets where individual allowance holders could impair liquidity and increase allowance prices.  EPA believes intrastate trading would require the Agency to conduct at least 58 separate auctions annually for at least 22 states, with state-specific screening of auction participants to ensure fair access to intrastate allowances.  For discussion on the assurance provisions, please see sections  VII E in the preamble to the final Transport Rule.  Variability and assurance are discussed in sections VI E and F.  For these reasons and the reasons discussed in section VII.J of the preamble to the final Transport Rule, EPA believes we have finalized a rule that comports with the Court's decision in North Carolina while providing sources with the most flexibility through cost-effective trading programs that are administratively manageable. 
Organization: EquiPower Resources Corp.
Comment: 
EquiPower Resources Corp.
In sum, there is no basis to support EPA's assertions that the (i) assurance provisions will be triggered infrequently and will not be punitive, and (ii) Rule's limited trading provisions are sufficient, as both are premised on the notion that EPA based its allocations on accurate assumptions and that unit utilization will not vary in the future. These deficiencies mean that the Transport Rule effectively implements a command-and-control program (with operational restrictions), which is why various groups have projected that compliance costs will be high because interstate trading will be dramatically limited under the Rule. Thus, it is unclear how EPA can support its suggestion that the cap-and-trade mechanism in the Proposed Rule will, "even without assurance provisions ... succeed[] in reducing emissions below allowance levels." Trading programs that have achieved such reductions (e.g., the NOx Sip Call and Title IV programs) have done so because those programs, unlike the Transport Rule, allowed unfettered trading. Such trading is not permitted under the Transport Rule, and therefore the Rule cannot take advantage of the efficiencies offered by cap-and-trade mechanisms. As explained below, EquiPower submits that there are alternative mechanisms that the Agency could have considered which would have addressed the D.C. Circuit's concern in North Carolina v. EPA that there be reasonable assurances that upwind emissions do not contribute to downwind nonattainment, while still permitting unfettered trading in the Transport Rule States. [EPA-HQ-OAR-2009-0491-2704.1, p.8]
Response: 
EPA disagrees with the commenter's assertions regarding the assurance provisions and the trading provisions.  EPA is finalizing the air quality-assured trading remedy for the reasons discussed in section VII A of the preamble to the final Transport Rule.  EPA believes this final rule strongly hews to the Court's decision in North Carolina and addresses the Court's concerns.  Please see section VII J of the preamble to the final Transport Rule for the reasons why we believe this approach comports with the Court's opinion.  For further discussions on the variability limits and assurance provisions, please see sections VI E and F of the preamble to the final Transport Rule, as well as section VII E.  The Transport Rule does not preclude trading; rather sources in Group 1 states may only use SO2 allowances allocated to group 1 states for compliance with the SO2 program, and sources in group 2 states may only use allowances allocated to group 2 states for compliance with the SO2 trading program. For compliance with the annual and ozone season NOx trading programs sources may use annual and ozone season allowances allocated for any state, even if that state is in a different group for SO2 than the source's state.   The discussion of EPA's legal authority and the environmental basis for the rule is found in section IV of the preamble for the final Transport Rule.  While EPA appreciates the thoughtful suggestions that EquiPower has put forth, we do not find that they improve our ability to address interstate transport under CAA section 110(a)(2)(D)(i)(I), in line with the Court decision, in an administratively practical way.  Therefore, we have decided to finalize a different alternative from what you suggest in order to address the court decision in North Carolina requiring us to align compliance schedules and attainment schedules, quantify and address each upwind state's significant contribution, give an independent meaning to the interfere with maintenance prong of CAA section 110(a)(2)(D)(i)(I); properly establish state-level emission budgets for SO2 and NOx; and provide adequate assurance that necessary reductions would occur within each state.  We believe the approach that we are finalizing is consistent with the decisions of the Court and will ensure the reductions necessary to meet statutory requirements while still providing flexibility for covered sources to comply with the program.
Organization: Florida Municipal Electric Association (FMEA)
Comment: 
Florida Municipal Electric Association (FMEA)
The EPA preferred cap and trading program is overly complicated: Trading intrastate is unlimited but interstate trading is limited to approximately 10% of the state's budget. However, Florida can only trade with Group 2 states. These include Alabama and Mississippi, but not Georgia which is a Group 1 state. Since the EGUs with controls in place or planned are given allowances based on estimated emissions with controls operating at full rated capability, what is there left to trade? The key principle of the cap and trade methodology is over-control of some units to allow under control of others with utility decisions based on where the cheapest reductions can be made. Again, FMEA urges EPA to use a methodology for allocating allowances for compliance with the Transport Rule based on heat input. This would operate similar to the NOx allowance allocation methodology without a fuel factor. [EPA-HQ-OAR-2009-0491-2731.1, p. 10]
Response: 
Thank you for your comments.  EPA is finalizing an allowance allocation methodology based on heat input for the reasons discussed in section VIID of the preamble to the final Transport Rule.  Please also see the technical support document titled Allowance Allocations in the Transport Rule FIPS Final Rule available in the docket of this rule.  Additionally, your comments are based on modeling assumptions in the proposed Transport Rule which showed Florida covered for annual SO2 and NOx reductions.  In the final Transport Rule, Florida is now covered only for ozone-season NOx reductions.  Sources in Florida may trade with any state.  In fact, any source may trade with any other source in any other state.  The only limit is on allowance surrender for SO2 program compliance.  In this case, a group 1 source can only use SO2 allowances allocated to group 1 states for compliance with the SO2 trading program.  A source in a group 2 state can only use SO2 allowances allocated to Group 2 states for compliance with the SO2 trading program.  For compliance in the annual NOx and ozone season NOx trading programs, sources may use annual and ozone season NOx allowances allocated for any state, even if that state is in a different group for SO2 than the source's state.  EPA believes the approach we are finalizing addresses the Court's concerns in the North Carolina decision while providing sources with flexibility to comply with the program requirements.
Organization: George Washington University Regulatory Study Center
Comment: 
George Washington University Regulatory Study Center
The D.C. Circuit's rejection of CAIR in North Carolina v. EPA has created substantial uncertainty about future regulation of NOx and SO2 emissions through emissions-trading programs. Members of Congress and the EPA have both reacted to this uncertainty with proposals for new cap-and-trade programs for these pollutants.  [EPA-HQ-OAR-2009-0491-2573.1, p.5]
The EPA's proposed Transport Rule, like the CAIR rule that it would replace, would create new cap-and-trade programs: two programs for SO2 (one for core coal-using states and another for peripheral states), one for ozone-season NOx, and one for annual NOx. It is almost entirely a creature of the North Carolina v. EPA decision in that most of its provisions are carefully worded and constructed so as to comply with the holdings in that case. Perhaps most notably, the rule would sharply restrict or eliminate interstate trading of SO2 and NOx allowances because the EPA determined that doing so would be the only way to comply with the court's requirement that each state's emissions not interfere with NAAQS compliance in downwind states.  [EPA-HQ-OAR-2009-0491-2573.1, p.5]
In addition, the Transport rule proposes to restrict the use of banked allowances through the "assurance provisions" in the proposal. [EPA-HQ-OAR-2009-0491-2573.1, p.5]
Response: 
Thank you for your comments.  For the reasons discussed in section IV and VII J, EPA believes we are finalizing a rule that comports with the Court decision in North Carolina while providing flexibility to covered sources in complying with program requirements to reduce emissions that significantly contribute to or interfere with maintenance of downwind air quality.  Regarding your assertion that the proposed Transport Rule "restricts the use of banked allowances through the assurance provisions", EPA disagrees.  The Transport Rule neither restricts the use of banked allowances, nor limits trading.  Please see section VII.E of the preamble to the final Transport Rule for a discussion of the assurance provisions.  See also the technical support document titled Assurance Level Penalty Level Analysis in the docket to this rulemaking. As regards trading, any source may trade with any other source in any other state.  The only limit is on allowance surrender for SO2 program compliance.  In this case, a group 1 source can only use SO2 allowances allocated to group 1 states for compliance with the SO2 trading program.  A source in a group 2 state can only use SO2 allowances allocated to Group 2 states for compliance with the SO2 trading program.  For compliance in the annual NOx and ozone season NOx trading programs, sources may use annual and ozone season NOx allowances allocated for any state, even if that state is in a different group for SO2 than the source's state.  EPA believes the approach we are finalizing addresses the Court's concerns in the North Carolina decision while providing sources with flexibility to comply with the program requirements cost-effectively.
Organization: Great River Energy
Comment: 
Great River Energy
The Transport Rule proposes three options. Great River Energy can only support EPA's State Budgets/Limited Trading Proposed Remedy (the 'Preferred Option') subject to comments provided herein. The Preferred Option has numerous limitations and contains critical errors, as discussed. Our support is contingent upon a viable and active interstate trading program and we have strong reservations about the existence of such activity. With respect to EPA's State Budgets/Intrastate Trading Remedy Option ('Option 2'), Great River Energy questions the 'flexible and cost effective' nature of this program for Minnesota, given the effective monopoly that two utilities will have on the state's allowances. (See Attachment 3, Transport Rule Minnesota Allocations by Company.) More specifically, Great River Energy will be placed at a competitive disadvantage and in an inflexible compliance position due to our limited allowance allocations as viewed in the context of our historical emissions and projected operational capacity. Further, with respect to EPA's Direct Control Remedy Option ('Option 3'), EPA projects NOx lb/mmBtu emission rates, as an example, for Great River Energy simple cycle combustion turbines. Specifically, EPA has determined that Lakefield Junction Station would be limited to an annual lb/mmBtu emission rate at 0.033 lb/mmBtu. Pleasant Valley Station is generally at 0.1 lb/mmBtu. Cambridge Station at 0.086 lb/mmBtu. Upon reviewing recent operational data, it is clear that the existing DLN burners may not be sufficient to consistently meet these projected emission rates on a continuous basis. Therefore, under Option 3, GRE could be expected to install SCR as the final level of NOx control in order to meet the projected emission rates, even though at one of our sources, six units have BACT controls in the form of DLN burners and water injection. In essence, with Option 3, EPA places us in a position of having to go beyond BACT in order to comply with the Option 3 requirement. These additional control costs, like Option 2, would place Great River Energy at a competitive disadvantage in the state and region. As a member of MISO, our simple cycle combustion turbines would effectively be priced out of the market, especially for contiguous states not subject to Transport Rule controls. It would also cause rate increases to our member cooperatives, which have struggled as a result of recent increases and demand reductions due to economic downturn. EPA should not underestimate the significance of these costs with respect to small cooperatives, reliant upon peaking turbines, across the Transport Rule region. [EPA-HQ-OAR-2009-0491-2758.1 p.8]
Response: 
Thank you for your comments.  EPA is finalizing the air quality-assured trading remedy for the reasons discussed in section VII.A of the preamble to the final Transport Rule.  EPA notes that we are finalizing an allowance allocation methodology based on historical heat input as discussed in section VII.D of the preamble to the final Transport Rule.  Section VII.J explains why EPA believes this program structure is consistent with the Court's opinion in the North Carolina decision.  EPA discusses price increases in section XII.H, which EPA projects to be within the range of price variability that is regularly experienced in markets.  Projected retail electricity prices are also discussed in Chapter 7 section 9 of the Regulatory Impact Assessment (RIA) in the docket to this final rule.
Organization: Greater Philadelphia Chamber of Commerce
Comment: 
Greater Philadelphia Chamber of Commerce
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.206.]
The EPA preferred option, which allows for intrastate trading and limited interstate trading among power plants, but assures that each state will meet its pollution control obligations, would seem to make sense for our region.
Response: 
Thank you for your comments.
Organization: Independence Power & Light (IPL)
Comment: 
Independence Power & Light (IPL)
For the reasons stated herein, IPL requests that EPA modify the proposed Rule by:
3. replacing the allowances for IPL's Blue Valley 3 unit listed in Appendix A with the following allowances:  
2012 S02: 4300 tons of S02 
2014 S02: 4300 tons  
2012 NOx: 330 tons [EPA-HQ-OAR-2009-0491-2741.1, p.18] 
Response: 
Thank you for your comment. EPA is finalizing a heat input methodology for allowance allocations that is indexed to historic data as described in section VII.D of the preamble to the final Transport Rule.  For additional information, please see the Allowance Allocations in the Transport Rule FIPS Final Rule technical support document in the docket to this rulemaking.
Organization: JEA
Comment: 
JEA
JEA supports EPA's proposal to permit at least some degree of allowance trading. Permitting interstate allowance trading would provide for increased flexibility and permit more cost-effective compliance options. Increased flexibility will be particularly important in the early years of the program, especially if EPA does not change the proposed rule's unreasonably accelerated compliance schedule. [EPA-HQ-OAR-2009-0491-2713.1, p.4]
Response: 
Thank you for your comment.  EPA is finalizing the air quality-assured trading remedy in the preamble to this final Transport Rule for the reasons discussed in section VII A.  EPA discusses responses to comments on compliance deadlines in section VII.C.
Organization: Kansas City Power and Light Company (KCP&L)
Comment: 
Kansas City Power and Light Company (KCP&L)
8. While KCP&L generally supports interstate trading versus intrastate-only trading or specific limits, to provide some flexibility and allow cost-effective compliance options, the relatively small size of the variability pools will not provide enough flexibility.
a. EPA should consider increasing the variability limit threshold from 10% to perhaps 20% of each state's budget.
b. Since it would have a negligible impact on the regional dispersion modeling used to develop the rule, KCP&L suggests EPA allow unlimited interstate trading between units within a certain distance from shared state borders (e.g., 10 miles or less).[EPA-HQ-OAR-2009-0491-2709.1, p.4]
Response: 
Thank you for your comments.  EPA is finalizing the air quality-assured trading remedy for the reasons discussed in section VII.A of the preamble to the final Transport Rule.  EPA notes that trading is not restricted between sources or states under the Transport Rule.  However, an SO2 source in a Group 1 state can only use SO2 allowances allocated to Group 1 states for compliance with the SO2 trading program.  Likewise, a source in a Group 2 state can only use SO2 allowances allocated to Group 2 states for compliance with the SO2 trading program.  For compliance in the annual NOx and ozone season trading programs, sources may use annual NOx and ozone season allowances allocated for any state, even if that state is in a different group for SO2 than the source's state.  Section VII.J of the preamble to the final Transport Rule discusses how the program structure comports with the Court's opinion in the North Carolina decision.  EPA discusses the use of variability limits in the Transport rule in the technical support document entitled Power Sector Variability Final Rule in the docket for this rule.  Information on the variability limits may also be found in sections VI.E and F of the preamble for the final Transport Rule.
Organization: Large Public Power Council (LPPC)
Comment: 
Large Public Power Council (LPPC)
Although LPPC supports EPA's decision not to propose "direct control" and "intrastate trading" approaches to regulation of interstate emissions, we have also identified aspects of the proposed Transport Rule that needlessly increase the cost and complexity of the regional trading program. These features  -  such as the three-year variability limit, the mechanism for enforcing the variability limits, and limitations on banking  -  are not needed to achieve the environmental objectives of the Transport Rule or ensure consistency with North Carolina. [EPA-HQ-OAR-2009-0491-2667.1, p.2]
Briefly stated, our principal recommendations to EPA are:
- Eliminate the proposed three-year variability limit, which is problematic to apply, is not required by North Carolina, and reduces the benefits of interstate trading;
- Replace the proposed "assurance provisions" for enforcing the variability limits with a straightforward financial penalty linked to the market value of allowances. The current assurance provisions would remove allowances from circulation and unfairly penalize all sources subject to the Transport Rule.
- Ensure that banked Transport Rule allowances do not count against a source's allowed share of the state budget plus variability limit;
- Consider various options to preserve the value of banked CAIR allowances, a step that would both be fair to sources that have achieved early and aggressive emission reductions under CAIR, and avoid discouraging similar reductions under the Transport Rule;
- Allow states to propose alternative allowance allocation methodologies for inclusion in FIPs; and
- Maintain the proposed 3% set-aside for new electric generating units (EGUs) and the seven-year period for allocation of allowances to retired EGUs. [EPA-HQ-OAR-2009-0491-2667.1, p.2]
As a general matter, LPPC believes that a cap-and-trade system is the most efficient and effective means of controlling interstate emissions of NOx and SO2, and strongly supports EPA's decision to adopt this approach (albeit in a limited form) in the proposed Transport Rule. Emissions trading encourages abatement at facilities that have the most cost-effective opportunities to control emissions; promotes innovation in the field of pollution control; is administratively more efficient than source-by-source "command-and-control" regulation; and has a proven track record in controlling both NOx and SO2. [EPA-HQ-OAR-2009-0491-2667.1, p.10]
Even so, LPPC believes that the emissions trading system described in the proposed Transport Rule includes features that would needlessly reduce the system's efficiency and increase its complexity. These features  -  which include the three-year variability limit; the "assurance provision" mechanism for enforcing the variability limits, and the restrictions on banking that result from the variability limit  -  are not compelled by the North Carolina decision and in most cases do not have compensating environmental benefits. Each of these issues is discussed below. [EPA-HQ-OAR-2009-0491-2667.1, pp.10-11]
Response: 
Thank you for your comments.EPA is finalizing the air quality-assured trading remedy for the reasons discussed in section VII.A of the preamble to the final Transport Rule.  EPA is not finalizing the 3-year variability limit.  For information on variability and the variability limits used in the Transport Rule, see sections VI.E and F of the preamble to the final Transport Rule, as well as the technical support document entitled, Power Sector Variability Final Rule, in the docket for this rule.  The Transport Rule FIPs include assurance provisions specifically designed to ensure that no state's emissions will exceed that state's emission budget plus the variability limit, i.e., the state's assurance level.  The assurance provisions are discussed in section VII.E of the preamble to the final Transport Rule.  Penalty provisions are discussed in section VII.F of the preamble to the final Transport Rule.  A technical support document entitled, Assurance Penalty Level Analysis Final Rule, provides additional information on the assurance provisions and is available in the docket to this rule.  EPA is not restricting banking or trading.  A source may trade with any other source in any other state.  Allowances may be banked without penalty or restriction.  However, for SO2 trading program compliance, a source in a group 1 state can only use SO2 allowances allocated to group 1 states.  Likewise, a source in a group 2 state can only use SO2 allowances allocated to group 2 states for compliance with the SO2 trading program.  For compliance in the annual NOx and ozone season NOx trading programs, sources may use annual NOx and ozone season allowances allocated for any state, even if that state is in a different group for SO2 than the source's state.  EPA has decided not to carry-over banked CAIR allowances for the reasons discussed in section IX.A.2 of the preamble to the final Transport Rule.  EPA is finalizing ways for states to manage Transport Rule allowance allocations as early as 2013.  See section X of the preamble to the final rule for more information on the Transport Rule SIP process.  Discussion of the new unit set aside and information on the retired unit allocation are found in section VII.D.2 of the preamble to the final Transport Rule.  EPA discusses its legal authority and the environmental basis for this rule in section IV of the preamble to the final Transport Rule.  EPA discusses how the program structure is consistent with the Court decision in North Carolina in section VII.J of the preamble to the final Transport Rule.  Section VI.G of the preamble to the final Transport Rule discusses how the emission reduction requirements are consistent with judicial opinions. 
Organization: Midamerican Energy Holdings Company
Comment: 
Midamerican Energy Holdings Company
Of the Alternatives Presented, MidAmerican Supports EPA's Preferred Approach to Emissions Trading
Subject to the other concerns expressed herein, MidAmerican supports the EPA's preferred approach that allows limited interstate trading and unlimited intrastate trading. This approach fundamentally frustrates the underlying purpose of the Clean Air Act's Acid Rain program and calls into question the continued value of implementing that program. Nonetheless, limited trading, while not optimal, is preferable to no trading. While the variability limits provide a slight degree of flexibility, given their significant constraints based on the state budgets, the practical effect is that most facilities will attempt to control their emissions as much as possible to avoid the significant penalty provisions. [EPA-HQ-OAR-2009-0491-2748.1 4]
MidAmerican believes that EPA's alternative direct control option is not only unnecessary, but also unachievable. An examination of the EPA allocation table's direct control alternative allowable rate presents a 2014 emissions rate for SO2 of 0.059 lbs/mmBtu for MidAmerican's Louisa Generating Station. The Louisa Generating Station was equipped with a state-of-the-art dry scrubber and baghouse in 2007; however, the well-controlled emission rate at the Louisa Generating Station averages 0.10 lb/mmBtu SO2 -- almost twice the emission rate under the direct control alternative rate for the facility. Regardless of how well the Louisa scrubber performs, it is not capable of achieving an emissions rate of 0.059 lbs/mmBtu. Control equipment that is designed to achieve a 90% reduction in emissions cannot achieve an additional 45 - 50% reduction in emissions. A scrubber installed in 2007 is not, under any circumstances, contemplated to be replaced in 2014. Presumably, EPA calculated the requisite emission reduction without the recognition that controls had already been installed. [EPA-HQ-OAR-2009-0491-2748.1 5]
Response: 
Thank you for your comments.  EPA is not finalizing the direct control remedy in the proposal but is finalizing the air quality-assured trading remedy.
Organization: Morgan Stanly Capital Group
Comment: 
Morgan Stanly Capital Group
It should be noted that these problems disproportionately affect independent generators and peaking plants. Independent generators, including many peaking facilities, compete for customers and, unlike regulated utilities, have no captive rate base to which they can pass on operating costs.12 Consequently, it is very important for independent generators to accurately project their costs in order to effectively manage operations. Under the Proposed Rule, facilities are permitted to operate up to their allocation of allowances.13 If they can attain additional allowances from the market, they may also emit up to their portion of the state's "variability limit," but can only exceed it if the state meets its overall compliance obligation for the applicable period.14 Facilities will not have the information necessary to ascertain whether the state will be within its limits for the compliance period. Yet, they will be subject to penalties, including the surrender of two allowances for every ton of excess emissions, as well as unknown discretionary civil penalties under the CAA, if they emit over their portion of the state's variability limit and the state fails to meet its overall cap. An independent generator cannot manage this exposure.  [EPA-HQ-OAR-2009-0491-2819.1 P.4]
These problems are compounded for peaking plants, which are brought online in times of high demand or unusual system events to ensure system reliability. When called upon to run, system reliability typically requires them to come online immediately. Yet, many peaking plants, including MSCG's facilities, have been functionally denied an emissions budget. In fact, in all but one instance, MSCG's peaking plants are not allocated any allowances.15 As designed, the Proposed Rule also would not allow them much, if any, portion of the state's variability limit. Consequently, peaking plants may violate the Proposed Rule if the state has exceeded its variability limit. This would act as a strong disincentive against operation of such plants to meet system demands because they would risk violating the provisions of the CAA every time they run. Moreover, even if they are able to operate in compliance with the Proposed Rule, they still have no allowances and could have difficulty procuring them at a reasonable price and on a timely basis  -  assuming they can procure them at all. [EPA-HQ-OAR-2009-0491-2819.1 P.4]
MSCG believes that the concerns described above can be addressed by modifications to the Proposed Rule that meets the requirements of North Carolina v. EPA while ensuring that:
-Electrical generating units with little or no allowance allocations can obtain the allowances needed to ensure reliable and cost effective power generation;
-Such electrical generating units are provided with a sufficient increment of the applicable state variability limit;
-The compliance provisions are structured so as not to unduly penalize facilities whose modes of operation makes it particularly difficult to project their annual emissions; and
-All currently banked allowances are fully transferable for use under the new program.
[EPA-HQ-OAR-2009-0491-2819.1 p.5]
As discussed above, MSCG generally supports the concept underlying the Administrator's primary proposal for a multi-state, cap-and-trade program to reduce SO2 and NOx emissions, and appreciates that the Administrator has tried to design a program consistent with the D.C. Circuit Court's decision in North Carolina v. EPA. As explained herein, we encourage the Administrator to make certain important modifications that are consistent with the D.C. Circuit Court's directive in order to ensure that independent generators and peaking plants have the ability to start-up and operate. We welcome the opportunity to discuss these issues further with the Administrator and her staff. [EPA-HQ-OAR-2009-0491-2819.1 p.11] 
Response: 
Thank you for your comments.  EPA is finalizing the air quality-assured trading remedy for the reasons discussed in section VII.A of the preamble to the final Transport Rule.  EPA is finalizing an allowance allocation methodology based on historical heat input instead of projected emissions as discussed in section VII.D of the preamble to the final Transport Rule.  See the technical support document entitled, Allowance Allocations in the Transport Rule FIPs Final Rule, which is available in the docket to this rule.  The use of variability limits in the Transport Rule is discussed in section VI.E and F of the preamble, and in the technical support document entitled Power Sector Variability Final Rule in the docket to this rule.  The assurance provisions and penalties are discussed in sections VII.E and F of the preamble to the final Transport Rule.  See also the technical support document entitled, Assurance Penalty Level Analysis Final Rule, also available in the docket to this rule. Section VII.J of the preamble to the final Transport Rule discusses how the program structure that EPA is finalizing comports with the Court's opinion in the North Carolina decision. EPA is not allowing carryover of CAIR allowances for the reasons discussed in section IX.A of the preamble to the final Transport Rule.
Organization: National Association of Clean of Air Agencies (NACAA)
Comment: 
National Association of Clean of Air Agencies (NACAA)
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.106. Also as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.80.]
For example, we are encouraged by EPA's provisions limiting interstate trading. These will ensure that a substantial portion of a state's assigned emissions reduction occur in that state.
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.80.]
rather than through the purchase and use of out-of-state allowances to achieve compliance deadlines with attainment deadlines for the 1997 ozone, 1997 PM 2.5 and 2006 PM 2.5 air quality standards.
Response: 
Thank you for your comments.  EPA is finalizing the air quality-assured trading remedy for the reasons discussed in section VII.A of the preamble to the final Transport Rule.  EPA is finalizing assurance provisions that go into effect in 2012 to ensure that the FIP requires the elimination of all emissions that EPA has identified that significantly contribute to nonattainment or interfere with maintenance within each individual state, as required under CAA section 110(a)(2)(D)(i)(I).  Information on the assurance provisions is found in section VII.E of the preamble to the final Transport Rule.  For the reasons discussed in section VII.J, EPA believes the program structure we are finalizing to achieve the needed reductions comports with the Court's opinion in the North Carolina decision.
Organization: New Jersey Department of Environmental Protection (NJDEP)
Comment: 
New Jersey Department of Environmental Protection (NJDEP)
The NESCAUM states support use of a regional cap-and-trade program as a means to reduce regional NOx emissions. We recognize that an interstate trading program has a place in addressing transport, but may not be able to do handle the all transport issues completely. EPA needs to ensure that it and states have mechanisms in place to address those cases where specific controls or rules are warranted.
For example, EPA's framework for addressing significant contribution does not help states address the short-term public health effects of ozone, PM 2.5, NOx and SO2 exposures during high electricity demand days. It may even exacerbate this problem. Analyses indicate that, in the Northeast, NOx emissions are much higher, and in some cases nearly three times higher, on high electric demand days than during average summer days. Regulatory approaches that set standards, caps, or budgets that are based on annual averaging will likely be insufficient in addressing the peak exposures. EPA's proposed option for performance standards has an annual averaging time, and is therefore inappropriate for this purpose. EPA should incorporate short-term performance standards for electric generating units that apply to each upwind source. Such performance standards could co-exist with a trading program.   [EPA-HQ-OAR-2009-0491-2684.1 p.4]
Response: 
Thank you for your comments and your support of cap and trade programs to reduce regional NOx emissions.  EPA is finalizing the air quality-assured trading remedy for the reasons discussed in Section VII.A of the preamble to the final Transport Rule.  EPA discusses its authority and environmental basis for the Transport Rule in section IV of the preamble to the final Transport Rule.  As NESCAUM knows, the Clean Air Act provides states with several approaches to meet the NAAQS, including Title I.  EPA believes the remedy finalized in the preamble to the final Transport Rule addresses the Court's concerns in the North Carolina decision, as discussed in Section VII.J of the preamble to the final Transport Rule, and also addresses EPA's statutory responsibility under Section 110(a)(2)(D)(i)(I).  EPA decided that performance standards in addition to the remedy finalized would not further the attainment and interference with maintenance objectives of the statute.
Organization: New York University School of Law, Institute for Policy Integrity
Comment: 
New York University School of Law, Institute for Policy Integrity
EPA's preferred approach to the proposed Transport Rule will significantly advance the Agency's efforts to address the interstate transport of emissions of nitrogen oxides (NOx) and sulfur dioxides (SO2), but the Rule should be modified to improve efficiency and cost-effectiveness, and the Rule's justification should be clarified and strengthened. [EPA-HQ-OAR-2009-0491-2691.1, p.1]
EPA should adopt the preferred approach in its final rulemaking, with the following five specific improvements. [EPA-HQ-OAR-2009-0491-2691.1, p.6]
1. Create an Assurance Allowance Mechanism
Problems with the Preferred Approach
EPA's preferred approach permits the use of both intra- and interstate trading. Cap-and-trade economic models provide significant advantages over other forms of regulation by offering flexibility and by achieving emissions reductions in the most cost-effective manner. The extensive limits on trading in the two alternative approaches are inadvisable, because they impose greater costs to achieve the same level of reductions. [EPA-HQ-OAR-2009-0491-2691.1, p.6]
EPA's preferred approach takes a significant step forward in addressing the interstate transport of emissions of nitrogen oxides and sulfur dioxides. But before it finalizes new rules, EPA should reconsider its methodology and provide greater transparency in its approach. [EPA-HQ-OAR-2009-0491-2691.1, p.13]
Response: 
Thank you for your comments and your thoughtful alternative proposal.  EPA gave it thorough consideration and decided to finalize the air quality-assured trading remedy for the reasons discussed in section VII.A of the preamble to the final Transport Rule.  Regarding your proposal for an assurance allowance mechanism, we have given your proposal due consideration but do not find that it improved our ability to address interstate transport under CAA section 110(a)(2)(D)(i)(I), in line with the Court decision, in an administratively practical way.  In addition, EPA analyzed the degrees of power sector market concentration in each state using the Herfindahl-Hirschman index, that indicates only 6 Transport Rule states have power markets sufficiently diffuse to assure fair access to intrastate allowances.  The remaining states have highly concentrated power markets where individual allowance holders could impair liquidity and increase allowance prices.  For discussion on the assurance provisions that EPA is finalizing, please see sections  VII E in the preamble to the final Transport Rule.  Variability and assurance are also discussed in sections VI E and F.  EPA strives to continually improve our transparency with the public by engaging in public hearings, webinars, outreach, stakeholder meetings, etc., providing public comment periods, and putting all relevant process documents and analyses in the docket to this rulemaking and making the regulations, supporting analyses, modeling runs, technical support documents, communications materials, etc. available on our web site.  For all these reasons and the reasons discussed in section VII.J of the preamble to the final Transport Rule, EPA believes we have finalized a rule that comports with the Court's decision in North Carolina while providing sources with the most flexibility through trading programs that are cost-effective and administratively manageable.
Organization: Northern Indiana Public Service Company (NIPSCO)
Comment: 
Northern Indiana Public Service Company (NIPSCO)
In order to provide for a more viable trading program in the Transport Rule, NIPSCO recommends that EPA include unlimited intrastate trading as a component of the preferred approach. The trading program in the preferred approach limits the use of out of state, banked and in-state vintage year allowance when the assurance levels are exceeded in the state. NIPSCO believes that the use of in-state allowances for the applicable vintage year to comply with the Transport Rule requirements should be unlimited and not subject to the assurance provisions. [EPA-HQ-OAR-2009-0491-2747.1 p.6]
Response: 
Thank you for your comments.  EPA is finalizing the air quality-assured trading remedy for the reasons discussed in section VII.A. of the preamble to the final Transport Rule.  EPA notes that there are no limits on trading or banking in the Transport Rule.  For SO2 compliance purposes, however, a source in a group 1 state (such as Indiana) can only use SO2 allowances allocated to Group 1 states for compliance with the SO2 trading program. Likewise, a source in a group 2 state can only use SO2 allowances allocated to group 2 states for compliance with the SO2 trading program.  For compliance in the annual NOX and ozone-season trading programs respectively, sources may use annual NOX and ozone-season allowances allocated for any state, even if that state is in a different group for SO2 than the source's state.  For a discussion on the interstate trading programs, see section VII.A.  The assurance provisions are discussed in section VII.E. of the preamble to the final Transport Rule.  See the technical support document entitled, Assurance Penalty Level Analysis Final Rule, in the docket of this rule making.
Organization: Ozone Transport Commission (OTC)
Comment: 
Ozone Transport Commission (OTC)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.112 & 116-117.]
Further, the proposed rule limits the degree to which such plants can engage in interstate trading of emissions. By restricting interstate trading, EPA has taken a major step towards addressing the courts finding and the CAA requirement that each state mush reduce its share of transported pollution.
Another flaw in the proposed Transport Rule is the design of the remedy. EPA proposes to set state EGU budgets, but then allows sources within that state to emit above these already inadequate budgets up to the variability limit.
In order to meet the statutes requirement and the Courts mandate, EPA need to implement a trading program that sets a state emissions budget at the level necessary to eliminate transport and that requires mitigation in a specific state if the collective sources in the state exceed the budget.
Response: 
Thank you for your comments.  EPA is finalizing the air quality-assured trading remedy for the reasons discussed in section VII.A of the preamble to the final Transport Rule.  EPA is also finalizing assurance provisions that go into effect in 2012 to ensure the necessary reductions will occur within every covered state.  Information on the assurance provisions is found in section VII.E of the preamble to the final Transport Rule.  Variability and the use of variability limits in the Transport Rule are discussed in sections VI.E and F as well as in a technical support document entitled, Power Sector Variability Final Rule, that is available in the docket to this rule.  EPA discusses why we think this program structure comports with the Court's opinion in the North Carolina decision in section VII.J of the preamble to the final Transport Rule.
Organization: Pennsylvania Department of Environmental Protection
Comment: 
Pennsylvania Department of Environmental Protection
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.51.]
We support EPA's approach for the Transport Rule, to the extent allowed under the Clean Air Act. This approach, which provides for intrastate trading and limited trading, requires EGU owners and operators to achieve actual emission reduction.
Response: 
Thank you for your comment.
Organization: PPL Corporation
Comment: 
PPL Corporation
8. Support of EPA's Preferred, Limited Interstate Trading Option.
The EPA is proposing to regulate the state budgets through a program that would allow limited interstate trading of allowances and unlimited intrastate trading. Under this approach, there is an assurance provision starting in 2014 specifying that annual emissions within the state could only exceed the state budget (through purchase of out-of-state allowances) by up to a variability amount specified in the proposal and based on the annual variation of emissions. This is EPA's preferred regulatory alternative and the alternative that PPL supports. The EPA also identified in the proposed rule two alternatives. The first alternative would allow unlimited intrastate trading but no interstate trading. The second alternative would restrict individual EGUs on an annual basis to the specific emission rates set forth in the rule with the only caveat being that owners would be allowed to average among their own in-state units. [EPA-HQ-OAR-2009-0491-2739.1, p.9]
PPL prefers EPA's proposed and preferred option that would allow limited interstate trading because it is the lowest cost option and would attain the same region-wide reductions as the two alternative options. The integrity of reducing the state's significant contribution to downwind nonattainment would be maintained because only the annual variability amounts (10 percent per year, 5.8 percent per three-year average) could be used in interstate trading. [EPA-HQ-OAR-2009-0491-2739.1, p.9]
Response: 
Thank you for your support.  EPA is finalizing the air quality-assured trading remedy for the reasons discussed in section VII.A of the preamble to the final Transport Rule.  EPA explains the variability limits in section VI E and VI F of the preamble to the final Transport Rule.  EPA discusses the assurance provisions that will begin in 2012 instead of 2014, as was proposed, in section VII.E of the preamble to the final Transport Rule. 
Organization: Prairie State Generating Company, LLC
Comment: 
Prairie State Generating Company, LLC
6. PSGC'S PREFERRED APPROACH
Emissions trading restricted by variability limits is one way to address the North Carolina court's concerns with the perceived failure of the Clean Air Interstate Rule ('CAIR'), 40 CFR 96, Subparts AA through IIII (nonconsecutive), to require emission reductions in certain upwind states. Of the three options that the U.S. EPA presented in the proposed Transport Rule, PSGC prefers the limited interstate trading approach, the U.S. EPA's 'preferred' approach. [EPA-HQ-OAR-2009-0491-2842.1, p.6]
However, PSGC believes that a 2012 compliance date is too soon and that the program should begin in 2014 or preferably in 2015, which would have been the beginning of Phase II of the CAIR. Although the North Carolina court remanded the entirety of the CAIR, the CAIR remains in place as an applicable requirement and, as the U.S. EPA has acknowledged, is causing reductions in region-wide NOx and SO2 levels. Therefore, it is providing the transport reductions the U.S. EPA has identified as required consistent with NAAQS attainment dates. [EPA-HQ-OAR-2009-0491-2842.1, p.6]
There are other ways to achieve this reduction certainty, including a floor rate. There is some state-wide average emissions rate that, considering the state's coal-fired generation portfolio combined with projected transport from that state, would achieve the same ends as the U.S. EPA's proposal and would still allow greater flexibility through a more robust emissions trading program. The U.S. EPA performed the type of modeling that could determine these rates for the NOx SIP call 63 Fed. Reg. 57355 (October 27, 1998). This approach would provide a more level playing field that is protective against interference with downwind attainment and maintenance while creating a more robust emissions trading regime of allowances reflective of emissions above the emissions rate floor. [EPA-HQ-OAR-2009-0491-2842.1, p.6]
Response: 
Thank you for your comments.  EPA is finalizing the air quality-assured trading remedy for the reasons discussed in section VIIA of the preamble to the final Transport Rule.  For a discussion on the compliance deadlines, see section VII.C of the preamble to the final Transport Rule.  EPA believes the remedy we are finalizing addresses the Court's concerns in the North Carolina decision, as discussed in section VII J, as well as the statutory requirements in the Clean Air Act section 110(a)(2)(D)(i)(I). 
Organization: PSEG Services Corporation
RRI Energy, Inc.
Empire District Electric Company (Empire District)
American Forest & Paper Association (AF&PA)
Old Dominion Electric Cooperative
American Public Power Association (APPA)
Public Interest Law Center of Philadelphia
Oren, Craig N.
Comment: 
American Forest & Paper Association (AF&PA)
AF&PA supports the broadest possible trading mechanisms as we believe this allows for the most cost effective implementation of any emissions controls. We agree with the Edison Electric Institute (EEI) in supporting a broader authorization of trading [EPA-HQ-OAR-2009-0491-2643.1, p.2]
American Public Power Association (APPA)
For example APPA supports EPA`s preferred option of permitting some degree of emission allowance trading (although, as discussed subsequently in the comments, APPA urges EPA to expand the margin for trading). [EPA-HQ-OAR-2009-0491-2812.1, p.7]
EPA`s Proposed Remedy Option allows limited interstate allowance trading, while its two alternative options would not allow any interstate trading. APPA supports EPA's proposal to permit at least some degree of allowance trading. Permitting interstate allowance trading would provide for increased flexibility and permit more cost-effective compliance options. Increased flexibility will be particularly important in the early years of the program, especially if EPA does not change the proposed rule`s unreasonably accelerated compliance schedule as suggested in these comments. [EPA-HQ-OAR-2009-0491-2812.1, p.9]
APPA strongly believes that the interstate trading program described in the proposal should resolve the problems with the CAIR program`s unrestricting trading that the court cited in North Carolina v. EPA. The court held that the CAIR interstate trading program was inconsistent with the Act, based mainly on the program`s region-wide approach. Noting that "EPA is not exercising its section 110(a)(2)(D)(i)(I) duty unless it is promulgating a rule that achieves something measurable toward the goal of prohibiting sources `within the State' from contributing to nonattainment or interfering with maintenance `in any other State'," the court held that "EPA`s apportionment decisions have nothing to do with each state`s `significant contribution'." 531 F.3d at 907. Although the Proposed Transport Rule is flawed for reasons discussed elsewhere in these comments, the Proposed Remedy Option incorporates a mechanism for addressing the significant contribution of individual states to downwind nonattainment and maintenance problems. [EPA-HQ-OAR-2009-0491-2812.1, p.9]
Empire District Electric Company (Empire District)
Empire District supports EPA's preferred approach of establishing state budget and implementing a limited interstate trading program.  We do not support the intrastate trading alternative or the site-specific emission limits with limited averaging alternative.  The Title IV Acid Rain Program, NOx SIP Call and CAIR have proven that an allowance trading approach to emission control is both effective and efficient.  Given the current financial strain on our national economy and our customers' household budgets in particular we urge EPA to finalize their preferred approach. [EPA-HQ-OAR-2009-0491-2659.1, p.5]
Old Dominion Electric Cooperative
ODEC also supports the proposal's remedy option and the intrastate trading option in the second compliance period to the extent that both allow allowance trading, because program costs would be reduced without jeopardizing emission reduction goals. [EPA-HQ-OAR-2009-0491-2877.1,p.3] [[This comment is also in Section V.D.3.]]
Oren, Craig N.
The agency's trading proposal appears legally defensible and well-thought out. It is too bad, though, that EPA has had to retreat from full trading, which would probably cut compliance costs. [EPA-HQ-OAR-2009-0491-2644-cp, p.1]
PSEG Services Corporation
PSEG supports the cap and trade option with limited interstate trading. While PSEG's preference would have been for incorporating the Acid Rain Title IV allowance system, given the constraints that the DC Circuit Court imposed on EPA, PSEG believes the unlimited intra-state and limited interstate emission trading option that EPA has proposed is as vigorous as EPA could make the rule, and we believe it to be workable. [EPA-HQ-OAR-2009-0491-2726.1, pp.1-2]
PSEG supports EPA's preferred market based cap and trade emissions approach. The D.C. Circuit court's CAIR decision limited EPA's authority to allow interstate trading. Despite this constraint, our first impression is that EPA has proposed a reasonable approach that balances the industry's ability to trade allowances and implement the most cost-effective control options while at the same time recognizing that the Clean Air Act requires EPA to prohibit emissions that significantly contribute to nonattainment or interfere with maintenance in downwind states. PSEG is a strong supporter of market-based regulatory approaches because of their cost effectiveness, and we hope that EPA will, at a minimum, preserve its preferred trading approach as it develops its final rule. The cap-and-trade approach has a long history of success in regulating power plant emissions. [EPA-HQ-OAR-2009-0491-2726.1, p.4]
Although PSEG has significant concerns about EPA's use of projected emissions to allocate allowances to emission units, we strongly support the overall framework of the preferred option including unlimited intrastate trading and limited interstate trading using the variability and assurance level provisions. The preferred option stays within the constraints of the D.C. Circuit decision by ensuring the necessary emissions reductions occur in the states identified as contributing to nonattainment or interfering with maintenance in other states. At the same time, the preferred option allows owners to use market mechanisms to buy and sell allowances. Allowance markets are essential to promoting cost-effective reductions. [EPA-HQ-OAR-2009-0491-2627.1, p.10]
Public Interest Law Center of Philadelphia
The EPA's preferred approach for attaining these emissions reductions includes setting individual emissions caps for each state, and allowing unlimited intrastate trading of pollution allowances, so long as each state does not exceed its assigned emissions allowance. This proposal would also allow energy companies to engage in a limited amount of interstate emissions trading, but only as long as total statewide emissions remain below the mandated cap. [EPA-HQ-OAR-2009-0491-2817.1, p.2]
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.124-125.]
I want to comment specifically on the fact that EPAs preferred rule would allow unlimited intrastate trading and limited interstate trading of allowances between EGUs as part of the agency's strategy to in the words of the Transport Rules preamble 'assure environmental results while providing some limited flexibility to covered sources.'  
RRI Energy, Inc.
RRI supports EPA's preferred option (State Budgets / Limited Trading) to identify the emissions reductions requirements, state budgets and variability limits (effective in 2014) in lieu of the alternate remedy options (State Budgets / Intrastate Trading option, Direct Control option and any option that utilizes trading ratios). The preferred option is consistent with EPA's Key Guiding Principles (e.g., to provide incentives and flexibility to the regulated community) while also providing the emissions reductions necessary to eliminate states' significant contribution and interference with maintenance with the applicable NAAQS. RRI notes that the 2014 state SO2 and NOx emissions budgets under the preferred option are equivalent to the state budgets under the more restrictive alternate remedy options (per Tables V.E-5 through V.E-7 of the proposed CATR). [EPA-HQ-OAR-2009-0491-2717.1 p.1]
Response: 
EPA thanks you for your comments.  As discussed in the proposal, EPA has a long history of successful implementation of national and regional trading programs.  EPA has put forth a rule that we believe provides flexibility for EGUs while hewing to the Court's opinion.
Organization: San Miguel Electric Cooperative, Inc.
Comment: 
San Miguel Electric Cooperative, Inc.
 Limitations on interstate allowance trading are too stringent. Both the annual and three year rolling average limitations could be loosened while still meeting North Carolina legal mandates.   [EPA-HQ-OAR-2009-0491-2641.1, p.6]
Response: 
Thank you for your comment.  EPA is finalizing the air quality-assured trading remedy for the reasons discussed in section VII.A of the preamble to the final Transport Rule.  EPA is also finalizing assurance provisions that go into effect in 2012 to ensure that the necessary reductions will occur within every covered state.  Information on the assurance provisions is found in section VII.E of the preamble to the final Transport Rule.  Section VII.J discusses why EPA believes the program structure we are finalizing comports with the Court's opinion in the North Carolina decision.
Organization: State of Missouri Department of Natural Resources
Comment: 
State of Missouri Department of Natural Resources
Missouri is supportive of the preferred option proposed by EPA in the Transport Rule because it provides Missouri utilities with the greatest flexibility to meet emission reduction requirements in the most economically viable manner. However, even with the flexibility provided in the proposal, some of the restrictions included do cause some concern. For example, utility owners which have facilities in neighboring states that fall into group 1 and group 2 under the SO2 requirements cannot trade between their own facilities. Missouri recognizes the difference in the contribution to affected areas between the two (2) groups, but limited or 'ratio trading,' if only allowed within a facility or utilities in the same regional electrical grid, could alleviate this concern and further ensure greater reliability for regional electrical service. [EPA-HQ-OAR-2009-0491-3806, p.2]
Response: 
Thank you for your comments.  EPA is finalizing the air quality-assured trading remedy for the reasons discussed in section VII A of the preamble to the final Transport Rule.  EPA believes the program structure we are finalizing comports with the Court's opinion in the North Carolina decision, as discussed in section VII J of the preamble to the final Transport Rule.  How EPA developed the two SO2 groups of states and the reason EPA feels it is important to finalize the two groups of states for SO2 reductions that eliminate a state's significant contribution to downwind air quality are explained in sections VIB. and VID: EPA does not believe that limited or ratio trading between the two groups would improve on the remedy EPA is finalizing or enhance the assurance that reductions take place within each state, as required by statute and in the Court's North Carolina decision.
Organization: State of Wisconsin, Department of Natural Resources
Comment: 
State of Wisconsin, Department of Natural Resources
Wisconsin can support a trading and banking program or a simple averaging program to meet reduction targets established for the sector for NOx and S02 emission reductions within the state. With strong limits to the level of trading away emission reduction obligations, Wisconsin can also support interstate trading structures that facilitate efficient emission control retrofit schedules, so long as the needed Wisconsin and downwind state air quality improvement is not compromised in 2014 and thereafter. [Better than Intra-State or Averaging Demonstration of Air Quality effect during critical periods.] [EPA-HQ-OAR-2009-0491-2829.2, p.1]
Consequences of an inadequate remedy to significant contribution affecting Wisconsin air quality. [EPA-HQ-OAR-2009-0491-2829.2, p.3]
While EPA suggests the current proposal is a viable framework for addressing future standards, it has actually proposed a basic remedy focused only on the electric utility sector and strictly as a replacement to CAIR that can affect much, but nowhere near all, of the significant contributing (upwind) NOx and S02 emissions. This approach will likely preclude Wisconsin's capability to attain and maintain new, lower ambient ozone and PM-2.5 standards on a schedule required under the Clean Air Act. [EPA-HQ-OAR-2009-0491-2829.2, p.3]
A basic flaw of the proposed framework is that the proscribed remedy leaves Wisconsin at risk for potential continuing nonattainment status and the resultant public health concerns/costs. This places Wisconsin emission sources at risk for the need to implement incrementally more severe emission control installations compared to some of our upwind neighboring states that are contributing significantly to our ambient air quality problems. Some of the proposed state EOU 2014 budgets proposed reflect a backsliding from budget levels established in CAIR for 2015. This is, in part, due to questions regarding the feasibility of installing sufficient controls in the contributing states to meet the budgets that are equal to or deeper than final CAIR budget levels before 2015. Under the framework, as crafted, Wisconsin is unable to demonstrate a full attainment and maintenance strategy for either standard, placing the State at risk for major parts of federal funding and exposing major sources in Wisconsin to larger offsets for new S02 and NOx emissions than in neighboring states with greater emissions. Wisconsin sources will also retain much higher uncertainty into the near future regarding the level and speed of anticipated emission control installation requirements. [EPA-HQ-OAR-2009-0491-2829.2, p.4]
Response: 
Thank you for your comments.  EPA is finalizing the air quality-assured trading remedy for the reasons discussed in section VII A of the preamble to the final Transport Rule.  While EPA is finalizing a framework for addressing future standards, as your comments suggest, EPA also is aware that other sectors may be implicated in emission contributions to downwind nonattainment and interference with maintenance in the future and intends to look at other sectors and sources of emissions going forward, along with the electricity generating sector.  The methodologies EPA is finalizing to develop budgets and allocate emissions are found in sections VI and VIID, respectively, of the preamble to the final Transport Rule.
In the proposed Transport Rule, EPA's air quality modeling projected a wintertime PM problem in Wisconsin.  The final air quality modeling indicates that there is no longer a wintertime PM problem in Wisconsin.  That is, we project that all areas in Wisconsin will be in attainment with both annual and 24-hour PM standards by 2014.  See section VI.A. in the preamble to the final Transport Rule and the Air Quality Modeling Final Rule TSD in the docket to the rulemaking.
Organization: Texas Commission on Environmental Quality
Comment: 
Texas Commission on Environmental Quality
The TCEQ finds that the EPA's proposed preferred state budget/limited trading option to be flawed in its design. The proposed option purports to be a cap and trade program; however, the trading limits and restrictions (assurance provisions) proposed undermine the goal of a cap and trade program - that is, to provide emission reductions in a cost-effective manner that utilizes market flexibility. Further, the manner in which violations are assessed under the proposed option creates an unreasonable burden on individual sources that would require interdependence among sources to determine each entity's own compliance. It is disingenuous to provide a trading program that, upon familiarity with the details, provides no viable trading alternative to comply with the rule. [EPA-HQ-OAR-2009-0491-2857.1, p.2]
Response: 
EPA is finalizing the air quality-assured trading remedy for the reasons discussed in section VII A of the preamble to the final rule.  For a discussion of the assurance provisions, please see section VII E of the preamble to the final Transport Rule.  EPA disagrees with the commenter's opinion that the trading program "provides no viable trading alternative to comply with the rule."  EPA believes we have structured a flexible and effective remedy that also addresses the concerns of the Court in the North Carolina decision, as described in section VII.J of the preamble to the final Transport Rule. Sources that emit up to their state budget allocation plus share of the state's variability limit will not face penalties, if they have allowances to cover their emissions.  Other options are for sources to improve efficiency, add on pollution controls, switch fuels, or pursue other such alternatives to reduce emissions to meet the state budgets.  EPA discusses penalties in section VII.F of the preamble to the final Transport Rule.
Organization: Utility Air Regulatory Group (UARG)
American Electric Power
Metropolitan Washington Air Quality Committee
Mississippi Department of Environmental Quality
Southern Company
NRG Energy
Exelon
GE Energy Financial Services (GE EFS)
Florida Electric Power Coordinating Group, Inc. (FCG)
Dynegy, Inc.
Indiana Energy Association
Ameren Services Company
Dominion
Michigan Department of Natural Resources and Environment
Minnesota Power 
Tampa Electric Company
Cogen Technologies Linden Venture, LP
Institute of Clean Air Companies (ICAC)
Sunbury Generation LP
Progress Energy Service Company
Wisconsin Power and Light Company
Oglethorpe Power
Birchwood Power Partners, L.P.
Santee Cooper
Entergy Services, Inc.
TransCanada
Owensboro Municipal Utilities (OMU)
Comment: 
Ameren Services Company
Ameren supports the trading and banking option for compliance between states
EPA's Proposed Remedy Option allows limited interstate allowance trading, although its two alternative options would not allow any interstate trading. Ameren supports EPA's proposal to permit at least some degree of interstate trading in order to provide flexibility and permit more cost-effective compliance options. Ameren believes that the Intrastate Trading Remedy Option and the Direct Control Remedy Option offer no or minimal flexibility from a compliance perspective and thus would cause an undue burden on the utility sector. Ameren does not support either of these options. [EPA-HQ-OAR-2009-0491-2722.1, p.9]
American Electric Power
Aside from our preference to keep the budgets and timelines the same as the existing CAIR program, the proposed remedy option which includes interstate trading of allowances is highly preferred to the other alternative approaches proposed by EPA. The main reason for this preference is that economies of scale are lost when taking a smaller (i.e. state or unit level) approaches to emissions trading or averaging, which will ultimately drive up cost to customers and increase the risk of stranded or misplaced investments. Secondly, administration of the alternative approaches may be more challenging by creating additional allowance markets and/or limitations which need to developed, implemented and monitored. AEP agrees with EPA's selection of the interstate trading option. [EPA-HQ-OAR-2009-0491-2665.1,p.11]
Birchwood Power Partners, L.P.
E. Birchwood Power Supports the Broadest Trading Program That Can be Implemented in Accordance with the Court's Decision in North Carolina v. EPA
Birchwood Power supports the Proposed Transport Rule's proposed remedy of using state-specific control budgets and allowing for intrastate and limited interstate trading. This option would allow flexibility for generators to undertake the most cost-effective reductions available, while assuring (through the 'assurance provisions') that the resulting reductions occur within particular states, in accordance with the requirements articulated by the D.C. Circuit in North Carolina v. EPA, 531 F.3d 896 (DC Cir. 2008). In general, Birchwood Power would support the broadest trading program that EPA determines can be accomplished consistent with the court's decision. Birchwood Power does not support EPA's proposed alternative of implementing a direct control program without any emissions trading. [EPA-HQ-OAR-2009-0491-2706.1, p.6]
Cogen Technologies Linden Venture, LP
:: Linden Cogen supports EPA's proposed limited trading option and, in general, would support the most robust and flexible trading program that can be implemented in accordance with the principles articulated by the court in North Carolina v. EPA. [EPA-HQ-OAR-2009-0491-2712.1, p.5]
N. Linden Cogen Supports the Broadest Trading Program that Can Be Implemented in Accordance with the Court's Decision in North Carolina v. EPA
Linden Cogen supports the Proposed Transport Rule's limited trading option because it would allow flexibility for generators to undertake the most cost-effective reductions available, while assuring that the resulting reductions occur within particular states, in accordance with the requirements articulated by the D.C. Circuit in North Carolina v. EPA, 531 F.3d 896 (DC Cir. 2008). In general, Linden Cogen would support the broadest trading program that EPA determines can be accomplished consistent with the court's decision. [EPA-HQ-OAR-2009-0491-2712.1, p.23]
Dominion
Interstate Trading
Dominion supports EPA's preferred approach that would allow limited interstate trading and unlimited intrastate trading and commends the Agency for its continued application of a market-based approach in achieving emission reductions. EPA's proposal to permit at least some degree of allowance trading will provide some flexibility for companies to target reductions at units where it is more cost-effective to do and reduce the potential for forced investments or even unit shutdowns at units for which major pollution control investments are not economically feasible. The alternative approaches discussed by EPA in the rulemaking (allowing only intrastate trading and imposing emission limits at the unit level) would provide much less flexibility and unnecessarily increase costs of emission reductions. [EPA-HQ-OAR-2009-0491-2715.1, pp.2-3]
Dynegy, Inc.
Dynegy Supports Interstate Trading
Dynegy, which owns and operates EGUs in several affected states, supports EPA's proposal to allow interstate allowance trading. While Dynegy would prefer unlimited interstate trading to the extent permitted by the Clean Air Act, even EPA's proposed limited interstate trading as described in its Preferred Remedy Option would improve compliance costs. Limited interstate trading would give companies such as Dynegy the flexibility to decide where to make its most cost effective emission reductions and then move allowances between its units (within the proposed variability limits) rather than purchasing allowances from other out-of-state sources. [EPA-HQ-OAR-2009-0491-2698.1,p.8]
Entergy Services, Inc.
We also agree that allowing unlimited intrastate trading combined with limited interstate trading among power plants is an effective means to assure each state will meet its pollution control obligations and minimize downwind contributions.  [EPA-HQ-OAR-2009-0491-2847.1, p.1]  
Exelon
EPA'S PREFERRED ALTERNATIVE OF STATE BUDGETS/LIMITED TRADING WILL COST-EFFECTIVELY REDUCE INTERSTATE EMISSIONS CONSISTENT WITH THE REQUIREMENTS OF THE CAA, BUT CAN BE MADE MORE EFFECTIVE WITH CERTAIN CHANGES.
EPA'S STATE BUDGETS/LIMITED TRADING REMEDY WILL MORE COST-EFFECTIVELY LIMIT INTERSTATE INTERFERENCE WITH MAINTENANCE OF NAAQS AND SIGNIFICANT CONTRIBUTION TO NONATTAINMENT THAN THE OTHER ALTERNATIVES CONSIDERED BY EPA.
Experience with the Title IV program, the NOx SIP Call program that preceded CAIR and the California RECLAIM program have confirmed that trading-based programs provide a powerful tool to achieve cost-effective reductions in emissions. Accordingly, some level of interstate trading, as proposed by EPA in its selected State Budgets/Limited Trading remedy, can be expected to lower the cost to achieve the emission levels set out in Transport Rule. EPA forecasts 2012 power industry implementation costs would be more than 10% lower under the preferred option of State Budgets/Limited Trading compared to either the State Budgets/Intrastate Trading option or the Direct Control option. [EPA-HQ-OAR-2009-0491-2666.1, p.21]
Neither the State Budgets/Intrastate Trading remedy option nor the Direct Control option will achieve the Transport Rule emission levels as inexpensively as EPA's preferred option. A remedy allowing emission trading will promote fuel and technology switching, supplementing the reductions that can be achieved with cost-effective installation of emission control equipment at fossil fuel generators. In particular, the Direct Control option will not encourage switching to less polluting fuels or technologies to nearly the same extent. Exelon also agrees that the State Budgets/Intrastate Trading remedy option would be less flexible than the preferred option, and potentially more susceptible to market manipulation. [EPA-HQ-OAR-2009-0491-2666.1, pp.21-22]
Florida Electric Power Coordinating Group, Inc. (FCG)
While the FCG requests that EPA wait and develop a single, accurate rule, as explained above, if EPA finalizes the proposal, the FCG's preference is that EPA choose its preferred option, which would allow limited interstate trading of allowances. The alternatives of allowing only intrastate trading, and unit-specific limits are much less desirable. [EPA-HQ-OAR-2009-0491-2658.1, p.11]
GE Energy Financial Services (GE EFS)
GE EFS supports the Proposed Transport Rule's proposed remedy of using state-specific control budgets and allowing for intrastate and limited interstate trading. This option would allow flexibility for generators to undertake the most cost-effective reductions available, while assuring that the resulting reductions occur within particular states, in accordance with the requirements articulated by the court in North Carolina v. EPA. In general, GE EFS would support the broadest trading program that EPA determines can be accomplished consistent with the court's decision. [EPA-HQ-OAR-2009-0491-2701.1, pp.4-5]
Indiana Energy Association
a. The Indiana Utility Group supports EPA's preferred approach (limited interstate trading) over other less flexible alternatives and, specifically, supports trading across Group 1 and Group 2 states, at a minimum for the initial program phase when all states are in the same phase of the program. [EPA-HQ-OAR-2009-0491-3711 p.5]
Institute of Clean Air Companies (ICAC)
a. ICAC Acknowledges and Supports EPA's Efforts to Respond to the CAIR Remand and to Finalize a Legally-Defensible Transport Rule. ICAC acknowledges the constraints EPA faces in responding to the Court's remand of the Clean Air Interstate Rule (CAIR), and believes that EPA has proposed a remedy that will answer the Court's legal objections to CAIR. In particular, EPA proposes its preferred remedy that incorporates flexibility for sources while still measuring each state's significant contribution and giving independent meaning to the interference with maintenance prong of section 110(a)(2)(D)(i)(I) of the Clean Air Act (CAA). Also, EPA's has coordinated the 2012/2014 compliance deadlines with the 1997 PM2.5 National Ambient Air Quality Standard (NAAQS) April 2015 extension of the April 2010 attainment date, the 2006 24-hour PM2.5 NAAQS December 2014 attainment date, and the 1997 8-hour ozone NAAQS attainment date of June 2013 for serious nonattainment areas. [EPA-HQ-OAR-2009-0491-2695.1, p. 2]
ICAC supports EPA's analysis of and response to the CAIR ruling, and EPA's unstated effort to finalize a critically needed Transport Rule that is legally defensible. A new Transport Rule that will not be delayed by litigation is vitally important to providing not only the health benefits promised by the CAA, but the regulatory certainty that sources need to plan their pollution control investments. [EPA-HQ-OAR-2009-0491-2695.1, p. 2]
b. ICAC Supports EPA's Efforts to Provide Maximum Flexibility to Sources. ICAC realizes that EPA is attempting to provide as much flexibility to sources within the constraints of responding to the legal objections of the District of Columbia Circuit Court of Appeals in its 2008 vacatur and remand of CAIR, and we support those efforts. We believe that the greatest source of flexibility in the proposed rule is EPA's preferred remedy of allowing unlimited and intrastate and limited interstate allowance trading thereby allowing sources to achieve compliance at least cost.  [EPA-HQ-OAR-2009-0491-2695.1, p. 3]
c. ICAC Supports EPA's Preferred Remedy. ICAC supports EPA's preferred remedy in the proposed rule which will provide sources the maximum amount of flexibility within the legal constraints imposed by the CAIR remand as allowance trading will allow each source to make the best and most economical decision with respect to compliance timing. [EPA-HQ-OAR-2009-0491-2695.1, p. 3]
Metropolitan Washington Air Quality Committee
MWAQC supports the proposed remedy of state budgets with limited interstate trading. Restricting trading to only intrastate transactions would require development of state-by-state trading programs resulting in a patchwork of systems that would be an inefficient use of state government resources. Source-specific control requirements may be overly burdensome on the regulated community in that it would remove flexibility for sources to install controls where it may make most economic or logistical sense at any given time. Such an approach may also not result in real improvements to air quality depending on how EPA specifies controls for individual sources. [EPA-HQ-OAR-2009-0491-2618.1, p.2]
Michigan Department of Natural Resources and Environment
The EPA requested comments on the proposed preferred method of compliance and two alternative methods. The preferred compliance option would use state-specific control budgets and allow for intrastate and limited interstate trading of emissions, allowing for four trading regions. These regions are ozone season NOx, annual NOx, Group 1 S02 and Group 2 S02. [EPA-HQ-OAR-2009-0491-2774.1 p.5]
The DNRE supports the preferred compliance method because it provides the most flexibility to affected sources. [EPA-HQ-OAR-2009-0491-2774.1 p.5]
Minnesota Power 
Limited interstate trading.  Minnesota Power agrees with EPA's preferred option that would provide for limited interstate trading of Transport Rule allowances (e.g. up to 10%), acknowledging that EPA's year to year unit production variability analysis provides a reasonable supportive basis for such interstate emissions allowance trading.  [EPA-HQ-OAR-2009-0491-2750.1, p.6]    
Mississippi Department of Environmental Quality
We would like to comment that Mississippi supports the proposed allowance trading approach which allows intrastate trading with limited interstate trading.  [EPA-HQ-OAR-2009-0491-2634.1, p.1]
NRG Energy
NRG supports the EPA's preferred limited interstate trading approach in that it achieves the goals of the Transport Rule while providing the flexibility of a market based program. [EPA-HQ-OAR-2009-0491-2749.1, p. 4]
Oglethorpe Power
IX. Alternatives to EPA's Preferred Option
While there are numerous deficiencies and problems with the current proposal, Oglethorpe Power believes that the remedy option preferred by EPA is greatly superior to the other proposed options. neither of  which provide for any interstate trading of allowances. Interstate trading - even limited trading - is very important, to provide increase flexibility and allow for more cost-effective options for compliance. As a not-for-profit utility, any cost savings realized in an emissions reduction program (as compared to other, optional and less flexible programs) will necessarily flow directly to Oglethorpe Power's Members, all of which are also not-for-profit utilities. Here, the preferred option will produce reductions more efficiently than either of the other approaches. Option one, while allowing intrastate trading, prohibits interstate transactions of any kind. Some interstate trading of allowances is clearly allowed for under the CAA (more we think than EPA is proposing even in its preferred remedy), and we strongly encourage EPA to include that feature in any control program it finalizes to reduce interstate transport of ozone and tine particulate precursors. The direct 'command-and-control' option will be the most inefficient of the three approaches, as it removes any economic incentives to reduce emissions beyond those needed for compliance. As the Agency proceeds toward finalization of the Transport Rule, it should reject any control option that prohibits the creation and trading of allowances. [EPA-HQ-OAR-2009-0491-2732.1, pp.13-14]
Owensboro Municipal Utilities (OMU)
OMU supports the approach that allows the maximum amount of trading among electric generating units (EGUs) but still assures that each state will meet its pollution control obligations. [EPA-HQ-OAR-2009-0491-2811.1,p.1]
Allowing interstate trading would increase flexibility to meeting reduction goals and minimizes increases in power costs. [EPA-HQ-OAR-2009-0491-2811.1,p.1]
Progress Energy Service Company
Progress Energy understands that development of an effective replacement rule for CAIR that complies with the court's decision in North Carolina v. EPA is a difficult task. While the proposed rule contains a number of issues that concern Progress Energy, we agree with several aspects of the proposal, such as (i) allowance banking beginning in 2012, (ii) some degree of interstate allowance trading, (iii) the curb on allowance auctions, and (iv) the decision not to apply higher cost-effectiveness thresholds in the determination of emission reduction requirements.  [EPA-HQ-OAR-2009-0491-2831.1 p.2]
EPA's Proposed Remedy Option allows limited interstate allowance trading, although its two alternative options would not allow any interstate trading. Progress Energy supports EPA's proposal to permit at least some allowance trading in order to provide as much flexibility as possible given the court's decision and permit the development of more cost-effective compliance options.  [EPA-HQ-OAR-2009-0491-2831.1 p.2]
Santee Cooper
SANTEE COOPER SUPPORTS THE LIMITED INTERSTATE TRADING APPROACH OVER EPA's ALTERNATIVE REMEDIES
Santee Cooper generally supports EPA's decision to implement the Transport Rule by means of statewide NOx, and S02 budgets with limited interstate trading, instead of the 'direct control' and 'intrastate trading only' alternatives the agency also considered. Of the three remedies considered, the proposed State Budgets Limited Interstate trading approach allows EGUs to achieve the environmental objectives of Section 110 with maximum compliance flexibility within the constraints imposed by the D.C. Circuit's opinion in North Carolina v. EPA. Although Santee Cooper would prefer unlimited regional NOx and SO2 trading, and our comments below detail numerous respects in which the mechanics of the proposed trading system could be improved (most importantly by eliminating the 3-year variability limit and the prohibition on trading between EGUs in Group 1 and Group 2 states), we do not believe EPA should opt for one of the suggested (less flexible) alternative remedies in the final Transport Rule. [EPA-HQ-OAR-2009-0491-2820.1, pp.3-4]
Southern Company
XIV. EPA Should Adopt an Interstate Trading Program and Abandon the Alternatives Offered for Comment
EPA's proposed limited interstate trading option provides a limited amount of flexibility and allows more cost-effective compliance options. EPA has historically allowed interstate trading in transport rules and should do so in this case. The intrastate trading option (Alternative 1) is completely unworkable and cumbersome. And EPA has no authority for the direct control option (Alternative 2), which provides for little to no flexibility. As stated, Southern Company strongly supports a flexible interstate trading program. Although EPA's interstate trading option is preferable to either of the two proposed alternatives, as explained in Section V, EPA should evaluate whether less stringent limits on trading can be adopted without compromising the anticipated air quality benefits of the Transport Rule. [EPA-HQ-OAR-2009-0491-2864.1, p. 50]  [This comment can also be found at section V.D.1, V.D.3. and V.D.4 of this comment summary.]
XVI. Southern Company Supports Several of EPA's Decisions in the Proposed Transport Rule As discussed throughout these comments, Southern Company has many concerns with the Proposed Transport Rule. However, we support several of EPA's decisions in the proposed rule including: EPA's decision to allow interstate trading, albeit overly limited, in the preferred approach; as discussed earlier, EPA should consider additional trading flexibility and EPA's decision to not establish allowance auctions in the preferred approach.  [EPA-HQ-OAR-2009-0491-2864.1, P. 52]
Sunbury Generation LP
To the extent that EPA nonetheless proceeds with implementation of one of the three options discussed in the Proposed Rule, Sunbury supports the use of the remedy option proposed by EPA through the Proposed Rule - i.e., the State Budgets/Limited Trading option. [EPA-HQ-OAR-2009-0491-3615, p.8]
Tampa Electric Company
Tampa Electric Supports Some Elements of the Proposed Rule
Tampa Electric supports EPA's preferred approach, which allows limited interstate trading among power plants but assures that each state will meet its pollution control obligations consistent with the requirements of § 110(a)(2)(D)(i)(I) of the Clean Air Act [42.U.S.C. § 7410(a)(2)(D)(i)(I)].  We believe this proposal generally results in a reasonable approach to meeting reduction goals and could help to minimize the cost increase for power assuming the allocations are not too restrictive to allow market dynamics to occur. [EPA-HQ-OAR-2009-0491-2745.1 p.2] [These comments were also submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.74.]
Although we believe that the implementation schedule is unreasonable, we agree with EPA that banking should be allowed beginning the first year of the program. [EPA-HQ-OAR-2009-0491-2745.1 p.2]
The 1st alternative, "intra-state trading only" is unfavorable for our customers because it unnecessarily limits the trading market and the ability to achieve the greatest cost reductions and would cause unnecessary increases in the cost of electricity at a time when our customers can least afford it. The 2nd alternative is potentially more detrimental because it further reduces compliance flexibility and ignores the highly successful market-based system of emission reduction.  This option intuitively results in higher overall compliance costs without guaranteeing any additional environmental benefit. [EPA-HQ-OAR-2009-0491-2745.1 p.2]
[These comments were also submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.53-54.]
TransCanada
Comment 3: Support for EPA's Preferred Approach to the Allowance Trading Options
Of the stated options contained in the proposed Transport Rule, TransCanada supports the EPA's preferred approach that would allow intrastate trading of NOx and SO2 allowances and limited interstate trading of allowances. The alternative approaches contained in the proposed Transport Rule, as opposed to the preferred approach, would provide much less flexibility and unnecessarily increase the cost of the significant emission reductions required by the proposed Transport Rule. Additionally, having a larger market that allows for some interstate trading of excess allowances may provide more of an incentive for facilities to reduce emissions so that allowances can be freed up and sold on the market. [EPA-HQ-OAR-2009-0491-2827.1, p.3]
Utility Air Regulatory Group (UARG)
UARG supports EPA's preferred option of permitting some degree of emission allowance trading (although, as discussed subsequently in the comments, UARG urges EPA to consider expanding the margin for trading). [EPA-HQ-OAR-2009-0491-2756.1, p.9]
EPA's Proposed Remedy Option allows limited interstate allowance trading, while its two alternative options would not allow any interstate trading. UARG supports EPA's proposal to permit at least some degree of allowance trading. Permitting interstate allowance trading would provide for increased flexibility and permit more cost-effective compliance options. Increased flexibility will be particularly important in the early years of the program, especially if EPA does not change the proposed rule's unreasonably accelerated compliance schedule as suggested in these comments. [EPA-HQ-OAR-2009-0491-2756.1, pp.10-11]
UARG believes that the interstate trading program described in the proposal should resolve the problems with the CAIR program's unrestricting trading that the court cited in North Carolina v. EPA. The court held that the CAIR interstate trading program was inconsistent with the Act, based mainly on the program's region wide approach. Noting that "EPA is not exercising its section 110(a)(2)(D)(i)(I) duty unless it is promulgating a rule that achieves something measurable toward the goal of prohibiting sources `within the State' from contributing to nonattainment or interfering with maintenance `in any other State,'" the court held that "EPA's apportionment decisions have nothing to do with each state's `significant contribution.'" 531 F.3d at 907. Although the Proposed Transport Rule is flawed for reasons discussed elsewhere in these comments, the Proposed Remedy Option incorporates a mechanism for addressing the significant contribution of individual states to downwind nonattainment and maintenance problems. [EPA-HQ-OAR-2009-0491-2756.1, p.11]
Wisconsin Power and Light Company
WPL emphasizes that EPA must allow for interstate trading as a means to cost-effectively achieve emissions reductions. Of utmost importance is that EPA issue a rule that provides for the most compliance flexibility given the stringent emissions reductions and tight timeframes in the proposed CATR. Therefore, WPL supports EPA's preferred rule option subject to the comments provided herein. EPA's preferred approach allows intrastate trading and limited interstate trading among power plants but assures that each state will meet its pollution control obligations. This approach will provide the most environmental benefit while also offering necessary compliance flexibility for electric generation units (EGUs) that must produce affordable and reliable power to meet our customer's energy demands. [EPA-HQ-OAR-2009-0491-2844.1 p.3]
Response: 
EPA thanks you for your comments.  EPA strove to develop a rule that comported with the 2008 Court decisions while providing the regulated sector compliance flexibility to ensure cost-effective state-specific reductions that eliminate downwind impacts.
Organization: Western Farmers Electric Cooperative (WFEC)
Comment: 
Western Farmers Electric Cooperative (WFEC)
Of the three options presented by EPA in this proposal, option #1 is preferred for WFEC.  This option will allow limited inter-state trading.  Being a small electric utility to have any options for trading, WFEC would have to outside of its company.  If trading were limited to in state utilities, WFEC would have fewer options.  As a small non-profit supplier of power, it is imperative that WFEC's options not be limited.  [EPA-HQ-OAR-2009-0491-2642.1,p.3]
WFEC has an energy portfolio in the state of Oklahoma that is highest percentage of renewable energy than any other electric utility in the state at this time.  In effect, our emissions have already been reduced and given emissions allocations based on the already reduced emissions does seem fair. [EPA-HQ-OAR-2009-0491-2642.1,p.3]
Response: 
Thank you for your comments.  EPA is finalizing the air quality-assured trading remedy for the reasons discussed in section VII.A of the preamble to the final Transport Rule.  EPA is finalizing an allowance allocation methodology based on historical heat input as discussed in section VII.D of the preamble to the final Transport Rule.  Please refer to additional information on allocations which is found in a technical support document entitled, Allowance Allocations in the Transport Rule FIPs Final Rule, and is available in the docket to this rule.  Section VII.J provides information on why EPA believes this program structure comports with the Court's opinion in the North Carolina decision.
Organization: Wholesale Markets Brokers' Association
Comment: 
Wholesale Markets Brokers' Association
I. Discussion of the Benefits of Cap and Trade
The record is clear that the use of flexible emissions trading programs, such as the program authorized under Title IV of the Clean Air Act, has efficiently and effectively reduced SO2 and NOx emissions. Cap and trade programs are highly effective in reducing emission levels by incentivizing behavioral changes, leaving the decision of how to achieve compliance up to owners since they are best able to determine the most economically effective compliance strategy for a particular unit. As the head of a respected non-partisan think tank once noted regarding the US SO2 cap and trade program:
'...the program has succeeded spectacularly...between 1995 and 2007, the trading program will result in greater reductions on a much faster schedule than likely would have been the case under the more traditional technology based standards and will save more than $20 billion cumulatively over that time period. Even the most vocal ex ante critics of emissions trading now agree that the program has been a raging success.' [EPA-HQ-OAR-2009-0491-2799.1, p.2]
A review of historic emissions levels in the U.S. (as shown in the attached charts) clearly show that emissions of SO2 and NOx have dropped substantially since the inception of these cap and trade programs, and these facts are further confirmed in the EPA's own white paper dated April 2009. The EPA should continue its well-founded commitment to a cap and trade system while modifying its previous proposal only to the extent strictly necessary to satisfy the Court's legal concerns. [EPA-HQ-OAR-2009-0491-2799.1, p.2]
II. Cap and Trade Systems Need to Be Nurtured
Significant legal uncertainty now dominates the domestic emissions markets for SO2 and NOx due to the Court vacating the CAIR rule. The average monthly SO2 allowance prices have collapsed since the CAIR rule was vacated in 2008, from around $300 per ton down to around $15 per ton in July 2010. This price collapse clearly demonstrates the market impact when the structure of a market is changed with the stroke of a pen. Market participants are also now faced with a proposed CATR in which future trading in these allowances would be highly restricted. Under current accounting rules, many market participants are now facing the significant likelihood that they will have to write-off millions of dollars associated with their previous purchases of "banked" allowances  -  allowances that will become worthless under the CATR proposal. The write-off by Pennsylvania Power & Light (PPL) of over $30 million in NOx allowances in 2008 as a result of the court's decision underscores to investors and other potential market participants that these allowances are potentially much riskier investments than EPA assumes, since an unexpected EPA or court decision can wipe out their value overnight. As a result of these events, participants have now been "burned" by forces outside market fundamentals. [EPA-HQ-OAR-2009-0491-2799.1, pp.2-3]
EPA can easily address these potential concerns by simply remaining committed to reducing overall emissions through the fostering of a cap and trade system in the U.S. that is similar to those that are increasingly being adopted by regulators to other industrialized nations. A crucial characteristic of these marketplaces is the presence of a broad range of market participants with different viewpoints and objectives. For instance, dealers and other liquidity providers supply end-users with indicative prices, research and general market color about current bid/ask levels and depth of the market. IDBs also play a role as they facilitate price discovery and price inquires on an anonymous basis. IDBs active presence thus enables end-users and others to make informed investment decisions and to execute their strategy efficiently. Committed long and short-term investors are needed to take a contrarian or independent view on the direction of the market. Their presence is critical to enabling end-users to more actively manage their risks, end-users who have come to rely on the existence of an orderly and liquid secondary market in which to buy and sell credits. While all of these "players" have different objectives, they are all crucial to the proper functioning of the market. As a 2009 EPA White Paper recently noted: "firms operating specialized trading operations entered the market to seek arbitrage opportunities. These firms helped increase trading activity and efficiency. [EPA-HQ-OAR-2009-0491-2799.1, p.3]
If EPA wishes to preserve a market-based mechanism, it needs to act quickly and boldly. It also needs to understand the environment in which such private marketplaces typically flourish. The available data shows that emissions trading markets can be safe, robust, and effective in reducing overall emission levels provided they are nurtured. [EPA-HQ-OAR-2009-0491-2799.1, p.3]
As EPA considers how to preserve a market based component to the CATR during the next several years that is similar to CAIR, it should bear in mind two key points. First, there is a need to incentivize current market participants to continue to invest resources towards preserving what has become a robust market. As discussed above, EPA's own figures suggest that a reduced number of committed market participants can impact the liquidity and flexibility of this market. Recent commentary by SEC Chairman Mary Schapiro has underscored this exact point, and our members all agree that a firm's willingness to participate in the market depends greatly on the liquidity levels at the time they wish to transact. The smaller the market in terms of participants and volume of trades, the less liquid the market and the more difficult it is for end-users to sell or buy allowances. Secondly, EPA should seek to instill confidence in market participants that the rules will not materially change during a program. The market uncertainty that is created from a constant changing of the rules results in decreased market participants. [EPA-HQ-OAR-2009-0491-2799.1, pp.3-4]
III. EPA's Proposed Market Design Is Unduly Restrictive
The EPA market design under the proposed CATR program is highly restrictive and more "command and control" than "cap and trade." EPA has requested that respondents comment on one of their three proposed trading options.
(a) allow full intrastate trading with limited interstate trading;
(b) allow only intrastate trading among power plants within a state; or
(c) impose emission limits by power plan with some averaging but no trading. [EPA-HQ-OAR-2009-0491-2799.1, p.4]
If these are indeed the only options EPA is considering, the WMBAA strongly prefers EPA option (a). However, we would not that EPA has, in our view, imposed needless restrictions which will make that market much less effective in achieving the desired emission reductions. [EPA-HQ-OAR-2009-0491-2799.1, p.4]
Similarly, EPA's proposal restricts the use of CAIR allowances for compliance purposes after 2012, assuming that FGD scrubbers can be installed on a widespread basis on a 27 month timeline. That timeline is unrealistic in the utility industry, particularly for a high cost, specially manufactured item made by only a limited number of vendors, requiring many additional highly trained welders (who are in short supply). Further, the availability of reasonable financing arrangements to EGU owners in the currently restrictive lending environments can make capital investment in the installation of scrubbers impossible for certain operators. Expenditures of this magnitude in equipment intended to last decades ordinarily require approvals not only from senior management but sometimes also from state regulatory commissions. If EPA's timeline proves over optimistic, as seems likely, the availability of CAIR options through 2014 or 2015 would be a wise step to help assure both compliance and market stability. [EPA-HQ-OAR-2009-0491-2799.1, pp.4-5]
In summary, the WMBAA strongly urges EPA to reconsider the undue restrictions the proposed CATR rule imposes on trading emission allowances. The Association believes that EPA can create a regime that is: (i) less restrictive on trading, (ii) Fully consistent with the court's mandate to consider the effects on downwind states, (iii) achieves the same emission reductions as a "command and control" system buy at a lower cost, and (iv) consistent with ongoing efforts to reduce future GHG emissions. [EPA-HQ-OAR-2009-0491-2799.1, p.5]
Response: 
Thank you for your comments.  EPA is finalizing the air quality-assured trading remedy for the reasons discussed in section VII.A of the preamble to the final Transport Rule.  EPA believes that this program structure, as discussed in section VII.J of the preamble to the final Transport Rule, provides sources with compliance flexibility while meeting statutory requirements and addressing the Court's concerns in the North Carolina decision.  EPA appreciates your deep understanding and analysis of markets, market participants and market signals.  It is not EPA's intention to "materially change [rules] during a program."  In fact, the Transport Rule was proposed and finalized to address the Clean Air Interstate Rule (CAIR) law suits which resulted in the North Carolina decision, and the ultimate remand of CAIR to EPA.  The Court emphasized that the rule was fatally flawed and could not be fixed; rather a re-write addressing the Court's concerns -- which ranged from EPA's lack of authority to use Title IV SO2 allowances to issues with the state budgets and 2015 compliance deadline, among many other points -- was in order.  EPA has painstakingly sought to craft a rule that preserves as much of the flexibility and market-based nature of our previously successful cap and trade programs while hewing to the Court's decision.  As such, the Transport Rule is the CAIR replacement rule, the result of a Court decision remanding a previous rule to EPA.  There is little more we can do to address market uncertainty in the face of a Court decision.  EPA disagrees with the commenter that the remedy approach finalized is more "command and control" than cap and trade (refer again to Section VII.A of the preamble to the final Transport Rule).  EPA is not allowing the carry-over of CAIR allowances for the reasons discussed in section IX of the preamble to the final Transport Rule.  EPA discusses the Transport Rule compliance deadlines in section VII.C of the preamble to the final Transport Rule and why EPA believes the 2014 compliance schedule is reasonable and the number of different compliance options available for sources that choose to reduce emissions.  EPA notes that there are no restrictions per se on trading allowances.  Rather, for compliance with the SO2 trading programs, a source in a group 1 state can only use SO2 allowances allocated to group 1 states.  Likewise a source in a group 2 state can only use SO2 allowances allocated to group 2 states for compliance with the SO2 trading program.  For compliance in the annual NOx and ozone season NOx trading programs, sources may use annual NOx and ozone season allowances, respectively, allocated for any state, even if that state is in a different group for SO2 than the source's state.  Additionally, preamble section VI explains how EPA quantifies and eliminates each individual state's significant contribution and gives independent meaning to the prohibition against upwind states interfering with maintenance in downwind states, weighing both cost and air quality metrics, as the Court suggested.  In order to ensure reductions take place in the upwind state per the Court's direction of the requirements of the statute (CAA Section 110(a)(2)(D)(i)(I)), EPA has put in place assurance provisions, as discussed in section VII.E of the preamble to the final Transport Rule.
Organization: Wolverine Power Supply Cooperative
Comment: 
Wolverine Power Supply Cooperative
The proposed structure of the rule strongly benefits large generators with multiple units at the expense of small generators and stranded units. We believe the allowance markets will be very tight in the early years of the programs, and that large generators will both receive and hoard through banking most of the allowances. Market concentration and possible manipulation will crowd small generators out, and particularly peaking units, like the Sumpter plant, that receive allocations far below their potential weather-related needs. [EPA-HQ-OAR-2009-0491-2825.1 p.4]
Although some restrictions on interstate trading may be required in view of the CAIR decision in North Carolina, EPA's proposed system of very tight budgets combined with 1-year and 3-year variability limits will not result in a robust trading program, but will result in severe uncertainty. First, the variability limits are so low as to essentially prevent significant interstate trading, and second, the compliance mechanism of reconciliation as far as four years in the future will promote hording of allowances and thus no robust trading program. A holder of any excess allowances will not trade them if they may be needed two or four years out when the variability limits are exceeded. We recommend the following to in part alleviate concerns for market concentration: [EPA-HQ-OAR-2009-0491-2825.1 
1. Create a small generator auction pool as described in EPA's Alternative
2, which would guarantee access to the allowance markets for small generators and stranded units. 2. Eliminate the Variability Limits that will provide incentive for hoarding allowances due to the uncertainty of surrender requirements in subsequent years.
3. If the variability limits are retained, the owner-average methodology for the assurance mechanism should be expanded to any group of owners that aggregate on a contractual basis.
4. Provide a safety valve mechanism on allowance prices. 
[EPA-HQ-OAR-2009-0491-2825.1 
Response: 
Thank you for your comments.  EPA disagrees that the proposed structure of the final rule strongly benefits large generators with multiple units at the expense of small generators and stranded units.  For instance, in response to comments, owners and operators have the option to aggregate small units in a state under one Designated Representative (DR) with owners and operators of other units in the state. The common DR approach provides additional flexibility to owners and operators who have only one or a few units in a given state.  See section VII.E in the preamble to the final rule for a detailed discussion of this topic.  In the final Transport Rule, allowances are allocated based on historic heat input.  See section VII.D of the preamble to the final rule for the allocation methodology EPA is finalizing in the FIPs.  Furthermore, in the final Transport Rule, states are provided the opportunity to replace the FIP allowance allocations to sources in their state as early as 2013. See section X of the preamble to the final rule.  In order to address weather-related needs and other variability in the power sector, EPA has established new variability limits in the final Transport Rule to provide sources with flexibility when needed.  These are discussed in section VI.E.  EPA thanks you for your suggestions which we considered thoroughly in a number of the modifications to the final rule we have made.  We believe the rule that we are finalizing is consistent with the decisions of the Court and will ensure the reductions necessary to meet statutory requirements while still providing flexibility for covered sources to comply with the program.
Organization: Xcel Energy Inc.
Comment: 
Xcel Energy Inc.
Xcel Energy supports the most flexible trading approach possible to achieve the greatest reductions at the least cost. As such, Xcel Energy believes that EPA's preferred alternative under CATR is the best of the three options presented. We believe the preferred alternative represents the best, most flexible program of the options proposed by EPA. As we have consistently stated over the years, we support trading to minimize buyer and seller allowance constraints. [EPA-HQ-OAR-2009-0491-2728.1, pp.4-5]
In conclusion, we recommend that the EPA utilize an interstate trading program, eliminate the multi-group trading restrictions, refine the allowance allocations, IPM modeling analysis and incorrect data for our facilities as per our comments, and clarify the penalty provisions for state budget exceedances. Xcel Energy also supports the information provided by the EEI regarding this EPA request as well as the comments of the Class of `85 Regulatory Response Group. [EPA-HQ-OAR-2009-0491-2728.1, p.12]
Response: 
Thank you for your comments. EPA is finalizing the air quality-assured trading remedy for the reasons discussed in section VII A of the preamble to the final Transport Rule.  EPA is maintaining the 2-group SO2 trading programs for reasons discussed in sections VI.B and VI.D of the preamble to the final Transport Rule.  For a discussion on the allowance allocation methodology that EPA is finalizing, see section VII.D of the preamble to the final Transport Rule.  For a discussion on updates to EPA's modeling, please see section V.C of the preamble to the final Transport Rule, as well as the Emission Inventory Final Rule TSD in the docket for the rulemaking.  For clarification of the assurance provisions please see section VII.E of the preamble to the final Transport Rule and the technical support document entitled, Assurance Penalty Level Analysis Final Rule, in the docket for this rulemaking.

V.D.2.a. Applicability/ Opt-in Units

Organization: 8-Hour Ozone State Implementation Plan (SIP) Coalition
Comment: 
8-Hour Ozone State Implementation Plan (SIP) Coalition
Provisions Concerning Cogeneration Units. Coalition members are particularly affected by the provision of the rule that directly impacts our members -- the exemption for cogeneration units.  The Coalition supports the retention of this exemption. [EPA-HQ-OAR-2009-0491-2736.1, p. 2]
EPA requests comment on whether it may be problematic to obtain sufficiently detailed information about unit efficiency and operation back to November 15, 1990 and whether the efficiency and operating standards should be limited to even more recent years by requiring that the standards be met every year starting the later of a date (e.g., January 1) of a more recent year (e.g., 2000, 2005, or 2009) or the date on which the unit first produces electricity.  The Coalition concurs that it may be problematic to obtain the older data, and supports the use of 2005 as the baseline date that should be used as the initial year for which a cogeneration unit must meet efficiency and operating standards.  This five year period closely aligns with existing Title V record retention requirements. [EPA-HQ-OAR-2009-0491-2736.1, p. 2]
Similarly, the Coalition concurs with EPA's concern about whether it may be problematic to obtain sufficiently detailed information about the disposition of a unit's generation (e.g., how much was used on site or by an industrial host and how much was supplied to a utility distribution system for sale) back to November 15, 1990.  The Coalition supports a change to the proposed rule to require that the limit be met every year starting the later of a date (e.g., January 1) of 2005, or the start-up of a unit's combustion chamber.  As expressed above, this five year period is consistent with Title V record retention requirements. [EPA-HQ-OAR-2009-0491-2736.1, pp. 2-3]
EPA requested comments on a potential exclusion from the requirement to meet the operating and efficiency standards for calendar years in which a unit does not operate at all.  The Coalition concurs with this approach.  [EPA-HQ-OAR-2009-0491-2736.1, p. 3]
Under CAIR, each unit had to meet individually the efficiency standard (i.e., the requirement that useful thermal or electrical output be at least a specified percentage of energy input).  In contrast, under the proposed CATR definition of "cogeneration unit," if the cogeneration system of which a topping-cycle unit is a part of meets the efficiency standard on a system-wide basis, then the unit is also deemed to meet that efficiency standard.  The Coalition urges EPA to adopt this same approach for bottoming-cycle units (where useful thermal energy is produced first and then useful power is produced using the resulting waste energy). [EPA-HQ-OAR-2009-0491-2736.1, p. 3]
Provisions Concerning the Opting-In of Non-EGUs to the Transport Rule Trading Program  Coalition members are also directly affected by the provisions of the TR which allow certain non-EGUs to opt in to a state's trading program, for the purpose of cost-effectively generating and selling emission allowances.  As a general comment on the opt-in provision, the Coalition notes that there have been similar opt-in provisions in the Acid Rain and NOx SIP Call programs, and that they have not been widely used.  We believe that the primary reason that the opt-in provisions have not been employed is that petrochemical and refining facilities across the nation have been subject to numerous federal and state regulations over the past 40 years, and that the most cost-effective reductions from our sector have already occurred.  We also note that the stringent nature of the opt-in provisions act as a disincentive to our members in those rare cases in which they might generate cost-effective emission reductions.  However, we support retention of the opt-in provision concept, and offer our comments on the three elements of the rule for which EPA requested specific comments.  [EPA-HQ-OAR-2009-0491-2736.1, p. 3]
First, EPA requests commenters to explain how much interest they believe owners and operators of non-covered sources would have in using these proposed provisions to opt into one or more of the proposed trading programs and what types of sources would be most likely to opt in.  As noted above, the Coalition members' experience, and EPA's own analysis, shows that there are few non-EGU sources that can, after implementing numerous regulatory programs, make reductions in SO2 or NOx more cost-effectively than some EGU sources.  (We note that in the 8-County Houston/Galveston/Brazoria ozone nonattainment area, because of extensive state regulatory programs, highly cost effective reductions are also no longer available to EGUs.)  We believe participation will continue to be low, but that it is important to retain the opt-in provisions for those cases in which an environmental benefit can be achieved in a more cost-effective manner. [EPA-HQ-OAR-2009-0491-2736.1, p. 3]
Second, EPA requests comment on whether it is necessary to take steps to identify in this application process whether emissions reductions identified by these facilities are reductions units would not have made for other reasons unrelated to the opt in.  The Coalition believes new provisions to this effect would not serve an air quality benefit, and would be both speculative and ultimately unenforceable.  Facilities make decisions about emission reduction programs for a multiplicity of reasons, and it is neither possible nor appropriate to ask the facility or the EPA to parse them as they review an opt-in application.  The test of an appropriate opt-in is whether an emissions reduction program achieved a tangible air quality benefit, was not duplicative of a required state or federal reduction program, and was cost-effective enough to generate a credit. [EPA-HQ-OAR-2009-0491-2736.1, pp. 3-4]
EPA later requests comment on whether, in the circumstance described above, the total emissions reduction still may be sufficient to satisfy the interstate transport issue if such reductions were not anticipated in state budgets. In other words, even if emissions reductions would have happened in the absence of the program, they may still be reductions that alleviate attainment or maintenance issues in downwind states.  The Coalition concurs with this statement for the reasons articulated above. [EPA-HQ-OAR-2009-0491-2736.1, p. 4]
Third, EPA requests comment on whether the baseline emission rate used to determine the allocations for each opt-in unit should be multiplied by 70 percent before EPA compares that rate to the unit's most stringent applicable emissions limitation in order to determine which is lower. The lower emission rate would then be used in calculating the opt-in unit's allocation.  EPA also requests comment on whether the allocation for an opt-in unit during Phase II of the proposed SO2 Group 1 85 Planned units, as identified in the EGU inventory and included in IPM modeling projections, comprise units that had broken ground or secured financing and were expected to be online by the end of 2011 trading program should be reduced by 45 percent, reflecting the average percent reduction in state SO2 Group 1 budgets from Phase I to Phase II. The Coalition supports the elimination of this provision.  As described above, the test of an appropriate opt-in is whether an emissions reduction program achieved a tangible air quality benefit, was not duplicative of a required state or federal reduction program, and was cost-effective enough to generate a credit.  A multiplier at any level will reduce the number of otherwise eligible units and facilities that can opt in to the program. [EPA-HQ-OAR-2009-0491-2736.1, p. 4]
Response: 
See section VII.B of the preamble.
Organization: AES Corporation (AES)
Comment: 
AES Corporation (AES)
Inclusion of contracted cogeneration is particularly troubling for Independent Power Production ("IPP") facilities with extended power purchase agreements ("PPA") without provisions to recapture compliance costs. Facilities with long term PPAs should be exempt from the Transport Rule until the PPA allows for recovery of compliance cost or the contract expiration date. This was the intent of the 1990 Congressional exemption of Title IV Acid Rain Program (for well controlled facilities) and should remain true for this rulemaking. [EPA-HQ-OAR-2009-0491-2791, p.5]

The Transport Rule SO2 regulations essentially remove an exemption that Congress specifically afforded to IPPs and qualifying facilities (QF) under the Title IV Acid Rain Program in the 1990 Clean Air Act Amendments for facilities that had long term PPA in place. They have no way of passing these new compliance costs onto the power purchaser under the fixed price formula contracts that they entered prior to the enactment of the 1990 Title IV Clean Air Act Amendments. The statutory exemption from the SO2 reduction requirements of the Acid Rain Program was one of the important factors that investors considered when financing the construction of these plants. [EPA-HQ-OAR-2009-0491-2791, p.5]

We request that EPA grant IPPs and Qualifying Facilities (QFs) an exemption from the Transport Rule SO2 requirements substantially similar to the IPP and QF exemptions provided under the Acid Rain Program. The well controlled IPPs and QFs continue to be penalized even though they typically emit far less SO2 than uncontrolled older electric generating stations. There is nothing to indicate that it was the intent of congress to sunset this provision. As noted on 70 Fed. Reg. 72272, "Congress clearly did not choose a policy to regularly revisit and revise these allocations, believing that its allocations methodology for Title IV allowances would be appropriate for future time periods." By implication, it was the intent of Congress to maintain the subject exemption as long as the basis for the exemption remained unchanged (i.e., plants have preexisting contacts for their power with no provisions to pass through additional compliance costs). [EPA-HQ-OAR-2009-0491-2791, pp.5-6]

Accordingly, we request that EPA grant IPPs and QFs an exemption from compliance with the Transport Rule SO2 requirements until such time as their contracts expire. After which, the units can be appropriated with the proper opt in allotment of allowances and operate in the open market similar to every other market or regulated facility. An exemption for IPPs and QFs under the Transport Rule would ensure that these plants are not unfairly penalized for entering into fixed price power contracts prior to the enactment of the 1990 Clean Air Act Amendments. [EPA-HQ-OAR-2009-0491-2791, p.6]
Response: 
See section VII.B of the preamble.  EPA rejects the commenter's position that IPP and QF facilities with long-term power purchase contracts in place since 1990 should be exempt from the Transport Rule trading programs.  While these facilities have an exemption under the Acid Rain Program established in 1990 under CAA title IV, EPA maintains that the commenter failed to provide a basis for establishing such an exemption under the final Transport Rule.  The Acid Rain Program began in 1995, and the exemption for these facilities provided a transition for them from non-regulation, or limited regulation, of their emissions to more stringent regulation of their emissions under CAA title IV.  In effect, the commenter claimed that CAA title IV created a permanent exemption for these facilities (until certain changes occur in their power purchase contracts) covering not only the Acid Rain Program, but also in all trading programs covering the electricity generation sector.  However, neither the statutory language nor the legislative history of CAA title IV supports the commenter's claim that Congress intended that the IPP and QF exemptions apply in trading programs established after the Acid Rain Program that were had not even been proposed, but less implemented, when CAA title IV was passed.  Further, the circumstances under which the Acid Rain Program exemption was established have changed.  The Acid Rain Program was one of the first programs to require significant emission reductions throughout the electricity generation sector.  An exemption for IPPs and QFs with such long-term power contracts was not adopted in subsequent trading programs covering electricity generation, i.e., the NOx Budget Trading Program and the CAIR trading programs.  Also, the current market for electricity is much broader and less geographically segmented than it was in 1990, before the introduction of significant utility rate deregulation and electric industry restructuring.  Under these circumstances, EPA maintains that an exemption providing a transition from non- or limited emissions regulation to more stringent regulation is not appropriate since this category of units is already subject to emissions regulation.  In addition, an exemption for IPPs and QFs with long-term power purchase agreements could result in shifting of generation and emissions from units regulated under the Transport Rule to these units (the potential for which is enhanced by the existence of a broader, less segmented electricity market).  Such a shift could threaten achievement of elimination of states' significant contribution and interference with maintenance, which is the goal of the Transport Rule.  Although the exemption of any portion of the electricity generation sector creates the potential for generation shifting, the greater the number and scope of the exemptions, the greater the likelihood and likely magnitude of the potential generation shifting.  After the balancing the commenter's claimed rationale for the requested exemption and the potential adverse effect of such an exemption, EPA rejects the commenter's position.  EPA also notes that, although this category of units has been covered by the NOx Budget Trading Program (beginning in 2003) and the CAIR trading programs (beginning in 2009), the commenter failed to provide any information showing that any units in this category have suffered any financial hardship as a result of not being exempt from these trading programs.  
Organization: Alcoa Power Generating Inc. - Warrick Power Plant
Comment: 
Alcoa Power Generating Inc. - Warrick Power Plant
APGI supports provisions permitting non-EGUs that can cost-effectively reduce their emissions to opt-in and participate in the trading program. However, the rule should provide a methodology to fairly allocate credits to non-EGUs that opt in. Non-EGUs that opt in benefit the overall program, by widening the pool of market participants and ensuring additional emission reductions. Therefore, EPA should encourage their participation by ensuring equity in credit distribution and trading. In addition, EPA requests comment (7SFR45308-45309) with respect to reducing an opt-in source allocations by 70% for NOx and 45% for S02. If an opt-in has emissions of NO x or S02 it is willing to reduce, and which reduction will improve air quality, EPA has correctly concluded that the reduction of opt-in source allocations by the NOx and 802 reductions· would serve to lower the number .of facilities that would opt into the program. APGI thus encourages EPA not to reduce opt-in allocations by any of the reductions for which it has requested comment. [EPA-HQ-OAR-2009-0491-3648,p.3]
The definition of cogeneration unit is unnecessarily restrictive and reduces incentives to use excess steam efficiently. The proposed rule would require EGUs with capacities greater than 25 MWe in the covered states to reduce emissions of SO2, NOX. and ozone season NOX. An exception is made for certain cogeneration units, but the definition of these units is unfairly restrictive and discourages efficient use of resources. [EPA-HQ-OAR-2009-0491-3648,p.4]
In order to meet the requirements for exemption, a unit 'must operate as part of a cogeneration system.' EPA defines this as it an integrated group of equipment at a source (including a boiler or combustion turbine, and a steam turbine generator) designed to produce useful thermal energy for industrial, commercial, heating, or cooling purposes and electricity through the sequential use of energy.' 75 FR 45306. The definition in the proposed CATR is similar to the cogeneration definition contained in the NSPS for utility boilers, i.e.
'Cogeneration, also known as 'combined heat and power,' means a steam generating unit that simultaneously produces both electric (or mechanical) and useful thermal energy from the same primary energy source.' [EPA-HQ-OAR-2009-0491-3648,p.4]
CATR should not include the provisions that cogeneration units must also meet, with respect to topping and bottom cycle units. EPA should instead use the long-standing definition of cogenerator that has been consistently used under the CAA, such as the definition of cogenerator contained in 40 CFR 64, Subpart Da. [EPA-HQ-OAR-2009-0491-3648, pp.4-5]
Response: 
With respect to opt-in units, see section VII.B of the preamble. 
With respect to cogeneration units, the commenter claims that all such units are efficient and should be exempt from the Transport Rule trading programs.  In the final rule EPA exempts those cogeneration units that meet certain requirements.  First, the units must meet certain operating and efficiency requirements, and the commenter failed to show that these requirements are unreasonable.  EPA believes that it is reasonable to limit the cogeneration unit exemption to units that demonstrate their efficiency.  Second, the units must meet the electricity sales limitation.  Those units that sell less than the electricity sales limitation are treated as industrial, rather than electric generation, units and are exempt because the final rule is aimed at the electric generation sector. The commenter failed to show that either of these requirements is unreasonable.  Finally, if all cogeneration units were excluded from the trading programs, utilization for electric generation, and the resulting emissions, could shift to those units from covered units because of the high level of integration of the electric generation, transmission, and distribution system (which has increased with the significant restructuring and deregulation of electric utilities) and thereby threaten achievement of elimination of states' significant contribution and interference with maintenance, which is the goal of the Transport Rule.  Although the exemption of any portion of the electricity generation sector creates the potential for generation shifting, the greater the number and scope of the exemptions, the greater the likelihood and likely magnitude of the potential generation shifting.  After the balancing the commenter's claimed rationale for the requested exemption and the potential adverse effect of such an exemption, EPA rejects the commenter's position and maintains that the approach in the final rule is reasonable.
Organization: Algonquin Power Windsor Locks, LLC
Comment: 
Algonquin Power Windsor Locks, LLC
The proposed regulations should exempt combined heat and power cogeneration facilities using combustion turbines. It is well known that these facilities operate the most energy efficient fuel burning equipment with the lowest amount of NOx emissions per unit of utilized energy output. There is no justification to require these facilities to further reduce NOx emissions. [EPA-HQ-OAR-2009-0491-2779.1, p.1]
Response: 
See section VII.B of the preamble.  EPA rejects the commenter's claim that all cogeneration units with combustion turbines should be exempt because they are "efficient" and "low emitting".  In the final rule EPA exempts those cogeneration units that meet certain requirements.  First, the units must meet certain operating and efficiency requirements, and the commenter failed to show that these requirements are unreasonable.  EPA believes that it is reasonable to limit the exemption to units that demonstrate their efficiency.  Second, the units must meet the electricity sales limitation. Those units that sell less than the electricity sales limitation are treated as industrial, rather than electric generation, units and are exempt because the final rule is aimed at the electric generation sector. The commenter does not explain its apparent opposition to the sales limitation, much less show that it is unreasonable.  Further, the commenter failed to specify what "low" emission rates are achieved by cogeneration units with combustion turbines, but, even assuming that they have relatively low emission rates, it is mass or tons of emissions (not emission rates) that contribute to a state's significant contribution or interference with maintenance, which the final rule is aimed at eliminating.  In addition, if all cogeneration units with combustion turbines were excluded from the trading programs, utilization for electric generation, and the resulting emissions, could shift to those units from covered units because of the high level of integration of the electric generation, transmission, and distribution system (which has increased with the significant restructuring and deregulation of electric utilities) and thereby threaten achievement of elimination of states' significant contribution and interference with maintenance, which is the goal of the Transport Rule.   Although the exemption of any portion of the electricity generation sector creates the potential for generation shifting, the greater the number and scope of the exemptions, the greater the likelihood and likely magnitude of the potential generation shifting.  After the balancing the commenter's claimed rationale for the requested exemption and the potential adverse effect of such an exemption, EPA rejects the commenter's position and maintains that the approach in the final rule is reasonable.
Organization: American Chemistry Council
Comment: 
American Chemistry Council
ACC urges EPA to revise the recordkeeping requirements from a twenty-year look back period to a five-year look back period, which aligns with recordkeeping requirements for Title V permits and other programs. EPA should be rewarding the use of energy-efficient technologies, such as cogeneration units, rather than subjecting them to onerous requirements under this rule. [EPA-HQ-OAR-2009-0491-2716.1, p.1]
ACC is particularly concerned about the adverse impact the rule will have on cogeneration units. Chemical manufacturing is the largest industrial sector utilizing cogeneration units. EPA should also continue to exclude cogeneration units that supply 1/3 or less of their electricity generated to the public grid. Furthermore, ACC believes that all gas-fired cogeneration units should be completely exempted from the rule, as these are the highest-efficiency, lowest-emitting units. [EPA-HQ-OAR-2009-0491-2716.1, p.1]
However, we do support the provision that allows non-EGU units to opt-into the program. We believe that industrial facilities should have the opportunity, based on their own election, to join the trading program. [EPA-HQ-OAR-2009-0491-2716.1, p.2]
A number of ACC members have cogeneration units onsite, and these units co-produce electricity and steam which result in a higher energy efficiency for the units than a traditional boiler or buying electricity from the grid. Accordingly, these units should be rewarded under the Transport Rule. [EPA-HQ-OAR-2009-0491-2716.1, p.2]
A. Cogeneration Unit Exemptions
ACC supports an exemption from the Transport Rule for cogeneration units that supply no more than one-third of its potential electric output capacity, or 219,000 MWh, whichever is greater, to any utility power distribution system for sale. In addition, we believe all gas-fired cogeneration units should not be subject to the Transport Rule. These units typically are more efficient electricity and steam generators than all other stand-alone steam or electricity generators combusting hydrocarbons for fuel. In addition, these units are short-stack, low plume-rise sources with emissions that do not have long-range transport impacts like large utility units with high stacks and buoyant plumes. [EPA-HQ-OAR-2009-0491-2716.1, p.3]
B. Qualification and Recordkeeping
EPA is proposing that a unit can qualify as a "cogeneration unit" if it meets the efficiency and operating standards every year starting the later of November 15, 1990 or the date on which the unit first produces electricity. EPA is requesting comment on whether it may be problematic to obtain sufficiently detailed information about unit efficiency and operation back to November 15, 1990 and whether the efficiency and operating standards should be limited to even more recent years by requiring that the standards be met every year starting the later of a date (e.g., January 1) of a more recent year (e.g., 2000, 2005, or 2009) or the date on which the unit first produces electricity. (75 Fed. Reg. at 45307.) [EPA-HQ-OAR-2009-0491-2716.1, p.3]
In many cases, cogeneration facilities are older energy systems that are integrated with large industrial complexes. Data availability is limited to the type of data collection system installed at each respective facility. These older data collection systems have not always captured the required data to perform these assessments electronically. This lack of electronic data would necessitate evaluating this data by hand, if hardcopy charts and graphs are still available. [EPA-HQ-OAR-2009-0491-2716.1, p.3]
Many companies have record retention policies that, consistent with other regulatory guidance, require records be kept for five years. For example, Title V Permit recordkeeping requirements and recordkeeping requirements contained in the CAIR, 40 CFR §96.106(e), require records to demonstrate compliance for a period of five years. [EPA-HQ-OAR-2009-0491-2716.1, p.3]
ACC recommends that both the unit efficiency and operating standards, and the electricity sales data be limited to more recent years by requiring that the unit efficiency and operation standards and the sales limit be met annually starting with the later of November 15, 2005 or the start-up of a unit's combustion chamber. Maintaining records dating back to 1990 is neither consistent nor reflective of current industry operations. Many cogeneration and combustion devices have been upgraded with state-of-the-art NOX control technology such as low NOx burners, SCR, and flue gas recirculation to reduce emissions. Consistent with current regulatory recordkeeping requirements, applicability determinations for this regulation must be evaluated based on reasonably current data rather than historical data. Therefore, we recommend that EPA allow applicability determinations based on the last five years' worth of data, and require records to be kept for the past five years. [EPA-HQ-OAR-2009-0491-2716.1, pp.3-4]
Similarly, those cogeneration units that qualify for the proposed exemption from the Transport Rule requirements should also have a five-year recordkeeping requirement. [EPA-HQ-OAR-2009-0491-2716.1, p.4]
ACC also agrees that EPA should exclude from the requirement to meet the operating and efficiency standards for calendar years during which a unit does not operate at all. [EPA-HQ-OAR-2009-0491-2716.1, p.4]
C. Efficiency Standard
Under CAIR, each unit had to meet individually the efficiency standard (i.e., the requirement that useful thermal or electrical output be at least a specified percentage of energy input). In contrast, under the proposed Transport Rule definition of "cogeneration unit," if the cogeneration system of which a topping-cycle unit is a part of meets the efficiency standard on a system-wide basis, then the unit is also deemed to meet that efficiency standard. ACC urges EPA to adopt this same approach for bottoming-cycle units (where useful thermal energy is produced first and then useful power is produced using the resulting useful (waste) energy). [EPA-HQ-OAR-2009-0491-2716.1, p.4]
Response: 
See section VII.B of the preamble.  EPA rejects the commenter's claim that all gas-fired cogeneration units should be exempt because they are "efficient" and "low emitting".  In the final rule EPA exempts those cogeneration units that meet certain requirements.  First, the units must meet certain operating and efficiency requirements, and the commenter failed to show that these requirements are unreasonable.  EPA believes that it is reasonable to limit the exemption to units that demonstrate their efficiency.  Second, the units must meet the electricity sales limitation. Those units that sell less than the electricity sales limitation are treated as industrial, rather than electric generation, units and are exempt because the final rule is aimed at the electric generation sector. The commenter does not explain its apparent opposition to the sales limitation, much less show that it is unreasonable.  Further, while some of these units may have relatively low emission rates, it is mass or tons of emissions (not emission rates) that contribute to a state's significant contribution or interference with maintenance, which the final rule is aimed at eliminating.  The commenter fails to provide any support for its claim that the emissions from these units are from short stacks and in low rise plumes and therefore are not part of a state's significant contribution or interference with maintenance.  EPA rejects this factual claim as speculative and unsupported.  Finally, if all gas-fired cogeneration units were excluded from the trading programs, utilization for electric generation, and the resulting emissions, could shift to those units from covered units because of the high level of integration of the electric generation, transmission, and distribution system (which has increased with the significant restructuring and deregulation of electric utilities) and thereby threaten achievement of elimination of states' significant contribution and interference with maintenance, which is the goal of the Transport Rule.  Although the exemption of any portion of the electricity generation sector creates the potential for generation shifting, the greater the number and scope of the exemptions, the greater the likelihood and likely magnitude of the potential generation shifting.  After the balancing the commenter's claimed rationale for the requested exemption and the potential adverse effect of such an exemption, EPA rejects the commenter's position.
Organization: American Forest & Paper Association (AF&PA)
Comment: 
American Forest & Paper Association (AF&PA)
Second, we agree with EPA's proposed approaches to defining "cogeneration units" that are also exempt from the Transport Rule even though they generate some electricity for sale. We support allowing for voluntary "opt-ins" under the program but we believe the conditions EPA proposes are too stringent and will discourage participation. [EPA-HQ-OAR-2009-0491-2643.1, p.2]
approaches in the final rule. We also support EPA's decision to exempt "waste incineration units" from the proposed rule. [EPA-HQ-OAR-2009-0491-2643.1, p.2]
A. EPA's Approach to Defining "Cogeneration Units"
The CAIR rule out of which the Transport Rule arose exempted cogeneration units from regulation as EGUs. Roughly speaking, a unit would be a cogeneration unit if it (1) generated both electricity and useful heat (2) met certain thermal efficiency standards and (3) did not sell more than 1/3 of its potential electric output to the grid. See 70 Fed. Reg. 25277 (May 12, 2005). [EPA-HQ-OAR-2009-0491-2643.1, p.3]
EPA proposes to continue this exclusion in the Transport Rule, including the continued use of a potential output approach. AF&PA supports this decision. We are particularly pleased that EPA also proposes to continue the exclusion of biomass from thermal efficiency calculations. As the Agency knows from the rulemaking that established this exclusion in 2007, 72 Fed. Reg. 59195 (Oct. 17, 2007), that reform was necessary to avoid a major unintended negative impact on the use of biomass for fuel in our industry. We urge EPA to make clear that its definition of biomass includes spent pulping liquor (black liquor). EPA clearly intended to include it, and the issue is important enough to be reflected in the regulatory text. See 72 Fed. Re. 59190, 59194 (October 19, 2007).  [EPA-HQ-OAR-2009-0491-2643.1, pp.3-4]
While we agree with the cogeneration exclusion, AF&PA believes that the procedures to qualify as a cogenerator could be further simplified. [EPA-HQ-OAR-2009-0491-2643.1, p.4]
[For additional comments pertaining to "Cogeneration Units", see pages 3-5 of this comment.]
B. EPA Should Make it Easier for Sources to Opt in to the Transport Rule
As with CAIR, EPA proposes to allow sources that are not subject to the Transport Rule to "opt in" to Transport Rule coverage. To do this, sources would have to monitor their activity levels and emissions (using Part 75 monitoring) for at least a year to establish a baseline. They could then opt in for a minimum of 4 years at an emission rate that would be the lesser of 70% of their baseline emissions or any lower emission rate required by regulations that had taken effect since the baseline was established. If the source could reduce its emissions below this level, it could generate cap and trade allowances for sale to other sources. [EPA-HQ-OAR-2009-0491-2643.1, pp.5-6]
EPA notes that only a handful of sources have taken advantage of prior opt-in provisions, and asks for comment on that point. AF&PA has long supported the opt-in provisions of CAIR and other rules. We support an opt-in provision for the Transport Rule. However, we do not see much prospect of its widespread use unless EPA makes using it more attractive. We think two specific steps would help. [EPA-HQ-OAR-2009-0491-2643.1, p.6]
First, the requirement for an up-front 30% emission reduction before allowances can be earned is undoubtedly too strict. Voluntary opt-in will only be attractive to a source if it can generate allowances that it can sell for more than the cost of the controls needed to generate them. We are confident based on member input that requiring an initial uncompensated 30% reduction in emissions from baseline will put that goal far out of reach for essentially all our sources. [EPA-HQ-OAR-2009-0491-2643.1, p.6]
Second, as AF&PA has pointed out before, the requirement for Part 75 monitoring is a potent additional discouragement to voluntary opt-in. Even with recent cost-reducing improvements Part 75 CEMs are very expensive, particularly if they are retrofitted in existing units. Because the costs of CEMS tend not to decline as much as output or emissions, the cost of CEMs per ton of emission reduction is much greater for smaller industrial units than for large EGUs. Indeed, the cost of CEMs is likely to be greater than the potential gains from opt-in for many smaller industrial sources, thereby discouraging these units from opting in and thus forfeiting the cost-saving and emission reduction gains from the opt-in program. [EPA-HQ-OAR-2009-0491-2643.1, p.6]
To correct these problems, we recommend that EPA withdraw its proposal to require CEMs for all but the very largest opt-in units, and instead call on States to select monitoring requirement for such units that meet the following tests: the monitoring (a) should be able to detect deliberate violations of emission control requirements; (b) be enforceable with reasonable effort and (c) should be able to quantify annual emissions reductions accurately at an acceptable cost. Acceptable cost should be determined by considering both the likely impact of any inaccuracies on the integrity of the overall CAIR control scheme, and the cost of making monitoring improvements that would avoid these inaccuracies. If necessary, the permitting authority might consider applying a small "discount factor" in the range of 2% to 5% to compensate for any loss in accuracy resulting from the use of alternative monitoring methods. [EPA-HQ-OAR-2009-0491-2643.1, p.6]
C. AF&PA Supports Excluding Waste Incineration Units from the Transport Rule
AF&PA supports EPA's proposal to exclude waste incineration units from the Transport Rule as long as they burn a certain minimum percentage of non-fossil fuel. AF&PA also supports EPA's proposal to reduce the number of years in which that minimum percentage showing must be made. For reasons explained earlier, we believe that the showing should only be required for years during which Transport Rule requirements are in effect. [EPA-HQ-OAR-2009-0491-2643.1, p.7]
AF&PA also requests that EPA invite supplemental comment on this issue after it has promulgated the CISWI rule and the CISWI waste identification rule. Until these rules set the standards for which units are subject to the requirements of CAA §129 and which are not, it will be very difficult to evaluate the significance of EPA's proposed Transport Rule exclusion for incineration units. [EPA-HQ-OAR-2009-0491-2643.1, p.7]
Response: 
See section VII.B of the preamble.  EPA rejects the commenter's suggestion that the fossil-fuel-use limitation in the solid waste incineration unit exemption be limited only to years when the Transport Rule is in effect.  Under the commenter's approach, the owners and operators would not know whether the units were subject to the Transport Rule trading programs until after the first year of the programs was completed.  This would make compliance planning problematic, if not impossible, and would mean that owners and operators would not know whether they should be monitoring and reporting their emissions during the year.   EPA maintains that it is reasonable to base the exemption initially on historical data from a period starting relatively recently and of a length that makes it reasonably representative and then on future data developed on an ongoing basis, as in the final rule.   Further, the commenter failed to explain why a supplemental opportunity for comment is needed in light of the CISWI rulemakings. The commenter failed to assert that there should be any connection between the solid waste incineration unit exemption requirements and CISWI requirements, much less explain why there should be such a connection.
Organization: American Municipal Power, Inc. (AMP)
Comment: 
American Municipal Power, Inc. (AMP)
The 25 MW Threshold Should be Maintained
While the proposed Transport Rule has a 25 MW applicability threshold, EPA is still contemplating including units with a nameplate capacity less than or equal to 25 MW. EPA should not lower the applicability threshold as it would needlessly burden smaller sources for little environmental benefit. According to the Transport Rule's Regulatory Impact Analysis, the current applicability threshold of greater than 25 MW already accounts for sources representing 84% of nationwide SO2 emissions and 73% NOx emissions. Lowering the threshold would add 600 small entities into regulation by the Transport Rule, which, as EPA itself acknowledges, would be burdensome. In fact, according to the EPA, it was the exclusion of such small sources and small entities that supported EPA's conclusion that the Transport Rule did not significantly economically impact small entities. As previously noted, AMP has several member communities that operate units that are less than 25 MW. Subjecting these members to the Transport Rule would have disastrous and financially devastating consequences, would be contrary to EPA's own findings, and would overload already struggling state permitting agencies like Ohio EPA with additional sources. [EPA-HQ-OAR-2009-0491-2678.1, p.3]
Response: 
See sections VII.B and X of the preamble.  The final rule gives states the option of expanding the applicability provisions of the Transport Rule NOx ozone season trading program to include units serving generators with a nameplate capacity of 15 MWe or greater producing electricity for sale.  This is consistent with the approach taken in the NOx Budget Trading Program, where some states elected to include units serving generators with a nameplate capacity of 15 MWe or greater producing electricity for sale. 
Organization: American Petroleum Institute (API)
Comment: 
American Petroleum Institute (API)
Provisions Concerning Cogeneration Units. API members are particularly affected by the provision of the rule that directly impacts our members -- the exemption for cogeneration units. API supports the retention of this exemption, and the definitions and applicability provisions for cogeneration units specified in the rule proposal. [EPA-HQ-OAR-2009-0491-2649.1, p. 2]
EPA requests comment on whether it may also be problematic to obtain sufficiently detailed information about unit efficiency and operation back to November 15, 1990 and whether the efficiency and operating standards should be limited to even more recent years by requiring that the standards be met every year starting the later of a date (e.g., January 1) of a more recent year (e.g., 2000, 2005, or 2009) or the date on which the unit first produces electricity. API concurs that it may be problematic to obtain the older data, and supports the use of 2005 as the baseline date that should be used as the initial year for which a cogeneration unit must meet efficiency and operating standards. This five year period closely aligns with existing Title V record retention requirements. [EPA-HQ-OAR-2009-0491-2649.1, p. 2]
Similarly, API concurs with EPA's concern about whether it may be problematic to obtain sufficiently detailed information about the disposition of a unit's generation (e.g., how much was used on site or by an industrial host and how much was supplied to a utility distribution system for sale) back to November 15, 1990. API supports a change to the proposed rule to require that the limit be met every year starting the later of a date (e.g., January 1) of 2005, or the start-up of a unit's combustion chamber. As expressed above, this five year period is consistent with Title V record retention requirements. [EPA-HQ-OAR-2009-0491-2649.1, p. 2]
EPA requested comments on a potential exclusion from the requirement to meet the operating and efficiency standards for calendar years in which a unit does not operate at all. API concurs with this approach. [EPA-HQ-OAR-2009-0491-2649.1, p. 3]
Under CAIR, each unit had to meet individually the efficiency standard (i.e., the requirement that useful thermal or electrical output be at least a specified percentage of energy input). In contrast, under the proposed CATR definition of ?cogeneration unit,? if the cogeneration system of which a topping-cycle unit is a part of meets the efficiency standard on a system-wide basis, then the unit is also deemed to meet that efficiency standard. API urges EPA to adopt this same approach for bottoming-cycle units (where useful thermal energy is produced first and then useful power is produced using the resulting waste energy). [EPA-HQ-OAR-2009-0491-2649.1, p. 3]
Provisions Concerning the Opting-In of Non-EGUs to the Transport Rule Trading Program. API members are also directly affected by the provisions of the TR which allow certain non-EGUs to opt in to a state's trading program, for the purpose of cost-effectively generating and selling emission allowances. As a general comment on the opt-in provision, API notes that there have been similar opt-in provisions in the Acid Rain and NOx SIP Call programs, and that they have not been widely used. We believe that the primary reason that the opt-in provisions have not been employed is that petrochemical and refining facilities across the nation have been subject to numerous federal and state regulations over the past 40 years, and that the most cost-effective reductions from our sector have already occurred. We also note that the stringent nature of the opt-in provisions act as a disincentive to our members in those rare cases in which they might generate cost-effective emission reductions. However, we support retention of the opt-in provision concept, and offer our comments on the three elements of the rule for which EPA requested specific comments. [EPA-HQ-OAR-2009-0491-2649.1, p. 3]
First, EPA requests commenters to explain how much interest they believe owners and operators of non-covered sources would have in using these proposed provisions to opt into one or more of the proposed trading programs and what types of sources would be most likely to opt in. As noted above, API members' experience, and EPA's own analysis shows that there are few, if any non-EGU sources that can, after implementing numerous regulatory programs, make reductions in SO2 or NOx more cost-effectively than some EGU sources. We believe participation will continue to be low, but that it is important to retain the opt-in provisions for those cases in which an environmental benefit can be achieved in a more cost-effective manner. [EPA-HQ-OAR-2009-0491-2649.1, p. 3]
Second, EPA requests comment on whether it is necessary to take steps to identify in this application process whether emissions reductions identified by these facilities are reductions units would not have made for other reasons unrelated to the opt in. API believes new provisions to this effect would not serve an air quality benefit, and would be both speculative and ultimately unenforceable. Facilities make decisions about emission reduction programs for a multiplicity of reasons, and it is neither possible nor appropriate to ask the facility or the EPA to parse them as they review an opt-in application. The test of an appropriate opt-in is whether an emissions reduction program achieved a tangible air quality benefit, was not duplicative of a required state or federal reduction program, and was cost-effective enough to generate a credit. [EPA-HQ-OAR-2009-0491-2649.1, pp. 3-4]
EPA later requests comment on whether, in the circumstance described above, the total emissions reduction still may be sufficient to satisfy the interstate transport issue if such reductions were not anticipated in state budgets. In other words, even if emissions reductions would have happened in the absence of the program, they may still be reductions that alleviate attainment or maintenance issues in downwind states. API concurs with this statement for reasons articulated above. [EPA-HQ-OAR-2009-0491-2649.1, p. 4]
Third, EPA requests comment on whether the baseline emission rate used to determine the allocations for each opt-in unit should be multiplied by 70 percent before EPA compares that rate to the unit's most stringent applicable emissions limitation in order to determine which is lower. The lower emission rate would then be used in calculating the opt-in unit's allocation. EPA also requests comment on whether the allocation for an opt-in unit during Phase II of the proposed SO2 Group 1 85 Planned units, as identified in the EGU inventory and included in IPM modeling projections, comprise units that had broken ground or secured financing and were expected to be online by the end of 2011 trading program should be reduced by 45 percent, reflecting the average percent reduction in state SO2 Group 1 budgets from Phase I to Phase II. API supports the elimination of this provision. As described above, the test of an appropriate opt-in is whether an emissions reduction program achieved a tangible air quality benefit, was not duplicative of a required state or federal reduction program, and was cost-effective enough to generate a credit. A multiplier at any level will reduce the number of otherwise eligible units and facilities that can opt in to the program. [EPA-HQ-OAR-2009-0491-2649.1, p. 4]
Response: 
See section VII.B of the preamble.
Organization: ARIPPA
Comment: 
ARIPPA
A. The ARIPPA facilities should not be subject to the Proposed Rule, because EPA has not justified a finding of significant contribution as to these facilities.  
In developing an approach for controlling emissions under the Proposed Rule, EPA considered emission estimates for a variety of sources, including "EGUs, non-EGU point sources, stationary nonpoint sources, onroad mobile sources, and nonroad mobile sources." See 75 Fed. Reg. 45238. This analysis confirmed that multiple source categories are responsible for significant generation of nitrous oxide ("NOx") and sulfur dioxide ("SO2") emissions, relative to the total emission inventories of the affected states. EPA nonetheless concluded that the objectives of the Proposed Rule can most cost effectively be achieved by regulating only EGUs. However, EPA's categorization of sources for purposes of the Proposed Rule is inconsistent with the objectives stated by EPA for the Proposed Rule, and results in distinctions in proposed applicability of the regulation that are not supported by EPA's analysis. [EPA-HQ-OAR-2009-0491-2794.1, p.3]  
Specifically, the Proposed Rule applies to any stationary fossil fuel-fired boiler or combustion turbine meeting the definition of EGU under the Proposed Rule. 1  Importantly, the Proposed Rule does not distinguish among types of EGUs, on the basis of emissions characteristics, fuel source, operational design, emissions control options, or any other criteria. In this way, the Proposed Rule at once eliminates from regulation numerous significant NOx and SO2 emission sources based on categorical distinctions, while at the same time establishing a "one-size-fits-all" approach to evaluating EGUs under the Proposed Rule. See 75 Fed. Reg. 45272 ("EPA determined for specific cost per ton thresholds, the emissions reductions that would be achieved in a state if all EGUs in that state used all emission controls and emission reduction measures available at that cost threshold" (emphasis added)). EPA's proposed approach of regulating all EGUs under the Proposed Rule, without giving any consideration to significant distinguishing characteristics among those EGUs, is inappropriate, and results in arbitrary applicability determinations. Indeed, for the reasons discussed below, the ARIPPA facilities are fundamentally different from traditional EGUs in ways that distinguish the ARIPPA plants from other EGUs to the same extent that unregulated non-EGUs are distinguished by EPA. Therefore, the ARIPPA facilities should not be subject to the Proposed Rule. [EPA-HQ-OAR-2009-0491-2794.1, p.3]
[For additional comments pertaining to ARIPPA facilities not being subject to the Proposed Rule, see pages 3-7 of this comment.]
This "one-size-fits-all" approach cannot appropriately be applied to the ARIPPA facilities, which are fundamentally different from traditional EGUs, due to their use of CFB technology. As detailed above, this technology's unique characteristics make it infeasible  -  in terms of both technology and economics  -  for the ARIPPA plants to achieve the emission reduction requirements in the Proposed Rule, as can traditional EGUs. Additionally, the ARIPPA facilities are generally required to combust coal refuse, at least as a primary fuel component, in accordance with contractual and other legal requirements, which, together with the technological limitations inherent in CFB technology, prevent the ARIPPA facilities from simply engaging in fuel switching as a means of reducing SO2 emissions. [EPA-HQ-OAR-2009-0491-2794.1, p.20]
For these reasons, the ARIPPA facilities are more closely related to non-EGUs, such as biomass units, which EPA clearly distinguishes from traditional EGUs in the Proposed Rule on the basis that non-EGUs cannot achieve comparable cost effective emissions reductions. Accordingly, EPA's analysis as reflected in the Proposed Rule does not support a finding that the ARIPPA facilities significantly contribute to nonattainment in downwind states, nor that emissions from ARIPPA facilities can be cost effectively controlled. [EPA-HQ-OAR-2009-0491-2794.1, p.20]

1. According to the Proposed Rule, the following units would qualify as EGUs subject to the Transport Rule: "[a]ny stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine serving at any time, since the later of November 15, 1990 or the start-up of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe producing electricity for sale." 75 Fed. Reg. 45372. [EPA-HQ-OAR-2009-0491-2794.1, p.3]
Response: 
See section VII.B of the preamble.  EPA rejects the commenter's approach of separating units using one combustion technology -- i.e., circulating fluidized bed boilers combusting waste coal -- to generate electricity for sale from units using other types of combustion technology -- such as steam boilers and combined cycle combustion turbines -- to generate electricity for sale.  EPA maintains that it is reasonable to consider the electricity generation sector as a whole in determining the cost of available emission reductions and in determining a state's significant contribution and interference with maintenance.  In past trading programs (such as the Acid Rain Program, NOx Budget Trading Program, and CAIR trading programs), EPA has taken the general approach of regulating the entire electricity generation sector, rather than treating the different combustion technologies separately.  Further, if units with different combustion technologies were treated differently for purposes of regulating their emissions, the highly integrated nature of electricity generation, transmission, and distribution system (which has increased with the significant restructuring and deregulation of electric utilities) could result in shifting of generation and emissions to those units whose emissions were unregulated from those units whose emissions are regulated and could thereby threaten achievement of elimination of states' significant contribution and interference with maintenance, which is the goal of the Transport Rule.  Although the exemption of any portion of the electricity generation sector creates the potential for generation shifting, the greater the number and scope of the exemptions, the greater the likelihood and likely magnitude of the potential generation shifting.  After the balancing the commenter's claimed rationale for the requested exemption and the potential adverse effect of such an exemption, EPA rejects the commenter's position and maintains that EPA's approach of regulating emissions from essentially the entire electricity generation sector -- with a few, limited exemptions, e.g., for certain cogeneration units and solid waste incineration units -- is consistent with the goal of the Transport Rule.
The commenter claimed that its members' facilities "are more closely related to non-EGUs, such as biomass units".  However, like its members' facilities (which, of course, burn fossil fuel (i.e., coal)), biomass units that serve a generator with a nameplate capacity greater than 25 MWe producing electricity for sale and burn any amount of fossil fuel are subject to the Transport Rule trading programs, unless the requirements of the cogeneration unit or solid waste incineration unit exemption are met. 
The commenter claimed, without support, that it is "infeasible -- in terms of both technology and economics --"for its members' facilities to "achieve the emission reduction requirements" in the Transport Rule.  In particular, the commenter asserted, without citing any support, that  coal refuse-fired CFB units do not utilize [dry scrubber] technology", which is used to reduce SO2 emissions.   The commenter said little about the availability of  NOX control technology for CFB units except to assert that, if limestone injection is increased to achieve greater SO2 reductions , NOX emissions would likely increase.  EPA rejects the commenter's claims as unsupported.   In fact, contrary to the commenter's assertions, a number of circulating fluidized bed boilers in EPA's inventory, including some combusting waste coal, have dry scrubbers and selective non-catalytic reduction (SNCR) , which is used to reduce NOX emissions.  (See table below.) Moreover, the final Transport Rule allows the use of alternative compliance methods, including the use of allocated allowances supplemented by allowances purchased on the allowance market.  The commenter failed to provide information about the costs of alternative compliance methods (such as the use of allowances) as compared with its members' other costs and revenues.   EPA also notes that, although this category of units has been covered by the CAIR trading programs (beginning in 2009), the commenter failed to provide any information showing that any units in this category have suffered any financial hardship as a result of not being exempt from this trading program.  
Circulating fluidized bed coal units with scrubbers, SCRs, and/or SNCRs as of 2010 (NEEDS v.4.10 PTox Database)
Plant Name
State
Capacity (MW)
NEEDS ID
ORIS
Boiler
Plant Type
Modeled Fuels
Firing
Scrubber?
Scrubber On-line Year
SCR or SNCR?
SNCR On-line Year
ACE Cogeneration Facility
California
                                                                            101
10002_B_CFB
                                                                          10002
CFB
Coal Steam
Bituminous
FBC
 
 
SNCR
                                                                           2000
Rio Bravo Jasmin
California
                                                                             33
10768_B_CFB
                                                                          10768
CFB
Coal Steam
Petroleum Coke
FBC
 
 
SNCR
                                                                           1989
Rio Bravo Poso
California
                                                                             33
10769_B_CFB
                                                                          10769
CFB
Coal Steam
Petroleum Coke
FBC
 
 
SNCR
                                                                           1989
Nucla
Colorado
                                                                            100
527_B_1
                                                                            527
1
Coal Steam
Bituminous
FBC
 
 
SNCR
                                                                           1900
Cedar Bay Generating LP
Florida
                                                                             83
10672_B_CBA
                                                                          10672
CBA
Coal Steam
Bituminous
FBC
 
 
SNCR
                                                                           1994
Cedar Bay Generating LP
Florida
                                                                             83
10672_B_CBB
                                                                          10672
CBB
Coal Steam
Bituminous
FBC
 
 
SNCR
                                                                           1994
Cedar Bay Generating LP
Florida
                                                                             83
10672_B_CBC
                                                                          10672
CBC
Coal Steam
Bituminous
FBC
 
 
SNCR
                                                                           1994
Northside Generating Station
Florida
                                                                            275
667_B_1
                                                                            667
1
Coal Steam
Petroleum Coke
FBC
Dry Scrubber
                                                                           2002
SNCR
                                                                           2002
Northside Generating Station
Florida
                                                                            275
667_B_2
                                                                            667
2
Coal Steam
Petroleum Coke
FBC
Dry Scrubber
                                                                           2002
SNCR
                                                                           2002
Marion
Illinois
                                                                            120
976_B_123
                                                                            976
123
Coal Steam
Waste Coal
FBC
 
 
SNCR
                                                                           2003
H L Spurlock
Kentucky
                                                                            268
6041_B_3
                                                                           6041
3
Coal Steam
Bituminous
FBC
 
 
SNCR
                                                                           2005
H L Spurlock
Kentucky
                                                                            268
6041_B_4
                                                                           6041
4
Coal Steam
Bituminous
FBC
 
 
SNCR
                                                                           2008
Rodemacher
Louisiana
                                                                            330
6190_B_3A
                                                                           6190
3A
Coal Steam
Petroleum Coke
FBC
 
 
SNCR
                                                                           2009
Rodemacher
Louisiana
                                                                            330
6190_B_3B
                                                                           6190
3B
Coal Steam
Petroleum Coke
FBC
 
 
SNCR
                                                                           2009
AES Warrior Run Cogeneration Facility
Maryland
                                                                            180
10678_B_BLR1
                                                                          10678
BLR1
Coal Steam
Bituminous
FBC
 
 
SNCR
                                                                           2000
WPS Power Niagara
New York
                                                                             53
50202_B_1
                                                                          50202
1
Coal Steam
Bituminous
FBC
 
 
SNCR
                                                                           2000
Cambria Cogen
Pennsylvania
                                                                             44
10641_B_B1
                                                                          10641
B1
Coal Steam
Waste Coal
FBC
 
 
SNCR
                                                                           1998
Cambria Cogen
Pennsylvania
                                                                             44
10641_B_B2
                                                                          10641
B2
Coal Steam
Waste Coal
FBC
 
 
SNCR
                                                                           1998
Colver Power Project
Pennsylvania
                                                                            110
10143_B_ABB01
                                                                          10143
ABB01
Coal Steam
Waste Coal
FBC
 
 
SNCR
                                                                           1995
Foster Wheeler Mt Carmel Cogen
Pennsylvania
                                                                             43
10343_B_SG-101
                                                                          10343
SG-101
Coal Steam
Waste Coal
FBC
Dry Scrubber
                                                                           1990
 
 
Northampton Generating Company
Pennsylvania
                                                                            112
50888_B_BLR1
                                                                          50888
BLR1
Coal Steam
Waste Coal
FBC
 
 
SNCR
                                                                           1995
P H Glatfelter
Pennsylvania
                                                                             36
50397_B_5PB036
                                                                          50397
5PB036
Coal Steam
Bituminous
FBC
 
 
SNCR
                                                                           2005
Panther Creek Energy Facility
Pennsylvania
                                                                             42
50776_B_BLR1
                                                                          50776
BLR1
Coal Steam
Waste Coal
FBC
 
 
SNCR
                                                                           1992
Panther Creek Energy Facility
Pennsylvania
                                                                             42
50776_B_BLR2
                                                                          50776
BLR2
Coal Steam
Waste Coal
FBC
 
 
SNCR
                                                                           1992
Piney Creek Project
Pennsylvania
                                                                             33
54144_B_BRBR1
                                                                          54144
BRBR1
Coal Steam
Waste Coal
FBC
 
 
SNCR
                                                                           2003
Scrubgrass Generating
Pennsylvania
                                                                             43
50974_B_UNIT 1
                                                                          50974
UNIT 1
Coal Steam
Waste Coal
FBC
 
 
SNCR
                                                                           1998
Scrubgrass Generating
Pennsylvania
                                                                             43
50974_B_UNIT 2
                                                                          50974
UNIT 2
Coal Steam
Waste Coal
FBC
 
 
SNCR
                                                                           1998
Seward
Pennsylvania
                                                                            261
3130_B_1
                                                                           3130
1
Coal Steam
Waste Coal
FBC
Dry Scrubber
                                                                           2004
SNCR
                                                                           2004
Seward
Pennsylvania
                                                                            261
3130_B_2
                                                                           3130
2
Coal Steam
Waste Coal
FBC
Dry Scrubber
                                                                           2004
SNCR
                                                                           2004
Sandow 5
Texas
                                                                            300
52071_B_5A
                                                                          52071
5A
Coal Steam
Lignite
FBC
Dry Scrubber
                                                                           2009
SNCR
                                                                           2009
Sandow 5
Texas
                                                                            300
52071_B_5B
                                                                          52071
5B
Coal Steam
Lignite
FBC
Dry Scrubber
                                                                           2009
SNCR
                                                                           2009
Grant Town Power Plant
West Virginia
                                                                             40
10151_B_BLR1A
                                                                          10151
BLR1A
Coal Steam
Waste Coal
FBC
 
 
SNCR
                                                                           2003
Grant Town Power Plant
West Virginia
                                                                             40
10151_B_BLR1B
                                                                          10151
BLR1B
Coal Steam
Waste Coal
FBC
 
 
SNCR
                                                                           2003
Manitowoc
Wisconsin
                                                                             30
4125_B_9
                                                                           4125
9
Coal Steam
Petroleum Coke
FBC
 
 
SNCR
                                                                           2006

Organization: Capital Power Corporation
Comment: 
Capital Power Corporation
Much of the confusion stems for the Rule's requirement s to be exempted as a cogeneration unit. The definition of cogeneration unit is unnecessarily restrictive and reduces incentives to use excess steam efficiently. Cogeneration units must meet, on an annual basis, specified efficiency and operating standards (e.g., the useful power + (1/2) of useful thermal energy output of the unit >= a certain percentage of the total energy input, useful thermal energy >= a certain percentage of total energy output, and useful power >= a certain percentage of total energy input), for each year back to November 15, 1990, or since it began operation. [EPA-HQ-OAR-2009-0491-2753.1, p.4]
As noted above the Rule's efficiency standard is impossible for any solid fuel-fired unit to meet, so they appear to be automatically excluded. Furthermore, it requires legitimate cogeneration operations that have operated as such for many years to produce records dating back to November 15, 1990. This is, frankly, unreasonable, arbitrary and contrary to EPA's goals of encouraging efficient use of energy. Retaining records for 20 years is far beyond most companies' legitimate record retention policies. Many of the units have changed names and owners over their operational lives and such records are not available. Also, many of these companies have revised their operations to comply with promulgated rules  -  such as the vacated Clean Air Interstate Rule - that have required significant periods of decreased operation and other changes which could negatively affect their ability to meet EPA's current cogeneration criteria. Moreover, requiring consistent operation of 20 years serves to discourage companies from pursuing cogeneration at a time when economics and good business practices would otherwise encourage companies to upgrade their facilities for greater efficiency by installing cogeneration units. [EPA-HQ-OAR-2009-0491-2753.1, p.4]
To resolve this, CPC recommends that EPA revise their definition of cogeneration and base it not on operation since 1990, but just look back to 2009. We ask that EPA make the cogeneration more consistent with their policies under the Title IV Acid Rain program, and should remove the efficiency test for solid fuel-fired units. [EPA-HQ-OAR-2009-0491-2753.1, p.4]
Response: 
See section VII.B of the preamble.  As discussed in the preamble, EPA is using 2005 as the start of the lookback period because this will provide about 5 years of data, which is consistent with the recordkeeping requirements under the CAA title V permit provisions and still provides a representative period.  The commenter's suggestion of using 2009 lacks these advantages. The commenter asserts, without providing any support, that no solid-fuel-fired unit can meet the efficiency requirements for qualifying as a cogeneration unit.  EPA rejects commenters claim as speculative and unsupported.  In addition, based on analysis conducted in connection with CAIR, in which the operating and efficiency requirements were adopted for the cogeneration unit exemption, EPA believes that most coal-fired cogeneration units can meet the efficiency requirements.  See "Cogeneration Unit Efficiency Calculations", March 2005.
Organization: City of Tallahassee
Comment: 
City of Tallahassee
The Municipal Generators support a 25 MW applicability threshold for the Federal Implementation Plans To Reduce Interstate Transport of Fine Particulate Matter and Ozone, 75Fed. Reg. 45210 (proposed Aug. 2, 2010) ("Transport Rule"). While the Municipal Generators, both individually and collectively, may have other substantive concerns with the Transport Rule, those concerns have been articulated in AMP's comment letter and this letter only addresses the applicability threshold issue. EPA's decision to regulate only units serving "a generator with a nameplate capacity of more than 25 megawatts" is consistent with EPA's past rulemakings that define electric generating units ("EGUs"). This long-standing approach to EGU regulation is well supported. The Municipal Generators ask that EPA retain in the final rule the proposed 25MW nameplate capacity threshold used to exclude smaller utility boilers, like those operated by Municipal Generators, from the Transport Rule. [EPA-HQ-OAR-2009-0491-2669.1, p.1]
This exemption streamlines this rulemaking by minimizing its impact on small business and state and municipal governments operating small utility boilers. EPA has estimated that approximately 600 small business and 380 state and municipally-owned utilities would be exempt from this Rule because of the 25 megawatt threshold. This exclusion allows EPA to make a determination that the Transport Rule will not adversely affect a significant number of small businesses for purposes of the RFA, as amended by the Small Business Regulatory Enforcement Fairness Act ("SBREFA"), and that a small government plan is not required by the Unfunded Mandates Reform Act ("UMRA"). Lowering the size threshold to include small utilities would require new analysis under both of these statutes, which could significantly delay a final rule. [EPA-HQ-OAR-2009-0491-2669.1, p.2]
Such a delay is unjustified in light of EPA's conclusion that cost-effective limits on EGUs in the Transport Rule may be sufficient to eliminate the adverse effect of transported fine particle, nitrogen oxide, and sulfur dioxide emissions on all or virtually all affected downwind states. Given this conclusion, EPA is not required to include small utilities in the Transport Rule because EPA does not have sufficient evidence at this time to justify regulating entities that may not be contributing significantly to nonattainment in downwind states or interfering with maintenance of a National Ambient Air Quality Standard ("NAAQS"). EPA has ample authority to impose cost-effective emission reductions on EGUs in Ohio without going any further with its Transport Rule. Thus, AMP's small utilities generating in Ohio are appropriately excluded from the reach of the Transport Rule at least until the proposed EGU approach falls short of the statutory obligation and EPA gathers evidence sufficient to demonstrate that small utilities in Ohio contribute significantly or interfere with achieving the NAAQS obligations in a downwind state. [EPA-HQ-OAR-2009-0491-2669.1, p.2]
Finally, the Municipal Generators support EPA's use of generator nameplate capacity as the correct measure of a unit's generating capacity. Nameplate capacity represents the maximum generating capacity that a unit is designed to meet on a steady-state basis. This figure is set by the manufacturer, and is a stable basis for determining applicability. In the dynamic operating environment actual maximum generation is more variable and therefore, less reliable for determining applicability for a significant federal rule. Generator nameplate capacity is a clear threshold that provides regulatory certainty, and should continue to set the applicability threshold in the final rule. [EPA-HQ-OAR-2009-0491-2669.1, p.2]
EPA Lacks Data Necessary to Support Regulation of Sources 25 Megawatts or Less Under the Transport Rule [EPA-HQ-OAR-2009-0491-2669.1, p.3]
EPA provided three justifications for including only EGUs under the Transport Rule: 1) large utilities can achieve significant emissions reductions far more cost-effectively than smaller units; 2) regulating only large utilities is "sufficient to eliminate the quantity of emissions identified by EPA as significantly contributing to or interfering with maintenance of the 1997PM2.5 NAAQS in downwind areas"; and 3) EPA is still investigating whether regulation of smaller units will be necessary to address ozone. See 75 Fed. Reg. 45300. [EPA-HQ-OAR-2009-0491-2669.1, p.2]
EPA SHOULD REGULATE ONLY UNITS SERVING GENERATORS GREATER THAN 25 MEGAWATTS UNDER THE TRANSPORT RULE
EPA requested comment on whether it would be appropriate to regulate units serving generators less than 25 megawatts under the Transport Rule. 75 Fed. Reg. at 45309. Lowering the threshold below 25 megawatts would be inappropriate. These smaller units have not been subject to the previous Clean Air Interstate Rule, nor have they been subject to the NOx SIP call or the acid rain program. As a result, significant additional monitoring costs would be incurred by small utilities that have not been considered in the cost analysis. In addition, reducing the size threshold below 25 MW would bring a significant number of small entities into the rule and would require a new assessment under the RFA and the UMRA. This would require promulgation of a new proposed rule, and delay promulgation of a final rule. Furthermore, EPA lacks evidence to support a finding that regulation of these smaller units is necessary to achieving and maintaining National Ambient Air Quality Standards ("NAAQS") in downwind states. The 25 megawatt threshold, on the other hand, is consistent with EPA's prior rulemakings and should be maintained in the final rule. [EPA-HQ-OAR-2009-0491-2669.1, p.3]
EPA estimates that the proposed Transport Rule, which applies only to EGUs and requires only those emissions reductions that can be achieved in a cost-effective manner, will address 84 % of nationwide NOx emissions and 73% of nationwide SO2 emissions. RIA at 235.EPA concluded, for purposes of the Transport Rule, that a reasonable cost threshold for NOX reductions is $500/ton. Id. at 45282. EPA has been unable to identify controls for small utilities that would achieve significant emission reductions at this cost. See 75 Fed. Reg. at 45286-90.As noted by the Northeast States for Coordinated Air Use Management ("NESCAUM"), NOX control costs for these smaller, non-EGU boilers range from $1,000 to $7,000 per ton of NOX removed, and can run as high as $14,000 per ton. See NESCAUM, APPLICABILITY ANDFEASIBILITY OF NOX, SO2, AND PM EMISSIONS CONTROL TECHNOLOGIES FOR INDUSTRIAL, COMMERCIAL, AND INSTITUTIONAL (ICI) BOILERS at 6-1 (Nov. 2008). These data indicate that highly cost-effective controls are not available for these smaller utilities and they would face a disproportionate cost burden if required to meet the same emission limits as the larger EGUs. Therefore, the available data support excluding small utilities from the Transport Rule. [EPA-HQ-OAR-2009-0491-2669.1, pp.3-4]
Furthermore, EPA does not possess data demonstrating that regulation of small utilities under the Transport Rule will have a significant impact on emissions. Instead, EPA determined that small utilities and other non-EGU sources are not significant contributors to PM2.5, and that any reductions in SO2 would be variable and difficult to measure. 75 Fed. Reg. at 45286-90,45300. EPA also acknowledged that it does not have sufficient data to determine whether regulation of small utilities under the Transport Rule will have a significant impact on attainment or maintenance of ozone NAAQS or other future NAAQS. See 75 Fed. Reg. at 45300. [EPA-HQ-OAR-2009-0491-2669.1, p.4]
EPA can achieve significant emissions reductions in a cost-effective manner by regulating only EGUs. EPA lacks sufficient data to determine whether regulation of other small utilities is necessary to fulfill the purposes of the Transport Rule. Thus, EPA's proposed decision to regulate only those units definitively identified as significant contributors to pollution in downwind states  -  i.e., units serving generators with a nameplate capacity greater than 25megawatts  -  is an appropriate basis for a federal implementation plan created under Clean Air Act § 110(c). [EPA-HQ-OAR-2009-0491-2669.1, p.4]
EPA Historically Has Regulated Units Serving Generators 25 Megawatts or Less Differently Than Larger Units [EPA-HQ-OAR-2009-0491-2669.1, p.4]
The proposed Transport Rule's 25 megawatt threshold is well supported by past rulemakings. EPA used identical language to define an "electric generating unit" in setting New Source Performance Standards ("NSPS") and developing state implementation plan guidelines. See 40 C.F.R. §§ 60.24, 51.123, 51.124, 52.34 (defining an "electric generating unit" as a unit serving "a generator with nameplate capacity of more than 25 megawatts electric (MWe)"(emphasis added)). EPA has also used the 25 megawatt threshold to distinguish between source categories subject to different NSPS and Maximum Achievable Control Technology ("MACT") standards. The 25 megawatt threshold determines which units are regulated under NSPS standards in Subpart Da, as opposed to the standards of Subpart D or Db. See 40 C.F.R. §§ 60.2,60.40(e), 60.41a, 60.40b(e). Likewise, the proposed National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers and Process Heaters ("Boiler MACT") uses a 25 megawatt threshold to identify sources that are not subject to Boiler MACT standards, but will instead be subject to a separate MACT standard with distinct control requirements and emission limits. See 75 Fed. Reg. 32006, 32050, 32064 (proposed June 4,2010). EPA has routinely used a 25 megawatt threshold to separately regulate large and small utilities, and should continue to do so under the Transport Rule. [EPA-HQ-OAR-2009-0491-2669.1, pp.4-5]
Response: 
See sections VII.B and X of the preamble.  The final rule gives states the option of expanding the applicability provisions of the Transport Rule NOx ozone season trading program to include units serving generators with a nameplate capacity of 15 MWe or greater producing electricity for sale.  This is consistent with the approach taken in the NOx Budget Trading Program, where some state elected to include units serving generators with a nameplate capacity of 15 MWe or greater producing electricity for sale. 
Organization: Connecticut Department of Environmental Protection
Comment: 
Connecticut Department of Environmental Protection
Lowering applicability threshold in ozone season. EPA requests comment on lowering the greater than 25 MW applicability threshold for EGUs during the ozone season, and whether a trading program offers the right approach for addressing NOx emissions from these smaller EGUs. (75 FR 45309) In Connecticut, CAIR applicability includes units at and above 15 MW, and several 20 MW peaking turbines have been included in CTDEP's existing trading programs. CTDEP supports lowering the applicability threshold for EGUs during the ozone season to between 2 - 15 MW, but recommends that any control program for these smaller EGUs be based on short-term performance standards since these smaller peaking units tend to emit at high rates and operate on the worst air quality days. [EPA-HQ-OAR-2009-0491-2780.1 p.21]
Response: 
See sections VII.B and X of the preamble.  The final rule gives states the option of expanding the applicability provisions of the Transport Rule NOx ozone season trading program to include units serving generators with a nameplate capacity of 15 MWe or greater producing electricity for sale.  This is consistent with the approach taken in the NOx Budget Trading Program, where some state elected to include units serving generators with a nameplate capacity of 15 MWe or greater producing electricity for sale. 
Organization: Council of Industrial Boiler Owners (CIBO)
Comment: 
Council of Industrial Boiler Owners (CIBO)
The rule, as clarified by EPA's September 14, 2010 correcting amendments, allows ICI boilers to opt in under the Proposed Rule. CIBO supports provisions permitting non- EGUs that can cost-effectively reduce their emissions to opt-in and participate in the trading program. CIBO supports the intended use of a separate pool of allowances for opt-in units and the ability to trade excess allowances with other covered entities. However, the rule should provide a methodology to fairly allocate credits to non- EGUs that opt in. Non- EGUs that opt in benefit the overall program, by widening the pool of market participants and ensuring additional emission reductions. Therefore, EPA should encourage their participation by ensuring equity in credit distribution and trading. In addition, EPA should not mandate a high level of required emissions reductions as a condition of opt-in. As indicated above, the cost effectiveness for ICI units is generally much higher than EGUs, so that if similar reductions were required, that would impose a severe penalty and neuter the potential benefit for opting-in. EPA needs to recognize that the cost of emissions monitoring alone is basically the same regardless of unit size, so that cost alone presents a significant disincentive for opting-in.
Since ICI boilers may need to control HAP emissions with installation of acid gas emissions controls in response to the upcoming Boiler MACT or CISWI rules, EPA should allow such collateral reduction of SO2 emissions to be eligible for opt-in allowances. The basis for this approach is that the potential value available through sales of excess allowances could allow the facility to support the economics for such emissions control installation rather than shut down the emission units or production facility, thus enabling continuation of high value jobs and the collateral economic benefits. Having this opt-in capability available might also help support use of an additional level of emissions control that might not have otherwise been implemented. Recognition of this potential benefit of integrating regulatory compliance may necessitate alternative baseline determination, however due to regulatory schedules. Where the Transport Rule requires a 1 to 3 year period of emissions monitoring with Part 75 CEMS, an alternative defensible approach should be allowed so that the timing of equipment installation could be accommodated in response to regulatory requirements. Such an approach could utilize fuel use data, fuel quality data, and Reference Method emissions testing in lieu of 1-3 years of Part 75 monitoring. CIBO recommends that EPA consider adding this flexibility since emissions reductions of any kind contribute toward NAAQS attainment.
The rule, as clarified by EPA's September 14, 2010 correcting amendments, allows ICI boilers to opt in under the Proposed Rule. CIBO supports provisions permitting non- EGUs that can cost-effectively reduce their emissions to opt-in and participate in the trading program. CIBO supports the intended use of a separate pool of allowances for opt-in units and the ability to trade excess allowances with other covered entities. However, the rule should provide a methodology to fairly allocate credits to non- EGUs that opt in. Non- EGUs that opt in benefit the overall program, by widening the pool of market participants and ensuring additional emission reductions. Therefore, EPA should encourage their participation by ensuring equity in credit distribution and trading. In addition, EPA should not mandate a high level of required emissions reductions as a condition of opt-in. As indicated above, the cost effectiveness for ICI units is generally much higher than EGUs, so that if similar reductions were required, that would impose a severe penalty and neuter the potential benefit for opting-in. EPA needs to recognize that the cost of emissions monitoring alone is basically the same regardless of unit size, so that cost alone presents a significant disincentive for opting-in.
Since ICI boilers may need to control HAP emissions with installation of acid gas emissions controls in response to the upcoming Boiler MACT or CISWI rules, EPA should allow such collateral reduction of SO2 emissions to be eligible for opt-in allowances. The basis for this approach is that the potential value available through sales of excess allowances could allow the facility to support the economics for such emissions control installation rather than shut down the emission units or production facility, thus enabling continuation of high value jobs and the collateral economic benefits. Having this opt-in capability available might also help support use of an additional level of emissions control that might not have otherwise been implemented. Recognition of this potential benefit of integrating regulatory compliance may necessitate alternative baseline determination, however due to regulatory schedules. Where the Transport Rule requires a 1 to 3 year period of emissions monitoring with Part 75 CEMS, an alternative defensible approach should be allowed so that the timing of equipment installation could be accommodated in response to regulatory requirements. Such an approach could utilize fuel use data, fuel quality data, and Reference Method emissions testing in lieu of 1-3 years of Part 75 monitoring. CIBO recommends that EPA consider adding this flexibility since emissions reductions of any kind contribute toward NAAQS attainment.  [EPA-HQ-OAR-2009-0491-2751.1 p.6]
A. Records requirements for cogenerators.
A problem with the cogeneration unit exemption is the requirement that in order to qualify, a facility must have records dating back to 11/15/1990. This has been a problem in the past, as EPA recognizes in the Preamble (75 FR 45307) by asking 'whether the efficiency and operating standards should be limited to even more recent years.' CIBO suggests that the annual evaluation start more recently, certainly no later than typical record retention practices required under EPA Title V requirements of five years.
B. Efficiency standard. 
CAIR required each cogeneration unit to meet the efficiency standard. However, under the proposed definition of "cogeneration unit," if a cogeneration system that includes a topping-cycle unit meets the efficiency standard on a system-wide basis, then the unit is also deemed to meet that efficiency standard. CIBO supports this and urges EPA to adopt this same approach for bottoming-cycle units.   [EPA-HQ-OAR-2009-0491-2751.1 p.10]
Response: 
See section VII.B of the preamble.  EPA agrees that significant SO2 emission reductions can result from non-covered units' compliance with the non-SO2 emission standards imposed in the Boiler MACT rule (76 FR 15608 (March 21, 2011)).  Because, among other things, these reductions will occur whether or not these units would be allowed to opt into the Transport Rule trading programs and allocating allowances to these units for their emissions before these reductions occur would effectively convert the units' required reductions into increased emissions by covered EGUs, the final Transport Rule does not allow units to opt in.  
Organization: Dow Chemical Company
Comment: 
Dow Chemical Company
EPA has also requested comments on certain aspects of its proposed rule. One of the areas where EPA requested comments concerns whether it would be problematic for sources to obtain detailed information about the disposition of a unit's generation back to November 15, 1990 and whether the efficiency and operating standards should be limited to more recent years rather than November 15, 1990. EPA suggested as an alternative for comment whether the exemption requirements should only be met every year starting the later of a date of a more recent year (e.g., 2000, 2005, or 2009) or the date on which the unit first produces electricity.8 EPA also requests comment on whether the electricity sales limit should be restricted to more recent years by requiring that the limit be met every year starting the later of a date of a more recent year (e.g., 2000, 2005, or 2009) or the start-up of a unit's combustion chamber. [EPA-HQ-OAR-2009-0491-2775.1 p.7]
Dow believes that it could be problematic to produce detailed information about the disposition of a unit's generation, its efficiency and operating standards, and its electricity sales from as far back as November 15, 1990, which is nearly twenty years ago. The time period for recordkeeping under the Clean Air Act Title V permit program and similar programs is generally only five years. While most sources will have records of this type of information on major EGUs for the last 5 years, they may not have kept detailed information for prior years. Thus, the 'start-date' for the exemption criteria should extend no further back than five years prior to the adoption of the final Transport Rule/FIP.  [EPA-HQ-OAR-2009-0491-2775.1 p.8]
The 'cogeneration unit' definition proposed under the Transport Rule/FIP differs from that under the Clean Air Interstate Rule (CAIR). Under CAIR, each unit had to meet individually the efficiency standard. Under the proposed rule, however, if the cogeneration system of which a topping-cycle unit is a part meets the efficiency standard on a system-wide basis, then the unit is also deemed to meet that efficiency standard. EPA requested comments on whether this approach should also be applied to bottoming-cycle units. [EPA-HQ-OAR-2009-0491-2775.1 p.8]
Dow supports applying the approach of meeting efficiency standards on a system-wide basis to bottom-cycle units for the same reason that EPA has applied this approach to topping-cycle units. Allowing one unit in a cogeneration system to act as a 'swing' unit and operate at a lower efficiency will allow the other units in the system to operate at higher efficiencies. Further, there is no basis for EPA to treat these two types of units differently for the purposes of meeting efficiency standards. Topping-cycle units and bottoming-cycle units have the same purpose -- to produce electricity and thermal power. The fundamental difference between these two types of units is the order in which electricity and thermal energy are produced. In topping-cycle units, the energy input to the unit is first used to produce useful power, including electricity, and then some of the reject heat from the electricity production is used to provide useful thermal energy.11 In bottoming-cycle units, the process is reversed, with the energy input to the unit first being used to produce useful thermal energy and then some of the reject heat from the useful thermal energy process being used for electricity production.12 As topping-cycle units and bottoming-cycle units have the same purpose and produce the same products, EPA should apply the same efficiency standards requirements to both types of units. [EPA-HQ-OAR-2009-0491-2775.1 p.8]
EPA requested comment on whether the agency should exclude, from the requirement to meet the operating and efficiency standards, calendar years -- if any -- during which a unit does not operate at all. Under the proposed Transport Rule, the operating and efficiency standards in the 'cogeneration unit' definition must be met every year. EPA is concerned because, as the rule is currently written, these annual standards would be applied in calendar years when a unit does not operate at all. Dow agrees with this concern and requests EPA to exclude these requirements in calendar years when the unit does not operate at all. [EPA-HQ-OAR-2009-0491-2775.1 p.9]
Response: 
See section VII.B of the preamble.
Organization: DTE Energy Services (DTEES)
Comment: 
DTE Energy Services (DTEES)
Applicability of proposed rule to biomass facilities
The definition of fossil fuel fired should exempt units that previously fired fossil fuels at any time since 1990 and now burn woody biomass. Looking back to 1990 for fuel use often does not reflect the current fueling of a facility and penalizes facilities that have switched to renewable fuels such as biomass. The definition should also exempt units that burn de minimis amounts of fossil fuel only to start up the boiler. Biomass units are not fossil fuel fired units and should not be subject to a regulatory program designed to regulate fossil fuel units. Biomass is an attractive alternative to coal and other fossil fuels given that it is a renewable fuel; the use of biomass as a fuel for electricity generation should be encouraged by EPA. [EPA-HQ-OAR-2009-0491-2699.1,p.1]
Exemption for qualifying solid waste incineration units
The solid waste incineration unit exemption should be expanded to cover facilities that historically did not meet this definition and due to EPA's reinterpretation of what constitutes a solid waste (rather than fuel) the unit then becomes a solid waste incinerator (see Proposed Rules in Federal Register notices from Friday June 4, 2010, 40 CFR 241 Identification of Non-Hazardous Secondary Materials That Are Solid Waste and 40 CFR 60 Standards of Performance for New Stationary Sources of Emission Guidelines for Existing Sources: Commercial and Industrial Solid Waste Incineration Units). After becoming a solid waste incinerator due to the reinterpretation that unit should be exempt from the Transport Rule. [EPA-HQ-OAR-2009-0491-2699.1,pp.1-2]
Response: 
See section VII.B of the preamble.  
The final rule defines "fossil-fuel-fired" as combusting any amount of fossil fuel in 2005 or later.  EPA rejects, for several reasons, the commenter's approach of excluding so-called "de minimis" amounts of fossil fuel use.  The approach in the final rule is consistent with the approach used in prior EPA trading programs covering the electric generation industry, e.g., the Acid Rain Program, the NOx Budget Trading Program, and the CAIR trading programs.  The commenter did not provide any basis for using a different approach in the Transport Rule trading programs covering the same industry or specifically suggest what level of fossil fuel use as a % of total fuel use should constitute "de minimis" fossil fuel use in these programs.  Moreover, if the applicability of the Transport Rule trading programs for all units were to depend on exceeding a specific level of fossil fuel use, the regulatory status of units could change during the course of the year.  Specifically, a unit's fossil fuel use can vary, depending on, among other things, changes in unit operation and fuels.  As noted by the commenter, some units use fossil fuel for startup and combustion stabilization, and so fossil fuel use can vary depending on the frequency of startups and shutdowns and on factors (such as the moisture content and other characteristics of the other fuels being combusted) affecting the need for combustion stabilization.  Units that were excluded from the Transport Rule trading programs because of their fossil fuel use at some specified level would not report fuel use to EPA, and so determination of whether a significant number of units were subject to the trading programs, and assurance of compliance, would be problematic.  Although units that burned no fossil fuel starting in 2005 are excluded from the Transport Rule and could potentially have their regulatory status change by beginning to burn fossil fuel, EPA believes that this is less likely to occur than in the case of units have been burning some fossil fuel.  EPA therefore maintains that the approach in the final rule of covering units that burned any fossil fuel starting in 2005 and that serve a generator with a nameplate capacity greater than 25 MWe producing electricity for sale and excluding units that burned no fossil fuel starting in 2005 is reasonable. 
Organization: Environmental Law & Policy Center
Comment: 
Environmental Law & Policy Center
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.76.]
Targeting power plants is the right way to go.
Response: 
See sections VI.A, VII.B, IX.A and B, and X of the preamble.
Organization: Exeter Energy Limited Partnership
Comment: 
Exeter Energy Limited Partnership
I. EPA should restrict the qualification requirement for the solid waste incineration unit exemption in proposed 40 CFR 97.404(b) by imposing the qualification requirement every year starting with the later of 2009 or the date which the unit first produces electricity. This would modify the current proposed criteria that would impose the qualification requirement starting with the later of 1990 or the 12-month period starting on the date the unit first produces electricity. [EPA-HQ-OAR-2009-0491-2835.1 p.1]
2. Should the Proposed Transport Rule nonetheless end up applying to Exeter Energy, it would allocate ozone season NOx allowances for each of Exeter Energy's two units, but fails to allocate any annual NOx or S02 allowances for either unit. Therefore, Exeter Energy is submitting documentation of its NO, and SO, emissions on a per boiler and per month basis for EPA's use  in calculating annual allowances, in the event that Exeter Energy will ultimately he subject to the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2835.1 p.1]
These points are discussed in more detail below.
I. Modification of the solid waste incineration unit exemption qualification date:
For purposes of background, it should be noted that Exeter Energy had requested in 2006 and recently received EPA's determination' on the applicability of the CAIR NOx Ozone Season Trading Program to Exeter Energy. This determination concluded that ' ... if the boilers at the Exeter Facility are determined to combust 'solid waste' as defined pursuant to the ongoing EPA rulemaking proceeding to identify which non-hazardous secondary materials are solid wastes when combusted in a unit, the boilers will not be CAIR NOx Ozone Season units.' Since the applicability criteria for a solid waste incineration unit under the Proposed Transport Rule is similar to the criteria in the CAIR Rule, Exeter Energy understands that the potential exemption from the Proposed Transport Rule is also contingent on whether tires combusted in Exeter Energy's boilers are ultimately classified as solid waste under a separate rulemaking. However, there is one important difference in the criteria for the solid waste incineration unit exemption under the Proposed Transport Rule as currently drafted that would preclude Exeter Energy from qualifying for the exemption. As noted in EPA's CAIR applicability determination for Exeter Energy, the language in the CAIR Rule regarding the exemption was unclear whether a unit must qualify for the exemption when it begins generating electricity. EPA ultimately concluded in its determination that the Exeter boilers could qualify for the solid waste incineration unit exemption under the CAIR Rule even though they were previously (from June 23, 1991 until March 30, 200 I) a qualifying 'small power production facility' under Federal Energy Regulatory Commission rules ('qualifying SPP facility'), rather than incineration units. However, under the currently proposed Transport Rule, in order to qualify for the solid waste incineration unit exemption, a unit must have qualified as a solid waste incineration unit since the later of 1990 or the 12 months starting when the unit first produced electricity. Since Exeter Energy was classified as a 'qualifying SPP facility' until March 30, 2001, under the position indicated by EPA's CAIR applicability determination, the facility would not seem to qualify for the solid waste incineration unit exemption under the proposed rule.  [EPA-HQ-OAR-2009-0491-2835.1 p.2]
In section V.DA.b(l) (page 45307) of the preamble to the Proposed Transport Rule, EPA requests comment on whether the look-back date for the solid waste incineration unit exemption qualification should be made more recent than 1990. Exeter Energy respectfully proposes that the look-back date should be more recent, either 2009 (the year preceding the Proposed Transport Rule) or at the latest, 2005 (five years preceding the Proposed Transport Rule). In general, to base a significant new regulatory program on the availability of records going back nearly two decades is not a feature of good rulemaking practice, and does not promote a coherent regulatory scheme that can be readily understood and implemented by both regulators and regulated parties. Sufficiently detailed information on fuel input to each unit will likely be available only from a more recent timeframe to document that a unit meets the qualification criteria. The Clean Air Act itself and numerous derivative rulemakings commonly require records to be maintained, e.g. as part of Title V recordkeeping requirements, for a period of five years. Documentation based on a look-back date of 1990 or even 2000 would be problematic as facilities are not required and may not have records going back that far. [EPA-HQ-OAR-2009-0491-2835.1 p.2] 
With specific regard to Exeter Energy, since both units had been previously classified as a 'qualifying SPP facility' for a limited period in the first several years of operation, the units would not seem to qualify for the solid waste incineration unit exemption under the Proposed Transport Rule, unless the look-back date is modified to 2005 or 2009. The impact on Exeter Energy's operation and the valued environmental service it provides would be significant, in terms of the additional capital and operating costs of monitoring system upgrades and the potential costs of allowances, for very little environmental benefit, given its already low level of NOx and SO, emissions relative to other potentially regulated units. For these reasons, Exeter Energy respectfully requests EPA to revise the look-back to a more realistic period, either 2009 or at most, the standard Clean Air Act five-year period. [EPA-HQ-OAR-2009-0491-2835.1 p.2]
Response: 
See section VIIB of the preamble.
Organization: Great River Energy
Comment: 
Great River Energy
Throughout the preamble to the Transport Rule, EPA purports to create a cost effective and flexible program to address each state's significant contribution to downwind states. Unfortunately, EPA has punished inherently clean burning simple cycle combustion turbines, at least in Minnesota, by lumping them into the EGU category and by allocating limited allowances to them. Great River Energy firmly believes that our simple cycle combustion turbines, as emission sources, do not 'contribute significantly' to downwind annual non-attainment and should be treated separately from 'EGUs' under the Transport Rule. [EPA-HQ-OAR-2009-0491-2758.1 p.7]
Given the extent of the supporting documentation with associated references back to the CAIR rule, and its associated technical support documentation, it is virtually impossible to determine EPA's precise methodology for including simple cycle combustion turbines as part of the 'EGU' source category. [EPA-HQ-OAR-2009-0491-2758.1 p.7]
EPA makes the argument that controls are not cost effective for industrial boilers, as a source category, with estimates well below EPA's break point of$5,000/ton for the Transport Rule,2 and then proceeds to exempt them from the Transport Rule. As discussed elsewhere, Great River Energy's simple cycle combustion turbines generally have DLN and water injection for NOx control, and bum ULSD fuel oil for S02 control. Additional NOx reductions for these emission sources would require costly controls, such as SCR, approaching significantly more than $10,000/ton of emission reductions. Similarly, several of Great River Energy's peaking plants have state synthetic minor restrictions <<250 tpy NOx and S02), resulting in even less of a potential contribution to downwind annual non-attainment. [EPA-HQ-OAR-2009-0491-2758.1 p.7]
In addition, with respect to Minnesota state emissions, and other states for that matter, EPA argues that industrial boilers contribute relatively less to downwind non-attainment. As a source category, combustion turbines contribute even less to interstate transport than industrial boilers, and other exempted sources for that matter.3 Certainly, EPA can argue that a general SIC code determination has been made to include all 'EGUs,' as was made with CAIR. Yet, upon a more detailed review of the data, it is clear that the inclusion of combustion turbines, and the exemption of industrial boilers, is both arbitrary and capricious. [EPA-HQ-OAR-2009-0491-2758.1 p.7]
In summary, Great River Energy's peaking plants would be more costly to control than industrial, commercial and institutional boilers and represent a smaller portion of state emissions and associated contribution to downwind annual non-attainment. Consequently, they should be excluded as a source category from the Transport Rule, like the non-EGU boilers and turbines. [EPA-HQ-OAR-2009-0491-2758.1 p.7]
Response: 
With regard to allocations simple cycle combustion turbines, see section VII.D of the preamble.
With regard to applicability to simple cycle combustion turbines, see section VII.B of the preamble.  EPA rejects the commenter's approach of separating units using one combustion technology -- i.e., simple cycle combustion turbines -- to generate electricity for sale from units using other types of combustion technology -- such as boilers and combined cycle combustion turbines -- to generate electricity for sale.  EPA maintains that it is reasonable to consider the electricity generation section as a whole in determining the cost of available emission reductions and in determining a state's significant contribution and interference with maintenance.  In past trading programs (such as the Acid Rain Program, NOx Budget Trading Program, and CAIR trading programs), EPA has taken the general approach of regulating the entire electricity generation sector, rather than treating the different combustion technologies separately.  Further, if entire groups of units with different combustion technologies were treated differently for purposes of regulating their emissions, utilization for electricity generation, and the resulting emissions, could shift to those units from covered units because of the high level of integration of the electric generation, transmission, and distribution system (which has increased with the significant restructuring and deregulation of electric utilities) and thereby threaten achievement of elimination of states' significant contribution and interference with maintenance, which is the goal of the Transport Rule.  Although the exemption of any portion of the electricity generation sector creates the potential for generation shifting, the greater the number and scope of the exemptions, the greater the likelihood and likely magnitude of the potential generation shifting.  After the balancing the commenter's claimed rationale for the requested exemption and the potential adverse effect of such an exemption, EPA rejects the commenter's position and maintains that EPA's approach of regulating emissions from essentially the entire electricity generation sector -- with a few, limited exemptions, e.g., for certain cogeneration units and solid waste incineration units -- is consistent with the goal of the Transport Rule. 
Organization: Indiana Department of Environmental Management 
Clean Energy Group
Pennsylvania Department of Environmental Protection
Maryland Department of Environment (MDE)
Eco Power Solutions (USA) Corp.
State of Missouri Department of Natural Resources
Exelon
PPL Corporation
Class of '85 Regulatory Group
Fond du Lac Reservation
National Tribal Air Association (NTAA)
Portland Cement Association (PCA)
Comment: 
Class of '85 Regulatory Group
EPA Should Allow Additional Units to Opt-In.
The Class of '85 supports opt-in provisions, and believes that EPA can further broaden the scope of the preferred option's opt in provisions without any adverse impact on in-state emissions reductions. Specifically, units below the current 25 MW threshold are typically used for peaking purposes. As a result, many of those units do not operate for a sufficient amount of time to satisfy the requirement that an opt-in unit operate for at least 876 hours within six months. EPA should consider eliminating the 876-hour requirement and allow smaller units to opt in regardless of operating time. This change will increase the number of covered sources without affecting state budgets or emissions reductions in any way. Because many of these units are natural gas-fired peaking units with low emissions rates, the inclusion of additional smaller units will help to reduce emissions in a highly cost-effective manner. In addition, eliminating the 876-hour requirement will remove the perverse incentive to operate smaller units for additional hours simply to satisfy the opt-in requirement. [EPA-HQ-OAR-2009-0491-2854.1, p.14]
Clean Energy Group
Opt-in Provisions
At certain points on hot summer days, electric demand increases to accommodate air conditioning and other requirements, and a portion of the increase in electric demand is typically satisfied by peaking units such as combustion turbines and internal combustion engines. These 'peakers' are capable of responding to a dispatch request quickly and can attain full load in less than thirty minutes. Typically, peakers have high operating costs, and thus run as rarely and only when no more cost-effective EGUs are available to meet demand. Certain states, such as in the Northeast's Ozone Transport Region in particular, are adopting measures to require NOx emission controls on combustion turbines and other electric generating units of less than 25 MW capacity as part of 'high electric demand day' (HEDD) programs. Typical HEDD units operate less than 100 hours during the ozone season and are generally permitted to operate for less than one month at full load on a rolling 12-month basis (a five percent annual capacity factor). [EPA-HQ-OAR-2009-0491-2702.1, p. 11]
The Transport Rule allows units below the rule's 25 MW threshold to join the allowance trading programs. However, the owner of any unit opting in would be required to certify that the unit operated at least 876 hours in the six months prior to the opt-in request (a ten-percent capacity factor). As explained above, small peaking units below the proposed Transport Rule's 25 MW threshold typically do not operate for a sufficient amount of time to satisfy this criterion. Many units are in fact prohibited by permit or state law from operating even half that much on an annual basis. EPA should consider removing the 876-hour threshold and allow these small EGUs to opt-in regardless of the annual operating time. This change would increase the number of sources covered by the rule, resulting in an even greater improvement in air quality. Further, such an action would remove the perverse incentive to operate and emit more as a way to qualify as an opt-in unit. Finally, if state regulatory authorities allow these units' participation in the Transport Rule to fulfill state-level HEDD requirements, companies would be able to make more rational capital and operational decisions within a more efficient and integrated regulatory framework. If peaking units are allowed to opt in, states would see air quality benefits from reductions in HEDD emissions as soon as 2012, whereas state regulatory processes are unlikely to show results for several years beyond 2012.  [EPA-HQ-OAR-2009-0491-2702.1, p. 11]
Eco Power Solutions (USA) Corp.
Additionally, to the extent that the voluntary "opt-in" method for the non-EGU sector is to be encouraged, the "opt-out" provisions of the proposed rule need to be simplified. The current proposal creates an unnecessary "lock in" for four years and a risk of a further "lock in" that will likely discourage many in the non-EGU sector from participating on a voluntary "opt in" basis. [EPA-HQ-OAR-2009-0491-2692.1, p. 2]
In light of the foregoing, EPA has at least two options. First, it could simply reconsider its decision not to include non-EGUs. Since EPA did not in the original proposed rule give notice that it intended to regulate non-EGUs, it would likely have to give at least 60 days notice of its potential intention to do so. This would provide non-EGUs with an opportunity to comment on whether, in light of the availability of new more cost-effective technology, non-EGUs should be included in the Air Transport rule. Consideration would also have to be given to establishing the timing and structure for full integration of ICI boilers and potentially other industrial component sources in the context of the new Ozone rule and SO2 rule. [EPA-HQ-OAR-2009-0491-2692.1, p. 7]
A second alternative would be to not only allow non-EGUs to 'opt-in' to one or more of the proposed trading programs (as EPA has already proposed to do) but also to encourage such voluntary "opt-in" actions through liberalized "opt out" rules that would avoid the risk of a "lock in". Since the COMPLY 2000(R) costs for non-EGUs to control NOx and SO2 would be far less than EPA has estimated, non-EGUs might still want to "opt-in" because they will eventually need to reduce SO2 and NOx to conform to the newly adopted SO2 standards and the new proposed more stringent ozone regulations that EPA has said it will finalize in October 2010. And the salable SO2 and NOx credits from voluntary reductions made before final compliance dates would help reduce the potentially high cost to industry of implementing a new more stringent ozone rule. The more non-EGUs that voluntarily "opt-in" the sooner non-EGU emissions will be reduced. [EPA-HQ-OAR-2009-0491-2692.1, p. 8] [See 2692.1, pp. 8-10 for extensive discussion of 'opt-out' rules.]
Exelon
EXELON URGES EPA TO MODIFY THE OPT-IN REQUIREMENTS BYREMOVING THE "HOURS OF OPERATION" REQUIREMENT THAT RENDERS MANY "PEAKER"UNITS INELIGIBLE TO OPT IN TO TRANSPORT RULE ALLOWANCE PROGRAMS.
At certain points on hot summer days, electric demand increases to accommodate air conditioning demand, and a portion of the increase in electric demand is typically achieved with peaking units such as combustion turbines and internal combustion engines. The "peakers" are capable of responding to a dispatch request quickly and can be at full load in less than thirty minutes, which makes them suitable for this purpose. Typically, peakers have high operating costs, and thus run as rarely as possible, and only when no more cost-effective EGUs are available to meet demand. Certain states in the Northeast Ozone Transport Region are adopting measures to require NOX emission controls on combustion turbines and other electric generating units of less than 25 MW capacity as part of "high electric demand day" ("HEDD") programs.  For example, Pennsylvania is developing a regulatory program that would address fossil fuel combustion turbines and internal combustion engines that are electric generating units and operate less than 1,200 hours during the ozone season. [EPA-HQ-OAR-2009-0491-2666.1, p.42]
Exelon owns and operates twenty-three peaker turbines in the Philadelphia area that would be subject to Pennsylvania's HEDD program. These units typically operate less than 100 hours during the ozone season and indeed are not permitted to operate more than 438 hours at full load on a rolling 12-month basis (a five percent annual capacity factor). Under the Pennsylvania HEDD program, beginning as soon as 2012, these units would be required to retrofit NOX emission controls. The capital cost of those controls, combined with the very low capacity factors of these units, would likely make a retrofit economically infeasible. However, Pennsylvania's proposed HEDD program contemplates that units could opt in to the Transport Rule program in lieu of complying with the HEDD program. [EPA-HQ-OAR-2009-0491-2666.1, p.42]
The Transport Rule allows units below the rule's 25 MW threshold to opt in to the allowance trading programs under the rule. However, the owner of any unit opting in must certify that the unit operated at least 876 hours in the six months prior to the opt in request. Small EGUs of less than 25 MW typically do not operate for a sufficient amount of time to satisfy this criterion. Exelon's units, which are prohibited by permit from operating even half that much on an annual basis, certainly do not. Yet, Exelon's units are typical of peaking units operating all across the Transport Rule region. These units play an important role in electric reliability. [EPA-HQ-OAR-2009-0491-2666.1, p.43]
Exelon proposes that the Transport Rule be modified to allow EGUs of less than 25 MW to opt in to any of the Transport Rule allowance programs, regardless of hours of operation. Exelon does not propose that state emission budgets be expanded to provide additional allowances for sources opting in to the programs. Rather, units opting in will be required to purchase allowances at auction or from other facilities. The inclusion of small peakers would certainly not interfere with the objective of the Transport Rule to reduce impacts in downwind areas. The total amount of emissions from peaking units would likely be too small to influence liquidity or prices in allowance markets. If there were any influence at all, the inclusion of peakers would tend to increase demand, and thus prices, which could ultimately result in a decision by one or more large EGU owners to install additional controls. By allowing peakers to opt in, EPA would potentially increase the number of sources covered by the Transport Rule without increasing the state emission budgets, necessarily resulting in an even greater improvement in air quality. [EPA-HQ-OAR-2009-0491-2666.1, p.43]
HEDD programs are by nature state programs directed primarily to addressing local air quality concerns. Ultimately, it will be up to each state to determine whether it would be appropriate to allow a unit to opt in to a Transport Rule allowance program in lieu of complying with the requirements of the state program. Some states may provide that option, as Pennsylvania seems inclined to do, and some states may not. However, by allowing peaking units to opt in to the Transport Rule program, EPA would provide each state adopting a HEDD program with an additional regulatory option that would allow greater flexibility in meeting the state's air quality goals. [EPA-HQ-OAR-2009-0491-2666.1, p.43]
Fond du Lac Reservation
Opt-In of Non-Covered Sources
The Transport Rule also provides for non-covered sources (e.g., operating boiler, combustion turbine, or other stationary combustion device) to voluntarily enter trade programs with allowance allocations given to them based on their historical emissions. While the expectation of EPA is that these sources might be better able to make lower cost emissions reductions than EGUs within a state, thereby reducing the program's overall costs, this approach offers a more important benefit in advancing the Rule's larger purpose of limiting the 'interstate transport of emissions of nitrogen oxides (NOx) and sulfur dioxide (SO2).' As such, the Agency should be utilizing every opportunity to further this purpose which should include non-covered sources on tribal lands that lie contiguous or near to those states covered by the Rule. These sources, like those located on the lands of states, are not otherwise be obligated to reduce their NOx and/or SO2 emissions unless covered by the Rule. With coverage, however, the EPA could seize a valuable opportunity to further the Rule's purpose, and ultimately help improve the health and welfare of all people and lands in the Eastern U.S. [EPA-HQ-OAR-2009-0491-3707, p.6]
The Band therefore recommends that the EPA allow non-covered sources on tribal lands beyond EGUs to be covered under the Transport Rule but only on a voluntary basis, as is true for similar sources on state lands. [EPA-HQ-OAR-2009-0491-3707, p.6]
Indiana Department of Environmental Management 
Indiana generally favors the idea of 'opt-ins' if the opt-in sources can obtain reductions that are as cost-efficient as those for the EGUs. However, these various opt-in source categories are best addressed separately, which is reported to be the intent of the second Transport Rule that U.S. EPA is developing. It would help States if U.S. EPA would provide the States with timelines early in the rule development process so that those choosing to develop their own SIPs can do so in a timely manner. Further, any future Transport Rule should fully consider the needs of states in relation to the anticipated 2010 ozone and 2011 fine particulate (PM2.5) NAAQS' by aligning emissions reductions and attainment dates. [EPA-HQ-OAR-2009-0491-2645.1, p.3]
Maryland Department of Environment (MDE)
Opt-ins
EPA has made corrections to the preamble to the proposed Transport Rule, indicating that they allow units to opt-in to each trading program included in the proposed rule (see 75 Federal Register 55711). Maryland opposes the inclusion of these opt-in provisions as outlined in the proposed Transport Rule. We recall that EPA allowed opt-ins with the NOx SIP call, and these provisions were not successful. With regard to the proposed Transport Rule, we note two specific aspects of the opt-in provisions that we consider completely unworkable. [EPA-HQ-OAR-2009-0491-2639.2, pp.10-11]
First is EPA's presumption that non-EGUs should be allowed to opt-in to any of the trading programs because non-EGUs may be able to make reductions at a lower cost than other covered (EGU) sources (75 FR 45308). This is particularly troubling because earlier in the preamble EPA claims that non-EGUs are not included as covered sources because they exceed EPA's $500 per ton cost threshold and EPA has not had sufficient time to develop the technical information necessary to include them in this proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2639.2, p.11]
Second, EPA proposes that "the allowances created for and allocated to the opt-in units would be in addition to the allowances issued from the state budget and would be usable in compliance by any covered unit (or opt-in unit) just like the allowances allocated from the state budget to covered sources" (75 FR 45308). Maryland opposes inclusion of these opt-in provisions unless the opting-in units are included under existing state caps. [EPA-HQ-OAR-2009-0491-2639.2, p.11]
Maryland holds this position despite EPA's assurance provisions and penalties. Otherwise, the proposed opt-in provisions will result in reduced pressure on EGUs to limit their own emissions, and the provisions provide too much opportunity for states to exceed the emissions budgets established by the Transport Rule and put public health at risk. [EPA-HQ-OAR-2009-0491-2639.2, p.11]
National Tribal Air Association (NTAA)
Opt-In of Non-Covered Sources
The Transport Rule also provides for non-covered sources (e.g., operating boiler, combustion turbine, or other stationary combustion device) to voluntarily enter trade programs with allowance allocations given to them based on their historical emissions. While the expectation of EPA is that these sources might be better able to make lower cost emissions reductions than EGUs within a state, thereby reducing the program's overall costs, this approach offers a more important benefit in advancing the Rule's larger purpose of limiting the 'interstate transport of emissions of nitrogen oxides (NOx) and sulfur dioxide (SO2). As such, the Agency should be utilizing every opportunity to further this purpose which should include non-covered sources on Tribal lands that lie contiguous or near to those states covered by the Rule. These sources, like those located on the lands of states, are not otherwise be obligated to reduce their NOx and/or SO2 emissions unless covered by the Rule. With coverage, however, the EPA could seize a valuable opportunity to further the Rule's purpose, and ultimately help improve the health and welfare of all people and lands in the Eastern U.S. [EPA-HQ-OAR-2009-0491-2778.1, p.6]
The NTAA therefore recommends that the EPA allow non-covered sources on Tribal lands beyond EGUs to be covered under the Transport Rule but only on a voluntary basis as is true for similar sources on state lands. [EPA-HQ-OAR-2009-0491-2778.1, p.6]
Pennsylvania Department of Environmental Protection
EPA has requested comment on the opt-in process proposed in 40 CFR §§ 97.441- 97.444. The opt-in provisions include the requirement that a unit 'has documented heat input (greater than 0 mmBtu) for more than 876 hours during the 6 months immediately preceding submission of the TR opt-in application.' Proposed 40 CFR § 97.441(a)(2)(iv). EPA should reconsider the use of 876 hours of operation six months prior to the control period as an opt-in requirement, as it provides an unnecessary obstacle for units that wish to opt in. There are regulated EGUs under the current CATR rule and EGUs that will be regulated under the Transport Rule that have not and do not meet this requirement. Units should be able to opt into the Transport Rule based upon their actual operations and emission rate identified per control period using a three-year base period, adjusting the baseline allocations each time the regulatory emission standard is modified. This would prevent sources from generating allowances by making reductions that were required anyway. New units should also need to operate below their permitted emission rate to get allowances. The DEP also recommends that once a unit opts into the program, it may not withdraw from the program. [EPA-HQ-OAR-2009-0491-2660.1, p.8]
Opt-in provisions in previous trading programs did not provide an incentive to participate. The large allowance banks of previous trading programs and state budgets that were large enough to provide plenty of allowances to the affected units to comply with regulatory requirements did not provide the right mix to spark interest for opting into those market-based programs. The key element necessary to drive an opt-in program is scarcity. The scarcity imposed by intrastate trading along with tighter emission budgets may make the opt-in provisions in the Transport Rule more inviting than opt-in provisions of previous trading programs, provided EPA removes unnecessary road blocks. [EPA-HQ-OAR-2009-0491-2660.1, p.8]
It is also important to require that units opting into the Transport Rule get allocated opt-in allowances based upon their updated regulatory requirements; those allowances could only be sold if the EGO owners or operators went beyond their regulatory obligations. [EPA-HQ-OAR-2009-0491-2660.1, p.8]
Pennsylvania's Existing Non-EGU Program
In the CAIR SIP approval, EPA approved Pennsylvania's treatment of non-EGUs covered by the NOx Budget Trading Program, in 25 Pa. Code §145.8 (relating to the transition to CAIR NOx Trading Programs). The DEP did not incorporate NOx requirements for non- EGUs in the Commonwealth's CAIR program. Non-EGUs remain subject to the statewide emission budget of the NOx Budget Trading Program; and under 25 Pa. Code Chapter 129, small sources of NO x emissions may surrender NOx allowances as an option for compliance demonstrations. In the final Transport Rule, we recommend that EPA clarify whether Pennsylvania will continue to allow a NOx allowance surrender option for its non-EGU program after adjusting some of its provisions to comport with the new Transport Rule. The DEP recommends that the final Transport Rule provide for the use of Transport Rule NOx allowances as a compliance alternative. [EPA-HQ-OAR-2009-0491-2660.1, pp.8-9]
Portland Cement Association (PCA)
Discussion:
The proposed opt-in provisions would allow a non-covered unit to enter a proposed trading program voluntarily and obtain an allocation of allowances reflecting the unit's emissions before opting in. Once in the program, the unit could make emissions reductions at a lower cost than other units in the program and then sell, to covered sources for use in compliance, allocated allowances that are in excess of the unit's reduced emissions. The allowances created for and allocated to the opt-in unit would be in addition to the allowances issued from the state budget and would be usable in compliance by any covered unit (or opt-in unit) just like the allowances allocated from the state budget to covered sources. Replacing higher cost reductions by covered units by lower cost reductions by opt-in units could reduce the overall cost of controlling emissions. In the event EPA moves forward with stringent requirements as outlined in the proposed Clean Air Interstate Transport Rule - requirements that will result in higher electricity costs - cement manufacturers support the option to voluntarily participate in an emissions trading scheme as a means of offsetting the costs of multiple mandates from EPA. [EPA-HQ-OAR-2009-0491-2789.1, p. 12]
The proposed opt-in provisions would establish the following procedures, which are similar to those set forth in the CAIR FIPs. A unit would be eligible to opt into one of the proposed trading programs if the unit: (1) Is an operating boiler, combustion turbine, or other stationary combustion device; (2) is in a facility that is located in a state subject to that proposed trading program; (3) vents all its emissions through a stack or duct; and (4) would be able to meet the monitoring, reporting, and recordkeeping requirements for covered units under the proposed trading program. The owners and operators, through a designated representative, of a source with a unit seeking to opt in would submit to EPA an opt-in application, which must include an emissions monitoring plan for the unit. If EPA approved the monitoring plan, the unit would operate, monitor, and report emissions in accordance with the monitoring plan and monitoring and reporting requirements under Part 75, for at least one or for up to three full calendar years (or full ozone seasons, in the case of an opt-in unit in the proposed NOX ozone season trading program). [EPA-HQ-OAR-2009-0491-2789.1, p. 3]
As stated previously, the cement industry advocates an inclusive approach to the trading program to maximize the number of facilities that would be eligible to participate. Cement facilities typically emit nitrogen oxides and sulfur dioxide at various levels, and the industry has made great progress to reduce these emissions since the introduction of the Clean Air Act. Some facilities might be able to offer significant reductions of these compounds that could further the goals of the Clean Air Transport Rule. It is in EPA's interest to encourage participation by a broader universe of potential sources. [EPA-HQ-OAR-2009-0491-2789.1, p. 3]
PCA recommends flexibility and inclusive criteria with respect to establishing criteria for manufacturers' opt-in to intra-state trading of emissions credits. EPA should assure that the final rule takes additional steps to encourage participation by manufacturing facilities that utilize industrial furnaces and other sources that have historically measured emissions on an output basis. EPA can accomplish this objective by including 'industrial furnaces' within the regulatory definition of 'covered units,' further clarifying eligibility for cement plants. With respect to measuring emissions on an output basis, for example, this has always been the case for Portland cement plants. Such plants, when they opt in, should be evaluated on an output based basis. This is the traditional method by which sources in that industry calculate their emissions, and it would be very difficult if not impracticable for them to change. Inserting language that clarifies that the program includes those sources that could take advantage of an output-based basis would expand the universe of potential opt-in participants to the benefit of the program and the other participants.  [EPA-HQ-OAR-2009-0491-2789.1, p. 3]
Conclusion:
The Portland Cement Association appreciates the opportunity to comment on EPA's proposed Clean Air Transport Rule. Although cement manufacturers oppose mandates that will increase electricity costs for its members, cement manufacturers prefer to use market-based incentives to achieve environmental goals in the most efficient manner possible. PCA advocates an inclusive approach featured by the flexibility and incentives necessary to encourage participation by a broad spectrum of sources. [EPA-HQ-OAR-2009-0491-2789.1, p. 3]
PPL Corporation
6. Opt-in Requirements
The proposed rule has opt-in provisions for combustion units other than the units that are required to be in the program (EGUs over 25 MW). Units eligible to opt-in include EGUs of 25 MW or less. However, there is a requirement that they operate at least 876 hours in the six months prior to submittal of their opt-in application (i.e., 20 percent of the hours). PPL understands that this is to allow EPA to establish reliable baselines for the units. We question the need for this requirement. [EPA-HQ-OAR-2009-0491-2739.1, p.8]
PPL owns and operates several combustion turbines of less than 25 MW that we may want to opt-in to the program. However, they are peaking units with annual capacity factors well under 10 percent and therefore would not be eligible to opt-in. We believe that existing units such as these have a long history of operation from which baseline conditions can be determined and which is as reliable as or more reliable than operating conditions over the previous six months. [EPA-HQ-OAR-2009-0491-2739.1, p.8]
PPL recommends that operating characteristics over the previous three years be an allowed substitute to establish baseline conditions for opt-in units if they did not operate 20 percent of the hours of the previous six months. [EPA-HQ-OAR-2009-0491-2739.1, p.8]
State of Missouri Department of Natural Resources
As prescribed on page 45308 of the proposed rule the opt-in provisions would allow non-electric generating units the option to enter a Transport Rule trading program as was similarly done in CAIR. The concern with allowing opt-in units is that it could elevate a state above their state-wide NOX and SO2 allocations and increase contributions to downwind nonattainment and maintenance areas which would not fully satisfy the CAA Section 110(a)(2)(D) mandate to eliminate upwind emissions that prevent downwind nonattainment or maintenance areas. [EPA-HQ-OAR-2009-0491-3806, p.4]
Response: 
See section VII.B of the preamble.
Organization: Louisiana Chemical Association (LCA)
Comment: 
Louisiana Chemical Association (LCA)
Comments on Applicability and The Cogeneration Exemption.
EPA Erroneously Included Projections and Allowances for Units that Meet the Cogeneration Exemption.
As support documentation to the proposed rule and FIP, EPA made available an Allocation Table which provides annual and ozone season NOx allocations for regulated EGUs. Without waiving any of the above and foregoing comments, LCA believes that if EPA persists in adopting a FIP, a number of EGUs belonging to its member companies that EPA purports to cover under the proposed applicability of the rule/FIP are actually exempt under the proposed "cogeneration exemption" not regulated under the proposed rule. LCA requests that EPA delete these units from any Technical Support Documents implying applicability and from the FIP Allocation tables and from any modeling associated with covered EGUs. [EPA-HQ-OAR-2009-0491-3527.1, pp., 43-44; see pp. 44-46 for extensive discussion of this issue.]
Additional Comments on the Cogeneration Exemption.
Date for Commencement of Limitations to Qualify for Cogeneration Exemption.
 EPA has also requested comments on certain aspects of its proposed rule. One of the areas where EPA requested comments concerns whether it would be problematic for sources to obtain detailed information about the disposition of a unit's generation back to November 15, 1990 and whether the efficiency and operating standards should be limited to more recent years rather than November 15, 1990. EPA suggested as an alternative for comment whether the exemption requirements should only be met every year starting the later of a date of a more recent year (e.g., 2000, 2005, or 2009) or the date on which the unit first produces electricity.118 EPA also requests comment on whether the electricity sales limit should be restricted to more recent years by requiring that the limit be met every year starting the later of a date of a more recent year (e.g., 2000, 2005, or 2009) or the start-up of a unit's combustion chamber. [EPA-HQ-OAR-2009-0491-3527.1, p. 46]
LCA believes that it could be problematic to produce detailed information about the disposition of a unit's generation, its efficiency and operating standards, and its electricity sales from as far back as November 15, 1990, which is nearly twenty years ago. The time period for recordkeeping under the Clean Air Act Title V permit program and similar programs is generally only five years. While most sources will have records of this type of information on major EGUs for the last 5 years, they may not have kept detailed information for prior years. Thus, the "start-date" for the exemption criteria should extend no further back than five years prior to the adoption of the final Transport Rule/FIP. [EPA-HQ-OAR-2009-0491-3527.1, p. 46]
Definition/Efficiency Standard for Cogeneration Units.
The "cogeneration unit" definition proposed under the Transport Rule/FIP differs from that under the Clean Air Interstate Rule ("CAIR"). Under CAIR, each unit had to meet individually the efficiency standard. Under the proposed rule, however, if the cogeneration system of which a topping-cycle unit is a part meets the efficiency standard on a system-wide basis, then the unit is also deemed to meet that efficiency standard. EPA requested comments on whether this approach should also be applied to bottoming-cycle units. [EPA-HQ-OAR-2009-0491-3527.1, p. 46]
LCA supports applying the approach of meeting efficiency standards on a system-wide basis to bottom-cycle units for the same reason that EPA has applied this approach to topping-cycle units. Allowing one unit in a cogeneration system to act as a "swing" unit and operate at a lower efficiency will allow the other units in the system to operate at higher efficiencies. Further, there is no basis for EPA to treat these two types of units differently for the purposes of meeting efficiency standards. Topping-cycle units and bottoming-cycle units have the same purpose -- to produce electricity and thermal power. The fundamental difference between these two types of units is the order in which electricity and thermal energy are produced. In topping-cycle units, the energy input to the unit is first used to produce useful power, including electricity, and then some of the reject heat from the electricity production is used to provide useful thermal energy. In bottoming-cycle units, the process is reversed, with the energy input to the unit first being used to produce useful thermal energy and then some of the reject heat from the useful thermal energy process being used for electricity production. As topping-cycle units and bottoming-cycle units have the same purpose and produce the same products, EPA should apply the same efficiency standards requirements to both types of units. [EPA-HQ-OAR-2009-0491-3527.1, p. 47]
EPA requested comment on whether the agency should exclude, from the requirement to meet the operating and efficiency standards, calendar years -- if any -- during which a unit does not operate at all. Under the proposed Transport Rule, the operating and efficiency standards in the "cogeneration unit" definition must be met every year. EPA is concerned because, as the rule is currently written, these annual standards would be applied in calendar years when a unit does not operate at all. LCA agrees with this concern and requests EPA to exclude these requirements in calendar years when the unit does not operate at all. [EPA-HQ-OAR-2009-0491-3527.1, p. 47]
LCA requests that EPA consider an additional option  -  revising the requirements for application of the cogeneration exemption to be exactly the same as the cogeneration exemption under the Acid Rain program, per 40 C.F.R. 72.6(b)(4). LCA does not believe that EPA has articulated a reason to adopt requirements for such exemption that would be different from the requirements under the Acid Rain rule. The Acid Rain cogeneration exemption is a statutory exemption that clearly indicates Congressional concern with regulating units that meet these criteria. Sections 402(17)(A) and 405(g)(6)(A)of the Clean Air Act include provisions discussing in detail the conditions under which a cogeneration unit is exempt from the Acid Rain Program. See, e.g., 42 U.S.C. 7651d(g)(6)(A) (stating that Clean Air Act title IV does not apply to qualifying cogeneration facility that meets certain conditions as of November 15, 1990, the date of enactment of title IV). LCA requests that EPA revise the cogeneration exemption under the proposed Transport Rule/FIP to be equivalent to the Acid Rain program exemption. [EPA-HQ-OAR-2009-0491-3527.1, p. 47]
Request for Emergency Exemption.
As a separate comment, LCA believes that EPA should provide an exemption to sources that exceed the annual electricity sales limit due solely to the occurrence of an emergency. This should apply to any EGU, not just to cogeneration units. For instance, EGUs as well as local transmissions systems located in Louisiana can be adversely affected by hurricanes or floods. There have been occasions in the past where EGUs adversely impacted by hurricanes have been unable to provide electricity to their customers. In those cases, sources meeting the cogeneration exemption may be called upon to temporarily increase their electricity production to provide for critical infrastructure power needs until the primary utility systems can return to electrical power production. By selling electricity in these times of crisis, exempt sources may exceed the proposed Transport Rule/FIP electricity sales thresholds and therefore trigger applicability under the Transport Rule/FIP. LCA believes that these sources should not be penalized by triggering regulatory applicability solely due to provision of power during such emergency periods. LCA thus requests that EPA provide an exception to the Transport Rule stating that sources will not lose their exemption for temporary activities that occur in response to emergencies. EPA could impose appropriate criteria to limit the scope of this exception; however, such an emergency exception is needed under the proposed rule. [EPA-HQ-OAR-2009-0491-3527.1, p. 48]
Response: 
See  section VII.B of the preamble.  EPA rejects the commenter's position that QF cogeneration facilities with long-term power purchase contracts in place since 1990 should be exempt from the Transport Rule trading programs.  While these facilities have an exemption under the Acid Rain Program established in 1990 under CAA title IV, EPA maintains that the commenter failed to provide a basis for establishing such an exemption under the final Transport Rule.  The Acid Rain Program began in 1995, and the exemption for these facilities provided a transition for them from non-regulation, or limited regulation, of their emissions to more stringent regulation of their emissions under CAA title IV.  In effect, the commenter claimed that CAA title IV created a permanent exemption for these facilities (until certain changes occur in their power purchase contracts) covering not only the Acid Rain Program, but also in all trading programs covering the electricity generation sector.  However, neither the statutory language nor the legislative history of CAA title IV supports the commenter's claim that Congress intended that the IPP and QF exemptions apply in trading programs established after the Acid Rain Program that had not even been proposed, much less implemented, when CAA title IV was passed.  Further, the circumstances under which the Acid Rain Program exemption was established have changed.  The Acid Rain Program was one of the first programs to require significant emission reductions throughout the electricity generation sector.  An exemption for IPPs and QFs with such long-term power contracts was not adopted in subsequent trading programs covering electricity generation, i.e., the NOx Budget Trading Program and the CAIR trading programs.  Also, the current market for electricity is much broader and less geographically segmented than it was in 1990, before the introduction of significant utility rate deregulation and electric industry restructuring.  Under these circumstances, EPA maintains that an exemption providing a transition from non- or limited emissions regulation to more stringent regulation is not appropriate since this category of units is already subject to emissions regulation.  In addition, an exemption for QF cogeneration facilities with long-term power purchase agreements could result in shifting of generation and emissions from units regulated under the Transport Rule to these units (the potential for which is enhanced by the existence of a broader, less segmented electricity market).  Such a shift could threaten achievement of elimination of states' significant contribution and interference with maintenance, which is the goal of the Transport Rule.  Although the exemption of any portion of the electricity generation sector creates the potential for generation shifting, the greater the number and scope of the exemptions, the greater the likelihood and likely magnitude of the potential generation shifting.  After the balancing the commenter's claimed rationale for the requested exemption and the potential adverse effect of such an exemption, EPA rejects the commenter's position. 
EPA also rejects the commenter's position that the operating and efficiency requirements in the cogeneration unit exemption should be removed.  In the final rule EPA exempts those cogeneration units that meet certain requirements.  First, the units must meet certain operating and efficiency requirements, and the commenter failed to show that these requirements are unreasonable.  EPA believes that it is reasonable to limit the exemption to units that demonstrate their efficiency.  Second, the units must meet the electricity sales limitation. Those units that sell less than the electricity sales limitation are treated as industrial, rather than electric generation, units and are exempt because the final rule is aimed at the electric generation sector. 
The commenter suggested that EPA create an exemption to the electricity sale limitation under the cogeneration unit exemption.  EPA rejects the commenter's approach.  Whatever the motivation behind a unit's  electricity sales, EPA believes that the level of the electricity sales limitation provides a reasonable, objective way of differentiating between cogeneration units treated as industrial units and those treated as electricity generation units.   The commenter's approach would introduce a major subjective element into the cogeneration unit exemption by requiring EPA to define what constitutes an "emergency" and to determine whether particular circumstances constituted such an "emergency".  The commenter did not suggest, much less support, any specific "emergency" definition.  In addition, EPA notes that the Clean Air Act already includes provisions for addressing national or regional energy emergencies, as described in the CAA.  See 42 U.S.C. 7410(f).  
Organization: Manitowoc Public Utilities (MPU)
Comment: 
Manitowoc Public Utilities (MPU)
 MPU requests EPA to confirm that the Proposed Transport Rule intends to follow the CAIR and Acid Rain Program (ARP) applicability standard that includes all units that are connected to a steam generator of more than 25 MW.  [EPA-HQ-OAR-2009-0491-2860.1, p.2] 
Applicable Units  
MPU recommends that EPA clarify the applicability requirements for a small EGU. It is our understanding that the Proposed Transport Rule intends to follow the CAIR and Acid Rain Program (ARP) applicability standard that includes all units that are connected to a steam generator of more than 25 MW. We are confused because our steam generating units of less than 25 MW were not included in the allocation analysis. We have three steam generating units that have an MCR of less than 25 MW, however they are connected to steam turbine generator of more than 25 MW. The units are therefore currently regulated by CAIR and the ARP. [EPA-HQ-OAR-2009-0491-2860.1,p.4]
Response: 
See section VII.B of the preamble.
Organization: Massachusetts Department of Environmental Protection
Comment: 
Massachusetts Department of Environmental Protection
EPA seeks comment on whether it should include non-EGU NOx and S02 emissions in the Transport Rule programs. It also seeks comment on lowering the greater-than-25 megawatt (MWe) applicability threshold for EGUs during the ozone season. MassDEP believes additional cost-effective and timely reductions of NO x and S02 are available from both non-EGUs and smaller EGUs.4 It urges EPA to consider inclusion of these sources in the proposed Transport Rule. If the final Transport Rule does not include these sources, EPA should require reductions from non-EGUs and smaller EGUs under the next Transport Rule in the shortest possible time frame. [EPA-HQ-OAR-2009-0491-2787.2]
MassDEP also supports lowering the 25MWe applicability threshold for EGUs to include EGUs in the 15-25 MWe range. Although the overall emissions from these units are small in proportion to the larger EGUs, these units may be called upon on high-energy-demand days (HEDD), when ozone concentrations are often high. Because EPA has not proposed to otherwise address the concerns of ozone nonattainment areas related to HEDD, inclusion of these smaller units is one way to address HEDD emissions. [EPA-HQ-OAR-2009-0491-2787.2]
MassDEP believes that EPA is overlooking the significant S02 emissions reductions available from ICI boilers through fuel- switching, which can be cost-effective within the 2012-2014 timeframe. Several states within the Ozone Transport Region are pursuing sulfur in fuel reduction strategies.9 Recent amendments to the New Jersey Sulfur in Fuels regulation will further reduce the sulfur content of fuel oils beginning in 2014 through 2016. 10 The delay in implementation until 2016 in the revised New Jersey Sulfur in Fuels regulation is attributable in part to the reluctance of refiners to add desulfurization capacity absent strong market or regulatory signals. 11 Expanding the Transport Rule to require significant S02 emissions reductions available from ICI boilers through fuel- switching would send the necessary market and regulatory signals. For Massachusetts, S02 reductions in the 2012-2014 timeframe could also serve to meet requirements related to Regional Haze.   [EPA-HQ-OAR-2009-0491-2787.2 p.5]
Response: 
See sections VI.A, VII.B, IX.A and B, and X of the preamble. The final rule gives states the option of expanding the applicability provisions of the Transport Rule NOx ozone season trading program to include units serving generators with a nameplate capacity of 15 MWe or greater producing electricity for sale.  This is consistent with the approach taken in the NOx Budget Trading Program, where some state elected to include units serving generators with a nameplate capacity of 15 MWe or greater producing electricity for sale.
Organization: Michigan Department of Natural Resources and Environment
Comment: 
Michigan Department of Natural Resources and Environment
The proposal has electric generating units (EGUs) greater than 25 megawatt (MW) output subject to the TR. However, when reviewing Michigan subject source data, units with outputs less than 25 MW were included. The EPA apparently used these additional units to determine the electricity reliability in a given area. [EPA-HQ-OAR-2009-0491-2774.1 p.5]
The DNRE has concerns about this methodology and requests clarification as to why the smaller sources were included. First, the use of non-subject units to affect reliability is miniscule at best and is in direct opposition to the methods used by the Federal Electric Regulation Commission to indicate which unit will be 'turned on' to meet electricity demands. Coal-fired units have been the determining reliability factor in Michigan for several years. When additional demand occurs, the independent natural gas-fired units are utilized to meet additional electrical needs. The amount of electricity supplied by the smaller MW units is not sufficient to maintain reliability. The DNRE believes that these units should not be addressed in the TR, nor should they be used to determine electricity needs in Michigan. [EPA-HQ-OAR-2009-0491-2774.1 p.5]
The proposed TR opt-in provisions allow a non-covered unit to enter the proposed trading program voluntarily and obtain an allocation of allowances reflecting the unit's emissions prior to opting in. Sources choosing to participate in the opt-in program are required to remain in the program for a minimum of four years (or compliance periods). The allowances created for and allocated to the opt-in unit would be in addition to the allowances issued from the state budget. [EPA-HQ-OAR-2009-0491-2774.1 p.6]
The DNRE supports allowing non-affected sources to opt-in to the TR program and the opt-in provisions allowing a source to opt-in to a subset of the trading category (groups 1 or 2 for sulfur, NOx annual and NOx ozone season). [EPA-HQ-OAR-2009-0491-2774.1 p.6]
The proposed TR rule allows non-EGUs to opt-in under the FIP and includes the option of bringing in non-EGUs under the SIP as long as the FIP emissions budgets are not changed. However, it appears that states cannot require the sources to participate. The proposed TR envisions states addressing the non-EGUs as a NOx-SIP fix-up package, as once the CAIR program has been removed from the state rules an 'anti-backsliding' issue may exist for the NOx Budget Program.  [EPA-HQ-OAR-2009-0491-2774.1 p.6]
The DNRE supports the opt-in provisions because it allows the non-EGUs from CAIR to participate in the ozone season NOx program under the TR, which widens the non-EGUs trading capabilities from a small intrastate pool to the entire TR region.  [EPA-HQ-OAR-2009-0491-2774.1 p.6]
The DNRE has concerns about the length of time required to revise the state's rules, which will be necessary for the non-EGUs currently subject to the NOx SIP Budget Program. Our concerns include how the non-EGUs will address their ozone season NOx emissions, in particular when the FIP goes into effect prior to any SIP provisions by the state. To address the changes from the proposed TR, Michigan will need to revise the NOx rules that allowed the addition of the non-EGUs into the CAIR program and rescind the current state CAIR rules.  [EPA-HQ-OAR-2009-0491-2774.1 p.6]

 
The proposed TR exempts cogeneration units that supply, in any given calendar year, no more than one-third of its potential electric capacity, or 219,000 MWh, whichever is greater, to any utility power distribution system for sale.
The DNRE supports the concept of exempting cogeneration units meeting the above criteria. However, we have concerns that sources may, due to yearly determinations, be 'in and out' of the proposed TR requirements. The DNRE believes that source exemption determination should not be made on a yearly basis. Once a source has become subject to the program, they should remain subject and not be allowed to use the exemption for at least four future years and contrarily if a source is exempted, it should remain so for the next four year cycle, similar to the opt-in provisions within the TR. [EPA-HQ-OAR-2009-0491-2774.1 p.7]

 
Solid Waste Incineration Exemption
The proposed TR exempts solid waste incineration units using 80 percent or more non-fossil fuel, consistent with an EPA interpretation made during implementation of CAIR. The EPA interpretation limits the term 'fossil fuel' to natural gas, petroleum, coal, or any form of fuel derived from the previous types for the expressed purpose of creating useful heat. Following the previous interpretation, solid waste incineration units with 80 percent or more non-fossil fuel used would be exempt from TR. This eliminates tires and other products from becoming defined as fossil fuel as they were not manufactured to create a fuel source. [EPA-HQ-OAR-2009-0491-2774.1 p.7]
The DNRE agrees with this exemption; however, we request c1arifiQation regarding the limitations on the term fossil fuel fired. Several sources in Michigan incinerate solid waste, i.e., tires, trees, and other wood refuse to create electricity or steam. Are these units exempt if they use 80 percent or more of non-fossil fuel although they sell electricity to the grid from a unit with capacities greater than 25 MW? [EPA-HQ-OAR-2009-0491-2774.1 p.7]
The DNRE believes that sources which primarily use non-fossil fuels but generate electricity and are greater than 25 MW should be subject to the proposed TR programs. [EPA-HQ-OAR-2009-0491-2774.1 p.7]
The proposed TR includes a 'cogeneration' definition different than used under CAIR. The major significant change is the ability for topping-cycle units to meet the 'efficiency requirements' on a system-wide basis. Topping-cycle units produce steam to generate electricity and leftover steam is utilized in the facility for heat or hot water. Bottoming-cycle units typically produce steam for heat or hot water and any remaining steam is used to generate electricity. The EPA also requested comments regarding the use of the same system-wide efficiency for the bottom-cycling units. [EPA-HQ-OAR-2009-0491-2774.1 p.7]
The DNRE agrees that a system-wide basis for meeting efficiency is appropriate for topping cycle units. However, we have reservations about using the system-wide basis for the bottoming-cycle units. Most of the bottoming-cycle units consist of various process heaters and boilers. The DNRE believes these units could have a difficult time demonstrating efficiency on a system-wide basis due to the differences in sizes and capabilities of these process units. [EPA-HQ-OAR-2009-0491-2774.1 p.7]
Response: 
See sections VI.B, IX.A and B, and X of the preamble.  EPA notes that, even assuming that the commenter is correct that the electricity provided by small EGUs is alone insufficient to maintain reliability, the commenter failed to show why such units should be ignored in considering issues concerning electric reliability.  EPA also notes that, under the cogeneration unit and solid waste incineration unit exemptions in the final rule, a unit cannot "go in and out" of the exemption.  Once an exempt unit no longer meets the requirements for the exemption for a given year, that unit, by the terms of the exemption provisions, cannot meet the exemption requirements in any subsequent year and continues to be a covered unit.  See sections 97.404(b), 97.504(b), 97.604(b), and 97.704(b). 
Organization: Mostardi Platt Environmental
Comment: 
Mostardi Platt Environmental
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.91-92.]
I have not read the Rule yet. I'm going to be, but going back to the original CAIR rule, in the applicability section there was something I think the Agency did not intend, to bring a lot of new biomass projects coming on line into the CAIR rule, but it unintentionally did, because of the fossil fuel provision that said if you ever use any fossil fuel...
A lot of these biomass projects do use natural gas for startup, and startup alone for load balancing, but it's a very small percentage of the actual heat input into the biomass projects.
If that same language is contained in the new Transport Rule, it might be beneficial to encourage biomass to take a look at that language and maybe come up with some de minimis fossil fuel use, if used for startup and load balancing only, and that will certainly help encourage the biomass industry without I think sacrificing air quality.
Response: 
See section VII.B of the preamble.  The final rule covers fossil-fuel-fired units serving a generator with a nameplate capacity greater than 25 MWe and defines "fossil-fuel-fired" as combusting any amount of fossil fuel in 2005 or later.  EPA rejects, for several reasons, the commenter's approach of excluding units with so-called "de minimis" amounts of fossil fuel use.  The approach in the final rule is consistent with the approach used in prior EPA trading programs covering the electric generation industry, e.g., the Acid Rain Program, the NOx Budget Trading Program, and the CAIR trading programs.  The commenter did not provide any basis for using a different approach in the Transport Rule trading programs covering the same industry and did not specify a level of fossil fuel use (as a percentage of total fuel use) as the cut-off for what would constitute "de minimis" fossil fuel use in these programs.  Moreover, if the applicability of the Transport Rule trading programs for all units were to depend on exceeding a specific level of fossil fuel use, a significant number of units' regulatory status could change during the course of the year.  Specifically, a unit's fossil fuel use can vary, depending on, among other things,  changes in unit operation and fuels.  As noted by the commenter, some units use fossil fuel for startup and combustion stabilization, and so fossil fuel use can vary depending on the frequency of startups and shutdowns and on factors (such as the moisture content and other characteristics of the other fuels being combusted) affecting the need for combustion stabilization.  Units that were excluded from the Transport Rule trading programs because of their "de minimis" fossil fuel use would not report fuel use to EPA, and so determination of whether a significant number of units were subject to the trading programs, and assurance of compliance, would be problematic.  Although units that burned no fossil fuel starting in 2005 are excluded from the Transport Rule and could potentially have their regulatory status change by beginning to burn fossil fuel, EPA believes that this is less likely to occur than in the case of units have been burning some fossil fuel.  EPA therefore maintains that the approach in the final rule of covering units that burned any fossil fuel starting in 2005 and that serve a generator with a nameplate capacity greater than 25 MWe producing electricity for sale and excluding units that burned no fossil fuel starting in 2005 is reasonable.
Organization: National Environmental Development Association
Comment: 
National Environmental Development Association
NEDA/CAP Agrees That Many Cogeneration Owners Will Find It Difficult To Substantiate Electricity Generation And Meet Other Requirements of the Proposal in Order to Qualify for the Proposed CATR Exemption.
On pages 45306-7 of the Federal Register Notice, EPA discusses the rule's proposed exemption for "cogeneration units." In order to qualify for such exemption, however, the owner or operator of the proposed unit would be required to have records demonstrating that since November 15, 1990, that unit met the efficiency and operating standards set forth for such units in the proposal (e.g., the owner/operator of the unit would need to supply evidence that in every calendar year since 1990, that that no more than one-third of the unit's potential electric output capacity or 219,000MWh, whichever is greater, was supplied to any utility power distribution system for sale, and that the useful power plus one-half of useful thermal energy output of the unit must equal no less than a certain percentage of the total energy input). Id. EPA requests comment on whether it may be problematic to obtain sufficiently detailed information about the disposition of a unit's generation . . . back to November 15, 1990 and whether the electricity sales limit should be restricted to more recent years by requiring that the limit be met every year starting the later of a date (e.g., 2000, 2005, or 2009) or the start-up of the unit's combustion chamber. [EPA-HQ-OAR-2009-0491-2744.1 p.2]
NEDA/CAP's members appreciate EPA's sensitivity to this issue. The record-retention requirements of the Clean Air Act are also limited to five (5) years. Moreover, most, if not all of NEDA/CAP's members, have corporate document retention policies which limit records retained by a facility to no more than five (5) years. Thus, unless facilities retained records in violation of these corporate policies, they would be unable to meet the requirements to demonstrate they are exempt from the CATR rule. Yet to fail to exempt these units from CATR, we believe, would be counter to the nation's energy policies promoting construction and operation of cogeneration facilities. Regulation under the proposed CATR rule also may impose significant costs and potential feasibility issues on certain units. For these reasons, we recommend that EPA provide in the final rule that the exemption be based on a demonstration of information including but not limited to information on electricity sales every year starting the later of the date five years before the effective date of the final rule or the start-up of the unit's combustion chamber, whichever is later. [EPA-HQ-OAR-2009-0491-2744.1 p.2]
Response: 
See section VII.B of the preamble.
Organization: Nelson Industrial Steam Company (NISCO)
Comment: 
Nelson Industrial Steam Company (NISCO)
NISCO believes that it should not be subject to the CATR because its two units are efficient cogeneration units and because NISCO sells such a de minimis amount of electricity neither of the two units should be considered to be an Electric Generating Unit ('EGU') within the meaning of the proposed CATR. These two units meet the definition of cogeneration units under the Public Utilities Regulatory Policies Act ('PURPA'). In addition, they are exempt from the Clean Air Act's Acid Rain rules under the 'cogeneration exemption' of 40 C.F.R. 72.6(b)(4) because neither of the units provides more than 1/3 of its potential electrical output capacity ('PEOC') or more than 219,000 MWh to a utility power distribution system for sale. The NISCO facility is not regulated as a public utility by the Louisiana Public Service Commission. [EPA-HQ-OAR-2009-0491-2813.1, p.1]
Neither of the NISCO units has ever sold more than 1% of its electrical output to a utility power distribution system, except during the aftermath of Hurricanes Katrina and Rita in 2005 when the annual sale of electrical output from the two units combined was only 2.58% of the total annual output. In five of the last seventeen years, NISCO has not sold any electricity to the grid. In six or more of those years, sales were below 0.2% of total generation. Only in 2005 did sales to the grid exceed 1% and because 2005 was the year of Hurricanes Katrina and Rita, the special force majeure circumstances of those storms account for these extra sales. [EPA-HQ-OAR-2009-0491-2813.1, p.2]
III. EPA Should Revise the Requirements for the Cogeneration Exemption and/or Should Create an Exemption for De Minimis Sales of Electricity from Non-Cogeneration EGUs
As noted above, it is believed that very little, if any, NOx and SO2 reductions should be required of Louisiana EGUs in order to satisfy the 'good neighbor' provisions of the CAA by preventing interstate transport of Louisiana emissions that would adversely impact the annual PM2.5 design values or 1997 8-hour design values in areas of Texas. NISCO believes that even use of the IPM 4.10 Base Case values, will result in findings that Louisiana does not impact these NAAQS, even without the downward emission inventory revisions and other adjustments requested in these comments. However, in the unlikely event that EPA still finds that there is a requirement for reduction of Louisiana sources, there is no mandate that such reduction come from EGUs or even substantially from EGUs. Where, as indicated above, there are enforceable consent decree reductions already scheduled from other non-EGUs in an amount likely to reduce any significant contribution or interference with maintenance, it would be arbitrary for EPA to require more than is needed under a FIP (or SIP). After these reductions, very little, if any further reductions should be required in Louisiana from EGUs. For this reason, there is no need for EPA to go beyond the Acid Rain definitions of cogeneration unit to include an efficiency requirement.. EPA did not make any finding that NISCO needed to retrofit to meet the CATR. NISCO requests that if EPA moves forward with a Louisiana FIP, EPA should create a Louisiana-only exclusion for cogeneration units meeting the Acid Rain cogeneration exemption but not meeting the generic CATR proposed efficiency standard. [EPA-HQ-OAR-2009-0491-2813.1, pp.11-12]
EPA has not articulated a basis under CATR for requiring an efficiency requirement in addition to a unit meeting the other 'Acid Rain' requirements for a unit to qualify as a cogeneration unit, and thus be eligible for the proposed 'cogeneration exemption.' NISCO believes that in order for EPA to enact such a requirement that goes beyond the Acid Rain program, it must have a basis that is linked to the purpose of the good neighbor clause of the CAA. The purpose of the proposed CATR/FIP is to reduce interstate transport of PM2.5 and ozone precursors, not necessarily to penalize certain types of cogeneration units that EPA believes to be less efficient than other types of cogeneration units. The NISCO units received PSD permits and their S02 and NOx emissions meet Best Available Control Technology levels. They provide a valuable function by using readily available pet-coke supplies as fuel to power local manufacturing facilities. Thus, NISCO believes EPA should revise the cogeneration unit definition under the final CATR (nationwide) to be equivalent to the cogeneration unit definition under the Acid Rain program. But, as noted, if EPA does not make that a nationwide provision, it certainly should enact such a provision in any FIP for Louisiana, or should specify that if a state enacts a SIP to implement CATR, such state may provide for such a definition. [EPA-HQ-OAR-2009-0491-2813.1, p.12]
In the further alternative, NISCO believes that EPA should create an exemption from classification as a CATR applicable unit for facilities that sell de minimis amounts of electricity to the grid. As noted above, neither of the NISCO units has ever sold more than 1% of its electrical output to a utility power distribution system, except during the aftermath of Hurricanes Katrina and Rita. NISCO believes that EPA has the inherent authority to interpret the phrase 'producing electricity for sale' within the definition of EGU so as to exclude: a) incidental production of electricity for sale when it amounts to less than 1% of the unit's annual output and b) production of a small amount of electricity for sale only for limited periods during or in response to natural disasters. See Alabama Power Co. v. Castle, 636 F.2d 323 (D.C. Cir. 1979); United States v. American Trucking Ass'ns, 310 U.S. 534, 543, 60 S.Ct. 1059, 1063, 84 L.Ed. 1345 (1939); District of Columbia v. Orleans, 132 U.S.App.D.C. 139, 141, 406 F.2d 957, 959 (1968)); Ober v. Whitman, 243 F.3d 1190 (9th Cir. 2001); and Environmental Defense Fund, Inc. v. EPA, 82 F.3d 451 (D.C. Cir. 1996). [EPA-HQ-OAR-2009-0491-2813.1, p.12]
NISCO requests that EPA amend the proposed CATR to provide for a definition of 'cogeneration facility' equivalent to that found under the Acid Rain program, without the additional efficiency requirement proposed by EPA. Further, or in the alternative, NISCO requests that EPA amend the proposed CATR to provide for an exemption for EGUs that sell less than 1% of the PEOC to the grid. If such revisions are not made, and without waiving any legal rights to contest the necessity for the proposed FIP or any part thereof, NISCO also requests that to the extent EPA relies upon the IPM for any purpose, it should correct all of the data errors noted herein. [EPA-HQ-OAR-2009-0491-2813.1, p.13]
Response: 
See section VII.B of the preamble.  The commenter claimed, without providing any support, that its cogeneration units are "efficient" and argued that cogeneration facilities should be exempt from the Transport Rule trading programs without meeting any efficiency requirements simply because the Acid Rain Program included cogeneration unit exemptions without efficiency requirements.  EPA rejects the commenter's approach. In the final rule EPA exempts those cogeneration units that meet certain requirements.  First, the units must meet certain operating and efficiency requirements, and the commenter failed to show that these requirements are unreasonable.  EPA believes that it is reasonable to limit the cogeneration unit exemption to units that demonstrate their efficiency.  In effect, the commenter claims that CAA title IV created a permanent exemption for cogeneration units covering not only the Acid Rain Program, but also in all trading programs covering the electric generation sector including those that were not even proposed, much less implemented, when CAA title IV was passed.  Neither the statutory language nor the legislative history of CAA title IV supports such a claim.  EPA notes that the NOx Budget Trading Program did not include any exemption for cogeneration units.  Further, the circumstances under which the Acid Rain Program exemption was established have changed.  The current market for electricity is much broader and less geographically segmented than it was in 1990, before the introduction of significant utility rate deregulation and electric industry restructuring.  The broadening of the cogeneration unit exemption beyond that in the final Transport Rule could result in shifting of generation and emissions from units regulated under the Transport Rule to some of the additional cogeneration units that would be exempt because of the high level of integration of the electric generation, transmission, and distribution system (which has increased with the broader, less segmented electricity market) and thereby threaten achievement of elimination of states' significant contribution and interference with maintenance, which is the goal of the Transport Rule.  Although the exemption of any portion of the electricity generation sector creates the potential for generation shifting, the greater the number and scope of the exemptions, the greater the likelihood and likely magnitude of the potential generation shifting.  After the balancing the commenter's claimed rationale for the requested exemption and the potential adverse effect of such an exemption, EPA rejects the commenter's position
The second requirement for qualifying for the cogeneration unit exemption under the final Transport Rule is that the cogeneration unit must meet the electricity sales limitation.  Those units that sell less than the electricity sales limitation (i.e., the greater of 219,000 MWh, or one-third of the unit's potential electrical output capacity, per year) are treated as industrial, rather than electricity generation, units and are exempt because the final rule is aimed at the electricity generation sector.  The commenter claimed that the sales limitation should be changed.  The commenter's alternative to the sales limitation is unclear in that, at one point in the comments, the commenter suggested a limit of 1% of a unit's annual output, at another point the commenter suggested a limit of 1% of a unit's potential electrical output capacity (PEOC), and at another point the commenter seemed to limit the alternative limit to sales for only "limited periods during or in response to natural disasters".  EPA rejects commenter's approach.  First, it is unclear why the commenter suggested limits of 1% of annual output or 1% of PEOC when the final rule already sets a higher limit of the greater of 219,000 MWh, or one-third of PEOC, per year.  If the commenter intended to suggest that one of its three alternative electricity sales limitations be used and no operating and efficiency requirements be imposed, EPA rejects this for the reasons discussed above.  Further, the purpose of the electricity sales limitation is to distinguish between cogeneration units that are considered industrial and those that are considered part of the electricity generation sector, which is the sector whose emissions the final Transport Rule is aimed at reducing.  EPA notes that the electricity sales limitation has been used in the Acid Rain Program and in the CAIR trading programs to make this distinction.  Whatever the motivation behind a unit's  (e.g., the NISCO units) electricity sales, EPA believes that the level of the electricity sales limitation provides a reasonable, objective way of differentiating between cogeneration units treated as industrial units and those treated as electricity generation units.   The commenter's approach would introduce a subjective element into the cogeneration unit exemption by requiring EPA to determine what constitutes "a small amount" of sales for a "limited period" during a "natural disaster".  In addition, EPA notes that the Clean Air Act already includes provisions for addressing national or regional energy emergencies, as described in the CAA.  See 42 U.S.C. 7410(f).  
Organization: North Carolina Department of Environment and Natural Resources
Comment: 
North Carolina Department of Environment and Natural Resources
We concur with proposal to exempt cogeneration units on the basis of electrical generation and unit efficiency (although such units may choose to use the opt-in provisions discussed later). It appears beneficial! to encourage such energy efficient designs through the exemption process. Furthermore, future projects and an increase in co-generation projects would be reviewed under other regulatory programs I such as PSD and MACT to address emissions control technology and strategies to minimize downwind impacts concerns of FTR, if only in an indirect way, Complete and accurate records for older units may provide data challenges, as noted in the preamble, back to the signing of the 1990 Clean Air Act Amendments and the nature of unit operation may favor using the first complete set of operation data for a unit, selecting a later data may provide a more level regulatory basis for review of a cogeneration unit.  However operational records for periods after 2000 and certainly after 2003 should be retrievable, for most units. Use of this time period should provide a satisfactory basis for reviewing the exemption status. finally calendar years without any operation should not count against a unit's annual efficiency calculation. EPA could consider a minimum hour threshold to determine if the unit operated in the calendar year (e.g., 1000hr). [EPA-HQ-OAR-2009-0491-2767.1 p.7]
Response: 
See section VII.B of the preamble.
Organization: Northshore Mining Company
Comment: 
Northshore Mining Company
Northshore appreciates that allocations for NOx and S02 have been provided to SBP as noted in the Technical Support Document to the Proposed Rule at Docket ID No. EPA-HQ-:-OAR-2009- 0491-0057-1. However, Northshore remains concerned that privately owned and operated cogeneration power plants, which are not public utilities, are subject to the Transport Rule. EPA justifies the economic impact of the Transport Rule from the perspective that the cost of compliance will be passed on to electric utility rate payers. In drafting the proposed rule EPA states:

'Ultimately, we believe the electric power industry will pass along most of the costs of the rule to consumers, so that the costs of the rule will largely fall upon the consumers of electricity. ' [EPA-HQ-OAR-2009-0491-2822.1 p.1]

75 Fed. Reg. 45352 (August 2,2010). It is clear that EPA intended the Transport Rule to apply specifically to electric utilities, which have the ability to 'pass along most of the costs of the rule to consumers' and not to privately owned, industrial facilities. As EPA has explained since at least 1979, the Agency draws a distinction between 'electric utility steam generating units and industrial boilers because there are significant differences between the economic structure of utilities and the industrial sector.' See 44 Fed. Reg. 33580,33589 (June 11, 1979). Whereas a utility may pass on the costs of a rule such as the Transport Rule to its retail customers, an industrial facility, such as Northshore, which sells a wholesale product, concentrated iron ore pellets, to a limited customer base may not. To the contrary, the price for iron ore pellets is established in the world market place and Northshore must sell its pellets at that price. If Northshore were to add to the price of its pellets the cost of compliance with the Transport Rule, its customers would refuse to buy the pellets because they could buy pellets at the market price from other suppliers. [EPA-HQ-OAR-2009-0491-2822.1 p.1]

During 2010 EPA promulgated far more stringent National Ambient Ail' Quality Standards (NAAQS) for N02 and S02. During the next few years each state must designate areas of the state that are either in attainment or nonattainment with the NAAQS. As a result of the more stringent standards now in effect, there is high likelihood that more nonattainment areas will be designated in more states. This in turn will require reductions in emissions from sources in upwind states pursuant to the Transport Rule that are contributing to the nonattainment designations of areas in downwind states. [EPA-HQ-OAR-2009-0491-2822.1 p.2]

Assuming sufficient allocations would not be available for purchase and additional emission controls would have to be installed, the cost of the additional emission controls at public utilities will be passed on to the electricity rate payers. However, the cost of such increased emission controls at Northshore' s power plant, which could be several tens of millions of dollars, would have to be borne by Northshore. Installation of the emission control equipment at this level of cost would be cost prohibitive for Northshore and could lead to the shutdown of the iron ore operations. This would result in the loss of approximately 640 direct jobs and an estimated 1150 additional indirect jobs involved with supporting Northshore's operations. Mining is the single largest contributor to the region's economy. During 2009 Northshore's purchases of local services and supplies were more than $110 million, and it paid over $11 million in state and local taxes for a total economic impact of$121 million. These figures demonstrate that if Northshore were to shut down because it could not afford to comply with the Transport Rule, the economic impact to Northeastern Minnesota would be tremendous at a time when the country is just beginning to emerge from the longest recorded economic recession since the Great Depression. [EPA-HQ-OAR-2009-0491-2822.1 p.2]
For these reasons, Northshore requests that EPA clarify in the final Transport Rule that the rule is applicable to only public utilities that can pass the cost of compliance on to rate payers. Specifically, Northshore requests that EPA clearly state that the Transport Rule applies to the electric power sector (Electric Utilities and Independent Power Producers), which refers to that sector of the power generating industry that comprises electricity-only and combined-heat-and power (CHP) plants whose primary business is to sell electricity, or electricity and heat, to the public. In so doing, EPA will promulgate the Transport Rule in accordance with its premise as stated in the economic impact assessment of the rule that most of the cost of compliance with the rule will, in fact, be passed on to a wide array of consumers of electricity. With this approach, no industrial facility or single electricity rate payer will suffer a significant economic hardship from the Transport Rule while ail' quality improves in downwind states. [EPA-HQ-OAR-2009-0491-2822.1 p.2]
Response: 
EPA rejects the "clarification" requested by the commenter concerning the applicability of the Transport Rule.  The applicability criteria determining what units are subject to the Transport Rule trading programs, and the reasons for adopting these criteria, are set forth in section VII.B of the preamble.  These criteria cover units, like the commenter's units, that produce electricity for sale.  EPA maintains that it is reasonable to treat units (serving generators of the requisite size) producing electricity for sale as part of the electricity generation sector, which is subject to the Transport Rule trading programs.  While EPA believes that units subject to the Transport Rule trading programs will ultimately be able to pass through most costs of compliance, the ability to pass through is not one of the requirements for a unit to be subject to the trading programs.  See sections VIII.D and XII.H of the preamble.
The commenter claimed that its cogeneration units should not be treated "more stringently than their less-efficient industrial boiler counterparts" and argued that "historic" cogeneration units should be exempt from the Transport Rule trading programs without meeting any efficiency requirements.  EPA rejects the commenter's approach.  In the final rule EPA exempts those cogeneration units that meet certain requirements.  In particular, the units must meet certain operating and efficiency requirements, and the commenter failed to show that these requirements are unreasonable.  EPA believes that it is reasonable to limit the cogeneration unit exemption to units that demonstrate their efficiency.  See section VII.B of the preamble.
In addition, EPA rejects the commenter's claims that compliance with the final Transport Rule would be "cost prohibitive", and "could lead to the shutdown of [its] iron ore operations" as vague, unsupported, and speculative.  The commenter seemed to assume, without support, that sufficient allowances would not be available for purchase for compliance.  EPA's experience with prior trading programs, such as the Acid Rain Program, the NOx Budget Trading Program, and the CAIR trading programs, is that the trading programs result in robust allowance markets in which allowances are available for purchase.
Organization: NRG Energy	
Comment: 
NRG Energy
NRG recommends that EPA lower the CATR Applicability Threshold for Ozone Season CATR proposes an applicability threshold of 25 MWe for electric generating units (EGUs). EPA is requesting comment on the need to lower this EGU threshold for the Ozone Season to 15 MWe for sources within the Northeast region. [EPA-HQ-OAR-2009-0491-2749.1, p. 9]
The reasoning for the lower threshold is based on perceived issues related to NOx emission on High Electric Demand Days (HEDDs). On March 2, 2007 representatives from the Ozone Transport Commission (OTC) states signed a Memorandum of Understanding (MOU) regarding reductions of NOx emissions during HEDDs. Only five of the twelve OTC member states are listed in the MOU as having a tons per day reduction goal from historic NOx tons emitted by HEDD units. The MOU also lists seven actions that states may implement to meet their HEDD goals. [EPA-HQ-OAR-2009-0491-2749.1, p. 9]
In addition to addressing some HEDD issues, the inclusion of the 15  -  25 MWe units would address states' concerns on potentially having to regulate sources that are currently regulated by CAIR but would not be included in the TR. This could result in a state implementing its own Ozone Season cap-and-trade program and/or implementing regulations to lower the allowable NOx rate for these sources. [EPA-HQ-OAR-2009-0491-2749.1, p. 9]
A cap-and-trade program with a larger geographic area results in more emission reductions, a common platform for compliance, and a more liquid allowance market than a state-only program. Because source owners are currently included in the CAIR Ozone Season program, the transition to TR would not impose the financial burden and learning curve associated with individual state-only actions. Including the 15  -  25 MWe sources in TR's Ozone Season program will eliminate the time and financial burden that a state only program would place on state agencies and all affected sources. It is also doubtful that any state program would be developed and implemented as soon as the TR. [EPA-HQ-OAR-2009-0491-2749.1, pp. 9-10]
NRG supports the inclusion of the Northeast region 15  -  25 MWe sources in the TR Ozone Season programs provided the following design elements are included in the program: 1. The Northeast region is defined as the Ozone Transport Region, 2. Affected sources will be defined in the same manner as in CAIR, 3. State only programs are not required unless the individual states demonstrate that additional reductions from the 15  -  25 MWe sources are required to meet attainments, and 4. Affected states' Ozone Season budgets are adjusted to include allocations for affected sources based on the affected sources' Ozone Season 2008 emissions. [EPA-HQ-OAR-2009-0491-2749.1, p. 10]
Response: 
See sections VII.B, IX.A and B, and X of the preamble.
Organization: Occidental Chemical Corporation (OCC)
Comment: 
Occidental Chemical Corporation (OCC)
Each of OCC's cogeneration units meets the definition in the proposed rule for "cogeneration units". However, the test for determining whether these units meet the "cogeneration exemption" is extremely complex and we are continuing to review our data and apply EPA's criteria to determine whether the units qualify for the proposed exemption. In either case, as a preliminary yet fundamental matter, we identified numerous factual errors in the databases EPA used for modeling emissions transport and unit level allocations, as discussed in greater detail below. Consequently, one can only infer that the modeled output is also incorrect. [EPA-HQ-OAR-2009-0491-2754.1, p. 3]
Furthermore, we reject on policy grounds the idea that any cogeneration facility, let alone a cogeneration facility meeting the definition of "qualified facility" under the federal Public Utility Regulatory Policies Act ("QF"), should be subject to the Transport Rule, regardless of unit size, efficiency or the amount of power sold on the grid. [EPA-HQ-OAR-2009-0491-2754.1, pp. 3-4]
Consistent with PURPA, EPA Should Exempt All Qualifying Facility Cogeneration Units We have not been able to discern from the docket materials whether EPA has consciously adopted a unique allocation policy for cogeneration units. However, whether conscious or not, it is not rational for EPA to financially penalize modern, clean, efficient gas-fired cogeneration facilities under the CATR in order to "reduce" NOx emissions. Under the final Transport Rule, EPA should exempt all cogeneration units, regardless of size, efficiency and amount of power supplied to the grid.  [EPA-HQ-OAR-2009-0491-2754.1, p. 5] [See 2754.1, pp. 5-13 for extensive discussion of the following topics:  Occidental's Taft Generating Facility, a Qualifying Facility Under PURPA, Is Entitled to an Exemption from the Proposed Clean Air Transport Rule; EPA's Decision to Provide an Exemption to Some, but not All, Cogenerators Is Arbitrary, Capricious and an Abuse of Discretion; EPA's Failure to Provide a Rationale for Regulating Cogeneration Units as EGUs Rather Than Industrial Sources Is Arbitrary and Capricious and an Abuse of Discretion; EPA Must Avoid Issuing a Final Rule That Undermines FERC's Mandatory Obligation under PURPA to "Encourage Cogeneration"; EPA's Proposed Regulations are Arbitrary and Capricious and an Abuse of Discretion Because They Fail to Give Any Deference to the Federal Policy of Encouraging Cogeneration under PURPA; The Economic Benefits Afforded to QFs under FERC's PURPA Regulations Must Be Protected; QFs, Unlike Other Generators, Cannot Raise Their Rates for QF Sales To Cover the Compliance Costs Associated with the Proposed Transport Rule; Imposition of the Proposed Transport Rule on OCC's Taft QF Facility Is Arbitrary and Capricious and an Abuse of Discretion]
Review Period for Cogeneration Exemption We believe that consistent with data maintenance activities with other state and federal statutes and programs, that a review of the period of 5 years previous to the effective date should be sufficient to determine whether a facility qualifies for the cogeneration exemption. EPA has not modeled air quality and emissions since 1990, thus we do not see any value is such a lengthy review period to qualify for the exemption. Furthermore, it is not reasonable to expect that facilities will have the necessary data dating back beyond five years. [EPA-HQ-OAR-2009-0491-2754.1, p. 29]
Response: 
See section VII.B of the preamble.  EPA rejects the commenter's position that all cogeneration facilities (including all QF cogeneration facilities) should be exempt from the Transport Rule trading programs.  The commenter claims that such units are efficient and should be exempt from the Transport Rule trading programs.  In the final rule EPA exempts those cogeneration units that meet certain requirements.  First, the units must meet certain operating and efficiency requirements.  The commenter failed to show that these requirements are unreasonable, and in fact noted that the efficiency requirements as applied to its facilities are the same as under PURPA.  EPA believes that it is reasonable to limit the cogeneration unit exemption to units that demonstrate their efficiency.  Second, the units must meet the electricity sales limitation.  Those units that sell less than the electricity sales limitation are treated as industrial, rather than electricity generation, units and are exempt because the final rule is aimed at the electricity generation sector. The commenter claimed that electricity generation by its facilities is limited by the thermal load that the facilities need to provide for the host industrial facilities because of the operating and efficiency standards under PURPA, which has applied to the commenter's facilities, are the same as the operating and efficiency requirements for the cogeneration unit exemption under the Transport Rule.  However, these operating and efficiency requirements provide some flexibility in that, for example, the minimum percentage that thermal load must comprise of total energy output under these requirements is 5% and, in order for the lowest efficiency requirement to apply, is 15%.  The commenter failed to explain why these requirements do not provide some flexibility to the commenter in deciding what level of electricity to generate for sale.  In addition, the relationship between thermal load and electricity generation does not change the fact that the commenter's cogeneration facilities produce for sale on the grid a significant amount of electricity, and EPA maintains that the level of the electricity sales limitation provides a reasonable way of distinguishing between facilities that are substantially in the electricity generation business and thus should be treated as part of the electricity generation sector regulated under the Transport Rule and facilities that are not substantially in the electricity generation business and so are not covered by the Transport Rule.  Under the commenter's approach, there would be no electricity sales limitation and so all cogeneration units would be treated as outside of the electricity generation sector no matter how much electricity they sold on the grid and how important a role the units played in providing electricity supply to meet electricity demand on the grid.  Contrary to the commenter's claims, merely because a cogeneration facility is meeting a legitimate industrial or commercial need does not mean that the facility is not also reasonably treated as part of the electricity generation sector.  Moreover, if all cogeneration units were excluded from the Transport Rule trading programs, utilization for electric generation, and the resulting emissions, could shift to those units from covered units because of the high level of integration of the electric generation, transmission, and distribution system (which has increased with the significant restructuring and deregulation of electric utilities) and thereby threaten achievement of elimination of states' significant contribution and interference with maintenance, which is the goal of the Transport Rule.  Contrary to the commenter's claim that such shifting could not occur because many of the cogeneration facilities are not owned by utilities, such shifting could occur regardless in states where other electricity providers or end-users can purchase electricity from non-utility generators, who can make such sales whether or not the utilities want the sales to occur.  Although the exemption of any portion of the electricity generation sector creates the potential for generation shifting, the greater the number and scope of the exemptions, the greater the likelihood and likely magnitude of the potential generation shifting.  After the balancing the commenter's claimed rationale for the requested exemption and the potential adverse effect of such an exemption, EPA rejects the commenter's position
EPA maintains that the treatment of QF cogeneration units in the final Transport Rule is not inconsistent with PURPA.  PURPA addresses the prices of electricity that QFs produce and sell, not their emission requirements.  It is not inconsistent with PURPA to regulate the emissions of cogeneration units (including QF cogeneration units).  In fact, the Acid Rain Program established by Congress in CAA title IV did not contain a blanket exemption for all cogeneration units or all QF cogeneration units.  Only QF cogeneration units that either had power purchase agreements that were in place on November 15, 1990 and continued to be in place or that met the electricity sales limitation were exempt.  In addition. although the cogeneration unit exemption in both the final Transport Rule and in CAIR included the efficiency requirements and the electricity sale limitation and so cogeneration units not qualifying for the exemption have been subject to the emission reduction requirements of the CAIR trading programs, the commenter did not show that the regulation of the emissions of cogeneration units not qualifying for the exemption CAIR has had any significant, adverse financial consequences for the units under CAIR or will have any significant, adverse financial consequences for the units under the Transport Rule trading programs.  The mere assertion that these units cannot charge more than "avoided cost" does not demonstrate that compliance with the Transport Rule would have a significant, adverse effect.  The commenter's claim that its facilities might need to reduce their production of thermal output and electricity is speculative and unsupported.  Moreover, the commenter's suggestion that its facilities might need to reduce their electricity production and sales in order to meet the requirements of the cogeneration unit exemption is factually incorrect: because under the cogeneration unit exemption the electricity sales limitation must be met every year starting in 2005, a reduction in electricity production and sales by the commenter's facilities in a future year will not qualify the facilities for the cogeneration unit exemption.  EPA notes that many of the commenter's concerns stem from the allocations to the commenter's units in the proposed Transport Rule.  The final Transport Rule adopts a different method of allowance allocation and provides non-exempt cogeneration units reasonable access to allowances.  See section VII.D of the preamble. 
Organization: Oglethorpe Power
Comment: 
Oglethorpe Power
XI. Biomass
The proposal would apply the Transport Rule FIPs to 'large' EGUs, defined as any stationary, fossil fuel-fired boiler or stationary, fossil fuel-fired combustion turbine serving at any time, since the later of November 15, 1990 or the start-up of the unit's combustion device, a generator with nameplate capacity> 25 MWe producing electricity for sale. 'Fossil fuel' is defined as including natural gas, petroleum, coal or any form of fuel derived from natural gas, petroleum or coal, regardless of the purpose for which such material is derived. While there are certain exemptions written in to the proposed rule for cogeneration units or solid waste incinerators, biomass-fired units that might use small quantities of fossil fuels (e.g., for start-up purposes) do not appear to be exempt from coverage in the rule. EPA should consider including such an exemption in the rule, similar perhaps to that found for solid waste incineration units that stay below set percentages of fossil fuel usage. [EPA-HQ-OAR-2009-0491-2732.1, p.15]
Response: 
See section VII.B of the preamble.  The final rule covers fossil-fuel-fired units serving a generator with a nameplate capacity greater than 25 MWe and defines "fossil-fuel-fired" as combusting any amount of fossil fuel in 2005 or later.  EPA rejects, for several reasons, the commenter's approach of excluding all biomass units whose fossil fuel use is below some unspecified percentage of total fuel use.  The approach in the final rule is consistent with the approach used in prior EPA trading programs covering the electric generation industry, e.g., the Acid Rain Program, the NOx Budget Trading Program, and the CAIR trading programs.  The commenter did not provide any basis for using different approach in the Transport Rule trading programs covering the same industry and did not specify, much less support, a level of fossil fuel use (as a percentage of total fuel use) as the cut-off for determining which biomass units would be exempt from these programs.  Moreover, if the applicability of the Transport Rule trading programs to a significant number of units were to depend on exceeding a specific level of fossil fuel use, the units' regulatory status could change during the course of the year.  Specifically, a unit's fossil fuel use can vary, depending on, among other things, fluctuations in the fuel prices (e.g., natural gas prices) and changes in unit operation.  Some units use fossil fuel for startup and combustion stabilization, and so fossil fuel use can vary depending on the frequency of startups and shutdowns and on factors (such as the moisture content and other characteristics of the other fuels being combusted) affecting the need for combustion stabilization.  Units that were excluded from the Transport Rule trading programs because fossil fuel use was below the commenter's unspecified percentage of total fuel use would not report fuel use to EPA, and so determination of whether a significant number of units were subject to the trading programs, and assurance of compliance, would be problematic. 
Organization: Ozone Transport Commission (OTC)
Comment: 
Ozone Transport Commission (OTC)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.117-118.]
A third problem with the proposed rule is its failure to include emission reductions from all NOX sources that contribute to transport, particularly from large industrial, commercial and institutional (ICI) boilers. However, we urge EPA to examine the technical evaluation the OTC developed jointly with the Lake Michigan Air Directors Consortium (LADCO) for ICI boilers and include NOX and SO2 reductions from this sector in the final rulemaking for this proposed rule if possible. If not, we urge EPA to address emissions from ICI boilers in the second Transport Rule, as well as emissions from cement kilns, on-road vehicles, marine engines and locomotives.
EPA data shows that emissions from power plants, along with emissions from these other source categories, represent about 75% of the NOX emissions that remain to be regulated. These source categories are most effectively regulated by national rules promulgated by EPA.
Response: 
See sections VI.A, VII.B, IX.A and B, and X of the preamble.
Organization: PowerSouth Energy Cooperative
Comment: 
PowerSouth Energy Cooperative
No emission allowance allocations should be made to non-operating units.  PowerSouth opposes provisions in the Proposal to continue allocating allowances for 6 years to units that are shut down.  EPA need not incent power plant closures.  Such a provision further clouds and complicates the cap and trade mechanism, and precludes availability of allowances to units that need them.  [EPA-HQ-OAR-2009-0491-2693.1, p.6]  
Response: 
See section VII.D.1 of the preamble.
Organization: PSEG Services Corporation
Comment: 
PSEG Services Corporation
Additional areas for EPA's consideration on the proposed Transport Rule.
Small peaking units below the proposed Transport Rule's 25 megawatt threshold typically do not operate for a sufficient amount of time to satisfy the criterion that an opt-in unit demonstrate operation at least 876 hours in six months. EPA should consider removing the 876 hour threshold and allow small units to opt-in regardless of the operating time. This change would increase the number of sources covered by the rule without increasing the state budgets, resulting in an even greater improvement in air quality. Further, such as action would remove the perverse incentive to exceed the threshold as a way to qualify as an opt-in unit [EPA-HQ-OAR-2009-0491-2627.1, p.11]
Response: 
See section VII.B of the preamble.
Organization: Recycled Energy Development
Comment: 
Recycled Energy Development
Second, define (and qualify) recycled energy, sometimes known as the bottoming-cycle of CHP. By qualifying CHP only according to an efficiency measure based on energy input, EPA's proposed rules reject recycled energy projects that have no fuel inputs because they capture waste heat and pressure drops. A bottoming-cycle project, such as at the silicon manufacturer mentioned above, burns no incremental fuel and emits no additional pollution. Legislative tax proposals specifically except recycled energy from CHP's efficiency requirements because of the mathematical impossibility of dividing by zero, which is the fuel input of a bottoming-cycle CHP project. EPA should adopt similar exemptions. [EPA-HQ-OAR-2009-0491-2601.1, p.2]
Third, remove the sales restriction associated with CHP. Whether the purchaser of the CHP power is the grid or an industrial facility makes no difference to pollution output. EPA's proposal stipulation that CHP facilities can sell no more than a third of its output to the grid is arbitrary. The provision seems to confuse commercial considerations with technical ones. The decision to sell to the grid or to displace a local facility's power purchases should be made solely on economic grounds. Particularly in the industrial sector, CHP developers are inclined to sell power to the grid since wholesale prices typically exceed retail rates. Declaring that only one-third of CHP power can be sold, therefore, reduces the economic proposition of CHP in many industrial settings, thereby slowing investments in efficiency. Rather than dictate the point of sales, CHP's operative test should be efficiency (noting, as mentioned above, that an exception is needed for bottoming-cycle CHP or recycled energy). RED, therefore, recommends EPA strike the CHP sales restriction. [EPA-HQ-OAR-2009-0491-2601.1, p.2]
Response: 
The commenter's description of "recycled energy projects" is too vague, and lacks sufficient information, to determine what would be the regulatory status of such projects under the proposed Transport Rule and to provide a basis for adopting different provisions in the final Transport Rule.  For example, it is unclear from the commenter's description what types of equipment are associated with these projects and whether such projects depend on the use of a boiler or combustion turbine, which are covered by the Transport Rule trading programs and, of course, have heat input.  EPA notes that the definition of "combustion turbine" includes "any associated duct burner, heat recovery steam generator, and steam turbine".  See sections 97.402, 97.502, 97.602, and 97.702 of the Transport Rule trading program regulations (definition of "combustion turbine").  It is also unclear exactly what revisions of the proposed Transport Rule are sought by the commenter.  For example, the commenter failed to identify or describe the "[l[egislative tax proposals" that the commenter suggests should be used to adopt "similar exemptions" in the Transport Rule.
EPA rejects the commenter's suggestion that the electricity sales limitation in the cogeneration unit exemption be removed.  The purpose of the electricity sales limitation is to distinguish between cogeneration units that are considered industrial and those that are considered part of the electricity generation sector, which is the sector whose emissions the final Transport Rule is aimed at reducing.  EPA notes that the electricity sales limitation has been used in the Acid Rain Program and in the CAIR trading programs to make this distinction.  The commenter failed to provide any support for the claim that the using the electricity sales limitation as a requirement for the cogeneration unit exemption "significantly" slows "investments in efficiency and reducing the potential for emissions reductions".  EPA rejects this claim as speculative and unsupported.  EPA also notes that the inclusion of these units in the Transport Rule trading programs provides strong economic incentives for increasing efficiency and reducing emissions at these units because the units' owners and operators must hold allowances covering the units' emissions and can sell any allowances that are not needed for covering these emissions.
Organization: RRI Energy, Inc.
Comment: 
RRI Energy, Inc.
The CATR must not prohibit opt-in of EGUs with nameplate capacity less than or equal to 25 MWe as a means to satisfy any state agency-issued High Electric Demand Day (HEDD) / Demand Response (DR) requirements.
The proposed CATR includes provisions for non-CATR affected units (e.g., boilers, combustion turbines with a nameplate capacity less than or equal to 25 MWe or other stationary combustion sources) located in a state subject to a CATR emissions trading program to voluntarily opt-in to the CATR and obtain an allocation of allowances reflecting the unit's historic emissions. RRI supports this provision provided CATR does not prevent state efforts to utilize the program as part of their HEDD / DR plans. RRI has previously communicated with the Pennsylvania Department of Environmental (PA DEP) and EPA Clean Air Markets Division3 on the importance and benefits of including this provision within the proposed CATR. In summary, RRI has communicated that a local electrical system operator (PJM) is considering significant changes that will require customers to curtail operations (or turn on distributed generation) more frequently and for longer duration. This is essentially a new electric generation business that is being fostered by the system operator for the purpose of lowering wholesale electricity prices, but to the dis-benefit of the existing and likely new and more stringent ozone and PM2.5 standards. While curtailing operations during a HEDD period is a beneficial option, an unwelcome outcome is the proliferation of distributed generation. These emissions, regardless of their allowable emissions rates, are growing outside the EGU emissions budget and are priced more favorably due to a lack of permits, emissions limits and emissions allowance surrender requirements. This situation is also exacerbated by a recent proposal by PJM to allow DR, including distributed generation, to set market prices. While reducing prices to customers, this means that EGUs will be less able to recover the costs of controls, particularly for the peaking generation component, because their units will be competing against a demand response option that includes generating sources, many of which effectively have no environmental costs. Although several states are considering or proposing direct control emission limitations for these types of non-CATR EGUs, RRI believes that the opt-in provision outlined above provides for a flexible and more cost-effective option to address the air quality issues associated with non- CATR affected EGUs. Importantly, although the IPM includes all known EGUs regardless of nameplate generating capacity, EPA has admitted4 that IPM performs poorly with respect to utilization of small peaking oil-fired EGUs (IPM predicts that these unit will not operate when historic data have demonstrated otherwise). Consequently, the provision to allow EGU operators to include these units as CATR opt-in units would result in improved air quality and provide a cost-effective means for operators to account for their emissions. [EPA-HQ-OAR-2009-0491-2717.1 p.4]
Lastly, to further encourage non-CATR affected units to opt-in to CATR, the proposed rule must eliminate the requirement that the applicable unit have documented heat input (greater than 0 mmBtu) for more than 876 hours during the six months immediately preceding submission of the opt-in application. RRI believes that this requirement is unnecessary because (i) this provision is not required for CATR-affected units and (ii) allowances for opt-in units are allocated in proportion to the unit's baseline emissions (i.e., allowances are allocated to units that need such allowances). [EPA-HQ-OAR-2009-0491-2717.1 p.4]
Response: 
See sections VII.B, IXA. and B, and X of the preamble.  For the reasons set forth in the preamble, the final rule does not provide for units to opt into the Transport Rule trading programs, but allows states' SIPs to expand the applicability of the Transport Rule NOx Ozone Season trading program to make all small EGUs serving generators of a requisite size subject to that program.  Allowing states to expand the applicability of that trading program better addresses the concern raised by the commenter, who claimed that large EGUs subject to the Transport Rule trading programs would be competing against small EGUs that lack emission reduction requirements and costs.  Opt-in provisions would only apply to small EGUs that voluntarily decided to enter the Transport Rule trading programs and not to all small EGUs.  EPA also notes that the commenter did not claim, much less demonstrate, that. even if small EGUs are not brought into the Transport Rule trading programs through SIPs, there would be significant adverse impacts on air quality or on the owners and operators of large EGUs subject to the trading programs.
Organization: Shell Chemicals
Comment: 
Shell Chemicals
Date for Commencement of Limitations to Qualify for Cogeneration Exemption
EPA has also requested comments on certain aspects of its proposed rule. One of these areas concerns whether it would be problematic for sources to obtain detailed information about the disposition of a unit's generation back to November 15, 1990 and whether the efficiency and operating standards should be limited to more recent years rather than November 15, 1990. EPA suggested as an alternative for comment whether the exemption requirements should only be met every year starting the later of a date of a more recent year (e.g., 2000, 2005, or 2009) or the date on which the unit first produces electricity.' EPA also requests comment on whether the electricity sales limit should be restricted to more recent years by requiring that the limit be met every year starting the later of a date of a more recent year (e.g., 2000, 2005, or 2009) or the start-up of a unit's combustion chamber. [EPA-HQ-OAR-2009-0491-2614, pp.4-5]
Shell believes that it could be problematic to produce detailed information about the disposition of a unit's generation, its efficiency and operating standards, and its electricity sales from as far back as November 15, 1990, which is nearly twenty years ago. The time period for record keeping under the Clean Air Act Title V permit program and similar programs is generally only five years. While most sources will have records of this type of information on major EGUs for the last 5 years, they may not have kept detailed information for prior years. Thus, the 'start-date' for the exemption criteria should extend no further back than five years prior to the adoption of the final Transport Rule/FIP. [EPA-HQ-OAR-2009-0491-2614, p.5]
Definition/Efficiency Standard for Cogeneration Units
The 'cogeneration unit' definition proposed under the Transport Rule/FIP differs from that under the Clean Air Interstate Rule ('CAIR'). Under CAIR, each unit had to individually meet the efficiency standard. Under the proposed rule, however, if the cogeneration system of which a topping-cycle unit is a part meets the efficiency standard on a system-wide basis, then the unit is also deemed to meet that efficiency standard. EPA requested comments on whether this approach should also be applied to bottoming-cycle units. [EPA-HQ-OAR-2009-0491-2614, p.5]
Shell supports applying the approach of meeting efficiency standards on a system-wide basis to bottom-cycle units for the same reason that EPA has applied this approach to topping-cycle units. Allowing one unit in a cogeneration system to act as a 'swing' unit and operate at a lower efficiency will allow the other units in the system to operate at higher efficiencies. Further, there is no basis for EPA to treat these two types of units differently for the purposes of meeting efficiency standards. Topping-cycle units and bottoming-cycle units have the same purpose- to produce electricity and thermal power. The fundamental difference between these two types of units is the order in which electricity and thermal energy are produced. In topping-cycle units, the energy input to the unit is first used to produce useful power, including electricity, and then some of the reject heat from the electricity production is used to provide useful thermal energy. In bottoming-cycle units, the process is reversed, with the energy input to the unit first being used to produce useful thermal energy and then some of the reject heat from the useful thermal energy process being used for electricity production. As topping-cycle units and bottoming-cycle units have the same purpose and produce the same products, EPA should apply the same efficiency standards requirements to both types of units. [EPA-HQ-OAR-2009-0491-2614, p.5]
EPA requested comment on whether the agency should exclude, from the requirement to meet the operating and efficiency standards, calendar years- if any-during which a unit does not operate at all. Under the proposed Transport Rule, the operating and efficiency standards in the 'cogeneration unit' definition must be met every year. EPA is concerned because, as the rule is currently written, these annual standards would be applied in calendar years when a unit does not operate at all. Shell agrees with this concern and requests EPA to exclude these requirements in calendar years when the unit does not operate at all. [EPA-HQ-OAR-2009-0491-2614, p.5]
Request for Emergency Exemption
As a separate comment, Shell believes that EPA should provide an exemption to sources that exceed the annual electricity sales limit due solely to the occurrence of an emergency. For instance, EGUs as well as local transmissions systems located in Louisiana can be adversely affected by hurricanes or floods. There have been occasions in the past where EGUs adversely impacted by hurricanes have been unable to provide electricity to their customers. In those cases, sources meeting the cogeneration exemption may be called upon to temporarily increase their electricity production to provide for critical infrastructure power needs until the primary utility systems can return to electrical power production. By selling electricity in these times of crisis, exempt sources may exceed the proposed Transport Rule/FIP electricity sales thresholds and therefore trigger applicability under the Transport Rule/FIP. Shell believes that these sources should not be penalized by triggering regulatory applicability solely due to provision of power during such emergency periods. Shell thus requests that EPA provide an exception to the Transport Rule stating that sources will not lose their exemption for temporary activities that occur in response to emergencies. EPA could impose appropriate criteria to limit the scope of this exception; however, such an emergency exception is needed under the proposed rule. [EPA-HQ-OAR-2009-0491-2614, p.6]
Response: 
See section VII.B of the preamble.  With regard to the electricity sales limitation, the commenter argued that EPA should establish an emergency exemption from the sales limitation.  EPA rejects the commenter's approach.  Whatever the motivation behind a unit's electricity sales, EPA believes that the level of the electricity sales limitation provides a reasonable, objective way of differentiating between cogeneration units treated as industrial units and those treated as electricity generation units.   The commenter's approach would introduce a major subjective element into the cogeneration unit exemption by requiring EPA to define what constitutes an "emergency" and to determine whether particular circumstances constituted such an "emergency".  The commenter did not suggest, much less support, any specific "emergency" definition.  In addition, EPA notes that the Clean Air Act already includes provisions for addressing national or regional energy emergencies, as described in the CAA.  See 42 U.S.C. 7410(f).
Organization: Sierra Club, New Jersey Chapter
Comment: 
Sierra Club, New Jersey Chapter
It is also quite appropriate that the proposed rules (as noted in Section 'II General Information' of the subject document will apply to all Electric Generating Utilities (electric, natural gas, and other systems) in these states. [EPA-HQ-OAR-2009-0491-3649, p.1]
Response: 
See sections VI.A, VII.B, IX.A and B, and X of the preamble.
Organization: South Carolina Department of Health and Environmental Control 
Comment: 
South Carolina Department of Health and Environmental Control 
The EPA articulates the applicability of the proposed Transport Rule to biomass-fired EGUs only as they pertain to the cogeneration exemption.53 This leaves some questions that DHEC has encountered in making applicability determinations under the CAIR unanswered. The EPA should clarify Transport Rule applicability for a biomass-fired EGU that is not a cogeneration unit and is allowed to burn fossil fuel only at start-up. Simply relying on the definitions of "fossil-fuel-fired" and "commence operation" is unnecessarily opaque.  [EPA-HQ-OAR-2009-0491-2677.1 p.21]
Response: 
EPA maintains that the definition in the final rule clearly states that a unit that combusts any amount of fossil fuel (whether for start-up, combustion stabilization, or general operation) during 2005 or later is fossil-fuel-fired.  Obviously, a unit may also combust non-fossil fuel in addition to the fossil fuel and still be "fossil-fuel-fired".   See sections 97.402, 987.502.,97.602, and 97.702 of the Transport Rule trading program regulations (definition of "fossil-fuel-fired").   The commenter did not suggest that fuel use at start-up should be excluded from the determination of whether a unit is fossil-fuel-fired, much less any basis for such an approach.  Under the final rule, any fossil-fuel-fired boiler or combustion turbine serving a generator with a nameplate capacity greater than 25 MWe providing electricity for sale is a covered unit, unless the unit qualifies for the cogeneration unit or solid waste incineration unit exemption.  The final rule does not use, and does not include a definition of, the term "commence operation".
Organization: Southern Company
Comment: 
Southern Company
XV. EPA Should Encourage - Not Discourage - Fossil to Biomass Conversions
Southern Company encourages EPA to reconsider its definition of covered unit and allow for a limited exclusion for biomass facilities. As proposed, the Transport Rule covers any unit greater than 25 MW that bums (or has burned) any amount of fossil fuel since 1990. Under this structure, biomass-fired power plants that bum no fossil fuel are excluded, unless they have burned fossil fuel at some point since 1990. Thus, a facility that converts from fossil fuel to biomass is treated differently than a new biomass facility that has never burned fossil fuel. The former must hold allowances. The latter has no such requirement. There is no rational basis for such a distinction. To the contrary, EPA should encourage conversions from fossil fuels to renewable fuels. Furthermore, the Transport Rule concerns current and future air quality. That a given facility once burned fossil-fuel is wholly irrelevant to current and future air quality. Put simply, for purposes of this rule, there is no difference between a greenfield biomass facility and a new greenfield biomass facility, and EPA has no basis for including one and excluding the other. [EPA-HQ-OAR-2009-0491-2864.1, p. 52]
In addition, in order to promote the development of renewable biomass energy, Southern Company encourages EPA to exclude all biomass facilities that bum less than 10% fossil-fuel. Many biomass facilities use small amounts of fossil fuel to minimize emissions during startup and shutdown. Burning fuel oil or natural gas during these periods helps provide combustion stability and control during startup and shutdown, which can help operators optimize the fire to limit or prevent high emission events. As the fire becomes more stable through the startup process, biomass is introduced until combustion is optimal. EPA should encourage, not discourage, the use of minimal amounts of fossil fuels to reduce emissions. This proposed 10% fossil-fuel exclusion is consistent with New Source Performance Standard methods for categorizing multi-fuel units that bum one primary fuel with a very limited amount of another fuel. EPA should adopt a similar approach in this rule. [EPA-HQ-OAR-2009-0491-2864.1, p. 52]
XVI. Southern Company Supports Several of EPA's Decisions in the Proposed Transport Rule
As discussed throughout these comments, Southern Company has many concerns with the Proposed Transport Rule. However, we support several of EPA's decisions in the proposed rule including EPA's decision to limit the applicability for the Transport Rule to units greater than 25 megawatts. [EPA-HQ-OAR-2009-0491-2864.1, p. 52]
D. EPA's Decision to Limit the Applicability to Units Greater Than 25 MW Southern Company fully supports EPA's proposal to exclude small EGUs of less than 25 MW. Most units this size are used only rarely, for example, as emergency or backup units or during extreme peaks in demand. Accordingly, they are dispatched for short periods of time, primarily for electric reliability reasons. A cap and trade program, which determines compliance over an annual or seasonal basis, is ill-suited for addressing any emission concerns associated with such units. If these smaller units were included in the rule, they would become subject to costly monitoring requirements in addition to the S02 and NOx compliance obligations. Given the de minimis emissions involved, these costs far exceed any potential benefits and thus would not be cost-effective. EPA should retain its consistent practice of excluding these small units. In the unlikely event that EPA breaks from its historical practice, it should only do so after determining on an individual unit (or state-by-state) level that smaller units are linked to actual air quality concerns to an extent that warrants their inclusion in the program and that there are cost-effective means available to address those impacts.  [EPA-HQ-OAR-2009-0491-2864.1, p. 53]
Response: 
The final rule covers fossil-fuel-fired units serving generators with a nameplate capacity greater than 25 MWe producing electricity for sale and defines "fossil-fuel-fired" as combusting any amount of fossil fuel in 2005 or later.  The commenter claimed that biomass units that switch from burning some fossil fuel to burning no fossil fuel should be exempt just as new units that never burn fossil fuel are not covered by the Transport Rule trading programs.  EPA rejects the commenter's claim.  The approach in the final rule is consistent with the approach used in prior EPA trading programs covering the electric generation industry, e.g., the Acid Rain Program, the NOx Budget Trading Program, and the CAIR trading programs.  The commenter did not provide any basis for using a different approach in the Transport Rule trading programs covering the same industry.  Moreover, the commenter essentially suggested that the determination of whether a given biomass unit is subject to the Transport Rule trading programs should not be based on any historical information on whether the unit burned any fossil fuel, but rather only on what the unit is currently burning.  This approach would mean that, for all biomass units, owners and operators, and EPA, would not know at the start of the Transport Rule trading programs, whether the units were subject to the trading programs and that the units' regulatory status could change, and the units become subject to the trading programs, at any time that any fossil fuel was combusted.  Because all biomass units would not be reporting their fuel use to EPA until they became subject to the trading programs, the determination of whether specific units were subject to the trading programs, and assurance of compliance, would be problematic.  EPA believes that its approach is reasonable: biomass units that have recently (i.e., after 2004) operated burning some fossil fuel are treated differently than new biomass units that are initially designed to operate without combusting any fossil fuel and actually operate without any fossil fuel combustion.  The units burning fossil fuel after 2004 are more likely to continue to do so.  EPA maintains that it is reasonable to make these biomass units, like any other units burning at least some fossil fuel after 2004, subject to the Transport Rule trading programs.  Similarly, EPA believes it is reasonable to treat a biomass unit that has not burned and does not burn any fossil fuel (like any other units that have not burned and do not burn) any fossil fuel as not subject to the Transport Rule trading programs, unless and until they begin burning fossil fuel. 
The commenter also claims that all biomass units whose fossil fuel use is less than 10% should be exempt from the Transport Rule trading programs.  EPA rejects commenter's claim.  As discussed above, the approach in the final rule is consistent with the approach taken in the Acid Rain Program and the CAIR trading programs, and the commenter failed to show why a different approach is warranted here.  Further, the commenter failed to explain the basis for the suggested 10% level.  As noted by the commenter, the NSPS regulations refer to a 10% level of fossil fuel use in connection with certain NOx (but not SO2) emission requirements for certain types of units.  However, the exemption from NOx emission requirements based on the unit having annual capacity factor for coal, oil, and natural gas of 10% or less is limited to industrial, commercial, and institutional steam generating units and does not apply to electric utility steam generating units.    Compare  40 CFR 60.44Da (setting NOx emissions standard for electric utility steam generating units, without any exemption for units with 10% or less fossil fuel use) and 60.44b (setting NOx emissions standards for industrial, commercial, and institutional steam generating units, with an exemption for units with 10% or less fossil fuel use).  The use of the 10% cutoff in a different set of regulations applicable to a different category of units does not support the commenter's claim that the 10% level should be used to exempt certain units from the Transport Rule emission reduction requirements.  Moreover, the commenter failed to specify, much less justify, any period of time during which fossil fuel use would have to be less than 10%.  If the applicability of the Transport Rule trading programs for all biomass units were to depend on whether the unit's fossil fuel use, during some period, exceeded 10% of total fuel use, such units' regulatory status could change during the course of the year.  A unit's fossil fuel use can vary, depending on, among other things, changes in unit operation and fuels.  As noted by the commenter, some units use fossil fuel for startup and combustion stabilization, and so fossil fuel use can vary depending on the frequency of startups and shutdowns and on factors (such as the moisture content and other characteristics of the other fuels being combusted) affecting the need for combustion stabilization.  A unit that was excluded from the Transport Rule trading programs because of its below-10% fossil fuel use would not report fuel use to EPA, and so determination of which units were subject to the trading programs, and assurance of compliance, would be problematic.  
With regard to units serving generators with nameplate capacity at or below 25 MWe, see sections VII.B, IX.A and B, and X of the preamble. 
Organization: State of Connecticut
Comment: 
State of Connecticut
EPA should move forward and adopt strong national rules for all air pollution sources that contribute to interstate air pollution transport, not just electric generators as proposed in the Transport Rule. For example, the Ozone Transport Commission, of which Connecticut is a member, has repeatedly asked EPA to move forward with national rules limiting pollution from industrial, commercial and institutional boilers. [EPA-HQ-OAR-2009-0491-2534.1 p.2]
Response: 
See sections VI.A, VII.B, IX.A and B, and X of the preamble.
Organization: State of Delaware Department of Natural Resources & Environmental Control
Comment: 
State of Delaware Department of Natural Resources & Environmental Control
Co-generation Unit Exemption. In the preamble to the proposed rule EPA requested comments regarding the length of the historic period that would be appropriate for a 'look back' to determine if a unit met the efficiency and generation requirements to be eligible for the co-generation unit exemption provided for in the proposed rule. EPA is proposing the use of November 15, 1990 or the date on which the unit first produces electricity, whichever is later, as the date for which the unit must have started meeting the efficiency and generation requirements to be defined as a co-generation unit. In the preamble to the proposed rule EPA indicates that it may be difficult for some units to produce historic data of that age, and requests comments on utilization of a later date. Delaware agrees that the 'look back' period for co-generation unit exemption determination should be shorter than the EPA has included in the proposed rule. Specifically, Delaware believes the 'look back' period for determination of eligibility for the co-generation unit exemption should be the later of the calendar year prior to the effective date of the rule or the first full calendar year after the unit first produces electricity. Using this one year 'look back' for determination of co-generation exemption eligibility would make this requirement more consistent with proposed rule's requirement for co-generation units to re-qualify for the exemption on an annual basis. [EPA-HQ-OAR-2009-0491-2980.1, p.6]
Opt-in Provisions. Somewhat related to the issue of including the smaller size units in a proposed program is the concept of opt-in provisions in the proposed rule. EPA has requested comments regarding the appropriateness of the proposed rule's opt-in provisions. While Delaware does not necessarily oppose the opt-in provisions, Delaware is skeptical that the opt-in provisions would provide sufficient incentive for a source to make the commitment to perform an emission reduction project that would not have occurred anyway without the opt-in provisions. In this event, additional allowances would have been created without any environmental benefit as a direct result of the rule. In any event, it is Delaware's opinion that if the proposed rule addresses the smaller units (EGUs 15MW<>25 MW, co-generation units > 15MW, and ICI boilers > 250 MMBTU/hr) then the population of likely opt-in units will be greatly reduced. [EPA-HQ-OAR-2009-0491-2980.1, pp.9-10]
Response: 
With regard to the cogeneration unit exemption, see section VII.B of the preamble.  As discussed in the preamble, EPA is using 2005 as the start of the lookback period because this will provide about 5 years of data, which is consistent with the recordkeeping requirements under the CAA title V permit provisions and provides a representative period for units that have been operating more than 5 years.   The commenter's suggestion of using only one year (i.e., 2011) before the start of the Transport Rule trading programs lacks these advantages. 
With regard to opt-in units, see section VII.B of the preamble.
Organization: State of Wisconsin, Department of Natural Resources
Comment: 
State of Wisconsin, Department of Natural Resources
As part of this effort to address the Court directed progress, EPA needs to clarify emission sectors in contributing states that are significant relative to the EGD sector including at a minimum ICI boilers, cement kilns and other large non-EGD point sources using fossil fuels. [EPA-HQ-OAR-2009-0491-2829.2, p.2]
Response: 
See sections VI.A, VII.B, IX.A and B, and X of the preamble.
Organization: Tenaska, Inc.
Comment: 
Tenaska, Inc.
Finally, the Proposed Transport Rule should offer opt-out provisions which: (1) allow low-emitting units to operate outside the state budget with a commensurate reduction in that state budget; and (2) allow natural gas units to opt out of the state sulfur dioxide (SO2) budget altogether. [EPA-HQ-OAR-2009-0491-3705,p.4]
The Transport Rule Should Allow Low-Emitting Units to 'Opt Out.'
The ultimate way to reduce a state's contribution to non-attainment in a neighboring state is to have the lowest-emitting units operate more. One way to effectuate that principle is to allow units meeting the definition of 'low-emitting source' to operate unrestricted under the Transport Rule budgets subject instead to a stringent emission limitation. In order to keep the state budget intact, any allocation to a unit that opts out would be subtracted from the budget. For example, meeting BACT limits should not be subject to the rule. Similarly, units that have permit conditions limiting their fuel to pipeline quality natural gas should be able to opt out of the Proposed Transport Rule SO2 trading program. This feature would encourage owners to achieve state-of-the-art emissions performance while reducing the administrative burden of the program and associated costs. [EPA-HQ-OAR-2009-0491-3705, pp.17-18]
Response: 
The commenter suggests that "low-emitting" units in each state should be allowed to operate outside of the state budgets.  The commenter failed to explain exactly how this would be implemented.  However, the commenter's approach would effectively exempt these units from the Transport Rule trading programs.  The state budgets would not cover these units and so the units would not be allocated allowances and the units' owners and operators would not be required to hold allowances to cover the units' emissions.  Because the units would therefore have no emission reduction requirements, presumably the owners and operators would not have to report their emissions to EPA.
EPA rejects commenter's suggestion for several reasons.  The commenter failed to provide a basis for excluding so-called "low emitting" units from the Transport Rule trading programs and failed to explain what level of emissions would make a unit "low -emitting" and to provide any basis for selecting a level.  Specifically, with regard to units included in the Transport Rule trading programs for SO2 (and natural-gas-fired units in particular), the commenter failed to explain what emissions level should be used as the cutoff for including or excluding units from the program.  The commenter also failed to take account of the fact that many natural-gas-fired units are dual-fuel-fired units in that they can also combust oil, which when burned results in significantly higher emissions than natural gas; the mere fact that a unit is generally natural-gas-fired does not guarantee that its emissions will be "low".  EPA notes that historically natural-gas-fired units have been included in SO2 trading programs , such as the Acid Rain Program and the CAIR trading program, and the commenter failed to explain why these units should now be excluded from the Transport Rule trading programs.  
More generally, while some units may have relatively low emission rates, that is not a reasonable basis for eliminating the units from the Transport Rule trading programs because it is mass or tons of emissions (not emission rates) that contribute to a state's significant contribution or interference with maintenance, which the final Transport Rule is aimed at eliminating.  Further, a unit's level of emissions can vary depending on the type of fuel combusted, the amount of hours that the unit is operated, and the level of operation of any emission controls.  A unit that might emit at one point of time or during one period at the commenter's unspecified "low emissions" level would not necessarily continue to emit at that level and could have higher emissions at another point of time or during another period.  The commenter failed to suggest a required period for "low emissions", much less providing any basis for selecting such a required period.  Moreover, if "low-emitting" units were exempt from the Transport Rule trading programs and did not report their emissions, EPA would have no way of determining whether the units were continuing to be "low emitting".  In addition, if all "low emitting" units were excluded from the trading programs, utilization for electric generation, and the resulting emissions, could shift to those units from covered units because of the high level of integration of the electric generation, transmission, and distribution system (which has increased with the significant restructuring and deregulation of electric utilities) and thereby threaten achievement of elimination of states' significant contribution and interference with maintenance, which is the goal of the Transport Rule.  Although the exemption of any portion of the electricity generation sector creates the potential for generation shifting, the greater the number and scope of the exemptions, the greater the likelihood and likely magnitude of the potential generation shifting.  After the balancing the commenter's claimed rationale for the requested exemption and the potential adverse effect of such an exemption, EPA rejects the commenter's position and maintains that its approach -- of including all fossil-fuel-fired units serving a generator with a nameplate capacity of over 25 MWe producing electricity for sale and providing for units with low mass emissions alternative monitoring methods that are less expensive than continuous emission monitoring systems -- is a reasonable approach that avoids the above-described flaws in the commenter's vague suggestion of excluding these unit.  EPA also notes that the inclusion of these units (including "low-emitting" units) in the Transport Rule trading programs provides strong economic incentives for units to achieve state-of-the-art emissions performance because the units' owners and operators must hold allowances covering the units' emissions and can sell any allowances that are not needed for covering these emissions.  
Organization: Texas Chemical Council
Comment: 
Texas Chemical Council
II. The Transport Rule Should Exclude Cogeneration Facilities
In the preamble, EPA states that it is committed to meeting the challenge of achieving "a truly efficient, reliable, cost-effective electric power system." 75 Fed. Reg. at 45,229. Cogeneration  -  also known as recycled energy  -  is the simultaneous production of two or more forms of energy from a single fuel source. Cogeneration plants often operate at 50 to 70 percent higher efficiency rates than single-generation facilities. The cogeneration process uses otherwise wasted heat to produce additional energy, such as to provide heat or electricity for the plant in which it is operating. Cogeneration is both the present and future of energy efficient electricity production, and it also benefits the environment by recycling waste heat, thus preventing additional fossil fuels from being burned. Based on the efficiency, reliability and cost-effectiveness of the typical cogeneration operation, cogeneration should be exempt from any proposal such as the Transport Rule, the effect of which would only limit cogeneration's use and effectiveness. [EPA-HQ-OAR-2009-0491-2815.1, p.2]
Co-located cogeneration units are the primary source of steam for the host petrochemical facility. If the cogeneration operations are limited, then natural gas fired boilers will need to be operated to provide steam. Furthermore, limiting the operation of cogeneration units during the ozone season lowers the electrical output when the demand on the grid is at the highest. In the case of the Houston-Galveston-Brazoria (HGB) nonattainment area, that would likely lead to higher utilization of the coal-fired units or natural gas fired boilers. This in turn would lead to higher emissions. Including cogeneration in the proposed rule and limiting the amount of energy that may be produced by cogeneration is absolutely contrary to EPA's commitment to achieving an efficient, reliable, cost-effective electric power system. [EPA-HQ-OAR-2009-0491-2815.1, p.2]
Cogeneration facilities should also be exempt from the rule proposal because limiting the use of cogeneration directly contradicts the federal Public Utility Regulatory Policies Act (PURPA). PURPA Section 210 requires utilities to purchase excess electricity generated by qualifying facilities (QFs) and to provide backup power at a reasonable cost. QFs include plants that use renewable resources and/or cogeneration technologies to produce electricity. As discussed more fully below, EPA cannot simply put a new regulatory program in place that effectively ignores a class of highly energy efficient cogenerators that the Federal Energy Regulatory Commission (FERC), under its PURPA mandate, is tasked with protecting and encouraging. It is precisely because FERC's regulatory program under PURPA promotes the development of energy efficient cogeneration that EPA should not undercut PURPA by creating new rules that unduly burden the protected class of QFs . Instead, EPA must find ways to harmonize its mission with FERC's mandate under PURPA. [EPA-HQ-OAR-2009-0491-2815.1, p.3]
Obviously, the best way to do this is to exempt all cogeneration QFs entirely from the proposed Transport Rule. This makes particular sense given that the current cogeneration exemption from electric generating unit (EGU) status, as well as the proposed cogeneration exemption, are both based on FERC's cogeneration standards under PURPA. In particular, the exemption relies on the operating and efficiency standards for cogenerators established by FERC under PURPA. [EPA-HQ-OAR-2009-0491-2815.1, p.3]
Short of exempting QFs from the proposed Transport Rule, EPA must ensure that QFs at least have the same access to emissions allowances as under the current CAIR regulatory program. Otherwise, EPA will have created a situation in which coal-fired generators would be made whole with respect to emissions allowances, while clean-burning, energy efficient QFs will be subjected to additional economic burdens. Put another way, unless EPA finds a means of avoiding unnecessary conflict with the PURPA mandate, the result will be two federal agencies working at cross-purposes with respect to the promotion of energy efficiency  -  a result that Congress and this Administration could not have intended. [EPA-HQ-OAR-2009-0491-2815.1, p.3]
III. Cogeneration Facilities Should Not be Required to Submit Data Dating Back to 1990
In the preamble, EPA asked for specific comment on whether it will be problematic for cogeneration facilities to obtain sufficiently detailed information about 1) unit efficiency and operation, and 2) electricity sales information dating back to November 15, 1990. 75 Fed. Reg. at 45,307. TCC's position is that it would be extremely difficult for companies to obtain this information dating back to 1990, and there is no real justification for requiring information dating back this far. [EPA-HQ-OAR-2009-0491-2815.1, p.3]
The proposed regulation excludes cogeneration facilities meeting certain efficiency and operating requirements, as well as sales limitations of electricity to the utility power distribution systems. This exclusion is contingent on obtaining data for assessment purposes beginning in 1990 or the start-up of the unit, whichever is later. In many cases, cogeneration facilities are older energy systems that are integrated with large industrial complexes. Data availability is limited to the type of data collection system installed at each respective facility. These older data collection systems have not always captured the required data to perform these assessments electronically. This lack of electronic data would necessitate evaluating this data by hand, if hardcopy charts and graphs are still available. Local utility power distribution networks were also contacted to obtain relevant data for the specified time period. The Electric Reliability Council of Texas (ERCOT) suggested that the only available data, electrical sales data, would only be available for the time period 2000-present. To the extent that all required data is available, the burden in obtaining this historical data far outweighs the benefit derived from the data itself. [EPA-HQ-OAR-2009-0491-2815.1, pp.3-4]
In addition, many companies have record retention policies that, consistent with other regulatory guidance, require records be kept for five years. For example, Title V Permit recordkeeping requirements and recordkeeping requirements contained in the Clean Air Interstate Rule, 40 CFR § 96.106(e), require records to demonstrate compliance for a period of five years. Moreover, many companies do not have the data required to perform a full assessment of applicability under 40 CFR § 97.504 going back to 1990. Therefore, it is unreasonable and inconsistent with established regulations to require industry to analyze data that no longer exists or is not readily available. [EPA-HQ-OAR-2009-0491-2815.1, p.4]
Furthermore, we recommend that both the unit efficiency and operating standards and the electricity sales data be limited to more recent years by requiring that the unit efficiency and operation standards and the sales limit be met annually at either a more recent year, such as January 1, 2006, or the start-up of a unit's combustion chamber. Historical data dating back to 1990 is neither consistent nor reflective of current operations. Many cogeneration and combustion devices have been upgraded with state-of-the-art nitrogen oxide (NOx) control technology such as low NOx burners, selective catalytic reduction (SCR), and flue gas recirculation to reduce emissions. Consistent with current regulatory recordkeeping requirements, applicability determinations for this regulation must be evaluated based on current data rather than historical data. Therefore, we recommend that applicability determinations be performed based on the last five years worth of data. [EPA-HQ-OAR-2009-0491-2815.1, p.4]
IV. EPA's Annual Standards Should Not Apply to Units Not in Operation
EPA has also requested comment on whether the annual operating and efficiency standards in the definition of "cogeneration" should be applied to a calendar year when the unit did not operate at all. 75 Fed. Reg. at 45,307. It is TCC's position that they should not. [EPA-HQ-OAR-2009-0491-2815.1, p.4]
Under the EPA's proposal, a source could not meet the definition of a cogeneration facility if it was shut-down for an entire calendar year. Cogeneration facility outages could exceed one calendar year based on financial, repair, or other unforeseen requirement. Facilities that do not operate, and therefore have no covered emissions, should not be adversely impacted by this regulation. The regulation is intended to reduce emissions from facilities to prevent downstream impacts on other air sheds. If cogeneration facilities are not operating, nor emitting covered pollutants, there can be no adverse impact on these air sheds. Therefore, facilities that do not operate for a given year, that otherwise would meet the cogeneration exclusion, should be allowed to continue operation provided that the regulatory burdens are met upon start-up. [EPA-HQ-OAR-2009-0491-2815.1, p.4]
Response: 
See section VII.B of the preamble.  EPA rejects the commenter's position that all cogeneration facilities (including all QF cogeneration facilities) should be exempt from the Transport Rule trading programs.  The commenter claims that such units are efficient and should be exempt from the Transport Rule trading programs.  In the final rule EPA exempts those cogeneration units that meet certain requirements.  First, the units must meet certain operating and efficiency requirements, and the commenter failed to show that these requirements are unreasonable.  EPA believes that it is reasonable to limit the cogeneration unit exemption to units that demonstrate their efficiency.  Second, the units must meet the electricity sales limitation.  Those units that sell less than the electricity sales limitation are treated as industrial, rather than electric generation, units and are exempt because the final rule is aimed at the electric generation sector. The commenter failed to show that any of these requirements are unreasonable.  In addition, if all cogeneration units or all QF cogeneration units were excluded from the trading programs, utilization for electric generation, and the resulting emissions, could shift to those units from covered units because of the high level of integration of the electric generation, transmission, and distribution system (which has increased with the significant restructuring and deregulation of electric utilities) and thereby threaten achievement of elimination of states' significant contribution and interference with maintenance, which is the goal of the Transport Rule.  Although the exemption of any portion of the electricity generation sector creates the potential for generation shifting, the greater the number and scope of the exemptions, the greater the likelihood and likely magnitude of the potential generation shifting.  After the balancing the commenter's claimed rationale for the requested exemption and the potential adverse effect of such an exemption, EPA rejects the commenter's position and maintains that the approach in the final rule is reasonable.
EPA maintains that the treatment of QF cogeneration units in the final Transport Rule is not inconsistent with PURPA.  PURPA addresses the prices of electricity that QFs produce and sell, not their emission requirements.  In fact, in the Acid Rain Program under CAA title IV, Congress did not exempt all QF cogeneration units from the program, but rather limited the QF cogeneration unit exemption to those units meeting certain requirements (such as having a power purchase agreement as of November 15, 1990 or meeting an electricity sales limitation).  Moreover, under the final Transport Rule, those QF cogeneration units that are not covered by the cogeneration unit exemption have reasonable access to allowances.  The commenter failed to show otherwise.  See section VII.D of the preamble.
Organization: TransCanada
Comment: 
TransCanada
Comment 4: Non EGUs and Emission Units Less Than or Equal to 25 MW Should be Included in the Proposed Transport Rule
Under the proposed Transport Rule, certain units' emissions that contribute significantly to downwind fine particulate matter and ozone maintenance, and that are presently regulated under CAIR, are not captured or regulated. TransCanada urges the Agency to include these sources in the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2827.1, p.3]
The proposed Transport Rule applies only to those facilities that serve a generator with a nameplate capacity of more than 25 MW or those that opt-in to the program. The source emissions from non-EGU facilities and EGUs whose nameplate capacity is 25 MW or less significantly contribute and interfere with maintenance of downwind states' NOx and SO2 emissions transport problems. [EPA-HQ-OAR-2009-0491-2827.1, p.3]
CAIR, which was generally implemented through State Implementation Plans ("SIP"), allowed states to include sources equal to or less than 25 MW and non-EGUs. These sources should also be included in the proposed Transport Rule, which would ensure that the smaller EGUs and non-EGUs that are contributing and interfering with downwind maintenance are also contributing to reducing contributions to downwind maintenance. Adding these parties to the proposed Transport Rule could provide compliance flexibility and make for a more robust market for allowances, which may influence companies decisions on implementing emission controls. [EPA-HQ-OAR-2009-0491-2827.1, p.3]
Response: 
See sections VI.A, VII.B, IX.A and B, and X of the preamble.  The final rule gives states the option of expanding the applicability provisions of the Transport Rule NOx ozone season trading program to include units serving generators with a nameplate capacity of 15 MWe or greater producing electricity for sale.  This is consistent with the approach taken in the NOx Budget Trading Program, where some state elected to include units serving generators with a nameplate capacity of 15 MWe or greater producing electricity for sale. 
Organization: United States Clean Heat & Power Association (USCHPA)
Comment: 
United States Clean Heat & Power Association (USCHPA)
Second, define (and qualify) recycled energy, sometimes known as "bottoming-cycle" CHP. By qualifying CHP only according to an efficiency measure based on energy input, EPA's proposed rules reject recycled energy projects that have no fuel inputs because they capture waste heat and pressure drops. A bottoming-cycle project burns no incremental fuel and emits no additional pollution. Legislative tax proposals specifically except recycled energy from CHP's efficiency requirements because of the mathematical impossibility of dividing by zero, which is the fuel input of a bottoming-cycle CHP project. EPA should adopt similar exemptions. [EPA-HQ-OAR-2009-0491-2823.1, p. 2]
Third, remove the sales restriction associated with CHP. Whether the purchaser of the CHP power is the grid or an industrial facility makes no difference to pollution output. EPA's proposal stipulation that CHP facilities can sell no more than a third of its output to the grid is arbitrary. The provision seems to confuse commercial considerations with technical ones. The decision to sell to the grid or to displace a local facility's power purchases should be made solely on economic grounds. Particularly in the industrial sector, CHP developers are often required to sell power to the grid since local retail loads rarely match the electric outputs of CHP facilities, which are most economically sized to the local host's thermal loads. Declaring that only one-third of CHP power can be sold, therefore, has the potential to disqualify many CHP facilities without cause, thereby significantly slowing investments in efficiency and reducing the potential for emissions reductions. Rather than dictate the point of sales, CHP's operative test should be efficiency (noting, as mentioned above, that an exception is needed for bottoming-cycle CHP or recycled energy). EPA must strike the CHP sales restriction. [EPA-HQ-OAR-2009-0491-2823.1, p. 2]
Response: 
The commenter's description of "recycled energy projects" is too vague, and lacks sufficient information, to determine what would be the regulatory status of such projects under the proposed Transport Rule and to provide a basis for adopting different provisions in the final Transport Rule.  For example, it is unclear from the commenter's description what types of equipment are associated with these projects and whether such projects depend on the use of a boiler or combustion turbine, which are covered by the Transport Rule trading programs and, of course, have heat input.  EPA notes that the definition of "combustion turbine" includes "any associated duct burner, heat recovery steam generator, and steam turbine".  See sections 97.402, 97.502, 97.602, and 97.702 of the Transport Rule trading program regulations (definition of "combustion turbine").  It is also unclear exactly what revisions of the proposed Transport Rule are sought by the commenter.  For example, the commenter failed to identify or describe the "[l[egislative tax proposals" that the commenter suggested should be used to adopt "similar exemptions" in the Transport Rule.
EPA rejects the commenter's suggestion that the electricity sales limitation in the cogeneration unit exemption be removed.  The purpose of the electricity sales limitation is to distinguish between cogeneration units that are considered industrial and those that are considered part of the electricity generation sector, which is the sector whose emissions the final Transport Rule is aimed at reducing.  EPA notes that the electricity sales limitation has been used in the Acid Rain Program and in the CAIR trading programs to make this distinction.  The commenter failed to provide any support for the claim that the using the electricity sales limitation as a requirement for the cogeneration unit exemption "significantly" slows "investments in efficiency and reducing the potential for emissions reductions".  EPA rejects this claim as speculative and unsupported.  EPA also notes that the inclusion of these units in the Transport Rule trading programs provides strong economic incentives for increasing efficiency and reducing emissions at these units because the units' owners and operators must hold allowances covering the units' emissions and can sell any allowances that are not needed for covering these emissions.
Organization: Virginia Department of Environmental Quality (VDEQ)
Comment: 
Virginia Department of Environmental Quality (VDEQ)
The draft Transport Rule does not include many units that were originally part of the NOx Budget trading Program (NBTP) and that States could optionally include in the Clean Air Interstate Rule (CAIR) implementation plans. VDEQ believes that EPA should allow states to choose whether or not NBTP units should be included in the Transport Rule. The document entitled, 'Analysis of NOx Budget Trading Program Units Brought into the CAIR NOx Ozone Season Trading Program,' only looked at whether the expansion of the Clean Air Interstate Rule (CAIR) NOx ozone season trading program applicability to include the NBTP units actually resulted in NOx emission reductions. This comparison took place between 2004 and 2009. Units in the NBTP often chose to retrofit with highly cost effective controls such as low NOx burners (LNB), separated overfire air (SOFA), and/or flue gas recirculation (FGR). Sometimes facilities chose to retire the units. Regardless, the controls for the units located in Virginia were generally in place by 2004, or the retirement occurred shortly thereafter. A comparison of 2004 emission rates by unit to 2009 would not necessarily show the benefit of the continuation of trading program requirements on these units. The result of not including these units in the Transport Rule is that the voluntary controls installed and the voluntary unit retirements in lieu of purchasing credits or retrofit are no longer necessary. This could result in higher emission rates due to controls not being used. States should have the prerogative to analyze the units located within the state borders to determine if inclusion of these units is necessary to ensure that reductions of NOx already achieved are not lost. [EPA-HQ-OAR-2009-0491-2595.1, pp.1-2]
Response: 
See sections VI.A, VII.B, IX.A and B, and X of the preamble.  The final rule gives states the option of expanding the applicability provisions of the Transport Rule NOx ozone season trading program to include units serving generators with a nameplate capacity of 15 MWe or greater producing electricity for sale.  This is consistent with the approach taken in the NOx Budget Trading Program, where some state elected to include units serving generators with a nameplate capacity of 15 MWe or greater producing electricity for sale.  The commenter claimed, without support that non-EGUs have installed controls before 2004 and so a comparison of 2004 and 2009 emissions rates would not necessarily show the effect of including these units in the Transport Rule trading programs.  EPA rejects the commenter's claim as speculative and unsupported.  Moreover, the commenter's claim addressed only non-EGUs in Virginia and also failed to address the fact that non-EGUs, as a group, did not make significant emission reductions, were over-allocated allowances, and were net sellers of allowances to covered EGUs.  

V.D.2.b. Allocations

Organization: American Clean Skies Foundation (ACSF)
Comment: 
American Clean Skies Foundation (ACSF)
EPA proposes a two-step approach to measuring each regulated state's 'significant contribution' to downwind pollution, which informs the emissions caps. First, for each pollutant, EPA uses air quality monitoring to quantify a state's contributions to downwind non-attainment. Second, for states that significantly contribute to downwind pollution problems, EPA determines each state's 'significant contribution' based on an 'appropriate maximum cost' by which power plants could reduce such pollution through control measures. 9 It then applies those control measures to a power plant's actual or projected operations to arrive at emission caps (which are set as state 'budgets' and allocated back to individual power plants). 10 [EPA-HQ-OAR-2009-0491-2759.1, p.3]

9. ACSF's concerns with CATR's allocation method are relevant both to EPA's preferred regulatory option as proposed in CATR, which involves 'limited interstate trading,' as well as similar allocation problems with EPA's 'intrastate trading only' option, since they use comparable allocation methods. [EPA-HQ-OAR-2009-0491-2759.1, p.3]
10. By way of additional detail on CATR's allocation method, for SO2,EPA based the 2014 state budgets on projected generation (per the Integrated Planning Model or 'IPM') times reductions that could be achieved at $2,000 per ton. 75 FR 45290. There is then an 'off-ramp' for certain states ('Group 2') whose downwind pollution contributions can be sufficiently reduced by lesser control measures. For these Group 2 states, EPA set the 2012 SO2 state budgets based on 2009 actual unit performance, unless a source was modeled to install a scrubber by 2012 in which case the 2009 baseline is reduced to account for the new scrubber. 75 FR 45282, 45290. The SO2 caps are not further reduced from these 2012 levels for these Group 2 states. EPA says that CATR's NOx limits, though generally based on emission reductions at $500 are ton, are set similarly to the 2012 SO2 limits: basically requiring the running of control technology that already exists, or is scheduled to be installed by 2012 (SCR for NOx). 75 FR 45290-91. [EPA-HQ-OAR-2009-0491-2759.1, pp.3-4]
Response: 
EPA changed its allocation methodology to be based on historic heat input and emissions data that is generally reported by the sources' DR who testifies to its accuracy and completeness.  Because the final rule uses an historically-data based allocation methodology for existing units, those units' allocations under the rule would be unaffected by any potential modeling discrepancy between a unit's projected future operation and its eventual actual future operation.  For more information on the allocation method, see Preamble Section VII D. For more information on the air quality-assured trading structure of the Transport Rule programs, please see Preamble Section VII.A.
With respect to how EPA determined significant contribution, please see Preamble Section V.
Organization: American Coalition for Clean Coal Electricity (ACCCE)
Cleco Corporation
National Rural Electric Cooperative Association (NRECA)
Old Dominion Electric Cooperative
Louisiana Energy and Power Authority (LEPA)
Edison Mission Energy (EME)
Comment: 
American Coalition for Clean Coal Electricity (ACCCE)
COMPLIANCE ALTERNATIVES
Under the proposal, the alternatives to deferring the compliance deadlines would not adequately remedy the problem we have discussed above and would, in some cases, create complications. Below we discuss briefly the four most likely remedies if controls could not be installed by an EGU in time to meet the proposed deadlines. [EPA-HQ-OAR-2009-0491-2874.1 p.5]
Purchase Allowances
This alternative presumes that adequate quantities of allowances would be available at a reasonable price to meet the needs of EGUsthat are not able to meet the 2012 and 2014 compliance deadlines. Given the overall stringency of the Transport Rule emission budgets, we do not believe this presumption is valid if, as we expect, a significant number of EGUsare unable to meet the proposed deadlines. Moreover, the proposal to allow limited trading would greatly constrain interstate trading of allowances, thereby making it more difficult to meet reduction requirements through the purchase of allowances. Finally, uncertainty over future requirements may limit the availability of allowances if EGUsdecide to hold, rather than sell, allowances. [EPA-HQ-OAR-2009-0491-2874.1 p.6]
Cleco Corporation
The only realistic compliance option for many plants covered by this rule will be allowance purchases, but the proposed compliance schedule does not allow sufficient time for the new allowance markets to develop. Allowance market development may be particularly challenging in the SO2 market because EPA proposes two completely separate markets for Group 1 and Group 2 states, each with fewer participants than EPA's previous cap and trade programs. [EPA-HQ-OAR-2009-0491-2859.1 p.3]
Edison Mission Energy (EME)
EME has different concerns with respect to the Phase II unit-level emission allocations. Unlike Phase I, Phase II of the Transport Rule expressly contemplates the installation of additional controls to obtain additional SO2 reductions. As explained in Section IV.B.4, EME submits that the Phase II compliance cap should be pushed back until 2016 in order to ensure that affected EGUs actually have the time necessary to install these controls. [EPA-HQ-OAR-2009-0491-2707.1, p.33]
Louisiana Energy and Power Authority (LEPA)
The proposed Transport Rule would impose an initial compliance deadline of January 1, 2012. That would not allow enough time for LEPA to make changes necessary to comply with the rule. LEPA would receive no emission allowances for its critical units and may not be able to purchase any allowances under the constrained trading regime the rule would establish [EPA-HQ-OAR-2009-0491-2700.1, p.17-18].
National Rural Electric Cooperative Association (NRECA)
EPA incorporates these and other emissions reduction assumptions in its CATR modeling to conclude that the proposed CATR would result in one million more tons of SO2 reductions in 2012 than would result under CAIR. This conclusion rests on these assumptions being correct: that these units can undertake needed structural and fuel changes under compressed time constraints and at EPA estimated costs. The apparent fact is that the modeling resulting in this incredibly optimistic conclusion is a good indication that it is highly suspect. Because the proposal's unit allocations rest on this modeling, rational rulemaking dictates that at a minimum EPA delay any first compliance period to at least to 2013 and re-propose unit allocations incorporating sensible, realistic assumptions with particular emphasis on full costs, and consideration of unavoidable constraints. [EPA-HQ-OAR-2009-0491-2723.1, pp.6-7]
Old Dominion Electric Cooperative
EPA incorporates these and other emissions reduction assumptions in its Transport Rule modeling to conclude that the proposed Transport Rule would result in one million more tons of SO2 reductions in 2012 than would result under CAIR. This conclusion rests on these assumptions being correct: that these units can undertake needed structural and fuel changes under compressed time constraints and at EPA estimated costs. The fact that the incredibly optimistic conclusion is based upon modeling of flawed assumptions makes the conclusion itself highly suspect. Because the proposal's unit allocations rest on this modeling, rational rulemaking dictates that at a minimum EPA delay any first compliance period to at least to 2013 and re-propose unit allocations incorporating sensible, realistic assumptions with particular emphasis on fuel costs and constraints. [EPA-HQ-OAR-2009-0491-2877.1,p.5]
Response: 
For comments related to the compliance deadline, please see Preamble Section VII C. EPA notes that SO2 and NOX trading are well established practices under ARP, NBP, and CAIR, with an existing knowledge base of compliance options and how likely a entity is to have and need allowances. Additionally, companies have known of the Transport Rule approach since its proposal in July 2010, and past experience has shown that most will have moved to prepare for the new programs ahead of final promulgation of the rule. Finally, while the first control periods begin for the annual programs on January 1, 2012 and for the ozone-season program on May 1, 2012, sources have until the allowance transfer deadlines of March 1, 2013 for the annual programs and December 1, 2012 for the ozone-season program to reconcile total emissions from the control period with allowances submitted.  Although EPA believes that companies already have adequate time to achieve the feasible emission reduction strategies on which the state budgets are based by the beginning of the control periods, this timing for actual compliance demonstration allows individual companies to adapt flexibly to whatever circumstances may arise at their covered units over the course of the entire control period by obtaining the requisite number of allowances to cover total emissions during that time.  

The rationale for establishing air quality-assured trading programs can be found in section VII.A. EPA notes that SO2 and NOX trading are well established practices under ARP, NBP, and CAIR, with an existing knowledge base of compliance options and how to obtain sufficient allowances to cover total emissions in a control period. Because this is an emission reduction program, it would be unreasonable to expect that initial allowance allocations would cover current emission levels at all units.  The air quality-assured trading programs provide everyone the incentive to reduce emissions at or below the market price of an allowance for that pollutant, regardless of the initial allocation of allowances to any given unit, as such allocations could be sold and thus have an opportunity cost.  Please see the Allowance Allocation Final Rule TSD for more information. 

Organization: Associated Electric Cooperative, Inc. (AECI)
Comment: 
Associated Electric Cooperative, Inc. (AECI)
Information contained in the proposal and within the docket is insufficient to allow comprehensive comment on the proposed allowance allocations because many of individual unit control assumptions are unavailable, making the allowance allocations arbitrary. [EPA-HQ-OAR-2009-0491-2845.1 p.3]
Allowance movement should be permitted without restriction to and from unit accounts that fall under the control of a single company. Further, trading restrictions according to state borders should be removed and replaced with the boundaries that consider territories defined by regulated transmission system operators and any adjacent unregulated equivalents. The system operator often dictates the dispatch order and unit output from facilities under ownership of several different companies in multiple states. Consider: If the output of a large nuclear unit in "state A" is lost to an outage, the demand may be filled by one or more coal units in neighboring "state B". While the final destination of the electrical output is state A, the emissions are accounted for at the facility located in state B. Under the proposed Transport Rule, State B would be penalized due to higher coal consumption necessary to cover the loss of output from the nuclear unit in state A. Since the utility in state B won't know until the end of the compliance year whether it can purchase enough (limited) intra- or inter-state at an unknown cost, it cannot recover the additional cost of compliance in the price of the power sold to state A. Even if the utility in state B is able to project annual mass emissions of NOx and SO2, the inflated cost of the (limited) intra- and inter-state micro markets will add unnecessarily to the operating cost of the plants. Scarce allowances will drive up the cost of compliance while adding little or no environmental benefit. If utilities that emit under their CATR allocations decide not to sell the (few) remaining allowances that they hold after assuring their own compliance, many companies that emit above the CATR cap likely will not be able to purchase enough allowances to achieve compliance. [EPA-HQ-OAR-2009-0491-2845.1 P.6]
Associated agrees with the unlimited trading proposed for the initial years of the rule. However, the limited post-2013 trading regime does not allow for the economies inherent to the emissions markets of the past. While we recognize the limitations placed on EPA by the court ruling, we believe there are reasonable steps that could be taken to improve the Transport Rule and lower costs to the regulated utilities. EPA's preferred option is too restrictive and does not recognize the reality of the interconnectedness of facilities by a vast transmission grid. Because FERC rules require open access and coordinated transmission balancing for system reliability, facilities owned by multiple companies are under the control of a single controlling system operator in areas recognized by the North American Electric Reliability Corporation (NERC). Just as stack emissions do not respect state boundaries, neither do transmission systems. Therefore, it does not make sense to limit trading strictly by geographical state boundaries. [EPA-HQ-OAR-2009-0491-2845.1 P.6]
The map below is an example of how the proposed Group 1 and Group 2 states could be further subdivided into trading regions according to the NERC areas. Within these trading regions, utilities could freely trade allowances not to exceed twenty (20) percent of their prior year total mass emissions of either SO2 or NOx. This method would be a self regulating system and would provide utilities some certainty for planning. Further, because the proposed emission caps are so restrictive, the potential for concentrating emissions and negatively impacting ambient air quality in downwind areas must surely be negligible. Under such a plan there is no economic incentive to emit more since doing so would expose the utility to the allowance market. Indeed, emitting less would likely afford an economic opportunity in a semi-liquid market where allowances are certain to be scarce. As written, EPA's preferred option of limited trading does not provide market liquidity or compliance certainty. [EPA-HQ-OAR-2009-0491-2845.1 P.6]
The variability conditions that are proposed to take effect in the second phase are complicated and create compliance uncertainty because the utility cannot know if the state budget for the current year has been exceeded until the data is verified as quality assured at some point in the first quarter of the following year. This leaves a utility at the mercy of other allowance holders in the state to help satisfy its compliance obligation. Under EPA's limited trading option, allowance holders are likely to bank slim compliance margins for use in future years rather than sell to neighboring utilities. Further, a utility will not know whether it can buy out-of-state allowances until someone declares that the state budget is exceeded. Once this occurs, there will be a mad dash to secure scarce allowances at inflated prices in order to achieve compliance. [EPA-HQ-OAR-2009-0491-2845.1 P.7[EPA-HQ-OAR-2009-0491-2845.1]]
Request: AECI requests that EPA amend the Transport Rule to allow for unrestricted movement of allowances between unit accounts for facilities in neighboring states and under common control of a single company. [EPA-HQ-OAR-2009-0491-2845.1 P.7]
Request: AECI requests that EPA amend the Transport Rule to remove trading restriction defined by state borders and replace them with the boundaries of transmission operators recognized by NERC and the unregulated equivalents that border them. Trading regions should be expanded (as described above) to allow for a maximum of twenty (20) percent of a facility's annual SO2 or NOx emissions from the prior operating year. [EPA-HQ-OAR-2009-0491-2845.1 P.7]
Response: 
EPA provided unit level data, including controls, in the September 1, 2010 and January 7, 2011 NODAs and believes this data was sufficient for analysis, as evidenced by the numerous comments received on unit-level assumptions.
For an explanation of why EPA chose air quality-assured trading programs for the Transport Rule and responses to related comments, please see Preamble Section VII.A. 

Organization: City Utilities of Springfield
Comment: 
City Utilities of Springfield
The data sets that form the basis for all of the state allocations contain numerous errors. Since correction of these errors will necessarily affect final allocations, the regulated community has not been and will not be afforded adequate opportunity to review and comment on the overall impacts of this rule making. [EPA-HQ-OAR-2009-0491-2721.1 p.2]
Issue: The docket for this proposal includes data tables with calculated emission rates, assumed operating schedules, and derived emission allowance allocations for units affected by the Transport Rule. According to the proposal, the allocation table will be included in the final rule as Appendix A. However, EPA subsequently published a Notice of Data Availability, based on reported errors in the various data tables (75 FR 53613). Hopefully, the decision to submit public comments will lead EPA to correct the data tables and present more realistic and workable allowance allocations in Table A of the instant rule. However, the regulated community has no assurance that the corrections will be adequate and therefore can not evaluate the ultimate impact of this regulation prior to the close of comments for this docket. Although EPA has made considerable efforts to draft a Transport Rule that will withstand judicial challenge, this appears to be a fatal flaw that could ultimately render it inoperable. [EPA-HQ-OAR-2009-0491-2721.1 p.2]
Recommendation: EPA should hold open the comment period for this docket or, alternatively, reopen the proposal for additional comments following the final publication of corrected allocation data. [EPA-HQ-OAR-2009-0491-2721.1 p.3]

 
The proposal is ambiguous with respect to the treatment of new units that commence operation between the effective date and January 1, 2012.
Issue: As indicated above, the prepublication version of the proposal appeared to contain an inconsistency regarding new units. Specifically, the prepublication language created tension regarding the treatment of units that commence commercial operation between the effective date of the rule and January 1, 2012. These units were neither listed in Appendix A (since they are not part of the modeled database) nor eligible as post- 2012 units to participate in the new unit set-aside. Inclusion of the definition described above would assist immeasurably in clarifying that these "interstitial" units are to be treated as new. However, additional affirmation could be achieved by emphasizing this point within the text of the new unit set-aside sections. [EPA-HQ-OAR-2009-0491-2721.1 p.4]
Recommendation: We suggest inserting the phrase "including new units that commenced commercial operation prior to January 1, 2012" after the clause "that are not listed in Appendix A to this subpart" at §97.412(a), 97.512(a), 97.612(a), and 97.712(a). [EPA-HQ-OAR-2009-0491-2721.1 p.4]

 
The proposed treatment of new units inadvertently penalizes low emitting units that undergo extended maintenance outages.
Issue: CU supports the new unit program as described in most aspects. Specifically, we support a set-aside of at least 3% of the state's compliance pool, the proposal to allocate allowances based on actual emissions, and the reallocation of retired unit allowances into the new unit pool. New units will have the lowest emissions profiles of any units affected by these rules. As PSD permitted units, their emissions will naturally be limited by BACT guidelines. Accordingly, they will not have any emissions that fit the definition of significant contributors  -  i.e., those that can be reduced in a cost effective manner - under the Transport Rule, since they are already emitting at the lowest possible rates economically achievable. In addition, the extensive modeling required during the permitting process, including long-range transport modeling for visibility protection, should document their negligible impacts on downwind receptors. For all of these reasons, the operation of new units should be encouraged and their control period emissions should be made whole under the allocation schema. However, allocation based strictly on the previous year's emissions can have the effect of penalizing a unit that experiences extended down time, as might happen during the initial year of operation or resulting from periodic inspection and overhaul. Ironically, one cause of an extended unit outage would be the need to replace SCR catalyst, an event that would not befall a unit with lesser degrees of NOx controls. [EPA-HQ-OAR-2009-0491-2721.1 p.4-5]
Recommendation: We suggest a mechanism whereby a new unit could adjust its previous year's emissions to account for prolonged maintenance outages, catalyst management outages, etc. The mechanism should have a trigger that is activated if the unit availability factor falls below 85%, and should allow up to a 15% upward adjustment. Alternatively, a new unit that experiences prolonged unit unavailability might simply be allowed to revert to the second prior year in applying for current year allowances. [EPA-HQ-OAR-2009-0491-2721.1 p.5]
Response: 
EPA reviewed the comments and has made significant updates to its IPM v.3.02 modeling used at proposal.  These updates include changes to both the more general IPM assumptions (e.g., gas price assumptions) and specific unit level assumptions (e.g., that current retrofit status at a unit).  These updates were made to the IPM model, and the updated versions (EPA IPM v.4.10) was used for all the final rule analysis.  In regard to unit specific adjustments, EPA did not manually adjust projected unit level modeling outputs, but instead made unit level updates to its NEEDS database used as a model input that impacted the unit level model outputs.   Some of the most frequent general IPM comments that were addressed in the updates are: FGD removal efficiency was adjusted for new retrofits, and for existing retrofits it was indexed to historic performance at the unit.  Additionally, many comments were focused on a source's ability to switch coals.  EPA modified its modeling to better reflect the cost and feasibility of switching and blending coals.  For more detailed discussion of EPA IPM v.4.10 assumptions and assumption updates, see the EPA IPM v.4.10 documentation and the "Transport Rule IPM Assumptions Response to Comments" in the Appendix.
For information defining "new units" and their allocation, see Preamble Section VII.D and the Allowance Allocation Final Rule TSD.. EPA notes that, except for issues related to the first year of allocations for new units, that the impact of downtime on future allocations can be minimized by units. City Utilities of Springfield commented that downtime one year (year X) would affect the next year's (year X+1) allocation for a new unit. While this is true, that unit's allocation for year X would be based on its emissions in the previous year (year X-1). Since that downtime in year X would mean the unit would not use its full allocation for that year, it could bank those allowances and use them for the following year (year X+1) to cover the shortfall.
EPA posted the signed version of the Proposed Transport Rule to the web when it was signed on July 6, 2010.  The proposal was published in the Federal Register on August 2, 2010.  EPA held three public hearings on the rule on August 19, 2010 (Chicago, IL), August 26, 2010 (Philadelphia, PA), and September 1, 2010 (Atlanta, GA) and the public comment period closed on October 1, 2010.  The comment period was thus open for 60 days from the date of publication in the Federal Register and 90 days from the date the rule was widely disseminated to the public via publication on the web.  EPA posted the signed version of the first Transport Rule Notice of Data Availability (NODA) (IPM) to the web when it was signed on August 25, 2010.  The first NODA was published in the Federal Register on September 1, 2010, and the public comment period closed on October 15, 2010.  The comment period was open for 45 days from the date of publication in the Federal Register and 52 days from the date the NODA was widely disseminated to the public via publication on the web on August 25, 2010.  The second NODA (addressing emissions inventories) was published in the Federal Register on October 27, 2010 and the public comment period closed on November 26, 2010.  The comment period was open for 30 days from the date of publication in the Federal Register (and was widely disseminated to the public via publication on the web at the same time).  The third NODA (allocations and related matters) was published in the Federal Register on January 7, 2011 and the public comment period closed on February 7, 2011.    The comment period was open for 30 days from the date of publication in the Federal Register and 38 days from the date the NODA was widely disseminated to the public via publication on the web on December 30, 2010.  

EPA provided an adequate opportunity for public comment on the proposal and all three NODAs.  EPA complied with the procedural requirements of CAA section 307(d) including those regarding the length of the comment period.  EPA also received several hundred substantive comments during the comment period.  Many of these contained detailed data and analyses.   The volume and depth of the comments received suggests that the opportunity for public comment was adequate.  The fact that more comments could have been provided had the comment periods been extended, does not establish that the comment period was inadequate or not consistent with the procedural requirements of section 307(d).    EPA is mindful both of its obligation to provide an opportunity for public comment and of its obligation to proceed with this rule in a timely manner.
Organization: Clean Energy Group
North Carolina Department of Environment and Natural Resources
Great River Energy
Excelsior Energy
Exeter Energy Limited Partnership
Calpine Corporation
Southern IL Power Cooperative
North Carolina Electric Membership Corporation
Massachusetts Department of Environmental Protection
Northeast States for Coordinated Air Use Management (NESCAUM)
Constellation Energy
Comment: 
Calpine Corporation
Although, as discussed in our subsequent comments, IPM does not provide a realistic estimate of future heat input for specific units, it is a reasonable macro-level model for the purposes of predicting future emissions and electricity production at the state level. [EPA-HQ-OAR-2009-0491-3614, p.2]
Clean Energy Group
Below, we address several broad topics and include several recommendations. None of these recommended modifications to the proposed rule are intended to delay implementation of the rule on January 1,2012. However, in order for the rule to be implemented by January 2012, EP A must be able to make the necessary adjustments to the underlying data to ensure the allocations in 2012 and 2013 properly reflect the planned and installed air pollution controls as well as units' near-term operating circumstances and conditions. As EPA noted in the preamble, there is insufficient time for companies to install control technologies by 2012 unless they are already in progress, but new controls are possible by the 2014 deadline. [EPA-HQ-OAR-2009-0491-2702.1, p. 2]
We support securing these substantial benefits through the implementation of this rule by January 2012. To achieve these important benefits, EP A must address the data inaccuracies noted below and in individual members' comments or modify the unit allocation methodology as recommended below. [EPA-HQ-OAR-2009-0491-2702.1, p. 2]
Constellation Energy
Initially, it is essential that allocations be undertaken in a way that does not disrupt near-term business operations. These disruptions could spur a lengthy legal battle resulting in unproductive delays of improvements in public health. EPA's allocation proposal is the least operationally disruptive in that it allocates allowances roughly in line with companies' expected future emissions. [EPA-HQ-OAR-2009-0491-3613,p.2]
Excelsior Energy
Comment summary for overall allocation approach:
EPA's proposed approach for unit-by-unit allocation of allowances is inequitable, encourages inefficient behavior, and sets an undesirable precedent. However, EPA's alternative proposal would largely eliminate all three of these problems. [EPA-HQ-OAR-2009-0491-2810.1 p.1]
EPA's proposed allocation methodology, which would make a one-time allocation to existing sources based on 2009 or projected 2012 base case emissions, is inequitable. It is most favorable to the highest emitting (worst performing) units and least favorable to the lowest emitting (best performing) units as measured at the time the allocation is made. As EPA itself acknowledges, the proposed methodology 'means that a unit that installs control equipment receives fewer allowances than a similar unit that did not install control equipment' 7S F.R. 45311 (Aug. 2, 2010). Thus, existing units that have invested or committed to invest in retrofits to reduce emissions prior to the one-time allocation are punished with a reduced allocation, while those with the highest emissions are rewarded with a windfall of allowances for emission reductions that they could have made, but did not. Similarly, new units are punished for reducing emissions: under EPA's proposal, they will receive a reduced allocation, and any remaining portion of the new source set-aside will be allocated to existing sources in proportion to the magnitude of their emissions (again rewarding poor performance). If a state adds two new units of the same size, but one unit uses advanced control technology resulting in emissions 90% lower than the other, the allocation given to the unit with advanced controls will be 90% lower than the allocation given to its under-achieving counterpart. [EPA-HQ-OAR-2009-0491-2810.1 p.1]
Under EPA's currently-proposed approach, new and retrofitted units are effectively bearing the burden of achieving emissions reductions for un-retrofitted units, which is inconsistent with the D.C. Circuit Court of Appeals' opinion rejecting the Clean Air Interstate Rule. There, the Court found that the distribution of the burden is important, and objected to CAlR's allocation methodology in part because states with lower initial emission intensities would subsidize reductions in states with higher initial emission intensities. North Carolina v. EPA, 531 F.3d 896, 920 (D.C. Cir. 2008). The CATR's proposed allocation methodology is similar in principle to the one in CAIR that was rejected: it places heavy burdens upon individual units with low emissions in order to subsidize the inability of poorly-performing existing units with high emissions to achieve reductions-in effect, the proposed Rule makes one unit's significant contribution depend on another's cost of eliminating emissions. While the legal basis for the D.C. Circuit Court's objection to CAIR focused on the illogical (and inequitable) interstate distribution of the burden to reduce emissions, the same principle applies to EPA's proposed intrastate distribution of the same burden. [EPA-HQ-OAR-2009-0491-2810.1 p.1]
Secondly, the proposed approach encourages inefficient and counterproductive behavior. A primary aim of emission cap and trade programs is to achieve the most cost-efficient emissions reductions by requiring emitters who cannot cost effectively reduce their own emissions to purchase allowances from others who can. Such transactions thereby establish a price signal that leads to efficient behavior, minimizing the overall cost of compliance to the overall economy. The proposed approach is lacking in this regard, and in fact has the potential to cause inefficient behaVior. For example, under EPA's proposed approach, owners who might otherwise completely shut down older, economically-marginal, high-emitting units would be compelled to keep those units operating (potentially at diminished capacity factors) in order to continue receiving the financial benefit of their disproportionately large allocation of allowances. New units would be isolated within the new source set-aside, insulating existing sources from competition within emission allowance markets from lower-emitting new sources. Thus, counter productively, the very facilities in each state that have persisted in contributing to downwind non-attainment would be encouraged to continue operating, while facilities that have already made investments to minimize their downwind contributions would be arbitrarily and capriciously be denied the primary benefits of doing so. [EPA-HQ-OAR-2009-0491-2810.1 p.3]
Finally, the proposed approach sets an undesirable precedent. It discourages early action from sources that anticipate potential regulation, since those who reduced emissions early are effectively punished for their reduced emissions through the issuance of reduced allowance allocations. This sends the signal that early reduction of other pollutants (such as greenhouse gases) for which regulation is emerging may also be punished. In light of EPA's treatment of pollutants in this proposed Rule, entities contemplating projects that would reduce greenhouse gas emissions may decide that postponement of those projects is prudent to ensure that their good behavior is not punished with a reduced allocation. [EPA-HQ-OAR-2009-0491-2810.1 p.3]
In contrast, EPA's alternative approach of allocating to units within each state based on heat input would avoid these problems: such a methodology would be more equitable, encourage efficient behavior, and set a good precedent. Units that made early retrofits to reduce emissions would be properly rewarded and compensated by those who did not. Since allocations would be equitable and regularly adjusted, this approach would discourage inefficient behavior like keeping older, high-emitting units running beyond what would otherwise be the end of their useful economic life. A new source setaside would be unnecessary, and new units could capture the benefits of reducing emissions, making them able to freely compete with existing units. [EPA-HQ-OAR-2009-0491-2810.1 p.2]
The alternative heat input-based allocation approach EPA that is contemplating in the CATR differs from those in CAIR and overcomes the deficiencies that prompted the D.C. Circuit Court's rejection of CAIR. In North Carolina v. EPA, the Court rejected EPA's proposed fuel-adjustment factors primarily because EPA was trying to protect states with higher emission intensities out of 'fairness'; EPA adjusted each state's heat input for the mix of fuels its power plants used (i.e., coal-fired EGUs contributed full heat input to the state budget, but oil-fired and gas-fired EGUs contributed only 60% and 40% of their heat inputs respectively). The D.C. Circuit rejected the fuel adjustment factors because it found the effect of the fuel-adjustment factors irrational: 'in essence, a state having mostly coal-fired EGUs gets more credits because Louisiana [a state with EGUs that use more gas and oil than most other states' EGUs] can control emissions more cheaply.' Here, EPA dutifully reports that its proposed methodology for allocating allowances does not consider heat input or fuel adjustment factors-but by seeking to avoid similar objections to its allocation methodology, EPA unwittingly runs afoul of the very problem it seeks to avoid. By failing to adjust emission requirements for each facility based on heat input, EPA essentially gives more credits to (requires less reduction from) older, inefficient facilities because newer facilities can control their emissions more cheaply-making one unit's significant contribution and burden depend on another unit's cost of eliminating emissions. At the same time, EPA's alternative heat-rate based methodology would stand a lesser risk of rejection by a reviewing court because contrary to the method in CAIR, the methodology would not work to protect emitters, and the underlying reasoning for the methodology would be to reward and encourage future emission reductions-the very point of the Rule-rather than to arbitrarily and capriciously achieve 'fairness.' [EPA-HQ-OAR-2009-0491-2810.1 p.3]
Exeter Energy Limited Partnership
2. Annual NOx and SO, Allowance Allocations:
Should the Exeter Facility be subjected to the Proposed Transport Rule, it would be critical to rectify its apparent omission from the annual allowance allocations for either NOx or SO,. In section V.DA.b(2) (page 45309-453 10) of the preamble to the Proposed Transport Rule, EPA references the proposed unit level allocations for existing units (contained in 'State Budgets, Unit Allocations and Unit Emissions Rates' TSD in the docket). Based on review of this document, although Exeter Energy has been allocated ozone season NOx allowances for each unit, no annual NOx or SO, allowances have been allocated to Exeter Energy. In order to assist EPA in calculating allowance allocations, Exeter Energy is submitting documentation in the attached table of its NOx and SO, emissions on a per boiler and per month basis for calendar years 2007 through 2009. Monthly summaries for 20] 0 through June are also provided. [EPA-HQ-OAR-2009-0491-2835.1 p.3]
Great River Energy
As a generation and transmission cooperative, Great River Energy is required to provide the capacity and electrical supply projected for our member distribution cooperatives. As our cooperatives project their load, we are responsible for providing the necessary power to cover their load in MISO ('Midwest Independent System Operator' - our regional transmission operating system). Minnesota has a renewable energy standard requiring electrical suppliers' to provide 25% of their electrical power in a renewable form by 2025 (with interim requirements of 12% by 2012, 17% by 2016, etc.). A by-product ofthis standard is that when the renewable form of energy is not available due to environmental conditions, we must still hold enough capacity with other existing generating facilities to cover our demand on the regional transmission system. GRE utilizes simple cycle combustion turbines to meet this requirement. In addition to covering the renewable sources for the cooperatives our generating facilities are used to cover the peak electrical demand of our 28 distribution cooperatives. Our peak demand typically occurs during the summer months with a smaller peak also occurring in the winter months. Much of our peak demand is due to air conditioning usage during the hottest months in the summer. Projections of expected weather and economic development are used to ascertain the future generation needs of our distribution cooperatives. In mild summers our Minnesota generating sources are not heavily utilized. The summers of 2008 and 2009 were very mild and the data used in 2008 and 2009 were the lowest usage years since the startup of our combustion turbines. This fact, in combination with many data entry errors in the base case modeling information, has led GRE to believe that our allocations are lower than they should be.  [EPA-HQ-OAR-2009-0491-2758.1 p.2]
Great River Energy has reviewed the distribution of allowances in Minnesota and finds the EPA methodology to be illogical, inequitable, and inconsistent with the stated goal of a flexible program. EPA inherently recognizes the potential problem of creating virtual monopolies, as it describes in the allocation of resources within a specific state. 'The distribution of allowances would be modified because of the concentrated nature of numerous state power markets, which would be reflected in the state allowance market if all allowances were distributed in each state based on factors reflecting generation in that state. The electric power sector tends to be highly  concentrated, and, within a state, the majority of generation is often owned by a relatively small number of companies.' (emphasis added) (FR 45326)  [EPA-HQ-OAR-2009-0491-2758.1 p.8]
This is especially true in Minnesota. With respect to NOx allocations, as an example, EPA has allocated ~89% of allowances to two utilities. (See Attachment 3.)
Further, upon deeper review, one Minnesota plant alone accounts for ~40% of state NOx allocations and, by EPA's own analysis, this one plant is not projected to install SCR as a NOx control by 2012, or by 2014 for that matter. Given the concentration of allowances within two companies and the limited allocations to the remaining smaller sources within Minnesota, GRE is extremely concerned about a lack of allowances for intrastate trading. This has significant implications for us. Smaller cooperatives and municipal power providers such as Rochester Public Utilities, Otter Tail Power, Southern Minnesota Municipal Power Agency and Great River Energy will face limited allowance access and, in virtually all instances, cannot cost effectively control their emission sources and remain competitive in the region.  [EPA-HQ-OAR-2009-0491-2758.1 p.9]
As demonstrated in our emissions summary table (Attachment 1), GRE is projected to have a significant NOx allowance deficit from the beginning of the Transport Rule implementation. We disagree with EPA's allocation methodology, for the reasons stated in these comments. In addition, we do not expect a viable intrastate trading program under Option 2, which will force us and other smaller utilities to engage in limited interstate trading under the Preferred Option. GRE has concerns about legal challenges to the Preferred Option, and EPA's ability to address the D.C. Circuit Court's concerns on failing to address upwind state contributions to nonattainment, as was rej ected under CAIR.  [EPA-HQ-OAR-2009-0491-2758.1 p.9]
If allowance trading does not develop, as GRE expects, GRE will be penalized additional allowances, placing us more deeply into allowance deficit, and potentially facing Clean Air Act penalties for not holding sufficient allowances. EPA has made statements that under its Preferred Option, there will not be additional Clean Air Act penalties for failing to hold sufficient allowances. Yet, this is not readily apparent from reading the preamble and proposed Transport Rule. ?  [EPA-HQ-OAR-2009-0491-2758.1 p.9]???
 Under the Transport Rule, Great River Energy is faced with purchasing allowances as a sole compliance strategy. Great River Energy combustion turbines were not correctly allocated for the reasons presented herein. Controls are not cost effective for our combustion turbines, as deemed by EPA's own analysis. Great River Energy is worried that there will not be a viable intrastate trading program. Great River Energy is hopeful that interstate trading will bridge the compliance gap. This extremely awkward compliance strategy could easily result in years of allowance deficits and potential non-compliance, further penalizing Great River Energy's inherently clean simple cycle combustion sources.  [EPA-HQ-OAR-2009-0491-2758.1 p.9]
Massachusetts Department of Environmental Protection
For example, EPA could develop an output-based allocation methodology that would incorporate efficiency considerations. We recommend that rather than basing allocations on historical emissions as proposed in the Transport Rule, EPA allocate allowances using an output-based allocation methodology similar to that incorporated by Massachusetts in its NOx Budget (310 CMR 7.28(6)(c) and (d)) and CAIR NOx Ozone Season programs (310 CMR 7.32(5)(c)1.b.) Under this output-based approach, Massachusetts facilities received NOx allowances based on their net electricity and steam output thereby rewarding more efficient generation. Within the electrical grid system, rewarding allocations based on an output basis will encourage the utilization of the most cost-effective units, so that older, less-efficient units that have historically been dispatched will eventually be replaced with a fleet of newer and cleaner EGUs. [EPA-HQ-OAR-2009-0491-2787.2 p.11]
North Carolina Department of Environment and Natural Resources
In general, it has been recognized that allocations based upon heat input could 'penalize' high efficiency operations by granting less allowances due to lower heat input for a given heat output. It has been argued that allocations based upon output could and should force improvements in operations and increased operation efficiency. As noted, in future regulations where states are preparing SIPs to respond to new guidance and requirements, states may consider using output based allocations. However, it may require a transition period to convert from one method of allocation to another. In the end, both methods must address downwind impacts [EPA-HQ-OAR-2009-0491-2767.1 p.9].
North Carolina Electric Membership Corporation
Please see the attached file for corrections to the North Carolina Electric Membership Corporation (NCEMC) facilities in North Carolina (NCEMC Anson Plant and NCEMC Hamlet Plant). In the files, yellow highlighting indicates corrections of data and blue highlighting is data which should change based on the corrections. This file is based on the Budgets and Allocations table from the Technical Information section of EPA's Transport Rule website. [EPA-HQ-OAR-2009-0491-3764 p.1]
Items to note from the individual spreadsheet tabs. [EPA-HQ-OAR-2009-0491-3764 p.1] 
Unit Characteristics tab: The MW capacity apportioned for each of the turbines has been entered, the turbines are Pratt & Whitney Twin-Pacs which are two turbines connected to a single generator. [EPA-HQ-OAR-2009-0491-3764 p.1]
Projected Data tab: This tab appears to be related to the IMP modeling, pursuant to the comment noted below, all of the units should be included in the modeling.
Allocations & Rate Limits tab: The ES6-A and ES6-B units at the Anson Plant should be allocated annual NOx allowances. We feel that this was an error in the data which caused annual heat input to be blank. [EPA-HQ-OAR-2009-0491-3764 p.1]
Also, we have noticed that the NCEMC Hamlet Plant has not been included in the NEEDS database but the NCEMC Anson Plant has. Both plants should be included in the database and subsequent modeling. [EPA-HQ-OAR-2009-0491-3764 p.1]
Northeast States for Coordinated Air Use Management (NESCAUM)
EPA can and should, at minimum, establish allocations based on output.[EPA-HQ-OAR-2009-0491-2694.1 p.8]
Southern IL Power Cooperative
EPA's proposed system relies on computer modeling of future individual unit utilization and emissions controls operation or installation. In other words, the rationale for essentially permanent unit allocations comes from EPA's computerized virtual world containing numerous false assumptions. [EPA-HQ-OAR-2009-0491-2863.1 p.3]
Response: 
Thank you for your comment.
Organization: Cogen Technologies Linden Venture, LP
Comment: 
Cogen Technologies Linden Venture, LP
Linden Cogen operates a 900 megawatt ('MW') natural gas-fired cogeneration plant in Linden, New Jersey, which provides steam and power to ConocoPhillips' Bayway refinery and power to both the New York City grid operated by the New York Independent System Operator ('NYISO') and the Pennsylvania/Jersey/Maryland ('PJM') Interconnection. Linden Cogen objects to EPA's proposed allocation of allowances for both annual oxides of nitrogen ('NOx') and ozone season NOx for its natural gas-fired facility for the following reasons: [EPA-HQ-OAR-2009-0491-2712.1, p.1]
:: EPA's proposed allocation for Linden Cogen, which is a highly efficient combined-cycle plant equipped with selective catalytic reduction ('SCR'), would provide only a small fraction of the annual and ozone season NOx allowances it will need to continue meeting demand under its long-term contracts with utilities and its cogeneration host. These results are based upon erroneous projections EPA has made using the Integrated Planning Model ('IPM'), which predicted that Linden Cogen will only operate at a fraction of its historical capacity. In essence, IPM has predicted dispatch of Linden Cogen as a peaking plant, rather than a baseload generating plant, because IPM fails to account for the existence of long- term contracts that practically assure operation of Linden Cogen at baseload capacity throughout the term of its contracts. [EPA-HQ-OAR-2009-0491-2712.1, pp.1-2]
:: The IPM projections have no basis in reality and are clearly disproven by Linden Cogen's historical dispatch as a baseload plant and by its ongoing contractual obligations to provide power to New York City and both power and steam to the largest refinery on the East Coast. The D.C. Circuit has previously rejected EPA's reliance upon IPM projections which were based upon certain false assumptions concerning future utilization, where the resulting projections were seemingly implausible and ran contrary to 'real world observations'. See Appalachian Power Co. v. EPA, 249 F.3d 1032, 1054 (D.C. Cir. 2001) ('Appalachian Power f'); Appalachian Power Co. v. EPA, 251 F.3d 1026, 1035 (D.C. Cir. 2001) ('Appalachian Power If'). EPA must resolve these serious deficiencies in IPM, so that it accurately predicts dispatch of facilities subject to long-term contracts. [EPA-HQ-OAR-2009-0491-2712.1, p.2]
:: In addition to IPM's failure to reflect the reality of dispatch for plants with long-term contracts, Linden Cogen believes IPM's inaccurate projections are due to EPA's reliance upon an erroneous heat rate and application of the wrong assumptions concerning fixed operating and maintenance ('FOM') costs, variable operating and maintenance ('VOM') costs and fuel costs for each of Linden's generating units. EPA's IPM runs assumed an erroneous heat rate of 9173 British thermal units per kilowatt hour ('Btu/kWh'), which is dramatically higher than the plant's actual average heat rate of 7965 Btu/kWh. EPA cannot assign FOM, YOM and fuel costs to Linden Cogen significantly greater than a similar combined-cycle facility in New Jersey, without providing specific justification for such disparate treatment. Further, EPA must provide an opportunity for parties to correct these erroneous model inputs and must then re-run the model, before relying upon the results as the basis for allocating allowances. [EPA-HQ-OAR-2009-0491-2712.1, p.2]
:: The preamble to the Proposed Transport Rule says that EPA rejected IPM's projected utilization and emissions as the basis for setting state-wide budgets because IPM's projections were less reliable than actual operating data. EPA has provided no explanation for how it could reject IPM's projections as less reliable than actual data in setting state budgets, but then rely upon those same projections in establishing unit-by-unit allowance allocations. It would be arbitrary and capricious for EPA to rely upon IPM's projections as the basis for establishing allocations, when EPA has already acknowledged that those projections cannot be relied upon to establish the corresponding state budgets. IPM has projected utilization of existing units in New Jersey at heat rates that are wildly inaccurate and, in the case of Linden Cogen, wholly inconsistent with its long-term contractual obligations. EPA cannot simply ignore these discrepancies. To do so would run afoul of the D.C. Circuit's mandate that EPA explain disparities between IPM's projected future utilization rates and 'real world' evidence to the contrary. See Appalachian Power 1,249 F.3d at 1054. [EPA-HQ-OAR-2009-0491-2712.1, pp.2-3]
:: The practical consequences of EPA's allocation methodology for Linden Cogen are that it will likely need to purchase the vast majority of allowances it needs to continue meeting its contractual obligations. In contrast, EPA's proposed allocation methodology would allocate nearly 90% of the State's overall budget to a number of coal generating units in New Jersey, which would also receive a significantly greater number of allowances under the Proposed Transport Rule than they received under the Clean Air Interstate Rule ('CAIR'). Thus, under EPA's proposed methodology for New Jersey, these coal plants would likely become sellers of allowances, while Linden Cogen would become a buyer. As a result, these coal plants may be gaining a substantial subsidy, at the expense of cleaner burning facilities such as Linden Cogen, which will undoubtedly need to purchase NOx allowances to continue meeting its long-term contractual obligations. The costs to obtain such allowances cannot, for the most part, be passed along to Linden Cogen's customers and would therefore place Linden Cogen at a significant disadvantage. Such a policy outcome would be wholly at odds with the Administrator's stated goal of fostering investment in a 'clean, efficient, and completely modem power sector.' 75 Fed. Reg. at 45227. [EPA-HQ-OAR-2009-0491-2712.1, p.3]
:: Before relying upon IPM projections as the basis for setting unit allocations for New Jersey, EPA must re-run IPM using corrected inputs for Linden Cogen's heat rate, FOM costs, VOM costs and fuel costs. EPA must also account for the fact that Linden Cogen is operated pursuant to long-term power sales agreements and a steam sales agreement, which require its continued operation as a baseload plant. Accordingly, in the event that EPA continues to rely upon IPM's projections as the basis for allocating allowances to individual units, EPA must either incorporate the contractual terms governing dispatch into IPM or establish rules within IPM that essentially 'force' the model to predict dispatch of Linden Cogen consistent with the requirements of its power sales and steam sales agreements. [EPA-HQ-OAR-2009-0491-2712.1, p.3]
:: If EPA cannot correct the errors in IPM that have generated arbitrary and unrealistic predictions of future dispatch for Linden Cogen, EPA should instead base the unit-specific NOx allocations for New Jersey on the same methodology which was used to derive the state budgets. The preamble to the Proposed Transport Rule indicates that New Jersey's state budgets (as well as all other state budgets, other than the 2014 SO2 budgets for group I states) were based on historical operating data, as augmented by assumptions about when existing and planned emissions controls will be operated. Accordingly, the unit-specific allocations for New Jersey should similarly be based on such historical data and operating assumptions. An allocation methodology based on historic operating data is not at all inconsistent with the court's decision in North Carolina v. EPA and would assure that the same analyses and data supporting establishment of a state's budget are used to support the unit-specific allocations within the state. In fact, for all allocations but the 2014 sulfur dioxide ('SO2') allocations in group 1 states, EPA has already proposed basing allocations on historical data, augmented by assumptions about the operation of existing and planned controls, wherever those data resulted in lower statewide emissions than projected by IPM. [EPA-HQ-OAR-2009-0491-2712.1, pp.3-4]
:: If EPA cannot correct the errors in IPM that have resulted in its erroneously low projections for dispatch of Linden Cogen, then the agency should instead decide to base New Jersey NOx allocations for individual units on historical data. EPA should base such allocations on data, not from a single year, but from a more representative period of time. Once each facility's representative baseline has been established, EPA should then sum together all facilities' baseline emissions, compare the total with the state budget, and then reduce each facility's allocation by whatever percentage is needed for the total statewide emissions (plus the 3% set aside for new facilities) to fit within the budget. Using only one year's data as the basis for allocations could penalize facilities that had lower emissions in 2008 or 2009 because they operated at a lower capacity factor due to the recession or were down for an extended period of time to install controls in advance of CAIR. [EPA-HQ-OAR-2009-0491-2712.1, p.4]
:: Linden Cogen does not support the alternative allocation methodology described by EPA in the preamble, wherein each facility would be allocated allowances based on its 'share of projected heat input' within the state. 75 Fed. Reg. at 45311. As presented, this alternative allocation methodology would not resolve the serious problems associated with allocating allowances based on IPM's projected dispatch of facilities such as Linden Cogen, which are subject to long-term contractual obligations that mandate their operation. However, if EPA can successfully resolve the errors in IPM that resulted in its erroneously low projected dispatch for Linden Cogen or if EPA's proposal were to allocate allowances based on each source's share of historical (rather than projected) statewide heat input, Linden Cogen agrees that this would be a fair and equitable approach. [EPA-HQ-OAR-2009-0491-2712.1, p.4]
:: As an alternative to resolving the errors in IPM or basing New Jersey NOx allocations on historical heat input data, EPA could refrain altogether from promulgation of the proposed Federal Implementation Plans ('FIPs') and instead support states' efforts to submit adequate State Implementation Plan ('SIP') revisions within a reasonable amount of time. While awaiting states' submission of SIP revisions might delay implementation of the CAIR's replacement program until after 2012, it should not result in any delay in attainment or interference of maintenance of the National Ambient Air Quality Standards ('NAAQS'). It also would provide states the opportunity to develop SIP revisions that also addressed anticipated revisions of the NAAQS, without requiring an unnecessary and duplicative series of rulemakings and SIP revisions. [EPA-HQ-OAR-2009-0491-2712.1, p.4]
:: Linden Cogen believes EPA should provide relief, as Congress previously has, for long-term contract generators who have no means of recovering the cost of emissions allowances. EPA should make any remaining allowances in the new unit set-aside available to long-term contract generators who exceeded their allocation in the preceding control period due solely to an increase in utilization back to levels achieved prior to the recession. This would prevent long-term contract generators from needing to pay potentially significant costs to purchase allowances after the conclusion of a control period. It also could be accomplished without compromising the integrity of the statewide emissions budgets. [EPA-HQ-OAR-2009-0491-2712.1, p.5]
Response: 
Regarding allowance allocations and the dispatch of electricity generation, please see the Allowance Allocation Final Rule TSD.
EPA does not agree with the commenter that "providing relief" to specific generators or other detailed considerations of equity are relevant to the statutory mandate of section 110(a)(2)(D)(i)(I); instead, EPA is using a fuel- and control-neutral approach to allocations under the FIPs, as explained in section VII.D of the final rule preamble.
Organization: Connecticut Department of Environmental Protection
Comment: 
Connecticut Department of Environmental Protection
Allocation proposal rewards dirtier units. CTDEP does not support the proposed allocation methodology in the Transport Rule because it rewards dirtier units. EPA states that "...all units are allocated allowances consistent with their projected emissions; this means that a unit that installs control equipment receives fewer allowances than a similar unit that did not install control equipment." (75 FR 45311) EPA requested comment on an alternative methodology that would distribute allowances equal to a state's emissions budget without variability to each covered source in the state based on each source's proportional share of total state heat input. EPA should base allocations on individual EGU's electricity output provided that EPA continues to link each state's budget to significant contribution. [EPA-HQ-OAR-2009-0491-2780.1 p.20]
Allocations to non-operating units. CTDEP does not support EPA's proposal to continue allocating allowances to non-operating units for up to 6 years following non-operation. CTDEP believes that allowances should be allocated on the basis of recent history of operations, preferably output based, in proportion to the unit's generation the previous year. At a minimum, allowance allocations should cease after 3 years of non-operation. The financial incentive gained from receiving allowances beyond the 3 year period after non-operation will play a limited role in determining future EGU operations and is insignificant compared to operating costs associated with fuel use. [EPA-HQ-OAR-2009-0491-2780.1 p.20]
Response: 
EPA has decided to base allocations made under the FIPs on historic heat input, subject to a maximum allocation limit to any individual unit based on that unit's maximum historic emissions. Further detail on the implementation of this approach, rationale, and response to comments on the allocation method is provided in Preamble Section VII.D. as well as in the Allowance Allocation Final Rule TSD in the docket for this rulemaking.
Please see Preamble Section VII.D.2. for a description of how the Transport Rule will handle allocations to non-operating units and responses to comments on the topic.
Organization: Consumers Energy
Comment: 
Consumers Energy
 Allocations should be handled by the states. The states know their jurisdictions and their sources best. A total allowance budget should be assigned to each state. They can handle the distribution schemes.  [EPA-HQ-OAR-2009-0491-3795.1_NODA, p.5]
Response: 
For an explanation of FIP Authority for each State and NAAQS Covered and response to relevant comments, see Preamble Section IV C 2.
Organization: Dow Chemical Company
Comment: 
Dow Chemical Company
As a separate comment, Dow believes that EPA should provide an exemption to sources that exceed the annual electricity sales limit due solely to the occurrence of an emergency. For instance, EGUs as well as local transmissions systems located in Louisiana can be adversely affected by hurricanes or floods. There have been occasions in the past where EGUs adversely impacted by hurricanes have been unable to provide electricity to their customers. In those cases, sources meeting the cogeneration exemption may be called upon to temporarily increase their electricity production to provide for critical infrastructure power needs until the primary utility systems can return to electrical power production. By selling electricity in these times of crisis, exempt sources may exceed the proposed Transport Rule/FIP electricity sales thresholds and therefore trigger applicability under the Transport Rule/FIP. Dow believes that these sources should not be penalized by triggering regulatory applicability solely due to provision of power during such emergency periods. Dow thus requests that EPA provide an exception to the Transport Rule stating that sources will not lose their exemption for temporary activities that occur in response to emergencies. EPA could impose appropriate criteria to limit the scope of this exception; however, such an emergency exception is needed under the proposed rule. [EPA-HQ-OAR-2009-0491-2775.1 p.9]
Response: 
EPA believes that the allowance trading provisions in the Transport Rule will provide sufficient flexibility in such emergency situations. For more information on the trading provisions, please see Preamble Section VII.
Organization: East Texas Electric Cooperative
Comment: 
East Texas Electric Cooperative
Units relocated from one state to another should be recognized in the state to which they have been relocated and allocated new unit allowances based upon the most current data available. [EPA-HQ-OAR-2009-0491-2770.1 p.2]
Response: 
Please see Preamble Section VII.D.2. for an explanation of how allocations for relocated units will be handled.
Organization: Edison Electric Institute (EEI)
Comment: 
Edison Electric Institute (EEI)
EEI supports banking of allowances beginning in 2012 under the preferred approach. The proposed Transport Rule properly recognizes the important environmental and economic benefits of allowance banking, and that allowance banking as an element of EPA's CAIR program was in no way undermined by the court's decision in North Carolina v. EPA. [EPA-HQ-OAR-2009-0491-2697.1, p.16]
Response: 
Thank you for the comment. EPA has retained the banking provisions in the final rule. For more information on banking, see Preamble Section XI.
Organization: Exxon Mobil Corporation
Comment: 
Exxon Mobil Corporation
Considering the unreasonable and unsupported initial allocations under the proposed FIP, it is also unreasonable for a facility to expend resources prior to final rule promulgation since it is not reasonable to predict how EP A may respond to the significant errors found in the proposed rule. [EPA-HQ-OAR-2009-0491-2841.1, p.16]
Response: 
Thank you for your comment.Organization: Green Exchange, LLC
Comment: 
Green Exchange, LLC
Green Exchange recognizes EPA's efforts in the proposed Transport Rule to have emissions trading play a central role in the Transport Rule, while working within the bounds of the D.C. Circuit's earlier decision. We appreciate that the EPA understands the importance of maintaining the integrity of allowances as they represent the return on emission reduction investments. [EPA-HQ-OAR-2009-0491-1105.1, p.2]
Response: 
Thank you for the comment. EPA has maintained the trading provisions in the final Transport Rule. For more information, please see Preamble Section VII.
Organization: Independence Power & Light (IPL)
Comment: 
Independence Power & Light (IPL)
For the reasons stated herein, IPL requests that EPA modify the proposed Rule by:  
4. confirming that units in existence but not online, or units that are newly constructed but not online as of the effective date of the proposed Rule are eligible for allocations. [EPA-HQ-OAR-2009-0491-2741.1, p.18] 
Response: 
Please see Preamble Section VII C for a description of how units are assigned allocations.
Organization: Indiana Energy Association
Comment: 
Indiana Energy Association
f. The Indiana Utility Group supports EPA's direct issuance of allowances to affected sources and no auction of allowances. [EPA-HQ-OAR-2009-0491-3711 p.5]
e . The Indiana Utility Group supports unlimited banking of allowances. [EPA-HQ-OAR-2009-0491-3711 p.5]
Response: 
Thank you for the comments. EPA has chosen to maintain direct issuance of allowances under the final Transport Rule and banking of allowances. For more information on these topics, see Preamble Sections VII and XI.
Organization: Kansas City Board of Public Utilities (BPU)
Comment: 
Kansas City Board of Public Utilities (BPU)
For the reasons stated herein, BPU requests alternative modifications to the proposed Rule by: 
2. eliminating the ozone season NOx allocation restrictions for all Kansas EGUs listed in Appendix A; 
4. removing BPU's units from the NOx and SO, allocation restrictions listed in Appendix A;  
6. clarifying that zero allocation units listed in Appendix A will obtain a positive allocation immediately upon completion of retrofitting;  
8. replacing the allowances for BPU's electrical generating units listed in Appendix A with the following allowances:
Quindaro, CT2 - NOx:22 tons; S02:12 tons
Quindaro, CT3 - NOx:34 tons; S02:20 tons
Neannan, CT4 - NOx:40 tons; S02:8 tons
Neannan, Nl - SO2:6390 tons
Quindaro, Q2 - SO2:2079 tons
Quindaro, Ql - NOx:2547 tons; S02:2032 tons 10  [EPA-HQ-OAR-2009-0491-2740.1, p.23]

10 The allocations for the CTs are derived from the highest annual NOx & S02 tons that BPU reported during the period 2005-2009. For S02, the requested allocations match BPU's Acid Rain Permits,  
Response: 
For a description of the method and response to comments for identifying states that have a significant contribution to nonattainment or interfere with maintenance in other states, please see Preamble Section V.
Organization: Michigan Department of Natural Resources and Environment
Comment: 
Michigan Department of Natural Resources and Environment
The EPA has supplied data (in particular the spreadsheets titled BADetailedData.xls and AliocationTable.xls) regarding projected allocation budgets for the years 2012 and 2014 using the preferred compliance option. The TR proposal used the 2004, 2005, and 2006 EGU heat input data to determine the allocations. Michigan used the heat inputs from 2004, 2005, 2006, 2007, and 2008 to determine the CAIR bUdgets for the EGUs within the state. However, the DNRE has concerns about the differences in budgets and allocations from CAIR to TR, so we conducted a careful review of the data. The DNRE would like to add that while we noted the potential for additional allowances under the variability calculations, those amounts are not included in this discussion. [EPA-HQ-OAR-2009-0491-2774.1 p.7]
However, the proposed TR FIP NOx allocations, which are specific to individual sources, are significantly different than under CAIR (see Tables 1, 2, and 3 in Appendix C). Some sources in Michigan's CAIR program were left out of the allocations under the FIP. In addition, other sources were given amounts significantly less or more than under Michigan's CAIR rules. For example, DTE's Maryville's plant has not operated since before 2004 and was not given allowances under the CAIR program for 2012 and beyond. Yet the EPA's FIP allocated large amounts of allowances for these units. The DNRE recommends that state allocations under a SIP would eliminate the uncertainties noted using allowances under the proposed FIP. [EPA-HQ-OAR-2009-0491-2774.1 p.7]
Furthermore, the DNRE would like clarification as to whether the budget totals noted above (and in the attached tables) includes the three percent to be set aside for new sources. [EPA-HQ-OAR-2009-0491-2774.1 p.8]
The proposed TR will 'set-aside' three percent of a state's total budget to be used for new source allowances. A new source would be required to request allowances from the new source set-aside the year following the first year of operation. In the case where assurance provisions (variability) for a state are triggered in the year that a new unit first operates, the new unit would have no allocation for that year. Therefore, the owner's share would necessarily be zero. A specific surrogate emission number would be used to calculate the maximum amount the unit would have emitted in that year before being required to surrender allowances under the assurance provisions. The surrogate emissions number would apply only if the state's assurance provisions were triggered and only in the first year of the new unit's operation. [EPA-HQ-OAR-2009-0491-2774.1 p.9]
The DNRE requests the following clarifications:
1. Does this mean that for the first year of a new source's existence they are not required to hold allowances or does this mean that new sources would be required to obtain allowances for the first year of operations from somewhere else, as in trading?
2. Where do the 'surrogate emissions' come from?
3. Will these 'new' sources ever become existing within the TR framework or will they remain 'new' sources indefinitely?
The DNRE also believes that three percent for the set-aside is an arbitrarily determined number, not based on potential installations or start-ups. During the CAIR program in Michigan, the new source set-aside retained 1 to 2.5 percent of allowances from the original budget. These numbers were determined using a projected number of potential new sources in the state. [EPA-HQ-OAR-2009-0491-2774.1 p.9]

 
Concern is expressed in the proposed TR that states allocated allowances differently than the CAIR FIP as originally proposed, and whether states implemented the fuel adjustment factor. [EPA-HQ-OAR-2009-0491-2774.1 p.9]
Michigan utilized a 'hybrid' fuel adjustment to determine allowances to sources based on the fuel used by the sources. This hybrid approach used the terms solid, liquid, and gas in place of coal, fuel oil, and natural gas. The DNRE believed that the change in terms better defined the types of fuel used in Michigan. For instance, the solid fuel terminology included biomass, coal and tires, where gas included natural gas, propane, and blast furnace gases. [EPA-HQ-OAR-2009-0491-2774.1 p.10]
Response: 
For more information on the new unit set aside and how the size was determined, see Preamble Section VII.D.2. 
For information on how surrogate emissions are calculated under the final rule, please see Preamble Section VII.E. and the Capacity Factors Analysis for New Units Final Rule TSD.
Organization: Minnesota Pollution Control Agency (MPCA)
Comment: 
Minnesota Pollution Control Agency (MPCA)
If EPA intends to change the unit by unit allocations in the final Transport Rule, the MPCA believes that it is important that EPA provide additional notice on the final allocations, prior to finalizing the rule. The EPA has released the new Integrated Planning Model data, which is being reviewed by states and facilities. If changes to the allocations result from this review or from other comments on the Transport Rule, EPA should release a Notice of Data Availability, supplemental notice, or similar document in order to allow units to review the changes to their allocations. The MPCA believes this can, and should, be done without jeopardizing the overall schedule for rule promulgation. This additional notice is especially important due to the short time frame between the anticipated finalization of the Transport Rule in June 2011 and the start of the program in January 2012. [EPA-HQ-OAR-2009-0491-2521.1, p.2]
Response: 
EPA followed guidelines for public comment periods and gave as much time as possible for receiving comments while abiding by the court's order to move as expeditiously as possible in replacing the Clean Air Interstate Rule. For a history of the rulemaking, including a description of supplemental Notices of Data Availability, please see Preamble Section IV B.
EPA received and declined several requests to extend the comment period for the proposed Transport Rule. The comment period on this rule ended on October 1, 2010. The proposed rule and much of the key supporting documentation was posted on our website on July 6, 2010 and the rule was formally published in the Federal Register on August 2, 2010. We believe the comment period provided was sufficient for interested parties to review the rule, prepare and submit input. This time frame allowed EPA to consider public comments and develop a final rule in time to obtain needed emission reductions.
Organization: Morgan Stanly Capital Group
Comment: 
Morgan Stanly Capital Group
MSCG generally supports the premise underlying the Administrator's proposal for a multi-state, cap-and-trade program to reduce SO2 and NOx emissions, and appreciates that the Administrator has tried to design a program that will be consistent with the D.C. Circuit Court's decision in North Carolina v. EPA.3 Based on years of experience in both the power and emissions markets, MSCG believes that the primary mechanism for emissions allocation should be an auction process. However, to the extent that such allowances are allocated, the EPA's remedy option utilizing state budgets with limited interstate trading (the "Primary Proposal"), is superior to either of the alternatives developed in the Proposed Rule.4 However, unless it is modified in certain key respects, as described below, MSCG believes that the Primary Proposal is flawed because it presents unmanageable risks for independent power generators generally, and peaking plants in particular.5 The following aspects of the Primary Proposal are particularly problematic: [EPA-HQ-OAR-2009-0491-2819.1 p.2 ]
Many peaking plants, including those owned by MSCG, have been allocated few to no allowances.7 As now designed, the Proposed Rule also would not allow them much, if any, portion of the state's variability limit. Therefore, operation of such facilities in compliance with the Proposed Rule could be very difficult, if not impossible; [EPA-HQ-OAR-2009-0491-2819.1 p.3]
Most, if not all, allowances will be allocated, and the allocations are likely to cover less than the operating capacity of many units. Consequently, MSCG anticipates that the allowance market will be highly illiquid; [EPA-HQ-OAR-2009-0491-2819.1 p.3]
If the allowance market is as illiquid as MSCG (and the EPA) projects, peaking unit operators will not be able to evaluate operating costs and price their product on a timely enough basis to provide a quick response which constitutes their primary function (i.e., to provide power in times of high demand or unusual system events) [EPA-HQ-OAR-2009-0491-2819.1 p.3]
1. Allocation of Allowances on Basis of Currently Permitted Emissions or Exemption of Peaking Plants from Proposed Rule Peaking plants are brought online in times of high demand or unusual system events to ensure the reliability of the electric transmission grid. Yet, under the Proposed Rule, peaking plants are not allocated enough allowances to start up and operate. In fact, in all but two instances, MSCG's peaking plants are not allocated any allowances at all. [EPA-HQ-OAR-2009-0491-2819.1 p.6]
The Administrator should consider allocating emissions allowances to all plants based on currently permitted emissions under CAA permits, rather than on historical or projected emissions. This would better provide the necessary allowances for start-up and operation. In the alternative, the EPA could either (1) allocate allowances to peaking plants only based on permitted emissions for peaking plants only, or (2) exempt peaking plants from the Proposed Rule. [EPA-HQ-OAR-2009-0491-2819.1 p.6]
4. Close-out of Allowance Allocation Upon Plant Closure
Given the likely illiquidity of allowance markets under the Proposed Rule, the EPA should not allocate scarce allowances to closed plants.22 MSCG does not believe that allowance revenue, or the lack thereof, will have a significant impact on closure decisions. Furthermore, the underlying purpose of a market is to use allowance prices to drive investment and closure decisions. Providing allowances to a closed plant as an "extra" incentive to close is unnecessary, distorts the market, and is contrary to the underlying "cap-and-trade" approach. [EPA-HQ-OAR-2009-0491-2819.1 p.8]
Response: 
Thank you for your comment.Organization: Nelson Industrial Steam Company (NISCO)
Comment: 
Nelson Industrial Steam Company (NISCO)
If NISCO is not allocated sufficient NOx allowances, it will be impossible to meet this deadline. Further, it is not known whether allowances will be available for purchase in such a limited trading market. Considering the unreasonable and unsupported initial allocations under the proposed FIP, it is also unreasonable for a facility to expend resources prior to final rule promulgation since it is not reasonable to predict how EPA may respond to the significant errors found in the proposed rule. [EPA-HQ-OAR-2009-0491-2813.1, p.12]
Response: 
Thank you for your comment.Organization: Northern Indiana Public Service Company (NIPSCO)
Comment: 
Northern Indiana Public Service Company (NIPSCO)
Regarding specific allocations, NIPSCO appreciates that EPA will include both the state-specific and unit-specific allowance allocations in the body of the rule instead of referencing the unit-specific values in various files within the docket. The current method of including the unit-specific data in various files within the regulatory docket has complicated the efficient and meaningful review of the rule and its effects on companies. [EPA-HQ-OAR-2009-0491-2747.1 p.7]
Response: 
Thank you for your comment.
Organization: Oglethorpe Power
Comment: 
Oglethorpe Power
VII. Multiple Owner Provisions
Oglethorpe Power supports the inclusion by EPA of provisions that ensure the proper distribution of allowance allocations to the owners and operators of co-owned EGUs, in accordance with their legal, equitable, leasehold or contractual rights. See 75 Fed. Reg. 45379, 45403 & 4, 45428 & 9, & 45452 & 3, to be codified at 40 C.F.R. §§ 97.416, 97.516,97.616 & 97.716 (Certificate of Representation requirements for designated representatives for the four Transport Rule allowance programs). As Congress recognized when enacting the Acid Rain Program as part of the Clean Air Act Amendments of 1990, allowances issued for covered source operation accrue to the benefit and use of all unit co-owners holding a legal, equitable, leasehold or contractual right in a unit that has been allocated allowances. 10 Thus, where a designated representative ('DR') and alternate designated representative ("ADR") (typically employees of the company operating the unit and holding the permit) are appointed to represent a co-owned source (and all covered units of the source) in matters pertaining to an allowance program, the allowances belong to the co-owners, in proportion to their ownership interest in the covered units. Since the enactment of that provision by the Congress, EPA has consistently, for every emission allowance program created, included a 'multiple owner' regulation mirroring the requirements of CAA § 408(i). Oglethorpe Power strongly supports the inclusion of those same § 408(i) requirements in the Transport Rule for its allowance programs, so as to explicitly recognize allowance program duties on a DR and an ADR of co-owned covered sources (and co-owned units). [EPA-HQ-OAR-2009-0491-2732.1, p.12]

10. CAA § 408(i). That provision requires the filing of a certificate of representation by the DR and ADR for matters pertaining to the Acid Rain Program, including the distribution of allowances. The Legislative history of the 1990 amendments to the CAA states that § 408(i) establishes an affirmative responsibility for the DR to hold and distribute allowances to each holder of an interest in a unit, in proportion to each holder's legal, equitable or contractual share of the unit, unless the parties agree otherwise by contract. 136 Cong. Rec. S3380 (March 28, 1990). [EPA-HQ-OAR-2009-0491-2732.1, p.12]
Response: 
Thank you for your comment. For more information on designated representatives in the final Transport Rule, see Preamble Section VII.E.
Organization: PPG Industries, Inc.
Comment: 
PPG Industries, Inc.
Considering the unreasonable and unsupported initial allocations under the proposed FIP, it is also unreasonable for a facility to expend resources prior to final rule promulgation since it is not reasonable to predict how EPA may respond to the significant errors found in the proposed rule. [EPA-HQ-OAR-2009-0491-2763.1, pp. 18-19]
Response: 
Thank you for your comment.Organization: PPL Corporation
Comment: 
PPL Corporation
Solution
PPL recommends that the alternative approach EPA is taking comment on in the proposed rule be used. Under this alternative, all units within a state would be allocated allowances based on their proportional share of the total heat input from all affected EGUs in the state. This process would effectively result in unit allocations based on the same emission rates for all units in the state. We also recommend that gas-fired only units not be included in the SO2 program because their SO2 emissions are comparatively low and there is not a feasible control alternative to lower their emissions further that the Transport Rule would encourage. Finally we suggest that EPA allocate allowances based on historical operating levels rather than at the operating levels that IPM projects. [EPA-HQ-OAR-2009-0491-2739.1, p.4]
Although the emission reductions that EPA anticipates for 2012 are not intended to require installation of new FGD or selective catalytic reduction (SCR) systems, the emission rates for which the allocations are based are very low and in some cases at the cutting edge of the technology. To attain these emission rates, companies may need to purchase additional hardware and may need to change fuel supply. This is exacerbated by the 3 percent portion of the unit allocations that would be set aside for new units because it would require that EGUs on average operate below the already low emission rates that are assumed in the proposed rule. [EPA-HQ-OAR-2009-0491-2739.1, p.9]
Response: 
Thank you for your comment.Organization: Progress Energy Service Company
Comment: 
Progress Energy Service Company
Progress Energy supports EPA's proposal not to permit government run allowance auctioning. In addition, the Company urges EPA to prohibit allowance auctioning under the intrastate trading remedy option. Although Progress Energy does not support the intrastate trading remedy option, in the event that EPA promulgates a final rule based on this option, EPA should avoid government-run allowance auctions. Governmental auctioning of allowances is contrary to the principle that regulated sources are permitted to emit up to their allowance allocation levels without any obligation to pay for the right to emit up to those levels. [EPA-HQ-OAR-2009-0491-2831.1 p.2]
Despite these aspects of the proposal, with which the Company agrees, there are many other aspects of the Proposed Transport Rule that cause considerable concern. [EPA-HQ-OAR-2009-0491-2831.1 p.2]
Response: 
Thank you for your comment. EPA has chosen to NOT use auctions in the final Transport Rule. For more information on this decision, see Preamble Section VII.A.
Organization: RRI Energy, Inc.
Comment: 
RRI Energy, Inc.
RRI supports allocating unit-level allowances to existing units commensurate with the existing unit's share of its state emissions assumed in developing the budget. This methodology is consistent with EPA's Key Guiding Principles (e.g., to provide for costeffectiveness) and is also consistent with EPA's proposed approach to (i) terminate allowance allocations to non-operating / retired units following an extended period of suspended operations and (ii) distribute any allowances remaining in the new unit setaside to the existing units for each control period in proportion to the existing unit's initial allocation (i.e., propose to allocate allowances to units that actually need such allowances). [EPA-HQ-OAR-2009-0491-2717.1 p.2]
The CATR should allow existing units that are repowered to retain the allowances allocated to the existing units
RRI wishes to acknowledge our support the proposed new source set-aside budget and allowance allocation methodology. However, RRI strongly recommends that existing CATR-affected units that are repowered (using either clean coal technologies or replaced with natural gas-fired combined cycle combustion turbines) be permitted to retain the allowances allocated to the existing units in lieu of receiving an allowance allocation from the new source set-aside budget. The proposed CATR provides a greater incentive for existing units to install emissions controls (by permitting those units to retain their allowance allocation) rather than retire existing units and construct new or replacement units (these new units would likely be allocated fewer allowances as compared with the retired units). RRI believes that acceptance of this recommendation would provide the necessary incentives to EGU operators to retire coal-fired EGUs that are not equipped with contemporary SO2 and NOx emissions controls and replace these units with lower emitting clean coal technology boilers or natural gas-fired combustion turbines. [EPA-HQ-OAR-2009-0491-2717.1 p.5]
Response: 
In the final Transport Rule, EPA is basing allocations to existing units on historic data, as explained in section VII.D of the final rule preamble.  If an existing unit repowers in the future, its historic data basis for Transport Rule allocations will not have changed, and therefore an existing unit that repowers in the future will continue to receive the same allocation under the FIPs as originally determined based on its historic data. 
Organization: South Carolina Department of Health and Environmental Control 
Comment: 
South Carolina Department of Health and Environmental Control 
DHEC notes that the NODA potentially rendered the comment period for the proposed Transport Rule irrelevant. The new IPM and NEEDS data affect the Budgets and Allocations Spreadsheet in the docket, which includes state emissions budgets and unit-level allowance allocations. The EPA however did not update the Budgets and Allocations Spreadsheet with publication of the NODA, so DHEC will not know the state budgets and unit-level allocations until publication of the Final Rule. State budgets and unit-level allocations are of central relevance to the outcome of the proposed Transport Rule, yet because of the EPA's midstream revisions to the technical foundation of the proposed Transport Rule, the public will not be provided the opportunity to review and provide meaningful comments to this major rule. Further, the new IPM and NEEDS data may influence the EPA's determination of which downwind states that South Carolina affects, and if the EPA does not re-notice the proposal, DHEC would not have opportunity to participate in the comment process on this important question. [EPA-HQ-OAR-2009-0491-3718.1_NODA, p.2] 
Response: 
EPA's response to these comments on updating unit data and allowance allocation methods in the final Transport Rule is multi-faceted:
First, EPA changed its allocation methodology to be based on historic heat input and emissions data that is generally reported by the sources' DR who testifies to its accuracy and completeness.  This change was in response to comments that expressed concern/disagreement about the IPM unit level projected emissions on which the proposed allocations were based.  By switching to a historically-data based methodology, the degree to which any discrepancy between a units actual future operation and its projected future operation would impact the unit's allocation is greatly diminished.  EPA recognizes that IPM is a dynamic linear programming model that generates optimal decisions under the assumptions of perfect foresight and results in a least cost method of meeting demand.  However, invariably, there will be discrepancies between IPM unit level projections and a unit's actual future operations due to non-economic or other variables that IPM does not capture.  While at the state and regional level, the discrepancies are small and random and thus do not result in biases.  However, their impact at the unit level may be significant and this was one of the drivers behind switching to an allocation method based on historic data. Changing the methodology also either corrected or obviated the need to change issues that some commenters raised about incomplete or incorrect data in the allocation worksheets. For more information on the allocation method, see Preamble Section VII D.
Second, EPA reviewed the comments and has made significant updates to its IPM v.3.02 modeling used at proposal.  These updates include changes to both the more general IPM assumptions (e.g., gas price assumptions) and specific unit level assumptions (e.g., that current retrofit status at a unit).  These updates were made to the IPM model, and the updated versions (EPA IPM v.4.10) was used for all the final rule analysis.  In regard to unit specific adjustments, EPA did not manually adjust projected unit level modeling outputs, but instead made unit level updates to its NEEDS database used as a model input that impacted the unit level model outputs.   Some of the most frequent general IPM comments that were addressed in the updates are: FGD removal efficiency was adjusted for new retrofits, and for existing retrofits it was indexed to historic performance at the unit.  Additionally, many comments were focused on a source's ability to switch coals.  EPA modified its modeling to better reflect the cost and feasibility of switching and blending coals.  For more detailed discussion of EPA IPM v.4.10 assumptions and assumption updates, see the EPA IPM v.4.10 documentation and the "Transport Rule IPM Assumptions Response to Comments" in the Appendix.
These two adjustments, updates to the modeling and updates to the allocation methodology, work in concert to comprehensively address many of the concerns expressed by commenters on their unit level projections and allocations.
EPA posted the signed version of the Proposed Transport Rule to the web when it was signed on July 6, 2010.  The proposal was published in the Federal Register on August 2, 2010.  EPA held three public hearings on the rule on August 19, 2010 (Chicago, IL), August 26, 2010 (Philadelphia, PA), and September 1, 2010 (Atlanta, GA) and the public comment period closed on October 1, 2010.  The comment period was thus open for 60 days from the date of publication in the Federal Register and 90 days from the date the rule was widely disseminated to the public via publication on the web.  EPA posted the signed version of the first Transport Rule Notice of Data Availability (NODA) (IPM) to the web when it was signed on August 25, 2010.  The first NODA was published in the Federal Register on September 1, 2010, and the public comment period closed on October 15, 2010.  The comment period was open for 45 days from the date of publication in the Federal Register and 52 days from the date the NODA was widely disseminated to the public via publication on the web on August 25, 2010.  The second NODA (addressing emissions inventories) was published in the Federal Register on October 27, 2010 and the public comment period closed on November 26, 2010.  The comment period was open for 30 days from the date of publication in the Federal Register (and was widely disseminated to the public via publication on the web at the same time).  The third NODA (allocations and related matters) was published in the Federal Register on January 7, 2011 and the public comment period closed on February 7, 2011.  The comment period was open for 30 days from the date of publication in the Federal Register and 38 days from the date the NODA was widely disseminated to the public via publication on the web on December 30, 2010.  

EPA provided an adequate opportunity for public comment on the proposal and all three NODAs.  EPA complied with the procedural requirements of CAA section 307(d) including those regarding the length of the comment period.  EPA also received several hundred substantive comments during the comment period.  Many of these contained detailed data and analyses.   The volume and depth of the comments received suggests that the opportunity for public comment was adequate.  The fact that more comments could have been provided had the comment periods been extended, does not establish that the comment period was inadequate or not consistent with the procedural requirements of section 307(d).  EPA is mindful both of its obligation to provide an opportunity for public comment and of its obligation to proceed with this rule in a timely manner.
For comments related to the compliance deadline, please see Preamble Section VII C. EPA notes that SO2 and NOX trading are well established practices under ARP, NBP, and CAIR, with an existing knowledge base of compliance options and how likely a entity is to have and need allowances. Additionally, EPA proposed the Transport Rule last July. Finally, the compliance programs start January 1 and May 1, 2012 but the coverage of emissions with allowances awarded and purchased is much later, leaving ample time for companies to adapt.
Finally, EPA notes that as stated in NODA3, the purpose of the NODA was to provide the proportion of a state budget that units would receive under the various methodologies, not the exact allocation that each unit would receive.
Organization: Tenaska, Inc.
Comment: 
Tenaska, Inc.
Tenaska is concerned that EPA's preferred allocation scheme provides insufficient flexibility and could result in: (1) an allowance market without the liquidity necessary for Tenaska to comply with the generation obligations of these contracts; and (2) decreased growth in the use of natural gas. As explained further in these comments, Tenaska believes greater flexibility, specifically initial allocation of allowances based on heat input, periodic reevaluation and readjustment of allowance allocations, and an opt-out provision for very low-emitting sources, are necessary to address market dynamics and avoid unintended adverse consequences. [EPA-HQ-OAR-2009-0491-3705, p.2]
Response: 

Thank you for your comment.

V.D.2.b.i. Comments on Allocations Data/Corrections to Allocations Data

Organization: American Electric Power
Comment: 
American Electric Power
Transmission/Black Start with Retirements
AEP's current transmission grid restoration plan is built around the control functionality of its smaller subcritical unit turbines successfully load rejecting during a system or national electrical grid emergency. This functionality is premised around our fleet's subcritical generators that are in operation at the time of emergency, needing to successfully separate, or load reject from a voltage decaying grid. Units that have successfully load rejected will remain lb, only generating enough to support their own auxiliary loads, until at such time, they are advised to re-parallel in a systematic manner in an effort to re-energize the electrical transmission grid. All of AEP's 18 subcritical units capable of automatic load rejection are now being threatened by the currently proposed Clean Air Transport Rule, and thus facing probable unit retirement. The economics of localized transmission constraints and ancillary services provided by ALR and blackstart units should be included in future modeling scenarios and reviewed with increased scrutiny, particularly as individual units are selected for retirement. [EPA-HQ-OAR-2009-0491-2665.1, p.23] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.8]
Response: 
EPA finds that the commenter identifies no specific basis on which the Transport Rule negatively affects a utility's ability to maintain "black start" units.  EPA notes that the Agency does not "select" any units for retirement.  While it is possible that EPA's power sector modeling may project a cost-effective retirement of a unit that a utility currently maintains for ancillary services or as a black start unit, the Transport Rule in no way constraints the utility's ability to determine whether to operate or retire such a unit in real-life compliance with the rule's state emission budgets.  As explained in the Reliability and Resource Adequacy Final Rule TSD, EPA's power sector modeling projections are entirely consistent with reliable operation of the power grid, and because EPA is not basing any individual unit's compliance requirements off of that specific unit's projected behavior, it is illogical and incorrect for the commenter to assert that the Transport Rule impairs in any way a utility's capacity for maintaining reliable grid operations while also complying with state emission budgets.  Furthermore, EPA explains in the Allowance Allocation Final Rule TSD that the economic determination of unit dispatch will reflect the market value of emitting (i.e., the allowance price) regardless of whether the relevant allowances were initially allocated to that unit, and notwithstanding that important point, EPA is basing existing unit allocations under the FIPs on historic data, which renders any specific existing unit's projected behavior moot insofar as allowance allocations are concerned.
Birchwood Power Partners, L.P.
A. EPA's Proposed Allocation of Annual NOx Allowances for Birchwood is Insufficient to Meet Pre-Recessionary Demand
Birchwood Power is concerned that the number of allowances EPA has proposed to allocate to it for annual NOx emissions may be insufficient to meet its contractual demand in years when the facility is called to dispatch as frequently as it was prior to the recession. According to the Proposed Transport Rule, EPA has proposed to allocate 676 tons of annual NOx allowances to Birchwood Power. See Technical Support Document, State Budgets Unit Allocations, and Unit Emissions Rates, EPA Office of Air and Radiation, July 2010, Appendix: Table of Unit-Level Allocations and Rate Limits. This is less than Birchwood Power's reported NOx emissions in two of the past five calendar years: in 2008, Birchwood Power's annual NOx emissions were 678.6 tons and, in 2005, they were 741.4 tons. While the proposed number of allowances would have been sufficient to cover emissions during other years (including 2009, when utilization was significantly lower throughout the country due to the recession), Birchwood Power anticipates that demand for electricity will return to pre-recessionary levels, and it could again be called to dispatch at levels that will require the purchase of additional NOx allowances. Table 1 below shows Birchwood Power's annual NOx emissions, heat input, operating hours and capacity factor for calendar years 2005 through 2010 (year to-date). While the year 2009 shows a substantial reduction in dispatch, Birchwood has already started seeing an increase in demand during 2010. [EPA-HQ-OAR-2009-0491-2706.1, pp.2-3]
[Table 1 can be found on page 3 of this comment.]
Response: 
EPA has finalized an allowance allocation methodology that is different from the one proposed and may address some of Birchwood's concerns.  Specifically, the final allocation approach is based purely on historic data and used a larger, five year baseline to determine a representative "heat input".  Because the approach takes the three highest years of data among a five year baseline, it could potentially be selecting pre-recessionary years for the Birchwood unit if reported heat input were higher during those years.  However, EPA also notes that the purpose of allowance allocation is to implement the state emission budgets that reflect the elimination of significant contribution.  The purpose is not to allocate in a manner that fully covers historic emission levels for all sources.  Doing so would not result in a program that achieves the necessary emission reductions.  Therefore, EPA emphasizes that some sources will have allocations that are less than their historic emission levels and will comply with Transport Rule budgets through allowance purchase or other compliance options discussed in section VII.C.  See section VII.D of the preamble for more discussion on the final Transport Rule allowance allocation approach under the FIP.
Organization: City of Ames, Iowa
Comment: 
City of Ames, Iowa
3) There is no allocation for SO2 and NOx for GT2 (ORIS Code 6463), yet we need to operate this unit for peaking and system reliability purposes, and most likely will need to do so more as native demand (load growth) increases.
4) Why is there no ozone season NOx allocation for any of our units (Unit 7, Unit 8, and GT2)? [EPA-HQ-OAR-2009-0491-2769, p.2]
21) The allocations in 2012 for SO2 for Unit 7 and Unit 8 are so restrictive, they would limit the capacity factors (CF) for Unit 7 at 55% and for Unit 8 at 42%. For our utility, these units are considered baseload units. U.S. EPA's own documentation for new coal steam units uses a default capacity of 84% for SO2 and NOX annual, and 89% during the NOx ozone season. The annual NOx allocation for Unit 8 is also so restrictive, that it would limit Unit 8's capacity factor at 47%. Once again, U.S. EPA's own documentation for new coal steam units uses a default capacity factor of 84% for annual SO2 and NOx, and 89% during the NOx ozone season. [EPA-HQ-OAR-2009-0491-2769, p.4]
Response: 
The final Transport Rule allocation methodology under the FIPs is explained in section VII.D of the preamble.  The commenter is mistaken that unit-level allowance allocations "limit the capacity factors" at any given unit.  Allowance allocations are not equivalent to compliance requirements under the Transport Rule air quality-assured trading programs.  Units may emit as many tons for which they hold the relevant allowances, whether or not those allowances were initially allocated to the units in question.  As explained in the Allowance Allocation Final Rule TSD, the economic determination of unit dispatch in the power sector factors in the cost of any emissions under the programs (i.e., the market value of an allowance) whether or not an allowance for that emitted ton was freely allocated to that unit in the first place.
EPA notes that units 7, 8, and GT2 did not receive ozone season allowance allocations in the proposed unit level allocations because Iowa (the state in which those units are located) was not subject to the ozone-season NOX program in the proposal.  EPA has promulgated a Transport Rule SNPR including Iowa as covered under the TR ozone season program; the SNPR includes a presentation of proposed unit-level allocations under those FIPs.
Organization: Formosa Plastics Corporation, LA
Prairie State Generating Company, LLC
CPS Energy
Shell Chemicals
Consolidated Asset Management Services (CAMS)
Illinois Environmental Protection Agency
City of Springfield, Illinois, Office of Public Utilities
we energies
Wabash Valley Power
Lakeland Electric
Seminole Electric Cooperative Inc.
Tennessee Valley Authority (TVA)
Constellation Energy
Vectren Corporation 
Southern Company
North Carolina Department of Environment and Natural Resources
Duke Energy
Massachusetts Department of Environmental Protection
State of Missouri Department of Natural Resources
NRG Energy
City Utilities of Springfield
San Miguel Electric Cooperative, Inc.
DTE Energy Services (DTEES)
Dynegy, Inc.
Indiana Energy Association
Great River Energy
Borger Energy Associates (Blackhawk)
East Kentucky Power Cooperative
Sunbury Generation LP
Black River Generation
New York Power Authority
Florida Municipal Power Agency (FMPA)
Associated Electric Cooperative, Inc. (AECI)
Faribault Energy Park
Spruance Genco, LLC
Selkirk Cogeneration Project (SCP)
Morgantown Energy Associates
Entergy Services, Inc.
DTE Energy
Rochester Public Utilities (RPU)
Potomac Power Resources
Sabine Cogen, LP
Denver City Energy Associates, LP
Manitowoc Public Utilities (MPU)
MIT Central Utility Plant
Lafayette Utilities System
Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
Giarmarco, Mullins & Horton, P.C.
AES Corporation (AES)
Comment: 
AES Corporation (AES)
The following are examples of errors for the allocations that do not reflect current operations. All of the following facilities have S02 and NOx controls and improvements to these are unlikely due to operational and or market circumstances. [EPA-HQ-OAR-2009-0491-3793.1_NODA, p.7]
:: For AES Warrior Run the NOx and S02 allocations are far lower than current or historical operations. The unit is already very well controlled with no pass through on additional costs to over comply
:: For AES Ironwood, there was no S02 allocations planned and less than a third of the NOx allocations needed. These units already have low NOx gas turbines and SCR and are considered best in class emissions
:: For AES Beaver Valley, the S02 allocation is less than half of current and historical operations. The units are already scrubbed, with no pass through of increased costs to over comply
:: For AES Cayuga, the NOx and S02 allocations are far lower than current or historical operations. Both units have scrubbers and NOx controls. [EPA-HQ-OAR-2009-0491-3793.1_NODA, p.7]
:: For AES Somerset the NOx allocation is less than third of current and historical operations. The unit already has an SCR that cannot be operated at reduced loads
:: For AES Thames the S02 allocation is less than half of current and historical operations. The units are already very well controlled for NOx and S02 and have no pass through option on increased costs to over comply
:: For AES Shady Point the NOx allocation is far less than current and historical operations. The units are already very well controlled with no pass through option on increased costs to over comply. [EPA-HQ-OAR-2009-0491-3793.1_NODA, p.8]
Associated Electric Cooperative, Inc. (AECI)
One of the generating facilities that provide bulk baseload power to Associated and its member-cooperatives is the New Madrid Power Plant. A smaller facility, Chamois Power Plant, also supplies baseload power to the system and is owned by Central Electric Power Cooperative (CEPC). CEPC is one of the six generating and transmission (G&T) cooperatives that own AECI. [EPA-HQ-OAR-2009-0491-2845.1 p.10]
The assumed heat input in EPA's "ParsedFile_TR_SB_Limited_Trading" tables for the affected units at New Madrid and Chamois plants appear to be in significant error. [EPA-HQ-OAR-2009-0491-2845.1 p.10]
[[Data Table Here]]
The comparison values in the "CAMD Actual" column are taken directly from the Clean Air Markets Division (CAMD) "Data and Maps" database (http://camddataandmaps.epa.gov/gdm/). The values in this column are the average of the three highest annual heat input totals from the years 2005 through 2009. It is unclear where data came from that populates the CATR files, but it is clearly in error. With respect to the New Madrid units, even if one were to compare the CATR assumptions to the lowest heat input years during the lookback range (33.0 TBtu and 36.0 TBtu, respectively) the difference is still significant. [EPA-HQ-OAR-2009-0491-2845.1 p.10]
Request: Associated requests that EPA review the heat input assumptions for these units and adjust the allocations accordingly. [EPA-HQ-OAR-2009-0491-2845.1 p.11]
The three identical units at AECI's Holden plant (ORIS 07848) are permitted to operate up to 500 hours each (3 units) burning No. 2 fuel oil up to 0.05 %S. This could be up to 54 TPY SO2 for all 3 units. The CATR FIP includes no allowances for the SO2 program. Given the significant regulatory pressures on coal-fired power plants, it is likely that combustion turbine facilities like Holden will be utilized more in the future. [EPA-HQ-OAR-2009-0491-2845.1 p.11]
Request: Associated requests that EPA consider emissions from combustion turbines that are permitted to burn fuel oil and assign allowances to these facilities according to permit restrictions for burning low sulfur fuel oil per the applicable fuel sulfur limit in the facility's permit. [EPA-HQ-OAR-2009-0491-2845.1 p.11]
The units at AECI's Chouteau power plant in northeastern Oklahoma are impacted by the proposed Transport Rule where they were not under CAIR. The facility is a combined-cycle gas plant with a total of three electricity generators. Two combustion turbines (CTs) drive one shaft each, and a steam turbine powered by waste heat from the CTs drives a third shaft. The CATR erroneously includes a NOx allocation for the steam turbine which does not generate emissions. We assume that this is a mistake. [EPA-HQ-OAR-2009-0491-2845.1 p.11]
The assumed heat inputs for the two emitting units are about 16% lower than the heat input recorded in 2009. 
[[Data Table Here]]
Request: Associated requests that EPA remove the steam turbine from the allocation tables and adjust the heat input assumptions for the two emitting combustion turbine units.  [EPA-HQ-OAR-2009-0491-2845.1 p.11]
Black River Generation
Black River Generation, LLC appreciates the opportunity to provide comments on the proposed Transport Rule that was published on August 2,2010. The comments herein are focused on the proposed allowance allocation details presented in the budgets and allocation section of the technical support documents. Primarily, in its proposed allocations, EPA has not provided allowances for the boilers at Black River Generation, LLC (ORIS Code 10464) located in Fort Drum, NY. It appears that EPA assumed that these particular units serve a generator of less than 2S MW and are, therefore exempt from the Transport Rule requirements. [EPA-HQ-OAR-2009-0491-2836.1 p.1]
The Black River Generation facility is configured with three boilers that serve one common steam turbine generator with a rated capacity of 5S MW, as reported on the CAMD database. The MW capacity data provided in the Transport Rule allocation tables is reportedly derived from the NEEDS database and was split across the boilers to arrive at a per-boiler rating of 18.333 MW for each of the boilers. [EPA-HQ-OAR-2009-0491-2836.1 p.1]
However, the applicability provisions of the proposed Transport Rule (proposed Section 97.404(a)(1) for the Annual NOx subpart, proposed Section 97.S04(a)(1) for the Ozone Season subpart; and proposed Section 97.604(a)(1) for the Annual S02 subpart), state that the rule is applicable to the following units:
Any stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine serving at any time, since the later of November 15, 1990 or the start-up of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe producing electricity for sale. [EPA-HQ-OAR-2009-0491-2836.1 p.1]
As stated above, each of the boilers at the Black River Generation facility serves a generator with a nameplate capacity of 55 MWe and, therefore, is subject to the Transport Rule. We also note that EPA included this facility (for these reasons) as an affected facility under the NOx SIP Call and CAIR. As such, this facility should be treated as a CATR-affected facility and EPA should allocate appropriate S02 and NOx allowances to this facility. [EPA-HQ-OAR-2009-0491-2836.1 p.2]
Specifically, the Excel spreadsheet contained on the EPA web page and referenced as 'Budget and Allocations - Detailed Unit-Level Data (Excel)' includes a listing of each unit for which allocation data was determined. The following comments are provided with regard to allocation calculations in that spreadsheet and final Allocations Table provided in the docket. [EPA-HQ-OAR-2009-0491-2836.1 p.2]
The worksheets provide data and analyses for the facility's three boilers (E001, E002, and E003 ). However, in the final worksheet entitled 'Allocations & Rate limits' and in the final Allocation Table provided in the docket, the table lists zero allocations for these units under each of the four programs Annual NOx, Ozone Season NOx, 2012 502, and 2014 S02. There is no explanation to account for the removal of the allocations for these units. However, as explained above, it appears that EPA incorrectly assumed that these units were exempt. [EPA-HQ-OAR-2009-0491-2836.1 p.2]
 :: Black River Generation, LLC requests that EPA review this worksheet and provide the allocations as indicated and calculated in the previous worksheets. Based on review of similar units, the allocations would be calculated as 97% of the Projected Annual NOx and Ozone Season NOx Mass, and as 97% of the Adjusted Annual S02 - Projected Base Case, as provided below. The calculation methodology for the 2014 and Beyond 502 allowances could not be determined. [EPA-HQ-OAR-2009-0491-2836.1 p.2]
[[Data Table Here]]
Borger Energy Associates (Blackhawk)
On behalf of Borger Energy Associates, LP, owner of Blackhawk Station (Blackhawk), Consolidated Asset Management Services respectfully requests that your office review the Environmental Protection Agency's (EPA) database inputs used to calculate the nitrogen oxides (NOx) allocations under the proposed Transport Rule (Federal Register, Vol. 75, NO. 147, Monday, August 2, 2010, Proposed Rules, Environmental Protection Agency, 40 CFR Parts 51, 52, 72, 78 and 97, Federal Implementation Plans to Reduce Interstate transport of Fine Particulate Matter and Ozone).
All comments provided in this letter are related to ORIS code 55064 and the following units:
:: Blackhawk Station Unit UNT1; and
:: Blackhawk Station Unit UNT2.
Errors related to the Air Transport Rule, Technical Information section of the EPA website (http://www.epa.gov/airquality/transporVtech.html). document Budgets and Allocations - Detailed Unit-Level Data (Excel), are identified in this letter. In particular, Blackhawk is represented as not having an SCR for NOx control, when, in fact, there is in an existing SCR system on both units. Blackhawk respectfully requests that EPA consider the information contained in this submittal when determining final allocations under the Transport Rule. [EPA-HQ-OAR-2009-0491-2798.1 p.1]
City of Springfield, Illinois, Office of Public Utilities
[See Docket Number EPA-HQ-OAR-2009-0491-2635.1, pp.4-5 for specific comments on the Affected Units and Assumed Heat Inputs.]
[[See Docket Number EPA-HQ-OAR-2009-0491-2635.1, pp.6- for specific comments on the SO2 and NOx Emission Rates.]]
Since having provided the attached to Illinois EPA and the publication of the NODA (and webinars with speakers from USEPA on the Rule and the NODA) CWLP has noted that the Rule database lists Factory's capacity at 21 MW, whereas the Clean Air Market Division ('CAMD') has its nameplate capacity at 26.6 MW. CWLP also notes that Dallman Unit 31 had a Significant outage due to a turbine generator explosion from November 11, 2007, through April 7, 2009. This outage will cause the unit to have artificially lower emissions and heat input during this period due to this unusual, onetime event. [EPA-HQ-OAR-2009-0491-2635.1, p.2]
[[See Docket Number EPA-HQ-OAR-2009-0491-2635.1, pp.7 for specific comments on the SO2 and NOx Allocations.]]
City Utilities of Springfield
Issue: City Utilities is aware of substantial errors in EPA's operating and emission assumptions regarding our Southwest, James River, and McCartney Generating Stations. We will be submitting comments to this effect under the separate but related NODA but will also briefly describe them here to complete the record. The NEEDS 3.02 database indicates that the Southwest Power Station has a wet FGD in place. As we have indicated in our EIA Form 860 filings and our revised monitoring plan under the Acid Rain Program, the FGD at this facility had to be decommissioned and removed due to severe scaling, corrosion, and structural integrity concerns. Southwest Power Station now complies with all federal and state SO2 requirements by burning compliance coal from the Powder River Basin. This correction in the NEEDS database would materially impact the cost efficiency of additional SO2 control at the Southwest Station and the resulting state budget for Missouri. The database also assumes that the combustion turbines located at our Southwest, James River, and McCartney generating stations will cease to operate following promulgation of this rule. Accordingly, Table A affords them zero allowances. In actuality, combustion turbines will continue to be a valuable generating asset for City Utilities and other Missouri municipal utilities. These units not only provide rapid response to peak demand in ways that our steam units are unable, but also represent spinning reserve capacity required by electric reliability regulators. These factors presumably were not considered in the cost-based IPM modeling analysis. [EPA-HQ-OAR-2009-0491-2721.1 p.3]
Recommendation: The Appendix A allocation table should be corrected to reflect actual existing conditions and expected operating scenarios for affected City Utilities units. [EPA-HQ-OAR-2009-0491-2721.1 p.3]
Consolidated Asset Management Services (CAMS)
EPA posted their current approach calculations of unit allocations and unit descriptive data on their Technical Information website found in the documents titled Allocation Table, revision dated 07/21/2010, and Budgets and Allocations  -  Detailed Unit-Level Data. Below is a list of errors found in the referenced documents. [EPA-HQ-OAR-2009-0491-2612.1, p.2]
1) The Unit ID STG for the Effingham County Power facility (ORIS 55406) is a steam turbine generation and not a TR NOx Annual unit, TR NOx Ozone Season unit, nor a TR SO2 Group 1 unit. However, in EPA's currently posted approach this steam turbine generator has been allocated allowances for the various TR markets. After review of units reported in the above referenced document there are numerous units reported and allocated allowances that are not and should not be a TR unit. [EPA-HQ-OAR-2009-0491-2612.1, p.2]
2) Waterside Power facility (ORIS 56189) consists of 3 simple-cycle combustion turbine units (Unit ID 4, 5, and 7) each with a nameplate capacity of 23.2 MWs. The units have been granted the New Unit Exemption per the Acid Rain Program, however they currently participate in the CAIR NOx Ozone Season Program because Connecticut's revised the definition of a CAIR NOx Ozone Season Unit from a nameplate capacity of 25 MWs to 15 MWs. The capacity for Unit 7 is given as 0, zero, and reported as an affected unit under the various TR programs. Under the definition of the applicable unit to the TR programs Unit 7 should be delisted from the list of applicable units. [EPA-HQ-OAR-2009-0491-2612.1, p.2]
Constellation Energy
In order for the rule to be implemented by January 2012, EPA must be able to make the necessary adjustments to the underlying data to ensure the allocations in 2012 and 2013 properly reflect the planned and installed air pollution controls as well as units' near-term operating circumstances and conditions. Constellation Energy has attached its recommended data corrections in a table to this letter. These corrections include inaccurate emission rates for some of our units which, once corrected, will provide adequate allowances for operation. [EPA-HQ-OAR-2009-0491-3613, pp.2-3] [[See Docket Number EPA-HQ-OAR-2009-0491-3613, p.4 for the data corrections.]]
CPS Energy
The allocation tables provided in the technical documents on the EPA's website are not correct for several of CPS Energy units.  [EPA-HQ-OAR-2009-0491-2524.1, p.1]
The Arthur Von Rosenburg combined cycle unit that is located at our V H Braunig Power Station site is listed in multiple ways and would be receiving double allocations if not corrected. There are three units listed as Arthur Von Rosenburg Units 1, 2, and 3 with the ORIS code 7512. Those units need to be removed from the allocation table; they are duplicates of V H Braunig CT01 and CT02 ORIS code 3612. We do not own/operate any units with ORIS code 7512. However the Energy Information Administration (EIA) has the Arthur Von Rosenburg units listed incorrectly with the ORIS code 7512 in their records. We have tried to correct this with the EIA. For all other reporting, the Arthur Von Rosenburg units are identified by ORIS code 3612 because they are on our V H Braunig Power Station plant site. So to clarify, Arthur Von Rosenburg ORIS code 7512 Units 1,2, and 3 need to be removed from the allocation spreadsheet for the Transport Rule. The Arthur Von Rosenburg units (a combined cycle unit) are correctly listed as V H Braunig ORIS code 3612 Units CT01 and CT02. [EPA-HQ-OAR-2009-0491-2524.1, p.1]
CPS Energy has a second comment regarding two other units at the V H Braunig Power Station site. V H Braunig Units 1 & 2 (gas fired steam boilers) allocations are very low compared to actual emissions. The allocations spreadsheet shows 13 and 8 allocations, respectively for V H Braunig Units 1 & 2. However reported emissions during Ozone season in 2008 and 2009 were in the 90 - 160 tons range. The lb/mmBtu rates for the V H Braunig Units 1 & 2 are also too low. The spreadsheet shows 0.019 and 0.016 lb/mmBtu, respectively. But the reported rates for those two units are typically around 0.15 lb/mmBtu. The units are not equipped with Selective Catalytic Reduction (SCRs), so they would never be able to achieve a rate as low as 0.019 or 0.016 lb/mmBtu. [EPA-HQ-OAR-2009-0491-2524.1, p.2]
The allocations and allowable NOx rates for all of our other units are correct. [EPA-HQ-OAR-2009-0491-2524.1, p.2]
Denver City Energy Associates, LP
Power Station (Mustang), Consolidated Asset Management Services respectfully requests that your office review the Environmental Protection Agency's (EPA) database inputs used to calculate the nitrogen oxides (NOx) allocations under the proposed Transport Rule (Federal Register, Vol. 75, NO. 147, Monday, August 2, 2010, Proposed Rules, Environmental Protection Agency, 40 CFR Parts 51, 52, 72, 78 and 97, Federal Implementation Plans to Reduce Interstate transport of Fine Particulate Matter and Ozone).  [EPA-HQ-OAR-2009-0491-2878.1,p.1]
All comments are directed toward ORIS code 55065 and associated units:
:: Mustang Station Unit GEN1;
:: Mustang Station Unit GEN2; and
:: Mustang Station Unit GEN3. [EPA-HQ-OAR-2009-0491-2878.1,p.1]
Errors related to the Air Transport Rule, Technical Information section of the EPA website (http://www.epa.gov/airguality/transport/tech.html). document Budgets and Allocations - Detailed Unit-Level Data (Excel), are identified in this letter and supporting calculations. In particular, GEN3 is a steam turbine and, therefore, is not an affected source under the Transport Rule. Emissions attributed to this unit should actually be combined with those attributed to unit GEN1 . Denver City respectfully requests that EPA consider the information contained in this submittal, so that the appropriate number of Transport Rule Ozone Season NOx allowances may be allocated. [EPA-HQ-OAR-2009-0491-2878.1,p.1]
DTE Energy
Incorrect Inputs to the Integrated Planning Model (IPM) and Incorrect Emission Model Assumptions; DTE-Specific Comments
The attached table includes specific data extracted from EPA's CATR Allocation Table for sources owned and operated by DTE Energy. These listed values are the product of a number of erroneous results generated by the IPM Model that was used to identify 'least-costly' EGU operation and control device installation, to meet future projected generation needs. The following comments relate to specific IPM Model projections that are inconsistent with our analysis of future operating, and most cost-effective control device installation plans.  [EPA-HQ-OAR-2009-0491-2851.1,p.6] [[See Docket Number EPA-HQ-OAR-2009-0491-2851.1, p.9 for the table with the specific data.]]
1. Projections of future year operation are reasonable except IPM projections that show:
a. Greenwood Energy Center Unit No.1 has zero future generation. This oil and natural gas-fired unit will likely operate with a capacity factor in a range from 2 to 5 percent, based on future load projections from DTE Energy's load forecasting staff. Over the last ten years, this unit's capacity factor has ranged from 2 to 20 percent. Also, depending on fuel price variations and emission allowance costs, it operates with residual oil or natural gas. EPA's assumption that it would only use natural gas is incorrect.
b. The amount of generation that IPM estimates for Marysville Power Plant is too high. The four units at this coal-fired power plant on the St. Clair River have not operated since 2001, and our current plans do not anticipate operating this plant in the near future. [EPA-HQ-OAR-2009-0491-2851.1, p.6]
2. The 502 emission rates that assume 100 percent subbituminous coal for all units that fire even small amounts of this fuel are unrealistic. None of these units can operate at full capacity burning 100 percent subbituminous (i.e., western) coal. Converting to 100 percent subbituminous coal would require all DTE Energy units not currently firing this blend to make significant modifications to existing equipment such as coal mills, coal handling equipment, fans, burners, etc. In addition, this would include modification of particulate matter control devices, and installation of flue gas conditioning systems to meet opacity and particulate matter emission limits. Time and resources necessary to engineer, permit and install these modifications would certainly delay implementing these EPA-predicted operating changes. The only DTE Energy coal-fired units that currently operate with 100 percent subbituminous coal are Belle River Units 1 & 2.  [EPA-HQ-OAR-2009-0491-2851.1,p.6]
a. Units with unrealistic 502 emission rates in 2012 due to 100 percent subbituminous coal use include:
i. Monroe Units 1 & 2
ii. River Rouge Units 2 & 3
iii. St. Clair Units 1-4, 6-7 6 [EPA-HQ-OAR-2009-0491-2851.1,p.6]
iv. Trenton Channel 16-19 & 9A
b. Units with unrealistic S02 emission rates in 2014 due to 100 percent subbituminous coal use include:
i. Harbor Beach Unit 1
ii. Marysville Units 9-12
iii. Monroe Units 1 & 2
iv. River Rouge Units 2 & 3
v. St. Clair Units 1-4, 6-7
vi. Trenton Channel 16-19 & 9A [EPA-HQ-OAR-2009-0491-2851.1, p.7]
3. The SO2 emission rates assumed for the EGUs burning 100 percent subbituminous coal are too low. Since DTE Energy has a long history firing this fuel at Belle River Power Plant, the actual emission rate from that facility provides a very good estimate of the emission rate that is achievable with this coal type. The 0.581 lb/mmBtu figure for Harbor Beach and Marysville is reasonable, but the 0.529 figure for the remainder of DTE's coal-fired units is too low. Belle River Power Plant's SO2 emission rates have ranged from 0.55 to 0.59 lb/mmBtu over the last five years. [EPA-HQ-OAR-2009-0491-2851.1,p.7]
4. The IPM runs for EPA showed that FGD installation on Belle River Units 1 & 2 were 'cost-effective' and possible by January 1, 2014. Considering projects already underway throughout the portfolio, these devices could not be permitted, engineered, constructed and operational by this deadline. DTE Energy has already begun FGD construction on Monroe Power Plant Units 1 & 2 for operation in 2014. We are applying for a PSD permit for SCR installation at Monroe Power Plant Unit 2 with an operational target date of 2015. Completion of these projects already demand a significant amount of resources and capital during the next four years. Also, the electrical system reliability requires other plants such as Belle River Units 1 & 2 to be available to make up for the time these two Monroe Power Plant units will be unavailable during this upcoming construction period. [EPA-HQ-OAR-2009-0491-2851.1,p.7]
5. The assumed SO2 emission rates for Units 3 & 4 at Monroe Power Plant are too low. The figures cited in the allocation table (0.058 (2012) & 0.055 (2014) lb/mmBtu) are too low. The recently issued PSD permit for these sources includes a SO2 emission limit of 0.107 lb/mmBtu, which is the result of a BACT review for these sources. The values that EPA assumed do not account for an adequate amount of actual emission data with the FGD systems operating, and an allowance allocation at, or close to, the emission limit is more appropriate. [EPA-HQ-OAR-2009-0491-2851.1,p.7]
6. EPA's estimated NOx emission rates for DTE Energy's EGUs having combustion controls, but no post-combustion reductions, are too low compared to actual emission rates shown in the enclosed table. The NOx emission rates for the following units are underestimated:
a. Belle River 1 & 2
b. Harbor Beach 1
c. Marysville 9-12
d. Monroe 2
e. River Rouge 2 & 3
f. St. Clair 1-4, 6-7
g. Trenton Channel 16-19  [EPA-HQ-OAR-2009-0491-2851.1,p.8]
7. Monroe Power Plant Units 1, 3 and 4 currently operate with SCRs to reduce NOx emissions. EPA's NOx emission estimate for the controlled emission rate is too low. This value (0.058 lbs/mmBtu) is achievable under optimum operating conditions, but is not sustainable on a long-term basis. DTE Energy believes that the NOx limit finalized in the recent PSD permit for Units 3 & 4 (0.08 lbs/mmBtu) is more appropriate for calculating CATR NOx allowances. [EPA-HQ-OAR-2009-0491-2851.1, p.8]
DTE Energy Services (DTEES)
Unit-specific comments
DTEES owns and operates three facilities that we believe are subject to the Proposed Transport Rule and have either not been identified by EPA as subject to the rule or have not received any allowances under the proposed allocation methodology. Each facility is discussed below.  [EPA-HQ-OAR-2009-0491-2699.1,p.2]
DTE East China. This facility is located in East China, Ml (ORIS Code: 55718). It consists of four natural gas- fired simple cycle turbines each rated at 82 MW. Emissions from these natural gas-fired peaking units are controlled by low NOx burners. EPA's 1PM projections have resulted in each unit receiving zero allowances for the NOx Annual and Ozone Season. We believe that DTE East China is an important facility for supporting the electrical system. These units were called to run by the Regional Transmission Authority, MISC, 28 times thus far in 2010. Our internal forecasts predict demand for power to begin growing over the next several years. With this outlook, we would predict DTE East China to be called to run at least as much as it did in 2010. [EPA-HQ-OAR-2009-0491-2699.1,p.2]
DTEES believes that EPA is underestimating the heat input for DTE East China for the annual NOx allocation and ozone season NOx allocation. In the " BADetailedData" spreadsheet "Allocations and Rate Limits" tab, EPA assumes the following heat inputs (mmBtu) for the annual NOx allocation: Unit 1 --  34,937, Unit 2  --  34,615, Unit 3  --  35,683, Unit 4 --  34,754. In the " BADetailedData" spreadsheet "Allocations and Rate Limits" tab, EPA assumes the following heat inputs ( mmBtu) for the ozone season NOx allocation: Unit 1 --  3,494, Unit 2  --  3,461, Unit 3  -- 3,568, Unit 4 -- 3,475. In 2009 the average annual heat input for the East China units was 43,048 mmBtu and the average ozone season heat input was 20,935 mmBtu. The East China units are on track to reach 50,000 mmBtu heat input for 2010. A table showing DTE East China's heat input, NOx rate, and NOx emissions for the period 2005  --  June 2010 is attached. [EPA-HQ-OAR-2009-0491-2699.1,p.3]
These gas peaking units are already equipped with low NOx burners. DTEES requests that, based on past operations and projections of future operations, EPA increase the projected heat input for the East China units and allocate additional allowances to DTE East China. [EPA-HQ-OAR-2009-0491-2699.1,p.3]
DTE Pontiac North. This facility is located in Pontiac, Michigan (ORIS Code: 880081) and consists of three natural gas-fired boilers with rated capacities of 201.9 mmBtu/hr each and one circulating fluidized bed coal-fired boiler with a rated capacity of 443 mmBtu/hr. The coal-fired boiler was installed August 1, 1984 and operates in cogeneration mode. It is connected to a single steam turbine generator set with a nameplate capacity of 28 MW. High pressure steam from the boiler is fed to the steam turbine to produce electricity and Low pressure steam is extracted from the turbine for process use at the plant. This unit was subject to the NOx budget program, CAIR NOx Annual, CAIR NOx Ozone Season and CAIR S02 programs. The facility has not operated the coal-fired boiler since May 2009. DTE Pontiac North cannot be found in any EPA documentation for the proposed Transport Rule. The facility is not listed in the NEEDs database and is also not listed in the BADetailedData spreadsheet or Allocation spreadsheet. We believe DTE Pontiac North is subject to the proposed Transport Rule and request that EPA update the database to reflect this unit and assign allowances as appropriate. [EPA-HQ-OAR-2009-0491-2699.1,p.3]
E J Stoneman, Cassville, WI, ORIS code 4146. The facility consists of two 340 mmBtu/hr rated boilers serving through cross connected steam headers, 33 MW and 18 MW generators. Emissions are through a combined stack. [EPA-HQ-OAR-2009-0491-2699.1,p.3] [EPA-HQ-OAR-2009-0491-3721.1_NODA, p.3]
This facility is subject to the Acid Rain program and CAIR. The two units were originally built in 1950 and 1951 and designed to burn coal. DTEES purchased the facility in May 2008. Prior to the purchase, the previous owner operated the plant intermittently, selling the electricity through the Midwest Independent System Operator (MISO) at market rates. After the facility was purchased by DTEES, the units were operated intermittently to burn down the remaining coal pile in preparation for the conversion from coal to wood biomass firing. The remaining coal pile was depleted in March 2009. The facility was shut down during the March 2009 to July 28, 2010 period while it was modified and is currently being repowered burning 100% woody biomass. The facility will sell all of the renewable electrical output while firing woody biomass. We believe the historical coal-fired operations are not indicative of future operations burning woody biomass. Once the commissioning process is complete the plant will be operating at full load. [EPA-HQ-OAR-2009-0491-2699.1,pp.3-4] [EPA-HQ-OAR-2009-0491-3721.1_NODA, p.3]
Based on a discussion with EPA staff, EJ Stoneman will not receive allocations due to being exempt from the rule. The proposed rule applies to, 'Any stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine serving at any time, since the later of November IS, 1990 or the start-up of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe producing electricity for sale'. EPA is currently viewing these units as exempt from the rule and does not list them receiving any allowances due to the units being listed as 25 MW in the 'BADetailedData' spreadsheet .. Since the units both serve a 33 MW generator through a cross connected steam header we believe the units are subject to the proposed NOx annual and S02 annual rule and should receive allowances. However, EPA may determine that this is not a correct interpretation. If EPA agrees that the units are subject to the rule, DTEES requests that the appropriate allowance allocations are issued to the units as outlined in the proposed rule. [EPA-HQ-OAR-2009-0491-2699.1, p.4] [EPA-HQ-OAR-2009-0491-3721.1_NODA, p.3]
DTEES believes that EPA has underestimated the projected heat input to the units. Based on the changes to the facility outlined above the heat input will be much greater than EPA has anticipated. The projected heat input in 2012, and in subsequent years, to each unit should be 2,978,400 mmBtu. EPA should use these projected heat input values to determine the NOx and S02 annual allowances for the units. Comparing reported heat input to projected heat input is not appropriate due to the change in fuel type and full utilization of the units once the conversion to woody biomass firing is completed. Additionally, the air pollution construction permit issued by the Wisconsin Department of Natural Resources for the conversion to woody biomass firing required the facility to install Selective NonCatalytic Reduction (SNCR) and over fired air for NOx control. Additional S02 controls are not cost effective. Therefore, using the projected heat inputs and the permitted emission rates of the modified units (0.2 lbs/mmBtu for NOx and 3.17 lbs/mmBtu for S02), each unit should receive 298 NOx annual and 4721 S02 annual allowances. [EPA-HQ-OAR-2009-0491-2699.1,p.4] [EPA-HQ-OAR-2009-0491-3721.1_NODA, p.3]
EPA should also allow the most flexible trading system. E J Stoneman has no other facilities owned by the same parent company within the state with which it might be able to average emissions or trade allowances, making it a small unit/stranded unit. If EPA does not use the most flexible trading system these units will be unable to secure allowances at a reasonable price, or perhaps not at all. This scenario would make future operation of the units uncertain at a time when conversion of coal fired units to woody biomass firing to produce renewable electricity should be encouraged. [EPA-HQ-OAR-2009-0491-2699.1,p.4] [EPA-HQ-OAR-2009-0491-3721.1_NODA, pp.3-4]
Duke Energy
EPA's Proposed Transport Rule Analysis Contains Numerous Unit Specific Errors that Need to Be Corrected.
Edwardsport Units 7-8 are Affected Units under the Transport Rule and Should Receive Allowance Allocations.
The Edwardsport (ORISPL 1004) units 7-1, 7-2, and 8-1are each existing PTR NOx Annual, PTR Ozone Season, and PTR SO2 Group 1 units based on the applicability criteria of §97.404, §97.504, and §97.604 of the PTR. Each of these units reports emissions data to EPA under the Acid Rain Program and the CAIR SO2 and NOx programs. None of these units, however, appear in the NEEDSv3.02_EISA database and are therefore not included in the IPM modeling. EPA states in its PTR State Budget, Unit Allocations, and Unit Emissions Rates Technical Support Document that "IPM is a representation of all units which are capable of supplying electricity to the US electric grid..." Each of these units meets this criterion for inclusion in IPM.  [EPA-HQ-OAR-2009-0491-2689.1, p.33]
It appears that none of these units were included in the inventory of units used by EPA to establish the IndianaSO2 and NOx budgets, but per EPA's stated methodology for establishing state budgets, they should have been included. In addition, per EPA's stated methodology for allocating allowances to individual units, each of these units should have received both SO2 and NOx allowance allocations, but EPA has proposed neither SO2 nor NOx allocations for any of the units.  [EPA-HQ-OAR-2009-0491-2689.1, p.33]
Duke Energy requests that EPA include each of these units in the determination of the Indiana SO2 and NOx budgets, and allocate allowances appropriately. [EPA-HQ-OAR-2009-0491-2689.1, p.33]
IPM Incorrectly Retrofits Dan River Unit 3 with SCR in 2012.
The "Retrofit Control 1" column of the ParsedFile_TR_BaseCase.xls file shows the Dan River (ORISPL 2723) unit 3 getting SCR in 2012. This is an error. An SCR on this unit is neither existing, under construction nor planned for 2012 or for any year after 2012. EPA states in the PTR that it did not assume post combustion controls (SCR) in 2012 that aren't already existing or planned by 2012. The retrofit SCR should be removed from this unit and the North Carolina annual and ozone season NOx budgets and the unit's annual and ozone season NOx allocations should be adjusted upward accordingly. [EPA-HQ-OAR-2009-0491-2689.1, pp.33-34]
IPM Incorrectly Retrofit Buck Units 5, 6, and 7 and Dan River Units 1 and 2 with SNCR in 2012.  
The "Retrofit Control 1" column of the ParsedFile_TR_BaseCase.xls file shows the Buck (ORISPL 2720) units 5, 6, and 7 and Dan River (ORISPL 2723) units 1 and 2 getting SNCR in 2012. This is an error. SNCR on these units is neither existing, under construction nor planned for 2012 or for any year after 2012 for these units. The retrofit SNCR should be removed from these units and the North Carolina annual and ozone season NOx budgets and each unit's annual and ozone season NOx allocations should be adjusted upward accordingly. [EPA-HQ-OAR-2009-0491-2689.1, p.34]
The Duke Energy units that IPM has modeled as fuel switching to 100% subbituminous coal (reference ParsedFile TR_SB_Limited Trading 2014) include R Gallagher (ORISPL 1008) units 1-4, Miami Fort (ORISPL 2832) unit 6, and Walter C Beckjord (ORISPL 2830) units 1-5 (Walter C Beckjord (ORISPL 2830) unit 6 is modeled with a small amount of subbituminous coal being blended with bituminous coal, with an FGD). None of these units are capable of burning subbituminous coals. No capital investment has been made that would allow these units to safely handle and burn this fuel type, such as fuel handling upgrades, dust suppression, mill modifications and fire protection, boiler tube surface changes, sootblower additions, etc. Also, the Beckjord Station does not have a coal handling system that would allow for the controlled blending of bituminous and subbituminous coals for Unit 6, and this unit cannot burn straight subbituminous coal (such as with alternating the fuel types). Therefore, EPA must include the cost of an on-site coal blending system (approximately $70 million to manage all six units, or approximately $40 million for Unit 6 only), or increase the cost of the delivered fuel to account for off-site blending cost premiums (approximately $10 to $14 per ton of blended coal from terminals on the Ohio River). In addition to the fact that none of these units have ever burned any subbituminous coal, Duke Energy has estimated the cost of fuel switching these units to be far in excess of EPA's $2,000 per ton cost breakpoint for SO2. It is therefore not appropriate for IPM to model any of these units as burning subbituminous coal. [EPA-HQ-OAR-2009-0491-2689.1, pp.35-36]
EPA's Assumption That Coal Switching within the Bituminous Coal Grade to a Lower Sulfur Coal Will Can Be Accommodated at Relatively Little Cost is Wrong.
EPA states that in its PTR analysis it does not add capital or operations and maintenance costs for coal switching from higher to lower sulfur bituminous coals, and asks for comment on the reasonableness of this assumption. For a number of Duke Energy units that IPM has switched to lower sulfur bituminous coal, this assumption is wrong.  [EPA-HQ-OAR-2009-0491-2689.1,p.36]
The ParsedFile TR_SB_Limited Trading 2014 shows that IPM has switched Duke Energy's Gibson (ORISPL 6113) unit 5 to a 1.4 lb /mmBtu SO2 bituminous coal. The unit is not capable of burning a coal with this low sulfur content without incurring significant costs for precipitator upgrades and increased fuel costs.  [EPA-HQ-OAR-2009-0491-2689.1,p.36]
The existing electrostatic precipitators ("ESP") on Gibson Unit 5 were designed by Buell and installed in 1982. It consists of two casings arranged in a chevron configuration. Each precipitator casing has four chambers, each with forty gas passages spaced at nine inches and ten fields, each nominally three feet long by thirty-one feet tall. Each ESP casing is currently powered by sixteen 45kV, 1400 mA transformer-rectifier sets. The precipitator is a weighted wire design and treats 2,300,000 ACFM of flue gas at 305 degrees Fahrenheit. Design gas velocity is 5.3 feet per second and the SCA is approximately 254. [EPA-HQ-OAR-2009-0491-2689.1, p.36]
The unit's precipitator design particulate removal efficiency is 99.5%, burning 2.6 lb sulfur coal. At present the unit typically burns 4.5 lb coal and at times suffers opacity excursions when one or two fields in the precipitator are out of service. Burning a 1.4 lb/mmBtu SO2 coal in this unit would not be possible without a major precipitator rebuild or baghouse addition. A baghouse addition would cost approximately $200 million. A precipitator rebuild would cost around $25 million. Duke Energy has estimated the $/ton cost of a precipitator upgrade required to allow the unit to burn this lower sulfur coal to be far in excess of the $2000/ton cost breakpoint that EPA is using for SO2. [EPA-HQ-OAR-2009-0491-2689.1, pp.36-37]
Similarly, the ParsedFile TR_SB_Limited Trading 2014 shows that IPM has switched Duke Energy's Wabash River (ORISPL 1010) units 2, 3, 4, and 5 to a 0.83 to 0.93 lb/mmBtu SO2 bituminous coal. However, EPA has not provided any additional detail about the quality and nature of this proposed fuel, including full proximate and/or ultimate analysis or the modeled source region. The constituents of coal can vary dramatically, even within the same seam and general sulfur grade. It is difficult for Duke Energy to assess the potential impact of this fuel on the units without knowing this additional detail. This would include ash content and moisture content, as well as fuel combustion characteristics such as grindability, slagging and fouling indices, and volatility. Knowing these details is critical to making an assessment of whether the unit can manage this fuel. Wabash River Units 2, 3, 4, and 5 have ball mills, which are especially susceptible to changes in coal properties. Higher ash, higher moisture, and/or lower grindability characteristics, which are typical in some combination for most lower sulfur coals (whether bituminous or subbituminous), can result in mill skidding; reduced mill fineness. This usually results in increased boiler slagging and fouling; pluggage; higher NOx and CO emissions; lower unit efficiency; higher opacity; and therefore reduced unit availability and capacity. It can also result in mill explosions, which are a significant safety hazard, and require expensive fire protection and suppression system upgrades (again, even for bituminous coals); and also, in conjunction with ash resistivity impacts, reductions in precipitator performance requiring precipitator conditioning systems and/or expensive precipitator upgrades or replacements, as the precipitators on these specific units are very small (only 130 SCA, with rigid discharge electrodes and 11 inch plate spacing), and were originally designed for 6 to 7 lb/mmBtu SO2 fuels. [EPA-HQ-OAR-2009-0491-2689.1, pp.37-38]
These units have not been able to burn coals with less than 2.8 lb/mmBtu SO2 without suffering constant opacity exceedances. Further, IPM has specified different coal grades for Units 2 through 5, versus Wabash River Unit 6 (approximately 4.6 lb/mmBtu SO2 on Unit 6). Wabash River Station has a common coal handling system for all of the units; a capital investment would be required to separate the system to allow Unit 6 to manage a vastly different fuel from Units 2 through 5. Lastly, the ability to specify a suitable fuel of this sulfur grade in the market that has the requisite composition and characteristics to minimize the operational problems on these specific units may significantly limit the volume of fuel available, thereby resulting in higher coal costs than what IPM may be modeling (and thus affecting the economic assessment of this fuel choice relative to the $2000/ton cost breakpoint for SO2). Otherwise, a considerable capital investment would be required, including investments in the precipitators, mills, (and the coal handling system), again affecting the economic assessment of this option. [EPA-HQ-OAR-2009-0491-2689.1, p.38]
Due to the limited information provided, and the limited time allotted for comments, Duke Energy cannot reasonably research, engineer, and develop a capital cost estimate for this grouping of projects that would be instructive for EPA to consider in its economic assessment. Duke Energy can therefore only recommend, due to the configuration of these specific units and the recognized impact that coals of this general characteristic can have, that these units are not capable of burning the fuel selected by IPM (or equivalently, that given the proper time for project development, cost estimation, and assessment of the impacts on unit availability and capacity, that this option has a high likelihood of exceeding the $2000/ton cost breakpoint for SO2). Duke Energy requests that EPA model no less than a 1.67 lb/mmBtu SO2 bituminous coal for Wabash River Units 2 through 5. Coals of this general sulfur grade represent a vastly larger market share than the ~0.9 lb/mmBtu SO2 coal, offer wider variability in constituents and combustion characteristics (thereby making finding a suitable fuel more likely), and may even represent a mix of higher and lower sulfur fuels, again optimizing sourcing options, and reducing the impacts of incidental bunkering of higher sulfur coal from Unit 6 into Units 2 through 5.  In summary, at least for these Duke Energy units, EPA's assumption that a fuel switch to lower sulfur bituminous coal can be accomplished at relatively little cost is not correct and should be revisited. Any switch to lower sulfur bituminous coals if even feasible, would come at considerable cost that must be evaluated to determine the $/ton cost of such a switch and whether it would be within EPA's $2000/ton cost breakpoint for SO2. [EPA-HQ-OAR-2009-0491-2689.1, pp.38-39]
Duke Energy Recommends Modifications to the Way EPA Is Allocating Allowances to Peaking Turbines.
In review of the IPM projected heat input and emissions for peaking units, it is clear that the model projections consistently under-predict the potential for generation from these units. As a result, the model is then under-projecting the emissions from these units, which leads to an inadequate allocation when the projected emissions are the basis for determining a unit's allocation. It is generally accepted that most dispatch models do a very poor job of predicting peaking unit generation, and a load duration model, such as IPM, is even worse (in comparison to a chronological simulation model, for example). The multiple uses of peaking units make modeling their dispatch difficult; this includes actual coverage of peak load, but also ancillary services, such as operating for spinning reserve, VAR support, fast-startup for forced outage events, fast-response load following, interaction with energy storage (such as pumped storage hydro), and even testing (such as CEM RATAs, load proof tests, etc.). These various uses of peaking units, not just for meeting peak load, but for system reliability, are not well represented in the IPM. Comparing the TR Base Case 2012 and TR SB Limited Trading 2014 IPM projections of heat input on the Duke Energy fleet of natural gas fired combustion turbine units to the average historical heat input over the period 2005-2008, the IPM heat input projection was approximately 57% below the historical actual heat input for the ozone season period, and approximately 67% below the historical actual for the annual period. This very large under-representation of heat input leads directly to an under-prediction of emissions and a smaller allowance allocation than these units should receive. This problem with under-predicting heat input and emissions for combustion turbines would be magnified under the direct control remedy.  [EPA-HQ-OAR-2009-0491-2689.1, pp.41-42]
As a result of this problem, Duke Energy recommends that EPA modify its method for allocating allowances to peaking units from its stated method of using the lower of adjusted projected and adjusted reported emissions at the state level, and for peaking units only (whether combustion turbine or internal combustion, natural gas or oil) select the higher of the adjusted reported or adjusted projected emission, by unit. This will at least ensure that these units are provided an allocation that is consistent with their past level of generation and emissions and not biased downward or even totally eliminated due to an inadequate model representation of peaking units' full range of operation to serve both load and system reliability. [EPA-HQ-OAR-2009-0491-2689.1, p.42]
A Correction Is Needed to the Annual NOx Allowance Allocations for Some Peaking Units
EPA has proposed to allocate ozone season NOx allowances to a large number of peaking units, but it has not proposed to allocate any annual NOx allowances to those same units. Regardless of whether a state's budget and unit allocations were determined based on reported or projected emissions, a unit that receives an ozone season NOx allowance allocation must also receive an annual NOx allowance allocation consisting of at least the same number of allowances. To allocate ozone season but no annual NOx allowances to a unit makes no sense because the ozone season program and the data used to establish the ozone season allocations is a subset of the annual program regardless of whether reported or projected data was used.  [EPA-HQ-OAR-2009-0491-2689.1, p.51]
Duke Energy's Lincoln Combustion Unit 8 (ORIS 7277) located in North Carolina is an example of a unit whose annual NOx allocation exhibits this problem. EPA used adjusted reported emissions to set the North Carolina annual and ozone season NOx budgets and unit-level allocations. Based on the adjusted reported data, EPA determined that this unit should  receive two ozone-season NOx allowances. By definition it therefore must have also emitted at least two annual NOx tons for the annual reported period since the ozone season reporting period data is a subset of the annual reporting period data. However, a zero annual NOx allocation is proposed for this unit. Duke Energy can only conclude that this is an error.  [EPA-HQ-OAR-2009-0491-2689.1, pp.51-52]
Further, reviewing the BADetailedData.xls data file for this unit, the tab "Reported Data tab," row 7727, shows that the reported emission and heat input data was summarized for the ozone season, but that no data was shown in the column AW ("2008 Reported Annual Heat Input (mmBtu)") to represent the annual reported heat input for NOx (since EPA is adjusting reported NOx emissions to year 2008 heat input). In addition, columns F, I, L, (heat input for 2008 quarters 1 through 3 respectively), show reported heat input for this period that should have been summed to determine the 2008 annual heat input to use in calculating the unit's annual NOx allocation. The following table provides a listing of the Duke Energy units that exhibit this problem. [EPA-HQ-OAR-2009-0491-2689.1, p.52] [[See Docket Number EPA-HQ-OAR-2009-0491-2689.1, p.53 for the table.]]
Duke Energy requests that EPA correct the data errors and provide the appropriate annual NOx allocation to the Duke Energy units listed above, and to all other peaking units exhibiting this problem because, logically, a ton emitted in the ozone season is a ton emitted in the annual period. [EPA-HQ-OAR-2009-0491-2689.1, p.53]
Dynegy, Inc.
EPA has incorrectly identified the effective date for an FGD requirement at Baldwin Unit 2 as set out in the applicable NSR settlement action. EPA's Base Case v.4.W, at Appendix 3- 3.9, identifies ' 12/3112011' as the 'effective date' for SO2 Control (install wet or dry FGD) for Baldwin Units 1 and 2 under the Illinois Power Settlement Action. However, by its plain language, the Consent Decree (66) only requires an FGD to be installed and operating on Baldwin Unit 2 'by no later than ... December 31 , 2012'; the Consent Decree does not require an FGD on Baldwin Unit 2 by December 31, 2011.3 In fact, the Baldwin Unit 2 FGD will not be operable until late 2012. Given that the in-service date of the Baldwin Unit 2 FGD will not occur until late 2012 and the correct effective date of the FGD requirement (December 31, 2012), the SO2 allowance allocations for Baldwin Unit 2 in 2012 and 2013 should be based on Baldwin Unit 2's current SO2 emission rate, rather than a fraction of the December 31, 2012 Consent Decree emission limit. By correcting the effective date of the FGD requirement on Baldwin Unit 2 and using Unit 2's current emission rate, the SO2 allowance allocation for Unit 2 should increase from 1,319 allowances per year in 2012 and 2013 to 7,809 allowances per year. [EPA-HQ-OAR-2009-0491-2698.1,pp.3-4] This correction of the FGD effective date and allowance calculation for Baldwin Unit 2 is consistent with EPA's proposed allowance allocation for Dynegy's Havana Unit 6, which is also subject to the same 'no later than' December 3 1,2012 FGD compliance date in the Consent Decree. Because EPA adjusted allocations downward only 'if the unit has additional pollution controls projected to be online by 2012' (75 Fed. Reg. at 45309), and because Baldwin Unit 2 will not have an FOD online by January 1, 2012, the allowance allocation for Baldwin Unit 2 should not have been adjusted downward. Thus, EPA must correct the allocation for Baldwin Unit 2 and Illinois state budget, which can be made without adversely impacting any other EGU. [EPA-HQ-OAR-2009-0491-2698.1,p.4]   
EPA's proposed SO2 allowance allocations for units operating existing scrubbers are based on reductions up to the scrubbers ' 'design removal efficiencies'. See 75 Fed. Reg. at 45281. The design removal efficiency EPA has assumed for the Baldwin Unit 1, 2 and 3 scrubbers (i. C., 95%) is incorrect. The incorrect assumptions for the Baldwin scrubbers are found in the NEEDSv3.02 EISA.xls spreadsheet (i.e., see 'Wet/Dry Scrubber' column V which indicates a Wet Scrubber, and the 'Scrubber Efficiency' in column Y that indicates 95% removal efficiency). Also, these incorrect assumptions are found in the NEEDSv4.10.xls spreadsheet, where column W represents 'Wet Scrubbers' but the column Y 'Scrubber Efficiency' now lists 98% removal efficiency. If as indicated in the September I, 2010 NODA EPA uses that IPM and NEEDSv4.10 to determine the final allocations for the Transport Rule, the NEEDSv4.10 file also needs correction. [EPA-HQ-OAR-2009-0491-2698.1,p.4] The correct design emission rate for each of the Baldwin dry scrubbers is 0. 100 lb/mmBtu SO2. That design emission rate -- 0. 100 lbs/mmBtu SO2 (1-hour average) -- is specified in the conformed FGD project specifications, as well as in the air construction permit applications submitted by Dynegy for the dry scrubbers at Baldwin. Furthermore, the Illinois EPA-issued construction permits authorizing installation of the dry scrubbers on Baldwin Units 1, 2 and 3 are based on 0.100 lb/mmBtu SO2. No other more stringent SO2 emission limit applies. Indeed, Dynegy has already entered into contracts and has begun construction of all four dry scrubbers required by the Consent Decree. It is not possible to re-design these dry scrubbers at this point because it would cause Dynegy to violate the compliance deadlines of the Consent Decree. [EPA-HQ-OAR-2009-0491-2698.1,p.4]    
Importantly, EPA's incorrect assumption regard ing a 95 percent removal efficiency for the Baldwin scrubbers also fails to recognize a key difference between wet and dry scrubbers. Paragraph 67 o f the Consent Decree (see Attachment A) expressly allows installation of either wet or dry scrubbers at Baldwin. Dynegy has elected to construct dry scrubbers, since it had previously converted the Baldwin units to low sulfur Powder River Basin (PRS) coal. With our PRB coal having uncontrolled S0:2 emissions of 0.4 to 0.5 lbs SO2/mmBtu , Dynegy's dry scrubbers need to achieve 75% to 80% removal efficiency to attain the Consent Decree required emission limit of 0. 1 00 lb/mmBtu S02 30-day rolling average. Only if the Baldwin units were combusting high sulfur coal, which they are not, would wet scrubbers capable of 95 percent (or greater) removal efficiency have been needed. EPA must recognize in this rulemaking and in its IPM model that the design removal capability of wet and dry scrubbers arc appreciably different and that dry scrubbers designed for low sulfur PRB coal do not need to attain the same high removal efficiencies as wet scrubbers. [EPA-HQ-OAR-2009-0491-2698.1,pp.4-5] In short, if EPA retains Phase 1 (2012-2013) of this proposed rule, the Phase 1 SO2 allowance allocations for Baldwin Units 1 and 3 should be based on 0.100 lb/mmBtu SO2 with Baldwin Unit 1 allocated 2,054 SO2 allowances per year in 2012 and 2013 and Baldwin Unit 3 allocated 2,077 SO2 allowances per year in 2012 and 2013. Baldwin Unit 2, which will not have a scrubber until 20 13 (i.e., December 31, 2012), should be allocated 7,809 SO2 allowances per year in 2012 and 2013. Likewise, the Phase 2 allocations for the Baldwin units should based on 0.100 lb/mmBtu SO2 with Baldwin Unit 1 allocated 2, 187 SO2 allowances per year, Baldwin Unit 2 2,255 SO2 allowances per year and Baldwin Unit 3 2,328 allowances per year. [EPA-HQ-OAR-2009-0491-2698.1, p.5]  
At several of Dynegy's EGUs the four quarters of heat input data used by EPA to determine allowance allocations were not representative of normal unit operation. See EPA spreadsheet 'BADetailedData.xls' in the Allocations & Rate Limits worksheet. The data are in column O 'Heat Input Assumed in 2012 SO2 Allocation', column Q 'Heat Input Assumed in Annual NOx Allocation', and column R 'Heat Input Assumed in Ozone Season NOx Allocation.' These instances of unusually low heat inputs were largely due to extended outages associated with the installation of new baghouse systems and activated carbon injection systems (i.e., Baldwin Unit 3, Havana Unit 6, Hennepin Units 1 and 2). Economic and weather conditions during 2008 and 2009 also resulted in unit heat inputs that were significantly lower than typical. [EPA-HQ-OAR-2009-0491-2698.1,p.5]  
Attachment B to this letter identifies the heat input values EPA used for the affected Dynegy units and the heat input values that Dynegy believes are more representative of normal unit operation. Attachment B also explains the reasons EPA's heat input values are not representative. Dynegy requests that EPA replace its original heat input values with the more representative heat inputs when it recalculates Dynegy's allowance allocations for these units. EPA's recalculation of Dynegy's allocations should result in 6,407 SO2 allowances in 2012 and 2013 for Havana Unit 6; 4,752 SO2 allowances in 2012 and 2013 for Hennepin Unit 2; 993 Annual NOx allowances per year for Baldwin Unit 1; 379 Annual NOx allowances per year for Hennepin Unit 1; 1,279 Annual NOX allowances per year for Hennepin Unit 2; 590 Annual NOx allowances per year for Wood River Unit 4; and 159 ozone season NOx allowances for Hennepin Unit 1. [EPA-HQ-OAR-2009-0491-2698.1,p.5] [[See Docket Number EPA-HQ-OAR-2009-0491-2698.1, pp.20-21 for Attachment B.]]  
Other Technical Errors Involving Dynegy EGUs  
EPA's data tables and allowance allocations for Dynegy units also include other technical errors. These Dynegy unit-specific errors are identified in Attachment C to this letter. EPA must correct each of these errors and recalculate the allowance allocations accordingly. [EPA-HQ-OAR-2009-0491-2698.1, p.6] [[See Docket Number EPA-HQ-OAR-2009-0491-2698.1, pp.22-30 for Attachment C.]]  
Footnote 3: Specifically, 66 of the Consent Decree -- see Attachment A -- requires installation and operation of an FGD on each of the three units at Baldwin according to the following staggered scheduled: on anyone of the three Baldwin units by no later than December 31, 2010, on a second Baldwin unit by December 31, 2011, and on the remaining third Baldwin unit by December 31, 2012. Baldwin Unit 2 is the last of the three Baldwin units on which an FGD will be installed. [EPA-HQ-OAR-2009-0491-2698.1,p.3] [[See Docket Number EPA-HQ-OAR-2009-0491-2698.1, pp.10-19 for Attachment A]]    
East Kentucky Power Cooperative
Further, at the EKPC Spurlock Station, Units 3 and 4 have the same NOx control equipment, yet they are given different NOx rates without explanation. Also without explanation, EPA assigned no annual NOx or S02 allocations for the natural gas turbines at EKPC's Smith Station. Again, there are no S02 allocations for EKPC's Dale Stations Units 1 and 2 for 2014. Further, the rated capacities for most of EKPC's units are incorrect and appear to be based on original unit guarantees rather than on actual 2009 operating data or data from EKPC's Consent Decree entered into with EPA. The capacities as stated in the Consent Decrees EKPC entered into with EPA are contained in the following chart: [EPA-HQ-OAR-2009-0491-2776.1, p.2; see p.3 of this comment summary for the capacities as stated in the Consent Decrees EKPC entered into with EPA]
Also, EPA assigned allocations to Cooper Units 1 and 2 based on controls that do not yet exist and thus assigned allocations that are too low. While controls will be installed on these units in the future per a Consent Decree entered into with EPA, the analysis for the rule is based on 2009 data when the units have no scrubbers in operation, no SCRs in operation and have only low NOx burners in operation. Therefore, the allocations are artificially low. [EPA-HQ-OAR-2009-0491-2776.1, p.3]
Additionally, the emission allocation for EKPC Spurlock Unit 4 was based on 2009 which is the year the unit began operation, creating a lower allocation than is appropriate since no emissions were considered from January 1 through March 19, 2009 when the unit experienced initial startup. Along these same lines, EKPC's Spurlock Unit 1 commenced commercial operation of the new pollution control train consisting of a SCR, WFGD and WESP on April 1, 2009. EPA should therefore use 12 months of the unscrubbed allocations based upon this fact, otherwise the rule unfairly penalizes EKPC. [EPA-HQ-OAR-2009-0491-2776.1, p.3]
EKPC is generally concerned that the basis for emissions allocations utilize 2009 emissions data for SO2 and NOx. As with the remainder of the economy, coal-fired generation and emissions were significantly depressed during the 2008 2009 year due to the economic recession. Therefore, data from this period is inappropriate as it is not representative of normal conditions. EPA should utilize data from 2005-2007. A three year averaging methodology, as was used for CAIR, is consistent with EPA historical approaches and the 2005-2007 period provides a more accurate database for establishing allocations. [EPA-HQ-OAR-2009-0491-2776.1, p.3]
The above are just a few examples of questions that arise when examining EPA's underlying data by only one regulated entity. EPA should revisit the rule to examine the underlying data for accuracy or, at the very least, provide valid explanations for such inconsistencies. EPA should also clarify the methodology and calculations used to develop the 2012 and 2014 emissions and allocations for S02 and NOx such that its calculations are transparent and the regulated community can fully understand the allocations assigned. EKPC further requests that EPA clarify that compliance with CATR would be based on a system-wide approach rather than a plant or unit approach. [EPA-HQ-OAR-2009-0491-2776.1, p.3]
Entergy Services, Inc.
Warren Peaking Power Facility 
Entergy would like to take this opportunity to correct an error in the Mississippi allocation pool of allowances.  The proposed rule states that the Warren Peaking Power Facility (ORIS 55303) is located in Mississippi when in fact these four peaking units were decommissioned, sold, and relocated to two non-Entergy sites in Texas in 2008.  Two of the units were installed at the San Jacinto County Peaking Facility (ORIS 56603) and the other two units were installed at the Hardin County Peaking Facility (ORIS 56604).  Entergy requests that EPA remove the Warren Peaking Power Facility from the Mississippi pool and add the San Jacinto County and Hardin County Peaking Facilities to the Texas pool of allowances.  [EPA-HQ-OAR-2009-0491-2847.1, p.14]
Nelson Industrial Steam Electric Company (NISCO) Units 
Entergy would like to take this opportunity to correct an error in the Louisiana allocation pool of allowances.  The proposed rule states that NOx and SO2 allowances are allocated to R S Nelson, ORIS Code 1393, Units 1A and 2A.  These units are actually named Nelson Industrial Steam and Operating Company (NISCO), ORIS Code 50030, Units 1A and 2A.   Entergy requests that EPA correct this error in the final regulation so the NISCO units are awarded the appropriate allowances. [EPA-HQ-OAR-2009-0491-2847.1, p.14]
Faribault Energy Park
During review of data used by the EPA to calculate projected NOx and SOx emission values for the Faribault Energy Park, MN facility (ORIS ID No. 56164), it appears that the Projected Annual Heat Input values used for SOx and NOx are 437,400 mmBtu and 1,314,500 mmBtu respectively. We feel this basis is neither typical nor representative of our current operation due to the following reasons.
- This was a newly constructed facility in 2005 that operated only for the last 6 months in 2005 in Simple-Cycle mode using natural gas as a fuel source. At that time there was no historical data for this facility to provide information on typical operations.
- In the third quarter of 2007 the plant was converted to a Combined-Cycle operation.
- In 2008, the first full year operating as a combined cycle, the actual reported annual Heat Input value was 3,069,445 mmBtu as reported in our quarterly reports to the EPA.
Due to the significant difference in annual Heat Input values utilized for calculating the two emissions and the actual 2008 reported Heat Input value, we respectfully request the EPA use the actual report 2008 Heat Input value of 3,069,445 mmBtu to calculate both SOx and NOx emissions. [EPA-HQ-OAR-2009-0491-3146 p.1]
Florida Municipal Power Agency (FMPA)
C.     The Allocation Table in the TSDs Contains Errors and Omissions
FMPA believes there are errors and omissions with respect to certain FMPA generating units in the Allocation Table included in the Technical Support Documents for the Proposed Transport Rule, which we understand EPA intends to incorporate into the Final Rule as Appendix A.[2]  The following errors and omissions must be corrected prior to their incorporation into the Final Rule: [EPA-HQ-OAR-2009-0491-2725.1, pp.5-6]
[For additional comments pertaining to errors and omissions, see pp. 5-6 of this comment]

2.  FMPA intends to submit additional comments on errors in the characterization of our generating units in the NEEDS database prior to the October 15, 2010, deadline. [EPA-HQ-OAR-2009-0491-2725.1, p.5]
Formosa Plastics Corporation, LA
A review of the Allocation Table indicates the EPA has allocated 8 tons of Annual and Ozone Seasonal NOx for each of three gas turbines (GT1, GT2, and GT3) operated by FPC. Please know that FPC recently decommissioned GTI and is no longer a source at FPC. [EPA-HQ-OAR-2009-0491-1258, p.1]
Additionally, FPC understands that existing units GT2 and GT3 are cogeneration units as defined in the above referenced rule. However, as these cogeneration units do not serve a generator with a nameplate capacity of more than 25 MWe that supplies for sale more than 219,000 MWh of electricity in a calendar year, these sources are exempted from applicability of the above referenced rule per 40 CFR 97.404(b)(1)(i), 97.504(b)(l)(i), and 97.604(b)(I)(i). As such, FPC requests removal of FPC's sources from the Allocation Table since none of the FPC listed sources meet the applicability criteria in the proposed EPA Federal Implementation Plan. [EPA-HQ-OAR-2009-0491-1258, p.1]
Giarmarco, Mullins & Horton, P.C.
- The unit specific data for MCV does not identify allowances for units 016, 017, 018, 019,020 and 021. MCV commenced operation of these units in the spring of 2009 and seeks allowances commensurate with its anticipated operations from that date forward. [EPA-HQ-OAR-2009-0491-2766.1, p.3]
MCV has reviewed the allocation information contained in the 'Budget and Allocations - Detailed Unit-Level Data' spreadsheets as part of EPA's Notice of Data Availability dated September 1, 2010. Comments related to that review have been submitted to EPA on October 1, 2010. As part of that submittal, MCV referenced and incorporated those comments submitted by the State of Michigan and/or its Department of Natural Resources and Environment. Upon further review of the exhibits to those comments, MCV uncovered typographical errors related to MCV's unit specific allocations for the NOx annual and ozone season. MCV has provided revised tables for the annual and ozone season for consideration by EPA which are attached in Exhibit A and B, respectively.  [EPA-HQ-OAR-2009-0491-3760.1_NODA, p.1] [[See Docket Number EPA-HQ-OAR-2009-0491-3760.1_NODA, pp.3-4 for Exhibits A and B.]]
As is evident in both exhibits, projected TR NOx allocations for MCV are extremely low and represent about 5% of the amount that MCV was expected to receive in the CAIR 2012 allocation. As stated in the previously submitted comments, MCV believes that the cause of this occurrence is EPA's treatment of MCV as a peaker facility in its IPM model assumptions, which would be incorrect. As EPA is aware, a peaking power plant, by definition, is a quick-start resource that generates electricity in periods of high demand. Peaker plants are generally simple cycle gas plants with quick-start capability able to generate within 10 to 30 minutes from start-up. Unlike peakers, MCV is a combined-cycle cogeneration plant without quick start capability and designed to run as a base load plant. MCV has baseload generation serving 100% of the electric energy and process steam process requirements of The Dow Chemical Company's Michigan Division under a long-term contract. Additionally, MCV's steam turbine is synched to the transmission grid on a constant 24/7 basis, and when combined with the gas turbines the facility delivers full plant capacity under its long-term Power Purchase Agreement with Consumers Energy. The baseload operation of the plant is further reflected in the historical heat input values identified in Exhibits A and B. [EPA-HQ-OAR-2009-0491-3760.1_NODA, p.2]
Great River Energy
 :: The model had many inaccuracies. Some specific examples include:
[EPA-HQ-OAR-2009-0491-2758.1 p.3]
o Pleasant Valley Station (ORIS Code 7843) Unit 11 had data missing (heat input, NOx and S02 mass emissions) for the 3rd quarter of2009.
o Elk River Peaking Station (ORIS Code 2039) Unit 11
:: Due to CEMS commissioning, EDR data provided by the Clean Air Markets Division of EPA did not include emissions until Oct. 2009. :: 2009 is not a representative year for this unit. (See Attachment 1.)
o Maple Lake Station (ORIS Code 2042) Unit 1
:: Is listed twice and one of the listings with a capacity of 0 MW is checked as being a covered unit>25 MW.
:: There are no emissions associated with this listing in the model but the second listing has emissions associated with the entry. It has the capacity listed at ~19MW and is not checked as a covered unit> 25 MW.
:: Data are missing for S02 mass emissions for 2008 since this unit reported emissions under the CAIR program prior to it being stayed for Minnesota. 
o Rock Lake (ORIS Code 6741) Unit 1
:: Is also listed twice and one of the listings with a capacity of 0 MW is checked as being a covered unit >25 MW.
:: There are no emissions associated with this listing in the model but the second listing has emissions associated with the entry and it has the capacity listed at ~19MW and is not checked as a covered unit> 25 MW.
:: Data are missing for S02 mass emissions for 2008 since this unit reported emissions under the CAIR program prior to it being stayed for Minnesota.
o Cambridge Station (ORIS Code 2038) Unit 1
[EPA-HQ-OAR-2009-0491-2758.1 p.3]
:: Data are missing for S02 mass emissions for 2008 since these units reported emissions under the CAIR program prior to the rules for the state of Minnesota being stayed.
:: Is an identically sized unit as ORIS code 2042 and 6741 and this unit was not included as a covered unit> 25 MW. [EPA-HQ-OAR-2009-0491-2758.1 p.4]
:: At times, EPA uses a different heat input value for determining NOx versus S02 allocations. It is unclear how and why EPA uses these different values. As one example, for Lakefield Junction, EPA uses a much lower S02 heat input (174,306 mmBtu for all units) than different and variable NOx heat input for each unit. The lower S02 heat input results in fewer S02 allowances allocated to our units. [EPA-HQ-OAR-2009-0491-2758.1 p.4]
:: EPA's model incorrectly assumes only natural gas combustion for our dual fuel peaking turbines. The vast majority of our peaking turbines are dual fuel fired, with gas contracts that are interruptible. Each plant has different gas contracts and is supplied by different gas companies and/or lines. In general, the gas fired units can be curtailed in winter, requiring them to run on fuel oil. Unfortunately, EPA does not factor this fuel variability into their modeling. GRE would be forced to shut down units in the winter, when gas is curtailed, and allowances may not be available. EPA must revise the projected emissions to be inclusive of dual fuel capability for both NOx and S02 allowances. [EPA-HQ-OAR-2009-0491-2758.1 p.4]
Illinois Environmental Protection Agency
Technical Corrections Needed for Illinois EGUs
In reviewing U.S. EPA's technical support information accompanying the proposed Transport Rule, Illinois EPA identified several inaccuracies that should be addressed before final allocations are determined. Listed below are brief descriptions of the needed corrections. The Illinois EPA, in conjunction with Illinois utilities, will work with U.S. EPA to provide corrections consistent with the Notice of Data Availability, announced by U.S. EPA on September 1, 2010.
 :: Prairie State Energy Campus, a 1,600-megawatt coal-fired electric generating facility in Illinois, commenced construction in 2007, and will begin operating in late 2011 and early in 2012. This facility has not been included in U.S. EPA's modeling and therefore has not been proposed to receive allocations. The Illinois EPA recommends that Prairie State be considered as an existing source for the purposes of the Transport Rule and should be allocated allowances consistent with an annual and seasonal utilization as a base-load facility. Illinois EPA looks forward to working with U.S. EPA to determine an appropriate allowance allocation for this facility.
 :: U.S. EPA's list of affected sources includes four emission units at Morris Cogeneration (ORIS ill 55216) that should not be included as EGUs. The Illinois EPA has permitted Morris Cogeneration as a non-EGU, and it has not received allowances under Illinois' CAIR rule. Illinois EPA recommends that Morris Cogeneration be removed from the list of EGUs affected by the proposed Transport Rule.
 :: City Water Light & Power's (CWLP) Dalhnan plant Unit 4 (Oris 963) is misidentified as Unit 34. Also, since the Dallman 4 unit has only recently been constructed, the historical heat input used by U.S. EPA in calculating its proposed allocation is not representative of expected operations of this unit. Illinois EPA looks forward to working with U.S. EPA to determine an appropriate allowance allocation for this unit.
 :: The assumed heat input for City Water Light & Power's (CWLP) Dallman Unit 31 is not representative of historic operations of this unit (in fact the heat input is listed as 0 for the annual and seasonal NOx allocations). The heat input for this unit should mirror the value for its sister unit, Dallman Unit 32, with which it shares a common scrubber and stack. Also, the emission rates for Dallman Units 31 and 32 should be the same because they share a common FGD and stack.
 :: U.S. EPA's assumption that the FGD system controlling Dynegy's Baldwin unit 2 will be operational prior to 2012 is incorrect. Based on a Federal consent decree, the FGD system should be in operation by December 31, 2012 for Baldwin unit 2.
 :: U.S. EPA assumed that Ameren's Joppa unit 2 has an existing OFA, which is incorrect. Also, Joppa units 5 and 6 have OF A, but these are not listed.
 :: U.S. EPA's modeling has determined that Ameren's Meredosia units 1 and 2 will be shut down by 2014. Ameren has no plans to shut down these units. U.S. EPA should provide adequate allowances for these units.  [EPA-HQ-OAR-2009-0491-2781.1 p.3-4]
Indiana Energy Association
c. The aforementioned errors in technical assumptions have resulted in such significant errors in allocation budgets that the allocation scheme as proposed is arbitrary. The Indiana Utility Group suggests that the proposed allocation budgets bear little resemblance to existing or projected EGU operations . The Indiana Utility Group urges EPA to develop a revised allocation budget that is consistent with actual EGU operations . [EPA-HQ-OAR-2009-0491-3711 p.3]
Lafayette Utilities System
Comments on NOx Unit Level Allocations
EPA should not regulate NOx emissions from Louisiana EGUs at all, for the reasons stated above. However, in the alternative, and without waiving any legal right to challenge EPA's determination to impose a FIP with annual or ozone season NOx controls, LUS believes that EPA must either allow Louisiana to perform the NOx unit level allocations, or should substantially revise the NOx unit level allocations in Louisiana. [EPA-HQ-OAR-2009-0491-2983.1,p.8]
Errors in the EPA Modeling and Projections
Based on its review of EPA's Allocation Table, LUS has discovered quite a number of errors made by EPA regarding the EGUs' actual emissions rates. LUS believes that this information has directly impacted the units' allocations. [EPA-HQ-OAR-2009-0491-2983.1,p.9]
a. The Louis Doc Bonin Unit 1 and Unit 2 did not receive any NOx allocations under the proposed Transport Rule/FIP.  The Louis Doc Bonin Unit 3 did receive proposed allocations. Under the Direct Control alternative, EPA failed to provide the Louis Doc Bonin Unit 1 and Unit 2 with 0.000 allowable annual and ozone season NOx emission rates.  Unit 1 and 2 are not scheduled to retire and are subject to dispatch by the Southwest Power Pool. They have in fact been dispatched over the past five years. While the allocations for Unit 3 could be used for Units 1 and 2 under some of EPA's proposed options, these may not be sufficient. Further, the ozone season heat input data for the Louis Doc Bonin units appears to be an arbitrary 10% of the annual heat input. This appears to be a data error that should certainly be adjusted in any final projections if they are to be used for unit-level allocations. [EPA-HQ-OAR-2009-0491-2983.1,p.9]
The actual data concerning the utilization of these units, as reported to EPA's CAMD under the CAIR program compared to the Transport Rule/FIP projections are as follows: [EPA-HQ-OAR-2009-0491-2983.1,p .9] [[See Docket Number EPA-HQ-OAR-2009-0491-2983.1,p.10 for the table.]]
It is clear that these units have run every year and are continuing to be utilized. Moreover, they are utilized for a substantial portion of time outside of the May-September ozone season. EPA has provided no transparent or rational reason as to why the Doc Bonin Units 1 and 2 would not be allocated NOx emissions or why they believe these would not run in 2012. EPA did not project that any of these units would require retrofit. If the IPM 'economic' projection is the rationale, EP A must explain the basis for that economic rationale in a maImer that allows LUS comment. LUS does not believe that the Clean Air Act authorizes EPA to 'project' Unit 1 and 2 out of operation for no discernable environmental reason. Similarly, the Act does not authorize EPA to limit operation of the No. 3 unit simply because EPA projects that it will operate less for economic, nonenvironmental reasons. In essence, this is what EP A has done through its unit level allocations for the proposed trading options. [EPA-HQ-OAR-2009-0491-2983.1,p.10]
Under the direct control alternative, as LUS understands it, Units 1 and 2 could not run at all because they are not provided with allowable emission rates. CAMD data show that the NOx emission rates for Units 1 and 2 are as follows:
 Unit 1 has run at annual average rates of 0.03 to 0.19 lb/mmBtu for the last several years
Unit 2 has run at annual average rates of 0.10 to 0.12 lb/mmBtu for the last several years. [EPA-HQ-OAR-2009-0491-2983.1,p.10]
The ozone season and annual NOx emission rates were identical in each year. LUS requests that the direct control option be amended to provide that such units are authorized to run at such rates. [EPA-HQ-OAR-2009-0491-2983.1,p.11]
b. The annual and ozone season NOx allocations for T J Labbe' Unit 1 and Unit 2 and Hargis-Hebert Unit 1 and Unit 2 are significantly less than actual NOx reported emissions and are based on projected heat input much less than actual heat input rates have historically been. Again, as for the Doc Bonin units, the ozone season heat input data for the Louis Doc Bonin units appears to be an arbitrary 10% of the annual heat input. This appears to be a data error as these units clearly run for more than 10% of each year. Further, the annual NOx rates listed under the Direct Control Alternative for T J Labbe' Unit 1 and Unit 2 and Hargis-Hebert Unit 1 and Unit 2 are less than actual reported emission rates.  Because EPA has allocated to these units far less than the allowances necessary to operate at their present operating levels, LUS will be forced to either pay for NOx allowances if it is able to purchase them from another Louisiana utility or install additional controls to keep these units in production. However, these additional controls cannot be put into place by the January 1, 2012 compliance date, which means that LUS may have to cut these units' production to remain in compliance with federal regulations. Such an action will have a devastating impact on the LUS customers relying on these units for their electrical needs. [EPA-HQ-OAR-2009-0491-2983.1,p.11]
It is clear that these units have run every year and are continuing to be utilized. Moreover, they are utilized for a substantial portion of time outside of the May-September ozone season. EPA has provided no transparent or rational reason as to why the Hargis-Hebert and TJ Labbe units would be allocated NOx emissions so far below those that would be indicated by their actual historic operating rates. EPA does not explain at all, other than to say it is an economic output of the IPM, why it believes these units would be utilized so much less in 2012 than the actual historic data would suggest. EPA did not project that any of these units would require retrofit. LUS has no plan to curtail operation of these units in that time period. If the IPM 'economic' projection is the rationale, EPA must explain the basis for that economic rationale in a manner that is transparent and allows LUS comment. LUS does not believe that the Clean Air Act authorizes EPA to limit operation of these units simply because EPA projects that they will operate less in 2012 due to economic, non environmental reasons. In essence, this is what EP A has done through its unit level allocations for the proposed trading options. [EPA-HQ-OAR-2009-0491-2983.1,pp.12-13]
LUS has also discovered additional incomplete and/or inaccurate emissions data for its EGUs in the Excel spreadsheets for the Detailed Unit-Level Allocations. LUS's comments are as follows: [EPA-HQ-OAR-2009-0491-2983.1,p.13]
Reported Table Data:
i. The 2008 reported annual heat input is missing for Louis Doc Bonin Unit 1, Unit 2 and Unit 3.
ii. The 2008 reported annual heat input is missing for T J Labbe' Unit 1.
iii. The most recent fourth quarter emissions of annual NOx mass, annual SO2 mass, and annual heat input are missing for Louis Doc Bonin Unit 3. [EPA-HQ-OAR-2009-0491-2983.1,p.13]
Projected Data Table:
i. The annual heat inputs assumed for Louis Doc Bonin Unit 3, T J Labbe' Unit 1 and Unit 2, and Hargis-Hebert Unit 1 and Unit 2 are significantly lower than reported emissions data. For example, the annual heat input for Hargis-Hebert Unit 1 was 961,796 mmBtu for 2008 and 466,058 mmBtu for 2009. However, EPA listed the Projected Base Case annual heat input in the Projected Data Table as 99,100 mmBtu. [EPA-HQ-OAR-2009-0491-2983.1,p.13]
ii. The heat inputs for Louis Doc Bonin Unit 1 and Unit 2 are listed as 0 mmBtu. These units are not scheduled to retire and are subject to dispatch by the Southwest Power Pool.
iii. The annual and ozone season NOx emissions are significantly lower than reported emissions data. [EPA-HQ-OAR-2009-0491-2983.1,p.14]
Adjusted Data Table:
i. The adjusted annual and ozone season NOx emissions are significantly lower than reported emissions data. [EPA-HQ-OAR-2009-0491-2983.1,p.14]
LUS believes that EPA made the following data errors in the IPM Model Parsed Files:
i. The summer fuel use and total fuel use for Louis Doc Bonin Unit 3, T J Labbe' Unit 1 and Unit 2 and Hargis-Hebert Unit 1 and Unit 2 is significantly lower than reported emissions data.
ii. The summer fuel use and total fuel use for Louis Doc Bonin Unit 3 and T J Labbe' Unit 1 and Unit 2 have the same values in the spreadsheets. However, the total fuel use per year is greater than summer fuel use.
iii. The summer fuel use and total fuel use for Louis Doc Bonin Unit 1 and Unit 2 are listed as 0 TBtu in the Parsed File Tables. These units are not scheduled to retire and are subject to dispatch by the Southwest Power Pool.
IV. Summer and Total NOx emissions are significantly lower than reported emissions data.
v. Total C02 emissions are significantly lower than reported emissions data. [EPA-HQ-OAR-2009-0491-2983.1,p.14]
Lakeland Electric
In Technical Support Document (TSD) #320292, EPA provides a spreadsheet tab labeled "Unit Characteristics" which contains columns for the installation date of SCRs, SNCRs, and FGDs. Unit ID 3 at C.D. McIntosh, Jr. Power Plant (ORIS 0676) has had an FGD scrubber installed since its construction in 1980 and is required to operate under the Plant's Title V operating permit. Unit 3 also has an SCR, which began operating in 2009 and is required to operate under the same Title V operating permit issued by the State of Florida. This appears to be inconsistent with the TSD which does not list either of these two control equipment processes installed and cites that Unit 3 will be required to scrub SO2 by 85.8% in excess of what it is doing presently in the future which will be unobtainable and will force this unit to shut down or change fuel to natural gas. [EPA-HQ-OAR-2009-0491-2630.1 ,p.2]
In the same TSD, EPA has cited Lakeland's Winston Peaking Station as not having SCRs on any of its 20 peaking units. However, the units at Winston Peaking Station are required to run and operate their individual SCRs in order to remain in compliance with the Facility's Title V permit. These Units' SCRs were installed in 2001 and therefore, this TSD should be updated to reflect the actual control equipment present at this facility and EPA should perform an updated modeling run which reflects these changes. [EPA-HQ-OAR-2009-0491-2630.1, p.2]
Lakeland operates multiple units that have the ability to fire pipeline natural gas (PNG) and fuel oil. Most of these units have fired fuel oil in the past 12 months on multiple occasions; however, EPA has not allotted any SO2 allowances to these units. [EPA-HQ-OAR-2009-0491-2630.1, p.3]
A good example is Lakeland's Winston Peaking Station. This power plant consists of 20 peaking stations which, although permitted to fire PNG, at this time only fires #2 fuel oil because of the lack of PNG in the vicinity and thus has been unable to utilize this fuel. EPA, according to the above cited TSD, has not projected any SO2 emissions from this plant even though EPA assumes that the plant will have an annual heat input value of approximately 121,700 mmBtu. In fact, these units are required to operate periodically (i.e., monthly) in order to meet reliability requirements. Therefore, Lakeland requests that this facility be given representative SO2 allowances based on historical operational data. Although Winston plant operates every month consistently throughout the year, and the Plant's highest operations are usually during the summer months, EPA, in the above cited referenced TSD, has only allotted these units a heat input value for non-summer months, thus negating these units from having any Ozone Season allowances. In the same TSD, on the "Allocations and Rate Limits" tab, EPA has cited a heat input value for SO2 allowance allocations, but EPA has not cited any NOx allowance heat input values. These units, when burning #2 fuel oil, emit SO2 AND NOx emissions, however, it appears EPA has not allocated any heat input associated with NOx emissions. Lakeland believes that the Winston Peaking Station units should be allocated heat input values based on its past operation for calculating future NOx allowances because such changes would be consistent with actual operating data. EPA's TSD projected data does not appear to represent past or current operations at this site and therefore EPA should revisit this Plant's data and allocate Ozone Season and Annual NOx allowances and Annual SO2 allowances to this Plant's units. [EPA-HQ-OAR-2009-0491-2630.1 ,p.3]
Unit 8 at Lakeland's Charles Larsen Memorial Power Plant (ORIS 0675) also has dual fuel firing capability (PNG and fuel oil) but has not received any SO2 allowances. Over the past five years annually, Unit 8 has operated on fuel oil and Lakeland believes that this Unit will continue to fire fuel oil in the future and specially when there are natural gas spikes, as has been seen consistently in the past. Records of Unit 8's past fuel oil firing data has been uploaded to EPA's CAMD website and EPA should consider this Unit's current and past actual operation instead of relying completely on modeling software. [EPA-HQ-OAR-2009-0491-2630.1, p.3]
Unit 2 at Lakeland's C.D. McIntosh, Jr. Power Plant was projected by EPA not to operate at all on any fuel in the future per EPA's above cited TSD (see "Projected Data" tab). This reasoning is quite bizarre as EPA has chosen this Unit to perform Part III Emissions Testing per EPA's Utility MACT ICR. This is a dual-fuel fired unit (PNG and fuel oil), which was required to operate on fuel oil in order to satisfy EPA's testing conditions. As it appears, EPA has requested Lakeland to perform over $100,000 in testing on Unit 2, through the Utility MACT ICR, for what EPA projects to be a maximum of one year of additional operation (no operation projected for 2012 and beyond).  [EPA-HQ-OAR-2009-0491-2630.1,p.4]
This surely must be an oversight, as Lakeland Electric has no intention on retiring Unit 2 anytime soon and in fact believes it to be a major contributor to its fleet for at least the next 15-20 years. Additionally, if EPA believes the unit will be retired in the next year, why did EPA require Unit 2 to perform Part III Emissions Testing under the Utility MACT ICR and what will EPA do with the results of an emission unit which it has modeled will be retired before the final MACT rule is implemented? [EPA-HQ-OAR-2009-0491-2630.1, p.4]
Unit 1 at Lakeland's C.D. McIntosh, Jr. Power Plant was also projected not to operate at all on any fuel in the future per EPA's above cited TSD (see "Projected Data" tab). However, Lakeland is currently performing routine maintenance on the Unit in order to bring the Unit back to operation from a forced outage. This unit can fire PNG and or fuel oil, and Lakeland believes that this Unit will operate in the future or else it would not be performing maintenance on the Unit. This is a case where EPA should analyze a different time frame over the past five year period in order to determine a better average heat input and emissions rate for the unit as suggested earlier. [EPA-HQ-OAR-2009-0491-2630.1, p.4]
In addition to the above cited believed discrepancies, the following peaking units at the C.D. McIntosh, Jr. Power Plant and Charles Larsen Memorial Power Plant were all assumed to no longer operate past 2011 per the above cited TSD. Again, each of these units has operated over the past 12 months, which can be verified through the Florida Department of Environmental Protection's (FDEP) Annual Operating Report (AOR) database system. The concerned units are:
(1) Unit ID GT1  -  C.D. McIntosh, Jr. Power Plant
(2) Unit ID 2  - Charles Larsen Memorial Power Plant
(3) Unit ID 3  - Charles Larsen Memorial Power Plant [EPA-HQ-OAR-2009-0491-2630.1, p.4]
Lakeland believes all three of these units should be allotted emissions allowances per their past and current operational capacities. Lakeland also believes that EPA should utilize FDEP's AOR database for these units instead of relying on modeling software which appears to have projected incorrect assumptions for multiple Lakeland's units. The AOR information can readily be obtained from FDEP and should be utilized where EPA has a lack of information, as in the case of many peaking units. [EPA-HQ-OAR-2009-0491-2630.1, pp.4-5]
EPA appears to have utilized 2008 and 2009 unit specific data for certain future allowance allocations calculations. For some of Lakeland's units, 2008 was more representative of a "normal" year than 2009, and for other units, it is the reverse. For example, on the above cited TSD, EPA cites on the "Projected Data" characteristics tab, that Unit 3 (same as above) is projected to emit 1923.7 tons SO2/year by 2012. In 2008, Unit 3 emitted 7599.2 tons of SO2 after scrubber. This represents an unprecedented additional 75% reduction on this Unit's SO2 emissions in one year (beginning of 2012). However, as stated earlier, this Unit already has a scrubber installed and classified under Subpart Da for PSC purposed and is required to operate the scrubber with certain efficiency in order to satisfy conditions in its Title V operating permit. Additionally, this Unit is restricted to a coal sulfur content not exceeding 1.92% sulfur. [EPA-HQ-OAR-2009-0491-2630.1 , p.2]
Lakeland further suspects that EPA may have based some of its calculations using Unit 3 emissions, heat input, or operating capacity from the 2009 operating year. In 2009, Unit 3 was in an extended outage for the installation of its SCR to allow for more compliance flexibility with EPA's Clean Air Interstate Rule (CAIR). This Unit has also experienced forced outages due to unplanned outages caused by the initial startup of the SCR system. Therefore, using 2009 for baseline calculations for Unit 3 is not a representative year for this unit. [EPA-HQ-OAR-2009-0491-2630.1, p.2]
Respectfully Lakeland suggests that EPA chooses a representative period (e.g., 12 months) over the past five years, or use an average of the previous five year period which does not include excessive unplanned outages, for determining a unit's operating parameters instead of selecting the years 2008 and 2009 for NOx and SO2 respectively. Additionally, Lakeland urges EPA to make the aforementioned corrections to the units' parameters that have been cited in this comment letter. Furthermore, Lakeland requests that EPA provide an additional notice and comment period to the electric utility industry for reviewing and correcting EPA's revisions to the allowances and unit parameters so that EPA can develop a more accurate database. [EPA-HQ-OAR-2009-0491-2630.1, pp.2-3]
Manitowoc Public Utilities (MPU)
 MPU (Manitowoc), ORIS 4125, unit 9 is included on the Proposed Transport Rule allocation table. However, the SO2 and NOx emission rates do not appear to be correct. We propose that the SO2 emission rate for 2012 and 2014 should be 0.30 lb/mmBtu and the NOx emission rate should be 0.077 lb/mmBtu.  [EPA-HQ-OAR-2009-0491-2860.1,p]
 MPU (Manitowoc), ORIS 4125, units 6,7 and 8 are not included on the Proposed Transport Rule allocation table. Units 6, 7, and 8 are regulated under CAIR and the ARP and we expect to receive a fair allocation for these existing units.  [EPA-HQ-OAR-2009-0491-2860.1,p.2]
MPU Unit 9 SO2 and NOx Emission Rates  
MPU (Manitowoc), ORIS 4125, unit 9 is included on the Proposed Transport Rule allocation table. However, the SO2 and NOx emission rates utilized to make the allocations do not appear to be correct.  [EPA-HQ-OAR-2009-0491-2860.1,p.3]
We propose that the SO2 emission rate (lb/mmBtu) for 2012 and 2014 should be 0.30. The 2012 emission rate of 0.592 and the 2014 rate of 0.498 used in the EPA analysis are not realistic, as the unit 9 permitted emission limit for SO2 is 0.30. The actual annual SO2 emissions for 2012 and 2014 are expected to remain at the 2009 level of 450.2 tons per year.  [EPA-HQ-OAR-2009-0491-2860.1,p.3]
We propose that the NOx emission rate (lb/mmBtu) should be 0.077. We believe the NOx emission rate of 0.048 is not reasonable. During the permitting of unit 9 in 2003 it was believed that the NOx BACT limit for the CFB boiler would be 0.07. However, we could not get the boiler manufacturer to guarantee performance at that level and we utilized an alternate method. In 2009 the actual emission rate for unit 9 was 0.077 and total annual emissions were 131.9 tons, well above the allocated annual allowance of 102 tons. The actual annual NOx emissions for 2012 and 2014 are expected to remain at the 2010 level of 182 tons per year. [EPA-HQ-OAR-2009-0491-2860.1,p.3]
ORIS 4125, Units 6,7 and 8 Missing Allocation  
MPU (Manitowoc), ORIS 4125, units 6,7 and 8 are not included on the Proposed Transport Rule allocation table. Units 6,7,and 8 are regulated under CAIR and the ARP and we expect to receive a fair allocation for these existing units. The actual annual SO2 emissions for 2012 and 2014 are expected to remain at the 2009 level of 336.6 tons per year for units 6,7, and 8 at an emission rate of 0.79 lb/mmBtu. The actual annual NOx emissions for 2012 and 2014 are expected to remain at the 2009 level of 85.5 tons per year for units 6,7, and 8 at an emission rate of 0.189 lb/mmBtu. Units 6, 7, 8 received a total CAIR annual allocation of 417 tons. [EPA-HQ-OAR-2009-0491-2860.1,pp.3-4]
Massachusetts Department of Environmental Protection
MassDEP requested that the affected facilities in Massachusetts review the proposed Transport Rule annual NOx and S02 allowance allocations. A number of facilities identified inconsistencies and incorrect assumptions in EPA's technical support documentation, including the IPM assumptions. For several Massachusetts sources, EPA's data on unit specific emission rates and controls used in the base case, 2012, and 2014 appear to omit existing pollution control devices. In addition, there are errors in primary fuel for several oil-fired EGU boilers in Massachusetts. The units and the corrected information are identified in the attached 'Corrections to Data and Assumptions for Massachusetts Facilities.'
EPA needs to correct these omissions and errors for individual units prior to finalizing final state budgets in the final Transport Rule. We encourage EPA to make the revised analysis and outcomes that incorporate the corrected information for units in Massachusetts and other states available for review as soon as possible.  [EPA-HQ-OAR-2009-0491-2787.2 p.10]
A material error for Massachusetts facilities identified in EPA's Technical Support Document (TSD) State Budgets, Unit Allocations and Unit Emissions Rate concerns Brayton Point Unit 3 (ORISPL 1619). In the TSD, EPA states that Brayton Point Unit 3 is 'expected to have a dry flue gas desulfurization unit (dry scrubber) rather than a wet scrubber by 2012.,,24 EPA's TSD accurately reflects the substitution of a wet scrubber with a dry scrubber on this unit, but does it not reflect the current timetable for installation of the dry scrubber.
The current PSD approval and MassDEP modified plan approval allows the operator to begin construction of a dry scrubber by April 2011. Dominion Energy New England, Inc., the operator of the Brayton Point facility, has provided a schedule to MassDEP showing construction of the scrubber commencing in 2012 with full operation by 1st Quarter 2014. We believe that EPA's incorrect assumption concerning the timeframe for installation of the scrubber must be corrected and that the Massachusetts 2012 S02 budget must be revised accordingly.
However, for 2014 and beyond, we believe the S02 allocation for Brayton Point and the Massachusetts Annual S02 budget should reflect the reduced emissions that will result from the installation of the scrubber, which has been in the planning stage since 2002. Assuming that EP A makes the correction to the scrubber installation date and the corresponding increase in the 2012 allocation for Brayton Point Unit 3, Brayton Point will continue to receive this allocation permanently until either EPA issues a subsequent transport rule or MassDEP changes allocations through a SIP.
Because Massachusetts is in the Group 2 S02 trading program it does not have a proposed lower budget in 2014. If Massachusetts remains in Group 2 in the final Transport Rule (see our Comment #7 above concerning switching from Group 2 to Group 1), despite the significantly reduced emissions from Brayton Point Unit 3 once the scrubber is operation, the budget and allocations will not change. We do not support this result and encourage EPA to provide allowances at the 2012 level only through 2013 for this unit.
EPA's revised analysis incorporating the increased 2012 and 2013 emissions from Brayton Point Unit 3 may result in Massachusetts showing an impact on downwind nonattainment and maintenance for PM2.S in 2012. If so, EPA may place Massachusetts in Group 1 in the final rule. In this case, a reduced Massachusetts S02 budget in 2014 should take into account the installation of the scrubber and its full operation in 2014.
Salem Harbor
We note that EPA has assumed that a scrubber will be installed on Unit 3 at the Salem Harbor facility in 2012. There are no plans to install a scrubber on this unit according to comments we have received from Dominion New England, Inc.
[EPA-HQ-OAR-2009-0491-2787.2 p.10-11]
Discrepancies in Allocations
Several facilities reported common concerns and issues identified in several supporting technical documents for the Transport Rule (75 Fed.Reg. 45210, August 2, 2010), including: the Technical Support Document entitled, State Budgets, Unit Allocations and Unit Emissions Rates (July 2010); the Budgets and Allocations Detailed Unit-Level Data spreadsheet. Common concerns included:
:: Heat input generation and emissions data for Steam generator and combustion turbines at combined cycle units were divided out between the combustion turbines and frequently shared steam generator in Budgets and Allocations Detailed Unit-Level Data spreadsheet, several facilities suspected this adversely affected allocation assumptions for low emitting gas/oil-fired combined cycle units for S02 allocations;
:: The 0.000 lbs/mmBtu S02 emission rate for combined cycle units in 2012 and 2014 in the Allocations & Rate Limits tab in the Budgets and Allocations Detailed Unit-Level Data spreadsheet should be replaced with the pipeline natural gas S02 emission factor and applicable emission limit for many affected combined cycle units of 0.0006 lbs/mmBtu when firing natural gas;
:: The Budgets and Allocations Detailed Unit-Level Data spreadsheet NOx and S02 emission rates appear to assume that combined cycle units fire exclusively natural gas, although many such units throughout New England are specifically permitted to also fire distillate fuel for limited periods of time in the event of winter supply interruptions. [EPA-HQ-OAR-2009-0491-2787.2] [EPA-HQ-OAR-2009-0491-3818.1_NODA, pp.7-8]
Blackstone (ORISPL 1594)
Blackstone Units 11 and 12 located at the Harvard University steam generation plant in Cambridge, MA and serve a common steam header along with two other boilers (Units 6 and 13 not affected Transport Rule EGUs). Units 11 and 12 are allocated allowances in the proposed Appendix A, but according to the operator neither qualify as Transport Rule eligible EGUs, with a nameplate capacity equal to or greater than 25 MWe.
:: Unit 11 is a Combustion Engineering VU-60 dual fuel boiler, rated at 252 mmBtu/hr (commenced operation in 1963) firing No.6 Fuel Oil and natural gas
:: Unit 12 is a Combustion Engineering VU-60 dual fuel boiler, rated at 286 mmBtu/hr (commenced operation in 1963) firing NO.6 Fuel Oil and natural gas. Blackstone Units 11 & 12, along with other two boilers (Units 6 and 13) feed at most 5 MW back pressure to a steam turbine that generates electricity. The name plate capacity for each of the boilers is less than 25 MW. Their inclusions in the Appendix A proposed allocations is likely attributable to the fact that Massachusetts included both units in the NOx SIP Call and CAIR NOx Ozone Season control programs as noted in the Transport Rule. As the proposed Transport Rule excludes EGUs below 25 MWe and non-EGUs, neither unit should be included in the Transport Rule 502 or NOx Annual Control Programs. [EPA-HQ-OAR-2009-0491-2787.2] [EPA-HQ-OAR-2009-0491-3818.1_NODA, p.8]
Brayton Point (ORISPL 1619)
Brayton Point (ORISPL 1619) Unit 3 is listed as a 612 MWe coal steam bituminous-fired boiler, equipped with wet scrubber online in 2006 in NEEDS v.4.10 EPA-HQ-OAR-2009-0491-0310. The reported nameplate capacity is 633 MWe, and as of September 2010 no scrubber has been installed. Current PSD approval and modified plan approval allows operator to commence construction of dry scrubber by April 2011. Operator provided construction schedule indicates dry scrubber online by 1st Quarter 2014. The dry scrubber will be equipped with a fabric filter baghouse for particulate control. [EPA-HQ-OAR-2009-0491-2787.2] [EPA-HQ-OAR-2009-0491-3818.1_NODA, p.8]
Montgomery L'Energia (ORSIPL 54586)
Combined cycle Rolls Royce Trent 60 with 545 mmBtu/hr maximum heat input, commenced operation in 2008. Allocated no allowances despite having higher 2009 heat input than other unit types having lower heat inputs. [EPA-HQ-OAR-2009-0491-2787.2]
We have provided above the corrections for NEEDS vA.l0 for this facility, noting that Montgomery L'Energia (ORSIPL 54586) Unit 2 was omitted from NEEDS v4.10 EPA-HQ-OAR-2009-0491-0310. The facility commenced commercial operation on October 29, 2008. We include the following data to demonstrate recent operations of the facility. [EPA-HQ-OAR-2009-0491-3818.1_NODA, p.9]
Mystic Station (ORISPL 1588)
Units 81, 82, 93, and 94 averaged 4.48 tons S02and average over 14,500,000 mmBtu heat input in 2009, but were allocated no 502 allowances, despite being intermediate- to base-loaded in dispatch. [EPA-HQ-OAR-2009-0491-2787.2]
We have provided above the corrections that are needed in NEEDS v4.10 for this facility. Units 81, 82, 93, and 94 (1558_G_GT81, 1558_G_GT81, 1558_G_GT93, 1558_G_GT94) are combined cycle units, consisting of a Mitsubishi Heavy Industries 501G combustion turbine and heat recovery steam generator with supplemental duct burners having in combination a maximum heat input of 2,995 mmBtu/hour HHV when firing natural gas, and a maximum heat input of 2,734 mmBtu/hour HHV when firing distillate oil. These units averaged 4048 tons S02and over 14,500,000 mmBtu heat input in 2009, but were allocated no S02 allowances, despite being intermediate- to base-loaded in dispatch. We are including the following data to demonstrate recent operations of the facility. [EPA-HQ-OAR-2009-0491-3818.1_NODA,pp.9-10]
Pittsfield Generating (ORISPL 50002)
Inconsistent allocation Units 1, 2, 3, received 1, 1, and 2 NOx allowances despite near identical operations and heat input. Doesn't agree with allocation methodology. [EPA-HQ-OAR-2009-0491-2787.2 p.13-17]
The operator reported an adjustment made in reported annual NOx emissions for units with SCRs installed prior to 2009 to equal the ozone season NOx emission rate. EPA also added another unit (50002_G_GEN4) to account for the steam turbine generator output and assigned reported and projected emissions. Assigning emissions to an unfired steam turbine generator is inappropriate and emissions should be allocated in NEEDS v.4.10 to the combustion turbine reporting the emissions. MassDEP agrees with the operator and recommends attributing all emissions and heat input to the fired generating units. [EPA-HQ-OAR-2009-0491-3818.1_NODA, p.10]
Kendall Square (ORISPL 1595)
Kendall Square (ORISPL 1595) Unit 4 (1595_G_GEN4), is a combined cycle unit consisting of a General Electric 7241 FA combustion turbine with a nominal output of 170 MWe and a maximum heat input of 1,766 mmBtu/hour HHV when firing natural gas, and a maximum heat input of 1,927 mmBtu/hour HHV when firing distillate fuel oil. A heat recovery steam generator with supplemental duct burners has maximum heat input of 350 mmBtu/hour HHV when firing natural gas. In their Transport Rule comments, the operator reports a significant discrepancy between NOx allocations for Unit 4 Unit 4 (1595_G_GEN4) and other similar combined cycle units operating elsewhere in Massachusetts, as demonstrated in the following table. [EPA-HQ-OAR-2009-0491-3818.1_NODA, pp.8-9] [[See Docket Number EPA-HQ-OAR-2009-0491-3818.1_NODA, p.9 for the table.]]
With respect to IPM, we recommend that EPA examine the work of the Regional Greenhouse Gas Initiative (RGGI) and the use of IPM for the RGGI 2012 program review. We suggest that EPA review the following attached documents presented at the September 13, 2010 RGGI stakeholder meeting. (These documents are available at www.rggLorg/stakeholder meeting.) [EPA-HQ-OAR-2009-0491-3818.1_NODA, cover letter]
:: A slide presentation entitled Assumptions Development for IPM Modeling to Support RGGI Program Review, September 1,2010. MassDEP believes these assumptions reflect appropriate considerations for the ten state RGGI Region and differ from those assumed by EPA. [[See Docket Number [EPA-HQ-OAR-2009-0491-3818.2_NODA for attachment.]
:: Another slide presentation entitled 'Additional slides presented at stakeholder meeting' describes how energy efficiency and other variables should figure into IPM modeling. [[See Docket Number EPA-HQ-OAR-2009-0491-3818.5_NODA for attachment.]]
:: A spreadsheet entitled 'RGGI Firm Capacity and Retirement Assumptions -Draft' provides a list of new capacity assumptions and a list of firm retirements and fuel switching assumptions. [[See Docket Number EPA-HQ-OAR-2009-0491-3818.4_NODA for attachment.]]
Finally, we suggest that EPA consult the RGGI website for updates to RGGI's IPM modeling assumptions. Updates will be posted before and following a November 12th stakeholder meeting. EPA may also want to review comments submitted to RGGI Inc. after the September stakeholder meeting; those can be found on the same website. [EPA-HQ-OAR-2009-0491-3818.1_NODA, cover letter.]
MIT Central Utility Plant
The MIT-CUP houses and operates a combustion turbine with a supplementary-fired heat recovery steam generator (cogeneration unit) used to supply both electricity and steam to the MIT campus. The combustion turbine is rated at 22 MW output and 229 mmBtu/hr input. while the heat recovery steam generator (HRSG) is rated at 210.7 mmBtu/hr input (64.7 mmBtu/hr from the supplemental duct burners and 146 mmBtu/hr from the combustion turbine hot exhaust gases). The cogeneration unit fires natural gas as the primary fuel and when natural gas is unavailable the secondary fuel is transportation diesel fuel with a sulfur content not to exceed 0.05 weight percent. [EPA-HQ-OAR-2009-0491-2870.1 p.1]
The cogeneration unit (ORIS Code 54907) is currently subject to the 310 CMR 7.32 Massachusetts Clean Air lnterstate Rule (CAIR) since the Massachusetts CAIR applicability requirements include combustion units rated greater than or equal to 15 MW. Since EPA has requested cogeneration units report equivalent load within the quarterly Electronic Data Report (EDR), most recently within the April 2010 Part 75 Emissions Monitoring Policy Manual Question 17.2, the cogeneration unit's total load data (i.e. Megawatts from the combustion turbine + Equivalent Megawatts from the HRSG) are reported within the EDR. Although the cogeneration unit's total load reported within the quarterly EDR is greater than 25MW, as mentioned above, the rated output of the combustion turbine is 22MW and does not satisfy the 25 MW threshold for applicability under the Proposed Clean Air Transport Rule (CATR). [EPA-HQ-OAR-2009-0491-2870.1 p.1]
Since the cogeneration unit at the MIT·CUP does not meet the applicability criteria of the Proposed CATR, we want to point out that within the Budget and Allocations - Detailed Unit Level Data spreadsheet, MIT-CUP is currently listed by EPA as an EGU receiving 2012 NOx allocations (i.e., 56 NOx allowances) under the CATR, Considering the combustion turbine at MIT is rated at 22 MW and does not satisfy the CATR applicability requirements, we are requesting that EPA remove the MIT·CUP cogeneration unit from the CATR data analysis. [EPA-HQ-OAR-2009-0491-2870.1 p.2]
Morgantown Energy Associates
In its proposed allocations, EPA has not provided allowances for Morgantown Energy Center (ORIS Plant Code: 10743) located in Morgantown, WV. We believe EPA may have assumed that the facility is exempt from the CATR requirements under the proposed provisions of the rule that exempt certain cogeneration units. The exemption for cogen units is provided in the applicability provisions of the proposed Transport Rule (proposed Section 97.404(b)(1)(i) for the Annual NOx subpart, proposed Section 97.504(b)(1)(i) for the Ozone Season subpart; and proposed Section 97.604(b)(1)(i) for the Annual S02 subpart), which state that a unit meeting the following requirements shall NOT be a 'transport rule' unit: [EPA-HQ-OAR-2009-0491-2826.1, p. 1]
Any unit (A) qualifying as a cogeneration unit during the later of 1990 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a cogeneration unit; and (B) not serving at any time, since the later of November 15, 1990 or the start-up of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe supplying in any calendar year more than one-third of the unit's potential electricity output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale. [EPA-HQ-OAR-2009-0491-2826.1, p. 1]
We do not believe that Morgantown meets the proposed applicability exemption for cogeneration facilities by virtue of Part (B) of the applicability provisions above. Morgantown is a cogeneration facility that is comprised of two CFB boilers feeding a single steam turbine generator as well as a steam system for West Virginia University (WVU). The electric generator is under contract to MonPower to provide SOMW of baseload electricity until 2027. Additionally, the project is under contract with WVU to provide steam to the University until 2027. These contracts have been in place since the early 1990's. Capacity factors for the electric generator have been consistently well above 50% which approximately equates to the 219,000 MWh exemption level. We also note that EPA included this facility (for these reasons) as an affected facility under the NOx SIP Call and CAIR. As such, this facility should be treated as a CATR-affected facility and EPA should allocate appropriate 502 and NOx allowances to this facility. [EPA-HQ-OAR-2009-0491-2826.1, p. 2]
Specifically, the Excel spreadsheet contained on the EPA web page and referenced as 'Budget and Allocations - Detailed Unit-Level Data (Excel)' includes a listing of each unit for which allocation data was determined. The following comments are provided with regard to allocation calculations in that spreadsheet and final Allocations Table provided in the docket. The worksheets provide data and analyses for the facility's two boilers (CFB1 and CFB2). However, in the final worksheet entitled 'Allocations & Rate Limits' and in the final Allocation Table provided in the docket, the table lists zero allocations for these units under each of the four programs - Annual NOx, Ozone Season NOx, 2012 502, and 2014 502. There is no explanation to account for the removal of the allocations for these units. [EPA-HQ-OAR-2009-0491-2826.1, p. 2]
Morgantown Energy Associates requests that EPA review this worksheet and provide the allocations as indicated and calculated in the previous worksheets. Based on review of similar units, the allocations would be calculated as 97% of the Reported Annual and Ozone Season NOx - Adjusted for controls and heat input, and as 97% of the Adjusted Annual S02 - Projected Base Case, as provided below. The calculation methodology for the 2014 and Beyond S02 allowances could not be determined. [EPA-HQ-OAR-2009-0491-2826.1, p. 2; see p. 2 for table of allocations.]
New York Power Authority
The EPA did not consider important contractual obligations when allocating emission allowances to individual units.
The Richard M. Flynn Combined Cycle (Flynn) unit is a 150MW dual fired unit, capable of firing natural gas and 0.2 % sulfur distillate oil. The sale of electricity produced by the Flynn plant is covered by a long term Capacity Supply Agreement (CSA) and amendments between NYPA and the Long Island Power Authority (LIPA) effective through April 30, 2020. The Authority also has a contractual obligation to provide natural gas peaking services to the local gas distribution company (National Grid) for up to thirty (30) days each year during winter months. As a result, the Authority normally sustains operation of Flynn with distillate fuel oil for up to thirty days each winter. The permit limit for NOx when the unit is burning natural gas is 9 ppm and 42 ppm when the unit is burning fuel oil. [EPA-HQ-OAR-2009-0491-3820, pp.1-2]
Table 1 shows wide disparity between the EPA's proposed allowance allocations to Flynn and the average actual three year emissions. With the EPA proposed NOx and 802 allocations NYPA would expect to curtail the facility's operations in order to comply. [EPA-HQ-OAR-2009-0491-3820, p.2] [[See Docket Number EPA-HQ-OAR-2009-0491-3820, p.4 for Table 1.]]
Table 2 compares the actual heat inputs for the recent three years, and shows EPA's predicted heat inputs for 2012 and beyond. Comparison of heat inputs clearly indicates that EPA's model predicted that the unit will operate only at an approximately 10% capacity factor. [EPA-HQ-OAR-2009-0491-3820, p.2] [[See Docket Number EPA-HQ-OAR-2009-0491-3820, p.5 for Table 2.]]
Table 3 shows ozone season heat inputs for the most recent three years and EPA predicted ozone season heat inputs. During ozone season the predicted ozone season heat input results in approximately 18% of the historical ozone season heat input. The EPA predicted ozone season heat input and ozone season NOx allowances will allow NYPA to operate the unit for approximately 25 days of ozone season. It appears the major discrepancy could be that the facilities permit conditions (and contractual agreements) were not considered. Further EPA allocates no S02 allowances for the year 2014 and beyond, indicating that the unit cannot burn fuel oil beginning in 2.014. [EPA-HQ-OAR-2009-0491-3820, p.2] [[See Docket Number EPA-HQ-OAR-2009-0491-3820, p.6 for Table 3.]]
The EPA's IPM predicted System heat inputs that are well below historical figures.
NYPA reviewed the EPA's projected heat inputs for the entire NYPA system as well as individually for three units and found them unrealistically low. [EPA-HQ-OAR-2009-0491-3820, p.2]
The reported total NYPA system heat input for the year 2008 was 59,420,994 mmBtu. The original EPA IPM modeling predicted 30,716,418 mmBtu heat input for the year 2014, and the recently revised model predicted 14,135,352 mmBtu for the year 2014, which is approximately 24% of the NYPA reported 2008 heat input. [EPA-HQ-OAR-2009-0491-3820,p.2]
More specifically, in reviewing EPA's heat input predictions for Flynn, NYPA found that the figures drastically underestimates its operation. This units 2008 reported annual heat input was 9,852,938 mmBtu, EPA's original model run predicted 1,007,100 mmBtu for the year 2014 (approximately 10% of the 2008 reported heat input). The revised EPA's model predicted the 2014 heat input to be 293,843 mmBtu for the year 2014 (0.03% of the 2008 reported heat input). A heat input of that size would severely limit Flynn's ability to operate, and the unit would not be able to meet its contractual obligations with LlPA and National Grid, which currently require it to operate the majority of the time. [EPA-HQ-OAR-2009-0491-3820, p.2]
In addition, the revised model assumes most of the units run on natural gas for economic reasons (EPA revised model assumes natural gas prices will be 30-40% lower in real terms than in the original runs), which is not true in the case of Flynn unit since it runs based on its contractual agreement with LIPA and National Grid. The Flynn unit's permit allows it to operate on 0.2%sulfur fuel oil, which it generally does during winter months. But EPA did not assign 802 allowances in 2014. Again, this methodology, if implemented, would hinder NYPA's ability to operate and meet its contractual obligations. EPA's original model of NYPA's 500 MW Combined Cycle unit predicted 23,915,000 mmBtu heat input in 2014 compared to NYPA's 2008 reported heat input was 19,723,520 mmBtu. The revised EPA model predicted an even lower heat input of 10,388,835 mmBtu in 2014, which is approximately 53% of the 2008 reported heat input value. This unit is also dual fired and permitted to burn 0.04% kerosene for 30 days a year. With zero 802 allowances assigned to the 500 MW Combined Cycle plant, NYPA's ability to provide reliable power during the winter months and responsibly hedge fuel purchases for New York City governmental customers would be jeopardized despite appropriate permitting authorization. [EPA-HQ-OAR-2009-0491-3820,p .2]
North Carolina Department of Environment and Natural Resources
In reviewing the Technical Support Documentation (TSD) table entitled Allocation Table it appears that the NC EMC Anson Plant has been double counted by also listing it as Anson County Generation Facility. The table did not include several EGUs subject to CAIR, including; Craven County Wood Energy, Primary Energy Roxboro and Primary Energy Sonthport. Additionally, Progress Energy's Cape Fear Unit #5 has NOx allocations, but no S02 allocations. It is our understanding this coal-fired unit will continue to operate in 2012 and 2014 and thus an S02 allocation is needed. We also note that the TSD assumes Duke Energy's Dan River 3 will install and operate an SCR system to control NOx in 2012. Duke has indicated that this unit will limit NOx emissions through the use of Low NOx burners in their CSA filings with North Carolina and not SCR as is indicated in the TSD. Finally, the table included 2 facilities (VACA NC Combustion Turbine and Wayne County) that are not subject to CAIR.  [EPA-HQ-OAR-2009-0491-2767.1 p.4]
NRG Energy
NRG believes the IPM model results and allocations for NRG's Indian River Units 3 and 4 (IR3 and IR4) warrant revision. IR3 was originally scheduled for emission control technology starting January 1, 2012. This control technology is reflected in EPA's IPM work, and in the July 6, 2010 allocation table IR3 received allocations based on having these controls and associated resulting emissions rates. Effective July 16, 2010, however, a Consent Order between the Delaware Department of Natural Resources and Environmental Control and Indian River Power LLC revised the future operating characteristics for IR3. No additional emissions controls beyond those already installed and in use at the facility (including year round SNCR, Low NOx Burner and Over Fire Air Technology) will be installed. The unit's NOx limit is 0.3 lbs/mmBtu. For SO2, IR3 has a sulfur in coal limit of 1.2% sulfur content to achieve a representative 1.7 lb/mmBtu emission rate. Finally, IR3 will cease operations on December 31, 2013. These operational changes should be included in EPA's modeling. [EPA-HQ-OAR-2009-0491-2749.1, p. 7]
IR4 received an allocation in the July 6, 2010 allocation table associated with the proposed Rule. However, it shows to have no operations in the output file associated with the NODA, and therefore under this revised modeling it would not receive an allocation. It appears EPA believes this unit is scheduled for retirement. The unit is not scheduled for retirement in the 2012  -  2014 timeframe covered by the NODA. NRG is investing $360 million in back-end controls which will be in service by January 1, 2012. The assumptions on the IR4 emission rates based on the installation of emissions controls are correct. [EPA-HQ-OAR-2009-0491-2749.1, p. 7]
It appears that certain alternate capacity projects in PJM are not modeled correctly. The proposed MAPP transmission line 2015 and offshore wind development (2016) have revised installation schedules. This impacts projected emissions from the Indian River Generating Station. While coal fired generation operating hours have been impacted by lower than usual natural gas pricing and a slow economy, NRG anticipates Indian River to maintain a capacity factor near 50% which is lower than the typical 60%. [EPA-HQ-OAR-2009-0491-2749.1, p. 7]
Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
Finally, it appears that EPA failed to account for the fact that all of the OVEC Units are equipped with wet-bottom boilers. As EPA has previously acknowledged, units with wet-bottom boilers are inherently higher NOx emitters than dry-bottom boilers. As part of the Acid Rain NOx Emission Reduction Program, EPA made a clear distinction between wall-fired and tangentially fired boilers (Group 1 boilers) and wet-bottom, cyclone, and cell burner boilers (Group 2). 61 Fed. Reg. 67,113 (Dec. 19,1996). The Group 2 Emission Limit was almost twice that for the Group 1 boilers, yet EPA now ignores those differences. 61 Fed. Reg. 67,113-14 (0.46 Lb/mmBtu for Group 1,0.84Ib/mmBtu for Group 2). EPA must acknowledge and account for the basic physical differences between different types of boilers that have an important effect on achievable NOx emission rates in order to set any meaningful emission reduction targets. EPA therefore greatly underestimated the number of allowances that should be allocated to the OVEC Units. EPA has also overestimated the achievable emission rates achieved by OFA and SCR technologies combined on these types of units. [EPA-HQ-OAR-2009-0491-2803.1, pp.4-5]
EPA should correct the factual mistakes it made about the OVEC Units. These corrections will change the OVEC unit allowance allocations that EPA proposes. However, OVEC still believes there are fatal problems with the Proposed Transport Rule as it is currently proposed. OVEC now turns to the emission reduction caps EPA is attempting to impose in 2012 and 2014. [EPA-HQ-OAR-2009-0491-2803.1, p.5]
Neither Clifty Creek or Kyger Creek have met the proposed emissions allocations in any of the past five years, despite having operated in each of the past five years with the very controls assumed by EPA in the Proposed Transport Rule. While some of the problem may be explained by EPA's failure to consider the fact that the units have wet-bottom boilers, as discussed above, OVEC believes the NOx allocations under the Proposed Transport Rule are inadequate and must be reassessed considering the known facts so that OVEC's eleven units - ten of which are fully controlled for NOx with OFA and SCR technology - are not forced into non-compliance by EPA's mistakes. [EPA-HQ-OAR-2009-0491-2803.1, p.7]
Further complicating the S02 allocation problems is the fact that OVEC is a small utility with only two plants in the adjacent states of Ohio and Indiana. Under the Proposed Transport Rule, OVEC will have no ability during or after 2014 to trade S02 allowances between its units located in different states. At the very least, EPA should provide an exemption to utilities that operate units in adjacent states to allow for unrestricted intra-company trading after 2014. Once EPA reassesses its allocations based on the corrected facts and the FGDs are complete and operating at both Kyger and Clifty, there may be an opportunity for some S02 allocation trading between the plants, and even for NOx trading if the allocations are properly adjusted in the final rule. [EPA-HQ-OAR-2009-0491-2803.1, p.8]
Potomac Power Resources
Additionally, there appears to be two errors found in the data matrix for this facility:
1. The 'Heat Input Assumption for Ozone NOX Season Allocation' is missing for both Unit ID's 15 and 16. There is 'Heat Input Assumption for Annual NOX Allocation', so this is an obvious error.
2. There have been no 'Ozone Season NOX Rates' set for either Unit ID's 15 and 16. There are 'Annual NOX Rates' set for both Units, so this is an obvious error. [EPA-HQ-OAR-2009-0491-3017,p.1]
Prairie State Generating Company, LLC
Prairie State Generating Company, LLC ('PSGC') is a new, mine-mouth, coal-fired electric generating station located in Washington County, Illinois. PSGC has 'planned units' as described in footnote 85 of the proposed Transport Rule at 75 Fed. Reg. 45309 (August 2, 2010). One of the two units at PSGC will go online in 2011 and, therefore, will be an 'existing' unit subject to the Transport Rule as proposed. The U.S. Environmental Protection Agency has apparently not recognized PSGC, as it has not proposed any allowances to be allocated to PSGC Unit 1. Therefore, it is incumbent upon PSGC to propose the appropriate number of allowances to be permanently allocated and to provide the necessary support and justification for that level of allocation.  [EPA-HQ-OAR-2009-0491-1026.1, p.1]
Rochester Public Utilities (RPU)
RPU strongly disagrees with the sulfur dioxide (SO2) and nitrogen oxides (NOx) allocations listed in technical support document, "Budgets and Allocations  -  Detailed Unit-Level Data," (EPA-HQOAR- 2009-0491-0074.1) for Silver Lake Unit 4 (ORIS 2008). More specifically, RPU disagrees with EPA's proposed allocation of zero SO2 allowances under the proposed Transport Rule. Although Silver Lake Unit 4 received an allocation of NOx allowances in the Transport Rule, these too are under allocated. RPU expended $38 million over the past 5 years to retrofit Unit 4 with an AQCS that would meet CAIR requirements for SO2 and NOx. However, the allowance allocations, or lack thereof, for RPU under the currently proposed Transport Rule would apply an undue burden upon the citizens of Rochester, MN by requiring additional expenditures in order to operate a unit with a state of the art AQCS and meet the requirements of the Rule. In a worst-case scenario, Silver Lake Unit 4, and its multi-million dollar AQCS, could be shut down due to the unavailability of allowances or the restrictive budget for the State of Minnesota. [EPA-HQ-OAR-2009-0491-2802.1,p.2]
RPU is also concerned that the IPM Modeling does not accurately reflect the SO2 and NOx controls on Silver Lake Unit 4. This information does not appear to be accurately listed in the "Unit Characteristics" tab in the "Budgets and Allocations  -  Detailed Unit-Level Data" technical support document. Pre 2009 controls on Unit 4 consisted of an ESP for control of Particulate Matter and Low NOx Burners for NOx control. The emission controls on Unit 4 starting in 2009 include SNCR with urea injection and overfire air for NOx control (partially operational in the first half 2009, fully operational in the second half 2009), a SDA for removal of acid gases, and a pulse jet fabric filter baghouse (PJFF) for the removal of PM and Hg.  [EPA-HQ-OAR-2009-0491-2802.1,p.5]
Table 4 is a comparison of units in Minnesota similar to Silver Lake Unit 4. This table illustrates that there is no apparent consistency in the way that the IPM modeling distributed the allocations. [EPA-HQ-OAR-2009-0491-2802.1,p.5] [[See Docket Number EPA-HQ-OAR-2009-0491-2802.1, p.5 fpr Table 4.]]
Based on the comparison of Table 4, it appears RPU is effectively penalized for installing an AQCS. The consequence of this is Silver Lake Unit 4 will not have allowances needed to operate, whereas units with no or less investment in S02 and NOx emission control have substantial allowances allocated. [EPA-HQ-OAR-2009-0491-2802.1,p.6]
Sabine Cogen, LP
On behalf of Sabine Cogen, LP, owner of the Sabine Cogeneration Facility (Sabine), Consolidated Asset Management Services respectfully requests that your office review the Environmental Protection Agency's (EPA) database inputs used to calculate the nitrogen oxides (NOx) allocations under the proposed Transport Rule (Federal Register, Vol. 75, NO. 147, Monday, August 2,2010, Proposed Rules, Environmental Protection Agency, 40 CFR Parts 51,52,72,78 and 97, Federal Implementation Plans to Reduce Interstate transport of Fine Particulate Matter and Ozone). [EPA-HQ-OAR-2009-0491-2982.1,p.1]
All comments provided in this letter are related to ORIS code 55104 and the following units:
:: Sabine Cogen Unit SAB1;
:: Sabine Cogen Unit SAB2; and
:: Sabine Cogen Unit STG. [EPA-HQ-OAR-2009-0491-2982.1,p.1]
Errors related to the Air Transport Rule, Technical Information section of the EPA website (http://www.epa.gov/airguality/transport/tech.html). document Budgets and Allocations - Detailed Unit-Level Data (Excel), are identified in this letter and the attached supporting calculations. In particular, the STG is not an affected source under the Transport Rule. Emissions attributed to this unit should actually be attributed to unit SAB1, in addition to those already represented. Sabine respectfully requests that EPA consider the information contained in this submittal, so that the appropriate number of Transport Rule Ozone Season NOx allowances may be allocated. [EPA-HQ-OAR-2009-0491-2982.1, p.1]
San Miguel Electric Cooperative, Inc.
San Miguel is located in Texas and per the unit allocation table is allocated allowances on reported data. Since units could be allocated on projected data our review included a review of the projected data. San Miguel discovered errors in the review of the following Technical Support Documents (TSD): Budget and Allocation  -  Detailed Unit-level data; and the IPM parsed files for the TR base case, SB limited trading case, Intrastate trading case and direct control case. The discovered errors are for the San Miguel generating unit and require correction. The ID number for the San Miguel generating unit is 6183_B_SM-1. [EPA-HQ-OAR-2009-0491-2641.1,p.2]
1) The following corrections to the TSD "Budget & Allocation Detailed Unit  - Level Data" spreadsheet are required:
-Sheet titled "Unit Characteristics"; column titled "Projected Base Case Non-Dispatchable SCR Retrofit" shows the San Miguel unit has an SCR. The unit does not have an SCR, nor is one under construction and there is no plan to install an SCR.   
-Sheet titled "Projected Data", columns titled Proj Base Case  -  Ozone Season and Annual for both Heat Input and NOx Mass and Annual SO2 Mass are all very low compared to historical (reported) data. The table below compares these values to the most recent four quarters, as stated on the "Reported Data" sheet:   [EPA-HQ-OAR-2009-0491-2641.1, p.2][[See Docket Number EPA-HQ-OAR-2009-0491-2641.1, p.3 for the Table.]]
In the above table you will note the large deviation in all values between projected data and reported data:  
-Projected ozone season heat input (corrected) is 61.3% of the reported data  
-Projected annual heat input is 31.5% of the reported data  
-Projected ozone season NOx mass is 56.7% of the reported data  
-Projected annual NOx mass is 28.1% of the reported data  
-Projected annual SO2 mass is 7.1% of the reported data   [EPA-HQ-OAR-2009-0491-2641.1, p.3] 
For the above reasons San Miguel requests that the heat inputs be corrected, the SCR be deleted and the SO2 mass emissions be corrected to reflect actual fuel and scrubber performance in the Projected Base Case and all other IPM model runs. After this is corrected the revised mass NOx and SO2 values need to be reviewed to ensure the results are indicative of how the unit is actually run. [EPA-HQ-OAR-2009-0491-2641.1, p.4]
Selkirk Cogeneration Project (SCP)
1) In the Budgets and Allocations Detailed Unit-Level Data spreadsheet, EPA divided the reported and projected emissions and heat input data for the Phase I unit between the combustion turbine generator (GEN1) and the steam turbine generator (GEN2), but no allocations were assigned to GEN2. Additional allocations need be assigned to the facility in accordance with the procedures in the TSD, based on the heat input and emissions data assigned to GEN2. [EPA-HQ-OAR-2009-0491-2816.1, p.1]
2) In the Budgets and Allocations Detailed Unit-Level Data spreadsheet, an adjustment is applied for GEN 1 and GEN2 to the projected Annual NOx Mass Emissions for 'Existing/committed SCR (non-dispatchable)'. Per the Data Fields Description document, this adjustment 'is made to 2012 projected annual NOx emissions in TR Base Case for units with non-dispatchable SCR expected online by 1/1/2012', but the Phase I Unit does not incorporate SCR and no additional emission controls are required or planned for implementation during the stated timeframe. [EPA-HQ-OAR-2009-0491-2816.1, pp.1-2]
3) In the Budgets and Allocations Detailed Unit-Level Data spreadsheet, the NOx Annual and OS allocations were based on the projected data. The NOx emission rate used in the projected data calculation is grossly underestimated. It appears that the NOx emission rate underestimation may be the result of a decimal point error. SCP recommends assigning a NOx emission rate consistent with the reported emission rate for the facility. [EPA-HQ-OAR-2009-0491-2816.1, p.2]
4) In the Budgets and Allocations Detailed Unit-Level Data spreadsheet, the S02 emission rate assigned to the Phase II Units (GEN3, GEN4 and GEN5) under the Direct Control Option is'0.000 lb/MMBTU'. While SCP Phase II has low emission rates, they are greater than zero. Since the Direct Control Option has no provisions for trading, the facility would not be able to comply with a limit of zero. SCP recommends assigning an S02 emission rate for low emitting facilities based on the highest fuel sulfur content the unit is permitted to combust. [EPA-HQ-OAR-2009-0491-2816.1, p.2]
5) In the Budgets and Allocations Detailed Unit-Level Data spreadsheet, EPA divided the reported and projected emissions and heat input data for combined-cycle facilities between the combustion turbine generator(s) and the steam turbine generator(s). This methodology is questionable because a steam turbine primarily uses waste heat from the combustion turbine generator (plus some supplemental firing in the heat recovery steam generator) and all emissions reported under the current CAIR Program are attributed to the combustion turbine (and duct burners, as applicable) as a single unit. SCP recommends attributing all emissions and heat input to the fired generating unit. [EPA-HQ-OAR-2009-0491-2816.1, p.2]
6) The 2012 S02 allocation for the facility in the Budgets and Allocations Detailed Unit-Level Data spreadsheet is '1'. This is a result of the facility's low S02 emission rate and the rounding conventions used in the calculations. Because the facility would need to purchase allocations for any S02 emissions, this disadvantages units with low S02 emission rates. SCP requests that appropriate S02 allocations be assigned to the facility. [EPA-HQ-OAR-2009-0491-2816.1, p.2]
7) In the Budgets and Allocations Detailed Unit-Level Data spreadsheet, an adjustment is made to the reported Annual NOx emissions for units with pre-2009 SCRs to adjust the annual NOx emission rate to be equal the ozone season NOx emission rate. This adjustment is not appropriate. There are reasons for combined cycle generating units to have different emission rates during the ozone season and the non-ozone season periods, including: [EPA-HQ-OAR-2009-0491-2816.1, p.2]
Combustion turbines are more efficient with low ambient temperatures and may therefore have a higher firing rate and NOx emissions during colder periods.   b. Dual fuel capable generating facilities may utilize backup fuels such as distillate oil, which typically result in a higher NOx emission rate, during winter periods or when natural gas supply is curtailed.   [EPA-HQ-OAR-2009-0491-2816.1, p.2]
The adjustment of reported annual NOx emissions can impact the economic dispatch of units, particularly on alternate fuel, and could affect electrical system reliability. SCP recommends removing this adjustment. [EPA-HQ-OAR-2009-0491-2816.1, p.3]
Seminole Electric Cooperative Inc.
a. Seminole Generating Station
Background. The Seminole Generating Station contains two coal-fired electric generating units nominally rated at over 700 MW each. These two base load units have historically operated at a capacity factor between 80 and 85 percent, and supply approximately 60 percent of the energy needs of Seminole's distribution cooperatives. These two units were in commercial operation by the end of 1984, and were initially permitted under the federal PSD program. Accordingly, these units are subject to Best Available Control Technology limitations, 40 CFR Part 60, Subpart Da, the Acid Rain Program and several state-imposed emission limitations, all of which are contained in Title V Permit No. 1070025-0 15-AV. Both units were initially equipped with limestone slurry FGD systems capable of achieving 90 percent S02 removal. Recent upgrades to the FGD systems, in part to comply with CAIR, raised the removal efficiency to approximately 92 percent. These units were also initially equipped with ESPs to control particulate matter, and over the last several years have added 10w-NOx burners, over fire air controls, and SCRs to control NOx, and an alkali injection system to control sulfuric acid mist emissions. These upgrades and new controls cost Seminole approximately $275,000,000. [EPA-HQ-OAR-2009-0491-2632.1, pp.2-3]
Each unit burns approximately 2 million tons of coal per year, which primarily comes from western Kentucky and southern Illinois. After coal washing, the sulfur content of this fuel is approximately 3 percent by weight. These units are also authorized to burn up to 30 percent petroleum coke by weight, which cannot exceed 7 percent sulfur by weight. Seminole is subject to a long-term contract for over 60 percent of its coal supply, and has been contracting with this coal supplier since 1982. [EPA-HQ-OAR-2009-0491-2632.1, p.3]
Unit 1 and 2 Actual Emissions and EPA's Proposed 502 Allocation. In a Technical Support Document referenced in EPA's August 2 proposal, Seminole Units 1 and 2 are allocated 2105 and 2072 S02 allowances, respectively. Yet, in 2009, utilizing their recently-upgraded FGD systems and substantially lower-than- historical capacity factors, these units emitted 7,709 and 12,867 tons of S02, respectively. As stated, 2009 is not a representative year for emissions from Units 1 or Unit 2, as the units operated less than they had in any of the prior five years. Unit 1 operated only 5,138 hours due to several major extended outages to repair the unit. Unit 2 operated 7,210 hours, which again is less than it has in the prior 5 years, due to extended outages to fix turbine vibrational problems and to tie-in the new SCR system. The actual 2009 heat input for Units 1 and 2 was 29,206,824 and 45,703,994, respectively. EPA's 2012 projected heat input is actually closer to the historical/representative capacity of these units. [EPA-HQ-OAR-2009-0491-2632.1,p.3] [[See Docket Number EPA-HQ-OAR-2009-0491-2632.1, p.3 for the chart.]]
As this chart shows, EPA projects that in 2012, Units 1 and 2 will have 22 percent greater heat input than in 2009, yet their emissions will be 80 percent less. And this is for Units that have been scrubbed since they came online 25 years ago, and had a significantly reduced output in the chosen year (2009). There is obviously a fundamental flaw in EPA's analysis - EPA's proposed allocation (i.e., emission levels) is inequitable and unachievable. In order for Seminole to lower its emissions to the level of EPA's allocation, it would have to either replace or install an additional FGD system, change the fuel quality, or substantially de-rate the unit. And as explained below, changing fuel quality would impact the operation of the FGD and SCR controls, lower the efficiency of the unit, and require new coal and coal transportation arrangements and contracts. [EPA-HQ-OAR-2009-0491-2632.1, pp.3-4]
Midulla Generating Station
Seminole has also identified numerous errors and issues associated with EPA's data and assumptions related to Seminole's Midulla Generating Station, as explained below.
1) Combined Cycle Units: CT1, CT2, ST3
i. The heat input value used to calculate the annual NOx allocation reflects the heat input from only CT1 and does not include that of CT2. Therefore the proposed NOx allocation is artificially low.
ii. The annual S02 annual allocation calculation utilized a combined annual heat input for CT1 and CT2 of approximately 20,000,000 mmBtu. The annual heat input utilized for the calculation of the annual NOx allocation is approximately 11,600,000 mmBtu, which reflects the heat input from only one CT and reduces the NOx allocation by approximately one-half of what it should be.
iii. The heat input value used to calculate the ozone season NOx allocation is approximately 1,400,000 mmBtu less than the amount reported for 2009. In 2009, Seminole reported that the heat input for the 2009 ozone season for the combined cycle unit at the Midulla Generating Station was approximately 7,315,000 mmBtu. The NOx ozone season allocation used a heat input of 5,900,000 mmBtu, resulting in an artificially low allocation of NOx ozone season allowances. [EPA-HQ-OAR-2009-0491-2632.1,p.6]
2) Aeroderivative Units: GT 4-GT8
i. The heat input used to calculate the annual NOx allocation is based on the heat input from 1 of the 10 engines that comprise GT 4-GT8, resulting in a significantly lower amount of annual NOx season allowances. GT 4-GT8 are five Pratt & Whitney FT8-3 combustion turbines. Each FT8-3 has two engines that drive a single turbine. The 2009 heat input submitted to EPA by Seminole shows that GT4-GT8 units utilized approximately 4,500,000 mmBtu. The heat input EPA utilized to calculate the NOx annual allowance allocation in the Transport Rule was approximately 530,000 mmBtu, which is reflective of the heat input from only one of the 10 engines that make up GT 4-GT8. [EPA-HQ-OAR-2009-0491-2632.1, pp.6-7]
ii. The heat input used to calculate the ozone season NOx allocation is also based on the heat input from 1 of the 10 engines that comprise GT 4-GT8, resulting in a significantly lower amount of ozone season NOx allowances. The 2009 heat input data submitted to EPA by Seminole shows that approximately 2,900,000 million BTUs were utilized by GT4-GT8. EPA used a heat input value of 375,000 million BTUs to calculate the ozone season NOx allowances in the Transport Rule which is reflective of the heat input from one of the 10 engines. [EPA-HQ-OAR-2009-0491-2632.1, p.7]
Accordingly, EPA's data and assumptions for the Midulla Generating Station must be corrected. And Seminole must be given an opportunity to review EPA's corrections and revised allocations, for accuracy and achievability, prior to this rule becoming final. [EPA-HQ-OAR-2009-0491-2632.1, p.7]
Shell Chemicals
Shell Chemical LP (Shell) owns and operates a chemical manufacturing complex located in Geismar, Ascension Parish, Louisiana. The facility is operated for the manufacture of olefins, specialty alcohols and ethoxylates, ethylene oxide, and ethylene glycol. Two Cogeneration units (Cogens) are operated in support of the Shell facility . Reviewing the Proposal to assess the draft requirements, it was apparent that the Allocation Table included as part of the proposed rule two line items for 'Shell Chemical, Louisiana .' Although the Proposal identifies unit designations that do not match typical Shell names for the Geismar Cogens, all other descriptors indicate that the two listed line items are, in fact, referring to the Geismar units. [EPA-HQ-OAR-2009-0491-2572, p.1]
Shell is submitting comments to this proposed rule in order to provide clarification regarding the nature of the Cogeneration operations and to request that the EPA correct the draft designations in the proposal and remove them from applicability . As part of initiating registration for full operation of the Cogens, Shell filed a, 'Certification of Qualifying Facility (QF) Status For a Proposed Cogeneration Facility' to the Federal Energy Regulatory Commission, or FERC (FERC Form 556). As reported in the FERC filing, the Cogeneration Facility is wholly-owned by Geismar Cogen Statutory Trust, a special purpose entity formed to serve as the owner/lessor of the Facility . Shell Chemical LP is the Lessee of the facility and Air Liquide America Corporation (ALAC) operates the facility. The referenced Allocation Table lists the two Cogens, which indicates that the facility may be presumptively subject to the proposed rule. Of heightened concern is the fact that the units are apparently not allocated a default emissions baseline in the proposed table . However, based on language contained in the proposed rule, Shell has reason to question whether the proposed rule applies to these units. [EPA-HQ-OAR-2009-0491-2572,p .1]
Taking into account the previously existing information referenced above, Shell believes that the units listed for its facility were mistakenly or inadvertently included in the collection of facilities initially identified as being subject to this proposed regulation. All actual physical and operating information indicates that the devices would not meet the applicability requirements for the Proposal, and thus there should be no corresponding reference to the devices within the Allocation Table that included in the Proposal. [EPA-HQ-OAR-2009-0491-2572, p.2]
EPA Erred in Including Shell's EGUs As They Meet the Cogeneration Exemption
As support documentation to the proposed rule and FIP, EPA made available an Allocation Table which provides annual and ozone season NOx allocations for regulated EGUs.  As mentioned, there are two Cogens operated in support of the Geismar Louisiana facility. EPA purports to cover the following EGUs under the proposed applicability of the rule/FIP: [[See Docket Number EPA-HQ-OAR-2009-0491-2614, p.3 for the table]]
Because each of these EGUs qualifies under the Transport Rule/FIP's definition of 'cogeneration unit ,' and has never supplied more than one-third of its potential electrical output capacity or more than 219,000 MWh of electricity to the electrical grid for sale within the applicable time periods proposed in the rule/FIP, Shell believes its units have been erroneously listed as regulated EGUs and requests that EPA delete these units from any documents implying applicability and from the allocation tables. [EPA-HQ-OAR-2009-0491-2614, p.3]
Under the proposed Transport Rule/FIP, a covered source is any stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine serving at any time, since the later of November 15, 1990 or the startup of the unit's combustion device, a generator with nameplate capacity of more than 25 MWe producing electricity for sale. Certain cogeneration units are exempt, however, from these requirements. A source qualifies for the 'cogeneration unit exemption' if the unit meets the following conditions: [EPA-HQ-OAR-2009-0491-2614, pp.3-4]
1. operates as part of a 'cogeneration system,'
2. meets, on an annual basis, specified efficiency and operating standards, and
3. supplies in any calendar year-starting the later of November 15, 1990 or the start-up of the unit's combustion chamber-no more than one-third of its potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale. [EPA-HQ-OAR-2009-0491-2614, p.4]
Shell believes that its EGUs qualify under the 'cogeneration unit exemption' and, thus, have been improperly listed as being subject to the proposed Transport Rule/FIP. While the Shell's units are cogeneration units, as defined under the proposed Transport Rule, these units do not meet the electricity sales thresholds that would subject them to regulation under the proposal. These units, on an individual unit-by-unit basis, do not distribute the greater of more than one-third of their potential electric output or 219,000 MWh for sale. As such, because none of its units meet the applicability criteria in the proposed Transport Rule, Shell requests the removal of the units from the Allocation Table and from any other Technical Support Documents pertaining to regulated EGUs under the rule/FIP. [EPA-HQ-OAR-2009-0491-2614, p.4]
Southern Company
B. EPA's 'Adjustments' Are Flawed and Inconsistently Applied
EPA 'adjusts' both reported and projected data in the process of setting state budgets and unit allocations. Based on our review in the time EPA has allowed, we have uncovered flaws in the methodologies, examples of where the stated methodologies appear not to have been applied, and situations were EPA adjusts similar data differently. Some examples include:
:: Gadsden 2 (methodology misapplied/unclear). EPA does not appear to have applied its prescribed methodology when setting Gadsden 2's S02 allocation. It appears that a unique adjustment was made to the Heat Input for Gadsden 2, but it is very difficult to determine EPA's methodology.
:: Bowen 2 (flawed methodology). Bowen 2 experienced a prolonged outage in the first quarter of 2009 to install FGD controls. Under EPA's stated methodology for adjusting reported data for controls installed during the reporting period EPA essentially ends up using data from only the third quarter in 2009 to set Bowen 2's annual S02 allocation. 49 Using limited operating time to establish a long-term average emission rate is inadequate and may be unrepresentative. In this case, the flawed methodology results in the Bowen 2 adjusted projected emission rate and 2012 S02 allocations to be much lower than the other, similar units at the same site.
:: Bowen 1 (inconsistent application of methodology). Bowen 1 experienced a regularly planned outage in approximately half of the fourth quarter 2008. Accordingly, its heat input and NOx and S02 emissions for that quarter were half of what they would be in a typical quarter. Yet EPA used this quarterly data to set Georgia's state budget and Bowen 1's allocations. To be consistent of its treatment of other units, EPA should use heat input and emissions data from the fourth quarter 2007 in place of the unrepresentative data reported in the fourth quarter of 2008. [EPA-HQ-OAR-2009-0491-2864.1, p. 49]
Spruance Genco, LLC
As stated above, each of the boilers at the Spruance Genco facility serves a generator with a nameplate capacity of 67.5 MWe and, therefore, is subject to the Transport Rule. We also note that EPA included this facility (for these reasons) as an affected facility under the NOx SIP Call and CAIR. As such, this facility should be treated as a CATR-affected facility and EPA should allocate appropriate S02 and NOx allowances to this facility. [EPA-HQ-OAR-2009-0491-2832.1 p.2]
Specifically, the Excel spreadsheet contained on the EPA web page and referenced as 'Budget and Allocations - Detailed Unit-level Data (Excel)' includes a listing of each unit for which allocation data was determined. The following comments are provided with regard to allocation calculations in that spreadsheet and final Allocations Table provided in the docket.
1. The Spruance Genco, LLC (ORIS Code 54081) units were included in the table under the former facility name Cogentrix of Richmond. [EPA-HQ-OAR-2009-0491-2832.1 p.2]
:: Spruance Genco, LLC requests that this information be properly referenced to the current facility name, Spruance Genco, LLC.
2. The worksheet titled 'Adjustments' lists an Adjustment to Reported Annual NOx pre-2009 SNCR for six of the facility's eight boilers. While an SNCR system was permitted at the facility, the pilot SNCR system was unsuccessful and was subsequently removed. Spruance Genco will be removing this equipment in the upcoming Title V renewal. p.2
:: Spruance Genco, LLC requests that any SNCR-related adjustments be removed from the calculations.
3. The worksheets provide data and analyses for all eight of the facility's boilers (1A, 1B, 2A, 2B, 3A, 3B, 4A, and 4B). However, in the final worksheet entitled 'Allocations & Rate limits' and in the final Allocation Table provided in the docket, the table lists zero allocations for boilers 3A, 3B, 4A, and 4B under each of the four programs - Annual NOx, Ozone Season NOx, 2012 S02, and 2014 502. There is no explanation to account for the removal of the allocations for these units. However, as explained above, it appears that EPA incorrectly assumed that these units were exempt. [EPA-HQ-OAR-2009-0491-2832.1 p.2]
:: Spruance Genco, LLC requests that EPA review this worksheet and provide the allocations as indicated and calculated in the previous worksheets. Based on review of similar units, the allocations would be calculated as 97% of the Reported Annual and Ozone Season NOx - Adjusted for controls and heat input, and as 97% of the Adjusted Annual S02 - Projected Base Case, as provided below. The calculation methodology for the 2014 and Beyond S02 allowances could not be determined. [EPA-HQ-OAR-2009-0491-2832.1 p.2]
[[Data Table Here]]
State of Missouri Department of Natural Resources
EPA's allocation table that outlines the emission rate and unit-by-unit emission limits appears to have significant flaws that would make it difficult for facilities to meet their limits and ensure air quality improvement. The specific unit-by-unit emission allocations that do not seem reasonable are the following:
(1) The 2014 SO2 allocation for Iatan, ORIS 6065, does not seem reasonable given the state requirement of continued operation of a wet-scrubber on unit 1 per permit 012006-019D. The allocation does not appear to include this permit condition and treats the scrubber as a dispatchable control, and the allocation is increased to account for the potential non-operation of the scrubber. [EPA-HQ-OAR-2009-0491-3806, p.3]
(2) The placeholder plant name SPPN MO Coal Steam, ORIS 82710, appears in the allocation table, but further investigation reveals that these allocations may be an erroneous combination of units planned to be online in the (SPPN) by January 1, 2012.  Iatan unit 2 with 850 Mega-Watt (MW) capacity is located in Platte County. Southwest, OR-IS 6195, unit 2 with 300 MW capacity is located in Greene County. The National Electric Energy Data System 3.02 database seems to combine the capacity of these two (2) separate units into one (1) larger unit with 1,150 MW capacity and located it in Platte County. Additionally, the allocation of 2010 SO2 is exactly equal to the annual NOX allocation at 2,087 tons. This seems highly unlikely and needs further review. The 2014 SO2 allocation is also zero (0) tons for these new units, a situation that EPA should correct since it is in the best interest of air quality to have the most efficient and least emitting units continue operation. (3) Sibley, ORIS 2094, and Blue Valley, ORIS 2132, have units that receive SO2 allocations in 2012, but then receive zero (0) allocations in 2014. While the analysis of the cost of control indicates that these units are not cost effective to control and should be retired early, that analysis may produce opposite results for air quality. If Blue Valley unit 3 has no allocations, it may be more cost effective to run units 1 and 2 that are not covered by the Transport Rule than to purchase allocations for unit 3. Running older, less efficient and less controlled units may produce more emissions than revisiting the allocation methodology and assumptions. [EPA-HQ-OAR-2009-0491-3806, p.3]
The items listed above are only the most obvious problems that should be addressed. Given more time to analyze EPA's allocation method down to the unit level, more inconsistent allocations and inaccuracies may be found. [EPA-HQ-OAR-2009-0491-3806, p.3]
Sunbury Generation LP
EPA has misstated the capacities for certain boilers at the Facility within the technical supporting documentation for the Proposed Rule. See 'Attachment' to TSD for the Transport Rule, 'State Budgets, Unit Allocations, and Unit Emissions Rate: Field Descriptions for Detailed Unit-Level Data', EPA, Office of Air and Radiation, July 2010, Document ID No. EPA-HQ-OAR-2009-0491-0071.4 (available at http://www.regulations.gov/search/Regs/ home.html#home), The incorrect capacities identified by EPA and the correct capacities for the relevant units, as identified by Sunbury, are detailed in the following table: [EPA-HQ-OAR-2009-0491-3615,p.6] [[See Docket Number EPA-HQ-OAR-2009-0491-3615, p.6 for the table.]]
Tennessee Valley Authority (TVA)
C. Issue: EPA's assumed baseline 2012 emissions for Tennessee without CAIR are in error for TVA's Cumberland plant. [EPA-HQ-OAR-2009-0491-2782.1, p. 8]
TVA Comment: EPA assumed in the proposed Transport Rule a baseline SO2 emission rate for TVA's Cumberland Fossil Plant of 5.0 lbs/mmBtu. The Tennessee Department of Environment and Conservation (i.e. the State permitting authority in Tennessee) issued Permit 061875H (Attachment 2)[Note that Attachment 2 was not in the docket at the time of this summary.]  for the Cumberland Plant on March 31, 2008 with the requirement to meet a Best Available Retrofit Technology (BART) limit of 0.5 lb of SO2 per mmBtu SO2 "as expeditiously as practicable." The Cumberland units are equipped with FGD and meet the 0.5 lb/MmBtu limit. EPA should correct the baseline 2012 emissions for the Cumberland units to reflect this 0.5 lb/MmBtu limit. [EPA-HQ-OAR-2009-0491-2782.1, pp. 8-9]
D. Issue: EPA's assumed baseline 2012 emissions for Alabama and Tennessee (i.e. the 2012 emissions without CAIR) are in error for TVA's Bull Run, John Sevier, Kingston, and Widows Creek plants. [EPA-HQ-OAR-2009-0491-2782.1, p. 9]
TVA Comment: EPA appears to have included the emission control requirements in the Order issued by the U. S. District Court in North Carolina vs. TVA since the 2012 baseline includes add-on controls for these four plants as was required by that Order. Subsequent to the publication of the Proposed Transport Rule on EPA's website, the United States Court of Appeals for the Fourth Circuit reversed the decision of the U.S. District Court. See North Carolina v. TVA, No. 09-1623 (4th Circuit., July 26, 2010). Accordingly, the 2012 baseline should not include the add-on controls at these four plants. This is not only important for John Sevier (all four units) and Widows Creek (Units 1-6) since FGD and SCR are not currently installed on these units but also relevant to the other units at these four plants for which the applicable emission control requirements are less stringent than required under the vacated Order of the U.S. District Court in North Carolina v. TVA. [EPA-HQ-OAR-2009-0491-2782.1, p. 9]
F. Issue: EPA's Parsed file for Limited Trading in 2014 released with the Proposed Transport Rule has numerous problems with emission rates, plant listings, control technology selection, and more. [EPA-HQ-OAR-2009-0491-2782.1, p. 9]
TVA Comment: Since the initial Proposed Transport Rule release of the 2014 parsed file for limited trading has been replaced in its entirety by the September 1 NODA, TVA defers comments for this area of response to October 15th. However, TVA provides the following as examples of current problems with this initial release of 2014 data; numerous emission rates on both SO2 and NOx are unachievable for the TVA units shown, 2014 emissions are listed for a new TVA coal unit in Kentucky which does not even exist and is not planned; and a 2014 retrofit control, mistakenly entitled "Coal Early Retirement" for the Red Hills Generating Facility in relation to which TVA has a long term purchased power contract. The Red Hills facility is a relatively new coal-fired plant and there are no plans for early retirement of that plant in 2014 or anytime in the near future. These and other comments will be provided and updated as TVA submits their NODA response on October 15th. [EPA-HQ-OAR-2009-0491-2782.1, p. 9]
Vectren Corporation 
With respect to NOx emission rates, it is not clear from the technical support material where EPA got a 0.06 lb/mmBtu rate for FB Culley Unit 3, AB Brown Units I and 2, and Warrick Unit 4 as reflected in the 'Controlled NOx Base Rate' data column. The lowest NOx emission rate for any of the Vectren units is 0.10 lb/mmBtu for FB Culley Unit 3. Vectren does not currently have actual operating data that indicates that its units can actually achieve sustained NOx emission rates of 0.06 lb/mmBtu for compliance purposes. [EPA-HQ-OAR-2009-0491-2654.1, p. 7]
EPA's assumptions regarding Vectren's capacity factors are inaccurate.
EPA's assumptions regarding the capacity factors for the Vectren units are inaccurate. The capacity factors assigned to Vectren's units are net capacity factors, not gross. As such, the actual capacity factors for Vectren's units are understated by 15 MWs per unit. [EPA-HQ-OAR-2009-0491-2654.1, p. 7]
EPA's assumptions regarding Vectren's historic emissions are inaccurate.
EPA's assumptions regarding Vectren's historic emissions are inaccurate. This is a particularly critical error given the fact that EPA is using historic emissions baseline to allocate emission allowances under the caps instead of heat input. Attached as Exhibit I [See EPA-HQ-OAR-2009-0491-2654.1, pp. 11-14 for Exhibit I] is a table containing the corrected actual emission data. The source for the corrected emission data is the annual emission statements filed for each unit under the applicable Title V permit for each plant. [EPA-HQ-OAR-2009-0491-2654.1, p. 8]
EPA has allocated different emission budgets to identically sized and controlled units.
When EPA promulgated the Clean Air Interstate Rule, it established state budgets in the federal rule and the individual states then had the responsibility to allocate allowances to the individual units located within each state. This resulted in a highly transparent emission allocation process driven at a state level. In the case of Indiana, Vectren and the other Indiana utilities were able to work closely with the Indiana Department of Environmental Management (IDEM) to ensure that IDEM had correct and accurate information for each unit and proved to be a very transparent and beneficial working relationship for all parties involved. By contrast, individual unit allowance allocations are set directly in the proposed federal rule which has resulted in less transparency and opportunity for accurate modeling inputs. [EPA-HQ-OAR-2009-0491-2654.1, p. 8]
An example of the lack of transparency in the proposed rule is that despite an in depth review of the detailed technical support documentation for the proposed rule, Vectren is unable to determine why EPA has allocated different emissions budgets to identically sized and controlled units. While it is evident across the emissions allocations tables provided in the proposed rule, Vectren's AB Brown Units I and2 provide a glaring example of this disconnect. Both AB Brown units are 250 MW units of comparable vintage (1979 and 1982, respectively). Both units have dual alkali scrubbers and SCRs. [EPA-HQ-OAR-2009-0491-2654.1, p. 8]
Both units have the same availability assumptions (90.8%). Yet the S02 emission allocations for AB Brown Unit 2 are a fraction of those allotted to AB Brown Unit 1 under the proposed rule. [EPA-HQ-OAR-2009-0491-2654.1, p. 9]
AB Brown Unit 1-4,494 tons (2012)-2,422 tons (2014)
AB Brown Unit 2-2,924 tons (2012)-925 tons (2014)
It is not evident in the preamble to the proposed rule or the extensive technical support documents provided with the rule, how EPA arrived at such divergent S02 emission allocations for identically sized and controlled units such as Vectren's AB Brown Units 1 and 2. [EPA-HQ-OAR-2009-0491-2654.1, p. 9]
Vectren requests that the extensive errors referenced above be corrected and the model re-run for the Vectren units. [EPA-HQ-OAR-2009-0491-2654.1, p. 9]
The aforementioned errors in technical assumptions have resulted in such significant errors in allocation budgets that the allocation scheme as proposed for the Vectren units is arbitrary. As proposed, the allocation budgets for the Vectren units do not accurately reflect existing or projected unit operations. Accordingly, Vectren would request a meeting with EPA to discuss the modeling assumptions for Vectren's units and urges EPA to develop a revised allocations budget that is consistent with unit operations in the final Transport Rule. [EPA-HQ-OAR-2009-0491-2654.1, p. 9]
Finally, upon discussion with other Indiana and regional utilities it is clear that EPA has used erroneous assumptions throughout the regional electric generation fleet included in the proposed rule. Inaccurate factual inputs into the Integrated Planning Model and erroneous modeling assumptions raise serious questions about the proposed rule. Inaccurate information at the company and unit level such as provided in Vectrcn's comments, and undoubtedly provided in a myriad of other industry comments, must be addressed and new modeling runs will necessarily lead to revisions in unit allocations. As such, EPA should reissue the rule for public comment as a Supplemental Notice of Proposed Rulemaking with the revised allocations prior to finalization. [EPA-HQ-OAR-2009-0491-2654.1, pp. 9-10]
Wabash Valley Power
Gibson Unit 5:
WVPA and the Indiana Municipal Power Agency (IMP A) are co-owners of Gibson Unit 5 along with Duke Energy Indiana, the majority owner and operator. Gibson Unit 5, a nominal 650 MW supercritical coal-fired unit equipped with SCR and an NSPS FGD scrubber, is directly impacted by this rulemaking. [EPA-HQ-OAR-2009-0491-2627.1, p.4]
EPA's assumption that coal switching within the bituminous coal grade to a lower sulfur coal can be accommodated at relatively little cost is incorrect. The ParsedFile TR _ SB Limited Trading 2014 shows that IPM has switched Gibson Unit 5 to a 1.4 lb sulfur bituminous coal. At present the unit typically burns 2.8 lb or higher coal. Burning a 1.4 lb sulfur coal would not be possible without a major precipitator rebuild or baghouse addition. Duke estimates that a baghouse addition would cost approximately $200 million. A precipitator rebuild would cost around $30 million. Duke Energy has estimated the $/ton cost of a precipitator upgrade required to allow the unit to bum lower sulfur coal to be far in excess of the $2000/ton threshold cost that EPA is using as a ceiling for SO2 removal. The unit is not capable of burning a coal with this low sulfur content without incurring significant costs for precipitator upgrades and increased fuel costs for compliance coal. Additionally, the time required for such upgrades would not likely be completed by the proposed rule's compliance deadline. This is an example of unit specific complexities not adequately captured in EPA's assumptions or its modeling. [EPA-HQ-OAR-2009-0491-2627.1, p.4]
We recommend that EPA use separate ozone season and non-ozone season NOx emission rates for units with an existing SCR instead of using a unit's ozone season emission rate to represent its emissions over the entire year. A unit's ozone season NOx emission rate is typically not representative of its non-ozone season emission rate. Therefore the ozone season rate is not representative of a unit's capability over an entire year. A review of 2009 ozone season and non-ozone season NOx emission rates for units with SCRs operating year around clearly shows that the ozone season NOx emission rates are lower than the non-ozone season rates. [EPA-HQ-OAR-2009-0491-2627.1, p.4]
Applying a unit's ozone season NOx emission rate to the non-ozone season under predicts a unit's annual NOx emissions, the state budgets, and the unit allowance allocations. The fact that the ozone season NOx emission rate is not representative of the non-ozone season emission rate is due to many factors, including:
1. Most units have the fewest number of outages during the ozone season which results in the most continuous period of SCR operation. Outside of the ozone season, most units experience the bulk of planned and maintenance outage ' activity. This results in higher occurrences of unit start-up's and shut-down's when emission rates are higher than during continuous operation. [EPA-HQ-OAR-2009-0491-2627.1, p.4]
2. Lower ambient temperatures in the winter season generally result in a higher propensity for ammonium bisulfate formation in the air heaters and downstream ductwork on SCR units, resulting in air heater and ductwork pluggage.
3. Most units tend to have catalyst replacement outages in the spring outage season, resulting in peak SCR removal capability during the ozone season immediately following the outage. As the catalyst degrades, SCR removal capability decreases in the months following the ozone season. [EPA-HQ-OAR-2009-0491-2627.1, p.5]
Upon making these adjustments, EPA should rerun the critical IPM model runs that are the basis for developing state budgets and unit allocations. EPA should then publish revised proposed budgets and allocations for public review and comment. [EPA-HQ-OAR-2009-0491-2627.1, p.5]
EPA's model incorrectly lists Gibson Unit 5 with a 0.0600 lb/mmBtu NOx annual and ozone season emission rate (which equates to an effective rate of 0.0582 lb/mmBtu after factoring in the 3% new source set-aside). This unit cannot perform at or below a rate of 0.060 lb/mmBtu, as demonstrated in the actual 2009 performance which reflects year-round operation of the SCR for CAIR Annual and Ozone NOx compliance. The SCR was operated to the maximum extent possible, given the operating conditions of the unit. The 2009 ozone season and non-ozone season NOx emission rates for this unit were 0.1088 lb/mmBtu and 0.1105 lb/mmBtu respectively. These are the emission rates that we recommend EPA use for this unit. Duke estimates that the SCR upgrades needed to consistently achieve the 0.060 lb/mmBtu emission rate would far exceed $500/ton threshold cost that EPA is using as a ceiling for NOx removal. In addition, it would not be possible to complete such upgrades by January 1, 2012 and unlikely that it could be completed by 2014. [EPA-HQ-OAR-2009-0491-2627.1, p.5]
Landfill Methane Facilities: 
WVPA owns several landfill methane generation facilities throughout Indiana, including the facilities listed in the EPA database as the Deercroft Gas Recovery units, Prairie View Gas Recovery units, and Twin Bridges Gas Recovery units. These are nonfossil fuel, small (less than 25 MW) spark ignition reciprocating internal combustion engines (SI RICE) units that utilize landfill methane. These facilities are not subject to the proposed program and should be removed from the database. [EPA-HQ-OAR-2009-0491-2627.1, p.5]
we energies
EPA incorrectly assumes that some of our coal generation will be retired: South Oak Creek Units 5&6 and Valley Units 1-4. We are currently installing flue gas desulfurization and selective catalytic reduction equipment on South Oak Creek Units 5&6 (along with 7&8). This equipment will be in place no later than December 31, 2012. Valley Units 1-4 are scheduled to continue to provide electricity to the grid and steam to approximately 450 industrial, commercial, university, and government customers. Because all of the affected units at these plants will continue to operate for the foreseeable future, EPA must provide future allowance allocations for these units. [EPA-HQ-OAR-2009-0491-2629.1, p.3]
Allocations for our Presque Isle units 3&4, which were retired in 2009, also need to be corrected, as these units only receive SO2 allocations in 2012. [EPA-HQ-OAR-2009-0491-2629.1, p.3]
First, there are errors in the baseline data EPA has used which describes We Energies generation units. Appendix A, attached includes detailed corrections to EPA's 'Budgets and Allocations Detailed Unit Level Data' spreadsheet. [EPA-HQ-OAR-2009-0491-2629.1, p.3] [[See Docket Number EPA-HQ-OAR-2009-0491-2629.1, pp.9-13 for Attachment (Appendix) A.]]
Response: 
Thank you for your comment.
Organization: Georgia Department of Natural Resources, Air Protection Branch
Comment: 
Georgia Department of Natural Resources, Air Protection Branch
The proposed rule includes non-EGU sources of emissions in Georgia
EPA has identified Weyerhaeuser-Flint River and International Paper-Augusta Mill as potentially subject to the proposed rule. Both of these facilities are pulp and paper manufacturers that have the potential to sell excess power to the grid. EPD determined that they were not subject to CAIR after the CAIR rule was amended to change the definition of a cogeneration unit. Prior to the change, these facilities did file under CAIR to identify a designated representative, which may be the reason that they are identified in the proposed rule. EPD does not believe that these facilities should be subject to the rule and requests that they be removed from the technical analysis suggesting they are. However, if they are subject to the proposed rule, EPA's allocation method does not allocate any annual NOx, annual SO2, or ozone season NOx emissions to these facilities which may prove very harmful to their economic vitality. Georgia EPD requests that EPA allocate annual NOx, annual SO2, and ozone season NOx emissions to these facilities if they are indeed subject to the final rule. [EPA-HQ-OAR-2009-0491-2647.1, p.3]
Response: 
EPA is not making applicability determinations for any units in this final Transport Rule.  The Allowance Allocation Final Rule TSD includes a list of "potential" existing Transport Rule units that is based on EPA best available data.  The above units have not been included in that table.
Organization: Holland Board of Public Works
Comment: 
Holland Board of Public Works
Specifically, we are concerned with the proposed S02 allocation of '0' given to our Unit 5 starting in 2014. [EPA-HQ-OAR-2009-0491-2861.1, p.2]
In addition, the Holland BPW was recently denied by the State of Michigan to build a new larger coal-fired electric generating unit with state-of-the-art pollution controls (78 MW unit with emissions similar to our smallest, oldest unit 3,11.5 MW; and would be able to burn biomass fuels). Now, as a result of this rule, we would be mandated to cease coal-firing our 'newest' existing Unit 5 by 2014. [EPA-HQ-OAR-2009-0491-2861.1,p.2]
As pointed out in the comments from MMEA, Holland is the site for two recently announced lithium-ion battery advanced energy storage plants. Three months ago President Obama visited Holland for the ground breaking for one of those plants, LG Chem. Unit 5 will be critical to meeting the power supply needs of these facilities in a cost-effective manner. [EPA-HQ-OAR-2009-0491-2861.1, p.2]
Response: 
EPA has finalized an allocation methodology different than that proposed.  The modification was made in response to concerns such as those expressed above.  Unit level allowance allocation under the final rule is tied to historic operating data.  See section VII.D of the preamble for further allocation details.
Organization: Hoosier Rural Electric Cooperative
Comment: 
Hoosier Rural Electric Cooperative
a. The EPA CATR analysis on allocation budgets appear to be erroneous due to seriously flawed assumptions made on affected Indiana electric utilities. For example, in the proposed scheme, Hoosier's Worthington Generating Station Unit 2 was not projected to operate when in reality it will operate. Hoosier requests the same amount of annual and seasonal NOx allowances be allotted for that unit as the other units listed.  [EPA-HQ-OAR-2009-0491-2724.1 p.1] [EPA-HQ-OAR-2009-0491-3758.1_NODA, p.1]
Response: 
EPA updated its IPM model based on comments received during the proposal comment period.  It than reran its IPM modeling analysis, and the Worthington Gen. Station Unit 2 is projected to run in base case and policy case for the final Transport Rule analysis.  However, EPA also updated its allocation methodology based on concerns such as these expressed at proposal.  The final allocation methodology (see section VII.D of the preamble), indexes a units allocation to its historic heat input emissions data.  The Worthington unit 2 allocation amount is determined off this historic data. 
Organization: Independence Power & Light (IPL)
Piney Creek LP
Oklahoma Department of Environmental Quality
Arkansas Department of Environmental Quality
Allegheny Energy
State of Delaware Department of Natural Resources & Environmental Control
Louisiana Public Service Commission
Tennessee Department of Environment and Conservation, Division of Air Pollution Control
Utility Air Regulatory Group (UARG)
Occidental Chemical Corporation (OCC)
Capital Power Corporation
Boston Generating
GE Energy Financial Services (GE EFS)
Kansas Department of Health and Environment
Florida Electric Power Coordinating Group, Inc. (FCG)
Lansing Board of Water & Light
Dairyland Power Cooperative
Minnesota Power 
City of Tallahassee
Louisiana Energy and Power Authority (LEPA)
Buckeye Power, Inc.
Cogen Technologies Linden Venture, LP
First Energy
Calpine Corporation
Wisconsin Power and Light Company
EquiPower Resources Corp.
PowerSouth Energy Cooperative
Omaha Public Power District
Renaissance Power
Old Dominion Electric Cooperative
Class of '85 Regulatory Group
Michigan Municipal Electric Association (MMEA)
Louisiana Chemical Association (LCA)
Missouri Public Utilities Alliance (MPUA)
JEA
Gainesville Regional Utilities (GRU)
Tampa Electric Company
New York State Department of Environmental Conservation
Comment: 
Allegheny Energy
The proposed rule's state allowance budgets are larger in some states and smaller in other states as compared to the budgets established under CAIR. For example, AE generates in Pennsylvania, Maryland and West Virginia and under the proposed rule Pennsylvania's budget increased by 14,854 allowances over its CAIR NOx annual allowance budget but Maryland and West Virginia both found their budgets decreased (Maryland by 10,680 allowances and West Virginia by 22,230). The net effect is that AE is now subject to a net loss of over 18,000 allowances from the states in which the company has generation. Moreover, the majority of AE's coal-fired generation is located in West Virginia (5067 MW versus 2346 MW in PA and 116 MW in MD). Although 18,000 or even 22,000 allowances are but a fraction of the overall proposed rule's total budget it is still significant in the compliance planning strategy of the company. These types of ostensibly insignificant changes (e.g. state allowance budgets, compressed implementation dates, etc.) in the requirements of the proposed rule from those currently in place under CAIR, when added together make compliance a far more challenging prospect than EPA's modeling suggests, and thus renders EPA's compliance projections highly suspect. [EPA-HQ-OAR-2009-0491-2605.1, p.4]
Arkansas Department of Environmental Quality
Arkansas is included, under CAIR and the proposed Transport Rule, for NOx ozone season only. In the first phase of CAIR, Arkansas's ozone season NOx budget was 11,515 allocations. In the second phase, Arkansas's CAIR budget was reduced to 9,596 allocations. In the proposed Transport Rule, the budget for both phases is 16,660, which represents a 73.6% increase in allowable emissions over Phase 2 CAIR allocations. ADEQ is concerned that in an effort to comply with the Transport Rule, any future SIPs based on this increase in budget allocations will be construed as 'backsliding' by the EPA or others, since traditionally a SIP can only replace an existing SIP element if the new SIP measures achieve equivalent or better emission reductions. Therefore ADEQ requests clarification in the final rule on how the issue of backsliding within SIPs will be addressed.  [EPA-HQ-OAR-2009-0491-2676.2 p.2]
Boston Generating
EPA proposes zero SO, allocations for the Mystic Generating Station, Unit IDs GT81, GT82, GT93 and GT94. The gas turbines combust only pipeline natural gas. Actual annual SO, emissions are typically five tons per unit per year, as summarized in the table below. It is unclear why NO, allocations approximate 2009 actual emissions yet SO, allocations are zero. With respect to SO' the units are already burning the cleanest fuel and there are no feasible add-on emission controls. The facility proposes a 2012 SO, allocation of five tons per unit, equivalent to the average actual emissions from a 3-year look back period. [EPA-HQ-OAR-2009-0491-3804.1 p.2]
[[Next entry in docket is a data table]]
EPA proposes zero SO, allocations for the Fore River Generating Station, Unit IDs GT11 and GT12. The gas turbines combust pipeline natural gas and ultra low sulfur fuel oil. Actual annual SO, emissions are typically between three and four tons per unit per year, as summarized in the table below. It is unclear why NO, allocations approximate 2009 actual emissions yet SO, allocations are zero. With respect to SO' the units are already burning the cleanest fuel and there are no feasible add-on emission controls. The facility proposes a 2012 SO, allocation of three tons per unit, equivalent to the average actual emissions from a 3-year look back period. [EPA-HQ-OAR-2009-0491-3804.1 p.2]
[[Next entry in docket is a data table]]
Buckeye Power, Inc.
For all of the foregoing reasons, Buckeye Power urges EPA to withdraw its proposed CATR program. If it does proceed, EPA should (3) correct errors in the data inputs used in its modeling and methodology. [EPA-HQ-OAR-2009-0491-2710.1, p.13]
F. The Policy Outcome of EPA's Proposed Allocation to Linden Cogen Would Be Grossly At Odds With the Administrator's Goal of Fostering Investment in a Clean and Efficient Power Sector 
EPA has proposed to allocate 88% of New Jersey's budgeted emissions to six coal-fired generating plants. A comparison of these facilities' allocations under the CAIR and under the Proposed Transport Rule appears at Table 8 attached at Attachment 3. In the case of one of those facilities, B. L. England, the allocation resulting from IPM projections is several times larger than the CAIR allocation issued by NJDEP. Under the CAIR program implemented by NJDEP, B. L. England would have received 894 tons of annual NOx allowances and 508 tons of ozone season NOx allowances. In contrast, under the Proposed Transport Rule, B. L. England will receive 4,139 tons of annual NOx allowances and 1,798 tons of ozone season NOx allowances, which is also a significantly greater number of allowances than its reported annual NOx emissions of approximately 1,700 tons and its 2009 ozone season reported NOx emissions of approximately 543 tons, according to EPA's data set. Therefore, under EPA's proposed allocation, B. L. England would be awarded more than twice as many allowances as its most recent annual and ozone season NOx emissions and will likely have more allowances than it needs. [EPA-HQ-OAR-2009-0491-2710.1, p.17] 
[Table 8 can be found on page 28 as attachment 3 of this comment.] 
In contrast, in light of Linden Cogen's contractual obligations to provide heat and power to its steam host and the grid, there is little doubt that IPM's projected dispatch of Linden Cogen is significantly understated and Linden Cogen will need to obtain additional allowances. Thus, as a likely consequence of EPA's allocation methodology, coal-burning facilities such as B. L. England would presumably become sellers of allowances and gain a substantial subsidy, at the expense of cleaner facilities such as Linden Cogen that would become buyers of allowances. Such a policy outcome would run contrary to the goal stated by the Administrator upon proposing the Transport Rule 'of fostering investments in compliance that represent the most efficient and forward-looking expenditure of investor, shareholder, and public funds, resulting, in turn in the creation of a clean, efficient, and completely modem power sector.' 75 Fed. Reg. at 45227. [EPA-HQ-OAR-2009-0491-2710.1, p.18] 
While NJDEP could presumably correct the errors created by EPA's proposed allocation methodology and impose more equitable allocations upon obtaining EPA's approval of a SIP revision that is likely to take a number of years to complete, 14 EPA's allocation methodology would place Linden Cogen at a significant competitive disadvantage to other generators which have received proposed allocations more consistent with or in excess of their historic emissions. [EPA-HQ-OAR-2009-0491-2710.1, p.18] 
Further, as the court said in Appalachian Power I, the fact that a source owner can purchase allowances or that disparities between historic emissions and IPM projections disappear when viewed on a more aggregate level 'is no answer' to those who would be harmed by EPA's allocation methodology. See Appalachian Power 1,249 F.3d at 1054 ('The EPA first claims that regulated facilities can always purchase additional allowances, albeit at their own expense. This is no answer... Finally the EPA claims that when the projections are considered on a region-wide level such disparities are likely to disappear. As budgets are set on a state-by-state level, this is small consolation to petitioners.') Accordingly, it is no defense for EPA to explain that any allocation methodology is likely to pick winners and losers or that when reviewed in the aggregate, the results are roughly fair. Thus, EPA's proposed allocation methodology not only runs contrary to the Administrator's stated policy goals, but falls far short of assuring a non-arbitrary result. [EPA-HQ-OAR-2009-0491-2710.1, p.18] 

14. We note that, if EPA has already allocated annual or ozone season NOx allowances for a particular year, it is unclear whether a SIP could, in fact, change the allocation. See Proposed Transport Rule, 75 Fed. Reg. at 45362 (proposing 40 CFR §§ 52.37(a)(4) and (b)(4) providing that, 'if at the time of such approval of the State's SIP, the Administrator has already allocated any TR NOx Annual [or Ozone Season] allowances to sources in the State for any years, the provisions of part 97 of this chapter authorizing the Administrator to complete the allocation of TR NOx Annual [or Ozone Season] allowances for those years shall continue to apply, unless provided otherwise by such approval of the State's SIP.'). [EPA-HQ-OAR-2009-0491-2710.1, p.18] 
Calpine Corporation
The Case for Updating Allocations
Calpine urges EPA to consider an updating allocation approach in order to ensure that units that operate at higher capacity factors in the future will be provided with an increasing share of allowances to reflect the increased contribution to satisfying electricity demand in the state. EPA is correct in asserting that cleaner units will tend to operate more in the future; however, if these units have to purchase allowances on the open market the cost of allowances will be added to their cost of generation thereby decreasing their competitiveness in the dispatch stack at the expense of higher emitting units. There are many successful examples of updating allocation approaches in states like Pennsylvania, Massachusetts, New Jersey and New York to name a few. Updating allocations will ensure that cleaner units remain competitive in the marketplace and are not unnecessarily penalized. Calpine supports updating every three years based on the previous three-year electric production or, alternatively, heat input. EPA could include some method to ensure that units that were subject to significant operating constraints during the three-year reallocation period (e.g., major outage or other operational failure) would not be unduly harmed. [EPA-HQ-OAR-2009-0491-3614, p.4]
Technical Corrections and Miscellaneous Issues with Calpine Units
During the review of the proposed rulemaking the following issues were identified: [EPA-HQ-OAR-2009-0491-3614,p.5]
:: Units with SO2 and NOx allocations of 0.5 tons and less were issued zero allowances. Calpine requests that all units be issued one allowance in order to not disadvantage these units over a rounding issue.
:: In many instances EPA has divided the heat input and the reported emissions of combined-cycle units between the first-listed combustion turbine and the steam turbine. Not only is this an arbitrary representation of the true heat input but it also can result in the loss of one allowance. For combined-cycle plants it is more accurate to apportion the heat input to the emitting units (i.e. the combustion turbines). Carville Energy Center (LA), a CHP facility with two combustion turbines and one steam turbine, provides an example of this issue. EPA allocated one SO2 allowance to the first combustion turbine and one S02 allowance to be steam turbine; however the combined SO2 allocation should be based on 2.9 tons of SO2, which would equate to three allowances. [EPA-HQ-OAR-2009-0491-3614,p.5]
:: In many instances the BADetailedData sheet does not recognize heat input in 2008 for units that operated. This is significant to those facilities issued NOx allowances based on 97 percent of the 2009 emissions adjusted for 2008 heat input. For example, Broad River Energy Center (SC) Units 4 and 5, Edge Moor Energy Center (DE) Unit 5, and Santa Rosa Energy Center (FL) show 2008 Annual Reported Heat Input of zero. Therefore, the reported emissions adjust to zero. These units ran in 2008 as confirmed in EPA's CAMD database. [EPA-HQ-OAR-2009-0491-3614, pp.5-6]
:: Texas facilities are allocated allowances based on reported emissions. Therefore, all unit allocations should be based on reported emissions. However, Texas City Power Plant (TX) Unit I is based on projected adjusted values while Units 2-4 are based on reported emissions. The BADetailedData Sheet does not list the 2009 data even though it is available in the CAMD database.
:: EPA acknowledges that it was not possible to run a combined IPM allocation model and this is the reason for varied heat inputs between the model runs. However, the variances between runs are so significant that it should not be used as the basis for allocating to units. For example, IPM projects the Morgan Energy Center (AL) Unit I will have an annual heat input of 5,837,442 MmBtu per the S02 model and 178,342 MmBtu per the annual NOx model. IPM projects the Santa Rosa Energy Center will have an annual heat input of 1,112,978 MmBtu per the S02 modeling and 0 MmBtu per the annual NOx modeling.
:: In many instances, EPA projects heat input in the SO2 modeling but allocates zero allowances. For example, the Morgan Energy Center (AL) annual heat input projections would indicate an allocation of 9 tons of SO2 assuming EPA is using the traditional 0.0006 lb/mmBtu S02 emission factor for pipeline quality natural gas. However, the facility was allocated zero tons. [EPA-HQ-OAR-2009-0491-3614, p.6]
Capital Power Corporation
CPC accepts EPA's use of dispatch modeling to determine the individual state caps on historic and projected emissions. Although it is a reasonable macro-level model for the purposes of predicting future emissions and electricity consumption at the state level, as noted by some other commenters, the IPM model inputs used by EPA do not provide a realistic estimate of future heat input for specific units. EPA should allow companies the opportunity to fully review and correct model input errors. [EPA-HQ-OAR-2009-0491-2753.1, pp.2-3]
EPA's Allocation Table is incorrect and contrary to the Transport Rule's stated applicability criteria. For example, EPA proposes to regulate EGUs under the rule, and as indicated in Footnote 77, does not define Industrial, Commercial, and Institutional (ICI) Boilers as covered sources in the proposed rule: "Certain non-EGUs and smaller EGUs were included in the CAIR NOX ozone season program in some CAIR states. EPA proposes that such units would not be covered by the Transport Rule requirements; see section V.F in this preamble for further discussion of these units.' [EPA-HQ-OAR-2009-0491-2753.1, p.3]
However, the Allocation Table includes CPC's Portside Energy (ORIS 55096) and Morris Cogeneration (ORIS 555216) facilities The Portside facility is and has been a cogeneration facility servicing a US Steel plant which receives all its power and thermal production. While the Morris Cogeneration facility does sell some amount of power to the grid, its historical sales to the grid are significantly less than one-third of its potential electrical generation capacity and less than 219,000 MW hrs/year. Both of these units should not be included. [EPA-HQ-OAR-2009-0491-2753.1, p.3]
Conversely, CPC has two solid fuel-fired facilities in Roxboro and Southport, North Carolina (ORIS 10379 and 10378) that are not listed on the Allocation Table, and so apparently would not receive any allocation. The Roxboro facility was an exempt cogeneration unit under the Acid Rain Program but not under the CAIR program, as it lost its steam host in 2007. The facility is a Qualifying Facility  -  Small Power Producer and currently sells all its power to the grid. Through most of its operating life, it was a base loaded cogeneration operation that burned coal. As virtually no coal-fired unit can meet the cogeneration efficiency standard, it would appear the facility would be covered under the Rule. However, while its nameplate generation capacity is 50 MW, it now must burn at least 75 percent alternative fuels, and 50 percent of the total is biomass. The lowered heat value of the biomass (primarily wood) has significantly reduced its generation capacity. [EPA-HQ-OAR-2009-0491-2753.1, pp.3-4]
Further complicating the question, Roxboro has three boilers serving the one generator. Given the definition of unit under the rule, the generation capacity of each unit appears to be less than 25 MW. [EPA-HQ-OAR-2009-0491-2753.1, p.4]
The Southport facility has some of the same issues, but it continues to have a steam host. It too is a Qualifying Facility  -  but as a Cogeneration Unit. It would appear to qualify for an exemption under the Rule except that as an historically coal-fired operation it apparently cannot meet the efficiency standard listed in the Rule. CPC is concerned that these facilities be appropriately classified to assure that if they are exempt, EPA recognizes them as such. If they are covered, EPA needs to assure they are granted appropriate allocations. [EPA-HQ-OAR-2009-0491-2753.1, p.4]
City of Tallahassee
The EPA should give careful consideration to using a different approach to selecting the baseline years of 2008 and 2009. These two years do not represent normal operating conditions for many of the units regulated under this rulemaking, and therefore, EPA should allow for the selection of a more representative time period.  The units regulated by this rulemaking are also regulated under CAIR, many of which had extended outages in 2008 and 2009 to install SO2 and NOx control equipment.  Additionally, in 2008 and further into 2009, the U.S. economy plunged into an economic "crisis," and electricity demand dropped significantly.  Therefore, 2008 and 2009 are not representative years for many of the units regulated by this rulemaking.  In the case of the City, in 2008 Unit No. 2 was retired and Unit 2A (the combined cycle unit) was brought online in the second half of 2008.  To support this conversion, Unit 2 was off line for an extended period of time during 2008.  Emissions during that year are hardly representative of a full year of operation on either of those two units. [EPA-HQ-OAR-2009-0491-2669.1, p.3]
The City suggests that EPA utilize an approach similar to CAIR, and use an average capacity of the past five years, or perhaps the selection of the two highest years of NOx and SO2 emissions out of the past five years.  For new units, allowances should be based on heat input that is representative of the maximum allowable operation hours that the unit is permitted for (in the case of unit 2A, 8,760 hours per year). [EPA-HQ-OAR-2009-0491-2669.1, p.3]
Errors in Proposed Allowance Allocation Table. [EPA-HQ-OAR-2009-0491-2669.1, p.3]
The proposed allowance allocation table (EPA's posted "Projected Data" spreadsheet), which was published with the proposed rule, EPA has not allotted SO2 allowances for those units which burn fuel oil and natural gas.  The City understands that these dual-fuel fired units were predicted, incorrectly, to only burn natural gas in the future. [EPA-HQ-OAR-2009-0491-2669.1, p.3]
Florida receives gas from only three pipelines.  During the 2005 Hurricane season, Florida nearly depleted its supplies of natural gas due to interruptions in the Gulf of Mexico.  During this emergency period, utilities held daily meetings to assess the situation and discuss possible contingency plans, many of which centered on utilities ability to burn fuel oil in their dual-fuel fired natural gas units.  As EPA has cited in their Endangerment Finding, the U.S. should be encountering increased storm activity in the near future, and so the U.S. should plan accordingly.  Assuming for the sake of argument, this rule proposal merely pushes Florida sources to become much more reliant on natural gas, which will only exacerbate any future issues with curtailed or jeopardized gas supplies. More importantly, the law of supply and demand dictates that increased costs will be incurred, costs that will be passed on to the City of Tallahassee's customers. [EPA-HQ-OAR-2009-0491-2669.1, p.3]
EPA must conduct an analysis of the capacity of Florida's natural gas pipelines to accommodate the increased requirement in natural gas consumption needed to meet EPA's assumptions by 2012.  EPA must also perform reliability analysis as to Florida's unique situation as a peninsula regarding FCG members' ability to meet reliability requirements in the future.  And EPA's analysis must consider the parasitic load from new control equipment, such as FGD and SCR systems. [EPA-HQ-OAR-2009-0491-2669.1, p.3]
More specifically, for the City, the allocation table has a number of errors.  Hopkins Unit 2A, which is under-allocated for allowances as explained in section D above, has been proposed zero allocations for NOx annual allowances, yet 18 allowances for the ozone season.  Wouldn't one need, at the very least, 18 annual NOx allowances to cover the emissions during ozone season?  The proposed allocation table predicates an emission rate of zero for the annual NOx emissions rate.  Yet this unit has averaged over the two and half years of operation 0.02 lbs/mmBtu.  During ozone season, the NOx emission rate is predicated as being a little over half of that, 0.07 lbs/mmBtu.  The City of Tallahassee's heat input is assumed as zero for the years 2014 and beyond.  In addition, the City's Purdom facility would receive allocations for a unit 9 that does not exist.  The EPA would benefit from extra time to correct mistakes such as these and allow potentially regulated facilities to delve more deeply into EPA's allocation methodology to undercover additional mistakes, as well as the ability to further instruct EPA on the potential future operations of the State of Florida's electric generating fleet. [EPA-HQ-OAR-2009-0491-2669.1, p.4]
Class of '85 Regulatory Group
Despite its support for the general structure of the preferred option, the Group is concerned that errors in the data and operational assumptions underlying the Proposal will jeopardize the effectiveness of the final rule. EP A must correct these errors to ensure that it is feasible for sources to comply with the Proposal's emissions reduction requirements. Unfortunately, the 60-day comment period severely restricts the ability of interested parties, such as the Class of '85, to identify errors in the Proposal and provide feedback on the viability of the proposed programs. As a result, many of the errors in EPA's data and assumptions may not be discovered by the close of the comment period. [EPA-HQ-OAR-2009-0491-2854.1,pp.1-2]
Cogen Technologies Linden Venture, LP
F. The Policy Outcome of EPA's Proposed Allocation to Linden Cogen Would Be Grossly At Odds With the Administrator's Goal of Fostering Investment in a Clean and Efficient Power Sector
EPA has proposed to allocate 88% of New Jersey's budgeted emissions to six coal-fired generating plants. A comparison of these facilities' allocations under the CAIR and under the Proposed Transport Rule appears at Table 8 attached at Attachment 3. In the case of one of those facilities, B. L. England, the allocation resulting from IPM projections is several times larger than the CAIR allocation issued by NJDEP. Under the CAIR program implemented by NJDEP, B. L. England would have received 894 tons of annual NOx allowances and 508 tons of ozone season NOx allowances. In contrast, under the Proposed Transport Rule, B. L. England will receive 4,139 tons of annual NOx allowances and 1,798 tons of ozone season NOx allowances, which is also a significantly greater number of allowances than its reported annual NOx emissions of approximately 1,700 tons and its 2009 ozone season reported NOx emissions of approximately 543 tons, according to EPA's data set. Therefore, under EPA's proposed allocation, B. L. England would be awarded more than twice as many allowances as its most recent annual and ozone season NOx emissions and will likely have more allowances than it needs. [EPA-HQ-OAR-2009-0491-2712.1, p.17]
[Table 8 can be found on page 28 as attachment 3 of this comment.]
In contrast, in light of Linden Cogen's contractual obligations to provide heat and power to its steam host and the grid, there is little doubt that IPM's projected dispatch of Linden Cogen is significantly understated and Linden Cogen will need to obtain additional allowances. Thus, as a likely consequence of EPA's allocation methodology, coal-burning facilities such as B. L. England would presumably become sellers of allowances and gain a substantial subsidy, at the expense of cleaner facilities such as Linden Cogen that would become buyers of allowances. Such a policy outcome would run contrary to the goal stated by the Administrator upon proposing the Transport Rule 'of fostering investments in compliance that represent the most efficient and forward-looking expenditure of investor, shareholder, and public funds, resulting, in turn in the creation of a clean, efficient, and completely modem power sector.' 75 Fed. Reg. at 45227. [EPA-HQ-OAR-2009-0491-2712.1, p.18]
While NJDEP could presumably correct the errors created by EPA's proposed allocation methodology and impose more equitable allocations upon obtaining EPA's approval of a SIP revision that is likely to take a number of years to complete, 14 EPA's allocation methodology would place Linden Cogen at a significant competitive disadvantage to other generators which have received proposed allocations more consistent with or in excess of their historic emissions. [EPA-HQ-OAR-2009-0491-2712.1, p.18]
Further, as the court said in Appalachian Power I, the fact that a source owner can purchase allowances or that disparities between historic emissions and IPM projections disappear when viewed on a more aggregate level 'is no answer' to those who would be harmed by EPA's allocation methodology. See Appalachian Power 1,249 F.3d at 1054 ('The EPA first claims that regulated facilities can always purchase additional allowances, albeit at their own expense. This is no answer... Finally the EPA claims that when the projections are considered on a region-wide level such disparities are likely to disappear. As budgets are set on a state-by-state level, this is small consolation to petitioners.') Accordingly, it is no defense for EPA to explain that any allocation methodology is likely to pick winners and losers or that when reviewed in the aggregate, the results are roughly fair. Thus, EPA's proposed allocation methodology not only runs contrary to the Administrator's stated policy goals, but falls far short of assuring a non-arbitrary result. [EPA-HQ-OAR-2009-0491-2712.1, p.18]

14. We note that, if EPA has already allocated annual or ozone season NOx allowances for a particular year, it is unclear whether a SIP could, in fact, change the allocation. See Proposed Transport Rule, 75 Fed. Reg. at 45362 (proposing 40 CFR §§ 52.37(a)(4) and (b)(4) providing that, 'if at the time of such approval of the State's SIP, the Administrator has already allocated any TR NOx Annual [or Ozone Season] allowances to sources in the State for any years, the provisions of part 97 of this chapter authorizing the Administrator to complete the allocation of TR NOx Annual [or Ozone Season] allowances for those years shall continue to apply, unless provided otherwise by such approval of the State's SIP.'). [EPA-HQ-OAR-2009-0491-2712.1, p.18]
Dairyland Power Cooperative
I. Alma Unit 4 (B4) and Alma Unit 5 (B5): Boilers Designed to Burn High Heating Value Bituminous Coal Can Not Simply Be 'Fuel-Switched' to Burn 100% Low Sulfur, Low Heating Value, Subbituminous Coal Without Significant Modifications and Without A Significant Loss of Electric Output Capacity. [EPA-HQ-OAR-2009-0491-2733.1p.2]
In Attachment 1, Dairyland Power proposes revisions to the 2012 and 2014 S02 allocations and direct control S02 emission rates for Alma Unit 4 and Alma Unit 5. In making these allocations, EPA has erroneously assumed that these units can simply be switched to fueling with 100% PRB quality coal. These units were designed to burn Illinois Basin bituminous coal. The historical fuel supply has been ranging from 100% bituminous coal to a typical maximum of 30% PRB coal blended with 70% bituminous coal. Switching these units to 100% PRB would present a significant safety issue. The issue related to compliance with safety codes and prudent avoidance of known safety hazards associated with the combustion of 100% PRB coal - - in units not designed for handling and combusting 100% PRB coal - - is detailed below. [EPA-HQ-OAR-2009-0491-2733.1p.2]
In accordance with the National Fire Protection Association (NFPA) and the National Electric Code (NEC) standards associated with combustible dust hazards, a considerable amount of modification to existing equipment, along with installation of new or redesigned equipment, is required on coal-fired electric utility steam generating units designed for bituminous coal in order to convert these units to safely burn 100% subbituminous coal. Insurance carriers providing insurance coverage on coal-fired boilers are well aware of safety issues relating to the increased volatility of subbituminous coal dust and are routinely inspecting facilities for code compliance. [EPA-HQ-OAR-2009-0491-2733.1p.2]
Typical modifications necessary for safely handling and combusting 100% PRB coal include the following:
:: modification of coal mills to add water or steam inerting for explosion prevention
:: modification to the boiler to add additional sootblowers due to the increase reflectivity of subbituminous coal ash
:: installations/modifications to dust collection and suppression systems, including: o upgrading electrical switchgear, junction boxes, and lighting fixtures to dust-tight and explosion-proof standards o modification to coal chutes, liners, and conveyor belt skirting to contain and eliminate coal and coal dust leakage
:: modification to install methane gas detectors in coal conveying reclaim areas and other potential areas where coal may reside
:: upgrades to fire sprinklers and detection systems in the coal handling areas
:: installation of wash-down facilities inside coal conveying tunnels and alongside coal conveyor enclosures
:: modification to upgrade wastewater sumps to remove the waste wash water
:: modification to wastewater processing facilities 
:: additional modifications, as necessary, in response to a new OSHA directive on general housekeeping practices in enclosed areas to minimize the accumulation of combustible coal dust
It appears doubtful that the EPA has taken the safety issue related to combustible coal dust into consideration in proposing that Dairyland Power's Alma Unit 4 and Alma Unit 5 can switch to 100% low sulfur PRE fuel by January 1,2012. It is simply not possible that Dairyland Power could make the type of modifications detailed above between the time the Transport Rule is promulgated and 2012. Also, it is of great concern that other staff within the EPA may consider a fuel switch and the type of projects listed above to be physical and operational changes and potentially subject to NSRJPSD permitting requirements. [EPA-HQ-OAR-2009-0491-2733.1p.2]
In addition to combustible dust issues, it is Dairyland Power's estimate that fueling Alma Unit 4 and Alma Unit 5 with 100% PRE coal will result in an electric output capacity reduction of 37% for each unit resulting from the reduced heat input to the boiler due to the lower heating value of PRE coal. Modifications to the units to alleviate the electric output derate associated with 100% PRE fuel may be considered by some staff within EPA to be a physical change triggering NSRJPSD permitting requirements.  [EPA-HQ-OAR-2009-0491-2733.1p.2-3]
EquiPower Resources Corp.
The Proposed Rule relies on flawed data and assumptions resulting in significant errors in unit-level allocations and state emission budgets. By (i) making unrealistic assumptions about the capacity factors of individual units, (ii) failing to accurately account for emissions from dual fuel combustion units, (iii) making inaccurate assumptions about the control efficiency that can be obtained from existing emission controls, and (iv) failing to provide SO2 allowances to natural gas-fired units contrary to its own regulations, EPA has miscalculated state emissions budgets and by extension erred in its proposed unit level allocations. These errors make compliance with the Phase I and Phase II emissions caps impracticable and causes the Transport Rule to penalize clean sources and those with existing emission controls. [EPA-HQ-OAR-2009-0491-2704.1, p.2]
First Energy
Heat Input Data
EPA's Heat Input (HI) data for Bruce Mansfield Units 1 and 3 and Eastlake Unit 5 are not representative of the heat input for a typical year. In 2008, EL5 had an unplanned forced outage and extended derate due to a catastrophic failure of a critical piece of equipment. This event dropped the expected heat input data for 2008 to about 5,000,000 mmBtu. Years 2005 & 2006 are more typical operating years for Eastlake 5. In order to improve data accuracy, FE requests the EPA correct the heat input data to reflect the typical heat input of the generating unit. [EPA-HQ-OAR-2009-0491-2657.1,p.12]
An alternative to the EPA's allocation structure that would levelize the Unit variability driven by forced and unforced outages is to use select heat input data from 2007 and 2008. Specifically, the EPA would improve operating characteristics of an individual unit by selecting the highest heat input quarters from Q1 & Q4 along w/ the median HI data over the two year window. This approach would address unit heat input variability driven by unit outages. Once the normalized heat input is established, the EPA could use the 2009 NOx rate and the correct availability data to establish an allocation level for the generating units that would reflect typical unit operation. The heat input assumptions in general do not account for typical multi-year operation. Correcting the heat input data to reflect normal operations will improve the accuracy of the IPM model.  [EPA-HQ-OAR-2009-0491-2657.1, p.12]
CATR Zone (Group) Interactions
FE questions the increase in emission allocations between the 2014 base case and the 2014 control case for Arkansas, Mississippi, North Dakota, South Dakota, and Texas. EPA allows a combined emissions increase in those five states of 504,000 tons of SO2. This increase is greater than the combined 2014 control case state budgets for Ohio, Pennsylvania, West Virginia, and Maryland. The EPA should not allow emissions increases based on model output anomalies. FE recommends the EPA hold the state budgets flat for Arkansas, Mississippi, North Dakota, South Dakota, and Texas to prevent any potential impact on another states attainment that could impact maintenance within a group 1 state. [EPA-HQ-OAR-2009-0491-2657.1,p.13]
Further, the likely increases in power prices will move the production of lower cost power further west into Group 2 and into the states that are not impacted. It is not clear that EPA models the increase in western state emissions in this likely scenario. Utility power sales from Group 2 should be carefully monitored as power production moves into other states from Group 1, since their increased power production will likely relate to an increase in emissions that could impact a CATR states' maintenance sites. [EPA-HQ-OAR-2009-0491-2657.1,p.13]
Florida Electric Power Coordinating Group, Inc. (FCG)
EPA has chosen 2008 and 2009 as baseline years for NOx and S02 emissions, respectively. These two years do not represent normal operating conditions for many of the units regulated under this rulemaking, and therefore, EPA should allow for the selection of a more representative time period. The units regulated by this rulemaking are also regulated under CAIR, many of which had extended outages in 2008 and 2009 to install S02 and NOx control equipment. Additionally, in 2008 and further into 2009, the U.S. economy plunged into an economic 'crisis,' and electricity demand dropped significantly. Therefore, 2008 and 2009 are not representative years for many of the units regulated by this rulemaking. The FCG suggests that EPA utilize an approach similar to CAIR, and use an average capacity of the past five years, or some other period that would accurately represent past performance. [EPA-HQ-OAR-2009-0491-2658.1, p.6]
To better understand the absurd outcome caused by the baseline methodology proposed by EPA in the Transport Rule, we offer the following example. A small Florida utility with a single 50-MW natural gas fired cogeneration facility is now proposed under the Transport Rule, based on its 2008 heat input, to receive 98% less NOx credits than previously allocated under CAIR. During 2008, the unit ran only 195 hours, thus providing a heat input that is not representative of a unit which is permitted to operate 8,760 hours per year. Under the Transport Rule, this unit will receive only one NOx annual credit and one ozone season credit compared to its current allocation under CAIR of 52 annual credits and 23 ozone season credits. Given the short time frame provided for in this rule, it is unrealistic to factor in adequate controls in developing compliance strategies for this unit Therefore, the utility has no recourse but to rely solely on the purchase of credits, and there is no guarantee that any, much less a sufficient number of credits will be available. There are no emissions controls known at this time that would allow this unit to comply with the rule without the purchase of additional NOx credits. Consequently, the cost estimate for 2012 is based solely on the purchase of credits. In early 2009, the utility received quotes for NOx credits in the range of $7,000 per ton. At $7,000 per ton, it is estimated that it could cost as much as $1.1 million to obtain the necessary credits to operate this small, single unit utility in 2012. Accordingly, under the proposed Transport Rule, this small utility will be unreasonably penalized to operate in 2012 and future years. [EPA-HQ-OAR-2009-0491-2658.1,pp.6-7]
Gainesville Regional Utilities (GRU)
In addition, the proposed SO2 allowance allocations for DH#2 are significantly lower than what we expect the annual SO2 emissions will be. Currently we have two quarters of 2010 data that supports our expectation (see Table 2). [EPA-HQ-OAR-2009-0491-2674.1, p.3]
[Table 2 can be found on page 3 of this comment.]
Since EPA's preferred option for the Proposed CATR is a limited interstate cap and trade program, GRU feels strongly that realistic input data and assumptions for GRU must used by EPA in any future allocation scheme. [EPA-HQ-OAR-2009-0491-2674.1, p.3]
GE Energy Financial Services (GE EFS)
EPA Must Provide Facilities an Opportunity to Correct Inaccuracies in the Data Used by IPM, Before Relying Upon IPM's Projected Dispatch as the Basis for Allocations
GE EFS is also aware of instances in which the data used by IPM to predict future dispatch are inaccurate. While such inaccuracies may not have a material impact on the overall model results at the statewide or regional level, they can, at the level of the individual unit, have drastic and material impacts on the projected dispatch of a facility. In the case of Linden Cogen, these errors in the underlying data appear to have resulted in IPM's projection of dispatch at only a small fraction of its historical utilization, as described in more detail in the comments submitted by Linden Cogen. The IPM projections treat Linden Cogen as a peaking plant, instead of as one of the most efficient combined cycle cogeneration plants in the state. Before relying on IPM's resulting projections of future dispatch as the basis for unit-specific allocations, EPA must provide affected facilities such as Linden Cogen an opportunity to correct any inaccuracies in the data set and then re-run the model. [EPA-HQ-OAR-2009-0491-2701.1,pp.2-3]
Independence Power & Light (IPL)
As proposed, the rule would significantly affect the planning and operations of IPL. IPL has one unit listed in the rule, Blue Valley 3, and one unit that it expects to come online in 2012. Not only does the new rule fail to allocate any allowances to Blue Valley 3, it also states that this unit is scheduled for early retirement. Blue Valley 3 is an integral part of IPL's operations; by forcing it to shut down prematurely IPL and its customers could face increased costs and a potential electricity shortage. As a public utility, IPL must go through a lengthy and time-consuming process to obtain funding for emissions controls required by the proposed rule. Assuming IPL could obtain funding, this process often takes over a year to complete in addition to construction time for the new controls. This would be an almost impossible task to complete by 2014. Additionally, such projects require Independence taxpayers to foot the bill. I'm sure you can understand that this is a difficult proposition even in the best economic times. We certainly do not want to rush to conclusions about the best options for IPL and its customers. [EPA-HQ-OAR-2009-0491-1940.1, pp.1-2]
The inclusion of 2009 data in setting allowances has a deleterious effect on IPL because 2009 included a relatively cooler than normal summer. This resulted in greater availability of generation during what is normally IPL's peak season. One consequence of the abnormally cool summer was that IPL could purchase power more cheaply than it could generate electricity, which is a reverse from IPL's normal experience. Including the reduced use of IPL's own generation during 2009 in EPA's modeling produced lower emissions level for IPL than would normally be experienced and, as a result, proposed emissions allowances will be inadequate to permit IPL to meet its normal summer load. [EPA-HQ-OAR-2009-0491-2741.1, p.18]
JEA
EPA appears to be relying on data that are incorrect and result in unrealistic expectations for future emission rates
Specifically, the EPA assumed seasonal NOx emission rates of 0.043 lb/mmBtu for the CFBs at NGS Units 1 and 2 are unrealistic and may be unachievable even though both units are equipped with non-selective catalytic reduction (NSCR) technology. An ozone season NOx emission rate closer to the permitted value of 0.09 lb/mmBtu should be applied to these units. [EPA-HQ-OAR-2009-0491-2713.1, p.2]
NGS Unit 3, equipped with 10w-NOx burners, cannot possibly meet the EPA assumed annual NOx emission rate of 0.142 lb/mmBtu during normal operation and cannot meet the ozone season NOx rate of 0.069 lb/mmBtu even during natural gas operation at low load. A more reasonable projected emission rate for this unit would be 0.2 lb/mmBtu or higher for both annual and seasonal NOx since there are no NOx controls on this unit that can be adjusted to meet these low NOx emission rates regardless of the season. [EPA-HQ-OAR-2009-0491-2713.1, p.2]
In EPA's posted 'Projected Data' spreadsheet which was published with the proposed rule, it appears that EPA had not allotted SO2 allowances for those units which burn fuel oil and natural gas. JEA believes this reasoning is fatally flawed and does not have realistic assumptions related to the availability of natural gas in the state of Florida and in our service area. No SO2allowances were allocated to NGS Unit 3. It appears that EPA assumed that this unit can and will switch to lower sulfur fuels such as natural gas in order to meet SO2reduction requirements. This is not practical for JEA because JEA is a winter peaking utility and relies on this oil fired unit (capable of firing natural gas) to meet demand and maintain system reliability. Not having the ability to fire oil would reduce the availability of this unit during this critical time when natural gas is subject to curtailment due to higher priority uses in the state. [EPA-HQ-OAR-2009-0491-2713.1, p.2]
Achieving the EPA assumed SO2emission rates of 0.137 and 0.167 lb/mmBtu, respectively, for SJRPP Units 1 and 2 would require the use of low sulfur fuel, which may not be available, as well as the excessive and non-conventional use of dibasic acid, which already has limited availability and high cost. Assumptions that coal units can and will switch to lower sulfur burning coals in order to meet SO2reduction requirements is invalid. Many of the same questions apply to coal as with natural gas, those being what appears to be a lack of EPA's analysis on current burned coal sulfur limits and the capacity of rail lines to meet EPA assumed fuel switching requirements. [EPA-HQ-OAR-2009-0491-2713.1, pp.2-3]
JEA is open to and willing to work with EPA to develop more realistic and achievable emission rates for all its units. [EPA-HQ-OAR-2009-0491-2713.1, p.3]
Kansas Department of Health and Environment
KDHE is unsure how the revised IPM data in the NODA might impact allocations. It appears allocations will likely change to reflect updated utility data. Rather than comment on an unknown, KDHE would just point out the fact that there are currently several Kansas units listed in the proposed rule that have an ozone season allocation-but have no annual allocation. KDHE recommends this either be further explained or corrected. KDHE also recommends that the state be responsible for determining unit-level allocations after the EPA-derived state budget is finalized. [EPA-HQ-OAR-2009-0491-2606.1, p.6]
Lansing Board of Water & Light
EPA's spreadsheet "Budgets and Allocations - Detailed Unit-Level Data.xls" does not properly explain the rationale behind the emission rates, and heat inputs, and subsequent allocations. While data within the tabs "Unit Characteristics", "Reported Data", and "Adjustments" appear to be correct, BWL has concerns regarding the remaining tabs. [EPA-HQ-OAR-2009-0491-2752.1,p.2]
Very little explanation is provided regarding the "Projected" heat inputs. In the Technical Support Document (TSD) "State Budgets, Unit Allocations, and Unit Emissions Rates", a brief paragraph explains that the "projected data are assumed to be the annual (SO2, NOX, heat input) and ozone season (NOX, heat input) data projected by the IPM run". However, this does not properly explain why BWL units would see a drastic cut in the heat input rates. The following table contains information directly from the tab "Allocations & Rate Limits". [EPA-HQ-OAR-2009-0491-2752.1,p.2] [[See Docket Number EPA-HQ-OAR-2009-0491-2752.1, p.2 for the table.]]
The heat inputs that EPA is using to determine allocations are, for the most part, much lower than our actual operating history. BWL does not feel that it is appropriate for EPA to try to limit the heat input of our units. Setting an allocation based on a reduced heat input not only reduces the amount of pollutants but artificially reduces the generation. Instead the allocations should be based on actual (or an average of actual) generation. Table 2 presents the heat input for each unit from calendar years 2007 and 2008. Calendar year 2009 is not presented because it represents a statistical anomaly due to the severe economic downturn. [EPA-HQ-OAR-2009-0491-2752.1,pp.2-3] [[See Docket Number EPA-HQ-OAR-2009-0491-2752.1, p.3 for Table 2.]]
BWL has no objections to the proposed 2014 SO2 emission rate of 0.529 lb/MmBtu and believes compliance will be obtained through the continued use of low sulfur Powder River Basin coal. Therefore, using EPA's proposed emission rate and the 2-year average heat inputs from the previous table, BWL proposes the 2014 SO2 emission allocations as found in Table 3. [EPA-HQ-OAR-2009-0491-2752.1, p.3] [[See Docket Number EPA-HQ-OAR-2009-0491-2752.1, p.3 for Table 3.]]
In the same manner, the Annual and Seasonal NOx allocations can be calculated. However, BWL takes objection to the proposed emission rates. On page 45281 of the proposed rule, EPA states:
While EPA believes that it is not possible to require the installation of post-combustion SO2 controls (scrubbers) or post-combustion NOX controls (SCRs) before 2014 (because it takes about 27 months to install a scrubber and 21 months to install an SCR), EPA believes that there are significant reductions that can occur earlier. For SO2, reductions from operating existing scrubbers up to their design removal efficiencies and from the use of lower sulfur coals are possible by 2012. For NOX, reductions from operating existing SCRs on a year-round basis and up to their design removal efficiencies and the installation of limited amounts of low NOX burners are possible by 2012. For this reason, EPA believes it is appropriate to require these emissions to be removed in 2012  [EPA-HQ-OAR-2009-0491-2752.1,p.4]
EPAs proposed emission rates ranging from 0.1167 to 0.1814 lb/MmBtu are simply not achievable by January 1, 2012. Currently, BWL does not have any SCRs and has no plans for installation of this technology. The NEEDSv410.xls correctly lists the annual average NOx emission factor. However, this spreadsheet incorrectly lists the control technology currently employed by BWL, and thus incorrectly lists the assumed achievable controlled emission factor. BWL already operates low NOx burners with overfire air on all units except ORIS 1831, Unit ID 2. To make things more confusing, the NEEDSv410 spreadsheet does not match the Budgets and Allocations - Detailed Unit-Level Data spreadsheet. BWL believes the appropriate emission rates in which to base the allocations upon would be the NEEDSv410 modeled rates, albeit with corrected rates from Units 2 and 3. [EPA-HQ-OAR-2009-0491-2752.1, p.4]
As shown in Table 5, BWL proposes to use the modeled rates from the NEEDSv410 spreadsheet in conjunction with our 2-year average heat inputs to create an appropriate allocation. Table 6 uses the same concepts to create an appropriate allocation for the Seasonal NOx allowances.  [EPA-HQ-OAR-2009-0491-2752.1,p.5] [[See Docket Number EPA-HQ-OAR-2009-0491-2752.1, p.5 for Table 5.]] [[See Docket Number EPA-HQ-OAR-2009-0491-2752.1, p.6 for Table 6.]]
Louisiana Chemical Association (LCA)
Comments on NOx Allowance Unit Level Allocations.
EPA's IPM Projections for Louisiana EGUs Do Not Comport With Reality.
LCA believes that the EPA's allocation of NOx allowances under the proposed Transport Rule/FIP is fundamentally flawed. If it is determined that a FIP is still authorized and needed after consideration of the comments above, LCA requests that EPA substantially revise its methodology for allocations and the allocations themselves. EPA's scheme causes great economic inequity, for no discernible environmental reasons. EPA has refused to allocate any allowances to quite a number of sources in Louisiana simply because EPA's IPM modeling projects that they will no longer be operating or will be operating at only minimal rates. This means, if they are actually operating, they will have to purchase potentially millions of dollars per year worth of NOx allowances. While the economic model EPA used is not well understood, LCA suspects that the major cause of this projection is that EPA has erroneously projected natural gas prices, although that factor alone cannot account for the huge discrepancy between empirical data and the IPM projections. The majority of these sources are well controlled natural gas fired sources. For some reason, not completely accounted for in the data surrounding the proprietary IPM model, EPA has presumed these sources will not be operating at all, or will not be operating as much. As they are gas-fired sources are the sources that received such poor allowances (or no allowances) it is presumed that sensitivity to gas prices is a major factor in the model. However, because EPA projected these sources would not be operating, or operating at minimal rates, EPA apparently was unconcerned about providing allowances nor taking into account the impact on the numerous customers of these sources, residential, industrial and commercial if they received insufficient allowances. [EPA-HQ-OAR-2009-0491-3527.1, p. 40]
LCA believes that EPA cannot create this "alternate reality" simply by projecting that such units will not be operating. A comparison of actual data to the IPM projections in v. 3.02 shows that the IPM is highly inaccurate at predicting what fuel usage rates will be, utilization of EGUs outside the ozone season, and what units are "must run" units. EPA could have performed a "reasonableness check" or "calibration" on its' IPM assumptions simply by checking data reported to the Clean Air Markets Division by the EGUs regulated under the Acid Rain and CAIR programs, but apparently did not do so.109 LCA is attaching as Exhibit 10 hereto a table showing actual fuel usage during both the full year and the ozone season, actual NOx emissions during the full year and ozone season, and actual annual SO2 emissions during the full year for each year (each year 2005 - 2009 and the first 6 months of 2010). This highly reliable data was obtained directly from EPA's Clean Air Markets Division ("CAMD") and is based upon Continuous Emissions Monitoring Systems, certified fuel meters, and certifications by the designated representatives of each EGU. LCA has added columns to the table in Exhibit 10 to compare the actual CAMD data to the data from EPA's projections, via the IPM v. 3.02 Base Case modeling for 2012. This projection purports to reflect what EPA believes will occur in less than 18 months. This comparison shows large discrepancies between the actual data and the projected data and easily demonstrates that the IPM is inaccurate. This Exhibit is clear evidence as to why the IPM should not be used for the Transport Rule projections, and certainly not for making detailed, unit-level allocations where millions of dollars worth of allowances could be misallocated. [EPA-HQ-OAR-2009-0491-3527.1, pp. 40-41]
EPA Failed to Consider that Cogeneration Units Serving Industrial Facilities are Must Run Units.
 LCA is particularly concerned with the proposed impact of the NOx allocations on the facilities of four of its members: Dow Chemical, the owner/operator of the Plaquemine Cogeneration facility; ExxonMobil Chemicals, the lessee of the Louisiana 1 Facility; Occidental Chemicals, the owner/operator of the Taft Cogeneration facility; and PPG Industries, a 50% joint venture owner and the operator of the RS Cogen facility. Each of these EGUs are gas fired cogeneration sources providing critical steam and electricity to the Dow, Exxon Mobil, Occidental and PPG chemical manufacturing facilities. Excess electricity is sold to the grid. Each of these EGUs runs year round, not simply during ozone season. All of these units represent substantial investments in the hundreds of millions of dollars to Dow, ExxonMobil, Occidental and PPG. All have been operating at a high percentage of their capacity and have no plans whatsoever to curtail operations. [EPA-HQ-OAR-2009-0491-3527.1, p. 41]
It is unfathomable why, given these facts, that EPA would project that these four facilities would operate at trivial rates and only during ozone season. EPA sent no data requests to these facilities about future operations. EPA CAMD has a wealth of evidence indicating they were "alive and well," yet the IPM projects that they will be barely functioning in eighteen months. For this reason alone, not due to any environmental impact, EPA has proposed to provide each of these units with allowances covering only a small fraction of their annual NOx emissions and ozone season NOx emissions. Three of these four units are to receive proposed allocations less than 5% of their actual 2009 and historic operating rates would otherwise indicate. The fourth will receive allocations less than 10% of its 2009 actual NOx emissions and its 5 year average historic emissions as shown on Exhibit 10, attached. [EPA-HQ-OAR-2009-0491-3527.1, pp. 41-42]
Whatever assumptions EPA used to reach this result must be modified to comport with reality. The adverse financial impact to each of these facilities associated with the cost of purchasing NOx allocations would be enormous. The staff for the Louisiana Public Service Commission has estimated at least the following annual costs to these facilities for annual NOx allowances (i.e., not including ozone season allowances): Dow $159,768, ExxonMobil $1,224,000, Occidental $ 509,502, PPG $ 880,000. This estimate was based on a conservative assumption that annual NOx allowances would be valued at $1,200 per ton. With such a limited trading market as proposed by EPA, the adverse economic impact could be much higher. These are highly efficient, low emitting cogeneration units. EPA has no rational reason for imposing such costs on these facilities. [EPA-HQ-OAR-2009-0491-3527.1, p. 42]
The IPM is Deficient Through Failure to Consider Transmission Constraints.
LCA is also concerned about the proposed allocation of NOx allowances to public utilities from which LCA members purchase power. Many of the Louisiana Public Service Commission regulated EGUs in Louisiana received zero NOx allocations even though they have been providing critical power to Louisiana businesses and residential consumers for the past 5 years and have no announced plans to curtail operations. EPA's support documents indicated these same units do not need retrofits to reduce emissions. After weeks of communications with EPA trying to understand the basis of these proposed unit allocations, LCA was informed that the basis for this allocation scheme was EPA's IPM TR Base Case 3.02 modeling, which simply projects that due to economic factors unrelated to environmental issues, some units will not be running in 2012 or will be running at greatly reduced rates. As with the industrial cogeneration units discussed in the prior sub-section, the allocations among units were based on these projected, modeled economic consequences, not on any determination of environmental need. The result will be millions of dollars in windfall profits to certain units and significant costs to others, including the industrial consumers of such power. [EPA-HQ-OAR-2009-0491-3527.1, p. 42]
EPA staff also informed LCA that the IPM model does not account for transmission constraints or other factors that make these "must run" units.111 We are concerned that all of the units in the New Orleans area and across much of South Louisiana did not receive adequate allowances to allow operation at a level commensurate with local needs and that there are significant deficiencies in the IPM and/or with economic assumptions used therein that do not reflect real world constraints. See the map attached as Exhibit 12. As can be readily seen, EPA's projection via the IPM would have one believe that most of the power plants in south Louisiana will be shut down. Addressing such assumptions requires gathering of a significant amount of data from a number of EGUs, including those that are not LCA members, to demonstrate why such units are "must run" units, what the transmission constraints are, and how other factors that the model did not take into account will impact the utilization of those EGUs. This will take more time than EPA has allowed for the comment period. LCA will supplement this data as it becomes available. LCA urges EPA to consider the comments of the staff of the Louisiana Public Service Commission and the comments of the Louisiana Energy and Power Authority filed in this docket concerning this issue.  [EPA-HQ-OAR-2009-0491-3527.1, p. 43]
Louisiana Energy and Power Authority (LEPA)
LEPA is a political subdivision of the State of Louisiana created by statute to assist small and medium-sized towns and cities throughout Louisiana in obtaining reliable and economic wholesale power and energy. Many of LEPA's member municipalities are located in transmission constrained areas and have limited options for serving load. LEPA and its member cities and towns obtain the most economic, efficient resources available to it, but have limited access to such resources because of limited available transmission capacity. As a result, LEPA has several must run generating units that must run to serve load in LEPA's service area. Yet, the proposed Transport Rule allocates no emission allowances to those must-run units. LEPA's member cities and towns would be disproportionately and detrimentally impacted by this lack of emission allowances by way of dramatically increased costs, and/or total lack of electric power during thousands of hours of peak usage annually. [EPA-HQ-OAR-2009-0491-2700.1, pp.1-2]
THE PROPOSED RULE WOULD SIGNIFICANTLY RAISE ECONOMIC AND SOCIAL COSTS IN TRANSMISSION CONSTRAINED AREAS, DISPROPORTIONATE TO THEIR CONTRIBUTION TO THE POLLUTION EPA SEEKS TO ADDRESS. [EPA-HQ-OAR-2009-0491-2700.1, p.19]
The proposed Transport Rule does not allocate allowances in a manner that appropriately recognizes must-run capacity in transmission constrained areas, and allocates no allowances to LEPA's critical must-run units. LEPA would be forced to buy expensive allowances in a constrained trading market, if allowances are available at all. More likely, LEPA would be forced to rely on capital investment to achieve compliance. That investment would require the expenditure of unknown millions of dollars that may be spread over the very small population of LEPA's member communities. The costs per electric customer in LEPA's service area could be significant. [EPA-HQ-OAR-2009-0491-2700.1, p.19; for additional comments pertaining to see pp.19-20]
Louisiana Public Service Commission
The LPSC Staff is particularly concerned about the baseline data used in developing the allocations for each of the electric generating units ('EGUs') under the newly proposed Transport Rule. Louisiana has a complicated set of generation and transmission arrangements, largely the result of a diversity of both regulated utility EGUs and non-regulated independent power producers ('IPPs') and industrial cogeneration units. The LPSC Staff has a number of analysts examining EPA's baseline data, models, and model assumptions as they relate to our unit EGU mix. [EPA-HQ-OAR-2009-0491-1928.1, p.1]
Furthermore, the LPSC Staff is concerned about the proposed allocation of NOx allowances under the proposed rule, particularly the allocations estimated for many of Louisiana's highly efficient natural gas-fired cogeneration units that supply up to 25 percent of the state's electricity to regulated customers. Inappropriate allocations to these industrial facilities could increase the cost and/or availability of electricity generated on behalf of the state's regulated customers (through their qualifying power sales to regulated utilities). An inappropriate allocation also impacts these industrial facilities' economic competitiveness.[EPA-HQ-OAR-2009-0491-1928.1, p.2]
The LPSC Staff's initial review of the cogeneration allocations suggests that these units have received allocations that are some 20 percent below their 2009 actual NOx emissions, as well as below their 5 year average historic emissions. However, additional time is necessary to prepare comments on these issues and their impact on the reliable generation of power for Louisiana ratepayers. [EPA-HQ-OAR-2009-0491-1928.1, p.2]
The EPA's proposed allocation for cogeneration facilities fails to appreciate the state-specific solution all stakeholders reached during the CAIR process of 2006. The original CAIR Model Rule, which set allocations on a heat input basis, would have provided cogeneration facilities with considerable extra allowances given their efficiency and state-of-the-art controls since most of the cogeneration and IPP generators were either developed or repowered after 1999. Recognizing this potential windfall, the Commission recommended, and LDEQ adopted, an allocation mechanism that would make every cogeneration and IPP facility whole for their reported emissions and no more. The LPSC recommended 'clawing back' part of those allowances to serve as offsets to support older regulated generation, including the new unit addition at the Brame Energy Center. The EPA's proposal in CATR, however, undermines close to a year's worth of effort in developing a compromise in this regard. [EPA-HQ-OAR-2009-0491-2670.1, pp.13-14]
Schedule LPSC-6 summarizes the NOx allocation changes from CAIR to CATR on a summary basis for each of the EGU operators, per fuel type, in Louisiana. Under CAIR, Dolet Hills and the Brame Energy Center were scheduled to receive meaningful and significant allocations of between 9.0 percent and 11.5 percent of the statewide total allocation. Under EPA's proposal, both of those units will retain 26.2 and 21.0 percent of the statewide total, respectively. Looked at differently, almost half (47.2 percent) of the total NOx statewide allowances have been allocated to two units that generate less than 10 percent of the fossil-fired electricity in Louisiana. [EPA-HQ-OAR-2009-0491-2670.1, p.14]
Schedule LPSC-6 clearly shows those that are advantaged versus disadvantage under EPA's CATR proposals. Utility gas units are significantly disadvantaged, with ELL being penalized the most significantly of the entire group. EPA would allocate 13 percent fewer allowances to ELL relative to CAIR, or a 96 percent reduction in the amount ELL has anticipated, to date. The same is true for ENO, which will see its share of the statewide total reduced by 4.2 percent. Since ENO only received a 4.2 percent allocation in the first place under CAIR, the EPA proposal represents an unexplained 100 percent reduction in ENO's NOx allocations. The LPSC finds this result to be unacceptable. [EPA-HQ-OAR-2009-0491-2670.1, pp.14-15]
[Schedule LPSC-6 can found at the end of this comment.]
Michigan Municipal Electric Association (MMEA)
EPA's assumptions and unit-specific allocation methodologies for several Michigan municipal utility units are in error. [EPA-HQ-OAR-2009-0491-2828.1, p.2]
6.) EPA's Unit-Specific Allowance Allocations Have Significant Errors & Problems
These comments provide input on several data errors with respect to Michigan public power EGUs that have impacted the rule and allowance allocations. The prevalence of data errors and misassumptions with respect to our relatively small group of covered sources makes the entire emissions and allocation model suspect, and makes the imposition of a FIP and its unit-specific allocations even more of a concern. These errors include: [EPA-HQ-OAR-2009-0491-2828.1, p.11]
[For tables and additional comments pertaining to EPA's Unit-Specific Allowance Allocations, see pages 11-14 of this comment.]
Minnesota Power 
Data discrepancies.  There are still apparent discrepancies in Minnesota source emissions data used by EPA in their modeling and the Minnesota actual emissions and projected emissions at modeled output levels and permitted emission rates.  It creates difficulties in assessing the correctness of unit data when the same unit can be posted with projected emissions based on historic actual emissions, projected emissions at the actual emission rate or projected emissions at the permitted emission rate.  EPA should clearly identify the basis for unit level emissions applied when they estimated state significant contributions to nonattainment and state emission budgets calculated relative to a 2005 base year, emission control retrofit estimates and assumptions about future unit generation output.  It is not clear if EPA is giving reasonable consideration or credit for early controls installation in the Transport Rule.   [EPA-HQ-OAR-2009-0491-2750.1, pp.8-9]
Unit level data and budget calculation discrepancies. Several Minnesota generating units are presented by EPA with little or no budget allocations. Some units appear to have discrepancies with how EPA described permitted emission limitations. Examples include the M.L. Hibbard Energy Center Units 3 and 4, which are not included in EPA's unit allocations listing. Taconite Harbor Energy Center Unit 3 permitted emission rates do not match. Estimates for unit level budget allocations assigned under EPA's methodology appear to assign smaller allocations for units that provided for post 2005 emission controls than for units that have implemented no emission reduction measures.  Minnesota Power intends to provide further commentary to address such matters when submitting comments to the Transport Rule Notice of Data Availability. Regardless, EPA needs to provide information that explains the basis for budget allocations and emission projections on a unit specific basis.    [EPA-HQ-OAR-2009-0491-2750.1, p.9]
Correction review time before rule finalization. If EPA corrections in proposed Transport Rule data inputs or modeling design are made, EPA should offer those changes for public review and comment before EPA finalizes the Transport Rule. [EPA-HQ-OAR-2009-0491-2750.1, p.9]
Missouri Public Utilities Alliance (MPUA)
4. We believe that 2009 is an inappropriate and misleading baseline year for determining emissions both for reasons related to weather and to the economy.  NOAA ranked the Midwest as in the lower range of normal temperatures for the year of 2009.  Additionally the region also saw significant cuts in demand for electric power as businesses, especially manufacturing, cut operations because of the financial recession.   As a result our power plants operated at lower levels and emitted lower emissions than what would be considered "normal".  We request that EPA provide greater justification for the selection of the year and demonstrate that emissions were in a normal ranger or explain how lower emissions for weather and the economy were considered in setting the final limits. [EPA-HQ-OAR-2009-0491-2785.1, p.3]
New York State Department of Environmental Conservation
In the supplemental notice, EPA specifically requests comment on the appropriate natural gas assumptions to use. When attempting to analyze the data from the original Transport Rule proposal, in the 'Budgets and Allocations - Detailed Unit-Level Data,' to determine the appropriateness and accuracy of EPA proposed allocations to generating units in New York, Department staff found that the heat input data was misstated by a factor of ten. Given the incorrect values provided in the data tables, the Department was unable to properly analyze the data and is not comfortable with the allocations EPA has provided to any of the units. Despite the poor quality of the data presented in EPA's original analysis, the Department was able to identify serious inequities in the proposed state level allocations. See Department comment letter to the docket dated October 1, 2010. [EPA-HQ-OAR-2009-0491-3763.1_NODA, p.1]
Occidental Chemical Corporation (OCC)
Furthermore, EPA's databases supporting the proposed rule do not include any information with regard to OCC's La Porte, Texas cogeneration facility, despite the fact that it is located in a state subject to the ozone season NOx control and allowance trading requirements of the proposed rule. OCC has no plans to close this facility. We agree that the La Porte facility need not receive emissions allocations if we conclude that it is an exempt cogeneration facility. However, we believe that EPA should include technical information on the facility in the relevant modeling databases. [EPA-HQ-OAR-2009-0491-2754.1, p. 3]
However, should EPA feel compelled to include certain QF cogeneration units in Texas and Louisiana in the Transport Rule's emissions allocation scheme, we respectfully request that if our units are not exempt, EPA grant at least 1,463 tons of annual NOx allowances, 17.7 tons of annual SO2 allowances, and 610 ozone season NOx allowances to OCC's Taft cogeneration units; grant at least 200 tons of ozone season NOx allowances to our La Porte facility; and retain the Ingleside facility's proposed ozone season NOx allowances. These allocations will ensure that we may continue to generate power and steam for internal and external consumption from our modern, clean-burning and ultra-efficient units. [EPA-HQ-OAR-2009-0491-2754.1, p. 4]
Problems with the Modeling and Resulting Unit-Level Allowance Allocations
In the event EPA elects to retain cogeneration units in the final CATR, it is imperative that EPA correct the various databases and modeling efforts supporting the proposed rule. EPA used either faulty assumptions and incorrect inputs or a faulty model. The model and its associated documentation are not transparent. EPA's allocation system is flawed and inconsistent with reductions possible at a cogeneration facility.  [EPA-HQ-OAR-2009-0491-2754.1, p.16]
Summary of OCC Unit Information Set forth in the following chart is a technical summary of OCC's cogeneration units covered, or potentially covered, by the proposed Transport Rule. This information provides the basis for identifying several errors in EPA's databases.  [EPA-HQ-OAR-2009-0491-2754.1, p. 16; see pp. 16-17 for the chart.]
NOx Emissions Abatement Technology and Unit-Level Allocations OCC has extensive experience with NOX emissions abatement technology. OCC has installed dry low NOx burner technology at the Taft and Ingleside facilities; ultra dry low NOx burner technology at the La Porte facility; and Selective Catalytic Reduction ("SCR") technology at the La Porte facility. A summary of emission rates from these facilities is as follows:   [EPA-HQ-OAR-2009-0491-2754.1, pp. 17-18; see p. 18 for the table.]
The Taft cogeneration facility fires pipeline quality natural gas in combustion turbines and natural gas and hydrogen in heat recovery steam generators ("HRSGs"). Both the combustion turbines and HRSGs are equipped with dry low NOX burner control technology. On average, in 2009 the facility's NOX emission rate was approximately 0.027 pounds per MMBTU. The facility's 2009 estimated emissions totaled 505 tons of NOX. However, OCC anticipates that steam demand from the host facility and electricity demand will increase over the next decade in response to an improving U.S. economy and OCC's long-term power supply agreement with the local utility. OCC anticipates increased demand in 2010 over 2009 requirements, such that 2010 NOx emissions are expected to increase.  [EPA-HQ-OAR-2009-0491-2754.1, p.18]
Based on information provided in EPA's emissions allocation table associated with the proposed rule,34 the Taft cogeneration facility would be allocated only 26 tons per year ("tpy") of NOX emissions in 2012. Thus, assuming that the Taft facility is not exempt and assuming operating rates equivalent to 2009 rates, OCC would be required in 2012 either to abate 479 tons of NOX emissions (which is not technically feasible), purchase 479 allowances (equivalent to 479 tons of emissions), or a combination thereof. At full rates, it is estimated that the facility would need to abate and or obtain allowances for an additional 1,437 tons of NOX emissions.  [EPA-HQ-OAR-2009-0491-2754.1, p.18]
As noted further in our comments, there is not any mention of the La Porte, Texas facility in any of the IPM information, including any of the supporting data bases. If this facility is not exempt and is subject to the final CATR, it must be allocated 200 tons of NOX for ozone season emissions.  [EPA-HQ-OAR-2009-0491-2754.1, p.18]
We support the ozone season NOx allowances (227 tons) provided to the Ingleside cogeneration facility. [EPA-HQ-OAR-2009-0491-2754.1, p.18]
The information contained Budgets and Allocations - Detailed Unit-Level Data Base3 is not accurate. We reviewed the information contained in the following spreadsheets that were presented in the Budgets and Allocations  -  Detailed Unit Level Data base: Unit Characteristics, Reported Data, Projected Data, Adjustments, Adjusted Data, Allocations and rate Limits. Our comments on information contained in each of the spreadsheets (where applicable) are as follows:  [EPA-HQ-OAR-2009-0491-2754.1, p.21; see pp. 21-27 for spreadsheets and comments]
In summary, we are extremely concerned that since the Agency does not have accurate information regarding certain model parameters, the output from the IPM is flawed. In particular, we are concerned that the there is no reference to our La Porte Cogeneration facility; the steam turbines at both the Ingleside and Taft facilities are being modeled as emission sources; and further, that erroneous heat rates are being used to develop power distribution and emissions analyses. Consequently, due to the numerous data inconsistencies and errors noted above, we seriously question the validity of the output from the IPM. [EPA-HQ-OAR-2009-0491-2754.1, p.27]
We presume that since the IPM uses historical data to determine future fuel use and power projections and emission allowances, the use of Ingleside's historical data would be needed to develop an accurate assessment of both power distribution and emissions. Thus, we request that historical information for the Ingleside facility be included in the IPM for this rulemaking. [EPA-HQ-OAR-2009-0491-2754.1, p.27]
We request that modeling inputs be corrected to account for the information listed above before any additional modeling occurs. Furthermore, while the record provides some information on the IPM, based on the fact that the model predicts different heat inputs for the same facility in 2012, we question whether it can be used to model unit specific power generation, emissions and emission rates across half of the United States. [EPA-HQ-OAR-2009-0491-2754.1, p.27]
In particular, we question EPA's use of the Integrated Planning Model ('I PM') for developing emissions allowance allocations. It is our understanding that the I PM is an economic model that cannot account for the complex and realistic operations of power generating facilities and transmission grids. For example, the IPM apparently does not take into account electric load or steam demand by a co-located power/steam host. Thus, the operation of a facility like our Taft cogeneration plant, which provides both a significant amount of steam and electricity to the co-located OCC-owned manufacturing facility, is not modeled correctly. EPA's failure to recognize, model and allocate allowances to cover nondiscretionary emissions generated in connection with the legitimate operation of a manufacturing facility constitutes a fundamental flaw in EPA's allocation of emissions allowances and the CA TR. Furthermore, the model does not take into account legally binding power contracts or other supply mechanisms that exist now and into the future, or state and federal regulations governing electricity pricing and cost recovery. [EPA-HQ-OAR-2009-0491-3796.1, p. 2]
The Documentation for the IPM v. 4.10 Base Case, Chapter 3.5.1 indicates that EPA made certain assumptions about EGU availability in its modeling. EPA stated 'Power plant availability is the percentage of time that a generating unit is available to produce electricity to the grid. Availability takes into account both scheduled maintenance and forced outages ... ' EPA indicated that Appendix 3-9 shows the availability assumptions for all EGUs in EPA Base Case 4.10. EPA indicated that it used an 85% availability assumption for all combined cycle units. With the exception of total plant outages which occur infrequently, combined cycle facilities provide power on a nearly continuous basis. Percent availability information for our Taft Cogeneration plant is as follows: 
:: 2007 97.3 Percent Availability
:: 2008 89.3 Percent Availability
:: 2009 87.3 Percent Availability
:: 2010 (YTD) 97.3 Percent Availability
:: Average 92.8 Percent Availability [EPA-HQ-OAR-2009-0491-3796.1, p. 2]
These values take into account scheduled and unscheduled maintenance outages. Note that even in 2009 when the facility had several significant outages for scheduled maintenance, the percent availability was still above EPA's assumption. Thus, we question the validity and value of using the 85% availability assumption. Presuming that other combined cycle plants operate similarly, the IPM v. 4.10 Base Case would seem to be flawed. [EPA-HQ-OAR-2009-0491-3796.1, pp. 2-3]
We noted that the IPM v. 4.10 Base Case contains revised emission rates for the Taft Cogeneration plant. Specifically, it appears that emissions for the Taft Cogeneration plant are estimated to be approximately 49 tons of NOx per year. We presume that EPA will base a revised allowance allocation for OCC's Taft cogeneration facility on this revised emission rate, even though the allocation table provided by EPA for the IPM v. 4.10 Base Case does not appear to reflect this change. Irrespective of the presumed re-allocation, however, the revised emissions estimates are less than 10 percent of what the Taft cogeneration facility emitted in 2009, and only 3 percent of what it is authorized to emit. As mentioned in our previous comments, we respectfully request that EPA grant at least 1,463 tons of annual NOx allowances, 17.7 tons of annual S02 allowances, and 610 ozone season NOx allowances to OCC's Taft cogeneration facility so that if the facility does not meet the rule's current cogeneration exemptions, we may continue to generate power and steam for internal and external consumption from our modern, clean-burning and ultra-efficient units. [EPA-HQ-OAR-2009-0491-3796.1, p. 3]
In light of the deficiencies in the IPM capabilities, data inputs and assumptions, we strongly recommend that EPA abandon the use of the IPM (any version) for allocating unit level allocations. If fact, we are not aware of the IPM being used to model individual emission sources like, for example, single gas turbines at a multi-turbine facility. As an alternative, EPA should rely on the unit-level allocations previously established in State Implementation Plans ('SIPs') pursuant to the CAIR as the basis for allocating emissions in the CATR, including the Louisiana SIP. It is particularly important for EPA to allocate allowances in a manner consistent with existing SIP allocations because many EGU owners have already invested heavily in control technology strategies. These activities cannot be undone with any degree of economic rationality in response to EPA's proposed misallocation of allowances in the CATR. In this regard, EPA should take note of the fact that the Court's remand of CAIR had nothing to do with unit-level allocations. [EPA-HQ-OAR-2009-0491-3796.1, p. 3]
Oklahoma Department of Environmental Quality
[[2662.1 p.2-3]]
Oklahoma's Budget Allocation
Identification of Affected EGUs in Oklahoma
Based on our review of the Electric Generating Unit ("EGUs") listed by EPA in the proposed rule, we do not believe that any of Oklahoma's EGUs have been overlooked; all seem to have been accounted for.
Allocations to Specific Facilities
An analysis of the allocations proposed to be distributed to the Western Farmers Electric Cooperative Anadarko Facility indicates that the allocations were not properly calculated for all the units at that facility. That facility is comprised of some units that are required to report to the Acid Rain Program and some that are not. This may have been overlooked when EPA was developing the emissions data. The Acid Rain units for that facility usually emit about 10 tons of NOx per year, but the emissions for the Acid Rain and non-Acid Rain units approach 3,000 tons of NOx per year.
I. Natural Gas versus Coal-Fired Facilities
In Oklahoma, and perhaps elsewhere, natural gas-fired units were given much smaller budgets as compared to coal-fired units. The coal-fired power plants were allotted 27,088 credits, 3.41% more than their three year (2007  -  2009) average ozone season emissions of 26,194.  The gas-fired plants were allotted 8,064 credits, 6.20% less than their three year average ozone season emissions of 8,597. We are interested to know if this result was purposeful and, if so, why. It seems that EPA would want to incentivize facilities to switch to natural gas, a cleaner burning fuel; however, allotting fewer allocations for natural gas-fired units will not have that result.
[[2662.1 p.3]]
Oklahoma wishes to call EPA's attention to the Western Farmers Anadarko Facility's allocation as well as the apparent discrepancy between the allocations given to natural gas-fired versus coal-fired units.
Old Dominion Electric Cooperative
Based upon this assumption, the Louisa Generation Facility (ORIS Code 7837) and Marsh Run Generation Facility (ORIS Code 7836) were not provided any SO2 allocations and less than adequate allowances for NOx. ODEC requests that these units be provided allowances as listed in the following table. The number of allowances is based upon an average of the annual emissions for the calendar years 2007 through 2010. The ozone season allocations are based upon the maximum ozone season emissions for the same time period. ODEC's peaking units typically operate on natural gas during the ozone season, are very efficient, and, unlike base load units, have no technically feasible controls to reduce NOx emissions beyond the current design. Therefore, ODEC is requesting additional allocations to a maximum value from representative years. These numbers are still significantly below the maximum emissions reported during the same period. [EPA-HQ-OAR-2009-0491-2877.1,p p.4-5] [[See Docket Number EPA-HQ-OAR-2009-0491-2877.1, p.5 for the table.]]
Omaha Public Power District
Given the substantive issues with the Nebraska emission inventory used by EPA for its analysis, the appropriateness of using an episode-based procedure (see comment #8 above) for establishing significant contributions for 24-hour PM2.5, and the need for consistency in setting and rounding of significant impact levels, EP A should revise its analysis to determine if the TR should be applied to Nebraska.[EPA-HQ-OAR-2009-0491-2680.1, p. 6]
If after revising its analysis as appropriate to determine if Nebraska should be included in the TR, and if Nebraska is still determined to be included in the rule, we have the following additional comments:
1. EPA should clarify whether the allocations for the Nebraska 'MRO Coal Steam' unit listed in the allocation table are actually intended for OPPD's Nebraska City Station Unit 2, which came on-line in 2009. If these are meant to apply to Nebraska City Station Unit 2, the basis for the allocation is not consistent with the prevention of significant deterioration (PSD) BACT determination for this unit. While this unit has a PSD permit BACT S02 limit of 0.095 lb/MmBtu, the allowance allocation is based on an S02 emission rate of 0.06lb/MmBtu. It is not reasonable to assume that a unit will operate at a level that is over 35 percent lower than a recent stringent BACT limit. We request that EPA assign an S02 allowance allocation for this new well controlled unit based on an S02 emission rate of 0.095lb/MmBtu, commensurate with the BACT limit. [EPA-HQ-OAR-2009-0491-2680.1, p. 6]
Piney Creek LP
Supporting data for emissions values is incorrect.
1. The method is `generic', essentially using a ratio of annual unit heat values for each state to the total heat values reported to `divide up' the emissions that will be allowed from units in that state.
2. The method of calculating heat rates/heat input is `biased' using a cost value to `simulate' constant MW output within the state to the grid; this cost value is from `real coal' and about three times the actual cost of transport and preparation of waste coal for most of our units, which in the end reduces that `amount of heat input' on each ARIPPA unit to control total emissions within the state and yet provide grid reliability. It falsely approximates total heat input annually to operate at the reported MW net value from Part 75 reporting.
3. Additionally, a `false heat rate' is derived from previously reported data under NOx budget reporting that `back calculates' heat input using a `default' `f' factor that ignores heat input to Calcine limestone in addition to the absorbed heat loss in a high ash fuel which is not recovered into the `steam cycle' but lost to ash processing. This problem is `enhanced by item 2 above, by `adjusting' an incorrect heat input with an incorrect cost bias. A more realistic approach is to directly multiply the mass of fuel put into the boiler times it's heat value as that method was `mandated' when these plants were designed.
4. The result of the above `errors' results in an annual reduced heat input allowance for each ARIPPA unit, often to the point of listing annual heat inputs as calculated with the current `cost bias' method of about 2/3 of the real value. This often will cause units to `violate' terms of their existing PPA's, that require 80-85% peak generation of the last few years. It also `falsely' causes `winners' and `losers' in a deregulated market though `caps' that are disproportionately applied to ARIPPA CFB units.   [EPA-HQ-OAR-2009-0491-2535, p.1]
PowerSouth Energy Cooperative
The data period used to develop the Proposal is too short to fairly represent each plant's range of operations and penalizes units for planned and unplanned outages that occurred during the extremely brief data period.  The Proposal uses only four strategically selected quarters of data to determine heat inputs and emission rates.  While this tact may have made it easier for EPA to design its regulatory remedy, it is inappropriate for such an important part of the Proposal.  EPA must use more data.  An alternative EPA has successfully used in the past is the highest three of five year methodology for heat inputs in the NOx SIP Call.   A larger data period more representative of plant operations is absolutely vital if the Proposal is enacted. [EPA-HQ-OAR-2009-0491-2693.1,p.5] 
The Proposal as written contains grievous errors and should be discarded.  As noted above, the Proposal is ill-conceived on so many levels.  To add insult to injury, the Detailed Unit Level Data Spreadsheet omits units, mislabels units and allocates allowances to units not entitled to allowances.  The Proposal should be scrapped and a new rule should be developed with input from the stakeholders.  [EPA-HQ-OAR-2009-0491-2693.1,p.7]  
Renaissance Power
In review of the budget allocations for the Renaissance Power Plant in Michigan, ORIS 55402, Renaissance Power believes that the use of the projected data to estimate the allowances for this project significantly misrepresents the expected usage of the plant. Renaissance Power has had capacity factors of
2005  -  7.41%
2006  -  4.89%
2007  -  5.29%
2008  -  4.07%
2009  -  3.33% 2010  -  6.44% (YTD)  [EPA-HQ-OAR-2009-0491-3018,p.1]
The allocation uses projected data which shows that the capacity factor for the plant will drop to 0.6% - a significant change (88% reduction from the 5 year average) from the above historical capacity factors. As Renaissance Power is a peaker facility, the addition of new controls on major units won't change their ability to provide power during peak periods so Renaissance Power does not believe that the use of projected data is appropriate for its facility. [EPA-HQ-OAR-2009-0491-3018,p.1]
State of Delaware Department of Natural Resources & Environmental Control
The first recommendation is that EPA reconsiders the use of the most recent quarterly data from the period 2007 through 2009 as the baseline. It is popularly viewed that calendar year 2007 is the last calendar year that has little effect from the current economic downturn. As such, it is assumed that the operation of EGUs in 2007 is more representative of expected normal operation for the units that operated during that period. For many of the units not incorporating post-combustion controls, unit hourly loading and average capacity factor can have a noticeable effect on emission rates (in terms of 1b/MMBTU or lb/MW). Therefore, it is Delaware's opinion that utilizing 2007 operating data would provide a more accurate indication of both the units' uncontrolled emission rate and the emission rate resulting from the theoretical installation of emission controls. For units that did not operate in 2007, such as new units, emissions data from the earliest of 2008 or 2009, as applicable to the individual unit, could be utilized. EPA-HQ-OAR-2009-0491-2980.1, p.5]
EGU Inventories. During review of EPA's technical support documents for budgets and allocations for the proposed rule, Delaware has identified a number of problems with the inventory of EGU's included by EPA in the development of the budget and allocation levels for Delaware. 4 The problems noted during Delaware's review include the following: [EPA-HQ-OAR-2009-0491-2980.1, p.7] 
EPA's proposed rule unit inventory has included in Delaware's unit inventory a number of units that are co-generation units. [EPA-HQ-OAR-2009-0491-2980.1, p.7]By combining sources of data and information concerning units, as discussed in EPA's TSD State Budgets, Unit Allocations, and Unit Emissions Rates, EPA 'double counted' emissions among three Delaware units, by accounting for emissions for two header supplied steam turbine- generators from one data source, and then from another data source accounting for emissions from a boiler that supplies that steam header for the two header supplied steam turbine-generators. [EPA-HQ-OAR-2009-0491-2980.1, p.7]
EPA's emissions data and allowance allocations have included header steam turbine generating units that are supplied by multiple non-fired heat recovery steam generating units. As the boilers are not fired, it is uncertain how they would produce emissions given that the emissions associated with related combustion turbines are attributed directly to those combustion turbines. [EPA-HQ-OAR-2009-0491-2980.1, p.7]
EPA excluded two Delaware units from the proposed program, apparently due to the EPA's data assigning the units output ratings less than 25 MW. It appears that the EPA based this rating on data that indicates that these units have 'summer' ratings of 22 MW on a net output basis. However, these particular units have 'nameplate' ratings in excess of 25 MW, and also have 'winter' ratings of 25 MW on a net basis. There are three apparent issues demonstrated within this problem. [EPA-HQ-OAR-2009-0491-2980.1, p.7]
The first apparent issue is the use of 'summer' output ratings, which includes the effect of higher summer temperatures reducing the output of the unit, which is contrary to the definition of nameplate rating included in the EPA's proposed rule which states, 'Nameplate capacity means, starting from the initial installation of a generator, the maximum electrical generating output (in MWe) that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings) as of such installation as specified by the manufacturer of the generator ... ' [EPA-HQ-OAR-2009-0491-2980.1, pp.7-8]
The second apparent issue with the use of 'summer' output ratings, is that the 'summer' output ratings includes the effect of higher summer temperatures that . tend to reduce the output of some units (combustion turbines and steam units). This appears to be contrary to EPA's definition in the proposed rule, as noted above, that indicates that the nameplate rating should not include any capacity restrictions due to 'seasonal or other deratings'. [EPA-HQ-OAR-2009-0491-2980.1, p.8]
The third apparent issue is the use of these values that are 'net' unit electrical outputs, or the electrical output available to the grid after subtracting any electrical energy that is utilized by the unit in the generation of the total electrical energy. The definition of nameplate capacity in EPA's proposed rule, as noted above, clearly indicates that EPA intends that nameplate capacity be the gross electrical output, or total electrical output from the generator. [EPA-HQ-OAR-2009-0491-2980.1, p.8]

Footnote:
4 Because of the generic nature of some of these apparent problems, Delaware is of the opinion that similar issues may exist for some other states subject to this proposed rule. These problems that appear to have the potential to generic in nature should be investigated by EPA and corrected as necessary in establishing final emissions budgets, allocations, etc. [EPA-HQ-OAR-2009-0491-2980.1, p.7]
Tampa Electric Company
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.55.]
Given the short period of time to evaluate, that's been a recurring theme I guess in talking with our other -- our peers, colleagues.
If we could have -- I know I've gotten a lot of information on the website, spreadsheets with maybe formulas and links. It's just data in there.
Sometimes it's difficult and time-consuming to decipher how we got those, so that would be helpful, and then maybe we can get with the specific people, some specific people on that.
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.70-71.]
However, we are still unable to determine how the allocation spreadsheet inputs are related to one another and are utilized in determining the models outputs.
One suggestion, please provide the links within the spreadsheets, unless only macros are used, to help us follow along the allocation logic. We believe the models outputs can be used as a powerful tool to aid in the development of the Transport Rule, but it should not be a definitive artifact in the formation of the rule and determining states emission budgets. EPA has already identified that a number of data errors exist in the model. These errors can have potentially dramatic impacts on the results of the model.
Just within our mid-sized electric generation fleet, a number of model input assumption errors have been identified. Examples of the types of errors found include: Allocating different emission budgets to identically sized and controlled units, or dispatching the same unit differently for estimated NOX and SO2 future emissions and consequential downwind effects.
Tennessee Department of Environment and Conservation, Division of Air Pollution Control
Comment #3 on Emissions Budgets: We reviewed the annual SO2 budgets for 2012 and 2014, annual and ozone season NOX budgets for 2012, estimated emissions, and IPM projections for several States (see Attachment #3) [[See Docket Number OAR-2009-0491-0553.1, pp.8-13 for Attachment 3]]. When variability is considered, the 2014 budgets appear to be fairly close to the IPM predictions, but IPM predicts that emissions from most of these States will be slightly above their three-year allowance (see Table 1b in Attachment #3, column #6). EPA should consider adjustments to bring the 2014 budgets plus variability into line with IPM predictions. [EPA-HQ-OAR-2009-0491-0553.1, p.4]
Comparison of the 2012 budgets with actual emissions, rather than IPM predictions (see Table 1b in Attachment 3, columns #5 and #8), suggests that many States will require greater SO2 reductions than predicted by IPM. The Transport Rule analysis assumes no additional add-on controls between 2010 and 2012, but we are concerned that the necessary reductions for 2012 may not be achievable with existing controls and low-sulfur coal. This analysis is based on lowest corrected emissions (i.e., lowest emission rate and lowest heat input), and greater reductions would be required at higher heat inputs. [EPA-HQ-OAR-2009-0491-0553.1, p.4]
To a lesser extent, we have similar concerns with annual and ozone season NOX emissions (see Tables 2 and 3 in Attachment #3). The 2012 emissions budgets appear to be attainable at lower heat inputs, but some States may encounter similar difficulties with NOX reductions at higher heat inputs. [EPA-HQ-OAR-2009-0491-0553.1,p.4]
We understand that EPA has reviewed these issues in detail, but we request that EPA take a closer look at IPM data and historic emissions to ensure that all factors have been taken into consideration. [EPA-HQ-OAR-2009-0491-0553.1, p.4]
Utility Air Regulatory Group (UARG)
In addition to the NEEDS and IPM input errors, it appears EPA made downward adjustments to NOx emission rates in IPM that are unwarranted, unreasonable, and inaccurately described in the State Budgets TSD. The State Budgets TSD indicates that "NOx controls were assumed not to control beyond a floor of 0.06 lb/mmBtu." The 0.06 lb/mmBtu rate would be more accurately described as a ceiling than a floor because of the adjustments EPA made to NOx emission rates. If a unit reported historical data that supported a NOx emission rate lower than 0.06 lb/mmBtu, EPA used that lower emission rate. Yet if a unit reported historical data that demonstrated a NOx emission rate higher than 0.06 lb/mmBtu, EPA -- apparently arbitrarily -- made a downward adjustment of that rate to 0.06 lb/mmBtu. Such downward adjustments are unfair and unwarranted. Incentives exist in most cases to emit at the lowest reasonably achievable NOx emission rate, and if a given unit reports NOx emissions at rates above 0.06 lbs/mmBtu, it is likely that that unit cannot physically and consistently operate at a lower rate. At a minimum, an across-the-board downward adjustment to 0.06 lb/mmBtu, without consideration of case-by-case factors, cannot be justified. Under EPA's proposed approach, where an existing unit cannot in fact meet the 0.06 lb/mmBtu rate, that unit may well be forced to upgrade its pollution control device or acquire allowances. EPA did not anticipate either of these options in the PTR and does not seem to have accounted for the costs associated with these options in the PTR. EPA should abandon its approach of making across-the-board downward adjustments to 0.06 lb/mmBtu and should instead use historical reported emission rates on a unit-by-unit basis. [EPA-HQ-OAR-2009-0491-2756.1, pp.84-85]
Wisconsin Power and Light Company
Finally, WPL is highly concerned that flawed data and operational assumptions will negatively and disproportionately impact the implementation of EPA's preferred option. As a consequence of the NODA, the EPA has stated that issuance of the final rule will require significant changes to modeled outcomes impacting both state budgets and individual EGU allocations. WPL recommends that prior to issuing a final rule, EPA release a Supplemental Notice of Proposed Rulemaking and/or a Notice of Data Availability ('NODA') that allows owners of covered units to verify the data underlying the allocations in the final rule and provide any necessary comments correcting the data. Without the critical step, it is inconceivable that the EPA will be able to realistically revise its state budgets and source allowance allocations to accurately reflect when and where emissions reductions can be achieved in a highly cost-effective manner. EPA must allow affected sources to validate the use of these models on the operation of their electric generation fleet and ensure sufficient time to prepare for compliance. [EPA-HQ-OAR-2009-0491-2844.1 p.6]
Response: 
The final Transport Rule allowance allocation tables can be found in the Allowance Allocation Final Rule TSD.  EPA also notes that, as requested by commenters, it made all the historic data used in the heat input allocation alternatives available to the public for review and comment through the January 7, 2011 NODA.  Because those approaches were based on historic data that had been reported by the source's designated representative who had testified to its accuracy and completeness, EPA did not expect many corrections.  Nevertheless, the Agency still allowed for a public review of the data and subsequently made corrections to historic heat input and emissions data where the commenters provided reasonable corrections.
The final Transport Rule approach to determining state budgets reflects improvements made from the proposal based on comments.  Some commenters noted that the proposal's budgets did not appear to match the IPM projected state-level emissions at the final cost thresholds determined in the multi-factor analysis.  EPA used an approach for determining budgets in the final rule that is directly based on projected IPM emission levels from fossil fuel-fired units greater than 25 MW that remain after significant contribution has been eliminated in an average year.  Additionally, EPA notes that there is no relationship between final Transport Rule state emission budgets and CAIR state emission budgets.  As discussed in the preamble (see section III, V.B, and VI), the Court determined those budgets to be illegal and the Transport Rule was designed to replace those budgets with new budgets that reflected the elimination of significant contribution at the state level.
EPA also made updated to its IPM modeling (see EPA IPMv.4.10 documentation) to better reflect the feasibility and cost-effectiveness of coal switching. 
Organization: International Paper
Comment: 
International Paper
International Paper was alerted to the fact that its units were listed on Transport Rule Allocation tables associated with the proposed Transport rule. International Paper operates its Augusta Mill under Part 70 Permit 2631-245-0006-V-02-0; Facility AIRS Number 04-13-245-00006 [EPA-HQ-OAR-2009-0491-2784.1 p.1]
Specifically, International Paper-Augusta Mill's Kraft pulping liquor recovery furnaces, RB2A No.2 Recovery Boiler and RB3A No.3 Recovery Boiler, were listed as affected units (ORIS 54358) in Georgia. These units, prior to EPA revising the cogeneration definition on October 19, 2007 72FR59,190, where affected facilities under the CAIR rule. However, based on EPA's current definition RB2A and RB3A are cogeneration units and not subject to CAIR or the Transport rule. [EPA-HQ-OAR-2009-0491-2784.1 p.1]
Augusta Mill's Recovery Boilers meet the definition of cogeneration units with useful power efficiencies consistently in the 100% to 10,000 % range for the RB2 and RB3. The high power efficiencies are a result of the boilers primarily being biomass burners. [EPA-HQ-OAR-2009-0491-2784.1 p.1]
Recovery Boilers at Augusta are not subject to the various sections of the Transport Rule as outlined in the proposed applicability sections (§§ 97.404 and 97.405, 97.504 and 97.505, 97.604 and 97.605, and 97.704 and 97.705-Applicability). Specifically, these units are not applicable unit because they qualify as exempt cogeneration units as outlined in, for example, 97.404(b)(1 )(i). [EPA-HQ-OAR-2009-0491-2784.1 p.1]
We support EPA's applicability definitions. However, please remove the recovery boilers from the applicable units table.' If you would like to contact us, feel free to call or write Jeremy.Pearson@ipaper.com or 706-796-5363. Thank you. [EPA-HQ-OAR-2009-0491-2784.1 p.1]
[[These comments are also posted under section V.F.3]]
Response: 
EPA is not making any applicability determinations in its final Transport Rule.  As explained in the TSD for Allowance Allocation, EPA developed a list of potential covered Transport Rule units based on best available data.  Updated were made to the list based on commenter data, and EPA notes that the final allocation tables do not list the above units as potential existing Transport Rule units.
Organization: Kentucky Division for Air Quality
Public Power Generation Agency
Virginia Department of Environmental Quality (VDEQ)
Comment: 
Kentucky Division for Air Quality
Proposed Transport Rule SO2 Unit Allocation  
Pursuant to the proposed Transport Rule Preamble Section V.D.4., Allocation of Emissions Allowances (75 FR 45309-45312), the EPA SO2 unit allocations may be incorrect. Even though the 2014 Transport Rule SO2 budget decreased by 48% from the 2012 Transport Rule SO2 budget, certain unit's SO2 allocation in 2014 actually increased and in some cases significantly. Based on the Division's experience in providing previous allocations for the NOx SIP Call and Clean Air Interstate Rule (CAIR) NOx emissions trading programs, the Division contends that the 2014 allocation could not have been performed on a proportional (pro rata) basis since in that instance no unit's allocation for 2014 would have increased from its 2012 allowance allocation. Therefore, the Division requests that EPA verify the SO2 unit allocations to ensure that they were allocated properly. [EPA-HQ-OAR-2009-0491-2805.1, p.3]  
Proposed Transport Rule NOx Unit Allocation  
Pursuant to the proposed Transport Rule Preamble Section V.D.4., Allocation of Emissions Allowances (75 FR 45309-45312), in light of the Division's comments on EPAs SO2 unit allocations, the Division requests that EPA verify the NOx unit allocations to ensure that they were allocated properly. [EPA-HQ-OAR-2009-0491-2805.1, p.4]  
Applicable Units    
Pursuant to the proposed Transport Rule Preamble Section V.D.4., How the proposal Would Be Implemented, Applicability (75 FR 45306-45309), the Calvert City Cogeneration EGU (turbine  -  ORIS - 55308-Gen1) as shown in EPA's Technical Support detailed allocation file (BADetailedData.xls, Units Characteristics Worksheet) should indicate a capacity of 26 MWe instead of 23 MWe as is listed. This cogeneration EGU was part of the NOx SIP Call NOx ozone season trading program and was brought into the CAIR NOx ozone season program. However, the unit was exempted from the CAIR NOx annual program since it met the CAIR NOx annual program cogeneration exemption. Even with the CAIR ozone season cogeneration exemption, the unit was subject to the CAIR NOx ozone season trading program since it was previously subject to the NOx SIP Call NOx ozone season program which did not provide a cogeneration exemption. The Division requests that EPA work with the Division to verify that the Calvert City Cogeneration EGU is also exempt from the proposed Transport Rule NOx annual trading program pursuant to the Transport Rule cogeneration exemption and to include this unit in the proposed Transport Rule NOx ozone season trading program. [EPA-HQ-OAR-2009-0491-2805.1, pp.4-5]  
E.ON U.S., (ORISID 6071) Trimble Unit 2, which started operation in 2010, should be included in the proposed Transport Rule emissions trading programs. In addition, the Division recommends that before the Transport Rule unit allocations are finalized and recorded that EPA consult with the Division to make sure that all existing units subject to the proposed Transport Rule have been properly accounted for in the proposed rule's unit allocations. The Division reserves the right to inform EPA of any additional unit omission or incorrect inclusion for EPA's Transport Rule even after the comment period deadline has passed. [EPA-HQ-OAR-2009-0491-2805.1, p.5]  
Public Power Generation Agency
WEC Unit 2 meets the applicability requirements of the PTR to be characterized as an 'existing unit' and should have been allocated allowances. WEC Unit 2 was not included in either the NEEDS database or the IPM modeling and did not receive any allowances in the PTR. The purpose of these comments is to describe the relevant characteristics of WEC Unit 2, explain why it constitutes an existing unit under the PTR, and address the number of allowances WEC Unit 2 should receive in the final rule. [EPA-HQ-OAR-2009-0491-2705.1, p.1]
PTR Applicability and 'Existing Units'
According to the PTR, 'a covered source would be any stationary, fossil-fuel-fired boiler or stationary, fossil -fuel-fired combustion turbine serving at any time, since the later of November 15, 1990 or the start-up of the unit's combustion device, a generator with nameplate capacity of more than 25 MWe producing electricity for sale.' 75 Fed. Reg. at 45306. The units to which the PTR applies are further parsed into two categories: 'existing units' and 'new units.' An existing unit is a 'unit[ ], as described in the Applicability section, [quoted above] .. . , that commenced commercial operation, or [is] planned to commence commercial operation, prior to January 1, 2012.'3 1d. at 45309 (footnote omitted) (emphasis added). 'Planned' units are defined as 'units that had broken ground or secured financing and were expected to be online by the end of 2011.' [d. at n.85. The section of the PTR that provides the definitions of existing and planned units also describes how those units are allocated allowances. [EPA-HQ-OAR-2009-0491-2705.1,p.4]
WEC Unit 2 meets the definition of a planned unit as described in the PTR preamble and thus is an existing unit as defined by EPA. WEC Unit 2 has broken ground and obtained financing and is currently planned to be in commercial operation well before January 1, 2012, and thus meets the definition of a planned unit - and therefore is an existing unit. WEC Unit 2 is scheduled to come online in early 2011 and begin producing electricity for sale from its 220-MW generator at that time. According to the provisions set forth in the PTR, WEC Unit 2 is entitled to an allocation of allowances. [EPA-HQ-OAR-2009-0491-2705.1,pp.4-5]

3 The proposed regulatory language for §§ 97.411 and 97.711, found at 75 Fed. Reg. 45376 and 45450, respectively, discusses the allowance allocation process for 'existing units' but does not provide the same explicit discussion of 'existing' and 'planned' units that is provided in the preamble discussion.
Virginia Department of Environmental Quality (VDEQ)
It is unclear why allocations were provided to Dominion Bear Garden and Dominion Warren County, two planned facilities that will burn natural gas in combined cyc1e units, but allocations were not provided to the Virginia City Hybrid Energy Center (VCHEC), a 585 MW state of the art facility that will mainly burn coal and coal refuse. Construction began at VCHEC in June 2008 and as of July, 2010, is approximately 65 percent complete. VCHEC is on schedule to begin generating electricity commercially in the summer of2012. See the websites listed above for the relevant permits. [EPA-HQ-OAR-2009-0491-2595.1, p.4]
Spruance Erigenco (ORIS 54081) and Hopewell Cogeneration (ORIS 10633) received allocations but James River Cogentrix (ORIS 10377) and Portsmouth Cogentrix (ORIS 10071) did not. It is unclear why these facilities were not included. Both are large emitters of SO2 and burn coal. Both installed dry scrubbers 10 participate in CMR, and these scrubbers are capable of reducing SO2 emissions by 90% or more. However, if they are not included in the Transport Rule trading scheme as applicable units, then there will be no impetus for them to operate the dry lime scrubbers. James River does have a steam host that uses some steam from the facility. However, Portsmouth Cogentrix has no steam host and operates only to produce power. [EPA-HQ-OAR-2009-0491-2595.1,p.4]
For certain units such as Birchwood Power (ORIS 54304), the 2012 annual NOx allowances and the 2012 annual SO2 allowances are based on significantly different heat inputs (for Birchwood, about 15,000,000 mmBtu and 18,000,000 mmBtu respectively). This inconsistency appears to be due to the fact that NOx allocations are based on 2008 actual heat input whereas SO2 allocations are based on predicted heat input using IPM. Putting aside the relative merits of using real data versus using predicted data from a model that has performed very poorly in the past, this inconsistent use of heat inputs to calculate allocations unnecessarily complicates the allocation process. Additionally, the purpose of trying to estimate future heat input is to calculate expected emissions and the resultant downwind impacts. Therefore, the most likely heat input scenario should be chosen to estimate emissions and allowances for both pollutants. Using disparate heat input estimates for the same unit for the same year creates emissions estimates that are not based on the same amounts of fuel used, adding not only confusion but also inaccuracies to the process. For any given unit, one value for heat input should be used for 2012, and that heat input should be the basis for 2012 allocations of allowances for both NOx and SO2 for that unit. As noted in previous comments, VDEQ suggests abandoning the use of IPM for future allocations and using previous years' activity data to calculate allocations. [EPA-HQ-OAR-2009-0491-2595.1, p.4]
Ladysmith Combustion Turbine Power Station has several units that are incorrectly assigned to ORIS 7838. The correct ORIS for this facility is 7839. This issue may be the result of an incorrect cross index between units reporting to CAMD and unit information in the NEI. VDEQ recommends that EPA acquire the most recent MARAMA crosswalk between CAMD and NEI identifiers and that EP A ensure that this information is applied to both the modeling inventories as well as the data used for determining allocations. [EPA-HQ-OAR-2009-0491-2595.1, pp.4-5]
There are instances where steam generators that have no emissions are assigned allocations, such as Hopewell Cogeneration, ORIS 10633. CAMD data clearly show only 3 emission points, as does the NEI (facility code 51-670-0058). However, the 'Budget and Allocations Details.xls' spreadsheet has 4 emissions points from the facility with allocations assigned. [EPA-HQ-OAR-2009-0491-2595.1, p.5]
Response: 
Units commencing commercial operation after January 1, 2010 would not be included in the list of potential existing Transport Rule units because they would be considered new, not existing, units under the final Transport Rule.  Such units would be able to receive allowances through the state's new unit set-aside account.  Additionally, the list of potential existing covered units under the Transport Rule that EPA identifies for receiving allowances under the FIP by no means reflects a Transport Rule applicability determination for EGUs.  It simply reflects EPA's preliminary assessment of covered sources based on best available data and comment received during the Transport Rule comment periods.
Organization: Michigan Department of Natural Resources and Environment
Comment: 
Michigan Department of Natural Resources and Environment
The proposed TR allowance/budget data supplied in the BADetailedData.xls spreadsheet shows major differences as compared to the state's CAIR program in the projected emissions for several of Michigan's municipally owned and operated EGUs. [EPA-HQ-OAR-2009-0491-2774.1 p.8]
The DNRE disagrees with the EPA's assumptions in this area. We believe that several sources were erroneously projected to have zero emissions in 2012 and after. The DNRE notes that several of these smaller municipally owned EGUs, which have the obligation to serve, will continue to operate far into the future. We believe that making these assumptions in the proposed TR has created an area of economic hardship for small business sources within Michigan. [EPA-HQ-OAR-2009-0491-2774.1 p.8]
In particular, the DNRE would like to point out that:
 :: MSCPA Endicott and Wyandotte's units were not given any allowances. The DNRE has no knowledge that these sources will cease to operate and expects that they will continue to operate as they have in the past.
:: Holland Board of Public Works' 48th Street Unit #7 was given not any allowances, but the other units were at the location were allocated for 2012 and beyond. Once again, the DNRE expects that Unit # 7 will continue to operate as in the past.
:: Holland Board of Public Works' De Young plant received more allowances under the proposed TR than the CAIR program.
:: Genesee Power and Grayling Generation were left out of the allocations. The DNRE expects these plants will continue to operate as they have in the past.
:: Cadillac Renewable, Lansing Board of Water and Light, Grand Haven Power Plant, and the City of Marquette's Shiras Power Plant all received significant allowances, but very different than in CAlR.
:: Michigan Power Limited received token allowances, not anywhere near what they received under CAIR. In recent conversations with the facility, they said they are under an obligation to serve their community for quite some time into the future.
The DNRE's review raises serious concerns about the accuracy of the assumptions used to identify units that would not be operating in the future and with the allocation method in general. [EPA-HQ-OAR-2009-0491-2774.1 p.8]
Response: 
EPA received significant comment on the proposed Transport Rule allocation methodology that expressed concerns similar to those expressed by commenter.  EPA subsequently developed two alternative historic heat input alternatives, took comment on the approaches, and is finalizing an allocation methodology that does not rely on IPM projections.  This addresses concerns about units not receiving allocations because IPM projected them not to operate.  Under the final allocation methodology approach, a unit's allocation is indexed to its historic operation.  This approach is described in section VII.D of the preamble.  Many of the units described above as receiving 0 allocations, do receive allocations under the allocation methodology finalized for the Transport Rule.
Organization: Pratt & Whitney
Comment: 
Pratt & Whitney
Pratt & Whitney notes that the Pratt & Whitney Cogeneration unit (Cogen), ORIS 54605, located in East Hartford, CT, is included in the Allocation Table, which is listed in the Technical Support Documents for the Proposed Transport Rule. This unit should not be included in the documentation for the Transport Rule as it meets the cogeneration exemption of not 'supplying in any calendar year more than one-third of the unit's potential electric output capacity [104,292 MWe-hrs] or 219,000 MWh, whichever is greater'. [EPA-HQ-OAR-2009-0491-2584.1, p.1]
The Pratt & Whitney Cogen permit was upgraded to allow a 32 MW unit at the end of 2002. The cogeneration unit provides a portion of the electrical power required by the facility and also provides steam for process and building heating and cooling. If at any time the cogeneration unit creates more power than the facility is using at the moment, the excess power is sold to the grid. The annual data since 2003 clearly indicates that Pratt & Whitney has consistently sold below the 219,000 MWh cogeneration exemption threshold:[[See [EPA-HQ-OAR-2009-0491-2584.1, p.1 for a table that shows Power sold to the grid by Pratt & Whitney.]]
Pratt & Whitney requests that our cogeneration unit, ORIS 54605, be removed from the proposed Transport Rule FIPs Allocation Table and that the EPA confirms that this regulation will not apply to the Pratt & Whitney Cogen. [EPA-HQ-OAR-2009-0491-2584.1, p.1]
Response: 
Connecticut, and the units located in the state (including Pratt & Whitney), were not determined to be a contributing state in the final Transport Rule.  Therefore, the units of concern to the commenter are not subject to the Transport Rule and are not in the final allocation tables.
Organization: South Carolina Department of Health and Environmental Control 
Comment: 
South Carolina Department of Health and Environmental Control 
The Budgets and Allocations Spreadsheet fails to include SO2 controls that Santee Cooper installed at its Cross25 and Winyah facilities, and NOX controls at its Grainger and Jeffries facilities, to comply with its 2004 consent decree,26 yet the EPA notes these consent decree requirements in other areas of the proposed Transport Rule.27 DHEC notes that without the projected SO2 reductions from the flue gas desulfurization ("FGD") units at Cross and Winyah, and NOX reductions from the low NOX burners at Grainger and Jeffries, South Carolina's emissions projections are unnecessarily high. As discussed earlier, the EPA failed to include other controls in the Budgets and Allocations Spreadsheet, but those are most likely because the EPA is assuming that they were installed to comply with the CAIR. With the Santee Cooper controls, however, the consent decree is an independent reason for Santee Cooper to maintain these controls, and thus there is no apparent justification for not including the controls in the budgets and allocations analysis. [EPA-HQ-OAR-2009-0491-2677.1 p.13]
If the EPA adds the mandated Cross FGD units to its Transport Rule modeling, then South Carolina's projected SO2 emissions would be significantly lower. This offers additional evidence that the uncertainty surrounding the IPM projections should lead the EPA to adopt the higher 1 μg/m3 threshold and remove South Carolina from the SO2 Group 2 trading program. Even if the EPA retains its proposed thresholds, South Carolina may fall under the thresholds if the EPA uses the actual SO2 emissions data that includes the correct Cross controls rather than fallacious projections. [EPA-HQ-OAR-2009-0491-2677.1 p.13]
Response: 
EPA updated its IPM modeling and reran its analysis to determine states that contribute to downwind nonattainment and/or interference with maintenance.  The updated model reflects the FGDs at Cross and Winyah, and the LNB at Grainger and Jeffries as described above.  The final Transport Rule air quality analysis still linked, even with the modeling updates, South Carolina to states with nonattainment and or maintenance issue. 
Organization: Sunflower Electric Power Corporation
Comment: 
Sunflower Electric Power Corporation
Sunflower requests that EPA provide annual NOX allowances for the Garden City S2 unit (Oris ID Code 1336) in the appropriate manner as it has allocated allowances to that unit for the ozone season. EPA, we think by oversight, did not include an annual allocation for S2. As an example, our Great Bend Station (Oris ID Code 1235) was allocated both annual and ozone season allowances. Both the S2 and Great Bend units are operated for intermediate-duty, both are dispatched in much the same manner throughout the year, and both should be allocated annual and ozone season allowances in much the same manner. We think these facts substantiate our analysis, and we respectfully request that EPA correct the oversight by promptly allocating an appropriate number of annual NOX allowances to the facility (Oris ID Code 1336). [EPA-HQ-OAR-2009-0491-2833.1 p.2]
Response: 
Under the final Transport Rule allocation methodology, a unit's allocation is indexed to its historic operation over a five year baseline (see section VII.D of the preamble).  This results in the Garden City S2 unit receiving an allocation. 
Organization: U.S. Congressman Pete Hoekstra
Comment: 
U.S. Congressman Pete Hoekstra
Specifically, we are concerned with the proposed SO2 allocation of '0' given to our Unit 5 starting in 2014. The methodology document that the EPA provides ('State Budgets, Unit Allocations and Unit Emission Rates', prepared July 2010 in support of this rule, states on page 12 'Units in group 1 states without an IPM projection do not receive SO2 allocations in 2014 and beyond'. Why? We are unclear after reviewing the document how and why this allocation was made. The HBPW has no intention of retiring this unit at any time in the near future. We are confident that certain control methodologies can be implemented to reduce emissions consistent with the average percentage reduction required of the State of Michigan. The modeling program is arbitrary and fails to consider the real-life evaluations and decisions that will be made by municipalities like the HBPW. [EPA-HQ-OAR-2009-0491-3662, p.3]
In addition, the Holland BPW was recently denied by the State of Michigan to build a new larger coal-fired electric generating unit with state-of the-art pollution controls (78 MW unit with emissions similar to our smallest, oldest unit 3, 11.5 MW.; and would be able to bum biomass fuels). Now, as a result of this rule, we would be mandated to cease coal-firing our 'newest' existing Unit 5 by 2014. [EPA-HQ-OAR-2009-0491-3662, p.3]
As pointed out in the comments from MMEA, Holland is the site for two recently announced lithium-ion battery advanced energy storage plants. Three months ago President Obama visited Holland for the ground breaking for one of those plants, LG Chern. Unit 5 will be critical to meeting the power supply needs of these facilities in a cost-effective manner [EPA-HQ-OAR-2009-0491-3662, p.3].
Response: 
EPA has revised its allocation methodology to address concerns about units receiving 0 allocations because IPM projected them to not operate.  The final Transport Rule allocation methodology is based on historic heat input over a five year baseline.  Therefore, if the unit operated during that time period, it would be receiving an allocation amount that reflected such operation.  The specific allocation methodology is described in section VI of the preamble.  Also, for any new units commencing operation, they would have access to the new source set-aside allowances.  This set-aside account in the final rule has been modified (increased in some states) to reflect planned units under construction and/or coming online after Jan. 1, 2010.  This approach for determining set asides in the final rule makes more allowances available to newer, cleaner units as a percentage of state budgets relative to the proposal.
Organization: West Virginia Department of Environmental Protection
Comment: 
West Virginia Department of Environmental Protection
[[2790.1 p.4]]
While both the ozone season and annual NOx budgets for 2012 and 2014 for West Virginia have been reduced from CAIR levels under the proposed Transport Rule, the budgets for some other states have increased by significant amounts. Florida and Pennsylvania both receive large proposed increases in their annual NOx budgets - 20,556 and 14,854 tons, respectively in 2012, and 37,130 and 31,362 tons, respectively in 2015; and their ozone season NOx budgets are proposed to increase by 9,027 and 6,100 tons, respectively, in 2012 and 17,013 and 13,128 tons, respectively in 2015. It is difficult to perform a comparison of the regional budgets because the states affected by the Transport Rule and CAIR vary. An analysis of the budgets of the states affected by both CAIR and the Transport Rule for annual NOx shows there are twelve states that have increased annual NOx budgets under the proposed Transport Rule, and twelve states with decreased annual NOx budgets, resulting in a decrease of 49,858 tons for the states covered under both rules for 2012. However, only seven states show a decrease in their annual NOx budgets for 2015, and there is a regional increase of 170,621 tons of annual NOx in 2015. Similar issues arise with the ozone season NOx budgets.
Under the proposed Transport Rule, the 2014 annual NOx emission cap is too generous - more than CAIR Phase II. It is widely assumed that Transport Rule II will rectify this, as the intended rule will address a new ozone standard. Leaving the 2014 NOx cap at its proposed level will hinder efforts to mitigate interstate transport and significant contribution, especially if Transport Rule II is not promulgated for some reason. In the final rule, EPA should include a 2014 annual NOx emission budget which is technologically feasible and cost effective. WVDAQ questions whether the proposed 2014 NOx cap might be considered backsliding under the Clean Air Act.
Pennsylvania is central to the Northeast's nonattainment problems, and Pennsylvania sources have 'rented compliance' in past and current transport programs. Comparing the proposed Transport Rule 2012 budgets to the budgets under CAIR, Pennsylvania would receive 15 percent more of the annual NOx budget over that state's allotment under CAIR, while West Virginia would receive a 30 percent decrease in annual NOx budget from CAIR. Considering that West Virginia sources have made significant reductions in S02 and NOx emissions, this and similar comparisons indicate that the proposed budget methodology in the Transport Rule creates a situation where states that already have highly controlled sources (under the NOx Budget Trading Program and CAIR) receive budgets that disadvantage the units that controlled their emissions earlier in favor of states with many yet uncontrolled units. EPA should revise the Transport Rule allocation methodology to minimize such disadvantages, provide increased incentive to control uncontrolled units, and distribute allowances in a more equitable manner.
[[2790.1 p.2-3]]
WVDAQ has analyzed the initial data contained in the proposed Transfer Rule docket, and have found the following errors that should be corrected in the final rule:
a. The Alloy Steam Plant is a non-EGU source and should not be grouped with EGU sources nor included in the IPM modeling or allocated allowances in the Transport Rule. The Alloy Steam Plant was erroneously included in both the NEEDS v3.02 EISA and NEEDS v4.l0 databases (ORIS 50012, Unique ID 50012_B_BLR4), and was allocated allowances in the TSD Allocation Table. The allowances allocated to Alloy should be redistributed to existing EGU sources in West Virginia.
b. The Longview Power Plant was incorrectly identified in the NEEDS v3.02 EISA database as RFCP _WV_Coal steam, ORIS Code 82716, Unique ID 82716_B_l, and was incorrectly identified in NEEDS v4.l0 database as RFCP _WV_Coal steam, ORIS Plant Code 82914, Unique ID 82914_C_1. Longview Power Plant's correct ORIS Code is 56671. Although Longview was included as an existing unit in 2012 and allocated allowances for 2012 in the TSD Allocation Table, the source was not allocated any allowances in 2014, even though it was included in the modeling and parsed files for 2014. Longview is scheduled to be online in early 2011, and by definition will be an existing EGU under the proposed rule. Longview Power Plant identification data should be corrected, and the source should receive allowances for both 2012 and 2014, along with other existing EGU sources in West Virginia.
c. The Big Sandy Peaker Plant (ORIS ID 55284) was allocated allowances for its twelve units identified in the TSD Allocation Table as units BSG 1,BSG2, BSG3, BSG4, BSG5 and BSG6; GS07, GS08, GS09, GS10, GSII and GSI2. However, only six of the units (BSGl, BSG2, BSG3, BSG4, BSG5 and BSG6), are included in the parsed files. Big Sandy Peaker Plant has six generators, each served by two turbines, for a total of twelve turbines with a combined generation capacity of 300 MWe.

Response: 
See section VI of the preamble for a detailed explanation of why EPA does not consider CAIR state emission budgets when determining Transport Rule State budgets.  Transport Rule budgets are determined through a state-by-state multifactor analysis and reflect the elimination of significant contribution or interference with maintenance at each state.  CAIR did not determine state budgets in this manner, and the Court subsequently determined that this aspect of CAIR was flawed.  Because Transport Rule is designed to replace CAIR and correct its flaws, EPA has no legal basis for setting Transport Rule budgets based on CAIR budgets that were explicitly found by the Court to be flawed.
Section III of the preamble discusses future rulemakings to address future ozone NAAQS.  Finally, EPA notes that it has finalized an allocation methodology under a FIP scenario that improves upon that which was proposed.  The updated methodology obviates some of the concerns addressed above.  Specifically, Longview Power would be considered a "new unit" under the final allocation methodology and the new unit set-asides under the final rule are determined specifically to accommodate emissions from these planned units, as explained in detail in section VII.D.  Furthermore, in regards to comment C, EPA notes that the inventories in the allocation tables will not always match the representation of units in the parsed IPM modeling files.  This is due to the list of potential existing Transport Rule units being based on units as they report, and the parsed file presents units as modeled.  In most cases, there is 1:1 alignment.  However, there may be some units that report emissions data to EPA at the boiler level but are identified at the generator level in IPM modeling, or vice-versa.  This can lead to instances where, for example, Unit A that is 50 MW in the reported data is disaggregated and listed as two units in the parsed file (each being approximately 25 MW).  These are unit-level accounting differences between reported data and modeling inventories that do not affect the modeling of aggregate facility- or state-level emission projections.
Organization: Westar Energy, Inc.
Comment: 	
Westar Energy, Inc.
THE ALLOCATION ADJUSTMENT METHODOLOGY FOR WESTAR AS APPLIED BY EPA IS NOT CORRECT [EPA-HQ-OAR-2009-0491-2757.1, p.24]
The Technical Support Document for State Budgets, Unit Allocations, and Unit Emission Rates describes EPA's approach for determining the allocations that comprise the state budgets. In short, EPA based allocations on the lesser of adjusted reported emissions or adjusted 2012 emission projections. In adjusting reported emissions, one step in EPA's methodology was to adjust reported annual and ozone season NOx emissions to account for 'unusually low utilization in 2009'. The annual emissions were adjusted by multiplying the emissions by the ratio of the 2008 heat input to the heat input determined for the fourth quarter of 2008 and the first three quarters of 2009. Similarly, the ozone season emissions were adjusted by multiplying the emissions by the ratio of the 2008 ozone season heat input to the 2009 ozone season heat input. EPA states that 'because 2009 was an unusually low year, rebasing emissions on 2008 heat input typically results in larger NOx emissions.' But applying this adjustment to all units fails to recognize that some units did not have an unusually low year, and are therefore adversely affected by the adjustment. [EPA-HQ-OAR-2009-0491-2757.1, pp.24-25]
As it appears that the adjustment was intended as a step to increase allocations to offset the abnormally low 2009 numbers, it is unnecessary to make the adjustment for those units that were not abnormally affected. One way to measure whether 2009 was abnormal in comparison to 2008 is to determine if units had a lower heat input for 2008 than 2009. In Westar's view, such units do need adjustment. Specifically for Westar, the following units had negative annual NOx adjustments between 2008 and 2009: Jeffrey Energy Center Unit 4, Lawrence Energy Center Unit 4, Tecumseh Energy Center Unit 9, and Gordon Evans Energy Center Units 1 and 2. Also, the following units had negative ozone season adjustments between those years: Lawrence Energy Center Unit 4, Tecumseh Energy Center Unit 9, and Emporia Energy Center Units (EEC) 1 - 5. Since allocations in the state of Kansas were based on reported emission as adjusted by EPA, the use of a negative adjustment factor for those units that with lower heat input in 2008 than 2009 unfairly reduces the NOx allocations below what was normal for those units. Further, as emission limitations under the direct control option are also based on reported emissions as adjusted by EPA, the direct control limits are biased low for units with lower heat input in 2008 than 2009. [EPA-HQ-OAR-2009-0491-2757.1, p.25]
In addition to artificially allocations for those units several of Westar' s units have zero allocations. This includes annual NOx allocations for EECI -7, Hutchison Energy Center GT 14, Murray Gill Unit 1 and 2, and Neosho Unit 7, ozone season NOx allocations for EECl - 5 and Hutchison Energy Center GT 1-4, and annual S02 allocations for Hutchison Energy Center GT 1 - 4, EEC Units 1 -7, Murray Gill Unit 4, Neosho Unit 7. As all of these units operated in 2009, and all but two of the Emporia Energy Center units operated in 2008, none of the units should have zero allocations. [EPA-HQ-OAR-2009-0491-2757.1, p.25-26]
Also, it should be noticed that the seven gas turbines at the Emporia Energy Center are listed twice in EPA's allocation tables. This double listing of units appears to have caused some misrepresentation of the heat input and emissions information and ultimately resulted in incorrect allocations. [EPA-HQ-OAR-2009-0491-2757.1, p.26]
Response: 
Based on these comments, EPA updated its representation of the Emporia facility to include seven units, and EPA has included the historic heat input for Westar facilities that operated between 2006 and 2010 in the underlying data used to establish allowance allocations for these units under the final rule FIPs.  See section VII.D of the preamble for more discussion on the final allocation methodology and the Allowance Allocation Final Transport Rule TSD for unit level allowance allocations under the FIPs.
Organization: Weyerhaeuser Company
PPG Industries, Inc.
Dow Chemical Company
Comment: 
Dow Chemical Company
As support documentation to the proposed rule and FIP, EPA made available an Allocation Table which provides annual and ozone season NOx allocations for regulated EGUs. Dow currently owns and operates the following EGUs which EPA purports to cover under the proposed applicability of the rule/FIP: [EPA-HQ-OAR-2009-0491-2775.1 p.6]
[[Data Table Here]]
Because each of these EGUs qualifies under the Transport Rule/FIP's definition of 'cogeneration unit ,' and has never supplied more than one-third of its potential electrical output capacity or more than or 219,000 MWh of electricity to the electrical grid for sale within the applicable time periods proposed in the rule/FIP, Dow believes its units have been erroneously listed as regulated EGUs and requests that EPA delete these units from any documents implying applicability and from the allocation tables. [EPA-HQ-OAR-2009-0491-2775.1 p.6]
Under the proposed Transport Rule/FIP, a covered source is any stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine serving at any time, since the later of November 15, 1990 or the startup of the unit's combustion device, a generator with nameplate capacity of more than 25 MWe producing electricity for sale.3 Certain cogeneration units4 are exempt, however, from these requirements. A source qualifies for the ?cogeneration unit exemption? if the unit meets the following conditions: [EPA-HQ-OAR-2009-0491-2775.1 p.6]
1. operates as part of a 'cogeneration system,'
2. meets, on an annual basis, specified efficiency and operating standards, and
3. supplies in any calendar year -- starting the later of November 15, 1990 or the start-up of the unit's combustion chamber -- no more than one-third of its potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale.  [EPA-HQ-OAR-2009-0491-2775.1 p.7]
Dow believes that the Saint Charles Operations (SCO) EGUs qualify under the 'cogeneration unit exemption' and, thus, have been improperly listed as being subject to the proposed Transport Rule/FIP. While the Dow units are cogeneration units, as defined under the proposed Transport Rule, these units do not meet the electricity sales thresholds that would subject them to regulation under the proposal. These units, on an individual unit-by-unit basis, do not distribute the greater of more than one-third of their potential electric output or 219,000 MWh for sale. As such, because none of units meet the applicability criteria in the proposed Transport Rule, Dow requests the removal of the SCO units from the Allocation Table and from any other Technical Support Documents pertaining to regulated EGUs under the rule/FIP. [EPA-HQ-OAR-2009-0491-2775.1 p.7]
PPG Industries, Inc.
In addition, PPG is the owner and operator of five combined cycle units identified by EPA in the proposed Transport Rule/FIP as "PPG Powerhouse C" Units C1-C5 (EPA Plant ID 50489) that are also located at PPG's Lake Charles Chemical Complex. Although EPA has included these five units under the scope of the proposed Transport Rule/FIP, such units are exempt cogeneration units that do not sell sufficient power to the grid to be within the applicability requirements of the proposed rule/FIP. [EPA-HQ-OAR-2009-0491-1926.1, p.1]
In addition, PPG is the owner and operator of five combined cycle units identified by EPA in the proposed CATR/FIP as ?PPG Powerhouse C? Units C1-C5 (EPA Plant ID 50489) that are also located at PPG's Lake Charles Chemical Complex. Although EPA has included these five units under the scope of the proposed CATR/FIP, such units are exempt cogeneration units that do not sell sufficient power to the grid to be within the applicability requirements of the proposed CATR/FIP. [EPA-HQ-OAR-2009-0491-2763.1, p. 1]
Weyerhaeuser Company
Weyerhaeuser Company ("Weyerhaeuser") is filing this request to remove a unit belonging to the Weyerhaeuser - Flint River mill located in Oglethorpe, Georgia, from the analyses and allocations tables included in the support materials for this rulemaking. [EPA-HQ-OAR-2009-0491-2602.1, p.1]
The facility is listed in two key technical support documents to the proposed rule made available at http://www.epa.gov/airquality/transport/tech.html, EPA's BADetailedDatat.xls (on the web page this is titled "Budgets and Allocations - Detailed Unit-Level Data (Excel)") and Allocation Table.xls, and has the identifiers:  Weyerhaeuser Company  -  Flint River  ORIS ID: 50465  Unit ID: U500  [EPA-HQ-OAR-2009-0491-2602.1, p.1]
The listing and inclusion of this facility in the proposed Clean Air Transport rule (CATR) is an error, presumably due to residual records of the unit stemming from its potential applicability under the Clean Air Interstate Transport Rule (CAIR) prior to the October 2007 amendments to CAIR that modified how biomass fuel heat input is evaluated to qualify cogeneration units. [EPA-HQ-OAR-2009-0491-2602.1, p.1]
This unit is a pulp mill recovery furnace that Weyerhaeuser determined to be exempt from the current CAIR (see Exhibit 1), and based on the definitions and applicability sections of proposed Subparts AAAAA -- TR NOX Annual Trading Program, BBBBB -- TR NOX Ozone Season Trading Program, CCCCC -- TR SO2 Group 1 Trading Program, and DDDDD -- TR SO2 Group 2 Trading Program, will be exempt from the proposed CATR for the same reason. [EPA-HQ-OAR-2009-0491-2602.1, p.2]
That reason is that the unit meets the requirements to be an exempt cogeneration unit. That is: (a) it predominantly burns biomass (> 99.5 % on an annual average heat input basis) and therefore easily meets the criteria in the proposed definition for a topping cycle cogeneration unit, and; (b) per the applicability provisions it "...does not serve at any time, since the later of November 15, 1990 or the startup of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe supplying in any calendar year more than one-third of the unit's potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale."  [EPA-HQ-OAR-2009-0491-2602.1, p.2]
The unit therefore will not be subject to the CATR, and we request EPA eliminate the unit from further CATR analyses and actions under this rulemaking. [EPA-HQ-OAR-2009-0491-2602.1, p.2]
Response: 
See section VII.B of the Transport Rule preamble for a description of final Transport Rule applicability.  EPA is issuing a list of potential existing covered units to receive allocations under a FIP, but notes that inclusion of a unit in, or exclusion of a unit from, the list of potential existing Transport Rule units reflects only a preliminary assessment of the applicability of the Transport Rule and in no way suggests that EPA has made a determination about the applicability of the Transport Rule to any unit.  While allocations calculated for the final Transport Rule FIP are based on the best available data provided to EPA by the time of the calculation, the applicability of the final Transport Rule to an individual unit would be determined based on all relevant data, whether or not EPA would have such data at the time that allocations would be calculated.  The list of potential existing covered units was updated to reflect comments received on the proposed Transport Rule and subsequent NODAs.
V.D.2.b.ii. Comments on Allocations Methodology

Organization: Allegheny Energy
Comment: 
Allegheny Energy
To establish state allocation budgets under the proposed rule, EPA modeled assumed reductions based on installed controls listed in the National Electric Energy Data System (NEEDS) database, rather than using actual emissions or heat input data. EPA assumed in their Integrated Planning Model (IPM) program that certain controls were already installed on certain units and, moreover, that those controls would operate at certain efficiencies, stations would use specific fuels and additional controls would be installed by dates certain. [EPA-HQ-OAR-2009-0491-2605.1, p.3]
A major problem with EPA's approach is the vast number of assumptions made on how companies will decide to comply with the regulation. In addition, EPA distinguishes between the control efficiencies of existing controls as compared to the same control yet to be constructed. For example, some existing scrubbers are being modeled at control efficiencies as high as 98% while planned scrubbers yet to be constructed are being modeled at 95%. This creates a disadvantage for states with existing controlled units and ultimately the units themselves, when smaller state budgets are allocated among the EGUs. Controlled units are being allocated fewer allowances than their 'to be constructed' counterparts even though they already 1) have made the capital investments, 2) have significant operation and maintenance costs, and 3) have created the emissions reductions currently realized. As a result, both the units and the states they are located in receive a reduced allocation of allowances. If EPA insists on using predictive models rather than actual heat inputs to establish allowance budgets then the allocation of those allowances should at least be done on a consistent basis for the type of control equipment used. A scrubber should be considered 95% efficient for the IPM regardless of whether it already exists or is yet to be constructed. [EPA-HQ-OAR-2009-0491-2605.1, pp.3-4]
Response: 
Based on comments received both on the Transport Rule proposal and the January 7, 2011 NODA on alternative allocation methodology, EPA has made significant changes to its methodology for allocating allowances to existing units and new units under a FIP.  This is discussed in detail in Section VII of the preamble.  Additionally, the "Allowance Allocation Final Rule Technical Support Document" provides a more detailed description of the methodology and data used to determine final unit level allocations under a FIP.  Furthermore, the "Documentation Supplement for EPA Base Case v.4.10_FTransport - Updates for Final Transport Rule" discusses some of the broader modeling comments and subsequent modeling changes that were submitted in the context of "allocation methodology" comments.  Finally, the "Transport Rule IPM Assumptions Response to Comments" in the Response to Comment Document summarizes individual unit level changes that were made to the IPM model in response to comments received in the context of "allocation methodology" comments. 
The proposed Transport Rule linked unit level allocations directly to unit level model emissions projections.  As discussed in Preamble Section VII, EPA received many comments objecting to the use of the model at this level of granularity.  As the unit level model projections were the basis for allocations, many commenters submitted corrections or comments on the unit level attributes that they disagreed with in the model.  EPA reviewed and revised its modeling given the new information submitted.  EPA also eliminated the use of unit-level modeling projections in its determination of existing unit-level allocations under the final Transport Rule FIPs.  As explained in Preamble Section VII, the final Transport Rule allocations to existing units are based on a methodology that relies on historic heat input values, not projected data.  
Please see section X of the preamble for discussion of Transport Rule SIPs and abbreviated SIPs for state-determined allocations.
Organization: Ameren Services Company
Comment: 
Ameren Services Company
EPA should allow full trading between the group 1 and group 2 states
The proposed Transport Rule imposes an additional reduction in the number of allowances to be allocated to electric generating units (EGUs) in group 1 states in 2014. Group 2 states will not suffer that additional reduction. The Transport Rule also imposes variability limits on all states. The combination of the variability limits and the reduction in allocations in 2014 make any restrictions on trading between group 1 and group 2 states unnecessary. The environmental protections created by the statewide budgets with variability limits are sufficient without further limiting trading to the group in which a state happens to be placed. EPA has not identified any environmental benefit that would result from restricting trading between the two groups beyond that conferred by the budgets with variability limits. Therefore, there does not appear to be a rational reason for the restriction on trading between the two groups. EPA should remove that restriction. [EPA-HQ-OAR-2009-0491-2722.1, p.8]
The allocation scheme that the Transport Rule uses appears to penalize units that have installed controls by 2012 [EPA-HQ-OAR-2009-0491-2722.1, p.8]
Based on the EPAs analysis EPA has assigned allowance allocations for both NOx and S02 in the 2012 timeframe based on the actual controls in place or planned to be in place by 2012. This scheme basically penalizes utilities that have installed controls early to meet the requirements of CAIR or other state programs. Utilities that have installed these controls have spent 100s of millions of dollars on these control devices to reduce NOx and S02 and are now penalized by this allocation scheme. Allocation of both NOx and S02 as has been done in previous rules should be based on past utilization of the unit not on its current emission capabilities. Ameren suggests in the allocation of allowances that heat input be used as this was used in the NOx SIP Call and CAIR and created a generally fair and equitable result. [EPA-HQ-OAR-2009-0491-2722.1, pp.8-9]
EPA should provide for borrowing allowances from future years [EPA-HQ-OAR-2009-0491-2722.1, p.26]
EPA should allow units to borrow allowances from future-year accounts for use in compliance with in the first 5 years of the program at least on a limited basis. This would allow for increased flexibility, especially if the final rule promulgated by EPA includes the ambitious compliance schedule that is currently proposed. Allowing for borrowing of allowances would still result in units receiving and using a finite number of allowances over the years and thus, produce no overall increase in emissions and still achieve the air quality results required. [EPA-HQ-OAR-2009-0491-2722.1, pp. 26-27]
Response: 
Preamble Section VI.D.2. explains EPA's rationale for not allowing sources in Group 1 states to use Group 2 SO2 allowances for compliance, and likewise not to allow sources in Group 2 states to use Group 1 SO2 allowances for compliance at any time.
Organization: American Municipal Power, Inc. (AMP)
Comment: 
American Municipal Power, Inc. (AMP)
The New Source Set-Aside Should Encourage Power Sector Growth EPA proposes to set aside 3% of each state's emissions budgets for new units. This new unit set-aside is deficient and discourages growth of new units that are designed and operated with advanced pollution control equipment. The blanket 3% per state new unit set-aside also fails to account for states experiencing significant growth in the electric power sector. This failure by EPA to account for such growth could likewise overlook other factors affecting power sector growth, such as growth in manufacturing or similar development. Thus, growing states or regions are stymied by a one-size-fits-all approach to new unit emission budgets. Finally, EPA should clarify the Transport Rule to provide that 'new units' move from the new unit set-aside to an existing unit allocation pool after a certain period of time to assure a long-term allowance structure and in order to free up new unit set-asides for future projects. Just as EPA should clarify when new units have existed for a sufficient period to warrant classification as existing units, EPA should clarify the time periods associated with allocations for retired or retiring units. Such clarification is necessary to assure that trading markets and new units will not be unnecessarily impacted by unit retirement. [EPA-HQ-OAR-2009-0491-2678.1, pp.3-4]
Response: 
The methodology for allocating allowances two new units and the size of the new unit set-aside in the final rule are reasonable and provide for a reasonable allocation of allowances to new units.  The final rule entails state-specific set-asides that are tailored to the amount of planned new units (online after January 1, 2010) in each covered state.  The result is a greater percentage of the state budget set-aside for new units than would have otherwise occurred under the proposed method for calculating new source-set aside budgets.  As existing units are retired, the allocations for those units are eventually redirected to the new unit set-asides, as described in Preamble Section VII.D.2. In this manner, additional allowances will become available in the new unit set-asides in the future as existing units retire and the EGU fleet turns over to newer sources of generation.
Organization: Attorney General of North Carolina
Comment: 
Attorney General of North Carolina
The rule text does not make clear that each State's new unit set-aside for a particular pollutant is a subcategory of the State's total allocation for that pollutant. That is, the rules are not clear that the new unit set-aside is to be 36 subtracted from the State's total budget and is not an allocation that is in addition to the State's budget. Appendix A, when developed, will list the allocations for each unit. These allocations, if they track the allocations in EPA-HQ-OAR-2009- 0491-0057.1, will presumably demonstrate that the total of the existing unit allocations plus the new unit set-aside equals the State's total budget. However, the rule should be revised to clarify that the new unit set-asides are a part of, and not in addition to, the State's total budget. [EPA-HQ-OAR-2009-0491-2685.1, p. 36]
Response: 
The commenter is correct that the new unit set-aside is a portion of the total state allowance budget, not an addition to it. For more information on new-unit allocations, please see Preamble Section VII.D.2.
Organization: Big Rivers Electric Corporation
Comment: 
Big Rivers Electric Corporation
The cap and trade option for compliance will only work if allowances are available.  It is likely that utilities that are allocated more allowances than are needed to meet compliance will hold onto those allowances to meet future needs.  EPA should consider creating a pool of allowances that are available for purchase in the early years, following the effective date of the regulation to cover the time utilities are required to comply with the new regulation and the installation of control equipment.  Without this pool of allowances, it is likely that a reduction in generation will be the only option for compliance in the early years following the program inception. [EPA-HQ-OAR-2009-0491-2661.1, pp.2-3]
Response: 
Thank you for your comment.Organization: Birchwood Power Partners, L.P.
Comment: 
Birchwood Power Partners, L.P.
Birchwood Power is concerned that EPA's proposed allocation of annual NOx allowances will be insufficient when demand for electricity returns to levels experienced prior to the recession. Already, dispatch in 2010 has shown a significant increase over dispatch in 2009. [EPA-HQ-OAR-2009-0491-2706.1, p.1]
Birchwood Power is operated pursuant to a long-term contract that does not allow for the recovery of the costs for emissions allowances. Further, under this contract, Birchwood does not exercise control over when the facility can be dispatched, but must operate whenever called upon by Dominion. Accordingly, any shortfall in allowances could have drastic consequences on the facility's continued operation by significantly increasing the plant's operating costs. [EPA-HQ-OAR-2009-0491-2706.1, p.2]
Birchwood Power believes EPA should provide relief, as Congress previously has, for long-term contract generators who have no means of recovering the cost of emissions allowances. As described in more detail below, EPA should make any remaining allowances in the new unit set-aside available to long-term contract generators who exceeded their allocation in the preceding control period due solely to an increase in utilization back to levels achieved prior to the recession. This would prevent long-term contract generators from needing to pay potentially significant costs for allowances on the spot market after the conclusion of a control period. It also could be accomplished without compromising the integrity of the statewide emissions budgets. [EPA-HQ-OAR-2009-0491-2706.1, p.2]
The Proposed Transport Rule's 'assurance provisions' will unfairly prejudice the .interest of long-term contract generators vis-a.-vis utility-owned or merchant generating facilities, which can recover the costs for additional allowances from ratepayers or through the market price of electricity. Birchwood Power would encourage EPA to include provisions in the final rule that would provide relief to long-term contract generators from the impacts that the assurance provisions could have on their operating costs and competitiveness. At the very least, Birchwood Power believes that this concern supports EPA's proposal to delay implementation of the assurance provisions until 2014. Birchwood Power would also suggest that EPA increase both the one-year and three-year variability limits to 15% and 10%, respectively, of a state's budget. [EPA-HQ-OAR-2009-0491-2706.1, p.2]
B. As a Long-Term Contract Generator, Birchwood Power Cannot Pass Along the Costs for Emissions Allowances to Its Customers
Birchwood Power is operated pursuant to a contract with Dominion (Virginia Power) that does not allow for the pass-through of costs associated with emissions allowances. Unlike a utility that can seek to recover costs associated with emissions allowances from its ratepayers or a merchant generator that can recover such costs through the market price of electricity, long-term contractor generators such as Birchwood Power can be severely impacted by the requirement to purchase emissions allowances. Further, long-term contractor generators do not exercise control over when their facilities can be dispatched, but must operate whenever called upon by their customers. [EPA-HQ-OAR-2009-0491-2706.1, p.3]
Congress previously recognized that long-term contract generators do not have a mechanism to pass through new environmental costs to their power purchasers, and exempted these plants from the Acid Rain Program under the 1990 Clean Air Act Amendments so long as the long-term agreements remained in effect. More recently, under The American Clean Energy and Security Act of 2009,' (H.R. 2454) ('Waxman-Markey'), the House of Representatives passed legislation that would have made a pool of allowances available at no cost to long-term contract generators with an agreement executed before March 1, 2007 'that does not allow for recovery of the costs of compliance with the limitation on greenhouse gas emissions under this title.' (Id. § 783(a)(5)(B).) Similar provisions were included in the 'Clean Energy Jobs and American Power Act,' ('Kerry-Boxer') that was reported out of the Senate Environment and Public Works Committee in November 2009. [EPA-HQ-OAR-2009-0491-2706.1, pp.3-4]
C. EPA Should Make the Remaining Allowances in the New Unit Set-Aside Available to Long-Term Contract Generators That Exceed Their Allocation Due to an Increase in Dispatch Back to a Level Achieved Since 2005, Before Distributing Any Remaining Portion of the Set-Aside to Other Existing Sources
As Congress has previously done, EPA should recognize the unique situation of long-term contract generators that cannot pass along the costs of emissions allowances. to their customers. EPA could do this by making available any allowances that remain in the new unit set-aside for any control period in which the long term contract generator's emissions exceeded its allocation due solely to a return of the facility's dispatch back to pre-recessionary levels, i.e., where emissions increased because the facility's heat input had increased to a level that the generator had, in fact, achieved in any calendar year or ozone season since 2005. This would provide relief for long-term contact generators who experience an increase in utilization from the levels EPA has relied upon in establishing allocations, without providing a permanent allocation that could be sold to others. [EPA-HQ-OAR-2009-0491-2706.1, p.4]
Our proposed approach could be implemented as follows:
:: EPA would make allocations to new units from the new unit set-aside as currently proposed (by September 1 of any control period for the annual NOx and S02 trading programs and June 1 for the ozone season NOx trading program). [EPA-HQ-OAR-2009-0491-2706.1, p.4]
:: However, rather than distribute any remaining allowances in the new unit set-aside to existing eligible sources, EPA would wait until after completion of the control period (i.e., after December 31 for the annual programs or September 30 for the ozone season program) and would then provide any long-term contract generator the opportunity to demonstrate, upon submission of an application to the Administrator (within 30 days of the end of the control period), that it exceeded its allocation in the preceding control period due solely to an increase in its dispatch (i.e., heat input), back to a level that it had achieved during any calendar year or ozone season since 2005. The long-term contact generator would also need to demonstrate that it was operated during the control period pursuant to one or more contracts that do not allow for recovery of costs associated with purchase of emissions allowances and were executed prior to the effective date of the Transport Rule. [EPA-HQ-OAR-2009-0491-2706.1, p.4]
:: Then, at least 30 days prior to the allowance transfer deadline for each control period (March 1 of the subsequent year for the annual trading programs and December 1 of the same year for the ozone season trading program), the Administrator would record in the account of any contract generator that has adequately demonstrated its eligibility per preceding paragraph an amount of allowances equal to the number of tons by which the long-term contract generator had exceeded its allocation in the preceding control period. [EPA-HQ-OAR-2009-0491-2706.1, pp.4-5]
:: If the total amount of allowances requested by long-term contract generators for any control period should be greater than the remaining portion of the new unit set-aside, each qualifying generator would receive a proportionate share of the remaining portion of the set-aside, just as EPA has already proposed for new units. [EPA-HQ-OAR-2009-0491-2706.1, p.5]
:: If some portion of the new unit set-aside should still remain after recording allowances in the accounts of long-term contract generators per the preceding paragraphs, the Administrator would then allocate that remaining portion to all other existing eligible units, as EPA has already proposed in the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2706.1, p.5]
For facilities like Birchwood Power, which already operates with state-of-the-art emissions control technology, our proposed approach would provide needed relief should the facility be called to dispatch more frequently than in the period upon which EPA based its allocation, but no more frequently than it was operated prior to the recession. Moreover, this relief could be provided to such generators without compromising the integrity of the cap. [EPA-HQ-OAR-2009-0491-2706.1, p.5]
By providing priority access to remaining allowances in the new unit set-aside, EPA could spare long-term contract generators the potentially significant cost of purchasing allowances from the spot market after the conclusion of a control period. In addition, the proposed approach would not alter investment decisions, since a long-term contract generator that anticipates increased utilization and can achieve additional cost-effective reductions or purchase additional allowances at a reasonable cost will presumably do so, rather than risk that no allowances will remain in the new unit set-aside. [EPA-HQ-OAR-2009-0491-2706.1, p.5]
Response: 
Thank you for your comment.Organization: City of Ames, Iowa
Comment: 
City of Ames, Iowa
2) The SO2 allocations for 2012 for the City of Ames Units 7 & 8 (ORIS Code 1122) are inadequate to serve the citizens of Ames who rely upon us for electricity, steam for the hospital, and the burning of municipal solid waste (refuse-derived-fuel a.k.a. RDF). [EPA-HQ-OAR-2009-0491-2769, p.2]
6) The allowances allocated under this proposed rule are inadequate to allow the electric utility for the City of Ames to supply the electricity to meet the demand of the city, especially so when accounting for the city's load growth which will increase the utilization of the existing generation infrastructure. [EPA-HQ-OAR-2009-0491-2769, p.2]
8) The SO2 allocations for Unit 7 and Unit 8 in 2012 are not adequate to meet the generation requirements of the utility . We already are using one of if not the premier super low sulfur Powder River Basin (PRB) coals available. The combination of high Btu value (8800 Btu/lb) and low sulfur (0.21%) yields the least SO2 (0.48 lbs. SO2/mmBtu) available. Yet we still are short of SO2 allocations.
9) The heat input (HI) allocation in 2012 for Unit 8 for SO2 of 2,839,221 mmBtus must be a mistake . The value is so low that it cripples the use of the unit to meet the needs of the utility to supply electrical power (and steam to the hospital ) for the City of Ames (Iowa). In fact, the HI allocation for Unit 8 is lower than the actual HI for Unit 8 for the past ten (10) years, 2000 through 2009.
10) The combined HI allocations in 2012 for Unit 7 and Unit 8 for SO2 of 5,021,132 mmBtus (2,181,911 + 2,839,221 = 5,021,132) is also inadequate to meet the generation needs of the utility to serve the City of Ames . The value of 5,021,132 mmBtus is less than the combined actual HI for Unit 7 and Unit 8 for every year but one in the past ten (10) years, 2000-2009. The only exception is in year 2009, which as was already discussed in Item 7 above was a very unusual year due to reduced sales due to the recession, and reduced native generation due to extremely low priced purchased power, also a result of the recession. (See Item 7 above.) The combined allocation of 5,021,132 mmBtus is 15% less than the average actual HI for both units (Unit 7 & 8) for the period 2000-2009, and is 40% less than the actual HI (7,009,958 mmBtus) for both units that occurred in 2005. [EPA-HQ-OAR-2009-0491-2769, p.3]
11) Why are the allocated Heat Inputs for NOx different than the allocated Heat Inputs for SO2?
12) Why are there no ozone season allocations for NOx?
13) Why are there no allocations for GT2?
14) Ames Diesel Generating Stations 1 & 2 (ORIS code 1052) are not active generating units for the City of Ames (Iowa) Municipal Electric Services.
15) In the technical supporting document (BADetailedData.xls; tab sheet 'Projected Data'; column E), the values for Units 7 & 8 are in error. The are shown as 120,700 and 256,030 mmBtus for Units 7 & 8, respectively. It appears the intended values should have been 1,207,000 and 2,560,300. [EPA-HQ-OAR-2009-0491-2769, p.4]
17) The 'Air Transport Rule' itself and the HI, SO2, and NOx allocations assigned to the individual EGUs are so complex, confusing, and nearly untraceable, that we were so far unable to understand the logic and the path of calculations that led to the assignment of allocations to our units. [EPA-HQ-OAR-2009-0491-2769, p.4]
19) As of September 1, 2009, the City of Ames Municipal Electric Services became a market participant of the Midwest Independent Transmission System Operator (Midwest ISO) headquartered in Carmel, Indiana. As such, the power generation philosophy and requirements to serve load and provide for system reliability and stability, is vastly different from historical and traditional philosophy. Whereas we used to operate units almost exclusively to serve native load, now we may be required to provide generation and/or voltage support for a regional problem. For example, this may require the utilization of our peakers (GT1 and GT2) more than what we have used them for in the past. We need sufficient allocations for our units to carry out our responsibilities in the market. [EPA-HQ-OAR-2009-0491-2769, p.4]
20) The HI allocations for NOx , and the allocations for NOX are not adequate to serve the needs of the City of Ames. This is especially true for Unit 8. The NOx allocation for Unit 8 is less than the actual NOx emissions for every year but one in the past ten (10) years. In fact, the one exception is a tie , 605 tons to 605 tons. The Unit 8 NOx emissions for the past ten (10) years averages 42% more than the allocation. [EPA-HQ-OAR-2009-0491-2769, p.4]
Response: 
Thank you for your comment.Organization: Class of '85 Regulatory Group
Comment: 
Class of '85 Regulatory Group
EPA Should Allow Trading Between Both SO2 Groups
The 'State Budgets/Limited Trading' remedy currently divides covered states into two groups for the purposes of SO2 emissions budgeting and trading. The 'Group One' states face additional reductions in their SO2 budgets beginning in 2014, while 'Group Two' states do not face additional SO2 reductions. At the same time, EGU owners are limited to their SO2 group for allowance trading purposes. In other words, an EGU owner cannot purchase SO2 allowances from an entity in a 'Group Two' state to comply with allowance requirements in a 'Group One' state. While creating two separate SO2 groups for emissions budgeting and allocation may be a reasonable mechanism for achieving further SO2 reductions in some states, the proposed prohibition on SO2 allowance trading between groups is unnecessary in light of the variability requirements, appears arbitrary, and will not further EPA's goal of assuring state-specific emission reductions. [EPA-HQ-OAR-2009-0491-2854.1,p.10]
The emissions markets established by the preferred option are already small because they are limited by the ten percent variability limits. But a liquid market is essential for the successful implementation of the Transport Rule within EPA's proposed timeframe. Without allowances available for purchase, or with concentrated market power distorting allowance markets, the variability limits are all but useless. By limiting SO2 allowance trading to within an individual SO2 group, the preferred option effectively halves the SO2 allowance market, exacerbating many of the same market power problems, allowance shortages, and other market inefficiencies identified as shortcomings in the 'State Budgets/Intrastate Trading' alternative. As EPA correctly observes, limited markets are less efficient, raise costs, and may reduce benefits, which is clearly demonstrated by a comparison of the interstate and intrastate trading remedy options. [EPA-HQ-OAR-2009-0491-2854.1, pp.10-11]
The preferred option relies on strict annual variability limits at both the unit and state levels, additional state-level rolling three-year variability limits, and allowance surrender requirements to assure that state-specific emissions reductions occur. Because it is these provisions that assure that emissions reductions take place in a given state, and not any limits on the geographic source of allowances, allowing trading across SO2 groups does nothing to undermine the goal of state-specific emissions reductions and is consistent with North Carolina. And, by 2014, the state SO2 budgets are very similar in any event, further indicating that restricting trading to within each SO2 group is unnecessary. EPA has not provided any valid justification for restricting trading to within a given SO2 group. Accordingly, EPA should remove this artificial and unnecessary limitation and allow emission allowance trading across S02 groups. This will improve emissions markets and have no adverse impact on specific instate emissions reductions. [EPA-HQ-OAR-2009-0491-2854.1,p.11]
EP A Should Clarify That Retired Unit Allowances Remain Available to New Units.
The Class of '85 supports a new unit allowance allocation set-aside. The Class of '85 also supports the expansion of the new unit set-aside through the addition of allowances from retired units. EPA should retain this provision and clarify that all allowances from retired units will become available to new units through the mechanism described in the preferred option. At the same time, EPA should retain the continuing allocation provisions for non-operating units, which will decrease incentives to continue operating certain units. EPA also should clarify that repowered units are not 'new' and allow those units to retain their initial allowance allocations. Because repowered units face uncertainty in the current new-unit allocation process, this clarification will remove a disincentive to repower existing units. [EPA-HQ-OAR-2009-0491-2854.1,pp.13-14]
Response: 
Thank you for your comment.Organization: Cogen Technologies Linden Venture, LP
Comment: 
Cogen Technologies Linden Venture, LP
M. EPA Should Make Remaining Allowances in the New Unit Set-Aside Available to Long-Term Contract Generators Who Experience a Shortfall Due to a Return of Utilization Back to Levels Achieved Prior to the Recession
Linden Cogen believes EPA should make any remaining allowances in the new unit set-aside available to long-term contract generators who exceeded their allocation due solely to an increase in utilization back to levels achieved prior to the recession. Unlike a utility that can seek to recover costs associated with emissions allowances from its ratepayers or a merchant generator that can recover such costs through the market price of electricity, long-term contractor generators can be severely impacted by the requirement to purchase emissions allowances. Further, long-term contractor generators do not exercise control over when their facilities can be dispatched, but must operate whenever called upon by their customers. [EPA-HQ-OAR-2009-0491-2712.1, p.22]
Congress has previously recognized the economic realities faced by long-term contract generators who have no way of recovering the cost of emissions allowances, both upon enacting the Acid Rain Program under the 1990 Clean Air Act Amendments and more recently as part of the development of a federal cap and trade program for emissions of greenhouse gases. By making allowances remaining in the new unit set-aside available to long-term contract generators before distributing the remainder of the set-aside to eligible existing facilities, EPA could prevent long-term contract generators from needing to pay potentially significant costs for allowances that cannot be passed along to their customers. [EPA-HQ-OAR-2009-0491-2712.1, p.22]
As described previously, EPA must either address the errors in IPM that have resulted in its unrealistically low projections for dispatch of Linden Cogen or base allocations for individual units in New Jersey on historic heat input data. Even if EPA should take either of those two approaches to resolve Linden Cogen's concerns regarding the proposed NOx allocations, EPA should nonetheless make any remaining allowances in the new unit set-aside available to long-term contract generators. This would provide needed relief if a long-term contract generator experiences a shortfall in allowances due to a return of demand to pre-recessionary levels, without compromising the integrity of the statewide emissions budgets. [EPA-HQ-OAR-2009-0491-2712.1, p.22]
Response: 
Thank you for your comment.Organization: Cogentrix Energy, LLC
Comment: 
Cogentrix Energy, LLC
Cogentrix has found conflicts in definitions of applicability between the proposed Transport Rule and the Acid Rain and CAIR Rules that have resulted in our two Virginia units being excluded from allocations in the draft Rule, In addition, Cogentrix supports any opportunity to trade credits to promote economic efficiency. By doing so, electricity consumers will not bear unnecessary economic costs in their rates and service. Finally, we believe the implementation process may be more efficient - for both generators and regulators - if state agencies are given a more active role. Our more detailed comments on each of these items follow. [EPA-HQ-OAR-2009-0491-2772.1, p.1]
Cogentrix Sites in Hopewell, VA and Portsmouth, VA are not included in proposed allocations. Cogentrix has reviewed proposed allocations listed in EPA's Technical Information for the Transport Rule. Cogentrix-owned sites in Hopewell, VA (ORIS Code 10377) and Portsmouth, VA (ORIS Code 10071) were not included in either 'AllocationTable.pdf' or 'AllocationTable.xls.' Both sites operate with two 'three on one' boiler to generator designs, where three boilers provide steam to one 55-MWe electric generator. The Transport Rule provides applicability requirements listed under Title 40 Code of Federal Regulations 97.404(a)(1) as follows: [EPA-HQ-OAR-2009-0491-2772.1, pp.1-2]
The following units in a State shall be TR NOx Annual units, and an source that includes one or more such units shall be a TR NOx Annual source, subject to the requirements of this subpart: Any stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine serving at any time, since the later of November 15, 1990 or the startup of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe producing electricity for sale. [EPA-HQ-OAR-2009-0491-2772.1, p.2]
Since the 'generator... nameplate capacity' for each generator (emphasis added) at each site is greater than 25 MWe, Cogentrix sites are included within the scope of the Transport Rule and therefore allocations for each site should be assigned. Cogentrix also reviewed EPA's Technical Infonnation file entitled 'BADetailData.xls.' The analysis shown in this file appears to use the definition of applicability taken from the Acid Rain rules, where 'units' (interpreted to be boilers) with a capacity of less than 25 MWe are not included within the scope of the Acid Rain rule. Both Cogentrix facilities opted into the Acid Rain Program in 2008; and should have been included in EPA's al1ocation analysis on that basis alone. Both Cogentrix facilities have also been participants in the CAIR program since its inception and likewise, should have been included in EPA's al1ocation analysis on that basis alone. [EPA-HQ-OAR-2009-0491-2772.1, p.2]
Because both units meet the applicability definition in the proposed Transport Rule, Cogentrix has conducted an analysis of allocations and required reductions from 2005 baseline emissions data using the methodology discussed in the preamble of the proposed rule. The calculation methodology is presented in Attachment I and the results are presented in Table I. Cogentrix requests that allocations for both the Hopewell and Portsmouth sites be added to the Virginia state-wide allocation allotment as detailed in Table 1 below. Cogentrix has used 2005 coal throughput data to develop these allocation estimates as prescribed in the proposed rule background. In addition, current S02 control efficiencies have been incorporated into the allocation estimates as these units were installed after 2005. [EPA-HQ-OAR-2009-0491-2772.1, p.2]
[See EPA-HQ-OAR-2009-0491-2772.1, p.3 for Table 1]
Cogentrix Supports Credit Allocation Delegation to State Agencies. [EPA-HQ-OAR-2009-0491-2772.1, p.4]
EPA proposes a very aggressive timeline for implementation ofthe Transport Rule, with allocations for some states beginning in 2012. Given the number of affected facilities and short timeframe for implementation, Cogentrix supports the maximum possible delegation of the Transport Rule and allocation allotment to state agencies. [EPA-HQ-OAR-2009-0491-2772.1, p.4]
Since the criteria for affected sources differs under many EPA rules, a true dataset for emissions allocation development is unlikely to be available for EPA's use. Cogentrix has already identified two of its sites that were not included in the allocation allotments used for proposed rule development. Cogentrix believes that each state is likely to have hands-on knowledge of affected facilities, implemented controls, and operational status so that allocation allotments can be properly and more readily distributed and reviewed. Furthermore, Cogentrix requests that each state be able to comment on their allocation allotment to ensure that all sources are properly accounted for in the state's total and that proper adjustments can be made prior to rule finalization. [EPA-HQ-OAR-2009-0491-2772.1, p.4]
Response: 
Thank you for your comment.Organization: Consumers Energy
Comment: 
Consumers Energy
F. The Proposed Allowance Allocations Are Inadequate to Support a Limited Trading Program
1. Group 1 SO2 States
In order to understand whether or not allowances will be available in the market to purchase, Consumers Energy first took a look at historic S02 emission rates and heat input data (2005-2009) for each of the states listed as a Group I state. The maximum heat input over that five year period was multiplied by the minimum SO2 emission rate over that same time period and the resulting emissions were used as a baseline emission for the years 2012 through 2016. The announced Flue Gas Desulfurization (FGD) retrofits as of August 2010 that were reported by CERA were compiled for each state (assuming a 95% reduction in SO2 emissions for each unit retrofitted) and the emissions were then adjusted downward accordingly. The newly adjusted emissions for each state were then compared to their proposed state budgets. As shown in the tables below, there will be little to no excess SO2 allowances available for purchase in any of the 15 Group 1 states. [EPA-HQ-OAR-2009-0491-2837.1, p.11]
[The tables referred to in 1. Group 1 SO2 States can be found on page 11 of this comment.]
2. Annual NOx States
In order to understand whether or not allowances will be available in the market to purchase, Consumers Energy first took a look at historic NOx emission rates and heat input data (2005-2009) for each of the states that have Annual NOx compliance requirements. The maximum heat input over that five year period was multiplied by the minimum NOx emission rate over that same time period and the resulting emissions were used as a baseline emission for the years 2012 through 2016. The announced Selective Catalytic Reduction (SCR)/Selective Non-Catalytic Reduction (SNCR) retrofits as of August 2010 that were reported by CERA were compiled for each state (assuming a 30% reduction in SO2 emissions for each unit retrofitted with an SNCR and a 0.06 lb/mmbtu emission rate for each unit retrofitted with an SCR) and the emissions were then adjusted downward accordingly. The newly adjusted emissions for each state were then compared to each state's proposed budget. As shown in the tables below, there will be little to no excess Annual NOx allowances available for purchase in any of the states that are required to comply with the Annual NOx limits as proposed by the EPA. [EPA-HQ-OAR-2009-0491-2837.1, p.12]
[The tables referred to in 2. Annual NOx States can be found on pages 12-13 of this comment.]
Given the limited amount of time available due to the compressed comment period, and using the most readily available information, preliminary analysis results indicate there will be little to no allowance markets. Under CAIR companies had the option to use banked allowances, both SO2 and NOx, as part of their compliance plan in order to reasonably stagger the scheduled installation of Pollution Control Equipment for a 2017 compliance date. There are many benefits to this approach:
:: Less demand on materials; this means lower procurement costs and lower impact to customers.
:: Less demand on replacement power; this also means lower impact to customers.
:: Staggered installations result in multiple gradual increases to customer rates as opposed to a few rather large rate increases. [EPA-HQ-OAR-2009-0491-2837.1, p.13]
:: If a limited trading program cannot be crafted to satisfy the D.C. Circuit Court's ruling, then state-wide trading or averaging should be the next choice.
:: Allocations should be handled by the states. The states know their jurisdictions and their sources best. A total allowance budget should be assigned to each state. They can handle the distribution schemes. [EPA-HQ-OAR-2009-0491-2837.1, p.16]
Response: 
As described in Preamble Section VII.A, banking of allowances is allowed under the Transport Rule programs.  EPA's modeling projections of the Transport Rule show that many states, particularly Group 1 states, have the capacity to overcomply with (i.e., emit below) their 2012 budgets and therefore establish an allowance bank that they may access in subsequent years to gain all of the economic and planning advantages cited by the commenter.  EPA's detailed power sector dispatch modeling offers a superior degree of unit-level detail and least-cost electricity supply functions than the calculations provided by the commenter, and based on these modeled projections, EPA disagrees with the commenter that "little to no excess" allowances will be available under the Transport Rule air quality-assured trading programs.  EPA notes that the intent of the Transport Rule's market-based regulation is to incentivize every covered unit to achieve whatever cost-effective reductions are available based on the market signal (e.g., allowance price) created by the imposition of state budgets on the fleet.  In prior market-based emissions trading programs, sources have found cost-effective reduction strategies that were not anticipated by regulators, which have helped to create even larger allowance banks than originally modeled upon promulgation of the related regulations.  EPA believes that the Transport Rule programs as designed will promote liquid allowance markets with an adequate margin for trading and banking at the outset of the program, as its modeling projections show; however, although the Agency could not base the details (e.g., state budgets) of this regulation on this expectation, EPA also finds it reasonable to anticipate that the sector may again outstrip the modeled cost-effective emission reductions and potentially provide additional reductions that the programs incentivize but that regulators do not specifically foresee at this time.  For these reasons, EPA believes the concerns raised by this commenter are unfounded and unsupported by either the information presented for this rulemaking or the wealth of experience the power sector and the Agency have gained from prior emissions trading programs.
Organization: Dairyland Power Cooperative
Comment: 
Dairyland Power Cooperative
II. John P. Madgett (Bl): S02 Allocations and Direct Control Alternative S02 Emission Rates Based on Only the Lowest Sulfur Coal Quality Produced in the Powder River Basin is Not a Reasonable Assumption.
In Attachment I, Dairyland Power proposes revisions to the S02 allocations and direct control S02 emission rates for John P. Madgett (BI). Historically, Dairyland Power has procured coal from the Power River Basin (PRE) for John P. Madgett (BI) with a range of coal sulfur quality and corresponding S02 emission rate that is generally representative - - up to approx. 1.1 lb S02 /rnrnBtu - - of the range of sulfur concentration found in coals produced in the PRB. Coal procurement decisions are based on numerous factors, some of which are, compatibility with boiler performance, product availability to a low volume buyer like Dairyland Power, product price, transportation availability, transportation price, along with other typical contractual terms. [EPA-HQ-OAR-2009-0491-2733.1 p.3-4
It is not conceivable that coal production from only a limited portion of the PRB coal fields - only the mine(s) in the PRB having the very lowest sulfur quality coal - - could satisfy the coal demand created by the EPA's assumed 2012 and 2014 S02 direct control emission rate, and corresponding S02 allocations, based on the 'lowest sulfur' coal quality produced in the PRB. Not only is it questionable to assume there is the production capacity to produce the quantities necessary to meet demand for the lowest sulfur quality PRB coal, it is also questionable that the infrastructure will exist to load-out, transport, and deliver the coal product to utility sites. [EPA-HQ-OAR-2009-0491-2733.1 p.4
It is imperative that the final Transport Rule does not preclude Dairyland Power from the flexibility to procure coal from a range of suppliers and mines in the PRB. We urge the EPA to take our comments into consideration when finalizing the Transport Rule S02 allocations and direct control alternative S02 emission rates for John P. Madgett (B1).  [EPA-HQ-OAR-2009-0491-2733.1 p.4]
III. Genoa (1): The EPA's Proposal For S02 and NOx Allocations and Direct Control Alternative S02 and NOx Emission Rates Fail to Take Into Account the Boiler Design Heat Input and Will Result in a Significant Loss of Electric Output Capacity From the Unit. [EPA-HQ-OAR-2009-0491-2733.1 p.4]
In Attachment 1, Dairyland Power proposes revisions to the 2012 and 2014 S02 and NOx allocations and direct control S02 emission rates for Genoa (1). In making these allocations, the EPA has erroneously assumed 100% PRB quality coal for the basis of crafting the proposed 2012 and 2014 S02 and NOx allocations and direct control alternative S02 and NOx emission rates. Typically, the Genoa (l) unit has been fueled with a blend of bituminous coal and subbituminous coal. Historically, the blend ratio, and corresponding resulting boiler heat input, was determined by the need to match unit electrical output to system electrical demand; while preserving the capability to 'blend-up' to a high heating value coal to attain typical maximum output capacity during periods of peak system demand. It is only during the recent economic recession that slack system demand caused Dairyland Power to alter the historical fueling strategy of bit/subbituminous 'blend' fuel to one of burning 100% PRB coal during so-called 'shoulder' season months - a time that typical lower electric demand due to seasonal factors was pushed even lower due to factors related to the economic recession. [EPA-HQ-OAR-2009-0491-2733.1 p.4]
It is expected that the economy will recover from the recent slump and, along with it, return to historical electrical demand. It is expected that the Genoa (l) unit will again be needed to produce the maximum electrical output corresponding to the unit design; a capacity which can only be achieved with a greater heating value coal blend than with straight 100% PRB coal. [EPA-HQ-OAR-2009-0491-2733.1 p.4]
Dairyland Power's experience with fueling the Genoa (l) unit with 100% PRB coal results in an electric output capacity reduction of approximately 23% to 28% resulting from the reduced boiler heat input. Making modifications to the tmit to alleviate the electric output derate associated with lower heating value of 100% PRB coal may be considered by some staff at EPA to be a physical change triggering NSR/PSD permitting requirements. [EPA-HQ-OAR-2009-0491-2733.1 p.4-4]
The 23% to 28% derate in maximum unit electric output capacity of the Genoa (1) unit on 100% PRB coal is the equivalent of a 90 to 110 gross MWe generating unit. This magnitude of lost generating capacity is significant to a small rural electric cooperative like Dairyland Power which has a small portfolio of generating assets. It is infeasible at this point in time for Dairyland Power to build replacement generating capacity by 2012. Dairyland Power would face a very constrained timeline to attempt to contract for replacement capacity between the time of rule promulgation and 2012. [EPA-HQ-OAR-2009-0491-2733.1 p.5]
The Genoa (1) unit can not meet the EPA's proposed S02 and NOx allocations and direct control alternative S02 and NOx emission rates and achieve the unit's full electric output capacity. We urge the EPA to take our comments into consideration when finalizing the Transport Rule S02 and NOx allocations and direct control alternative S02 and NOx emission rates for Genoa (1). [EPA-HQ-OAR-2009-0491-2733.1 p.5]
IV. Elk Mound Unit 1 and Elk Mound Unit 2: The EPA's Failure to Propose Any S02 and NOx Allocations and Direct Control Alternative S02 and NOx Emission Rates is an Indication That EPA's IPM Model is Flawed and Does Not Reflect the Reality That These Units Do Dispatch in the Midwest ISO Market. [EPA-HQ-OAR-2009-0491-2733.1 p.5]
Since Dairyland Power joined the Midwest ISO in June of2010, Elk Mound Unit I and Elk Mound Unit 2 have operated at a significantly higher capacity factor than recent past years. The Midwest ISO is dispatching these units for 'reliability dispatch' rather than 'economic dispatch.' The units are geographically located in a 'transmission constrained' area, and even though these units would not otherwise be called upon to operate in a strict economic model, they are called upon to operate to relieve a transmission constraint. This is an example that EPA's IPM model fails to take into account real-world generation supply and transmission grid limitations. Dairyland Power's energy supply planning model has these units continuing to dispatch in future years and, therefore, it is imperative that these units receive S02 and NOx allocation and direct control alternative S02 and NOx emission rates in the final Transport Rule. [EPA-HQ-OAR-2009-0491-2733.1 p.5]
We urge the EPA to take our comments into consideration when finalizing the Transport Rule S02 and NOx allocations and direct control alternative S02 and NOx emission rates for Elk Mound Unit 1 and Elk Mound Unit 2. [EPA-HQ-OAR-2009-0491-2733.1 p.5]
Response: 
Thank you for your comment.Organization: Dayton Power and Light Company (DP&L)
Comment: 
Dayton Power and Light Company (DP&L)
DP&L has invested hundreds of millions in environmental controls that significantly reduce air emissions in a region already hit hard by the recession. DP&L requests that EPA not inordinately minimize allowance allocations to those who have invested in air pollution control equipment, in order to provide extra allowances to those who have not. [EPA-HQ-OAR-2009-0491-2637.1, p. 2]
DP&L, like UARG, also favors aspects of the EPA's 'preferred option,' specifically allowing interstate trading on at least a limited basis and EPA's decision to issue, not auction the allowances. [EPA-HQ-OAR-2009-0491-2637.1, p. 3]
Allowance Budgets Should Align with the Capabilities of Currently Operating NOx Control Equipment
For the reasons set forth below, DP&L recommends that the EPA consider and adopt one of two potential modifications to its proposed rules with respect to the NOx emissions budgets. Item #1 is the approach preferred by DP&L. [EPA-HQ-OAR-2009-0491-2637.1, p. 4]
1. State Implementation Plans to Reduce Interstate Transport. EPA should closely comply with the 1990 CAA and allow the states to develop SIPs that would include the apportionment of Ohio's NOx transport tonnage cap in an appropriate manner to affected sources. Ohio would also be able to include alternative approaches in its SIP to address the contributions from local emissions sources to any non-attainment area. 2. Federal Implementation Plans to Reduce Interstate Transport. If Ohio allocations are made through a Federal Implementation Plan ('FIP') at the EGU level as proposed, EPA should model with a NOx floor of 0.10 pounds per mmBtu. This level is in line with the median design of SCR infrastructure and New Source Review ('NSR') consent agreements. Such a floor would adjust the allocation method to the extent necessary to ensure that the NOx emissions budgets for base loaded coal units would not drop below 0.10 pounds of NOx per mmBtu. [EPA-HQ-OAR-2009-0491-2637.1, p. 4]
The NOx SIP Call, which preceded the CAIR rule, was intended to address ozone nonattainment due to the interstate transport ofNOx emissions. In Ohio, allowances were distributed by the state on a historical heat input basis that yielded approximately 0.15 pounds of NOx allowances per mmBtu. The NOx SIP Call further projected a year when this would be reduced to approximately 0.12 pounds of NOx allowances per mmBtu. Not surprisingly, the utilities who were contemplating the installation of SCRs had SCR's designed and installed to meet the then-current standards, with the flexibility to install additional equipment or make modifications that would permit the utility to meet a future standard of approximately 0.12 pounds. [EPA-HQ-OAR-2009-0491-2637.1, p. 4]
Recent consent decrees with major utilities approved by the EPA have instituted limits of 0.12 Ib/mmBtu and 0.10 lbs per mmBtu for units with SCRs, which appears consistent with the expectations of the CAIR program. DP&L is subject to a consent decree under which it is required to meet 0.10 lbs per mmBtu limit at its Stuart Station by January 2015. [EPA-HQ-OAR-2009-0491-2637.1, p. 4]
EPA's methodology, however, results in an unrealistic emissions budget level for the Stuart Station of less than 0.06 pounds of NOx per mmBtu beginning in 2012. If the EPA was to use existing information related to currently operating equipment there is every reason to believe that the values settled upon would be in the range of 0.10 to 0.12 pounds per mmBtu. Yet, EPA proposes a value significantly lower. It is not clear at this point what operational and structural changes would be necessary at Stuart Station to operate at such levels. [EPA-HQ-OAR-2009-0491-2637.1, p. 4]
The end-result is equally unrealistic for the Killen Station. The Killen SCR was designed to achieve 0.12 pounds ofNOx per mmBtu. That emission level was well suited to all previous NOx trading programs in Ohio and Ohio's CAIR transport allocation. The proposed rule provides Killen a budget allocation that assumes that it could operate at less than the 0.06 pounds ofNOx per mmBtu level, far below its current capability. Structural changes and an intensive catalyst replacement program would be necessary to approach these levels on a consistent basis. Operating flexibility (such as aligning with reduced load at night) might become incompatible with SCR operating temperature requirements. [EPA-HQ-OAR-2009-0491-2637.1, p. 5]
The 0.06 pounds per mmBtu level is also inexplicable when compared to the allowance allocations of the CAIR program. CATR reduces the amount of NOx allowances that would be provided to Killen and Stuart Stations by over 60% as compared to the amount of allowances that was to be provided under the CAIR program. US EPA has not fully explained the rationale for these reductions in NOx allowances, given that Ohio is a state in which the overall NOx cap remains relatively steady between the two programs. [EPA-HQ-OAR-2009-0491-2637.1, p. 5]
Response: 
Thank you for your comment.Organization: Detroit Regional Chamber
Comment: 
Detroit Regional Chamber
Innaccurate, outdated data has also skewed state and electric generating unit budget allocations by failing to account for emmision reductions since 2005. [EPA-HQ-OAR-2009-0491-2720.1, p.1]
Response: 
Thank you for your comment.Organization: Dominion
Comment: 
Dominion
Unlimited Banking of Allowances [EPA-HQ-OAR-2009-0491-2715.1, p.3]
EPA's proposal allows banking of allowances beginning in 2012 and thus recognizes the importance of environmental and economic benefits of allowance banking. We support this concept. The ability of sources to use banked allowances for compliance provides an incentive to make early reductions, to the extent that cost-effective early reductions are possible. [EPA-HQ-OAR-2009-0491-2715.1, p.3]
Retention of Allowances from Unit-Shutdowns or Retirements for 6 Years [EPA-HQ-OAR-2009-0491-2715.1, p.3]
We support EPA's approach that would continue to allocate allowances to non-operating and/or retired units for six years. This option provides an incentive to affected entities to retire older units for which retrofit installations would not be economically feasible as acompliance option. We also support EPA's proposed approach to allocate the allowances that would have otherwise been allocated to the retired unit to the state's new source set aside (each year beginning in the seventh year after unit retires) as a means of increasing the new source set aside over time. [EPA-HQ-OAR-2009-0491-2715.1, p.3]
New Source Set Aside [EPA-HQ-OAR-2009-0491-2715.1, p.3]
We support EPA's proposal to set aside a percentage of each state's budget (under each of the emissions budget trading programs) for distribution to new sources. In addition, we support the proposed approach to redistribute any unused allowances from the new source set aside to existing sources on a pro-rata basis in proportion to each existing unit's original allocation following each control period. We request, however, that EPA record allowances for new units by June 30th of each year (instead of the proposed date of September 1st) for the annual S02 and NOx programs and May 1st (instead of the proposed June 1st) for the ozone season NOx program so facilities have assurances oftheir allocations as quickly as possible for compliance planning purposes. [EPA-HQ-OAR-2009-0491-2715.1, p.3]
Decision not to Auction Allowances [EPA-HQ-OAR-2009-0491-2715.1, p.4]
We strongly agree with EPA's proposal to provide direct allowances to affected sources and not to auction allowances. The purpose of the Transport Rule is to reduce those emissions deemed to 'contribute significantly' to downwind nonattainment. Under the proposed regulation, each source is capped at a level that EPA has determined is necessary to eliminate its 'significant contribution' and is granted allowances (free of charge) to emit to that level. Sources that choose to emit above their cap must purchase additional allowances to do so. The use of auctions inappropriately forces affected sources to purchase allowances not only for emissions that exceed their capped emission levels, but also for the right to emit at levels below these levels. However, as noted briefly above and discussed in more detail below, we have serious concerns with assumptions EPA used in establishing unit allocations in the proposal. [EPA-HQ-OAR-2009-0491-2715.1, p.4]
EPA Should Allow Trading Across the SO2 Zones [EPA-HQ-OAR-2009-0491-2715.1, p.5]
EPA should consider allowing trading across the Group 1 and Group 2 S02 states, particularly during the first two years of the proposed program when emission reduction requirements are, according to EPA, established on the same basis. First, it appears that EPA's analysis of state emission and downwind nonattainment linkages used to determine the 'Group 1 states' that would require additional S02 reductions beginning in 2014 did not take into account the impact (benefit) of emission reductions required and expected to be achieved (in both upwind and downwind states) during the initial 2 years of the program. This raises question as to the necessity, level and geographic make-up ofthe Phase 2 requirements. Second, the grouping of states into different zones complicates compliance planning and could disadvantage companies that have generation assets spread across the 2 different regions, particularly if the majority of assets are concentrated in one trading region and a few others become 'isolated' in the other trading region. For example, Dominion owns and operates electric generating facilities in 7 states that will be subject to the Transport Rule as proposed. All of these assets withthe exception of 2 facilities are located in Group 1 states. Therefore, the Company's compliance for the 2 facilities in the Group 2 state will not be able to include the use of excess allowances (to the extent available) from its larger fleet in the Group 1 states as aviable option and may require potentially more costly acquisition of allowances from the open market or unit curtailments. This issue is amplified by a significant shortfall ofallowances allocated to these facilities in 2012 and 2013 under the proposed rule as a result of erroneous IPM model input assumptions used in establishing the state budgets (discussed in more detail in Section III below). To the extent EPA is concerned about impacts of trading across the 2 zones in 2014 and beyond when the tighter reductions are required in the Group 1 states, EPA is proposing to impose the assurance provisions of the that should serve to limit the amount of 'out-of-state' allowances used for compliance by affected sources in a Group 1 state regardless of whether those allowancesare generated in Group 1 or Group 2 states. [EPA-HQ-OAR-2009-0491-2715.1, p.5]
Response: 
Preamble Sections VII.D and XI provide detail on the schedule for recording allowances under the final Transport Rule and EPA's reason for choosing that schedule.
Organization: DTE Energy Services (DTEES)
Comment: 
DTE Energy Services (DTEES)
Relief for stranded units
As discussed below DTEES owns several facilities that are subject to the proposed Transport Rule, but have received zero allowances. DTEES considers these units stranded units because they are small units with no facilities owned by the same parent company with which allowances can be shared and emission rates can be averaged. DTEES is not confident that there will be a robust allowance trading market for Transport Rule, and as a result, these units will be unable to secure allowances at a reasonable price, or perhaps not at all. Is it EPA's intention for units such as these to shut down? DTEES believes EPA should allocate States' additional allowances for the purpose of creating a hardship set aside pool. [EPA-HQ-OAR-2009-0491-2699.1,p.2] [EPA-HQ-OAR-2009-0491-3721.1_NODA, p.1]
Response: 
Thank you for your comment.Organization: Dynegy, Inc.
Comment: 
Dynegy, Inc.
EPA's proposed allocation of SO2 allowances is based on the Agency's assumptions regarding reductions that could be achieved by 2012. In order to achieve such SO2 reductions from a FGD, that FGD must be constructed and placed into operation prior to 2012. [EPA-HQ-OAR-2009-0491-2698.1, p.3]
IPM-Modeled Outcomes Do Not Reflect Actual Source Operations
IPM predicted that the vast majority of dual-fuel oil and gas units would run exclusively on natural gas. Therefore, EPA did not allocate any SO2 allowances to dual fuel units. Apparently, IPM concluded that it was most 'economical' to run these units on natural gas and failed to consider seasonal constraints on natural gas supply. Shortage of natural gas supply during winter months, especially in the Northeast, is a real concern and is one of the primary reason these units have dual-fuel capability. The reality is that many of these units burn oil during winter months and need to do so to ensure a reliable electric supply. This is specifically the case with Dynegy's Roseton Units 1 and 2 located in Newburgh, NY. [EPA-HQ-OAR-2009-0491-2698.1,p.6]
In addition, IPM projects early retirement of our Danskammer Units 1 and 2 (dual-fuel oil and gas units located in New York) by 2014, but Dynegy does not have any plans to retire these units by 2014. It is unclear why EPA has made such a unilateral decision without recognizing the continued need for these units during periods of high peak demand to support the reliable supply of electricity, a vital role they have played many times during their past history of service. [EPA-HQ-OAR-2009-0491-2698.1,p.6]
Allowance Allocations Should Not Disadvantage Well-controlled EGUs
EPA's proposed allowance allocation methodology would not only reward high emitters and punish well-controlled EGUs, but also encourage increased operation of higher emitting EGUs relative to well-controlled EGUs. Rather than promoting such an inequitable result and its associated adverse implications for air quality, EPA should modify its allowance allocation methodology to ensure that allocations do not disadvantage well-controlled EGUs relative to higher emitting EGUs. [EPA-HQ-OAR-2009-0491-2698.1, p.6]
Impact on Operating Cost
EGUs are typically dispatched based on operating cost with the least expensive units dispatched more than higher priced units. An EGU's operating cost includes the price of fuel and operating efficiency, along with several environmental factors including the cost of chemicals used to control emissions, the cost to dispose control system by-products, and the cost of emission allowances. For example, units with scrubbers incur significant expenditures for chemicals (e.g., lime or limestone) and auxiliary power, as well as significant expenses associated with byproduct disposal. In fact, the byproduct disposal for scrubbed units will increase dramatically if EPA regulates scrubber material under RCRA Subtitle C. Likewise, units with SCRs incur significant expenses associated for ammonia and catalyst replacement. [EPA-HQ-OAR-2009-0491-2698.1,p.6]
Because these well-controlled units incur significant additional expenses that are not incurred by uncontrolled units, the higher-emitting, least controlled units are, aU things being equal, dispatched more. [EPA-HQ-OAR-2009-0491-2698.1,p.7]
EPA's proposed allowance allocation methodology would further encourage higher capacity factors for the least controlled and higher emitting units that do not have as many environmental costs. Specifically, EPA would allocate relatively few SO2 and NOx allowances to well-controlled units, but allocate relatively few SO2 and NOx allowances to units with higher emissions rates. Thus, these higher emitting units that do not have costs for SCRs or FGDs could enjoy a two-fold competitive advantage over well-controlled units equipped with both an SCR and FGD. [EPA-HQ-OAR-2009-0491-2698.1,p.7]
EPA's IPM model has attempted to consider these numerous economic impacts when predicting unit heat inputs. Since EPA does not have unit-specific operating costs, numerous and broad assumptions have been used in IPM. EPA's assumptions produce significantly different and often lower operating predictions than Dynegy's internal commercial business model. Rather than relying on either simulation model, Dynegy recommends EPA use representative historic unit heat input or gross electrical output to allocate emission allowances (see Dynegy Comment 3.b below). [EPA-HQ-OAR-2009-0491-2698.1, p.7]
Alternative Allocation Methodology
Instead of rewarding higher emitting EGUs through its proposed allowance allocation methodology and projected heat inputs, EPA should allocate allowances to all fossil-fuel-fired EGUs based on each source's proportional share of historic total state heat input or gross electrical output. This alternative allowance allocation approach is similar to EPA's alternative methodology discussed in the preamble (75 Fed. Reg. at 45311) and would create an opportunity for well-controlled units to recover a portion of their operating costs and at the same time create an incentive for higher emitting units to lower their emissions, except that it would rely on historic operating levels instead of predicted future operations. This would effectively impose the cost of buying allowances on less controlled sources making their operational cost nearer to that of the well-controlled sources. Or in EPA's words ''this alternative method for distributing allowances would have the effect of distributing the responsibility for eliminating all or part of a state's overall significant contribution and interference with maintenance to individual units', 75 Fed. Reg. at 45311 , rather than focusing that responsibility on the well-controlled units. This alternative allocation method, similar in concept to EPA's Acid Rain allowance allocations, would create a level playing field for all sources by not rewarding high emitting units with extra allowances and not penalizing well-controlled units with low allocations. [EPA-HQ-OAR-2009-0491-2698.1,p.7]
Voluntary Early Compliance or Over-Compliance Should Not be the Basis for Lower NOX Allowance Allocations
From 2005 through 2009 Dynegy voluntarily operated its SCR-controlled units well below all applicable NOx limits. As proposed, the Transport Rule would inexplicably penalize Dynegy for voluntarily having achieved addit ional NOx reductions at its SCR units by allocating approximately 60 percent fewer annual and ozone season NOX allowances to these units than would otherwise be allocated if Dynegy had only met its enforceable NOx emission limits. Other EGUs that voluntarily over-controlled would be similarly penalized. [EPA-HQ-OAR-2009-0491-2698.1,pp.7-8]
EPA's use of the lowest NOx rates ever achieved at such voluntarily over-controlled units to determine NOX allowance allocations would also have other negative impacts. For example, it would indirectly hinder compliance flexibility by eliminating a possible source of tradable allowances. More specifically, it would essentially eliminate Dynegy's ability to generate any NOX allowances it will need for compliance at its other units in Illinois, thereby limiting compliance options and increasing compliance costs. Moreover, basing Transport Rule NOX allowance allocations on these previous voluntary over-control efforts would perpetuate the need to use disproportionately large quantities of ammonia at Dynegy's SCR-controlled units, more than 500 tons of ammonia per year for each SCR-controlled unit and much more than needed to comply with the federally enforceable NOX limits. [EPA-HQ-OAR-2009-0491-2698.1, p.8]
In short, EPA's proposed allocation methodology is poor environmental policy in that it would punish EGUs that have installed and operated state-of-the-art pollution control systems beyond applicable requirements, while rewarding those EGUs that have lagging environmental performance. It also would create a disincentive for an affected facility to go beyond its minimum compliance requirements. [EPA-HQ-OAR-2009-0491-2698.1,p.8]
Dynegy, which owns and operates EGUs in several affected states, supports EPA's proposal to allow interstate allowance trading. While Dynegy would prefer unlimited interstate trading to the extent permitted by the Clean Air Act, even EPA's proposed limited interstate trading as described in its Preferred Remedy Option would improve compliance costs. Limited interstate trading would give companies such as Dynegy the flexibility to decide where to make its most cost effective emission reductions and then move allowances between its units 9within the proposed variability limits) rather than purchasing allowances from other out-of-state sources. [EPA-HQ-OAR-2009-0491-2698.1, p.8]
In the event EPA does not defer to effective date of the Transport Rule until 30-36 months after promulgation, Dynegy strongly supports EPA's proposal for unlimited intrastate trading and no variability limits prior to 2014. Such compliance flexibility will be essential for effective transition to the Transport Rule program. [EPA-HQ-OAR-2009-0491-2698.1, p.8]
Dynegy Supports EPA's Decision Not to Auction Allowances [EPA-HQ-OAR-2009-0491-2698.1, p.8]
Although Dynegy does not support the intrastate-only trading option, in the event that EPA promulgates a final rule based on the option, EPA should not enable or endorse government-run allowance auctions. Governmental auctioning of allowances would substantially increase the cost of the Transport Rule upon regulated entities, adding to viability concerns for many units and, thus, ultimately increasing costs to consumers and decreasing the reliability of electric supply. [EPA-HQ-OAR-2009-0491-2698.1, pp.8-9] 
Response: 
Thank you for your comment.Organization: East Kentucky Power Cooperative
Comment: 
East Kentucky Power Cooperative
EKPC General Comments [EPA-HQ-OAR-2009-0491-2776.1, p.5]
EKPC strongly urges EPA to allow electric generating units to bank SO2, annual NOx and Ozone NOx allowances as well as to carry over banked allowances from the CAIR program. EKPC also strongly urges EPA to clarify that should a unit be permanently removed from service, the allowances from that unit are the property of the unit owner. [EPA-HQ-OAR-2009-0491-2776.1, p.5]
As is true of many electric utilities, over the past number of years EKPC has invested heavily in emissions reductions at its facilities. Utilities such as EKPC should not now be penalized for those emission reductions efforts by receiving lower allocations as a result reductions achieved. This rule has the potential to ultimately result in the permanent removal from service of many units, in a significantly short time frame that would severely impact the grid system which powers our homes and cities. Further, thousands of jobs could potentially be eliminated in the electric utility industry due to unit and plant closings. Such implications should be seriously considered by EPA in finalizing the rule. [EPA-HQ-OAR-2009-0491-2776.1, p.5]
Response: 
In Preamble Section IX.A, EPA provides its rationale for not allowing allowances from the CAIR programs to be used to comply with the Transport Rule.
Organization: Edison Electric Institute (EEI)
Comment: 
Edison Electric Institute (EEI)
EEI supports EPA's proposal for allocating emission allowances under the preferred approach no later than September 1, 2011 for control periods in 2012, 2013 and 2014, and to allocate for future years starting on July 1, 2012 for the 2015 period, and on July 1 for each control period thereafter. [EPA-HQ-OAR-2009-0491-2697.1, p.16]
While supporting the referred approach, EEI offers the following additional input   
There are different views amongst EEI members on the most appropriate allocation methodology. Some companies support EPA's proposed methodology, while others will advocate for use of alternate methodologies.  [EPA-HQ-OAR-2009-0491-2697.1, p.17]
EPA's preferred approach prohibits the usage of banked Title IV, NOx SIP Call and CAIR allowances. EEI recognizes the legal challenges to incorporating these allowances in the Proposed Rule and, indeed, some EEI member companies support EPA's preferred approach. However, some EEI member companies observe that they have installed pollution control equipment to comply with CAIR and reduced emission below their allowance allocations. These companies believe the preferred approach proposed by EPA, in effect, penalizes them by stranding their banked allowances, They emphasize that many of those banked allowances exist due to overcompliance by the affected utilities and represent additional costs incurred by the companies and their customers. If the preferred interstate trading program is finalized as proposed, such an approach by EPA would send a negative message regarding overcompliance with any future regulation. Therefore, these companies would support an equitable approach to continued use of such banked allowances. [EPA-HQ-OAR-2009-0491-2697.1, p.17]
EEI supports EPA's proposal not to require a government-run allowance auction of the entire inventory of allowances under the preferred remedy option. Governmental auctioning of allowances is contrary to the principle that regulated sources should be permitted to emit up to their allowance allocation levels without any obligation to pay for the right to emit up to those levels. Some companies have suggested, however, that a small government auction, along the lines of the auctioning of a small number of allowances under the Acid Rain Program, may be necessary given the restrictions on trading contemplated under the preferred approach which may inhibit market formation. Such an auction could help provide the market with a price signal and liquidity, which may be important to support the market, especially in its early stages. [EPA-HQ-OAR-2009-0491-2697.1, p.17]
[This comment was also submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.28.]
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.29.]
EEI is also concerned that trading restrictions between Group 1 and Group 2 facilities can pose a problem for some of our other members with service territories that cross state lines but where facilities lie within the same air shed.
Response: 
EPA appreciates the suggestion from EEI regarding the inherent value in allowance auctions, but the Agency also notes that the commenter does not provide any technical basis for its suggestion that the proposed Transport Rule's preferred approach for interstate trading would require such auctions to operate effectively.  EPA notes that the small auctions conducted in the Acid Rain Program were intended mainly to ensure access to allowances for new units under that trading program, whereas the Transport Rule includes new unit set-asides to ensure that new units will have access to allowances under this rule's air quality-assured trading programs. 
Organization: Electric Energy, Inc. 
Comment: 
Electric Energy, Inc. 
The proposed Transport Rule will require SO2 emission reductions beyond what is required by the CAIR rule. Because the transport rule only allows intrastate allowance trading, we expect there will not be sufficient cost effective allowances available within the state of Illinois to meet EEl's compliance needs without additional pollution controls. This will require installation of SO2 control equipment beyond what is currently planned after the Transport Rule is final. The amount of additional control will be dependent on what is required by the final Transport rule. [EPA-HQ-OAR-2009-0491-2628.1, pp.1-2]
II. The use of IPM to assign allocations on a unit by unit basis is inappropriate
We do not believe it appropriate to use the IPM model to allocate allowances to the individual units in the state. The allocation should be based on historical utilization as was done in the NOx SOP rule and CAIR. [EPA-HQ-OAR-2009-0491-2628.1, p.2]
Response: 
EPA notes that interstate trading of allowances is allowed in the final Transport Rule.
Organization: Empire District Electric Company (Empire District)
Comment: 
Empire District Electric Company (Empire District)
EPA's preferred approach established Group 1 and Group 2 states for SO2 emission control.  Empire District is considered a relatively small electric utility.  Our contiguous service territory is bisected by the state line between Missouri, a Group 1 state, and Kansas, a Group 2 state.  Under the preferred approach, trading is not permitting between Kansas and Missouri generating facilities.  This would result in our Riverton, KS Power Station and Asbury, MO Generation Station being prohibited from trading SO2 allowances even though they are only 25 miles apart and only 5 miles apart on a north-south basis.  In addition, our State Line Generating Station west of Joplin, MO, is located just 5 miles due east of our Riverton Generating Station  This makes no logical scientific air shed sense in the regional control of SO2 and certainly is financially harmful to Empire District and its customers.  We recommend that EPA consider allowing the trading of SO2 allowances between emission units that are owned by the same local distribution utility with a contiguous service territory whose contiguous service territory is bisected by a Group 1/Group 2 state line.  Units owned by such a utility that are not located within the contiguous service territory or air shed should be excluded.  This is a very important issue for Empire District and like utilities bisected by a Group 1, Group 2 state line.  State budgets should not be penalized for such contiguous service territory trading.  However, Empire District understands that this could create issues with the court ruling.  If a direct change cannot be made to address this issue, we recommend that EPA have the ability to grant a utility a specific waiver in circumstances where two or more facilities of such a utility are within close geographical proximity but in different states.  With appropriate adjustments, as mentioned above, to the proposed variability rule such a waiver should not create a state compliance problem. [EPA-HQ-OAR-2009-2659.1, pp.5-6]
Response: 
EPA appreciates the comments regarding the geographic relationship of common airsheds and state boundaries.  In many respects, important elements of the natural environment cross administrative jurisdictions such as state borders.  EPA is authorized to require emission reductions to eliminate significant contribution to nonattainment and interference with maintenance from each upwind state under CAA section 110(a)(2)(D) and does not have the ability to vary the requirements of that statutory provision, particularly where the Court has interpreted the statute to require the Agency to define and eliminate significant contribution at the state level.  EPA does not believe it is unreasonable or unprecedented for a utility to have differing regulatory requirements at facilities located in different states; indeed, electricity regulation is routinely designed at the state level and utilities with service territories covering multiple states are clearly adept at managing the provision of electricity in each state in accordance with the laws and regulations affecting a facility within a given state.  EPA sees no meaningful basis to consider a "waiver" for the requirements on any given facility simply because the owner or operator may own or operate facilities in another state, whether or not that state is geographically adjacent; such considerations are irrelevant to the establishment of state budgets under the Transport Rule to satisfy the Clean Air Act's mandate in section 110(a)(2)(D) to eliminate significant contribution to nonattainment and interference with maintenance from each upwind state.
Organization: Environmental Energy Alliance of New York, LLC
Comment: 
Environmental Energy Alliance of New York, LLC
EPA's treatment of New York in the Transport Rule runs counter to previous rule makings. On page 106 of 1361 of the preamble, EPA discusses other factors used to determine the reasonableness of upwind control obligations in other rules. EPA noted that "in general, areas that currently have, or that in the past have had, nonattainment problems ... have already incurred ozone control costs." As noted earlier, not only have New York EGU's incurred ozone control costs for Federal programs, New York only acid deposition reduction rules have resulted in significant emission reductions and required additional control costs. The emissions data and Transport Rule projections indicate that EPA's methodology apparently does not recognize the resulting emission reductions. Consequently, the Transport Rule is proposing a NY budget allocation that includes additional reductions on top of the controls already implemented. As a result, EPA's projected "highly cost effective" reductions may not be as cost effective and New York EGU sources may not have cost effective controls available. It is not likely that New York EGU facilities can meet the resulting allowance allocations without curtailing operations at some facilities because the IPM projections for additional controls and operations are not consistent with historical operations and projections for cost-effective controls. [EPA-HQ-OAR-2009-0491-2638.1, p.3]
Therefore the Alliance recommends the following:
-Revise the unit-specific allocations to be based on three-year average heat input; and  
-Allow adjustments to allocations to credit New York State for its emission reduction programs to get the state budget right.   [EPA-HQ-OAR-2009-0491-2638.1, pp.4-5]
Response: 
EPA includes all known and legally applicable emission control requirements in its baseline power sector modeling; therefore, EPA has already "credited" states for their pre-existing emission reduction programs (except CAIR, as explained in section V.B of the preamble) before the Agency then analyzed whether additional emission reductions would be necessary from each state to eliminate significant contribution to nonattainment or interference with maintenance of the relevant NAAQS in a downwind state..
Organization: EquiPower Resources Corp.
Comment: 
EquiPower Resources Corp.
The Transport rule unfairly penalizes certain electric generating units ("EGUs"). The Rule's variability and assurance provisions cause regulatory uncertainty because of their look back enforcement provisions, which will result in sources retaining allowances instead of trading them, further hampering what limited emissions trading might occur under the rule. Similarly, the Proposed Rule's aggressive and inaccurate assumptions penalize early sources and states that were early adopters of emission controls. [EPA-HQ-OAR-2009-0491-2704.1, p.2]
Under CAIR, EPA set presumptive average emission rates that had to be achieved uniformly bysources throughout the CAIR region, and set state-wide budgets on that basis. States then allocating allowances to sources within their jurisdictions using either an input- or an output-based allocation methodology. Although the reductions were stringent and the timetable aggressive, all sources essentially were treated equally. Sources could trade allowances freely, enabling companies to make rational choices about which units should receive controls and which should not. Here, in contrast, EPA has make assumptions about the level of control which it believes each unit should achieve  -  i.e., EPA has decided which units should install controls  -  and has made individual unit allocations based on those assumptions. Moreover, unlike CAIR, which permitted unlimited trading among sources in the covered states, allowing emissions reductions to be obtained from the lowest cost sources first, the Transport Rule imposes hard state-level emission caps (subject to very limited variability provisions) that provide a hard ceiling on the aggregate emissions from affected EGUs. In effect, then, the combination of EPA's allocation approach and its state-level emission caps means that, if EPA assumed that a unit would install a certain control technology, that unit must install that control technology, because the state-level emission cap will make trading essentially unavailable (except for within-company trading where the company has several plants located within the same state  -  i.e., intra-company/intra-state trading). [EPA-HQ-OAR-2009-0491-2704.1, p.5]
The statewide caps (even accounting for the variability limits) represent a dramatic disincentive to trading because, under the Rule, if a state cap is exceeded, then all sources within the state are penalized on a 2-to-1 basis for their proportional share of the emissions exceedance. Moreover, sources cannot know contemporaneously whether or not the state cap will be exceeded, as variability is assessed retrospectively on an annual basis initially and then using a three-year rolling average.12 These penalty provisions mean that, in addition to holding allowances equal to annual NOX and SO2 emissions, a source needs to hold extra emission allowances in reserve to account for the contingency that a state's emission cap (plus variability limit) will be exceeded and that the source will be subject to a penalty. The potential for the state cap to be exceeded creates strong disincentives to trading; that is, it makes sources more likely to retain allowances instead of trading them, and as a result, sources will be forced to reduce emissions to levels that are equal to their initial allocations, such that the Transport Rule looks more like a command-and-control regime in that sources are forced to simply meet the emission rates implied by their initial unit-level allocations. More troubling, unlike a traditional command-and-control regimes where emission are limited to specific rates and not aggregate emissions (i.e., a source complying with the emissions rate can emit as much as it wants), the Transport Rule effectively requires a source to comply with a specific emissions rate as established by its initial allocations and then limits its aggregate emissions unless/until the source obtains additional reductions in its emission rate beyond the implied rate contemplated by its initial allocations. [EPA-HQ-OAR-2009-0491-2704.1, pp.5-6]
In essence, then, EPA's approach not only mandates the control technology that each unit must install, it also mandates the level at which that unit can be operated into the foreseeable future. This is particularly problematic where EPA's assumptions essentially mandate that a unit install SCR or FGD; for both economic efficiency and environmental protection, those units ought to operate at maximum capacity  -  whether or not they were operating at that level prior to the Transport Rule. Instead, EPA's assumed capacity factors (and resultant allocations) will determine the degree to which these units can operate. Not surprisingly, therefore, analysts have predicted that the Transport Rule will be dramatically more expensive than CAIR (although obtaining essentially no greater environmental benefits). [EPA-HQ-OAR-2009-0491-2704.1, p.6]
Many parties have predicted that the Transport Rule, combined with mercury regulations, could result in a significant percentage of the U.S. coal fleet being at risk for shut down.13 EPA should be mindful that if these shut downs should occur, combined cycle gas plants are the most likely source to make up for the lost baseload capacity provided by those units. It is possible that gas plants would need to run at as high as 90% capacity in some areas to make up for shut downs in the coal fleet. However, since the Transport Rule restrictions are imposed on a unit-by-unit basis, these plants will not likely have the allowances needed to fully substitute for the lost baseload capacity and, given the limitations on trading, are not likely to be able to acquire them. This problem could be avoided if EPA followed the procedural mandates of the CAA and allowed states to promulgate SIPs to meet the applicable air quality standards (as described in Section IV below). At a minimum, EPA should revise its allocations to correct for this issue. [EPA-HQ-OAR-2009-0491-2704.1, pp.6-7]
The One-Size-Fits-All Approach Ignores Important Distinctions in State Regulatory Regimes [EPA-HQ-OAR-2009-0491-2704.1, p.16]
 The FIP that the Transport Rule would impose upon the states uses input-based calculations in determining allocations. However, some states, such as Connecticut, Massachusetts, and New Jersey, have already been using output-based allocations in emission trading programs for a number of years. In mandating an input-based regulation, EPA will usurp state authority to use a system that EPA itself has advocated for more than a decade. [EPA-HQ-OAR-2009-0491-2704.1, p.16]
Output-based environmental regulations are calculated on the energy output of the process, which may be electricity, thermal, or mechanical output, and take into account the emissions benefits of efficiency. Input-based regulations are calculated on the heat input of the fuel burned in the process. [EPA-HQ-OAR-2009-0491-2704.1, p.16]
The use of an input-based calculation will lead to different allocations than an output-based calculation, which provides a greater number of allowances to more efficient plants. An example of this different outcome is provided in EPA's Output-Based Regulations: A Handbook for Air Regulators. The example considers: [EPA-HQ-OAR-2009-0491-2704.1, p.16]
a hypothetical state with emissions of 1,700 tons per year and a cap of 1,500 tons per year (a 12% reduction); [EPA-HQ-OAR-2009-0491-2704.1, p.16]
where two plants are the only sources of emissions in that state; [EPA-HQ-OAR-2009-0491-2704.1, p.16]
Plant 1 uses 61% of the heat input and Plant 2 uses 39%; [EPA-HQ-OAR-2009-0491-2704.1, p.16]
Plants 1 and 2 have identical output. [EPA-HQ-OAR-2009-0491-2704.1, p.16]
Under an input-based allocation, Plant 1 would receive 909 tons of allowances and Plant 2 would receive591 tons. Under an output-based allocation, each plant would receive 750 tons of allowances. [EPA-HQ-OAR-2009-0491-2704.1, p.16]
These differences in the allocations may have a significant impact on EGUs in output-based states. Since the Transport Rule effectively dictates both the control technology required for an EGU and the level at which that unit can be operated into the foreseeable future (see section III.B. above), this difference in the allocation method (and the resulting allowance allocations) will cause disruptions in these states because EGUs have made significant investments based on an output-based system of allocations. [EPA-HQ-OAR-2009-0491-2704.1, pp.16-17]
The Transport Rule also creates a considerable disincentive for a state to promulgate a SIP to replace the Transport Rule FIP, as EPA suggests states may do. If output-based states are forced to adopt EPA's input-based method, they would be unlikely to impose upon their sources the disruption that would result from changing the allocation method back to an output-basis. EPA has provided no guidance for states to do so in any case. Thus, while EPA suggests that states may promulgate SIPs, EPA cannot assume that states will be able to do so. This is particularly problematic given that the Transport Rule presents a one-time allocation that lasts throughout the duration of the Rule. In contrast, states typically do regular re-allocations to adjust for changes in the source mix, capacity, etc. Given the predictions regarding the coal fleet shut downs that are likely to result from the implementation of the Transport Rule, re-allocations will be necessary to reflect the current status of statewide generation. Thus, EPA's one-size-fits-all approach is flawed in that it disregards the changes that are expected to occur. Additionally, in mandating an input-based method of allocations, the Transport Rule effectively throws Connecticut, Massachusetts, and New Jersey's investment and advances in emissions reductions out the window. [EPA-HQ-OAR-2009-0491-2704.1, p.17]
EPA Failed To Properly Account For Dual Fuel Combustion Units [EPA-HQ-OAR-2009-0491-2704.1, p.22]
Three of EquiPower's four facilities  -  Lake Road, Empire and MASSPOWER  -  are dual fuel units. While all three are permitted to burn natural gas, the Empire Facility can also burn ultra low sulfur diesel ("ULSD") (sulfur content 0.0015%), the Lake Road Facility can burn low-sulfur diesel ("LSD")(sulfur content 0.05%), and MASSPOWER can burn fuel oil with a sulfur content of 0.2% or less, including LSD and ULSD. In each instance the permits for these plants allow them to run for some specified number of hours using these alternate fuels. During these periods of operation, the SO2 and NOX emissions from the plant increase relative to operations burning natural gas. The dual fuel nature of these units is important from an electrical system reliability perspective. By having flexibility in the types of fuel that can be burned, these units are capable of producing power while responding to price fluctuations, supply disruptions, or supply curtailments. In fact, when some of those facilities were permitted and approved, the relevant regulators required them to have the production flexibility provided by multiple fuels because they know that periodic natural gas supply disruptions can occur (e.g., pipeline disruptions or pipeline capacity constraints) which would impair electrical system reliability if the plants were not able to burn other fuels during those periods. It is sound public policy to not have our generation capacity reliant on a single fuel source with no back up plan. Thus, while a duel fuel unit generally burns natural gas, it is permitted to burn other fuels and at times can be required to do so. [EPA-HQ-OAR-2009-0491-2704.1, p.22]
Despite the sound public policy reasons behind the dual fuel units, EPA's projected emissions for EquiPower's dual fuel facilities appear to assume 100% natural gas combustion, and as a result the facilities have been under-allocated allowances for both SO2 and NOX. EPA's failure to account for distillate fuel operation is significant given the limited allowance availability that is likely to result under23the Transport Rule. It effectively limits those facilities to natural gas only operation, and therefore it is not sound public policy because it interferes with electrical system reliability. EquiPower submits that, at minimum, dual fuel units like Lake Road, Empire and MASSPOWER, should be allocated allowances using a methodology that accounts for both their gas-fired and non-gas-fired operations. EquiPower has looked at its own units and calculated the additional SO2 and NOX emissions that would result from operating those facilities using fuel oil/diesel fuels for the maximum amount of time permitted under their permits. Table 4 [See p.23 of this comment summary for Table 4] shows the additional allowances that would be required at each facility to account for the non-natural gas operations at each facility assuming that (i) the facility burns the highest sulfur content fuel for the maximum time allowed by its permit, and (ii) it burns only ULSD for the maximum time allowed by the permit. Table 4 [See p.23 of this comment summary for Table 4] clearly shows that the failure to account for dual fuel operations, even assuming ULSD only, resulted in a significant under-allocation of allowances at these facilities (particularly for NOX) that must be corrected by EPA. [EPA-HQ-OAR-2009-0491-2704.1, pp.22-23]
Recognizing that one potential consequence of the Transport Rule is that EGUs will have to switch from higher sulfur content fuels to lower content distillates, EquiPower believes that EPA should, at minimum, adopt a phased approach to SO2 allowance allocation for dual fuel units. A phased approach for SO2 allowances is appropriate given that many of these plants, particularly older ones, are expressly allowed by their permits to burn fuels that are higher in sulfur content than ULSD and that those facilities may already have inventories of such higher sulfur content fuels. EquiPower proposes that during Phase I any dual fuel units receive SO2 allowances equal to 50% of the allowances that would be required for the maximum level of non-gas-fired operations allowed under those units' permits. In Phase II those units should receive the minimum number of allowances required for those units assuming they burn only ULSD. With respect to NOX, since those emissions are not affected by the fuel burned, EquiPower submits that EPA should revisit the NOX allowance allocations for those units and adjust them upwards to account for alternate fuel operations. Table 5 [See p.24 of this comment summary for Table 4] below presents EquiPower's proposed additions to the allowance allocations for its dual fuel units using the preceding approach. [EPA-HQ-OAR-2009-0491-2704.1, p.23]
FLAWS IN SEVERAL TRANSPORT RULE PROVISIONS UNFAIRLY PENALIZE CERTAIN EGUS [EPA-HQ-OAR-2009-0491-2704.1, p.25]
The Transport Rule Should Have Provided SO2 Allocations for Electric Generating Facilities Fueled by Natural Gas [EPA-HQ-OAR-2009-0491-2704.1, p.25]
EPA has unfairly penalized many natural gas-fueled EGUs in the Transport Rule by not allocating them any SO2 allowances despite EPA's own position that at least some SO2 is emitted from these facilities. EPA assumes, in its Optional SO2 Emissions Data Protocol for Gas-Fired and Oil-Fired Units that accompanies its regulations for Continuous Emission Monitoring,53 that some small amount ofSO2 is emitted from natural gas fueled generating facilities. The optional protocol, which may be used by natural gas-fueled units in lieu of continuous SO2 monitoring, establishes a default SO2 emission rate of0.0006 lb/mmBtu for those facilities.54 Despite its own recognition that natural gas-fired units emit someSO2, EPA appears to apply a zero SO2 emissions factor for natural gas plants for purposes of unit-level allocations under the Transport Rule. As a result, EPA allocates no SO2 allowances to natural gas-fired facilities allocated under EPA's Projected methodology. Not only is this outcome plainly at odds with the Agency's own regulations, it also potentially hampers those units' operations given the limited supply of allowances that EquiPower believes will actually be available for sale under the Rule. [EPA-HQ-OAR-2009-0491-2704.1, p.25]
This penalty is problematic based on the de minimis quantities of SO2 that EPA assumes are present in a natural gas-fired EGU's exhaust stream. Given the very low potential levels, the majority of natural gas plants do not monitor for SO2 and instead rely on EPA's default emissions rate of 0.0006lb/mmBtu as their emissions rate for SO2. Moreover, given this low level of SO2 emissions, it is impractical for natural gas plants to control for SO2, even if they chose to, because such a small amount ofSO2 could not be scrubbed or otherwise be removed cost-effectively. This problem of the lack of SO2allocations and lack of control options will be exacerbated by the Transport Rule's limited trading scheme, which will result in very limited allowance availability. Natural gas-fired units will have great difficulty in obtaining allowances, if there are even any allowances to be had (as explained in Section III.B. above). In Massachusetts, for example, all available SO2 allowances will likely be needed to address EPA's significant miscalculation in the Commonwealth's budget due to mistaken assumptions regarding Brayton Point's installation of an FGD. [EPA-HQ-OAR-2009-0491-2704.1, pp.25-26]
Therefore, EPA should revise its unit-level allocations to account for SO2 emissions from natural gas facilities. EPA should calculate an EGU's SO2 allowance using the default SO2 emission rate in EPA's regulations -- 0.0006 lb/mmBtu -- and the applicable EGU's heat input capacity rating. As explained in Section V.B.1 above, EquiPower believes that the capacity ratings for its units should be increased and that its SO2 allocations under this proposed approach should reflect those increased ratings. [EPA-HQ-OAR-2009-0491-2704.1, p.26]
The Transport Rule's State Budgets Penalize Early Adopters [EPA-HQ-OAR-2009-0491-2704.1, p.27]
By allocating allowances based on its assumptions about the types of controls that will be employed and the level of emissions reduction that will be obtained, EPA effectively penalizes sources that have taken early action on emission reductions, but as a result have existing emissions control equipment that do not necessarily achieve the control levels assumed by EPA in the Transport Rule. Given EPA's long-standing efforts to encourage sources to reduce their emissions, it cannot be the intent of the Proposed Rule to punish those sources that provided those early emission reductions. As a result, EquiPower encourages EPA to revise the Proposed Rule to ensure that the allowance allocations in the final Transport Rule do not penalize early actors. [EPA-HQ-OAR-2009-0491-2704.1, p.27]
Response: 
As described in section VII.D of the preamble, EPA is allocating allowances to existing units based on historic data under the final Transport Rule FIPs.  As a result, historic emissions from duel-fuel units would accurately capture the type of operations described by the commenter to the extent they occurred at specific units over the historic baseline period used for allocation purposes.  In addition, historic emissions data for gas-fired units would accurately reflect SO2 emissions and thus provide a basis for SO2 allowance allocations to those units; these allocations are fully detailed in the Allowance Allocation Final Rule TSD.
Organization: Exelon
Comment: 
Exelon
Because of the manner in which unit allowances would be distributed under the proposed rule, each revision to a state budget would require a reallocation of allowances among all of the units in the state. As discussed in Comment 8.2 below, Exelon believes that reallocation of allowance budgets unnecessarily introduces complexity, perverse operating incentives and litigation risk into what could otherwise be a simple pro rata reduction in allowance budgets. Therefore, while Exelon recognizes the validity of EPA's approach to the implementation of future NAAQS revisions and revised state budgets, Exelon urges EPA to adopt in the final Transport Rule the more streamlined methodology described in Comment 8.2 for unit allocations. The proposed methodology would also enable companies to anticipate future reductions in allocations, and thus improve their ability to plan future capital expenditures. [EPA-HQ-OAR-2009-0491-2666.1, p.13]
ALTHOUGH EPA'S PROPOSED ALLOWANCE ALLOCATION SCHEME IS CONSISTENT WITH THE REQUIREMENTS OF THE CAA, EPA SHOULD MODIFY ITS ALLOCATION SCHEME IN SEVERAL WAYS TO ALLOW EXPEDITIOUS FUTURE REDUCTIONS INSTATE BUDGETS, TO REMOVE PERVERSE INCENTIVES AND TO ENCOURAGE PERMANENT REDUCTIONS IN EMISSIONS.
EPA SHOULD ALLOCATE SOME ALLOWANCES BY AUCTION, ALLOCATE ALL FREE ALLOWANCES ON THE BASIS OF SOME COMBINATION OF HISTORICAL ELECTRIC OUTPUT AND HEAT INPUT, AND PROVIDE A CLEAR MECHANISM TO REDUCE FREE ALLOCATIONS UNIFORMLY WHEN STATE EMISSIONS BUDGETS ARE REDUCED. Exelon believes that the system for allocating allowances should comport with the following principles: (1) it should not affect investment or operating decisions of source owners or create perverse incentives; (2) it must be statutorily authorized and consistent with the legislative intent; (3) it should be based on method or metric that will not produce erroneous or anomalous results or be so unfair as to be deemed arbitrary and capricious; and (4) it should allow uniform percentage reductions in unit emissions budgets when state budgets are reduced. [EPA-HQ-OAR-2009-0491-2666.1, pp.30-31]
In particular, the key principle to any effective allowance distribution mechanism is that the distribution of allowance value be completely independent of operating, investment, retirement, or banking decisions made by entities covered by the Transport Rule and participating in the allowance trading regime. Allowance allocations must be based on a metric that is measured and fixed prior to the effective date of the Transport Rule and not updated except insofar as percentage reductions are required to meet lower state budgets (i.e., "nonupdating"). Without this independence, the rule could create incentives for source owners that are inconsistent with the goals of the rule and that distort allowance price signals. For example, if the original allowance allocation was to be updated based on electric output during the period covered by the Transport Rule (i.e., 2012 or later), source owners would face an incentive to increase output (and therefore emissions) in order to increase their future allocation of allowances. Further, the source owner would build the future value of allowance allocations into its bids to supply electric energy in competitive electricity markets, distorting price signals and causing high-emission sources such as coal to dispatch more frequently than they otherwise would. In contrast, if allowance allocations are based on a non-updating metric that is measured and fixed prior to the effective date of the Transport Rule, as is the case in the proposed rule, then these perverse operating incentives are largely avoided. [EPA-HQ-OAR-2009-0491-2666.1, p.31]
Exelon believes that the proposed Transport Rule partially satisfies these criteria but could nonetheless be improved. Exelon is concerned that EGUs may still face perverse operating incentives because the Transport Rule is silent on how allowance allocations will be adjusted when NAAQS are further revised and state budgets are accordingly adjusted. In particular, if emitters anticipate that EPA may "reset" allocations in the future based on new IPM modeling or actual emissions in the period after 2012, they may face an incentive to delay installation of pollution control equipment in the near-term in order to capture potentially a higher allocation following the "reset." On a market-wide basis, this anticipation of a future "reset" could lead to higher emissions in the near-term, less allowance banking, and market prices that do not reflect the true marginal cost of emission reduction. Exelon also believes that basing free allocations on IPM modeling is problematic because a future allocation "reset" would rely on new IPM modeling (see Comment 2.3), which would leave future state budget revisions vulnerable to legal challenges. [EPA-HQ-OAR-2009-0491-2666.1, p.31]
Given these concerns, Exelon proposes that EPA make three changes to the allowance allocation mechanism for the Transport Rule:
1. Rather than basing free allocations to EGUs on IPM modeling, Exelon proposes that allocations of free allowances be fixed based on a simple, non-updating historical metrics measured prior to the commencement of the Transport Rule. Possible metrics include historical heat input or historical electric output of EGUs regulated under the Transport Rule, either alone or in some combination. To the extent that EPA retains IPM modeling as a metric for allocations, Exelon urges EPA to provide strong assurances that the allowance allocations will not be updated in the future based on new IPM modeling. Comment 8.2, Comment 8.3, and Comment 8.5 further discuss the legal and policy basis for different metrics. [EPA-HQ-OAR-2009-0491-2666.1, pp.31-32]
2. Exelon proposes that EPA distribute a small but increasing portion of allowances via auction rather than free allocation to EGUs. Distribution via auction avoids the potential incentive problems associated with free allocations and has many other benefits as well. Comment 8.4 provides a detailed discussion of the mechanics and benefits of Exelon's auction proposal. [EPA-HQ-OAR-2009-0491-2666.1, p.32]
3. Exelon proposes that EPA augment the Transport Rule with a clear mechanism describing how allowance allocations will be adjusted to accommodate anticipated changes to the NAAQS. This mechanism should be designed so that it does not create incentives for EGUs to emit more in the near-term. Comment 8.5 describes a mechanism to accomplish this goal. [EPA-HQ-OAR-2009-0491-2666.1, p.32]
Although Exelon is suggesting several improvements to EPA's allocation method, EPA could adopt any one of them without the others. For example, it could adopt the auction proposal but not revise its method for allocating free allowances and vice versa. The benefits of these allocation options are discussed in comments related to each option. However, Exelon believes that it is particularly important to revise the allocation method because the alternatives suggested here will better facilitate the implementation of reduced state budgets in the future without creating the perverse operating incentives that would result from a re-allocation of allowances each time state budgets must be reduced. Moreover, the alternatives proposed by Exelon will eliminate the significance of any errors or anomalies in establishing unit budgets based on the IPM. The alternative methods suggested here are also more consistent with allocation methods used by EPA in the past. Use of an auction will provide additional assurance that those with concentrated market power will not be able to manipulate markets and will lower barriers to entry by new, zero or low pollution generation technologies. [EPA-HQ-OAR-2009-0491-2666.1, p.32]
FREE ALLOWANCES SHOULD BE ALLOCATED ON THE BASIS OF SOME HISTORICAL METRIC AND EPA SHOULD REMOVE ANY LINKAGE BETWEEN THE NUMBER OF FREE ALLOWANCES ALLOCATED TO A UNIT AND THE COMPLIANCE ASSURANCE PROVISIONS OF THE TRANSPORT RULE.
Exelon proposes that EPA retain IPM modeling results as a means of determining overall state budgets, but utilize a simple, verifiable historical metric to apportion free allowance allocations to individual EGUs. The historical metric could be historical heat input or historical output of regulated units, alone or in some combination. 57 The historical metric would be based on some period prior to the promulgation of the Transport Rule, such as 2009, or a three-year average covering 2007-2009. Regardless of the individual metric chosen, in each case the metric should be utilized to calculate a share for each EGU of the total allowances available for free allocations to EGUs in each state, which would be based on the overall state budget. For example, if a state has a total budget of 100 tons, of which 94 are available for free allocation, a regulated unit whose historical heat input (or output, etc.) comprised 10% of total state historical heat input would receive an annual allocation of 9.4 allowances. [EPA-HQ-OAR-2009-0491-2666.1, pp.32-33]
The compliance assurance mechanism proposed by Exelon in Comment 5 removes the linkage between free allocations and compliance assurance altogether and will most readily allow the adoption of an allocation method that will permit uniform percentage reductions in unit allocations. However, this can also be accomplished by retaining EPA's current compliance assurance mechanism and delinking unit compliance budgets and unit allocations. In that case, when a state budget is reduced, EPA could reduce allowance allocations by a uniform percentage but reduce unit compliance budgets to the emissions levels needed to achieve the budget as determined by EPA's IPM modeling. In that case, uncontrolled units would have new reduced compliance budgets potentially reflecting installation and operation of controls, while already-controlled units would have unchanged compliance budgets. [EPA-HQ-OAR-2009-0491-2666.1, pp.34-35]
[For additional comments pertaining to FREE ALLOWANCES SHOULD BE ALLOCATED ON THE BASIS OF SOME HISTORICAL METRIC AND EPA SHOULD REMOVE ANY LINKAGE BETWEEN THE NUMBER OF FREE ALLOWANCES ALLOCATED TO A UNIT AND THE COMPLIANCE ASSURANCE PROVISIONS OF THE TRANSPORT RULE see pp.32-35]
This language provides EPA with broad authority to implement any of the alternative allocation methodologies set forth above. The language generally authorizes use of "economic incentives" as one of many alternative "control measures, means or techniques." Since a cap and trade program is an incentive-based means of controlling emissions, this language authorizes a cap and trade system. The method for initially allocating allowances, therefore, is left to EPA's discretion, as long as it generally falls within the ambit of the term "economic incentives." Each of the allocation methodologies set forth above satisfies this test, although some allocation methodologies fall more clearly within the legislative intent than others. Exelon believes that the allocation methodology that it proposes herein hews more closely to the legislative intent than does the one that EPA has proposed. [EPA-HQ-OAR-2009-0491-2666.1, pp.35-36]
Specifically, because an auction of emissions allowances is specifically referenced in the statutory language, EPA would be on the soundest legal ground if it utilized an auction to distribute allowances. For this reason, EPA should utilize an auction to distribute some or all of its allowances. Because the CAA includes no restriction on using multiple incentives, an auction of some, but not all of the allowances should also be permitted. [EPA-HQ-OAR-2009-0491-2666.1, p.36]
Although EPA's proposed allocation methodology  -  giving away allowances based on either projected modeled emissions or historical emissions  -  is authorized under the statute, it has aspects that make it the most problematic of the allocation methodologies. Because it is awarding allowances based on past or projected pollution and awards the fewest allowances to those who have done the most to limit their emissions, one might argue that it is not an incentive at all. However, the CAA specifically mentions marketable permits and arguably awarding allowances based on projected or historical permitted amounts of emissions is, in fact, a marketable permit. [EPA-HQ-OAR-2009-0491-2666.1, pp.36-37]
Section 110(a)(2)(A) and the CAA's definition of FIP also provide EPA with sufficient authority to allocate allowances to all electric generating units or fossil fuel generating units based on historical electric production. If allowances are to be allocated for free, an allocation that favors zero or low pollution production techniques would advance the statutory intent of creating incentives to reduce pollution than free allocation based on pollutants emitted. 61 The statute's use of the term "economic incentives" suggests that a free allocation of allowances that gives more allowances to the facilities that produce the highest level of pollution per unit of production is inconsistent with the statutory mandate. [EPA-HQ-OAR-2009-0491-2666.1, p.37]
Finally, the statute also would authorize an allocation based on historical heat input. This would still reward plants that install pollution control equipment but would not provide as large a reward to plants that achieve emissions reductions through efficient production or use of low- or zero-pollution electric production technologies. Nevertheless, this allocation method is more consistent with statutory intent and prior EPA practice that the method set forth in the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2666.1, p.37]
Thus, given the breadth of EPA's discretion, EPA could likely adopt a mix of allocation methods. Certainly, it could distribute a portion of the credits by auction and award the balance for free based on historical emissions, electric output, heat input or some combination of the foregoing. [EPA-HQ-OAR-2009-0491-2666.1, p.38]
EPA SHOULD MODIFY ITS PROPOSED ALLOCATION SCHEME TO INCLUDE AN AUCTION OF A PORTION OF ALLOWANCES AVAILABLE FOR EXISTING UNITS, AUGMENTED BY ALLOWANCES NO LONGER ALLOCATED TO RETIRED UNITS. [EPA-HQ-OAR-2009-0491-2666.1, p.38]
Exelon believes that auctioning some or all allowances is a key element to an effective cap and trade program. Accordingly, while Exelon's auction proposals are linked to a number of other changes to the allocation of allowances and the structure of the assurance provisions, Exelon believes that EPA should consider adopting its auction proposal regardless of whether the other elements of Exelon's comments are ultimately incorporated as part of the Transport Rule. Auctions are specifically referenced in the authorizing legislation and therefore should be viewed as a Congressionally-preferred method of allocation. Auctions are an exceptionally "clean" mechanism for distributing allowances in that they completely de-link EGU decisions concerning unit operations, pollution control investments and retirement from the award of financial value associated with allowances, because the financial value of the allowances is retained by the auctioning authority and does not flow to the EGUs. Auctioning some or all allowances thus helps ensure that EGUs will face proper economic incentives to comply with the goals of the proposed Transport Rule in the most economically efficient manner. [EPA-HQ-OAR-2009-0491-2666.1, p.38; For additional comments pertaining to EPA SHOULD MODIFY ITS PROPOSED ALLOCATION SCHEME TO INCLUDE AN AUCTION OF A PORTION OF ALLOWANCES AVAILABLE FOR EXISTING UNITS, AUGMENTED BY ALLOWANCES NO LONGER ALLOCATED TO RETIRED UNITS see pp.38-40 of this comment summary]
ALL ALLOWANCES THAT ARE ALLOCATED TO EXISTING UNITS FREE OF CHARGE SHOULD BE ALLOCATED BASED ON ELECTRIC OUTPUT, HEAT INPUT, OR SOME COMBINATION OF THOSE METRICS. EPA SHOULD SPECIFICALLY PROVIDE THAT UNIT ALLOCATIONS WILL BE REDUCED BY THE SAME PERCENTAGE AS STATE BUDGETS WHENEVER THOSE BUDGETS ARE REDUCED IN THE FUTURE.
Although EPA's method for allocating free allowances to existing units is permissible, as discussed above, alternative mechanisms better advance a number of important policy objectives and are more consistent with statutory intent. Exelon therefore suggests that all free allowances be allocated to existing units based on some combination of historical heat input or historical electric output from regulated units. [EPA-HQ-OAR-2009-0491-2666.1, p.40]
Exelon believes that it is essential that EPA propose a clear and uniform mechanism to reduce free allocations proportionally whenever state budgets are reduced, and these alternative historical metrics will facilitate such a mechanism. As noted in Comment 8.1, as proposed, the Transport Rule is silent on how future changes in state budgets associated with revised NAAQS will be incorporated into the allowance allocation mechanism. Exelon believes that additional clarity surrounding this issue is important to ensure an efficient emission allowance market with proper price signals for unit operations, pollution control investments, and retirement. Accordingly, Exelon proposes that EPA augment the Transport Rule with a mechanism providing that free allocations to individual EGUs will be reduced on a proportionate basis with any future reductions in state budgets. For example, if a state budget is currently set at 100 tons, and after incorporating a revision to a NAAQS, EPA determines that the state budget should be revised downward to 90 tons, the free allocations to all EGUs in that state would be reduced by 10%, regardless of any modeling or analysis performed by EPA in setting the revised state budget. However, this system could not be equitably imposed if allowances are allocated based on historical emissions, as discussed in Comment 8.2 above. [EPA-HQ-OAR-2009-0491-2666.1, pp.40-41; for additional comments pertaining to ALL ALLOWANCES THAT ARE ALLOCATED TO EXISTING UNITS FREE OF CHARGE SHOULD BE ALLOCATED BASED ON ELECTRIC OUTPUT, HEAT INPUT, OR SOME COMBINATION OF THOSE METRICS. EPA SHOULD SPECIFICALLY PROVIDE THAT UNIT ALLOCATIONS WILL BE REDUCED BY THE SAME PERCENTAGE AS STATE BUDGETS WHENEVER THOSE BUDGETS ARE REDUCED IN THE FUTURE see pp.40-41 of this comment summary]
EPA'S PROPOSAL TO ALLOW OWNERS OF RETIRING UNITS TO RETAIN ALLOWANCES FOR SIX YEARS REDUCES THE PERVERSE INCENTIVE TO KEEP HIGHLY POLLUTING UNITS IN OPERATION, BUT ALL ACTIVE UNITS SHOULD RECEIVE ALLOWANCES, EVEN IF THEY RETIRE BEFORE JANUARY 1, 2012.
Exelon notes that EPA's proposal to continue to allocate allowances to retiring units for six years blunts the perverse incentive for units to continue operation simply to receive allowances. If allowances were discontinued after a shorter period of time, units would have such an incentive. Therefore, unless EPA moves to something approaching a 100% auction for allowance allocation, it should retain this part of its proposal in order to reduce incentives to keep high pollution, low output facilities operating. [EPA-HQ-OAR-2009-0491-2666.1, p.41]
For the same reason, EPA should not create an incentive for owners who are considering, or who have announced, the retirement of units prior to January 1, 2012, to defer that retirement until after the Transport Rule goes into effect. As explained in the preamble to the proposed rule, if a unit is permanently retired prior to January 1, 2012, and thus is not required to hold allowances for compliance on that date, the unit will receive no allowances, and EPA will effectively withdraw any allowances allocated to that facility, even if they were already placed in the unit owner's account. In contrast, if a unit operates on January 1, 2012, and retires at the end of the day, that unit will be entitled to receive allowances through 2019. [EPA-HQ-OAR-2009-0491-2666.1, pp.41-42]
This concern is not hypothetical to Exelon. Exelon has announced that it intends to retire four old fossil fuel units in Pennsylvania, all of which have received a proposed allocation of allowances in the technical support document for the Transport Rule allocations. Three of these four units have proposed retirement dates before January 1, 2012. Under the current proposed rule, Exelon has a significant economic incentive to continue to operate these three units until at least January 1, 2012  --  seven years of allowances to offset one day of emissions. Yet, the policy behind the Transport Rule would be better served if Exelon retired those units as soon as possible. EPA should reward companies that have already decided to reduce pollution by closing inefficient plants, not create incentives to defer retirement. Accordingly, Exelon urges EPA to revise the final Transport Rule to allocate allowances through 2018 to units currently in operation, which are permanently retired before January 1, 2012. [EPA-HQ-OAR-2009-0491-2666.1, p.42]
EXELON URGES EPA TO ACCEPT CERTAIN TECHNICAL CORRECTIONS SET FORTH HEREIN.
As discussed in Comment 8.1, Exelon suggests that EPA not use its IPM modeling as the basis for unit allocations. Rather, Exelon proposes that EPA use an allocation system based on recent historical generating unit activity. However, should EPA elect to retain its generating unit allocation methodology based on IPM projections, Exelon recommends that EPA consider the issue of peaking units that are projected to have less than 0.5 tons of emissionsby the IPM modeling. In its current methodology, EPA utilizes a conventional rounding technique to round down units that are projected to have less than 0.5 tons of emissions to receive zero allowances. Exelon recommends that for these peaking units EPA adopt a rounding convention that "rounds up" so that such units would receive one allowance, rather than zero allowances. An allocation system based on recent historical generating unit activity would obviate the need for this accommodation to address the limitations of IPM modeling to project emissions from small peaking units that are infrequently operated, but that nonetheless do emit greater than zero emissions. [EPA-HQ-OAR-2009-0491-2666.1, pp.43-44] 
57 Even an allocation based on historical emissions, as in the proposed rule, meets the primary criterion that the allocation be non-updating, although Exelon believes that heat input and electricity output are both preferable historical metrics for the reasons discussed below.
61 It also appears to fall within EPA's discretion to award allowances to regulated electric distribution companies rather than generators, the methodology that Exelon has supported with respect to award of GHG emissions allowances. Under that method, the distribution companies would receive allowances based in part on the electricity distributed by the company, regardless of the method by which the electricity is generated, and then the distribution companies would sell allowances to generators, so that customers would benefit, but the customers of electricity generating lower levels of pollution would benefit more. Although Section 110 includes restrictions on EPA's authority to require parking surcharges, and certain mobile source controls, it contains no restriction upon how EPA structures cap and trade programs, auctions and marketable permits. Indeed, limiting the award of free allowances to the regulated industry sector of the electric generation and distribution industry may be more consistent with the original Congressional intent. Congress added the authorizing language quoted above to the CAA in the 1990 Amendments, when it also created the Title IV cap and trade program to limit acid rain. In 1990, both electric generation and distribution were price regulated and consumers, rather than generating companies, would reap the benefit of the distribution of free allowances. Since that time, many states have deregulated the generation sector, while leaving the distribution companies price regulated. Indeed, it is for that reason that in the climate bill passed by the House of Representatives, the American Clean Energy and Security Act, HR 2454, the House awarded GHG emissions allowances based on electric generation to distribution companies, contemplating that they would sell them to the carbon emitters, so that carbon free generation would be favored but the award of free allowances would go to the general public. The very broad authorizing language in the CAA and its intent to incentivize pollution-free generation provides authority to employ a similar mechanism in a regulation establishing a cap and trade program.
Response: 
Thank you for your comment.Organization: Florida Municipal Electric Association (FMEA)
Comment: 
Florida Municipal Electric Association (FMEA)
In addition, EPA should not add provisions and new methodologies in the Proposed Transport Rule that are not designed to directly respond to the Court remand directing EPA to retain the environmental values of CAIR to the greatest degree practical. As currently proposed, the allowance allocation scheme in this rule will disadvantage utilities that have made major expenditures to add air pollution controls to meet the CAIR emission caps compared with those that have not. EPA's preferred allowance allocation option has the effect of punishing utilities that have taken early actions to comply with CAIR. [EPA-HQ-OAR-2009-0491-2731.1, pp. 1-2]
EPA's emission allowance allocations are unfair and are counter to cap and trade market based principles: The allocations proposed by EPA will be based on the "Optimized" operation of the pollution reduction equipment of each EGU. This means that a utility that installed a new flue gas desulfurization (FGD) scrubber to meet CAIR requirements that gets up to 90% or better SO2 removal would get SO2 allowances based on the equipment running at 90% or better. The same situation applies to utilities that installed new selective catalytic reduction (SCR) equipment. At the same time, EPA proposes to allocate allowances to those utilities that have not made the expensive control technology investments based on the far lower cost compliance options of using low sulfur fuels or low NOx burners. [EPA-HQ-OAR-2009-0491-2731.1, p. 3]
FMEA believes that a serious equity and fairness issue is created by the allocation methodology proposed in the Proposed Transport Rule. While the Court found fault with EPA's attempt to address equity with the fuel factor, there is no indication that the Court required EPA to go to the other extreme. A few examples illustrate this point. The Florida Municipal Power Agency (FMPA) owns and operates state-of-the-art gas-fired combined-cycle units that under CAIR would have received 448 NOx allowances. However, under the Proposed Transport rule, FMPA would receive only 70 allowances, which is insufficient to run these units without purchasing allowances. Gainesville Regional Utilities (GRU) spent $141 million to install a FGD scrubber on its Deerhaven #2 coal-fired generating unit to meet and exceed CAIR requirements. Under CAIR GRU was expected to receive about 3,136 allowances but under the Proposed Transport Rule the utility would receive 614 allowances. [EPA-HQ-OAR-2009-0491-2731.1, p. 3]
The Proposed Transport Rule allowance allocation methodology is poor public policy. First, the proposed allowance allocation methodology violates a key cap and trade success principle. The proposed allocation method fails to allow utilities to choose to over-control their emissions at electric generating units (EGUs) where it is cost-effective and under control at sources where it is less cost-effective. For example, if under CAIR an 80% removal of SO2 would achieve compliance and running at 95% removal could generate surplus allowances for sale, the Proposed Transport Rule would not allow that benefit for installing expensive pollution controls. [EPA-HQ-OAR-2009-0491-2731.1, pp. 3-4]
Second, the Proposed Transport Rule punishes aggressive early emission reductions. Unlike the CAIR rule, by reducing allowances to those who installed expensive air pollution control equipment, EPA is actually financially punishing utilities for both early compliance and aggressive emission reductions. In addition, EPA proposes that units that haven't installed any controls will get allowances based on operation with lower-cost low sulfur fuels and low-NOx burners. [EPA-HQ-OAR-2009-0491-2731.1, p. 4]
Third, the Proposed Transport Rule allowance allocation methodology will hurt future proactive emission reductions by industry. The shift away from the CAIR allocation methodology, one that rewards over-control and early-emission reductions, to the proposed Transport Rule methodology that punishes the very same behavior, will create a long-lasting chilling effect on future proactive emission reductions by industry. [EPA-HQ-OAR-2009-0491-2731.1, p. 4]
Finally, the Proposed Transport Rule allowance allocation method ignores the fact that many costly decisions were made by the utility industry based on the CAIR. To meet the CAIR compliance requirements FMEA members committed to costly emission control systems while the rule was under court challenge. Those commitments by FMEA members were based in part on the assumption that EPA would keep as much of CAIR intact as the Court would allow. In response to EPA's request for suggestions for an alternative allowance allocation method, FMEA strongly recommends that EPA allocate both SO2 and NOx allowances based on heat input at the emission rates necessary to achieve the state emission budget. Using the allocation method would not only address the Court's remands based on the fuel factor and improper use of Acid Rain SO2 allowances, it would bring fairness back to the allocation methodology. [EPA-HQ-OAR-2009-0491-2731.1, p. 4]
EPA's Use of IPM Produced Materially-Flawed Allocations. In EPA's posted "Projected Data" spreadsheet which was published with the proposed rule, FMEA realized that EPA had not allotted SO2 allowances for those units which burn fuel oil and natural gas. Following conversations with EPA representatives, FMEA understands that IPM predicted that these dual-fuel fired units will only be burning natural gas in the future. This is one of the many flaws in EPA's methods.  [EPA-HQ-OAR-2009-0491-2731.1, p. 8]
First, fuel oil currently provides 16% of Florida's electric generating Summer capacity (MW) and is being assumed to represent 13% of such capacity in 2019 (Florida Public Service Commission, Fuel Diversity Workshop, August 5, 2010). Florida receives gas from only three pipelines. During the 2005 Hurricane Season, Florida nearly depleted its supplies of natural gas supplies due to interruptions in the Gulf of Mexico. During this emergency period, utilities held daily meetings to assess the situation and discuss possible contingency plans, many of which centered on utilities ability to burn fuel oil in their dual-fuel fired natural gas units. As EPA has cited in their Endangerment Finding, the U.S. should be encountering increased storm activity in the near future, and so the U.S. should plan accordingly. Assuming arguendo, this rule proposal merely pushes Florida sources to become much more reliant on natural gas, which will only exacerbate any future issues with curtailed or jeopardized gas supplies.  [EPA-HQ-OAR-2009-0491-2731.1, p. 8]
It also appears that IPM predicts that coal units can and will switch to lower sulfur coals in order to meet SO2 reduction requirements. Many of the same questions apply with coal as did natural gas, namely EPA's lack of analysis on current permitted coal sulfur limits, the cost and availability of the targeted fuel, and the railroad line capacity to meet the predicted dramatic increase in fuel switching.  [EPA-HQ-OAR-2009-0491-2731.1, p. 8]
EPA must conduct an analysis of the capacity of Florida's natural gas pipelines to accommodate the increased requirement in natural gas consumption needed to meet EPA's assumptions by 2012. EPA must also perform reliability analysis as to Florida's unique situation as a peninsula regarding FMEA members' ability to meet reliability requirements in the future. And EPA's analysis must consider the parasitic load from new control equipment, such as FGD and SCR systems.  [EPA-HQ-OAR-2009-0491-2731.1, p. 8]
Response: 
The commenter appears to assume that dual-fueled units would be unable to consume oil if their initial allowance allocations are calculated on the basis of natural gas consumption instead.  This assumption ignores the ability of owners and operators to determine their cost-effective EGU operations, including related emissions, and acquire the requisite number of allowances accordingly under the Transport Rule's market-based air quality-assured trading programs.  In addition, this assumption is flawed because as explained in the Allowance Allocation Final Rule TSD, the economic determination of unit dispatch (including limitations on the availability of certain fuels at certain times) will always reflect the cost of emitting under the programs (i.e., the market price of an allowance) whether or not an allowance for that emission was originally allocated to the unit in question.  In this instance, a dual-fuel unit firing with oil would still dispatch if the cost of its generation, including the value of the allowances to cover emissions from such generation, is among the least-cost method of meeting demand and maintaining the viability of the grid at that time, whether or not that unit had been allocated the allowances in question in the first place.  Notwithstanding this important point, the final Transport Rule's allocations to existing units under the FIPs are based on historic data that would reflect emissions from the balance of oil and natural gas consumed by the units cited by the commenter.
Organization: Fond du Lac Reservation
Comment: 
Fond du Lac Reservation
Need for Tribal Set-Aside
Aside from the above, the Transport Rule fails to provide Indian tribes with an opportunity to become part of the EPA's proposed trading scenarios. As drafted, the Rule provides allowance allocations solely to states and the District of Columbia. Under the Tribal Authority Rule, however, tribes may adopt whole or parts of air programs based on 'reasonable severability' without being subject to deadlines or other requirements imposed upon states and other jurisdictions . This is something that the Agency acknowledged in the former Clean Air Interstate Rule ('CAIR') in which it went to great lengths to address the unique circumstances of Indian tribes and the need to accommodate future electrical generating units ('EGUs') that should locate on tribal lands. 8  Unfortunately, the EPA chose to ignore this earlier assessment of tribal issues without providing a valid reason for doing so. The Band there .fore recommends that the Agency revisit its earlier analysis under the CAIR concerning tribes and establish a mechanism which allows such tribes to enter into any trading program adopted under the Rule, specifically providing EGUs locating on tribal lands with an appropriate portion of allowances. [EPA-HQ-OAR-2009-0491-3707, pp.4-5]
In addition, the EPA should provide for the inclusion of a tribal set-aside under the Transport Rule that is based on factors other than EGUs located on state lands. As reference, the Agency only needs to look to an effort in the Western U.S. which provided for a similar set-aside that received support from a wide range of stakeholders. [EPA-HQ-OAR-2009-0491-3707, p.5]
The Western Regional Air Partnership ('WRAP'), a partnership between Indian tribes, states and federal agencies (including the EPA) and with participation from such entities as environmental organizations and industry, advocated for a tribal set-aside during the late 1990s that was eventually adopted as part of the Annex to the Regional Haze Rule ('RHR'). The Annex established declining SO2 emission milestones for major sources. If the milestones were exceeded, then a cap-and-trade program would be initiated to ensure continued SO2 reductions. As part of the Annex, an annual SO2 tribal set-aside of 20,000 tons was made available to tribes within a nine-state region, regardless if such tribes had major industrial sources emitting SO2. This set-aside was to be distributed as determined by the region's tribes (e.g., for future industrial sources, other economic development purposes, tribal scholarships, etc.). This annual tribal set-aside also grew out multiple discussions among the WRAP's partners and participants where issues of equity and economic development kept coming up during conversations with respect to the tribes that had hardly contributed to visibility impairment in the West but whose environment and health had been adversely affected by neighboring jurisdictions with sources emitting significant amounts of SO2. At that time, neither the WRAP partners or participants had sufficient information about future EGUs in Indian country but they felt it imperative to address equity issues properly before and not after the Annex was implemented. [EPA-HQ-OAR-2009-0491-3707, p.5]
The Band therefore recommends that the EPA include a tribal set-aside as part of any trading program adopted in accordance with the Transport Rule. A determination about the appropriate size for such a set-aside and the means for its allocation requires the Agency to consult with tribes. [EPA-HQ-OAR-2009-0491-3707, pp.5-6]

8. Rule To Reduce Interstate Transport of Fine Particulate Matter and Ozone ('Clean Air Interstate Rule'); Revisions to Acid Rain Program; Revisions to the NOx SIP Call; Final Rule, 70 Fed. Reg. 25162, 25167 (May 12, 2005) (to be codified at 40 CFR Parts 51, 72, 73, 74, 77, 78 and 96) ('[I]n the event of any future planned construction of EGUs on Tribal lands within the CAIR region, EPA intends to work with the relevant Tribal government to regulate the EGU through either a Tribal implementation plan ('TIP') or a Federal implementation plan ('FIP'). We anticipate that at a minimum, a proposed EGU on a reservation within a State participating in the CAIR cap and trade program would need to be made subject to the cap and trade program. In the case of a new EGU on a reservation in a CAIR-affected State which chose not to participate in the cap and trade program, the new EGU might also be required, through a TIP or FIP, to participate in the program. This would depend on the potential for emissions shifting and other specific circumstances (e.g., whether the EGU would service the electric grid of States involved in the cap and trade program.) Again, EPA will work with the relevant Tribal government to determine the appropriate application of the CAIR). [EPA-HQ-OAR-2009-0491-3707, p.4]
Response: 
As described in Preamble Section VII.D., under the final Transport Rule 0.1% of the state budget will be set aside for the Indian country new unit set-aside
Organization: Golden Spread Electric Cooperative
Comment: 
Golden Spread Electric Cooperative
I. Database corrections: Comments are directed towards the following ORIS codes and associated electric generating units (EGUs): 
55065  -  Mustang Station GEN1
55065  -  Mustang Station GEN2
55065  -  Mustang Station GEN3
56326  -  Mustang Station Unit 4GEN1
56326  -  Mustang Station Unit 4 GEN2 
From the Air Transport Rule, Technical Information section of the EPA website (http://www.epa.gov/airquality/transport/tech.html), the following documents require revision in order for the EPA to accurately calculate, based on the current methodology set forth by the proposed Transport Rule, the appropriate number of NOx allocations the aforementioned EGUs should be given:
A. From the Excel spreadsheet titled, "Budgets and Allocations  -  Detailed Unit-Level Data," the following corrections are required:
Under the Worksheet titled, "Unit Characteristics,"
The capacity (MW) rating for Mustang Station Unit 4 GEN1 and GEN2 in rows 9203 and 9204 respectively should both read 152 in cells F9203 and F9204 respectively. The spreadsheet inaccurately reflects capacity ratings of 145 MW for Mustang Station Unit 4 GEN1 and 0.5 MW for Mustang Station Unit 4 GEN2. This precludes GEN 2 from receiving any NOx allocations, unfairly increasing the operating costs of the unit. In addition, the designation for "Mustang Station Unit 4" GEN1 and GEN2 should be "Mustang Station Unit 4 & 5" GEN1 and GEN2, as GEN1 is Mustang Station Unit 4 and GEN2 is Mustang Station Unit 5.
Cell N9203 inaccurately reflects that an SCR is installed on Mustang Station Unit 4 GEN1. This potentially precludes Mustang Station Unit 4 GEN1 from receiving the appropriate amount of NOx allocations under the proposed Transport Rule. Cell N9203 should not have an "X" indicating an installed SCR.
[EPA-HQ-OAR-2009-0491-2808.1 p.3]
Cell S9203 inaccurately reflects the intentions of our company(ies) to install an SCR on Mustang Station Unit 4 GEN1. Cell S9203 should not have an "X" marking the intention to have an SCR "existing or committed by 2012."
Cell W9202 should not have an "X" indicating that Mustang Station GEN3 is a "Covered Unit (Fossil >25 MW)." Mustang Station GEN3 is a steam turbine with no combustion source. This is also incorrectly reflected in the "ParsedFile[series]" Excel spreadsheets.
Cell W9204 should have an "X" indicating that Mustang Station Unit 4 GEN2 is a "Covered Unit (Fossil >25 MW)" (see 1. i. above).
Under the Worksheet titled, "Reported Data,"
The entries for rows 9200 and 9202, for Mustang Station GEN1 and Mustang Station GEN3 inaccurately reflect the characteristics of Mustang Station GEN1 and Mustang Station GEN3 (see 1. iv. above). All data should be added together and attributed to Mustang Station GEN1 based on data reported to EPA (e.g. the "Heat Input Q1  -  2008" for Mustang Station GEN1 in cell F9200 should read "2,583,932"). While this correction may not immediately affect the number of NOx allocations received by Mustang Station GEN1-3, it should be corrected in the database to prevent future errors as Mustang Station GEN3 is a steam turbine with no combustion source and not a natural gas fired turbine.
Under the Worksheet titled, "Allocations & Rate Limits,"
The same problem as 2. i. above exists and should be corrected for Mustang Station GEN1 and GEN3.
The "Heat Input assumed in Ozone Season NOx Allocation" data in cell R9204 is inaccurate and should read "882,252."
[EPA-HQ-OAR-2009-0491-2808.1 p.3]
The "Ozone Season NOx Rate[s]" in column V are inaccurate and should be changed as follows:
Cell V9200 should read "0.035."
Cell V9201 should read "0.035."
Cell V9203 should read "0.030."
Cell V9204 should read "0.045."
Using the corrected values from 3. i-iii. above, the Ozone Season NOx Allocations in column M should be changed to read 97% of the calculated value (3% reserved for new units per EPA proposed rule), rounded up to the nearest ton, as follows:
Cell M9200 should read "86."
Cell M9201 should read "84."
Cell M9203 should read "15."
Cell M9204 should read "20." 
[EPA-HQ-OAR-2009-0491-2808.1 p.4]
Response: 
Thank you for your comment.Organization: Institute of Clean Air Companies (ICAC)
Comment: 
Institute of Clean Air Companies (ICAC)
Another benefit of maximizing flexibility for sources via EPA's preferred remedy is that sources need not have control equipment installed and operational by January 1, 2014, as explained below, especially for the Group 1 SO2 states. Sources will have the flexibility to go to the intrastate and/or interstate allowance markets to acquire the emission allowances they need for budget reconciliation. [EPA-HQ-OAR-2009-0491-2695.1, p. 3]
Response: 
Thank you for your comment.Organization: JEA
Comment: 
JEA
The Proposed Transport Rule properly recognizes the important environmental and economic benefits of allowance banking and that allowance banking as an element of EPA's program was in no way undermined by the court's decision in North Carolina v. EPA. [EPA-HQ-OAR-2009-0491-2713.1, p.5]
Response: 
Thank you for your comment. Banking of allowances is allowed under the final Transport Rule.
Organization: Kansas City Power and Light Company (KCP&L)
Comment: 
Kansas City Power and Light Company (KCP&L)
7. Prohibiting SO2 allowance trading between Group 1 and Group 2 states unfairly penalizes utilities with sources located in the same air shed, but on opposite sides of state boundaries. EPA should consider allowing trading between Group 1 and Group 2 states, or at a minimum, allow intra-utility trading between units in Group 1 and Group 2 states. [EPA-HQ-OAR-2009-0491-2709.1, p.4]
Response: 
Preamble Section VI.D.2. explains EPA's rationale for and responds to comments on not allowing sources in Group 1 states to use Group 2 SO2 allowances for compliance, and likewise not to allow sources in Group 2 states to use Group 1 SO2 allowances for compliance at any time.
Organization: Lafayette Utilities System
Comment: 
Lafayette Utilities System
EPA indicated that each state's budget comprises the emissions that EPA estimates remain after the state has made the reductions required to eliminate its significant contribution to nonattainment and interference with maintenance of the relevant NAAQS in other states in an average year. Under either the proposed State Budgets/Limited Trading remedy or the State Budgets/Intrastate Trading alternative remedy, each state's budget is allocated to sources within that state and EPA determines how much each source can emit without trading allowances. As support documentation to the proposed Transport Rule/FIP, EPA made available an Allocation Table which provides annual and ozone season NOx allocations for regulated EGUS. Under the Direct Control alternative, EPA projects that a state will be able to meet its good neighbor obligations each regulated EGU meeting the direct control emissions rates proposed. [EPA-HQ-OAR-2009-0491-2983.1,p.8]
LUS Objects to Use of the IPM to Make Unit Level Allocations
LUS is concerned with the NOx allocations provided to its units. An economic analysis performed for the Louisiana Public Service Commission projects that there will be an annual economic impact of $345,149 more than the cost incurred by LUS under CAIR for LUS to acquire annual NOx allowances. There will be additional cost to acquire ozone season NOx reductions. This assumes $1,200 per ton of NOx and is based upon the difference between allocations under the proposed Transport Rule/FIP and actual emissions from 2006. The projected annual average impact to LUS ratepayers would be $7.40 each. (Again, this estimate does not include the cost for ozone season NOx allowance acquisition.) This estimate would be accurate only if LUS is actually able to purchase NOx allocations from other Louisiana EGUs. LUS questions why the citizens of Lafayette should have to pay for allowances from utilities elsewhere in Louisiana. EP A does not appear to have any rational basis for these allocations. [EPA-HQ-OAR-2009-0491-2983.1,p.8]
Response: 
Thank you for your comment.Organization: Large Public Power Council (LPPC)
Comment: 
Large Public Power Council (LPPC)
However, LPPC also recognizes that the D.C. Circuit's decision in North Carolina placed legal constraints on EPA's ability to establish a fully fledged regional emissions trading system under Section 110 of the CAA. The most significant of these constraints is the court's holding that Section 110 requires each individual state to reduce its own significant contribution to nonattainment (and interference with maintenance) in downwind states. 38 This interpretation necessarily restricts the ability of states to "shift" emissions to other states on a regional basis through the trading of allowances  -  despite the gains in efficiency that might result from so doing. [EPA-HQ-OAR-2009-0491-2667.1, p.10]
B. Variability Limits Should Not Apply to Transport Rule Allowances That Were Banked Within the Same State in Which They are Submitted for Compliance
LPPC also objects to EPA's proposal that variability limits restrict not just the use of allowances that have been procured through interstate trading, but also banked allowances that are used by EGUs within the same state where the banked allowances were allocated. As noted in the preamble to the Transport Rule, 45 banking is a critical efficiency-enhancing feature of cap-and-trade programs that allows for cost-effective "shifting" of emissions from earlier periods of time to later periods when emissions abatement may be more costly. In addition, banking yields environmental benefits by encouraging sources to reduce emissions early, in excess of what is required by current levels of the emissions cap, in order to accumulate allowances for future use. The preamble to the Transport Rule explicitly touts the advantages of banking in support of EPA's proposed policy design, noting that "the banking provisions of the State Budgets/Limited Trading approach would provide incentives to reduce emissions as quickly and early as possible." 46 [EPA-HQ-OAR-2009-0491-2667.1, pp.13-14]
EPA's proposal, however, would needlessly limit the extent to which EGUs can realize those benefits. EPA's proposed combination of state emission budgets and variability limits is primarily intended to ensure that sources "within each State" reduce their significant contributions or interference with maintenance in downwind areas, as required by the D.C. Circuit in North Carolina. Unlimited use of banked allowances is consistent with the D.C. Circuit's holding in that case, because a source that achieves early emission reductions and banks its allowances for future use still eliminates its contribution to downwind air quality problems  -  albeit on a schedule different than is contemplated by the emissions cap. So long as they are not traded to EGUs in a different state, banked allowances do not result in the geographic displacement of emissions from one state to another, which was the D.C. Circuit's principal concern in North Carolina. [EPA-HQ-OAR-2009-0491-2667.1, p.14]
Because the use of banked allowances does not present the legal difficulties that unrestricted interstate trading was found to create in North Carolina, EPA is wrong to propose that the use of banked allowances be subject to the variability limits in the same manner as allowances traded interstate. Thus, LPPC recommends that usage of banked allowances be disregarded both for purposes of assessing whether the assurance provisions are triggered, and for determining whether a particular EGU owner has exceeded its share of the state budget plus the variability limit. This recommended exemption for banked allowances would, of course, only apply to Transport Rule allowances that are held within the same state in which they are allocated. [EPA-HQ-OAR-2009-0491-2667.1, p.14]
V. COMMENTS ON ALLOWANCE ALLOCATION METHODS
A. If EPA Rejects LPPC's Request for a Deferred Compliance Deadline, States Should Be Allowed to Elect the Allowance Allocation Methodology That Would Be Included In Individual FIPs
If EPA rejects LPPC's request for a one to two year deferral in the Transport Rule compliance deadlines, and thereby makes it impossible for states to revise their SIPs in time to avoid the imposition of a FIP, we request that EPA craft FIPs that reflect the preferences of individual states regarding the allocation of allowances to EGUs. The proposed Transport Rule would allocate NOx and SO2 allowances to existing EGUs on the basis of either their share of 2009 emissions within each state, or their share of projected 2012 base case emissions and 2014 emissions budgets as estimated by EPA. This emissions-based allocation method ensures that EGUs with the greatest demand for allowances (those with the highest NOx and SO2 emissions) receive relatively more allowances. On the other hand, this method also disadvantages EGUs that have made significant investments in conversion to cleaner fuels and installations of pollution control equipment. We believe states should have the primary role in deciding such sensitive issues of equity. In addition, we believe states are generally best informed as to the needs and circumstances of individual EGUs within their jurisdiction, and are thus in a superior position to make allowance allocations. [EPA-HQ-OAR-2009-0491-2667.1, p.17]
Thus, in the event that the Transport Rule deadlines are not changed, EPA should at least provide an informal mechanism by which states could submit their desired allowance allocation methodologies to EPA for inclusion in the Transport Rule FIPs. This mechanism would be akin to the process by which EPA has recently requested that states recommend a "reasonable deadline" for submitting revised SIPs addressing authority to issue PSD permits that include greenhouse gas limitations. 53  Such informal submissions would allow states to have voice in the allowance allocation process even if they are not able to revise their SIPs before the Transport Rule takes effect. [EPA-HQ-OAR-2009-0491-2667.1, p.17]
B. LPPC Supports the Proposed Set-Aside for New EGUs and Limited Allocations for Retired EGUs
LPPC supports EPA's proposal to reserve 3% of each state's annual emissions budget for distribution to new units. We agree this amount should be adequate to meet demand from new EGUs. Moreover, a specific set-aside for new EGUs provides existing EGUs with much-needed certainty as to the minimum quantity of allowances they would be entitled to. [EPA-HQ-OAR-2009-0491-2667.1, pp.17-18]
In addition, LPPC supports EPA's proposal to continue allocating allowances to retired EGUs for a total period of seven years after those EGUs cease operations. Retirement of aging EGUs is likely to be the most efficient and environmentally effective pollution control strategy in at least some cases. The proposed continuation of allowance allocations to retired EGUs will avoid discouraging utilities from removing units from service where it is appropriate to do so, and will smooth the path for retirements by helping mitigate the substantial costs of decommissioning, demolition and site remediation. [EPA-HQ-OAR-2009-0491-2667.1, p.18]
Response: 
Thank you for your comment.Organization: Luminant
Comment: 
Luminant
:: Luminant supports EPA's decisions to provide some regulatory certainty by allocating allowances permanently and to permit allowance banking beginning in 2012, to allow at least some degree of interstate trading and to not include allowance auctions in its preferred limited interstate trading option. [EPA-HQ-OAR-2009-0491-2729.1, p.2]
III. Luminant Supports Other Aspects of the CATR
Luminant supports EPA's decision to allocate permanent allowances and to provide for banking of allowances starting in 2012. Banking encourages sources owners to make early emission reductions. Luminant also supports the use of interstate trading in EPA's preferred regulatory approach. [EPA-HQ-OAR-2009-0491-2729.1, pp.5-6]
In addition, Luminant agrees with EPA's decision not to include any allowance auctioning under its preferred limited trading option. Allowance allocation provides greater regulatory certainty and flexibility in implementing reductions. [EPA-HQ-OAR-2009-0491-2729.1, p.6]
Response: 
Thank you for your comment.Organization: Massachusetts Department of Environmental Protection
Comment: 
Massachusetts Department of Environmental Protection
Massachusetts has included non-EGUs and smaller EGUs in both its NOx SIP Call (310 CMR 7.28) and its CAIR ozone season NOx control programs (310 CMR 7.32). MassDEP's existing CAIR NOx Allowance Trading Program applies to units that burn more than 50% fossil fuel and have a maximum heat input capacity of250 million British thermal units (MMBtu) or more, or serve a generator with a nameplate capacity of 15 MW or more. Units are included in the NOx Allowance Trading Program whether or not they produce electricity for sale. MassDEP recommends that EPA apply a similar applicability standard in the final Transport Rule. [EPA-HQ-OAR-2009-0491-2787.2]
EPA requested comment on the proposed approach for allocating allowances to non-operating units, including suggestions for simplifying allocations by not allocating at all to non-operating units, and on the question of maintaining perpetual allocations to non-operating units similar to the treatment of such units in the Title IV Acid Rain Program of the Clean Air Act.
MassDEP strongly objects to the proposal that non-operating units continue to receive allocations until the seventh year after the first year of non-operation. We urge EPA to not allocate any allowances in Transport Rule control programs to existing non-operating units to avoid the repeating perpetual allocations to non-operating units that occurred with the Title IV Acid Rain Program.
MassDEP urges that for all Transport Rule control programs, allowances allocated to Transport Rule eligible units not operating for three consecutive years be reallocated to the new unit set aside for the state where the unit is located beginning the next year (i.e., the fourth year), rather than the seventh year of non-operation. This will encourage operators to incorporate decisions about retirement or repowering units earlier into their compliance plamling and make additional allowances available to cleaner and presumably more efficient new electric generation resources.
We disagree with the contention that continuing to allocate allowances during the initial three consecutive years of non-operations plus another three year period will 'reduce the incentive for owners to keep units operating simply to avoid losing the allowance allocation for those units.',23 While allowance allocations are a factor in compliance planning and dispatch bidding, facilities report that fuel, operation and maintenance costs largely determine whether to bid a unit into the market or self-schedule operation for other purposes.
If EPA is concerned that operators will have an incentive to operate a unit for a limited period on an annual basis (less than 24 hours), then it should consider other alternatives, including using the 40 CFR Part 75 definition of an reliable operating quarter with a minimum of 168 hours, and require that to continue as eligible Transport Rule units, each unit must have a minimum of 2 or more quarters with more than 168 hours of operation during any year in order for it not to be a Transport Rule non-operating year.  [EPA-HQ-OAR-2009-0491-2787.2 p.9-10]
EPA proposes that, for 2012, each existing unit in a given state receives allowances commensurate with the unit's emissions. We have been unable to determine whether the proposed unit allocations in EPA's proposed Appendix A20 for the Annual NOx and 802 Transport programs for Massachusetts, or any other OTC jurisdiction, actually follow the specified methodology in the preamble or relevant Technical SuppOli Document. We recommend that, at a minimum, EPA identify whether individual unit allocations are based on projected or actual emissions and provide the actual spreadsheet calculations to facilities and states for evaluation well before the proposed initial allocation deadline of September 2011.   [EPA-HQ-OAR-2009-0491-2787.2 p.9]
Response: 
Thank you for your comment.Organization: Minnesota Pollution Control Agency (MPCA)
Comment: 
Minnesota Pollution Control Agency (MPCA)
In addition, the MPCA has some specific concerns for the current Transport Rule. First is the determination of unit budgets. The MPCA is concerned that the historical baseline emissions used as part of determining unit budgets looked only at 2008 and 2009 emission data. This is a short time frame, and one that is likely to be affected by the recent economic downturn. The MPCA would encourage BPA to look at emissions over a slightly longer period in order to determine baseline data. Looking at earlier data, from 2007 for example, could be used to alter the baseline, or at least to determine if 2008 and 2009 data are representative of facility operations. [EPA-HQ-OAR-2009-0491-2521.1, p.2]
Response: 
In the final Transport Rule, EPA uses projected data, not historic data, to determine state budgets.  Please see preamble section VI.D and the Significant Contribution Final Rule TSD for more information.
Organization: Minnesota Power 
Comment: 
Minnesota Power 
These new developments regarding treatment of Minnesota's status under the CAIR or proposed treatment under the Transport Rule raise multiple areas of factual questions as well as areas of concern about the methodology that EPA has applied in their assessment of Transport Rule requirements.  From the standpoint of Minnesota compliance planning, Minnesota Power had communicated with EPA during the CAIR promulgation process that Minnesota was already in the process of providing for reductions in PM2.5 precursor emissions as part of Minnesota programs designed to reduce Minnesota utility emissions in a cost effective manner. These emission reductions improve the air quality in Minnesota and address Minnesota requirements like making reasonable further progress on reducing visibility impairment in Northern Minnesota Class 1 Wilderness Areas.  These control measures were established even though Minnesota is in attainment with all of the NAAQS.    [EPA-HQ-OAR-2009-0491-2750.1, p.3]
Access to emission allowances needed for compliance.  EPA has not clarified what a unit operator is to do to continue operations if their budget allocations are insufficient to support designed or intended electricity production and no Transport Rule allowances are available for purchase.  All units accredited for dispatch should have a means by which they can provide for compliance with their Transport Rule budget. [EPA-HQ-OAR-2009-0491-2750.1, p.9]  
Response: 
EPA notes that the commenter provides no technical basis for the concern that "no Transport Rule allowances are available for purchase."  EPA's modeling of the final Transport Rule air quality-assured trading programs shows that cost-effective compliance would, in many states, lead to emission levels below the 2012 state budgets, showing that there will be more than enough allowances in the system to support a liquid interstate market in each program.
The commenter also mistakenly refers to Transport Rule budgets applicable to "units accredited for dispatch."  The Transport Rule does not apply any emission budget to any specific unit; instead, the Transport Rule establishes emission budgets at the state level and gives individual units the flexibility to determine their cost-effective emissions under that state-level budget.  Therefore, for purposes of the Transport Rule, units may emit in whatever amount for which they can provide sufficient allowances to cover in that control period.  As with prior emission trading programs, no unit is limited by its initial allocation and may acquire additional allowances in the marketplace.
Organization: Missouri Public Utilities Alliance (MPUA)
Comment: 
Missouri Public Utilities Alliance (MPUA)
7. Because EPA has decided that all power plants regardless of age or current pollution control equipment will need to make ongoing reductions in emissions, new power plants will be placed at a particular disadvantage.  During the permitting process, these plants have already had to meet much more stringent regulations for SO2, NOX and PM2.5 as part of the BACT process.  Because their current emission control equipment and processes are already the best available, it may not be possible to achieve any significant reductions for several years.  The current approach penalizes the regions cleanest plants while rewarding those which can more easily reduce much larger amounts of pollution. [EPA-HQ-OAR-2009-0491-2785.1, pp.3-4]
8. The EPA compliance strategy appears to ignore the realities of transmission congestion.  The Agency assumes that utilities that shutter older plants with higher amounts of emissions can easily replace that power with electricity generated outside the area.  While the existing utilities grid is marginally capable of shifting power within the region to meet shifting needs, it was not designed and does have the capacity to handle the level of shifts that will be necessary should power plant retirements meet the estimates identified in a number of studies.  It appears that within Missouri, those retirements are likely to be significantly higher than EPA is projecting. [EPA-HQ-OAR-2009-0491-2785.1, p.4]
While problems will develop with transmission congestion for individual utilities, the problem will be more complicated within a state or region as the impact is multiplied by many more utilities. [EPA-HQ-OAR-2009-0491-2785.1, p.4]
9. There does not appear to be clear process for units receiving emission allowance under NUSA to become classified as existing units.  EPA should identify that critical process and then resubmit for additional public comments. [EPA-HQ-OAR-2009-0491-2785.1, p.4]
Response: 
The commenter does not provide a technical basis for alleging that retirements within Missouri should be different than EPA projects.  EPA's power sector modeling accounts for interregional transmission limitations which are described in detail in the Resource Adequacy and Reliability in the IPM Projections for the Transport Rule TSD.
Organization: National Tribal Air Association (NTAA)
Comment: 
National Tribal Air Association (NTAA)
Need for Tribal Set-Aside
Aside from the above, the Transport Rule fails to provide Indian Tribes with an opportunity to become part of EPA's proposed trading scenarios. As drafted, the Rule provides allowance allocations solely to states and the District of Columbia. Under the Tribal Authority Rule, however, Tribes may adopt whole or parts of air programs based on 'reasonable severability' without being subject to deadlines or other requirements imposed upon states and other jurisdictions. This is something that the Agency acknowledged in the former Clean Air Interstate Rule (CAIR) in which it went to great lengths to address the unique circumstances of Indian Tribes and the need to accommodate future electrical generating units (EGUs) that should locate on Tribal lands. 8 Unfortunately, the EPA chose to ignore this earlier assessment of Tribal issues without providing a valid reason for doing so. The NTAA therefore recommends that the Agency revisit its earlier analysis under the CAIR concerning Tribes and establish a mechanism which allows such Tribes to enter into any trading program adopted under the Rule, specifically providing EGUs locating on Tribal lands with an appropriate portion of allowances. [EPA-HQ-OAR-2009-0491-2778.1, pp.4-5]
In addition, the EPA should provide for the inclusion of a Tribal set-aside under the Transport Rule that is based on factors other than EGUs located on state lands. As reference, the Agency only needs to look to an effort in the Western U.S. which provided for a similar set-aside that received support from a wide range of stakeholders. [EPA-HQ-OAR-2009-0491-2778.1, p.5]
The Western Regional Air Partnership (WRAP), a partnership between Indian Tribes, states and federal agencies (including the EPA) and with participation from such entities as environmental organizations and industry, advocated for a Tribal set-aside during the late 1990s that was eventually adopted as part of the Annex to the Regional Haze Rule (RHR). The Annex established declining SO2 emission milestones for major sources. If the milestones were exceeded, then a cap-and-trade program would be initiated to ensure continued SO2 reductions. As part of the Annex, an annual SO2 Tribal set-aside of 20,000 tons was made available to Tribes within a nine-state region, regardless if such Tribes had major industrial sources emitting SO2. This set-aside was to be distributed as determined by the region's Tribes (e.g., for future industrial sources, other economic development purposes, Tribal scholarships, etc.). This annual Tribal set-aside also grew out multiple discussions among the WRAP's partners and participants where issues of equity and economic development kept coming up during conversations with respect to the Tribes that had hardly contributed to visibility impairment in the West but whose environment and health had been adversely affected by neighboring jurisdictions with sources emitting significant amounts of SO2. At that time, neither the WRAP partners or participants had sufficient information about future EGUs in Indian Country but they felt it imperative to address equity issues properly before and not after the Annex was implemented. [EPA-HQ-OAR-2009-0491-2778.1, p.5]
The NTAA therefore recommends that the EPA include a Tribal set-aside as part of any trading program adopted in accordance with the Transport Rule. A determination about the appropriate size for such a set-aside and the means for its allocation requires the Agency to consult with Tribes. In this effort, the NTAA offers its assistance to the Agency by bringing a great deal of experience and involvement with the Tribal set-aside that was created under the RHR Annex, and also based on its longstanding relationships within Indian Country. [EPA-HQ-OAR-2009-0491-2778.1, p.6]
8. Rule To Reduce Interstate Transport of Fine Particulate Matter and Ozone (Clean Air Interstate Rule); Revisions to Acid Rain Program; Revisions to the NOx SIP Call; Final Rule, 70 Fed. Reg. 25162, 25167 (May 12, 2005) (to be codified at 40 CFR Parts 51, 72, 73, 74, 77, 78 and 96) ('[I]n the event of any future planned construction of EGUs on Tribal lands within the CAIR region, EPA intends to work with the relevant Tribal government to regulate the EGU through either a Tribal implementation plan (TIP) or a Federal implementation plan (FIP). We anticipate that at a minimum, a proposed EGU on a reservation within a State participating in the CAIR cap and trade program would need to be made subject to the cap and trade program. In the case of a new EGU on a reservation in a CAIR-affected State which chose not to participate in the cap and trade program, the new EGU might also be required, through a TIP or FIP, to participate in the program. This would depend on the potential for emissions shifting and other specific circumstances (e.g., whether the EGU would service the electric grid of States involved in the cap and trade program.) Again, EPA will work with the relevant Tribal government to determine the appropriate application of the CAIR.'). [EPA-HQ-OAR-2009-0491-2778.1, pp.4-5]
Response: 
As described in Preamble Section VII.D, the final Transport Rule establishes Indian country new unit set-asides to provide allowances for new units built in Indian country.
Organization: North Carolina Department of Environment and Natural Resources
Comment: 
North Carolina Department of Environment and Natural Resources
Handling of Biomass Units
Some sources are transitioning from fossil fuel to biomass to meet state Renewable Portfolio Standards. Some are cogeneration units and some are not. If the source has burned any amount of fossil fuel in 1990 or any year thereafter, and it meets the other applicability criteria, and does not meet the cogeneration exemption, it is subject to FTR. NCDAQ requests a clarification on how existing fossil-fuel fired units that convert to biomass are to be treated under the Transport Rule including what the allocations will be based on for such units (total heat input or jnst fossil fuel used for start-up). What if an existing fossil-fired unit converts completely to biomass (no fossil fuel for start-up)? Also, please clarify how new biomass units are treated and what the associated allocations methodology is. For instance, does it matter whether the source was previously a NOx SIP Call source that also later met the CAIR applicability criteria? [EPA-HQ-OAR-2009-0491-2767.1 p.4]
The allocation method relies on historical emissions. NCDAQ believes it would be beneficial to look at energy output as a way to promote energy efficiency. Heat input could also be used as an alternate allocation methodology. [EPA-HQ-OAR-2009-0491-2767.1 p.7]
Response: 
The final rule covers fossil-fuel-fired units serving generators with a nameplate capacity greater than 25 MWe producing electricity for sale and defines "fossil-fuel-fired" as combusting any amount of fossil fuel in 2005 or later.  The commenter claimed that biomass units that switch from burning some fossil fuel to burning no fossil fuel should be exempt just as new units that never burn fossil fuel are not covered by the Transport Rule trading programs.  EPA rejects the commenter's claim.  The approach in the final rule is consistent with the approach used in prior EPA trading programs covering the electric generation industry, e.g., the Acid Rain Program, the NOx Budget Trading Program, and the CAIR trading programs.  The commenter did not provide any basis for using a different approach in the Transport Rule trading programs covering the same industry.  Moreover, the commenter essentially suggested that the determination of whether a given biomass unit is subject to the Transport Rule trading programs should not be based on any historical information on whether the unit burned any fossil fuel, but rather only on what the unit is currently burning.  This approach would mean that, for all biomass units, owners and operators, and EPA, would not know at the start of the Transport Rule trading programs, whether the units were subject to the trading programs and that the units' regulatory status could change, and the units become subject to the trading programs, at any time that any fossil fuel was combusted.  Because all biomass units would not be reporting their fuel use to EPA until they became subject to the trading programs, the determination of whether specific units were subject to the trading programs, and assurance of compliance, would be problematic.  EPA believes that its approach is reasonable: biomass units that have recently (i.e., after 2004) operated burning some fossil fuel are treated differently than new biomass units that are initially designed to operate without combusting any fossil fuel and actually operate without any fossil fuel combustion.  The units burning fossil fuel after 2004 are more likely to continue to do so.  EPA maintains that it is reasonable to make these biomass units, like any other units burning at least some fossil fuel after 2004, subject to the Transport Rule trading programs.  Similarly, EPA believes it is reasonable to treat a biomass unit that has not burned and does not burn any fossil fuel (like any other units that have not burned and do not burn) any fossil fuel as not subject to the Transport Rule trading programs, unless and until they begin burning fossil fuel.
Organization: NRG Energy
Comment: 
NRG Energy
Use of projected emissions for developing state budgets and source allocations NRG supports the overall methodology to base state budgets and source allocations on projected emissions. While we are disappointed that no credit is given to the investments already made in emission controls, we recognize that this approach brings parity to the industry. Energy markets have gone through a sea change based on lower gas prices, increased renewables, and lower demand in strained economic conditions. Even estimates based on recent historical emissions, heat input or output will not reflect the future. This is true in both the short term (2012-2014) and beyond. Other allocation methodologies such as historical output or emissions can create large windfalls for some sources and leave huge shortfalls for others. The projected methodology is most equitable in that EGUs should all receive allocations approaching their expected emissions. This recognizes the need for a diverse set of fuels and technologies to meet the needs of the energy markets. [EPA-HQ-OAR-2009-0491-2749.1, p. 3]
An alternative method for allocations to new units The proposed Transport Rule contains the methodology to allocate allowances to new units. The methodology is identical for all four allowances programs (Group 1 SO2, Group 2 SO2, Annual NOx, and Seasonal NOx). NRG assumes that a new unit would be one that is not listed in Appendix A as having an allocation, but operates on or after January 1, 2012. It is presumed that EPA will capture in Appendix A all sources that are operational prior to January 1, 2012 (or May 1, 2012 in the case of Seasonal NOx). [EPA-HQ-OAR-2009-0491-2749.1, p. 5]
A new unit must submit to EPA a request for an allocation of allowances based on actual emissions from the prior control period. This proposed allocation methodology will penalize a source that is operational prior to the beginning of a control period in that the request for an allocation may only be based on emissions from a partial control period. For example, a source that commences operation on June 1, 2013, would only have emissions data for 7/12th of the annual and 4/5th of the Ozone Season control periods. [EPA-HQ-OAR-2009-0491-2749.1, p. 5]
NRG proposes that a new unit be allocated allowances based on 97% of its permitted emissions in tons per year. The 97% allocation is similar to the allocation given to existing units; i.e., existing units' allocations are minus 3% in order to fund the New Unit Set Aside Account. A new unit however, should not profit from the allocation, in that if actual emissions were less than permitted emissions, the new unit would have a surplus of allowances. Instead, EPA could use a method similar to that used in the NOx SIP and CAIR programs. That is, the state would hold the allowances in the state Set Aside Account. After the end of the relevant control period, the state would deduct from the Set Aside Account, allowances equal to 97% of actual control period emissions. If the Set Aside Account is oversubscribed (i.e., total emissions from new units in the state are greater than the amount of allowances in the Set Aside Account) then, the allowances would be allocated to each new unit would be adjusted by the percent the account is undersubscribed. That is, if the account has only 90% of the needed allowances then, each new unit would receive allowances based on 90% of their emissions. This methodology would continue for the first five control periods for the new unit. [EPA-HQ-OAR-2009-0491-2749.1, p. 5]
EPA allocations should account for self-scheduled operations by using historical emissions. EPA proposes in the Transport Rule to allocate SO2 and NOx allowances based on a generating unit's projected operation using IPM outputs. This model is an energy dispatch model and does not account for operations that are self-scheduled. This is an especially critical issue for steam electric generating units projected to have little or no operations in IPM. These units are commonly called "peaking units." [EPA-HQ-OAR-2009-0491-2749.1, p. 7]
Self-scheduled operations are due to two main requirements: energy market rules and environmental regulations. These Peaking Units may operate to stabilize transmission lines which would not be recognized in IPM. They also run to conduct mandatory energy market seasonal capacity demonstrations. For a Peaking Unit, this means that it would likely be scheduled to operate outside of its dispatch order for a short period. Similarly, most NRG Peaking Units measure their emissions via a Continuous Emissions Monitoring System (CEMS) and therefore are required to perform an annual RATA and/or particulate matter stack testing. [EPA-HQ-OAR-2009-0491-2749.1, pp. 7-8]
As a result, NRG peaking units located in Connecticut, Maryland, and New York are not properly allocated allowances in the proposed Rule. These requirements and the historic operations are further discussed in the following paragraphs. While NRG supports allocation on projected emissions, this type of unit should be allocated allowances based on historical emissions. NRG suggests, at a minimum, each peaking unit receive SO2 and NOx allowances equal to their three year average historic emissions from required testing, and that state budgets are amended accordingly to account for these allocations. Three year average historic emissions from self-scheduled operations for NRG peaking units are listed in Table 2-1. [EPA-HQ-OAR-2009-0491-2749.1, p. 8; see pp. 8 for information on three peaking units and p. 9 for Table 2-1]
Response: 
.Because EPA allocates to existing units based on historic data under the final Transport Rule FIPs, peaking unit operations should be accurately reflected in the historic data basis for existing unit allocations.  Please see section VII.D of the preamble and the Allowance Allocation Final Rule TSD for more information.
Organization: Occidental Chemical Corporation (OCC)
Comment: 
Occidental Chemical Corporation (OCC)
If adopted in its current form, the proposed rule could have a significant negative impact on OCC's modern, clean-burning cogeneration facility at Taft, Louisiana, if the facility cannot meet the proposed exemption for cogeneration units. Commissioned in 2002, this facility is equipped with drylow NOX burners and is permitted to emit approximately 1,463 tons of NOX per year. However, the proposed rule provides annual allowances to this facility totaling only 26 tons of NOX per year beginning in 2012. In other words, EPA has proposed to grant only about 2% of the annual NOx allowances needed to run the Taft facility at its full capacity. For the sake of argument, assuming that Taft is running at full capacity and NOX allowances are valued at $1,200 per ton, OCC would need to purchase 1,438 tons of NOX allowances at an annual cost of about $1.7 million. This presumes, of course, that such allowances would be available on the market. OCC has significant concerns with EPA's modeling efforts and methodology used to develop overall emissions allowances and to allocate allowances to individual units. [EPA-HQ-OAR-2009-0491-2754.1, p. 3]
While the ozone season NOX allowances for our Ingleside, Texas facility are sufficient for current operating rates (227 tons) if the facility is not exempt, we do not know how the allocation was developed and ask that EPA provide additional information explaining how the allocation was made. [EPA-HQ-OAR-2009-0491-2754.1, p. 3]
The Proposed Rule Contradicts Current EPA Policy and Programs
If EPA will not exempt all QF cogeneration units, it should ensure that such units are allocated sufficient allowances to continue operating and supplying clean energy to the Louisiana electricity market. [EPA-HQ-OAR-2009-0491-2754.1, p. 14]
For many years, EPA has encouraged the installation of cogeneration facilities. Recently, EPA Administrator Jackson stated the following with regard to combined cycle/cogeneration facilities during a speech on November 20, 2009 at the White House Clean Energy Forum on Public Health: "Win-win changes for our health and environment  -  like installing co-generation units at a manufacturing plant or mass transit expansions  -  require large up-front investments...." In this case, we believe that the Administrator is correct. Cogeneration is costly to install, but is a win-win for the environment and industry when compared to traditional EGUs because it produces low-cost, clean power and steam with less energy. In support of cogeneration, EPA established the Combined Heat and Power Partnership. According to EPA,'The CHP Partnership is a voluntary program seeking to reduce the environmental impact of power generation by promoting the use of CHP. The Partnership works closely with energy users, the CHP industry, state and local governments, and other clean energy stakeholders to facilitate the development of new projects and to promote their environmental and economic benefits.'  [EPA-HQ-OAR-2009-0491-2754.1, p. 14]
However, it would seem that the "win-win" identified by the Administrator and the types of units promoted by the EPA CHP partnership - which are the types of units that OCC has installed at Taft, - are the types of units that the IPM predicts will no longer operate and that EPA penalizes by failing to allocate sufficient emissions allowances in the CATR program. [EPA-HQ-OAR-2009-0491-2754.1, p. 14]
In the report entitled "Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model" (August 2010), EPA states the following on page 7-1: "...existing generating units have the option of maintaining their current system configuration, retrofitting with pollution controls, or retiring early. The decision to retrofit or retire is endogenous to IPM and based on the least cost approach to meeting the system and other operating constraints...Table 7-2 and 7-3 present the first and second stage retrofit options respectively." [EPA-HQ-OAR-2009-0491-2754.1, p. 14]
We interpret this explanation to mean that the IPM assumes that decisions to retire or retrofit EGUs, including cogeneration units, will be based on the assumed least cost approach to meeting regional power system requirements, not environmental concerns or other business interests of the cogeneration facility operator. The assumptions contained in Table 7-2 for combined cycle (cogeneration) and combustion turbines are as follows: [see 2754.1, p. 15 for Table 7-2.] [EPA-HQ-OAR-2009-0491-2754.1, p. 15]
Thus, EPA's IPM predicts that all cogeneration and combustion turbine units will retire early because it may be more cost effective, on a regional system basis, to generate electricity with, for example, coal-fired units. Apparently following this rationale, EPA allocates almost no allowances to the Taft cogeneration units (and units like it), presumably because EPA assumes that the 8-year old facility will be retired in 2012 (or run at only about 5% of usual operating rates), and granted other units all the allowances they will need to continue business as usual. We randomly selected emission rate data contained in the Parsed File Transport Rule Base Case for 201231 and the Budgets and Allocations - Detailed Unit-Level Data Base32 for a Midwest coal unit and noted the following comparison of historic emissions and CATR allocated allowances:  [EPA-HQ-OAR-2009-0491-2754.1, p. 15] [See 2754.1, p. 15 for the comparison.]
This particular unit is receiving 212 tons of annual allowances and 982 tons of ozone season emission allowances more than it currently needs (presuming that annual emissions remain consistent). We are baffled as to why a clean burning and energy efficient facility like OCC's natural gas cogeneration plant at Taft, assuming it is not exempt, would be provided allowances to cover only a small fraction of what it emits and that another higher emitting facility would be given excess allowances. In an interim public notice, we respectively request that the EPA respond to this apparently unprincipled discrepancy. [EPA-HQ-OAR-2009-0491-2754.1, pp. 15-16]
Not only is this result contrary to EPA's public remarks and programs, it unfortunately will do nothing to reduce air emissions. It appears that EPA's reliance on the IPM would result in increased emissions rates, not emissions reductions, in order to promote electric generation system efficiencies. We do not believe, however, that decisions regarding the efficient dispatch of electricity and the appropriate inventory of regional EGU fleets are within EPA's area of expertise or jurisdiction. [EPA-HQ-OAR-2009-0491-2754.1, p. 16]
As noted above, OCC has no intention of idling the Taft cogeneration facility or its steam host, or any of our cogeneration and steam host facilities. Thus, we strongly object to the assumption that cogeneration units should be retired in 2012 and recommend that EPA abandon the use of the IPM for making unit-level allocations to EGUs under the CATR, and rather rely on historic emission rate information to establish allowance allocations, as it did with SO2 allowances. [EPA-HQ-OAR-2009-0491-2754.1, p. 16]
Problems with the Use of the Model for Unit Level Allocations
EPA used the IPM to determine unit-level emissions allowances for 2012 and beyond for facilities affected by the proposed Transport Rule. Our limited information about the IPM suggests that the proper use of the model is for electric utilities, public utility commissions and investors to mysterious factors not explained in any of the docket materials. Nowhere were we able to identify any environmental considerations in the IPM, other than assumptions about how much it would cost to install control technology. In that regard, we question whether EPA is qualified, let alone authorized, to impose regulations that effectively reconfigure a large portion of the nation's power generating fleet  -  the domain traditionally addressed by FERC, the Department of Energy and state utility commissions. In any event, given the distorted pattern of allocations distributed by the IPM, we firmly believe that EPA should NOT use the IPM to allocate emissions allowances. [EPA-HQ-OAR-2009-0491-2754.1, pp. 18-19]
The IPM appears to predict that electricity from coal-fired units will be less expensive than electricity from gas-fired cogeneration units in 2012. Based on that assumption, it appears the model projected that coal-fired units will run at significantly higher rates that natural gas-fired units. Given the model's prediction that coal units will face higher demand than gas units, EPA generously awarded coal units with enough allowances to run at recent, or even higher operating rates. By relying on the IPM's economic predictions to grant generous allocations to coal units while drastically short-changing cogeneration units, EPA would effectively force modern, clean and efficient cogeneration units, such as OCC's Taft units, to buy a huge number of allowances simply in order to run, thus providing an enormous financial windfall to higher-emitting coal units. In essence, EPA has endorsed the idea that coal-fired plants should keep on running, displacing the power previously supplied by ultra efficient and clean cogeneration units. Furthermore, although one might argue that high-emitting coal units would be able to pay for SCR technology with the revenue generated by cogeneration payments for allowances, we find no incentive in the proposed rule for coal units to install SCRs, given that such units will receive a sufficient number of allowances to operate without SCRs. One can only conclude that not only does EPA's proposed rule directly contradict the Congressional objectives of the PURPA cogeneration exemption, it is, with respect to the purported objective of reducing air emissions, arbitrary and capricious and an abuse of power. [EPA-HQ-OAR-2009-0491-2754.1, p. 19]
Allocating Allowances to Non-Operating Units We are confused as to why the EPA would provide allocations for non-operating units, and not provide enough for those that operate. In the preamble to the proposed rule, EPA states the following  [EPA-HQ-OAR-2009-0491-2754.1, p. 28; see pp. 28-29 for quote from 75 FR 45310-11]
Response: 
Thank you for your comment.Organization: Old Dominion Electric Cooperative
Comment: 
Old Dominion Electric Cooperative
The emission reductions compliance deadlines under both the 2012 and 2014 are overly optimistic and unachievable, certainly for many units. As close as can be reckoned from the proposed Transport Rule preamble and technical information contained in the rulemaking docket, EPA has modeled emission reductions capabilities for each unit within the trading programs based on generic assumptions. Moreover when queried to explain individual allocation unit outcomes, EPA staff have been in some cases unable to meaningfully respond. Considering that the proposed allocation of emission allowances to individual units is based on this modeling and that these allocations are essentially permanent, EPA should have gone above merely assembling broad based and inaccurate assumptions, and modeling unit allowance destinies based on them, as it seems to have done in this case. [EPA-HQ-OAR-2009-0491-2877.1,pp.3-4]
The proposed Transport Rule would significantly restrict emissions within the 32 trading areas and therefore allowance allocations. EPA has offered limited explanation to explain the proposal's continuing allocation of allowances to retired or non-operating units for a full six years after operation ceases at full allocation rate under existing unit formulas, except to surmise it would discourage older units from operating, Id. at 45,311. Not discussed in the proposal, however, is the fact that older units will be discouraged from retiring. Further, no data or documentation is offered to explain the six year time period or the full allocation rationale. A certain fact here is non-operating units would receive allowances not needed for compliance. [EPA-HQ-OAR-2009-0491-2877.1, pp.6-7]
The proposed Transport Rule states, '...once an EGU does not operate (i.e., does not combust any fuel) for 3 consecutive years, the Agency would no longer allocate allowances to the unit, starting in the seventh year after the first year of non-operation', ld. at 45,310. However, an unintended consequence would be to award older less-effìcient units with allowances. A utility could combust fuel once every three years to be considered operational and continue receiving allowances. [EPA-HQ-OAR-2009-0491-2877.1,p.7]
The proposed Transport Rule should allow economics to determine if a unit will operate or not. The proposed Transport Rule should use 50 percent of the default capacity factors found on page 45313 of the proposed rule to determine if a unit is an operating unit. ln that same thought, ODEC believes that the default capacity factor for the simple cycle peaking facilities of 15% is overestimated. For planning and financing purposes, peaking facilities will typically be forecasted to not run more than 5%. lf a unit does not meet the minimum default capacity factor, for 3 years, it would not be provided allowances. The non-operating units' allowances would go to the new source set-aside pool and should remain in the pool for a minimum of 10 years to ensure there are adequate allowances for new generation. After 10 years, the unused allowances should be returned to existing operating units on a pro-rata basis. [EPA-HQ-OAR-2009-0491-2877.1,p.7]
EPA proposes a 3% set-aside from state allowance budgets for new units, but proposes no allowances for the initial control period after the unit comes on line, ld. at 45,310. ln the event of insufficient allowances in the set-aside, available allowances are distributed pro-rata to new units. So under EPA's proposal non-operating units receive un-needed allowances and new units may well end up with a fraction of what's needed and none for the first year of operation. As stated previously, construction of a new multi-billion dollar power station requires certainty that there will be allowances available to operate. Without this certainty it is unlikely that new, cleaner and more efficient generation plants will be able to obtain financing to construct. [EPA-HQ-OAR-2009-0491-2877.1, p.7] 
EPA's proposed non-operating and new unit allowance policies are arbitrary and exemplify the importance of letting states determine these types of policies based on local considerations and needs. ln this context, it is a mistake for EPA to short circuit the SIP process. The Transport Rule allowance allocation methodology should ensure new units equipped with best technologies and techniques to minimize emissions receive 100% of allowances needed for commercial operation, including initial year requirements. [EPA-HQ-OAR-2009-0491-2877.1,p.7]
The proposed Transport Rule should be changed to accommodate new unit allowance allocations. As stated above, the allowances from non-operating units need to go to the new source set-aside pool and be provided to new sources at no charge. As EPA points out in the proposal, retired units do not need them, ld. at 45,311. Additionally, instead of eliminating unused CAIR allowances, at least a portion of them could be set-aside for new unit utilization in the event of a shortfall in the new unit set-aside. [EPA-HQ-OAR-2009-0491-2877.1, p.7]
The proposed Transport Rule allowance allocation scheme is flawed for numerous reasons. lt is based on EPA computer model projections of both future individual unit utilization and emission reduction capabilities at specified marginal cost of emission reduction levels. The model attempts to predict the future of literally thousands of electric utility fossil fuel units located within the proposed 32 trading areas. Regardless of the purported sophistication of EPA's model, it does not and cannot accurately forecast how each and every fossil fuel unit among thousands will be utilized. For example, the model cannot account for the presence or ramifications of short and long term wholesale power agreements under which unit owner obligations include future system and individual unit power demands. The model cannot account for future business decisions, the necessity of which is not yet presently known or anticipated. This uncertainty would have a significant effect on an individual unit's utilization within the utility system. The model cannot predict or account for how units will operate through the regional transmission organization (RTO) that coordinates the movement of wholesale electricity. There are literally dozens of significant factors that affect future unit utilization of which the model does not and cannot take into account. [EPA-HQ-OAR-2009-0491-2877.1,pp.8-9]
The model does not and cannot accurately forecast for each and every fossil fuel unit within the 32 trading regions the actual future costs of meeting the emission reduction obligations dictated by the model. For example, the model cannot account for costs, on a unit basis, associated with contract breaches associated with early termination of coal and associated transportation contracts necessitated by the model to switch coals. The model cannot account for costs associated with obtaining new contracts for new coal deliveries especially when potential contracting parties for supply are aware of reduction obligations dictated by EPA's model and the essence of time. The model assumes 'just in time' expanded natural gas transportation capabilities to meet the aggregate demand the model's emission reduction mandates place on affected units within a geographic area. Likewise, there are literally dozens of significant factors that affect future costs of emissions controls of which the model cannot take into account. [EPA-HQ-OAR-2009-0491-2877.1,p.9]
ln short, EPA's model puts real life units within its virtual world and dictates unit utilization and emissions reduction destinies based on this fantasy. EPA may argue that emissions trading allowed under its remedy and preferred options would correct all the deficiencies inherent in this entire scheme. As EPA is well aware, however, trading is necessarily limited by the North Carolina decisions and is even entirely prohibited by at least one option in the proposed Transport Rule, so it is unlikely trading would save the day. [EPA-HQ-OAR-2009-0491-2877.1,p.9]
Additionally, EPA's proposed allowance allocation trading scheme fails to reward cleaner emissions units and the electric consumers who have borne higher electricity costs because they must pay for existing, expensive emission controls. The model metrics do not consider existing unit generation costs, and as such some of the most costly fossil fuel generation affected by the proposal would have to incur even higher costs as compared to Transport Rule compliance costs associated with more polluting less efficient affected units. [EPA-HQ-OAR-2009-0491-2877.1, p.9]
ODEC, however, commends EPA for willingly opening up its proposed allocation methodology for comment on alternative methods that still link unit allowances directly to the way state budgets were developed, ld. at 45,311. ODEC construes this EPA-stated limitation on alternatives to mean that so long as the aggregate allowable emissions within individual state budgets are not affected or altered by the unit allowance allocation methodology, EPA would deem it within its regulatory discretion. EPA's limitation here appears to be based on the North Carolina decisions in that it limits EPA's discretion in allocating allowances for S 110(a)(2)(D)(i) purposes to the extent that the distribution cannot in effect determine or partially determine state's emissions budgets. ODEC believes the North Carolina decisions do in fact impose this limitation but it does not prohibit allocations methods under state budgets determined based on the need to address interstate air pollution. [EPA-HQ-OAR-2009-0491-2877.1,pp.9-10]
Alternative Allocation Methodology
ODEC believes many of the troublesome aspects of the proposed Transport Rule could be addressed if the allocation methodology were structured in a manner similar to that contained in CAIR for annual NO' allocations as a SIP (or FIP option as the case may be) for all the Transport Rule trading programs. Specifically the salient features of this methodology include allocating allowances to existing units based on historic heat in-put using the 3 highest heat inputs of the past 5 years to derive annual averages (seasonal for ozone), and allocating allowances to new units based on a set aside and folding new units into existing unit category after 5 years of operation. [EPA-HQ-OAR-2009-0491-2877.1,p.10]
EPA mentions an option for allowance distribution to units placed into various subcategories of units that have similar characteristics, ld. at 45,311. lf this is implemented, ODEC suggests that coal, gas and oil units be divided into three categories and that allowances be distributed pro rata to units in each category based on unit heat in-puts as a percentage of categorical heat inputs, ODEC believes that this methodology is rational and well within the bounds of the North Carolina decisions. Additionally, this allocation rewards not punishes electric consumers that have already incurred high costs of emissions controls. [EPA-HQ-OAR-2009-0491-2877.1,p.10]
As with EPA's proposed Transport Rule approach, this methodology could provide options for each state to consider whether new units should receive allowances from a set-aside during their initial year of operation and whether retired/non-operating units should continue to receive allowances, and if so how long or at a diminished allocation. [EPA-HQ-OAR-2009-0491-2877.1,p.10]
Response: 
Thank you for your comment.Organization: Omaha Public Power District
Comment: 
Omaha Public Power District
Given the substantive issues with the Nebraska emission inventory used by EPA for its analysis, the appropriateness of using an episode-based procedure (see comment #8 above) for establishing significant contributions for 24-hour PM2.5, and the need for consistency in setting and rounding of significant impact levels, EP A should revise its analysis to determine if the TR should be applied to Nebraska. [EPA-HQ-OAR-2009-0491-2680.1, p. 6]
If after revising its analysis as appropriate to determine if Nebraska should be included in the TR, and if Nebraska is still determined to be included in the rule, we have the following additional comments: [EPA-HQ-OAR-2009-0491-2680.1, p. 6]
As indicated in the Transport Rule documentation, Nebraska is a Group 2 state for S02. As such, the basis for the proposed Nebraska State S02 budget and the unit specific S02 allowance allocations was actual emissions with given adjustments to include continuous use of existing add-on controls and add-on controls that are planned to be added for reasons other than the transport rule. There were no such adjustments for Nebraska units, so the allowance allocations are based on actual emissions. In setting the S02 emissions budget, the actual emissions from the last quarter of 2008 and the first three quarters of 2009 were used as a basis. Four continuous quarters of operation is simply a snapshot of the actual operation of a utility boiler. This snapshot does not account for the variability in individual utility unit operation and utility operation throughout the state. This was recognized by EPA in their development of the CAIR rule, where four years of operating data were used as a basis to establish allowance allocations. The fact that a single four quarter period is inadequate to establish state budgets or unit allowance allocations was also recognized to some extent in the methodology used to establish the Transport Rule proposed NOx state budgets and unit specific allowance allocations. On page 9 of the Technical Support Document for the Transport Rule titled 'State Budgets, Unit Allocations, and Emission Rates' it is indicated that in setting the NOx budgets and unit allowance allocations, reported annual and ozone season NOx emissions were adjusted to account for unusually low utilization in 2009. Therefore, EPA based NOx budgets and unit allowance allocations on 2008 heat input data, presumably because it was considered more representative of typical operations. However, the same data set that EPA deemed inappropriate for use in setting the NOx budgets and unit allowance allocations was used to set the S02 budgets and unit allowance allocations, with no apparent reason given for using this data that represents ''unusually low utilization'. We request that EPA use a data set with a longer timeframe in setting S02 budgets and unit allowance allocations, such as the most recent three full years of data, or make adjustments to the S02 budgets and unit allowance allocations as was done in setting the NOx budgets and unit allowance allocations. [EPA-HQ-OAR-2009-0491-2680.1, pp. 6-7]
Response: 
Preamble Section V has a description of EPA's air quality analysis used to determine states that should be covered under the final Transport Rule.
Organization: Pennsylvania Department of Environmental Protection
Comment: 
Pennsylvania Department of Environmental Protection
The DEP supports EPA's use of air quality factors and a health benefits assessment in calculating states' emissions budgets, rather than basing the budgets solely on the availability of highly cost-effective controls. However, we do not believe that EPA established a transparent process for determining budgets and allocations. [EPA-HQ-OAR-2009-0491-2660.1, p.5]
We understand that the allocations arc based upon a model that uses fuel prices, cost of controls, unit operation practices, a unit's business environment, electricity prices, demand, growth, and renewable energy and energy efficiency programs, as well as a host of other economic and environmental variables that may reflect future outcomes. However, allowance allocations should nut be based solely upon a unit's past heat input or electric output. Allowance allocations based upon heat input or electric output might not result in individual units eliminating their significant contribution to another State's nonattainment of the NAAQS. Instead, heat input and output methods can result in greater allocations for EGUs that contribute significantly to nonattainment in downwind areas. The DEP understands that EPA has indicated that such allocations would be in conflict with the Court's decision. While DEP is supportive of EPA's allocation methodology, we strongly recommend that EPA use an average of several years for its modeling run inputs. [EPA-HQ-OAR-2009-0491-2660.1, p.5]
Variability within Budgets
The DEP acknowledges the need for some flexibility to account for differences in weather, unplanned outages, and other factors between years, and supports the approach EPA has used to allow variability in interstate trading. However, DEP has concerns with placing the variability outside each state emissions budget. EPA should consider containing variability within the proposed budgets rather than in addition to the proposed budgets. This approach should help to ensure that the emission reductions achieve EPA's modeling projections related to significant contribution and interference with attainment and maintenance. The DEP would also support the suggestion made by the National Association of Clean Air Agencies to set aside an emergency reserve of allowances each year (subtracted proportionately from each state's budget) that can be used in states to address weather, unplanned outages, and other factors that result in emission variability. This recommendation should help to ensure the integrity of the emissions budget while accounting for variability. [EPA-HQ-OAR-2009-0491-2660.1, p.7]
Response: 
A description of and rationale for EPA's approach to variability limits can be found in Preamble Section VI.E.
Organization: Pfeiff, Mike
Comment: 
Pfeiff, Mike
6. Title IV allowance auction - The EPA's modeling shows that if the EPA's preferred FIP is implemented as part of the Proposed Transport Rule, the quantity of SO2 emissions will decrease substantially (TR SB Limited Trading System Summary Report.xls). Since the Title IV allowance allocation does not decrease commensurate with the Proposed Transport Rule budgets, the quantity of previously unused (a/k/a 'Banked') Title IV allowances will increase substantially each year. The EPA Administrator should use her existing authority granted under section 416(e) of the CAA to mitigate this impact by limiting the quantity of allowances allocated in the ARP annual allowance auction. [EPA-HQ-OAR-2009-0491-2742.1, p.4]
Because of the existing massive surplus of Title IV allowance, restricting the quantity of Title IV allowances would provide benefits regardless of the direction the EPA ultimately pursues regarding the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2742.1, p.5]
The Administrator should initiate a separate new stand alone to institute a new mechanism to link the quantity of Title IV allowances auctioned annually by the EPA to the quantity of previously unused (aka Banked) Title IV allowances. For example, if the quantity of banked Title IV allowances is greater some percentage (say 20%) of the current year's Title IV allocation, allowances that would ordinarily be introduced into the market through the annual auction would be withheld. A 'Title IV Allowance Auction Quantity' rule should be undertaken separate from the Proposed Transport Rule to prevent its demise if the Proposed Transport Rule is struck down during judicial review. [EPA-HQ-OAR-2009-0491-2742.1, p.5]
While the quantity of allowances auctioned in the Title IV program may seem small relative to the existing bank and/or annual allocation, the cumulative effect of withholding this supply over multiple years would not be insignificant. Under the Title IV program, 250,000 additional allowances are introduced each year trough the annual auction. While, the annual incremental quantity of these allowances represent a modest percentage relative to the approximately 9 million allowances allocated each year, their cumulative effect can be substantial. Elimination of the 250,000 allowances that are introduced each year beginning 2011 through the last analytical year (2030) would prevent the Title IV bank from building by approximately 5 million tons. [EPA-HQ-OAR-2009-0491-2742.1, p.5]
It simply dose not make any sense to continue to inject a new supply of Title IV allowances into the market that is already significantly oversupplied. I request that the EPA Administrator initiate a new rulemaking proceeding to establish a mechanism for limit the quantity of new Title IV ARP allowances which are introduced into the market each year thought the annual allowance auction. [EPA-HQ-OAR-2009-0491-2742.1, p.5]
7. Pollution by Wire - The EPA's preferred FIP creates perverse economic incentive to Electric Generating Units ('EGU') located outside of the proposed Sulfur Dioxide ('SO2') control regions to increase emissions. [EPA-HQ-OAR-2009-0491-2742.1, p.5]
The Proposed Transport Rule would operate concurrently with the existing Acid Rain Program ('ARP') created by Congress in 1990 through Title IV of the Clean Air Act ('CAA'). As proposed the preferred FIP would establish a new separate allowance 'currency' for SO2 emissions. Since the Proposed Transport Rule will allocate fewer allowances (i.e. the emission cap) than the existing ARP allocation, there will be less S02 emissions inside the proposed SO2 control regions. However, since the ARP allowance allocation which was explicitly set by Congress as part of the CAA amendments of 1990 will not be lowered commensurate with the Proposed Transport Rule allowance allocations, the de facto impact will be a net increase in the quantity of ARP allowances that are available for use with compliance with the ARP. [EPA-HQ-OAR-2009-0491-2742.1, p.5]
[For additional comments pertaining to Pollution by Wire, see pages 5-7 of this comment.]
Response: 
EPA's analysis accounted for the impacts of the Transport Rule on emissions from states outside of the programs.  EPA did not find that the Transport Rule would lead to any meaningful increases in SO2 or NOx emissions outside of the covered states. 
Organization: PPG Industries, Inc.
Comment: 
PPG Industries, Inc.
  EPA's proposed NOx allowances would provide the RS Cogen units with less than 5% of the allowances that they need to operate at the levels they have operated at for the past 5 years and intend to operate at in the forseeable future. These units are well controlled with low NOx burners and an SCR system. To meet the requirements of the proposed FIP, PPG may have to expend a million dollars per year or more to acquire NOx allowances. For this reason, PPG has spent a great deal of time in trying to understand the basis for EPA's proposed allocation scheme, but this has been difficult due to the tremendous volume of technical support data and lack of transparency concerning the assumptions used by EPA in their IPM runs upon which the rule is based. [EPA-HQ-OAR-2009-0491-1926.1, pp.1-2]
The NOx Allowance Allocations for the RS Cogen Units Are Wholly Insufficient and Based Upon Flawed Modeling and Projections. It is arbitrary and capricious for EPA to provide unit-level allocations based upon the Integrated Planning Model (IPM). EPA's proposed NOx allowance allocations would provide the RS Cogen units with less than 5% of the allowances that they need to operate at the levels they have operated at for the past 5 years and intend to operate at in the foreseeable future. These units are well controlled with low NOx burners and an SCR system. They are critical to meeting PPG's electrical demand and continued manufacturing operations. PPG has invested heavily in the construction and maintenance of these units, which went on-line in 2002.  To meet the requirements of the proposed FIP, PPG may have to expend a million dollars per year or more to acquire NOx allowances.18 For this reason, PPG has spent a great deal of time in trying to understand the basis for EPA's proposed allocation scheme, but this has been difficult due to the tremendous volume of technical support data and lack of transparency concerning the assumptions used by EPA in their IPM runs upon which the rule is based. PPG is diligently reviewing updates to the IPM announced in the September 1, 2010 Notice of Data Availability, but to date cannot understand why that IPM v.4.10 projects such limited operation of the RS Cogen units. PPG's manufacturing operations depend on the steam and electricity produced from the RS Cogen units. There is no reason to expect the curtailed operation predicted by the IPM. [EPA-HQ-OAR-2009-0491-2763.1, p. 11]
As indicated in the table above, RS Cogen has been significantly under-allocated both in comparison with actual operations and also with the final allocations under CAIR. It should be noted that the CAIR allocations are based on a Louisiana SIP approved by EPA. As an alternative to the CATR, EPA could make NOx allocations (both annual and ozone season) in the same relative percentages to the state budget that Louisiana used under the CAIR allocations. PPG does not believe there are any significant new sources that would cause a need to substantially revise that ratio. [EPA-HQ-OAR-2009-0491-2763.1, p. 14, see p. 14 for the table.]
The IPM based unit-level allocations are illogical and unfair. PPG's RS Cogen units are less than 10-year old, highly efficient gas turbines equipped with both low NOx burner technology and selective catalytic reductions (SCR) post-combustion control technology. The allocations provided by EPA under the proposed CATR FIP penalize these units even though they are some of the most efficient and lowest-polluting units. Projecting the cost of purchasing allowances is difficult as their costs will be market driven. In addition, allowance costs may vary widely based on the trading scheme chosen for the final rule. However, based on historical costs from CAIR trading, the additional annual cost for allowances for the RS Cogen units could well exceed one million dollars annually. Adding additional control to these units is not likely to be effective since they are already efficient and aggressively controlled. As EPA is aware, cost per ton for NOx control rises exponentially with additional control and reaches the point of diminishing returns after the control technology currently in place for these units. EPA has simply provided no rational basis for this inequitable treatment for the RS Cogen units. [EPA-HQ-OAR-2009-0491-2763.1, pp. 14-15]
PPG urges EPA to abandon its proposed unit-level allocations and allow Louisiana DEQ to make allocations through a state SIP, if it is finally concluded that a SIP is even needed to address interstate transport of PM2.5 and/or ozone precursors. In the alternative, EPA should substantially revise the allocations under the FIP and re-propose such allocations for further comment. [EPA-HQ-OAR-2009-0491-2763.1, p. 15]
Comments on Non-Applicability of Proposed Rule to PPG Powerhouse C Units.  PPG Powerhouse C units C1, C2, C3, C4 and C5 are listed in the proposed allocation table under ORIS code 50489. Each unit has proposed NOx allocations under the CATR as follows: [EPA-HQ-OAR-2009-0491-2763.1, p. 15; see p. 15 for allocation table.]
Units C1, C2, C4 and C5 all meet the criteria for not selling more than the greater of one-third of the potential electrical output capacity (PEOC) or 219,000 MWh to any utility power system since November 15, 1990. Therefore, PPG Powerhouse C1, C2, C4 and C5 units -are not subject to the proposed CATR and are not TR NOx Annual Units. [EPA-HQ-OAR-2009-0491-2763.1, p. 17; see pp. 15-17 for extensive discussion of this issue.]
The PPG Powerhouse C unit C-3 is a steam turbine that does not, by itself fall within the definition of TR NOx Annual unit, the definition of TR NOx Ozone unit or the definition of TR SO2 Unit under the proposed CATR because it is not a fossil-fuel fired unit.  [EPA-HQ-OAR-2009-0491-2763.1, p. 17; see pp. 15-17 for extensive discussion of this issue.]
Without waiving any legal rights to contest the necessity for the proposed FIP or any part thereof, PPG also requests that EPA abandon the use of the IPM-based method for allocation of unit-level NOx allowances. Further, to the extent EPA relies upon the IPM for any purpose, it should correct all of the data errors noted herein.  [EPA-HQ-OAR-2009-0491-2763.1, p. 19]
Response: 
Thank you for your comment.Organization: Prairie State Generating Company, LLC
Comment: 
Prairie State Generating Company, LLC
2. ALLOCATIONS FOR NEW UNITS
If the U.S. EPA is not willing to expand the definition of what comprises 'existing' units to include those that are permitted, funded, and under construction by January 1, 2012, and will have commenced commercial operation by January 1, 2014, the Transport Rule should provide permanent allocations for 'new units' as quickly as possible after they commence commercial operation. [EPA-HQ-OAR-2009-0491-2842.1, pp.2-3]
In the U.S. EPA's proposal, allocations to existing units are permanent and new units must forever obtain allowances from the New Unit Set-Aside ('NUSA'). pp. 45309-45310. PSGC is concerned that there will be insufficient allowances available for new units because of the restrictions on trading the U.S. EPA believes is necessary to respond to the court's order in North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008). [EPA-HQ-OAR-2009-0491-2842.1, p.3]
PSGC proposes that 'new' units become 'existing' units at some point in time, preferably as soon as possible. Since the U.S. EPA proposes to allocate allowances three years in advance of their vintage date, PSGC proposes that 'new' units should become 'existing' units in the fourth year after the new unit commences commercial operation. [EPA-HQ-OAR-2009-0491-2842.1, p.3]
PSGC recognizes that the U.S. EPA may not be willing to expand the statewide budgets to provide allowances for 'new existing' units. However, there are potential sources of allowances for 'new existing' units:
a. The allocations for all 'existing' units in a state could be adjusted to provide allowances for the 'new existing' unit, thereby maintaining the state's cap.
b. In the alternative, allowances normally allocated to the NUSA could be made permanent allocations to the 'new existing' unit.
c. Adjust current allocations to existing units to account for federal and state agreements already in place, including to units which are required to be shut down as a result of those agreements and where the agreements restrict trading. [EPA-HQ-OAR-2009-0491-2842.1, p.3]
Consistent with this suggested alternative, PSGC proposes that 'existing' units that shut down should not receive their allocations beginning in the fourth year after their shutdown, rather than in the seventh as EPA has proposed. Additionally, there should be some other mechanism besides non-operation to trigger unit allowance reduction or elimination, thereby increasing the size of the NUSA and of allowances available for 'new existing' units. [EPA-HQ-OAR-2009-0491-2842.1, p.3]
The U.S. EPA has proposed that units shut down more than three years that are then restarted are to be treated as 'new' units. Because the U.S. EPA has proposed that shutdown units receive allowances for six years following their shutdown, theoretically a unit could shut down in year 1 and start up again in year 4 or 5 as a new unit, thus making it eligible to receive both its 'permanent' allocation plus allowances from the NUSA. PSGC suggests that EPA prohibit this potential for double-dipping. [EPA-HQ-OAR-2009-0491-2842.1, p.3]
One way to prohibit such double-dipping is as PSGC has suggested: shutdown units should receive their 'permanent' allocations for only the three years for which it would have been allocated allowances in advance (except for those units that are shut down prior to January 1, 2012 which should not receive any). That is, the unit would have received allowances in year 1 for year 4, year 2 for year 5, and year 3 for year 6. If it shuts down in year 3, it has already received allocations for years 3, 4, and 5 and should not receive an allocation for year 6 and thereafter. [EPA-HQ-OAR-2009-0491-2842.1, p.3]
3. SIZE OF THE NUSA
The U.S. EPA has proposed that the NUSA be 3% of the state's emissions cap (without the variability limit). p.45310. The U.S. EPA determined that 3% was the appropriate size for the NUSA because it predicts that there will be new generation equal to 3% of the existing generation in the entire region. Id. However, the U.S. EPA's assignment of the NUSA failed to consider the location of the predicted new generation. That is, the U.S. EPA's analysis and ultimate assignment of a 3% NUSA to each state does not reflect what is actually projected for each state, thereby creating inequities across the region, in part because of the constraints inherent with the application of the variability limits. [EPA-HQ-OAR-2009-0491-2842.1, p.4]
The IPM projected that there will be a significant increase in electrical demand in Illinois. The IPM accounted for alternative types of generation, including, among others, wind, nuclear, biomass, and so forth on a regional basis. However, the U.S. EPA did not provide sufficient data for PSGC to determine whether a 3% NUSA is sufficient to meet Illinois' new demand and whether the alternative sources of energy are sufficiently reliable to meet that demand. Coal-fired energy is reliable and could be sufficient to meet the new demand. [EPA-HQ-OAR-2009-0491-2842.1, p.4]
PSGC suggest that the NUSA be appropriate for the units currently under construction rather than randomly selected based on the entire region. [EPA-HQ-OAR-2009-0491-2842.1, p.4]
In the alternative, PSGC suggests that the U.S. EPA provide for more flexibility in the variability limits as they apply to states with new units, particularly if the gross new generation is in excess of 3% of the statewide cap. [EPA-HQ-OAR-2009-0491-2842.1, p.4]
The U.S. EPA should ensure that there are enough allowances accumulated in the NUSA to accommodate the additional emissions from new units. New units are likely to be more efficient and less polluting and so should be encouraged to be developed and operated. [EPA-HQ-OAR-2009-0491-2842.1, p.4]
4. BASIS OF ALLOCATIONS
The U.S. EPA has based allocations on actual 2009 emissions projected to 2012, incorporating the reductions that will occur with planned emission controls and required emission reductions. PSGC believes this approach creates unacceptable inequities. Both weather conditions and the economy caused 2009 to be a low utilization year and an inappropriate base year for determining allowance allocations. [EPA-HQ-OAR-2009-0491-2842.1, p.4]
Further, the U.S. EPA's reliance on emissions as the basis for determining allocations rewards sources that deferred controls under previous programs, perhaps preferring to buy allowances rather than to invest in pollution control equipment. At the same time, this approach effectively penalizes sources that have invested in and operated pollution controls and units that are very efficient. [EPA-HQ-OAR-2009-0491-2842.1, p.4]
In the case of PSGC, a merchant plant, it penalizes PSGC for being a state-of-the-art, extremely well-controlled, very efficient plant, because the PSD permit limits, which would have to be the basis of allocations to PSGC, already incorporate operation of the pollution control equipment and the efficiencies of the new plant. To further 'ratchet' the PSGC units downward in their allowance allocations on the basis of emissions projected directly or indirectly by the IPM confers unfair economic and competitive advantages to PSGC's competitors. [EPA-HQ-OAR-2009-0491-2842.1, p.4]
PSGC requests that the U.S. EPA base allocations on either gross megawatt output or heat input, of which PSGC prefers gross megawatt output. Either approach would level the playing field among generators, something that the U.S. EPA's approach clearly does not do, as the U.S. EPA acknowledges. p. 45311. However, basing allocations on gross megawatt output would reward efficiencies and encourage electrical dispatch of newer, better-controlled plants as well as improvements in efficiencies at older plants. [EPA-HQ-OAR-2009-0491-2842.1, p.5]
In Illinois, state rules limit emissions from certain plants. Those plants should not be allocated allowances in excess of their agreements reflected in state rules, particularly where those rules preclude emissions trading despite the proposal for limited interstate trading in the Transport Rule. [EPA-HQ-OAR-2009-0491-2842.1, p.5]
5. NUMBER OF ALLOWANCES THAT SHOULD BE ALLOCATED TO PSGC
PSGC should receive 2,282 annual NOx allowances for Unit 1 and 2,282 annual NOx allowances for Unit 2.
PSGC should receive 957 seasonal NOx allowances for Unit 1 and 957 seasonal NOx allowances for Unit 2.
PSGC should receive 5,933 SO2 allowances for Unit 1 and 5,933 SO2 allowances for Unit 2. [EPA-HQ-OAR-2009-0491-2842.1, p.5]
PSGC was issued a PSD permit on April 28, 2005, that includes emissions caps that reflect operation of a state-of-the-art, extremely well-controlled, very efficient coal-fired power plant. At the time the caps were developed, they reflected what the designers of the plant and the permitting authority determined was best available control technology limits ('BACT'). Moreover, these caps were developed in cooperation with the Federal Land Manager and determined to be protective of the downwind wilderness area that could otherwise have been affected by the plant. Additionally, projected emissions from the plant have been modeled to determine whether they would negatively impact downwind areas. The plant has been designed and constrained through its PSD permit so that downwind impacts would not occur. Therefore, the downwind impacts of this plant in particular have already been assessed and addressed at the level of the enforceable emission caps contained in the PSD permit. [EPA-HQ-OAR-2009-0491-2842.1, p.5]
Moreover, an examination of the data that EPA has posted indicates that the planned-committed coal-fired generation modeled for the Gateway Region was not attributable to any specific units. The level of this generation was approximately equivalent to PSGC's projected generation. Therefore, allocating allowances to PSGC in the amounts requested has already been included in the U.S. EPA's evaluation of downwind impacts and poses no potential disruption to the overall analysis. Documentation for EPA `s Basecase v.4.10, Ch. 4, Table 4-12, p. 4-14. Essentially, the U.S. EPA analyzed emissions from 'planned-committed' and new units on a regional basis, but must implement the program on the basis of political boundaries, yielding inconsistencies between the two analytical boundaries. [EPA-HQ-OAR-2009-0491-2842.1, p.5]
The U.S. EPA announced in the Preamble to the proposal that it views the Transport Rule to be a template for addressing the requirements of the Clean Air Act § 110(a)(2)(D) as new national ambient air quality standards ('NAAQS') are developed or existing NAAQS are revised. p. 45213. When this occurs, it is reasonable to expect that the number of allowances assigned to each unit will be reduced. Since PSGC is already extremely well-controlled and since all the alternatives that the U.S. EPA has proposed restrict or even preclude emissions trading, PSGC, already subject to BACT limits, may not be able to further control in order to comply with future amendments to the proposal. Therefore, assigning PSGC with at least the number of allowances corresponding to the emissions caps in its PSD permit is reasonable and protective of the environment. [EPA-HQ-OAR-2009-0491-2842.1, pp.5-6]
10. GENERAL CONCERN WITH THE BUDGETS
In proposed Appendix A, the U.S. EPA has listed the proposed allocations for each unit as well as the emission rates that would be assigned under the Direct Control option. p.45310. In the Technical Support Document ('TSD') addressing state budgets and unit allocations, the U.S. EPA claims the NOx, budgets were projected on emission rates of no less than 0.06 lb/mmBtu, because this is the lowest rate the U.S. EPA believes is attainable by new SCRs. State Budgets, Unit Allocations, and Unit Emissions Rates, TSD, p. 6. Additionally, the U.S. EPA says the rates assigned under the Direct Control option were based upon projected emissions. p. 45330. If the U.S. EPA were to adopt the Direct Control option, sources would remain subject to the same mass caps comprising the statewide budgets proposed for the U.S. EPA's 'preferred' option in addition to the rate limitations of the Direct Control option. Therefore, the rates of the Direct Control option appear to generally reflect the rates that the U.S. EPA projects units will have to achieve in order to comply with the statewide budgets. [EPA-HQ-OAR-2009-0491-2842.1, p.8]
Some of the assigned rates are less than 0.06 lb/mmBtu, and in some cases, the assigned rates are considerably less than 0.06 lb/mmBtu. See, e.g., Baldwin Units 1 and 2 (0.047 and 0.046, respectively), Havana Unit 9 (0.028), Marion Unit 4 (0.031), Powerton (0.058). The fact that some of the rates are less than 0.06 lb/mmBtu and that some are so much lower than 0.06 lb/mmBtu calls into question the validity of the statewide caps. If the Direct Control rates were back-calculated from the projected emissions that are the basis of the caps and those rates are below 0.06 lb/mmBtu, then the caps must be unattainable. [EPA-HQ-OAR-2009-0491-2842.1, p.8]
Allowances for PSGC have not been incorporated into Illinois' statewide budgets, but PSGC requests the U.S. EPA to recognize and allocate allowances to both Unit 1 and Unit 2, whose construction is well underway, as existing units, with the effect of increasing Illinois' budgets by those amounts. 3  The number of allowances in the NUSA and in the variability limits are directly dependent upon the size of the statewide budgets. If the U.S. EPA has been overly aggressive in establishing the appropriate levels of the budgets, PSGC is directly affected because the sizes of the NUSAs and variability limits will be less than they should be. PSGC's permitted NOx rate is 0.07 lb/mmBtu. As a new plant, its SCRs are also new and will operate better than SCRs installed years ago, exacerbating PSGC's concerns with the statewide budget that the U.S. EPA proposes. [EPA-HQ-OAR-2009-0491-2842.1, pp.8-9]
The data that the U.S. EPA has provided is insufficiently detailed for sources to determine the veracity of the results of the modeling. Moreover, a 60-day comment period is insufficient for sources to review modeling inputs once the U.S.. EPA makes them available. Evaluation of the modeling inputs requires expert analysis. As a result, it is infeasible for sources to realistically comment on the budgets and the allocations to individual units. [EPA-HQ-OAR-2009-0491-2842.1, p.9]
Additionally, PSGC, as a new plant, is very concerned with whether there will be sufficient allowances available. PSGC is not only concerned that the NUSA will not be sufficient but also that the allowance market will not be robust. PSGC is very concerned that the constraints on trading and the stringency of the reductions will cause sources to hoard their allowances. The U.S. EPA should encourage the operation of new, efficient plants such as PSGC rather than effectively penalize them through market constraints. Adding PSGC's emissions allocations to the current state budget and higher, more reasonable variability limits could help to effectuate this goal. [EPA-HQ-OAR-2009-0491-2842.1, p.9]
11. ALLOCATION METHODOLOGY
The U.S. EPA requested comment on its proposed allocation methodology that keeps all EGUs subject to the program, i.e., those serving generators with nameplate capacities greater than 25 MWe, in a single group as opposed to grouping EGUs according to size or percentage of generation in a state. pp. 45311-45312. PSGC agrees that EGUs should not be subgrouped and treated differently depending upon their group placements. [EPA-HQ-OAR-2009-0491-2842.1, p.9]
Moreover, PSGC believes that allocations based preferably on electrical output (or heat input) would offer a more equitable basis for allocations than projected emissions that incorporate planned and implemented pollution controls. A heat input- or electrical output-based allocation methodology would create a more level playing field among electrical generating units ('EGUs') in that those who deferred installation of controls would not be rewarded with more allowances because their emissions were higher during the base-year period. Likewise, those units that are controlled and are more efficient would not be placed at a disadvantage because of their improvements or, as in the case of PSGC, their initial design caused them to emit less. Using gross megawatt output would reward efficiencies while using heat input would not penalize early controllers. Either approach would level the playing field among generators, with gross electrical output actually rewarding efficient units, thereby promoting the operation of newer, highly controlled units to the benefit of the environment. [EPA-HQ-OAR-2009-0491-2842.1, p.9]
The U.S. EPA also requested comment on an allocation methodology that assumes operation of identified control measures and state and federal requirements in 2012 and 2013 and without variability limits. p. 45315. As stated above, PSGC believes that an allocation methodology based on heat input or electrical output would be more equitable than one based on projected emissions that automatically reflects reductions not required by rule that occurred prior to 2012. Early reducers and greater operational efficiencies should be rewarded, not penalized. [EPA-HQ-OAR-2009-0491-2842.1, p.9]
PSGC recognizes the U.S. EPA's stated interpretation of the North Carolina decision is to require reductions in the 2012-2013 timeframe. Perpetuating the approach that penalizes early reducers or low emitters and rewards those who delayed, however, is not an equitable approach or the approach that is best for the environment. The 2012 base-case upon which allowances are proposed includes adjustments intended to reflect reductions that are required by states and consent decrees and that can be achieved by currently-installed control equipment that is not otherwise required to be operated. That allocation base-case is less than the projected 2012 base-case that reflects only emissions projected to 2012 without assuming operation of installed control equipment not otherwise required to be operated. PSGC suggests that the U.S. EPA apply that percentage of reduction in either the overall region-wide budget or on a state-by-state basis and then allocate allowances to existing units pro-rata based on gross electrical output (or heat input). The exception to this is sources such as PSGC that are new but 'existing' and have permits that require them to be extremely well-controlled. Such sources' allocations should be equal to those permit limits. In PSGC's case, the permit includes emission caps already approved by the U.S. EPA through the PSD permitting process that should be honored in this rulemaking. This approach would put all EGUs, including 'new existing' EGUs such as PSGC, on an equal footing on a going-forward basis. [EPA-HQ-OAR-2009-0491-2842.1, pp.9-10]
13. ALLOWANCE SURRENDER FOR EXCESS EMISSIONS AND EMISSIONS IN EXCESS OF THE VARIABILITY LIMITS
The U.S. EPA requested comment regarding the number of allowances to be surrendered for failure to hold sufficient allowances in a source's compliance account on the date of true-up. p. 45314. The U.S. EPA proposes that the sources surrender an allowance for each ton of excess emissions plus an additional allowance per excess ton as an automatic penalty. p. 45314. Additionally, the source is potentially subject to discretionary enforcement action, including statutory penalties, for each ton of excess emissions. p. 45314. PSGC agrees that the surrender of one allowance for each ton of excess emissions as an automatic penalty is appropriate. [EPA-HQ-OAR-2009-0491-2842.1, p.10]
The U.S. EPA also requested comment on whether the proposed surrender of one allowance for each ton of emissions in excess of a unit's share of the state's variability limit, if statewide emissions are in excess of the statewide variability limit, is appropriate. p. 45314. PSGC agrees that the surrender of one allowance per ton of emissions equaling the owner's share of the total in excess of the variability limits is reasonable. PSGC also supports the U.S. EPA's proposal that exceedance of the variability limits not be violation of the Clean Air Act. [EPA-HQ-OAR-2009-0491-2842.1, p.10]

 3. On September 28, 2010, PSGC submitted its data for updating the NEEDS database to the docket and to the Clean Air Markets Division. [EPA-HQ-OAR-2009-0491-2842.1, p.8]
Response: 
Thank you for your comment.Organization: Progress Energy Service Company
Comment: 
Progress Energy Service Company
Progress Energy recommends that EPA allow units to borrow allowances from future years for use in compliance. This would provide increased flexibility, which will be particularly important in the early years of the program. This flexibility will be especially important if EPA promulgates a final rule that includes the ambitious compliance schedule that it proposes. [EPA-HQ-OAR-2009-0491-2831.1 p.8]
Response: 
EPA believes that borrowing allowances from future control periods would contradict the mandate underlying the Transport Rule programs, which is to eliminate significant contribution to nonattainment and interference with maintenance as expeditiously as practicable.  EPA's power sector modeling show that far from needing future control period allowances, most states are capable of overcomplying with their 2012 emission budgets and thus establishing a bank of allowances to carry forward for year-to-year flexibility under the programs where needed.  EPA's prior trading programs, including the ARP, NOx SIP Call, and CAIR, have not included an allowance borrowing feature and have revealed no flaw for lacking such a feature; on the contrary, all of those programs have established substantial allowance banks near their outset. Additionally the final Transport Rule is designed to ensure that states achieve highly cost-effective emission reductions on a schedule compatible with attainment deadlines in downwind states. Allowing borrowing of allowances from future control periods would risk undermining that schedule by allowing EGUs to delay emission reductions beyond the time in which they are required to eliminate significant contribution to nonattainment and interference with maintenance in downwind states.
Organization: Public Power Generation Agency
Comment: 
Public Power Generation Agency
Allowance Allocation for WEC Unit 2
According to the PTR and technical support documents ('TSDs') associated with it, Nebraska is a 'Group 2 state' and the PTR bases the nitrogen oxide ('NOx') and sulfur dioxide ('SO2') allowance allocations for Nebraska existing units on their 2009 'reported' emissions. Because WEC Unit 2 was not in commercial operation in 2009, it of course did not report any emissions in 2009. Neither the PTR nor the TSDs describe a specific methodology to calculate allowances for a unit that did not operate in 2009 and was not included in the IPM projections, yet meets the definition of an existing unit that will be in commercial operation before 2012. [EPA-HQ-OAR-2009-0491-2705.1,p.5]
In the absence of any other methodology or guidance on the issue, PPGA believes that its NOx and SO2 allowance allocations should be calculated and based on the information contained in its PSD permit. The permitted SO2 emission rate limit in the PSD permit is 0.12 lb/MMBtu and the permitted NOx emission rate limit is 0.08 lb/MMBtu (30-day rolling averages). The heat input capacity of WEC Unit 2 is 2,211 MMBtu/hr. These emission rates and heat input translate into annual emissions of 1,162 tons of SO2 and at least 775 tons of NOx. The emission rates and heat input - and annual emissions calculated from those two parameters -- were the basis ofWEC Unit 2's PSD permit, and allocation of PTR allowances should be based on these amounts, minus the 3% new source set aside. Accounting for the new source set aside, WEC Unit 2 should be allocated 1,127 SO2 allowances and at least 752 NOx allowances in the final rule.8 [EPA-HQ-OAR-2009-0491-2705.1,pp.5-6]
Counsel for PPGA contacted EPA's Clean Air Markets Division on multiple occasions to discuss an appropriate methodology for allocating allowances for WEC Unit 2, but no guidance or suggestions were provided by EPA. To the extent EPA may have a different view as to the appropriate allowance allocation from the position stated in these comments, PPGA respectfully requests that EPA provide its view and the specific basis for any alternative allocation methodology. PPGA would also be willing to meet with EPA prior to promulgation of the final rule to discuss any questions concerning the appropriate allowance allocation for WEC Unit 2. [EPA-HQ-OAR-2009-0491-2705.1,p.6]

8 If the NOx emission rate is raised to 0.12 lb/MMBtu, WEe Unit 2 should be allocated 1,127 NOx allowances.
Response: 
Thank you for your comment.Organization: Santee Cooper
Comment: 
Santee Cooper
Santee Cooper supports the limited interstate trading approach over EPA's alternative remedies because it allows electric generating units (EGUs) to achieve the emissions reductions and environmental objectives in the least cost manner that are within the constraints of the law. [EPA-HQ-OAR-2009-0491-2820.1, p.2]
EPA should eliminate the prohibition on trading of SO2 allowances between Group 1 and Group 2 states. The prohibition is not mandated by law, is economically inefficient, and has no environmental benefits. [EPA-HQ-OAR-2009-0491-2820.1, p.2]
EPA should extend the allowance transfer deadline for the annual SO2 and NOx emissions trading programs by an additional month. [EPA-HQ-OAR-2009-0491-2820.1, p.2]
EPA's proposed methodology for allocating allowances to existing affected W1itsis neither mandated by the statute (as interpreted by court decisions) nor establishes a reasonable method for allocating allowances to affected W1its within a state. In the case of Santee Cooper, EPA's allocations are completely inadequate to accommodate anticipated growth in electricity demand within our service territory. Like the states themselves, EPA has significant discretion to adopt an alternative allocation methodology that results in more logical assignments to individual EGUs. [EPA-HQ-OAR-2009-0491-2820.1, p.2]
If EPA decides to use the proposed allowance allocation methodology for existing affected units, the assumptions and data used for calculating the allowance allocations need to be corrected within the Santee Cooper system. [EPA-HQ-OAR-2009-0491-2820.1, p.3]
To avoid penalizing utilities that have already invested heavily in controlling emissions from their EGUs, EPA should consider adopting an alternative approach for allocating allowances to existing affected units based on 'well controlled' emissions benchmarks and historic baseline activity levels. [EPA-HQ-OAR-2009-0491-2820.1, p.3]
In the event that EPA chooses not to adjust the compliance deadlines for the Transport Rule and thus prevents states from submitting revised SIPs, EPA should at least solicit each state's preferences as to allowance allocation methodology and incorporate those preferences into each state's FIP. States could submit these allocation preferences to EPA on an informal basis before the finalization of the Transport Rule rather than as part of a full-blown SIP revision. [EPA-HQ-OAR-2009-0491-2820.1, p.3]
THE PROPOSED PROHIBITION ON TRADING OF S02 ALLOWANCES BETWEEN GROUP 1 AND GROUP 2 STATES IS ECONOMICALLY INEFFICIENT AND HAS No ENVIRONMENTAL BENEFITS [EPA-HQ-OAR-2009-0491-2820.1, p.5]
As proposed, the Transport Rule would establish two groups of states for purposes of interstate trading of SO2 allowances - a 'Group 1' consisting of states that would be required to achieve more stringent SO2 reductions in 2014 to fully address downwind air quality problems, and a 'Group 2' consisting of states that would be held to less costly and stringent SO2 reductions beginning in 2012. Trading of SO2 allowances among EGUs in different groups would be prohibited, even though the two groupings are not geographically contiguous. For example, the proposed rule would prohibit Santee Cooper's EGUs in South Carolina (a Group 2 state) from trading allowances with EGUs in the neighboring states of Georgia and North Carolina (both Group 1 states), even if doing so would prove more cost-effective than trading with EGUs in other, more distant Group 2 states. [EPA-HQ-OAR-2009-0491-2820.1, p.5]
Santee Cooper believes the proposed prohibition on trading among Group 1 and Group 2 states is arbitrary because it has no environmental benefit and could even have counterproductive impacts by forcing trading between EGUs located in two distant Group 2 states. As noted above, the prohibition against trading with neighboring Group 1 states will force Santee Cooper to trade allowances with EGUs located in far-off states, including Connecticut, Delaware, Kansas, Massachusetts, Nebraska and New Jersey. In addition, the proposed prohibition makes compliance with the Transport Rule needlessly costly and complex. With respect to SO2 emissions, the proposed Transport Rule already ensures that each state addresses its significant contributions to downwind nonattainment, or interference with maintenance of attainment, through the imposition of strict state-specific SO2 emission budgets (with variability limits on trading). The variability limits provide the necessary assurances that states achieve within the state the emissions reductions that are necessary to eliminate significant contribution. In other words, compliance with Section II0(a)(2)(D) of the Clean Air Act is assured so long as EGUs within a given state submit a quantity of SO2 allowances that falls within that state's budget. Whether those allowances were originally allocated within a Group 1 or Group 2 state simply has no bearing on the environmental performance of the Transport Rule. [EPA-HQ-OAR-2009-0491-2820.1, pp.5-6]
However, the prohibition on trading between Group 1 and Group 2 states does affect the cost of the Transport Rule. The most economically efficient way to meet the objectives of the Transport Rule is for EGUs that face the lowest cost of abatement (whether they be located in Group I or Group 2 states) to reduce their SO2 emissions. Yet under the proposed rule, an EGU in a Group 1 state that cost-effectively reduced its SO2 emissions could not sell its excess allowances to an EGU in a Group 2 state, or vice versa. The impediments to efficient trading are aggravated by the geographic distribution of Group 1 and Group 2 states; as a South Carolina utility, Santee Cooper expects that it would have significant opportunities to trade with utilities in the neighboring states of Georgia and North Carolina. These opportunities would be blocked - with no apparent environmental benefit - under EPA's proposal. Santee Cooper therefore urges EPA to dispense with the ban on trading between Group 1 and Group 2 states in the final version of the Transport Rule. [EPA-HQ-OAR-2009-0491-2820.1, p.6]
EPA HAS FAILED TO RECOGNIZE THE BROAD DISCRETION CONVEYED WITH REGARD TO THE ALLOCATION OF ALLOWANCES TO AFFECTED UNITS UNDER THE TRANSPORT RULE. [EPA-HQ-OAR-2009-0491-2820.1, p.9]
In contrast to the development of state emission budgets (as discussed in the previous section), we believe that EPA has significant discretion to determine the best method for allocating allowances to individual EGUs within each state. Neither the statute nor the D.C. Circuit's opinion in North Carolina require EPA to allocate allowances to EGUs on the basis of modeled or measured emissions, as EPA has proposed to do. First, North Carolina's discussion of the CAIR emission budgets did not, of course, place any explicit constraint on the method for allocating each state budget among individual emitting units - requiring EPA to instead only 'evaluate contributing emissions on a state-by-state basis.' Second, if North Carolina were interpreted to require individual EGU allocations to be based on projected emissions (as suggested by EPA in the proposed Transport Rule), then the necessary implication is that any SIP that does not make EGU allocations on this basis is somehow inconsistent with Section 110(a)(2)(D). We do not believe EPA can justify an interpretation of the statute that so narrowly constrains each state's allocations to individual EGUs. And if states have authority to prescribe alternative allocation methodologies in their SIPs, then EPA a fortiori has that same authority in prescribing a FIP under the Transport Rule. In Section II below, we urge EPA to exercise this discretion by adopting an allocation method that better accommodates projected growth and is more equitable to units that have already made costly pollution control investments. [EPA-HQ-OAR-2009-0491-2820.1, p.9]
EPA SHOULD EXTEND THE ALLOWANCE TRANSFER DEADLINE BY AN ADDITIONAL MONTH. [EPA-HQ-OAR-2009-0491-2820.1, p.17]
Under the proposed Transport Rule, the date by which affected units must surrender annual NOx, seasonal NOx, and annual SO2 allowances to cover their emissions - the 'allowance transfer deadline' - is March I after the relevant control period. Santee Cooper respectfully requests that EPA modify this deadline to April I in the final version of the Transport Rule. [EPA-HQ-OAR-2009-0491-2820.1, p.17]
An April deadline would ease the administrative burdens on both the regulated entities and the regulators. Practically all affected units under the Transport Rule are also covered units under the Title IV Acid Rain Program, and must hold Title V permits. Accordingly, these units already must comply with a series of data submission requirements in the first months of the year. Santee Cooper, for example, faces: (1) an annual January 30 deadline for fourth quarter Electronic Data Reporting under the Acid Rain Program, and submission of a Title V semi-annual report to the South Carolina Department of Health and Envirornnenta1 Control (S.c. DHEC); (2) an annual February 15 deadline for submitting a 'long form' Title V annual compliance report to S.C. DHEC; and (3) an annual March 1st allowance transfer deadline for the Acid Rain Program. In light of these existing report and data submission deadlines, it would be significantly easier for entities such as Santee Cooper to have an April 1 allowance transfer deadline under the CATR. [EPA-HQ-OAR-2009-0491-2820.1, p.17]
Furthermore, the shift from March to April would have no environmental impacts; an affected unit would still be required to hold allowances to cover its emissions in the relevant control period. The modification only would apply to accounting, not environmental performance. [EPA-HQ-OAR-2009-0491-2820.1, p.18]
Establishing an April 1 deadline falls well within the authority of the EPA and its broad discretion to design a regulatory program that is administratively manageable. While the Clean Air Act specified a March I deadline for the Acid Rain Program, the statute is silent on the deadline for allowance reconciliation for an emissions trading program to address interstate pollutant transport pursuant to section 110(a)(2)(D). [EPA-HQ-OAR-2009-0491-2820.1, p.18]
For the above reasons, Santee Cooper respectfully urges EPA to shift the allowance transfer deadline for the CATR trading programs to April 1. [EPA-HQ-OAR-2009-0491-2820.1, p.18]
COMMENTS ON PROPOSED ALLOWANCE ALLOCATIONS TO SANTEE COOPER [EPA-HQ-OAR-2009-0491-2820.1, p.18]
As discussed above in Section I, Santee Cooper supports EPA's proposed approach for setting the state emissions budgets based state-specific factors that analyze both control costs and air quality impacts in downwind nonattainment areas. EPA's proposed approach corrects the legal flaws inherent in the regional significant contribution analysis that was used in the CAIR program and establishes a reasonable state-specific methodology for quantifying each state's significant contribution. However, Santee Cooper has major objections to the proposed approach for allocating allowances to affected existing units from the newly established state emissions budgets. The EPA proposal would base allowance allocations to existing units on projected emissions from these units after elimination of some or all of the significant contribution and interference with maintenance. Specifically, EPA would allocate allowances to existing units by using the same theoretical method and assumptions that were used in developing the proposed emissions budgets. Santee Cooper believes that the EPA approach is neither mandated by statute (as interpreted by court decisions) nor establishes a reasonable method for allocating allowances to affected units within a state. [EPA-HQ-OAR-2009-0491-2820.1, p.18]
EPA's PROPOSED METHODOLOGY IS NOT MANDATED BY THE CLEAN AIR ACT. In Section I.E. above, Santee Cooper discussed the legal reasons why EPA is not required to adhere to the same methodology used in setting the state emissions budgets. The statute focuses on eliminating significant contribution and interference with maintenance within the state and requires that the state develop a SIP control program that achieves the emissions reductions necessary for achieving this objective (specifically, meeting its section 110(a)(2)(D) requirement). Both the statute and North Carolina decision make it clear that each state has wide latitude in crafting a control program for achieving the necessary emissions reductions within the state, which - in this case - involves achieving the applicable state emissions budget set for EGUs within the particular state. A state, on the one hand, may elect to adopt any mix of command-and control requirements that achieve the requisite emissions reductions from EGUs and other types of sources within the state. If, on the other hand, a state elects to opt-into the model regional trading program established by EPA, the state may choose any allocation scheme it deems appropriate so long as the state trading program can achieve the emissions reductions necessary for meeting its significant contribution requirement under section 110(a)(2)(D). [EPA-HQ-OAR-2009-0491-2820.1, p.19]
The fact that EPA itself is proposing to implement control requirements of the Transport Rule through a FIP does nothing to diminish EPA's discretion in selecting an appropriate allocation methodology. Notably, EPA has effectively recognized its broad discretion on this element of the proposed Transport Rule by seeking public comment on a wide-range of alternative allocation methods. Furthermore, recognizing the broad discretion on the allowance allocation method is consistent with how EPA has implemented past regional trading programs pursuant to section 110(a)(2)(D), including the NOx SIP Call and the CAIR programs. [EPA-HQ-OAR-2009-0491-2820.1, p.19]
EPA's PROPOSED METHODOLOGY IS NOT A REASONABLE METHOD FOR ALLOCATING ALLOWANCES. [EPA-HQ-OAR-2009-0491-2820.1, p.20]
In addition to not being mandated by statute, the EPA proposal does not establish a reasonable method for allocating allowances to affected units within a state. This is first and foremost reflected by the fact the proposed EPA approach fails to provide appropriate recognition of the action that electric utilities have achieved to lower their emissions prior to 2012. In the case of the Santee Cooper system, for example, Santee Cooper has installed FGD scrubbers for reducing SO2 on 88 percent of its coal-fired generation. Similarly, Santee Cooper has installed SCR systems for controlling NOx emissions on 88 percent of its coal-fired generation. As result of these control efforts, Santee Cooper has reduced its annual SO2 emissions by approximately 70,000 tons per year based on a comparison of 2005 and 2009 emissions levels. This amounts to about an 80 percent reduction in SO2 emissions. Similarly, Santee Cooper has reduced its NOx emissions by approximately 35,000 tons per year between 2000 and 2009, which amounts to a 77 percent reduction in annual NOx emissions. Notwithstanding, Santee Cooper is projected to have a substantial short fall in annual SO2 allowances given that - in EPA's own words - 'a unit that installs control equipment receives fewer allowances than a similar unit that did not install control equipment." [EPA-HQ-OAR-2009-0491-2820.1, p.20]
The punitive effect of the proposed EPA allocation scheme is illustrated in the following two charts. In particular, Chart I [See p.22 of this comment summary for Chart I] below compares the SO2 emissions in 2000, 2005 and 2009, to allowance allocations to the coal-fired units owned and operated by Santee Cooper under the EPA proposal. A similar comparison is made for NOx emissions and allowances allocations in Chart II [See p.22 of this comment summary for Chart II] below. These two charts clearly demonstrate that Santee Cooper has made extraordinary efforts to reduce its SO2 and NOx emissions by very substantial amounts over the last decade. Notably, Santee Cooper achieved in 2009 system-wide emissions rates for its coal-fired generation of 0.16 Ibs/mmBtu for SO2 and 0.09 Ibs/mmBtu for NOx Moreover, the two charts show that not only are these efforts entirely overlooked by EPA, but also that EPA's allocation methodology effectively penalizes clean electric utilities like Santee Cooper by lowering their allowance allocation to the extent that they have reduced their emissions through the installation (or upgrading) of pollution control equipment. [EPA-HQ-OAR-2009-0491-2820.1, pp.20-21]
This is especially the case with respect to SO2. Specifically, Chart III [See p.23 of this comment summary for Chart III] below shows that the Santee Cooper coal-fired system will have a substantial short fall of SO2 allowances in 2012 and future years thereafter of the Transport Rule program. The shortfall of allowances identified in Chart III ranges from 11,038 allowances in 2012, to 5,848 allowances in 2015. This means that Santee Cooper will have to purchase a large number of SO2 allowances from other electric utilities, not withstanding its very substantial efforts to control its SO2 emissions and achieve a very low system-wide SO2 emissions rate of 0.16 lbs/mmBtu in 2009. [EPA-HQ-OAR-2009-0491-2820.1, p.21]
The unreasonableness of the EPA approach is further demonstrated in Charts IV [See p.23 of this comment summary for Chart III] and V [See p.24 of this comment summary for Chart V] below. These charts provide a comparison of the coal unit emissions levels and the 2012 Transport Rule allowance allocations for Santee Cooper and the other major electric utility systems in South Carolina. Chart IV provides such a comparison of SO2 and NOx emissions to allowance allocations based on a MW of coal capacity basis. Chart V provides a similar comparison of coal unit system-wide allocation SO2 and NOx emission rates for Santee Cooper and the other major South Carolina electric utility systems. In each chart, the comparison illustrates that both SCANA and Progress will be rewarded for not installing pollution control equipment or undertaking other measures for reducing their emissions. The egregiousness of the EPA approach is particularly illustrated in the case of SO2. SCANA and Progress will receive proportionately more allowances than Santee Cooper to cover emissions from their units - a high percentage of which operate without stringent emissions controls. Notably, Progress is allocated SO2 allowance at a rate 8.6 times higher, and SCANA 5 times higher, than Santee Cooper based on a MW of capacity basis in Chart IV. [EPA-HQ-OAR-2009-0491-2820.1, p.23]
SUMMARY OF DISCREPANCIES IDENTIFIED IN SANTEE COOPER DATA [EPA-HQ-OAR-2009-0491-2820.1, p.26]
The following items are discrepancies that Santee Cooper has identified in EPA-HQ-OAR- 2009-0491-0074 1 data sheets: [EPA-HQ-OAR-2009-0491-2820.1, p.27]
Winyah Unit 3 received no ozone season NO, allowances despite the fact the unit is projected to operate as a baseload unit. [EPA-HQ-OAR-2009-0491-2820.1, p.27]
Jefferies Unit 3 SO2 allowances appear to be based on arbitrary assumptions and data input that do not reflect normal operation of the unit. Historically, Jefferies Units 3 and 4 are dispatched at similar utilization levels and Santee Cooper's model projects similar dispatch levels to continue in the future. In addition, the two units bum the same coal. These similarities clearly indicate that the allocations should be set at similar levels. Although the allocations for NOx for the two units are similar, the SO2 allocation for Unit 4 is 4.7 times higher than Unit 3. [EPA-HQ-OAR-2009-0491-2820.1, p.27]
Cross Units I, 3, and 4 have projected SO2 rates that are approximately one half of the PSD netting rates for these units that reflected in federally enforceable permit conditions. [EPA-HQ-OAR-2009-0491-2820.1, p.27]
Grainger Units I and 2 and Jefferies Units 3 and 4 have projected SO2 rates that are approximately one half of the expected rates for these units. [EPA-HQ-OAR-2009-0491-2820.1, p.27]
The NEEDS data show NOx emission rates for Cross Units I & 2 and Winyall Units I, 2 and 4 are well below their consent decree limits:  [EPA-HQ-OAR-2009-0491-2820.1, p.27; See p.27 of this comment summary for NEEDS data showing NOx emission rates for Cross Units 1 & 2 and Winyah Units 1, 2 and 4 are well below their consent decree limits]
EPA SHOULD ALLOCATE ALLOWANCES TO EXISTING UNITS BASED ON WELL-CONTROLLED EMISSIONS BENCHMARKS AND HISTORIC BASELINE ACTIVITY LEVELS. [EPA-HQ-OAR-2009-0491-2820.1, p.29]
Santee Cooper urges the adoption of an alterative approach that avoids the unreasonable and arbitrary effects of EPA's proposed scheme for allocating allowances to existing units affected under the Transport Rule. Key objectives of such an alterative allocation scheme should include the following: [EPA-HQ-OAR-2009-0491-2820.1, p.29]
Allocate equivalent allowances to same types of units burning the same fuels; [EPA-HQ-OAR-2009-0491-2820.1, p.29]
Do not penalize those units that have reduced their emissions through the installation of pollution control equipment or other such emissions reduction measures prior to the start of the control period; and [EPA-HQ-OAR-2009-0491-2820.1, p.29]
Do not reward uncontrolled units, but rather provide incentives for such units to reduce their emissions. [EPA-HQ-OAR-2009-0491-2820.1, p.29]
One approach deserving special consideration is a system that would allocate allowances based on the SO2 and NOx emissions levels of a well-controlled electric generating unit. Under this approach, EPA would make a determination on what would be the SO2 and NOx emissions rates of a well-controlled coal unit, well-controlled gas unit, and a well-controlled oil unit. Such a determination could be made based on representative average control levels for each category of affected units. Once the emissions rate has been determined for each category of units, the allowances then would be allocated in accordance with the following formula: [EPA-HQ-OAR-2009-0491-2820.1, p.29]
A = WC EMISSION RATE X BASELINE [EPA-HQ-OAR-2009-0491-2820.1, p.29]
Where: A = Number of allowances allocated to an existing affected electric generating unit [EPA-HQ-OAR-2009-0491-2820.1, p.29]
WC Emissions Rate = Emissions rate established for well-controlled electric generating unit for the particular category of units (expressed in terms of either Ibs/mmBtn or IbsIMWH) [EPA-HQ-OAR-2009-0491-2820.1, p.29]
Baseline = Historic activity level of the affected electric generating unit (either heat input or MWH output) [EPA-HQ-OAR-2009-0491-2820.1, p.30]
Baseline levels should be determined based on actual activity levels of the unit (either heat input or MWH output) during a representative historic period. Santee Cooper suggests that the initial baseline period should be the annual average of the 3 highest years during the previous prior 5 years. This flexibility in setting the initial baseline period is appropriate in order to ensure a representative baseline period and given the general economic downturn in many parts of the country over the past few years. Santee Cooper would also recommend an updating baseline on a periodic basis (such as every five years) to reflect major shifts in the utilization of affected units in future years of the program. Such an updating function is critical for states such as South Carolina where certain service territories of some electric utilities are expected to experience high growth, while the electric demand of other electric utility service territories may remain flat or have low growth. [EPA-HQ-OAR-2009-0491-2820.1, p.30]
Finally, EPA should adopt an adjustment mechanism to ensure that the total number of allowances allocated to all affected units within a state does not exceed the emissions budget established for that state. This adjustment mechanism could be modeled after the ratchet mechanism established under the acid rain program, whereby EPA will reduce each unit's allocation on a pro rata basis based on the number of allowances allocated to each unit under the preceding formula. [EPA-HQ-OAR-2009-0491-2820.1, p.30]
Response: 
EPA disagrees with the commenter's assertion that an "updating function" for existing unit allocations is "critical... where certain service territories of some electric utilities are expected to experience high growth."  This comment ignores the fact that the economic determination of unit dispatch to meet electricity demand will factor in the cost of emitting (i.e., the market price of an allowance) whether or not an allowance was freely allocated for a ton emitted from that unit's generation.  It is not necessary, therefore, for EPA to update the allocation pattern to existing units because utilities will continue to meet electricity demand (no matter the rate of growth) with the least-cost generation available, including the cost of such generation's emissions under the state budgets whether or not such emissions are covered by initially allocated or purchased allowances.  A utility whose service territory experiences future load growth will seek to minimize operating costs of meeting that increased load; that cost accounting will always incorporate the cost of emitting because such emissions will require allowances (with market value) to be submitted whether or not those allowances were originally allocated to the unit in question,  In addition to being unnecessary, EPA believes updating allocations to existing units would introduce unwarranted uncertainty into the programs as administered under the FIPs, whose existing unit allocations are being presented with the promulgation of this final rulemaking in order to aid advance allowance transaction planning among sources in the marketplace.  While states have the prerogative to replace the FIPs with SIPs and determine a different allocation methodology for future control periods under that SIP, EPA does not believe it is reasonable to introduce further uncertainty into the FIP structure by shifting the allocation pattern to existing units in future control periods in ways that are difficult, if not impossible, to anticipate.
Organization: Southern Company
Duke Energy
American Electric Power
National Rural Electric Cooperative Association (NRECA)
Louisiana Chemical Association (LCA)
National Grid
Consolidated Asset Management Services (CAMS)
Mississippi Department of Environmental Quality
City of Dover, Delaware
Indiana Department of Environmental Management 
Clean Energy Group
New Jersey Department of Environmental Protection (NJDEP)
Illinois Environmental Protection Agency
West Virginia Department of Environmental Protection
we energies
New York State Department of Environmental Conservation
Seminole Electric Cooperative Inc.
State of Delaware Department of Natural Resources & Environmental Control
Maryland Department of Environment (MDE)
Constellation Energy
Council of Industrial Boiler Owners (CIBO)
State of Wisconsin, Department of Natural Resources
Vectren Corporation 
Louisiana Public Service Commission
State of Ohio Environmental Protection Agency (Ohio EPA)
Oklahoma Department of Environmental Quality
State of Louisiana, Department of Environmental Quality
Virginia Department of Environmental Quality (VDEQ)
Kansas City Board of Public Utilities (BPU)
Virginia Independent Power Producers
Independence Power & Light (IPL)
NextEra Energy, Inc.
Florida Electric Power Coordinating Group, Inc. (FCG)
GE Energy Financial Services (GE EFS)
East Texas Electric Cooperative
San Miguel Electric Cooperative, Inc.
Lansing Board of Water & Light
Northern Indiana Public Service Company (NIPSCO)
PSEG Services Corporation
Xcel Energy Inc.
PPL Corporation
Connecticut Department of Environmental Protection
Wolverine Power Supply Cooperative
Edison Mission Energy (EME)
City of Tallahasse
Buckeye Power, Inc.
Great River Energy
Louisiana Energy and Power Authority (LEPA)
Excelsior Energy
AES Corporation (AES)
First Energy
Sunbury Generation LP
Calpine Corporation
New York Power Authority
Oglethorpe Power
Alcoa Power Generating Inc. - Warrick Power Plant
Florida Municipal Power Agency (FMPA)
PowerSouth Energy Cooperative
Tenaska, Inc.
Cleco Corporation
Associated Electric Cooperative, Inc. (AECI)
Southern IL Power Cooperative
Northern Star Generation LLC
Marquette Board of Light and Power
ARIPPA
Entergy Services, Inc.
DTE Energy
Rochester Public Utilities (RPU)
Potomac Power Resources
Dow Chemical Company
Manitowoc Public Utilities (MPU)
Holland Board of Public Works
Exxon Mobil Corporation
Piney Creek LP
Mirant Corporation
Michigan Municipal Electric Association (MMEA)
American Public Power Association (APPA)
Alliance to Save Energy
New York University School of Law, Institute for Policy Integrity
American Clean Skies Foundation (ACSF)
Texas Chemical Council
Gainesville Regional Utilities (GRU)
Reiss, J.
Machaver, Bob
E.ON U.S.
Northeast States for Coordinated Air Use Management (NESCAUM)
Comment: 
AES Corporation (AES)
The proposed allowance allocations in the proposed rule and supporting technical information are flawed. The allowance allocations in the Technical Support Documents are based on flawed historical data and emissions level model inputs that do not incorporate startup, shutdown and malfunction periods. EPA is aware of the limitations of FGD and SCR technology, especially on start-up and low-load operation. Without compliance flexibility for low-load, startup, shutdown and malfunction events, it is probable that some units will have to comply by either increasing minimum generation or discontinuing operations. Reduced operating flexibility or discontinuation of operations could result in system reliability related issues especially since this applies to a large fleet of assets. [EPA-HQ-OAR-2009-0491-2791, p.3] [EPA-HQ-OAR-2009-0491-3793.1_NODA, p.3]
The use of one year for base line allowances does not account for normal fluctuations in markets, operations, major outages, long term forced outages, etc. We request that the rule be revised to incorporate a more realistic multi-year baseline to incorporate the changes in emissions levels due to system demand, fuel pricing, and operational variances. A simple 24 month out of the past 60 month is an easy method to ensure that the likely operations are taken into account for setting budgets. [EPA-HQ-OAR-2009-0491-2791, p.6]
The proposed allowance allocations in the NODA for the proposed rule and supporting technical information are flawed. The NODA states that some of the data used is reported and in inaccurate for many cases. Also the results do not incorporate startup, shutdown and malfunction periods. [EPA-HQ-OAR-2009-0491-3793.1_NODA, p.3]
The short time period to determine base line allowances does not account for normal fluctuations in markets, operations, major outages, long term forced outages, etc. We request that the rule be revised to incorporate a more realistic multi-year baseline to incorporate the changes in emissions levels due to system demand, fuel pricing, and operational variances. A simple 24 month out of the past 60 month is an easy method to ensure that the likely operations are taken into account for setting budgets. [EPA-HQ-OAR-2009-0491-3793.1_NODA,p.7]
Alcoa Power Generating Inc. - Warrick Power Plant
Warrick 4 had a selective catalytic reduction unit for NQx control during the ozone season installed in 2004, and a wet flue gas desulfurization scrubber installed in 2008 for SO2 control as required by CAIR at capital costs in excess of $200 MM, The allocation procedure described on 75FR45311,i.e
'...all units are allocated allowances consistent with their projected emissions; this means that a unit that installs control equipment receives fewer allowances than a similar unit that did not install control equipment.' 
thus unfairly penalizes EGU' s, such as Warrick 4, that have gone to the expense of installing the control device hardware needed to meet previous requirements, and appears to reward BGU' s that have not installed control equipment. [EPA-HQ-OAR-2009-0491-3648,p.3]
APGI recommends a 2-step approach for allowance allocation, after EPA re-examines the emission reductions, as suggested in the first two comments. Step 1 would be to reduce each EGU's emissions in 2005 by the efficiencies required to reduce emissions to the state budgets for SO2 and NOx 2012 and 2014 levels. If, after the application of Step 1, emissions equal the state budget, allowances would be established at those emission levels, minus the new source set-asides. If Step 1 exceeds the budgets, a Step 2 calculated adjustment for additional emission reductions would be derived by each EGU's proportional share of total state EGU heat input, multiplied by the amount that Step 1 exceeds the budget. The Step 1 allowance for each EGU would then be reduced by its Step 2 calculated adjustment. [EPA-HQ-OAR-2009-0491-3648, p.3]
Alliance to Save Energy
As noted in the NOPR, under a FIP the EPA allocates emission allowances directly to individual sources. However, we understand that some states may prefer to use their own procedures, rather than EPA's, to allocate emissions allowances to in-state sources. In some cases states may wish to include set-asides for energy efficiency and renewable energy (EERE) measures. The Alliance believes that states following their own procedures, including inclusion ofEERE set-asides, should not affect the approvability of SIPs because the distribution of allowances within a state does not affect overall emissions in the state. [EPA-HQ-OAR-2009-0491-2800.1 p.3]
However, the NOPR does not provide guidance to states on what EPA would accept asallowance distribution approaches or mechanisms. The Alliance urges EPA to:
:: indicate to states that it will duly consider state SIPs that incorporate FIPcomponents but only differ in terms of allowance allocation mechanisms;
:: provide guidance on what allowance distribution approaches or mechanisms itwill accept; and
:: provide guidance on criteria that state SIPs would have to meet to allowapplicable emission sources in a state to participate in the interstate emissions trading program. [EPA-HQ-OAR-2009-0491-2800.1 p.2]
The Alliance understands that those states that incorporated EERE set-asides under CAIR required significant technical assistance from EPA, the Department of Energy (DOE), and outside consultants. Each of those states individually struggled to determine EPA-acceptable SIP parameters, including such things as, among others, additionality and enforceability concerns, measurement & verification (M&Y) issues, and types of energy efficiency measures that could be eligible for set-asides. Guidance offered in the previously cited 2004 EPA document 'Guidance on State Implementation Plan (SIP) Credits for Emission Reductions from Electric-Sector Energy Efficiency and Renewable Energy Measures' is at a very high and broad level and was of limited utility for state and local air quality agencies seeking to incorporate EERE set-asides into their programs. [EPA-HQ-OAR-2009-0491-2800.1 p.2]
Thus, the Alliance urges the EPA to provide greater guidance and technical assistance to states on incorporating EERE set-asides or other energy efficiency provisions into a SIP, including:
[EPA-HQ-OAR-2009-0491-2800.1 p.2]
 :: model rules; and
:: adviee on measure eligibility, M&Y, and other parameters that must be met for EPA aeceptanee of a SIP.
We note that the Commonwealth of Massachusetts implemented a successful EERENOx allowance set-aside program under CAIR in which EERE set-asides have been oversubscribed and such allowances have been sold in the market. Thus,Massachusetts may serve as a good case for guidance and assistanee to other states. [EPA-HQ-OAR-2009-0491-2800.1 p.2]
(We also recognize that some states may opt for an alternative EERE set-aside program in which emissions allowances attributed to EERE are retired as creditable NOx reductions under the SIP rather than sold into the market.) [EPA-HQ-OAR-2009-0491-2800.1 p.3]
The Alliance recognizes that establishing emissions allowances on an output basis may be more complex than using a heat-input basis in the case of combined heat and power (CHP) systems, where useful heat energy is captured and utilized. However, very few existing utility power generators that would be regulated under the Transport Rule are CHP facilities, a number of states have successfully enacted output-based standards that accommodate and credit CHP facilities for useful thermal output, and an existing NSPS for electric utility steam generating units incorporates output-based standards. These facts suggest that EPA can use output-bases for developing emissions allocations. [EPA-HQ-OAR-2009-0491-3926[1].1, p.4]
American Clean Skies Foundation (ACSF)
Despite supporting much of the Proposed Rule, ACSF has significant concerns regarding CATR's proposed method for allocating emission allowances that cap power plant emissions. In particular, the Proposed Rule's emission-based allocation method irrationally subsidizes high-emitting coal-fired generation, to the disadvantage of clean-burning gas generation and in contravention of air quality and public health goals. Furthermore, failing to adequately address upwind pollution from coal-fired power plants violates the statutory language of the Clean Air Act. [EPA-HQ-OAR-2009-0491-2759.1, p.2]
As noted above, the Proposed Rule would regulate NOx and SO2 emissions from power plants that drift across state borders and contribute to downwind states failing to attain compliance with national air quality standards. However, CATR's proposed emission reductions are just a first step, as EPA anticipates additional reductions will be needed through updates to the transport rule. Thus, adopting a rational and appropriate allocation method now is crucial because it is likely to affect future transport rulemakings as well. [EPA-HQ-OAR-2009-0491-2759.1, p.3]
ACSF submits that the purpose of the Proposed Rule is unnecessarily jeopardized by basing allocations on historic emissions. [EPA-HQ-OAR-2009-0491-2759.1, p.4]
a. Basing allocations on historic emissions penalizes utilities--and ratepayers--who have incurred costs to switch to cleaner forms of generation, including renewables and natural gas.
An emissions based allocation method provides a subsidy to those utilities with higher-emitting units, to the detriment of those utilities with lower-emitting units. CATR's emission-based allocation penalizes utilities (and states in which those utilities are located) that have installed control equipment, or converted to cleaner-burning generation sources, prior to the baseline years used by EPA for setting allocations. Simply put, utilities that have switched to natural gas (or installed scrubbers and SCRs or 'greened' their portfolios with wind and solar generation) should not be required to subsidize the installation of new emission controls on coal plants by utilities (and states) that have delayed such measures. In addition to the patent unfairness and ratepayer impacts, historic emissions allocations may encourage power plants (and states) to avoid installing needed controls (or taking other measures) for as long as possible so as to maximize their baseline allocations. [EPA-HQ-OAR-2009-0491-2759.1, p.4]
EPA's previous allocation method in CAIR favored coal over gas and was rejected by the D.C. Circuit. CAIR was rejected by the D.C. Circuit, among other reasons, because of a flawed system that disproportionately taxed gas-fired generators. For instance, because Louisiana's power plants used more gas than coal, its NOx budget was reduced to 29,000 tons, from the 42,000 tons that it would have otherwise received. The court found 'the net result will be that states with mainly oil- and gas-fired EGUs will subsidize reductions in states with mainly coal-fired EGUS.' The court rejected this subsidy. In its CAIR decision, the court found that "those states with the greatest emissions are those with mainly coal-fired EGUs, which are precisely the states that get extra credits." The court determined that EPA had favored high-emitting coal based on a misguided sense of 'equity among upwind states,' which was 'improper,' and that the resulting emission budgets were arbitrary and capricious. Unfortunately, as further explained below, the Proposed Rule allocation method continues to subsidize high-emitting coal plants to the detriment of cleaner-burning gas generation and is similarly arbitrary and capricious. [EPA-HQ-OAR-2009-0491-2759.1, pp.4-5]
b. EPA should consider other allocation methods besides CATR's proposed emission-based approach.
EPA should consider an output-based methodology or a BTU-based methodology that does not penalize natural gas and other less polluting sources of electricity. A number of states have adopted output-based allocation methods, which allocate emission allowances based on megawatts produced by power plants. This could allow states with large amounts of generation to retain significant generation, while rewarding the most efficient units. As an alternative, EPA could continue with the BTU-based allocation method it originally proposed in CAIR, without the natural gas-harming 'fuel factors' adjustment that the D.C. Circuit rejected. 14 This could allow states and utilities that combust significant quantity of BTUs to continue to do so, without penalizing a unit that has installed 'back end' emission controls. Natural gas combined cycle power plants can provide low emitting, high efficiency generation, to help meet the Clean Air Act's important air quality goals. [EPA-HQ-OAR-2009-0491-2759.1, p.5]
c. By subsidizing coal with over-allocations, EPA is failing to achieve cost-effective emission reductions that can be achieved through the increased use of natural gas.
The choice of emission allocations has real-world impacts: by subsidizing coal-fired generators with overgenerous allocations, EPA is failing to achieve cost-effective emission reductions. That would burden consumers and delay needed pollution resolutions. Numerous facts make this point clear, including the following: [EPA-HQ-OAR-2009-0491-2759.1, p.5]
Overgenerous allocations to coal-fired power plants in upwind states are subsidies that keep marginally economic, high-emitting plants operating, inhibiting emission reductions from cleaner sources of generation. In particular, the oldest and least efficient coal-burning plants may be kept operational by this subsidy. Furthermore, this subsidy may allow old coal units to escape emission controls that would be otherwise required. This subsidy for coal plants should be eliminated through a better allocation method. 15 [EPA-HQ-OAR-2009-0491-2759.1, pp.5-6]
High-emitting upwind generation makes it more difficult to develop clean downwind generation. As an example of increased costs for downwind generators, the developer of a natural gas power plant may be required to acquire expensive NOx 'offsets,' a requirement under the Clean Air Act in states that fail to attain compliance with air quality standards, which the developer wouldn't otherwise be required to obtain but for the pollution from upwind states causing the downwind state to violate the air quality standard. [EPA-HQ-OAR-2009-0491-2759.1, p.6]
CAIR's emission-based allocation has real-world impacts, and results in increased pollution from coal-fired power plants. For instance, the EPA's Regulatory Impact Analysis for CATR shows that under CATR coal generation actually increase from 2008 levels, and natural gas generation decreases. The Regulatory Impact Analysis notes that both "the base case and all three remedies show shifts away from oil and natural gas generation and toward increased coal generation between 2012 and 2014." This is a perverse result from an air quality standpoint that shows the weakness of CAIR as proposed: high-emitting coal generation increases, while clean-burning natural gas generation faces disincentives and decreases. [EPA-HQ-OAR-2009-0491-2759.1, p.6]
3. The new unit set-aside should not disadvantage to-he-constructed natural gas units.
EPA proposes new unit set asides equal to 3% of each state's budget. The size of each new unit set aside is based on 'a comparison of projected emissions from new units to projected emissions from existing units for all covered states.' If requests by new units exceed supply in a given year, new units would only receive their 'proportionate share of the new unit set-aside." Therefore, if new natural gas capacity is developed with allowance needs that exceed the set-aside, these new units may be 'short' allowances while incumbent, higher-emitting coal plants receive overgenerous allocations due to the emission-based allocation method discussed above. Moreover, a single new coal plant may consume an inordinate share of allowances from a new-source set-aside, compared to lower-emitting natural gas units. EPA should assess whether the design of the new unit set aside is sufficient for projected new types of generation, in particular projected substantial amounts of low-emitting gas-fired generation. EPA could also consider the auctioning of some portion of allowances, which could allow new generators (or natural gas units that increase their generation above baseline capacity factors) to compete with incumbent coal generation on a level playing field. [EPA-HQ-OAR-2009-0491-2759.1, p.8]
EPA should also consider provisions, either at the federal or state level, that would allow a portion of allowances that are no longer needed by non-operating units to specifically incentivize cost-effective fuel-switching to lower emitting forms of generation. These types of 'bridge fuel credit' programs have been proposed for inclusion in federal cap-and-trade legislation for greenhouse gases. [EPA-HQ-OAR-2009-0491-2759.1, p.8]
Furthermore, EPA should avoid making its allocations permanent (as it has proposed), but rather update them as necessary to reflect changes in generation sources. [EPA-HQ-OAR-2009-0491-2759.1, p.9]
14. EPA specifically requested comment on a heat-input (Le., BTU) based approach as part of the Proposed Rule. 75 FR 45311. [EPA-HQ-OAR-2009-0491-2759.1, p.5]
15. Consider the case of two utility companies that each has four units of the same vintage and megawatt capacity: one modern, 500-megawatt natural gas combined cycle unit; two large 500-megawatt coal units built in the 1970s; and one smaller coal unit built in the 1950s. Generator 1 ('Cleaner Generator') recently installed scrubbers on its two large coal units and increased its customer rates to pay for installation. Generator 2 ('Dirtier Generator') has not installed scrubbers on any of its units. Under CATR, Dirtier Generator would receive more allowances for failing to reduce emissions, and could use these allowances to offset the cost of installing scrubbers. Cleaner Generator may have to buy allowances from Dirtier Generator to cover its shortfall in allowances, so that Cleaner Generator directly subsidizes Dirtier Generator. A similar situation would occur if Cleaner Generator recently retired a coal unit and replaced it with a low-emitting NGCC unit-Cleaner Generator would receive no emission allowances to offset the cost of this conversion, while Dirtier Generator would receive extra allowances based on its high-emitting coal generation. Finally, Cleaner Generator, short allowances, may be forced to shut down its small coal unit while Dirtier Generator, with surplus allowances, could keep its dirtiest unit running without emission controls. Worse still, Cleaner Generator may then need to buy power from Dirtier Generator, increasing the demand for the uncontrolled, oldest, least-efficient, highest-emitting plant in Dirtier Generator's fleet. [EPA-HQ-OAR-2009-0491-2759.1, p.6]
American Electric Power
AEP has serious concerns with the bottom-up approach used by EPA in apportioning reductions to states and specific units as this requires that both the data and modeling assumptions be highly accurate to ensure an optimal outcome. However, in the case of this rulemaking, the data and assumptions are not representative of the actual economic and operating conditions of the electric generating fleet. Employing a methodology which specifies budgets and allocates allowances on the basis of speculative modeled reductions will lead to costs much higher and disproportionate than optimally needed. [EPA-HQ-OAR-2009-0491-2665.1, p.11] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.7]
The modeling support for the Proposed Transport Rule does not take into account the reductions that are occurring under the current CAIR program in the absence of this rulemaking. CAIR continues to be in effect until further regulations are promulgated and utilities are currently factoring this into their planning process. Additionally, the IPM modeling did not contemplate the myriad of other regulations (e.g. coal combustion residuals, hazardous air pollutants, cooling water intake) that EPA is currently developing that affect the same electric generating units subject to the Proposed Transport Rule. Planning decisions do not occur in isolation within the electric utility sector, particularly those relating to retirement and retrofit decisions. Given EPA's schedule for rule promulgation, it is arbitrary and irrational to base a rule and allocation system on modeled reductions that do not take into account the effects of the full suite of related new regulations which are currently proposed or publicly announced and soon to be proposed by EPA. AEP and all other utilities must take into account potential outcomes for new regulation in the real world planning process and EPA's modeling efforts should be revised to take into account likely regulatory outcomes as well. As a result of EPA's artificial and myopic IPM modeling approach, combined with data and assumption errors, the IPM modeling relied upon by EPA dramatically underestimates the amount of coal unit retirements due to the proposed rule. Accompanying these coal units retirements will be lost jobs, lost tax revenue and higher energy prices, all presenting major obstacles to an economic recovery. These enormous indirect costs of the Proposed Transport Rule have been arbitrarily ignored by EPA in formulating its proposal. [EPA-HQ-OAR-2009-0491-2665.1, pp.11-12
Additionally, the complexity of the model makes it impossible to review the accuracy of all inputs and outputs of the model with the level of scrutiny required given the enormous financial implications of this model. This frustrates the ability to meaningfully comment on the true basis and purpose of EPA's proposal. Furthermore, EPA has indicated its intention to continue changing the NEEDS database and IPM modeling inputs and outputs without adequate notice and opportunity to comment on those ongoing changes. Therefore, AEP requests any interim model updates which include the incorporation of data corrections or new information be released publicly upon completion to ensure they can be reviewed for accuracy. Additionally, AEP requests that a full suite of IPM results be released on an individual unit basis and not just through the parsed file and grouped model outputs, with an adequate opportunity for review and comment. [EPA-HQ-OAR-2009-0491-2665.1, p.12] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.7]
Budget Allocations aud Equity
The allocations as detailed in the proposed remedy are based on the lower of historical or forecast emission levels in 2012 and forecast emissions in 2014. These allocations take into account modeled control equipment installations, dispatch changes, and fuel switching. This system sets a new precedent for a cap-and-trade program by allocating based on what a computer model calculates to be economic. This takes the modeling logic one step too far, given the considerable uncertainty surrounding the economics of utility system future planning decisions. While modeling could be used to specify state or regional permissible emissions, the model outcomes should not be used to drive allocations at the unit level. Rather, unit-level allocations should: I) be determined by the host states through a state implementation plan; and 2) be based on historical emissions. Taking historical emissions into account is much more equitable in that it does not penalize companies who have invested heavily in controls in advance of future regulations. [EPA-HQ-OAR-2009-0491-2665.1, p.15]
AEP is disproportionately affected by the proposed budget allocation methodology as a result of both projected controls and incorrect data. As an example, initial EPA modeling of the interstate trading option indicates that 5.7 gigawatts electric generating capacity within the AEP eastern fleet would install FGD systems as a result of the rule, or 40% of the projected FGD installations from the entire Proposed Transport Rule program. In other words, 40% of the burden of reductions (as dictated by commensurately decreased allocations) for the program has been placed on AEP and its customers even though it is responsible for well less than 10% of covered source emissions, and virtually zero of the contribution to predicted pockets of nonattaimnent remaining after implementation of the current CArR program and other existing regulatory requirements. [EPA-HQ-OAR-2009-0491-2665.1, pp.15-16]
AEP is also concerned with the use of the lower of historical versus modeled emissions and the discrepancies this has caused. The historical data used for 2012 SO2 budget development are from the years 2008-2009. Late 2008 and early 2009 happen to coincide with the longest and deepest economic recession since World War II, and represent one of the lowest periods in recent history of utility power plant utilization. [EPA-HQ-OAR-2009-0491-2665.1, p.16]
Additionally, emissions during this period were exceptionally low as high cost uncontrolled units did not run. Thus, using the portions of 2008 and 2009 as a heat input basis for state and unit level budgets is highly punitive and arbitrary. Additionally, this budgeting method is punitive to units which had an outage to install controls (as AEP was required to do at a number of its units under its NSR Consent Decree with EPA) which reduced heat input relative to other periods. Furthermore, subsequent corrections to emission rates based on projected control installations is also inaccurate because installations dates are rounded to the nearest years and thus don't consider partial years of operation, resulting in an additional haircut. [EPA-HQ-OAR-2009-0491-2665.1, p.16]
Given the aforementioned issues, a more representative historical time perspective should be used to set 2012 S02 budgets. We would recommend a three year average from 2006- 2008 to capture more typical plant operation. Furthermore, any corrections to unit emission rates for controls should: a) take into account more realistic performance expectations (see NEEDS FGD Removal Assumptions comments); b) adjust for higher sulfur coal use with FGD installations; and c) take into account only partial year operation of control equipment. [EPA-HQ-OAR-2009-0491-2665.1, p.16]
American Public Power Association (APPA)
In developing the Proposed Transport Rule, EPA used photochemical source apportionment modeling to identify the impact of emissions from specific upwind states on downwind areas projected to be in nonattainment or to have maintenance problems in 2012. 75 Fed. Reg. at 45253/1. Then, EPA determined each state's significant contribution to nonattainment and interference with maintenance based on the emissions that EPA projected could be eliminated from that state for a specific cost (in dollars per ton of reduced emissions), in conjunction with an analysis of air quality benefits at various cost levels, and set state budgets accordingly. 75 Fed. Reg. at 45271/1-2. Thus, although APPA disagrees with many aspects of the data and methodology that EPA used in this analysis, EPA`s methodology does, as a general matter, attempt to address the EPA-projected contribution to nonattainment and interference with maintenance in downwind states from emissions from particular upwind states. At least in broad terms, the PTR`s focus on state-specific data should align with the court`s characterization of states` section 110(a)(2)(D)(i)(I) duties. [EPA-HQ-OAR-2009-0491-2812.1, pp.9-10]
APPA applauds the U.S. EPA`s proposal for the decision not to include any allowance auctioning under its Proposed Remedy Option. No need or reason exists to use allowance auctions to implement the Proposed Transport Rule`s emission reduction requirements. If, however, EPA promulgates a final rule based on the Intrastate Trading Remedy Option, an option that APPA (and UARG) does not support, EPA should remove from that option the proposed provisions for allowance auctions. It is entirely possible to accomplish the objectives of those proposed auctions through distribution of allowances free of charge. [EPA-HQ-OAR-2009-0491-2812.1, p.13]
As explained in section VI below, government auctioning of allowances is contrary to the principle that regulated sources are not subject to any obligation to emit below their allowance allocation levels established by the program. Revenues from the allowance auctions that EPA describes in the Intrastate Trading Remedy Option would be deposited into the U.S. Treasury. 75 Fed. Reg. at 45327/2. The effect of such auctions, in which proceeds accrue to the government, is to force affected sources to pay not only for emissions that exceed their emission allocation levels but also for the right to emit below those levels. There is no legal basis for charging sources for the right to emit tons of emissions that are within their allowance allocation levels -- indeed, the very word "allowance" denotes that a source is allowed to emit within the limits of its allowance allocations -- and providing revenue to the U. S. Treasury is not a legitimate purpose of section 110(a)(2)(D)(i)(I). [EPA-HQ-OAR-2009-0491-2812.1, pp.13-14]
ARIPPA
These projections directly translate into disparate and unsupportable allowance allocation proposals under the FIP. EPA proposes to allocate unit-specific allowances to ARIPPA facilities (and apparently other small independent power production units) at a substantially reduced rate, in significant part on the basis that EPA projects that such sources will operate at reduced capacity compared to current levels. EPA conversely proposes to provide increased allowance allocations to certain larger traditional utility units, by projecting that such sources will increase their relative operating rates. [EPA-HQ-OAR-2009-0491-2794.1, p.10] 
Significantly contrary to EPA's approach in the context of all prior Title I emission transport programs, EPA does not propose through the Proposed Rule to establish allowance allocations based upon heat input, but rather projected emission rates. EPA's projected emission rates rely upon both EPA's projections of electricity generation rate and EPA's assumed future emission rates for the relevant pollutant. For the reasons discussed above, the component of the projection relying upon rates of generation is inappropriately skewed based upon consideration of incomplete and incorrect factors in reasonably estimating relative rates of future electricity generation. EPA's analysis is similarly flawed with respect to the other component of its projection  -  emission rate. Perhaps more significantly, however, relying upon this basis for projection is contrary to the mandate of the Clean Air Act, the directives of the Court in North Carolina, and inconsistent with appropriate public policy. In particular, those affected EGUs projected by EPA to emit regulated pollutants at higher rates would receive a higher relative allowance allocation under the Proposed Rule. Under other prior regulatory trading programs, consistent with the objectives of the Clean Air Act, EPA instead proposed to provide allowances based upon established heat input, and application of a consistent emission rate to that established heat input. Because of the approach utilized in this case, the ARIPPA facilities are effectively penalized relative to the proposed allowance allocation because they are relatively lower emitting sources. [EPA-HQ-OAR-2009-0491-2794.1, p.10]   
 
Further, in proposing unit-specific allowance obligations under the Proposed Rule, EPA projects emission rates, based on EPA's analysis of "cost effective" controls for these EGUs. As more fully detailed above, EPA inaccurately predicts that the control options identified for traditional EGUs under the Proposed Rule would likewise apply to the ARIPPA facilities. Therefore, EPA appears to project that the ARIPPA facilities would achieve anticipated emission reductions assumed through the application of the specified control options. As described above, these assumptions are incorrect when applied to the operating and technological characteristics of the ARIPPA CFB sources. Therefore, the same emission rates for ARIPPA facilities would not be "cost effectively" controlled to the lower emission rates calculated by EPA based upon technologies that cannot be cost effectively applied to ARIPPA sources. In this way as well, EPA has inappropriately reduced the proposed allocation for these sources. [EPA-HQ-OAR-2009-0491-2794.1, p.11] 
The combination of EPA's incorrect projections of both future rates of generation and future emission rates results in a greatly magnified discrepancy between appropriate estimation of future rates of emissions relative to those identified by EPA. In turn, these errors translate into EPA's proposed unit-specific allowance allocations, as EPA proposes to provide substantially greater allowances to larger, higher-emitting traditional coal-fired EGUs, while materially reducing the relative allowance allocations for smaller independent power production facilities, including the ARIPPA facilities. This disparity in projected rates relative to EPA's proposed unit-specific allowance allocations, is reflected in the following table depicting NOx emissions and allowance information for selective EGUs in Pennsylvania: [EPA-HQ-OAR-2009-0491-2794.1, p.11]   
 
[Table 2 can be found on page 12 of this comment.] 
The information presented in Table 2 demonstrates that the ARIPPA plants, which are inherently cleaner burning than larger traditional utility units (with NOx emission rates, on a pound per MMBtu basis, two-to-nine times lower for ARIPPA plants), would actually receive fewer allowances under the Proposed Rule (on both absolute and relative bases) than larger traditional utility units, as a result of EPA's assumptions regarding operating and emissions rates at the ARIPPA facilities in the future. Indeed, under the Proposed Rule, certain traditional utility units would only be required to reduce emission rates to levels that are higher than those already being achieved by the ARIPPA plants. [EPA-HQ-OAR-2009-0491-2794.1, pp.12-13] 
 
For these reasons, the approach toward unit-specific allowance allocations selected by EPA through the Proposed Rule cannot be justified relative to the mandates imposed through the Clean Air Act, the direction of the Court in North Carolina, or defensible public policy. The information in Table 2 reflects that numerous larger EGUs would receive a substantially higher allowance allocation under the Proposed Rule than provided to such sources under CAIR. By contrast, the ARIPPA facilities and other smaller units receive a substantially reduced allocation relative to that established under CAIR. The bases for these relative changes and proposed distribution of allowances relate to EPA's attempts to justify provision of greater allowances to sources with higher emitting rates, rather than establishing an allowance allocation scheme that is tied to an objective rate of emissions and an established pattern of operation. The Court's directive  -  that EPA should ensure that its rulemaking more directly requires emission reductions in a manner that is linked to prevention of significant contribution to downward nonattainment  -  is clearly ignored in the circumstance in which larger emitting units with emission characteristics far more likely to cause downward impacts would be afforded the opportunity to substantially increase emissions under the Proposed Rule when compared to CAIR, while the smaller emitting units, for which EPA has not even established significant contribution to downward nonattainment, would be driven to reduced rates of emissions. [EPA-HQ-OAR-2009-0491-2794.1, p.13] 
 
In essence, through the Proposed Rule, EPA proposes to make determinations regarding relative electric generating distribution among various sources. By proposing allowance allocations consistent with these relative electric generating rates, EPA would propose to influence this distribution of generating capacity among source types. Any such judgments regarding relative electric generating capacity among various sources is entirely inappropriate for EPA's determination, inconsistent with lawful objectives of the Proposed Rule, and clearly not consistent with statutory mandates imposed on EPA through the Clean Air Act. [EPA-HQ-OAR-2009-0491-2794.1, p.13] 
 
The significance of EPA's approach under the Proposed Rule is substantially magnified because of EPA's proposed restrictions on allowance transfer. By severely limiting opportunities for securing allowances necessary for compliance demonstrations, EPA would restrict the ability of sources to comply with allowance obligations by more cost effectively securing greater emission reductions at other sources. These restrictions are least pronounced for companies that operate multiple emission units, at least within the same state, since the freedom to transfer allowances among such units is greatest under EPA's various approaches. By contrast, smaller facilities with single affected units are afforded no such option. Where such sources also cannot cost effectively reduce emissions at the affected source because of the unique operating, design or fuel characteristics, as in the case of the waste coal-fired CFB units, such facilities may not be afforded any compliance option under the Proposed Rule. [EPA-HQ-OAR-2009-0491-2794.1, p.13] 
 
ARIPPA objects to the approach used by EPA for determining unit-specific allowance allocations under the proposed FIP. Allowance allocations should be consistent with previously established heat input rates, as reflected in historical data. The allocation methodology should also reflect appropriate equitable considerations, including a source's emissions characteristics, emissions control limitations, and fuel source. Consistent with EPA's proposed approach, the allowance allocation methodology should not result in a "windfall" to any facility? this can be ensured by limiting the maximum allocation to any affected facility to emission levels established by that source. Such approach would also be consistent with the objectives of the Clean Air Act and the D.C. Circuit Court's decision in North Carolina, by ensuring that the proposed program does not result in an emissions increase for any source. Significantly, the proposed allocations should not reflect EPA's judgments about shifting generation rates among source types. 6   [EPA-HQ-OAR-2009-0491-2794.1, p.14] 
 
To the extent that EPA identifies a justifiable basis to regulate the ARIPPA facilities under the Proposed Rule, EPA's proposed basis for determining unit-specific allowance allocations to these waste coal-fired CFB units under the proposed FIP is inappropriate and inequitable. In determining the proposed allowance allocations for affected EGUs in Pennsylvania, EPA relied on several considerations, including, most notably, projected emissions. EPA derived these projections based, in part, on anticipated generating rates, which EPA calculated by focusing primarily on fuel cost. EPA's reliance on fuel cost as a primary factor in determining future generating rates for the ARIPPA sources is flawed, because (1) EPA's cost estimates for coal refuse in the Proposed Rule are incorrect, and (2) EPA fails to consider the significant additional factors which affect generating rates, such as state-specific requirements to use renewable energy sources, and contractual obligations limiting operating rate. For the ARIPPA facilities, EPA has apparently predicted a substantial decline in operating rates, which is directly inconsistent with the operating history for these plants (see Section I.B., Table 1). Moreover, operation at the rates projected by EPA would cause certain ARIPPA facilities to breach their contractual obligations pursuant to PPAs. [EPA-HQ-OAR-2009-0491-2794.1, p.20] 
 
ARIPPA instead recommends that allowance allocations should be determined based on previously established heat input rates, as reflected in historical data reported by each source. This approach would be consistent with the objectives of the Clean Air Act, as well as the directives of the Court in North Carolina, by ensuring that the Transport Rule targets emission reductions from those sources most likely contributing significantly to downwind nonattainment, rather than lower emitting units projected by EPA (based on limited criteria) to reduce rates of generation. [EPA-HQ-OAR-2009-0491-2794.1, p.20] 
 
Additionally, EPA's proposed approach of establishing allowance allocations based on emission rates is contrary to the approach used in the context of all prior Title I emission transport programs, which based allowance allocations on heat input, and is fundamentally inconsistent with the requirements of the Clean Air Act. EPA's proposal to allocate unit-specific allowances based on projected operating rates results in the ARIPPA facilities being allocated allowances at a substantially reduced rate, while larger traditional utility units, for whom EPA has predicted an increase in generating rates in future years, would receive increased allowance allocations. This aberrational result is not only contrary to the Court's analysis in North Carolina but flawed as a matter of public policy. [EPA-HQ-OAR-2009-0491-2794.1, p.21] 
 
Within the Proposed Rule, EPA explains that it wants to offer states substantial flexibility for addressing the Section 110(a)(2)(D)(i)(I) transport issues through a SIP should they choose to do so. Indeed, EPA's stated intent is to provide states with substantial flexibility in implementing the Transport Rule. ARIPPA strongly endorses EPA's intention to ensure states substantial flexibility in implementing the requirements of the Transport Rule. Consistent with this approach, states should be allowed under the Proposed Rule to allocate allowances to affected EGUs in any manner, and on any basis, they deem appropriate to satisfy their established emission budgets. [EPA-HQ-OAR-2009-0491-2794.1, p.21] 
 
ARIPPA also urges EPA to finalize a Transport Rule that maximizes flexibility for interstate allowance trading. EPA has previously promulgated, and continues to implement, successful emission control programs under Title I which rely on the availability of interstate trading for their effectiveness, and which have survived judicial scrutiny. Additionally, due to the marked conservatism inherent in the state emission budgets, EPA could eliminate the restrictions on interstate trading in the Proposed Rule and still meet its objectives for addressing interstate transport. [EPA-HQ-OAR-2009-0491-2794.1, p.21] 
 
An affected source must be able to rely upon allowances secured through interstate trading as its compliance strategy, without being concerned that those allowances may lose their emission value or must be surrendered by the facility because of overall emission rates for the state. This notion becomes especially critical for facilities, like the ARIPPA plants, that would not receive an adequate allowance allocation under the Proposed Rule and, accordingly, would be forced to rely on allowance trading to secure sufficient allowances to offset their emissions. The implementation of a flexible interstate allowance trading program through the Transport Rule would be consistent with EPA's stated key guiding principles for development of the Proposed Rule, including cost effectiveness, providing incentives and flexibility to the regulated community, and ensuring a reliable power supply. [EPA-HQ-OAR-2009-0491-2794.1, p.21] 
 
A. EPA's proposed unit-specific allowance allocations under the Proposed FIP remain inappropriate and inequitable under the NODA, as applied to the ARIPPA plants. 
 
ARIPPA provided extensive comments on the Proposed Transport Rule in support of the position that EPA's stated basis for determining unit-specific allowance allocations under the proposed FIP is inappropriate and inequitable. In publishing the NODA, EPA reports that it devised a more refined model for projecting information relevant to the proposed allocation of unit-specific allowances under the FIP. Although the information identified through the NODA appears to represent a positive refinement in the accuracy and appropriateness of EPA's projections, for the reasons more fully detailed below, EPA's modeled projections remain substantially inaccurate and inappropriate, at least with respect to the ARIPPA facilities. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.2] 
 
EPA proposed through the Proposed Transport Rule that each state's emission budget would be constructed from a combination of reported data and projected emissions data for the EGUs in that state. See "State Budgets, Unit Allocations, and Unit Emissions Rates", Technical Support Document ("TSD") for the Transport Rule, Dkt. ID No. EPAHQOAR20090491, EPA, Office of Air and Radiation, July 2010, at *3. In turn, each EGU's contribution to the state's budget forms the basis of its specific allowance allocation. Id. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.2] 
 
In determining the proposed allowance allocations for affected EGUs in Pennsylvania, EPA relied on several considerations, including projected emissions. EPA attempts to project emission rates based upon its own assessment, reflective of integration between different modeled projections, of anticipated generating rates in the future. EPA's projections for future generating rates are closely linked to its assumptions concerning the future cost of electricity generation, focusing principally on fuel cost. Relative to the ARIPPA facilities, EPA's consideration of fuel cost is flawed in two important respects. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.2] 
 
First, EPA incorrectly estimates the cost of coal refuse as a fuel, as reflected by current fuel costs incurred at the point of fuel production. For example, an evaluation of current actual fuel costs for five representative ARIPPA plants yields an average cost of $1.48/MMBtu. One of these plants reports a current actual fuel cost as low as $0.82/MMBtu. These fuel costs are somewhat inflated insofar as they include, in some cases, costs not directly attributable to the cost of fuel, including ash disposal. Nonetheless, these cost figures are still meaningfully lower than the cost estimates relied upon by EPA to project future fuel costs for coal refuse. EPA appears to have adjusted the bases for its fuel cost analyses relative to coal refuse in the context of the NODA. In fact, it appears that EPA substantially increases its projected fuel cost factor for the use of coal refuse as a fuel. This substantial increase in fuel cost (without regard to other factors used in the model) has the effect of prompting a projected decrease in utilization of EGUs firing coal refuse as a primary fuel. Therefore, at least with respect to this one factor relevant to EPA's modeled generating rates, EPA's change in fuel cost for coal refuse through the NODA would exacerbate the problems with EPA's modeled projections for future generation rates, which would translate into further inaccuracies in the proposed unit-specific allocations under the FIP. [EPA-HQ-OAR-2009-0491-3794.1_NODA,p.2] 
 
Second, EPA's reliance on fuel cost as the primary basis for projecting future generating rates fails to adequately account for numerous other factors affecting generating rates. For example, in Pennsylvania, electricity distribution facilities and suppliers are required to supply a certain percentage of energy from Tier I or Tier II renewable energy sources, irrespective of electricity prices. Therefore, distribution of the generation of electricity will not strictly adhere to lowest cost of generation, as other operative criteria dictate distribution. Because coal refuse-generated electricity qualifies as a Tier II renewable energy source, coal refuse-fired sources will operate at a higher generating rate than cost alone would suggest. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.3] 
 
Additionally, the ARIPPA facilities are subject to contractual agreements pursuant to PPAs and other legal vehicles which dictate minimum or required energy generation and purchase rates, as between these generating facilities and electricity supply and distribution utilities. Pursuant to these agreements, subject to certain allowances for maintenance and downtime, these "coal refusefired EGUs" will operate at a certain rate and supply a certain baseload quantity of electricity to the grid, regardless of relative costs of generation. Although EPA's refined model mitigates, to some extent, the inaccurate projections of future generation rates to the extent influenced by factors other than fuel costs, the refined model does not sufficiently address these considerations and continues to result in incorrect and inequitable projected outcomes. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.3] 
 
Likely because of its failure to accurately consider the true cost of coal refuse as a fuel and account for non-fuel cost considerations, EPA apparently "predicts" a substantial decline in operating rates for virtually all the ARIPPA facilities, and then uses these predictions to determine allowance allocations for the facilities. By contrast, EPA projects that many larger traditional coal-fired EGUs will increase generating rates in the future, in some cases, substantially. In all cases, these projections are directly inconsistent with the operating history for these plants. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.3] 
 
ARRIPA recognizes that the NODA identifies the use of EPA's more refined modeling analysis, and that such refined model reduces the degree of inaccuracy in future projections. However, these refinements far from eliminate such inaccuracies. Specifically, the following tables reflect the disparity between established operating rates for a representative group of existing Pennsylvania facilities and the operating rates projected by EPA through application of its models. Table 1 provides the comparison relative to the information and projections identified by EPA through the Proposed Transport Rule. The Table clearly reveals that EPA projects a material increase in generation rates for larger, higher emitting, traditional coal-fired facilities, while correspondingly projecting material decreases in generation rates for smaller, nonconventional, coal refuse-fired CFB units. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.3] 
 
Table 2 summarizes similar information, but reflects the analysis resulting from application of EPA's refined modeling evaluation described in the NODA. A comparison of the information included within Table 1 with the information included within Table 2 reveals that the extent of the disparity between the source types is less under EPA's refined modeling. However, it is also evident that, even applying the refined model identified by EPA through the NODA, EPA continues to project future generation rates in a way that proposes to shift electricity distribution from smaller, cleaner, nonconventional, coal refusefired CFBs to larger, traditional, higheremitting coalfired sources. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.3] [[See Docket Number EPA-HQ-OAR-2009-0491-3794.1_NODA, p.3 4 for Table 1 and p.5 for Table 5.]] 
 
Relative to the ARIPPA plants, for the reasons stated above, EPA's projected rates of generation clearly understate reasonable estimations of future operations based on consideration of all relevant factors. Indeed, in many cases, EPA's projections directly conflict with specific contractual obligations undertaken by the plants pursuant to PPAs to supply alternative energy to utility companies at a fixed price. In other words, operation at the rates projected by EPA for purposes of the Proposed Rule would cause certain ARIPPA facilities to breach their contractual obligations. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.5] 
 
These projections directly translate into disparate and unsupportable allowance allocation proposals under the FIP. EPA proposes to allocate unitspecific allowances to ARIPPA facilities (and apparently other small independent power production units) at a substantially reduced rate, in significant part on the basis that EPA projects that such sources will operate at reduced capacity compared to current levels. EPA conversely proposes to provide increased allowance allocations to certain larger traditional utility units, by projecting that such sources will increase their relative operating rates. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.5] 
 
Significantly, contrary to EPA's approach in the context of all prior Title I emission transport programs, EPA does not propose through the Proposed Rule to establish allowance allocations based upon heat input, but rather projected emission rates. EPA's projected emission rates rely upon both EPA's projections of electricity generation rate and EPA's assumed future emission rates for the relevant pollutant. For the reasons discussed above, the component of the projection relying upon rates of generation is inappropriately skewed based upon consideration of incomplete and incorrect factors in reasonably estimating relative rates of future electricity generation. EPA's analysis is similarly flawed with respect to the other component of its projection  -  emission rate. It does not appear from the information identified through the NODA that EPA's refined modeling analysis corrects, in any way, the flaws in its emission rate projections through the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.6] 
 
Based upon our review of EPA's database, the inaccuracies in EPA's modeled projections may result, in significant part, from EPA's incorrect information or assumptions concerning facility-specific heat rate and availability  -  factors relied heavily upon by EPA in projecting future generation rates. Individual ARIPPA facilities will provide additional site-specific comments on certain of these inaccuracies. However, it is important to note generally that EPA's approach toward heat rate reflects fundamental misconceptions in the operation of CFB units, especially with respect to the methods used to control emissions. As more thoroughly discussed by ARIPPA in the context of its comments on the Proposed Transport Rule, CFB units inject limestone directly into the combustion bed to achieve SO2 control. To the extent that additional limestone can be added to achieve any further SO2 reduction, 2 such further increase in the addition of limestone will bear upon the actual heat rates for these facilities. 3 Specifically, increased limestone injection requires additional fuel usage, thereby increasing the total heat input to the boiler without correspondingly increasing energy production. At the rates of SO2 control already achieved by these plants, significant additional limestone is required for minor further reduction in SO2 emissions? therefore, the ARIPPA facilities would experience a substantial increase in heat input per unit output in an effort to pursue compliance with the emission standards identified in the Proposed Transport Rule. This corresponds to an increased heat rate for these plants relative to that projected by EPA. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.6] 
 
The combination of EPA's incorrect projections of both future rates of generation and future emission rates results in a greatly magnified discrepancy between appropriate estimation of future rates of emissions relative to those identified by EPA. In turn, these errors translate into EPA's proposed unit-specific allowance allocations, as EPA proposes to provide substantially greater allowances to larger, higher-emitting traditional coal-fired EGUs, while materially reducing the relative allowance allocations for smaller independent power production facilities, including the ARIPPA facilities. ARIPPA's comments on the Proposed Transport Rule discuss these flaws and their bases, and ARIPPA incorporates those comments into these comments on the NODA. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.6] 
 
ARIPPA objects to the approach used by EPA for determining unitspecific allowance allocations under the proposed FIP. As addressed and supported in ARIPPA's comments on the Proposed Transport Rule, allowance allocations should be consistent with previously established heat input rates, as reflected in historical data. The allocation methodology should also reflect appropriate equitable considerations, including a source's emissions characteristics, emissions control limitations, and fuel source. Consistent with EPA's proposed approach, the allowance allocation methodology should not result in a "windfall" to any facility? this can be ensured by limiting the maximum allocation to any affected facility to emission levels established by that source. Such approach would also be consistent with the objectives of the Clean Air Act and the D.C. Circuit Court's decision in North Carolina, by ensuring that the proposed program does not result in an emissions increase for any source. Significantly, the proposed allocations should not reflect EPA's judgments about shifting generation rates among source types. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.7] 
 

 6 For these purposes, ARIPPA distinguishes between circumstances in which a facility has shutdown and/or surrendered its air quality permits. ARIPPA acknowledges that, to the extent that a facility is no longer physically or legally capable of operating at heat input rates previously achieved and documented for such sources, providing allocations to such sources based upon historic heat input rates would inappropriately direct an emission distribution to sources that clearly cannot generate comparable emissions. Such circumstances, however, are significantly distinct from the situation, reflected in the Proposed Rule, in which EPA proposes to distribute allowances based upon EPA's projections of shifting electricity generation, where such projections are not dictated by any factual or legal requirement. [EPA-HQ-OAR-2009-0491-2794.1, p.14] 
2 ARIPPA has separately commented that many factors restrict the ability of individual plants from achieving material improvements in SO2 reduction through limestone addition. In fact, it is not even possible for these plants to achieve the degree of SO2 emission controls contemplated by EPA for these sources through the Proposed Transport Rule by increasing limestone addition rates. Moreover, the increase in limestone addition has corresponding impacts on emission rates for other pollutants? for example, such change in limestone addition will likely contribute to additional NOx formation and emissions. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.6] 
3 With respect to NOx emission controls, as stated above, increased utilization of limestone to attempt to further reduce SO2 emission rates would contribute to increases in uncontrolled NOx emissions and increased heat input. Although increases in ammonia injection (though costly) could theoretically achieve enhanced NOx emission reduction, the permits applicable to most ARIPPA members include strict limitations on ammonia slip. Therefore, these facilities cannot materially increase ammonia injection rates while still adhering to their permit limits. [EPA-HQ-OAR-2009-0491-3794.1_NODA, p.6]   
 
 
Associated Electric Cooperative, Inc. (AECI)
Under the Clean Air Interstate Rule (CAIR), states developed their own methods to arrive at approvable plans largely through engaging the regulated community as stakeholders. Given more time, states could put in motion the same allocation procedures to distribute their budgets under the Transport Rule. The states are closer to the regulated facilities and are better equipped to distribute allowances, implement regulations, and issue permits.  [EPA-HQ-OAR-2009-0491-2845.1 p.3]
EPA's method of assigning unit allocations in the proposed rule is confusing at best and in many cases appears to include bad assumptions. Individual states are better equipped to assure the quality of the information and assumptions for the smaller set of units within their borders. [EPA-HQ-OAR-2009-0491-2845.1 p.3]
There are no legal mandates to replace CAIR by a date certain, thus making the proposed 2012 CATR deadline unnecessary. Associated doubts that EPA can demonstrate measurable environmental benefits by ending Phase I of CAIR in favor of the CATR FIP. Even if demonstrable benefits exist, Associated questions whether EPA has the authority to mandate CATR by a FIP. [EPA-HQ-OAR-2009-0491-2845.1 p.3]
EPA's presumptions on existing or projected emission rates and representative annual heat input totals are simply wrong in many cases. The methodology of picking emissions and heat input data from a potentially non-representative and narrow operating window (i.e. all or part of years 2007, 2008, and 2009) is misguided and faulty. Further, the quality of the IPM/NEEDS inventory assumptions is certain to be too weak for assigning emission allowances and it presumes too much on the generating plans of utilities. There is no way that EPA can look into a crystal ball and predict how much a unit will operate in the future. [EPA-HQ-OAR-2009-0491-2845.1 p.3]
The proposed allocation methodology departs radically from previous air act allowance allocation without explanation. By using only the most recent operating and emissions data from periods of economic downturn, EPA's allocation methodology includes potentially non-representative unit data. Further, EPA's proposed system relies on computer modeling of future individual unit utilization and emissions controls operation or installation. In other words the rationale for the unit allocations comes from EPA's computerized virtual world containing numerous false assumptions. [EPA-HQ-OAR-2009-0491-2845.1 p.8]
The proposed system punishes, not rewards cleaner units, and penalizes rate payers buying from cleaner generating sources at necessarily higher electric rates. EPA has not explained why it has chosen this allocation methodology over more equitable and historic formulas. [EPA-HQ-OAR-2009-0491-2845.1 p.9]
The proposal does solicit comment for alternative approaches, and in particular an approach based on heat input, p. 45311. Associated suggests the allocation methodology similar to that promulgated in CAIR FIP for annual NOx emissions. (See 70 Fed. Reg. 25162, at 25279). This heat input driven system was not overturned by the court's decision in North Carolina. [EPA-HQ-OAR-2009-0491-2845.1 p.9]
As this alternative is detailed somewhat in the proposal, state budgets would be distributed pro rata based on unit historic heat input. Several subcategories could be developed, such as coal and natural gas generation, whereby allowances are distributed based on state allowance budgets and historic heat input from each subcategory. As with the CAIR NOx allowance state option, the allowance allocations to existing units should be based on historic unit highest three of five years heat input. [EPA-HQ-OAR-2009-0491-2845.1 p.9]
Associated advocates the Missouri model for distributing the state CAIR budget that was written into the SIP at 10 CSR 6.362 and 10 CSR 10-6.364. These CAIR NOx allocations were developed by taking the average of the highest three heat input (total annual MMBTU) of a five (consecutive) year range. Each unit was given the benefit its highest heat input, thus putting each unit on a level playing field. The unit heat input was then summed to a total state heat input pool, and a percentage of the total was calculated for each unit according to its contribution to the pool. Each unit was then allocated a pro rata share of the state budget equal to it's percentage of the state heat input pool. Using this method would result in filtering out years of lower production due to special circumstances and put each unit/facility on a more level playing field. Associated recommends using the years 2005  -  2009 for these calculations. [EPA-HQ-OAR-2009-0491-2845.1 p.9]
Request: Should a FIP become necessary according to CAA 110, AECI requests that EPA modify the allocation methodology to the states and to individual units by averaging the three highest heat input years from the years 2005  -  2009. The allowances to the states would be  distributed as a pro-rata share of the total cap of the Transport Rule. Unit/facility allocations would be distributed as a pro-rata share of the state cap. [EPA-HQ-OAR-2009-0491-2845.1 p.9]
Buckeye Power, Inc.
Buckeye is concerned that CATR will punish, rather than reward, electric generating facilities that have already installed emission control systems. Regardless of the methodology used to develop the allowance allocation scheme, EPA must not penalize those that have been proactive in reducing emissions. At a cost of almost $1 billion, Buckeye has installed state of the art and high performing selective catalytic reduction technology ('SCRs') on 100% of its coal-fired units, and has or will soon have installed jet bubbling reactor ('JBR') flue gas desulfurization ('FGD') equipment on 100% of its coal-fired units. At a minimum, CATR must not result in Buckeye being allocated less allowances than it needs to operate its units while employing best available control technology. We understand that a purpose of the rule is to require other utilities to commit to the same scope of an emissions control program as Buckeye has already undertaken, and we support that goal. We agree that uncontrolled coal-fired units need to reduce emissions, but Buckeye already has invested in such an emissions control program at a substantial cost to its members and their approximately 380,000 retail members/consumers in the State of Ohio. Buckeye should be rewarded, not punished, for having already installed these technologies. [EPA-HQ-OAR-2009-0491-2710.1, pp.1-2]
Whether allocations are made pursuant to a FIP or a SIP, individual unit allocations should be based on a unit's historic heat input rates, rather than emissions. Utilizing EPA's proposed approach rewards companies that have delayed installation of control technology. [EPA-HQ-OAR-2009-0491-2710.1, p.2]
Furthermore, whether using historic emissions or heat input to allocate emission allowances, a multi-year test period, rather than a single test year, is clearly more representative of a unit's operations and, therefore, a fairer allocation methodology. In anyone year, such variables as economic circumstances, weather, performance of generating equipment, and/or performance of emission control equipment, including scheduled and forced outages, may skew an allowance calculation, if it's based only on such year. On the other hand, a multi-year test period can average these variables over time. Such a risk is exacerbated for a small utility such as Buckeye with only a few electric generating units, which can not average such variables over a large number of generating units and different geographic locations, as larger utilities can. [EPA-HQ-OAR-2009-0491-2710.1, p.2]
EPA's proposed allocation methodology departs radically from previous Clean Air Act allowance schemes without explanation. EPA's proposed system relies on a single test year of historic actual emissions and on computer modeling of future individual unit utilization and emissions controls operation or installation, rather than relying on heat input and a multi-year test period as used in previous EPA emission allowance allocation proposals. It proposes a federal implementation plan rather than the use of a state implementation plan as the Clean Air Act requires. It unfairly and unreasonably requires utilities, such as Buckeye, who have or will have installed best available pollution control technology, to acquire additional emission allowances (if any will be available under CATR) or to curtail operations in order to meet emission control limitations under CATR. It unfairly and unreasonably renders worthless emission allowances that utilities, such as Buckeye, acquired under CAIR to meet the obligations and requirements of existing law. [EPA-HQ-OAR-2009-0491-2710.1, p.4]
1. Allowances should be apportioned by heat input.
The proposed system punishes, not rewards, cleaner units, by basing the allocation of emission allowances on historic actual emissions, which are necessarily lower on existing controlled units than uncontrolled units. This penalizes utilities, such as Buckeye, who have already made substantial investments in pollution control technology, when such utilities should be rewarded for having made the decision to install pollution control equipment before such equipment was required by law. In the case of Buckeye and its members, who operate on a nonprofit cooperative basis, these costs have been incurred 100% by their ultimate retail members/consumers. It is bad public policy for EPA to discourage utilities from making voluntary investments in pollution control technology, which discouragement will be the result if EPA's proposal is adopted. In the future, utilities will likely only take such minimal actions as are required by law in order to avoid being penalized for having done more than the law minimally requires. EPA has not explained why it has chosen this allocation methodology over more equitable and traditional formulas. [EPA-HQ-OAR-2009-0491-2710.1, p.5]
The proposal solicits comment for alternative approaches, and in particular an approach based on heat input. P. 45311. We urge EPA to adopt the allocation methodology similar to that promulgated in the CAIR FIP for annual NOx emissions. (See 70 Fed. Reg. 25162, at 25279). This heat input driven system was not overturned by the court's decision in North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008). As this alternative is described in the proposal, allowances could be distributed pro rata under state allowance budgets based on unit historic heat input rates. Several subcategories may be developed, such as coal and natural gas generation, with allowances distributed based on state allowance budgets and historic heat input within each subcategory. [EPA-HQ-OAR-2009-0491-2710.1, p.5]
Using historic actual emissions as the basis for allowances punishes early adopters of emission controls. Obviously, baseline emissions will be lower for a unit equipped with pollution controls. EPA's preferred CATR approach would penalize that facility by allocating to it fewer allowances. A heat input approach, unlike an emissions-based approach, would eliminate perpetual allocations to the highest emitting units, and does not punish consumers who have paid for investments in emission control equipment, thereby effectuating a rational policy. This method would be lawful under North Carolina. [EPA-HQ-OAR-2009-0491-2710.1, p.5]
2. A multi-year test period should be used.
Furthermore, a multi-year database, rather than a single test year, is appropriate. It appears that EPA's preferred approach is to allocate allowances based upon historic emissions, using a single test year. Using a single test year is particularly onerous for a relatively small utility like Buckeye. With only a few units, operational aberrations may occur in any single year. The unit could be out of service, thus greatly reducing the emissions for that year. If environmental controls were already installed, they could be having a high performance year, resulting in abnormally low emissions. Buckeye's SCR systems, for example, performed at extraordinarily high control efficiencies in 2006-2007. It is unrealistic and unreasonable to assume that such performance can be sustained. Using a multi-year test period is much more fair and will reduce the impact of such aberrations. For the same reasons, if EPA adopts Buckeye's preferred heat input approach, a multi-year period should be used to determine the appropriate heat input factor. For large utilities with many units, a single test year may be more appropriate than with smaller utilities such as Buckeye, since larger utilities can absorb abnormalities in emissions or control efficiencies within their control technology over a greater number of units; Buckeye, on the other hand, with two units, cannot absorb abnormalities in emissions or control efficiencies since Buckeye does not have as many units to average these abnormalities. The risk of such anomalies must be reduced by lengthening the 'base' period. [EPA-HQ-OAR-2009-0491-2710.1, pp.5-6]
As with EPA's setting of NOx allowances under CAIR, allowance allocations for SO2 and NOx should be updated every five years to reflect a unit's highest three of five years of heat input. [EPA-HQ-OAR-2009-0491-2710.1, p.6]
c. EPA's proposal does not allocate sufficient allowances to allow utilities to operate their facilities with best available emission control technology installed.
The following table identifies the actual annual NOx emissions from Cardinal Unit No. 3 for 2005 and 2009, as well as EPA's proposed annual NOx emission allowances for 2012 and 2014 under CATR:
[Table can be found on page 8 of this comment] [EPA-HQ-OAR-2009-0491-2710.1, p.8]
Buckeye will be allocated annual NOx allowances below those required to operate its units even when they are fully controlled with best available pollution control technology. Cardinal Unit No. 3 had best in class SCRs installed in 2003, and its actual NOx emissions in 2009, when its SCRs were operating on a full year basis, rather than a seasonal basis as in 2005, were 883 tons. These were among the best performing SCRs in the country, with a 93.4% removal rate that year. In fact, the Cardinal Unit No. 3 SCR has ranked in the top decile of SCR performance nationwide every year since 2004. Nevertheless, for 2012 year, Buckeye has been allocated only 621 NOx allowances for Cardinal Unit No. 3; however, Buckeye's emissions exceeded those levels in 2009 even with best in class SCRs already installed. Buckeye's SCR performance is likely to decline over time from its base year performance, since Buckeye's SCRs only recently began year-round operation. A utility that has installed best available control technology should be allocated enough allowances to operate with BACT installed. [EPA-HQ-OAR-2009-0491-2710.1, pp.8-9]
The following table sets forth actual annual 2005 and 2009 SO2 emissions for Buckeye's Cardinal Unit Nos. 2 and 3, as well as proposed SO2 annual emission allowances for such units under the EPA's CATR proposal:
[Table can be found on page 9 of this comment] [EPA-HQ-OAR-2009-0491-2710.1, p.9]
Cardinal Unit No. 2 had FGD equipment installed in 2008, and its actual SO2 emissions in 2009, when its SCRs were operating on a full year basis, were 4,273 tons. Nevertheless, for 2014 year, Buckeye has been allocated only 4,205 SO2 emission allowances for Cardinal Unit No. 2; however, Buckeye's emissions exceeded those levels in 2009 even with JBR FGD equipment already installed. A utility which has installed best available control technology should not be allocated less allowances than are required to operate with BACT installed. [EPA-HQ-OAR-2009-0491-2710.1, p.9]
This unfair allocation is the result of EPA's use of historic emissions rates and a single test year, rather than heat input and a multi-year test year, as the baseline. Buckeye should not be punished for having already installed BACT. Ohio cooperative members/consumers have already spent or will soon spend approximately $1 Billion to install state of the art high performing pollution control equipment for NOx and SO2 on 100% of their base-load coal fired generation. Ohio cooperative consumers should not be required to curtail operations and purchase replacement power, nor to acquire additional emission control allowances (if any are available under CATR), in order to meet EPA's mandates under CATR. Since Ohio cooperatives have already installed or will soon install best available control technology for SO2 and NOx on 100% of their coal-fired generation, it is unreasonable and unfair to require them to do more, when other utilities have not yet undertaken the steps that Buckeye already has or will soon complete. [EPA-HQ-OAR-2009-0491-2710.1, p.9]
d. EPA's CATR proposal will punish existing units with high performing emission controls and reward units that have not invested in adequate emission control technology.
According to EPA's database, the WH Sammis units (Stratton, Ohio) are equipped with SNCR control systems. EPA has allocated the WH Sammis plant 3.22 tons of annual NOx per MW of capacity. But Buckeye's Cardinal Units have been allocated 1.2 tons of annual NOx per MW of capacity. The SNCR NOx control system is less expensive and less efficient than Buckeye's SCR NOx emission control system. Nevertheless, Buckeye's Cardinal Units have been allocated less NOx emission allowances than the Sammis units because Buckeye's Cardinal Units have more expensive and more efficient NOx emission control equipment, which establish lower historic baseline emissions than the Sammis units. This is patently unfair and unreasonable. Buckeye should be rewarded, not punished, for having installed state of the art and high performing SCR equipment. [EPA-HQ-OAR-2009-0491-2710.1, pp.9-10]
In addition, the JM Stuart units have been allocated a total 1.9 tons of annual NOx per MW of capacity, whereas Buckeye's Cardinal units have been allocated only 1.2 tons of annual NOx emissions per MW of capacity. In this case, Buckeye's Cardinal units and the Stuart units have similar SCR systems installed and therefore the two facilities should be allocated similar emission allowances. However, EPA has provided less allowances to Buckeye's Cardinal Units than to the Stuart units. This is arbitrary and unreasonable. [EPA-HQ-OAR-2009-0491-2710.1, p.10]
Furthermore, uncontrolled units have received significantly higher proposed allocations than Buckeye's controlled units. Examples include the Gorsuch plant, which has been allocated 10.36 tons annual NOx/MW, the RE Burger facility, which has been allocated 14.2 tons annual NOx/MW, and the Eastlake plant, which has been allocated 6.06 tons annual NOx/MW, whereas Buckeye's Cardinal Units were allocated only 1.2 tons annual NOx/MW. [EPA-HQ-OAR-2009-0491-2710.1, p.10]
Similarly, Buckeye was penalized and provided significantly less SO2 allocations as compared to uncontrolled units. Buckeye's Cardinal Units received 7.15 tons of SO2 (2014 and beyond) per MW of capacity; whereas the uncontrolled units at Sammis received approximately 14.5 tons/MW. Other uncontrolled units received larger allocations of SO2 on a ton/MW basis. Examples include the Gorsuch Plant at approximately 26.1 tons SO2/MW, RE Burger at 30.62 tons SO2/MW, and the Eastlake plant at 15.63 tons SO2/MW. [EPA-HQ-OAR-2009-0491-2710.1, p.10]
Moreover, our preliminary evaluation of the additional data from the NODA suggests that these circumstances will become even more pronounced. While allocations have not been published for the revised model, it appears that using the NODA data and inputs, the allocations of SO2 allowances to Buckeye's Cardinal Units will be cut in half. As noted above, Buckeye anticipates submitting additional comments on the NODA materials and information. [EPA-HQ-OAR-2009-0491-2710.1, p.10]
Each of these examples illustrates the inequity in the current EPA proposed CATR, which rewards the units that have not invested in BACT, and punishes those that have. Why should Buckeye's controlled units receive less emission allowance allocations than uncontrolled units, when the reason Buckeye and its members are receiving less emission allowances is because they incurred substantial costs to install state of the art and high performing emission control equipment, i.e. JBR FGD equipment and SCR equipment? This result is bad public policy and will not encourage future investments in pollution control equipment absent a mandate. [EPA-HQ-OAR-2009-0491-2710.1, p.10]
e. Natural gas peaking units must be allocated allowances at the lesser of their actual or permitted emission levels in order to allow them to support grid reliability and meet peak demand as and when needed.
With respect to Buckeye's natural gas-fired peaking units, the Greenville Station and the Robert P. Mone Plant, actual NOx emissions for the Greenville Station were 26 tons in 2007, and actual NOx emissions for the Mone Plant were 27 tons in 2007. Under EPA's CATR proposal, the Greenville Station has been allocated 14 NOx allowances, and the Mone Station has been allocated zero NOx allowances. These are clearly insufficient allowances to allow these plants to operate normally. Buckeye's natural gas-fired peaking plants should be allocated sufficient NOx allowances to allow them to operate up to the lesser of their operating permit limits or actual emissions. [EPA-HQ-OAR-2009-0491-2710.1, p.11]
Using historic emissions and a single test year for Buckeye's peaking units is not going to allocate sufficient NOx emission allowances to allow these peaking units to operate the number of hours that will be needed when load and economic conditions improve, or when more extreme weather conditions such as those experienced in the abnormally hot summer of 2010 require the increased dispatch of peaking capacity. Whereas Buckeye's baseload coal-fired units have continued to operate near their historic levels of output during the recent recession, Buckeye's peaking units have not. Baseload units must operate at minimum loading levels or not at all. On the other hand, peaking units are designed to operate only when needed to meet peak load demands. Accordingly, during these recent recessionary times and relatively mild summers of 2008 and 2009, Buckeye's peaking units have not been operating nearly as many hours as they will be needed when the economy and load improves or when extreme temperatures increase the demand for electricity. Since peaking units are critical to grid reliability and only contribute minimally to NOx emissions (being classified as Minor Sources), Buckeye's peaking units should be allocated sufficient NOx emission allowances to allow them to operate up to the lesser of their actual emissions or their permitted limits, which will be needed as the economy improves and these units are called upon to support grid reliability and meet peak load demands. [EPA-HQ-OAR-2009-0491-2710.1, p.11]
Buckeye's Peaking Units Require Increased Allowances
Although Buckeye's Robert P. Mone and Greenville Station natural gas-fired peaking units appear to be allocated some additional allowances under the NODA model (although it is hard to confirm this as EPA has not provided new specific unit allocations for NOx and S02 emission allowances using the updated assumptions contained in the NODA data), they still are not allocated sufficient NOx allowances to allow them to operate consistent with historical practices and up to their permitted limits. Buckeye reiterates its CATR comments that peaking units must be allocated sufficient allowances to allow these minor sources of emissions to operate at the lesser of their actual emissions levels or their permitted limits. Peaking units must be available to function in their critical role of maintaining grid reliability at times of peak demand. [EPA-HQ-OAR-2009-0491-3724.1_NODA, p.6] 
For all of the foregoing reasons, Buckeye Power urges EPA to withdraw its proposed CATR program. If it does proceed, EPA should (1) base its allocation of allowances on heat input rather than historic emissions; (2) employ a multi-year test period, rather than a single test year, for calculating allowance allocations; (5) allocate sufficient emission allowances to units with best available emission control technology already installed or to be installed, so that such units can operate normally and without needing to acquire additional allowances (if any are available under CATR) or to curtail operations; (6) allocate sufficient NOx emission allowances to natural gas-fired peaking units to allow them to operate up to the lesser of their actual emissions or their operating permit limits; and (7) incorporate into CATR existing emission control allowances acquired under CAIR and prior law. [EPA-HQ-OAR-2009-0491-2710.1, p.13]
Calpine Corporation
Calpine believes that the proposed rulemaking could better promote the goal of reducing SO2 and NOx emissions from the electricity sector and level the playing field for companies that have invested in air pollution controls. EPA should develop an allowance allocation mechanism that does not financially harm the very units that are critical to reducing overall emissions from the electric generation sector - namely modern national gas-fired units and other units that have invested in pollution controls. Specifically: [EPA-HQ-OAR-2009-0491-3614, pp.2-3]
:: The current EPA unit allocation method is based on emissions. This approach rewards older, dirtier units.
:: The current EPA unit allocation method is not updated based on changes to future generation patterns. This static allocation does not provide sufficient allowances to low- emitting units that are expected to increase their capacity factor over time.
:: When combined with indefinitely fixed allocations, the limitations on interstate allowance trading create the potential for anti-competitive behavior in some states if large generators hoard their allowances. 
:: Using dispatch models such as IPM as the basis for allowance allocation will disadvantage units that have power purchase agreements in place as well as those in transmission-constrained regions.
:: There are a several inaccuracies related to Calpine units in the EPA allocation database. [EPA-HQ-OAR-2009-0491-3614, p.3]
EPA Should Distribute Allowances Using Output-Based Allocation
Calpine objects to EPA's allocation method that is based on historic emissions because it rewards older, dirtier units and penalizes cleaner, more energy efficient units. We prefer an updating, fuel-neutral, output-based allocation scheme. Output-based allocation (i.e. basing allocations on electricity production) allows units that have invested in air pollution controls to recoup a portion of their investment. Output based allocation encourages the dispatch of cleaner, more efficient units to the overall benefit of ambient air quality and in support of the emission reduction goals of the proposed rulemaking. Such emissions reductions have been achieved in states that have adopted output based allocation in state implementation plans (SIP) for other cap and trade programs such as CAIR and the NOX SIP Call. [EPA-HQ-OAR-2009-0491-3614, p.3]
If it is not feasible to promulgate a rule featuring output-based unit allocation then Calpine urges EPA to allocate allowances to units based on historical heat input. Allocating to units based on heat input could be accomplished by determining each unit's pro rata share of the total state heat input then multiplying by the total state emissions budget. Such an approach would drive emissions reductions and ensure that less polluting units do not have an allowance shortfall. [EPA-HQ-OAR-2009-0491-3614, p.3]
Calpine believes that a heat input allocation approach is responsive to the Court ruling. Specifically, the Court objected to EPA's use of fuel allocation factors finding:
' ... states with mainly oil- and gas-fired EGUs will subsidize reductions in states with mainly coal-fired EGUs.' [EPA-HQ-OAR-2009-0491-3614, pp.3-4]
The Court reached this decision in the context of the state allowance budget allocations -- a prcblem EPA has fixed in the proposed rulemaking by determining each state's contribution to downwind nonattainment. The Court offered no opinion on the unit specific allocation methodology except that it was borne of a flawed state allowance allocation scheme. Thus, EPA is not precluded from allocating allowances to units using the heat-input approach. [EPA-HQ-OAR-2009-0491-3614, p.4]
EPA Should Discourage Anti-Competitive Behavior
There are several states affected by the proposed rulemaking where an inordinate amount of allowances were allocated to a single company. Because interstate trading is limited under the proposed rulemaking, Calpine is concerned that some companies may exhibit anti-competitive behavior and hoard allowances to the detriment of companies that need a liquid market in order to purchase allowances for compliance. This concern is amplified when combined with the proposed concept of allocating allowances in fixed quantities for indefinite periods. For Calpine, this presents a significant concern given the isolated nature of some of our facilities outside of California and Texas. EPA should consider additional mechanisms beyond the limited interstate trading to help companies that may be victimized by anti-competitive hoarding behavior. Calpine supports EPA's option of a limited auction to help with market liquidity. [EPA-HQ-OAR-2009-0491-3614, p.4]
Problems with Basing Allocations on Dispatch Modeling
IPIM is a complex model that attempts to simulate unit behavior in a deregulated electricity market. Unfortunately the electricity market is not fully deregulated and unit operation is dictated by additional factors, most significantly energy purchase agreements and local grid reliability considerations. Calpine is the largest provider of CHP in the country and most of these units have steam sale contracts and power off-take agreements that require the units to operate more than may be predicted by a simulation model. In addition, ERCOT is transitioning to a nodal market that could further restrict electricity flow by affecting local pricing and dispatch. [EPA-HQ-OAR-2009-0491-3614, p.5]
Consider the following examples. Our Carville (LA), Morgan (AL), and Decatur (AL) facilities operate under long term contracts and historic annual heat input of these plants are all above 20 X 106 MMBtu. Yet the IPM model predicts future heat input for these plants with be less than 1.1 X 106 MMBtu per facility, well below levels that will allow Calpine to fulfill its contractual obligations. [EPA-HQ-OAR-2009-0491-3614, p.5]
EPA should consider using the greater of historic heat input and modeled future heat input when apportioning allowance budgets or otherwise allow sources that will have higher than predicted future capacity factors attributable to long term contracts to obtain an increased allowance allocation such as a long-term contract allowance set-aside similar to the new source set-aside. [EPA-HQ-OAR-2009-0491-3614, p.5]
City of Dover, Delaware
The City is concerned that limiting interstate allowance trading will be particularly disadvantageous to small states, such as Delaware, in which there are fewer covered units thus leaving each more exposed to potential short falls of allowances in a given year. Where a larger state, with a diverse mix of electric generating sources and higher total allowance caps, might be better positioned to absorb fluctuations in the allowance markets, smaller states may be constrained by lower total allowance volumes resulting in rate spikes for customers. This is of particular concern for peaking units and states such as Delaware for which peaking capacity is the vast majority of its supply (Delaware imports the majority of its base load supply). This issue is particularly acute if allowance allocations remain as they are under the proposed methodology. At current proposed allocation levels if the City were required to run their two covered peaking units extensively in a year, forcing them to procure allowances in the marketplace, they may find limited supply in a small state such as Delaware. Greater flexibility to trade with generators from other states, above the variability limits currently proposed, would help protect generators in smaller states. [EPA-HQ-OAR-2009-0491-2636.1, p.3]
In order to limit the costs of electricity service to its customers, the City has developed a strategic plan for managing their compliance requirements under CAIR. Part of this plan depends on a reliable source of SO2, NOx annual, and NOx seasonal allowances allocated by program administrators. In addition, prudent management of Dover's requirements under these regulations requires that Dover bank a portion of their allowances for future years as a hedge against spikes in allowance prices and the volatile nature of the dispatch of their peaking units year to year. Under the proposed Transport Rule, the City has serious concerns as to the lack of fungibility of CAIR allowances and the allocation methodology that significantly reduces the number of allowances allocated each year. Under this new structure the City's customers will be unnecessarily exposed to increased electricity costs. [EPA-HQ-OAR-2009-0491-2636.1, p.1]
Under the Transport Rule, covered units receive allowance allocations equal to the lesser of their total 2009 emissions and their total projected 2012 emissions based on EPA's Integrated Planning Model (lPM). The City feels that this methodology insufficiently reflects emission levels for smaller peaking units. The amount of time a peaking unit runs is determined by a number of factors and often varies greatly from year to year. Higher temperatures and increased industrial production often leads to higher electricity demands requiring peaking units to run more frequently. With electricity demand generally lower during 2009 from a receding economy and relatively mild temperatures, peaking units were not required to run as frequently. These factors led to low 2009 emission levels, particularly for peaking units. [EPA-HQ-OAR-2009-0491-2636.1, pp.1-2]
Using the City's units as an example, during all of 2009 the two units ran a total of 174 hours. By way of comparison, through the end of August 2010, the same two units have already run 782 hours. Reviewing other years' generation levels further supports the proposition that 2009 was an abnormally low generation year - the City's two units ran 507 hours and 396 hours in 2006 and 2007 respectively. [EPA-HQ-OAR-2009-0491-2636.1, p.2]
Peaking units play a critical role in overall electricity system reliability and security. By restraining these units with insufficient allocations, EPA threatens to damage system reliability and customer needs for electricity. [EPA-HQ-OAR-2009-0491-2636.1, p.2]
The City feels that a baseline period averaged over a larger period of time, greater than 1 year, would more accurately reflect the reality that peaking units have varied emission levels from year to year. The City recommends using a 5 year baseline period for determining unit allocations. A 5 year time period would provide a more realistic baseline, allowing abnormally high and low generation years to be accounted for and normalized. While the City appreciates the need to set unit allocations and state budgets levels designed to achieve attainment of National Ambient Air Quality Standards (NAAQS), using a singular year for determining baseline allocations has the potential to, and in this case does, disproportionately restrain peaking units. [EPA-HQ-OAR-2009-0491-2636.1, p.2]
City of Tallahasse
The Penalty for "Getting Clean Early" and Baseline Years.
Over the last ten years, the City of Tallahassee has made significant efforts to voluntarily initiate programs to reduce their emissions of NOx, SO2, PM, and Ozone.  Many of these efforts were done to reduce emissions prior to the implementation of different regulatory programs that at the time had not been fleshed out: mandatory greenhouse gas reduction programs, regional haze, and CAIR, just to name a few.  Utilities like the City of Tallahassee, that include environmental protection in all their decision making processes often initiate voluntary reductions prior to future potential enactment of environmental regulations.  Specifically, the City has implemented a number of major electric generating improvements that have significantly improved the efficiency and environmental profile of its two power generating facilities.  These include the construction of Combined Cycle Combustion Turbine Unit No. 8 at the Sam O. Purdom Electric Generating Station (ORIS Code 689), two Sprint Combustion Turbines at the Arvah B. Hopkins (ORIS Code 688) Electric Generating Station (Hopkins), and the repowering of Unit No. 2 at the Hopkins Plant from a conventional steam boiler to a combined cycle unit. The City has installed SCR on the two combustion turbines and the combined cycle unit at Hopkins.  Had the City chosen not to do so, it would have been "rewarded" with additional allowances that the City could bank or sell.  This is a huge disincentive for companies to enact positive environmental benefits before regulatory mandates. [EPA-HQ-OAR-2009-0491-2669.1, pp.2-3]
Clean Energy Group
The language of the Clean Air Act provides EPA with broad authority to implement any of the alternative allocation methodologies set forth in the proposed rule or recommended below. Section 302(y) states that a FIP 'includes enforceable emission limitations or other control measures, means or techniques (including economic incentives, such as marketable permits or auctions of emissions allowances), and provides for attainment of the relevant national ambient air quality standard.' However, while EPA has significant latitude with regard to choosing an allocation structure, the methodology proposed is based on data with notable inaccuracies. The Clean Energy Group is concerned that there is not sufficient time and resources for the final rule to reflect all of the necessary corrections to the underlying data to ensure the rule is based on a legally sound allocation approach. A program that is based on erroneous data and is unnecessarily complex could cause a court to deem it arbitrary and capricious, leading to further delay in addressing air pollution transport. EPA should also consider what methodology will best accomplish the goals of Section 110 - to encourage the most cost-effective emissions reductions and drive investment in the technologies necessary to address transport and nonattainment on a long-term basis.  [EPA-HQ-OAR-2009-0491-2702.1, pp. 4-5]
The Clean Energy Group Does Not Support Allocating Allowances to Units Based on Projected Emissions
While the Clean Energy Group supports the proposed methodology for developing state budgets, it does not support the proposed methodology for allocating allowances to units. The Clean Energy Group recommends an alternative to the use of projected emissions from IPM runs as the basis for unit-level allocations in 2012,2014, or future recalculations for the reasons discussed below. IPM does not consider a range of non-economic factors that may influence a company's decision to operate particular types of units or for the respective Independent System Operator (ISO) to call upon specific units. As a result, the modeling creates unrealistic scenarios for some individual units, such as ignoring dispatch requirements of EGUs subject to power purchase agreements, running natural gas combined cycle units at higher utilization than can be accommodated by the local natural gas pipeline network, and not running oil-fired units that are required to operate to meet load requirements. These distortions of the electricity market are masked when data are aggregated at the state level for setting state budgets, but result in unrealistic or infeasible outcomes when used at the unit level to allocate allowances. As we note above, the Clean Energy Group believes it is important for EPA to propose a rule that withstands, and preferably forestalls, litigation and that can be implemented as quickly and smoothly as practicable. We are concerned that even with EPA's best efforts to correct the underlying data, allocating allowances to units based on projected emissions is not appropriate, and creates an unnecessarily complex system that has the potential for flaws that the rulemaking process cannot address in time to implement the program in 2012. The proposed approach could create a number of erroneous or anomalous results that could cause courts to deem the program arbitrary and capricious.  [EPA-HQ-OAR-2009-0491-2702.1, p. 5]
Further, by basing unit allocations for 2012 on a methodology that assumes an owner will operate installed or planned pollution control technologies at maximum emission control rates, EPA is penalizing companies that have made the capital investments needed to control emissions while rewarding companies that are not controlling emissions. As EPA states in the preamble to the proposed rule, 'this means that a unit that installs control equipment receives fewer allowances than a similar unit that did not install control equipment.' This result is counterproductive to EPA's overarching goal of driving investment in strategies to improve environmental performance. [EPA-HQ-OAR-2009-0491-2702.1, p. 5]
Therefore, the Clean Energy Group recommends that EPA modify the unit allocation scheme. There is no strong policy or legal reason that the methodology for determining state budgets and the methodology for distributing allowances to units need to be the same. Below, the Clean Energy Group proposes alternative unit allocation approaches that are consistent with the D.C. Circuit's decision because they do not alter the state budgets, which are based on each state's significant contribution. Additionally, the proposed approaches are fuel-neutral and would not raise the concerns identified by the court regarding CAIR's use of fuel adjustment factors. [EPA-HQ-OAR-2009-0491-2702.1, p. 6]
Alternative Allocation Methodologies to Promote Cost-Effective, Consistent Emissions Reductions
In order to ensure the data underlying the allocations to units are legally sound, we propose that EPA adopt a historic basis for unit allocations, such as historic output or heat input, which could be adopted without additional notice and comment. Many of the Clean Energy Group companies have long supported output-based allocation approaches. An output-based allocation relies on energy production (megawatt-hour [MWh]) as the basis for determining the number of allowances that a unit will receive prior to the compliance year. For example, if a unit generates 10 percent of the electricity produced by covered units, it would receive 10 percent of the available allowances. The benefits of an output-based allocation include promoting more efficient and cleaner production of electricity. In addition, the methodology does not further penalize companies and their customers for investments made in cleaner generation prior to a regulatory mandate.  [EPA-HQ-OAR-2009-0491-2702.1, p. 6]
Given EPA's use of historic heat input in previous allocation proposals, the Clean Energy Group also supports allocating allowances to units based on a unit's pro rata share of its state's historic heat input (i.e., million British thermal units [mmBtu]), as was originally proposed for CAIR, prior to the introduction of the fuel adjustment factors. We note that the D.C. Circuit invalidated the use of fuel adjustment factors, not the use of historic heat input. The historic heat input should be based on the maximum annual heat input for units during the period of calendar years 2007 through 2009. We recommend using the annual maximum of reported data during the three-year period rather than the average of those three years in order to ensure an outlier year does not dramatically affect the allocation (e.g., the unusually low utilization in 2009). In cases where an owner has not reported heat input data for one or all 0 f the years, we propose that EPA allow the owner to submit such data for consideration, provided that the data are of equivalent quality. [EPA-HQ-OAR-2009-0491-2702.1, p. 6]
Such an allocation methodology would address many of the Clean Energy Group's concerns with EPA's preferred approach. Most significantly, it would not be based on modeled future emissions with its known inaccuracies for some types of units that may dispatch for noneconomic purposes and would be based on verified data EPA already holds. Additionally, this approach would correct the proposed methodology's disadvantages for early actors that EPA acknowledges in the proposal. [EPA-HQ-OAR-2009-0491-2702.1, p. 6]
It is important to note that the Clean Energy Group is proposing this approach with the goal of EPA implementing the Transport Rule by January 1,2012. Thus, we would welcome the opportunity to discuss and provide feedback on any additional allocation approaches suggested in other stakeholders' comments. However, the Clean Energy Group companies oppose an allocation approach based solely on historic emissions. Emissions-based allocations, similar to the fuel-adjusted heat input-based allocation rejected by the D.C. Circuit, reward higher-emitting facilities at the expense of early actors and discourage future early action by companies. Penalizing early actors and rewarding high-emitters is exactly the wrong signal EPA should send to industry as the Agency works to develop and implement multiple regulations for the electric sector and other industries. [EPA-HQ-OAR-2009-0491-2702.1, pp. 6-7]
The allocation methodology for 2014 and thereafter must send a clear and long-term price signal to drive the installation of cost-effective emission controls to address air transport. If EPA allocates allowances to units based on historic output, historic heat input, or a combination of the two, the Clean Energy Group recognizes flexibility in 2012 and 2013 may be necessary. This flexibility during the transition period could include, for example, EPA's proposed unlimited interstate trading or an alternative allocation methodology that transitions to a historic heat input allocation. We agree with EPA that as-yet-unplanned controls cannot be implemented before 2014 and, therefore, the 2012 to 2013 transition period must seek lock in the expected gains from CAIR, rather than drive additional reductions. This transition period must ensure air quality does not backslide from what CAIR has accomplished, or would have accomplished before 2014, while allowing companies to plan for further necessary emissions reductions beginning in 2014. [EPA-HQ-OAR-2009-0491-2702.1, p. 7]
Future-Year Unit Allocations
Finally, EPA must propose a clear and uniform mechanism to reduce unit allocations when necessary (e.g., when future NAAQS revisions result in lowered state budgets). Regardless of EPA's ultimate allocation methodology, transparency will be essential to continued stakeholder support. The alternative allocation methodology proposed above will facilitate such a mechanism in a clear and transparent manner that also drives emission reductions, in support of the aims of Section 1l0(a)(2)(d).  [EPA-HQ-OAR-2009-0491-2702.1, p. 7]
While the proposed Transport Rule is silent on how a revised NAAQS would affect future state budgets, we believe that clarity on this issue in this rulemaking is imperative to ensure an efficient emission allowance market with proper price signals for unit operations, pollution control investments, and retirement. Prolonging this uncertainty until [mal promulgation of a future Transport Rule would only weaken price signals and stifle incentives to invest in cleaner generation.  [EPA-HQ-OAR-2009-0491-2702.1, p. 7]
Some members of the Clean Energy Group are concerned that the proposal's fixed allocation methodology would disadvantage clean generating units whose utilization is expected to increase over time. To address this problem, EPA could update unit allocations for non-retired units every three years to account for changes in utilization. Other members of the Clean Energy Group recommend that EPA's incorporation of the auction provisions proposed in these comments, below, is sufficient to address changes in generation. [EPA-HQ-OAR-2009-0491-2702.1, p. 7]
Peaking Units and Rounding Conventions
a. Auction the Clean Energy Group recommends that EPA establish a small auction of allowances that is initially similar in size to the proposed new unit set aside. Similar to the small auction in the Acid Rain Program in structure and implementation, an auction would promote price discovery and liquidity. Although the Clean Energy Group believes that market manipulation would be a greater risk under EPA's proposed Alternative 1 than under the preferred alternative, we are concerned that the limited trading under the preferred option has the potential to result in some market manipulation in isolated areas. An auction would mitigate these concerns. Additionally, we propose below that EPA consider shifting excess allowances from retired units to the auction rather than the new unit set aside. An auction that gradually increased in size would phase-in a more level playing field for all emission units in terms of allowance pricing. A growing auction would likely also further drive investment in control technologies by higher emitting units. Finally, owners who have already incurred the cost of installing and operating control technologies would benefit by needing to purchase relatively fewer allowances at auction. [EPA-HQ-OAR-2009-0491-2702.1, p. 8]
The Clean Energy Group is also concerned that EPA's proposed methodology disadvantages natural gas peaking units relative to higher-emitting units, in clear contrast to the emissions reduction goals of Section 110. Because these units have low annual emissions and only run at times of high demand, the IPM model projects S02 emissions of slightly less than 0.5 tons. Based on the proposed methodology, EPA would round these allocations to zero when calculating the unit's allowance allocations. If EPA retains the preferred allocation methodology, the Clean Energy Group recommends that EPA at least round these units' allocations to one ton (in contrast to the zero proposed) so as not to discourage use of cleaner fuels during periods of peak demand. [EPA-HQ-OAR-2009-0491-2702.1, p. 8]
If EPA agrees to modify the unit allocation methodology as the Clean Energy Group recommends, EPA may need to consider whether to also adjust the method for calculating the surrender requirement for complying with assurance provisions. The proposed rule links a unit's allocation and the assignment of responsibility for the assurance provisions, but this linkage may or may not be appropriate depending on the final allocation methodology. [EPA-HQ-OAR-2009-0491-2702.1, p. 10]
Treatment of Retired Units' Allocations
The Clean Energy Group supports EPA's proposal to continue to allocate allowances to retired units for six years after ceasing operations. The six-year period ensures that companies make retirement decisions independent of any allocation and allowance value. However, rather than placing these allowances in the new unit pool or redistributing these allowances at the end of the six-year period, the Clean Energy Group recommends that EPA use these allowances to increase the auction pool over time. [EPA-HQ-OAR-2009-0491-2702.1, p. 8]
Corrections to the Modeling Assumptions
When reviewing EPA's modeling assumptions and results, the Clean Energy Group companies have noted a number of incorrect assumptions and unrealistic results (e.g., pollution controls assumed but not planned, units not projected to run that are contractually required to, etc.). To address unit level data issues and potential inaccuracies, individual Clean Energy Group companies will submit separate comments with technical corrections on a unit basis in separate comments to EPA. There are a number of other issues that cannot be appropriately handled by the model. For example, Clean Energy Group companies have:
-units with power purchase agreements that are modeled as having a lower heat input than is required to fulfill contractual requirements,
-units located in load pockets with high demand that are modeled as having a lower heat input than has historically been required to maintain reliability, and
-units that are modeled to run on natural gas at rates that exceed local pipeline capacity. [EPA-HQ-OAR-2009-0491-2702.1, pp. 8-9]
Another area of particular concern is the model's treatment of dual-fuel oil and gas units. During a July 7, 2010, EPA briefing hosted by the Edison Electric Institute (EEl), EPA staff acknowledged that IPM has difficulty handling dual-fuel units because there are non-economic reasons that a company must run such units that the model is not capable of considering. The Clean Energy Group strongly encourages EPA to correct this modeling limitation through adjustments to the model or through post-modeling adjustments to unit emissions. We also note that this issue is not limited to dual-fueled units, and would be resolved by allocating according to our proposed methodology. [EPA-HQ-OAR-2009-0491-2702.1, p. 9]
These issues provide clear examples of why EPA should move away from the model-based approach to allocating allowances and toward a historic basis as recommended by the Clean Energy Group. If EPA elects not to change the allocation approach, then EPA will need to make the necessary adjustments to the model or its output. [EPA-HQ-OAR-2009-0491-2702.1, p. 9]
We also recommend that prior to finalizing the Transport Rule, EPA release as soon as feasible a Supplemental Notice of Proposed Rulemaking and/or additional Notice of Data Availability (NODA) that allows owners of covered units to verify the data underlying the allocations in the final rule and provide any necessary comments to correct the data. For example, if EPA decides to retain the proposed allocation methodology, the Clean Energy Group recommends that EPA release the updated assumptions and modeling results used as the basis for the allocations, along with revised unit allocations. Such a process would ensure the final data underlying the rule are as accurate as possible by providing stakeholders with an opportunity to submit additional corrections. This effort could occur while EPA is drafting other provisions of the final rule and thus would not delay release of the final rule in early 2011 or implementation on January 1, 2012. It would, however, improve the accuracy of and the confidence in EPA's underlying data. [EPA-HQ-OAR-2009-0491-2702.1, p. 9]
The Clean Energy Group has historically preferred a legislative solution that reduces ozone and particulate concentrations in the Eastern U.S. through unlimited interstate trading because market-based programs provide the most cost-effective reductions. However, we recognize that EPA is constrained from allowing unlimited interstate trading. EPA's proposal remains within the constraints of the D.C. Circuit's decision while offering as much trading as possible under Section 110. Legislation granting EPA authority for regional trading is likely the only way to allow an unlimited trading system that ensures the most cost-effecive reductions.  [EPA-HQ-OAR-2009-0491-2702.1, p. 10]
The preferred option manages to allow some interstate trading while staying within the constraints of the D.C. Circuit decision by ensuring the necessary emissions reductions occur in the states identified as contributing to nonattainment or interfering with maintenance in other states. At the same time, the preferred option allows owners to use market mechanisms to buy and sell allowances. Allowance markets are essential to promoting cost-effective reductions.  [EPA-HQ-OAR-2009-0491-2702.1, p. 10]
Cleco Corporation
B. Unit Allocations Should Have Firm Basis in Actual Emissions Data.
Cleco is troubled by EPA's sole reliance on projected data, in some cases, to set unit allocations. As noted above, unit allocations should be left to the individual states, who understand the unique aspects of electric generation within their jurisdiction. But should EPA persist with imposing a FIP, it should ground unit allocations in actual emissions and dispatch data. To the extent EPA relies on projected data, at all, it should do so cautiously. Predicting fuel costs, dispatch etc. involves numerous variables, which if imprecise can lead to unrealistic projections. Based on what we have been able to determine at this point, EPA's IPM projections lead to allocations that simply do not reflect reality  -  as evidenced in Louisiana's NOx allocations. At this point, we caution EPA against relying too heavily on its own projections to set unit allocations. We will continue to review this issue in the context of EPA's new IPM runs provided with the NODA and will refine this comment, as appropriate. [EPA-HQ-OAR-2009-0491-2859.1 p.8]
Connecticut Department of Environmental Protection
EPA's allocation methodology is inconsistent and does not reflect reality. The Integrated Planning Model (IPM) has historically been used to predict large regional trends in EGU operations and the associated emissions from these stationary sources. IPM results at the state and local levels are less reliable and using IPM for predicting operations of individual EGUs is simply not accurate. For example, the IPM Base Case model run for 2012 projects that the 9 oil/gas LFBs in Connecticut (see Table A-4) will not operate in 2012. However, all 9 LFBs have already bid into the ISO-NE Forward Capacity Market through May 2013 and are contractually obligated to be available through that date, making it highly unlikely that they will cease operations by 2012. Furthermore, 8 of the 9 LFBs are contractually obligated to be available in the Forward Capacity Market through May 2014 (only Bridgeport 2 is not contractually obligated through May 2014). [EPA-HQ-OAR-2009-0491-2780.1 p.15]
[[Data Table Here]]
The IPM also led to incorrect source specific allowance allocations. The EPA proposed allocation to AES Thames is 847 SO2 allowances in 2012 based on IPM projections. EPA identified this allocation because AES Thames does not have reported SO2 data in the CAMD data system. However, AES Thames reported SO2 emissions to CTDEP in 2009 were 2298 tons (see Attachment D). AES Thames units operate under permits that require flue gas desulfurization accomplished by in-bed injection of limestone into the boilers for a minimum 75% SOx control efficiency. No additional controls are planned and cannot be reflected in 2012-2014 allocations. Furthermore, AES Thames operates under a long-term power purchase agreement that contractually obligates them to deliver their electrical output under a fixed price through 2015. The allocation to AES Thames must be corrected in the final Transport Rule. [EPA-HQ-OAR-2009-0491-2780.1 p.15]
EPA has indicated that SO2 allocations to Bridgeport Station 3 are based on operating data during the 4th quarter of 2008 and the first 3 quarters of 2009. The 2009 operations of Bridgeport Station 3 were notably lower than previous years due to the cool wet summer, poor economic conditions and natural gas prices that pushed Bridgeport Station 3 down the bid stack.
The IPM is also internally inconsistent. It projected that LFBs will not operate in Connecticut in 20123 yet still allocated 634 SO2 allowances to these sources. In contrast to the IPM projections that all 9 LFBs in Connecticut will shut down by 2012, the IRP model, described in the Peak Emissions discussion above, projects a more rational outcome; that 4 LFBs (Bridgeport 2, Middletown 3 and Norwalk 1 & 2) may shut down in 2013 and 2 additional LFBs (Middletown 4 and Montville 6) may shut down in 2016. Given the poor correlation between the IRP and IPM models and the inability of the IPM to track the reality of contractual agreements such as long term power purchase agreements and the operation of the forward capacity market in ISO-NE, the IPM cannot accurately predict unit level operations and should not be used by EPA to base unit level allocations in Connecticut. [EPA-HQ-OAR-2009-0491-2780.1 p.16]
Given the demonstrated flaws inherent in the IPM, CTDEP recommends EPA utilize the IRP modeling data in Attachment C in its allocation methodology for the Connecticut LFBs. CTDEP also requests that EPA revise its NOx and SO2 allocations to Connecticut consistent with the data provided in Attachments B-D based on historical electricity output basis. Additional Connecticut-specific allocation issues are set forth in Attachment B.  [EPA-HQ-OAR-2009-0491-2780.1 p.16]
Consolidated Asset Management Services (CAMS)
In regard to the unit specific allocation methodology, we request that EPA allow for either a state-specific defined approach or a heat-input approach be taken instead of the current approach as detailed in the State Budgets, Unit Allocations, and Unit Emission Rates TSD including associated Allocation Tables. In the state-specific approach each state shall implement their own methodology for allocating the allowances as provided in the State Emission Budgets. This approach would allow each state to craft a methodology best fitted for its energy profile and future growth, with an allowance variability for defined interstate trading. The other approach to assigning unit-specific allocations is similar to the heat-input approach as described in Alternative allocation methods section of the proposed TR preamble, page 45311. This approach would allocate allowances to units based on a ratio of the unit specific annual heat input and the summation of each unit's heat input in the state with the State Emission Budget. This methodology could use 3-year average look-back approach to be calculated on an annual basis for future year allocations. Therefore, the State Emission Budget is being met, with an allowance variability for defined interstate trading, while the level of activity a unit exhibits is being properly captured in the allocation process. [EPA-HQ-OAR-2009-0491-2612.1, p.1]
Unit Heat Input Approach Example Calculation: 
Given, for example: 
Unit 3-year average Heat Input (HHV) = 8,000,000 mmbtu State Total 3-year average Heat Input (HHV) from affected units = 1,200,000,000 mmbtu State Emission Budget = 75,000 tons of given Pollutant of Concern, taking into account new-unit set aside and other account subtractions. [EPA-HQ-OAR-2009-0491-2612.1, p.1]
Calculation: 
(8,000,000 / 1,200,000,000) * 75,000 = 500 Unit Specific Allocations of Pollutant of Concern [EPA-HQ-OAR-2009-0491-2612.1, p.1]
Both of these approaches also allow for the state to apply a broader definition of an affected unit, as seen in some of the Northeastern states in regards to lowering the nameplate capacity threshold of an affected unit from 25 MW to 15 MW, without impacting the existing units that were not considered in the proposed unit allocations as defined in the State Budgets, Unit Allocations, and Unit Emission Rates TSD including associated Allocation Tables. [EPA-HQ-OAR-2009-0491-2612.1, p.2]
Constellation Energy
One criticism of this approach is that it rewards companies that delayed installing controls and penalizes companies who controlled early, or invested in low-emitting generation in anticipation of tightening emission limits. Once the Transport Rule is promulgated, should EPA transition to an alternative methodology to address these criticisms, Constellation Energy urges that EPA refrain from schemes with frequent allowance allocation updating; those that provide incentive to delay coal unit retirement; or those that provide an incentive to increase utilization in order to capture more allowances via the updating process. [EPA-HQ-OAR-2009-0491-3613, p.2]
Council of Industrial Boiler Owners (CIBO)
The Transport Rule establishes a new SO2 trading program, independent of the existing Title IV program. EPA and others have touted the Acid Rain Program as an example of how market based regulatory programs can reduce the cost of emissions reductions. The underlying reason for this is that the Acid Rain Program set total emissions limits that were attainable with use of conventional emissions control technology and/or fuel selection so that cost effective over-control could be employed at some units and other less costly approaches could be used at other locations with use of emissions trading. EPA's proposed Transport Rule, however, imposes increased emissions reductions with the promise of continuing reductions in the future, and it openly limits the ability to broadly trade emissions allowances. Thus EPA has demonstrated how reliant market based programs are on basic requirements such as trading and cost effective over-control, and without those, market forces cannot function, as evidenced by the recent precipitous drop in SO2 allowance prices. [EPA-HQ-OAR-2009-0491-2751.1 pp.3-4; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, p.3, 10/15/2010]
The problem with the allowance allocation methodology being used by EPA to provide allowances under the Proposed Rule is substantially magnified by EPA's proposed restrictions on allowance transfer. By severely limiting opportunities for securing allowances necessary for compliance demonstrations, EPA would restrict the ability of sources to comply with allowance obligations by more cost effectively securing greater emission reductions at other sources. These restrictions are least pronounced for companies that operate multiple emission units, at least within the same state, since the freedom to transfer allowances among such units is greatest under EPA's various approaches. By contrast, smaller facilities with single affected units are afforded no such option. Where such sources also cannot cost effectively reduce emissions at the affected source because of the unique operating, design or fuel characteristics, as in the case of the waste coal-fired CFB units, such facilities may not be afforded any compliance option under the Proposed Rule.   [EPA-HQ-OAR-2009-0491-2751.1 p.4; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, p.3, 10/15/2010]
Allocations [EPA-HQ-OAR-2009-0491-2751.1 p.8]
EGUs allocation given to non- EGUs. [EPA-HQ-OAR-2009-0491-2751.1 p.8]
In some cases, EPA has incorrectly identified non- EGUs as covered units. EPA needs to carefully evaluate the facilities it included in the modeling as Transport Rule units and remove those that are inappropriate. [EPA-HQ-OAR-2009-0491-2751.1 p.8]
Allocations, including allocations in the NODA, are incorrect and will greatly increase costs for some sources. [EPA-HQ-OAR-2009-0491-2751.1 p.8; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, p.4, 10/15/2010]
Allocations are incorrect because they are based on very erroneous assumptions. For example, in determining the proposed allowance allocations for affected EGUs, EPA relied on several considerations, including projected emissions. EPA attempts to project emission rates based upon its own assessment, reflective of integration between different modeled projections, of anticipated generating rates in the future. EPA's projections for future generating rates are closely linked to its assumptions concerning the future cost of electricity generation, with a major focus on fuel cost. [EPA-HQ-OAR-2009-0491-2751.1 p.8; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, pp.4-5, 10/15/2010]
Base summary data shows cost curves and pricing for coal, waste coal, landfill, gas, etc. This is used in the model to determine dispatch. Some CIBO members run waste coal-fired units. EPA discusses waste coal in Chapter 11 of the documentation. In that Chapter, the pricing for waste coal is tied to DOE-EIA AEO 2010 supply curves. Yet, the coal supply curves set forth in Chapter 9  -  Appendix 9- 4 data reveal a code and a cost for waste coal but provide no economic supporting data or explanation. (In the model run between v3.02 and v4.10, the prices of waste coal on a cost per MMBtus goes from $1.29 MMBtus to $2.27/MMBtus. Reported waste coal costs have averaged $1.48/MMBtus but include additional cost beyond the fuel cost including FOB mine and transportation costs (i.e., coal combustion byproduct management and transportation). There are reported costs in the $0.82/MMBtu range. The incorrect cost assumptions distort the ultimate dispatch calculations, resulting in much lower total Btus/year, and as a result, the allocations are impacted. Data for one CIBO member indicated a 76% availability, which is below that facility's normal availability range. Further, that facility is contracted for power and its normal availability is significantly higher. [EPA-HQ-OAR-2009-0491-2751.1 p.8; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, p.5, 10/15/2010]
Another example is that IPM did not consider whether sources have a contract, REC credits, or other reasons to run at higher availability. Ultimately, if dispatch and allocations do not reflect the reality of a plant's operations, a plant will be forced to purchase credits at whatever cost, if credits are available. As there is intrastate-only trading in the SO2 Group 1 States (PA, WV, OH and others), credits will be less available and compliance more costly. [EPA-HQ-OAR-2009-0491-2751.1 p.8; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, p.5, 10/15/2010]
Allowance allocations should be consistent with previously established heat input rates, as reflected in historical data. The allocation methodology should also reflect appropriate equitable considerations, including a source's emissions characteristics, emissions control limitations, and fuel source. Consistent with EPA's proposed approach, the allowance allocation methodology should not result in a "windfall" to any facility; this can be ensured by limiting the maximum allocation to any affected facility to emission levels established by that source. [EPA-HQ-OAR-2009-0491-2751.1 p.9; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, p.5, 10/15/2010]
There is a concern about how EPA determined the emission rate/allowance rate for SO2, NOx and Ozone NOx. Emission rates are based on EPA's definition of highly cost effective controls -  made not on plant basis but on a model plant basis. In regard to the waste coal plants, the assumptions in the documents refer to bituminous coal, not waste coal from anthracite or bituminous operations. Since the waste coal plants utilize circulating fluidized bed (CFB) combustion and inject limestone to control SO2 emissions, the incremental costs for controlling SO2 by adding a scrubber (wet or dry) is higher than what is projected. In many cases, the CFB unit cannot simply add more limestone to obtain 95% to 98% reduction in SO2. There are limitations to what the boiler can be fed or hold. The additional limestone means additional fuel with more sulfur going to the boiler and increased uncontrolled NOx emissions. The increased uncontrolled NOx means an increase in ammonia usage for SNCR units. However, the amount of ammonia that can be utilized is limited by permitted levels of ammonia slip (5ppms). Therefore, all of these issues need to be considered when evaluating actual unit operation and equitable distribution of allowances. [EPA-HQ-OAR-2009-0491-2751.1 p.9]
Dow Chemical Company
Dow believes that EPA's allocation of NOx allowances under the Transport Rule/FIP is flawed. If it is determined that a FIP is still authorized and needed after consideration of the comments above and the more detailed comments submitted by LCA, Dow requests that EPA substantially revise its methodology for allocations and the allocations themselves. EPA's scheme causes an economic inequity, for no discernable environmental reasons. EPA has refused to allocate any allowances to quite a number of sources in Louisiana simply because EPA's IPM modeling projects that they will no longer be operating or will be operating at only minimal or reduced rates.1 This means, if they are actually operating, they will have to purchase potentially millions of dollars per year worth of NOx allowances. While the economic model EPA used is not well understood, the reality is that the proposed allocations do not align with the very data submitted to EPA CAMD for the units under CAIR. [EPA-HQ-OAR-2009-0491-2775.1 p.3]
Dow is the owner and operator of the Plaquemine Cogeneration facility which is subject to Acid Rain requirements for SO2 and CAIR requirements for NOx. The Plaquemine Cogeneration facility consists of four gas-fired GE Frame 7 FA gas turbines which are equipped with dry low NOx combustors. Each turbine is equipped with a heat recovery steam generator (HRSG) and a supplemental-fired duct burner system. Each gas turbine/duct burner unit is equipped with a Selective Catalytic Reduction (SCR) unit for further NOx reduction. Thus these units employ Best Available Control Technology.  [EPA-HQ-OAR-2009-0491-2775.1 p.3]
The Dow Plaquemine Cogeneration facility provides critical steam and electricity to the Dow Louisiana Operations chemical manufacturing facilities. Excess electricity is sold to the grid. Each of these EGUs runs year round, not simply during ozone season. These units represent a considerable investment to Dow. These units operate a high percentage of their capacity and Dow has no plans whatsoever to curtail operations. [EPA-HQ-OAR-2009-0491-2775.1 p.3]
It is difficult to understand, given the above, that EPA would project that the Dow Plaquemine Cogeneration facility would operate at reduced rates. EPA sent no data requests to Dow asking about future operations of the Plaquemine Cogeneration units. EPA CAMD has a considerable amount of historical data indicating the units operating rates and emissions, yet the IPM projects that these units will be operating at reduced rates in eighteen months. For this reason alone, note due to any environmental impact, EPA has proposed to provide each of the Dow units with allowances covering only a portion of their annual NOx emissions. The below table demonstrates this point: [EPA-HQ-OAR-2009-0491-2775.1 p.3]
[[Data Table Here]]
The assumptions EPA used to reach this result must be modified to reflect reality. The adverse impact to Dow associated with the cost of purchasing NOx allocations would be significant. The staff for the Louisiana Public Service Commission has estimated at least the following annual costs to Dow (i.e., not including ozone season allowances) to be $159,768. This estimate was based on a conservative assumption that annual NOx allowances would be valued at $1,200 per ton. With such a limited trading market as proposed by EPA, the adverse economic impact could be much higher. The Dow Plaquemine Cogeneration units are highly efficient, low emitting cogeneration units. EPA has no rational reason for imposing such costs on these units.  [EPA-HQ-OAR-2009-0491-2775.1 p.5]
If Interstate Transport impacts from Louisiana need to be addressed, EPA should allow Louisiana to make the required NOx and SO2 allocations in a SIP. Alternatively, in the event a FIP is needed and justified to address interstate transport of Louisiana emissions on Texas receptors, then Dow requests that EPA allocate the NOx allowances by providing EGUs with the same % of the total state budget that were approved in the Louisiana NOx CAIR SIP. [EPA-HQ-OAR-2009-0491-2775.1 p.5]
DTE Energy
DTE supports EPA's proposal not to permit government-run allowance auctioning under the preferred remedy option. EPA should remain opposed to allowance auctioning under the preferred option or the intrastate trading alternative. [EPA-HQ-OAR-2009-0491-2851.1, p.3]
Duke Energy
Duke Energy Supports EPA's Proposal to Permit Banking of Allowances Beginning in the First Year of the Program.  In the PTR, EPA properly recognizes the important environmental and economic benefits of allowance banking. The ability of sources to use banked allowances for compliance with the program encourages them to make early emission reductions to the extent that cost-effective early reductions are possible. While the nature and stringency of the PTR's emission reduction requirements and its proposed compliance schedule make the extent to which it might be possible for sources to make extra emission reductions highly uncertain, nevertheless, having the option of being able to make extra reductions and bank allowances is an important flexibility measure that EPA should retain. [EPA-HQ-OAR-2009-0491-2689.1, p.3]  
Duke Energy Supports EPA's Decision Not to Auction Allowances under the Proposed Limited Trading Remedy Option.  
Duke Energy supports EPA's proposal not to include any allowance auctioning under its Proposed Limited Interstate Trading Remedy Option. The only outcome of an allowance auction is an increase the cost of the program for companies and their customers. An auction would make no contribution toward achieving emission reductions or the environmental objectives of the program. If, however, EPA promulgates a final rule based on the Intrastate Trading Remedy Option, an option that Duke Energy does not support, EPA should remove from that option the proposed provisions for allowance auctions. It is entirely possible to accomplish the objectives of those proposed auctions through a no-cost distribution of allowances. [EPA-HQ-OAR-2009-0491-2689.1, p.5]  
Duke Energy Supports EPA's Proposal to Continue to Allocate Allowances to Non-Operating Units for a Limited Period of Time.  
In the PTR, EPA proposes that once an electric generating unit ("EGU") does not operate (i.e., does not combust any fuel) for 3 consecutive years, the Agency would no longer allocate allowances to the unit, starting in the seventh year after the first year of non-operation, and beginning with the seventh year, all allowances that would otherwise have been allocated to the unit would be allocated to the new unit set-aside for the state in which the non-operating unit is located. Duke Energy supports this approach.4 Duke Energy agrees with EPA that this will reduce the incentive to keep marginal units operating, and it strikes a reasonable middle ground between the options of immediately stopping allocations for non-operating units and continuing to provide allowances to non-operating units for an unlimited period of time.  
Duke Energy Recommends Using Heat Input to Allocate State Budgets to Individual Units.  
EPA asks for comment on alternatives to its proposed method of allocating allowances to individual units based on adjusted reported or adjusted projected emissions. EPA specifically asks for comment on an alternative method for allocating allowances to individual units based on projected heat input. Duke Energy believes that allocating allowances equal to each state's budget based on each source's pro rata share of total state heat input is a better way of distributing allowances than EPA's proposed method and Duke Energy supports EPA's use of a heat input-based allocation approach.  [EPA-HQ-OAR-2009-0491-2689.1, pp.17-18]  
Using heat input to allocate allowances does not affect the size of state budgets or the level of emissions that sources in a state can collectively emit in a given year so it is totally consistent with the overall program objective of eliminating each state's significant contribution to downwind nonattainment and interference with maintenance. A heat input allocation method simply distributes each state's responsibility for reducing emissions in a different way. The environmental endpoint will not be affected. Allocating allowances based on heat input treats all sources equally. In other words, it doesn't differentiate between sources that have installed controls and those that have not installed controls. Duke Energy believes that fundamentally this is a more equitable and preferred method compared to EPA's proposed emissions-based allocation method.  [EPA-HQ-OAR-2009-0491-2689.1, p.18]  
In its proposal EPA lays out two possible approaches for allocating allowances using heat input. With one approach EPA would group all covered units in a state into a single group. With the other approach EPA would form subgroups of covered units within a given state with the subgroups formed based on characteristics such as size, fuel type, or age. [EPA-HQ-OAR-2009-0491-2689.1 ,p.18]  
For the ozone season and annual NOx programs, Duke Energy recommends forming two subgroups. One subgroup would be made up of all covered coal-fired units and the other subgroup would be made up of all other covered units. EPA would establish budgets for each subgroup that represents each subgroup's collective share of, or contribution to state annual and ozone season NOx budgets. EPA would then allocate a subgroup's budget to all units within a subgroup based on each unit's pro rata share of the subgroup's total heat input.  [EPA-HQ-OAR-2009-0491-2689.1, pp.18-19]  
For the annual SO2 program, Duke Energy recommends that units which burn only natural gas or natural gas and distillate oil (mainly combustion turbines) be excluded from the program. EPA's modeling for 2012 shows that total SO2 emissions from the entire universe of oil and gas units across all PTR states is under 40 tons, with most of this coming from just a few oil and gas fired steam units. Because of the small amount of emissions, there is no need to allocate SO2 allowances to these types of units. Removing these types of units from the program will eliminate an administrative burden on industry and EPA, and because these units collectively emit almost no SO2, doing so will not adversely impact the environmental performance of the program.  [EPA-HQ-OAR-2009-0491-2689.1, p.19]  
While many gas and oil-fired units may be required to monitor, report, and provide allowances for emissions under the Title IV Acid Rain Program, the additional administrative requirements associated with permitting, allocation, monitoring, reporting, and market transactions for the PTR are unwarranted. Any unit that currently burns exclusively natural gas and/or distillate fuel oil or any new unit permitted to burn exclusively these fuels will not be defined as a covered unit for the PTR SO2 budget program. As EPA proposes, an existing covered unit that switches to natural gas and/or distillate fuel oil for any reason would retain its SO2 allocation provided under the PTR based on its current fuel as long as the unit remains in operation. [EPA-HQ-OAR-2009-0491-2689.1, p.19]  
After eliminating natural gas and distillate oil-fired units from the SO2 program, Duke Energy recommends that EPA form two subgroups with the remaining units. One subgroup would consist of only coal-fired units and the other subgroup would consist of all remaining units. Duke Energy recommends that EPA then establish budgets for each subgroup equal to the collective contribution of all units in each subgroup to a state's SO2 budget. For each subgroup, EPA would allocate SO2 allowances to each unit in the subgroup based on each unit's pro rata share of the total heat input of all units in the subgroup.  [EPA-HQ-OAR-2009-0491-2689.1, pp.19-20]  
Alternately, if EPA does not remove all natural gas and distillate oil-fired units from the SO2 program, Duke Energy recommends forming two subgroups, one consisting of all covered coal-fired units and the other consisting of all other covered units. EPA would then establish separate budgets for each subgroup based on the contribution of all units in each subgroup to the total state budget. For each subgroup, EPA would allocate SO2 allowances to each unit in the subgroup based on each unit's pro rata share of the total heat input of all units in the subgroup.  [EPA-HQ-OAR-2009-0491-2689.1, p.20]  
In the PTR, EPA suggests that under an alternative heat input allocation method the heat input used to make the allocations would be the heat input projected for the initial year of the program. This would be acceptable to Duke Energy's. [EPA-HQ-OAR-2009-0491-2689.1, p.20]  
Duke Energy Recommends That EPA Adopt the Following Method for Allocating Allowances to New Units.  
Under EPA's proposed method for allocating allowances to new units, a new unit would not receive any allocation for the control period during which it commences commercial operation. In addition, EPA proposes to allocate allowances to a new unit for each subsequent control period based on the unit's reported emissions from the previous control period. EPA requests comment on its proposed approach and on alternative allocation approaches that would provide allowances to new units for the control period during which the unit commences commercial operation. [EPA-HQ-OAR-2009-0491-2689.1, p.20]  
EPA's proposed approach for allocating allowances to new units would penalize new units during the control period of initial commercial operation and during the next control period where under EPA's method, allocations would be based on reported emissions during the initial control period (the later in the control period of initial commercial operation a new unit begins operation, the greater the penalty the unit would incur the following year). In order to provide new units with a fair allocation, Duke Energy recommends modifying EPA's proposed allocation approach so new units receive an allocation from the new source set-aside for the control period during which they commence initial commercial operation, and receive an allocation during the following two control periods that is not linked to the reported emissions during the previous control period. [EPA-HQ-OAR-2009-0491-2689.1, pp.20-21]  
Duke Energy recommends that EPA adopt the same basic method for allocating to a new unit during its first year of commercial operation that it proposes to use to establish a new unit's surrogate emissions number to calculate the maximum amount a new unit could emit in its initial year of commercial operation before being required to surrender allowances under the assurance provisions.  [EPA-HQ-OAR-2009-0491-2689.1, p.21]  
Using this approach, a new unit's allocations for the control period of initial commercial operation would be calculated by multiplying the unit's allowable emissions rate (in lbs/MWe) by the unit's maximum hourly load (in MWe/hr), its expected hours of operation during the control period (defined as the hours remaining in the control period from the date of initial commercial operation), and a default capacity factor specific to the unit type. As EPA proposes for purposes of establishing a new unit's surrogate emission number, the default capacity factors would be 84 percent for coal-fired units, 66 percent for gas-fired combined cycle units, and 15 percent for combustion turbines in the NOx annual and SO2 trading programs; and 89 percent for coal-fired units, 72 percent for gas-fired combined cycle units, and 22 percent for combustion turbines in the NOx ozone season trading program. [EPA-HQ-OAR-2009-0491-2689.1, p.21]  
Any request for allocations for new units would need to be submitted on or before May 1 of the control period in which a new unit will begin or has begun initial commercial operation. If a unit begins commercial operation prior to the date the request is submitted, the above specified calculation, which will be the basis for the allocation request, would reflect the actual start date of the unit. If a unit has not begun commercial operation by the date the request is submitted, the above specified calculation and allocation request would reflect the expected start date for the unit. The request for an allocation for the year of initial commercial operation would be required to include information supporting either the actual start date of the unit if it occurred prior to the request being submitted, or the expected start date of the unit if it is to occur after the request is submitted. The supporting information should be based on official filings (for example, to the Department of Energy or state utilities commission) the company has made concerning the schedule for bringing a unit on line. The request for allocation would need to be certified by the Designated Representative as true and accurate based on prudent inquiry. If a state's new source set aside is over subscribed for a given control period, all new units, including any new units beginning commercial operation during the control period the set aside is oversubscribed, would receive a pro rata share of the total number of allowances in the new source set aside. [EPA-HQ-OAR-2009-0491-2689.1, p.22]  
At the end of the control period there would be a true-up for all new units that commenced commercial operation in that control period. The true-up would consist of comparing a unit's allocation with its actual control period emissions. Units would be required to surrender to EPA any allocation received in excess of actual emissions. Any surrendered allowances would be allocated to other new sources if the new source set aside was oversubscribed for the subject control period, or returned to the new source set aside and reallocated to existing covered units if the new source set aside was not over-subscribed for the subject control period.  [EPA-HQ-OAR-2009-0491-2689.1, pp.22-23]  
For the two control periods immediately following the control period of initial commercial operation, Duke Energy recommends that the number of allowances a new unit is allocated be determined using the above specified calculation based on 8760 hours of operation and application of the appropriate capacity factor. At the end of each of these two control periods for affected new units there would be a true up as described for the control period of initial commercial operation. The true-up would consist of comparing a unit's control period allocation with its actual control period emissions. Affected new units would be required to surrender to EPA any allocation it received in excess of its actual emissions. For all subsequent control periods, Duke Energy recommends that the allocations to a new unit be equal to a unit's reported average emissions during the previous two control periods. There would be no true up for a new unit for any control period following its second control period of full year operation. [EPA-HQ-OAR-2009-0491-2689.1, p.23]  
EPA Should Allow EGUs in Group 2 States to Purchase Allowances from EGUs in Group 1 States.  
EPA should allow sources in Group 2 states to use SO2 allowances from Group 1 states. Trading allowances from Group 1 to Group 2 sources will not impact EPA's analysis of what it deemed to be cost-effective emission reductions because the Group 1 allocations are based on a much higher cost of control ($2000 per ton vs. $500 per ton). A Group 2 source will, of course, first look for cost-effective measures to control emissions or the availability of allowances from other Group 2 sources before going after higher priced Group 1 allowances. This provision would still be subject to the statewide variability limits, so there would be no impact on the significant impact analysis for each state. In addition, to the extent that allowing such trading would result in fewer emissions in a Group 1 state (in order to free up allowances to trade to the Group 2 state), the overall environmental benefit should be enhanced since the Group 1 state presumably has a greater impact on downwind non-attainment areas. Because of the limited pool of Group 2 allowances due to the small number of states in that category, a utility with limited operations in a Group 2 state may be placed at a disadvantage since it may not have any cost effective reduction opportunities at its units within a Group 2 state.  [EPA-HQ-OAR-2009-0491-2689.1, p.26]  
Alternatively, EPA should allow a Group 2 source within a regulated electric utility system to use allowances allocated to any other source within the same regulated utility system. Group 1 sources within the utility system would not be allowed to use Group 2 allowances, thus maintaining the cost-effectiveness assumptions that were the basis for allocations to Group 1 and Group 2 states. Restricting this Group 1 to Group 2 option to trading within a single regulated utility operation will assure that such trades occur within a limited geographical area, which should eliminate any potential concerns over how impacts from each state were modeled. [EPA-HQ-OAR-2009-0491-2689.1, p.26]  
Units Should Be Permitted To Use Allowances from Future Year Allowance Accounts, at Least on a Limited Basis  
EPA should allow units to use a limited number allowances from future-year accounts for use in compliance in an earlier year. This would allow for increased flexibility, which will be particularly important in the early years of the program, especially if EPA promulgates a final rule that includes the unreasonable compliance schedule that it proposes and it continues to overstate the ability of existing emission controls to reduce emissions. It would also reduce reliance on an uncertain trading market. This feature would still result in units receiving and using a finite number of allowances over the years and, thus, produce no overall increase in emissions, while also potentially encouraging early retirement of some units. [EPA-HQ-OAR-2009-0491-2689.1,p.32]  
One possible way to implement this concept would be to allow a given vintage year allowance to be used for compliance in that year plus in the year immediately preceding the vintage year of the allowances. For example, a 2016 vintage allowance could be used for compliance in 2015 or in any year after 2015. A limit on the number of allowances an entity could use in this manner along with a limit on the number of years this option is available might be appropriate. [EPA-HQ-OAR-2009-0491-2689.1, pp.32-33]   
Upon making these recommended adjustments to NOx emission rates, EPA should rerun the critical IPM model runs that are the basis for developing state budgets and unit allocations. Because EPA needs to make dramatic technical changes to its calculations, EPA should then repropose the budgets and allocations for public review and comment.  [EPA-HQ-OAR-2009-0491-2689.1, p.47]

Footnote 4: Duke Energy's support for this approach is based on its understanding of the proposal that once a non-operating unit's allocation stops and all future allowances are then transferred to the new source set-aside that the allocation of any unallocated new source set aside allowances to existing covered units will include the reallocation of the allowances from non-operating units. If EPA were to not include these allowances in any reallocation of unused new source set aside allowances to existing covered units then Duke Energy favors the option that continues to allocate allowances for an unlimited period of time to units that discontinue operations. Not to reallocate all unused new source set aside allowances to existing covered units would have the effect of making the state budgets, and therefore the program more and more stringent[EPA-HQ-OAR-2009-0491-2689.1, p.6]  
E.ON U.S.
We support EPA's proposal not to permit government-run allowance auctioning.
The costs associated with compliance with the Proposed Transport Rule will be significant and these costs will impact utility customers through higher utility rates. If allowance auctions were authorized, the costs of procuring allowances would be borne by utility customers who ultimately pay the cost of environmental compliance. EPA should avoid placing additional cost burdens on utility customers already impacted by the economic downturn. Consequently, we urge EPA to decline to adopt allowance auctioning as a component of its final program [EPA-HQ-OAR-2009-0491-2797.1, pp.8-9]
East Texas Electric Cooperative
The use of a single year (or four quarters) of emissions or the heat input from a single ozone season as the baseline for allowance allocation breaks with EPA precedent and is likely to produce inequitable results; the use of at least three years of emissions/heat input data would provide a more accurate baseline and is consistent with EPA's previous practices. [EPA-HQ-OAR-2009-0491-2770.1 p.2]
Edison Mission Energy (EME)
The Transport Rule's proposed SO2 and NOX allowance allocations penalize states that have taken early action on emission reductions. Compared to CAIR, the Transport Rule's state-level allocations appear to reward some states and penalize others without explanation or apparent consideration of the aggressive emission reductions that have already been obtained by a state like Illinois, which appears to have been penalized. [EPA-HQ-OAR-2009-0491-2707.1, p.3]
The Transport Rule's proposed SO2 and NOX allowance allocations also penalize sources that have taken early action on emission reductions. By making unrealistic assumptions about the control efficiency that can be obtained by existing emission controls, EPA has not provided sufficient allocations during Phase I such that sources can actually comply by simply operating controls year round as EPA suggests. Similarly, those same unrealistic assumptions are made with respect to Phase II allocations in 2014 and cause the Transport Rule to penalizes sources that have already installed controls. [EPA-HQ-OAR-2009-0491-2707.1, p.3]
THE TRANSPORT RULE'S ALLOWANCE ALLOCATIONS PENALIZE STATES AND SOURCES THAT HAVE TAKEN EARLY ACTION ONE MISSION REDUCTIONS [EPA-HQ-OAR-2009-0491-2707.1, p.29]
The Transport Rule's State-Level Allocations Appear To Reward Some States And Penalize Others Without Justification [EPA-HQ-OAR-2009-0491-2707.1, p.29]
The stated purpose of the Transport Rule is to limit emissions of NOX and SO2 in a 32 state region to ensure that emissions of those constituents in upwind states do not impact attainment of the 1997 and 2006 PM2.5 NAAQSs and the 1997 Ozone NAAQS in downwind states  -  i.e., the same goal as CAIR. Based on this similarity of purpose, it is not surprising that EPA projected that both rules will have the same impact  -  namely, attainment in all but a handful of areas. Given this uniformity of purpose, one would expect that the required reductions under CAIR would bear some relationship to the projected reductions under the Transport Rule. However, if one compares the Agency's state-level allocations under the Transport Rule to those under CAIR, it becomes readily apparent that some states benefited materially, while others appeared to be penalized with respect to their overall allocations. For example, as the data in Table 3 [See p.30 of this comment summary for Table 3 entitled, Comparison of Final NOx Emission Budgets Under the Transport Rule vs. CAIR] illustrate Illinois will be required to reduce its overall NOX emissions 12% further relative to CAIR, while each of its neighbors will be permitted to increase their NOX emissions by at least 10% relative to what would have been required under CAIR. A similar phenomenon can be seen in Table 4 [See p.30 of this comment summary for Table 4 entitled, Comparison of Final SO2 Emission Budgets Under The Transport Rule vs. CAIR] with respect to SO2. The Agency offers no analysis or explanation for the disparity between the allocations under the two rules despite the fact that both rules were intended to achieve the same net result. [EPA-HQ-OAR-2009-0491-2707.1, pp.29-30]
[See EPA-HQ-OAR-2009-0491-2707.1, p.30-31 for additional comments pertaining to The Transport Rule's State-Level Allocations Appear To Reward Some States And Penalize Others Without Justification, including Table 5 at p. 30 entitled, Comparison of Current SO2 and NOx Emission Rates vs. Implied Rates Under the Transport Rule]
EME recognizes that the Agency based the Transport Rule's state-level allocations on new modeling and modeling tools developed specifically for the Rule; however, there are conceptual similarities in the terms of approach with respect to both rules. Thus, logic dictates, given the uniformity in the overall objective of the two rules, that allocations under the new rule should not be dramatically different from the prior one. Since such disparity in the state-level allocations exist, the Agency, at a minimum, should revisit those allocations to insure they are not unfairly penalizing one state vis-à-vis another, especially states like Illinois which have taken aggressive and early action on emission reductions. [EPA-HQ-OAR-2009-0491-2707.1, p.31]
B. The Transport Rule's Unit-Level Allocations Are Not Based On Reliable Assumptions And Penalized Sources That Have Already Installed Controls [EPA-HQ-OAR-2009-0491-2707.1, p.31]
The Transport Rule proposes to distribute allowances to individual EGUs, such that "each unit receives a proportional share of its...[state's allowance allocation] budget based on that unit's share of state emissions assumed in developing the budget."64 In calculating a unit's share of emissions, EPA made assumptions about the types of controls that will be employed by a given unit and the level of emissions reduction that will be obtained as a result of those controls. This approach is problematic because it penalizes sources that have taken early action on emission reductions, but as a result have existing emissions control equipment that does not necessarily achieve the control levels assumed by EPA in the Proposed Rule. Given EPA's longstanding efforts to encourage sources to reduce their emissions, it cannot be the intent of the Rule to punish those sources that provided those early emission reductions. As a result, EME suggests that EPA revise the Proposed Rule to ensure that the allowance allocations in the final Transport Rule do not penalize early actors. The subsections below address EME's concerns with respect to unit-level allocations in Phase I (2012) and Phase II (currently 2014) caps. [EPA-HQ-OAR-2009-0491-2707.1, pp.31-32]
1. The Phase I Unit-Level Allocations Do Not Reflect The Emissions Reductions That Can Actually Be Achieved Using Existing Controls [EPA-HQ-OAR-2009-0491-2707.1, p.32]
As explained in Section IV.B.1, EPA assumes that compliance with the 2012 cap will only require affected EGUs to (i) operate existing emissions controls year-round, and/or (ii) complete the installation of proposed controls that are scheduled to be online by 2012.65 But these assumptions are not technically feasible. EPA's assertions are premised on the erroneous assumption that existing controls will be able to obtain the absolute highest levels of control  - e.g., those that are obtained when control equipment is operating at peak load with fresh catalyst. Thus, EPA has overestimated the level of control that can actually be obtained by 2012, and therefore has imposed state-wide Phase I emissions caps that are too restrictive. As a result unit level allocations for units with existing controls, such as EME's Homer City facility, are not sufficient to cover emissions there. [EPA-HQ-OAR-2009-0491-2707.1, p.32]
By assuming that Homer City's emissions controls can achieve very low emission levels (levels that EME is not even sure are obtainable on an operational basis using new equipment, let alone existing equipment) and allocating allowances on that basis, the Transport Rule effectively penalizes the Homer City facility for having already installed emissions controls (controls which have removed well over 200,000 tons of SO2 and NOX from the facility's emissions stream). If EPA had in fact drafted the Transport Rule such that compliance with the 2012 cap only required sources to operate existing controls, then the Homer City facility should have received allocations equal to its emissions, which it has not. As explained in Section IV.B.1, EME believes that the assumptions underlying the EPA's 2012 cap have caused EPA to overstate the reductions that can actually be obtained using existing controls, and therefore that the Agency should increase the 2012 compliance caps based on more realistic assumptions about the level of control that can actually be obtained using existing controls. In turn, EPA should increase individual unit-level allocations proportionally and, at a minimum, in a manner that ensures that sources with existing controls, such as Homer City, have sufficient allocations to cover their emissions. The CEMs data maintained by affected EGUs means EPA has access to the data it needs to make these adjustments to the Rule. In addition, EPA should amend the Rule to permit affected sources to use previously banked CAIR emissions allowances to comply with Phase I emission caps. [EPA-HQ-OAR-2009-0491-2707.1, pp.32-33]
In addition to that timing concern, EME also believes that EPA should re-evaluate its unit-level allocations for Phase II to ensure that they do not penalize early adopters of emission controls. As explained above, EPA distributed allowances based on its determination of a unit's proportional share of emissions in state  -  a determination that EPA based on its own inaccurate assumptions about the level of control a given unit would obtain. [EPA-HQ-OAR-2009-0491-2707.1, p.33]
EME believes generally that EPA has overestimated a source's ability to control emissions, and as a result may have understated an individual unit's proportional share of emissions causing that unit to receive a smaller allocation than is justified by the Agency's allocation methodology. For example, by projecting emissions at the Homer City's Unit 3 facility using an assumption that its FGD achieves an emissions rate of 0.103 lbs/MMBtu even though it actually achieves 0.180 lbs/MMBtu, EPA has understated Unit 3's 2014 emissions by more than 40%. Lower estimated emissions at Unit 3 means that Homer City's proportional share of total emissions is smaller, which causes Homer City's overall allowance allocation to be smaller. This outcome effectively penalizes Homer City for having existing controls, even though EPA had access to CEMs data that would have permitted it to make more accurate assumptions about actual control rates at the Homer City facility. If the Agency elects to retain the emissions-based allocation approach in the Final Rule, it should verify that its emissions estimates are accurate.[EPA-HQ-OAR-2009-0491-2707.1, pp.33-34]
Alongside its recommendation that the Phase II compliance deadline be pushed back until 2016, EME recommends that EPA retain the banking provisions in the Proposed Rule. By permitting sources to bank allowances for future use, the rule encourages early reductions during Phase I  -  i.e., by allowing sources to bank allowances for future use sources are incented to take capital investment risks on emission controls and/or try promising, but currently unproven, emissions reduction technologies. [EPA-HQ-OAR-2009-0491-2707.1, p.35]
Entergy Services, Inc.
Entergy Does Not Support Using Integrated Planning Model (IPM) Results for Unit Allowance Allocations  
Entergy urges EPA to reconsider the use of the IPM results in allocating NOx allowances from the state budgets among the individual sources.  IPM is a production cost simulation model focused on analyzing wholesale power markets and assessing competitive market prices based on an analysis of the fundamentals relating to supply and demand.  While it is capable of producing projections of emissions by taking an integrated approach to regional fuel, power, and emission markets, IPM possesses several characteristics that may contribute to its under-prediction of unit operations and premature retirement or significant reduction of generation from oil/gas steam units.  This is demonstrated in the data contained in Attachment A.  A review of this data reveals IPM modeling marks the early retirement  23 Entergy oil/gas steam units that were utilized significantly in 2007-2010 to supply power to the grid and underutilizes 10 Entergy combustion turbine units that were utilized significantly in 2007-2010 to supply power to the grid.  Entergy does not have any plans to retire the units predicted to retire, nor do we expect utilization of these units or the turbines to change significantly. The table below shows the difference in allowances allocated to these units using the IPM 2012 projected utilization verses an allocation based on the ratio of the unit's average 2007  -  2009 heat input and the 2007-2009 respective state heat input.  [EPA-HQ-OAR-2009-0491-2847.1,p.2] [[See Docket Number EPA-HQ-OAR-2009-0491-2847.2 for Attachment A.]]  [[See Docket Number EPA-HQ-OAR-2009-0491-2847.1, p. 2 for the state heat input table.]]
The first IPM characteristic causing these unrealistic projections is that, as a regional model, IPM represents the electric transmission system on an interregional basis, with regional boundaries determined by known transmission bottlenecks.  Unlike ICF's private sector version of IPM that contains 104 U.S. regions, EPA's version contains only 32.  Entergy is modeled as a single region, an over- simplification that might have limited impact for state-level modeling results, but which becomes problematic when relying on detailed regional results, especially at the individual source level.  Transmission-related issues inherent to IPM's regional models include missing intraregional load pockets, voltage support, ancillary services, local requirements, etc.  These limitations are further exacerbated by the limited number of regions in EPA's IPM, resulting in the premature reduced generation from oil/gas steam units as depicted in Attachment A.  [EPA-HQ-OAR-2009-0491-2847.1,p.3]
The second issue is the lack of time detail in EPA's version of IPM which underestimates the operational value of oil/gas steam units.  Oil/gas steam units are typically responsive to short term fluctuations in demand and are used frequently to provide operational flexibility.  IPM, which is not an hourly model and dispatches to broader time segments, has no way of capturing the daily and hourly dispatch decisions that might drive generation for these units. [EPA-HQ-OAR-2009-0491-2847.1, p.3]   
There are additional modeling assumptions that may contribute to reduced oil/gas steam unit dispatch (overstating turndown requirements, such that units may ramp at low levels for a more limited variable cost than what is represented in IPM, etc.), but the core issue is that IPM is a model that assumes perfect system optimization.  The IPM model predicts a least-cost scenario for the electric power system while ignoring these stated system limitations.  In none of the three Base Cases was there any projected generation attributed to the `Oil/Gas Steam' capacity type.  Attachment A contains a brief explanation of why Entergy's oil/gas steam units will be utilized even though the IPM model shows zero utilization. [EPA-HQ-OAR-2009-0491-2847.1,p.3]
In summary, IPM does not consider a range of real-life factors that influence a company's decision to operate a unit.  As a result, allocating allowances to emission units on the basis of IPM modeling creates unrealistic scenarios such as running natural gas combined cycle units at higher utilization than can be accommodated by the local natural gas pipeline network, running coal units so they emit higher than permitted annual emissions, and not running units that are required to operate to meet load/transmission requirements.  These distortions of the electricity market are masked when data are aggregated at the state level for setting state budgets but result in obvious inaccuracies and inequities when used at the unit level to allocate allowances.  For these reasons, Entergy encourages EPA to reconsider the use of the IPM as a fair means of allocating allowances and supports the use of a proven, reliable methodology of allocating allowances, such as historical MW output.  The inequity in the utilization of IPM projections as compared to the proven, reliable method of allocating allowances on historical heat input is depicted in Attachment A.  [EPA-HQ-OAR-2009-0491-2847.1,p.3]
Alternative Unit Allocation Methodologies  
Entergy supports output-based allocation approaches.  An output-based allocation relies on energy production (output; megawatt-hour [MWh]) as the basis for determining the number of allowances that a unit will receive.  The benefits of an output-based allocation include promoting more efficient and cleaner production of electricity to maintain economic competitiveness.  Further, the methodology does not penalize companies and their customers for investments made in cleaner generation prior to a regulatory mandate.  Alternatively, Entergy proposes that EPA consider a historic fuel-input basis for unit allocations.  The historic basis should be a unit's proportion of its state's historic heat input (i.e., million British thermal units, mmBtu), as was originally proposed for CAIR, prior to the introduction of the fuel adjustment factors.  We note that the federal appellate court invalidated the use of fuel factors, not the use of historic heat input.  The historic heat input should be based on the maximum annual heat input for units during the period of calendar years 2007 through 2009.  We recommend using the annual maximum of reported data during the three-year period rather than the average of those three years in order to ensure that an atypical year does not dramatically affect the allocation (e.g., the unusually low utilization in 2009).  Such an allocation methodology would address Entergy's concern with allocations based on modeled future emissions with its known inaccuracies and would be based on verified data that companies have already submitted to EPA.   [EPA-HQ-OAR-2009-0491-2847.1,pp.3-4]
Heat Input Adjustment Methodology  
In EPA's technical support document "State Budgets, Unit Allocations, and Unit Emission Rates," the motivation and methodology for the heat input adjustment is described:
 "Reported annual and ozone season NOX emissions are adjusted to account for unusually low utilization in 2009. For units reporting emissions (Sets A and B), the annual emissions assumed in the budget calculation are calculated by applying the 2008 heat input to the annual average emissions rate determined from the most recent quarter 1, quarter 2, quarter 3, and quarter 4 (and potentially adjusted for controls, as described above).  2009 heat input is used for units which did not report 2008 heat input data. Ozone season emissions are assumed to be 2008 ozone season heat input multiplied by the most recent ozone season average emissions rate." [EPA-HQ-OAR-2009-0491-2847.1,p.4]
The intent of this adjustment is to rebase emissions on a more historically representative heat input year as a way to increase annual NOx emissions and provide a more appropriate allocation level.  However, in Arkansas the heat input adjustment often works to reduce reported NOx emissions from Entergy's units.  The table below displays each of Entergy's Arkansas units that was assigned a non-zero heat input adjustment by EPA.  [EPA-HQ-OAR-2009-0491-2847.1,p.4] [[See Docket Number EPA-HQ-OAR-2009-0491-2847.1, p.4 for the table.]]
Every heat input adjustment except for the adjustment at Independence 1 revised the reported NOx emissions lower, reducing Entergy's overall allocation by approximately 643 tons.  This outcome appears to stand in direct contradiction to the stated purpose of the heat input adjustment. As demonstrated by the Harvey Couch 2 unit allocation, the methodology for determining the adjustment is problematic and can produce results that are difficult to justify.  Harvey Couch 2 does not have a listed heat input for any quarter of 2008; this fact reduces the unit's 2009 reported emissions of 234 tons to zero as the basis for its 2012 allocation.  [EPA-HQ-OAR-2009-0491-2847.1, p.5]
If any of the state budget methodologies switch from projected to reported emissions, the heat input methodology will become even more important.  In several instances, the current methodology produces counterintuitive results.  For example, Little Gypsy 1 has reported emissions of 636 tons under the Annual NOx program.  EPA then applied a heat input adjustment that zeroes out Little Gypsy 1's emissions.  In EPA's reported data, the unit has heat input values listed for all but the first quarter of 2008.  Under the methodology, if there is a single null value in any quarter of 2008, the annual heat input becomes zero and reported Annual NOx emissions are eliminated.  In this way, the final reported NOx emissions of Little Gypsy 1 are lower under the Annual Program (0 tons) than under the Seasonal Program (407 tons), because the null heat input value happens to be in the first quarter of 2008. [EPA-HQ-OAR-2009-0491-2847.1,p.5] 
For a revision intended to produce a more equitable NOx allocation level, the heat input adjustment may be functioning to produce the opposite result. Using the highest heat input value in a consecutive three year period as outlined in the section of these comments describing the Alternative Unit Allocation Methodologies would alleviate undesirable results when adjusting heat input to produce a more equitable NOx allocation level.  [EPA-HQ-OAR-2009-0491-2847.1, p.5] 
Excelsior Energy
Comment summarv for allocation among unit groups:
Within the alternative heat input allocation method, units using natural gas as a primary fuel should not be allocated SO, allowances.
Under the alternative heat input allocation approach, EPA contemplates creation of subcategories:
'There are other approaches to allocation. For example, EPA could identify groups of units in each state that are capable of having similar emissions characteristics (e.g., grouped by size, fuel type, or age). EPA would distribute a state's emissions budget without variability to each group of units in the state (in effect, distributing the responsibility for eliminating all or part of significant contribution) perhaps based on each group's proportional share ofthe state budget as projected in the initial year of the program. After apportioning a state's budget to the groups ofunits, under such an approach EPA could distribute allocations to individual sources within each group based on each source's proportional share ofprojected heat input.' (Federal Register, Vol. 75, No. 147, Aug 2, 2010, p. 45311). [EPA-HQ-OAR-2009-0491-2810.1 p.3]
There is one group or subcategory that would be appropriate. The allocation process should take into account whether a unit (as defined in the Rule) has negligible emissions of SO, without controls (i.e., units for which natural gas is the primary fuel) and should limit the distribution of allowances to those units accordingly. Allowances should not be 'diluted', which is to say that they should not be given to units that have virtually no SO, emissions and are unable to reduce emissions with addition of such controls. Allocating allowances to units physically incapable of reducing emissions would not result in any emission reduction and would therefore not serve the purposes behind the CATR.
The allocation process described above would only require the creation of two categories across all units covered under the Rule and would only apply to SO, (since all units emit NOx). One category would include units with negligible uncontrolled emissions of SO,; the other, all remaining units. As described above, units in the former category would not receive allowances. Allowances for a given unit in the latter category would be allocated in accordance with that unit's proportional heat input across the total annual heat input of all emitting units in the same category, i.e., exclusive of the units for which natural gas is used as a primary fuel. [EPA-HQ-OAR-2009-0491-2810.1 p.3]
As discussed above, in North Carolina v. EPA, the Court rejected EPA's proposed fuel-adjustment factors because EPA used the impermissible grounds of 'fairness' as the only legal justification for the use of the factors. By contrast, dividing units within a state into the two categories described above is consistent with North Carolina v. EPA, because the justification in this case is that allocating S0, allowances to units unable to make any reductions would not reduce emissions and would not reduce contributions to downwind attainment. On the contrary, it would have the potential to reduce the incentive for sources that do emit S0, to implement emission reduction retrofits. [EPA-HQ-OAR-2009-0491-2810.1 p.4]
Exxon Mobil Corporation
THE NOx ALLOWANCE ALLOCATIONS FOR THE LOUISIANA 1 UNITS ARE WHOLLY INSUFFICIENT AND BASED UPON FLAWED MODELING AND PROJECTIONS
It is arbitrary and capricious for EPA to provide unit-level allocations based upon the Integrated Planning Model (IPM). EPA's proposed NOx allowance allocations would provide the Louisiana 1 units with only about 4.5% of the allowances that they need to operate at the levels they have operated at for the past 5 years and intend to operate at in the foreseeable future. These units are well controlled with low NOx burners and/or water injection systems. They are critical to meeting EM's electrical demand and continued manufacturing operations. [EPA-HQ-OAR-2009-0491-2841.1,p.12]
To meet the requirements of the proposed FIP, EM may have to expend more than $1.2 million dollars per year to acquire NOx allowances.19 TIns is solely because EPA is basing the allocations on the IPM projections, not due to any need for NOx emission controls at these units. [EPA-HQ-OAR-2009-0491-2841.1,p.12]
EM believes that it is unreasonable for EPA to use the IPM results to allocate NOx allowances from the state budgets at the unit-level basis. The IPM is a production cost simulation model that was designed to investigate wholesale power markets and assist in making projections about competitive electrical market prices. It was not designed for the purposes for which EPA is using the model. It has several important deficiencies for such service. It is clear from the comments of the Louisiana Chemical Association that the model erroneously predicts premature retirement or significant reduction of generation from oil/gas fired units.20 In addition, as discussed in the comments of the Louisiana Public Service Commission staff, the IPM fails to recognize important transmission constraints that exist within Louisiana.21 Further, the IPM appears to have problem with realistically projecting utilization rates for cogeneration units such as the Louisiana 1 units. A comparison of actual data for fuel input and S02 and NOx emissions for the Louisiana 1 units to the values for these projected by the EPA IPM model v. 3.02 follows: [EPA-HQ-OAR-2009-0491-2841.1, p.12] [[See Docket Number EPA-HQ-OAR-2009-0491-2841.1, p.13 for a table with the comparison.]]
EM's Louisiana 1 units have total SO2 allocations based on an assumed total 2012 heat input for 32,976,586 mmBtu. This is a reasonable value based on past and projected future operations as can be seen from the certified data reported to EPA under the Acid Rain and CAIR programs. However, the same units have an assumed heat input for NOx annual allocations of only 614,500 mmBtu and an ozone season assumption of only 61,450 mmBtu. Thus, the assumed heat input for NOx is only 1.9% of the actual adjusted reported value used for SO2. The projected heat input values are not reasonable and because they were the product of the IPM model, EM has grave questions about the accuracy of the model to predict heat input in future years. EM does not understand the basis for the modeled predictions and believes that they are arbitrary and capricious. If EPA is going to undertake to make unit level allocations, it has a duty to gather sufficient empirical data about the regulated units before doing so. [EPA-HQ-OAR-2009-0491-2841.1, p.13]
It appears that the ozone season allocation heat input basis is exactly 10% of the annual NOx heat input basis (which as noted is already woefully short of an accurate prediction). This assumption clearly does not comport with actual data. EM's units operate year around on the same basic operational schedule and therefore the ozone season heat input should be based on a realistic percentage based on May-September operation. EPA has the data in its quarterly CAMD reports and could have reviewed those from recent years to confirm that these units operate year round. [EPA-HQ-OAR-2009-0491-2841.1,pp.13-14]
Although the difference between reported and projected values improves very slightly under the IPM v.4.1 0, the same fundamental problem exists there as well. The annual and ozone season heat input and corresponding NOx emissions are only a tiny fraction of the Louisiana 1 facility actual heat input and emission levels. [EPA-HQ-OAR-2009-0491-2841.1,p.14]
EM is diligently reviewing updates to the IPM announced in the September 1, 2010 Notice of Data Availability, but to date cannot understand how IPM v.4.10 projects such limited operation of the Louisiana 1 units. EM's manufacturing operations depend on continuous large volumes of steam and electricity from reliable and highly efficient cogeneration units. These cogeneration units are significantly more fuel-efficient and have better emissions controls than typical utility electricity generation and stand-alone boilers; further, the steam demand can only be supplied from these sources and is not available from an external 'pipeline grid'. Therefore, there is no known reason to expect the curtailed operation predicted by the IPM, either version 3.02 or version 4.10. [EPA-HQ-OAR-2009-0491-2841.1, p.14]
EM requests EPA abandon use of the IPM model for projecting electric utility operation in Louisiana for purposes of allocating unit-level allowances under CATR for cogeneration units as well as other EGUs. There are several fundamental issues with EPA's use of the IPM for this purpose. One of the foremost reasons is the lack of transparency concerning how the IPM accounts for economic and fuel cost factors in determining how much a unit will be utilized in future years. As clearly shown above, the output of the IPM does not come close to matching actual utilization for EM's cogeneration facilities. The year 2012 is less than one and one-half years away and therefore is well within EM's reasonable ability to project operations. The assumed heat inputs associated with NOx allocations for 2012 are not consistent with EM projections. [EPA-HQ-OAR-2009-0491-2841.1,p.14]
If EPA insists upon enacting a FIP for Louisiana based upon its IPM projections to date, EM recommends that EPA at least use a different system for unit level allocations. One possibility would be for use the adjusted reported heat input data for NOx rather than the IPM projections. In the event EPA chooses to continue using projected emission for NOx allocations, EM requests EPA modify the model to accurately project emissions from cogeneration facilities co-located with production facilities dependent upon cogeneration power. [EPA-HQ-OAR-2009-0491-2841.1,p.14]
As an alternative to the TR/FIP proposed unit allocation methodology, EPA could make NOx allocations (both annual and ozone season) in the same relative percentages to the state budget that Louisiana used under its approved CAIR SIP as NOx allocations. EM does not believe there are any significant new sources that would cause a need to substantially revise that ratio. While EM has a new CLECO Rodemacher/Madison 3 pet coke generation unit, EM believes the unit will not cause a substantial impact on the allocations of the total state emissions budget. [EPA-HQ-OAR-2009-0491-2841.1,pp.14-15]
The IPM based unit-level allocations are illogical and unfair. EM's Louisiana 1 units are efficient gas turbines equipped with both low NOx burner technology or other controls. Under the proposed TR/FIP, EPA's NOx unit-level allocations penalize these units even though they are some of the most efficient and lowest-polluting units. Projecting the cost of purchasing allowances is difficult as their costs will be market driven. In addition, allowance costs may vary widely based on the trading scheme chosen for the final rule. However, based on historical costs from CAIR trading, the additional annual cost for allowances for the Louisiana 1 units could well exceed $1.2 million dollars annually. Adding additional control to these units is not likely to be effective since they are already efficient and well controlled. As EPA is aware, cost per ton for NOx control rises exponentially with additional control and reaches the point of diminishing returns after the control technology currently in place for these units. EPA has simply provided no rational basis for this inequitable treatment for the Louisiana 1 units. [EPA-HQ-OAR-2009-0491-2841.1,p.15]
EM also urges EPA to abandon its proposed unit-level allocations and allow Louisiana DEQ to make allocations through a state SIP, if it is finally concluded that a SIP is even needed to address interstate transport of PM2.5 and/or ozone precursors from Louisiana. In the alternative, EPA should substantially revise the allocations under the FIP and re-propose such allocations for further comment. [EPA-HQ-OAR-2009-0491-2841.1, p.15]

19 The Louisiana Public Service Commission conducted an economic analysis of the proposed TR/FIP that indicates that the annual impact to the Louisiana 1 station for purchases of annual NOx allowances would be approximately $1,224,000 more per year than was the cost to Louisiana 1 to comply with CAIR. This amount is based on an assumption that the cost per ton of a NOx allowance is only $1200. The estimate did not include the additional cost for ozone season NOx allowance purchases and therefore understates the estimate. See comments of Louisiana Public Service Commission submitted in this docket. [EPA-HQ-OAR-2009-0491-2841.1, p.12]
20 See also the comments ofEntergy Corporation filed in this docket. [EPA-HQ-OAR-2009-0491-2841.1,p.12] 
21 EM incorporates by reference the comments of the Louisiana Public Service Commission staff. [EPA-HQ-OAR-2009-0491-2841.1,p.12]
First Energy
EPA's unprecedented use of the proprietary Integrated Planning Model to model every significant source in the entire industry produces results that appear to inappropriately reward some sources with allowances over others, and those results cannot be independently substantiated or verified. The output of IPM essentially defines which sources are awarded allowances and which aren't, and, when coupled with limited emission trading opportunities this may very well define those sources that survive and continue to operate and those that do not. The financial and human capital implications for individual plants and Companies associated with this exercise are profound. [EPA-HQ-OAR-2009-0491-2657.1, p.4; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.4 10/15/2010]
Use of a proprietary model is not appropriate for this purpose as it deprives the public and regulated community of the opportunity to independently evaluate the inner workings of the model and ensure that it is accurate, precise and robust enough to perform this enormous task. Likewise, the public and regulated community cannot tell whether questionable output is the result of an error in a modeling assumption or algorithm, or if the model itself inappropriately amplifies irregularities in the input database. [EPA-HQ-OAR-2009-0491-2657.1, p.4; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.4 10/15/2010]
The model also appears to inappropriately apply the same financial metrics to all sources, irrespective of whether they are regulated, municipal or merchant facilities. As an owner of merchant generating facilities, FE appears to be unfairly handicapped by the use of the same financial assumptions for all classes of generators. As noted by Du and Parsons (2009),
"It is important to understand that these costs of capital are meant to reflect a `merchant model' in which the nuclear plant delivers power into a competitive wholesale market without any assured rate of return. A nuclear plant built by a regulated utility, with the construction costs approved and passed along to customers with greater certainty could probably be financed at a lower cost of capital. This would reflect the fact that some of the construction, completion, operating and price risks are being shared between the shareholders in the regulated utility and the customers of the regulated utility. The total risks are the same, but in the merchant model the shareholders bear all of the risk." (p. 20) [EPA-HQ-OAR-2009-0491-2657.1,p.5; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.4 10/15/2010]
The input files for the model should reflect the very different financial and operating environments of regulated, municipal and merchant EGU's and IPM should be rerun. [EPA-HQ-OAR-2009-0491-2657.1,p.5; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.4 10/15/2010]
FE strongly suggests that EPA provide the regulated community sufficient detail and opportunity to comment on the IPM and its application to ensure that the model is appropriate and it is appropriately applied to this purpose.[EPA-HQ-OAR-2009-0491-2657.1, p.5; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.4 10/15/2010]
Potential Reliability Issues
The EPA assumption for unit retirements range from 2GW in 2012 to 12 GW in 2014. This does not match up with other analyses and actual utility announcements concerning shutdowns or transitioning units into a moth-balled state. FE has seen estimates from knowledgeable sources that state that as much 15% of the affected capacity could be retired. EPA's unit retirement assumptions should be evaluated by each Independent System Operator to ensure system reliability after EPA corrects all the assumptions used in IPM. [EPA-HQ-OAR-2009-0491-2657.1,p.13]
Florida Electric Power Coordinating Group, Inc. (FCG)
In EPA's posted 'Projected Data' spreadsheet which was published with the proposed rule, the FCG realized that EPA had not allotted S02 allowances for those units which burn fuel oil and natural gas. Following conversations with EPA representatives, the FCG understands that IPM predicted that these dual-fuel fired units will only be burning natural gas in the future. This is one of the many flaws in EPA's methods. [EPA-HQ-OAR-2009-0491-2658.1, p.8]
First, fuel oil currently consists of 16% of Florida's electric generating Summer capacity (MW) and is being assumed to represent 13% of such capacity in 2019 (Florida Public Service Commission, Fuel Diversity Workshop, August 5, 2010). Florida receives gas from only three pipelines. During the 2005 Hurricane Season, Florida nearly depleted its supplies of natural gas supplies due to interruptions in the Gulf of Mexico. During this emergency period, utilities held daily meetings to assess the situation and discuss possible contingency plans, many of which centered on utilities ability to burn fuel oil in their dual-fuel fired natural gas units. As EPA has cited in their Endangerment Finding, the U.S. should be encountering increased storm activity in the near future, and so the U.S. should plan accordingly. Assuming arguendo, this rule proposal merely pushes Florida sources to become much more reliant on natural gas, which will only exacerbate any future issues with curtailed or jeopardized gas supplies. [EPA-HQ-OAR-2009-0491-2658.1,p.9]
It also appears that IPM predicts that coal units can and will switch to lower sulfur coals in order to meet S02 reduction requirements. Many of the same questions apply with coal as did natural gas, namely EPA's lack of analysis on current permitted coal sulfur limits, the cost and availability of the targeted fuel, and the railroad line capacity to meet the predicted dramatic increase in fuel switching. [EPA-HQ-OAR-2009-0491-2658.1, p.9]
EPA must conduct an analysis of the capacity of Florida's natural gas pipelines to accommodate the increased requirement in natural gas consumption needed to meet EPA's assumptions by 2012. EPA must also perform reliability analysis as to Florida's unique situation as a peninsula regarding FCG members' ability to meet reliability requirements in the future. And EPA's analysis must consider the parasitic load from new control equipment, such as FGD and SCR systems. [EPA-HQ-OAR-2009-0491-2658.1,p.9]
Florida Municipal Power Agency (FMPA)
B. Heat Input Allocation Method Should be Used Instead of the Proposed Allowance Allocation Method
FMPA supports FMEA's comments regarding the use of the heat input allocation method instead of the proposed allowance allocation method. FMPA believes the heat input method results in a more fair allocation. EPA's proposed allocation method results in an unfairly low allocation of allowances to low-emitting facilities with existing control equipment. As shown in Table 1, below, FMPA's units already have NOx controls installed and operating which are required to meet the emissions limits in our Title V operating permits. Furthermore, other than Stock Island CT4 which does not have access to natural gas, all FMPA units fire primarily natural gas, a low sulfur fuel, and either low sulfur or ultra low sulfur diesel as a necessary backup fuel source. Because FMPA's units already have NOx controls and burn very low sulfur fuels, and therefore do not have the ability to add additional measures to reduce emissions, FMPA would have no choice under the proposed allocation but to purchase additional allowances to keep these units running. For these reasons, FMPA does not support EPA's proposed emissions-based allowance allocation method and believes that EPA should instead utilize a heat input-based allowance allocation method. [EPA-HQ-OAR-2009-0491-2725.1, pp.2-3]
[Table 1 can be found on pages 3-4 of this comment.]
Furthermore, EPA's procedure for determining reported NOx emissions, which applied the 2008 heat input to the 2009 NOx emissions data, results in unjust and unreasonable allowance allocations to all FMPA units. EPA's assumption of unusually low utilization in 2009 (Technical Support Document "State Budgets, Unit Allocations, and Unit Emissions Rates") is not valid for any of FMPA's affected units, as shown in Table 2 below. Please also note that Treasure Coast Unit 1 was a new unit in 2008 and only operated for approximately the second half of that calendar year, whereas 2009 was a full operating year. [EPA-HQ-OAR-2009-0491-2725.1, p.4]
[Table 2 can be found on page 4 of this comment.]
Although we understand that EPA is attempting to account for abnormally low usage rates by applying this adjustment, it is not fair to utilities for which this assumption is invalid, particularly when the overall allocation methodology is already shortchanging well-controlled units. FMPA believes that EPA should not adjust the 2009 emissions data for 2008 heat input for any units for which this will result in lower NOx emissions and thus, lower NOx allowance allocations. We would also like to restate our preference for a heat input-based allowance allocation method since EPA's proposed method punishes low-emitters regardless of what calendar year it is based on. [EPA-HQ-OAR-2009-0491-2725.1, p.4]
4. The following FMPA units were improperly assigned SO2 allowance allocations of zero tons and SO2 emission rates under the direct control option of 0.000 lb/mmBtu:
Cane Island (ORIS Code 7238) - Units 1, 2+2A, 3+3A  4
Hansel (ORIS Code 672) - Unit 21
Stock Island (ORIS Code 6584) - Unit CT4. [EPA-HQ-OAR-2009-0491-2725.1, p.6]
According to the proposed Allocation Table, these assigned values are based on "projected" emissions. It is our understanding that, in assigning SO2 allowance allocations, EPA has assumed that dual-fuel fired units will burn only natural gas in the future and will not burn any fuel oil. We believe this is an improper assumption that leads to improper SO2 allowance allocations. This assumption ignores factors, such as, for example, reliability issues associated with hurricanes or the limited peninsular supply of natural gas in Florida, that necessitate the use of fuel oil as a back-up fuel. This issue is discussed in more detail in the comments submitted by the FCG, which FMPA fully supports. [EPA-HQ-OAR-2009-0491-2725.1, p.6]
Specific to FMPA, the "gas-only" assumption is an erroneous assumption for FMPA's Stock Island CT4 because it can only fire fuel oil due to its location. Stock Island CT4 is located in Key West, Florida, on an island on which there is no access to natural gas. Therefore, EPA's assumption that all dual-fuel-fired units will burn only natural gas for purposes of calculating and assigning SO2 allowance allocations is improper and leads to unreasonable results. [EPA-HQ-OAR-2009-0491-2725.1, p.6]
Finally, even if dual-fuel fired units did only fire natural gas in the future, the assumption of zero SO2 emissions is still erroneous. Reported emissions would be at least 0.0006 lb/mmBtu under the direct control option (due to the emissions reporting methods of 40 CFR 75, Appendix D, which allow the use of this emission factor for pipeline quality natural gas). This emission factor rounds up to 0.001 lb/mmBtu, thus the assignment of SO2 emission rates of 0.000 lb/mmBtu under the direct control option is inappropriate. Additionally, the 0.0006 lb/mmBtu emission factor frequently results in reported SO2 tons greater than zero for gas-fired units with higher capacity factors. For this reason, the proposed SO2 allocations of zero tons are also inappropriate. Table 3 below gives specific examples of SO2 emissions for calendar years in which FMPA units fired natural gas exclusively. [EPA-HQ-OAR-2009-0491-2725.1, pp.6-7]
[Table 3 can be found on page 7 of this comment.]

4. See infra at paragraph II.C.5. [EPA-HQ-OAR-2009-0491-2725.1, p.6]
Gainesville Regional Utilities (GRU)
In addition, EPA should not add provisions and new methodologies in the proposed CATR that are not designed to directly respond to the Court remand directing EPA to retain the environmental values of CAIR to the greatest degree practical. As currently proposed, the allowance allocation scheme in this rule will disadvantage utilities like GRU that have made major expenditures to add air pollution controls to meet the CAIR emission caps compared with those that have not. EPA's preferred allowance allocation option has the effect of punishing utilities that have taken early actions to comply with CAIR. [EPA-HQ-OAR-2009-0491-2674.1, p.2]
The Proposed CATR Unfairly Financially Punishes GRU for Its Installation of Advanced Air Pollution Control Equipment
GRU's decision to install air pollution control equipment to meet CAIR was based in part on the assumption that EPA would support CAIR to the greatest extent allowed by the Court. The preferred allocation scheme outlined in the proposed CATR is blatantly unfair in that it determines allowance allocations based on the maximum removal efficiency of installed or planned air pollution control systems. This means the utility installing the air pollution control system will lose the benefit of over controlling a source to accrue surplus allowances. GRU can find nothing in the Court Ruling to justify the move to the EPA preferred allowance allocation scheme. GRU believes that EPA should allocate allowances based on heat input in a similar manner as the CAIR NOx allocation but without the fuel factor. This method will answer the Court remand and also return some fairness to the allocation process. [EPA-HQ-OAR-2009-0491-2674.1, p.3]
The Proposed CATR Disadvantages GRU Relative to Utilities that Elected Not to Control Their Emissions Early
A major consideration in GRU's decision to add air pollution controls to DH#2 was the ability to have surplus allowances to support new generation resources. Currently a 100 MW (net) biomass generating unit is in the final approval stage for construction at the Deerhaven Generating Station (DGS). Under the CAIR allowance allocation methodology, GRU would have been allocated sufficient allowances to cover this new unit. As currently proposed, there will be insufficient allowances for both DH#2 and the new biomass unit. [EPA-HQ-OAR-2009-0491-2674.1, p.3]
EPA's Emission Allowance Allocations are Unfair and Are Counter to Cap and Trade Market Based Principles
The allocations proposed by EPA will be based on the 'Optimized' operation of the pollution reduction equipment of each EGU. This means a utility that installed a new flue gas desulfurization (FGD) scrubber to meet CAIR requirements that gets up to 90% or better SO2 removal would get SO2 allowances based on the equipment running at 90% or better. The same situation applies to utilities that installed new selective catalytic reduction (SCR) equipment. At the same time, EPA proposes to allocate allowances to those utilities that have not made the expensive control technology investments based on the far lower cost compliance options of using low sulfur fuels or low NOx burners. [EPA-HQ-OAR-2009-0491-2674.1, p.5]
GRU believes that a serious equity and fairness issue is created by the allocation methodology used in the proposed CATR. While the Court found fault with EPA's attempt address equity with the fuel factor, there is no indication that the Court required EPA to go to the other extreme. Gainesville Regional Utilities (GRU) spent more than $140 million to install state of the art SO2 and NOx controls on its Deerhaven #2 coal-fired generating unit to meet and exceed CAIR requirements. Under CAIR GRU was expected to receive about 3,136 SO2 allowances but under the proposed CATR the utility would receive only 614 SO2 allowances. [EPA-HQ-OAR-2009-0491-2674.1, p.5]
The Proposed CATR Allowance Allocation Methodology is Poor Public Policy for Several Reasons
First, the proposed allowance allocation methodology violates a key cap and trade success principle. The proposed allocation method fails to allow utilities to choose to over-control their emissions at electric generating units (EGUs) where it is cost-effective and under control at sources where it is less cost-effective. For example, if under CAIR an 80% removal of SO2 would achieve compliance and running at 95% removal could generate surplus allowances for sale, the proposed CATR would not allow that benefit for installing expensive pollution controls. [EPA-HQ-OAR-2009-0491-2674.1, p.6]
Second, the proposed CATR punishes aggressive early emission reductions. Unlike the CAIR rule, by reducing allowances to those who installed expensive air pollution control equipment, EPA is actually financially punishing utilities like GRU for both early compliance and aggressive emission reductions. In addition, EPA proposes that units that haven't installed any controls will get allowances based on operation with lower cost low sulfur fuels and low NOx burners. [EPA-HQ-OAR-2009-0491-2674.1, p.6]
Third, the proposed CATR allowance allocation methodology will hurt future proactive emission reductions by industry. The shift away from the CAIR allocation methodology, one that rewards over control and early emission reductions, to the proposed CATR methodology that punishes the very same behavior, will create a long lasting chilling effect on future proactive emission reductions by industry. [EPA-HQ-OAR-2009-0491-2674.1, p.6]
Finally, the proposed CATR allowance allocation method ignores the fact that many costly decisions were made by the utility industry based on the provisions of CAIR. To meet the CAIR compliance requirements GRU committed to costly emission control systems while the rule was under court challenge. That commitment by GRU was based in part on the assumption that EPA would keep as much of CAIR intact as the Court would allow. [EPA-HQ-OAR-2009-0491-2674.1, p.6]
In response to EPA's request for suggestions for an alternative allowance allocation method, GRU strongly recommends that EPA allocate both SO2 and NOx allowances based on heat input without a fuel factor at the emission rates necessary to achieve the state emission budget. Using that allocation method would not only address the Court's remands based on the fuel factor and improper use of Acid Rain SO2 allowances, it would bring fairness back to the allocation methodology. [EPA-HQ-OAR-2009-0491-2674.1, p.6]
The EPA Preferred Cap and Trading Program is Overly Complicated
Intrastate trading is unlimited but interstate trading is limited to - 10% of the state's budget. However, Florida can only trade with Group 2 states. These include Alabama and Mississippi but not Georgia which is a Group 1 state. Since the EGUs with controls in place or planned are given allowances based on estimated emissions with controls operating at full rated capability, what is there left to trade? The key principle of the cap and trade methodology is over control of some units to allow under control of others with utility decisions based on where the cheapest reductions can be made. Again, GRU urges EPA to use a methodology for allocating allowances for compliance with the proposed CATR based on heat input. This would operate similar to the NOx allowance allocation methodology without a fuel factor. [EPA-HQ-OAR-2009-0491-2674.1, p.7]
GE Energy Financial Services (GE EFS)
EPA Cannot Rely Upon Projections of Dispatch Generated by Its Integrated Planning Model ('IPM') as the Basis for Allocating Allowances to Individual Units, Unless EPA First Resolves Serious Errors With the Model
While GE EFS supports EPA's use of the Integrated Planning Model ('IPM') to establish statewide budgets and facilitate policy development, GE EFS does not believe EPA can or should rely upon IPM's projections of future dispatch to establish allocations of emissions allowances down to the level of the individual unit, unless EPA first resolves a number of significant errors in the model and its underlying data set. [EPA-HQ-OAR-2009-0491-2701.1,p.2]
EPA Must Account for the Impact That Long-Term Contracts Have on Facility Dispatch by Revising IPM So That It Models Dispatch of Facilities Consistent With the Requirements of Their Long-Term Contractual Obligations
GE EFS is aware of instances in which IPM has predicted incredibly low dispatch levels for facilities subject to long-term contracts. As an example of such erroneous projections, GE EFS would refer to the comments submitted by Cogen Technologies Linden Venture, L.P. ('Linden Cogen') regarding its combined cycle cogeneration plant. Linden Cogen is owned by GE EFS. These projections of future dispatch have no basis in reality and are proven false by both the facility's operating history and its ongoing contractual obligations. To avoid such arbitrary model results for both Linden Cogen and the many other facilities subject to long-term contracts in which GE EFS has an interest, EPA must account for the impact that long-term contracts have on facility dispatch by revising its model, so that it predicts dispatch of facilities consistent with the requirements of their long-term contractual obligations. EPA must then re-run the model, incorporating real-world assumptions about dispatch of facilities operated pursuant to contracts. [EPA-HQ-OAR-2009-0491-2701.1, p.2]
If EPA cannot correct the errors in IPM that have generated arbitrary and unrealistic predictions of future dispatch at a unit level, including the failure to model facilities' dispatch consistent with their long-term contractual obligations, EPA should instead base allocations on historical operating data, just as it has proposed as the basis for state budgets (other than the 2014 sulfur dioxide ('S02') budgets for group 1 states). [EPA-HQ-OAR-2009-0491-2701.1,p.3]
If actual performance data are more accurate and representative in predicting emissions at the statewide level, they certainly should be deemed more accurate and representative in predicting the dispatch and emissions of individual facilities. It would be arbitrary and capricious for EPA to rely upon IPM's projections as the basis for establishing allocations, when EPA has already acknowledged that those projections cannot be relied upon to establish the corresponding state budgets. Accordingly, should EPA fail to correct the errors in IPM that have resulted in its erroneously low projections of dispatch for facilities operated pursuant to long-term contracts, EPA should instead base allocations on historic operating data, as adjusted to reflect the operation of existing and planned emissions controls. An allocation methodology based on historic operating data is not inconsistent with the court's decision in North Carolina v. EPA and would assure that the same analyses and data relied upon by EPA to establish a state's budget are used to establish the unit-specific allocations for that state. [EPA-HQ-OAR-2009-0491-2701.1,p.3]
Where Allocations Area Based on Historic Heat Input Data, They Should Be Based on Data From a More Representative Period of Time Than a Single Year
For those states in which EPA has already proposed to base allocations of allowances upon historical heat input data and for any other states where it should decide to do so because of the unreliability of IPM's projections, EPA should base allocations upon historical data not from a single year, but from a more representative period of time. Using only one year's data as the basis for allocations could penalize facilities that had lower emissions in 2008 or 2009 because they had lower utilization during that period due to the recession or were down for an extended period of time to install controls to comply with the requirements of CAIR. [EPA-HQ-OAR-2009-0491-2701.1,p.3]
GE EFS Does Not Support the Alternative Allocation Methodology, Whereby Each Facility Would Be Allocated Allowances Based on Its Share of Projected Statewide Heat Input
GE EFS does not support the alternative allocation methodology described by EPA in the preamble, wherein each facility would be allocated allowances based on its 'share of projected heat input' within the state. 75 Fed. Reg. at 45311. As presented, this alternative allocation methodology would not resolve the serious problems associated with allocating allowances based on IPM's erroneous projections of future dispatch for facilities subject to long-term contractual obligations. However, if EPA's proposed alternative were to allocate allowances based on each source's share of historical, rather than projected, statewide heat input, GE EFS agrees that this would be a fair and equitable approach. [EPA-HQ-OAR-2009-0491-2701.1,p.4]
EPA Should Make Remaining Allowances in the New Unit Set-Aside Available to Long-Term Contract Generators Who Experience a Shortfall One to a Return of Utilization Back to Levels Achieved Prior to the Recession
GE EFS believes EPA should make any remaining allowances in the new unit set-aside available to long-term contract generators who exceeded their allocation due solely to an increase in utilization back to levels achieved prior to the recession. Unlike a utility that can seek to recover costs associated with emissions allowances from its ratepayers or a merchant generator that can recover such costs through the market price of electricity, long-term contractor generators can be severely impacted by the requirement to purchase emissions allowances. Further, long-term contractor generators do not exercise control over when their facilities can be dispatched, but must operate whenever called upon by their customers. GE EFS holds interest in many long-term contract generators whose interests may be prejudiced by the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2701.1,p.5]
Congress has previously recognized the economic realities faced by long-term contract . generators who have no way of recovering the cost of emissions allowances, both upon enacting the Acid Rain Program under the 1990 Clean Air Act Amendments and more recently as part of the development of a federal cap and trade program for emissions of greenhouse gases. By making allowances remaining in the new unit set-aside available to long-term contract generators before distributing the remainder of the set-aside to eligible existing facilities, EPA could prevent long-term contract generators from needing to pay potentially significant costs for allowances that cannot be passed along to their customers. This would provide needed relief if a long-term contract generator experiences a shortfall in allowances due to a return of demand to pre-recessionary levels, without compromising the integrity of the statewide emissions budgets. A more detailed description of this proposal is contained in the comments filed by Birchwood Power Partners, L.P. ('Birchwood'), which is co-owned by GE EFS and a partner. [EPA-HQ-OAR-2009-0491-2701.1, p.5]
Great River Energy
Even if given more time to review EPA's technical supporting documentation, Great River Energy is not convinced that it could fully understand EPA's modeling and unit specific allocations. The proposed rule, and its underlying documentation, present something like a 'black box,' as described by the National Rural Electric Cooperative Association ('NRECA') in its comments to the proposed rule. EPA fails to present adequate information so as to allow full comment on unit emission allocations and other issues important to affected electric utilities. [EPA-HQ-OAR-2009-0491-2758.1 p.2]
Like NRECA, Great River Energy believes that EPA has a legal obligation to develop a rational rulemaking process that provides all the information needed to fully understand the proposal's rationale and interworking. The present 'black box' approach falls short. Accordingly, Great River Energy urges EPA to issue a supplemental Transport Rule proposal that specifies in adequate detail how specific unit emissions were determined so that we can provide more constructive comments for our specific units. [EPA-HQ-OAR-2009-0491-2758.1 p.2]
Notwithstanding these concerns, Great River Energy hereby provides some key comments and observations of errors in EPA's database concerning our units. We have also attached an emissions summary table (Attachment 1, Great River Energy - Emissions Summary) in an attempt to address the errors in EPA's IPM database:
 :: 2009 is not a representative year for Great River Energy's emission sources. EPA projects unit-by-unit heat input that differs greatly from historical values. (See Attachment 2, Great River Energy - Heat Input Variability and Attachment 1.)
o Load variability was at its lowest point in a 5 year period. See Attachment 2 as an indication of overall unit-by-unit variability. This table shows each unit's 5 year average heat input in addition to the plotted range of possible minimums and maXImums.
o Weather variability provided one ofthe coolest summers in Minnesota's history, resulting in very limited peaking turbine run times. (Again, see Attachment 2.)
o Fuel variability was non-existent, as GRE was able to run almost entirely on natural gas, even though historically gas is curtailed in the winter requiring fuel oil combustion and its corresponding higher NOx and S02 emissions.
o Elk River Peaking Station (ORIS Code 2039) began commercial operation in mid 2009, and completed CEMS certification in the 4th quarter. Reported emissions for 2009 are not indicative of future operation. EPA does not recognize this unit as new. As such, its emissions should be considered on a prorated basis. (See Attachment 1.) [EPA-HQ-OAR-2009-0491-2758.1 p.2]
For a relatively small cooperative representing a very minor percentage ofthe state's overall budget, these inaccuracies may seem insignificant to EPA and are arguably insignificant in downwind contributions to non-attainment areas. Nevertheless, these errors and false assumptions are extremely significant to our cooperative, our members and customers. Given load variability, temperature variability, fuel variability, and potential growth, Great River Energy will not have sufficient allocations to cover emissions, does not expect a viable trading program, and cannot cost effectively control our simple cycle peaking turbines, by EPA's own analysis, while remaining competitive in the Upper Midwest. EPA has unfairly punished clean burning peaking turbines, some of which already have BACT emission controls, with this rule. Further, from our very limited assessment ofthe data upon which the allocations were based, Great River Energy speculates that there are similar data inaccuracies, which if corrected, would lead to different allocation outcomes, at a minimum, and may also lead to different modeling results, which, like CAIR, could result in Minnesota being dropped from Transport Rule coverage. Great River Energy submits for EPA consideration our emissions summary table in Attachment 1 to best project our emissions, including variability issues, as discussed, and assuming that EPA does not intend to require beyond-BACT controls for our peaking plants. [EPA-HQ-OAR-2009-0491-2758.1 p.4]
Unfortunately, as a small rural electric cooperative, Great River Energy does not have the resources to review all of the data and re-evaluate EPA modeling assumptions in order to adequately question Minnesota's inclusion in the Transport Rule.. Nevertheless, Great River Energy does call attention to the electric generating unit ('EGU') category, which is the only source category covered by the Transport Rule. Given that the vast majority of state allowances will be given to two utilities in Minnesota, and primarily to their baseload units, Great River Energy questions the logic ofinc1uding simple cycle combustion turbines as part of the EGU source category. [EPA-HQ-OAR-2009-0491-2758.1 p.5]
It appears that Minnesota EGU simple cycle combustion turbines are included in the Transport Rule as an artifact from CAIR. In CAIR, as a generality, it may have made sense, in most states, to include combustion turbines with other EGUs, due to their increased operation and assumed significant contribution to ozone season non-attainment in those areas. However, with respect to the Transport Rule, EPA has determined that Minnesota does not contribute significantly to ozone season non-attainment. In fact, like CAIR, Minnesota may only contribute to annual PM2.5 non-attainment in certain areas. [EPA-HQ-OAR-2009-0491-2758.1 p.5]
Great River Energy questions some assumptions made by EPA that could lead to inclusion of simple cycle peaking plants. Upon reviewing the 'Technical Support Document (TSD) for the Transport Rule Docket ID No. EPA-HQ-OAR-2009-0491 State Budgets, Unit Allocations, and Unit Emissions Rates,' we first find EPA's lumping of all EGU's into one source category of '>25MW fossil fuel fired units,' even though there are distinct emission differences and cost effectiveness thresholds between baseload coal fired units and peaking units, as an example. There is no discussion or reference within the Transport Rule as to the EPA's rationale for including combustion turbines with all fossil fuel fired >25MW, other than for simple convenience. [EPA-HQ-OAR-2009-0491-2758.1 p.6]
As a different point of reference, in the IPM Base Case model v3.02 Table 21 , EPA assumes that 'advanced combustion turbines' are projected to have 92% availability. Clearly, with this incorrectly projected availability and assumed comparable 'capacity' factor, SCR retrofits may consequently be viewed as cost effective in EPA's modeling effort. However, our peaking turbines typically operate at a 10%, or less, annual capacity factor, which would cause a much higher $/ton cost and would be viewed as not cost effective by EPA's own thresholds. [EPA-HQ-OAR-2009-0491-2758.1 p.6]
While EPA cannot be expected to understand the nuances of each source and its existing permits and associated emission limits and controls, EPA must take into consideration Great River Energy's unique situation with respect to already controlled peaking plants, and its reduction of allowances to this small source category. [EPA-HQ-OAR-2009-0491-2758.1 p.6]
Certainly EPA has modeled a contribution from Minnesota to downwind annual non-attainment, despite numerous errors within the IPM dataset. Upon reviewing the broad category ofEGUs as the only regulated 'source' under the Transport Rule it is clear, based on both emissions and EPA's projected allowance allocations, that only a few sources in Minnesota are responsible for the downwind modeled contribution. (See Attachment 3, Transport Rule - Minnesota Allocations by Company.) Therefore, it does not make sense that a few smaller sources, within the broader EGU category, are included. They neither 'contribute significantly,' nor could add any significant economic incentives to a state trading program, given the concentration of allowances as proposed by EPA. Finally, EPA's distribution of allowances to these smaller sources is inequitable, relative to other larger sources in the state, and will place these smaller sources at a competitive disadvantage. Specifically, the larger sources are expected to reduce their NOx emission by a lesser percentage (30-38%) versus the smaller sources that range from 50-70%, based on our projections. Great River Energy cannot understand EPA's logic for including its combustion turbines in Minnesota. [EPA-HQ-OAR-2009-0491-2758.1 p.6]
Holland Board of Public Works
The methodology document that the EPA provides ('State Budgets, Unit Allocations and Unit Emission Rates', prepared July 2010) in support of this rule, states on page 12 'Units in group 1 states without an IPM projection do not receive S02 allocations in 2014 and beyond'. Why? We are unclear after reviewing the document how and why this allocation was made. The HBPW has no intention of retiring this unit at any time in the near future. We are confident that certain control methodologies can be implemented to reduce emissions consistent with the average percentage reduction required of the State of Michigan. The modeling program is arbitrary and fails to consider the real-life evaluations and decisions that will be made by municipal entities like the HBPW. [EPA-HQ-OAR-2009-0491-2861.1, p.2]
Illinois Environmental Protection Agency
U.S. EPA has proposed to establish S02 emissions budgets for the second phase of the Transport Rule based on unit-specific cost-effectiveness calculations using the Integrated Planning Model (IPM). While the IPM model is a useful and sophisticated planning tool, the Illinois EPA
believes that it is inappropriate to use the rPM for unit-by-unit allocations. For example, rPM does not allocate allowances to two units in illinois, Ameren's Meredosia units I and 2, because the model assumes that it is not cost-effective to control these units. However, Ameren has not announced any plans to shut down these units, and more importantly, it should be up to Ameren to make the determination of how best to comply. Illinois EPA recommends that rPM's costeffectiveness calculations be used regionally, or to establish state budgets, but that it not be used on a unit-by-unit basis.
To allocate allowances on a company or unit basis, Illinois EPA recommends that such allocations be based on gross electrical output. Illinois uses this approach to allocate allowances in CAIR. Historical output data on a unit basis are readily available and it would be a straightforward process to allocate a state's budget to existing units. This approach would be more equitable than U.S. EPA's proposed approach and would encourage utilization of the most efficient generating units.
Illinois EPA further recommends an approach to allow new emission units to be rolled in to the existing-source allocation pool. Illinois' current rules under CAIR requires the state to revise unit allocations periodically to include new sources as existing sources and to remove allocations to units that have been permanently shut down. This approach provides a mechanism for new, more efficient and better controlled uuits to receive allowances without permanently relying on allowances under the New Source Set-Aside. Illinois EPA recommends that future allocations be updated periodically to allow new units into the pool of existing units. [EPA-HQ-OAR-2009-0491-2781.1 p.2-3]
Independence Power & Light (IPL)
The Rule Creates A Perverse Incentive for EGU's Given 'Zero Allocations'to Refrain from Retrofitting
Another factor ignored in the Rule concerns the perverse incentive created in situations where an EGU has been allocated zero emissions allowance in 2014. The proposed rule does not appear to offer any prompt means to increase the zero allowance should an owner decide to retrofit that unit with the controls assumed in the Rule to lead to state compliance with allocations as to individual EGUs by 2014. Under the proposal, it appears that a 2014 zero allowance unit can obtain a positive allowance only by fitting within the definition of 'new unit' For this purpose, the applicable part of the definition states: 'any unit listed in Appendix A that stopped operating for three consecutive years, is no longer allocated allowances as an existing unit, but resumes operation' would be considered a new unit. 75 FR at 4531011-2.4 Even assuming this applies to a zero allowance EGU, that would mean at a minimum three, and possibly up to seven, years of non-operation before the retrofitted EGU qualifies for a positive allowance. During that time, and not withstanding that the EGU is in compliance, its owner would be required to purchase allowances to run the unit or purchase replacement electricity if the unit is shut down. [EPA-HQ-OAR-2009-0491-2741.1, pp.15-16]
This creates a perverse incentive for zero allowance EGU owners not to retrofit those units because the owners incur the substantial retrofit costs without any assurance that they will gain any benefit from their action. Unless owners are clearly assured that a zero allowance unit will promptly receive a positive allowance upon compliance, they face the real possibility of paying the same costs (for buying allowances or for purchasing replacement electricity) that they would face if the unit remained non-compliant. Even in a situation where the new unit definition would permit a positive allowance, that would not occur for several years, thus delaying the owner's opportunity to recoup the costs of retrofitting through the sale of electricity from that unit. From a rational economic perspective, the least cost approach in these circumstances would be not to retrofit the zero allowance unit. But that option serves neither the public interest related to air quality nor the public interest to increasing the availability of low cost electricity. Consequently, EPA should act to provide reasonable assurance on this point. [EPA-HQ-OAR-2009-0491-2741.1, p.16]

4 It is not entirely clear whether the three years is really seven years, given 'EPA proposes that, once an EGU does not operate ... for 3 consecutive years, the Agency would no longer allocate allowances to the unit, starting in the seventh year after the first year of non-operation.' 75 FR at 45310/3. This coupled with the new unit definition creates confusion as it relates to zero allowance EGUs: Does a zero allowance constitute an allowance that EPA must no longer allocate before the EGU meets the new unit definition? The preamble may also be inconsistent with the proposed rule, § 97.412(a)(2), which states an allowance may be request for 'the first control period after the control period in which the unit resumes operations (for a unit listed in appendix A of this subpart)' 75 FR at 45377/2.
Indiana Department of Environmental Management 
Although the currently proposed rule does not contain unit by unit emission caps, Indiana has several concerns regarding the accuracy of the data used for justifying the proposed rule, establishing state budgets, and sub-state allocations. There are several sources that are not 25 MWe electric generating units (EGUs), as well as some nonEGUs and utilities that have not operated for five years receiving allowances, and some non-EGUs and utilities that are operational but did not receive allowances or sufficient allowances. Especially with the 2014 budget, the allocation process is not transparent and it is impossible to determine if the distribution is fair and balanced. [EPA-HQ-OAR-2009-0491-2645.1, p.3]
Kansas City Board of Public Utilities (BPU)
The Rule Creates A Perverse Incentive for EGU's Given 'Zero Allocations' to Refrain from Retrofitting
Another factor ignored in the Rule concerns the perverse incentive created in situations where an EGU has been allocated zero emissions allowance in 2014. The proposed rule does not appear to offer any prompt means to increase the zero allowance should an owner decide to retrofit that unit with the controls assumed in the Rule to lead to state compliance with allocations as to individual EGUs by 2014. Under the proposal, it appears that a 2014 zero allowance unit can obtain a positive allowance only by fitting within the definition of 'new unit.' For this purpose, the applicable part of the definition states: 'any unit listed in Appendix A that stopped operating for three consecutive years, is no longer allocated allowances as an existing unit, but resumes operation' would be considered a new unit. 75 FR at 45310/1-2. 9 Even assuming this applies to a zero allowance EGU that would mean at a minimum three, and possibly up to seven, years of non-operation are required before the retrofitted EOU qualifies for a positive allowance. During that time, and notwithstanding that the EGU is in compliance, its owner would be required to purchase allowances to run the unit or purchase replacement electricity if the unit is shut down. [EPA-HQ-OAR-2009-0491-2740.1, pp.20-21]
This creates a perverse incentive for zero allowance EGU owners not to retrofit those units because the owners incur the substantial retrofit costs without any assurance that they will gain any benefit from their action. Unless owners are clearly assured that a zero allowance unit will promptly receive a positive allowance upon compliance, they face the real possibility of paying the same costs (for buying allowances or for purchasing replacement electricity) that they would face if the unit remained non-compliant. Even in a situation where the new unit definition would permit a positive allowance, that would not occur for several years, thus delaying the owner's opportunity to recoup the costs of retrofitting through the sale of electricity from that unit. From a rational economic perspective, the least cost approach in these circumstances would be not to retrofit the zero allowance unit. But that option serves neither the public interest related to air quality nor the public interest to increasing the availability of reasonably-priced electricity. Consequently, EPA should act to provide reasonable assurance on this point. [EPA-HQ-OAR-2009-0491-2740.1, pp.21-22]

9 It is not entirely clear whether the three years is really seven years, given 'EPA proposes that, once an EGU does not operate ... for 3 consecutive years, the Agency would no longer allocate allowances to the unit, starting in the seventh year after the first year of non-operation.' 75 FR at 45310/3. This coupled with the new unit definition creates confusion as it relates to zero allowance EGUs: Does a zero allowance constitute an allowance that EPA must no longer allocate before the EGU meets the new unit definition? The preamble may also be inconsistent with the proposed rule, § 97.412(a)(2), which states an allowance may be request for 'the first control period after the control period in which the unit resumes operations (for a unit listed in appendix A of this subpart).' 75 FR at 45377/2.
Lansing Board of Water & Light
BWL is extremely concerned about the lack of explanation regarding the methodology to determine a source's allocation, and the apparent errors found within the available spreadsheets. [EPA-HQ-OAR-2009-0491-2752.1, p.2]
Louisiana Chemical Association (LCA)
LCA also has grave concerns about the proposed allocation of NO x allowances under the FIP. LCA has individual members that own and/or operate highly efficient, well controlled natural gas fired cogeneration units that supply power to their industrial sources as well as some portion of their electrical output to the grid. Each of these cogeneration units received allocations less than 20% of their 2009 actual NOx emissions and their 5 year average historic emissions. Under EPA's proposal, these 'must run' EGUs received allocations that do not allow them to operate at needed rates without significant annual expenditures in the millions of dollars needed to purchase allowances. We are continuing to review the technical support documents, but have found no legitimate reason readily stated for EPA to penalize these sources in this fashion. The technical support documents are formatted in such a manner that they lack transparency and ease of use. [EPA-HQ-OAR-2009-0491-1925.1, p. 3]
LCA is also concerned about the proposed allocation of NOx allowances to public utilities from which LCA members purchase power. Many of the Louisiana Public Service Commission regulated EGUs in Louisiana received zero NOx allocations even though they have been providing critical power to Louisiana businesses and residential consumers for the past 5 years and have no announced plans to curtail operations. EP A's support documents indicated these same units do not need retrofits to reduce emissions. Other publicly regulated EGUs appear to have been allocated significantly more NOx allowances than their historical NOx emissions under EPA's proposal and stand to gain a significant financial windfall from the EPA allocation scheme. After weeks of communications with EPA trying to understand the basis of these proposed unit allocations, we have been informed that the basis for this allocation scheme was EPA's IPM TR Base Case 3.02 modeling, which simply projects that due to economic factors unrelated to environmental issues, some units will not be running in 2012 or will be running at greatly reduced rates. The allocations among units were based on these projected, modeled economic consequences, not on any determination of environmental need. The result will be millions of dollars in windfall profits to certain units and significant costs to others, including the industrial consumers of such power. [EPA-HQ-OAR-2009-0491-1925.1, p. 3]
EP A staff also informed LCA that the IPM model does not account for transmission constraints or other factors that make these 'must run' units. We are concerned that all of the units in the New Orleans area and across much of South Louisiana did not receive adequate allowances to allow operation at a level commensurate with local needs and that there are significant deficiencies in the IPM and/or with economic assumptions used therein that do not reflect real world constraints. See attached map. [See docket number EPA-HQ-OAR-2009-0491-1925.1, p. 6 for the map.] Addressing such assumptions requires gathering of a significant amount of data from a number of EGUs, including those that arc not LeA members, to demonstrate why such units are 'must run' units, what the transmission constraints are, and how other factors that the model did not take into account will impact the utilization of those EGUs. This will take more time than EPA has allowed. [EPA-HQ-OAR-2009-0491-1925.1, p. 3]
If Interstate Transport Needs to be Addressed, EPA Should Allow Louisiana to Make any Required NOx and SO2 Allocations in a SIP.
 As discussed in Section III., above, EPA should recognize the requirements of federalism inherent in the Clean Air Act and should allow Louisiana adequate opportunity to adopt a SIP with any required allocations. Louisiana may choose to regulate sources other than EGUs and /or could rely upon a combination of reductions from sources under consent decrees not included by EPA in its projections and reductions from EGUs or other emissions. Louisiana DEQ and the Louisiana Public Service Commission are in the best position to determine fair and equitable allocations that will avoid unnecessary impacts on the ability of the state's EGUs to provide its citizens and businesses with electrical power. [EPA-HQ-OAR-2009-0491-3527.1, p. 43]
As an Alternative, EPA Should Allow Sources the Same Percentage of the Budget that They Received Under CAIR Allocations.
As an alternative, and only in the event that it is determined a FIP is needed and justified to address intrastate transport of Louisiana emissions on Texas receptors (which is denied), then LCA requests that EPA allocate the NOx allowances by providing EGUs with the same % of the total state budget that they had under the approved Louisiana NOx CAIR SIP. [EPA-HQ-OAR-2009-0491-3527.1, p. 43]
Louisiana Energy and Power Authority (LEPA)
The EPA's methodology for allocating emission allowances to Electric Generating Units ('EGUs') is seriously flawed. That methodology fails to allocate any allowances to critical EGUs that must run to serve load in communities across Louisiana. Although the 60-day time frame allowed by the EPA for review and comment was grossly insufficient to permit a detailed analysis of the complex technical modeling supporting the allocations, this error appears to result from a lack of model inputs to properly capture transmission constraints or to otherwise reflect the fact that some EGUs, like LEPA's Morgan City and Houma units, must run to serve load. [EPA-HQ-OAR-2009-0491-2700.1, p.3]
The failure to allocate emission allowances to LEPA's critical units located in transmission constrained areas would significantly raise costs and could very possibly prevent LEPA from running those units. If LEPA cannot run those critical units and has insufficient time to secure necessary upgrades to serve its constrained areas in another way, there would be blackouts in LEPA's control area, and the North American Electric Reliability Corporation ('NERC') could revoke LEPA's designation as a balancing authority and control area, leaving LEPA's member communities unserved. LEPA urges the EPA to address this serious omission in any final rule it may promulgate. [EPA-HQ-OAR-2009-0491-2700.1, pp.3-4; These comments can also be found at EPA-HQ-OAR-2009-0491-3738.1_NODA, p.2, 10/15/2010]
LEPA MUST RUN ITS GAS-FIRED GENERATING UNITS IN HOUMA AND MORGAN CITY TO PROVIDE ELECTRICITY TO THE RESIDENTS AND BUSINESSES IN LEPA'S CONTROL AREA BECAUSE OF A CONGESTED TRANSMISSION GRID. [EPA-HQ-OAR-2009-0491-2700.1, p.6; To see additional comments pertaining to LEPA MUST RUN ITS GAS-FIRED GENERATING UNITS IN HOUMA AND MORGAN CITY TO PROVIDE ELECTRICITY TO THE RESIDENTS AND BUSINESSES IN LEPA'S CONTROL AREA BECAUSE OF A CONGESTED TRANSMISSION GRID, see pp.6-9]
Thus, LEPA's Houma and Morgan City units must run to serve load in LEPA's control area because of transmission constraints and there are no other options for serving load in that area. Those units must run when the transmission grid is overloaded, and they must be turned on and ramped up with sufficient lead time to ensure those units are available when transmission constraints are present. Yet, the proposed Transport Rule assumes those units never run and thus assigns those units no emission allowances. [EPA-HQ-OAR-2009-0491-2700.1, p.9]
IF THE MORGAN CITY AND HOUMA UNITS RECEIVE NO ALLOWANCES, LEPA COULD BE FORCED TO SHUT THOSE UNITS DOWN, CAUSING BLACKOUTS IN LEPA'S CONTROL AREA AND SUSPENSION OF LEPA'S BALANCING AND CONTROL AREA AUTHORITY.[EPA-HQ-OAR-2009-0491-2700.1, p.14]
The proposed Transport Rule allocates no emission allowances to LEPA's must run units, and at the same time would impose a more limited trading regime for allowances and a shorter time frame for compliance. LEPA could thus be facing an extremely tight market for available emission allowances, with little or no allowances available for purchase. If LEPA has no allowances of its own and is not able to purchase any allowances, it would be forced to shut down the Morgan City and Houma units. When transmission is not available to deliver power to LEPA's control area, there would be blackouts in LEPA's service territory and thousands of residents and businesses would be left without power. This would include a shut down in delivery of power to hospitals, schools, nursing homes, other critical businesses, government operations and thousands of residences. [EPA-HQ-OAR-2009-0491-2700.1, pp.13-14]
In addition, if LEP A cannot rely on the Houma and Morgan City units, it would not have sufficient capacity to cover the load in its control area, one of NERC's requirements for recognition as a balancing authority and control area. Thus, NERC potentially could withdraw or suspend LEP A's recognition as a balancing authority and control area. If that happens, LEP A would be unable to service many of its members' needs and the small cities and towns of Louisiana would lose the operational support and economies of scale that LEPA provides. [EPA-HQ-OAR-2009-0491-2700.1, p.15]
THE FAILURE OF THE PROPOSED TRANSPORT RULE TO ALLOCATE ALLOWANCES TO GENERATING UNITS IN TRANSMISSION CONSTRAINED AREAS IS INCONSISTENT WITH THE PUBLIC INTEREST AND WITH SEVERAL KEY PRINCIPLES UNDERLYING THE RULE. [EPA-HQ-OAR-2009-0491-2700.1, p.15; for additional comments pertaining to THE FAILURE OF THE PROPOSED TRANSPORT RULE TO ALLOCATE ALLOWANCES TO GENERATING UNITS IN TRANSMISSION CONSTRAINED AREAS IS INCONSISTENT WITH THE PUBLIC INTEREST AND WITH SEVERAL KEY PRINCIPLES UNDERLYING THE RULE, see pp.15-17]
In addition, by allocating no allowances to units that must run to serve load, the proposed Transport Rule provides LEPA with no flexibility III complying with the rules and no cost-effective means of complying with the rules. [EPA-HQ-OAR-2009-0491-2700.1, pp.15-16]
Louisiana Public Service Commission
Likewise, the LPSC Staff has concerns about the EPA's assumptions regarding how certain EGUs mayor may not be utilized (dispatched) on a forward-going basis. For instance, our initial review of the proposed rule indicates that there are several 'regulatory must-run' units modeled under the EPA Transport Rule as not running on a forward-going basis. It would appear that the model rule, and its associated allowance allocations, is not adequately recognizing the important voltage and load following support functions of these limited run units. However, our analysis is still in its early stages and we need additional time to review the reasonableness of this assumption, and to determine how the costs to our regulated utilities, and ultimately ratepayers, will change under these unit-specific operating estimates/assumptions.[EPA-HQ-OAR-2009-0491-1928.1, p.2]
The LPSC Staff is also concerned about the limitations for interstate allowance trading and the implications this has for Louisiana in meeting the overall emissions reductions envisioned by EPA. While interstate transactions were included in the CAIR, they are excluded in the proposed CATR. Recognizing the legal considerations leading to EPA's decision, the LPSC Staff notes that the restriction has important implications regarding how quickly, how costly, and how reliably Louisiana can move towards the EPA's emission goals. The use of tradable allowances for clean air and renewable markets is reflected by a number of important successes that, as a general matter, have helped drive down emissions compliance costs. The LPSC Staff is concerned that the removal of the interstate trading provisions, coupled with the speed of the implementation period, will drive-up compliance costs by reducing the supply of available credits relative to demand. [EPA-HQ-OAR-2009-0491-2670.1, pp.5-6]
The LPSC Staff has serious reservations about how allowances will be used, and the impact the interstate trading restriction will have on multi-state holding companies like Entergy Corporation, which operates in five different Gulf Coast states. Most holding companies attempt to reduce overhead and other general costs by pooling resources and optimizing their generation dispatch across a broad geographic region and diverse generation resource mix. The provisions in the EPA's proposed rule may negatively affect these synergies and increase rates for Louisiana and the other utilities that are subject to the multi-state operating agreements regulated by the Federal Energy Regulatory Commission ('FERC'). [EPA-HQ-OAR-2009-0491-2670.1, p.6]
Machaver, Bob
Allocations: If allowed in the FIP process, it is suggested that the rule establish State NOx and SO2 Budgets and allow the states to make allocations to the individual sources, rather than directly specifying unit level allocations in the rule. There are several reasons this approach is preferred:  
− Initial review of the Allocations for sources in Massachusetts, indicates that in many cases these allocations do not seem reasonable. Small peaking type sources have been allocated significant allocations, while larger sources have not been provided any allocations. More generally, it does not seem appropriate to designate Allocations based on a single operating year.  
− There is no provision for Allocations to be set aside for new sources. It would seem that EPA, and the states, would want to promote operation by new sources, and a set aside would seem an appropriate means to accomplish this. In most states, the NOx Budget rules have included a New Source set-aside.  
− There does not appear to be any mechanism for updating Unit level annual Allocations based on changing operating patterns among sources.  [EPA-HQ-OAR-2009-0491-2873.1, p.1]
While most of these issues might be addressed in a final rule that retains direct source allocations, it would seem more likely that an appropriate Allocation distribution would result if states were given responsibility for developing an Allocation scheme, as they are more familiar with the sources in their jurisdiction.  [EPA-HQ-OAR-2009-0491-2873.1, p.1]
If for some reason, EPA believes certain sources within states should be targeted for achieving emission reductions (and discouraged from using allowances) due to their interstate transport impacts, the State Budgets could perhaps be disaggregated to smaller sub-state regional areas.[EPA-HQ-OAR-2009-0491-2873.1, p.1]
Manitowoc Public Utilities (MPU)
 MPU supports the U. S. EPA's proposal not to include any allowance auctioning under its Proposed Remedy Option. No need or reason exists to use allowance auctions to implement the Proposed Transport Rule's emission reduction requirements.   [EPA-HQ-OAR-2009-0491-2860.1,p.3]
Allowance Auctioning Under the Proposed Remedy Option  
MPU supports the U. S. EPA's proposal not to include any allowance auctioning under its Proposed Remedy Option. No need or reason exists to use allowance auctions to implement the Proposed Transport Rule's emission reduction requirements. [EPA-HQ-OAR-2009-0491-2860.1, p.5]
Marquette Board of Light and Power
Inaccurate Projected Data for Heat Input
The Budgets and Allocations  - Detailed Unit-Level Data (Excel) file available at http://www.epa.gov/airquality/transport/tech.html contained inaccurate projected data. The heat input for Shiras Unit 3 has increased an average of 4% annually for calendar years 2005 to 2008. The recession of 2009 appears to be an anomaly on the heat input of Shiras Unit 3 because it appears that the 2010 heat input will be more representative of pre-2009 operating levels. Using the historical average of the past three years of heat input prior to the recession yields 4,114,467 mmBtu/yr. Assuming a much more conservative growth rate of 2% annually, will provide a projected heat input of 4,196,756 mmBtu/yr in 2012 and 4,336,305 mmBtu in 2014. This is an accurate representation of the projected operation of Shiras Unit 3. [EPA-HQ-OAR-2009-0491-2764.1, p.2]
Unintended Incentives to Pollute to Permitted Levels
The BLP has made significant reductions in Shiras Unit 3 NOx emission rates from 0.301 lbs/mmBtu (525 tons) in 1998 to our current rate of 0.150 lbs/mmBtu (246 tons) in 2009 by focusing our efforts of maximizing the efficient combustion in Shiras Unit 3. This transport rule is unintentionally structured to prohibit utilities from taking such measures proactively. In the future, out of concern of establishing a lower than needed baseline, rules such as this will force utilities to operate up to the permitted limit. The Clean Air Interstate Rule took this concept into account and set a flat emission rate for all applicable units and allocated allowances based on a consistent set of emission rates for all applicable units and historical heat input reported values. If the EPA's intention is to set systems up to proactively lower emissions on combustion units then the approach used in CAIR of allocating allowances should be incorporated in future rules. The other option would be to use the permitted emission limits as a baseline and require every applicable unit to make a standard percentage reduction from that baseline. [EPA-HQ-OAR-2009-0491-2764.1, p.3]
Establishing a Precedent that Eliminates Over Controlling of Emissions Perhaps most troubling about the Transport rule is that it is structured to prohibit controlling beyond what the rule requires. There are financial incentives to over control when a rule is structured such that it collaborates with a solid market based approach. However, it would be within short sightedness for companies in the future to over control to reduce costs through market trading of allowance only to have that market devalued by a future rule set upon a baseline of over controlled emissions. Companies will be looking at the approach taken by the EPA in the transport rule and apply the lessons learned to make sure they are not negatively affected on rules for other pollutants (specifically carbon dioxide emissions). Taking percentage reductions from permitted levels and establishing a solid banking system provides incentives for companies to control today and bank allowances that may carry them through the useful life span of their unit even taking into account further reductions from future rules. CAIR recognized this, which is why the EPA saw an immediate reduction in SO2 and NOx (28% reduction in ozone season emissions and 43% reduction in annual emissions) reported in the EPA Released 2009 Clean Air Interstate Rule Analysis Report. The benefits from the early results of the Clean Air Interstate Rule need to be taken into account in the IPM to determine the necessity and the extent of future emission reduction requirements. The EPA may discover, by modeling the effects of CAIR, that the proactive measures have resulted in the desired effect of bringing downstream nonattainment areas into attainment status. [EPA-HQ-OAR-2009-0491-2764.1, p.3]
Maryland Department of Environment (MDE)
State Budgets and Allocations, Trading, and Variability
Maryland has concerns over EPA's approach to setting state emissions budgets and the allocation of allowances, variability, and intrastate and other trading options. Maryland's comments are as follows. [EPA-HQ-OAR-2009-0491-2639.2, p.11]
State Budgets and Allocations
Maryland disagrees with EPA's methodology for allocating annual and ozone season NOx and annual SO2 allowances. EPA's methodology includes the use of historical emissions rates to determine the number of allowances to  allocate to a given EGU. Since emissions rates of units that are uncontrolled for NOx and SO2 are greater than those of controlled units, this methodology results in EPA awarding more allowances to dirtier units. Units that acted early to reduce their emissions, such as those controlled under Maryland's Healthy Air Act (HAA), are penalized with fewer allowances. Maryland urges EPA to redo its allocations based on heat input or output based emissions limits, rewarding the early actors and forcing dirtier units to buy allowances.  [EPA-HQ-OAR-2009-0491-2639.2, p.11]
Maryland also believes that 2009 was a low emission rate year, due to economic slowdowns and cooler than normal temperatures across the eastern seaboard. Lowered electrical demand would result in many of the dirtiest units running less or not at all. When OTC runs the numbers to compare emissions rates from EPA's modeling to the actual 2009 rates, EPA is predicting very low emission rates at the $500 per ton level, and Maryland believes that the emissions rates listed may be unattainable, especially at that cost level. [EPA-HQ-OAR-2009-0491-2639.2, p.12]
In addition, because EPA based its allocations on 2009 data, an unusually low emission rate year due to economic slowdowns and cooler than normal temperatures across the eastern seaboard, Maryland and other eastern states' EGUs may experience an unlevel playing field in the allocations they receive. [EPA-HQ-OAR-2009-0491-2639.2, p.12]
Maryland supports EPA's focus on reducing NOx and SO2 emissions from EGUs but we believe that EPA should also look into reductions from non-EGU sources as a means of controlling transported pollution. In the first of the three remedies, the "State Budgets/Limited Trading Proposed Remedy", sources would receive allocations based on state budgets alone (variability would not be included). There would be four trading groups established and banking of allowances would be permitted.
The proposed Transport Rule also allows sources to carryover allowances from one year to the next. Maryland is opposed to a large accumulation of carryover allowances and requests that EPA explicitly limit it in the rule. [EPA-HQ-OAR-2009-0491-2639.2, p.14]
Maryland has not found an explicit limit to the trading as it is outlined in the Transport Rule proposal. The only limit to trading seems to be the inherent fact that the trading is among the states in each trading category. [EPA-HQ-OAR-2009-0491-2639.2, p.15]
In allocating allowances EPA proposes to allocate any unused new source set asides proportionally to existing units. Maryland would like to see the new source set asides remain just that  -  set asides. In allocating these set-asides to existing units, newer cleaner generation is discouraged because allowances would have to be purchased from existing sources. [EPA-HQ-OAR-2009-0491-2639.2, p.15] 
Michigan Municipal Electric Association (MMEA)
However, the proposed Transport Rule approach is neither justified nor workable for Michigan public power communities. EPA's proposed rule, allocation methodology and unit-specific allocations will pose particularly drastic and disproportionate impacts on Michigan public power; [EPA-HQ-OAR-2009-0491-2828.1, p.2]
1.) EPA Should Not Allocate Allowances to Specific Units Based on IPM Model Runs that Ignore Reality on the Ground in Public Power Communities
The fates of Michigan's municipal utility generators are left in the hands of a modeling tool that is unaware and unable to process the reality on the ground in Michigan public power communities, where decisions about owning, operating, or potentially closing power plants are made by real people who must take into account legal obligations to serve, costs to ratepayers, the viability of their local communities, the economic and business climate of their regions, the long-term plans for environmental stewardship, and other important factors that are simply lost in the void of IPM model runs. And while it may be proper for EPA to use IPM to establish the structure of EPA Clean Air policies, the overall parameters for emission controls, and even the establishment of state emission budgets for targeted pollutants, in the case of this Transport Rule, EPA is making actual allowance allocations to specific units in specific communities based on IPM model runs  -  and thus allowing the IPM predictions to determine the fate of these units and communities. Coupled with EPA's proposal to virtually eliminate the potential for State-based allowance allocation decisions through State Implementation Plans (SIPs) and the numerous errors that are apparent in EPA's IPM modeling with respect to specific municipal utilities, this decision to allow IPM predictions to supplant the decisions of actual managers, community board members and city councils in public power systems is unwarranted and potentially very harmful to these communities. [EPA-HQ-OAR-2009-0491-2828.1, pp.4-5]
[For additional comments pertaining to IPM, see pages 5-7 of this comment.]
2.) EPA's Allowance Allocation Methodology Ignores the Cornerstone of Compliance for Michigan Public Power Communities
Michigan public power communities have been subject to NOx emission limitations for more than a decade, under the NOx SIP Call, the Section 126 NOx rule, the Clean Air Implementation Rule and, of course, the State of Michigan's implementation of these NOx requirements. What EPA might not (but should) know is that Michigan public power systems have complied with NOx regulations through a State of Michigan approach that distributes "hardship allowances" to small EGUs that will suffer drastic, disproportionate impacts from Clean Air Act rules. The proposed EPA Transport rule ignores the Michigan hardship allowance approach in a way that could cause sudden and drastic impacts on covered Michigan communities. Thus, EPA (and the IPM) must take the Michigan hardship allowance program into account when assessing the six Michigan municipal utilities and their units affected here. [EPA-HQ-OAR-2009-0491-2828.1, p.7]
[For additional comments pertaining to EPA's Allowance Allocation Methodology, see pages 7-9 of this comment.]
1.) Correct the data errors and information regarding specific municipal units.
2.) Drop erroneous assumptions that units will install pollution controls that have never been required nor planned, and erroneous assumptions that units will close prematurely.
3.) Adopt factors in the Transport rule, including in IPM modeling runs, which account for the obligation to serve and unique roles of Michigan public power communities to keep these plants cost-effectively operating.
4.) If projections regarding these Michigan municipal units cannot be corrected as stated herein, EPA should shift its allocation model entirely away from current and predicted actions at units, and return to the tried-and-true method of allocating emissions limitations based on historical heat input utilization. [EPA-HQ-OAR-2009-0491-2828.1, p.16]
Mirant Corporation
1. The proposed allowance allocation scheme is fundamentally unfair to companies like Mirant that have made substantial investments in pollution control technology. [EPA-HQ-OAR-2009-0491-2843.1, p.1]
2. To avoid penalizing companies that install expensive control technology and to ensure that pollution control costs are shared equitably, allowances should be allocated based on heat input, as in past EPA programs. Alternatively, for EGUs located in Maryland, allowances could be based on the approach that the Maryland already adopted in the Healthy Air Act (HAA) and the accompanying regulations. [EPA-HQ-OAR-2009-0491-2843.1, p.2]
I. The Proposed Approach for Distributing Allowances is Unfair and Inconsistent with EPA's Long-standing Concerns about Penalizing Units That Have Installed Emission Controls
In the past, EPA has always emphasized the need to maintain a level playing field by distributing allowances based on heat input, rather than emissions. The Agency has specifically stated that it would be improper to distribute allowances based on historic emissions, because such an approach would penalize facilities with the best controls. Yet that is precisely what the Agency has proposed in the Transport Rule, without providing any rational justification. [EPA-HQ-OAR-2009-0491-2843.1, p.2]
It appears that EPA has simply used the same approach for distributing allowances to individual units that it has used for setting state budgets  -  using the lower of historic emissions or projected future emissions. This simply makes no sense and fails to recognize the fundamental difference between (1) setting a state-wide emission level and (2) deciding how to allocate the burden of achieving that level. [EPA-HQ-OAR-2009-0491-2843.1, p.2]
The purpose for setting a state budget is to ensure that each state will eliminate all emissions that are "significantly contributing" to nonattainment or maintenance problems in other states. To accomplish this objective, the Transport Rule requires each state to eliminate all EGU emissions that can be reduced cost effectively. This is sensible and consistent with both the NOx SIP and CAIR. [EPA-HQ-OAR-2009-0491-2843.1, p.2]
The purpose of distributing allowances is to allocate, among individual plants, the burden of meeting the state budget. Rather than giving each plant the allowances it will need to cover its expected emissions, the Agency should try to ensure that the cost of reducing state-wide emissions will be shared equitably among all the plants in the state. For example, even if EPA's modeling predicts that it will not be cost-effective to install controls on Plant A, Plant A should not be given a free ride. Like all EGUs in the state, it should bear its fair share of the costs that will be incurred for the state to meets its budget. Under a well-designed cap-and-trade program, this is accomplished largely by requiring uncontrolled units to purchase allowances from units that have incurred the cost of installing and operating expensive emission controls, and thus to help pay for those controls. This equitable sharing arrangement -  all plants cover their share of the cost of emission controls that are installed only on some plants  -  cannot be accomplished under the allocation scheme in the proposed rule. [EPA-HQ-OAR-2009-0491-2843.1, p.3]
The proposed allocation scheme also creates the wrong incentives and sends the wrong signal to the marketplace. If a company anticipates that additional emission reductions will be required in the future and that allowances under a future program will be based on emissions, it will have an incentive to keep its emissions relatively high. This has long been a problem with the new source review (NSR) program. The Acid Rain program, the NOx SIP Call, and CAIR were all designed, in part, to overcome this problem. It would be unfortunate for the Agency to perpetuate it in the Transport Rule. [EPA-HQ-OAR-2009-0491-2843.1, p.3]
Under the proposed rule, Mirant would be at a significant disadvantage because of EPA's decision to reward units that have not installed scrubbers. In Maryland, Mirant has installed scrubbers on all its coal units (Dickerson units 1, 2, and 3, Morgantown 1 and 2, and Chalk 1 and 2), while coal units at CP Crane and Herbert A. Wagner (both of which are owned by Constellation) are not scrubbed. These scrubbed Mirant units would receive substantially fewer allowances than Crane and Wagner on a MW basis. [EPA-HQ-OAR-2009-0491-2843.1, p.3]
To avoid penalizing companies that install expensive control technology and to ensure that pollution control costs are shared equitably, allowances should be allocated based on heat input. This is the approach that the Agency used in both the NOx SIP Call and CAIR, and that EPA should use again in the Transport Rule. [EPA-HQ-OAR-2009-0491-2843.1, p.3]
Over the last few years, a number of plants have been shut down temporarily in order to complete the installation of new scrubbers and SCR units. Again, to avoid penalizing these units, EPA should determine the proper baseline heat input for each unit by looking back over the last 5 years  -  perhaps using the average of the highest 3 years over the last 5 year period. [EPA-HQ-OAR-2009-0491-2843.1, p.3]
II. Allowance Allocations for Units Located in Maryland Should be Consistent with the Maryland Healthy Air Act
The Clean Air Act (CAA) is very clear in assigning different roles and responsibilities to EPA, on the one hand, and the States on the other. In particular, the Act preserves for each State 'the primary responsibility for assuring air quality within the entire geographic area comprised in such State' by regulating sources within the State while relegating EPA 'to a secondary role' of determining whether a State's regulations are sufficient to meet Clean Air Act requirements. Train, 421 U.S. at 64, 79. In interpreting the CAA, the Supreme Court has stated:
Congress plainly left with the States, so long as the national standards were met, the power to determine which sources would be burdened by regulation and to what extent.
Union Electric Company v. EPA, 427 U.S. 246, 269 (1976) (emphasis added). [EPA-HQ-OAR-2009-0491-2843.1, p.4]
When it enacted the Health Air Act (HAA) in 2006, the Maryland State Legislature specifically addressed the issue of "which [Maryland EGUs] would be burdened by regulation and to what extent." In the Transport Rule, EPA has proposed to find that Maryland, even with the HAA, has not done quite enough to meet the requirements of section 110(a)(2)(D) of the CAA. Even if this finding is finalized, however, it does not mean that EPA can fundamentally change the State's recent decision as to how Maryland companies should share the burden of reducing total EGU emissions in the State  -  especially when there is no rational basis for EPA's approach. [EPA-HQ-OAR-2009-0491-2843.1, p.4]
The HAA established unit-specific emission allocations that are essentially the same as allowances under the proposed Transport Rule, except that the HHA 'allowances' can only be traded within a particular company. See COMAR 26.11.27.04(e) (System-Wide Compliance Determinations) and 26.11.27.01(B)(3) (defining system as 2 or more EGUs owned or operated by the same person). [EPA-HQ-OAR-2009-0491-2843.1, p.4]
The problems with EPA's proposed approach are apparent from the following charts, which show the 'allowances' that have been issued under the HAA compared to the allowances that would be allocated to those same EGUs under the Proposed Transport Rule. There are three charts: (1) Annual SO2; (2) Annual NOx; and (3) Ozone Season NOx. The colors on the charts are important because, as noted above, the HAA imposes company-wide mass limits on the three major power producers that operate EGUs in the State. In essence, Mirant units may trade allowances with other Mirant units, but they cannot meet their compliance obligations by acquiring allowances from units owned by either Constellation or Allegheny  -  the other two companies covered under the HAA. Nor can Mirant sell any of its excess allowances to Constellation or Allegheny. [EPA-HQ-OAR-2009-0491-2843.1, pp.4-5]
[For additional comments pertaining to the Maryland Healthy Air Act (HAA) and Annual SO2 and NOx charts, see pages 5-8 of this comment.]
Mirant recognizes that the proposed transport rule covers certain units that are not included in the HAA, but these are very small units  -  as indicated by the fact that only one of them that would receive any allowances under the proposed Transport Rule (AES Warrior Run) and would be given just 464 SO2 allowances. Note that the 2012 state-wide "cap" under the proposed rule is essentially the same as the 2013 HAA cap, but the number of allowances given to each company under the two programs is very different. The Allegheny plant, for example, will only be allowed to emit 768 tons of SO2 under the HAA. This is a hard cap that prohibits the plant from emitting more than 768 tons per year, but the plant would nevertheless receive 5124 SO2 allowances under the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2843.1, p.6]
Even so, there is no reason for EPA to base allowance allocations on modeling predictions when the Agency can easily use the method that the Maryland Legislature has chosen to allocate the burden of reducing EGU emissions in the State. To the extent that EPA believes that either the timing or the levels in the HAA are insufficient to meet the requirements of Section 110(a)(2)(D), the Agency can easily adapt the HAA approach to meet those objectives. To take a simple example, if EPA believes that an additional 5% reduction is needed, it can simply reduce each unit's HAA allocation by 5%. [EPA-HQ-OAR-2009-0491-2843.1, p.8]
Mississippi Department of Environmental Quality
For Mississippi (and other states) the allocations are based on the Integrated Planning Model (IPM) projections. These projections resulted in a number of currently operating facilities receiving no allocations under this rule. We understand that this is because the model determined what controls facilities would have in the future and that some would not even be operating in the future. We do not believe it is appropriate to use a modeling tool to make decisions about shutting down facilities or what level of control particular facilities might have in the future. [EPA-HQ-OAR-2009-0491-2634.1, p.1]
MS DEQ supports assigning the allocations based on historical heat input data that takes several years worth of data into account. We realize that using heat input data may assign more allowances to some sources than are allowed by their permits. In such cases, the allowances could be limited to be no more than their permit would allow and the remaining emissions be redistributed to the other facilities. The States should also have a period to review and approve the proposed allowances before they are made final. [EPA-HQ-OAR-2009-0491-2634.1, p.1]
National Grid
National Grid does not support the current allowance allocation methodology that relies on projected data. As noted above, we have serious concerns with the ability of the model to accurately reflect the unit by unit operation and feel that it is inappropriate for the EPA to use these results to allocate allowances. We support an allocation based on historical data, preferably historic heat input or output. National Grid would oppose an allocation based on historic emissions since this approach would unfairly penalize units that have already made significant emissions reductions. [EPA-HQ-OAR-2009-0491-2583.1, pp.3-4]
National Rural Electric Cooperative Association (NRECA)
Continuing allocations to "non-operating" units is too generous. Allocations to new units should be sufficient to cover emissions considering the prospective application of best available control technology (BACT). At least a portion of unused Clean Air Interstate Rule (CAIR) allowances should be available to assist in covering new unit needs. [EPA-HQ-OAR-2009-0491-2723.1, p.1]
The allowance allocation methodology radically departs from previous regulatory allocation methods and creates numerous inequities and other poor policies without rational justifications. The proposed allocation formulas punish cleaner emissions units and electric consumers who purchase power from them at higher costs. Most of the problems inherent in the proposal's methodology could be resolved if states budgeted allowances were distributed to each unit within the state based pro-rata on the unit's portion of the state historic heat rate updated periodically to include new units. Such distribution should sub-categorize between coal, gas, and oil. [EPA-HQ-OAR-2009-0491-2723.1, p.1]
The preferred remedy option allowing unlimited emissions trading during the initial 2012 compliance period and limited interstate trading in the second compliance period recognizes the economic benefits of trading and should be retained. The auctioning of allowances would drive up program compliance costs and, therefore, is justifiably excluded from the preferred remedy and proposed intrastate option.  [EPA-HQ-OAR-2009-0491-2723.1, p.1]  
While it is possible to dig through the annuals of EPA's technical supporting documentation within the rulemaking docket to ferret out proposed individual unit emission allowances, in many cases it is not possible to ascertain how or why EPA's modeling generated a given specific unit allocation. Thus, the proposed rule and underlying documentation present something like a "black box" for affected parties to comment. It fails to present adequate information so as to allow full comment on unit emissions allocations and other issues important to affected electric utilities. [EPA-HQ-OAR-2009-0491-2723.1, p.3]
EPA, by postponing implementation of the Transport Rule until at least 2014, will provide many benefits. This postponement will allow EPA the time which is needed in order to incorporate the new Ozone NAAQS. It will also give regulated CAIR I entities time to utilize their banked allowances, and will help avoid any Constitutional "Takings" arguments made by utilities which have experienced an economic loss by means of the Transport Rule. This additional time will also allow for additional review and comment periods by regulated industry to assist EPA in developing a more accurate regulation. As EPA is aware, EPA is not under any court order to finalize a rule by 2012, and so Lakeland Electric finds this time extension proposal a logical appeal. Therefore, EPA should postpone any compliance measures required under the Transport Rule until 2014. [EPA-HQ-OAR-2009-0491-2630.1,pp.5-6]
The proposed CATR would significantly restrict emissions within the 32 state trading areas and therefore allowance allocations. EPA has offered scant explanation to explain the proposal's continuing allocating of allowances to retired or non-operating units for a full six years after operation ceases at full allocation rates under original existing unit formulas, except to surmise it would discourage older units from operating. Not discussed in the proposal, however, is the fact that older units will be discouraged from retiring. Further, no data or documentation is offered to explain the six-year time period and full allocation after non-operation rationale. Since, as previously mentioned, EPA's analysis shows that CATR would mandate one million tons of SO2 reductions more than that of CAIR, EPA's wisdom of granting an allowance windfall to the oldest and most inefficient generating units is not equitable or otherwise justified. A certain fact here is non-operating units would receive allowances not needed for compliance; a proposed windfall established exclusively by EPA rulemaking.  [EPA-HQ-OAR-2009-0491-2723.1, p.10]
On the other hand, EPA proposes a 3 percent set-aside from state allowance budgets for new units, but no allowances for the initial control periods when the new units come on line. In the event of insufficient allowances in the set-aside, available allowances are distributed pro-rata to new units. So under EPA's proposal, older units receive un-needed allowances and new units may well end up with a fraction on what is needed and none for the first year of operation. It is quite plausible that without certainty that a stream of allowances would be available to cover new unit operation, no new units would be built. This is indeed a strange policy for EPA to conjure up under the CAA where old units can hoard allowances while new units get none at all, at least initially. [EPA-HQ-OAR-2009-0491-2723.1, p.10]
EPA's proposed old and new unit allowance policies are off the cuff and exemplify the importance of letting states determine these types of policies based on local considerations and needs. In this context, it is a mistake for EPA to short circuit the SIP process, as the proposal does, as NRECA has commented above. The CATR allowance allocation methodology should ensure new units equipped with best technologies and techniques to minimize emissions receive 100 percent of allowances needed for commercial operation, including initial year requirements.  [EPA-HQ-OAR-2009-0491-2723.1, p.11]
There are several ways the proposed CATR could be changed to accommodate new unit allowance allocations. First, to the extent that the new unit set-aside allowances are not available, allowances given to retired units could be siphoned off on a pro-rata basis as needed and reallocated at no charge to new units. As EPA points out in the proposal, retired units do not need them. Second, instead of eliminating unused CAIR allowances, at least a portion of them could be set-aside for new unit utilization in the event of a shortfall in the state's new unit set-asides. [EPA-HQ-OAR-2009-0491-2723.1, p.11]
The proposed CATR allowance allocation scheme is flawed for numerous reasons. It is based on EPA computer model projections of both future individual unit utilizations and emission reduction capabilities at specified marginal costs levels of emissions reductions. [EPA-HQ-OAR-2009-0491-2723.1, p.12]
The model attempts to predict the future of literally thousands of electric utility fossil fuel units located within the proposed CATR 32 state trading areas. Regardless of the purported sophistication of EPA's models, they do not and cannot accurately forecast how each and every fossil fuel unit among thousands will be utilized. For example, the models cannot account for the presence or ramifications of short and long term wholesale power agreements under which unit owner obligations include future system and individual unit power demands. The models cannot account for future business decisions, the necessities of which are not yet presently known or anticipated, but nonetheless may need to be made that would significantly affect individual unit utilization within a given utility system. There are literally thousands of significant factors that affect future unit utilization of which the models do not and cannot take into account. [EPA-HQ-OAR-2009-0491-2723.1, p.13]
The models do not and cannot accurately forecast for each and every fossil fuel unit within the 32 state trading regions the actual future costs of meeting the emission reduction obligations dictated by the models. For example, the models cannot account for on a unit basis costs associated with contract breaches associated with early termination of coal and associated transportation contracts necessitated by the models to switch coals. The models cannot account for costs associated with obtaining new contracts for new coal deliveries especially when potential contracting parties for supply are aware of reduction obligations dictated by EPA's models and the essence of time. The models assume "just in time" expanded natural gas transportation capabilities to meet the aggregate demand the models' emission reduction mandates place on affected units within a geographic area. Likewise, there are literally hundreds of significant factors that affect future costs of emissions controls of which the models cannot take into account. [EPA-HQ-OAR-2009-0491-2723.1, p.13]
In short, EPA's models put real life units within a virtual world and would dictate unit utilization and emissions reduction destinies based on this fantasy. EPA may argue that emissions trading allowed under its remedy and preferred options would wrong all the deficiencies inherent in this entire scheme.  As EPA is well aware, however, trading is necessarily limited by the North Carolina decisions and is even entirely prohibited by at least one option in the proposed CATR, so it is unlikely trading would save the day. [EPA-HQ-OAR-2009-0491-2723.1, pp.13-14]
Additionally, EPA's proposed allowance allocation trading scheme fails to reward cleaner emissions units and the electric consumers who have borne higher electricity costs because they must pay for existing, expensive emission controls. The model metrics do not consider existing unit generation costs, and as such some of the most costly fossil fuel generation affected by the proposal would have to incur even higher costs as compared to CATR compliance costs associated with more polluting and less efficient affected units. If EPA has the discretionary authority under the CAA to effectively reward more polluting units to the detriment of cleaner ones; and it may not, it represents poor policy judgment nonetheless. [EPA-HQ-OAR-2009-0491-2723.1, p.14]
NRECA, however, commends EPA for willingly opening up its proposed allocation methodology for comment on alternative methods that still link unit allowances directly to the way state budgets were developed. NRECA construes this EPA stated limitation on alternatives to mean that so long as the aggregate allowable emissions within individual state budgets are not affected or altered by the unit allowance allocation methodologies, EPA would deem it within its regulatory discretion. EPA's limitation here appears to be based on the North Carolina decisions that appear to limit EPA's discretion in allocating allowances for Section 110(a)(2)(D)(i) purposes to the extent that the distribution cannot in effect determine or partially determine states' emissions budgets. NRECA believes North Carolina decisions do in fact impose this limitation, but they do not prohibit allocations methods under state budgets already determined based on the need to address interstate air pollution. [EPA-HQ-OAR-2009-0491-2723.1, pp.14-15]
NRECA believes many of the troublesome aspects of the proposed CATR could be addressed if the allocation methodology was structured in a manner similar to that contained in CAIR for annual NOx allocations as a SIP (or FIP option as the case may be) for all the CATR trading programs. Specifically the salient features of this methodology include allocating allowances to existing units based on historic heat in-put using the three highest heat in-puts of the past five years to derive annual averages (seasonal for ozone), and allocating allowances to new units based on a set aside and folding new units into existing unit category after five years of operation. [EPA-HQ-OAR-2009-0491-2723.1, p.15]
EPA mentions an option for allowance distribution to units placed into various subcategories of units that have similar characteristics. In this light, NRECA advocates that coal, gas, and oil units be divided into three categories and that allowances be distributed pro rata to units in each category based on unit heat in-puts as a percentage categorical heat in-puts. NRECA believes that this methodology is rationale and well within the bounds of the in North Carolina decisions. Additionally, this allocation rewards, not punishes, electric consumers that have already incurred high costs of emissions controls. [EPA-HQ-OAR-2009-0491-2723.1, p.15]
As with the CAIR approach, this methodology could provide options for each state to consider whether new units should receive allowances from set-asides during their initial year of operation and whether retired units should continue to receive allowances and if so, how long or at a diminished allocation. [EPA-HQ-OAR-2009-0491-2723.1, pp.15-16]
Also, as a fundamental matter, the NODA additions to the CATR do not appear to alter the inequitable methodology utilized to allocate unit allowances. The proposed allocation methodology fails to equitably reward cleaner units with existing emissions controls and with associated higher generation costs that are passed onto cooperative consumers. The proposal also fails to provide reasonable methods of allocating allowances to new, to be constructed units. As NRECA advocated in its CATR comments, allocations based on historic heat in put to existing units with a reasonable set-aside for new units is a previously demonstrated and fair method. This methodology should be utilized here. [EPA-HQ-OAR-2009-0491-3756.1_NODA, pp.1-2]
It is impossible to comprehensively comment on the NODA. Under the proposed CATR framework, EPA through modeling would determine state by state emissions budgets it deems necessary for states to meet their Clean Air Act Section 110 (a)(2)(D) obligations to address interstate air pollution. Affected unit emissions allocations within each state in the aggregate would equal the state's budget.2 Thus two metrics within the proposed CATR are vital and necessary to properly evaluate the allocations to each affected unit: the emissions budget for the state in which a unit resides and the unit's emissions allocations. The NODA does not provide necessary information to allow comment on unit allocations that may result from it and deviate from those proposed earlier in the CATR. [EPA-HQ-OAR-2009-0491-3756.1_NODA, p.2]
The NODA leaves commenters in the dark insofar as the ability to evaluate potential changes in unit allocations relative to those in the proposed CATR. As evidenced in the NODA, EPA does not even know itself how it might use the additional NODA information to change the already proposed unit allocations. At the very least the following questions are raised by the NODA that must be answered to allow meaningful comment on it and on the proposed CATR generally: (1) Will state emissions budgets be adjusted based on new NODA modeling? (2) What natural gas resource assumptions will be used? (3) How can unit allowances be determined when, as stated, EPA will modify the modeling to reflect comments not yet evaluated, possible changes in cost and emission projections used in the multi-factor test to determine significant contribution, updated NOx rates, updated information on new units, updated information on pollution controls, and updated information on unit retirements? [EPA-HQ-OAR-2009-0491-3756.1_NODA, pp.2-3]

2 This presumption ignores the proposed state variability limits which NRECA supports. See the proposed CATR at 75 Fed. Reg. 45,210 at 45,292. [EPA-HQ-OAR-2009-0491-3756.1_NODA, p.2]
New Jersey Department of Environmental Protection (NJDEP)
The proposed allocation of allowances results in rewarding dirty units, while penalizing clean units. New Jersey urges the USEPA to revise their allocation method to be based on recent energy output with rolling updates, not historical fixed emission levels. Under the USEPA's proposal, clean units that currently meet the Phase 1 CAIR emission rate of 0.15 lbs/MMBtu account for 59 percent of the affected units, but only get 16 percent of the total Transport Rule ozone season NOx allowance. In tum, units that are dirtier than 0.15 lbs/MMBtu account for 41 percent of the affected units, but get 84 percent of the allowances. This provides disincentive for dirty units to control their emissions, while under allocates to clean units that have less ability to reduce emissions.
For example, the Bergen Generating Station has combined-cycle gas-fired units with emission rates below 0.10 lbs/MMBtu and emit about 200 tons of NOx each ozone season. The Transport Rule only allocates 41 allowances to this source. Conversely, the Transport Rule allocates 1,798 allowances to BL England, which more than covers the facility's current high NOx emissions and provides excess to sell to under allocated gas-fired facilities. This disparity is compounded because BL England has an enforcement agreement which, in conjunction with aNew Jersey rule approved by the USEP A, sets emission limits which require selective catalytic reduction (SCR) in 2012 and 2013. This will result in NOx emissions of about 600 tons per ozone season. It Inakes little sense to allocate excessive NOx allowances to poorly controlled or uncontrolled coal-fired power plants, which have the greatest potential for emissions reduction, while under allocating much cleaner gas fired units.
The USEP A should revise the allocation method to provide for fair allocation of allowances that provides incentive to reduce emissions and not reward poorly controlled or uncontrolled units. Also, the USEP A should allow the states to allocate the allowances in a more appropriate manner. The USEPA provided flexibility for states to allocate allowances under CAIR, and New Jersey did this. Our NOx allocation method is based on rolling 3 year electric output, which encourages energy efficiency. It was supported by our power companies, approved by the USEP A, and is being successfully implemented. We would not want to regress to the less fair and less environmentally sustainable method that has been proposed in this transport rule.   [EPA-HQ-OAR-2009-0491-2684.1 p.3]
New York Power Authority
While this IPM based allocation methodology might serve the purpose of establishing required reductions in emissions to satisfy Clean Air Act Section 110(a)(2)(D)(i)(1), it is based entirely on economic inputs and does not account for critical local factors such as reliability related issues like the New York State Reliability Council's 'Minimum oil burn' rule or individual contractual agreements. The IPM model is not considered historical inputs of individual units or actual permitted emissions of SO2 and NOx. Applying the IPM results to individual units would severely restrict the operation of otherwise clean power plants and thus could jeopardize reliability as described below. [EPA-HQ-OAR-2009-0491-3820, p.1]
NYPA believes the EPA should reconsider the unit allocations taking into consideration historical heat inputs or historical emission values and the facilities permit conditions.[EPA-HQ-OAR-2009-0491-3820, p.2]
New York State Department of Environmental Conservation
Under the current proposal, states' flexibility in administering a trading program would be limited under a FIP. In the proposal's discussion on how well state market trading programs have worked, several state programs are discussed. As the elements of the preferred trading program are finalized, it is worth considering New York's administration of its trading rules, including the federal CAIR program, which includes provisions to ensure that power plants in each state control their own emissions rather than buy out-of- state allowances. Allocations are [EPA-HQ-OAR-2009-0491-2730.1, p.6] based on historical heat input and provide a five percent set-aside for new sources. New York's program additionally provides for a 10 percent set-aside for energy efficiency improvement projects. New York's flexible trading program enables the effective management of allowances and emission reductions allowable under a state-specific SIP. To this end, EPA should provide states with the ability to develop its own allocation schemes to be used in concert with the FIP. [EPA-HQ-OAR-2009-0491-2730.1, p.7]
Budget Allocations under the FIP
EPA proposes that, for 2012, each existing unit in a given state receives allowances commensurate with the unit's emissions reflected in whichever total emissions amount is lower for the state, 2009 emissions or 2012 base case emissions projections. In any case, the allocation is adjusted downward if the unit has additional pollution controls projected to be online by 2012. This approach seems to 'punish' those states and units that have controlled and 'reward' those that have not controlled. EPA should base emission budgets and allowance allocations at the level needed to eliminate SC/IM, and develop an equitable formula for allocation. EPA should not use a permanent allocation approach, but rather use an approach that is able to adjust to market conditions and/or generation characteristics. [EPA-HQ-OAR-2009-0491-2730.1, p.8]
The Department suggests a historic heat-input or net energy output based methodology for determining allocations to existing units. This would allow for variations and adjustments from recent years of operation to provide more accurate allocations to affected units within the program. The number of allowances to be allocated to each unit would incorporate the heat input experienced by the unit for any single control period among the three most recent control periods, for which data is available. Units are capped at their potential to emit or any limiting permit condition. [EPA-HQ-OAR-2009-0491-2730.1, p.8]
Use of the IPM Model
The use of IPM is inappropriate for determining allowance allocations. EPA's analysis does not accurately reflect local transmission constraints and reliability rules. This results in some units being removed or shut off by IPM as uneconomic. However, these units are required to meet local demand for local reliability concerns and should be allocated based on historic generation. [EPA-HQ-OAR-2009-0491-2730.1, p.9]
In the proposal, each unit was allocated based on the lowest of either the 2014 base case (IPM run with no controls - $0 per ton) or 2009 emissions. Since New York's statewide budget is much closer to the 2009 emission level than it is to the 2014 base case level, it seems that many units in New York were allocated based upon 2009 emissions. 2009 was a cool summer in the Northeast, and a quick review of EPA's Clean Air Markets Division (CAMD) data shows New York State facilities consumed about 18% less fuel (based upon heat input) in 2009 than in 2008 (also a cool summer and the next lowest fuel consumption year). During a cool ozone season, many facilities operate at a significantly reduced rate, so to base allocations on an extreme year is not appropriate. [EPA-HQ-OAR-2009-0491-2730.1, p.13]
This inappropriate allocation methodology could produce a scenario where, in a warmer year when demand for electricity is higher in New York, facilities in New York would be unable to comply with the rule as proposed. For example, if New York's emissions increase 18% (essentially just returning to 2008 fuel usage rates), New York would exceed its proposed budget. If New York EGU sources were to return to 2008 emissions (which were very low, at a rate of less than 0.1 lbs 1 MMBtu), these sources would exceed the budget plus the 3-year variability and would only fall short of the allocation plus the 1-year variability by 115 tons. Since 2008 and 2009 were the lowest fuel consumption years since Title IV began, EPA should not use these years as a basis for allocation. [EPA-HQ-OAR-2009-0491-2730.1, p.13]
Additionally, many states prefer to allocate their own emissions allowances to in-state sources rather following EPA procedures. This should not pose a problem since the distribution of allowances within the state does not affect the overall emissions in the state. The proposal, however, does not provide guidance on a mechanism that EPA would consider an acceptable allowance mechanism. Additionally. guidance on what criteria state SIPs would need to meet in order for a state's sources to be able to participate in the interstate trading program must be provided. While we understand and agree that a FIP is necessary for this instance to obtain the emissions reductions in the most expeditious manner, EPA should indicate that it will quickly move to approve a state SIP that incorporates the Transport Rule FIP elements and only differs significantly from the FIP with respect to the allowance allocation scheme. [EPA-HQ-OAR-2009-0491-2730.1, p.5]
Proposed 'Remedy Options'
In developing approaches to eliminate emissions identified as contributing to all or part of a state's SC/IM, EPA proposed a remedy option and requested comment on two alternatives. The proposed remedy option is a combination approach that incorporates limited interstate trading with other requirements and would regulate S02 and NOx emissions from EGUs through FIPs in the covered states. New York supports the proposed remedy option. However, all elements of the interstate option must incorporate the necessary limitations to prevent emissions from exceeding the level needed to eliminate transport. Total emissions in any state in any year should not exceed the level that EPA has determined is needed to eliminate SC/IM. [EPA-HQ-OAR-2009-0491-2730.1, p.6]
The Department agrees with a new unit set-aside of 3 to 5 percent for each transport rule program with any unused allowances flowing back to the existing unit pool for redistribution to those units. The Department also agrees with the approach of proportionally reducing the number of allowances when the new unit set-aside is insufficient to provide allocations for all new units requesting allowances. [EPA-HQ-OAR-2009-0491-2730.1, p.8]
Budget Set-Asides
EPA proposes new unit set-asides that are 3 percent of the state emissions budgets. The size of the new unit set-aside would be 3 percent for the S02 group 1, S02 group 2, NOx annual, and NOx ozone season trading programs, as appropriate, for each state. EPA based the size of the proposed new unit set-asides on a comparison of projected emissions from new units to projected emissions from existing units for all covered states under the proposed State Budgets/Limited Trading remedy. For each control period, if the size of the new unit set-aside were insufficient to provide allocations for all new units requesting allowances, then allocations to all new units would be proportionally reduced. 
[EPA-HQ-OAR-2009-0491-2730.1, p.8]
The Department has incorporated a new unit set-aside for a number of years under New York's NOx Budget program, Acid Deposition Reduction Program, and CAIR. The set-aside provides a sufficient amount of allowances for new units to use and can be given back to the affected existing units if not needed/used by new units coming into the program for any given year/season. [EPA-HQ-OAR-2009-0491-2730.1, p.8]
New York University School of Law, Institute for Policy Integrity
:: EPA's preferred alternative should be modified to create a distinct intrastate assurance allowance trading mechanism to improve compliance with the statutory mandate while increasing flexibility, predictability, and cost-effectiveness; [EPA-HQ-OAR-2009-0491-2691.1, p.1]
:: An auction-based methodology should be used to allocate emissions allowances; [EPA-HQ-OAR-2009-0491-2691.1, p.1]
4. Auction-Based Method of Allocation of Emissions Allowances
EPA should use an auction-based method to allocate allowances to sources within each state. Under its preferred approach, EPA proposes to base allocations to existing sources on projected emissions, after elimination of some or all significant contribution to nonattainment or interference with maintenance. The allocations would be permanent, because original allocations would not be updated. Instead, EPA would allocate allowances for several years at once, in order to support trading programs. EPA would also set aside allowances to cover new sources within a state. If a source does not operate for three years, EPA would cease allocating allowances to that source. However, under its first alternative approach, EPA would withhold a small portion of emissions allowances for purchase, in an annual auction, by sources with a smaller share of the generation market within the state. EPA's purpose in relying on an auction for allocation is to limit direct purchase from larger generators -- in essence, trading -- which EPA finds may lead to market price manipulation. [EPA-HQ-OAR-2009-0491-2691.1, pp.11-12]
Auctioning all allowances would lead to the most efficient and equitable method of allocation. Under EPA's preferred approach, significant market inefficiencies would likely occur without an auction, due to inevitable inaccuracies in the initial allowance allocation. The initial allocation is based on projected emissions, which will not be updated to reflect true annual emissions. Such an allocation method is inherently error-prone, and consequently trading would be necessary to remedy the defects in the initial allocation, as some sources will exceed their initial share of the budget. Unfortunately, trading is restricted under the preferred approach's assurance provisions. As explained above (pages 6-7), allocating allowances instead of auctioning them magnifies the inefficiencies and uncertainties created by the current assurance provisions. By contrast, under an annual auction, sources would start each year with a number of permits much closer to the number they will actually need. Instead of relying on trades as a corrective measure for initial misallocations, post-auction trading would mostly just respond to unexpected variability, thus serving the intended purpose of the preferred approach's variability limits: "inherent variability in power system operations." [EPA-HQ-OAR-2009-0491-2691.1, p.12]
Under any regulatory alternative -- EPA's preferred approach, the modifications suggested in these comments, or some other trading system -- an auction is essential to prevent unfair windfalls. As soon as an emissions allowance cap is put in place, the cost of electricity and energy-intensive goods will rise, creating a price signal across the economy to save energy and reduce emissions. This effect will take place regardless of how permits are distributed, because utility companies will account for the market value of the permits, not the purchase price. Whether allowances are freely given away or auctioned off, firms will weigh the costs of reducing emissions against the revenue from selling extra allowances. The only difference is, when firms are given the valuable allowances for free, they are much more likely to pass on the windfall profits from trading to their shareholders than to their consumers, even as consumers see prices go up. 61 By contrast, when allowances are auctioned, the revenue generated can be directed back to consumers or the general public welfare. 62 A state can direct auction funds to benefit consumers, support energy efficiency projects, or otherwise aid the state in energy investments. While EPA notes its concerns about the use of revenues generated by an EPA-run auction, 64 EPA should consider the creation of incentives to encourage states to adopt auction-based methods to allocate allowances. [EPA-HQ-OAR-2009-0491-2691.1, pp.12-13]

61. The exception to this case is under regulated utilities, where consumers would have to rely on regulators to protect their interests by setting price ceilings. [EPA-HQ-OAR-2009-0491-2691.1, p.12]
62 There is broad support for allocating emissions allowances by auction within the economics and public policy communities, which recognize the cost-effectiveness and efficiency outcomes created by the auctioning of allowances. "[T]here are compelling arguments for the superiority of auctioned permits. First, auctions are more cost-effective in the presence of certain kinds of transactions costs. Second, the revenue raised by an auction mechanism can be used to finance a reduction in some distortionary tax . . . . Third, auctions provide greater incentives for firms to develop substitutes for regulated products, by requiring firms to pay for permits rather than giving them rents. Fourth, the revenue raised by auctions may provide administrative agencies with an incentive to monitor compliance." Nathaniel O. Keohane, Richard L. Revesz & Robert N. Stavins, The Choice of Regulatory Instruments in Environmental Policy, 22 HARV. ENVT'L L.REV. 313, 316 n.19 (1998) (internal citations omitted). See also Michael Abramowicz, The Law-and-Markets Movement, 49 AM. U. L. REV. 327, 353 n.112 (1999) ("[A]uctions may be both a fairer and an economically more efficient means of distributing pollution entitlements than preservation of the status quo."). [EPA-HQ-OAR-2009-0491-2691.1, p.13]
64. Transport Rule at 45,353 (noting that it did not propose using auction revenues to support energy efficiency projects because the requirements of the Transport Rule would be implemented through a Federal Implementation Plan (FIP), rather than a State Implementation Plan (SIP), and that under a FIP, EPA would allocate allowances according to the rule's requirements, whereas under a SIP, states would have flexibility to allocate or auction allowances in their budget and use revenues to support energy efficiency projects). [EPA-HQ-OAR-2009-0491-2691.1, p.13]
NextEra Energy, Inc.
EPA should abandon its proposed allowance allocation methodology based on the lower of projected 2012 emissions or actual 2009 emissions and adopt either a historic generation output-based allocation approach or a historic heat input-based approach
EPA proposes to distribute, to sources in each state covered under the proposed Transport Rule, a number of emissions allowances equal to the SO2, annual NOx, and ozone-season emissions budgets for that state, without variability, minus a three percent set-aside of allowances for new units. EPA would distribute four discrete types of emissions allowances for four separate cap and trade programs: SO2 group 1 allowances, SO2 group 2 allowances, NOx annual allowances, and NOx ozone season allowances. [EPA-HQ-OAR-2009-0491-2718.1, p.3]
EPA proposes that, for 2012, each existing unit in a given state receive allowances commensurate with the unit's emissions reflected in whichever total emissions amount is lower for the state, 2009 actual emissions or 2012 base case emissions projections. In either case, the allocation is adjusted downward, if the unit has additional pollution controls projected to be on-line by 2012. EPA proposes to use this same method to allocate allowances for each of the four trading programs (SO2 group 1, SO2 group 2, NOx annual, and NOx ozone season). [EPA-HQ-OAR-2009-0491-2718.1, p.3]
For states with lower SO, budgets in 2014 (SO2 group 1 states), each unit's allocation for 2014 and later would be determined in proportion to its share of the 2014 state budget, as projected by IPM. [EPA-HQ-OAR-2009-0491-2718.1, p.3]
EPA's proposed approach for allocating allowances under the Transport Rule is different than the NOx allowance allocation methodology adopted for existing units in CAIR, which was based on a unit's baseline heat input, adjusted for fuel type (with proportionately more allowances provided to unit's burning higher-emitting coal and proportionately fewer allowances allocated to units burning lower emitting oil and natural gas). In its July 2008 decision temporarily vacating CAIR, the D.C. Circuit Court determined the NOx allowance allocation methodology reflected in the rule to be arbitrary and capricious '[b]ecause the fuel adjustment factors shifted the burden of emission reductions solely in pursuit of equity among upwind states-an improper reason ... ' The court explained that EPA's [CAIR] rule essentially allocated more allowances to states having mostly coal-fired electric generating units because states that use more gas and oil can control emissions more cheaply. The court agreed with petitioners that fairness had nothing to do with the state's obligation to prohibit significant contributions to downwind nonattainment. [EPA-HQ-OAR-2009-0491-2718.1, p.3]
While EPA's proposed allowance allocation methodology in the Transport Rule does not rely on baseline heat input or fuel adjustment factors, NextEra Energy believes that the practical effect of the proposed methodology is very similar to the effect of the fuel-adjusted, heat input-based methodology rejected by the DC Circuit in the CAIR litigation because the methodology awards proportionately greater allowances to electric generating units (EGUs) burning inherently higher-emitting fuels (e.g., coal) and proportionately fewer allowances to EGUs burning inherently lower-emitting fuels (e.g., oil and natural gas). [EPA-HQ-OAR-2009-0491-2718.1, p.3]
Moreover, NextEra Energy believes that EPA's proposed allowance allocation methodology discriminates against companies that will have substantially reduced their emissions by 2012 by installing pollution control technologies, compared to companies that have done little or nothing to control their emissions in that timeframe, regardless of the fuel they burn. [EPA-HQ-OAR-2009-0491-2718.1, p.3]
While the proposed allowance allocation methodology in the Transport Rule mayor may not pass legal muster since it does not explicitly rely on fuel-adjusted heat input values, NextEra Energy strongly believes it is a poor public policy choice since it sends the wrong messages to companies contemplating taking early steps to reduce emissions from their electric generation fleet and will likely discourage such actions in the future. The proposed allowance allocation methodology rewards companies that have continued to burn higher emitting fuels and/or have not installed emission control technology (by 2012) with proportionately greater allowance allocations. Conversely, companies that have (1) installed new EGUs designed to burn cleaner fuels, (2) converted existing units to burn cleaner fuels and/or (3) taken steps to install advanced emission control technologies on their units would be allocated proportionately fewer allowance allocations. For example, under EPA's proposed allowance allocation methodology, a company that continued to operate an old, inefficient coal or oil/gas-fired steam unit would receive substantially greater SO2 and NOx allowances than a company that voluntarily repowered the unit with state-of-the art gas combined-cycle technology prior to 2012. Similarly, an existing coal-fired unit that installed advanced flue gas desulfurization equipment for SO, emissions control and selective catalytic oxidation for NOx emissions control prior to 2012 would receive substantially fewer SO2 and NOx allowances than the same unit that did nothing to control emissions prior to 2012. NextEra Energy believes that this sends the wrong messages to companies contemplating taking early steps to reduce emissions from their electric generation fleet and will discourage such actions in the future. NextEra Energy believes that basing allowance allocations on source emissions (future projected or historic emissions) is the worst approach for allocating allowances, from a public policy perspective, because it sends the wrong message to companies that want to do the right thing and violates the "polluter pays' principle. [EPA-HQ-OAR-2009-0491-2718.1, pp.3-4]
Proponents of EPA's proposed allowance allocation methodology are likely to use the argument that units with higher emission rates (e.g., coal versus natural gas, or uncontrolled coal units versus controlled coal units) need a proportionately greater share of allowances because they bear a greater cost burden to control emissions. This is exactly the same argument that EPA used in CAIR in support of the fuel-adjusted heat input NOx allowance allocation contained in the Model Rule that was determined to be illegal by the D.C. Circuit '[b]ecause the fuel-adjustment factors shifted the burden of emission reductions solely in pursuit of equity among upwind states-an improper reason ...' . As indicated above, this argument is not only flawed from a legal perspective but is misplaced from a public policy standpoint. What this argument is saying is that owners that continue to operate plants with higher emitting fuels and without emission controls are somehow entitled to a proportionately greater share of allowances (to help defray the costs they now face to comply with the Transport Rule) than companies that have already invested in clean energy technologies and pollution control technologies. In NextEra Energy's view, it is not in the public interest to reward companies that have done little or nothing to reduce their emissions prior to implementation of the rule in 2012 at the expense of companies like NextEra Energy that have taken early action to replace old, inefficient, high-emitting units with clean and efficient energy technologies such as natural gas combined-cycle units 01' to install emission control technologies. [EPA-HQ-OAR-2009-0491-2718.1, p.4]
EPA states in the preamble of the proposed Transport Rule that it believes that it is appropriate to allocate individual unit allowances consistent with the approach used in the development of the state budgets but acknowledges that there are many ways of linking unit allowance allocations directly to the way the state budgets were developed and, thus, significant contribution was defined. Aside from linking individual unit allowance allocations to the state budgets that EPA has established based on its analysis of significant contribution, then, (which EPA acknowledges can be accomplished with alternative allocation approaches) there is no apparent reason for EPA proposing that units receive allowances equal to the lower of 2009 actual emissions or 2012 projected emissions other than an equity rationale, something the DC Circuit found to be an 'improper reason' in North Carolina v. EPA. [EPA-HQ-OAR-2009-0491-2718.1, p.4]
As indicated above, NextEra Energy supports the derivation of state emission budgets based on analyses of significant contribution and the cost-effectiveness of emission reduction opportunities, as proposed in the rule. However', once these state emission budgets ate established, NextEra Energy recommends that all units within a state be treated as a single group and the state emission budgets be allocated to affected EGUs in 2012, 2014 and future re-calculations based on each source's proportional share of total baseline state generation output. NextEra Energy suggests that each unit's share of total state generation output should be determined on the basis of the average of each affected unit's annual generation output during the latest three calendar years of operation (e.g., 2007-2009). [EPA-HQ-OAR-2009-0491-2718.1, p.4]
The goal of output-based environmental regulations is to encourage the use of fuel conversion efficiency and clean energy as air pollution control measures. Output-based regulations can be an important tool for promoting an array of innovative energy technologies that will help achieve national environmental and energy goals by reducing fuel use. Output-based emission limits do not favor any particular technology and do not increase emissions. Output-based regulations simply level the playing field by establishing performance criteria and allowing energy efficiency and clean energy sources to compete on an equal footing with any other method of reducing emissions (e.g., combustion controls and add-on controls). [EPA-HQ-OAR-2009-0491-2718.1, p.5]
If EPA decides, for whatever reason, to reject the option of allocating allowances on the basis of generation output, NextEra Energy recommends that the Agency adopt a modified version of the alternative allowance allocation methodology discussed in the preamble of the proposed Transport Rule, which is to treat all units within a state as a single group and distribute allowances equal to a state's emissions budget, without variability, to each covered source in the state (in effect, distributing the responsibility for eliminating significant contribution and interference with maintenance) based on each source's proportional share of total state heat input. But rather than basing allocations on each units share of projected state heat input for the initial year of the program, NextEra Energy strongly recommends that the allocation be based on each unit's share of baseline state heat input. Baseline heat input would be determined based on the average of each affected unit's heat input during the latest three years of operation (e.g., 2007-2009). 1 [EPA-HQ-OAR-2009-0491-2718.1, p.5]
The IPM model is an excellent planning tool for analyzing the potential cost and energy impacts associated with various policy initiatives. However, NextEra Energy does not believe that this model was ever intended for, nor is capable of, providing projections that are anywhere near accurate enough (particularly for individual units) for basing something as important as allowance allocations on. Similar to other predictive models, IPM relies on a multitude of economic, energy-related and other assumptions that are subject to various degrees of uncertainty. The additive effect of this uncertainty is greater than the uncertainty associated with the individual assumptions. [EPA-HQ-OAR-2009-0491-2718.1, p.5]
Power plant owners, transmission system owners, and power system operators plan and operate their systems according to numerous federal, state and local regulations, policies and protocols, applying planning requirements designed to ensure electricity suppliers have adequate resources to meet current and future demand, and operational standards to ensure power is available when consumers turn on the lights. The IPM model appropriately determines how much a particular unit will operate in the future on an economic dispatch basis. However, the model does not consider a range of non-economic factors that influence a company's decision to operate a particular EGU such as grid stability considerations (e.g., voltage support), contractual generation commitments, reliability must-run requirements and fuel availability constraints. As a result, using the IPM model to project unit operations can create unrealistic scenarios such as running natural gas combined- cycle units at higher utilization than can be accommodated by the available natural gas pipeline network or not running oil-fired units that are required to operate to meet capacity requirements. These distortions of the electricity market may be masked when data are aggregated at the regional level or state level for setting state emission budgets, but can result in erroneous projections when used at the unit level to allocate allowances to individual units. Specific examples of these erroneous projections for a single electric generating fleet (NextEra Energy's) are presented in Appendix A of NextEra Energy's comments. [EPA-HQ-OAR-2009-0491-2718.1, p.5]
Not only docs basing allowance allocations based on IPM model projections raise potentially serious technical and policy issues, but NextEra Energy believes that this approach will subject the proposed Transport Rule to a much higher degree of risk from a legal perspective. NextEra Energy believes it is important for EPA to propose a rule that withstands, and preferably forestalls, litigation and that can be implemented as quickly and smoothly as practicable. We believe that using modeled projections as the basis for allocating allowances to affected EGUs has the potential for significant flaws that could cause the program to be deemed arbitrary and capricious. Accordingly, NextEra believes that the methodology for establishing allowance allocations should be based on actual (i.e., historic) data that has been verified by EPA. [EPA-HQ-OAR-2009-0491-2718.1, p.6]
As noted above, there are no legal or policy reasons that the methodology for determining state budgets and the methodology for distributing allowances to affected EGUs need to be the same. The historic generation output and heat-input allowance allocation approaches advocated by NextEra Energy are consistent with the D.C. Circuit's decision on CAIR because they do not alter the state budgets, which are based on each state's significant contribution. In addition. these allowance allocation approaches are fuel neutral and would not raise concerns similar to those identified by the D.C. Circuit regarding CAIR's use of fuel adjustment factors. The court rejected the fuel adjustment factors because they placed a disproportionate burden on downwind sources compared to the upwind sources contributing to the nonattainment problems. In NextEra Energy's view, adoption of a historic generation output- or heat input-based allowance allocation approach would provide greater insulation for the rule against litigation that could threaten implementation of the rule beginning January 1, 2012. [EPA-HQ-OAR-2009-0491-2718.1, p.6]
An historic generation output- or heat-input-based allowance allocation methodology would also address NextEra Energy's public policy concerns with EPA's preferred approach. Most significantly, it would not be based on modeled future emissions with its known inaccuracies but, rather, on verified data EPA already has obtained from companies. Additionally, it would correct the proposed methodology's disadvantages for early actors that EPA acknowledges in the preamble to the proposed rule. It would put all EGUs on equal footing and take the timing aspect of when emission reductions are achieved (i.e., prior to or after 2012) out of the allowance allocation equation. [EPA-HQ-OAR-2009-0491-2718.1, p.6]
EPA should establish a small auction under EPA's preferred limited trading option
Under EPA's preferred, limited trading option, NextEra Energy recommends that EPA establish a small auction of allowances that is similar in size to the proposed new unit set aside of three percent. Similar to the small auction in the Acid Rain Program, the auction would help for price discovery and liquidity purposes. Although NextEra Energy believes that market manipulation would be a greater risk under EPJ\'s proposed Alternative 1 (intra-state trading only), we are also concerned that limited trading under the preferred option could result in market manipulation in isolated areas. [EPA-HQ-OAR-2009-0491-0298.1 p.11]
EPA should use freed up allowances from retired units to increase the auction pool over time
NextEra Energy supports EPA's proposal to continue to allocate allowances to retired units for six years after ceasing operations. The six-year period ensures that companies make the retirement decisions independent of any allocation and allowance value, However, rather than placing these allowances in the new unit pool or redistributing these allowances at the end of the six-year period, NextEra Energy recommends that EPA use these allowances to increase the auction pool recommended above over time. [EPA-HQ-OAR-2009-0491-0298.1 p.11]

1. While NextEra Energy could support EPA adoption of an historic heat-input based allowance allocation methodology for SO2 and NOx in the Transport Rule, this docs not mean or imply that the Company could support such a methodology in future air quality control programs. For example, if CO2 emissions from EGUs arc regulated in the future under a market-based cap-and-trade program, it would be important to design the program to incentivize the adoption of energy efficiency measures as a cost-effective control option. A heat-input based allowance allocation approach does not provide the proper incentives to encourage the adoption of energy efficiency measures. Therefore, in this case, NextEra Energy would strongly support a generation output-based allowance allocation methodology. [EPA-HQ-OAR-2009-0491-2718.1, p.5]
Northeast States for Coordinated Air Use Management (NESCAUM)
The Transport Rule does not guarantee that the actual SO2 emissions from Portland will be reduced since there is the option to purchase allowances to cover the Portland Plant's emissions. Therefore, it is necessary to implement performance standards similar to those adopted by New Jersey (and approved by USEPA)i to fully address air pollution from electric generating units.  [EPA-HQ-OAR-2009-0491-2684.1 p.2]
We have concerns about the methodology used to develop the proposed remedy. It has been very difficult to ascertain the specific methodology employed. EPA has relied upon a proprietary model, the Integrated Planning Model (IPM), in developing its remedy. Notwithstanding our careful scrutiny, it has been extremely difficult for states to examine the underlying assumptions and processes used, and replicate EPA's budgets. If EPA chooses to continue using this model, it should purchase it and place it in the public domain, so that all data and cost algorithms used can be reviewed. As public agencies that must implement this program, we need more transparency and access. Moreover, the high cost of running IPM hinders our ability to conduct our own comparative analyses.
Without detailed explanation from EPA, we are not able determine which data sets were used to set the budgets for each state. State budgets were apparently established using different data sets (i.e., using either data from IPM or historical data, whichever were lower). This is troubling to us for several reasons. First, such an approach does not result in an equitable distribution of the allowance budgets from state to state. Second, the quality of the data used by EPA to set budgets may not accurately reflect the current and planned/committed controls on existing units. Third, it appears that the results allow existing uncontrolled units to be allocated more allowances than existing controlled units, thus discouraging uncontrolled units from installing controls. We recommend that EPA employ a methodology that relies on the same data set for all state budgets, and establish a single, quality-assured data set for this purpose. Furthermore, states should be allowed an opportunity to review and comment on the accuracy of that data set.
While EPA's use of this model is appropriate in some analytical situations, we have serious concerns with the manner in which IPM has been employed in this regulatory context (i.e., to set state budgets and allocations). Over the years, we have repeatedly observed IPM predictions that do not reflect real world conditions because transmission constraints and reliability rules for our region are not always fully reflected in the model. The IPM future case scenarios run by EPA often do not accurately reflect operations of the electrical generation system in the Northeast. For example, IPM future case outputs predict the economic shutdown of many New York City oil/gas steam generators, even though these units are required to run due to transmission constraints and local reliability rules, and are not scheduled to be replaced. It appears that certain assumptions built into the IPM analysis are contributing to an SO2 allowance allocation bias. Due to such issues, IPM is therefore not our preferred model for use in establishing state budgets and allocations. We urge EPA to use methodologies for this and future transport rules that are can be verified by the public and have the requisite resolution to more accurately predict operations of the electrical generating sector. Furthermore, when setting budgets, EPA should more closely review recent trends in the capacity factors and dispatch trends of regional transmission organizations for certain plant types, particularly oil/gas steam units and gas/oil combined cycle units.
The Northeast states, along with states in other regions, are seriously considering moving away from using IPM in future regional SIP modeling. We have been working with the Eastern Regional Technical Advisory Committee (ERTAC) on alternative modeling, which will be available for review in late Spring 2011 We urge EPA to examine this approach, participate in the ERTAC process, and consider its merits for use in future transport rules. [EPA-HQ-OAR-2009-0491-2694.1, pp.5-6]
NESCAUM states recommend that EPA use the most recent three-year average of unit specific data to establish the input/output rates for calculating NOx allocations for each unit, multiplied by the unit specific NOx emission rate, and then sum the resultant allocations for all units in a state to determine the amount of NOx allowances to be allocated to that state. The same procedure could also be used with unit-specific SO2 emission rates to determine the amount of SO2 allowances to be allocated to each state.
It should be noted that, under the proposed rule, most of the Northeast states have allocated budgets well below those of upwind states. Moreover, our cost of compliance appears to be far greater than the $500 cost per ton threshold that EPA appears to be using. This is not equitable. EPA must explain why the costs for reducing emissions are set higher in the Northeast. In addition, the location of emissions matters. Sources located near downwind borders contribute to out-of-state transport more than sources located farther from the border. The proposed rule does not guarantee that emissions from a specific source located in an upwind area that has a significant impact on a downwind area will be adequately controlled. These dynamics should be considered in how allowances are allowed to be distributed within a state, and EPA should ensure mechanisms are in place to address such emissions (e.g., employ performance standards as appropriate and/or allow states to allocate/control allowances).
Moreover, in order to achieve maximum public health protection, this allowance program should not link to past allowance programs. Neither the NOx SIP Call nor CAIR allowances should be allowed to be used in this program. We assume that Title IV Acid Rain SO2 allowances are precluded from use in this program, as per the court decision in North Carolina v. EPA. [EPA-HQ-OAR-2009-0491-2694.1 pp.7-8]
Northern Indiana Public Service Company (NIPSCO)
NIPSCO has concerns about the approach that EPA is using to determine an allocation of emission allowances derived from the state budgets and provided to individual units. First, NIPSCO believes the allocation methodology is a task that the individual states, in NIPSCO's case Indiana, would be in a much better position to fulfill. The individual states are more familiar with the sources within their state and, with input provided from the sources, could work to develop a much fairer and more equitable allowance allocation method more reflective of the needs of the state. States should weigh in on any unit-specific allocations to sources within their state.  [EPA-HQ-OAR-2009-0491-2747.1 p.3]
NIPSCO does not agree with the use of projected emissions for Indiana units as a basis for allocating allowances to individual units. NIPSCO finds a number of issues with the allowance allocation program as proposed in the Transport Rule. The proposed method appears to base unit allocations for 2012 on a methodology that attempts to match emission allowance allocations with the actual historical or IPM projected emissions for individual units. EPA's allocation methodology leads to a requirement for an owner to operate already installed or planned pollution control technologies at or beyond the maximum emission control rates capable of being achieved on a long-term basis. However, this approach allows other units without controls to be allocated enough emission allowances to comply without any significant additional reductions. With this approach, EPA penalizes companies that have made the capital investments needed to control emissions on units by providing fewer allowances to these companies while rewarding companies that are not controlling emissions by supplying additional allowances. Emission allowance allocation methodologies should not reward inaction on installation of emission control measures by sources nor should the allocation methodology disadvantage those companies or facilities that have decided to install emission controls to meet their emission reduction obligation. Further, the IPM model input needs simplifying assumptions in order to limit the number of choices for the application of emission controls and capability of those emission controls. While using assumptions such as these may be acceptable in IPM modeling in an attempt to characterize overall emission reductions across the entire United States, it is not a good method to predict with great accuracy applications of emission controls and resulting emissions for individual units. NIPSCO will later offer a recommendation on a different approach and also provide some unit-specific examples of the problems mentioned above. [EPA-HQ-OAR-2009-0491-2747.1 p.4]
Nevertheless, EPA, with use of the IPM model to allocate emission allowances, presumes an unreasonable level of emission control. This problem is further exacerbated when applied to an emission baseline that may be low in the first place. This results in applying removal efficiencies and final nitrogen oxide ('NOx') rates for Units on the NIPSCO system that have not been achieved in practice. The predictions are unrealistic and unachievable. The outcome is an unreasonably small number of NOx allowance allocations for units that already have installed and are operating stateof- the-art pollution controls. [EPA-HQ-OAR-2009-0491-2747.1 p.4]
Northern Star Generation LLC
Rather than re-state the comments provided by ARIPPA, Northern Star would like to focus our comments on one particular aspect of the proposed rulemaking, the allocation of NOx and S02 allowances at the unit level. EPA has apparently chosen to apply an economic model to predict the future dispatch of power plant units affected by this proposed rule and has used this prediction to allocate allowances. We strongly disagree with this approach for both philosophical and technical reasons. [EPA-HQ-OAR-2009-0491-2814.1, p.1]
EPA has successfully utilized cap and trade programs for air pollution control programs (e.g., Title IV Acid Rain, NOx Budget Program). The benefits of cap and trade have been touted by EPA in the past as providing for more a cost effective and flexible means of reducing emissions as compared to 'command and control' types of regulations. In other words, cap and trade allows the market and market participants to identify the lowest cost means of compliance. Emission allowances have been allocated in proportion to historic usage of units (i.e., heat input) and market participants have made economic decisions to either control (or even over-control emissions) versus the purchase and use of emission allowances. [EPA-HQ-OAR-2009-0491-2814.1, p.1]
In the proposed regulations, EPA has apparently decided to deviate from past allowance allocation practices and instead pick 'winners' and 'losers' by deciding how much each emission unit should operate in the future. Given the very strict S02 cap that will be in place by 2014 and the restrictions on interstate trading in many states, it is quite possible that S02 allowances will simply not be available at any price. Northern Star's CFB waste coal plants already have extensive emission controls for S02 and have few if any economic opportunities for further emission reductions. EPA has projected in its modeling that orthern Star's waste coal plants will experience significant reductions in operations post 2012 and has allocated S02 allowances on that basis. This may well prove to be a self-fulfilling prophecy if the S02 allowance market is not sufficiently liquid to allow purchase of allowances at any price. [EPA-HQ-OAR-2009-0491-2814.1, pp.1-2]
In the allocation of NOx allowances EPA's approach under the proposed rule will produce absurd results. As outlined in the ARIPPA comment letter, the allocation of NOx allowances in Pennsylvania greatly favors the highest emitting NOx sources. Low emitting NOx sources such as Northern Star's waste coal plants would receive considerably fewer NOx emission allowances under the Transport Rule than they would under the CAIR rule, even though the Pennsylvania cap under the Transport Rule is larger than the cap under CAIR. Several utility coal plants in Pennsylvania, with emission factors more than 5 times larger than our waste coal plants, would receive considerably more allowances under this rule than under the existing CAIR program. In fact, some of these plants would receive considerably more allowances than their historic emissions of NOx. The proposed EPA allowance allocation would produce a situation in which low-emitting sources would be forced to either try to reduce their emissions even further at great cost or purchase allowances from the windfall amounts awarded to high emitting sources. This makes absolutely no sense, particularly since the higher emitting sources have much greater potential for cost effective controls. [EPA-HQ-OAR-2009-0491-2814.1, p.2]
As a result of these considerations, Northern Star strongly recommends that EPA adopt the previously utilized method of unit allowance allocation; that is, by historic unit heat input. We also recommend that in order to avoid awarding windfall amounts of allowances to any source, that the allocations for both S02 and NOx be no more than the historic actual emissions of those pollutants over the past five years. [EPA-HQ-OAR-2009-0491-2814.1, p.2]
Even with the correction of inaccurate assumptions in the model, Northern Star has little confidence in the ability of EPA's model to accurately simulate power plant dispatch. It is highly unlikely that EPA has or will take into account unique factors that could affect dispatch beyond the calculation of demand and the cost of producing power based on fuel costs. One factor that can dramatically change a unit's dispatch profile is the presence of a contractual agreement, such as a power purchase agreement, that obligates the unit to run. Another major factor that is not incorporated in EPA's model, but could strongly affect the amount of dispatch, is the level of debt service present on individual units. Based on these technical considerations as well as the factors mentioned earlier in this letter, we strongly urge EPA to abandon this attempt to predict future events and return to the practice of allowance allocation by historic heat input. [EPA-HQ-OAR-2009-0491-2814.1, p.3]
Oglethorpe Power
Instead of making permanent allocations based on unrealistic models and abbreviated historical operations, EPA should follow more closely its approach taken in the final CAIR NOx allocation program, where allocations to all existing units were based on the average of the three highest amounts of the unit's control period heat input over a historical five year period, so as to even out the inevitable 'peaks and valleys' in individual unit (or source or utility system) operations. An approach (like that taken in CAIR) which constantly updates allowance allocations, by basing the calculation on a rolling five year lookback of operational history, appears to be much more equitable and fair to all EGUs and EGU owners/operators. It has the desirable effect of smoothing out short-term variations at the unit level, ensuring that any short-term inequity created by a specific unit's fact pattern (like a substantial outage in the baseline period) is rectified over the long term, through this continuous check or 'true-up' using the recent operational history of the covered unit. As long as state budgets remain the same, a core precept of the Transport Rule, then the CAA tests of §110(a)(2)(D) would still be met, i.e., the substantial contribution and interference with maintenance tests will be satisfied. EPA attempts to justify its approach on the basis that permanent allocations are needed to develop the allowance trading market. An approach where allowances are periodically being reallocated in the near future will not, however, unduly influence any market for allowances (and was, in fact the approach used in CAIR, where EPA must have concluded that this type of approach would not unduly chill allowance markets). Should the proposed remedy option be implemented, trading will be much more constrained by EPA's proposed variability provisions, than by an approach that periodically reallocates allowances. The justification also rings hollow when one considers that EPA will not, as was done in the Acid Rain Program, be distributing a 30-year stream of allowances to covered units at the commencement of the program, but instead will be distributing only an initial 3-year stream, followed by subsequent yearly allocations tor that control period 3 years out. Units in the Transport Rule as proposed, therefore, will never have more than 3 veal's worth of allowances on hand - virtually the same as in CAIR - with which to make a market. Periodic reallocations can be structured to maintain a similar stream of allowances for Transport Rule units, which is more equitable than the one-time, 'pot-luck' method proposed as the basis for making unit allocations in the current rule. [EPA-HQ-OAR-2009-0491-2732.1, p.8]
This approach would also resolve more fairly the issue of retired units - those that become nonoperational. Once the Transport Rule allocation programs begin. an approach that recalculates the upcoming stream of allocations periodically will automatically 'phase-out' units that reduce or cease operations over time. There will be no need to 'grandfather' such units in the allocation system for any length of time, as their actual operations in the recent past will dictate whether they continue to receive any allowances. If new units can become existing units over time again the approach taken in the CAIR - then those allowances realized from the shutdown (or reduced operation) of a unit will simply flow back into the state budgets over time, to be reallocated to units that continue to operate in the ensuing control periods. [EPA-HQ-OAR-2009-0491-2732.1, pp.8-9]
V. New Source Set-Asides
EPA seeks comment on the approach used in the rule f()r new source set-asides. Again. Oglethorpe Power believes that the Agency should follow the approach used in the CAIR NOx program, where new units would become existing units over time and thus gain access to the allocations made from the state budgets. EPA should also address the situation where a new unit comes on line late in the first year. No allocation will be made for that first year's operations, and any distribution tram the new source set-aside for the next control period (the next year) will also be severely depressed, due to limited operations that began so late in the initial year. EPA should consider an approach that allows for a reasonable projection of emissions for these first two control periods to ease the burden that will fall on new sources, especially those that begin operations late in a calendar year. [EPA-HQ-OAR-2009-0491-2732.1, pp.10-11]
VIII. Preferred Option
Oglethorpe Power supports the ability of sources to use banked allowances for compliance with the Transport Rule. EPA properly recognizes the important environmental and economic benefits of allowance banking, which was an aspect of CAIR that went unchallenged in that rule's subsequent litigation. The ability of sources to use banked allowances for compliance with the Rule program encourages early emission reductions. [EPA-HQ-OAR-2009-0491-2732.1, p.13]
Oglethorpe Power also supports EPA's proposal not to include auctions of allowances under its proposed remedy option. No environmental need or other valid reason exists to use allowance auctions to implement the emission reduction requirements in the Transport Rule. Moreover, Oglethorpe Power does not support the use of auctions in any other alternative control program EPA might adopt to implement the Transport Rule. Government auctioning of allowances which will provide no environmental benefit - is contrary to the principle that regulated sources are not subject to any obligation to emit below their allowance allocation levels established by an emissions control cap-and-trade program. [EPA-HQ-OAR-2009-0491-2732.1, p.13]
Oklahoma Department of Environmental Quality
First, EPA has not provided sufficient time for the States to fully review and understand the allocation method and the modeling on which the allocations are based. Ideally, EPA should have provided at least three months for each year that EPA conducted modeling. The IPM modeling method is quite complex, and sixty days was not enough time to review and provide considered and detailed comments. [EPA-HQ-OAR-2009-0491-2662.1, p. 1]
Piney Creek LP
B. EPA does not propose through the Proposed Rule to establish allowance allocations based upon heat input, but rather projected emission rates.
The Proposed Rule's reliance on fuel cost as the primary basis for projecting future generating rates fails to adequately account for numerous other factors affecting generating rates. For example, in Pennsylvania, electricity distribution facilities and suppliers are required to supply a certain percentage of energy from Tier I or Tier II renewable energy sources, irrespective of electricity prices. Therefore, distribution of the generation of electricity will not strictly adhere to lowest cost of generation, as other operative criteria dictate distribution. Because waste coal-generated electricity qualifies as a renewable energy source, waste coal-fired sources such as Piney Creek will operate at a higher generating rate than cost alone would suggest. [EPA-HQ-OAR-2009-0491-2849.1 p.2] [EPA-HQ-OAR-2009-0491-3809.1_NODA, p.2]
Piney Creek recommends that allowance allocations be determined based on previously established heat input rates, as reflected in historical data reported by each source. This approach would be consistent with the objectives of the Clean Air Act, as well as the directives of the Court in North Carolina, by ensuring that the Transport Rule targets emission reductions from those sources most likely contributing significantly to downwind nonattainment, rather than lower emitting units projected by EPA (based on limited criteria) to reduce rates of generation. [EPA-HQ-OAR-2009-0491-2849.1 p.2] [EPA-HQ-OAR-2009-0491-3809.1_NODA, p.2]
C. EPA inaccurately predicts that the emission control options identified for traditional EGUs under the Proposed Rule would likewise apply to the CFB sources such as Piney Creek.
CFB technology is fundamentally different from traditional EGUs in ways that distinguish Piney Creek from other EGUs. CFB technology is inherently cleaner-burning and, therefore, more environmentally friendly, than traditional coal combustion technology. Characteristically, for CFB units, emission controls are primarily achieved in the combustion zone, not through back-end control equipment. Specifically, the introduction of limestone into the circulating fluidized bed allows for the absorption of SO2 and significant reductions in SO2 emissions. With respect to NOx, strict management of combustion zone characteristics limit the formation of NOx. In both cases, the CFB technology emits substantially lower SO2 and NOx emissions  -  per ton of fuel, per MMBtu/hr of heat input and per MW/hr energy output  -  than conventional coal-fired EGUs. [EPA-HQ-OAR-2009-0491-2849.1 p.2] [EPA-HQ-OAR-2009-0491-3809.1_NODA, pp.2-3]
Moreover, because emission controls are achieved through careful management of the combustion zone, CFB operators must maintain careful control over combustion zone characteristics in order to prevent a shift in concentration of other pollutants. For example, to the extent a CFB operator increases limestone addition rates to attempt to achieve further SO2 emission reductions, such adjustments can affect characteristics in the combustion zone in a way that influences NOx formation, as well as particulate and carbon monoxide emission rates. Further, these control techniques face asymptotic limitations in effectiveness. At a critical point, the facility must add significantly greater quantities of limestone to achieve modest incremental reductions in SO2 emissions; for the reasons discussed above, such increases would also likely increase NOx and particulate emissions. Moreover, for certain CFB plants such as Piney Creek, it is not even possible to add sufficient quantities of limestone to achieve the SO2 emission reduction requirements in the Proposed Rule, due to design characteristics, heat transfer limits, and permit restrictions. [EPA-HQ-OAR-2009-0491-2849.1 p.3] [EPA-HQ-OAR-2009-0491-3809.1_NODA, p.3]
Similarly, attempts to maximize NOx emission reductions without regard to other combustion chemistry will result in increases in CO emissions, and perhaps other constituents. Further, the ability Piney Creek to reduce NOx emissions is directly limited by permitting requirements restricting ammonia slip. [EPA-HQ-OAR-2009-0491-2849.1 p.3] [EPA-HQ-OAR-2009-0491-3809.1_NODA, p.3]
Piney Creek LP feels the EPA's stated basis for determining unit-specific allowance allocations under the Proposed Rule is inappropriate and inequitable as applied to Piney Creek and other CFB plants. Also, emission control technologies considered by EPA for application to EGUs under the Proposed Rule do not readily extend to Piney Creek's CFB technology, in the same manner and extent as applied to traditional coal-fired units. [EPA-HQ-OAR-2009-0491-2849.1 p.3] [EPA-HQ-OAR-2009-0491-3809.1_NODA, p.3]
Potomac Power Resources
First, it seems the methodology proposed for emissions allocations does not work for a facility like Benning Road, which operates under peaking conditions. The methodology indicates it uses the last four quarters of data as a basis to calculate allocations. If a quarter does not have emissions data (does not operate), then how does the algorithm make adjustments for the allocations? Specific to your matrix, Unit ID 15 data reflects this discrepancy. The algorithm is using a quarter with missing data (no data since the unit did not operate) and thus seems to give incorrect allocations for NOX and SO2. (Annual NOx Mass, tons (most recent 4 Qs), Annual SO2 Mass, tons (most recent 4 Qs), Annual Heat Input, mmBtu (most recent 4 Qs) for Unit ID 15 are all blank). The methodology should therefore indicate it will use the last four quarters with operating data and not just the most recent four quarters to calculate allocations. [EPA-HQ-OAR-2009-0491-3017, p.1]
PowerSouth Energy Cooperative
The Proposal's allowance allocation methodology is unfair and punitive to PowerSouth and other utilities that made significant capital improvements to comply with CAIR and should be abandoned.  PowerSouth responded to CAIR by undertaking a multi-pollutant assessment, which included a myriad of control options, including the purchase of allowances.  PowerSouth's decision to retrofit the Lowman Plant in 2007 with an additional SO2 scrubber to allow 100% scrubbing of all three units and selective catalytic reduction (SCR) equipment for NOx emission reductions on two units in 2007 and 2008 at a cost of $300 million was based solely on compliance with CAIR and the economics of creating excess allowances to offset capital expenditures.  Allowance allocations to the Lowman Plant assigned in the Proposal  invalidate the rationale that led to the retrofits by only allocating enough allowances to meet compliance obligations at the manufacturer's guarantee level with no margin.  In fact, it will be very difficult to operate the control equipment continuously at the SO2 and NOx removal rates contemplated by the Proposal.  The cost of the capital project is not recoverable, PowerSouth has lost the opportunity to evaluate strategy based on true compliance options, and our flagship power plant is burdened with additional operational and cost constraints.   EPA should not now punish PowerSouth for investing capital to comply with CAIR.  [EPA-HQ-OAR-2009-0491-2693.1,p.3]
The Proposal as written penalizes early movers and encourages utilities to resist and delay investing capital in environmental improvements.  The drastic changes in the compliance "playing field" from CAIR to the Proposal teaches regulated entities to be recalcitrant and rewards utilities for not making capital investment to comply with EPA's rules.  The Proposal's allowance allocations and regulatory schemes incentivize regulated parties to resist capital improvements that benefit the environment and delay decisions as long as possible to see if regulatory conditions change.  The Proposal should be modified to recognize and reward regulated entities that have retrofitted units in a good faith effort to comply with CAIR, or, at the very least, not punish them.  [EPA-HQ-OAR-2009-0491-2693.1,pp.3-4]
Similarly situated facilities are disparately treated under the Proposal.  A look at various coal-fired units and their relative compliance position for SO2 in the Proposal illustrates how taking no action is the best compliance option to environmental regulations.   Those units, who chose to "do nothing" under CAIR are in many cases in a much better position than utilities like PowerSouth who invested capital dollars in expensive control equipment.  For instance, coal-fired units in Mississippi within one hundred miles of our Alabama plant chose not to make any capital improvements in response to CAIR and now are entirely omitted from SO2 compliance requirements under the current Proposal.   Arbitrary state lines should not be the determining factor in setting compliance requirements. [EPA-HQ-OAR-2009-0491-2693.1,p.4]
The Proposal's allowance methodology is unconscionable in that EPA rewards plants for being "dirty."   Units with no SO2 controls have been assigned allowances equivalent to their un-scrubbed emission rates in the Proposal.  In fact, some units in Alabama were assigned equivalent SO2 emission rates over 2.50 lb/MMBTU in the Proposal (for example, Alabama Power Company's Gorgas and Gaston units).  PowerSouth's Lowman Unit 1 flue gas can be directed through an uncontrolled by-pass yielding an emission rate of over 3 lb/MMBTU per hour.  In 2008-2009, the period EPA chose to use as the basis for allocations under the Proposal without our knowledge or input, PowerSouth was voluntarily directing flue gas from Unit 1 through a new scrubber for a portion of the period and therefore was assigned an equivalent SO2 emission rate of 0.478 lb/MMBTU.  Based on EPA's methodology, PowerSouth should not have built and operated the scrubbers or should have bypassed the scrubber on Unit 1.  PowerSouth emitting more would have resulted in a much more favorable compliance picture under the current Proposal.  PowerSouth is being penalized for voluntarily controlling its emissions.  It is unfathomable that utilities that responded proactively to EPA rules and installed and operated control equipment are disadvantaged and mistreated this way.  The Proposal's allocation methodology is not equitable, preferable, nor defensible. [EPA-HQ-OAR-2009-0491-2693.1,p.4]
Using the equipment manufacturer's emissions removal rates without regard to ambient conditions, fuel parameters, and the plant's operating mode (startup, shutdown, load change, upset, etc.) is unrealistic.  Controlled emission rates assumed in IPM modeling and the resulting state budgets and unit-level allocations need to include realistic estimates for control device performance.  EPA's emission rate assumptions for units with existing FGD or SCR control are based on removal rates that are equivalent to continuous operation at manufacturer's guaranteed removal rates.  This tact is unfair and punitive as noted previously.  Further, it is unrealistic.  No pollution control device can be operated continuously to such low levels.  Such guarantees are typically established for specific operating conditions (such as steady state load conditions) or are specified for certain ambient conditions or specific fuel parameters.  In actual operating practice, units typically experience a range of load points, ambient conditions change dramatically from season to season, and coal sources change over time.  PowerSouth has been operating FGDs at Lowman since 1979 and knows from experience that this equipment will malfunction during the course of normal operation despite a utility's best efforts.  PowerSouth's recent experience with forced outages due to air heater plugging problems after installation of SCRs further illustrates that guarantee levels should not be used to model expected emissions or set allocations.  EPA should recognize that operating conditions on air quality control equipment will necessitate certain understandings about reasonable ranges of operation and adjust the Proposal accordingly.  [EPA-HQ-OAR-2009-0491-2693.1,pp.4-5]
The Proposal arbitrarily "cherry picks" data to allocate emissions.   There is no rational basis for assigning emission rates based solely on four quarters of data.  Further, the methodology used in the Proposal to determine which four quarters to use is not adequately explained and documented.  Adding or deleting a single quarter to the data set can change the resulting emission rate dramatically.  PowerSouth's review of the SO2 allocations to the Lowman Plant illustrates that the methodology used is arbitrary, unfair, and results in highly variable emission rates.  The Proposal as written indicates that for all three Lowman units, 3Q2009, 2Q2009, 1Q2009, and 4Q2008 should have been used.  Instead, EPA used what appears to be a "cherry picking" method, resulting in lower assigned SO2 allowance allocations.  For example, compare PowerSouth's equivalent SO2 emission rates from the EPA database.  In the Proposal, Unit 1 calculations are based on data from 1Q2009, 4Q2008, 3Q2008, and 2Q2008, passing over two more recent valid operating quarters.  Similarly, Lowman Unit 2 was assigned an equivalent SO2 emission rate in the Proposal based on data from 1Q2009, 4Q2008, 3Q2008, and 2Q2008, again passing over two quarters of more recent data.  The resulting equivalent emission rates are dramatically different as shown in the table below.  The method appears to have been applied, as written in the Proposal, to Unit 3.  Interestingly, if the same four quarters of data had been applied to Unit 3 as were applied to the other two Lowman units, the equivalent SO2 emission rate for Unit 3 would have been 0.321 lb/MMBTU!  [EPA-HQ-OAR-2009-0491-2693.1,p.5]
Allocations should be based on heat input and fuel type irrespective of controls currently in place.  An alternative method of allowance allocation should be developed that is not based on the controls currently installed.  A reasonable method for allocating allowances is one based on heat input and fuel type.   Distinction based on fuel type would avoid assigning too many SO2 allowances to gas-fired units. [EPA-HQ-OAR-2009-0491-2693.1, p.6]  
PPL Corporation
A major concern of PPL is EPA's proposed, preferred approach for allocating allowances to individual generating units within each state. The approach assigns unit-specific allocations that are closely tied to unit-specific emission rates that EPA's Integrated Planning Model (IPM) forecasts are attainable in 2012 (nitrogen oxides and sulfur dioxide) and 2014 (sulfur dioxide in Group I states) at threshold control costs. This is an unfair approach because it allocates more allowances to units that have not invested in controls or that IPM projects will not attain emission rates as low as those of cleaner units. This is not only inequitable but also is inconsistent with a market-based approach that is intended to encourage dispatch of cleaner units by requiring dirtier units to purchase allowances to offset their higher emissions levels. [EPA-HQ-OAR-2009-0491-2739.1, p.1]
1. EPA's Approach for Allocating Allowances to Individual Units Within a State
Under the proposed rule, the 2012 NOx state budgets were created based on EGU emission reductions that EPA believes could be achieved for $500/ton or less and the 2014 SO2 state budgets for Group I states were created based on EGU emissions reductions that EPA believes could be achieved for $2000/ton or less. The 2012  SO2 state budgets were created based on increased operation of existing (or planned) FGD systems and/or the use of lower sulfur coal. Under EPA's proposed approach, individual units are allocated allowances the same way. That is, based on future unit-specific projections of their emissions. This results in higher emitting units receiving more allowances than lower emitting units. [EPA-HQ-OAR-2009-0491-2739.1, p.2]
PPL believes that this is not a fair way to allocate allowances to individual units. PPL invested $1.3 billion on control technologies at its units on the understanding that it could then sell allowances to those that did not, thereby spreading the control costs to EGUs that chose not to install controls. This is the fundamental reason to have a cap-and-trade program rather than a command-and-control approach. EPA's proposal turns this on its head, taking effectively a command-and-control approach under which no unit can have any allowances to sell because those units that have control technologies will be allocated fewer allowances. This effectively penalizes owners of units that have already invested in pollution control equipment and rewards those who have not made the investment. [EPA-HQ-OAR-2009-0491-2739.1, p.2]
An additional inequity that PPL observes in the allocation of each unit's portion of the state budget is that, for both the 2012 and 2014 budgets, coal-fired units are not allocated allowances at the same assumed emission rates, even though in many cases they are projected to have the same control technology installed. [EPA-HQ-OAR-2009-0491-2739.1, p.2]
PPL believes that the only rational and equitable way to allocate allowances to individual units is that all units should receive allowances based on the same assumed emission rate per million Btu heat input. This treats all units the same and does not reward those who have not invested in control technologies and does not arbitrarily award fewer allowances to some units than to others. Changes in utilization of units should be accounted for by reallocating allowances based on the past three years of utilization as was done under the NOx SIP call, rather than by using the IPM model that is clearly not robust enough for this purpose. [EPA-HQ-OAR-2009-0491-2739.1, p.3]
Fewer Allocations in 2012 for Units With Controls
The table provided at the end of these comments lists the emission rates that are assumed for individual bituminous coal-fired EGUs over 75 MW in Pennsylvania's 2012 and 2014 annual  SO2 budgets. This table demonstrates PPL's concern. It shows that units with FGD systems installed by 2012 are penalized with fewer allocated allowances than units that will not have FGD systems. [[EPA-HQ-OAR-2009-0491-2739.1, p.3] [See page 11 of this comment for the table.]]
The table shows that Pennsylvania units in 2012 without FGD systems would be allocated allowances based on emission rates of over 2 lb/MMBtu, whereas the units for which the owners have invested in and operate FGD systems would receive allowances based on dramatically lower emission rates. In the case of the Montour and Brunner Island units owned and operated by PPL, as a result of an investment of $1.3 billion to install and start operating the FGD systems in 2008 and 2009, PPL would receive allowances based on an emission rate of only 0.123 lb/MMBtu. It is not clear to PPL that such an emission rate would even be achievable on a sustained basis. Emissions from those units are currently at about 0.45 lb/MMBtu. With allowances based on an emission rate of 0.123 lb/MMBtu, PPL (the one who invested in emissions controls) may be put in the position of having to buy allowances from others who did not -- with the likely prospect that none will be available. [EPA-HQ-OAR-2009-0491-2739.1, p.3]
Differing Emission Rates For Units With the Same Controls
For 2014, when apparently all units over 150 MW in Pennsylvania are assumed to have FGD systems, the emission rate varies between 0.105 lb/MMBtu and 0.301 lb/MMBtu. This is unreasonable and inequitable. This is analogous to the use of fuel factors under CAIR that provided coal-fired units with a larger allocations than gas-fired units. This approach was expressly disapproved by the D.C. Circuit Court of Appeals. Allocations should be fairly distributed to all units and if some units operate 'dirtier' than others, then they should be required to obtain additional allowances at costs to which the market would adjust and give preference to the operation of the 'cleaner' units. PPL believes that this is a basic concept that the Transport Rule should encourage. It is a fundamental principle of the Acid Rain Program and the NOx SIP Call. [EPA-HQ-OAR-2009-0491-2739.1, p.3]
4. Allocations for Shutdown Units
The Transport Rule specifies that units in the program that do not operate for three consecutive years would no longer receive an allocation. And it specifies that starting the seventh year after the first year of non-operation that their allocation be transferred to the state's set-aside pool for new units. PPL does not understand why there would be such a long delay and recommends that the allocation be transferred immediately after the third consecutive non-operating year. Additionally, PPL does not believe that all of the shutdown allowances should be transferred to the new unit set-aside pool. The generation no longer supplied by shutdown units would be supplied by both new units and existing units that would operate more frequently. PPL therefore recommends that the allocation to units that shutdown be divided between new and existing units - with 50 percent going to the new unit set-aside program and 50 percent divided among the existing units in the program based on proportional heat input. [EPA-HQ-OAR-2009-0491-2739.1, p.8]
5. Future Allocations
PPL believes that unit allocations should be periodically adjusted based on recent operation rather than assigned forever at the start of the program. It makes sense to base the distribution of allocations for the year on current rather than past conditions. Allowances to individual units under the NOx SIP Call were adjusted based on three-year average actual heat input. PPL believes that this is a reasonable approach and far superior to the approach proposed in the Transport Rule that would not make such periodic adjustments. [EPA-HQ-OAR-2009-0491-2739.1, p.8]
10. Banked Allowances Under the Proposed Rule
Under the proposed Transport Rule allowances would be bankable for future use. PPL supports this approach. Permitting allowances to be banked for future use both encourages early reductions and provides more options for sources to meet the rule's requirements most cost effectively. [EPA-HQ-OAR-2009-0491-2739.1, p.10]
PSEG Services Corporation
PSEG recommends that EPA modify the unit allocation methodology. [EPA-HQ-OAR-2009-0491-2726.1, p.2]
Based on the D.C. Circuit's decision, the Agency is not proposing an allocation methodology that would rely on existing Title IV allowances to comply with the Transport Rule. This creates an unfortunate dynamic whereby companies, such as PSEG, that have invested in pollution control equipment are essentially penalized as the value of their banked allowances is reduced by exclusion of Title IV allowances in the new trading program. Additionally, the allocation structure proposed in the Transport Rule fails to recognize these early investments. These early reductions are the ones that EPA and Congress should be encouraging, and we are concerned that an unintended consequence of the proposal will be to deter companies from taking proactive actions to reduce emissions in the future. As such, PSEG recommends that EPA allocate the new allowances in the Transport Rule in a manner that recognizes early investments to reduce emissions as opposed to what has been proposed, an approach that rewards sources that have not taken such action. [EPA-HQ-OAR-2009-0491-2726.1, pp.4-5]
Recognizing that EPA's authority to use the existing Title IV Acid Rain trading system and to create a more robust interstate trading system has been limited by the DC Circuit Court's decision, PSEG continues to support new federal legislation that appropriately addresses these limitations and at the same time assures environmental integrity in achieving timely air quality improvements throughout the transport region. While such legislation in our view is desirable, the passage of such legislation appears highly problematic. Given the realities of the legislative process, and given our belief that EPA has the authority to make certain allocation changes to better incentivize and reward early emission reduction action, we believe the trading system EPA has proposed is workable. We therefore encourage EPA to move forward quickly to finalize the rule and to get the trading system up and running. [EPA-HQ-OAR-2009-0491-2726.1, p.5]
Further, by basing unit allocations for 2012 on a methodology that requires an owner to operate installed or planned pollution control technologies at maximum emission control rates, EPA is penalizing companies who have made the capital investments needed to control emissions while rewarding companies who are not controlling emissions. As EPA states in the preamble to the proposed rule, "this means that a unit that installs control equipment receives fewer allowances than a similar unit that did not install control equipment." This is counter-productive to EPA's overarching responsibility to encourage maximum environmental performance. [EPA-HQ-OAR-2009-0491-2726.1, p.6]
Rewarding higher emitters also removes the fundamental incentive of a cap and trade program; namely, the use of a market based incentive for owners and operators of uncontrolled generating units to install pollution control technologies or retire ineffective units. Under a properly constructed cap and trade program, owners and operators of uncontrolled units receive less than what they emit. As a result, owners and operators of those units must make fundamental economic decisions to either buy more allowances to operate the unit, install technologies to operate the unit, curb operations of the unit, or for those units which are uneconomical, retire the unit. These economic decisions drive the trading market, and thus incentivizing decisions for those owning units to reduce emissions, either through control or retirement. By using a historic heat input approach to allocations, these incentives are created fairly because units that have already installed controls will get more allowances than needed for operations, while higher emissions units that have not installed controls will be required to purchase allowances in the marketplace. This is not only an inherently fairer and environmentally-directionally positive approach for units that have invested in back end controls, but this will also significantly increase the number of allowance transactions taking place in the market, thus increasing liquidity. Entities with excess allowances will be able to liquidate excess allowances, while entities in need of allowances will have the robust information needed to make decisions regarding installing controls, modifying operations or buying allowances. In contrast, under EPA's proposed allocation methodology, units will roughly get much of what they need to operate, resulting in relatively little trading. Thus, as proposed, PSEG believes that the Transport Rule will provide weak market based incentives and may lead to very little improvement in air quality. [EPA-HQ-OAR-2009-0491-2726.1, pp.7-8]
PSEG supports EPA's proposal to continue to allocate allowances to retired units for six years after ceasing operations. The six-year period ensures that companies make the retirement decisions independent of any allocation and allowance value. [EPA-HQ-OAR-2009-0491-2726.1, p.8]
If EPA agrees with PSEG's recommendation to change the unit allocation methodology to a historic basis while maintaining the existing methodology for setting the state budget, EPA will need to evaluate whether that requires a change to the assignment of responsibility for the assurance provisions to owners. PSEG recommends that EPA identify allowances related to each state with a serial number and vintage that indicates which state the allowance was initially issued. A unit's budget, for the purposes of compliance assurance would be the number of in-state allowances that it holds for the year and surrenders for that year. An owner could, therefore, assure that it will not be subject to the requirement to surrender extra allowances if the state exceeds its budget plus variability by ensuring that no more than ten percent (or state-specific limit) of the allowances it surrenders in a given year are from out-of-state allowances or allowances from other years (the three-year variability would be calculated as an average of 5.8 percent annually or ten percent divided by the square root of three). [EPA-HQ-OAR-2009-0491-2726.1, p.10]
This approach would allow some interstate trading, provide some incentive for banking, create stronger incentives for states to not exceed its budget, and create greater certainty for individual owners. Further, this assurance mechanism would allow EPA to easily revise the initial allowance allocation mechanism in a way that would make the rule less subject to legal challenge and more readily accommodate future reductions in the state emissions budget. PSEG supports this modification to the assignment of the assurance provisions because it provides benefits to owners while maintaining, and potentially strengthening, the health benefits of the proposed rule. The benefits include: [EPA-HQ-OAR-2009-0491-2726.1, p.11]
The methodology encourages more in-state emission reductions in states that may exceed their emission cap by increasing the value of in-state emission reductions. In-state allowances would provide a hedge against the assurance provision. As a result the value of in-state emission reductions would increase to somewhere between one and two "national" allowances. This increases the likelihood that the necessary reductions would occur in targeted states. [EPA-HQ-OAR-2009-0491-2726.1, p.11]
The methodology provides a safe harbor for owners who want to manage the risk of the two-for-one assurance provision. [EPA-HQ-OAR-2009-0491-2726.1, p.11]
If EPA does not agree with PSEG's recommendation and distributes allocations based on emissions, EPA should base the unit's variability and assurance provisions in consideration of the emissions performance of the unit. If a unit has minimal controls they should have little or no variability; however, if a unit has extensive controls, they should have increased variability. A possible method to assign variability in this manner is to make it a function of the average emission rate of the state; whereby, a unit that is higher than the average would progressively receive less variability than a unit having an emission rate less than the average and progressively more variability. [EPA-HQ-OAR-2009-0491-2726.1, p.11]
Reiss, J.
For each allocation method, this Comment uses a hypothetical group of sources in a hypothetical state to calculate the number of allowances each source would receive under the given allocation method and the resulting percentage reduction in emissions. The goal of the hypothetical is to demonstrate which sources must achieve the least emissions reductions under each allocation method, thereby "benefitting" from that allocation method. The hypothetical assumes a state-specific emissions cap of 160 tons of emissions, which amounts to two-thirds of the state's current emissions. The hypothetical assumes Sources A through H are the only affected sources in the state and have the statistics shown in Table 1. For simplicity's sake, each statistic is given either as a low (10) or high (50) value; but clearly, in reality, these statistics are not measured within the same orders of magnitude. [EPA-HQ-OAR-2009-0491-2648.1, p.5]
[Table 1 can be found on page 6 of this comment.]
Source G represents a highly efficient electricity generating unit. While generating a lot of electricity, Source G's heat input and emissions remain low. To compare the hypothetical with a real-world example, Source G is somewhat similar to the Liberty Electric Power Plant in Pennsylvania. While generating almost 3 million MWh of electricity in 2009, the Liberty facility used just over 21 million mmBtu of fuel. The Liberty facility emitted just under 16,000 tons of SO2 in 2008. Source B, on the other hand, represents a highly inefficient electricity generating unit. Source B's heat input and emissions are high, but it generates very little electricity. Again, to compare the hypothetical with a real-world example, Source B is somewhat similar to the E W Brown facility in Kentucky. The Brown facility generated only just over almost 2.6 million MWh of electricity in 2009 while using over 27 million mmBtu of fuel (400,000 less MWh and 6 million more mmBtu than the Liberty facility). The Brown facility emitted over 52,000 tons of SO2 in 2008 (36,000 more tons than the Liberty facility). Sources A and H represent essentially the same source on different scales. Between these sources are sources with varying degrees of efficiency and emission levels. [EPA-HQ-OAR-2009-0491-2648.1, p.6]
Recognizing that reality does not provide perfect examples of each source in the hypothetical, the hypothetical is still useful. By it, this Comment will demonstrate which types of sources benefit from each allocation method by bearing a lower emissions reduction requirement. Because EPA has flexibility in allocating allowances from the state-specific caps to the sources, EPA should use this demonstration to determine the most productive method of allocating allowances. [EPA-HQ-OAR-2009-0491-2648.1, pp.6-7]
A. Emission Based Allocation: Requires All Sources to Reduce Emissions Uniformly, Regardless of Efficiency at Converting Fuel into Electricity
In our hypothetical state, Sources A through H would receive the following quantities of allowances under an emission based allocation method: [EPA-HQ-OAR-2009-0491-2648.1, p.7]
[Table 2 can be found on page 7 of this comment.]
If EPA allocates allowances based on emissions, all sources must attain the same emissions reduction. Emission based allocation requires inefficient and efficient sources alike to reduce emissions uniformly. A source's efficiency at converting fuel into electricity is not considered in emission based allocation. By treating efficient and inefficient sources exactly the same, emission based allocation actually disfavors sources capable of generating a lot of electricity without emitting a lot of pollutants or using a lot of fossil fuel resources. [EPA-HQ-OAR-2009-0491-2648.1, pp.7-8]
Treating efficient and inefficient sources the same is not recommended for two reasons. First, it penalizes sources that already took responsible actions to reduce emissions. Sources that already reduced emissions will receive fewer allowances and will have to make further emissions reductions. A system that penalizes early actors does not encourage efficient energy generation. Second, by treating efficient and inefficient sources the same, emission based allocation grandfathers in sources that emit large quantities of pollutants. In this context, grandfathering means creating a system that maintains or encourages the status quo. Because emission based allocation gives larger quantities of allowances to sources that historically emitted larger quantities of emissions, it maintains the status quo of emission control capabilities in the power sector, thereby missing the opportunity presented by the Transport Rule to encourage efficient energy generation. [EPA-HQ-OAR-2009-0491-2648.1, p.8]
B. Heat Input Based Allocation: Favors Sources that Use Large Quantities of Fuel, Regardless of Efficiency at Converting that Fuel into Electricity
In the Transport Rule, EPA specifically declines to consider allocating allowances based on heat input. EPA seems to base this decision on North Carolina, in which the court struck down EPA's use of heat input in CAIR to develop the state-specific emission caps. In CAIR, EPA determined the region-wide NOx cap "by multiplying current heat input by emission rates" and "allocated this regionwide [sic] amount to the individual States in accordance with their average heat input," adjusted "for type of fuel used." Although definitions are much more complicated, for practical purposes, heat input means the amount of fuel fed into the source. 44 In North Carolina, the court said the Clean Air Act required EPA to base the state-specific caps on each individual state's significant contribution or interference, not on heat input. In the Transport Rule, this is what EPA proposes to do. [EPA-HQ-OAR-2009-0491-2648.1, pp.8-9]
In North Carolina, the court did not discuss the propriety of using heat input to allocate allowances from the state-specific cap to the sources within that state. Heat input based allocation would require only a simple calculation: divide each source's fuel use by the total state fuel use and convert the result to a percentage. Each source would receive the resulting percentage of the state-specific cap. Sources that historically used large quantities of fuel would receive a larger quantity of allowances. Sources that historically used small quantities of fuel would receive a smaller quantity of allowances. [EPA-HQ-OAR-2009-0491-2648.1, p.9]
In our hypothetical state, Sources A through H would receive the following quantities of allowances under a heat input based allocation method: [EPA-HQ-OAR-2009-0491-2648.1, p.9]
[Table 3 can be found on page 9 of this comment.]
Heat input based allocation would require the most efficient sources, Sources C and G, to reduce their emissions to the same extent or more than the least efficient sources, Sources B and F. Source B (least efficient) and Source G (most efficient) would be required to make the same emissions reductions: 33 percent. Also, Source B would receive the same number of allowances as Source E, which generates magnitudes more electricity while emitting a fraction of the pollutants. Sources E and F would not required to reduce emissions at all and would, instead, sell allowances for profit. [EPA-HQ-OAR-2009-0491-2648.1, pp.9-10]
Heat input based allocation favors sources that use large quantities of fuel, regardless of the sources' efficiency at converting that fuel into electricity. By allocating the same or more allowances to inefficient sources, heat input based allocation disfavors sources capable of generating a lot of electricity without using a lot of fossil fuel resources. By benefiting inefficient sources, heat input based allocation does not encourage efficient electricity generation. [EPA-HQ-OAR-2009-0491-2648.1, p.10]
C. Full Auction: Internalizes Emissions for All Sources, but is Impractical
In the Transport Rule, EPA discusses and dismisses allocating allowances by auction. The statutory requirement to reduce emissions within the state likely prevents EPA from allocating allowances by auction. Allocation by auction would require each source to purchase one allowance for each ton of pollutant emitted. This method would be the simplest way to internalize the cost of emitting the pollutants because no source could emit the pollutant without paying for it. This allocation method would involve no calculations because each source would simply purchase an allowance for each ton emitted. [EPA-HQ-OAR-2009-0491-2648.1, p.10]
However, as EPA points out, the statutory requirement to reduce emissions within the state would require EPA to hold separate auctions in each state and for each pollutant. "[T]his approach, if implemented, would result in 28 separate trading programs for NOx annual, 26 trading programs for NOx ozone season, and 28 trading programs for SO2 for a total of 82 new trading programs to be administered by EPA." The administrative burden EPA would face in holding so many auctions makes allocation by full auction a problematic option in this context. [EPA-HQ-OAR-2009-0491-2648.1, p.10]
V. Recommendation: Energy Output Based Allocation
A. Energy Output Based Allocation: Encourages Efficient Energy Generation
EPA specifically "requests comment on whether there are alternative allocation methods EPA should consider that are consistent with the Court decision [in North Carolina] and the statutory mandate of section 110(a)(2)(D)." This Comment recommends EPA allocate allowances based on an alternative method: energy output. Energy output means the amount of electricity delivered by the source. 53 Like the other allocation methods, energy output based allocation would require only a simple calculation: divide each source's electricity generation by the total state generation of electricity and convert the result to a percentage. Each source would receive the resulting percentage of the state-specific cap. Sources that historically generated large amounts of electricity would receive a larger quantity of allowances. Sources that historically generated small amounts of electricity would receive a smaller quantity of allowances. 54 [EPA-HQ-OAR-2009-0491-2648.1, pp.10-11]
In our hypothetical state, Sources A through H would receive the following quantities of allowances under an energy output based allocation method: [EPA-HQ-OAR-2009-0491-2648.1, p.11]
[Table 4 can be found on page 11 of this comment.]
As in inverse to heat input based allocation, energy output based allocation would require the least efficient sources, Sources C and G, to reduce their emissions to the same extent or more than the most efficient sources, Sources B and F. Source G, the most efficient source, is not required to reduce emissions at all and can, instead, sell allowances for profit. Source B, the least efficient source, must make significant reductions in emissions. [EPA-HQ-OAR-2009-0491-2648.1, p.11]
Energy output based allocation favors sources that generate a lot of electricity while emitting few pollutants. Energy output based allocation disfavors sources that emit large quantities of pollutants without generating significant amounts of electricity (Sources B and D above). To compare each allocation method in our hypothetical state, Sources A through H would receive the following quantities of allowances under each allocation method: [EPA-HQ-OAR-2009-0491-2648.1, p.12]
[Table 5 can be found on page 12 of this comment.]
Energy output based allocation promotes efficient electricity generation more than the other allocation methods. The reality becomes more apparent in a comparison of the least and most efficient sources. [EPA-HQ-OAR-2009-0491-2648.1, p.12]
Table 6 shows that in heat input based allocation, favor falls on inefficient sources and disfavor falls on efficient sources. In energy output based allocation, favor falls on efficient sources and disfavor falls on inefficient sources. The efficient sources receive proportionally more allowances if EPA allocates based on energy output instead of emissions or heat input. By allocating proportionally more allowances to efficient sources, EPA favors and benefits those sources, thereby encouraging efficient electricity generation. [EPA-HQ-OAR-2009-0491-2648.1, p.13]
B. EPA Should Encourage Efficient Energy Generation
In all the examples above, the hypothetical state would never exceed the state-specific cap of 160 tons, or two-thirds current emissions levels. Because EPA proposes, in the Transport Rule, to base state-specific caps on each individual state's significant contribution or interference, EPA would meet the statutory mandate of the Clean Air Act regardless of how EPA allocated allowances from the state-specific caps to the individual sources. As long as the allocation from the state-specific cap to the sources does not cause the state as a whole to exceed the state-specific cap, EPA has some flexibility in allocating those allowances. This Comment recommends EPA allocate allowances based on energy output because that method will encourage efficient energy generation, which, in turn, will increase the productive capacity of the nation's power sector and will have residual environmental, health, and safety benefits. The other allocations methods do not provide such advantages. [EPA-HQ-OAR-2009-0491-2648.1, p.13]
[Table 6 can be found on page 13 of this comment.]
One of the purposes of the NAAQS is "to protect and enhance the quality of the Nation's air resources so as to promote . . . the productive capacity of its population." The statute does not define "productive capacity" and definitions vary. Essentially, productive capacity means the maximum achievable output of a thing, in this case, the Nation or the power sector. Efficient electricity generation means generating more electricity using fewer natural resources (fuels) and emitting fewer pollutants. In this way, efficient electricity generation increases the Nation's maximum achievable output. In other words, productive capacity is how much you can do with what you have. Increasing efficiency at generating electricity is doing more with less. When the Nation increases its efficiency at generating electricity, it inherently increases its productive capacity. Because one of the purposes of the NAAQS is to promote the productive capacity of the Nation, EPA should promote efficient electricity generation in implementing the NAAQS through the Transport Rule. Energy output based allocation encourages efficient electricity generation by allocating proportionally more allowances to efficient sources than to inefficient sources. Therefore, EPA should allocate allowances based on energy output. [EPA-HQ-OAR-2009-0491-2648.1, p.14]
[For additional comments on "EPA Should Encourage Efficient Energy Generation," see pages 14-15 of this comment.]
VI. Conclusion: EPA Should Allocate Allowances Based on Energy Output in Order to Encourage Efficient Energy Generation
Allocation based on energy output will encourage efficient electricity generation by allocating proportionately more allowances to sources that generate a lot of electricity while emitting few pollutants. Encouraging efficient electricity generation promotes the productive capacity of the Nation by allowing the Nation to create more electricity with fewer natural resources and fewer emissions. Because the NAAQS purpose "to protect and enhance the quality of the Nation's air resources so as to promote . . . the productive capacity of its population," EPA should allocate allowances in a way that increases the productive capacity of the Nation. Encouraging efficient electricity generation through energy output based allocation increases productive capacity. Therefore, in the Transport Rule, EPA should allocate allowances from the state-specific caps to the sources based on energy output. [EPA-HQ-OAR-2009-0491-2648.1, p.16]

44. Transport Rule, 75 Fed. Reg. at 45,370 (Heat input means, with regard to a unit for a specified period of time, the product (in mmBtu/time) of the gross calorific value of the fuel (in mmBtu/lb) multiplied by the fuel feed rate into a combustion device (in lb of fuel/time), as measured, recorded, and reported to the Administrator by the designated representative and as modified by the Administrator in accordance with this subpart and excluding the heat derived from preheated combustion air, recirculated flue gases, or exhaust.); ENERGY INFO. ADMIN., DEP'T OF ENERGY, REPORT NO. SR-OIAF/2004-05, ANALYSIS OF S.1844, THE CLEAR SKIES ACT OF 2003; S.843, THE CLEAN AIR PLANNING ACT OF 2003; AND S.366, THE CLEAN POWER ACT 2003 (2004) http://www.eia.doe.gov/oiaf/servicerpt/csa/background.html (last visited Sept. 30, 2010) ("[H]istorical heat input . . . allocation is based on historical fuel use."). [EPA-HQ-OAR-2009-0491-2648.1, p.8]
53. The Transport Rule defines "total energy output" as "the sum of useful power and useful thermal energy produced by the unit." Id. at 45,371. The Transport Rule also defines "gross electrical output," which means "electricity made available for use, including any such electricity used in the power production process (which process includes, but is not limited to, any on-site processing or treatment of fuel combusted at the unit and any on-site emission controls)." Id. at 45,370. In order to encourage efficient energy generation, energy output must be measured after internal uses of that electricity. A plant is not efficient if it uses significant amounts of its electricity internally. Measuring electricity output before internal uses would count the inefficient internal uses toward the plant's allowance allocation, thereby negating the efficiency-encouraging aspects of energy output based allocation. [EPA-HQ-OAR-2009-0491-2648.1, p.11]
54. The Massachusetts NOx Allowance Trading Program uses a similar method that allocates allowances based on "a unit's net electric output in MWh." 310 MASS. CODE REGS. 7.28(6)(d)(1). [EPA-HQ-OAR-2009-0491-2648.1, p.11]
Rochester Public Utilities (RPU)
RPU is not able to specifically comment on the calculations that EPA used to determine the allocations as there was insufficient time to review all of information provided, and further the methodology was not fully explained. RPU will, however, provide the following comments on some of the supporting information used by EPA to establish a baseline for the allocation. [EPA-HQ-OAR-2009-0491-2802.1,p.2]  
It is our understanding that EPA used operating data for Quarters 1  -  3 of 2009 and Quarter 4 of 2008, as listed in Table 1, to determine unit-level allowance allocations for Unit 4. This time period is not representative of Silver Lake Unit 4's normal operation. During this time, Unit 4's average operation was less than 500 hours and 150,000 million Btu (mmBtu) heat input per quarter. Typical operation of this unit is closer to 1,300 hours and 510,000 mmBtu heat input per quarter. Table 2 provides a summary of the average operating data of each quarter for the period between 2003 and 2008. A comparison of the data presented in Tables 1 and 2 clearly indicates that the operational data used in the development of the proposed Transport Rule was not representative of routine operation for Silver Lake Unit 4. [EPA-HQ-OAR-2009-0491-2802.1,p.3] [[See Docket Number EPA-HQ-OAR-2009-0491-2802.1, p.3 for Tables 1 & 2.]]  
The abnormally low operation of Unit 4 during the time period used by EPA is attributable to the installation of the new AQCS, milder weather and the economic downturn which affected the U.S. Energy Market1, especially in the midwest. As a participant of the Midwest Independent Transmission System Operators (MISO) market, RPU's dispatch of Silver Lake Unit 4 for operation is primarily related to electrical demand in the MISO region and local transmission and generation constraints. The quarters chosen by EPA should not be considered appropriate quarters for the following reasons:  [EPA-HQ-OAR-2009-0491-2802.1, pp.3-4]  
:: 4th Quarter 2008: Silver Lake Unit 4 was in a 6 week outage to interconnect the new AQCS. This outage began in October 2008 and ended in December 2008.
:: 1st Quarter of 2009: Though some operation for electrical demand did occur, tuning and testing of the SDA and PJFF occurred during this quarter.
:: 2nd Quarter of 2009: Unit 4 was not operational in part due to economic factors and installation of additional urea injection ports for the SNCR. There were only three hours in which the boiler was operated, solely for maintenance purposes and not electrical generation.
:: 3rd Quarter of 2009, Unit 4 was dispatched on a very limited basis due to the economic recession, and a good portion of the time the unit did operate was for the final tuning and testing of the SNCR.  [EPA-HQ-OAR-2009-0491-2802.1,p.4]
RPU requests that EPA repeat the procedures used to determine unit-level allocations using historical data that are more representative of Unit 4's typical operation. Table 3 provides an appropriate range of operating quarters that stays within the range of data sets laid out in the Transport Rule. [EPA-HQ-OAR-2009-0491-2802.1,p.3] [[See Docket Number EPA-HQ-OAR-2009-0491-2802.1, p.4 for Table 3.]]
RPU further requests that EPA use the 2007 quarter 4 heat input in any calculations or modeling instead of the incomplete 2008 quarter 4 heat input for the reasons provided above. Attachment A provides a copy of the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool Emissions Summary Report for Silver Lake Unit 4 for 2003  -  2009. [EPA-HQ-OAR-2009-0491-2802.1,p.4]

1. The U.S. Energy Information Administration's Annual Energy Outlook (AEO) for 2009 and 2010 reported a drop in total electricity generation of 1% in 2008 and 3% in 2009. The 2010 AEO further stated that "Although other factors, including weather, contributed to the decrease, it was the first time in the 60-year data series maintained by the EIA that electricity use fell in two consecutive years." But this is the time period EPA chose to use for their base case of actual data from annual emissions data starting in the most recent non-null first quarter, second quarter, third quarter, and fourth quarter emissions and heat input, between quarter 1 2007 and quarter 3 2009. A more appropriate time period to reflect normal operation should have started in 2007 or should have been an average of a period over several years.
San Miguel Electric Cooperative, Inc.
The proposed CATR outlines allocation to existing units (75FR45309), " EPA proposes that ...each existing unit in a given state receives allowances commensurate with the unit's emission reflected in whichever total emissions is lower for the state, 2009 emissions or 2012 base case emissions projections."  [EPA-HQ-OAR-2009-0491-2641.1, p.4]
The EPA proposed allowance allocation methodology radically departs from previous regulatory allocation methods and creates numerous inequities and other poor policies without justifications. The proposed allocation method is based on EPA computer model projections of both future individual unit utilization and emission reduction capabilities at specified marginal cost of emission reduction levels. The model attempts to predict the future of literally thousands of electric utility fossil fuel units located within the proposed CATR trading areas. Regardless of the purported sophistication of EPA's model, it does not and cannot accurately forecast how each and every fossil fuel unit among thousands will be utilized. Case in point is the numerous errors, outlined above, of the San Miguel generating unit. It is not likely that the San Miguel unit is the only unit where errors have occurred. [EPA-HQ-OAR-2009-0491-2641.1,p.4]
The model also cannot account for future business decisions, the necessity of which is not yet presently known or anticipated but nonetheless may need to be made that would significantly affect an individual unit's utilization within the utility system. There are literally dozens of significant factors that affect future unit utilization of which the model does not and cannot take into account. [EPA-HQ-OAR-2009-0491-2641.1,p.4]
San Miguel believes most of the problems inherent in the proposal's methodology could be resolved if state budgeted allowances were distributed to each unit within the state based pro-rata on the unit's portion of the state historic heat rate updated periodically to include new units. Such distribution should sub-categorize between coal, gas, and oil. The allocation methodology could be structured in a manner similar to that contained in Clean Air Interstate Rule (CAIR) for annual NOx allocations as a SIP for all the CATR trading programs. Specifically, the salient features of this methodology include allocating allowances to existing units based on historic heat input using the three highest heat inputs of the past five years to derive annual averages (seasonal for ozone), and allocating allowances to new units based on a set-aside and folding new units into existing unit category after five years of operation. As with the CAIR approach, this methodology could provide options for each state to consider whether new units should receive allowances from a set-aside during their initial year of operation and if retired units should continue to receive allowances, and if so how long or at a diminished allocation.  [EPA-HQ-OAR-2009-0491-2641.1, pp.4-5]
San Miguel encourages the EPA to revise the methodology for unit allocations from the proposed method to a historically based system similar to the CAIR proposal. [EPA-HQ-OAR-2009-0491-2641.1, p.5]
 The preferred remedy option allowing unlimited emissions trading during the initial 2012 compliance period and limited interstate trading in the second compliance period recognizes the economic benefits of trading and should be retained. The auctioning of allowances would drive up program compliance costs. Therefore, it is justifiably excluded from the preferred remedy and proposed intrastate option.   [EPA-HQ-OAR-2009-0491-2641.1, p.6][[This comment can also be found in Outline Heading V.D.3.a.]]
Seminole Electric Cooperative Inc.
IPM Prediction. Despite several phone calls to EPA's 'experts' on IPM modeling, neither EPA's experts nor Seminole can understand exactly what erroneous assumptions EPA is making to produce this fundamentally-flawed result. We can see the data going into the model, and we can see the results coming out, but it is apparently not possible to track a specific unit through the IPM model. EPA's use of a modeling platform that cannot explain how and why it arrived at a specific conclusion for a specific unit, and then EPA's reliance on that conclusion in establishing permanent compliance obligations, is an egregious abuse of discretion/power and a hallmark of an arbitrary and capricious rule. [EPA-HQ-OAR-2009-0491-2632.1, p.4]
According to EPA representatives, the three most likely variables affecting IPM's allocation to a specific unit are annual utilization of the unit (i.e., heat input), sulfur content of the fuel (i.e., percent by weight per ton of coal or lb/mmBtu inlet to the FGD), and removal efficiency of the FGD system (i.e., percent difference between the inlet and outlet of the FGD). In looking at the EPA projections, the heat input and removal efficiency appear to be within the ranges of reasonably representative values (although the projected FGD removal efficiency of 92.7 percent is on the high end of the range). This leaves the sulfur content of the fuel as the remaining variable primarily responsible for the unachievable allocation. As stated above, the sulfur content of Seminole's coal supply is approximately 3 percent by weight, with authority to co-fire up to 30 percent petcoke (which can be up to 7 percent sulfur by weight). In 2009, without burning any petcoke, Seminole's inlet-to-the-FGD sulfur content averaged approximately 4.7 lb/mmBtu; EPA's projected 2012 inlet is 1.4lb/mmBtu. To reach EPA's projection, Seminole would have to reduce the sulfur content of its fuel by over 70 percent. [EPA-HQ-OAR-2009-0491-2632.1, p.4]
Apparently, IPM predicted that Seminole (and according to EPA representatives, many other eastern coal-fired units) would immediately switch to coal from the Powder River Basin (PRB) in the western U.S. to achieve this level of reduction. [EPA-HQ-OAR-2009-0491-2632.1, p.4]
Technical, Practical and Economic Infeasibility of the IPM Prediction. Switching to lower sulfur coal, such as from PRB, would have substantial technical, practical and economic consequences, if it could be done at all. First, from a technical perspective, coal-fired boilers are designed for the fuel that it will burn, with special consideration of heat, sulfur and ash content. PRB coal, for example, has significantly lower heat content than eastern bituminous, requiring a corresponding increase of approximately 35 percent in the volumetric consumption required to generate the same/needed load. And there is a technical/physical limit on the quantity of coal that can be burned in the units, meaning that using a lower heat content coal would effectively de-rate the unit, requiring additional generation elsewhere to make up the loss. [EPA-HQ-OAR-2009-0491-2632.1, pp.4-5]
Lower sulfur western coals can also release heat in different locations than the boiler was designed for, resulting in increased tube failures and unit downtime. PRB coals also contain more volatiles, which increases the risk of explosions when the hot mill is shutdown and then restarted. Plants burning higher sulfur coals do not have the specially-designed mills to compensate for this increased risk. We estimate that a minimum of 20 months would be needed to design, fabricate, transport and install such special mills. Seminole's brand-new SCRs and existing ESP systems could also be materially impacted due to differences in ash contents of the different sulfur fuels. SCRs are impacted with differing ash contents that can have different mineral contents that can poison the catalyst, significantly shortening catalyst life. ESP performance is also impacted due to differences in resistivity and S03 rates. Correcting the resulting increased particulate emissions from the stack would require redesigning and substantially increasing the size of the ESP. Ash handling equipment and ash storage facilities would need to be expanded if the ash content is greater. And since no additional ash storage is available, any increase would have to be sent offsite. Finally, material handling and processing would increase due to lower heat content (and higher volume) of lower sulfur coal, possibly requiring additional equipment and increased fugitive emissions.  [EPA-HQ-OAR-2009-0491-2632.1, p.5]
Practically, EPA has not been able to explain how the existing PRB coal production and railroad transportation capacity can accommodate the exponential increase in the availability of western coals to all of the eastern units that IPM projects will/must switch. For starters, Seminole understands that there are considerable bottlenecks in the rail lines that cross the Mississippi River and are routed through the Southeast U.S. Any expansion of the use of PRB coals in the east will also require substantial expansion, development and permitting for new mines in the PRB, as well as a major expansion of all railroads capable of moving coal from the PRB to the east. This expansion will not happen overnight and could take a decade or more to become reality, assuming the states and environmental communities support such an expansion of PRB coal mining and related transportation networks through their backyards. [EPA-HQ-OAR-2009-0491-2632.1,p.5]
Economically, there will be a dramatic impact on Seminole if it was even possible for it to switch to western lower sulfur coals. In addition to the equipment costs above, Seminole would have to breach existing long-term contracts. In 2005, Seminole determined that switching to PRB coal would cost between $40,000,000 and $66,000,000 per year due to the higher price of this coal, increased transportation costs, and lower heating value of the coal. And this annual figure does not include de-rating the unit and the need for replacement power. If many other eastern companies are required to now switch as well, this cost would be expected to be dramatically higher. [EPA-HQ-OAR-2009-0491-2632.1, pp.5-6]
Accordingly, numerous questions must be answered to understand whether IPM's projection bears any resemblance to reality. What is the precise increase in the volume of coal that EPA expects will be transported from the west to the east as a result of the proposed rule? Will additional rail lines or routes be needed? What is the proposal's economic impact on the rail business? How will the massive fuel switch affect the national economic outlook for the U.S. for energy and GNP? How will it affect the cost of coal, in the short term and long term? How much lower sulfur coal is available in the west? And how long will this last, given EPA's projection of fuel switching? [EPA-HQ-OAR-2009-0491-2632.1, p.6]
Southern Company
XIII. EPA's State Budget and Unit Allocation Methodologies Are Fundamentally Flawed
To establish state budgets and unit allocations, EPA used a combination of reported data and projected data, both adjusted for controls. As mentioned earlier, EPA's methodology was not clearly defined and Southern Company spent  countless hours replicating EPA's approach. However, Southern Company has identified a number of fundamental flaws in EPA's methodologies for developing and adjusting this data for purposes of setting the state budgets and unit allocations. These flaws are described below. [EPA-HQ-OAR-2009-0491-2864.1, p. 48]
A. 2009 Was Not an 'Average Year'
To develop the reported emissions data for purposes of setting state budgets and unit allocations EPA took the most recent 'non-null' quarterly data (through the third quarter of 2009) for each quarter (quarter one through four). In most cases, this meant using data from the fourth quarter of 2008 through the third quarter of 2009 as a representative year (or 2009 ozone season data as a representative ozone season). This process is significantly flawed. EPA repeatedly claims that state budgets are based on emissions from an 'average year.' Yet its methods accomplish nothing of the sort. Put simply, EPA's selected representative year is anything but average. [EPA-HQ-OAR-2009-0491-2864.1, p. 48]
From 2008 through 2009, the nation was in the middle of the most significant economic downturn since the great depression. Electricity demand and heat input were unusually low. EPA appears to recognize this anomaly by adjusting reported NOx data based on 2008 heat input.4 But even that adjustment does not fully account for the unusually low demand for electricity beginning in the second half of 2008. In addition, in 2009 natural gas prices were at extraordinarily low resulting in highly unusual dispatch of the fossil fuel fired electric generating fleet. In some cases, large coal-fired units were idled while natural gas fired units - normally reserved for peaking power - ran at much higher capacity factors. Due to the combined forces of (i) decreased demand and (ii) low natural gas prices, 2009 is perhaps the least representative year in decades for determining average annual emissions. EPA should fully account for the economic downturn by selecting reporting years that were not impacted by the economic downturn. [EPA-HQ-OAR-2009-0491-2864.1, pp. 48-49]
Instead of attempting to select a single representative year, consistent with past practice, EPA should use a longer average period of time to develop reported emissions data. By selecting a longer period of time (e.g., three years as used in the Acid Rain Program, the NOx SIP Call and CAIR), EPA would capture data that is more representative. Selecting the three year period from 2005 to 2007 would fully account for the economic downturn, capture two full operational cycles for a typical unit, and would provide much more reliable data. [EPA-HQ-OAR-2009-0491-2864.1, p. 49]
[The above comments can also be found at section IV.E. of the comment summary.]
C. EPA Should Allow States To Develop Allocations
EPA should allow states to develop state-specific allocations through the SIP process. States were very successful in dividing allocations for CAIR and the NOx SIP Call and are better suited to developing fair and consistent allocations that take into consideration unique aspects of EGUs (e.g., fuel mixes or anticipated new unit construction) in the state. States are most familiar with the types of EGUs in their states and can best determine how allocations should be made. [EPA-HQ-OAR-2009-0491-2864.1, pp. 49-50]
D. EPA Should Reward, Not Penalize, Units for Early Reductions
EPA's methodology for distributing allocations based on unit-by-unit analysis unfairly penalizes sources that installed controls before 2010 (e.g., Miller 3 & 4 FGD, Miller 1, 2, 3 & 4 SCR, Gorgas 8, 9, and 10 FGD, Gorgas 10 SCR, Gaston 5 SCR). Allowances should be allocated to sources based on a universal methodology. Additionally sources that have been burning low sulfur coals, establishing a lower base of S02 emissions will be unfairly penalized under the current allocation methodology. Unfairly distributing allocations negates the value of a market based program. [EPA-HQ-OAR-2009-0491-2864.1, p. 50]
XVI. Southern Company Supports Several of EPA's Decisions in the Proposed Transport Rule
As discussed throughout these comments, Southern Company has many concerns with the Proposed Transport Rule. However, we support several of EPA's decisions in the proposed rule including EPA's decision to allow banking of allowances. [EPA-HQ-OAR-2009-0491-2864.1, p. 52]
XVI. Southern Company Supports Several of EPA's Decisions in the Proposed Transport Rule
As discussed throughout these comments, Southern Company has many concerns with the Proposed Transport Rule. However, we support several of EPA's decisions in the proposed rule including EPA's decision to allow retired units to continue to receive allowances for some time. [EPA-HQ-OAR-2009-0491-2864.1, p. 52]
A. EPA's Decision to Allow Interstate Trading, Although EPA Should Have Allowed More EPA's Proposed Remedy Option allows limited interstate allowance trading, while its two alternative options would not allow any interstate trading. Southern Company supports EPA's proposal to permit at least some degree of allowance trading, although as discussed elsewhere, EPA should have considered more trading. Permitting interstate allowance trading would provide for increased flexibility and permit more cost-effective compliance options. [EPA-HQ-OAR-2009-0491-2864.1, p. 52]
EPA's Decision to Not Establish Allowance Auctions in the Preferred Approach, Southern Company supports EPA's proposal not to include any allowance auctioning under its Proposed Remedy Option. No need or reason exists to use allowance auctions to implement the Proposed Transport Rule's emission reduction requirements. [EPA-HQ-OAR-2009-0491-2864.1, p. 53]
B. EPA's Decision to Allow Allowance Banking
The Proposed Transport Rule properly recognizes the important environmental and economic benefits of allowance banking, a feature of CAIR that was not challenged in the litigation on that rule and that the court's opinion in no way undermines. The ability of sources to use banked allowances for compliance with the program encourages them to make early emission reductions to the extent that cost-effective early reductions are possible. Unfortunately, the nature and stringency of the proposed rule's emission reduction requirements and its proposed compliance schedule would make it very difficult for most sources to make extra emission reductions during the early years of the program. Permitting allowance banking in conjunction with an adjustment to the compliance schedule that would allow sources adequate time to comply with the program (and give states adequate time to develop SIPs) could well result in greater amounts of early emission reductions and, most likely, greater emission reductions over the long run. [EPA-HQ-OAR-2009-0491-2864.1, pp. 52-53]
E. EPA's Decision to Allow Retired Units to Continue to Receive Allowances for Some Time
EPA requests comment on its proposal to continue to allocate allowances to non-operating units. 54 We support EPA's proposal to continue allocations to non-operating units but believe that the allocations should be perpetual, as they are under Title IV. Perpetual allocations encourage retirement of less efficient units, and, as EPA notes, discourages operators from continuing to operate older units 'simply to avoid losing the allowance allocations for those units.' EPA's proposal still promotes continued operation of older less efficient units because each year of operation continues the unit's allocation by an additional year. FU11her, unit owners will be much more likely to retire units if they have control over the allowances perpetually and could plan on the allocations for both existing and new units or choose to sell the allowances to other entities for their new units. In short, perpetual allocations make planning easier, provides more certainty and best encourages retirement of older units.[EPA-HQ-OAR-2009-0491-2864.1, p. 53]
Southern IL Power Cooperative
EPA's proposed system relies on computer modeling of future individual unit utilization and emissions controls operation or installation. In other words, the rationale for essentially permanent unit allocations comes from EPA's computerized virtual world containing numerous false assumptions. [EPA-HQ-OAR-2009-0491-2863.1 p.3]
The proposal does solicit comment for alternative approaches, and in particular an approach based on Heat Input, p. 45311. We suggest the allocation methodology similar to that promulgated in CAIR FIP for annual NOx emissions. (See 70 Fed. Reg. 25162, at 25279). This Heat Input driven system was not overturned by the court's decision in North Carolina. As this alternative is detailed somewhat in the proposal, allowances could be distributed based state allowance budgets pro rata based on unit historic heat rates. Several subcategories could be developed, such as coal and natural gas generation, whereby allowances are distributed based on state allowance budgets and historic heat input from each subcategory. This Heat Input approach would eliminate perpetual allocations to most polluting units, reward consumers who purchase power from new clean sources, and overall demonstrate a rational policy. This method would be lawful under North Carolina. [EPA-HQ-OAR-2009-0491-2863.1 p.3]
As proposed, unused CAIR allowances would be eliminated as a means of compliance beginning in 2012. For new units, a 3% set aside of CATR state allowance budgets shared pro rata in event of over demand, and no allocation during initial year of start- up provide no assurance that necessary allowances would be available for new units necessarily utilizing best emissions control technologies. EPA has stated that it wholly supports new cleaner fossil fuel generation. Yet this policy would function in opposite of encouraging the newer, cleaner generation. EPA should incorporate unused CAIR allowances into the CATR program and make available to new units to the extent that CATR allowances are not available from the 3% CATR new unit set-side. [EPA-HQ-OAR-2009-0491-2863.1 p.4]
As proposed, unused CAIR allowances would be eliminated as a means of compliance beginning in 2012. For new units, a 3% set aside of CATR state allowance budgets shared pro rata in event of over demand, and no allocation during initial year of start- up provide no assurance that necessary allowances would be available for new units necessarily utilizing best emissions control technologies. EPA has stated that it wholly supports new cleaner fossil fuel generation. Yet this policy would function in opposite of encouraging the newer, cleaner generation. EPA should incorporate unused CAIR allowances into the CATR program and make available to new units to the extent that CATR allowances are not available from the 3% CATR new unit set-side. [EPA-HQ-OAR-2009-0491-2863.1 p.4]
State of Delaware Department of Natural Resources & Environmental Control
Allowance Distribution Methodology. In the EPA's proposed rule and supporting technical support documents, EPA proposes an allowance distribution methodology for distributing allowances to individual units. The proposed unit-specific allowance allocations will be made on the basis of each unit receiving its proportional share of its state budget based on that unit's share of state emissions assumed in developing the budget. Using this methodology, the units that historically had the highest emissions (in percentage of the state's total) would be allocated that same percentage of the states allocation. It appears that such a methodology provides a negative benefit to those units that either had a lower emission rate by design or installed controls to achieve a lower emission rate in the past. It is Delaware's opinion that it would be more appropriate to allocate allowances on the basis of a specific unit's historic heat input, as a percentage of the entire heat input that resulted in the state's total allowance allocation. It is Delaware's opinion that this would establish a fuel-neutral allocation methodology that does not provide a negative benefit to those units that had previous reduced their emission rates. [EPA-HQ-OAR-2009-0491-2980.1, p.8]
State of Louisiana, Department of Environmental Quality
ALLOCATIONS/ALLOWANCES
Comment: EPA's inappropriate use of the IPM model to make short-term decisions about which units are slated for retirement does not account for real world truths about future use of gas-fired units within Louisiana. EPA should gather additional real-world information regarding must-run units and local grid constraints to update the expected conditions before finalizing this rule. [EPA-HQ-OAR-2009-0491-2655.1, p.4]
LDEQ must first reiterate its belief that the allocations are best handled in-state. Confirming this belief are the transport rule 2012 NOx allocations; the allocations represented in the Transport Rule differ greatly from the CAiR 2012 allocations as demonstrated in the attached table. (See Attachment C) [See EPA-HQ-OAR-2009-0491-2655.1, p.25 for Attachment C] Some sources are allocated significantly more NOx emissions than they require while other sources currently in operation are allocated absolutely no NOx emissions. Historically, the units that received insufficient or no allocations under the Transport Rule have operated in the past and are operational at the present time. There are no signs from industry to indicate that these units will be retired in the foreseeable future. [EPA-HQ-OAR-2009-0491-2655.1, p.4]
There are also issues of grid electrical constraints within our state which necessitate the operation of some older less efficient units. We believe that other commenters, such as the Louisiana Public Service Commission, have provided additional input on this issue. Based on the IPM model economic input data, natural gas-fired boilers will no longer be online and are therefore not included in the allocation scheme presented in the proposed transport rule. Louisiana holds that this is not accurate, as many of the electric generation facilities in this state, as well as those in Mississippi and Texas, use this type of generation. If these facilities are discounted due to the economic indicators of the IPM model and allowances are not provided to them, the citizens of Louisiana will face large rate increases as these facilities will have to purchase allowances in order to operate and provide power. [EPA-HQ-OAR-2009-0491-2655.1, pp.4-5]
Further, the permitting of these types of facilities usually includes an alternate fuel for operation, namely fuel oil. It is evident that this fuel type was not included in the IPM model; if this fuel type had been included, allowances would have been awarded to the facilities that have otherwise been excluded. Several cogeneration units that should be exempt from the transport rule were given allocations. These units are exempt under CAIR and under the proposed transport rule because they have not sold the greater of 1/3rd of their potential electrical output or 219,000 MWe to the grid in any calendar year since 1990 or the year of first fire, whichever is later. These units include: [EPA-HQ-OAR-2009-0491-2655.1, p.5]
A. Dow St. Charles Operations
B. Evangeline Power Station
C. Formosa Plastics
D. PPG Powerhouse C
E. Shell Chemical
F. Georgia-Gulf [EPA-HQ-OAR-2009-0491-2655.1, p.5]
Comment: LDEQ and other stakeholders should have the opportunity to review EPA's final rule prior to publication to make certain that the information provided and the future modeling runs that will be made will actually address the problems outlined in this proposal. Additionally, EPA should ensure that adequate consideration of comments received through the Notice of Data Availability is factored into the final version of the Transport Rule. [EPA-HQ-OAR-2009-0491-2655.1, p.6]
LDEQ has participated in a number of conference calls between EPA and both regional and national state air quality management organizations since the proposed rule was issued. During those calls it has become evident that EPA must address emissions inventory discrepancies as well as economic inputs before it can produce final IPM modeling runs to achieve meaningful results and final S02 and NOx allocations. State air quality agencies like LDEQ should have the opportunity to review this information before EPA goes final with this rulemaking. LDEQ strongly believes that allowing the state's input may deter allowance gaps as well as potential litigation, thus effecting a timelier implementation of the rule. [EPA-HQ-OAR-2009-0491-2655.1, p.6]
State of Ohio Environmental Protection Agency (Ohio EPA)
Ohio EPA disagrees with the use of the Integrated Planning Model (IPM) for allocating unit level emissions. U.S. EPA should' provide for unit level allocations to be the responsibility of the states as part of a State Implementation Plan (SIP) process. [EPA-HQ-OAR-2009-0491-2793.2, p. 3]
Ohio EPA has concerns with respect to the new~ource set aside and the treatment of shutdown units. U.S. EPA must provide a framework that allows for adequate and necessary growth in order to ensure electric reliability is maintained. [EPA-HQ-OAR-2009-0491-2793.2, p. 4]
a. The new unit set aside, 3%, is taken off the top of what is already a very restrictive S02 budget. [EPA-HQ-OAR-2009-0491-2793.2, p. 4]
b. Ohio EPA questions if a 3% new unit set aside is enough, especially given the approach for handling shutdown provisions.
Units that are permanently shut down would continue to collect allowances (theoretically for use by another unit at the facility or trading) for six years. Then, those allowances would go into the new unit set aside in the seventh year. Ohio EPA understands U.S. EPA's intention of limiting the likelihood of owners continuing to operate older units just to receive allowances. However, Ohio EPA has concerns that not distributing these allocations to the new unit set aside sooner, given the small new unit set aside allocation of 3%, may create reliability issues for the new, more efficient units. Given that allocations are based on a low demand year (discussed later), the variability limits are restrictive, and the new unit set aside is restrictive, owners may need to wait years before allocations are available for new units due from the shutdown of existing units. [EPA-HQ-OAR-2009-0491-2793.2, p. 4]
Further, U.S. EPA states in the proposal that the analysis used to determine the appropriate size of a new unit set aside assumed that allocations for non-operating units 'would be allocated to the new unit set aside after a unit had ceased operating for three consecutive years.' [75 FR 45310] It is not clear from the documentation whether the analysis considered those allocations to be available in the fourth year or seventh year. It is unclear if the analysis (which seems to allude to availability of allocations in the fourth year) is consistent with the outcome included in the proposal (availability of allocations in the seventh year). [EPA-HQ-OAR-2009-0491-2793.2, p. 4]
c. Ohio EPA is very concerned with the schedule for determining if sufficient allocations are available for all new units and for recording new unit allocations. [EPA-HQ-OAR-2009-0491-2793.2, p. 5]
In the proposal, U;S. EPA discusses how, if the new unit set aside does not contain sufficient allocations for all new units, then the allocation to all new units would be proportionally reduced. Further, for new units, allocations are not recorded until September of the year in which they are needed. This could in turn inhibit newer, more modern units from operating due to the uncertainty associated with the availability of allocations needed for the new unit and because of the lag between the new unit set aside account being populated when a unit shuts down. Ohio EPA believes it is completely unacceptable that U.S. EPA provides no assurance that the owner of a new unit will have sufficient allocations until nine months into the control year that they are needed. Further, there is no mechanism in this proposal for a new unit to become an existing unit. Over time, as more and more existing units retire and more and more new, more efficient units enter the program, they will be subject to new unit procedures and restrictions that are unreasonable. [EPA-HQ-OAR-2009-0491-2793.2, p. 5]
d. Ohio EPA is concerned the proposed rule will put newer, more efficient units at greater risk of noncompliance than existing units. [EPA-HQ-OAR-2009-0491-2793.2, p. 5]
While it may be assumed that owners with allowances being distributed for shut down units will be able to trade during their six year allowance allocation period to allow for new unit growth, this is not clear in the proposal. For example, what would happen to a new unit that is not able to purchase allocations from a shutdown unit and did not receive allocations, or enough allocations, from the new unit set aside? If the assurance provisions for the state were triggered, this company would be severely penalized for being over its allocation plus the variability limit when, in fact, it was just not able to receive sufficient allocations due to the restrictive new unit set aside account and the time lag between, populating that account from shut down units. [EPA-HQ-OAR-2009-0491-2793.2, p. 5]
e. Ohio EPA is concerned U.S. EPA has not adequately considered all variables that may affect the amount of allocations a new unit receives. Allocations are based on actual emissions during the first year (control period) of operation of a new unit. In other words, the first year's actual emissions determines future allocations. This raises many questions that are not addressed in the proposal. What will occur during the first year are new unit emissions not addressed or considered under the program in any manner? What if a unit doesn't begin operating at the beginning of the control period - will future allocations be based on only a partial year of operation? When this is re-calculated, based on actual emissions annually thereafter, what assurance is there that owners will not maximize emissions when there is incentive to obtain a greater portion of the new unit set aside? Appropriate flexibility and safeguards are needed. [EPA-HQ-OAR-2009-0491-2793.2, pp. 5-6]
6. Ohio EPA has concerns regarding the ramifications of inhibiting the limited trading program. U.S. EPA must provide a framework that provides assurances that allocations can be traded rather than forcing owners to retain excess allocations out of fear of a future short fall. [EPA-HQ-OAR-2009-0491-2793.2, p. 6]
a. Ohio EPA is very concerned that the insufficient allocations of S02, the restrictive variability limits, and limited trading scheme for Group 1 S02 states, in conjunction with the issues and questions raised regarding the new unit set aside, will inhibit trading. In fact, there are owners in the state that have installed state of the art NOx controls on some units, but nevertheless have NOx emissions greater than the proposed allocations. Due to the nature of the proposed program design, U.S. EPA cannot assume that wide-spread trading will occur to 'make up' for t~e short fall in allocations for certain units. With such insufficient allocations, if any allocations are left at the end of the year sources will likely bank for future years rather than trade due to the significant repercussions that occur when assurance provisions are triggered. [EPA-HQ-OAR-2009-0491-2793.2, p. 6]
Ohio EPA has concerns regarding the methodology to determine allocation budgets based on actual emissions. U.S. EPA must use appropriate years representative of normal operation when calculating allocations based upon actual emissions. [EPA-HQ-OAR-2009-0491-2793.2, p. 8]
a. Ohio EPA is concerned with what appears to be an arbitrary decision; using quarter 4 of 2008 and quarters 1, 2 and 3 of 2009 to establish 2012 budgets - both of which were low demand years. Nevertheless, U.S. EPA appears to believe that this time period accurately represents normal emissions from these sources. U.S. EPA should recognize that the nation, and particularly the Midwest, was in a severe economic downturn during 2008 and 2009. [EPA-HQ-OAR-2009-0491-2793.2, p. 8]
b. Ohio's budget, and unit specific allocations, are being established based on a specific period of time, a time of economic crisis, without any future adjustments being considered to those base budgets taking into account improvement in the economy, and therefore, demand. The variability limits are not sufficient to make up for the use of severely low demand years when calculating base budgets. In addition, some units were not operating for some or all of this· period in order to install controls to address CAIR. It appears from the technical support documents that U.S. EPA intended to substitute other quarters in the calculations when emissions were zero; however, if emissions were drastically under previous quarter's emissions (e.g., a unit may have operated for only a small part of a quarter) there was no such adjustment. In many cases, units are allocated budgets for 2012 and 2013 ba~ed on the assumption that demand will be as low as it was in 2008 and 2009. Such units may be forced to be underutilized if demand does improve. [EPA-HQ-OAR-2009-0491-2793.2, pp. 8-9]
State of Wisconsin, Department of Natural Resources
Once emission budgets are set, EPA should consider default alternative mechanisms within the FIP for allowing states to distribute allowances, such as providing the simple formulas for distribution of allowances within a trading program. Wisconsin disagrees with solely relying on the Integrated Planning Model (IPM). [EPA-HQ-OAR-2009-0491-2829.2, p.2]
EPA needs to primarily depend on air quality results instead of control costs in defining EGU responsibility to remedy significant contribution and to set final emission budgets.
State final emission budgets (2014) need to be set with a stronger linkage to residual air quality impact from the EGU on downwind sites compared to the current proposed linkage of limiting emission reductions by an arbitrarily low cost threshold. EPA has set which states have contribution reduction responsibility based on air quality impact, but appears to default to a modeling of the most efficient regional EGU control program based exclusively on cost-effectiveness. [EPA-HQ-OAR-2009-0491-2829.2, p.7]
In defining significant contribution, EPA should place a greater emphasis on air quality impact (contribution) remedy than the assessed state-by-state marginal control cost-effectiveness of proposed remedy in the setting of the 2014 state budgets for EGU reductions. Issues are both legal and a concern for some level of EGU system control installation equity between nearby states and between facilities with differing coal types which are dispatched within the same electricity markets. In the setting of budgets and within its allocation mechanism supporting a preferred trading program, EPA's budgets and allocations appear to reward states and utility systems that have delayed the longest in setting firm emission control installation schedules - whether the demonstrated progress results from consent decrees, state policies, other program compliance or basic corporate direction. [EPA-HQ-OAR-2009-0491-2829.2, p.7]
Modeling of the depth of the residual contribution problems shown after the implementation of the proposed remedy may also be biased low regarding summer sulfate and winter nitrate impact on PM formation (potentially up to 10% average and higher at peak). This suggests certain source areas might meet thresholds for no residual contribution during the 2nd and 3rd quarters under the 2014 remedy assessment when in fact residual contribution from the EGU sector still needs reduction in all seasons. This bias is inherent in the most current modeling platforms and needs to be accounted for - if not in the Transport Rule #1, certainly in following program steps to address 110(a)2(D). [EPA-HQ-OAR-2009-0491-2829.2, p.7]
Overall Budget Setting Framework
Summary - The program first needs to focus on achieving reasonably fixed state EGU emission budgets (including variance in EGU operation) that are identified for addressing significant contribution. The timing for meeting final budget levels by 2014 or in pursuant phases (if necessary) must follow technical feasibility. The Transport rule default allocations for 2012 and 2013 need to more accurately reflect actual operations or CAIR 2010 allocations. Allocations for 2014 and after need to be equitably distributed on a basis other than IPM predicted emission levels with provisions for periodic re-distribution such as every five years. At a minimum EPA needs to provide the States default alternative mechanisms within the rule for distributing allowances based on heat input and generation output and provide abbreviated SIP pathways. Full emissions trading and reasonable flexibilities should be allowed for the interim years (2012 and 2013) with trading increasingly limited in 2014 and after towards addressing full EGU significant contribution in a fashion that is creditable towards attainment demonstrations. [EPA-HQ-OAR-2009-2829.2, p.8]
Alternative allocation methods - EPA should provide default FIP allocations or mechanisms within the rule for distributing allowances on a heat input or output basis. If such alternatives can not be directly provided they should be allowed through abbreviated SIP mechanisms. Any method considered should provide a mechanism to periodically update the allocation of allowances. [EPA-HQ-OAR-2009-2829.2, p. 11]
EPA requested comment on alternative approaches, specifically on a heat input basis, for allocating allowances to affected sources. Wisconsin prefers EPA to use a historic baseline of either heat input or generation output versus IPM modeled emissions. The best approach, however, is to use generation output which is consistent with any potential greenhouse gas requirement. [EPA-HQ-OAR-2009-2829.2, p. 11]
Wisconsin feels aligning allocations based on actual operation instead of emissions is more appropriate for addressing electric reliability and for the equitable distribution of control effort among utilities. For units recently added to the fleet, EPA can apply the current proposed allocation method of assuming reasonable capacity factors and actual emission rates. Use of available actual year data has the benefit of collecting for deficiencies in the IPM modeling inputs and results. [EPA-HQ-OAR-2009-2829.2, p. 11]
EPA has used historic operational information under the CAIR rule and in evaluating variance needs under the Transport Rule. If EPA does not use historic activity data then, at a minimum, EPA should use the heat input or generation modeled by IPM rather than emissions to distribute allowances. In using heat input or generation the allocation of NOx allowances should be inclusive of all sources in the program. For S02 the appropriate method is to distribute allowances over only those sources that significantly contribute (e.g. - just coal EGU units or units fired by any fuel above a minimum sulfur content). [EPA-HQ-OAR-2009-2829.2, p. 11]
Whether under the proposed FIP allocation scheme or an alternative approach, EPA should provide a mechanism for periodically updating the allocation of allowances. It is not appropriate for allocations to remain fixed into the future as the generation fleet will change and dispatch evolve in response to actual generation requirements, renewable generation requirements, and future environmental regulations. EPA's current approach of placing retired unit allowances into the new source set-aside after seven years is not adequate to address these issues. An updating system was the default approach incorporated into EPA's CAIR model rule. And as adopted in the CAIR NOx SIP, Wisconsin found a five year window of rolling updates based on output generation to be appropriate for addressing these multiple issues. [EPA-HQ-OAR-2009-2829.2, p. 11]
To address alternative approaches, Wisconsin requests EPA incorporate a default mechanism into the finalized Transport Rule. This can best be done by simply incorporating the appropriate formulas for allocating allowances based on both generation output or heat input approaches. The states should be provided this elective directly within the rule. This serves to allow each state to determine the most appropriate approach for a seamless transition between the CAIR rule and Transport Rule. Within such a structure states can fully address technical corrections to base data which may affect distribution of allocations. Incorporating these approaches by default into the rule is critical as EPA's current approach does not provide states enough lead time to adopt a separate SIP. EPA could also provide the states a mechanism for adopting abbreviated SIP such as that provided under the CAIR rule.  [EPA-HQ-OAR-2009-2829.2, pp.11-12]
Another approach to providing alternative allocations is for EPA to utilize existing CAIR NOx SIP allowance information. The Transport Rule eliminates CAIR SIP mechanisms for several states which appear to meet the legal issues being addressed by the Transport Rule FIP allocations. Wisconsin is one such state with it's CAIR SIP rule for distributing CAIR NOx allocations based on recent generation output of the affected units. Other such states with an output allocation system provided in their CAIR SIP include Arkansas, New York, and New Jersey. Wisconsin asks EPA to strongly consider working from existing CAIR SIP NOx allocations which meet the necessary legal criteria, such as CAIR NOx output based allocations, as a basis for distributing Transport Rule emission budgets for both 2012 and 2014. As noted above, new unit information would need to be added and would adjust actual total allocations. This allocation of FIP allowances can be accomplished by proportionally distributing the Transport rule NOx and S02 emission budgets according to the CAIR NOx allocation of allowances. And in Wisconsin's case, where the NOx CAIR 2010 emission budget is less than the proposed Transport Rule NOx emission budget, EPA should consider directly adopting Wisconsin's CAIR NOx allocations as default TR NOx FIP allocations. Directly adopting Wisconsin's CAIR NOx allocations for the 2012 and 2013 TR NOx allocations is also consistent with EPA's intent to reflect current existing controls operated on a year round basis and accounting for operational flexibility. For reference Wisconsin's allocation of NOx CAIR allowances for 2010 through 2014 and a calculated basis for new units since the implementation of CAIR is provided in Appendix A [See EPA-HQ-OAR-2009-2829.3, p.1 for comments pertaining to Appendix A] and can also be referenced under NR 432.03, Table 1, Wis. Adm. Code. [EPA-HQ-OAR-2009-2829.2, p. 12]
Transport Rule default allocations - The Transport Rule as proposed will provide a default allocation of allowances based on IPM's predicted unit-by-unit absolute emissions levels. This approach is not preferred but technical comments and corrections are provided here and will be addressed again in comment to the current Transport Rule NODA (Sept 1,2010). [EPA-HQ-OAR-2009-0491-2829.2, p.12]
From a general approach, allocating allowances according to IPM modeled emissions biases control requirements to specific emission units. This automatic bias may not be consistent with best approaches or determinations made by state agencies which regulate electric utilities such as our Wisconsin Public Service Commission. Once again, the use of IPM may be consistent with setting state level requirements and assessing program control costs and schedules. But it is not appropriate for setting individual unit control requirements as criteria outside the IPM universe are part of a source and state decision process for applying controls. [EPA-HQ-OAR-2009-0491-2829.2, p.12]
From a practical point of view there are several concerns that must be addressed in using IPM results for setting allocations. In setting the default FIP allocations EPA directly applied the IPM predicted emissions for each unit and removed an additional 3% for the new source set-aside. By 2014 utilities may be able to respond to an allocation of allowances as provided through IPM modeling. But for the initial 2012 emission requirement this approach is likely to set more stringent and problematic requirements, at least for some individual units, than intended by EPA. These problems are amplified for facilities that have installed state-of-the-art emission controls that are already operated in an optimized fashion. If the IPM model is not accurate, sources which are not part of a larger system can be made dependent on purchasing emission credits to demonstrate compliance. At best if EPA corrects IPM inputs and 2012 emission budgets to reflect existing controls (as previously discussed) this leaves little room for operational variability (see previous comment on setting the level of the 2012 budgets). [See [EPA-HQ-OAR-2009-0491-2829.2, p.10 for comments pertaining to setting the level of the 2012 budgets; EPA-HQ-OAR-2009-0491-2829.2, pp.12-13]
A better approach to other sector significant contribution could be based on a simple unit-specific performance limit matrix rather than attempting a trading program for emission credits between fundamentally differing industries with differing financing and economic backdrops. An averaging component for single owners with multiple facilities could provide some level of flexibility as long as trading occurs within single area air sheds [but potentially could occur on an interstate basis if in close proximity]. [EPA-HQ-OAR-2009-2829.2, p. 13] 
Preferred Program Approach - Background and Starting Budget Level - Technical assessment of the preferred inter-state trading/banking program remedy indicates a high sensitivity to levels of allowed banks and the net level of out-of-state purchased allowances that may be used for compliance in a given year. EPA has also indicated that any effort to carry forward banked CAIR program allowances into the Transport Rule would confound the intended emission reduction intent of the program during the critical 2012-2014 period and might ultimately lead to banks of allowance credits at a scale that would forestall controls installations needed for attainment. Therefore Wisconsin finds EPA's approach to current banked emissions reasonable. EPA needs to start the new FIP programs at budget levels achievable in 2012, but with modest flexibility built in to address both variability and normal planned compliance margins. The real target control level for the first phase should come in 2014 in order to preclude the need for standing allowance banks in 2012. [EPA-HQ-OAR-2009-0491-2829.2, p.8]
Wisconsin does fully understand EPA's need to align the 2012 and 2013 allocations with actual emissions based on existing controls for both S02 and NOx emissions if it intends to start an all new banking program. For NOx, the most appropriate means may be to utilize existing CAIR NOx allocations (as discussed below). Another approach is for EPA to use the established CAIR base activity level and incorporate new units newly operated since that time. EPA can simply address existing controls by using the base activity date along with the appropriate emission rates. [EPA-HQ-OAR-2009-0491-2829.2, pp.8-9]
Banks under the new programs should build adequately between 2012 and 2014 and if targets are appropriately deep will naturally limit the scope of excessive new bank build-up through 2015. Wisconsin has consistently supported separation of Title 1 and Title 4 trading programs and agrees with EPA's interpretation of the Court finding indicating a need here for that separation. [EPA-HQ-OAR-2009-0491-2829.2, p.9]
The finalized assessment of significant contribution developed in support of this Transport Rule needs to provide more certainty of needed additional reduction targets from both EGUs and non-EGU sectors, particularly for NOx emissions, in light of the revised ozone standard now expected later this fall. [EPA-HQ-OAR-2009-0491-2829.2, p.13]
If EPA determines that an interstate trading/banking program is the final rule structure, it should limit future allowance allocation to ensure the current allowance allocations don't confound the timing of necessary additional contribution reduction achieved via actual emission controls installations by the sector. Program structure should detail all aspects including remedy timing for additional controls phases. As noted earlier, a major remedy improvement in this rule would be the next budget adjustment years and a target scope for the additional reduction levels - even if a range rather than a specific budget amount is included for the later phases in this rule. Wisconsin recommends 2016 as a next budget year after updated 2014 targets for EGOs for both NOx and S02. [EPA-HQ-OAR-2009-0491-2829.2, p.13]
Sunbury Generation LP
Under the Proposed Rule, emission allowance allocations to existing units are determined based on the unit's fractional share of emissions, as reflected in the emissions budget for the state in which the unit is located. Accordingly, under EPAs proposed approach, noted above, 'the allocation is adjusted downward, if the unit has additional pollution controls projected to be online by 2012.' 75 Fed, Reg, 45309. [EPA-HQ-OAR-2009-0491-3615 ,p.4]
Relative to Sunbury, in determining the proposed SO2 allowance allocations for the affected EGUs at the Facility, EPA considered (and is effectively requiring) emissions reductions achievable though the installation of the Proposed Scrubber by January 2012. See 'Attachment' to TSD for the Transport Rule, ('State Budgets, Unit Allocations, and Unit Emissions Rate: Field Descriptions for Detailed Unit-Level Data', EPA, Office of Air and Radiation, July 2010, Document ID No. EPA-HQ-OAR-2009-0491-0071.4 (available at http://www.regulations.gov/search/Regs/home) (identifying a downward '[a]djustment made to 2012 projected annual SO2 emissions', based on a 'dispatchable FGD [i.e., scrubber expected to be online by 1/112012' for certain boilers at the Facility). That is, Sunbury's SO2 allowance allocation was adjusted downward on the basis that the Facility took steps to secure authorization to install the Proposed Scrubber. However, as stated above, the Facility has not yet moved forward to any significant extent with the construction of the Proposed Scrubber. Thus, the Facility cannot provide any assurances, at this time, that it will complete installation of the Proposed Scrubber in the future. [EPA-HQ-OAR-2009-0491-3615, p.4]
EPA's proposed approach of requiring emission reductions that would (theoretically) be achieved by operation of a scrubber that may not be constructed at some future time, where there is currently no applicable statutory or regulatory basis for requiring such installation, is improper, arbitrary and capricious, and unsupported by any applicable legal standard. Instead, EPA's calculation of allowance allocations under the Proposed Rule should be based on the Facilty's current actual emissions, taking into account only those control devices which are already in operation, and for which there exists a legal basis requiring such operation. At a minimum, any consideration of the operation of the furure operation of a control device that is not currently operating must relate only, if at all, to the extent that the control device is assured to be operating, and legally required to be operating, by the relevant compliance dates. [EPA-HQ-OAR-2009-0491-3615,pp.4-5]
Because there is no legal basis requiring the installation of the Proposed Scrubber at the Facility, Sunbury's allowance allocation. under the Proposed Rule should not be based on the assumed installation and operation of the Proposed Scrubber by 2012. Further, even if it is determined that it is appropriate, for purposes of determining allowance allocations, for EPA to assume operation of a planned control device for which there is no legal basis supporting its installation, it is not feasible for Sunbury to install the Proposed Scrubber before January 2012. Indeed, by EPA's own reasoning, 'it is not possible to require the installation of post-combustion SO2 controls (scrubbers) ... before 2014 ... because it takes about 27 months to install a scrubber .... ' 75 Fed. Reg. 45281. Instead, EPA acknowledges that SO2 reductions from operating existing Scrubbers - as opposed to scrubbers that are simply planned and have not yet been built - up to their design removal efficiencies is possible by 2012. Id. See also 75 Fed. Reg. 45273 (EPA acknowledges that it takes approximately 27 months to build a ... Scrubber ... to reduce SO2 emissions ... , so if the [proposed Rule] is finalized in mid-2011, emissions reductions from scrubbers by 2012 or 2013 can only reasonably be achieved if that Scrubber either exists today, or it is currently under construction'). As explained above, the Proposed Scrubber has not yet been constructed, and the Facility has not moved forward to any significant extent with the construction of the Proposed Scrubber, nor are there any other scrubbers currently in operation at the Facility. [EPA-HQ-OAR-2009-0491-3615, p.5] 
EPA's proposed methodology for determining unit-specific allowance allocations under the Proposed FIP is inappropriate and inequitable as applied to Sunbury
To determine tho proposed allowance allocations for affected EGUs in Pennsylvania, EPA considered several factors, including projected emission levels. EPA attempted to project emission rates based on its own prediction of future anticipated generating rates, as reflected in different modeled projections. EPA then uses these predictions to determine allowance allocations for facilities. [EPA-HQ-OAR-2009-0491-3615, p.5]
Relative to Sunbury, EPA apparently predicts a decline in operating rates in future years. In turn, EPA proposes to allocate unit-specific allowances to Sunbury at a substantially reduced rate, in large part due to the fact that EPA projects that the Facility will operate at reduced capacity compared to current levels. [EPA-HQ-OAR-2009-0491-3615, p.5]
EPA's projected rates of generation clearly understate reasonable estimations of future operations and are inconsistent with the complete operating history for the Facility. Instead, in order to more accurately forecast future operating rates based on current data, EPA should, for purposes of determining allowance allocations under the Proposed Rule, base its projected generation rates for the Facility on representative operating conditions for the facility. With respect to Sunbury, operating levels (heat input rates) during 2007 and 2008 constitute an accurate representation of the Facilty's typical operating rates, and are consistent with Sunbury's expectations for future generation. Prior to 2007, the current owners of the Facility had not completed measures to ensure consistent operation of the facility at levels approaching operating capacity and historic operating rates. In addition, following 2008, several factors, including damage to an operating unit and reduced electricity demand arising from the struggling economy, caused a non-representative decline in generation. Based on the Facility's current operating conditions, Sunbury fully expects that future generating rates will be consistent with those demonstrated between 2007 and 2008. Use of 2007 and 2008 generating rates in predicting future operating rates for the Facility would yield meaningfully higher - and more accurate - allowance allocations for Sunbury under the Proposed Rule. [EPA-HQ-OAR-2009-0491-3615,pp.5-6]
Contrary to EPA's proposed approach for the Sunbury Facility, EPA proposes to provide increased allowance allocations to other EGUs, many of which are not materially distinguishable from the Sunbury Facility relative to issues bearing upon future generation rates. In this way, the Proposed Rule reflects judgments by EPA regarding relative electric generating distribution among various sources. By proposing allowance allocations consistent with these relative electric generating rates, EPA would effectively promulgate regulatory standards that drive the distribution of generating capacity among source types. Any such judgments regarding relative electric generating capacity among affected sources are completely inappropriate for EPA to determine, inconsistent with the stated objectives of the Proposed Rule, and contrary to statutory mandates imposed on EPA through the CAA. [EPA-HQ-OAR-2009-0491-3615, p.6]
Tenaska, Inc.
Tenaska believes the Proposed Transport Rule would achieve beneficial results faster if allowances are allocated based on heat input, rather than emissions, over the three previous years. This information is readily available and is consistent with agency past practice. Use of emissions in allocating allowances promotes continued emissions and penalizes low emission density sources. Use of heat input encourages higher efficiency and lower emissions. [EPA-HQ-OAR-2009-0491-3705,p.3]
The allowance allocations should be updated at frequent intervals (e.g., triennially) based on the previous three years' operating data. Such reallocation should apply well-articulated criteria that reward efficiency and low emissions and account for recently completed rulemakings under other programs.  [EPA-HQ-OAR-2009-0491-3705,p.3]
Retired units should not continue to receive allowance allocations beyond the triennial cycle in which retirement occurs. Retired unit allowances would then be available to new and existing units which will be obligated to increase operations to provide power in place of the retired units. [EPA-HQ-OAR-2009-0491-3705,p.3]
The Current Situation in the Energy Markets - Why Adiustments to Allocation are Necessary.
As a commodity, energy has always been subject to uncertainty caused by business cycles and attendant fluctuations in energy prices, as well as the high capital costs and long lead times of developing new energy infrastructure . To some extent, power producers have been able to manage these business risks by entering into long-term contracts with power purchasers. With the financial risks in check, the projects have been able to absorb greater risks in other areas such as accepting lower emission limits as Best Available Control Technology (BACT). The tradeoff is that the power generator has little, if any, say over when it must operate; the customer makes this decision based on market conditions. [EPA-HQ-OAR-2009-0491-3705, p.5]
EPA is proposing to base allocation of allowances on a time period in which market conditions did not favor operations of low-emitting sources as much as they do now and are projected to favor them in the future. This problem is compounded because EPA's proposed use of emissions as a measure of allocation favors higher-emitting sources by definition. Thus, there is a real risk that allocations based on time periods during which low-emitting sources were not called on to operate much will restrict those low emitters in the future. This is especially true in states where there are limited allowances available for intrastate trading and limited interstate trading . Moreover, the long-term nature of the contracts increases the risk that one party or the other will suffer a disproportionate risk of unforeseen or inequitable regulatory or other costs. Thus, while long-term contracts coupled with equitable regulation promotes more financially stable, lower-emitting generation. In contrast, inequitable and inflexible regulation can lead to adverse consequences regardless of intentions.  [EPA-HQ-OAR-2009-0491-3705,pp.5-6]
Events since 2008 have compounded the complexity and uncertainty in the energy marketplace as never before. These uncertainties can be broken down into: (1) demand uncertainty ; (2) supply uncertainty ; (3) distribution uncertainty ; (4) regulatory uncertainty ; and (5) price uncertainty. [EPA-HQ-OAR-2009-0491-3705, p.6] [[See Docket Number EPA-HQ-OAR-2009-0491-3705, pp.6-11 for a detailed discussion on these uncertainties.]]
Proposed Initial Allocation Based on Heat Input Over Previous Three Years
EPA specifically requested comments on the proposed allowance allocation system. See 75 Fed. Reg. 45309. EPA's proposal would initially allocate allowances based on actual heat input in 2008 and emissions rate in 2009, as well as projections of emissions from economic modeling. This is flawed for three reasons. First, using actual and projected emissions as a basis for estimating state budgets is reasonable for the pollutants in question because EPA's objective of reducing emissions at the state level. Nevertheless, allocation to units on the basis of emissions, actual or projected, rewards units with high emissions without regard to heat input, output or efficiency . As EPA recognizes, under this scheme, units which invested in control equipment received fewer allowances than those units which failed to do so. See 75 Fed. Reg. 45311 . Such lower-emitting sources are placed at a disadvantage . This allocation scheme is contrary to the purpose of the Transport Rule, which is to reduce the emission and transport of ozone and PM2.5 precursors by encouraging investment in control equipment. The best way to achieve that goal is to allocate based on output . Doing so would reward lower emission intensity (i.e., emissions per unit output and efficiency of the units) . One might argue, however, that this would be inequitable to larger, older, less-controlled facilities. Therefore, a compromise would be to allocate based on the heat input of the unit. EPA suggests this approach and requested comments on it. Id. This would reward efficiency while not penalizing older generating units. There is precedent in the Clean Air Interstate Rule and the NOx SIP Call where heat input was used as a basis for unit allocations. Because use of heat input would affect allocation among units within a state and not allocation among states, it does not implicate the issues caused by interstate trading in the CAIR rule. [EPA-HQ-OAR-2009-0491-3705, pp.11-12]
The second problem is in using the selected timeframe (2008 heat input and 2009 actual emissions) for allocating allowances . No one year is 'representative' but 2008 and 2009 are anomalies. As explained above, due to the financial meltdown and unusually mild weather, that was an unrepresentative period in the electric generating industry. As the U.S. Energy Information Agency stated,
In 2009, U.S. energy markets continued to show the impacts of the economic downturn that began in late 2007 . After falling by 1 percent in 2008, total electricity generation dropped by another 3 percent in 2009. Although other factors, including weather, contributed to the decrease, it was the first time in the 60-year data series maintained by the EIA that electricity use fell in two consecutive years. [EPA-HQ-OAR-2009-0491-3705,pp.12-13]
U.S. EIA 'Energy Outlook 2010,' www.eia.doe.gov/oiaf/aeo/pdf/0383(2010).pdf. The preamble to the Proposed Transport Rule states that the budget and emission reductions required should be set for the 'average year' (See 75 Fed. Reg. at 45290); such is not the case with 2008-2009 in term of energy consumption, production or emissions . Using 2008-2009 as a baseline year for purposes of allocation will serve only to inhibit economic development. [EPA-HQ-OAR-2009-0491-3705, p.13]
To address the recent volatility in the energy markets, Tenaska suggests that the allocation of allowances under a state budget be based on a unit's maximum heat input over a three-year period as a fraction of the sum of all electric generating units' maximum heat input over the same period. This will have the effect of leveling out the playing field and providing 'liquidity' to the allowance market. The result will be an acceleration of economic activity, consistent with the Administration's goals. [EPA-HQ-OAR-2009-0491-3705,p.13]
Third, while Tenaska does not contest the use of projected emissions from Integrated Planning Model (IPM) runs for the establishment of state emission budgets, such modeling should not be used for unit-level allocations. While IPM might be adequate for state level modeling, the unit-level results from the IPM dispatch model are driven by subjective input assumptions and distorted by modeling limitations . The future price of natural gas is an example of a subjective input assumption. There is considerable uncertainty surrounding that price due to the recent shale gas developments and fluctuating demand. In the IPM model, EPA uses an input assumption for the projected price of natural gas and any such number is certain to be wrong. This input alone can significantly alter the dispatch result for gas-fired generation. Other inputs which impact projected unit-level generation include economic growth, demand intensity, renewable generation additions, timing and location of plant retirements, timing and location of plant additions, and market structure. [EPA-HQ-OAR-2009-0491-3705,pp.13-14]
As an example of its inherent limitations, IPM models the United States electric markets as a number of large market zones with limited electric transfers between those zones . While this simplification is common and necessary for modeling purposes, this is not how the majority of markets covered by the Proposed Transport Rule are actually dispatched. MISO, PJM, NYISO and ISONE are nodal markets where each plant dispatches based on its relative daily bid price and the power price at its point of interconnection . Thus, the IPM model will understate the generation from units in constrained areas while overstating the generation in unconstrained areas. [EPA-HQ-OAR-2009-0491-3705,p.14]
It is not clear whether IPM is able to accurately model unit dispatch constraints such as start costs, start fuel costs, minimum run time after a start, minimum down time after a shutdown, minimum operating levels of a generating unit with a corresponding heat rate, etc . These unit-level modeling inputs will significantly impact projected unit level generation. [EPA-HQ-OAR-2009-0491-3705, p.14]
Finally, we are unable to reproduce the allocations in the technical support document and we attribute this deficiency to the IPM model and its inputs. Use of past heat input information poses no such problem. EPA could promptly make allocations based on heat input and submit them for review in a notice of data availability. [EPA-HQ-OAR-2009-0491-3705, p.14]
Allowance Allocation Should be Updated at Planned Intervals.
EPA has recognized that it will be necessary to update the state budgets and the allocations of allowances in light of new rules. 75 Fed. Reg. at 45301 . Otherwise, entirely new rulemakings would be required to update the standards or there would be a potential conflict between the Transport Rule and the new rules, as well as with SIP amendments to implement them. Periodic updating is also necessary because of the dynamic changes in the electric generation sector. Simply put, and borrowing from the Securities and Exchange Commission disclaimer language: '[p]ast performance does not guarantee future results.' Data shown in Figures 2 and 3 show that combined-cycle natural gas generation has quadrupled over the last ten years, while other forms of generation have been either declining or stable . It is highly likely that natural gas-fueled power generation will continue to increase significantly in the future . The periodic updates, i.e., at least triennially, would allow for adjustments to accommodate increased use of clean fuels. This three-year period is consistent with EPA's plan to record new allocations due to the new unit set aside and retirement. See 75 Fed. Reg. 45311. [EPA-HQ-OAR-2009-0491-3705,pp.14-15]
Tenaska also believes it is important for orderly investment in new energy infrastructure to have clear rules for the triennial review. If those principles are changed, then investment will be discouraged. Therefore, it is best to put in place a set of rules indicating how the allocations will be changed in the future so that behavior can be modified accordingly . We have seen from the vacatur of the CAIR rule, that allowance markets fall into chaos when the rules are changed and values are seriously discounted. Thus, it is important that the Transport Rule be made with provisions that allow updates to take into account changes in input in the various states and units within those states. [EPA-HQ-OAR-2009-0491-3705,p.15]
In addition to changes in the actual emissions and operations of EGUs going forward, we can contemplate that state budgets will also need to be changed to accommodate the anticipated effects of new NAAQS and other proposed rules. A rule that can be updated to accommodate these anticipated changes will be inherently more stable, offer greater liquidity, and support investment in lower emitting sources than an inflexible rule with fixed budgets. Such a rule would have to be scrapped if state budgets must be tightened in the future. The Courts have not allowed redefinition of the value of Acid Rain Program allowances. This suggests that permanent allowance allocations place an unnecessary regulatory burden on the proposed rule to anticipate needs for future adjustments in state budgets and the related unit allocations. [EPA-HQ-OAR-2009-0491-3705,pp.15-16]
Retired Unit Allowances Should Be Auctioned.
We also suggest that any retired units' allowances be auctioned in each state as part of the triennial readjustment . This would gradually remove from the market the distorting effect of free allowance allocations based on historical operations or, even worse, historical emissions. Allowance auctions align the markets with environmental performance and encourage the use of cleaner, more efficient technologies . Auctions also assure availability of allowances in a system with constrained interstate trading. [EPA-HQ-OAR-2009-0491-3705, p.16]
Texas Chemical Council
V. EPA Did Not Provide Enough Allocations for Many Texas Cogeneration Facilities
Many Texas cogeneration facilities were not provided enough allocations under the EPA proposal to continue operating during the summer ozone season. It is also unclear how EPA developed a basis for determining allowances, a fact which is extremely disconcerting. [EPA-HQ-OAR-2009-0491-2815.1, p.5]
Vectren Corporation 
Proposed Transport Rule unfairly disadvantages clean units such as Vectren's. [EPA-HQ-OAR-2009-0491-2654.1, p. 3]
What is perhaps a glaring example of the law of unintended consequences, EPA's proposed cap-and-trade rule will in some states such as Indiana unfairly disadvantage power companies that have already invested in pollution controls by awarding more emission credits to those utilities that have not installed controls. This is due to the unprecedented change in the approach that EPA has used for allocating emission allowances. [EPA-HQ-OAR-2009-0491-2654.1, p. 3]
Under the current Transport Rule proposal, EPA would distribute allowances based upon a facility's historic emissions. By contrast, under the Acid Rain Program, the NOx SIP Call, and the Clean Air Interstate Rule, allowances for NOx and S02 were allocated based upon a unit's heat input, or the amount of fuel used by the generating unit. This essentially created a level playing field for all similarly situated coal-fired units. Those units that were already controlled received allowances based upon a 'neutral' factor (i.e. heat input). Thus, they were not penalized for having already made the necessary emission reductions. Those companies who chose to construct pollution controls were able to sell excess allowances to offset the cost of installing the controls. Indeed, in highly regulated service territories such as Vectren's, 80-90% of the proceeds of the sale of emission allowances are credited back to the customer. [EPA-HQ-OAR-2009-0491-2654.1, p. 3]
A review of the emission allocation tables provided in the proposed rule clearly illustrates the inequities created by this new approach to the emission allowance allocation methodology. Vectren's units are already controlled and emissions are already low, yet an emission allowance allocation methodology based solely upon historic emissions, and not heat input, places the emission reduction baseline off an already low emission rate. Thus the starting point for further emission reductions for a unit with controls is significantly lower than for an uncontrolled unit. A review of the emission allowance allocation tables attached to the proposed rule clearly indicates that EPA allocated sufficient emission allowances to uncontrolled units in 2012 to allow those units to continue to operate uncontrolled until 20 I4. Thus, EPA is providing sufficient allowances to uncontrolled units to allow them to maintain 'status quo' until 2014, while controlled units such as Vectren's are required to make significant reductions in 2012 - a full two years before the uncontrolled units - and then further significant reductions in 2014. [n addition, a company that takes one of these uncontrolled units off-line for significant periods of time to construct a scrubber and / or SCR will be able to bank the resulting excess allowances for future use. Since clean units are not provided these excess allowances, companies with clean units such as Vectren that have already made the investment in pollution controls will not have the same opportunity to bank excess allowances, which sets up a competitive disadvantage and unintended penalty for having constructed actual controls on its units to comply with previous EPA emission reduction programs. [EPA-HQ-OAR-2009-0491-2654.1, pp. 3-4]
EPA unfairly used a recessionary emissions baseline year. By using an unrepresentative and depressed recessionary year for an emissions baseline, EPA has in effect imposed a 'double whammy' on clean units such as Vectren's. As indicated above, controlled units are already placed at a competitive disadvantage under the proposed Transport Rule by EPA's use of an altered emission allowance allocation methodology based solely upon historic emissions (which were already low for these units) instead of a neutral heat input factor. Compounding that clean penalty is the fact that the historic emission period that EPA bases its emission reduction requirements on was historic for its recessionary and steep decrease in generation (and thus emissions), and simply not representative of future electric demand and necessary generation to meet that demand. As a consequence, EPA is requiring steep reductions II·om an unrepresentative and artifically low emission reduction baseline. [EPA-HQ-OAR-2009-0491-2654.1, p. 4]
If despite the fact that its proposed emissions allocation methodology imposes a clean penalty on controlled units such as Vectren's EPA should stick with this flawed methodology in its final rule, at a minimum EPA should re-allocate emission allowances based upon a representative three year average emissions baseline for the affected units. While there may be differing opinions on how long it will take for the economy to rebound from its recessionary lows in 2009, no one bclieves the economy - and thus industrial demand for electric generation - will stay permanently depressed. Within the last 6 months Vectren has been fOliunate to see increased demand from a new industrial customer. Any economic recovery resulting in increased demand for generation was simply not taken into account when EPA established its recessionary emissions baseline, and makes the already low individual plant emission caps even more challenging to meet as the economy improves. [EPA-HQ-OAR-2009-0491-2654.1, pp. 4-5]
Virginia Department of Environmental Quality (VDEQ)
Activity data from the Clean Air Markets Division (CAMD) website or other sources rather than IPM projections should be used to allot allocations of SO2 and NOx to units in future years. Activity data was the basis for the NBTP allocations as well as the CAIR allocations. Only a small number of units do not report 12 months of activity data to CAMD. For those units that do not report 12 months of activity data to CAMD, additional activity data may be garnered from a variety of sources such as the National Emissions Inventory (NEI), State inventory databases, and the Energy Information Administration. EP A should not use IPM to estimate future activity data. Use of IPM adds an enormous amount of uncertainty to an already uncertain process. IPM is proprietary software that does not allow stakeholders to review decisions used to create predictions nor does it allow independent verification of the results without an unacceptable associated cost. Past use of IPM results for forecasting activity necessitated significant data revisions due to forecasts of unrealistic or inappropriate operations of significant emissions units in or near sensitive regions such as nonattainment and maintenance areas. Previous years' activity data, on the other hand, is readily available from a variety of sources in the public domain. [EPA-HQ-OAR-2009-0491-2595.1, pp.2-3]
Virginia Independent Power Producers
EGUs Must Have Access to Sufficient Allowances To Meet Customer Demand for Electricity.
AU EGUs - utilities, independents, cooperatives and others - operate in the public interest in that they provide a vital commodity - electricity - for public consumption on demand. The entire economy and well being of the Nation depend on the availability of sufficient quantities of affordable electricity available on an 'as demanded' basis. A regulatory system that artificially restricts the availability of required emissions allocations will threaten the integrity of the electricity supply system and, by extension, the well being of the Nation. [EPA-HQ-OAR-2009-0491-2640.1, p.3]
Unlike other industries, electricity producers (a) cannot feasibly store their product in inventory and (b) cannot tolerate supply disruptions. If EGUs are not provided sufficient emissions allocations to operate in the public interest to supply electricity as demanded by customers, supply disruptions will occur. In the electricity industry. supply disruptions are not matters of inconvenience; they are matters affecting the health, welfare and employment opportunities of the citizenry at large. [EPA-HQ-OAR-2009-0491-2640.1, p.3]
Furthermore, VIPP's member companies sell electric capacity and energy under longterm Contracts to Dominion (Virginia Power). The facilities of the member companies are operated pursuant to contracts with Dominion that do not allow for the pass-through of costs associated with emissions allowances. Unlike a utility that can seek to recover costs associated with emissions allowances from its ratepayers, or a merchant generator that can recover such costs through the market price of electricity, long-term contractor generators such as VIPP's member companies can be severely impacted by the requirement to purchase emissions allowances. Further. long-term contractor generators do not exereise control over when their facilities can be dispatched, but must operate whenever called upon by their customers. [EPA-HQ-OAR-2009-0491-2640.1,p .3]
For these reasons, it is imperative that independent power producers with long term contracts (like VIPP's member companies) be given sufficient emissions allocations to generate electricity as demanded by customers, and be provided access through intrastate and interstate trading mechanisms to acquire allowances as needed. Failure of the Transport Rule to provide sufficient allocations and access to efficient trading mechanisms has the potential to plunge the Nation into a worse and deeper recessionary period than already exists, causing great harm to the Nation's citizens, its businesses and industries. [EPA-HQ-OAR-2009-0491-2640.1, pp.3-4]
Congress previously recognized that long-term comract generators do not have a mechanism to pass through new environmental costs to their power purchasers, and exempted these plants from the Acid Rain Program under the  1990 Clean Air Act Amendments so long as the long-terml agreements remained in effect. As Congress has previously done, EPA should recognize the unique situation of long-term contract generators that cannot pass along the costs of emissions allowances to their customers. EPA could do this by allocating to long term contract generators any surplus allowances that remain in the new unit set-aside for any control period in which the long term comment generator 's emissions exceeded its allocation due solely to a return of the facility' s capacity back to pre-recessionary levels. In other words, surplus allowances from the new source set aside would be allocated as needed to a long term contract generator in situations where their emissions increased because the facility's heat input had increased to a level that the generator had, in fact, achieved in any calendar year or ozone season since 2005. This would provide relief for long-term contact generators who experience an increase in utilization from the levels EPA has relied upon in establishing allocations, without providing a permanent allocation that could be sold to others. [EPA-HQ-OAR-2009-0491-2640.1, pp.3-4]
we energies
We support EPA's proposal to continue allocating allowances to retired units during the 3 consecutive years of non-operations plus an additional 3-year period. The time period for this allocation should start, at the earliest, with the first year of the program. [EPA-HQ-OAR-2009-0491-2629.1, p.4] 
We agree with providing allocations to retired units for a limited period of time. Allocating allowances for a limited period time provides a retirement incentive, yet allows for a reasonable transition of allowance availability for new and continuing unit operations. Retaining retired unit allowances for a predetermined length of time also provides a system compliance margin while controls are being added to units that will continue operations. [EPA-HQ-OAR-2009-0491-2629.1, p.4]
EPA's proposed rule should go no further than providing for accurate state allocations, thus allowing the states to apply their knowledge of facility-specific data and current and future operating schemes. This approach was satisfactory under the CAIR rule, and a similar approach would provide continuity between the current and proposed rule. [EPA-HQ-OAR-2009-0491-2629.1, p.4]
We oppose the allocation of the state budgets to individual units as included in the proposed rule. While the mechanics of how these allocations were arrived at are not at all transparent, it appears that these allocations are based on several layers of errors, including errors in the NEEDs database, in the baseline assumptions, and in the IPM outputs. For example, We Energies receives no allocations for our South Oak Creek Units 5&6 and Valley Units 1-4 since the IPM model assumed that they would be retired, and they will not (see section on EPA Assumptions for EGU Retirement, above). [EPA-HQ-OAR-2009-0491-2629.1,p.4]
In addition, the current allocation method rewards units that have not added post-combustion controls, while penalizing those that have already added controls during the time period since CAIR was originally proposed, e.g., We Energies Pleasant Prairie units, where post-combustion controls have been fully operational since 2007 . Therefore, we advocate for state flexibility in determining final allocation budgets, and would specifically support the state budget in the transport rule to be allocated according to the proportions as reflected in the final CAIR budgets. The allocation methodology reflected in the final CAIR budgets are the result of an administrative rules process that considered several iterations of source-specific comments and information submittals. [EPA-HQ-OAR-2009-0491-2629.1, p.4]
Banking of emission allowances is another critical rule component for We Energies. It allows us to balance allowance shortages while additional controls are being installed, and to account for annual fluctuations in generation due to unit outages and unit capacity factors. Banking provisions are critical to maintaining a reasonable compliance margin for unit operations. [EPA-HQ-OAR-2009-0491-2629.1, p.7]
West Virginia Department of Environmental Protection
[[2790.1 p.4-6]]
Proposed Budget Methodology - WVDAQ is unable to fully duplicate the 2012 or 2014 allocations for West Virginia. Some allocations cannot be replicated using the methodology outlined in the proposed Transport Rule preamble. Such a problematic situation does not allow a clear and concise understanding of EPA's allowance allocation methodology.
In the supporting RIA document, EPA explains that the base case includes the Title IV Acid Rain Program, the NOx SIP Call, and states' rules through February 3,2009. CAIR subsumed the NOx Budget Trading Program, and West Virginia repealed its NOx Budget Trading Program rules and submitted the repealed rules to EPA as a revision to the SIP. Therefore, only the NOx SIP Call provisions for internal combustion engines and cement kilns are still on the books in West Virginia. EPA appears to count on the NOx SIP Call in the base case even though the program is effectively dismantled and not in force. WVDAQ believes that because CAIR was ultimately remanded and not vacated, EPA should rely on CAIR for a real-world base case analysis.
Use of IPM Model - WVDAQ questions the use of IPM predictions as the basis of determining emission budgets and allocations. In the past, IPM has delivered mixed results and does not appear to be a good predictor of the future, especially when applied at the source level. EPA has previously indicated that IPM is f!:. solution, not the solution, implying that there are different methods to determine transport emission budgets and allocations. Based on the constraints applied, IPM provides a least-cost solution, but IPM may not be the only method to determine emission budgets and allocations. Our experience with past applications of IPM shows that it can and does make problematic and significant mistakes, such as incorrect predictions of shut down or non-operating units, or applying controls for sources which the owner has no intention of installing.
As an example of the problematic use of IPM, the TSD Allocation Table indicates that IPM projections are used as the basis of the S02 allocations, yet reported emissions data are used as the basis of the NOx annual and ozone season allocations. A review of the docket spreadsheet BADetailedData.xls, on the Allocations and Rate Limits worksheet, under the column headings Heat Input Assumed in Annual NOx Allocation and Heat Input assumed in 2012 S02 Allocation, there are differences of more than 100 percent in the heat inputs which are used as the basis of the NOx and S02 allocations for 2012. For instance, Albright Unit 1 (ORIS Code 3942), has a Heat Input Assumed in Annual NOx Allocation of 2,050,480 mmBtu and a Heat Input assumed in 2012 S02 Allocation of 5,960,450 mmBtu.
In this example, the heat input assumed for Albright's S02 allocations is 290 percent of the heat input assumed for the NOx allocations for the same period. WVDAQ questions EPA's decision to use a different basis (projected vs. reported data), which assumes different heat inputs for the same time periods and for different pollutants. WVDAQ believes that this is but one demonstration of how the use of IPM model results can skew emission budgets and allocations from a reasonable result.
WVDAQ also questions whether it is appropriate to allocate allowances based on IPM predicted emissions for 2012. As previously noted, it is apparent that EPA's decision to base allocations on projected (or even historical) emissions penalizes sources that have installed controls. This observation is of greater concern considering that EPA proposes to allocate to existing units one time, before the Transport Rule cap and trade programs commence. Except for non-operating units, the allocations would be permanent as base amounts, and would not be updated. As such, WVDAQ does not believe it is appropriate for EPA to use IPM projections as the basis ofthe allocations. WVDAQ therefore supports a more appropriate metric, the alternative allocation method proposed in the Transport Rule.
Alternative Allocation Method - EPA requested comment on an alternative methodology that links unit allowances directly to the way state budgets were developed. This alternative method for allocating allowances would have the effect of distributing the responsibility for eliminating all or part of a state's overall significant contribution and interference with maintenance to individual units based on each unit's share of proj ected heat input. WVDAQ believes that the alternative allocation method is more straightforward, transparent and equitable to sources that have installed controls than the proposed allocation method. EPA should maintain a consistent policy that encourages early emission reductions and rewards sources which achieve them. Therefore, we support inclusion of this alternative methodology in the final Transport Rule.
Non-Operating Units - EPA requested comment on the proposed approach for allocating allowances to non-operating units, as well as simplifying allocations by not allocating at all to non-operating units. EPA also requested comment on maintaining perpetual allocations to non-operating units, similar to the treatment of non-operating units in the Title IV Acid Rain Program. WVDAQ believes that non-operating units should receive a time-limited allocation, and a seven year limitation would still provide an incentive to shut down certain units that may not be cost-effective to control. Not allocating at all to non-operating units will diminish or eliminate such an incentive, while allocating in perpetuity may hinder the ability to establish new units. Therefore, WVDAQ supports the proposed approach for allocating allowances to non-operating units, with the allocations transferred to the new unit set-aside after seven years.
Wolverine Power Supply Cooperative
The proposed allocation methodology departs radically from previous air act allowance allocation without explanation. The proposed system punishes, not rewards cleaner units, and penalizes rate payers buying from cleaner generating sources at necessarily higher electric rates. EPA has not explained why it has chosen this allocation methodology over more equitable and historic formulas. [EPA-HQ-OAR-2009-0491-2825.1 p.4]
The proposal does solicit comment for alternative approaches, and in particular an approach based on heat in-put, p. 45311. We suggest the allocation methodology similar to that promulgated in CAIR FIP for annual NOx emissions. (See 70 Fed. Reg. 25162, at 25279). This heat in-put driven system was not overturned by the court's decision in North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008) ("North Carolina"). As this alternative is detailed somewhat in the proposal, allowances should be distributed based on state allowance budgets pro rata based on unit historic heat rates. As with the CAIR NOx allowance state option, the allowance allocations to existing units should be based on historic unit highest three of five years heat-input and could accommodate new units after 5 years of operation into this baseline. This heat input approach would eliminate perpetual allocations to most polluting units, reward consumers who purchase power from new clean sources, and overall demonstrate a rational policy. This method would be lawful under North Carolina. [EPA-HQ-OAR-2009-0491-2825.1 p.4]
We also believe that EPA's proposed allowance allocation methodology discriminates against peaking units because the baseline years of 2007  -  09 were very-low utilization years due to a combination of unusually cool summers and very depressed economy in the upper Midwest. We propose using highest heat input of a current baseline (similar to NOx SIP Call and CAIR methodology) that for first allocation includes 2010 in the baseline, and that the allocations be rolled forward annually with newly calculated baselines. We again emphasize that EPA should follow this heat-input based allocation methodology in developing state budgets, but the states should perform the actual allocations through either the FIP or SIP process. [EPA-HQ-OAR-2009-0491-2825.1 p.5]
Wolverine's Sumpter peaking plant is a clear example of the above concerns. This plant, under its former owner, had very low duty schedules during EPA's proposed baseline due to the cool summers and very bad economy that reduced electric demand in the Upper Midwest. EPA proposal to allocate one NOx annual and ozone allowance to two of these units and zero to the other two, provides the plant with a total of two allowances for the four 85MW simple-cycle gas turbine units. Due to a warm summer in 2010, and slightly improved manufacturing load demand, this plant has required to date 8 annual and ozone season allowances, 400% greater than the proposed allocation. As the economy recovers, and as available base-load generation is in short supply due to this proposed rule, we anticipate that the Sumpter Plant will require higher utilization to meet demand and support electric reliability. We are very concerned that this plant is being penalized because it is a very clean and used in peaking duty. If a robust allowance trading program does not exist (see below), this plant will not be able to operate in future years when it will be needed most by the electric customers of Michigan. [EPA-HQ-OAR-2009-0491-2825.1 p.5]
We support a generous new source pool of allowances that will be allocated in the proposed method in EPA's proposed remedy, and support redistribution of unused allowances to existing sources. [EPA-HQ-OAR-2009-0491-2825.1 p.5]
Xcel Energy Inc.
I. ALLOWANCE TRADING PROVISIONS AND ALLOCATIONS.
1. The Transport Rule should protect companies that have already undertaken investment risk to reduce emissions and improve ambient air quality affected by downwind transport of pollution.
In EPA's preferred design, the Transport Rule would create a multi-tiered trading program for SO2 and NOx. Like all trading programs, trading under the Transport Rule can take place only after emission allowances are distributed to the utilities and covered sources that participate in the program. CATR would distribute the allowances based on projected emissions from each covered source in each state after removal of the emissions accounting for the state's significant contribution and interference with maintenance. [EPA-HQ-OAR-2009-0491-2728.1, p.2]
EPA in part based this program design on the mandates of the court's opinion regarding the Clean Air Interstate Rule ('CAIR') rule. Unfortunately, CATR does not adequately recognize and reward those companies and units that have already reduced emissions. As indicated above, our operating companies have made major investments in order to reduce emissions, including natural gas repowering at some of our largest generating facilities in Minnesota).1 [EPA-HQ-OAR-2009-0491-2728.1, pp.2-3]
[See page 3 of this comment for two examples from Xcel Energy's fleet.]
These emission reductions have played an important role in reducing ambient air quality issues in the transport region. Our customers are already paying for these emissions reductions through rate increases approved by utilities commissions in our states. The next group of emission reduction projects is likely to be more costly than the round that we have already undertaken. Unless EPA adopts an allocation mechanism to reward our early emissions reductions, the Transport Rule w/ill prove the old adage that 'no good deed goes unpunished.' Rather than recognizing this leadership and rewarding such investments, the CATR effectively punishes the company for reducing its emissions by basing the allowance allocation on projected emissions. By contrast, those companies who resisted investments in pollution control EPA reacted to the D.C. Circuit's opinion will receive much larger allocations, which they can use to finance belated investments in pollution control that Xcel Energy made several years ago. [EPA-HQ-OAR-2009-0491-2728.1, pp.3-4]
To avoid this kind of injustice, EPA can adopt a simple solution: It should allocate allowances based on historic emissions. We recommend that the Transport Rule allocate based on average emissions during any three year period between 2005 and 2009. This three year period predates most of the emission reductions undertaken as a result of CAIR and other programs and will reward companies like Xcel Energy that undertook significant emission reductions in the very recent past. [EPA-HQ-OAR-2009-0491-2728.1, p.4]
This allocation scheme is consistent with the court's opinion in the CAIR litigation. The opinion in the North Carolina case did not address the issue of early reduction allowance allocation. Because the allocation scheme we propose here does not interfere with the protections that EPA proposes to address the D.C. Circuit's concerns, the early reduction allocation formula is not inconsistent with Court's opinion. [EPA-HQ-OAR-2009-0491-2728.1, p.4]
Although Xcel Energy prefers an allocation methodology based on an historic emissions baseline, in the alternative we could also support the creation of a significant 'early reduction' allowance pool to reward those companies that made large investments in early, emission reductions and address the punitive effect of the proposed, forward-looking allocation model. We suggest a 10% reserve for reductions achieved since 2007 through retirement, repowering and installation of controls. We believe that such an early reduction credit set aside would adequately address overall policy objectives, including environmental effectiveness, cost effectiveness, and fairness to companies that have undertaken significant risk ha order to make progress towards environmental goals. If EPA chooses not to provide an early reduction credit set aside, it signals a large disincentive for companies implementing early reductions. This precedent would have a negative effect on future environmental compliance decision-making, dampening investments (and environmental benefits) in advance of regulation in favor of a just-in-time compliance philosophy. [EPA-HQ-OAR-2009-0491-2728.1, p.4]
2. Xcel Energy disagrees with EPA's proposal to eventually stop allocating allowances to units that cease operations.
On pages 45310-45311 EPA requested comment on allowance allocations to nonoperating units. Xcel Energy disagrees with EPA's proposal which would stop allocating allowances to units that cease operations after three years, with those allowances being redirected into the next unit set aside. As indicated above, Xcel Energy strongly believes that coal plant unit retirement, whether in the past decade or in the future, is an important tool that utilities may utilize to meet the obligations of the Transport Rule and other environmental mandates. Xcel Energy supports having allowance allocations that do not expire. This system has worked well under the Acid Rain program and should be continued into CATR. These programs have shown that long-term allowance allocations help pay for early reduction projects. As an alternative, to induce companies to retire units, EPA should allow companies to receive the allowances for at least 10 years after retirement. Without such a term, EPA will effectively induce companies to keep older, less efficient units in service longer than needed and, likely, defer the construction of newer, lower-emitting generation. [EPA-HQ-OAR-2009-0491-2728.1, p.4]
While we support EPA's preferred alternative, Xcel Energy is concerned about the complex trading rules and limitations in the preferred alternative. Our operations span eight states, with CATR affecting operations in three of those eight states, each with different potential obligations under CATR. The trading limitations and potential future changes under the CATR would make it very difficult for a multi-state electric company such as Xcel Energy to optimize its operations and investments. [EPA-HQ-OAR-2009-0491-2728.1, p.5]
To create the most flexible and cost effective compliance program, Xcel Energy requests that the EPA minimize restrictions on trading and future changes to market restruction as much as possible. In particular, Xcel Energy questions the need for multiple 'trading zones' through the grouping of states. EPA's proposed variability limitation will effectively protect against the concerns expressed by the D.C. Circuit such that the trading zone limitations are not necessary. Further, these zones will severely limit the effectiveness and transparency of the allowance trading market. It effectively would create a structure that will limit trading and create incentives for creating a range of derivatives and swaps that will open the agency and the system to criticism. [EPA-HQ-OAR-2009-0491-2728.1, p.5]
4. Xcel Energy supports the creation of a new unit allowance set aside.
On page 45310 EPA requested comment on the new unit allowance set aside provisions. New units must have allowance allocations or they will be completely dependent on the trading market. We believe that some allocations are needed for new units. Xcel Energy is supportive of the 3% allowance set aside for new units as proposed by EPA to address the risk of market limitations affecting supply for new sources. [EPA-HQ-OAR-2009-0491-2728.1, p.5]
5. Xcel Energy supports the use of the Acid Rain Program ('ARP') allowance and recording system.
On page 45311 EPA requested comment on the form of the allowance recording and surrendering system. Xcel Energy supports using an allowance recording and surrendering system similar to that used in the ARP and CAIR. This system has proved to be accurate and reliable. [EPA-HQ-OAR-2009-0491-2728.1, p.5]
6. Xcel Energy asks EPA to correct errors in the treatment of its Bay Front Units in Wisconsin.
Through its Wisconsin affiliate, Xcel Energy runs the Bay Front facility, a three-unit combined biomass and coal plant in Ashland, Wisconsin. Xcel Energy notes that Bay Front Units 1 and 2 are not included in CATR due to unit size, since both are less than the 25 megawatt electrical ('MWe') inclusion threshold. While both of these units primarily serve generators that are less than 25 MWe in size, they share a common steam header with Unit 5 which is greater than 25 MWe. As a result of this common header, Units 1 and 2 meet the applicability criteria of serving a generator with a nameplate capacity of more than 25 MWe. This issue has been previously addressed under the ARP and these units are included under that program. Therefore, these units should be granted allocations and included in CATR. [EPA-HQ-OAR-2009-0491-2728.1, pp.5-6]
3. Xcel Energy cautions EPA against assuming a given air pollution control device can operate effectively outside its design range.
Selective catalytic reduction systems ('SCRs') and SO2 scrubbers are designed to operate at a specific inlet and outlet concentration of the pollutant they are controlling. Generally, the outlet design value is set to the permit limit, with a small safety factor added in. Forcing a unit to operate outside of these design values increases the amount of wear and tear on the unit, which leads to more frequent malfunctions, accelerates component and catalyst replacement schedules, and shortens the life of the unit. [EPA-HQ-OAR-2009-0491-2728.1, p.9]
Adding additional control modules to increase the control efficiency is problematic, at best. This is especially true in the case where an existing electric generating unit has been retrofitted with pollution control equipment. These units are generally operating with a constrained equipment footprint, and additional control modules would be difficult and expensive, if even possible, to install. [EPA-HQ-OAR-2009-0491-2728.1, p.9]
An example of this is the Allen S. King (King) Plant, with one generating unit, which went through rehabilitation project and returned to service in July 2007. As part of this rehabilitation process, a SCR was added for NOx control, a semi-dry spray dryer absorber (SDA) was added for SO2 control, and a fabric filter baghouse was added for particulate matter control. [EPA-HQ-OAR-2009-0491-2728.1, p.9]
The CATR NOx allocation for the King Plant is based on the SCR operating at 0.081 pound NOx per million British thermal units ("lb NOx/mmBTU") due to EPA's assumption that a SCR is capable of 90 percent NOx reduction. The average NOx emission rates for King reported to EPA in 2008 and 2009 were 0.112 lb NOx/mmBTU2 and 0.087 lb NOx/mmBTU, respectively. As discussed above, King Plant is being penalized in two ways for installing a SCR earlier than requited by the Transport Rule. First, because the SCR is already installed, EPA allocates allowances based on projected emissions rather than pre-SCR emissions. Second, because the King SCR was installed in advance of the CATR, it was not designed to achieve 90% reduction, yet EPA incorrectly assumes that result in the allocation methodology. King would have received more allowances if the pollution control projects had been delayed until after the modeling for the Transport Rule had been completed. [EPA-HQ-OAR-2009-0491-2728.1, pp.9-10]
The situation for SO2 is similar. The CATR allocation is based on the SDA operating at 0.082 lb SO2/mmBTU. However, the King Plant's average SO2 emission rates reported to EPA in 2008 and 2009 were 0.109 lb SO2/mmBTU and 0.093 lb SO2/mmBTU, respectively. Thus, the King Plant is being penalized for installing a SDA earlier than required by the Transport Rule and the Rule assumes performance well beyond that required or achieved by the plant. [EPA-HQ-OAR-2009-0491-2728.1, p.10]
By adopting the allocation methodology as proposed, EPA risks discouraging future early reduction projects, undermining its own environmental goals as discussed in Section 1.1 of these comments. [EPA-HQ-OAR-2009-0491-2728.1, p.10]

1 We are currently in the planning stages of more major investments in Colorado under the provisions of the Colorado Clean Air Clean Jobs Act, which became law earlier this year. [EPA-HQ-OAR-2009-0491-2728.1, p.3]
2 Note that the SCR was put in service in January 2008. Compliance with the 30-day rolling average limit of  0.10 lb/mmBTU was not required until July 15, 2008 (450 days after first fire on coal, which occurred April 22, 2007). [EPA-HQ-OAR-2009-0491-2728.1, p.9]
Response: 
Thank you for your comment.Organization: State of Missouri Department of Natural Resources
Comment: 
State of Missouri Department of Natural Resources
Page 45310 of the proposed rule describes allocations to new units that are three percent (3%) of the state emission budgets for each trading program. 'EPA proposes that after a unit is not operating for three consecutive years, the allowances that would otherwise have been allocated to that unit, starting in the seventh year after the first year of non-operation, would be allocated to the new unit set-aside for the state in which the retired unit is located.' Missouri recommends that if a unit were to retire, these allowances be distributed in a state among existing operating participants. An alternative to this would be to create a new pool from the retired unit(s) allowances, to be reserved specifically for energy efficiency within a state instead of the allowances reverting to the new unit set aside pool. [EPA-HQ-OAR-2009-0491-3806, p.5]
Response: 
Thank you for your comment.Organization: Tampa Electric Company
Comment: 
Tampa Electric Company
As outlined above, EPA's time constraints and inadequate supporting documentation prevented Tampa Electric from determining the accuracy of EPA's allocation based on the IPM model output. Apparent errors possibly related to model inputs or algorithms resulted in arbitrary and capricious allocation results. The proposed allocation method penalizes companies like Tampa Electric that made early commitments to reduce emissions.  Tampa Electric has been a leader in making emission reductions (making a 88% and 90% system-wide reduction in SO2 & NOx, respectively over 1998 levels), yet the proposal does not provide sufficient SO2 allowances to even operate near our current permit limits. Furthermore, the allocations are not adequate to allow operation of some units with any available control schemes. Examples of apparent errors and inconsistencies include: [EPA-HQ-OAR-2009-0491-2745.1 p.4]
[These comments were also submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.54.]
At Tampa Electric's Big Bend Station, EPA allocated 3,936 SO2 allowances to Unit 2, but only 1,992 allowances to Unit 1. These units are both controlled by a common scrubber and have historically equivalent capacity factors. The illogical disparity could be due to outage schedules. Ironically, during the limited time frame that EPA used to determine the capacity factor, Tampa Electric was installing 2 SCR's as part of its $1.2 billion emission reduction initiative. It appears that Tampa Electric is being penalized for taking an outage to install controls necessary to comply with this rule. Regardless of whether or not the outage penalized the allocation, this highlights the flaws in EPA's use of a very limited baseline timeframe to develop a very important allowance allocation. EPA did not provide adequate supporting documentation to determine how these allocations were derived. [EPA-HQ-OAR-2009-0491-2745.1 p.4]
In a reversal in outcomes for NOx, Big Bend Station Unit 1 was allocated twice as many annual NOx allowances as Unit 2. As described above, these units were built during the same decade, have the same control equipment, the same limits, and operate with equivalent capacity factors. EPA did not provide adequate supporting documentation to determine how these allocations were derived. [EPA-HQ-OAR-2009-0491-2745.1 p.4]
Big Bend Station Unit 3 is listed in EPA's detailed data (see EPA technical support document "Budgets and Allocations - Detailed Unit-Level Data") as having zero heat input for 2008. This does not correlate to the "reported data" spreadsheet tab excerpted in Attachment A to these comments. Based on our discussions with Brian Fisher of EPA, this heat input value for Big Bend Unit 3 is inconsistent with the methodology and appears to be an error that likely impacts the modeling results.  [EPA-HQ-OAR-2009-0491-2745.1 p.4]
Although Tampa Electric understands EPA's motivation for using the model to allocate allowances, the results indicate that there are erroneous inputs or assumptions in the model. EPA did not provide adequate time or resources to determine the reason for these results, but the errors call the entire modeling process into question. Furthermore, the proposed allocation method penalizes those who have taken challenging and expensive early action to install controls. As noted in Section IV, below, we believe an allocation method utilizing heat input will avoid the potentially arbitrary and capricious result of rewarding inaction and penalizing those who have already installed controls. [EPA-HQ-OAR-2009-0491-2745.1 p.4]
Allowance Allocations Should be Based on Heat Input
Although it is conceivable that the IPM state allocations will meet the objectives of the Clean Air Act and Court ruling constraints, the lack of transparency, apparent errors, and inconsistencies make the proposed allocation scheme inappropriate. Therefore, we believe that individual unit allocations should be made based on heat input. The inventory of heat input data is robust, well vetted, and easily documented. We recommend that EPA use the following formula to calculate emission unit allowance allocations:
Emission Unit Allowance Allocation =
Where:
Emission Unit Allowance Allocations are the SO2, NOx annual, or NOx Ozone Season allowances provided each year for operation of the emission unit.
Emission Unit Heat Input (MMBtu) is the average of actual heat input of each emission unit in the program for each as compiled in CAMD Data & Maps (or EIA database) for years 2005-2009.
State Allowance Alloc. is the total amount of SO2, NOx annual, or NOx Ozone Season allowance provided each year to each State for operation of the emission units subject to the rule.
"N" represents the total number of emission units in each State subject to each respective program.
This alternative allocation methodology was described by EPA in the proposal (75 FR at 45311). Distribution of allowances based on heat input avoids arbitrarily rewarding those who did not install emission controls and avoids penalizing those who did install them. To continue with the proposed allocation method results in a disincentive for utilities to negotiate NSR agreements with EPA in the future. [EPA-HQ-OAR-2009-0491-2745.1 p.5]
Such an allocation methodology would not be prohibited under the dictates of the North Carolina v. Environmental Protection Agency decision because this relates to the per unit allocations within the EPA statewide allocation that is determined to be required to be met to address the nonattainment issues. This allocation method would not result in one upwind state sharing in the burden of reducing other upwind state's emissions, which the DC Circuit cites as the central deficiency resulting in the invalidation of use of fuel adjustment factor in the allowance allocation to the state. North Carolina v. Environmental Protection Agency @ p. 921. [EPA-HQ-OAR-2009-0491-2745.1 p.5]
EPA also requested comments on maintaining perpetual allocations to non-operating units, similar to the treatment of non-operating units in the Title IV Acid Rain Program. Tampa Electric supports maintaining perpetual allocations to non-operating units because it would avoid the incentive of keeping an older unit operating to continue receiving allowances and it would simplify the administrative allocation process. [EPA-HQ-OAR-2009-0491-2745.1 p.6]
EPA also requested comments on maintaining perpetual allocations to non-operating units, similar to the treatment of non-operating units in the Title IV Acid Rain Program. Tampa Electric supports maintaining perpetual allocations to non-operating units because it would avoid the incentive of keeping an older unit operating to continue receiving allowances and it would simplify the administrative allocation process. [EPA-HQ-OAR-2009-0491-2745.1 p.6]
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.72-73.]
Tampa Electric would also like to take this opportunity to express its preference for utilizing EPAs alternative proposal to use the heat input-based allocation method, rather than the wholly emissions based ones.
Using heat input would likely result in less of an allowance shortage for those who made early emission reductions and help mitigate the referenced allocation errors. Tampa Electric, who as previously stated has a 50/50 split of natural gas and coal generation, has made significant investments in emission reductions.
I would like to use this as an example. For the year 2009, accounts for nearly 15 percent of the Florida state total heat input in for Acid Rain units, but only 5 percent of Florida's SO2 emissions.
Under the proposed Transport Rule allowance allocation, Tampa Electric may or may not have enough allowances to cover its current generation needs, even though $1.2 billion was spent to reduce emissions and fully control all units.EPA should not include Florida as a Group one state. Minimal contribution from Florida sources can be attributed to downwind states, CAIR controls have not been properly reflected in projected emissions, and other model input inaccuracies can account for greater variability in the models output than verifiable point source emissions contribution to nonattainment areas.
Response: 
Thank you for your comment.Organization: Tennessee Valley Authority (TVA)
Comment: 
Tennessee Valley Authority (TVA)
A. Issue: EPA proposes that once an EGU does not operate for 3 consecutive years, the agency would no longer allocate allowances to the unit, starting in the seventh year after the first year of non-operation. After that seventh year the allowances would be allocated to the new unit set aside for the state. Other options EPA considered include continuing to allocate allowances for an unlimited period of time, or immediately discontinuing allocations to such units upon the unit ceasing operation. EPA seeks comment on the proposed approach for allocating allowances for non-operating units. [p. 45310- 11] [EPA-HQ-OAR-2009-0491-2782.1, pp. 14-15]
TVA Comment: Allowances to non-operating units should be allocated for an unlimited period of time. In this respect, non-operating units should be treated no different from units that reduce emissions by installing controls. Ending allocations for retired units could result in sub-optimal decisions, such as units electing to continue to operate units at very low capacity factors in order to retain their allocations. Moreover, in addition to the direct benefit of helping achieve and maintain the NAAQS for ozone and PM-2.5, the retirement of fossil units provide collateral environmental benefits such as the reduction in the emission of greenhouse gases. Therefore, EPA should continue to allocate allowances to non-operating units for an unlimited period of time and not discourage utilities from reducing emissions by retiring units. [EPA-HQ-OAR-2009-0491-2782.1, p. 15]
C. Issue: Banking of allowances for use in future years would be allowed under EPA's proposed remedy in the Transport Rule, but the rule is silent on the issue whether borrowing allowances from future years is permissible. [p. 45306] [EPA-HQ-OAR-2009-0491-2782.1, p. 14]
TVA Comment: EPA should allow sources to borrow allowances from future years as this increased flexibility helps EGUs make the transition from CAIR to the Transport Rule, overcoming the challenges posed by the stringent compliance dates of the Transport Rule. Allowing sources to borrow allowances from future years may be of concern in a traditional trading program because of the potential that improved air quality in the long term may be gained only at the expense of adverse impacts to air quality in the short term. However, any such concern is mitigated for the subject Transport Rule because of the assurance provisions of the rule that limit interstate trading. To this end, any temporal trading allowed by the rule should be subject to the assurance provisions. Allowing sources to borrow allowances from future years will help make up for any shortfall in allowances in the bank during the first few years of implementation of the Transport Rule. This capability would be especially important if EPA does not correct errors in its databases or fails to provide sufficient time to comply with the rule. [EPA-HQ-OAR-2009-0491-2782.1, p. 14]
Response: 
Thank you for your comment.  As described in Preamble Section VII.D, non-operating units will continue to receive allowances for four years under the final transport rule, rather than the seven years in the proposed rule. EPA believes this will help grow the number of allowances in the new unit set-aside faster and that a stream of allowances extending more than four years would have a small impact on operating decisions compared to other factors because generally, in light of the time value of money, the further into the future the stream is extended, the lower the value of the allowances added to the stream..   In addition, under the final rule, states may submit SIP revisions to replace the Transport Rule FIP existing-unit allocations for as early as 2013 by state-determined allocations.  Under the CAIR trading programs, many states used abbreviated and full SIP revisions to replace the EPA-determined allocations by state-determined allocations.   EPA therefore believes that it is likely that, through SIP revisions, states will ultimately determine whether or for how long a non-operating unit will continue to receive allocations and that EPA's approach provides a reasonable starting point. 

Organization: Texas Commission on Environmental Quality
Comment: 
Texas Commission on Environmental Quality
The TCEQ requests that the EPA revise and clarify definitions of new and existing units, due in part to inaccuracies in the technical support document upon which the definitions are at least partially based. [EPA-HQ-OAR-2009-0491-2857.1, p.1] 
Existing and New Unit Definitions 
 
The EPA should include and clarify definitions of new and existing units in the rule. The EPA has not explicitly written the definitions of existing and new units into the rule, but rather, has included definitions in the preamble, which, while useful to provide 'guidance' for interpreting the final rule, is not a 'rule.' The classification of a unit as an existing or new unit determines how allowances are allocated to the unit, the number of allowances allocated to the unit, and whether the unit will receive the same number of allowances every control period. Given these reasons, it is crucial that the definition of such units be included in the rule itself, and that the public be allowed to comment on those definitions, which form the basis for the entire program. If the foundation for the program is flawed, then the entire program is likely to fail.  [EPA-HQ-OAR-2009-0491-2857.2, p.3] 
The EPA states that 'existing units are units...that commenced commercial operation, or are planned to commence commercial operation, prior to January 1, 2012' (75 F:R 45309). This definition of existing units includes units that the EPA has identified as 'planned.' The EPA further states that 'planned units, as identified in the EGU inventory and included in IPM modeling projections, comprise units that had broken ground or secured financing and were expected to be online by the end of 2011.' Due to the inherent uncertainties associated with the date these planned units will actually commence commercial operation, the TCEQ recommends revising the definition of 'existing units' to exclude planned units.  [EPA-HQ-OAR-2009-0491-2857.2, p.3] 
The EPA states that new units are '...any covered EGU not listed in the table in Appendix A of the trading rule applicable to that program; any unit listed in Appendix A whose allocation is subject to the requirement that the Administrator not record the allocation or that the Administrator deduct the amount of the allocation ...' (75 FR45310). The EPA should clarify whether units listed in Appendix A are considered existing units for the purposes of this rule. Amajor failing in this preamble discussion is that the definition of new units assumes that all existing units (as characterized by the EPA) would be accounted for in Appendix A of the trading rule applicable to that program. The Allocation Table that will be published as AppendixA to the final rule was provided as the Technical Support Document (TSD) 'State Buqgets, Unit Allocations, and Unit Emissions Rates-Allocation Table.' Preliminary review of the Allocation Table revealed that the inventory of existing units contained inaccuracies. A complete and thorough review would necessitate an extension of the comment period, which the EPA has unreasonably refused to grant; however, as an example, Mustang Station Units 4 and 5 has a unit, GEN 2, that is listed in the Clean Air Markets Division database and the Clean Air Interstate Rule (CArR) allocation tables, but that is not listed in the Transport Rule Allocation Table. Therefore, an existing unit could be classified as new only because the EPA overlooked it. The EPA further compounds this error by not providing for a mechanism for correcting errors or omissions in their assumptions. The applicability of the rule is directly tied to the accuracy of the EPA's table, making the proposed rule biased against some companies simply because the EPA's table is inaccurate. Classifying a unit as new based on its exclusion from Appendix A is unreliable. Therefore, the TCEQ suggests that new units be defined as any covered EGU that commences commercial operation on or after January 1, 2012; any unit that did not meet the applicabilitY criteria for covered units as of January 1, 2012, but became a covered unit at a later time; or any existing unit that stopped operating for three consecutive years but resumes operation. [EPA-HQ-OAR-2009-0491-2857.2, pp.3-4] 
 
Response: 
The final rule provides that EPA will issue a Notice of Data Availability (NODA) for the allowance allocations to units that commenced commercial operation before January 1, 2010 and were operating in 2010.  The preamble of the final rule refers to these units as "existing units" and describes in detail the allocation methodology used by EPA to calculate the allocations, concerning which data will be made available that will be made through the NODA.  See Allowance Allocation Final Rule TSD (describing how EPA determined what units qualified for existing-unit allocations).  EPA provided notice and opportunity for comment on the allocation methodology and the resulting unit-by-unit allocations and includes in the rulemaking docket the final unit-by-unit allocations, as well as addressing them through the NODA.  Because the term "existing unit" is not used in the rule text of the final Transport Rule trading programs, EPA does not believe it is necessary to include, and define, the term in the definitions sections of the trading programs rules.  EPA notes that, if a unit is a covered unit but does not have an allocation that is addressed through the NODA, the final Transport Rule trading program rules provide that the unit will be eligible for allocations from the new unit set-aside, from which allocations will be provided by EPA without requiring the owners and operators to request such allocations.  
The final rule describes in detail the categories of units (referred to in the preamble as "new units") eligible for allocations from the new unit set-aside.  Because the units eligible for such allocations are described in the final Transport Rule trading program rules and the term "new unit" itself is not used in these rules except as part of a section title and as part of the term "new unit set-aside",  EPA does not believe that it is necessary to include, and define, the term "new unit" in the definitions section of these rules.   
See sections VII.D and XI of the preamble to the final rule.
Organization: Utility Air Regulatory Group (UARG)
Comment: 
Utility Air Regulatory Group (UARG)
EPA has failed to propose a defensible methodology for determining statewide emission reduction obligations and has required additional emission reductions even where they have not been shown to be needed to meet the air quality objectives that EPA asserts. [EPA-HQ-OAR-2009-0491-2756.1, p.9]
The Proposed Transport Rule properly recognizes the important environmental and economic benefits of allowance banking, a feature of CAIR that was not challenged in the litigation on that rule and that the court's opinion in no way undermines. The ability of sources to use banked allowances for compliance with the program encourages them to make early emission reductions to the extent that cost-effective early reductions are possible. Unfortunately, the nature and stringency of the proposed rule's emission reduction requirements and its proposed compliance schedule would make it very difficult for most sources to make extra emission reductions during the early years of the program. See sections III and V infra for UARG's comments on the compliance schedule. Permitting allowance banking in conjunction with an adjustment to the compliance schedule that would allow sources adequate time to comply with the program (and that would give states adequate time to develop SIPs) could well result in greater amounts of early emission reductions and, most likely, greater emission reductions over the long run. [EPA-HQ-OAR-2009-0491-2756.1, pp.12-13]
UARG supports EPA's proposal not to include any allowance auctioning under its Proposed Remedy Option. No need or reason exists to use allowance auctions to implement the Proposed Transport Rule's emission reduction requirements. If, however, EPA promulgates a final rule based on the Intrastate Trading Remedy Option, an option that UARG does not support, EPA should remove from that option the proposed provisions for allowance auctions. It is entirely possible to accomplish the objectives of those proposed auctions through distribution of allowances free of charge. This is particularly true if states are provided the time to develop SIPs that will allow each state to determine how best to make allocations that address that state's specific needs. [EPA-HQ-OAR-2009-0491-2756.1, pp.15-16]
As explained in section X.C below, government auctioning of allowances is contrary to the principle that regulated sources are not subject to any obligation to emit below their allowance allocation levels established by the program. Revenues from the allowance auctions that EPA describes in the Intrastate Trading Remedy Option would be deposited into the U.S. Treasury. 75 Fed. Reg. at 45327/2. The effect of such auctions, in which proceeds accrue to the government, is to force affected sources to pay not only for emissions that exceed their emission allocation levels but also for the right to emit below those levels. There is no legal basis for charging sources for the right to emit tons of emissions that are within their allowance allocation levels -- indeed, the very word "allowance" denotes that a source is allowed to emit within the limits of its allowance allocations -- and providing revenue to the U.S. Treasury is not a legitimate purpose of section 110(a)(2)(D)(i)(I). Moreover, EPA has not shown that any legal authority exists for EPA to auction allowances and thereby impose what amounts to a tax, with tax revenue flowing to the federal government. [EPA-HQ-OAR-2009-0491-2756.1, p.16]
UARG further notes that it would be possible for EPA to encourage early emission reductions beginning in 2012 under the proposed rule even if the initial binding compliance date under the rule was not until some years later. One possible approach would be to set "shadow" allowance allocations, using the best data available, for 2012 and each subsequent year until the new program begins. Then, during the period leading up to the new program's initial compliance year, EPA (or, more properly, a state) could credit sources with additional allowances corresponding to the number of tons they emitted below their shadow allowance allocation levels in those years, with those allowances eligible to be banked and used beginning in the first compliance year. The ability to earn allowances -- usable once the new program begins -- for early reductions would give sources a meaningful incentive to reduce their emissions prior to the start of the program, while allowing them the time they need to make the adjustments necessary for compliance, and affording states sufficient time to develop and submit SIPs consistent with the Act. [EPA-HQ-OAR-2009-0491-2756.1, p.23]
Units Should Be Permitted To Borrow Allowances From Future Year Allowance Accounts, at Least on a Limited Basis. 
EPA should allow units to "borrow" allowances from future-year accounts for use in compliance, at least on a limited basis. This would allow for increased flexibility, which will be particularly important in the early years of the program, especially if EPA promulgates a final rule that includes the ambitious compliance schedule that it proposes. See sections III and V supra for UARG's comments on the compliance schedule. However, this feature would still result in units receiving and using a finite number of allowances over the years and, thus, produce no overall increase in emissions. [EPA-HQ-OAR-2009-0491-2756.1, p.95]
Response: 
EPA strongly disagrees with the commenter's assertion that "the very word `allowance' denotes that a source is allowed to emit within the limits of its allowance allocations."  Such an allegation is a gross misinterpretation of the legal definition of an allowance, which is a transferable authorization to emit a specified amount of the relevant pollutant.   Because an allowance is a transferable authorization, it is in no way unique to its initial recipient at the outset of the program.  In addition, because it is a transferable authorization, its use by any entity bears an opportunity cost, in that by surrendering an allowance to authorize an emission, the entity is foregoing the opportunity to sell that transferable allowance to another party.  As such, the commenter is also incorrect in asserting that "there is no legal basis for charging sources for the right to emit tons of emissions that are within their allowance allocation levels," as the commenter thus ignores at least 16 years of emissions trading program precedent in which sources are annually obligated to surrender allowances for all relevant emissions and thus willingly forego the market value of the surrendered allowances for each ton emitted.  The commenter cites "the principle that regulated sources are not subject to any obligation to emit below their allowance allocation levels" but does not explain from where this principle emerges, or why it purportedly runs counter to allowance auctioning (which was explicitly authorized by Congress in statute for the Acid Rain Program).  Under an emission trading program such as the air quality-assured trading programs in the final Transport Rule, covered sources are obligated to surrender allowances to cover all emissions of the covered pollutants, including whatever quantity of emissions may be inferior to the amount of allowances initially allocated.  The commenter's "principle" ignores not only the legal requirements but also the fundamental purpose of market-based emission trading programs, which is to internalize the cost of pollution to polluting entities by establishing a visible price signal on the act of emitting any ton subject to the relevant cap.  It is this critical feature that provides the incentive for covered sources to deliver the most cost-effective reductions available across all sources, because any ton reduced has a market value  -  including tons reduced that could otherwise have been covered by initially allocated allowances at a particular source.
Furthermore, the commenter argues that "the effect of such auctions, in which proceeds accrue to the government, is to force affected sources to pay not only for emissions that exceed their emission allocation levels but also for the right to emit below those levels."  This argument is illogical and self-defeating.  For a given allowance, the government must make a mututally exclusive decision to auction it or to freely allocate it to a particular recipient.  Therefore, it is not possible for the government to simultaneously use the allowance as part of an "allocation level" for a given recipient and to also "force" that recipient to pay to acquire the same allowance at auction.  Although EPA has for policy reasons chosen not to establish allowance auctions under the Transport Rule FIPs, EPA has discretionary authority under the Clean Air Act to conduct such auctions and finds the commenter's arguments unsound and inapplicable to the context of this rulemaking and EPA's statutory authorities related to this rulemaking.
EPA also notes that the commenter's argument for allowance borrowing ignores the Court's clear direction in the North Carolina opinion that section 110(a)(2)(D) requires EPA to align the elimination of significant contribution to nonattainment and interference with maintenance of the NAAQS to the attainment schedule of the relevant NAAQS.  While it may be technically feasible for an allowance borrowing mechanism to preserve overall emission reductions over time, such a mechanism would allow sources to delay emission reductions which EPA has found in this rulemaking to be feasible and highly cost-effective by the 2012 and 2014 deadlines.  EPA believes such a mechanism would therefore be contrary to the intent of the statute and the Transport Rule programs.  In addition, EPA's modeling of the Transport Rule shows that many states are capable of overcomplying with their 2012 emission budgets and would find it economic to accelerate cost-effective emission reductions to build a bank, rather than borrow allowances from future control periods.   
Organization: Vermont Department of Environmental Conservation
Comment: 
Vermont Department of Environmental Conservation
[[2714.1 p.1-2]]
While we commend the EPA for their efforts to reduce the interstate transport of pollutants and to protect public health and the environment, this proposed rule raises the possibility of unintended consequences. Vermont, as a state identified by the EPA as not contributing significantly to downwind nonattainment (i.e., non-contributing state), could become a state of no new EGUs or a state of numerous EGUs, depending on the implementation and interpretation ofthis proposed rule.
This proposal allocates emission allowances to certain states within the transport region that have been determined to contribute significantly to downwind non-attainment. Emission allowances are not proposed to be allocated to non-contributing states. Therefore, it is unclear how the development of new sources in non-contributing states, identified by the EPA, will be addressed.
Specifically, what would the process be for the construction of a new EGU in a non-contributing state, but within the transport region? Further, would an incentive exist for new EGUs to be constructed in non-contributing states within the transport region? It is unclear how this would work toward the goal of reducing emissions across and throughout a designated transport region. We urge the EPA to initiate a mechanism to address these issues.
Response: 
EPA is not designating any "transport region" independent of the states covered under the Transport Rule's programs.  The construction of new EGUs in states not covered by the Transport Rule will continue to be subject to relevant Clean Air Act requirements for air quality management.
Organization: Victoria Power Station
Comment: 
Victoria Power Station
On behalf of Victoria WLE, LP, owner of the Victoria Power Station (Victoria), Consolidated Asset Management Services respectfully requests that your office review the Environmental Protection Agency's (EPA) database inputs used to calculate the nitrogen oxides (NOx) allocations for ORIS Code 3443, Unit 9, under the proposed Transport Rule (Federal Register, Vol. 75, NO. 147, Monday, August 2, 2010, Proposed Rules, Environmental Protection Agency, 40 CFR Parts 51, 52, 72, 78 and 97, Federal Implementation Plans to Reduce Interstate transport of Fine Particulate Matter and Ozone). [EPA-HQ-OAR-2009-0491-2786.1, p.1]
Errors related to the Air Transport Rule, Technical Information section of the EPA website (http://www.epa.gov/airqualityltransporUtech.html), document Budgets and Allocations - Detailed Unit-Level Data (Excel), are identified in this letter and the attached supporting calculations. In particular, Victoria is an existing site which started commercial operation in May 2009. The current Transport Rule Technical Information shows no allowances attributed to this Facility. [EPA-HQ-OAR-2009-0491-2786.1, p.1]
Victoria respectfully requests that EPA consider the information contained in this submittal, so that the appropriate number of Transport Rule Ozone Season NOx allowances may be allocated. [EPA-HQ-OAR-2009-0491-2786.1, p.1]
[See EPA-HQ-OAR-2009-0491-2786.1, p.2 for a table pertaining to Victoria Power Station (ORIS #3443)]
Response: 
Thank you for your comment.Organization: Westar Energy, Inc.
Comment: 
Westar Energy, Inc.
THE RULE CREATES A PERVERSE INCENTIVE FOR EGU'S GIVEN 'ZERO ALLOCATIONS' TO REFRAIN FROM RETROFITTING [EPA-HQ-OAR-2009-0491-2757.1, p.22]
Another factor ignored in the Rule concerns the perverse incentive created in situations where an EGU has been allocated zero emissions allowance in 2014. The proposed rule does not appear to offer any prompt means to increase the zero allowance should an owner decide to retrofit that unit with the controls assumed in the Rule to lead to state compliance with allocations as to individual EGUs by 2014. Under the proposal, it appears that a 2014 zero allowance unit can obtain a positive allowance only by fitting within the definition of 'new unit.' For this purpose, the applicable part of the definition states: 'any unit listed in Appendix A that stopped operating for three consecutive years, is no longer allocated allowances as an existing unit, but resumes operation' would be considered a new unit. 75 FR at 45310/1-2. 8 Even assuming this applies to a zero allowance EGU, that would mean at a minimum three, and possibly up to seven, years of non-operation before the retrofitted EGU qualifies for a positive allowance. During that time, and not withstanding that the EGU is in compliance, its owner would be required to purchase allowances to run the unit or purchase replacement electricity if the unit is shut down. [EPA-HQ-OAR-2009-0491-2757.1, p.22]
This creates a perverse incentive for zero allowance EGU owners not to retrofit those units because the owners incur the substantial retrofit costs without any assurance that they will gain any benefit from their action. Unless owners are clearly assured that a zero allowance unit will promptly receive a positive allowance upon compliance, they face the real possibility of paying the same costs (for buying allowances or for purchasing replacement electricity) that they would face if the unit remained non-compliant. Even in a situation where the new unit definition would permit a positive allowance, that would not occur for several years, thus delaying the owner's opportunity to recoup the costs of retrofitting through the sale of electricity from that unit. From a rational economic perspective, the least cost approach in these circumstances would be not to retrofit the zero allowance unit. But that option serves neither the public interest related to air quality nor the public interest to increasing the availability of low cost electricity. Consequently, EPA should act to provide reasonable assurance on this point. [EPA-HQ-OAR-2009-0491-2757.1, p.23]

8 It is not entirely clear whether the three years is really seven years, given 'EPA proposes that, once an EGU does not operate ... for 3 consecutive years, the Agency would no longer allocate allowances to the unit, starting in the seventh year after the first year of non-operation.' 75 FR at 45310/3. This coupled with the new unit definition creates confusion as it relates to zero allowance EGUs: Does a zero allowance constitute an allowance that EPA must no longer allocate before the EGU meets the new unit definition? 
Response: 
EPA's allocation methodology for existing units under the final Transport Rule FIPs is based on historic data; units which were slated to receive zero allocations at proposal based on projected data may now receive positive allocation amounts based on historic operations.  That being said, the commenter overlooks the fact that a decision to retrofit pollution control technology would bring benefits under the Transport Rule programs to any unit, because reducing emissions reduces the number of allowances required to be surrendered at the end of a control period, which provides either a cost savings (for avoided allowance purchases) or a salable asset (for retained allowances which could be sold or banked for future use) to that unit's owner or operator. 
Organization: Western Farmers Electric Cooperative (WFEC)
Comment: 
Western Farmers Electric Cooperative (WFEC)
While it is possible to dig through the annuals of EPA's technical supporting documentation within the rulemaking docket to ferret out proposed individual unit emission allowances, in some cases it is not possible to ascertain how or why EPA's modeling generated a given specific unit allocation.  Thus the proposed rule and underlying documentation present something like a "black box" for affected parties to comment.  It fails to present adequate information so as to allow full comment on unit emissions allocations and other issues important to affected electric utilities.  Notwithstanding, WFEC has made the effort to dig into the technical supporting documentation and has the following comments about specific units in WFEC's system. [EPA-HQ-OAR-2009-0491-2642.1, p.3] 
 Hugo unit #1 -  This unit is the only coal unit in the state of Oklahoma that already has installed low NOx burners and can achieve emission rates below 0.26 lb/mmBTU.  The other utilities have coal units that are allowed to meet emission rates much higher (0.286 lb/mmBTU) than WFEC's Hugo plant limit of .179 lb/mmBTU.  EPA's proposal fails to recognize units and the electric consumer who have borne the higher electricity costs because they must pay for existing, expensive emission controls.  If EPA has the discretionary authority under the CAA to effectively reward the more polluting units to the detriment of the cleaner units; and it may not, it represents poor policy judgment nonetheless.  [EPA-HQ-OAR-2009-0491-2642.1, p.4]
In addition WFEC has an energy portfolio with the highest percent of renewable energy so again it seems that EPA has failed to recognize energy consumers who have invested in the environment.  [EPA-HQ-OAR-2009-0491-2642.1,p.4]
 Anadarko units #1 and #2  -  These units have not been given allowances in the CATR Allocation Database.  Units #1 and #2 are very small units (15 MW) are therefore exempt from acid rain; therefore, allowances have not been provide.  WFEC would request allowances be provided for these units in the future.  [EPA-HQ-OAR-2009-0491-2642.1,p.4]  
Anadarko units #4, 5 and 6  -  All three of these units have been exempt from acid rain reporting and are not included in the CAMD database used in this proposal; however, this results in the CATR Allocation Database being incorrect.  This should be corrected by using data from other sources such as the Oklahoma Emission Inventory records which indicate the following:   [EPA-HQ-OAR-2009-0491-2642.1,p.4] [[See Docket Number EPA-HQ-OAR-2009-0491-2642.1, p.5 for the table with the corrected data.]]
Anadarko #9  -  11- There is limited data available for these three units as they began operation in mid - summer of 2009.  WFEC would like to suggest that estimated emission should be used to determine the allocations for these three units.  With that in mind WFEC anticipates the following emissions; therefore it is recommended that the allowances should be as shown below:   [EPA-HQ-OAR-2009-0491-2642.1,p.5] [[See Docket Number EPA-HQ-OAR-2009-0491-2642.1, p.5 for the table with the corrected data.]]
Response: 
Thank you for your comment.
Organization: Wisconsin Power and Light Company
Comment: 
Wisconsin Power and Light Company
WPL also supports the banking of emissions allowances for use in future years. [EPA-HQ-OAR-2009-0491-2844.1 p.3]
Response: 
Thank you for the comment. With regards to banking under the final Transport Rule, please see Preamble Section VII. 

V.D.2.c. Monitoring and Reporting

Organization: Nederhand, Frank
Comment: 
Nederhand, Frank
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.128-129.]
Additionally, in regards to the monitoring that's proposed by this rule, more monitoring is a good thing. There are areas in the state of Georgia that have no monitoring, mostly middle and south Georgia. So we don't really have a clear depiction of what the air quality issues are here in the state.
The Transport Rule would improve that. So we support that. However, we'd like to recommend that the stack monitoring data be real-time instead of letting the utility upload their monitoring data manually once a quarter or once a year, just so there's a better snapshot picture of the emissions coming from these coal plants.    
Response: 
See section VII.H of the preamble.  The final rule requires owners and operators to meet the stringent monitoring requirements for electricity generating units (EGUs) in Part 75 of EPA's regulations, which have been the backbone of EPA's emissions trading programs since the establishment of the Acid Rain Program under the 1990 Clean Air Act Amendments and provide owners and operators, EPA, and the public with detailed, accurate information on emissions and  emissions reductions.  Because owners and operators must report continuous emissions data  quarterly, the quarterly reports are audited, EPA has a robust enforcement program, and there are significant penalties for non-compliance, there has been a very high level of compliance with Part 75 monitoring, recordkeeping, and reporting requirements.  Real-time data from emission monitors are not necessarily quality - assured, and can be misleading.  For instance, excessive monitor drift or other monitor malfunctions that cause inaccurate readings may not be discovered immediately.  In such cases, the source owner or operator may have to retrospectively invalidate some of the previously-recorded real-time data. 
EPA requires quarterly electronic reporting of emissions data from EGUs.  Most continuous emission monitoring systems (CEMS) record emissions data in one-minute averages, which are automatically reduced to hourly averages by a data acquisition and handling system (DAHS).  The hourly average data are submitted to the Agency.  In addition to the hourly emissions data, each quarterly electronic data report includes cumulative emissions totals for that quarter and year-to-date emissions totals. 
All reported emissions data are quality assured before being submitted to the Agency, using a special EPA-provided software tool. The data are accepted and added to the EPA database only if the quarterly report is found to contain no serious errors.  The emissions data are made available to the public on our website at http://camddataandmaps.epa.gov/gdm/.  For further information on EPA's reporting requirements, please see section 10.0 of the "Plain English Guide to the Part 75 Rule", available on our web site, at: 
www.epa.gov/airmarkets/emissions/docs/plain_english_guide_par75_final_rule.pdf.
Organization: Utility Air Regulatory Group (UARG)
Comment: 
Utility Air Regulatory Group (UARG)
First, UARG objects to EPA's proposed requirement that source owners and operators submit electronic quarterly reports "in the format prescribed by the Administrator." Proposed §§ 97.434(d)(1), 97.534(d)(2)(ii), 97.634(d)(1), and 97.734(d)(1). In the preamble, EPA describes this requirement as identical to that contained in 40 C.F.R. Part 75 ("Part 75"), which establishes monitoring, record-keeping, and reporting requirements for the Acid Rain Program (ARP), NOx Budget Program, and CAIR. 75 Fed. Reg. at 45325/2 - 45326/1. UARG is surprised that EPA did not acknowledge in that discussion that the Part 75 requirement was challenged judicially (by UARG), and that the litigation has not yet been resolved. UARG objects to this requirement for the same reasons it objects to the requirement under Part 75. [EPA-HQ-OAR-2009-0491-2756.1, pp.96-97]
Under Part 75, reports must be submitted in a "format to be specified by the Administrator, including electronic submission of data" by "direct computer-to-computer electronic transfer via EPA-provided software, unless otherwise approved by the Administrator." 40 C.F.R. § 75.64(d) and (f). UARG challenged these provisions in part based on (1) concerns regarding the nature and content of EPA's format, which the Agency has changed with some frequency, (2) the EPA-provided software's failure to ensure compliance with basic requirements of the ARP and the Cross-Media Electronic Reporting Rule ("CROMERR"), and (3) the lack of appropriate procedures for submitting reports when a source is unable to gain access to EPA's computer with the EPA-provided software, or connect to the internet in a secure environment. See Appalachian Power Co., et al., v. EPA, No. 99-1302 (D.C. Cir., filed July 23, 1999); Utility Air Regulatory Group v. EPA, No. 02-1254 (D.C. Cir., filed August 12, 2002). These cases have been held in abeyance pending discussions aimed at resolving these concerns. [EPA-HQ-OAR-2009-0491-2756.1, p.97]
As UARG explained in the Part 75 rulemaking, if EPA makes the format itself (as opposed to the requirement to submit the information) a regulatory requirement, EPA has an 
obligation to subject that format to notice-and-comment rulemaking and review by the Office of Management and Budget ("OMB"). The EPA electronic reporting formats specified to date by the Administrator have been sufficiently complex and substantive that it is not appropriate to totally exempt them from rulemaking. To the extent some flexibility is needed to make adjustments to the format, that flexibility can be provided by rule. [EPA-HQ-OAR-2009-0491-2756.1,pp.97-98]
ARP sources have spent years and hundreds of thousands (if not millions) of dollars attempting to comply with these EPA-specified formats. The formats and related instructions for the ARP are hundreds, if not thousands, of pages in length with few or no citations to the underlying rule requirements. In some cases, the formats have included requirements to submit data that are not otherwise required to be reported under the rules. Each time EPA makes a revision to the format, software, or instructions, sources are required to respond. In some cases, this response requires modifications to the sources' own monitoring software at significant cost. Although EPA has responded to the electric generating industry's concerns by informally soliciting comment on the formats and instructions, committing to reducing the number of revisions to the format, and, in the recent redesign of the format, holding stakeholder meetings and providing contractor "technical support" during business hours, those efforts alone cannot cure what UARG believes is a legal defect in the rule. As implemented, EPA's electronic formats are substantive requirements that can impose significant burdens and impact sources' compliance status. [EPA-HQ-OAR-2009-0491-2756.1, p.98]
Adjustments to Certified Information by the Administrator 
Second, UARG objects to EPA's proposed language authorizing the Administrator to make adjustments to information personally certified by a designated representative ("DR") (or alternate DR, or "ADR"). Specifically, in proposed §§ 97.428, 97.528, 97.628, and 97.728, EPA proposes to allow the Administrator to perform independent audits concerning "any submission" and "make appropriate adjustments of the information in the submission." Under proposed §§ 97.414(a), 97.514(a), 97.614(a), and 97.714(a), DRs and ADRs are required to personally certify each submission as "true, accurate, and complete." At a minimum, EPA must make clear that any adjustments the Agency might make to information in a certified submission have not been certified by the DR or ADR. Moreover, UARG objects to the Agency's reservation to itself of the authority to unilaterally override a DR's or ADR's certification, without any procedure or criteria for establishing that the existing information is incorrect, or that the adjustment is in fact appropriate. EPA should remove these provisions. [EPA-HQ-OAR-2009-0491-2756.1, p.99]
Correction and Resubmission of Quarterly Reports 
Proposed §§ 97.434(d)(4), 97.534(d)(7), 97.634(d)(4), and 97.734(d)(4) are new provisions that do not exist in Part 75 that would authorize EPA to (1) conduct reviews and audits of DRs' certified quarterly reports to determine whether they "meet[ ] the requirements of this subpart and part 75," (2) notify the DR of any "determination" that the report "fails to meet those requirements," and (3) specify in that notification "any corrections the Administrator believes are necessary to make through resubmission of the quarterly report." EPA proposes to require that the DR make the specified corrections, or provide "information demonstrating that a specified correction is not necessary because the quarterly report already meets the requirements of this subpart and Part 75." Id. 60 In the preamble, EPA characterizes this provision as codifying a process that is "implicit under, and has been in continuous use in, the Acid Rain, NOX Budget, and CAIR trading programs." 75 Fed. Reg. at 45413/2-3. [EPA-HQ-OAR-2009-0491-2756.1, pp.99-100]
UARG disagrees that this provision is consistent with current practice and objects to its inclusion in this rule. Each electronic report submitted under Part 75 is required to contain a certification by the DR or ADR that the information in the report is "true, accurate, and complete," and that the reported data were recorded in accordance with Part 75. 40 C.F.R. § 75.64(c). EPA proposes to include similar provisions in this rule. See proposed §§ 97.414(a), 97.434(e), 97.514(a), 97.534(e), 97.614(a), 97.634(e), 97.714(a), 97.734(e). Under the current Part 75 program, disagreements between EPA and DRs or ADRs (particularly following adoption of a new rule, rule revision, or reporting format change) about the accuracy of reports are not uncommon. Disagreements can arise for many reasons, including as a result of differences in rounding methodologies, differences in interpretation, EPA's use of the reporting "format" to collect information not otherwise required by rule to be submitted, and other errors or programming "bugs" in the electronic data quality assurance checks used by EPA to identify errors. Disagreements also occur as a result of the Agency's attempt to develop and impose new (and often unsupported) rule interpretations through the use of automated checks built into the EPA-provided software. Although DRs and ADRs generally will engage in discussions with EPA when EPA's report auditing software generates an "error" message with which the DR or ADR disagrees, nothing in the current rule or process requires the DR or ADR to "demonstrate" the correctness of its position in order to certify and submit a report or to avoid resubmission of a report. [EPA-HQ-OAR-2009-0491-2756.1, pp.100-101]
To the extent the Administrator believes that a Part 75 report does not in fact meet the requirements of this subpart, EPA (not the DR or ADR) bears the burden of establishing that failure. EPA cannot use its reporting "format" and auditing techniques to establish a presumption of what constitutes compliance with Part 75, without subjecting its "reporting format" and software (including all of the audits contained in it) to rulemaking. EPA also cannot by rule shift the burden of proof with respect to establishing compliance to a source owner or operator's DR or ADR, who already has met the certification requirements of the rule, or compel a DR or ADR to certify a resubmitted report that the DR or ADR does not believe is correct. EPA should remove this provision, or restructure it to require resubmission only after the Administrator (not the source owner or operator) has established through an appropriate dispute resolution procedure that the report does not in fact meet the rule's requirement.[EPA-HQ-OAR-2009-0491-2756.1, p.101]

Footnote 60: EPA also proposes to provide the Administrator complete discretion to decide what "a reasonable time period" is for resubmission. UARG objects to this as well. If EPA can design an appropriate resubmission requirement, EPA also should propose and solicit comment on what would constitute a "reasonable time period."
Response: 
EPA rejects commenter's objections to the requirement that quarterly emissions reports be submitted electronically in a format prescribed by the Administrator.  First, EPA maintains that the electronic format itself is not substantive and is not subject to notice and comment requirements.  The electronic format is similar to a form in that neither is subject to notice and comment if the contents of the electronic format or a form reflect requirements that are already in rules that were subject to notice and comment.  All of the data elements required to be in the quarterly reports required under the Transport Rule trading programs are set forth in the emissions monitoring, reporting, and recordkeeping provisions of Transport Rule trading program rules and have been subject to public notice and opportunity for public comment in this rulemaking.  EPA notes that, whenever the commenter has suggested in the past -- in connection with the Acid Rain Program, NOx Budget Trading Program, and the CAIR trading programs -- that any data elements in the required format were not set forth in the relevant rule provisions, EPA has worked with the commenter to ensure that the rule provisions were corrected, with notice and opportunity for public comment provided.  In this case, the commenter's objection is speculative in that the commenter has not cited any specific data elements that are not set forth in the Transport Rule monitoring, reporting, and recordkeeping provisions.  Moreover, as the commenter noted, EPA has provided multiple opportunities for informal comment on the electronic formal and any revisions of the format, and consequently, even if notice and comment concerning the electronic format were required, the lack of formal notice and opportunity for comment would be harmless error. 
Second, the commenter failed to provide any basis for its claim that the EPA-provided software fails to ensure compliance with basic requirements of the Acid Rain Program and the Cross-Media Electronic Reporting Rule ("CROMERR").  The claim is therefore rejected as speculative and unsupported. 
Third, in the unlikely event that owners and operators will be unable, in some circumstances, to gain access to EPA's computer with the EPA-provided software, or connect to the internet in a secure environment, in order to submit electronically any required quarterly emissions report, the Transport Rule monitoring provisions already provide for the submission of petitions for alternatives (such as extension of time) to the monitoring and reporting requirements.   EPA notes that, under the Acid Rain Program, NOx Budget Trading Program, and the CAIR trading programs, owners and operators have successfully submitted electronically to EPA the required quarterly emissions data.  EPA has seen virtually 100 percent compliance with these requirements.
Regarding Adjustments to Certified Information by the Administrator:
EPA rejects the commenter's objections.   For each submission to EPA under the final Transport Rule trading programs, the designated representative (DR) or alternate designated representative (ADR) must certifies that the submission is "to the best of my knowledge and belief true, accurate, and complete" (§§97.414(a), 97.514(a), 97.614(a), and 97.714(a)).  The mere fact that the DR or ADR makes such a certification does not bar the Administrator  from disagreeing that the information in the submission is actually true, accurate, and complete and determining that the information needs to be corrected.  The commenter seems to assume, without any basis in the regulatory provisions at issue (§§97.428, 97.528, 97.628, and 97.728), that, if EPA makes such corrections of the information, the Administrator would claim that the corrected information had been certified by the DR or ADR even if the information was not so certified.   Moreover, the administrative appeals provisions in part 78, which are applicable to the Transport Rule trading programs, provide that any final decision taken by the Administrator under the Transport Rule trading programs may be appealed to the Environmental Appeals Board.  See §§78.1(a) and (b) and 78.3(d).  
Regarding Correction and Resubmission of Quarterly Reports
EPA rejects the commenter's objections.  EPA maintains that the rule provision (§§ 97.434(d)(4), 97.534(d)(5), 97.634(d)(4), and 97.734(d)(4)) establishes a reasonable process for addressing and resolving potential problems with information in quarterly emissions reports.  Under the provision, the Administrator must notify the designated representative (DR) if the Agency believes that a quarterly report does not meet the requirements of the monitoring and reporting requirements of the Transport Rule trading programs and must specify any corrections that the Agency believes are necessary to meet those requirements.  In short, the Administrator must initiate the correction process in a way that informs the DR about what the Agency believes should be done.  Further, the Administrator must establish a reasonable time period for a response by the DR, who may request reasonable extensions of the time period.  The rule provision does not state a fixed time period because what constitutes a reasonable time period obviously will depend on the specific circumstances involved (for example, the nature of the corrections identified by the Agency and whether the DR agrees that corrections are necessary or wants to dispute the identified corrections).  The DR may request an extension of the time period that the Administrator selected as reasonable.  Within the time period required or an extended time period, the DR must either make the specified corrections or provide information demonstrating that the corrections are not necessary.  Any final decision under the Transport Rule trading programs is subject to administrative appeal to the Environmental Appeals Board under part 78.  See §§78.1(a) and (b) and 78.3(d).  
The commenter erroneously claims that, because the DR (or alternate designated representative (ADR)) certified in each quarterly report that the report is "to the best of my knowledge and belief true, accurate, and complete" (§§97.414(a), 97.514(a), 97.614(a), and 97.714(a)) and that monitoring data in the report are in accordance with the monitoring and reporting requirements of the Transport Rule trading programs (§§97.434(e), 97.534(e), 97.634(e), and 97.734(e)), EPA "cannot by rule shift the burden of proof" and require the DR to respond.  First, the mere fact that the DR or ADR certifies that the information is consistent with the  monitoring and reporting requirements does not bar the Administrator from disagreeing that the information in the submission is actually true, accurate, and complete and consistent with such requirements and determining that the information needs to be corrected.  EPA maintains that a reasonable process for handling such a disagreement is for the Administrator to inform, and require a response from, the DR as described in the provisions at issue (§§ 97.434(d)(4), 97.534(d)(5), 97.634(d)(4), and 97.734(d)(4)).  Further, the commenter provided no basis for asserting that burden of proof of compliance with such requirements cannot be established by rule; on the contrary, a rulemaking with notice and opportunity for public comment is, on its face, a lawful context for establishing burden of proof in a regulatory process such as the submission and review of quarterly emissions reports.  In any event, EPA maintains that the provisions at issue do not establish burden of proof in that they do not address, or even purport to address, what party would carry the burden of proof in any administrative or judicial proceeding concerning any violation of the monitoring and reporting requirements of the Transport Rule trading programs.  Instead, these provisions establish what is essentially an audit procedure used by the Administrator to determine whether quarterly reports contain errors that should be corrected.  In this audit procedure, the Administrator is not making a determination that the owners and operators are in violation of the monitoring and reporting requirements, much less deciding that civil penalties should be assessed.  If, as a result of this process, the Administrator determines that owners and operators are in violation and initiates an enforcement proceeding concerning such violation, the presiding decision-making body (such as the Environmental Appeals Board or a court) will determine what parties bear the burden of proof.  EPA also notes that, contrary to commenter's claims, nothing in the provisions at issue requires the DR to resubmit a report that the DR believes is erroneous.  The provisions expressly allow the DR to claim, and to show, that the report does not need correction.   
The commenter also erroneously claims that EPA is using "the reporting `format' to collect information not otherwise required by the rule."  The provisions at issue here require that, when the Administrator notifies the DR that a quarterly report does not meet the monitoring and reporting requirements of the Transport Rule trading programs and specifies any necessary corrections, the DR must respond either by making the corrections or by showing that the corrections are not necessary.  In short, this rule provision -- not the electronic format used by the DR to submit quarterly reports and by the Administrator to notify the DR about any corrections -- describes what information is required.    

V.D.2.d. Assurance Provisions/Emissions Limitation Provisions

Organization: Adirondack Council
Comment: 
Adirondack Council
EPA is also requesting comment on the appropriateness of the assurance provisions that have been proposed, including whether they are adequate to assure that significant contribution and interference with maintenance are addressed in each state, whether they are overly restrictive, and whether there are less restrictive options that would provide adequate assurance that the statutory mandate is satisfied while providing more flexibility. (p. 402) As mentioned above, the Adirondack Council supports the budget for each affected state and would like to see the variability limits lowered, where possible. We agree that a one to one trading option is appropriate, as long as it remains within the same group for sulfur dioxide. We do not support any alternatives that would be less restrictive than EPA's proposal. [EPA-HQ-OAR-2009-0491-2848.1, p.4]
For the 2012-2013 transition period, EPA is proposing the State Budgets/Limited Trading remedy without the previously-described assurance provisions (penalty provisions would remain in effect), but taking comment on whether the assurance provisions should be in force during that period. (p. 451) As stated above for the question on page 407, the Adirondack Council would like to see the assurance provisions in place for the transition period. While it may not be needed, it should be put in place in case it is needed and any efforts EPA can take to ensure emissions reductions should be made. [EPA-HQ-OAR-2009-0491-2848.1, p.4]
EPA requests comment on whether the allowance surrender requirement should be different (either more or less) than one allowance per ton emitted over the owner's proportional share of the state budget with the variability limit. In addition, EPA requests comment on whether the exceedance of total emissions by an owner's sources over the owner's share of the state budget with the variability limit should be a violation of the CAA and thus subject to discretionary penalties. Finally, EPA requests comment on all aspects of the proposed assurance provisions in the proposed FIPs. (p. 450) The Adirondack Council encourages EPA to increase the surrender requirement for emissions exceedances from one allowance per ton to three allowances per ton. While some may believe this is punitive, since EPA has had nearly a 100 percent compliance with its current programs, we expect the same for the new Transport Rule. In the rare cases of violations, however, we believe that penalties should be swift and serve as a deterrent for any future violations. Therefore, we also believe that excess emissions should also be considered a violation of the Clean Air Act and have additional penalties associated with that violation. [EPA-HQ-OAR-2009-0491-2848.1, p.4]
Response: 

EPA modified slightly the variability limit methodology which simplified the determination of limits by eliminating the tonnage limits and giving all states the same percentage. For more information on variability limits, see section VI.E and VI.F in the preamble of the final Transport Rule. 
EPA is finalizing the assurance provisions to begin in 2012.  See the final Transport Rule preamble section VII.E for more information about the assurance provisions and EPA's decision to implement them starting in 2012. 
EPA has finalized an allowance surrender of 2 allowances for every 1 ton of emissions in excess of the state assurance level.  Exceeding the state assurance level is not a CAA violation in the final rule.  See preamble section VII.E in the preamble of the final Transport Rule for more information on assurance provisions and penalties.
Organization: American Electric Power
Comment: 	
American Electric Power
Variability Assessment and Assurance Provisions
The assurance provisions attempt to address the D.C. Circuit Court's concern that emission reductions must be guaranteed to take place within upwind states. However, the proposed approach is flawed in that intrastate trading and banking will be severely limited by the lack of compliance flexibility when adhering to state-specific limits. AEP recommends expanding and refining the variability provisions to remove arbitrary restrictions and allow economic solutions. We do not believe assurance provisions should be expanded for use in 2012-2013. We recommend that proposed assurance provisions should be either removed or substantially modified. [EPA-HQ-OAR-2009-0491-2665.1, p.16]
The assurance provisions will cause vast differences in state allowance markets as the majority of allowances can only be used within the state to which they were originally allocated, as trading for out of state allowances and exceeding state level allocations in a given year (plus variability limits) will result in significant penalties. We also have significant concern that owners can be held liable for a state exceeding the variability limit if their emissions exceed their plant level budget. This is fundamentally unfair as the flawed modeling and budget system is thereby dictating what actions individual plants must do to remove any chance of penalization in case of a state exceedance. This will dramatically raise the costs of compliance. AEP urges that any assurance based penalties or remedies be handled through a state implementation plan process where liability and equity can be better addressed. [EPA-HQ-OAR-2009-0491-2665.1, pp.16-17]
AEP recommends that the proposed one year limit be removed from the rule in favor of a broader three year average, which can provide added flexibility while still achieving the emission reduction goals. However, in the case of retention of either a one year or three year limit, we suggest expanding the limits for variability. Artificially excluding certain years in the baseline calculations for the variability analysis is arbitrary and punitive. 2000 and 2001 were excluded because EPA concluded these were 'large, uneven changes in annual heat input from fossil units for some states.' In fact, these years were a testament to the variability that can be inherent within the electric generating fleet, policy driven or not. Those two years, along with 2009, which was used in other portions of the rulemaking, should be also included in the variability analysis. However, in absence of a calculation revision, the one year variability limit for all states should be increased to reflect the variability of the most variable state (in the case of the proposed rule calculation, 28%). [EPA-HQ-OAR-2009-0491-2665.1, p.17]
Additionally, there was no evidence given supporting EPA's conclusion that heat input variability should serve as a proxy for emissions variability. Generally speaking, emissions can be more variable than heat input as units with full environmental controls tend to be baseload units that run regardless of electric demand. Conversely, uncontrolled units, which are responsible for the bulk of emissions, tend to cycle based on electric demand and thus are subject to greater variation from year to year. In other words, variability in heat input is not linearly correlated with the variability in emissions. EPA needs to revise the variability assessment to take into account increased emission variability. [EPA-HQ-OAR-2009-0491-2665.1, p.17]
Another recommended way to broaden the assurance provisions and allow for more economic decisions would be to provide that assurance be viewed on a more pure geographic basis that does not reflect arbitrary state boundaries. As an example the Ohio River serves as partial state boundary for Ohio, West Virginia, Kentucky and Indiana and a large amount of coal fired generation resides on both sides of the river. A plant on one side of the river could be severely impacted by the assurance provisions in one state forcing uneconomic reductions based on its unit-level budget, while a unit on the other side of the river might be able to make a economic reductions at a lower cost and have the identical impact on air quality, but will not do so due to its unit-level budget and lower state emissions. Thus, trading of 'state emissions' as counted toward the assurance provisions should be examined as well. [EPA-HQ-OAR-2009-0491-2665.1, p.17]
Response: 
The assurance provisions, as finalized, do not limit interstate trading, nor do they make use of state-specific allowances.  As such, there will be a single region-wide market for each type of allowance.  Assurance provisions begin in 2012 for reasons explained in the preamble section VII.E.
If assurance provisions are triggered, only those sources that exceed their allowance allocations plus share of the state's variability limit at the common designated representative level would be held responsible for surrendering allowances under the penalty provisions.  Those sources (at the DR level) that do not emit more than their allocations plus share of the state's variability limit do not pay any penalty, thereby providing certainty to those sources.
The allowance allocation approach in the final rule relies on historic data, not projections, making the comment about flawed modeling no longer relevant.  States will be able to implement their own allocations, once they submit and receive approval for their SIPs.  However, if they remain in the trading programs, they are not allowed to change the assurance provisions.  EPA is finalizing one-year variability limits only, not three-year variability limits.  For more on how variability limits were determined, see the Power Sector Variability Final Rule TSD.
EPA is authorized to require emission reductions to eliminate significant contribution and interference with maintenance in each upwind state under CAA section 110(a)(2)(D) and does not have authority to create new transport boundaries.
Organization: American Municipal Power, Inc. (AMP)
Comment: 
American Municipal Power, Inc. (AMP)
EPA's alternative proposals introduce the concept of assurance provisions aimed at ensuring that each state meets its pollution control obligations while accounting for inherent variability in power system operations. For the State Budgets/Limited Trading option, assurance provisions would be applicable in 2012, and for the Direct Control option, such provisions would be applicable in 2014. However, EPA does not explain how the assurance provisions will practically and functionally operate or why such provisions are necessary. As such, the Transport Rule should not include assurance provisions without additional demonstration by EPA justifying, clarifying and explaining how the assurance provisions would function in a document subject to public comment. [EPA-HQ-OAR-2009-0491-2678.1, p.3]
Response: 
EPA did explain variability limits and assurance provisions, why they would be necessary, and how they would be implemented in the proposal and took comments.  Other than this one, we did not generally receive comments that these concepts and provisions caused confusion.  For the final rule, see preamble sections VI.E and VI.F and the Variability Limits for Final Rule TSD for information about variability limits and preamble section VII.E for information about assurance provisions and penalties.  
Organization: Associated Electric Cooperative, Inc. (AECI)
Comment: 
Associated Electric Cooperative, Inc. (AECI)
Further, AECI requests that EPA remove the complicated variability conditions and replace them with limitations on facilities within trading regions as described above. [EPA-HQ-OAR-2009-0491-2845.1 P.7]
Response: 
EPA finalized a modified variability limit approach, which simplified the determination of limits by eliminating the tonnage limits and giving all states the same percentage. See preamble section VI.E and VI.F for more details on variability limits.
Organization: Attorney General of North Carolina
Comment: 
Attorney General of North Carolina
c. Penalties
EPA requests comment on whether penalties should apply in addition to the allowance surrender requirement of the assurance provisions. 75 Fed. Reg. at 45,314/2. North Carolina submits that penalties must remain an option. Although EPA has projected the price of allowances and the workings of the various markets, uncertainties remain. Historically, as EPA knows, allowances under the Clean Air Act's programs have traded, at least at times, at levels significantly lower than projections. Also, EPA cannot foresee all circumstances. For example, several States may impose state-law limits that are significantly lower than the proposed Transport FIP budgets. This could flood the market with inexpensive allowances. If allowances become readily available and very inexpensive, the 32 assurance provisions alone would not provide a sufficient incentive to ensure that sources comply with the budgets. Of course, with penalties EPA retains enforcement discretion. Therefore, there is no reason for EPA to completely abandon this enforcement tool at the outset.
Response: 
The penalty for triggering the assurance provisions is an allowance surrender of 2 allowances for every 1 ton of emissions that exceed the state assurance level (state budget + variability limit).  Exceeding the state assurance level is not a CAA violation.  However, if sources do not hold sufficient allowances to cover their share of the assurance provision penalty, they will be further penalized for their failure to hold allowances in their account and may potentially be found in violation of the CAA.  See preamble section VII.E and the Assurance Penalty Level TSD for more information about assurance provisions and penalties.
Organization: Birchwood Power Partners, L.P.
Comment: 
Birchwood Power Partners, L.P.
D. The Assurance Provisions Would Unfairly Prejudice Long-Term Contract Generators Who Cannot Pass Along the Costs of Additional Allowances
By requiring the surrender of one additional allowance for each ton emitted over a facility's proportional share of a state's exceedance of its budget and variability limit, the Proposed Transport Rule's 'assurance provisions' will unfairly prejudice the interest of long-term contract generators, vis-a-vis utility-owned or merchant generating facilities, which can recover the costs for additional allowances from ratepayers or through the market price of electricity. Birchwood Power would encourage EPA to include provisions in the final rule that would provide relief to long-term contract generators from the impacts that the assurance provisions could have on their operating costs and competitiveness. At the very least, Birchwood Power believes that this concern supports EPA's proposal to delay implementation of the assurance provisions until 2014. Birchwood Power would also suggest that EPA increase both the one-year and three-year variability limits to 15% and 10%, respectively, of a state's budget. [EPA-HQ-OAR-2009-0491-2706.1, p.5]
Response: 
If assurance provisions are triggered, only those sources that exceed their allowance allocations plus share of the state's variability limit at the common designated representative level would be held responsible for surrendering allowances under the penalty provisions.  Those sources (at the DR level) that do not emit more than their allocations plus share of the state's variability limit do not pay any penalty, thereby providing certainty to those sources.  Assurance provisions go into effect in 2012, not 2014, in order to comport with the court's ruling regarding elimination of significant contribution and interference with maintenance in each upwind state.  One-year variability limits have been modified slightly, although most states receive a 10 percent variability limit, unless a higher limit is supported by historical data.  Three-year variability limits have been removed from the final rule.  See preamble section VII.E for more information about assurance provisions and penalties. 
Organization: Class of '85 Regulatory Group
Comment: 
Class of '85 Regulatory Group
EPA's preferred option (the 'State Budgets/Limited Trading' remedy) would accomplish this by allowing limited interstate trading and creating a 'variability limit' to account for variations in energy demand and generation from year to year. EGU owners could utilize the proposed ten percent variability limit by purchasing allowances from within their state, or by purchasing those allowances from another state in the same trading program. [EPA-HQ-OAR-2009-0491-2854.1, pp.2-3]
In any given year, unforeseeable meteorological and economic forces will alter regional electricity supply and generation needs. For example, from 2007 to 2008, demand in the FRCC region (which encompasses Florida) dropped by about four percent, while demand during the same period rose by about three percent in the NPCC region (which encompasses New England and New York). But, from 2003 through 2004, demand rose in the FRCC region by about four percent while dropping by a similar amount in the NPCC region. These state and regional fluctuations are driven by factors too complex to discuss in these comments. However, variability in electricity supply and generation is a persistent challenge for EGU owners and state regulators who must generate and supply electricity based on the demands of consumers and the fiats of the weather. Although electricity demand may go up or down in any given year in any given state or region, these variations tend to balance out in the long term, as the above example demonstrates. Variability provisions are important because they help to account for this persistent annual variation by providing an efficient mechanism to help assure cost-effective compliance. And limits on variability assure the Proposal's goal of localized emission reductions, as discussed below. [EPA-HQ-OAR-2009-0491-2854.1,p.3]
Interstate trading is also important because it allows EGU owners to purchase a limited number of allowances from states or areas that are not experiencing high demand and have a surplus of allowances in a given year. For example, a hot summer in the Northeast could trigger the need to use variability provisions in several northeastern states. Since it is likely that no owner in any of those states would hold excess in-state allowances, they must seek additional allowances from areas experiencing lower demand. In our example, if the mid-Atlantic region experienced a cool summer, owners in those states might hold excess allowances that they could sell to allow units in the Northeastern states to meet their compliance obligations. Under an option that allowed only intrastate trading, no allowances would exist to supply the variability limit because it is likely that all units in that state (or interconnection region) would experience high demand in a given year. Thus, interstate trading is a necessary component of any variability provision, because without it there would be no available allowances with which to meet variances in annual emissions. In a similar way, allowance banking also helps to mitigate annual variations by allowing an EGU owner to bank allowances in low-demand years for later use in high-demand years, again subject to variability limits and assurance provisions.7 Because variability provisions, interstate trading, and allowance banking provide the most realistic and cost-effective mechanism for assuring compliance with the interstate transport requirements of the CAA, the Class of '85 supports the 'State Budgets/Limited Trading' remedy, subject to the comments below. [EPA-HQ-OAR-2009-0491-2854.1,pp.3-4]
EPA Should Increase the Variability Provisions.
As discussed, unpredictable weather and economic forces make variability provisions a necessary component of EPA's preferred option. Initially, variability limits will also provide an important compliance mechanism for several additional reasons, including:
:: Inaccuracies in initial emissions budgeting and allowance allocations;
:: Inaccurate assumptions about existing controls installations, operating rates, and availability;
:: Multi-year timeframes necessary to obtain permits and install additional controls;
:: Reliability concerns, including the potential for a major nuclear outage or other similar unexpected event that increases demand on fossil-fuel fired EGUs; and
:: Lack of any banked allowances for the first several years. [EPA-HQ-OAR-2009-0491-2854.1,p.11]
While Class of '85 members would prefer not to rely on the current ten percent variability provisions as an initial compliance mechanism, the above issues create a near certainty that utilization of variability limits will be required for initial compliance purposes. [EPA-HQ-OAR-2009-0491-2854.1,p.11]
But the current ten percent variability limit is insufficient to address the above concerns and assure initial compliance with the preferred option's initial emissions allocations. First, it is unclear that, for a given unit, initial emissions budgets will be an accurate reflection of current emissions and controls, given the inaccuracies identified above with EPA's baseline data and assumptions. Second, new controls can take several years to permit and install, which means that additional emissions reductions (and the corresponding availability of allowances from those sources) are years away. Third, annual generation variability in a region can easily exceed ten percent, especially as the economy begins to exit a multi-year recession. For example, from 2004 to 2005, electricity demand increased by about 11 percent in the NPCC region, 18 percent in the SERC region, and 10 percent in the NPCC region. The likelihood of another year of high demand growth (as we exit a major recession that caused several low-demand years), combined with initial inaccuracies in allowance allocations, suggest that a ten percent variability limit is inadequate. [EPA-HQ-OAR-2009-0491-2854.1,pp.11-12]
Compounding the problem of low variability limits is the lack of a viable initial allowance market. The Class of '85 expects very little initial trading to occur in any emissions markets created by the preferred option, due to an unavailability of emissions allowances. To help alleviate these issues and create a functional allowance market and variability program, EPA should consider the following changes to the preferred option's variability provisions: [EPA-HQ-OAR-2009-0491-2854.1, p.12]
:: Clarify that unit-specific variability limits apply in 'year one' (e.g., 2012)28;
:: Raise all variability limits (unit and state) to 20 percent, at least during the first five years of the program, with a corresponding increase in the rolling three-year variability provisions;
:: For each trading market (S02, annual NOx, and ozone season NOx), allocate or auction an additional set of allowances during the first five years of the program. This will help to stimulate trading markets and compensate for inaccuracies in initial allocations. The number of allowances allocated or auctioned should correspond to the rolling three-year variability limits, as applicable, which will assure that in-state emissions reductions are achieved within the state budget including variability limits. [EPA-HQ-OAR-2009-0491-2854.1,p.12]
These changes will help address initial inaccuracies in allowance budgets and mitigate unforeseen issues with initial compliance caused by the issues identified above. These changes are also consistent with the preferred option as proposed, which recognizes the inherent uncertainty and variability in both baseline and future annual demand and emissions requirements. And, by tying any additional allocation or auction of allowances to assurance provisions, EPA can assure that in-state emissions reductions are achieved in a manner consistent with North Carolina. [EPA-HQ-OAR-2009-0491-2854.1,p.12]
The Class of '85 supports an allowance surrender requirement in lieu of a penalty in instances where variability limits are exceeded and believes that the current 1: 1 surrender ratio is an appropriate penalty level. As discussed, emissions markets are expected to be tight, and even a 1: 1 allowance surrender requirement will create a significant deterrent to exceeding variability levels. EPA should retain these surrender requirements and clarify that only those units exceeding their individual unit-based budget with variability limits are subject to allowance surrender requirements in instances where an entire state exceeds its variability limit for a given compliance period. [EPA-HQ-OAR-2009-0491-2854.1, p.13]

7 The Proposal recognizes the important environmental and economic benefits of allowance banking. Allowance banking is a key component of other emissions trading schemes and in no way undermines the court's decision in North Carolina v. EPA because the use of banked allowances would be subject to the same assurance provisions that limit interstate trading. Accordingly, the Class of' 85 supports inclusion of allowance banking in the preferred option. [EPA-HQ-OAR-2009-0491-2854.1,p.4]
28 The Class of '85 supports the 2012 and 2013 'transition period,' which begins assurance provisions in 2014 as described at 75 Fed. Reg. 45314-15. This provides additional flexibility to address certain concerns identified in these comments. [EPA-HQ-OAR-2009-0491-2854.1,p.12]
Response: 
EPA has finalized an allowance allocation approach that is based on historic data and has updated the model to correct information about controls, fuels, etc.  The final rule also relies on fewer controls and included analysis to demonstrate feasibility.  Emission reductions are phased in 2012 and 2014 to allow sources the time necessary to make changes and also to ensure sufficient allowances in the early years.  Since EPA has addressed these concerns, we believe that a 10 percent variability for the majority of states is adequate to meet their operational needs.  A 117-year range was used to develop the variability limits, which covers a range of economic and meteorological conditions.
There are no unit-specific variability limits.  Variability limits are implemented at the state level. EPA finalized a modified variability limit approach, which simplified the determination of limits by eliminating the tonnage limits and giving all states the same percentage. The uniform percentage variability limits are higher than the 10% limits in the proposal. 
Again, the allowance allocation approach in the final rule is different from the proposal and based on historic data.
If assurance provisions are triggered, only those sources that exceed their allowance allocations plus share of the state's variability limit at the common designated representative level would be held responsible for surrendering allowances under the penalty provisions.  Those sources (at the DR level) that do not emit more than their allocations plus share of the state's variability limit do not pay any penalty, thereby providing certainty to those sources.  The penalty for triggering the assurance provisions is an allowance surrender of 2 allowances for every 1 ton of emissions that exceed the state assurance level (state budget + variability limit).  Exceeding the state assurance level is not a CAA violation.  See preamble section VII.E for more information about assurance provisions and penalties. 
Organization: Clean Energy Group
Comment: 
Clean Energy Group
The Clean Energy Group Supports the Proposed Assurance Provisions
Although the Clean Energy Group has significant concerns about EPA's proposed use of projected emissions to allocate allowances to emission units, we strongly support the overall framework of the preferred option, including unlimited intrastate trading and limited interstate trading using the variability and assurance level provisions. [EPA-HQ-OAR-2009-0491-2702.1, p. 9]
We support EPA's proposal to determine assurance provisions' surrender requirements at the owner level, rather than the plant or unit level, because this would allow companies to optimize the management of plants as a fleet. This allows much-needed flexibility while resulting in equal or lower emissions [EPA-HQ-OAR-2009-0491-2702.1, pp. 9-10]
The assurance provisions would create a powerful incentive to operate pollution control equipment rather than buy allowances. With a sufficient allowance price, the requirement that a unit owner surrender two allowances for every ton by which it exceeds the variability limit if a state exceeds its limit will likely result in companies limiting their reliance upon purchased allowances. Instead, companies will look to achieve further emissions reductions. This would ensure reductions occur in the necessary states so as to meet the requirements of Section 110, clarified in the D.C. Circuit decision. Some Clean Energy Group companies' individual comments will suggest additional opportunities to further strengthen the assurance provisions. [EPA-HQ-OAR-2009-0491-2702.1, p. 10]
Response: 
EPA has finalized an allowance allocation approach that uses historic heat input (and limited by maximum historic emissions) rather than the approach included in the proposal.  In addition, assurance provision penalties in the final rule are determined at the common designated representative level, rather than by owner, and still provides sources with compliance flexibility.  The assurance provision allowance surrender penalty in the final rule is 2 allowances for every ton of emissions in excess of the state assurance level (budget plus variability limit).  For more on assurance provisions and penalties, see preamble section VII.E.  
Organization: Dominion
Comment: 
Dominion
EPA Should Increase the Variability Limits
EPA should consider increasing the emission variability limit thresholds established under the assurance provisions of the proposed rule. EPA describes the approach used to evaluate and conclude that the 10% variability limits (for both a single year and a 3-year average) would not have a significant impact on downwind air quality. However, it is not apparent and EPA does not explain why it chose to perform this analysis with only 10% variability limits. EPA should evaluate higher variability limits of at least 20% and set higher limits if these additional analyses indicate limited impact of upwind emission variability on downwind air quality. [EPA-HQ-OAR-2009-0491-2715.1, p.5]
Response: 
EPA finalized a modified variability limit approach, which simplified the determination of limits by eliminating the tonnage limits and giving all states the same percentage. The uniform percentage variability limits are higher than the 10% limits in the proposal.  See preamble section VI.E and VI.F for more details on variability limits.
Organization: DTE Energy
Comment: 
DTE Energy
While DTE may not support the specified compliance deadlines in the proposed rule, DTE supports EPA's proposal not to apply variability limits until after the transition period proposed under the preferred approach. [EPA-HQ-OAR-2009-0491-2851.1, p.2]
Response: 
EPA is finalizing the assurance provisions to begin in 2012, not in 2014.  See preamble section VII.E for more information about the assurance provisions and EPA's decision to implement them starting in 2012. 
Organization: Duke Energy
Comment: 
Duke Energy
EPA requests comments on the proposed assurance provisions. 75 Fed. Reg. at 45314/2. Duke Energy believes that the allowance surrender requirement associated with the assurance provisions should be less than one allowance per ton emitted, in addition to the standard allowance surrender. An additional allowance surrender requirement of one allowance per ton would be unnecessarily burdensome and overly punitive. EPA states in the proposed rule that it "believes the likelihood of triggering assurance provisions is low." Id. at 45314/1. The example that EPA provides of a circumstance that may lead to emissions "approaching the variability limit" -- "an extended nuclear unit outage that causes a company to run its fossil fuel units harder to meet demand" -- indicates that EPA anticipates the assurance provisions would likely be triggered only in unusual conditions and for a temporary period, due to forces largely beyond the unit owner's control. Id. Any allowance surrender in addition to the standard allowance surrender of one allowance per ton -- for example, an additional (1/2) allowance (rather than the additional one allowance) on top of the standard one-allowance surrender requirement -- would provide an adequate incentive for unit owners to take all reasonable measures to avoid exceeding their share of the state budget with variability limits.  [EPA-HQ-OAR-2009-0491-2689.1, pp.31-32]
Duke Energy supports EPA's position that such an exceedance should not be considered a violation of the CAA, subject to discretionary penalties. The PTR contains separate penalty provisions and, as explained above, any additional allowance surrender requirement would provide sufficient incentive to avoid triggering the assurance provisions. [EPA-HQ-OAR-2009-0491-2689.1, p.32]
The penalty provisions for a utility operating system in a state that exceeds its assurance limits is not equitable for smaller utilities in the state or operators who may have just a few, or even one, unit in the state. The smaller operating company may have contributed very little to the exceedance and yet will be forced to pay a substantial penalty (in the form of additional allowances withheld). For example, a large utility that holds 5000 tons of allowances might emit 5,499 tons and remain below the 10% assurance limit with no penalty even though that utility added 499 tons towards the excess. Another utility that has just a few small and well-controlled combustion turbines may hold only 5 allowances but emitted 10 allowances during the year as a result of an increased demand for the units. (For a simple cycle turbine operating at very low capacity factor, a small change in demand may significantly increase total emissions.) While the small utility contributed only 5 tons towards the overall statewide exceedance of the assurance limits, for reasons beyond its reasonable control, the small utility would pay a substantial price relative to the allowances it holds in comparison to the much larger utility which will pay no penalty. [EPA-HQ-OAR-2009-0491-2689.1,p.66]
Response: 
In the final rule, the penalty for triggering the assurance provisions is an allowance surrender of 2 allowances for every 1 ton of emissions that exceed the state assurance level (state budget + variability limit).  Exceeding the state assurance level is not a CAA violation.  See preamble section VII.E and the Assurance Penalty Level TSD for more information about assurance provisions and penalties.
The assurance level is set at the state level, rather than the unit or company level, to provide flexibility.  Assurance provision penalties are determined on a common Designated Representative bases also to provide owners and operators with compliance flexibility.  Through this design, all owners and operators have the flexibility and also the responsibility to manage their operations for compliance with the program requirements.  Output and emissions data is available for owners and operators to make decisions regarding their emissions and allowance penalty risk.
Organization: Entergy Services, Inc.
Comment: 
Entergy Services, Inc.
Emergency Variance Provision  
Under either of the three options developed by EPA in the proposed rule, very little, if any, flexibility is provided for generating facilities that may be called on to provide electricity at unexpectedly high levels due to an emergency, natural disaster, long-term mechanical problem, shutdown because of a change in law or regulation, or other similar issue that forces a low- or no-emission facility to reduce its generation capacity significantly.   For example, the unexpected shutdown, for whatever reason, of a nuclear or hydroelectric facility that normally produces a significant generating capacity in a state, with no emissions from its electric generating functions, likely would require a corresponding increase in fossil generation in an amount that could exceed the maximum emissions allowed by the combination of allowances issued to the state plus the limited interstate trading which may be allowed by the rule.  Of course, a rule that allowed no interstate trading would be in even greater need of such an emergency variance provision.  The variance provision should allow states implementing the Transport Rule to grant a variance from the requirement for holding or obtaining allowances for those tons of emission created by a unit's response to another unit's emergency or unanticipated loss of generation. [EPA-HQ-OAR-2009-0491-2847.1,pp.5-6]
Response: 
The CAA requires significant contribution and interference with maintenance to be eliminated from upwind states and does not provide exceptions for unforeseen events.  EPA does not believe it has authority to expand upon the CAA and design new measures to manage emergency variance provisions for this rule, other than what already exists.  There are emergency provisions already in the CAA, that may be invoked, if appropriate.  This comment does not provide specific recommendations for how EPA should proceed with implementing "emergency variance provisions" within its current CAA authority.
Organization: EquiPower Resources Corp.
Comment: 
EquiPower Resources Corp.
EPA's state budget caps and assurance provisions stand in the way of an effective emissions trading market. A cap-and-trade mechanism would provide significant benefits to achieving emission reductions. However, the Transport Rule's limitations on trading created by the state budget caps and assurance provisions eliminate any advantages associated with a cap-and-trade program and preclude the development of a robust emissions trading market. EPA should adopt an alternative approach that addresses the D.C. Circuit's key holding in North Carolina v. EPA, by ensuring that upwind emissions do not contribute to downwind nonattainment, and also enables a robust emissions trading market to develop. [EPA-HQ-OAR-2009-2704.1, p.2]
Response: 
EPA has made an effort to design a remedy that minimizes program costs for covered sources, ensures the elimination of significant contribution and interference with maintenance from upwind states, and comports with the DC Circuit court's decision.  This comment does not provide enough information or a specific plan for EPA to consider and implement as an alternative remedy.
Organization: Exelon
New York University School of Law, Institute for Policy Integrity
Comment: 
Exelon
The selected remedy also provides a workable means to provide the assurances required by the court in North Carolina, that each state will eliminate its emissions that interfere with maintenance of the NAAQS or significantly contribute to non-attainment of NAAQS in downwind states ("interference with downwind air quality"). EPA's own modeling has confirmed that, if states meet their emissions budgets as augmented by the variability limits, the Transport Rule will assure a sufficient reduction in upwind emissions to reduce interference with downwind air quality. Exelon has conducted a peer review of EPA's modeling, and agrees with both its methodology and conclusions, as discussed in Comment 2.2 above. [EPA-HQ-OAR-2009-0491-2666.1, p.22]
EPA's selected remedy can reduce interference with downwind air quality and accommodate the inherent variability in state-by-state generation that might arise from the shutdown of a major zero pollution facility, such as a nuclear facility. EPA's modeling confirms that if emissions exceed a state budget but still fall within the one and three year variability limits, interference with downwind air quality will still be reduced sufficiently to allow the downwind states to meet and maintain the NAAQS. As discussed above, the electric system has sufficient low and zero pollution capacity to make the necessary reductions and stay within EPA's budgets with variability limits, even with an unexpected shutdown. [EPA-HQ-OAR-2009-0491-2666.1, p.22]
The selected remedy includes an enforcement mechanism that will provide the necessary incentives for source owners to keep within their respective share of EPA's state budgets, and therefore allows states to stay within their budgets. Specifically, each source owner knows that if its emissions exceed its share of the state budget by more than the variability limit ("excess emissions"), it runs the risk of needing to surrender an additional allowance for every ton of these excess emissions if the state exceeds its budget plus variability limit. This will create an incentive to operate pollution control equipment rather than buying allowances. Although the proposed rule is unclear on this point, it appears that if a state exceeds both its one year and three year variability limits, a source owner may need to surrender an extra allowance for every ton by which it exceeds either variability limit. That is, in some circumstances, an owner could be required to surrender up to three allowances for a single ton of emissions. This potential consequence will encourage companies to limit their emissions so that they need not purchase additional allowances to meet their compliance obligations beyond the amount of their variability limits. If all companies in a state limit their emissions in this manner, the state will not exceed its budget plus variability limits. Nonetheless, Exelon offers some enhancements to EPA's proposal in Comments 5.2, 5.3 and 5.4 to strengthen the incentives for owners to manage their emissions in support of states staying within their budgets plus variability limit. 44 [EPA-HQ-OAR-2009-0491-2666.1, pp.22-21]
AN ALTERNATIVE COMPLIANCE ASSURANCE MECHANISM COULD MORE EFFECTIVELY ACHIEVE THE REDUCTIONS NECESSARY UNDER THE CAA.
The compliance assurance mechanism is the critical aspect of the interstate trading program that ensures that each state's emissions will stay within the Transport Rule budget plus variability limits. EPA's proposed assurance mechanism will encourage this goal, but will not necessarily produce the least-cost outcome. Specifically, the annual emissions for each source owner will likely be dictated by its initial allowance allocation instead of a dynamically-optimized market solution. [EPA-HQ-OAR-2009-0491-2666.1, p.24]
EPA's assurance provision requires that if a state exceeds its budget plus variability limit, then each source owner with excess emissions must surrender additional allowances. However, because EPA's assurance provision assigns a fixed share of the state budget to each source owner, owners in the same state may face very different incentives to limit or reduce their emissions. [EPA-HQ-OAR-2009-0491-2666.1, p.24]
Consider the following example, illustrated below: a state has two source owners (A and B), each with an initial allocation of 100 allowances. In a particular year, Source A has physical emissions of 111 tons and Source B has physical emissions of 109 tons, so any additional emissions from either source owner will violate the one-year variability limit and trigger the assurance provision in that state (i.e., 220 tons of physical emissions in the state are equal to the 200 ton state budget plus the 10% variability limit). Source A has a strong incentive not to increase emissions because it will have to surrender two allowances for each ton of excess emissions if another ton is emitted in the state. But Source B has no such incentive and can emit another ton without having to surrender two allowances. In addition, if Source B were to reduce its emissions by one ton, then Source A could increase emissions without triggering the assurance provision. In this situation, a one ton reduction from Source B should have a value to Source A of up to twice the national allowance price, because Source A would need to surrender two allowances for each additional ton emitted (without the reduction from Source B). Unfortunately, EPA's proposed assurance provision does not provide a mechanism for Source B to realize more than the national allowance price for its emission reductions in this situation because emission allowances are not a state-specific product, and therefore cost-effective emission reductions in the state may not occur. [EPA-HQ-OAR-2009-0491-2666.1, p.24]
[See P.25 of this comment summary for a figure entitled EPA's Proposed Assurance Provision]
This inefficiency increases compliance costs, and therefore increases the likelihood that certain states will exceed their budget plus variability limit. In addition, EPA's proposed assurance provision complicates implementation of the future state budget reductions that will be necessary following the upcoming NAAQS revisions because it will require amendment of the allocations to each unit. [EPA-HQ-OAR-2009-0491-2666.1, p.25]
As recommended by The NorthBridge Group report, Exelon proposes two modifications to EPA's State Budgets/Limited Trading remedy that could improve the outcome, as illustrated below. Under Exelon's proposal, states would maintain their budgets, as determined by the IPM modeling, and variability limits and interstate trading would be permitted. First, the allowances related to each state would be identified by a serial number and vintage year. For example, the credits associated with the Pennsylvania budget would be identified as PA-2012-00001, etc., with Delaware as DE-2012-000001, etc. Second, excess emissions would be the determined by a comparison of physical emissions to the number of instate/ in-vintage year allowances that the owner surrenders for that year, rather than the initial allocation of allowances that the owner receives. Under this mechanism, if a state exceeded its budget plus variability limit, source owners in the state whose emissions exceeded the number of in-state/in-vintage year allowances that the owner has surrendered for its sources within the state, plus the variability limit (which could satisfied by out-of-state or out-of-year allowances) would need to surrender an additional allowance, just as is the case under the current program. [EPA-HQ-OAR-2009-0491-2666.1, p.25]
[See p.26 of this comment summary for a figure entitled Assurance Provision After Modifications] 
These modifications would create a much more dynamic intra-state trading market because all source owners within a state would have the same price incentive to reduce emissions regardless of their initial allocation of allowances. This would encourage all cost effective emission reductions in a state that approaches its budget plus variability limits rather than in a different state and create more options for source owners to manage compliance. The incentives for interstate trading and banking would also be kept intact. At the same time, this change would provide greater assurance that states would not exceed their budgets plus variability limits. [EPA-HQ-OAR-2009-0491-2666.1, p.26]
Exelon's proposed modification will provide two additional benefits as a result of removing the linkage between a unit's initial allocation and the compliance assurance mechanism. First, this compliance method would simplify rapid implementation of future reductions to state budgets (e.g., in response to more stringent NAAQS) by allowing unit allocations to be reduced by a uniform percentage rather than reallocating based upon future unit operations and pollution control investments. As discussed in Comment 8, reallocation of unit allowances based upon future operating decisions would create perverse incentives to continue to operate inefficient and highly polluting units. Second, this compliance mechanism would reduce the likelihood that the proposed Transport Rule or a revision of the rule to implement revisions to NAAQS will be challenged because of anomalies or errors in determining unit allowance allocations based on the IPM. The relative magnitude of an error in an individual unit's emissions allocation based on a model would ordinarily be greater than that of any error in the budget for the state as a whole, and could give rise to successful challenges based on individual unit reallocations regardless of the defensibility of the reduced state budget. [EPA-HQ-OAR-2009-0491-2666.1, p.26]
COMPLIANCE WITH STATE BUDGETS WOULD BE BETTER ASSURED BY MAKING SIGNIFICANT EXCEEDANCES OF BUDGETS PLUS VARIABILITY LIMITS A VIOLATION OF THE CAA.
The proposed Transport Rule's satisfaction of the requirements of the North Carolina decision depends upon creating sufficient incentives to ensure that the unit owners in a state do not collectively cause that state to exceed its budget by more than the variability limits. If every owner in a state operates its units so that it has no "excess emissions" (here, no more than the in-state, in-vintage year allowances it surrenders, plus the variability limits), it is mathematically impossible for a state to exceed its budget, plus variability limits. However, the penalty for each ton of excess emissions is limited to the lowest cost of an additional allowance that the owner can purchase from any state, and any vintage year. Under the proposed rule, an owner who has excess emissions would not violate the CAA regardless of the number of tons by which it exceeds its budget, provided the owner acquires an extra allowance for each ton of excess emissions. Under certain market conditions, emission allowance prices could be lower than the profit to be gained from generation, in which case an owner would have an incentive to operate regardless of whether it causes the state to exceed its budget. In order to ensure that the Transport Rule achieves its goal of eliminating each state's significant downwind contribution, the rule must limit the ability of owners to produce excess emissions without any certain financial penalty. Therefore, Exelon proposes that EPA establish a level of excess emissions that would constitute a violation of the CAA. Because, under Exelon's proposed compliance assurance mechanism, variability limits will reflect proportionally the demand for a given owner in a given year, Exelon proposes that EPA establish this compliance benchmark using a multiple of the variability limit for a given facility, such as twice the three-year variability limit. An owner who emits excess emissions above the level fixed by EPA in the final Transport Rule would be in violation of the CAA, and subject to civil penalties and other enforcement measures. Such a provision would create an additional and much more powerful incentive for source owners to avoid excess emissions, and thus for states to achieve their emission budgets. [EPA-HQ-OAR-2009-0491-2666.1, p.27]

44 See also The NorthBridge Group, An Alternative Compliance Assurance Mechanism Could More Effectively Achieve the Reduction Necessary Under the Clean Air Act, attached as Exhibit 3 [See p. 60, Appendix C The Potential Loss of Highway Funds.]
New York University School of Law, Institute for Policy Integrity
Even within the preferred approach, the assurance provisions create an important limit to trading. Under the current assurance provisions, if a state exceeds its total emissions budget plus the assigned variability limit (BVL), the sources within the state will be subject to an allowance surrender requirement. In years when a given state exceeds the BVL, those facilities that emit more than their share of the state BVL (as determined by the initial allocation of allowances) will be required to surrender an extra allowance for each ton they emit over their proportional share of the BVL. [EPA-HQ-OAR-2009-0491-2691.1, pp.6-7]
Therefore, each firm is given an initial allocation of allowances, reflecting a proportional share of the state budget, Bi for firm i. The firm is also allocated a proportional share of the budget plus variability limit, BVLi for firm i. As a firm purchases allowances over Bi but less than BVLi the price of the allowance is Þ. But, if a firm wishes to purchase total allowances for a year over the BVLi, the effective price is Þ plus the probability that the state will exceed its variability limit times the expected price of an allowance next year: Þ0 + PROBexceed*Þ1. This mechanism creates a significant degree of uncertainty for firms that are net purchasers of allowances and also has the potential to generate steep cost increases in the neighborhood of BVLi. This uncertainty is compounded by the existence of separate one-year and three-year variability limits. The current system also puts pressure on EPA to determine Bi correctly, because an initial misallocation of permits will increase the likelihood that firms will be forced to purchase allowances in excess of BVLi, triggering the uncertainty problem. [EPA-HQ-OAR-2009-0491-2691.1, p.7]
Further, in states that are likely to exceed their BVL, the effective price of allowances approaches Þ0 + Þ1. Any firm whose marginal abatement cost is greater than Þ0 but less than Þ0 + Þ1 will then reduce its own emissions rather than purchase an allowance. But within the range between Þ0 and Þ0 + Þ1 (which might be quite large), some firms in the state may have considerably lower marginal abatement costs than others, and yet these firms will not be incentivized to take advantage of such cost differences by trading. Because the current structure does not fully exploit each state's lowest-cost abatement opportunities, it is not as efficient as it could be. [EPA-HQ-OAR-2009-0491-2691.1, p.7]
Recommendation: Assurance Allowance Mechanism
EPA should consider a modification that would eliminate many of the uncertainty problems discussed above, while hewing even more closely to the judicial mandate in North Carolina. Through the creation of an intrastate Assurance Allowance Mechanism that operates in tandem with the interstate emissions trading program, EPA can provide states significant financial incentives to avoid emitting over the variability limit, while increasing predictability and flexibility for complying firms. [EPA-HQ-OAR-2009-0491-2691.1, p.7]
Under the Assurance Allowance Mechanism, each state would be allocated a total budget of interstate trading allowances (ITAs) for each pollutant category. These ITAs could be traded freely between and within states. States would also be allocated a budget of tradable assurance allowances (TAAs) for each pollutant category. The TAA budget would be defined as the state ITA budget plus a variability limit. TAAs would only be eligible for intrastate trading. Each firm would be required to surrender an ITA and a TAA for each ton of pollution it emits. [EPA-HQ-OAR-2009-0491-2691.1, p.7]
For states that are net exporters of ITAs, the price of TAAs will approach zero, because there will be excess supply. For states that are net importers of ITAs, the price of TAAs will increase as excess supply approaches zero. [EPA-HQ-OAR-2009-0491-2691.1, p.7]
The fixed number of TAAs will create an absolute assurance that a state will not exceed its variability limit in a given year. This rock-solid assurance will meet the requirements of North Carolina, but will also lead to potentially large interstate differences in marginal abatement costs, and the potential for states to "run out" of allowances if firms have not adequately anticipated their emissions requirements. To avoid these problems, EPA can increase flexibility in two ways: banking, and conversion of ITAs to TAAs at fixed conversion rates. [EPA-HQ-OAR-2009-0491-2691.1, p.7]
Banking is a preferable method for dealing with inter-year variability, compared to setting different one-year and three-year variability limits. Banking allows firms to determine how best to allocate emission over time, and prices are immediately updated to reflect changing market conditions -- providing more information to facilitate planning. By allowing the creation of a reserve of TAAs, banking also helps avoid price spikes if firms have not adequately predicted their needs in a given year. [EPA-HQ-OAR-2009-0491-2691.1, p.8]
A second flexibility mechanism would allow firms to convert ITAs to TAAs. At a 1:1 conversion ratio, the maximum price of a ton of emissions would be two times the price of an ITA. This is essentially the same as the maximum price set under EPA's current preferred approach. If EPA chose, it could also increase the conversion factor, or set an increasing scale conversion factor, such that a fixed number of ITAs could be converted to TAAs at a ratio of 1:1, another fixed number of conversions could be made at a ratio of 2:1, and so on. The increasing incremental scale would enhance the financial incentives for firms to reduce in-state emissions, while creating a pressure valve at all levels of emission to avoid extreme price spikes. [EPA-HQ-OAR-2009-0491-2691.1, p.8]
This proposal has several distinct advantages over both the preferred approach and the alternative approaches. Because it can be structured to create an absolute guarantee of no emission over the variability limit, while retaining robust interstate trading, it is superior to the two alternatives to the preferred approach. This proposed assurance allowance mechanism allows EPA to home in on the North Carolina mandate by creating guarantees and incentives for each state to make actual reductions, even while providing for greater flexibility and lower costs than EPA's preferred approach. Compared to the preferred approach, the assurance allowance mechanism provides better predictability and certainty to firms, avoids intrastate differentials in marginal abatement costs, allows firms to base decisions on allowance prices rather than guesses about the likelihood of the entire state exceeding the variability limit, and relies less heavily on EPA to perfectly predict the proportional share of state emissions for each facility during an initial allocation. [EPA-HQ-OAR-2009-0491-2691.1, p.8]
Overall, this proposal better meets the statutory and judicial guidance while lowering costs and increasing predictably and flexibility. EPA should give this alternative close consideration. [EPA-HQ-OAR-2009-0491-2691.1, p.8]
Response: 
These comments put forward an alternative approach to assurance provisions that would delink allocations from assurance provisions and create a new type of allowance for assurance compliance.  EPA considered these innovative approaches and found them interesting, but not free of obstacles.  EPA's principal concern with these alternatives is that they resemble the intrastate trading option described in the proposal, which faced market concentration problems.  In many states, a single large utility controls a majority of the generation and would have control of the majority of allowances in that state.  This leads to serious market liquidity and allowance pricing concerns.  For this reason, in addition to the complexity of running numerous trading programs and auctions, EPA chose not to implement these alternative approaches to assurance provisions.  See the proposal preamble section V and the Electric Generation Ownership, Market Concentration and Auction Size TSD for the proposal for more information about EPA's analysis of state markets and potential for market power problems.
EPA believes that the assurance provisions as finalized, with a few modifications and improvements from the proposal, provide a reasonable and effective solution to addressing the court's mandate that upwind states eliminate significant contribution to nonattainment and interference with maintenance of air quality standards.  The final approach provides the necessary assurance while still offering sources with compliance flexibility and allowing them to trade.  In general, other commenters did not disagree with EPA's approach and the linking of allocations to these provisions.
Organization: Florida Municipal Electric Association (FMEA)
Comment: 
Florida Municipal Electric Association (FMEA)
FMEA has concerns with EPA's automatic penalty provision: EPA establishes an automatic penalty system that will assess penalties on utilities retroactively if states exceed their state cap even if the individual utility is in compliance with its own allowance requirements. This is in addition to penalties based on the Clean Air Act (CAA) violations for emitting more emissions than the utility has allowances. This penalty system provides no compliance certainty for any given utility regardless of the precautions taken by an individual utility. [EPA-HQ-OAR-2009-0491-2731.1, p. 10]
Response: 
If assurance provisions are triggered, only those sources that exceed their allowance allocations plus share of the state's variability limit at the common designated representative level would be held responsible for surrendering allowances under the penalty provisions.  Those sources (at the DR level) that do not emit more than their allocations plus share of the state's variability limit do not pay any penalty, thereby providing certainty to those sources.  The penalty for triggering the assurance provisions is an allowance surrender of 2 allowances for every 1 ton of emissions that exceed the state assurance level (state budget + variability limit).  Exceeding the state assurance level is not a CAA violation.  See preamble section VII.E for more information about assurance provisions and penalties. 
Organization: GE Energy Financial Services (GE EFS)
Comment: 
GE Energy Financial Services (GE EFS)
The Assurance Provisions Would Unfairly Prejudice Long-Term Contract Generators Who Cannot Pass Along the Costs of Additional Allowances
By requiring the surrender of one additional allowance for each ton emitted over a facility's proportional share of a state's exceedance of its budget and variability limit, the Proposed Transport Rule's 'assurance provisions' will unfairly prejudice the interest of long-term contract generators, vis-a-vis utility-owned or merchant generating facilities, which can recover the costs for additional allowances from ratepayers or through the market price of electricity. GE EFS holds an interest in a number of facilities subject to long-term contracts which could be significantly impacted by the assurance provisions. In light of this, GE EFS would encourage EPA to include provisions in the final rule that would provide relief to long-term contract generators from the impacts that the assurance provisions could have on their operating costs and competitiveness. [EPA-HQ-OAR-2009-0491-2701.1, p.5]
Response: 
If assurance provisions are triggered, only those sources that exceed their allowance allocations plus share of the state's variability limit at the common designated representative level would be held responsible for surrendering allowances under the penalty provisions.  Those sources (at the DR level) that do not emit more than their allocations plus share of the state's variability limit do not pay any penalty, thereby providing certainty to those sources.  See preamble section VII.E for more information about assurance provisions and penalties. 
Organization: Indiana Energy Association
Comment: 
Indiana Energy Association
d. The Indiana Utility Group supports the concept that penalty provisions apply (1) only if state total budgets (plus variability limits) are exceeded and (2) if so, penalties are assessed on an individual company basis. [EPA-HQ-OAR-2009-0491-3711 p.5]
Response: 
In the final rule, penalties are assessed at the common designated representative level, which may or may not align with EGU ownership.  This still provides sources with some degree of compliance flexibility.  For more on assurance provisions, see preamble section VII.E.
Organization: Lansing Board of Water & Light
Comment: 
Lansing Board of Water & Light
BWL recognizes the need for "Assurance Provisions" but the current structure (especially when coupled with "variability limits") is simply not appropriate. The assurance provisions are tied to the interstate trading program; however, the associated risk with these two provisions effectively eliminates interstate trading. [EPA-HQ-OAR-2009-0491-2752.1,p.8]
Response: 
If assurance provisions are ever triggered, only those sources that exceed their allowance allocations plus share of the state's variability limit at the common designated representative level would be held responsible for surrendering allowances under the penalty provisions.  Those sources (at the DR level) that do not emit more than their allocations plus share of the state's variability limit do not pay any penalty, thereby providing certainty to those sources.  EPA does not anticipate that interstate trading will be eliminated and this comment does not provide any evidence to support its assertion.  See preamble section VII.E for more information about assurance provisions and penalties. 
Organization: Large Public Power Council (LPPC)
Comment: 
Large Public Power Council (LPPC)
C. The Assurance Provisions Unfairly Penalize All EGUs by Withdrawing Allowances From the Cap
LPPC believes that the proposed assurance provisions are an inequitable and unwise mechanism for enforcing the variability limits of the Transport Rule. As proposed, the assurance provisions would require owners of EGUs in states whose allowance usage exceeds the variability limits to submit an additional allowance for every ton of pollution in excess of the "owner's share" of the state emissions budget and variability limit. 47 Those additional allowances would have to be obtained from the owner's own reserves of banked allowances or from other owners of EGUs, making them unavailable for compliance. The end result of this mechanism would be to withdraw allowances from circulation in the Transport Rule trading system  -  and in so doing drive up the prices of allowances for all other market participants, including owners of EGUs that have not exceeded their owner's share or who are located in states that have not triggered the assurance provisions at all. These increased costs would, of course, be shared with ratepayers in many cases. From an environmental perspective, the submission of additional allowances is also unnecessary because even EGUs subject to the assurance provisions would still hold enough allowances to cover their emissions. [EPA-HQ-OAR-2009-0491-2667.1, pp.14-15]
Innocent owners of EGUs  -  and the customers they serve  -  should not be penalized for others' excessive use of allowances. LPPC recommends that EPA consider an alternative form of enforcement that would be equally effective and avoid these undesirable consequences: a straightforward cash payment. The amount of the payment could be set equal to the product obtained by multiplying the quantity of emissions in excess of the "owner's share" by the average market price of allowances in the relevant state during the compliance period for which the assurance provisions were triggered. This solution would leave the supply of allowances available for compliance unaffected, while providing the same economic incentive for owners of EGUs to remain within their share of the variability limit. [EPA-HQ-OAR-2009-0491-2667.1, p.15]

47 75 Fed. Reg. at 45,312-13. [EPA-HQ-OAR-2009-0491-2667.1, p.14]
Response: 
As explained in the preamble section VII.E, EPA has designed the assurance provisions and penalties to ensure that states will not exceed their assurance levels.  EPA believes that any assurance penalty would be de minimis and have no noticeable effect on the market, and that in all probability, the assurance provisions will not be triggered.  EPA does not anticipate sources having to surrender allowances in quantities large enough to impact allowance prices based on its experience with other trading programs such as the Acid Rain program and CAIR in which compliance problems have been very infrequent.  The use of allowances for penalties is also based on previous trading programs such as the Acid Rain program, NOx budget trading program, and CAIR.
Organization: Maryland Department of Environment (MDE)
Comment: 
Maryland Department of Environment (MDE)
Maryland prefers among the trading options the State Budgets/Limited Trading Proposed Remedy. The problem with it is that variability is being accounted for twice. Once through trading and banking and then again when trying to address "allowance surrender". Maryland suggests that the variability concept be applied within the individual state budgets rather than in addition to state budgets. Otherwise sources have the ability to emit up to their "proportional share of the variability limit" beyond the allocations purchased/used by a particular source. [EPA-HQ-OAR-2009-0491-2639.2, p.15]
EPA states that trading and banking "accounts for variability in the electricity sector". EPA is also proposing to impose assurance provisions starting in 2014. The assurance provisions will result in allowance surrender only if:
1. a state exceeds its budget plus variability in a given year or on average triennially AND
2. an owner's unit's emissions exceed the owner's share of the state budget PLUS variability limit [EPA-HQ-OAR-2009-0491-2639.2, pp.14-15; This comment can also be found at IV.D.6. of this comment summary]
Response: 
As explained in the preamble, state-level emissions are likely to vary even after all significant contribution to nonattainment and interference with maintenance that EPA identified in this final rule are eliminated. EPA believes that the remedy uses variability limits in a way that both provides the flexibility of limited interstate trading for dealing with real-world variability in the operation of the power system and for reducing costs of compliance with emission reduction requirements, as well as providing assurance for downwind states that significant contribution to nonattainment and interference with maintenance by upwind states will be eliminated.  This state- or system-level variability is not the same as unit-level compliance flexibility, which banking and trading address. 
EPA does not believe it has the authority to set budgets below what is required to eliminate significant contribution and interference with maintenance, which is what this comment seems to suggest.  EPA's remedy is consistent with CAA requirements and the court's rulings.  See preamble section VI.E for more information about variability limits and required reductions.
Organization: Metropolitan Washington Air Quality Committee
Mississippi Department of Environmental Quality
Kentucky Division for Air Quality
PSEG Services Corporation
Institute of Clean Air Companies (ICAC)
Comment: 
Institute of Clean Air Companies (ICAC)
Finally, ICAC supports EPA's variability limit calculation methodology for the preferred remedy. These variability limits will, in the spirit of maximizing flexibility for sources, in turn maximize trading opportunities for sources while assuring downwind states that upwind state significant contribution and interference with maintenance will be eliminated through actual reductions. [EPA-HQ-OAR-2009-0491-2695.1, p. 3]
Kentucky Division for Air Quality
Support of EPA Preferred Approach with Assurance Provisions for the Transport Rule and the Adding of Variability Limits to the State Emission Budgets  
Pursuant to the rule preamble Section V.D.4., State Budget/Limited Trading Proposed Remedy (75 FR 45305), EPA's preferred approach is to allow limited interstate trading, but to also include assurance provisions to ensure that the majority of power plants in each state control their own emissions rather than buy out-of-state allowances. This option is implemented by adding variability limits to each state budget starting in 2014, and if a state's emissions exceed the budget plus the variability limit, sources in the exceeding state are penalized (through the turn-in of allowances) based on their proportional share of the overage in emissions. The Division supports EPA's preferred approach with assurance provisions and the inclusion of variability limits added to each state's budgets. The Division agrees with EPA's position that variability limits should be included to account for unplanned increased emissions in a state due to situations such as extreme weather events, unplanned outages or unexpected load demands because of an unusually hot summer. [EPA-HQ-OAR-2009-0491-2805.1, p.5]
Metropolitan Washington Air Quality Committee
MWAQC also supports the proposal to limit interstate emissions trading through assurance provisions requiring states to maintain overall emission levels below the state caps. For regions to meet stringent NAAQS requirements, we must be able to rely on emission reductions occurring at sources that actually impact air quality in the region. While unrestricted interstate trading may assist the regulated community meet emission caps more cost-effectively, trading also removes the necessary impetus for achieving reductions where it may matter most. To that end, we applaud EPA for taking the bold steps needed to ensure this happens. [EPA-HQ-OAR-2009-0491-2618.1, p.2]
Mississippi Department of Environmental Quality
We also support the variability provisions in this option. [EPA-HQ-OAR-2009-0491-2634.1, p.1]
PSEG Services Corporation
PSEG supports the assurance provisions proposed in the Transport Rule. [EPA-HQ-OAR-2009-0491-2726.1, p.2]
Response: 
EPA is finalizing variability limits and assurance provisions for the Transport Rule.  Some minor modifications were made from what was included in the proposal as a logical outgrowth of our updated modeling and the public comments.  See preamble sections VI.E and VI.F for more information about variability limits and preamble section VII.E for information about assurance provisions.
Organization: Michigan Department of Natural Resources and Environment
Comment: 
Michigan Department of Natural Resources and Environment
In the proposed TR, a ten percent variability is described as the assurance provision for meeting Section 110 requirements. The EPA added that Section 110 does not require compliance with a budget but with emission reductions. The proposal indicated that if a state goes over their budget within the variability limits established, it is not considered a violation of provisions within the Clean Air Act. However, if a source in such a state exceeds the variability limit, based on budgets assigned in the TR, they would be determined responsible for the overage and liable for exceedance penalties as well as required to surrender extra allowances. [EPA-HQ-OAR-2009-0491-2774.1 p.4]
The DNRE disagrees that requirements for compliance with Section 110(a)(2)(d) rest solely in the ability of a source to meet the variability limits as indicated in the TR. We believe that the responsibility to effectively manage a program is the responsibility of the state. The DNRE believes that state determinations of allocations ensure more equity, due to stakeholder input during the SIP rulemaking process. To this end, we believe that the state should determine the allocations for each subject unit, based on the total state budget as stated in the TR. [EPA-HQ-OAR-2009-0491-2774.1 p.4]
Assurance Provisions and Variability Calculations The proposed TR assumed assurance provisions (i.e., variability limitations) will demonstrate compliance with the Section 110(a)(2)(d) transport requirements. Under the TR, larger states are assigned a variability of ten percent and smaller states a specified value. Variability limits were included to address concerns of electricity reliability in years or seasons of greater/higher demands. Variability limitations begin in 2014. At the end of 2014, the EPA will determine if the state has exceeded their budget by greater than ten percent; if so, the EPA will determine which sources created the overage. The proposed TR included an example:
A state is 20 percent over their budget:
:: The EPA determines that one source was ten percent below their budget; the remaining two sources were over by ten percent each.
:: To cover the overage for the state, each of the sources that were over would be required to surrender five percent more allowances. (Not ten percent because the entire state is allowed an overage of ten percent on a yearly basis.)
:: Additionally, the three-year average of variability overages cannot exceed three percent for the entire state.
In addition, the proposal indicated that 2015 and beyond allowances may be used for exceedances of variability only, not for regular compliance needs in 2014, since the true-up occurs after the end of the compliance year (i.e., in the next year 2015 or beyond). [EPA-HQ-OAR-2009-0491-2774.1 p.4]
The DNRE believes this process will unfairly impact sources choosing to add on controls. What incentive does the source that is below its budget by ten percent have to generate reductions? The DNRE does not believe the potential sale of their extra allowances to other sources with emissions contributing to a percent overage would be incentive enough to cover the original cost to the source for additional controls. The DNRE also believes this would hamper active trading of allowances and potentially create unnaturally high pricing of allowances within the market.[EPA-HQ-OAR-2009-0491-2774.1 p.4]
As noted above, we disagree that requirements for compliance with the Section 11 O(a)(2)(d) requirements rest solely on the ability of a source to meet the variability limits. The determination of impacts for the proposed TR was based on state-level specific emissions impacting areas downwind. This determination was not completed using source-level specific emissions as those emissions traveled downwind. [EPA-HQ-OAR-2009-0491-2774.1 p.5]
In several areas within the impact methodology discussion in the proposed TR, contributions to downwind areas, i.e., impacts on the attainment and maintenance for downwind areas, were calculated using a 'state's' contribution. The EPA indicated in their technical support documentation (TR_AQModeling_TSD.pdf) that they created pollutant 'tags' and followed these tagged emissions of NOx, S02 and primary fine particulate matter (PM2.5) across state borders to the impacted areas downwind. Further, the EPA did not indicate where a 'tagged' emission originated (such as Monroe power plant unit #4) other than from the state itself. Therefore, the DNRE believes it is logical that any determination of the assurances provisions should be based on a 'state's impact,' not on individual source impacts. This approach is another reason the DNRE believes that the SIP approach of allowing the state to address allocations is more consistent with the EPA analysis. [EPA-HQ-OAR-2009-0491-2774.1 p.5]
Response: 
States may submit and implement SIPs as early as 2013.  See preamble section X on state implementation plans for more details.
If assurance provisions are triggered for a state, only those sources that exceed their allowance allocations plus share of the state's variability limit at the common designated representative level, not the unit or source level, would be held responsible for surrendering allowances under the penalty provisions.  Those sources (at the DR level) that do not emit more than their allocations plus share of the state's variability limit do not pay any penalty, thereby providing certainty to those sources. See preamble section VII.E for more about assurance provisions and penalties.
Organization: Michigan Municipal Electric Association (MMEA)
Comment: 
Michigan Municipal Electric Association (MMEA)
7.) EPA's Assurance Provisions Could Be Particularly Problematic for Michigan Public Power Units
EPA's assurance compliance provisions will impose a significant pro-rata penalty on any unit that did not reduce emissions sufficiently in any state that exceeds its emissions budget plus variability margin. However, given that Michigan public power units do not have the ability to cost effectively apply major pollution controls, and instead comply through Michigan hardship allowances, the application of assurance provisions on Michigan would impose massive, disproportionate impacts on public power communities. If Michigan exceeds its annual budget with variability, it will not be because of the small units owned and operated by the six public power systems commenting here, which contribute a relatively small amount of NOx and SO2 pollutions in comparison to the large, investor-owned utilities in the State. If Michigan exceeds these levels, it will be because of other parties, and will be beyond any control by these public power communities. Yet the hardest impact of EPA assurance penalties will likely fall on these small public power units because they will continue to comply primarily through allowances (whether allocated by EPA or the State, via regular or hardship allowances, or by allowance purchases), because pollution controls are cost-ineffective. If and when the assurance boom comes down on Michigan in the future, small municipal utilities will be extremely vulnerable and will bear the worse brunt of the penalties. [EPA-HQ-OAR-2009-0491-2828.1, p.15]
8.) Avoid "assurance" mechanisms that would pose disproportionate penalties on small municipal utilities that depend on allowance trading to meet compliance obligations. [EPA-HQ-OAR-2009-0491-2828.1, p.16]
Response: 
If assurance provisions are triggered, only those sources that exceed their allowance allocations plus share of the state's variability limit at the common designated representative level would be held responsible for surrendering allowances under the penalty provisions.  Those sources (at the DR level) that do not emit more than their allocations plus share of the state's variability limit do not pay any penalty, thereby providing certainty to those sources.  Further, responsibility for exceeding the state assurance level is determined at the common DR level, so it is generally not the case that the emissions of a single unit will automatically result in a penalty if the state assurance level is exceeded.  In addition, allowing units to designate a single common DR provides them with greater compliance flexibility. See preamble section VII.E for more information about assurance provisions and penalties. 
Finally, if the state of Michigan submits and implements a SIP, it can choose to allocate allowances using a different approach that addresses these circumstances for Michigan's public power generators. 
Organization: Morgan Stanly Capital Group
Comment: 
Morgan Stanly Capital Group
An individual facility's compliance depends on the overall performance of the state in which it is located, over which it will have no control; [EPA-HQ-OAR-2009-0491-2819.1 p.2]
There will not be timely access to cumulative, state-by-state emissions data, which would be required for a generator to have any capability of managing the risk of incurring penalties for excess emissions; [EPA-HQ-OAR-2009-0491-2819.1 p.2]
A facility that exceeds its portion of the applicable state variability limit cannot cover its excess emissions by purchasing allowances. Instead, if the state exceeds its variability limit, that facility is required to surrender two allowances for every ton of excess emissions, in addition to being subject to discretionary penalties under the Clean Air Act ("CAA"); [EPA-HQ-OAR-2009-0491-2819.1 p.2]
The EPA's primary proposal can provide for additional flexibility and still be compliant with North Carolina v. EPA, where the D.C. Circuit Court found that the Clean Air Interstate Rule ("CAIR") trading program was not authorized under the CAA because the regional program failed to prohibit sources "within the State" from contributing to nonattainment "in any other State."23 The D.C. Circuit Court did not suggest that a cap-and-trade market design could never be effective, but rather, that "region wide caps with no state-specific quantitative contribution determinations or emissions requirements" were inadequate to address the CAA's directive.24 As a result, the EPA is required to:
[EPA-HQ-OAR-2009-0491-2819.1 p.8]
 link and measure a state's significant contribution to each downwind state's nonattainment (which is addressed in determining individual state emissions caps);25
consider more than "highly cost-effective controls" in quantifying a state's significant contribution of a pollutant (which the D.C. Circuit Court defined as taking reasonable measures to assure upwind states will reduce emissions below their calculated significant contribution).
The Proposed Rule addresses the D.C. Circuit Court's directive by:
measuring and linking each upwind source to its corresponding downwind nonattainment area;
quantifying the "significant contribution" of each precursor pollutant for each state using "maximum cost considerations" informed by air quality considerations;27 and
setting emissions budgets or caps for each state based on the state's significant contribution of the particular pollutant involved.
[EPA-HQ-OAR-2009-0491-2819.1 p.9]
However, the D.C. Circuit Court decision does not require the Proposed Rule's automatic double surrender of allowances under the assurance provisions, or the potential imposition of discretionary penalties under the CAA when a facility exceeds its share of the state's overall emissions budget and variability limits.28 Similarly, the decision does not mandate how allowances are to be provided or whether or how to structure the variability limits established in the Proposed Rule. Given the risks that the Proposed Rule may pose to the development and reliability of power generation, the EPA should consider modifications that provide greater flexibility and avoid a "one size fits all" approach which could severely handicap minor emission sources and those operating on an intermittent basis. [EPA-HQ-OAR-2009-0491-2819.1 p.9]
The modifications now suggested for EPA consideration do not affect the basic premises of the Proposed Rule or the principles enunciated in North Carolina v. EPA. Instead, they focus on deployment of a relatively small portion of the allowances, preservation of an increment of the variability limits to ensure compliant operation, and provision of a more workable compliance alternative for sources with limited emissions and intermittent operations that will find it especially difficult to operate in compliance with the Proposed Rule. Incorporation of the foregoing modifications into the Proposed Rule will therefore enhance compliance and strengthen its impact, thereby helping to ensure that the directives of the North Carolina decision are met.
3. Alternative Compliance Payment as Alternative to Double Allowance Surrender Provision
MSCG recognizes and understands the reason for the Administrator's inclusion of mandatory emissions budgets on a state-wide basis that impose penalties on non-compliant sources (i.e., "assurance provisions"). That reason is of course the D.C. Circuit Court's directive to reduce downwind nonattainment linked to state-level upwind emissions. However, such penalties can be particularly harsh when applied to intermittent sources of emissions whose operation is subject to outside demands and therefore have greater difficultly projecting and budgeting for their emissions. [EPA-HQ-OAR-2009-0491-2819.1 p.7]
Another option for this limited class of relatively minor emission sources is an up-front "alternative compliance payment," or ACP, in lieu of the double allowance surrender and potential penalty payment. The value of the ACP would be established on a state-specific basis and at a sufficiently high level to encourage installation of pollution control equipment in its stead, particularly in states that are significant contributors to downwind exceedances. Nevertheless, such an option could be utilized to ensure against the imposition of a penalty or where installation of pollution control equipment is not a viable option due to facility operations and size.
In addition to these practical considerations, MSCG strongly opposes the surrender of two allowances as a matter of public policy. Instead of solely "punishing" a violator, it punishes all market participants. In a program where there are a finite number of allowances, a "double surrender" will artificially reduce the total supply. All other things being equal, a reduction in supply will increase price. This in turn this raises costs for other producers who have complied with the Proposed Rule, and those costs ultimately get passed to consumers. [EPA-HQ-OAR-2009-0491-2819.1 p.7]
Response: 
There is timely generation and emissions data available to owners and operators to make decisions about buying or selling allowances and whether the state is likely to approach its state assurance level (budget plus variability limit) during the control period.  Covered sources have operational and compliance flexibility in this rule, to the extent possible under EPA's authority and the court rulings.
Exceeding the state assurance level is not a CAA violation.  See preamble section VII.E for more information about assurance provisions and penalties.
As explained in the preamble section VII.E, EPA has designed the assurance provisions and penalties to ensure that states will not exceed their assurance levels.  EPA believes that any assurance penalty would be de minimis and have no noticeable effect on the market, and that in all probability, the assurance provisions will not be triggered.  EPA does not anticipate sources having to surrender allowances in quantities large enough to impact allowance prices based on its experience with other trading programs such as the Acid Rain program and CAIR in which compliance problems have been very infrequent.  The use of allowances for penalties is also based on previous trading programs such as the Acid Rain program, NOx budget trading program, and CAIR.
Organization: National Association of Clean of Air Agencies (NACAA)
Comment: 
National Association of Clean of Air Agencies (NACAA)
Adding a Variability Factor to the Emissions Budgets Dilutes the Environmental Integrity of the Rule
EPA presents three "remedy" options for implementing the Transport Rule's emissions reduction requirements. EPA's preferred approach would use state-specific control budgets and allow for intrastate and limited interstate trading of emissions allowances allocated to power plants, to ensure that the majority of power plants in each state control their own emissions rather than buy out-of-state allowances. This option is implemented by adding a variability factor to each state budget, and if a state's emissions exceed the budget plus the variability factor, sources in the exceeding state are penalized (through the turn-in of allowances) based on their proportional share of the overage in emissions. [EPA-HQ-OAR-2009-0491-2771.1, p.4]
NACAA supports EPA's preferred approach but we recommend that the agency modify it to hew more closely to the Act's requirements under section 110(a)(2)(D) and to ensure protection of public health and the environment. Under EPA's preferred approach, if a state's emissions are below the budget plus a variability factor, then there is no penalty. However, EPA has determined that a state's emissions need to be at or under its budget (not at or under the inflated budget that includes the variability factor) in order to eliminate significant contribution to downwind nonattainment. In our reading of the Act, then, EPA cannot allow a state to emit any more than its emissions budget in order to eliminate significant contribution to downwind nonattainment and to not interfere with maintenance. [EPA-HQ-OAR-2009-0491-2771.1, p.5]
Response: 
As explained in the preamble, state-level emissions are likely to vary even after all significant contribution to nonattainment and interference with maintenance that EPA identified in this final rule are eliminated. EPA believes that the remedy uses variability limits in a way that both provides the flexibility of limited interstate trading for dealing with real-world variability in the operation of the power system and for reducing costs of compliance with emission reduction requirements, as well as providing assurance for downwind states that significant contribution to nonattainment and interference with maintenance by upwind states will be eliminated.  EPA's remedy is consistent with CAA requirements and the court's rulings.  See preamble section VI.E for more information about variability limits and required reductions.
Organization: NextEra Energy, Inc.
Comment: 
NextEra Energy, Inc.
NextEra Energy recommends revisions to the assurance provisions proposed in the Transport Rule.
Although NextEra Energy has significant concerns about EPA's use of projected emissions to allocate allowances to emission units, we strongly support the overall framework of the preferred option, including unlimited intrastate trading and limited interstate trading using the variability and assurance level provisions proposed in the rule. We support EPA's proposal to determine assurance provisions' surrender requiren1ents at the owner level, rather than the plant or unit level, because this would allow companies to optimize the management of their plants as a fleet. This allows much-needed flexibility while resulting in equal or lower emissions. The preferred option manages to allow some interstate trading while staying within the constraints of the D.C. Circuit decision by ensuring the necessary emissions reductions occur in the states identified as contributing to nonattainment or interfering with maintenance in other states. At the same time, the preferred option allows owners to use market mechanisms to buy and sell allowances. Allowance markets are essential to producing cost-effective reductions. [EPA-HQ-OAR-2009-0491-2718.1, p.10]
NextEra Energy believes that the assurance provisions proposed in the Transport Rule will create a powerful incentive to operate pollution control equipment rather than buying allowances. With a sufficient allowance price, the requirement that a unit owner surrender two allowances for every ton by which it exceeds the variability limit if a state exceeds its limit will likely result in companies limiting their reliance upon purchased allowances. Instead, companies will look to achieve further emissions reductions. This will ensure reductions occur in the necessary states so as to meet the requirements of Section 110, clarified in the D.C. Circuit decision. [EPA-HQ-OAR-2009-0491-2718.1, p.10]
If EPA agrees with NextEra Energy's recommendation to change the unit allocation methodology to a historic basis while maintaining the existing methodology for the setting the state budget, EPA will need to evaluate whether that requires a change to the assignment of responsibility for the assurance provisions to owners. NextEra Energy has considered this issue and, if EPA uses the allocation methodology supported by NextEra Energy, we recommend and support that EPA use the revised allocations as the basis for calculating the owner's share. That is, we believe that variability limits at the owner-level should be based on allocation. If an owner operates in a state where the variability Is ten percent of the state budget, the owner's variability should be ten percent of the owner's allocation. Any emissions above the owner's allocation plus variability would be used to calculate the owner's portion of the additional surrender requirement if the state exceeds the state budget plus variability limit.  [EPA-HQ-OAR-2009-0491-2718.1, pp.10-11]
Response: 
EPA has finalized an allowance allocation approach different from the proposal that uses historic heat input data.  EPA has also updated the responsibility for assurance provision penalties to be determined at the common designated representative level, rather than by owner.  Only those sources in a state at the DR level that exceed their allocations plus share of the state variability limit are required to surrender additional allowances if the assurance provisions are triggered.  See preamble section VII.E for more information about assurance provisions and penalties.
Organization: Northeast States for Coordinated Air Use Management (NESCAUM)
Comment: 
Northeast States for Coordinated Air Use Management (NESCAUM)
While we support the concept of provisions that limit interstate trading, some of the implementation specifics are troubling. EPA proposes to set state-specific trading budgets at the level necessary to significantly address transport, but then allows sources in a state to emit at the budget plus an increased variability limit, without mitigation in a specific state exceeding its budget. By allowing emissions in a state to be higher than the budget, the variability provisions weaken the state budgets that are already inadequate to fully address significant contribution in some states. EPA should correct this by setting the state-specific budgets with an adequate margin of safety that accounts for periods of high variability, so that emissions will not exceed the levels of significant contribution. [EPA-HQ-OAR-2009-0491-2694.1 p.8] 
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.11.]
Third, we recognize that emissions variability needs to be addressed and support the concept of the proposed provisions that limit interstate trading. However, with the proposed state budgets being inadequate to fully address significant contribution, an emission variability approach needs to include an adequate margin of safety in the state budgets such that periods of high emissions do not cause significant contributions downwind.
Response: 
As explained in the preamble, state-level emissions are likely to vary even after all significant contribution to nonattainment and interference with maintenance that EPA identified in this final rule are eliminated. EPA believes that the remedy uses variability limits in a way that both provides the flexibility of limited interstate trading for dealing with real-world variability in the operation of the power system and for reducing costs of compliance with emission reduction requirements, as well as providing assurance for downwind states that significant contribution to nonattainment and interference with maintenance by upwind states will be eliminated.  EPA does not believe it has the authority to set budgets below what is required to eliminate significant contribution and interference with maintenance, which is what this comment seems to suggest.  EPA's remedy is consistent with CAA requirements and the court's rulings.  See preamble section VI.E for more information about variability limits and required reductions.
Organization: Northern Indiana Public Service Company (NIPSCO)
Comment: 
Northern Indiana Public Service Company (NIPSCO)
As indicated above, NIPSCO prefers EPA's 'Preferred Option' over the two alternatives offered. However, NIPSCO believes that both the NOx Budget Trading Program and the CAIR have demonstrated that open market emissions trading results in reduced emissions and improved air quality on a region-wide basis at lower overall cost. EPA's proposal to restrict open trading through the imposition of the assurance provisions or variability limits will cause increased costs of compliance with this rule while not producing corresponding benefits to the environment. NIPSCO is greatly concerned that the emissions trading market will not be sufficiently robust as to make emissions trading viable, at least in the way it has been under the NOx Budget Trading Program or the CAIR. [EPA-HQ-OAR-2009-0491-2747.1 p.8]
EPA acknowledges that air quality has improved significantly in the past several years, to the point where EPA proposes no zonal geographic limitations on NOx trading, such as it proposes for S02, and does not propose a reduction in the states' NOx budgets in 2014 to coincide with the reduction in Group 1 states' S02 budgets. The variability limits that EPA has proposed as responsive to the court's decision in North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008), that reductions must occur in states having downwind impacts is overkill and should be removed from the proposal. [EPA-HQ-OAR-2009-0491-2747.1 p.8]
If EPA does not remove the assurance allowance surrender penalties, the assurance provision allowance surrender penalties should be reduced to not require an additional full allowance for each ton of emissions over the owner's proportional share of the state budget with the variability limit. We recommend one half of an allowance be established instead given the expected scarcity of allowances. [EPA-HQ-OAR-2009-0491-2747.1 p.8]
Response: 
Unlimited trading of the type allowed under CAIR was found by the court to lack the necessary assurances that each upwind state would make its required emissions reductions and therefore, cannot be part of EPA's remedy going forward regardless of program costs. 
The penalty for triggering the assurance provisions is an allowance surrender of 2 allowances for every 1 ton of emissions that exceed the state assurance level (state budget + variability limit).  Exceeding the state assurance level is not a CAA violation.  See preamble section VII.E and the Assurance Penalty Level TSD for more information about assurance provisions and penalties. 
Organization: NRG Energy
Comment: 
NRG Energy
It is recommended that EPA clarify the description of an Owner with relation to the variability conditions. Among unregulated EGU's it is common to create an LLC for each plant which ultimately rolls up to a parent entity. NRG believes that it is EPA's intent to evaluate variability as a parent company's fleet within the state. [EPA-HQ-OAR-2009-0491-2749.1, pp. 4-5]
Response: 
Variability was analyzed on a state-by-state basis and variability limits are set for the state emissions, as a whole, in any single control period.  However, to provide owners and operators with compliance flexibility, EPA is determining assurance provision penalties at the common designated representative level.  See preamble section VII.E for more information on assurance provisions and penalties.
Organization: Oglethorpe Power
Comment: 
Oglethorpe Power
VI. Assurance
In response to EPA's request for comments on the proposed assurance provisions, Oglethorpe Power believes that the allowance surrender requirement associated with the assurance provisions should be less than one allowance per ton emitted, in addition to the standard allowance surrender, since a one allowance/ton surrender requirement is unnecessarily burdensome and overly punitive. This is especially true, given EPA's belief that the likelihood of triggering assurance provisions is low. Any allowance surrender in addition to the standard allowance surrender of one allowance/ton will provide adequate incentive for unit owners to avoid exceeding their share of the state budget (with variability limits). For similar reasons, such an exceedance should not be considered a violation of the CAA, subject to discretionary monetary penalties. [EPA-HQ-OAR-2009-0491-2732.1, p.11]
Response: 
The penalty for triggering the assurance provisions is an allowance surrender of 2 allowances for every 1 ton of emissions that exceed the state assurance level (state budget + variability limit).  Exceeding the state assurance level is not a CAA violation.  See preamble section VII.E and the Assurance Penalty Level Analysis TSD for more information about assurance provisions and penalties. 
Organization: Ozone Transport Commission (OTC)
Comment: 
Ozone Transport Commission (OTC)
In the proposed Transport Rule EPA relies on the assurance provisions to limit emissions that could occur in excess of the state budgets. EPA's approach is to rely on the 1-year and then 3-year variability limits and the requirement that covered sources hold allowances sufficient to cover their emissions as a limit on the incentives to trade, thus ensuring that emissions within states will stay below the budget with the variability limit. OTC finds the design of the assurance provisions at odds with the 3-year timeframe in which states are required to provide clean data in order to demonstrate attainment. With variability limits added on top of the state budgets as well as the opportunity to use unlimited banked allowances created in the new trading program, we are not satisfied that the system will work as EPA foresees to eliminate significant contribution and interference with maintenance over the 3-year period. Surrender of allowances and penalties occur after the assurance provisions are triggered over the 3-year timeframe, so there is no opportunity within that time period to correct for the excess emissions. We must therefore strongly recommend that EPA revisit its assurance provisions, in addition to the banking of allowances, incorporating OTC's recommendations to design a program that will guarantee the remedy for transport will be achieved in timeframes that coincide with the CLEAN AIR ACT's attainment requirements.
OTC has serious concerns with the banking and assurance provisions in all of the remedy options outlined in the proposed Transport Rule. EPA is proposing the state budgets at a level that is supposed to eliminate significant contribution and interference with maintenance. Banked allowances are those saved in one year of a trading program for use in a subsequent year, thus potentially adding to the total amount of NOx or SO2 emitted into the air in a future year. Without flow control or other mechanisms, the use of banked allowances in any new trading program has the potential to exceed the budget and put the remedy for transport and associated air quality and health benefits at risk. OTC recommends EPA include such mechanisms in any trading program to remedy transport.
Response: 
EPA is finalizing one-year variability limits only, not three-year variability limits.  States must emit at or below their state assurance level (budget + variability limit) every single control period (i.e. every year).  The agency believes it has designed a remedy that eliminates significant contribution and interference with maintenance in upwind states and comports with the court's decision.  See preamble section VII for more information about the remedy.
Organization: Progress Energy Service Company
Comment: 
Progress Energy Service Company
Progress Energy believes that utility owners should be required to surrender less than one allowance per ton emitted, in addition to the standard allowance surrender of one allowance per ton emitted, in the event that emissions from their utilities exceed their share of the state budget with variability limits. In addition, the provision that counts as a separate violation each day of a year in which a unit's emissions exceed the quantity of allowances in its account is excessive. Progress Energy believes that it is unreasonable to assess each day of the year in this way. particularly when it is quite likely that excess emissions would not occur until late in the year. It is the Company's position that the allowance surrender and monetary penalties are sufficient incentive not to emit in excess of allowance holdings, and we urge EPA to remove this penalty provision from the Transport Rule. [EPA-HQ-OAR-2009-0491-2831.1 p.8]
Response: 
The penalty in the final rule for triggering the assurance provisions is an allowance surrender of 2 allowances for every 1 ton of emissions that exceed the state assurance level (state budget + variability limit).  Exceeding the state assurance level is not a CAA violation.  See preamble section VII.E for more information about assurance provisions and penalties. 
Organization: RRI Energy, Inc.
Comment: 
RRI Energy, Inc.
How the proposal would be implemented - assurance provisions RRI supports the surrender of two allowances for each ton of emission above the number of allowances in the account in lieu of the 1:1 surrender as proposed in the CATR. [EPA-HQ-OAR-2009-0491-2717.1 p.5]
Response: 
EPA has finalized an allowance surrender penalty of 2 allowances for every 1 ton of emissions in a state above its state assurance level (state budget + variability limit).
Organization: Southern Company
Comment: 
Southern Company
XVI. Southern Company Supports Several of EPA's Decisions in the Proposed Transport Rule
As discussed throughout these comments, Southern Company has many concerns with the Proposed Transport Rule. However, we support several of EPA's decisions in the proposed rule including EPA's decision to phase in the assurance provisions. [EPA-HQ-OAR-2009-0491-2864.1, p. 52]
G. EPA's Decision to Not Begin the Assurance Provisions Before 2014
Although EPA should not begin compliance any sooner than 2015, we support EPA's proposal to phase-in the assurance provisions. Transition from one allowance program to another e.g., from CAIR to the proposed Transport Rule or from it to a future transport rule is likely to require significant adjustments in unit operations and system dispatch. Owners and operators need a period of time to adjust to the new requirements without the assurance provisions in place. The assurance provisions only apply where all statewide covered unit emissions exceed the state budget plus variability limits. Since there are multiple owners and operators impacting statewide emissions and all are adjusting their operations to account for the new rule at the same time, it is all the more important that the assurance provisions be phased-in. Put simply, EPA's proposal to phase-in the assurance provisions is an important aspect of its transition policy and should be retained in this proposal and in future transition periods (e.g. from this to the next transport rule). [EPA-HQ-OAR-2009-0491-2864.1, p. 54]
Response: 
EPA is finalizing the assurance provisions to begin in 2012, rather than in 2014.  EPA received comments supporting the implementation in 2012 with the rationale that is was more consistent with the court decision in North Carolina.  See preamble section VII.E for more information about the assurance provisions and EPA's decision to implement them starting in 2012.
Organization: State of Wisconsin, Department of Natural Resources
Comment: 
State of Wisconsin, Department of Natural Resources
Preferred Program Approach - Addressing year-to-year Variance - Within both its preferred inter-state trading/banking program and its alternate intra-state trading program, EPA has added a component of emissions they call variance to account for year-to-year meteorology and economic variability in the level of actual annual emissions from the power sector. This variance structure effectively increases the 'working' budget for states by 10% or more for anyone year. By allowing for variance, EPA has placed the burden of impact on downwind states rather than accounting for it within the state emission budgets and makes the EPA-recommended trading structures too complex. One consequence is any modeled benefit projected within an attainment demonstration must necessarily discount the enforceable emission reduction by the same 10% because modeling needs to reflect actual system response during ozone and 24 hour PM-2.5 episodes. [EPA-HQ-OAR-2009-0491-2829.2, p. 9; This comment can also be found at IV.F.1 of this comment summary]
Wisconsin recommends that any variance in anticipated emission levels is addressed directly within the budget levels, thereby streamlining the trading and banking structure to avoid the potential air quality and legal problems associated with the proposed variance structure. A potential hybrid approach would be to combine a firmly limited inter-state trading program with a minimum rate-specified intra-state averaging program at a level that would reflect a slightly lower equivalent budget during typical periods. [EPA-HQ-OAR-2009-0491-2829.2, p. 9; This comment can also be found at IV.F.1 of this comment summary]
A simple assessment of the level of heat input modeled to establish the 2012 and 2014 budgets indicated that EPA already includes some portion of variance within the proposed budget levels. Any alternate variance structure should provide a lower net buffer than proposed in the current rule which provides for significantly greater system fuel consumption than 2009 levels and also includes a separate variance component. Sensitivity analysis suggests the current system annual operation level based on heat input could be raised by 6% for a 2014 budget (on average) in order to reflect the maximum level of system operation by state for the period 2005-2009 (see Figure 1), thus precluding the need for a separate variance structure. [EPA-HQ-OAR-2009-0491-2829.2, pp. 9-10; This comment can also be found at IV.F.1 of this comment summary]
Regardless of the final program structure adopted, EPA should retain some compliance flexibility, but focus that flexibility most in the early program years of 2012-2014 when it is most needed. 1t might make sense to start with a fairly open inter-state trading and banking program, but transition in later program phases (post-2014), to a structure that more reflects the Court's direction to meet state-by-state targets and to address the States' and Court's assurance concerns. [EPA-HQ-OAR-2009-0491-2829.2, p. 10; This comment can also be found at IV.F.1 of this comment summary]
Response: 
As explained in the preamble, state-level emissions are likely to vary even after all significant contribution to nonattainment and interference with maintenance that EPA identified in this final rule are eliminated. EPA believes that the remedy uses variability limits in a way that both provides the flexibility of limited interstate trading for dealing with real-world variability in the operation of the power system and for reducing costs of compliance with emission reduction requirements, as well as providing assurance for downwind states that significant contribution to nonattainment and interference with maintenance by upwind states will be eliminated.  EPA does not believe it has the authority to set budgets below what is required to eliminate significant contribution and interference with maintenance, which is what this comment seems to suggest.  EPA's remedy is consistent with CAA requirements and the court's rulings.  Assurance provisions start in 2012.  See preamble section VI.E for more information about variability limits and required reductions.
Organization: Tenaska, Inc.
Comment: 
Tenaska, Inc.
EPA's proposed assurance mechanism should be modified to allocate equitably the burden of compliance with state budgets on baseload, intermediate and peaking generation. Units should be given a portion of the assurance pool in proportion to the variability of the unit. In particular, peakers and intermediate units, which are inherently more variable in their operation than baseload units, should receive a greater distribution of variability allowances. [EPA-HQ-OAR-2009-0491-3705, pp.3-4]
Assurance Mechanism Should Allow Greater Flexibility.
Tenaska believes more flexibility is needed in the assurance program. Tenaska generally favors the preferred option assurance program which would allow intrastate and limited interstate trading of allowances within the target range. However, the initial assignment of variability should recognize and accommodate more variability in the operation of the units with the most inherent variability. Marginal peaking units and intermediate service units are far more variable in their seasonal and annual operation than baseload units. This relative variability is evident from Figure 4 which shows the standard deviations of heat input of various classes of units in the 2000-2009 timeframe. [EPA-HQ-OAR-2009-0491-3705,p.16] [[See Docket Number EPA-HQ-OAR-2009-0491-3705, p.16 for Figure 4.]]
Tenaska is concerned that allocation of allowed variability based upon historical emissions will have the effect of granting operating flexibility on base load units that need such flexibility least, while placing the entire burden of the assurance mechanism on intermediate and peaker EGUs. Allowed variability should reflect the role of the different classes of units to handle varying system load. Allocations of allowed variability among each class would be based on heat input (as we suggest) adjusted for the inherent variability of the class. Tenaska also supports the suggestion that the system be set up to label the allowances from each state and to allow unlimited trading of in-state allowances among units in that state, as well as the trading of allowances within the variability range for each state . This will make for a more liquid market promoting the goals of the Proposed Transport Rule and will enable owners to avoid the potential penalties of the assurance mechanism while investing in emission reductions in their state. Because the owners will have no knowledge during the compliance period regarding whether the assurance mechanism will be triggered in their state, the labeling of allowances by state will foster efficient targeting of investment in emission reduction. [EPA-HQ-OAR-2009-0491-3705,p.17]
Response: 
Variability limits are set at the state level, not the individual unit level, which accounts for and provides sufficient operational flexibility for all sources.  If assurance provisions are triggered, only those sources that exceed their allowance allocations plus share of the state's variability limit at the common designated representative level would be held responsible for surrendering allowances under the penalty provisions.  Those sources (at the DR level) that do not emit more than their allocations plus share of the state's variability limit do not pay any penalty, thereby providing certainty to those sources.  See preamble section VII.E for more information about assurance provisions and penalties. 
EPA did consider the use of state-specific allowances as an approach to assurance based on comments.  However, the same concerns that EPA expressed regarding the intrastate trading alternative option in the proposal also apply to state-specific allowance remedies. These issues include market power potential and small entity impacts, market size and liquidity, proliferation of trading programs to manage, higher program costs, etc. For these reasons, EPA is not finalizing state-specific allowances as part of the remedy. 
Organization: Tennessee Department of Environment and Conservation, Division of Air Pollution Control
Comment: 
Tennessee Department of Environment and Conservation, Division of Air Pollution Control
Comment on Assurance Provisions: The assurance provisions are likely to be controversial, since EPA will require source owners to surrender allowances in the absence of a violation. However, EPA has to use some mechanism to comply with the Court decision, and we don't have any better suggestions. [EPA-HQ-OAR-2009-0491-0553.1, p.4]
Response: 
If assurance provisions are triggered, only those sources that exceed their allowance allocations plus share of the state's variability limit at the common designated representative level would be held responsible for surrendering allowances under the penalty provisions.  Those sources (at the DR level) that do not emit more than their allocations plus share of the state's variability limit do not pay any penalty, thereby providing certainty to those sources.  See preamble section VII.E for more information about assurance provisions and penalties.
Organization: Tennessee Valley Authority (TVA)
Comment: 
Tennessee Valley Authority (TVA)
A. Issue: EPA requests comment on whether the exceedance of total emissions by a source over the source's share of the state budget should be considered a violation of the CAA and thus be subject to discretionary penalties. [p. 45314] [EPA-HQ-OAR-2009-0491-2782.1, p. 15]
TVA Comment: We believe the allowance surrender requirement is sufficient to ensure that the state emissions will not exceed the budget plus the variability. The requirement to surrender one additional allowance (on top of the normal allowance surrender requirement) for each ton emitted over the owner's proportional share would act as a sufficient economic deterrent to avoid any excess emissions. However, failure to hold sufficient allowances to meet the allowance surrender requirement might constitute a Clean Air Act Violation and subject to the Act's sanctions, including penalties. [EPA-HQ-OAR-2009-0491-2782.1, p. 15]
Response: 
In the final rule, the penalty for triggering the assurance provisions is an allowance surrender of 2 allowances for every 1 ton of emissions that exceed the state assurance level (state budget + variability limit).  Exceeding the state assurance level is not a CAA violation.  See preamble section VII.E and the Assurance Penalty Level TSD for more information about assurance provisions and penalties.
Organization: Texas Commission on Environmental Quality
Comment: 
Texas Commission on Environmental Quality
The TCEQ disagrees with the EPA's assessment of FCAA violations and discretionary penalties under the proposed Transport Rule (75 FR 45314). 
Because assurance provision requirements are not calculated until after a control period ends, and thus, sources have no valid means of ascertaining the state's total emissions to make informed trading decisions, they are also unable to ensure that they will be able obtain or provide additional allowances to cover an allowance surrender requirement. The same level of emissions plus trading activity by a given source in a given year may or may not lead to assurance provision allowance surrender requirements, depending on the emissions plus trading activity of all other sources in that state. It may be difficult for companies to decide whether to hold and/or acquire additional allowances (above those meant to provide for actual emissions) to cover allowance surrender requirements that may or may not be enacted. Additionally, tying the FCAA-compliance obligation of one source to the actions of all sources in a state is not only unreasonably burdensome, but illegal, since certifications of compliance may only be made by an official with personal knowledge. [EPA-HQ-OAR-2009-0491-2857.2, p.1] 
Assurance Provisions Under the EPA-preferred Option (State Budget/Limited Trading) 
The TCEQ does not support the assurance provisions that the EPA has included in the proposed preferred state budget/limited trading option because these provisions create substantial disincentives that the TCEQ expects will inhibit any trading, creating substantial costs that were not adequately analyzed by the EPA in its assessment of the proposed rule. [EPA-HQ-OAR-2009-0491-2857.2, p.4] 
The EPA states that in the event assurance provisions are triggered by a state's total emissions exceeding the state budget plus the variability limit(s), the allowance surrender requirements associated with assurance provisions are applicable only to sources in the state with emissions exceeding the source's allocation plus its proportional share of the variability limit (75 FR 45313). At any given time in a control period, sources have no valid means of ascertaining the state's total emissions to make informed trading decisions or operational decisions to ensure their individual compliance with the rule. Therefore, a source might choose to limit its operation to its allocation plus its proportional share of the variability limit (particularly since assurance provision requirements are not calculated until after a control period ends). Operating under these limits (base allocation plus proportional share of the variability limit) establishes a de-facto allowable emission rate on a source and deters all trading - both interstate and intrastate. A consequence of this strategy might lead to allowance hoarding and result in a static market. The EPA further states that the proposed assurance provisions ' ...limit incentives to trade...' and that'...there is likely to be less need for trading in order for sources to comply with the requirement to hold allowances covering emissions' (75 FR 45314). While the trading limits are obviously intended to ensure that necessary reductions occur within each state, the inability of each source to plan for its compliance because it relies, in part, on all other sources within a state, has a great potential to limit market activity in such a way that emission reductions are inefficient and unnecessarily expensive. The fundamental purpose of a cap and trade program is to provide units with the flexibility to achieve the required emissions reductions in the most cost effective manner that utilizes market flexibility, i.e., units that can reduce emissions inexpensively will reduce emissions and sell their allowances to units that are unable to reduce emissions in a inexpensive manner, so that the required reduction is achieved collectively by all units. By requiring all units to operate below a certain emission level and including such extreme deterrents to trading in the proposed rule, the EPA undermines the goal of cap and trade programs. It is disingenuous to provide a trading program that, upon familiarity with the details, provides no viable alternative for compliance. [EPA-HQ-OAR-2009-0491-2857.2, pp.4-5] 
The TCEQ does not support the prospect of making an exceedance of total emissions by an owner's sources over the owner's share of the state budget combined with the variability limit a violation of the FCAA and subject to discretionary penalties (75 FR 45314).  [EPA-HQ-OAR-2009-0491-2857.2, p. 5]  
The EPA does not currently propose to consider an 'exceedance of total emissions by an owner's sources over the owner's share of the state budget with the variability limit' a violation of the FCAA but does request comment on the option. The fundamental purpose of a cap and trade program is to provide sources with the flexibility to accomplish the required emissions reductions in the most cost effective manner, i.e., sources that can reduce emissions inexpensively will reduce emissions and sell their allowances to sources that are unable to reduce emissions in a inexpensive manner, so that the required reduction is accomplished collectively by all sources. Making the exceedance of an owner's share of the state budget including the variability limit regardless of the source's ability to provide allowances to cover its emissions- into an FCAA violation is effectively a direct-control program. If the EPA intends to regulate interstate transport of air pollution via a direct-control program, they should propose such an alternative on its own merits and provide an opportunity for the public to fully participate in the development of such a program. [EPA-HQ-OAR-2009-0491-2857.2, pp.5-6] 
 
Response: 
In the final Transport Rule, sources whose emissions exceed their allocations plus share of the state variability limit when assurance provisions are triggered are not in violation of the CAA.  However, owners and operators must hold sufficient allowances in their accounts to cover their allowance surrender requirement. 
EPA does not believe that trading will suffer dramatically or that liquidity will be a problem in the markets as a result of the rule's assurance provisions.  There are a large number of covered sources in the program that are expected to buy and sell allowances in the markets.  In addition, there is timely generation and emissions data available to owners and operators to make decisions about buying or selling allowances and whether the state is likely to approach its state assurance level (budget plus variability limit) during the control period.  Covered sources have operational and compliance flexibility in this rule, to the extent possible under EPA's authority and the court rulings.  For more on assurance provisions, see preamble section VII.E.
Organization: Utility Air Regulatory Group (UARG)
Comment: 
Utility Air Regulatory Group (UARG)
2. Assurance Provisions. 
EPA requests comments on the proposed assurance provisions. 75 Fed. Reg. at 45314/2. UARG believes that the allowance surrender requirement associated with the assurance provisions should be less than one allowance per ton emitted, in addition to the standard allowance surrender. An additional allowance surrender requirement of one allowance per ton would be unnecessarily burdensome and overly punitive. EPA states in the proposed rule that it "believes the likelihood of triggering assurance provisions is low." Id. at 45314/1. Indeed, the example that EPA provides of a circumstance that may lead to emissions "approaching the variability limit" -- "an extended nuclear unit outage that causes a company to run its fossil units harder to meet demand" -- indicates that EPA anticipates the assurance provisions would likely be triggered only in unusual conditions and for a temporary period, due to forces largely beyond the unit owner's control. Id. Any allowance surrender in addition to the standard allowance surrender of one allowance per ton -- perhaps, for example, an additional (1/2) allowance (rather than the additional one allowance) on top of the standard one-allowance surrender requirement -- would provide an adequate incentive for unit owners to avoid exceeding their share of the state budget with variability limits. [EPA-HQ-OAR-2009-0491-2756.1, p.94] 
Additionally, for similar reasons, UARG strongly believes that such an exceedance should not be considered a violation of the CAA, subject to discretionary penalties. See 75 Fed. Reg. at 45314/2 (requesting comment on whether such exceedances should be considered a violation of the CAA and be subject to discretionary penalties). As explained above, any additional allowance surrender requirement would provide sufficient incentive to avoid triggering the assurance provisions.55 [EPA-HQ-OAR-2009-0491-2756.1,pp.94-95] 

Footnote 55: UARG does not believe that EPA's proposed discretionary penalties for excess emissions, 75 Fed. Reg. at 45314/3, are appropriate. Those penalties could easily amount to millions of dollars for an inadvertent exceedance of allowance levels by even a few tons in one year. EPA should at a minimum clarify that in the allowance trading program that EPA proposes, an exceedance of one ton of emissions will be treated as a single violation over one year or ozone season, as the case may be, rather than as a separate violation for each day in that year or ozone season. This change is particularly appropriate because any exceedances of allowance levels under the Transport Rule are almost certain to be inadvertent. 
Response: 
If assurance provisions are triggered, only those sources that exceed their allowance allocations plus share of the state's variability limit at the common designated representative level would be held responsible for surrendering allowances under the penalty provisions.  Those sources (at the DR level) that do not emit more than their allocations plus share of the state's variability limit do not pay any penalty, thereby providing certainty to those sources.  The penalty for triggering the assurance provisions is an allowance surrender of 2 allowances for every 1 ton of emissions that exceed the state assurance level (state budget + variability limit).  Exceeding the state assurance level is not a CAA violation.  See preamble section VII.E and the Assurance Penalty Level TSD for more information about assurance provisions and penalties. 
Organization: West Virginia Department of Environmental Protection
Comment: 
West Virginia Department of Environmental Protection
[[2790.1 p.7]]
Violation Provisions - EPA requested comment on whether the exceedance of total emissions by an owner's sources over the owner's share of the state budget with the variability limit should be a violation of the Clean Air Act and thus subject to discretionary penalties. WVDAQ does not believe it is appropriate that an exceedance of the owner's share of the state budget with the variability limit should be a violation of the Clean Air Act, as it seems unfair that if a source holds enough allowances to cover their emissions, they are penalized for a situation that cannot be foreseen. If there are multiple companies operating in a state, they may not have immediate access to the emissions data for other's units and cannot predict that the total emissions for the state are going to exceed that variability limit. This is especially true for the three-year variability limit. WVDAQ believes that this Clean Air Act violation provision will discourage trading.
Response: 
For owners and operators that exceed their allowance allocations plus share of the state's variability limit in a state that triggers the assurance provisions, there is an allowance surrender penalty, but not a CAA violation in the final rule.  See preamble section VII.E for more on assurance provisions and penalties.
Organization: Wisconsin Power and Light Company
Comment: 
Wisconsin Power and Light Company
WPL supports the application of variability provisions to state budgets in order to account for fluctuations in electric generation operations to meet power demand and believes that these should be increased to 20 percent. The fact that many existing EGUs will require significant outages in the next four years in order to provide for air pollution control retrofits supports EPA's use of a higher variability provision.
Response: 
EPA finalized a modified variability limit approach, which simplified the determination of limits by eliminating the tonnage limits and giving all states the same percentage. The uniform percentage variability limits are higher than the 10% limits in the proposal.  See preamble section VI.E and VI.F for more details on variability limits.
Organization: Xcel Energy Inc.
Comment: 
Xcel Energy Inc.
1. Xcel Energy opposes the penalty provisions as proposed.
Under CATR, a company could be subject to substantial penalties if its total emissions exceed the company's share of the state budget. It appears that EPA is proposing an excess emission penalty, of $37,500 per ton of excess emissions, with each day of the year assessed as a separate penalty. This could result in a company being assessed a penalty of $13,687,500 for a single ton of excess emissions (e.g., 1 excess ton out of compliance for 365 days at $37,500 per day of violation). We understand from the stakeholder meetings with EPA that this is not EPA's intention. EPA needs to make clear that the only impact from such excess emissions is the surrender of allowances proportionate to the state's variance exceedance. [EPA-HQ-OAR-2009-0491-2728.1, p.11]
Response: 
The penalty for triggering the assurance provisions is an allowance surrender of 2 allowances for every 1 ton of emissions that exceed the state assurance level (state budget + variability limit).  Exceeding the state assurance level is not a CAA violation.  See preamble section VII.E for more information about assurance provisions and penalties. 

V.D.2.e. Should Assurance Provisions Start in 2012 Instead of 2014?

Organization: Adirondack Council
Comment: 
Adirondack Council
The Agency also requests comment on whether the remedy in the proposed FIPs should be modified so that the limits would apply starting in 2012 instead of 2014. (p. 357) The Adirondack Council supports the limits starting in 2012 instead of 2014. We believe that moving up compliance dates will provide human health and environmental benefits on an accelerated basis. [EPA-HQ-OAR-2009-0491-2848.1, pp.3-4]
For the 2012-2013 transition period, EPA is taking comment on whether the assurance provisions used to limit interstate trading are needed, since the state-specific budgets are based on known air pollution controls and thus a high level of certainty exists about where reductions will occur. (p. 407) The Adirondack Council believes that the assurance provisions should be in place during the 2012-2013 transition period. There is no legitimate reason for waiting for an additional two years when the same provisions will be in effect in 2014. We believe it is better to have the assurance provisions in place and not need them than to not have them in place during this time period and need them. [EPA-HQ-OAR-2009-0491-2848.1, p.4]
Response: 
EPA is finalizing the assurance provisions to begin in 2012.  See preamble section VII.E for more information about the assurance provisions and EPA's decision to implement them starting in 2012. 
Organization: American Public Power Association (APPA)
Comment: 
American Public Power Association (APPA)
In addition, if EPA retains its proposed two-phased compliance schedule, APPA supports EPA`s proposal not to apply variability limits and assurance provisions before 2014. 75 Fed. Reg at 45296/1, 45305/3. EPA states that assurance provisions will not be necessary to limit interstate trading during the first two years of the program because during those years, "state-specific budgets are based on known air pollution controls and thus a high level of certainty exists about where reductions will occur." 75 Fed. Reg. at 45306/1. Given the nature of EPA`s proposal, EPA`s approach is quite reasonable: If the state budgets are based on reductions that EPA expects will occur based on use of control equipment that will be installed and operational by that time, there is no need for assurance provisions during this time period. 6 [EPA-HQ-OAR-2009-0491-2812.1, pp.10-11]

6. However, as explained in section VIII below, many of EPA`s assumptions regarding which controls will be installed and operational by the beginning of 2012 are ill-founded. EPA thus should revise its calculations based on an accurate accounting of the controls that will be operational by the beginning of 2012. [EPA-HQ-OAR-2009-0491-2812.1, p.11]
Response: 
EPA is finalizing the assurance provisions to begin in 2012, rather than in 2014.  See preamble section VII.E for more information about the assurance provisions and EPA's decision to implement them starting in 2012. 
Organization: Attorney General of North Carolina
Comment: 
Attorney General of North Carolina
[[2685.1 p.26]]
a. Assurance Provisions for the 2012-13 Period The preamble and the proposed rules are clear that EPA is proposing that the assurance provisions do not apply to the 2012 and 2013 control periods. See 75 Fed. Reg. at 45,312/3 (Assurance provisions apply "[s]tarting in 2014 . . . ."); 45,314/3 ("For the 2012-2013 transition period, EPA is proposing the State Budgets/Limited Trading remedy without the . . . assurance provisions . . . ."), 45,383/2 (proposing rule §97.425(b)(1), which would provide that assurance provisions are assessed for the preceding year "[b]y June 1, 2015 and . . . each year thereafter . . . ."). Absent the assurance provisions during the 2012 and 2013 control periods, EPA's proposal manifestly violates the D.C. Circuit's holding in North Carolina regarding interstate trading. The assurance provisions are the proposed rule's only enforceable curb on interstate trading. Because EPA is proposing to determine that in 2012 and 2013 emissions in certain States are exceeding what is allowed under §110(a)(2)(D)(i)(I), EPA cannot then simply allow sources in those States to emit whatever the market can support.
Moreover, EPA's justification for the proposal is unlawfully irrational. EPA appears to present four justifications for allowing unfettered interstate trading in 2012 and 2013: (1) because the 2012 and 2013 budget reflect only controls that are under construction, there is a "high level of certainty" that reductions will occur where projected; (2) the other remedies offered by EPA "present greater implementation challenges;" (3) the 2012-13 period allows sources time to "migrate to the new rule requirements in 2014, such as preparing for the imposition of assurance provisions;" and (4) "[a]ssurance provisions would provide sources less flexibility and therefore likely increase compliance costs . . . ." 75 Fed. Reg. at 45,314/2-45,315/1. These justifications are legally insufficient.
Taking each in turn:
1. The fact that EPA has a "high level of certainty" where reductions will occur cuts both ways. If this "high level of certainty" is accurate and 100% compliance is achieved, EPA has cost sources nothing by retaining the assurance provisions as a backstop. But enforcement mechanisms are not designed for those that comply with the law; they are for those that do not. For example, without any disincentive to exceed the budget, a source that is currently constructing a scrubber for the sole purpose of meeting CAIR and the Transport FIP may find it unnecessary to complete and operate that scrubber  -  for economic reasons  -  before 2014 if it can collect sufficient allowances from sources in other States to cover the overage. EPA's "high level of certainty" that this will not occur is no assurance that it will not and is no reason to jettison the assurance provisions.
2. EPA next contends that the other remedies EPA offered "present greater implementation challenges" for the 2012-13 period. Whatever the merits of this comparison, it is irrelevant. Simply because EPA can hypothesize other regulatory possibilities where assurance provisions would be more necessary does not mean that in the preferred scenario they are not necessary. That a seatbelt is a critical safety device in a 65 mph collision does not mean that it can be dispensed with in a 50 mph crash.
3. EPA's "migration" justification also fails. The 2012-13 period is not simply a period for sources to transition to the new control requirements. During the years 2012 and 2013, sources are required to meet limits in order to eliminate the "contribut[ing]" and "interfere[ing]" emissions that EPA has determined exist during those years. The nature of the requirement that sources reduce emissions during 2012 and 2013 is no different than the nature of the requirement that those same sources reduce emissions in 2014 and beyond. Although the requirement to reduce emissions during 2012 and 2013 may be of a different magnitude than the requirement for 2014, 2015 etc. it is no less a violation of the Clean Air Act for sources to exceed their budget in 2012 and 2013 than it is for those same sources to exceed their budget after that. Therefore, the 2012-13 period should be treated similarly unless EPA can justify dissimilar treatment on some other ground.
EPA has made no case why a so-called 2012-13 "migration" period is necessary. EPA asserts that sources must be allowed time to "prepar[e] for the imposition of assurance provisions" but provides no support as to why this is the case. The facts oppose EPA's conclusory assertion. As EPA touts, during this "migration" period emissions will be those that result from the operation of existing controls and controls that are now under construction. It is unclear what, if anything, sources can do differently in 2012 and 2013 to "prepar[e] for the imposition of assurance provisions." EPA also contends, again without any explanation, that the lack of any assurance provisions in 2012 and 2013 is warranted because "some States" face "tighter SO2 budgets." First, this says nothing about why sources should be excused from assurance provisions for annual or seasonal NOX emissions or why all States should be excused from SO2 assurance provisions to accommodate just "some States." Second, as just discussed, EPA has expressed a "high level of certainty that emissions reductions projected for 2012-2013 with interstate trading would be achieved within the states where they are projected to occur . . . ." 75 Fed. Reg. at 45,314/3-15/1. Consequently, there is little justification during this period for any interstate trading, much less interstate trading absent the assurance protections.
4. Finally, EPA suggests that the imposition of assurance provisions in 2012 and 2013 will result in "less flexibility and therefore likely increase compliance costs." Of course, the same could be said for the period after 2013, when EPA will be imposing the assurance provisions. Regardless, if the 2012-13 budgets are simply an attempt to lock in existing and planned controls and EPA is relatively certain where these controls are and will be, it is unclear what flexibility is needed. Similarly, a mandate to sources in the 2012-13 period to operate the controls they have installed and continue to construct those that are as yet incomplete should not increase compliance costs; it should just require expenditures that are already planned. Indeed, if it is the case that more "flexibility" is needed during the near term, this completely undercuts EPA's "high level of certainty" regarding where emissions reductions will occur and therefore argues for retaining the assurance provisions.
Accordingly, EPA should impose the assurance provisions in 2012 and 2013.
b. Surrender of Allowances North Carolina seeks clarity on the mechanics of the assurance provisions. The proposed rules require a calculation of, roughly speaking, the amount by which each owner's share (using definition (1) of owner's share, see infra) exceeds that owner's assurance level. Once this overage is determined, the owner must surrender that number of allowances [hereinafter "overage allowances"]. North Carolina assumes that the overage allowances are in addition to the one-to-one surrender the source must make under any circumstances to cover its emissions in general. That is, if an owner's sources emit 30,000 tons of SO2 and EPA determines that the owner's share exceeds the assurance level by 2,500 tons, then the owner must surrender 32,500 allowances. Although this seems the logical reading, nowhere does the proposed rule explicitly state that the overage surrender is in addition to the owner's general obligation to surrender allowances to cover its emissions on a one-to-one basis.
Response: 
EPA is finalizing the assurance provisions to begin in 2012.  See preamble section VII.E for more information about the assurance provisions and EPA's decision to implement them starting in 2012. 
Organization: Dominion
Comment: 
Dominion
Decision to Defer Imposition of Assurance Provisions
EPA's proposes to defer any limitations to the use of interstate trading for the first 2 years of the program by not imposing the assurance provisions and variability limit provisions of the rule until 2014. To the extent EPA retains the accelerated and unrealistic compliance schedule of the proposal in the final rule, increased flexibility will be particularly important during the initial phase of the program. We support this approach and urge EPA to retain the deferred application of the assurance provisions in the final rule. We also support EPA's proposed two-phased approach in assessing whether the penalty provisions would apply by first evaluating whether a state's total budget (plus variability limits) is exceeded and only if so, would then impose the penalty provisions upon companies that exceed their state-aggregated total allowance allocations (plus their pro-rata share of the state variability limits). [EPA-HQ-OAR-2009-0491-2715.1, p.3]
Response: 
EPA is finalizing the assurance provisions to begin in 2012, rather than in 2014.  Assurance provision penalties in the final rule are assessed at the common designated representative level, rather than on an ownership basis.  See preamble section VII.E for more information about the assurance provisions and EPA's decision to implement them starting in 2012. 
Organization: Duke Energy
Comment: 
Duke Energy
While Duke Energy does not support EPA's PTR schedule, if EPA retains the proposed two-phased compliance schedule, Duke Energy supports EPA's proposal not to apply variability limits and assurance provisions before 2014. EPA states that assurance provisions will not be necessary to limit interstate trading during the first two years of the program because during those years, "state-specific budgets are based on known air pollution controls and thus a high level of certainty exists about where reductions will occur." Within the framework of EPA's proposal, Duke Energy agrees with EPA's reasoning on this point. If the state budgets are based on reductions that EPA expects will occur based on use of control equipment that will be installed and operational by that time, there is no need for assurance provisions during this time period. [EPA-HQ-OAR-2009-0491-2689.1, p.3]
Response: 
EPA is finalizing the assurance provisions to begin in 2012, rather than in 2014.  See preamble section VII.E for more information about the assurance provisions and EPA's decision to implement them starting in 2012. 
Organization: Edison Electric Institute (EEI)
Comment: 
Edison Electric Institute (EEI)
Many EEI members support EPA's proposal not to apply variability limits until 2014 after the transition period proposed under its preferred approach. They concur with EPA's rationale that the proposed interim remedy that does not impose the variability limits until 2014 is needed to provide compliance flexibility while not compromising the certainty that necessary emissions reductions will occur in 2012 and 2013. Others believe that the variability limits should be put into effect in 2012 to respond to the Court's direction that EPA act "as soon as practicable" to correct the deficiencies of CAIR and that, without the variability limits, EPA would essentially leave in place unrestricted interstate trading for two additional years, which the Court in North Carolina v. EPA found to be problematic. [EPA-HQ-OAR-2009-0491-2697.1, p.16]
[This comment was also submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.28.]
Response: 
EPA is finalizing the assurance provisions to begin in 2012.  See preamble section VII.E for more information about the assurance provisions and EPA's decision to implement them starting in 2012. 
Organization: Exelon
Comment: 
Exelon
EPA WOULD MOST CLOSELY FULFILL THE REQUIREMENT TO REPLACE CAIR "AS SOON AS PRACTICABLE" BY IMPLEMENTING THE TRANSPORT RULE ASSURANCE PROVISIONS IN 2012, RATHER THAN DEFERRING THEM UNTIL 2014.
Because the assurance provisions of the proposed Transport Rule are the essential mechanism for ensuring that the emissions from each state are limited to no more than the state's budget plus variability limit, EPA should implement the assurance provisions beginning in 2012 rather than 2014. Without the assurance mechanism, there is no effective means to assure that states stay within their budgets in 2012 and 2013. In that case, the proposed Transport Rule, without the assurance provision, will likely suffer from the same fatal defect that caused the Court of Appeals to invalidate CAIR in North Carolina. [EPA-HQ-OAR-2009-0491-2666.1, p.23]
The court has required EPA to redress the deficiencies in CAIR "as soon as practicable." Given EPA's conclusion, with which Exelon concurs, that no new controls beyond those already firmly planned need to be installed to achieve 2012 state emission budgets, it is "practicable" for EPA to implement the assurance provisions in 2012. Because the variability limits build in the necessary flexibility, it is also practicable to impose assurance provisions from a trading and reliability perspective. It would therefore be practicable for EPA to implement the assurance provisions based on the 2012 emission budgets beginning in 2012; and the Transport Rule may be subject to a challenge that it does not correct CAIR's deficiencies "as soon as practicable" if implementation is deferred until 2014. [EPA-HQ-OAR-2009-0491-2666.1, p.23]
The proposed Transport Rule contains no provision that would impose a burden, or even a disincentive, for any owner to emit excess emissions in 2012 or 2013. 47 Without such a provision, the Transport Rule is essentially the same as CAIR: there is a requirement that sources obtain allowances for each ton of emissions, but those allowances may be obtained from any state and for any vintage year. It is the compliance assurance provision that separates the Transport Rule from CAIR, and that provision is effectively absent in 2012 and 2013. There is no legal or practical reason why the assurance provisions do not apply to 2012-2013 budgets in 2012 and 2013. EPA has determined that those budgets are achievable. Exelon has confirmed EPA's conclusions through a peer review, and the variability limits function as a safeguard against any error. Accordingly, Exelon urges EPA to modify the final Transport Rule to impose assurance requirements beginning in 2012. [EPA-HQ-OAR-2009-0491-2666.1, pp.23-24]

47 As discussed in Comment 6 below, EPA has revised its modeling assumptions. These revisions have resulted in modeling projections showing that, if anything, the state budgets set out in the proposed Transport Rule, which EPA has not yet revised, are even more certain to be achieved in keeping with the schedule in the proposed rule. Whether or not EPA ultimately reduces the proposed state emission budgets, as Exelon urges in Comment 6, EPA must establish both achievable state budgets and a means to ensure compliance with those budgets.
Response: 
EPA is finalizing the assurance provisions to begin in 2012.  See preamble section VII.E for more information about the assurance provisions and EPA's decision to implement them starting in 2012. 
Organization: Florida Municipal Power Agency (FMPA)
Comment: 
Florida Municipal Power Agency (FMPA)
D. The Proposed Assurance Provisions May Lead to Retroactive Penalties
FMPA prefers EPA's Preferred Remedy Option  -  a cap-and-trade program with state-specific budgets and limited interstate trading  -  because it is more cost effective and provides increased flexibility. However, we share others', including FMEA's, concerns about the assurance provisions in which EPA would assess penalties on utilities retroactively if states exceed their state cap, even if the individual utility is in compliance with its own allowance requirements. This would provide no compliance certainty for a utility regardless of the precautions taken to ensure that it meets allowance requirements. FMPA recommends EPA add a provision that would protect those utilities that have stayed within their allowance requirements from retroactive penalties in cases where the utility did not receive reasonable advance notice that the state would exceed its allowance cap. [EPA-HQ-OAR-2009-0491-2725.1, pp.7-8]
Response: 
EPA is finalizing the assurance provisions to begin in 2012, rather than in 2014.  If a utility (at the designated representative level) does not exceed its allowance allocation plus share of the variability limit, it will not have to surrender allowances even if the state goes over the state assurance level.  Only those sources whose common DR exceeds the number of allocated allowances plus share of the variability limit are responsible for surrendering allowances to cover the penalty when assurance provisions are triggered.  See preamble section VII.E for more information about the assurance provisions and EPA's decision to implement them starting in 2012. 
Organization: GE Energy Financial Services (GE EFS)
Indiana Energy Association
Progress Energy Service Company
Comment: 
GE Energy Financial Services (GE EFS)
At the very least, GE EFS believes that this concern supports EPA's proposal to delay implementation of the assurance provisions until 2014. [EPA-HQ-OAR-2009-0491-2701.1,pp.5-6]
Indiana Energy Association
b. The Indiana Utility Group may support EPA's decision to defer imposition of 'limited trading' through assurance provisions until the second phase of the program in 2014. [EPA-HQ-OAR-2009-0491-3711 p.5]
Progress Energy Service Company
In addition, and again in order to provide flexibility while assuring that emissions are reduced, Progress Energy supports EPA's proposal not to apply variability limits until 2014.  [EPA-HQ-OAR-2009-0491-2831.1 p.2]
Response: 
EPA is finalizing the assurance provisions to begin in 2012, rather than in 2014.  See preamble section VII.E for more information about the assurance provisions and EPA's decision to implement them starting in 2012. 
Organization: Maryland Department of Environment (MDE)
Comment: 
Maryland Department of Environment (MDE)
Additionally in the years 2012 and 2013, EPA proposes to use the State Budgets/Limited Trading remedy without assurance provisions. This would allow members of each trading program to buy allowances from one another, and state budgets would not be evaluated for exceedances at all in those two years. Maryland would like to see the first two years of trading incorporated into the trading program with assurance provisions. [EPA-HQ-OAR-2009-0491-2639.2, p.15]
Response: 
EPA is finalizing the assurance provisions to begin in 2012.  See preamble section VII.E for more information about the assurance provisions and EPA's decision to implement them starting in 2012. 
Organization: Northeast States for Coordinated Air Use Management (NESCAUM)
Comment: 
Northeast States for Coordinated Air Use Management (NESCAUM)
We also urge EPA to require variability provisions to take effect in 2012 rather than 2014.  [EPA-HQ-OAR-2009-0491-2694.1 p.8]
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.11.]
We also urge EPA to require variability provisions to take effect in 2012 rather than 2014.
Response: 
EPA is finalizing the assurance provisions to begin in 2012.  See preamble section VII.E for more information about the assurance provisions and EPA's decision to implement them starting in 2012. 
Organization: Tennessee Valley Authority (TVA)
Comment: 
Tennessee Valley Authority (TVA)
B. Issue: Under EPA's proposal, the 1-year variability limit would start applying in 2014 and the 3-year limit in 2016. EPA is seeking comment on whether the 1-year variability limit should apply starting in 2012 instead of 2014. [p. 45296] EPA is also taking comment on whether the assurance provisions used to limit interstate trading should be in force during the 2012-13 period. [p. 45306, 45314] [EPA-HQ-OAR-2009-0491-2782.1, p. 15]
TVA Comment: EPA should not apply the 1-year variability limit starting in 2012. As stated elsewhere in our comments, EPA should eliminate the 2012 compliance date in the Proposed Transport Rule. In any event, no basis exists for including a 2012-13 phase because, by EPA's own analysis, the emission levels required in this phase reflect emission reductions that would occur even in the absence of additional FGDs and SCRs. Under EPA's analysis, a high level of certainty exists as to where reductions will occur in this phase based on known air pollution controls, eliminating the need for variability limits in 2012 and 2013. By the same token, assurance provisions should not be in force during the 2012-13 period. [EPA-HQ-OAR-2009-0491-2782.1, p. 15]
Response: 
EPA is finalizing the assurance provisions to begin in 2012, rather than in 2014.  EPA received comments supporting the implementation in 2012 with the rationale that is was more consistent with the court decision in North Carolina.  See preamble section VII.E for more information about the assurance provisions and EPA's decision to implement them starting in 2012. 
Organization: Utility Air Regulatory Group (UARG)
Comment: 
Utility Air Regulatory Group (UARG)
In addition, if EPA retains its proposed two-phased compliance schedule, UARG supports EPA's proposal not to apply variability limits and assurance provisions before 2014. 75 Fed. Reg at 45296/1, 45305/3. EPA states that assurance provisions will not be necessary to limit interstate trading during the first two years of the program because during those years, "state-specific budgets are based on known air pollution controls and thus a high level of certainty exists about where reductions will occur." 75 Fed. Reg. at 45306/1. Given the nature of EPA's proposal, EPA's reasoning is sound: If the state budgets are based on reductions that EPA expects will occur based on use of control equipment that will be installed and operational by that time, there is no need for assurance provisions during this time period. [EPA-HQ-OAR-2009-0491-2756.1, p.12]
Response: 
EPA is finalizing the assurance provisions to begin in 2012, rather than in 2014.  See preamble section VII.E for more information about the assurance provisions and EPA's decision to implement them starting in 2012. 
Organization: Wisconsin Power and Light Company
Comment: 
Wisconsin Power and Light Company
WPL further supports that the EPA would not apply the assurance provisions under the preferred option during the 2012-2013 transition period. [EPA-HQ-OAR-2009-0491-2844.1 p.3]
Response: 
EPA is finalizing the assurance provisions to begin in 2012, rather than in 2014.  See preamble section VII.E for more information about the assurance provisions and EPA's decision to implement them starting in 2012. 

V.D.2.f. Penalties

Organization: Edison Electric Institute (EEI)
RRI Energy, Inc.
E.ON U.S.
Class of '85 Regulatory Group
Gainesville Regional Utilities (GRU)
Duke Energy
Comment: 
Class of '85 Regulatory Group
EPA Should Clarify Civil Penalties.
The penalties for holding insufficient allowances during a compliance period are unclear as written. It appears that EPA is planning to impose both an allowance surrender requirement and a discretionary civil penalty in cases where an owner fails to hold sufficient allowances to cover emissions during a given compliance period. As currently written 'each ton of unauthorized emissions and each day of the control period' could constitute separate violations of the CAA. However, it is unclear whether an owner would be subject to penalties for each day within the entire control period, or only those days for which they held insufficient allowances. It also is unclear whether one day equals one violation, or whether there could be multiple violations for each day for each ton of unauthorized emissions occurring that day. [EPA-HQ-OAR-2009-0491-2854.1,p.13]
The Class of '85 does not believe that civil penalties are appropriate for failure to hold sufficient allowances. However, if EPA insists on retaining the option for civil penalties, the Class of '85 believes that a penalty based on every day within a control period and cumulative civil penalties are excessive and inconsistent with the structure of the CAA. To address these inconsistencies and the lack of clarity in the Proposal, EPA should clarify the penalty provisions. Specifically, EPA should clarify that civil penalties can only begin on the day that an owner 'runs out' of allowances for a unit during a given compliance period. EPA should also clarify that penalties are not cumulative, but calculated on a per-day basis. For example, in a scenario where there are 365 days in a compliance period and an owner 'ran out' of allowances on day 363, there could be a maximum of three days of violation of the CAA, corresponding to a maximum imposition of three separate penalties. This is consistent with CAA provisions that allow a single civil penalty 'per day of violation' and avoids potential confusion resulting from the current penalty provisions, which are unclear as written. Finally, the imposition of an allowance surrender requirement on top of this civil penalty is excessive, unnecessary, and inconsistent with the CAA. EPA should clarify that any allowance surrender requirement is in lieu of civil penalties and does not constitute an additional penalty. [EPA-HQ-OAR-2009-0491-2854.1,p.13]
Duke Energy
The compliance provisions for excess emissions are unreasonable. If the Transport Rule is to be based on an allowance trading provision, it is not appropriate to cite a unit for violations of the Clean Air Act both for the excess tons and for each day during the control period. The excess emissions above the allowances held in a compliance account do not reflect any exceedance related to daily operations on a given unit. As proposed, a generating unit that exceeded the allowances in its account by even one ton, whether due to an accounting error or the inability to secure sufficient allowances, would be subject to penalties for daily violations across the entire control period (that is, for 365 days in the case of the NOx and SO2 annual programs, or for the entire period from May through September for the NOx ozone season program). Penalties should be imposed based on either the number of tons of the exceedance or on an allocation of the available allowances to correspond sequentially with the hours operated during the control period, but not both. In the latter case, no daily exceedance would occur until the date on which the available allowances were all accounted for.  [EPA-HQ-OAR-2009-0491-2689.1,pp.65-66]
E.ON U.S.
The proposed penalties for excess emissions are extremely high and unnecessary.
EPA has proposed penalties for excess emissions as high as $37,500 per ton and treating each day of the year as a separate violation. As such, penalties could reach millions of dollars for what could easily have been an accounting error. Certainly, there should be penalties for excess emissions, but this proposal is extreme. By contrast, the Acid Rain Program imposes penalties which started at $2,000 per ton and has increased to about $3,500 per ton. Companies have rigorously sought to comply with the Acid Rain Program and the very few instances of excess emissions appear to be due to administrative or clerical errors. There is no evidence that any company intentionally exceeded its allowance holdings because the penalties were too low. [EPA-HQ-OAR-2009-0491-2797.1, p.9]
Edison Electric Institute (EEI)
EEI opposes EPA's proposal on discretionary penalties  
Under the construct of the Acid Rain Program, if a utility is found in violation of the requirement to hold sufficient allowances to cover its actual emissions, an excess emissions penalty is assessed automatically for each ton of excess emissions, and an automatic offset of emissions impact is made through the surrender of an allowance for each ton of excess emissions. The excess emissions penalty was set by statute, starting at $2,000, and has been CPI-adjusted annually. The current value for the excess emissions penalty for 2010 is $3,464. The success of this approach has been touted by EPA as a sufficient deterrent to non-compliance, and EPA has repeatedly emphasized a near perfect compliance record of the utility industry under the Acid Rain Program. EPA also has identified that most cases of non-compliance have only involved a few tons of excess emissions, and have resulted from administrative errors. [EPA-HQ-OAR-2009-0491-2697.1, p.18]
Despite this unassailable record, EPA has advanced in the Proposed Rule a draconian approach that could result in an excess emissions penalty assessed at the rate of $37,500 per ton of excess emissions, with each day of the averaging period assessed as a separate penalty. Such an approach could result in a company being assessed a penalty of $13,687,500 for a single ton of excess emissions under the proposed annual programs for SO2 and NOx. EPA has failed to provide any justification for such a radical change to the excess emissions penalty scheme as originally set by Congress, and should withdraw its proposed approach and return to a methodology consistent with the Acid Rain Program. [EPA-HQ-OAR-2009-0491-2697.1, pp.18-9]
Gainesville Regional Utilities (GRU)
GRU has Concerns with EPA's Automatic Penalty Provision
EPA establishes an automatic penalty system that will assess penalties on utilities retroactively if states exceed their specific caps even if the individual utility is in compliance with its own allowance requirements. This is in addition to penalties based on the CAA violations for emitting more emissions than the utility has allowances. This penalty system provides no compliance certainty for any given utility regardless of the precautions taken by an individual utility. [EPA-HQ-OAR-2009-0491-2674.1, p.7]
RRI Energy, Inc.
The penalties proposed for failure to hold an allowance for each ton of SO2 or NOx emitted are excessive and must be reduced.
RRI believes the proposed penalties are too severe for inadequate allowances being in an account at the required surrender date, and as such, proposes the following alternatives:
How the proposal would be implemented - penalties RRI supports the proposed penalty of $25,000 (adjusted per the CPI  -  $37,500 in 2009). However, RRI does not support a violation for every day in a control period when inadequate allowances are in an account. The daily violation should reflect the operating days remaining in a control period for which an inadequate number of allowances are available. For example, if an account is one allowance short for the control period, and there are adequate allowances in the account to cover the emissions for all operating days except the last one during the control period, then that unit would be accountable for two allowances  -  one for the short allowance and one for the operating day for which inadequate allowances are in the account. [EPA-HQ-OAR-2009-0491-2717.1 p.5]
Response: 
See section VII.F of the preamble.

V.D.2.g. Electric Reliability

Organization: American Electric Power
Comment: 
American Electric Power
The Proposed Transport Rule neglects to consider utility system planning factors that affect unit retirement decisions and deadline-driven resource and skilled labor shortages, and the consequences to electrical system reliability and functionality in the event of a national or regional grid emergency. [EPA-HQ-OAR-2009-0491-2665.1, p.26]
Response: 
EPA does not believe it has neglected utility system planning factors in its analysis of this rule.  As stated in the preamble (VII.A), EPA selected an interstate trading program structure in part because its market-based flexibility promotes the sector's capacity for providing electric reliability in unit retirement decisions.  EPA believes that the level of potential retirements, projected to be approximately 4.8 GW in 2014 (see the RIA and IPM documentation in this docket) is well within the capability of utilities and regional organizations to manage effectively.  The IPM modeling for the rule takes into account both the required regional reserve margins and the limitations of firm power transfers between regions, so that the basic reliability requirements are already incorporated in the analysis of the impact of the rule.  Moreover, because the rule provides the flexibility to purchase allowances rather than retire, projected retirements under the rule are based on economic considerations rather than fixed deadlines or unit-specific compliance requirements.  Consequently, EPA anticipates that the Transport Rule will not affect the ability of regional grid management organizations and/or interconnected utilities to routinely manage any local grid issues that may arise.  For further information, see the Technical Support Document on Resource Adequacy and Reliability in this docket.
Organization: Constellation Energy
Clean Energy Group
Exelon
NextEra Energy, Inc.
PSEG Services Corporation
Comment: 
Clean Energy Group
II. The Electric Sector has Tools at its Disposal to Implement the Transport Rule Without Significant Increased Reliability Risks
EPA was also reasonable in concluding that it will be feasible for the electric sector to comply with the Transport Rule, including in Group 1 S02 states. According to EPA's NEEDS database, approximately 56 GW of scrubbers were installed between 2006 and 2009, including 15 GW across 50 to 60 sites in 2009. EPA projects that an additional 19 GW of scrubbers will come online in 2010. In contrast, EPA estimates that between four and 14 GW of scrubbers and less than 1GW of SCR for NOx control will be required for the electric sector to comply with the proposed 2014 emission caps. [EPA-HQ-OAR-2009-0491-2702.1, p. 3]
EPA separately projects that 1.2 GW of generating capacity may be removed from operation by 2014 in response to the proposed rule. While the Clean Energy Group does not agree with some of the results of EPA's modeling on a unit level (see below and individual members' comments), we do not believe the Transport Rule, as proposed, would significantly increase system reliability risks. Reserve margins throughout the Transport Rule region exceed target reserve levels and there is substantial underutilized natural gas-fired combined cycle gas turbine capacity outfitted with advanced NOx controls, suggesting that the system has sufficient capacity to absorb additional retirements and compensate for scheduled outages for purposes of installing pollution control technologies.2 Additionally, substantial new capacity has been announced, planned, or is seeking grid interconnection studies. Across the regions of the North American Electric Reliability Corporation (NERC), a recent analysis identified over 55 GW of proposed generation in advanced stages of development. Although not all of this generation will be built, new capacity is expected to far exceed potential retirements related to the Transport Rule.  [EPA-HQ-OAR-2009-0491-2702.1, pp. 3-4]
Further, if there are isolated reliability issues in areas of heavy demand as a result of implementing the Transport Rule, other rules affecting the electric sector, or other reasons (e.g., weather), existing risk management procedures under the Clean Air Act, the Federal Power Act, and other statutes already provide EPA, the Department of Energy, the Federal Energy Regulatory Commission, and the President with tools to address unforeseen impacts on electric system reliability on an individual basis. In addition to these regulatory tools to mitigate risks to electric reliability, many of the competitive markets have forward capacity markets (for example, PJM's Reliability Pricing Model) that provide for coordinating unit retirement and system reliability. These forward capacity markets are approved by the Federal Energy Regulatory Commission (FERC) and supervised by independent market monitors. [EPA-HQ-OAR-2009-0491-2702.1, p. 4]
Constellation Energy
Reliability concerns will be the focus of many comments. Constellation Energy's view is that underutilized natural gas fired generating units are available with sufficient capacity to adequately supply any potential capacity deficit. This is possible because the Transport Rule appropriately strikes a balance between flexibility (market) and assurance of reductions (command/control). We urge EPA to employ the same type of balance in separate rulemakings on EGU MACT. Reliability could become a legitimate concern if MACT is employed strictly as an emissions rate-based approach. [EPA-HQ-OAR-2009-0491-3613,p.3]
Exelon
THE TRANSPORT RULE WILL NOT RESULT IN THE RETIREMENT OF FOSSIL FUEL GENERATION CAPACITY IN AN AMOUNT THAT IS MATERIAL TOTHE RELIABILITY OF THE ELECTRIC SYSTEM.
On a system-wide basis, no additional controls beyond those already firmly planned will be required by 2012, and few will be required by 2014. The industry has already installed far more controls in comparable periods in the past than will be required to achieve the emission budgets established by the Transport Rule. [EPA-HQ-OAR-2009-0491-2666.1, pp.18-19]
Exelon concurs with EPA's estimate that only a de minimis amount of fossil fuel generation capacity will become uneconomic to maintain as a result of the Transport Rule. There is over 55 GW of new generation capacity planned for 2013 already in the queue, far more than would be needed to replace any units retiring under the Transport Rule, even if none of the EPA-projected 14 GW of FGD and 1 GW of SCR required by 2014 were installed. Indeed, estimates across each of the North American Electric Reliability Corporation ("NERC") regions for 2013 anticipate actual capacity levels that exceed the minimum reserve requirements that protect against reliability threats such as unexpectedly high demand and transmission failures. Over 100 GW of surplus generating capacity is expected. There is adequate generating capacity to protect grid reliability even if older, uncontrolled power plants choose to retire rather than retrofit. [EPA-HQ-OAR-2009-0491-2666.1, p.19]
EPA CAN SUCCESSFULLY IMPLEMENT THE TRANSPORT RULE AS WELL AS FUTURE RULEMAKINGS NECESSARY TO PROTECT PUBLIC HEALTH AND THE ENVIRONMENT WITHOUT JEOPARDIZING SYSTEM RELIABILITY. EPA, DOE, INDEPENDENT SYSTEM OPERATORS/REGIONAL TRANSMISSION ORGANIZATIONS ("RTOS") AND INDUSTRY HAVE A WIDE RANGE OF TOOLS AVAILABLE TO SUPPORT THE TRANSITION.
Existing safeguards within the electric grid and coordination among government agencies and industry will ensure reliable energy distribution following implementation of the Transport Rule. As the comments submitted by the Clean Energy Group in response to EPA's Strategic Plan indicate, "the electric industry has demonstrated a proven ability to build replacement generation as needed or otherwise meet demand through demand response, energy efficiency, and conservation." Furthermore, regulatory agencies have legal tools that can be effectively coordinated to address issues that may threaten reliability. [EPA-HQ-OAR-2009-0491-2666.1, p.19; For additional comments pertaining to EPA CAN SUCCESSFULLY IMPLEMENT THE TRANSPORT RULE AS WELL AS FUTURE RULEMAKINGS NECESSARY TO PROTECT PUBLIC HEALTH AND THE ENVIRONMENT WITHOUT JEOPARDIZING SYSTEM RELIABILITY. EPA, DOE, INDEPENDENT SYSTEM OPERATORS/REGIONAL TRANSMISSION ORGANIZATIONS ("RTOS") AND INDUSTRY HAVE A WIDE RANGE OF TOOLS AVAILABLE TO SUPPORT THE TRANSITION, see pp.19-21 of this comment summary]
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.39-40.]
With regard to electric system reliability, the Transport Rule will not pose any significant reliability risks as it will not drive significant power plant retirements or result in unmanageable pollution control retrofit requirements.
For example, EPA forecasts that 1.2 gigawatts of generating capacity may become uneconomic under the Transport Rule. However, looking across all NERC regions of the country, on a combined basis, there is currently over 100 gigawatts of installed generating capacity above required reserve margins; an amount of excess capacity that far exceeds any reasonable forecast of unit retirements under the Transport Rule.
Recently, Exelon joined with like-minded utility companies, all of which are members of the Clean Energy Group, to sponsor a reliability study that considers all of EPAs rules on a holistic basis. The report, entitled, 'Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability,' proposes some common sense steps that will allow the power generation industry to meet all expected new EPA air and regulatory requirements on a timely basis.
NextEra Energy, Inc.
NextEra Energy believes that the air quality benefits of the proposed Transport Rule can be achieved without jeopardizing reliability of the electric system.
As indicated above, EPA estimates that approximately 14 GW of SO2 scrubbers and less than 1 GW of SCR for NOx control will be required for the electric sector to comply with the proposed 2014 emission caps. In addition, EPA projects that, relative to base case projections (i.e., business-as-usual), about 1.2 GW of coal-fired capacity (less than 1 percent of all coal-fired capacity in the Transport Rule states) may become uneconomic to continue operating by 2014 as a result of the cost of compliance with the Transport Rule. According to EPA, these units are, for the most part, small and infrequently used generating units that are dispersed throughout the states covered in the Transport Rule and that, in practice, units projected to be uneconomic to maintain may be 'mothballed,' retired, or kept in service to ensure transmission reliability in certain parts of the grid. [EPA-HQ-OAR-2009-0491-2718.1, p.8]
Some third-party analysts have concluded that the proposed Transport Rule, along with other upcoming rulemakings that will regulate air emissions from fossil fuel-fired power plants, such as the Electric Utility Hazardous Air Pollutant Maximum Achievable Control Technology (MACT) Rule could result in the retirement of a significantly greater amount of the nation's 1,030 GW of electric generating capacity than EPA has projected with respect to the Transport Rule. This has raised concerns about the combined effects over the next five years of anticipated power plant retirements and outages required to install new pollution control equipment on the ability of the industry to maintain reliability of the electric system. [EPA-HQ-OAR-2009-0491-2718.1, p.8]
NextEra Energy does not believe the Transport Rule, as proposed, would significantly increase electric system reliability risks. Reserve margins throughout the Transport Rule region are well in excess of target reserve levels, suggesting that the system has the capacity to absorb additional retirements and compensate for scheduled outages for purposes of installing pollution control technologies. Further, if there are isolated reliability issues in areas of heavy demand as a result of implementing the Transport Rule or additional rules affecting the electric sector, existing risk management procedures under the Clean Air Act, the Federal Power Act, and other statutes already provide EPA, the Department of Energy (DOE), the Federal Energy Regulatory Commission (FERC), and the President tools to address unforeseen impacts on electric system reliability on an individual basis. [EPA-HQ-OAR-2009-0491-2718.1, pp.8-9]
This viewpoint is supported by a recent analysis performed by M.J. Bradley and Associates and the Analysis Group of the potential impact of EPA's upcoming air regulations (including the proposed Transport Rule), with a focus on the issue of possible power plant retirements on electric reliability.' This analysis reached the following three conclusions:
1. Even though some units likely will retire in lieu of complying with the new regulations electric system reliability will not be compromised if the industry and its regulators proactively manage the transition to a cleaner. more efficient generation fleet. When assessing reliability impacts, not only must generation capacity and availability be considered but consumption levels and patterns, and transmission capacity and use must be taken into account as well. According to the analysis, existing power system capacity well in excess of minimum reserve levels, relatively modest projections of load growth over the next several years, a large amount of proposed generating resources, and the availability of load management practices indicate that the electric system can handle the level of projected EGU retirements. The industry has a proven track record of adding new generating capacity and transmission solutions when and where needed and of coordinating effectively to address reliability concerns. In the three years between 2001 and 2003, the electric industry built over 160 GW of new generation-about four times what some analysts project will retire over the next five years as a result of the Transport Rule and other upcoming EPA air regulations. [EPA-HQ-OAR-2009-0491-2718.1, p.9]
2. Concerns that it will cost the industry too much to comply with EPA's proposed air regulations that pollution controls cannot be installed soon enough, or that the EPA regulations will lead to the closure of otherwise economically healthy power plants are without merit. The proven technologies for controlling air pollution emissions, such as NOx, SO2, mercury and acid gases, are commercially available and have already been, or soon will be, installed on the majority of the nation's coal plants (65 percent with scrubbers; 50 percent with advanced NOx controls), demonstrating that the costs can be managed. The industry also has a demonstrated ability to schedule and sequence unit outages in an efficient and reliable manner and is capable of installing additional pollution control systems to comply with the Transport Rule and Utility MACT Rule. Many of the coal units that are the most likely candidates to shut down are smaller, 40 to 60 year old units, which are nearing the end of their design life expectancy and are already economically challenged. Additionally, the retirement of some existing generating capacity will create room on the transmission grid to accommodate additional power flows, or new generating capacity, without requiring attendant upgrades in transmission, thus mitigating reliability concerns while reducing the cost of transitioning to a cleaner, more efficient generation fleet. [EPA-HQ-OAR-2009-0491-2718.1, p.9]
3. EPA FERC DOE and State utility regulators, both together and separately, have an array of tools to moderate impacts on the electric industry:
:: EPA may, and if needed should, exercise its statutory authority under the Clean Air Act to grant, on a case-by-case basis, extensions of time to complete pollution control installations, where appropriate.
:: To the extent that its legal authority allows, EPA should adopt regulatory approaches that allow for cost-effective compliance, such as the emissions trading mechanism proposed in the Transport Rule. [EPA-HQ-OAR-2009-0491-2718.1, p.9]
:: In circumstances in which power plant retirements trigger localized reliability concerns, EPA and DOE should follow established precedent, including use of consent decrees, to permit continued operation for reliability purposes only, pending necessitate upgrades or generation additions. Additionally, the various federal agencies and offices with responsibility for assuring reliability for the nation's electricity capability should work together to help support the industry and states in complying with EPA's new air regulations. [EPA-HQ-OAR-2009-0491-2718.1, p.10]
:: Transparent, well-established market rules approved by FERC and overseen by independent market monitors, particularly the forward capacity markets relied on by some Regional Transmission Operators, as well as state regulatory agency oversight, provide additional safety nets to help ensure adequate capacity. Although EPA is under court order to promulgate its air regulations, the Agency can and should coordinate the implementation of anticipated water regulations under Section 316(b) of the Clean Water Act and new waste regulations to avoid possible reliability concerns. [EPA-HQ-OAR-2009-0491-2718.1, p.10]
PSEG Services Corporation
The electric sector has tools at its disposal to implement the Transport Rule without negative impacts on the reliability of the electric system. In the preamble to the proposed rule, EPA estimates that approximately 14 gigawatts ("GW") of SO2 scrubbers and less than 1 GW of SCR for NOx control will be required for the electric sector to comply with the proposed 2014 emission caps. The magnitude of anticipated retrofits is significantly less than the industry has added in recent construction cycles. For example, during the recent peak of scrubber construction between 2008 and 2010, approximately 60 GW of coal capacity was retrofit with scrubber controls, highlighting the industry's ability to complete a substantial number of retrofits over a short period of time. In 2009 and 2010, the industry completed between 50 and 60 scrubber retrofits each year. [EPA-HQ-OAR-2009-0491-2627.1, p.3]
EPA projects that 1.2 GW of generating capacity may be removed from operation by 2014 in response to the proposed rule and notes that these units are predominantly small and infrequently-used generating units dispersed throughout the area affected by the rule. We do not believe the Transport Rule, as proposed, would significantly increase system reliability risks. Reserve margins throughout the Transport Rule region are well in excess of target reserve levels, suggesting that the system has the capacity to absorb additional retirements and compensate for scheduled outages for purposes of installing pollution control technologies. 2 [EPA-HQ-OAR-2009-0491-2627.1, p.4]
Further, if there are isolated reliability issues in areas of heavy demand as a result of implementing the Transport Rule or additional rules affecting the electric sector, existing risk management procedures under the Clean Air Act, the Federal Power Act, and other statutes already provide EPA, the Department of Energy, the Federal Energy Regulatory Commission, and the President have tools to address unforeseen impacts on electric system reliability on an individual basis. [EPA-HQ-OAR-2009-0491-2627.1, p.4]

2 For further analysis of the electric industry's considerable capacity to manage system reliability while installing pollution control equipment and retiring a portion of the generating fleet, please see the recent report Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability available at http://mjbradley.com/documents/MJBAandAnalysisGroupReliabilityReportAugust2010.pdf. The report was prepared on behalf of several members of the Clean Energy Group, including: Calpine Corporation, Constellation Energy, Entergy Corporation, Exelon Corporation, NextEra Energy, National Grid, PG&E Corporation, and Public Service Enterprise Group (PSEG).
Response: 
These comments generally agree with EPA in maintaining that the rule will not impair the reliability of the electric power system.
Organization: Consumers Energy
Comment: 
Consumers Energy
:: With respect to low-sulfur sub-bituminous coal, more coal has to be burned to produce the same amount of electricity as eastern coal, requiring changes to the coal-handling systems and potentially to the permit (which takes about 1.5 years). In addition, our coal and rail contracts are negotiated several years ahead of time and cannot be changed within 6 months. Furthermore, there are logistical limits to how much more coal can be provided in the near term by the suppliers, rail and vessel delivery systems, all of which are currently operating near capacity. It is unlikely that these systems would be able to support large increases in coal requirements quickly. [EPA-HQ-OAR-2009-0491-2837.1, p.8]
:: To shutdown or restrict the operation of the units, approval must be granted by both the MPSC and the Midwest Independent Transmission System Operator (MISO). Furthermore, notification to EPA is required. Retiring units or placing units into long term cold storage earlier than planned will increase customer rates, which the MPSC is resistant to do, especially in Michigan's current economy. According to MISO FERC Electric Tariff, Fourth Revised Volume No. 1, a MISO market participant must deliver to the 'Transmission Provider Attachment Y, Notification of Potential Generation Resource or SCU Change of Status, if a Market Participant plans to either: (i) decommission and retire a Generation Resource or a Synchronous Condenser Unit (SCU) that it either owns or operates; (ii) suspend operation of and place into extended reserve shutdown such Generation Resource or SCU for a period of more than two (2) months; or (iii) disconnect such Generation Resource or SCU from the Transmission System for a period of more than two (2) months. Attachment Y must be submitted to the Transmission Provider at least twenty-six (26) weeks prior to the Market Participant engaging in any of the aforementioned activities.' MISO will then evaluate whether or not the Generation Resource is necessary for system reliability. The best case scenario would be for an approval from MISO, but the more likely scenario would require some form of transmission system upgrade in order to do so. Preliminary estimates for upgrades are upwards of 39 to 40 months. [EPA-HQ-OAR-2009-0491-2837.1, p.8]
Response: 
Transmission system concerns
      EPA modeling with IPM considered the issues of regional resource adequacy and inter-regional transmission of power. EPA recognizes that local grid issues, such as shifts in congestion patterns and transmission impacts from the retirement of specific power plants, will need to be coordinated at the utility and regional levels as they routinely managed for all changes in the power sector. However, EPA also believes that there are sufficient provisions in the rule for flexible coordination with regional entities and among utilities to permit these local issues to be resolved in the normal course of business.
      IPM modeling considers regional resource adequacy based on current and projected NERC reserve margins, and considers transmission system limitations by placing limits on flows between regions and on the amount of capacity that can be transferred between regions to meet regional reserve margins. This modeling is conservative, in the sense that it considers only current transmission capacity between regions and does not consider ways in which the transmission grid may be improved in the future to allow for additional flexibility in dispatch to meet load. In other words, EPA's projections show cost-effective EGU emission reductions subject to regional limitations of the transmission grid as it exists today, and its projections are fully compatible with the power sector's ability to comply with the rule's emission reductions while successfully operating the grid.
Coal switching concerns
      These comments make reference to retiring units but do not raise specific reliability concerns; in any case, the comments do not raise reliability concerns with respect to unit operation because the rule does not require fuel switching at individual units. In addition, EPA revised its modeling in response to comments on coal switching capability and costs in the analysis of the proposed rule. See preamble section VII.C.2 and IPM documentation in this docket.
Organization: Council of Industrial Boiler Owners (CIBO)
Comment: 
Council of Industrial Boiler Owners (CIBO)
CIBO supports market-based mechanisms to achieve reductions, as these have been proven to be the most cost-effective means of achieving reductions. In the context of this Proposed Rule, CIBO generally supports the state budget/limited trading remedy, as the best of the solutions offered. However, that program as proposed is not without its foreseen difficulties. One such difficulty is reliability. CIBO members, many of whom are major consumers of electricity, are directly affected by electricity reliability. In the Proposed Rule, 75 FR 45315: EPA states that the state budget/limited trading remedy is not a risk to electric reliability. The statement is that the ISOs have the flexibility to manage regional generation so that reliability is maintained. The first question is how this affects the many interests participating in an ISO? Does this give the ISO/RTO a need to favor generation from one part of the country over another? For example, would this drive a preference for the dispatch of east coast gas/oil generation over Midwest coal during certain times of the year in order to preserve the "room" within a variability limit for summer/winter demand? If so, does that create a disparity for Midwest customers who would lose their access to lower-cost power? How does this impact transmission congestion, grid reliability, and resultant costs of power? These issues do not appear to have been fully addressed and likely need FERC input.  [EPA-HQ-OAR-2009-0491-2751.1 p.12] 
Response: 
      EPA believes that the modeling performed for the analysis of this rule has addressed the reliability issues raised in these comments with respect to dispatch shifts. EPA's IPM modeling includes representation of regional dispatch that includes regional reserve margins and transmission limits on transfer of capacity between regions to meet reserve margins. See IPM documentation and results of the IPM modeling of this rule in this docket.
Organization: Dairyland Power Cooperative
Comment: 
Dairyland Power Cooperative
Considering the relative little time remaining prior to 2012, procurement and delivery of an adequate supply of PRE fuel for 2012 to the Dairyland Power's Alma Generating Station site, which only receives fuel delivery by river barge during the Mississippi River navigation season, appears more than a little problematic and places Dairyland Power in serious jeopardy of being able to operate Alma Unit 4 and Alma Unit 5 and comply with EPA's proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2733.1 p.3]
The magnitude of lost generating capacity associated with a fuel switch to 100% PRE coal, from design coal quality, is significant to a small rural electric cooperative like Dairyland Power which has a small portfolio of generating assets. It is infeasible at this point in time for Dairyland Power to build replacement generating capacity by 2012. In the alternative, Dairyland Power would face a very constrained timeline to attempt to contract for replacement capacity between the time of rule promulgation and 2012. [EPA-HQ-OAR-2009-0491-2733.1 p.3]
In summary, we do not believe that the EPA's proposed Transport Rule properly accounts for the extreme impacts imposed on Dairyland Power's Alma Unit 4 and Alma Unit 5 with an assumption that these units can simply be 'switched' to fueling with 100% PRB coal by 2012, the first compliance year for the Transport Rule. We urge the EPA to take our comments into consideration when finalizing the Transport Rule 2012 and 2014 S02 allocations and direct control alternative S02 emission rates for Alma Unit 4 and Alma Unit 5.  [EPA-HQ-OAR-2009-0491-2733.1 p.3]
Response: 
      These comments make reference to retiring units but do not raise specific reliability concerns; in any case, the comments do not raise reliability concerns with respect to unit operation because the rule does not require fuel switching at individual units. In addition, EPA revised its modeling in response to comments on coal switching capability and costs in the analysis of the proposed rule. See preamble section VII.C.2 and IPM documentation in this docket.
Organization: Florida Electric Power Coordinating Group, Inc. (FCG)
Comment: 
Florida Electric Power Coordinating Group, Inc. (FCG)
Nor has EPA attempted to assess the proposed Transport Rule's impact, or the impact of all relevant rules combined, on electric system reliability, our national economy (especially given these sensitive and volatile economic times), or the disproportionate impact on lower socio-economic groups and individuals. A few key regulatory examples that EPA must incorporate into its economic and reliability analysis include the:
(a) 2010 National Ambient Air Quality Standard for N02;
(b) 2010 National Ambient Air Quality Standard for S02;
(c) 2010 National Ambient Air Quality Standard for ozone;
 (d) 2011 National Ambient Air Quality Standard for PM2.5;
(e) 2011 National Ambient Air Quality Standard CO;
(f) 2011 revisions to the Transport Rule;
(g) Regional haze rule;
(h) Greenhouse gas regulations;
(i) 2011 industrial boiler MACT;
(i) 2011 utility MACT;
(k) 2010 revisions to 40 CFR 63, Subpart ZZZZ;
(I) 316(b) cooling water intake structures;
(m) numeric nutrient criteria; and
(n) coal combustion residuals. [EPA-HQ-OAR-2009-0491-2658.1, pp.4-5]
Any credible economic and reliability assessment must include the combined impact of all of these rules; to do otherwise would be negligent, an abuse of discretion, and arbitrary and capricious. EPA attempted to analyze the cost of its proposal, but has thus far kept blinders on when considering whether other regulations could be relevant to its overall impact assessment. As an example of a more holistic assessment, the North American Electric Reliability Corporation is currently evaluating the combined impact of four of the above EPA rules on the retirement of specific electric generating units, Planning Reserve Margins, and the need for additional generating units, as well as the magnitude of construction planning necessary for timely compliance. The specific rules NERC is evaluating are the Transport Rule, the utility MACT, 316(b) intake structures, and coal combustion residuals. Further, Electric utilities in Florida are required (annually) to plan on a 10-year horizon, and whenever they decide to make a prudent capital expenditure, it is made with a 20-30-40+ year vision considering all relevant and foreseeable regulatory initiatives. EPA must also consider the long-term consequences of its rules. [EPA-HQ-OAR-2009-0491-2658.1, p.5]
Response: 
      As discussed in section III of the Preamble to this rule, EPA will provide full opportunity for notice and comment on each rule as they are proposed and finalized. EPA will include the final Transport Rule in its regulatory impact analyses of subsequent rulemakings.
Organization: Independence Power & Light (IPL)
Public Utilities Commission of Ohio
E.ON U.S.
Edison Electric Institute (EEI)
First Energy
Four Flags Area Chamber of Commerce
Dominion
Indiana Utility Shareholders Association
Lansing Board of Water & Light
Michigan Manufacturers Association (MMA)
State of Ohio Environmental Protection Agency (Ohio EPA)
Comment: 
Dominion
EPA's assumption that the required retrofits can be completed to meet the required deadlines of the proposed rule is very questionable. At a minimum, we believe EPA needs to assess the impact of the 2014 deadline in terms of electric reliability given the significant amount of capacity that will require retrofits and the very careful alignment of installation schedules and unit tie-in outages that will be required between facilities. In addition, scheduled outages to complete installation and unit tie-ins must be submitted to and approved by the regional Independent System Operators (ISO). We urge EPA to reconsider the feasibility of the 2012 and 2014 compliance dates. [EPA-HQ-OAR-2009-0491-2715.1, p.14]
E.ON U.S.
EPA's approach requires compliance actions that could degrade system reliability. Installing FGD's and SCR's will require taking plants offline while equipment is being installed. The large number of required retrofits within a short timeframe will require many units to be off-line simultaneously. This could affect the industry's ability to provide reliable power to the nation. EPA should coordinate with the Federal Energy Regulatory Commission (FERC), the Department of Energy, and states to determine a compliance target that will ensure maintaining system reliability. [EPA-HQ-OAR-2009-0491-2797.1, p.3]
Edison Electric Institute (EEI)
Some companies also are concerned about the potential regional reliability risks that could come from taking key power plants offline while retrofits are completed, or from having many units off-line concurrently. This concern is more an issue for the broader suite of regulations discussed in Section I than for the proposed Transport Rule alone.  [EPA-HQ-OAR-2009-0491-2697.1, p.7]
First Energy
Multiple concurrent outages of generating equipment also may pose electricity reliability issues that will be unacceptable to the Independent System Operators managing electrical system reliability in the affected regions. EPA should confer with the ISO's to assure electric system reliability standards can be met. [EPA-HQ-OAR-2009-0491-2657.1,p.6]
Four Flags Area Chamber of Commerce
The most significant reductions under the current proposal occur in 2014 - only two-and-a-half years after the Rule is expected to become effective. Two-and-a-half years are not enough to design, permit, fabricate and install the necessary equipment. This unrealistic deadline could affect grid reliability if power companies are forced to prematurely close generation units to comply. If new scrubber byproduct storage facilities are needed in addition to emissions control equipment, the time line becomes much longer. [EPA-HQ-OAR-2009-0491-3807, p.2]
Independence Power & Light (IPL)
IV. THE RULE FAILS TO CONSIDER GRID RELIABILITY AND THE BURDENON EXISTING TRANSMISSION
The Rule demonstrates a misunderstanding about the potential effects that the proposed rule may have on grid reliability. The Rule postulates potential grid reliability problems in terms of the availability of electric generation: noting the preferred trading option 'gives ISOs (Independent System Operators) the flexibility to manage regional electricity generation so that reliability is maintained.' 75 FR at 45315/1; see also id. at 45328/3 ('the ability to obtain additional or replacement supply from sources in another part of the state or from another state enhances electric reliability'). But that tells only half the story, and not the more important part; the availability of electric generation has not been the sticking point for reliability. See, e.g., New York v. FERC, 535 U.S. 1,7 (2002) ('since 1935, and especially beginning in the 1970's and 1980's, the number of electricity suppliers has increased dramatically. Technological advance have made it possible to generate electricity efficiently in different ways and in smaller plants.')(footnote omitted). Rather, reliability problems arise because grid transmission facilities are not always adequate to move electricity from where it is generated to where it is consumed. See id. at 9-10 (summarizing statutory and regulatory efforts to encourage increased access to transmission). [EPA-HQ-OAR-2009-0491-2741.1, p.12]
Similarly, the Rule's view that ISOs 'manage regional electricity generation' (75 FR at45315) overstates the case. ISOs neither control nor operate generation facilities, but, rather, control and operate transmission facilities. See 16 U.S.C. § 8240(a)(6)('The term 'transmission organization' means ... Independent System Operator ... finally approved by the [FERC] for the operation of transmission facilities'); see, e.g., PUD No.1 Snohomish County v. FERC, 272F.3d 607, 611 n. 3 (D.C. Cir. 2001)('Independent system operators (ISOs), in contrast, are nonprofit organizations that operate the transmission facilities that others own.') 2 [EPA-HQ-OAR-2009-0491-2741.1, pp.12-13]
These factors raise doubt about the Rule's implicit assumption that the preferred trading program will not adversely affect grid reliability because adequate generation is available. 75 FR at 45315/1. Even accepting that adequate generation is available, that, by itself, does not assure grid reliability now and could not expected to do so after the rule is implemented, given that the preferred approach could easily increase potential transmission capacity constraints (congestion) that would impede the flow of electricity. In determining the potential impact of the proposed rule on grid reliability, EPA failed to consider the extra burden that the rule will place on existing transmission constraints or in creating new congestion points. Both situations present complex and costly issues related to assuring grid reliability. The failure to consider this central problem to the instant matter constitutes arbitrary and capricious decision-making. See, e.g., Motor Vehicle Mfrs. Ass'n v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983)('an agency rule would be arbitrary and capricious if the agency ... entirely failed to consider an important aspect of the problem'). [EPA-HQ-OAR-2009-0491-2741.1, p.13]
The situation faced by IPL under the proposed rule presents a representative example of the problems that transmission constraints pose for utilities that must rely on purchasing power or emissions allowances to satisfy the rule. Utilities serving retail customers, such as IPL, have a statutory obligation to provide all the electricity needed by their customers (commonly referred to as 'load'). This precludes options in responding to the rule that might be available to nonutility sources, such as reducing the amount of electricity made available to customers or moving operations to another location. Under the proposed rule, IPL has been given zero allocations for two of its EGUs, which represents approximately one-third of IPL's generation capacity. As IPL must nonetheless continue to supply its customers' full load, the proposed rule requires IPL either to purchase replacement power because it cannot run the EGUs or to purchase emissions allocations so it can run them. 3 [EPA-HQ-OAR-2009-0491-2741.1, pp.13-14]
IPL is a member of the Southwest Power Pool (''SPP'), which experiences constraints (congestion) on transmission paths throughout the year. Congestion can be caused by a number of factors: load increasing faster than transmission growth; scheduled (maintenance) or unscheduled (storm) outages; large interjections of electricity at a specific grid point. While unscheduled outages can occur at any time, congestion is likely to occur in peak load periods, which are also the likely times that older, less efficient EGUs will be called into service. Congestion does not necessarily mean customers will not receive electricity, but it does mean that they will pay substantially higher prices for that electricity. SPP offered an example (copy of page attached hereto) of the pricing differential experienced due to congestion at the Missouri- Kansas border, where IPL is located, on January 26, 2010: congestion 'triggered significant price separation in SPP, with prices ranging between -$475.00/MWh and $1,480.00/MWh. Absent this congestion event, the price at all locations would have been $24.26/MWh.' (Available at http://www.spp.org/section.asp?pageID~28, 'Intro to SPP Slideshow.' slide 40; last visited September 25, 2010). Obviously, this is an extreme example, but in many cases, congestion costs can easily double the cost of electricity in the transmission-constrained area. Further, while this example pertains to the Missouri-Kansas border, other transmission paths on SPP experience similar congestion events. Finally, these types of congestion problems are found in all the ISOs that serve the States covered by the proposed rule. [EPA-HQ-OAR-2009-0491-2741.1, p.14] 
These types of congestion problems, causing serious price differentials, are occurring now - before the rule change. Yet, no effort was made to examine how the rule change will affect this important concern or to quantify possible impact. For example, EGUs currently serving load in a specific area could shut down as they become uneconomic to operate with the required additional emission controls or as their owners decide to bank or to apply the units' emissions allocation for other owned generation. Any of those scenarios could create new transmission constrained areas or exacerbate existing ones, thus increasing congestion and costs of obtaining electricity. In other cases, owners may decide that it is cheaper to import purchased electricity than to retrofit existing EGUs, thereby placing more pressure on existing transmission facilities to serve increased load into a specific area. More examples can undoubtedly be fashioned, but the point is such foreseeable consequences should have been factored into the calculus of the rule's impact. The failure to do so ignores real, not abstract, concerns about grid reliability resulting from the proposed rule change as well as about the actual financial impact of following the preferred approach. Ignoring such important considerations is arbitrary and capricious. [EPA-HQ-OAR-2009-0491-2741.1, pp.14-15] 
For the reasons stated herein, IPL requests that EPA modify the proposed Rule by: 
1. taking into account the potential adverse effects of the proposed rules on transmission facilities and how that will impact grid reliability. [EPA-HQ-OAR-2009-0491-2741.1, p.18]

 
2 To be sure, ISOs operate real time markets that provide balancing services to compensate for differences between projected and actual electric loads as well as offer continuous economic dispatch of resources to serve load. In both cases. however, the ISO relies on generation made available by third parties. 
3 This ignores an obvious third option - adding sufficient controls to the units to reduce emissions to zero. This option is addressed later in these comments. The current discussion focuses only on options that would affect grid reliability.
Indiana Utility Shareholders Association
This unrealistic deadline could affect grid reliability if power companies are forced to prematurely close generation units to comply. [EPA-HQ-OAR-2009-0491-3845 p.2]
Lansing Board of Water & Light
This unrealistic compliance deadline will likely affect grid reliability as all power companies will be forced to bring units offline during the same time to install these controls. [EPA-HQ-OAR-2009-0491-2752.1,p.7]
Michigan Manufacturers Association (MMA)
The most significant reductions under the current proposal occur in 2014  -  only two and- a-half years after the Rule is expected to become effective. Two-and-a-half years are not enough to design, permit, fabricate and install the necessary equipment. This unrealistic deadline will affect grid reliability if power companies are forced to prematurely close generation units to comply. [EPA-HQ-OAR-2009-0491-2762.1, p.3]
Public Utilities Commission of Ohio
Statistics in 2009 demonstrate that coal fuels about 85% of the net electric generation in Ohio (Velocity Suite). The Edison Electric Institute Yearbook (2008 data) shows that the state of Ohio is sixth in electric generation and 24th in electricity consumption per capita. Coal makes up more than 65% of Ohio's generation capacity. The Transport Rule, which demands an SO2 emissions reduction of approximately 70%, could impact 16,000 MW of capacity. [EPA-HQ-OAR-2009-0491-2855.1 p.7]
EPA documents that implementing the rule as proposed will unquestionably have a negative impact on the production of electricity from coal. The proposed rule could force early decommissioning of coal-fired generating plants in Ohio, which, again, account for over 85% of net electric generation in the state.[EPA-HQ-OAR-2009-0491-2855.1 p.7] 
U.S. EPA's analysis concludes that the proposed rule will not affect the flow of electricity. We are not convinced, however, that this conclusion adequately accounts for the potential that industry's reaction to this rule, in concert with other U.S. EPA rules, may be to remove capacity from the electric grid within the same region. It appears that this potentiality was not examined. This rule, as well as those to come, will drive the need for new transmission and generation infrastructure investment which will be reflected in electric rates. If this potentiality comes to fruition, it will have a profound effect on regional transmission organization planning, and will result in significantly increased concern over meeting reliability standards. [EPA-HQ-OAR-2009-0491-2855.1 p.7]
Federal Energy Regulatory Commission (FERC) Commissioners echo our concerns regarding reliability challenges arising from EPA regulations in the past. Most recently, at a FERC hearing on September 16, 2010, Chairman Wellinghoff called for an inter-agency taskforce to examine EPA requirements that could affect reliability and the need to keep older generating plants open. Additionally, Commissioner Moeller expressed the importance of the need to understand the implications of shutting down some of the older power plants as a method of complying with, and in response to, EPA regulations.2 Commissioner Moeller further noted that the challenges of removing generation from the grid and ensuring reliable electricity supplies are largely determined by the location of power plants, and in an interview with energywashington.com, stressed the importance of understanding the complicated issue, and noted the pressing need to enter into any remedial situation "with our eyes wide open."3 The FERC Commissioners' comments strongly support a slow-down in implementation. [EPA-HQ-OAR-2009-0491-2855.1 p.8]
We believe that in terms of reliability, implementation of the Transport Rule, as proposed, will result in a level of uncertainty that is unacceptable and, further, irresponsible. As the rule is proposed, it is unclear how many power plants will need to be retrofitted to meet the rule's stringent emissions requirements. In Ohio, as well as a number of other states that will be affected by the rule, there are many power plants for which decommissioning, rather than retrofitting, will be a more cost-effective option. When evaluating whether to retrofit or decommission, utilities will need to take both unit and site-specific considerations into account. There will likely be significant variation in decision making regarding which practice to employ from utility to utility, causing further uncertainty with regard to reliability in the future. Additionally, utilities need only provide 90 days notice of their intent to retire certain generating units. Although historically utilities have provided more than 90 days notice, this circumstance may well change under the proposed rule, as utilities will have to make compliance decisions in a short time frame. Such shortened notice periods bear the risk of seriously endangering reliability throughout the region. [EPA-HQ-OAR-2009-0491-2855.1 p.8]
We are concerned that the rule, as proposed, will lead to a dangerously low level of adequate planning reserve margin, which endangers the provision of reliable power supply. The large scale of units that will be affected by the proposed rule, combined with the implementation time frame and the obvious need for capacity replacement leads the PUCO to believe that a longer time table for implementation of the Transport Rule is necessary, and well warranted. [EPA-HQ-OAR-2009-0491-2855.1 p.9]
State of Ohio Environmental Protection Agency (Ohio EPA)
Ohio EPA has concerns over the reliability of the electrical grid. U.S. EPA must provide an implementation schedule that is reasonably achievable without jeopardizing reliability of the electrical grid. [EPA-HQ-OAR-2009-0491-2793.2, p. 3]
Considering the deadlines imposed by this proposal and the need for a number of sources to rush to install controls in the specified time frame, reliability during the retrofit period will be a concern. Considering the time required for planning, procuring materials and installing controls, states could find themselves with significant generating capacity needing to go off line all at once. In totality, such an effort raises significant concerns regarding electrical reliability during this period. [EPA-HQ-OAR-2009-0491-2793.2, p. 3-4]
Response: 
These comments raise multiple concerns about how the rule will impact reliability of the generation system and the power grid as a result of retrofit requirement and potential retirements.  EPA does not agree that the concerns raised in these comments will result from the rule, and addresses the issues raised below.  For further information, see the Technical Support Document on Resource Adequacy and Reliability in this docket.
Retirements
EPA does not agree that retirements from the rule will cause reliability problems.  As stated in the preamble (VII.A) , EPA selected an interstate trading program structure in part because its market-based flexibility promotes the sector's capacity for providing electric reliability.  EPA believes that the level of potential retirements, projected to be approximately 4.8 GW in 2014 (see the RIA and IPM documentation in this docket) is well within the capability of utilities and regional organizations to manage effectively.  The IPM modeling for the rule takes into account both the required regional reserve margins and the limitations of firm power transfers between regions, so that the basic reliability requirements are already incorporated in the analysis of the impact of the rule.  Moreover, because the rule provides the flexibility to purchase allowances rather than retire, projected retirements under the rule are based on economic considerations rather than fixed deadlines or unit-specific compliance requirements.  Consequently, EPA anticipates that the Transport Rule will not affect the ability of regional grid management organizations and/or interconnected utilities to routinely manage any local grid issues that may arise. 
Retrofits
EPA does not agree that retrofits resulting from compliance with the rule will cause reliability problems.  EPA recognizes that an outage for the final tie-in of a retrofitted system to the existing system may be required, but believes that this installation can be managed through normal system planning without impairing system reliability, for several reasons.  First, many parts of the tie-in process can be completed during normally scheduled maintenance.  Second, the Transport Rule's interstate trading program structure provides additional flexibility for units  to coordinate the timing of retrofit installation schedules in order to promote system reliability.  In addition, EPA performed a sensitivity analysis of the IPM modeling for a "no-FGD" case (see preamble section VII.C) where additional post-combustion retrofits were disallowed by the 2014 timeframe.  This sensitivity analysis showed that compliance with the rule, with only moderate adjustments, could occur even if there were no additional post-combustion retrofits in the policy case compared to the base case.  As a result, EPA does not believe that any specific unit's retrofitting activity is necessary for states to meet their Transport Rule budgets (due to the rule's considerable flexibility), and therefore such retrofitting cannot logically pose an unresolvable concern for maintaining electric reliability.  For these reasons, EPA does not believe that potential retrofits arising from the rule will raise reliability concerns.
Coordination
The commenters also recommend that EPA coordinate with other agencies and groups, such as FERC, NERC and RTOs on reliability issues, EPA notes that each of the entities referenced have had the opportunity to submit comments on EPA rules in the record of this rule. EPA has been in contact with many of these groups during the development of this rule and expects to continue to engage proactively to promote planning for environmental compliance; however, these groups have not filed comments or expressed concerns over reliability in the record for this rule.
Other issues
Commenters also raise some general issues with respect to timing and feasibility as a contributing factor in reliability concerns.  EPA does not believe the general concerns are warranted.  Response to these issues can be found in the Section V.C.2 of this document on feasibility and compliance deadlines.
Organization: Kansas City Board of Public Utilities (BPU)
Comment: 
Kansas City Board of Public Utilities (BPU)
THE RULE FAILS TO CONSIDER GRID RELIABILITY AND THE BURDEN ON EXISTING TRANSMISSION  
The Rule demonstrates a misunderstanding about the potential effects that the proposed rule may have on the reliability of the regional electrical grid. The Rule postulates potential grid reliability problems in terms of the availability of electric generation: noting the preferred trading option 'gives ISOs (Independent System Operators) the flexibility to manage regional electricity generation so that reliability is maintained.' 75 FR at 4531511; see also id. at 45328/3 ('the ability to obtain additional or replacement supply from sources in another part of the state or from another state enhances electric reliability'). However, the availability of electric generation has not been the sticking point for reliability. See, e.g., New York v. FERC, 535 U.S.I, 7 (2002) ('since 1935, and especially beginning in the 1970's and 1980's, the number of electricity suppliers has increased dramatically. Technological advance have made it possible to generate electricity efficiently in different ways and in smaller plants.') (footnote omitted). Rather, reliability problems arise because grid transmission facilities are not always adequate to move electricity from where it is generated to where it is consumed. See id. at 9-10 (summarizing statutory and regulatory efforts to encourage increased access to transmission). [EPA-HQ-OAR-2009-0491-2740.1, p.17]  
Similarly, the Rule's view that ISOs 'manage regional electricity generation' (75 FR at 45315) overstates the case. ISOs neither control nor operate generation facilities, but, rather, control and operate transmission facilities only. See 16 U.S.C. § 8240(a)(6)('The term 'transmission organization' means... Independent System Operator... finally approved by the [FERC] for the operation of transmission facilities'); see, e.g., PUD No. 1 Snohomish County v. FERC, 272 F.3d 607, 611 n. 3 (D.C. Cir. 2001)('Independent system operators (ISOs), in contrast, are non-profit organizations that operate the transmission facilities that others own.'), 6 [EPA-HQ-OAR-2009-0491-2740.1, pp.17-18]  
These factors raise doubt the Rule's implicit assumption that the preferred trading program will not adversely affect grid reliability because adequate generation is available. 75 FR at 4531511. Even accepting that adequate generation is available, that, by itself, does not assure grid reliability now and could not be expected to do so after the rule is implemented, given that the preferred approach could easily increase potential transmission capacity constraints (congestion) that would impede the flow of electricity. In determining the potential impact of the proposed rule on grid reliability, EPA failed to consider the extra burden that the rule will place on existing transmission constraints or in creating new congestion points. Both situations present complex and costly issues related to assuring grid reliability. The failure to consider this central problem to the instant matter constitutes arbitrary and capricious decision-making. See, e.g., Motor Vehicle Mfrs. Ass'n v. State Farm Mut. Auto. Ins. Co., 463 U.S, 29,43 (I 983)('an agency rule would be arbitrary and capricious if the agency... entirely failed to consider an important aspect of the problem'). [EPA-HQ-OAR-2009-0491-2740.1, p.18]  
[See pp.18-20 of this comment for additional comments pertaining to The Rule Fails to Consider Grid Reliability and the Burden on Existing Transmission]  
For the reasons stated herein, BPU requests alternative modifications to the proposed Rule by:
5. taking into account the potential adverse effects of the proposed rules on transmission facilities and how that will impact grid reliability;  [EPA-HQ-OAR-2009-0491-2740.1, p.23]

6 To be sure, ISOs operate real time markets that provide balancing services to compensate for differences between projected and actual electric loads as well as offer continuous economic dispatch of resources to serve load. In both cases, however, the ISO relies on generation made available by third parties.  
Response: 
      EPA modeling with IPM considered the issues of regional resource adequacy and inter-regional transmission of power. EPA recognizes that local grid issues, such as shifts in congestion patterns and transmission impacts from the retirement of specific power plants, will need to be coordinated at the utility and regional levels as they routinely managed for all changes in the power sector. However, EPA also believes that there are sufficient provisions in the rule for flexible coordination with regional entities and among utilities to permit these local issues to be resolved in the normal course of business.
      IPM modeling considers regional resource adequacy based on current and projected NERC reserve margins, and considers transmission system limitations by placing limits on flows between regions and on the amount of capacity that can be transferred between regions to meet regional reserve margins. This modeling is conservative, in the sense that it considers only current transmission capacity between regions and does not consider ways in which the transmission grid may be improved in the future to allow for additional flexibility in dispatch to meet load. In other words, EPA's projections show cost-effective EGU emission reductions subject to regional limitations of the transmission grid as it exists today, and its projections are fully compatible with the power sector's ability to comply with the rule's emission reductions while successfully operating the grid.
Organization: Louisiana Energy and Power Authority (LEPA)
Comment: 
Louisiana Energy and Power Authority (LEPA)
LEPA strenuously objects to the January 2012 compliance deadline in the proposed rule. That deadline does not provide sufficient time to permit Louisiana to develop SIPs that would more appropriately consider and account for transmission constraints and reliability concerns in LEPA's service territory. [EPA-HQ-OAR-2009-0491-2700.1, p.3] [[This comment can also be found in Section VII.C.]]
The January 2012 compliance deadline also does not provide LEPA with sufficient time to secure and make capital investments necessary to comply with the proposed rule and reliably serve load if it does not receive its fair allocation of allowances. [EPA-HQ-OAR-2009-0491-2700.1, p.3]
If it receives or is unable to obtain sufficient allowances, LEPA's only options for compliance, other than curtailing power, would be either to pay Entergy or Cleco to upgrade their transmission lines or to invest in new generation construction within its control area. LEPA's past experience has proven that transmission upgrades would be very difficult to accomplish, could cost in excess of a hundred million dollars, and would likely take five to seven years to complete. LEPA would have no control over the upgrades. They would be subject to Entergy's and/or Cleco's approval and would be under their control. Necessary permits and rights-of-way would have to be obtained, which could take untold numbers of years. And there would be no guarantee the upgrades would improve transmission conditions for LEPA. The effect of transmission upgrades is uncertain, and, even if they are built, they may not alleviate transmission constraints as anticipated. LEPA's other option for compliance, building a new generator, would also cost millions and would take four to five years to complete. [EPA-HQ-OAR-2009-0491-2700.1, p.18]
Neither option could be completed by January 1, 2012. LEPA thus would experience disruptions in electric service in its control area for a minimum of three years under the proposed Transport Rule. This is an unacceptable result. The EPA should extend the deadline for compliance to a reasonable date that would allow LEPA a reasonable time to achieve compliance. [EPA-HQ-OAR-2009-0491-2700.1, p.18] 
Proposed Transport Rule § III(C)(2), 75 Fed. Reg. 45227. The proposed Transport Rule does not 'ensure a reliable power supply;' to the contrary, it threatens to cut off power to the constrained areas of South Louisiana and potentially to other transmission constrained areas in the United States. [EPA-HQ-OAR-2009-0491-2700.1, p.16]
Response: 
      As discussed in Section VII.C of the Preamble, EPA believes the 2012 deadline is feasible and will not result in any reliability issues. As noted in the preamble, there is a diverse set of readily attainable compliance options that can be undertaken by industry within the applicable compliance schedule. In addition, because the Transport Rule's interstate trading programs provide large, liquid markets for allowances, individual facilities may obtain allowances at any time from the market if necessary to cover their 2012 emissions.
Organization: Minnesota Power 
Comment: 
Minnesota Power 
Wind backup.  As the production of wind based generation increases in a region subject to renewables performance standards, there is an increasing need for backup resources like natural gas and coal based generation to provide reliability to the electric system when the wind is not blowing.  That sort of service can require that coal and natural gas units targeted for control under the proposed Transport Rule can fall short of budget allocations needed to preserve electric system reliability.  EPA should address the role of fossil fuels for supporting system reliability under wide scale deployment of renewables before they impose emission budgets that can impede local unit dispatch, prior to finalizing the Transport Rule. [EPA-HQ-OAR-2009-0491-2750.1, pp.9-10]  
Response: 
      The comments are mistaken in the assumption that the analysis does not take into account the need for dispatchable resource to back up wind development. The IPM model considers the need for backup in two primary ways. First, the percentage of wind generation is limited to 20 percent of load in each region, a generally conservative assumption of the maximum amount of wind that can be supported in a region without additional backup requirements. Second, the contribution of wind to capacity requirements in each region varies as a function of the type of wind resource and is designed to ensure that sufficient dispatchable capacity remains in the region to ensure reliable dispatch of the power system to meet projected loads. (For details of these parameters, see the IPM documentation in this docket.)
Organization: Morgan Stanly Capital Group
Comment: 
Morgan Stanly Capital Group
Forty years ago when the EPA made decisions regarding curtailing pollution, power plants were owned and operated primarily by integrated utilities. Wholesale power markets mostly amounted to occasional sales of "economy energy" between such utilities. Today, there is a thriving, diverse wholesale power market, a large independent power producer sector, and several multi-state ISOs that engage in optimizing cost and reliability decisions over large areas. For this reason, developing the optimum emissions control program is much more complicated than it has been at any time in the past. As it evaluates various options for achieving statutorily mandated emissions and ambient air quality standards, the EPA should consider the impact of the Proposed Rule on these sectors. Failure to take these impacts into account would likely result in significantly higher societal costs. These costs include less efficient generation dispatch, decreased electric system reliability, and reduced competition in the wholesale power markets. [EPA-HQ-OAR-2009-0491-2819.1 p.10]
The Federal Energy Regulatory Commission,29 the North American Electric Reliability Corporation,30 RTOs, and/or ISOs may proactively participate in this rulemaking and offer detailed analyses of such impacts. The Proposed Rule would impose significant constraints on the operation of RTOs and ISOs.31 By definition, additional constraints add costs, which will ultimately be borne by consumers. While it is clear that the EPA's primary responsibility is to ensure air quality standards, we encourage the EPA to do so in the least costly and disruptive manner possible. Therefore, if these entities do not participate in the rulemaking, we urge the EPA to reach out to them for expert advice on how various proposals would impact power markets. [EPA-HQ-OAR-2009-0491-2819.1 p.10]
Response: 
      EPA believes that the trading approach taken in the rule is consistent with the request in the comment to consider the impact on the wholesale power market in developing this rule.
      The commenters also recommend that EPA reach out to other agencies or groups for expert advice, specifically to FERC, NERC and RTOs on reliability issues. EPA notes that each the entities referenced have had the opportunity to submit comments on EPA rules in the record of this rule. EPA has been in contact with many of these groups during the development of this rule and expects to continue to engage proactively to promote planning for environmental compliance; however, these groups have not filed comments or expressed concerns over reliability in the record for this rule.
Organization: National Rural Electric Cooperative Association (NRECA)
Old Dominion Electric Cooperative
Comment: 
National Rural Electric Cooperative Association (NRECA)
The proposal encounters a similar problem regarding the presumption that dual fuel natural gas/oil turbines can utilize natural gas exclusively, even during the winter season when regional or local requirements may effectively prohibit natural gas use to generate electricity. EPA has not identified anywhere in the proposal how the additional natural gas and pipeline transportation needed to meet this presumption would be met, or how long constructing needed infrastructure is anticipated to take. [EPA-HQ-OAR-2009-0491-2723.1, p.6]
Old Dominion Electric Cooperative
As stated above ODEC owns and operates two simple cycle combustion turbine power stations that are dual fueled. The reason these stations are dual fuel is because natural gas becomes constrained during the winter months forcing the stations to use fuel oil for electric generation. This proposed rule assumes that dual fuel natural gas/oil turbines can utilize natural gas exclusively, even during the winter season when regional or local requirements may effectively prohibit natural gas use to generate electricity. Based upon information from EPA staff, ODEC understands that the IPM model is apparently not capable of modeling for dual fuel operation. However, there was no indication that an effort was made to adjust the model based upon actual operation. Further, EPA has not identified anywhere in the proposal (1) how their additional natural gas and pipeline transportation assumptions would be met, (2) the anticipated timeframe for construction of needed infrastructure, or (3) the increase in cost associated with the development of this infrastructure. [EPA-HQ-OAR-2009-0491-2877.1,p.4]
Response: 
Treatment of dual-fueled units
      In the IPM model, units are classified by whether they can burn only oil, only natural gas, or either oil or natural gas (dual-fired units). This classification is based on available historical information about each unit. The model dispatches units on an economic basis; dual fired units are permitted to burn natural gas during all time periods if it is economic to do so. This is a necessary modeling simplification; however, the model does incorporate a detailed natural gas pipeline representation where the cost of natural gas transportation to the unit includes any infrastructure upgrades that are needed if there are constraints in the pipeline system from increased use of natural gas.
      There are several reasons why these modeling simplifications do not affect the conclusions of the impact analysis with respect to reliability. First, dual fired units are not prohibited from using oil under the policy if, for example, natural gas is not available during those limited times when natural gas supply may be constrained in the winter. Second, the IPM modeling does not project additional closures of oil/gas steam plants from the policy, so that oil/gas steam units available under the base case are expected to remain in service under the policy and be available capacity for reliability purposes. For these reasons, EPA does not expect reliability problems related to the modeling of oil/gas unit operations under the Transport Rule.
       Natural Gas Infrastructure
      EPA disagrees with comments that maintain the analysis of the rule did not include costs associated with the development of natural gas infrastructure needed to serve any additional natural gas consumption that arises from the policy. IPM incorporates a detailed natural gas pipeline representation as well as a representation of natural gas resources and reserve development (see IPM documentation in this docket). The cost of natural gas delivered to a power plant includes both the cost of delivery from current infrastructure as well as the cost of any additional natural gas infrastructure needed to develop new reserves or construct new pipeline capacity to deliver increased flows of natural gas to power plants.
Organization: New Orleans City Council
Comment: 
New Orleans City Council
New Orleans is located in the Amite South planning region of the Entergy System behind a significant transmission constraint. This constraint is so severe that in early September 2008, Hurricanes Gustav and Ike highlighted the vulnerability of New Orleans to being cut off electrically from the rest of the electrical power grid -- the hurricanes severed the only major transmission pathway into New Orleans and New Orleans essentially became an electrical island unable to import or export power from anywhere else in the nation. Even when operating at full capacity, the transmission pathway into New Orleans does not allow enough power to be transmitted to offset uneconomic units in the Amite South planning region. [EPA-HQ-OAR-2009-0491-2719.1 p.3]
This severe transmission constraint requires the Entergy System to operate units at ENO's Michoud facility to provide load-following capability and voltage support -- regardless of whether or not it is economic to run those units. Michoud is a reliability-must-run facility. If the modeling system used to allocate emissions credits assumes that Michoud will not be run because it is uneconomic to do so, it will not reflect the reality of the operation of the Entergy System, and will unduly penalize New Orleans retail electricity customers. Any system for the allocation of emissions allowances adopted by the Agency must take into account the necessity of running units for load-following capability and voltage support. Such units cannot be ramped down -- the electrical system would collapse and blackouts would occur. Under regulatory ratemaking principles, costs associated with complying with federal regulations such as emissions regulations are generally allowed to be recovered from consumers by the utilities, so in most instances it will be the retail ratepayers who bear the burdens of increased compliance costs, not the utility. If allowances are not allocated to reliability-must-run units, such as Michoud, the Council is concerned that the utility will incur and pass on to its retail customers the substantial cost of bringing such units into compliance. This result would be highly detrimental to New Orleans ratepayers, many of whom are already facing significant financial hardship. [EPA-HQ-OAR-2009-0491-2719.1 p.4]
WHEREFORE, the Council respectfully requests that the Agency consider the comments set forth above and make the adjustments to the proposed rule necessary to minimize costs to ratepayers and to reflect the existence of transmission constraints in the allocation of emissions allowances. [EPA-HQ-OAR-2009-0491-2719.1 p.5]
Response: 
These comments assume the use of modeling projections for allocation of allowances.  In the final rule, EPA is basing allocations on historical data, so these comments no longer apply.
 To the extent that these concerns go beyond the issue of allocations, EPA believes that the flexibility inherent in the trading systems adopted in this rule permits dispatch of units where needed for reliability.  As discussed in the Preamble (Section XII.C) there are multiple compliance options that can be employed where needed to permit individual units to remain in service and comply with the rule while longer-term upgrades (such as transmission system modifications) are completed.  Because the Transport Rule's interstate trading programs provide large, liquid markets for allowances, individual facilities may obtain allowances at any time from the market to cover their emissions. 
Organization: State of Louisiana, Department of Environmental Quality
Comment: 
State of Louisiana, Department of Environmental Quality
Comment: EPA proposed compliance deadlines and schedules are inappropriate and unfeasible in light of electrical generation and transmission system constraints. Again, EPA should gather additional real-world information regarding must-run units and local grid constraints to update the expected conditions before finalizing this rule. [EPA-HQ-OAR-2009-0491-2655.1, p.5]
Response: 
      To the extent that these concerns go beyond the issue of allocations, EPA believes that the flexibility inherent in the trading systems adopted in this rule permits dispatch of units where needed for reliability. As discussed in the Preamble (Section XII.C) there are multiple compliance options that can be employed where needed to permit individual units to remain in service and comply with the rule while longer-term upgrades (such as transmission system modifications) are completed. Because the Transport Rule's interstate trading programs provide large, liquid markets for allowances, individual facilities may obtain allowances at any time from the market to cover their emissions.
Organization: U.S. Congressman Pete Hoekstra
Comment: 
U.S. Congressman Pete Hoekstra
It is my understanding that the proposal may negatively impact the reliability and diversity of public power entities and their ability to contribute to the national electric system and their local communities. [EPA-HQ-OAR-2009-0491-3662, p.1]
Response: 
EPA does not believe that the rule will harm reliability of the power system, and consequently will not diminish the ability of public power entities to reliably serve their local communities.  As stated in the preamble (VII.A) , EPA selected an interstate trading program structure in part because its market-based flexibility promotes the sector's capacity for providing electric reliability.  EPA believes that the level of potential retirements, projected to be approximately 4.8 GW in 2014 (see the RIA and IPM documentation in this docket) is well within the capability of utilities and regional organizations to manage effectively.  The IPM modeling for the rule takes into account both the required regional reserve margins and the limitations of firm power transfers between regions, so that the basic reliability requirements are already incorporated in the analysis of the impact of the rule.  Moreover, because the rule provides the flexibility to purchase allowances rather than retire, projected retirements under the rule are based on economic considerations rather than fixed deadlines or unit-specific compliance requirements.  Consequently, EPA anticipates that the Transport Rule will not affect the ability of regional grid management organizations and/or interconnected utilities to routinely manage any local grid issues that may arise.  For further information, see the Technical Support Document on Resource Adequacy and Reliability in this docket.
Organization: we energies
Comment: 
we energies
If retained as proposed, the 2012 deadline could pose a potential threat to electrical system reliability. We Energies service area in Michigan's Upper Peninsula has transmission system constraints, and unit outages at We Energies Presque Isle facility are limited to one planned unit outage at a time in order to avoid threats to system voltage and stability. [EPA-HQ-OAR-2009-0491-2629.1,p.6]
Response: 
      As discussed in Section VII.C of the Preamble, EPA believes the 2012 deadline is feasible and will not result in any reliability issues. As noted in the preamble, there is a diverse set of readily attainable compliance options that can be undertaken by industry within the applicable compliance schedule. In addition, because the Transport Rule's interstate trading programs provide large, liquid markets for allowances, individual facilities may obtain allowances at any time from the market if necessary to cover their 2012 emissions. 
      EPA believes that the flexibility inherent in the trading systems adopted in this rule permits dispatch of units where needed for reliability. As discussed in the Preamble (Section XII.C) there are multiple compliance options that can be employed where needed to permit individual units to remain in service and comply with the rule while longer-term upgrades (such as transmission system modifications) are completed. Because the Transport Rule's interstate trading programs provide large, liquid markets for allowances, individual facilities may obtain allowances at any time from the market to cover their emissions.
Organization: Westar Energy, Inc.
Comment: 
Westar Energy, Inc.
THE RULE FAILS TO CONSIDER GRID RELIABILITY AND THE BURDEN ON EXISTING TRANSMISSION [EPA-HQ-OAR-2009-0491-2757.1, p.18]
The Rule demonstrates a misunderstanding about the potential effects that the proposed rule may have on grid reliability. The Rule postulates potential grid reliability problems in terms of the availability of electric generation: noting the preferred trading option 'gives ISOs (Independent System Operators) the flexibility to manage regional electricity generation so that reliability is maintained.' 75 FR at 45315/1; see also id. at 45328/3 ('the ability to obtain additional or replacement supply from sources in another part of the state or from another state enhances electric reliability'). But that tells only half the story, and not the more important part; the availability of electric generation has not been the sticking point for reliability. See, e.g., New York v. FERC, 535 U.S. 1, 7 (2002) ('since 1935, and especially beginning in the 1970's and 1980's, the number of electricity suppliers has increased dramatically. Technological advances have made it possible to generate electricity efficiently in different ways and in smaller plants.')(footnote omitted). Rather, reliability problems arise because grid transmission facilities are not always adequate to move electricity from where it is generated to where it is consumed. See id. at 9-10 (summarizing statutory and regulatory efforts to encourage increased access to transmission). [EPA-HQ-OAR-2009-0491-2757.1, p.18]
Similarly, the Rule's view that ISOs 'manage regional electricity generation' (75 FR at 45315) overstates the case. ISOs neither control nor operate generation facilities, but, rather, control and operate transmission facilities. See 16 U.S.C. § 8240(a)(6)('The term 'transmission organization' means ... Independent System Operator ... finally approved by the [FERC] for the operation of transmission facilities'); see, e.g., PUD No.1 Snohomish County v. FERC, 272 F.3d 607, 611 n. 3 (D.C. Cir. 2001)('Independent system operators (1S0s), in contrast, are nonprofit organizations that operate the transmission facilities that others own.'). 6 [EPA-HQ-OAR-2009-0491-2757.1, pp.18-19]
These factors raise doubt concerning the Rule's implicit assumption that the preferred trading program will not adversely affect grid reliability because adequate generation is available. 75 FR at 45315/1. Even accepting that adequate generation is available, that, by itself, does not assure grid reliability now and could not be expected to do so after the rule is implemented, given that the preferred approach could easily increase potential transmission capacity constraints (congestion) that would impede the flow of electricity. In determining the potential impact of the proposed rule on grid reliability, EPA failed to consider the extra burden that the rule will place on existing transmission constraints or in creating new congestion points. Both situations present complex and costly issues related to assuring grid reliability. The failure to consider this central problem to the instant matter constitutes arbitrary and capricious decision making. See, e.g., Motor Vehicle Mfrs. Ass 'n v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983)('an agency rule would be arbitrary and capricious if the agency ... entirely failed to consider an important aspect of the problem'). [EPA-HQ-OAR-2009-0491-2757.1, p.19]
[See EPA-HQ-OAR-2009-0491-2757.1, pp.19-22 for additional comments pertaining to THE RULE FAILS TO CONSIDER GRID RELIABILITY AND THE BURDEN ON EXISTING TRANSMISSION]

6 To be sure, ISOs operate real time markets that provide balancing services to compensate for differences between projected and actual electric loads as well as offer continuous economic dispatch of resources to serve load. In both cases, however, the ISO relies on generation made available by third parties.
Response: 
      EPA does not agree that the rule impairs grid reliability and believes it has considered the burden of the rule on existing transmission.  EPA modeling with IPM considered the issues of regional resource adequacy and inter-regional transmission of power. EPA recognizes that local grid issues, such as shifts in congestion patterns and transmission impacts from the retirement of specific power plants, will need to be coordinated at the utility and regional levels as they routinely managed for all changes in the power sector. However, EPA also believes that there are sufficient provisions in the rule for flexible coordination with regional entities and among utilities to permit these local issues to be resolved in the normal course of business.
      IPM modeling considers regional resource adequacy based on current and projected NERC reserve margins, and considers transmission system limitations by placing limits on flows between regions and on the amount of capacity that can be transferred between regions to meet regional reserve margins. This modeling is conservative, in the sense that it considers only current transmission capacity between regions and does not consider ways in which the transmission grid may be improved in the future to allow for additional flexibility in dispatch to meet load. In other words, EPA's projections show cost-effective EGU emission reductions subject to regional limitations of the transmission grid as it exists today, and its projections are fully compatible with the power sector's ability to comply with the rule's emission reductions while successfully operating the grid.

V.D.2.h. How Proposed Remedy is Consistent With Court's Opinions

Organization: Capital Power Corporation
Comment: 
Capital Power Corporation
We commend EPA for responding largely to the court decision remanding the Clean Air Interstate Rule (CAIR). The limitations on interstate trading in the proposed rulemaking, while potentially creating issues regarding market liquidity, respond to the court's opinion that unlimited interstate trading cannot guarantee the necessary reductions in all the upwind states. [EPA-HQ-OAR-2009-0491-2753.1, p.2]
Response: 
EPA agrees that the remedy in the final rule is consistent with and responds to the decision of the D.C. Circuit in the North Carolina case.
Organization: Class of '85 Regulatory Group
Comment: 
Class of '85 Regulatory Group
The Preferred Option is Consistent with North Carolina v. EPA. In North Carolina v. EPA, the Court of Appeals for the District of Columbia Circuit ('D.C. Circuit') found CAIR unlawful and identified problems with CAIR's methodology for measuring and addressing each state's significant contribution to downwind nonattainment, as well as problems with certain aspects of CAIR's emissions trading programs. The preferred option addresses both of these concerns and is consistent with the court's remand of CAIR. [EPA-HQ-OAR-2009-0491-2854.1,p.4]
The Preferred Option relies on a state-specific methodology for identifying significant contribution to nonattainment and interference with maintenance. This methodology incorporates both air quality modeling and cost considerations to identify the portion of a state's contribution that is significant or that interferes with maintenance. The preferred option then eliminates this contribution by imposing annual state and unit-specific emissions budgets based directly on EPA's quantification of each individual state's significant contribution and interference with maintenance. In contrast to CAIR, in which 'EPA's apportionment decisions have nothing to do with each state's significant contribution, emission budgets and allowance allocations under EPA's preferred option are directly linked to in-state emissions and required reductions to those emissions. This methodology addresses the court's concern-and the CAA's mandate-that emissions reductions occur 'within the State.' The Class of '85 supports EPA's methodological approach defining 'significant contribution' on a state-by-state basis, and EPA's consideration of both air quality and cost factors in that analysis. [EPA-HQ-OAR-2009-0491-2854.1,p.4]
The limited interstate trading and variability provisions of the preferred option are consistent with the D.C. Circuit's opinion in North Carolina. Because CAIR based its allocations on the Acid Rain program (as opposed to required or quantified in-state emissions reductions targets) and allowed unlimited interstate trading, there was little assurance that required emissions reductions would occur in a given state. As a result, CAIR could not satisfy the CAA's mandate to address significant contribution by upwind states. As discussed, the preferred option solves this problem by setting state-specific emissions budgets that are directly tied to that state's 'significant contribution' and allocating allowances based on those budgets. At the same time, and in recognition of the inherent variability in both baseline emissions and year-to-year fluctuations in electricity demand, the preferred option provides for a modest 10 percent variability of emissions budgets in any given year, at both the state and unit level. To constrain variability further and assure that emissions reductions occur in-state, the preferred options' assurance provision imposes a rolling three-year variability limit at the state level, which effectively limits the total potential variability to 5.8 percent. The preferred option's interstate trading mechanism is a necessary component of the variability provision because interstate trading allows allowances to move from areas of low demand to areas of high demand in a given year (within the 10 and 5.8 percent variability limits), creating a viable emissions allowance market. [EPA-HQ-OAR-2009-0491-2854.1, p.4]
When remanding CAIR, the D.C. Circuit in North Carolina did not prohibit interstate trading or even suggest that all interstate trading was impermissible. Instead, the court expressed concern that unfettered trading, combined with an impermissible allocation scheme, would not assure that emissions reductions took place in specific upwind states. In defining EPA's obligations on remand, the court wrote that 'CAIR must include some assurance that it achieves something measurable towards the goal of prohibiting sources 'within the State' from contributing to nonattainment or interfering with maintenance in 'any other State. ', The preferred option is more than 'something measurable.' It is a quantifiable emissions reduction program based on state-specific emissions budgets and unit-specific allocations based on those budgets. The modest and well-constrained variability provisions contained in the preferred option assure long-term compliance with these budgets while smoothing out small year-to-year changes in electricity demand in a cost-effective manner. [EPA-HQ-OAR-2009-0491-2854.1, p.5]
Without variability provisions (and the interstate trading necessary to make them work), sources would face penalties for meeting an unexpected increase in demand caused by an unpredictable weather or economic events. The alternative is to not meet that demand, resulting in blackouts, brownouts, and a corresponding economic impact. A penalty would be neither cost-effective nor helpful from an environmental perspective, because it would do nothing to actually constrain emissions (most EGUs and all regulated public utilities cannot simply 'shut down' to avoid exceeding emissions budgets in a high-demand year). In contrast, the preferred option's variability provisions would allow sources to meet an unexpected increase in annual demand (which would cause a corresponding emissions increase) by purchasing and removing allowances from a lower-demand area. Not only is a variability provision more cost-effective and better aligned with reality, it actually assures a better overall environmental result because emissions allowances from low-demand areas are removed from the market, reducing overall emissions. [EPA-HQ-OAR-2009-0491-2854.1,p.5]
The variability provision in the preferred option was carefully designed to limit any annual variance to 10 percent and to constrain long-term use of variability provisions (by imposing a three-year variability limit on states). Under the preferred option, interstate trading can occur only within the constraints of the variability limits. Allowance surrender requirements would enforce variability limits while also helping to assure future emissions reductions by removing allowances from the market. As EPA explains, this 'approach takes into account the inherent variability of the baseline emissions without excusing any state from eliminating its significant contribution.' Accordingly, the preferred option is consistent with North Carolina and 'achieves something measurable' toward reducing significant contribution by upwind states. [EPA-HQ-OAR-2009-0491-2854.1,p.5]
Response: 
EPA agrees that the remedy in the final Transport Rule, which is based on the preferred option in the proposal, is consistent with the opinion of the D.C. Circuit opinion in North Carolina v. EPA.  EPA does, as the commenter suggest, define significant contribution to nonattainment on a state specific basis, considering both cost and air quality factors in that analysis.  In addition, EPA agrees that the D.C. Circuit did not hold that all interstate trading was impermissible.  The remedy utilized in the final transport rule was crafted to respond to the opinion in North Carolina while still providing regulated sources with flexible compliance options.
Organization: New York University School of Law, Institute for Policy Integrity
Comment: 
New York University School of Law, Institute for Policy Integrity
The preferred approach's overall structure should satisfy the D.C. Circuit requirement that the EPA "include some assurance that it achieves something measurable towards the goal of prohibiting sources `within the State' from contributing to nonattainment or interfering with maintenance in `any other State.'" But a clearer definition of "significant contribution" and some programmatic modifications would help EPA hew even more closely to the court's interpretation of statutory language, even while improving the rule's efficiency and predictability. [EPA-HQ-OAR-2009-0491-2691.1, p.5]
Response: 
EPA agrees that the final Transport Rule is consistent with the D.C. Circuit opinion in North Carolina v. EPA.  The rule clearly defines and quantifies emissions in each state that signmissions that must be prohibited because they have been found to significantly contribute to nonattainment or interfere with maintenance in another state.
Organization: Pennsylvania Department of Environmental Protection
Comment: 
Pennsylvania Department of Environmental Protection
In North Carolina v. EPA, the Court held that EPA gave no 'independent significance' to the 'interfere with maintenance' prong of Section 110(a)(2 )(D)( i)(I) to separately identify upwind sources interfering with downwind maintenance. EPA must ensure that the two components-- year to year variability in emissions and air quality and continued maintenance of air quality standard over time, comport with Section 110(a)(D)(i)(I) of the CAA. The final TR must also ensure that the reductions achieved under SIP-approved programs for the CAIR continue in effect-failure to do so would be contrary to the anti-backsliding provisions of the CAA. [EPA-HQ-OAR-2009-0491-2660.1 p. 4]
Response: 
As explained in the preamble, the analysis for the Transport Rule gives independent significance to the interfere with maintenance prong of section 110(a)(2)(D)(i)(I), and is consistent with the statutory mandate of that section as interpreted by the D.C. Circuit.  EPA does not agree, however, with the commenters' suggestion that the anti-backsliding provisions of the CAA require certain CAIR requirements to remain in effect.  The D.C. Circuit found CAIR to be unlawful and EPA promulgated the Transport Rule to replace CAIR.  EPA believes it would be inconsistent with the opinion of the Court in North Carolina, to require all states to continue meeting emission budgets established in CAIR, budgets the D.C. Circuit found to be unrelated to the statutory mandate of section 110(a)(2)(D)(i)(I)

V.D.2.i. Other Comments on State Budgets/Limited Trading Proposed Remedy

Organization: Constellation Energy
Comment: 
Constellation Energy
Constellation Energy acknowledges EPA's exemplary efforts in this difficult task, and enthusiastically supports EPA's Preferred Option. The Preferred Option continues the efficient market based system successfully employed in the Acid Rain control program and the Clean Air Interstate Rule with improvements to address the concerns of the U.S. Court of Appeals for the D.C. Circuit related to the Clean Air Interstate Rule. Implementation of the Preferred Option will lead to a reduction in emissions within the 31-state area that is subject to the Transport Rule. The emission caps are tight enough to ensure reductions throughout the region. Moreover, the compliance assurance provisions ensure that trading does not undermine local emission concerns. [EPA-HQ-OAR-2009-0491-3613,p.2]
Response: 
EPA appreciates Constellation's support.
Organization: Maryland Department of Environment (MDE)
Comment: 
Maryland Department of Environment (MDE)
Also, while there are aspects of EPA's preferred State Budgets/Limited Trading proposed remedy option that we like and support, we offer improvements to that option. Please see Appendix D: OTC-LADCO Recommendations to EPA Regarding the CAIR Replacement Rule, dated September 2, 2009, and Appendix E: OTC Additional Recommendations to EPA on the CAIR Replacement Rule, dated September 10, 2009. [See EPA-HQ-OAR-2009-0491-2639.2, p.35 for comments pertaining to Appendix D and p.42 for comments pertaining to Appendix E; EPA-HQ-OAR-2009-0491-2639.2, p.14]
Response: 
See Preamble Section VIIA
Organization: National Rural Electric Cooperative Association (NRECA)
Comment: 
National Rural Electric Cooperative Association (NRECA)
NRECA has traditionally supported allowance trading as a preferred means of achieving a given emissions reduction goal because practical economics demonstrates emissions trading reduces overall compliance costs. A primary goal of NRECA and its electric cooperative membership is the support of policies that keep electric cooperative consumer rates affordable. [EPA-HQ-OAR-2009-0491-2723.1, p.4]
Response: 
EPA appreciates your support and agrees with your goals.
Organization: Ozone Transport Commission (OTC)
Comment: 
Ozone Transport Commission (OTC)
Transition to Performance Standards
In OTC's supplemental letter to EPA the OTC states requested that EPA work with the states to develop and phase in unit-specific performance standards that owners of fossil fuel-fired units should comply with between 2017 and 2025, or earlier if EPA's technical analysis demonstrates that an earlier date is reasonable. We further recommended that the performance standards should be developed on a 1-hour to 24-hour time period in conformance with the appropriate NAAQS, and should either be output-based or transition to output-based standards to reward efficiency. Such performance standards will give greater regulatory certainty to EGU owners and encourage transformational change in the energy market. We also provided the following specifics regarding the development of performance standards for EGUs:
 :: EPA should consider fuels, types and sizes of EGUs, the timing of other requirements included in this and the September 2, 2009 letter, cost-effectiveness and the pollution control equipment already in place on the existing fleet of EGUs;
 :: EPA should phase in the performance standards to maximize efficiency and minimize costs to affected sources, for example: o The performance standards for coal-fired units greater than 100 MW should be coordinated with the state-by-state caps; and o The performance standards for units subject to the upcoming federal MACT requirements should be coordinated with the MACT requirements;
 :: In later phases (2020 to 2025), the performance standards should be coordinated with greenhouse gas reduction programs and other energy efficiency initiatives and be output-based; :: OTC's analysis (see the Technical Support Document included as part of Appendix 6) shows that performance standards on larger fossil-fuel fired EGUs (based on a 30-day rolling average) are feasible and should be implemented on an aggressive timeframe (as early as 2017); :: EPA should consider including incentives (e.g., alternative compliance schedules not to exceed three years), to promote the repowering or replacement of existing units; and :: After the adoption and implementation of performance standards, EPA should evaluate the feasibility of eliminating the state-by-state caps.
We highly recommend that EPA take the opportunity to include the transition to performance based standards in the final Transport Rule, and strongly recommend it be included in Transport 2.
Response: 
EPA appreciates the comments and input from OTC throughout the regulatory process.  Several of the comments go beyond the scope of this rule, which proposed to regulate emissions of SO2 and NOx from fossil-fuel-fired power plants in the eastern part of the US, and replaces the court-remanded CAIR rule.  As described in section VI of the proposal preamble (75 FR 45341) EPA engaged stakeholders early and often in the development of the Transport Rule, weighing suggestions, ideas, and approaches seriously for their technical, administrative, and legal merit.  While not all of the OTC's ideas are reflected in the rule, many are.  For the Transport Rule, EPA did not propose output-based standards because of the difficulty at this time of the availability of the necessary data to implement such an approach.  However, this idea is of interest and relevance and will continue to be considered in the future. For the Transport Rule, EPA tried to design a program that is fuel- and control-neutral in order not to disadvantage any class of EGUs.  As emission reductions become stricter and controls on uncontrolled units become necessary, EPA believes that market economics will put pressure on older, less efficient plants.  For the Transport Rule, EPA did not proposed performance standards for the preferred approach because we felt that our approach delivered the necessary reductions to address the statutory mandate under CAA section 110(a)(2)(D)(i)(I) efficiently and cost-effectively. The OTC's forward looking comments in the timeframe beyond 2016 concerning greenhouse gas programs and other energy efficiency initiatives, as well as comments related to the MACT standards, are beyond the scope of this rule.
Organization: we energies
Comment: 
we energies
Interstate trading and allowance banking are critical rule provisions and must be fully available to provide compliance flexibility. As proposed, the rule does not adequately define how the implementation of interstate trading would occur, and we request additional specificity on the mechanics of interstate trading.  [EPA-HQ-OAR-2009-0491-2629.1, p.7]
We also request that EPA provide an option for utilities that have generation facilities in multiple states. EPA could allow for utilities to request EPA approval of a utility-specific emission averaging plan that would allow for interstate "trading" across units included in the utility's generation fleet located in multiple states. EPA could use the underlying CAMX analysis supporting the rule in order to confirm that the "trading" does not negatively impact transport and downwind attainment. This is consistent with the transport and attainment objectives of the transport rule, and would allow additional compliance flexibility for utilities with generation facilities in multiple states.  [EPA-HQ-OAR-2009-0491-2629.1,p.7]
We Energies would benefit from this additional flexibility by being able to make additional reductions at our facilities in southeastern Wisconsin to supplement reductions made at our facilities in Michigan's Upper Peninsula. This type of compliance plan is consistent with regional air quality goals, and would both lessen compliance costs and address potential reliability issues in our transmission constrained northern service territory. [EPA-HQ-OAR-2009-0491-2629.1, p.7]
Response: 
EPA appreciates WE Energies comments.  In the preamble to the final rule (see Section VII.A), EPA explains that 4 trading programs will be established.  Specifically, SO2 states are in either group 1 or group 2.  Group 1 states need to make larger reductions to eliminate their significant contribution.  A source in a group 1 state can only use SO2 allowances allocated to group 1 states for compliance with the SO2 trading program.  A source in a group 2 state can only use SO2 allowances allocated to group 2 states for compliance with the SO2 trading program.  For compliance in the annual NOx and ozone-season NOx trading programs respectively, sources may use annual NOx and ozone-season allowances allocated for any state, even if that state is in a different group for SO2 than the source's state.  Banking is the same as in the Title IV program.  Allowances may be banked (saved) and do not expire.  While EPA understands how your proposed averaging plan could offer additional flexibility, we have not included it in the final rule due to the prescriptions in the 2008 court decisions requiring emissions reductions necessary to eliminate significant contribution and interference with maintenance occur in the state linked to downwind impacts.

V.D.3. State Budgets/Intrastate Trading Remedy Option

Organization: Adirondack Mountain Club
Comment: 
Adirondack Mountain Club
EPA's preferred alternative, which would allow for interstate trading among power plants, does not address the New York's problem with pollution hotspots. EPA acknowledges in this rulemaking that particular plants have very significant affects on very specific downwind regions. The preferred alternative, along with the first alternative to allow for unlimited trading within States and no interstate trading, do not address the regional pollution problems associated with upwind polluters. [EPA-HQ-OAR-2009-0491-2761, p.2]
Response: 
EPA is finalizing the air quality-assured trading remedy, not the alternative intrastate trading remedy.  The final remedy has been designed to ensure that all significant contribution and interference with maintenance from upwind states is eliminated in downwind states as required by CAA section (110)(a)(2)(D).  For more details on EPA's decision to finalize the air quality-assured trading remedy, see section VII.A of the preamble.
Organization: Clean Air Council
Comment: 
Clean Air Council
In testimony, the Council viewed favorably EPA's effort to limit interstate trading of emission allowances under the Transport Rule. EPA has sought comment upon three possible approaches to trading, with a preference for limited interstate trading. Although the Council respects the Agency's inclination in this regard, our preference would be to see the 'first alternative' employed, which would limit trading to power plants only within the same state. Too many power plants in Pennsylvania have avoided serious investment in pollution controls by buying allowances from other plants. As a result, some Commonwealth residents have not seen the improvements in air quality that should be their due. As the availability of allowances tightens up, the ability of old dirty units to continue to play this game should diminish. However, if access to a 31-state market is afforded by the Transport Rule, a lack of pollution control modernization at some power plants may plague communities in Pennsylvania for years to come. [EPA-HQ-OAR-2009-0491-2804.1, p.2]
Response: 
EPA is finalizing the air quality-assured trading remedy, not the alternative intrastate trading remedy.  The final remedy has been designed to ensure that all significant contribution to nonattainment and interference with maintenance from upwind states is eliminated in downwind states as required by CAA section (110)(a)(2)(D).  For more details on EPA's decision to finalize the air quality-assured trading remedy, see section VII.A of the preamble.  For more details on the air quality and human health benefits, see sections VI.C and VII.C of the preamble.
Organization: Clean Energy Group
Comment: 
Clean Energy Group
The Clean Energy Group Does Not Support Alternative 1 or Alternative 2
The first alternative approach proposed in the Transport Rule would use state-specific control budgets and allow intrastate trading of emissions allowances allocated to EGUs, but it would not allow interstate trading. The second alternative would be a direct control program and also would prohibit trading. Both options would be inefficient, more costly, and would unnecessarily limit the flexibility of interstate trading available under the preferred option. The preferred approach is structured to allow maximum trading while also addressing the court's concerns. We would strongly oppose any alternative that does not include an interstate trading component. [EPA-HQ-OAR-2009-0491-2702.1, p. 10] [This comment can also be found at Section V.D.5 of this comment summary.]
Response: 
EPA is finalizing the air quality-assured trading remedy, not the alternative intrastate trading remedy.  The final remedy has been designed to ensure that all significant contribution to nonattainment and interference with maintenance from upwind states is eliminated in downwind states as required by CAA section (110)(a)(2)(D).  For more details on EPA's decision to finalize the air quality-assured trading remedy, see section VII.A of the preamble.
Organization: Maryland Department of Environment (MDE)
Florida Electric Power Coordinating Group, Inc. (FCG)
Dynegy, Inc.
Michigan Department of Natural Resources and Environment
First Energy
Comment: 
Dynegy, Inc.
In the event EPA does not defer the effective date of the Transport Rule until 30-36 months after promulgation, Dynegy strongly supports EPA's proposal for unlimited intrastate trading and no variability limits prior to 2014. Such compliance flexibility will be essential for effective transition to the Transport Rule program. [EPA-HQ-OAR-2009-0491-2698.1,p.8]
First Energy
Intra-State Trading Alternative
FE does not support EPA's proposal to limit or potentially eliminate interstate trading in the proposed CATR rule. Interstate emissions trading was one of the hallmark successes of the Acid Rain program, providing sources cost-effective options that led to an extremely successful program. Arbitrarily limiting trading based on state boundary lines will significantly increase the cost of compliance of the proposed CATR rule. [EPA-HQ-OAR-2009-0491-2657.1,pp.13-14]
Florida Electric Power Coordinating Group, Inc. (FCG)
Regarding the state budgets/intrastate trading option, the FCG agrees with EPA that this approach is more problematic and costly than the preferred option. EPA notes in the proposed rule that this option would be 'more resource intensive, more complex, less flexible, and potentially more susceptible to market manipulation' than the other two options. EPA states that the additional resources and administrative burden would be required due to the 82 new trading programs (28 for annual NOx, 26 for ozone season NOx, and 28 for S02) that would result from the Intrastate Trading method. According to the proposed rule this option would provide less flexibility to ensure electric reliability than the preferred method, and according to the Regulatory Impact Analysis this option would result in greater private costs to the power sector and greater social costs for consumers than the preferred method. Due to the increased resources and costs and to the decreased flexibility, the FCG supports the preferred remedy over the intrastate trading option. [EPA-HQ-OAR-2009-0491-2658.1,pp.11-12]
Maryland Department of Environment (MDE)
In the State Budgets/Intrastate Trading Remedy Option there is no variability included. That fact is the only part of this option that is appealing. On the other hand, this option would result in 82 trading programs being created. Allowance banking would be permitted and some allowances would be withheld from larger generators for use in an annual auction. Overall this option is quite unwieldy, especially from a compliance perspective, due to the large number of trading programs that would need to be administered. Maryland does not believe that EPA has the resources to manage such a large trading program effectively. [EPA-HQ-OAR-2009-0491-2639.2, p.15]
Michigan Department of Natural Resources and Environment
An alternative compliance option that would use state-specific emissions budgets and allow for intrastate trading but prohibit interstate trading is included in the proposal. The DNRE disagrees with this alternative because it limits the ability of the subject sources to participate in a robust trading program and recoup some of their costs from implementing various control options. [EPA-HQ-OAR-2009-0491-2774.1 p.5]
Response: 
EPA is finalizing the air quality-assured trading remedy, not the alternative intrastate trading remedy.  The final remedy has been designed to ensure that all significant contribution and interference with maintenance from upwind states is eliminated in downwind states as required by CAA section (110)(a)(2)(D).  For more details on EPA's decision to finalize the air quality-assured trading remedy, see section VII.A of the preamble.
Organization: New York State Department of Environmental Conservation
Comment: 
New York State Department of Environmental Conservation
While the Department supports the preferred option that provides for limited inter-state trading, EPA's analysis of the intra-state trading option did not include New York State's successful Acid Deposition Reduction Program (ADRP). The ADRP was a NOx and SO2 cap and trade program for EGUs of 25 megawatts and greater, which is nearly identical to the alternative program being proposed. To be complete, EPA should include the ADRP in its analysis.  [EPA-HQ-OAR-2009-0491-2730.1, p.6]
Response: 
EPA is finalizing the air quality-assured trading remedy-- similar to the preferred remedy in the proposal with some modifications.  As such, EPA did not conduct additional analysis on the alternative intrastate trading remedy option.  This comment does not provide information about the ADRP program and what type or how additional analysis would benefit the final rule.
Organization: New York University School of Law, Institute for Policy Integrity
Comment: 
New York University School of Law, Institute for Policy Integrity
The first alternative approach does not create specific variability ranges or permit interstate trading, though it would permit unlimited intrastate trading.  This approach also would permit allowance banking from year to year. Consequently, despite the prohibition on interstate trading, this approach would also lead to variability in total state emissions if allowance banking occurred. [EPA-HQ-OAR-2009-0491-2691.1, pp.5-6]
EPA's first alternative approach is significantly less cost-effective because is prohibits interstate trading. EPA acknowledges concerns about the first alternative approach and notes that it is less flexible and more resource-intensive. Consequently, despite the prohibition on interstate trading, this approach would also lead to variability in total state emissions if allowance banking occurred. However, this approach is the only option that would include an auction system to allocate emissions allowances, although it would only auction a small portion of allowances. An auction-based method to allocate allowances would ensure the most efficient and fairest distribution of emissions allowances, and this method of allocation should be considered by EPA in its final rule. [EPA-HQ-OAR-2009-0491-2691.1, p.6]
Response: 
EPA is finalizing the air quality-assured trading remedy, not the alternative intrastate trading option.  The power sector, by its very nature, has operational and emissions variability that are a necessary part of reliable service.  EPA has modified the allowance allocation approach from what was proposed.  The final rule does not include auctions, which would increase program costs.
Organization: North Carolina Department of Environment and Natural Resources
Comment: 
North Carolina Department of Environment and Natural Resources
The NCDAQ submits that if EPA is not able to resolve . issues with the variability limits, then interstate trading ~ as considered in the 'proposed remedy option' - cannot be permitted. Instead, NCDAQ would propose the 'first alternative remedy option' (option 1 throughout). It provides some flexibility while ensuring that a substantial portion of a state's assigned emissions reductions occur in that state. Option 1 most closely aligns with the C5A with respect to trading among only intrastate sources. Our experience with this type of approach shows that it is a feasible option. The (SA program has successfully reduced NOx and 502 emissions with minimal agency oversight. We do not support the 'second alternative remedy option' (option 2 throughout) and have concerns with its prescribed limits and feel that this offers sources little incentive to be more energy efficient and limits flexibility. [EPA-HQ-OAR-2009-0491-2767.1 p.6]
EPA's FIP approach using the 'first alternative remedy option' is satisfactory to NCDAQ for this FTR, but it should not be construed as support for using this approach for the second FTR aimed at addressing the pending revision to the 8-hour ozone standard. The NCDAQ suggests the simplest and most defensible way to effectuate the mandate in §110(a)(2)(D)(i)(l) is for EPA to determine each State's significant contribution level and then allow the State to determine how to reduce its emissions to a level below that. [EPA-HQ-OAR-2009-0491-2767.1 p.7]
Response: 
EPA is finalizing the air quality-assured trading remedy, not the alternative intrastate trading remedy.  The final remedy has been designed to ensure that all significant contribution and interference with maintenance from upwind states is eliminated in downwind states as required by CAA section (110)(a)(2)(D).  For more details on EPA's decision to finalize the air quality-assured trading remedy, see section VII.A of the preamble.
Organization: Old Dominion Electric Cooperative
Comment: 
Old Dominion Electric Cooperative
ODEC also supports the proposal's remedy option and the intrastate trading option in the second compliance period to the extent that both allow allowance trading, because program costs would be reduced without jeopardizing emission reduction goals. [EPA-HQ-OAR-2009-0491-2877.1,p.3] [[This comment is also in Section V.D.2.]]
Response: 
EPA is finalizing the air quality-assured trading remedy, not the alternative intrastate trading remedy.  The final remedy has been designed to ensure that all significant contribution and interference with maintenance from upwind states is eliminated in downwind states as required by CAA section (110)(a)(2)(D).  For more details on EPA's decision to finalize the air quality-assured trading remedy, see section VII.A of the preamble.
Organization: Public Interest Law Center of Philadelphia
Comment: 
Public Interest Law Center of Philadelphia
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.125.]
Under the agency's first alternative, only intrastate trading would be allowed. 
Response: 
EPA is finalizing the air quality-assured trading remedy, not the alternative intrastate trading remedy.
Organization: Southern Company
Owensboro Municipal Utilities (OMU)
Comment: 
Owensboro Municipal Utilities (OMU)
We do not support EPA's first alternative because it unnecessarily limits the allowance trading market and ability to achieve more cost-effective compliance options. This alternative would result in higher electricity costs that would be very detrimental to the already weakened economy. [EPA-HQ-OAR-2009-0491-2811.1, p.1]
Southern Company
XIV. EPA Should Adopt an Interstate Trading Program and Abandon the Alternatives Offered for Comment
EPA's proposed limited interstate trading option provides a limited amount of flexibility and allows more cost-effective compliance options. EPA has historically allowed interstate trading in transport rules and should do so in this case. The intrastate trading option (Alternative 1) is completely unworkable and cumbersome. And EPA has no authority for the direct control option (Alternative 2), which provides for little to no flexibility. As stated, Southern Company strongly supports a flexible interstate trading program. Although EPA's interstate trading option is preferable to either of the two proposed alternatives, as explained in Section V, EPA should evaluate whether less stringent limits on trading can be adopted without compromising the anticipated air quality benefits of the Transport Rule. [EPA-HQ-OAR-2009-0491-2864.1, p. 50]  [This comment can also be found at section V.D.2, V.D.3. and V.D.5 of this comment summary.]
A. The Intrastate Trading Alternative Is Unworkable, Cumbersome and Far Inferior to EPA's Proposed Remedy
Southern Company agrees with EPA that the State Budgets/Intrastate Trading option is more problematic and costly than the preferred option. As noted, this option would be more resource intensive, more complex, and less flexible than the other two options. 51 Southern Company can hardly fathom the waste of federal, state and industry resources and the administrative burden if there were 82 allowance trading programs. Such limited allowance markets would provide very little of the flexibility that trading is designed to create, and would involve orders of magnitude more resources to implement. In addition to this alternative's lack of benefits and excessive burdens, it does not make sense given the regional analysis EPA applied for some of the rule's most significant determinations. For example, the proposed rule uses regional analysis to determine that the required reductions should come from the electric power sector and, in a limited way, to determine cost effectiveness, despite the fact that some states may have more cost effective control options from other sectors. [EPA-HQ-OAR-2009-0491-2864.1, p. 50]
Under this proposed alternative, it is all the more critical that EPA allow states the flexibility to determine how best to achieve any required reductions. As articulated in the proposed rule, under this alternative, EPA would identify linkages based on total anthropogenic emissions and then hamstring the states by imposing a FIP that requires all needed reductions to come from EGUs. If EPA were tempted to limit trading to state boundaries, there is absolutely no justification for further limiting where those reductions must be derived. As noted above, how reductions are achieved is the primary responsibility of the state. Absent the flexibility interstate trading allows, there is little to no basis for proscribing over 80 complex intrastate trading programs that are essentially identical for all states. [EPA-HQ-OAR-2009-0491-2864.1, pp. 50-51
More basically, however, Southern Company is certain that the modicum of benefit associated with such a restricted trading program is underwhelming in the face of the extraordinary administrative burden needed to implement this alternative. [EPA-HQ-OAR-2009-0491-2864.1, p. 51]
Response: 
EPA is finalizing the air quality-assured trading remedy, not the alternative intrastate trading remedy.  The final remedy has been designed to ensure that all significant contribution and interference with maintenance from upwind states is eliminated in downwind states as required by CAA section (110)(a)(2)(D).  For more details on EPA's decision to finalize the air quality-assured trading remedy, see section VII.A of the preamble.

V.D.3.a. Auctions of Allowances

Organization: DTE Energy
Comment: 
DTE Energy
EPA should remain opposed to allowance auctioning under the preferred option or the intrastate trading alternative. [EPA-HQ-OAR-2009-0491-2851.1, p.3]
Response: 
EPA is not implementing auctions of allowances in the final Transport Rule FIPs. See section VII.D of the preamble in the FR for more about allowance allocations.
Organization: DTE Energy Services (DTEES)
Comment: 
DTE Energy Services (DTEES)
Another option from the proposal that would provide relief for stranded units is an annual auction for small generators as described in the State Budgets/Intrastate Trading Alternative Remedy (described in 75 FR 45327). [EPA-HQ-OAR-2009-0491-2699.1,p.2] [EPA-HQ-OAR-2009-0491-3721.1_NODA, p.1]
Response: 
EPA is not implementing auctions of allowances in the final Transport Rule FIPs. See section VII.D of the preamble in the FR for more about allowance allocations.
Organization: Dynegy, Inc.
Comment: 
Dynegy, Inc.
Dynegy Supports EPA's Decision Not to Auction Allowances
Although Dynegy does not support the intrastate-only trading option, in the event that EPA promulgates a final rule based on this option, EPA should not enable or endorse government-run allowance auctions. Governmental auctioning of allowances would substantially increase the cost of the Transport Rule upon regulated entities, adding to viability concerns for many units and, thus, ultimately increasing costs to consumers and decreasing the reliability of electric supply. [EPA-HQ-OAR-2009-0491-2698.1,pp.8-9]
Response: 
EPA is not implementing auctions of allowances in the final Transport Rule FIPs. See section VII.D of the preamble in the FR for more about allowance allocations.
Organization: Florida Electric Power Coordinating Group, Inc. (FCG)
Comment: 
Florida Electric Power Coordinating Group, Inc. (FCG)
The FCG supports EPA's proposal not to permit government-run allowance auctioning. In addition, FCG urges EPA not to allow allowance auctioning under the intrastate trading remedy option. Governmental auctioning of allowances is contrary to the principle that regulated sources are permitted to emit up to their allowance allocation levels without any obligation to pay for the right to emit up to those levels, and any type of allowance auctioning would cause great uncertainty within FCG members' planning groups regarding their current financial obligations and financial forecasting procedures. [EPA-HQ-OAR-2009-0491-2658.1,p.12]
Response: 
EPA is not implementing auctions of allowances in the final Transport Rule FIPs. See section VII.D of the preamble in the FR for more about allowance allocations.
Organization: Large Public Power Council (LPPC)
Comment: 
Large Public Power Council (LPPC)
Second, LPPC is concerned that the Intrastate Trading option presumes auctions will be necessary in all states. LPPC believes allowances should be allocated directly to EGUs to the greatest extent possible in order to reduce cost impacts for consumers, and objects to the potential use of auctions to generate revenue for the U.S. Treasury. Moreover, LPPC is not convinced that EPA is in the best position to determine whether market power issues are present and must be remedied. If the Intrastate Trading option is adopted, LPPC suggests that a two-year trial period be established, during which time EPA can consult with the Federal Trade Commission to determine whether the emissions trading markets are functioning properly and whether any policy changes are warranted. LPPC notes that the federal government is already well-equipped to police markets for manipulation and other abusive practices if market power issues do arise during this trial period. [EPA-HQ-OAR-2009-0491-2667.1, p.19]
Response: 
EPA is not implementing auctions of allowances in the final Transport Rule FIPs. See section VII.D of the preamble in the FR for more about allowance allocations.
Organization: Missouri Public Utilities Alliance (MPUA)
Comment: 
Missouri Public Utilities Alliance (MPUA)
1. We join with APPA and other commentators in supporting the decision to avoid the unnecessary development costs and ongoing expense of operating an auction system for allocation of allowances.  There is no evidence that such an auction would increase compliance with the law, and in fact diverts limited resources from projects which will [sic] 6 month deadlines for compliance in a number of areas where it is impossible to secure the necessary engineering and manufacturing to fabricate the required units. [EPA-HQ-OAR-2009-0491-2785.1, pp.1-2]
Response: 
EPA is not implementing auctions of allowances in the final Transport Rule FIPs. See section VII.D of the preamble in the FR for more about allowance allocations.
Organization: National Rural Electric Cooperative Association (NRECA)
Comment: 
National Rural Electric Cooperative Association (NRECA)
Additionally, allowance auctions necessarily increase program costs while serving no environmental benefit. Moreover, depending on design, an auction can increase allowance price and allowance availability uncertainty. [EPA-HQ-OAR-2009-0491-2723.1, p.4]
NRECA commends EPA as well for proposing options that exclude auctions. [EPA-HQ-OAR-2009-0491-2723.1, p.4]
Response: 
EPA is not implementing auctions of allowances in the final Transport Rule FIPs. See section VII.D of the preamble in the FR for more about allowance allocations.
Organization: San Miguel Electric Cooperative, Inc.
Comment: 
San Miguel Electric Cooperative, Inc.
 The preferred remedy option allowing unlimited emissions trading during the initial 2012 compliance period and limited interstate trading in the second compliance period recognizes the economic benefits of trading and should be retained. The auctioning of allowances would drive up program compliance costs. Therefore, it is justifiably excluded from the preferred remedy and proposed intrastate option.   [EPA-HQ-OAR-2009-0491-2641.1, p.6][[This comment can also be found in Outline Heading V.D.2.b.ii.]]
Response: 
EPA is not implementing auctions of allowances in the final Transport Rule FIPs. See section VII.D of the preamble in the FR for more about allowance allocations.
Organization: Southern Company
Comment: 
Southern Company
In addition to the extraordinary administrative burden associated with allowance trading programs that may be required under this option, EPA proposes to run numerous auctions. Southern Company fundamentally disagrees that such auctions are necessary to avoid the exercise of market power.  [EPA-HQ-OAR-2009-0491-2864.1, p. 51]
If, however, EPA promulgates a final rule based on the Intrastate Trading Remedy Option, an option that Southern Company does not support, EPA should remove from that option the proposed provisions for allowance auctions. It is entirely possible to accomplish the objectives of those proposed auctions through distribution of allowances free of charge. [EPA-HQ-OAR-2009-0491-2864.1, p. 53]
Response: 
EPA is not implementing auctions of allowances in the final Transport Rule FIPs. See section VII.D of the preamble in the FR for more about allowance allocations.
Organization: Utility Air Regulatory Group (UARG)
Comment: 
Utility Air Regulatory Group (UARG)
EPA Should Not Establish Any Government-Run Allowance Auctions.
Although UARG does not support EPA's Intrastate Trading Remedy Option, if EPA promulgates a final rule based on this option, EPA should not provide for government-run allowance auctions. As noted above in section II.C, governmental auctioning of allowances is contrary to the principle that regulated sources are permitted to emit up to their allowance allocation levels without bearing any obligation to pay for the right to emit up to those levels. EPA explains in the Proposed Transport Rule that revenues from the allowance auctions described in the section on the Intrastate Trading Remedy Option would be deposited into the U.S. Treasury. 75 Fed. Reg. at 45327/2. The effect of such auctions, besides providing revenue to the federal government, would be to force affected sources to pay not only for emissions that exceed their emission allowance allocation limits (by purchasing allowances on the market) but also for the right to emit below those limits. No legal basis exists for charging sources for emissions below their allocation levels, and providing revenue to the U.S. Treasury is not a legitimate purpose of section 110(a)(2)(D)(i)(I) of the CAA. Moreover, as discussed above, EPA has not shown that any legal authority exists for EPA to auction allowances and thereby impose what amounts to a tax, with tax revenue flowing to the federal government. [EPA-HQ-OAR-2009-0491-2756.1, pp.95-96]
In short, EPA should not promulgate a rule based on the intrastate trading option, but if it does, it should remove government-run allowance auctions from the design of that option. Instead, to the extent EPA concludes it is necessary to make additional allowances available under that option to energy producers with limited market share, EPA should provide for adjustments in the distribution of allowance allocations but without auctioning the allowances. [EPA-HQ-OAR-2009-0491-2756.1,p.96]
Response: 
EPA is not implementing auctions of allowances in the final Transport Rule FIPs. See section VII.D of the preamble in the FR for more about allowance allocations.

V.D.3.b. Other Comments on State Budgets/Intrastate Trading Remedy Option

Organization: Attorney General of North Carolina
Comment: 
Attorney General of North Carolina
North Carolina submits that if EPA is not able to resolve these issues with the variability limits, then interstate trading cannot be permitted. Instead, in order to comply with Congress' clear mandate to "prohibit[] . . . emissions activity within the State" (emphasis added), as interpreted by the D.C. Circuit in North Carolina, EPA must implement a remedy that does not include interstate trading.
In that event, North Carolina would recommend EPA's "State Budgets/Intrastate Trading Remedy Option" [hereinafter "intrastate trading option"]. See 75 Fed. Reg. at 45,326/1. The intrastate trading option is consistent with North Carolina's successful Clean Smokestacks Act ("CSA"). The CSA caps coal-fired power plant SO2 and NOX emissions on a companywide basis within North Carolina for the two largest utilities. The NOX caps have been in place since 2007 and the SO2 limits began in 2009. N.C. Gen. Stat. §143-215.107D(b)-(g). The program has successfully reduced NOX and SO2 emissions with minimal agency oversight.
The CSA does not raise the problem of intercompany trading in a state-sized market. EPA discusses trading in more limited markets as a drawback of the intrastate trading option. 75 Fed. Reg. at 45,326/3-28/1. However, North Carolina submits that any difficulties raised by developing intrastate markets is outweighed by the need for expeditious implementation in compliance with the mandates of North Carolina. That is, considering the legally problematic nature of EPA's preferred option, EPA should pursue the remedy that has a greater chance of withstanding judicial scrutiny and delivering, in a certain and timely manner, the result required by North Carolina. EPA even concedes that "[o]f the three remedy options considered" the intrastate trading option "provides the most certainty regarding . . . emissions from each state. For this reason, it most directly addresses the statutory mandate that the emissions reductions occur `within the State.'" Id. at 45,328/2. Based on the current record, the intrastate trading option is more likely to provide downwind States with the relief that Congress required EPA to provide under the Clean Air Act.
Response: 
EPA is finalizing the limited interstate trading remedy, not the alternative intrastate trading remedy.  The final remedy has been designed to ensure that all significant contribution and interference with maintenance from upwind states is eliminated in downwind states as required by CAA section (110)(a)(2)(D).  This comment from the North Carolina AG does acknowledge that market power problems may arise, which continues to be a concern for EPA.  In addition, EPA received a significant number of comments supporting the limited interstate trading remedy and opposing the intrastate trading remedy.  For more details on EPA's decision to finalize the limited interstate trading remedy, see section VII.A of the preamble.
Organization: Large Public Power Council (LPPC)
Comment: 
Large Public Power Council (LPPC)
If EPA nonetheless reverses course and decides to propose one of these alternative remedies, LPPC urges EPA to consider modifying the options in the following ways. First, LPPC believes that the Intrastate Trading option must make accommodation for natural year-to-year variability in emissions. As EPA argues at several points in the preamble, allowing for variability is consistent with the mandate of Section 110 so long as the underlying state budgets ensure the elimination of significant contributions to downwind air quality problems. Moreover, variability limits are essential to ensuring reliability of electric service and coping with external shocks to electricity demand and emission rates. EPA should therefore ensure that state emission budgets established under the Intrastate Trading option include variability limits. [EPA-HQ-OAR-2009-0491-2667.1, pp.18-19]
Response: 
EPA is not finalizing the State Budgets/ Intrastate Trading remedy option in the Transport Rule.  See section VII of the preamble for more details on the final remedy and EPA's reasons for its decision to implement limited interstate trading.

V.D.4. Direct Control Remedy Option

Organization: Public Interest Law Center of Philadelphia
Ailey, John
Comment: 
Ailey, John
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.50-52]
The second point that I would like to emphasize is looking at your alternatives for enforcing this, to me it appears that the second alternative that you are proposing would be the best one in terms of the environmental justice standpoint. 
Part of the issue is that in particular we are very familiar with these two plants. There's a huge population density in the surrounding area. It's also a relatively low income area. 
If plants are allowed to trade, we're afraid that what's going to happen is that these two plants, which are relatively expensive to retrofit, and relatively small, the companies will avoid or postpone the retrofits that are needed and that our communities will continue to suffer the bad effect from these plants. 
And so, therefore, we feel that a fair approach, better approach would be to look at what is the population density around the various plants, try to set limits prioritizing, shall I say, those plants that are closest to large population densities. I feel that would be a fair way to do it. 
I support that second alternative. I think that would be the fairest way of determining environmental justice to implement the Rule. 
Public Interest Law Center of Philadelphia
II. The EPA's Direct Control Approach to Implementation Would Provide the Greatest Amount of Protection to EJ Communities.
The EPA's "direct control" approach would require setting strict guidelines that, in addition to setting an overall emissions cap for every state, would also create an individual emissions cap for each pollution source or power plant. The current structure of this option would still allow for limited, company-level emissions averaging within each state. This direct control alternative would provide the greatest amount of protection to EJ communities by ensuring that the pollution cap at each and every power plant is lowered. Under either of the other two approaches, there is the chance that localized pollution could increase as a result of intrastate and interstate trading of emissions allowances. By capping the maximum amount of emissions to be produced by any individual plant, the EPA can at least ensure that power plants located in close proximity to EJ communities do not acquire additional allowances under the trade system, which allow them to produce emissions at a higher level than under current regulations. [EPA-HQ-OAR-2009-0491-2817.1, pp.3-4]
The EPA has stated that this approach is unattractive because it is both expensive and difficult to handle from an administrative standpoint. The additional cost of implementing the direct control approach rather than the preferred approach is estimated at $600 million dollars, approximately a 36% increase over the estimated $2.2 billion dollar implementation cost for the preferred approach. However, that additional cost would represent a mere 0.002% of the total projected benefits of the Transport Rule, which the EPA has suggested could be upwards of $290 billion. Obviously the cost of implementing this approach is slightly higher than the cost of either of the other two approaches. However, if the EPA estimations of the projected economic benefit are correct, the additional expense of the tighter regulations set forth in the direct control approach offers an unpersuasive argument for settling for an approach with allowance trading provisions that could very easily create significant disparate impacts for EJ communities. [EPA-HQ-OAR-2009-0491-2817.1, p.4]
Equally uncompelling is the EPA's concern that implementing the direct control approach would be too difficult. While a direct control approach would clearly require more administrative oversight, these administrative "headaches" are no less warranted than the physical manifestations, or "disbenefits", that would be suffered by EJ communities who would have to endure increased localized pollution as a result of locally unfavorable emissions trading under either the preferred option or the more limited intrastate trading option. [EPA-HQ-OAR-2009-0491-2817.1, p.4]
We believe that the best implementation approach the EPA has presented would be the second alternative, or direct control option. The direct control approach provides the most protection to EJ communities by eliminating the allowance trading that could potentially impose disparate health impacts at a local level in the communities that can least endure them, even while emission caps are met at the state level. While we would support the removal of allowance trading all together, we believe that the Transport Rule can be highly effective with allowance trading if proper protections are afforded to EJ communities. Specifically, we suggest the implementation of additional rules aimed at regulation and monitoring of any allowance trading which sends emissions allowances to coal-fired power plants located in close proximity to EJ communities. [EPA-HQ-OAR-2009-0491-2817.1, pp.5-6]
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.125.]
Even under the second alternative, which would set emissions limits for each power plant individually, company-level averaging for sites within a given state would be permitted.
Response: 
EPA decided to finalize the air quality-assured trading programs instead of the direct control option, for the reasons presented in section VII.A of the preamble.  EPA has conducted an analysis of the effects of the Transport Rule on environmental justice and other vulnerable communities, as discussed in sections VII.A and XII of the preamble and Chapter 5 of the Regulatory Impact Analysis (RIA) for this rule.
Organization: State of Delaware Department of Natural Resources & Environmental Control
Adirondack Mountain Club
Peoria Families Against Toxic Waste
New Jersey Department of Environmental Protection (NJDEP)
Comment: 
Adirondack Mountain Club
The Clean Air Transport Rule (CATR) suggests three alternatives for states to obtain emissions reductions. Each alternative requires States to create an individual state budget of emissions. ADK supports EPA's second alternative to allow plants to participate in trading emissions allowances while setting a pollution limit for each state and specifying the allowable emission limit for each power plant and allow some averaging. Under the cap and trade system, a region encompassing 31 states plus the District of Columbia would reduce emissions by 6.3 million annual tons for SO2 and 1.4 million annual tons for NOx by 2014. [EPA-HQ-OAR-2009-0491-2761, p.2]
New Jersey Department of Environmental Protection (NJDEP)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.160.]
Although the USEPA offered a direct control alternative in the Transport Rule, it allows for annual averaging, which also will not solve the peak ozone day problem.
Peoria Families Against Toxic Waste
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.111.]
Your second alternative which sets a pollution limit for each state and specifies limits for each power plant I believe is the way to go, and I say that -- I live in Illinois, and I know that if there's a way to wheel and deal and put something off, it will happen in Illinois, and we'll be here 5 years from now, and Illinois won't be any further along, so I encourage that you do the strictest possible way to -- so that everybody knows what's happening in the state, what's going to happen for each power plant, not only in Illinois but all around us, because the other part of my thinking is that -- and I believe Mr. Aburano was gracious to be at an ozone forum in Peoria.
State of Delaware Department of Natural Resources & Environmental Control
Delaware generally agrees with the concept presented for EPA's second alternative to the proposed program that includes establishing unit-by-unit performance standards/emission rates along with an overlaying cap-and-trade program, but recommends EPA consider some revisions to the process presented by the EPA for that second alternative. EPA-HQ-OAR-2009-0491-2980.1, p.4]
The second recommendation is that EPA reconsiders the use of averaging the emission rate of all of a single company's EGUs in a given state as a compliance alternative. While Delaware agrees that this concept has merit in providing a company flexibility in control installation planning and compliance strategy, Delaware also believes that this flexibility could result in a number of smaller and/or low capacity factors to continue operation with little or no controls. The existence of such units contributes to transport issues and compliance with short term NAAQS. If EPA retains the concept of permitting same- company averaging for compliance, Delaware recommends that EPA consider doing so for only a small number of compliance periods to provide some initial flexibility for control installation planning until transitioning to a true unit-specific compliance requirement. [EPA-HQ-OAR-2009-0491-2980.1, p.5]
Response: 
EPA decided to finalize the air quality-assured trading programs instead of the direct control option, for the reasons presented in section VII.A of the preamble.
Organization: United States Clean Heat & Power Association (USCHPA)
Comment: 
United States Clean Heat & Power Association (USCHPA)
First, and most important, EPA should adopt output-based emissions standards in the Federal Plan. Rather than base pollution limits on the amount of fuel consumed, standards based on each unit of electricity (and thermal energy) produced would encourage efficiency and allow the EPA to calculate compliance based on efficiency and not on fuel consumed. As a result, pollution would be prevented and emissions reduced. [EPA-HQ-OAR-2009-0491-2823.1, p. 2]
Response: 
EPA believes that this comment may be about the alternative direct control remedy option on which we took comment in the proposal (although this comment is not clear) because the Transport Rule limited interstate trading programs do not include emissions standards.  EPA's response to this comment is based on that assumption.  EPA decided to finalize the limited interstate trading option instead of the direct control option, for the reasons presented in section VII.A of the preamble to the final Transport Rule.  In addition, as presented in preamble section VII.D, EPA is not allocating emission allowances to existing units using an output-based approach in the Transport Rule FIPs, because the Agency does not have access to unit-level output data that is as quality-assured or comprehensive as its data sets on heat input across the units considered.
Organization: Utility Air Regulatory Group (UARG)
Southern Company
Clean Energy Group
Tennessee Department of Environment and Conservation, Division of Air Pollution Control
Florida Electric Power Coordinating Group, Inc. (FCG)
GE Energy Financial Services (GE EFS)
Michigan Department of Natural Resources and Environment
Owensboro Municipal Utilities (OMU)
National Mining Association (NMA)
Michigan Municipal Electric Association (MMEA)
New York University School of Law, Institute for Policy Integrity
Comment: 
Clean Energy Group
The Clean Energy Group Does Not Support Alternative 1 or Alternative 2
The first alternative approach proposed in the Transport Rule would use state-specific control budgets and allow intrastate trading of emissions allowances allocated to EGUs, but it would not allow interstate trading. The second alternative would be a direct control program and also would prohibit trading. Both options would be inefficient, more costly, and would unnecessarily limit the flexibility of interstate trading available under the preferred option. The preferred approach is structured to allow maximum trading while also addressing the court's concerns. We would strongly oppose any alternative that does not include an interstate trading component. [EPA-HQ-OAR-2009-0491-2702.1, p. 10] [This comment can also be found at Section V.D.3 of this comment summary.]
Florida Electric Power Coordinating Group, Inc. (FCG)
Regarding the direct control option, the FCG agrees with EPA that it is inferior to the limited interstate trading option. EPA states in the proposed rule that for the direct control approach fewer emissions reductions were projected through modeling and those reductions would be more costly than under the preferred method. According to the proposed rule, this option would provide less flexibility to ensure electric reliability than the preferred option, and according to the Regulatory Impact Analysis this option would result in greater private costs to the power sector and greater social costs for consumers than the preferred option. EPA notes in the proposed rule that without a price on NOx and S02 emissions there is no incentive to reduce emissions, and as a result 'the direct control program provides less certainty regarding the location of emissions in the short term.' In addition to the economic concerns, EPA does not appear to have the legal authority to set direct control limits under Section 110(a)(2)(d)(i)(I). Due to the increased cost and uncertainty and to the decreased flexibility and clear legality, the FCG supports the preferred remedy over the Direct Control method. [EPA-HQ-OAR-2009-0491-2658.1,p.12]
GE Energy Financial Services (GE EFS)
GE EFS does not support EPA's proposed alternative of implementing a direct control program without any emissions trading. [EPA-HQ-OAR-2009-0491-2701.1, p.5]
Michigan Department of Natural Resources and Environment
The third compliance option would use state-specific budgets and emissions rate limits. The DNRE disagrees with this alternative due to the loss of any allowance trading within the program. There is also the potential for electricity market unreliability as sources, out of concerns for enforcement, may cease operations of specific units when approaching their emission rate limitations during high electricity demand periods. [EPA-HQ-OAR-2009-0491-2774.1 p.6]
Michigan Municipal Electric Association (MMEA)
9.) The Direct Control Remedy Would Be Particularly Harmful to Michigan Public Power
MMEA and its members strongly discourage EPA from adopting a direct control remedy, because the application of emission rates to small municipal units will cause drastic, disproportionate impacts on power plants that have major diseconomies of scale in pollution control. Engineering studies conducted by each one of the entities represented here show NOx control costs exceeding an average of $7,500 per ton of NOx removed for the control technologies that would be forced by the unit-specific FIP allocations proposed in this Transport rule. The systems in Holland and Marquette project NOx control costs for ozone season requirements exceeding $20,000 per ton of NOx removed. Given the diseconomies of scale and relatively insignificant contribution of small, municipal utility units to interstate transport, and the critical role of these units to public power communities, costs of this magnitude under a direct control remedy would simply be unbearable. [EPA-HQ-OAR-2009-0491-2828.1, pp.15-16]
9.) Do not adopt a direct control remedy for air pollution control, which would be particularly harmful to small public power communities. [EPA-HQ-OAR-2009-0491-2828.1, p.16]
National Mining Association (NMA)
The Direct Control Remedy Option Also Usurps State Authority
EPA requests comments on the option of EPA imposing a Direct Control Remedy on individual units by assigning them emission rates. As discussed, however, EPA does not have authority to bypass SIPs and impose specific requirements on individual units. In remedying significant contributions by states to downwind attainment under section 110, EPA may impose emission reduction obligations on states -- but not on individual units. [EPA-HQ-OAR-2009-0491-2868.1,p.18]
New York University School of Law, Institute for Policy Integrity
While on the surface EPA's second alternative approach may be easier to understand and to comply with, it would lead to fewer emissions reductions and a higher cost. EPA acknowledges serious concerns about the inflexibility and lack of cost-effectiveness of this approach, as compared to an approach that permits trading. [EPA-HQ-OAR-2009-0491-2691.1, p.6]
Owensboro Municipal Utilities (OMU)
OMU also does not support EPA's second alternative that takes a command and control approach to reduce emissions. This alternative is even more restrictive because it further reduces compliance flexibility and would increase compliance costs significantly. [EPA-HQ-OAR-2009-0491-2811.1,p.1]
Southern Company
XIV. EPA Should Adopt an Interstate Trading Program and Abandon the Alternatives Offered for Comment
EPA's proposed limited interstate trading option provides a limited amount of flexibility and allows more cost-effective compliance options. EPA has historically allowed interstate trading in transport rules and should do so in this case. The intrastate trading option (Alternative 1) is completely unworkable and cumbersome. And EPA has no authority for the direct control option (Alternative 2), which provides for little to no flexibility. As stated, Southern Company strongly supports a flexible interstate trading program. Although EPA's interstate trading option is preferable to either of the two proposed alternatives, as explained in Section V, EPA should evaluate whether less stringent limits on trading can be adopted without compromising the anticipated air quality benefits of the Transport Rule. [EPA-HQ-OAR-2009-0491-2864.1, p. 50] This comment can also be found at section V.D.1, V.D.2. and V.D.3 of this comment summary.]
B. EPA Cannot and Should Not Adopt the Direct Control Alternative
Under this alternative for addressing interstate transport, EPA would simply mandate unit-specific emission limits for the units in the affected states. 52 However, it is well-established that under Section 110 of the Act Congress reserved for the states the authority to decide which sources to control and to what extent. 53 Even if EPA had authority to mandate unit-specific limits under Section 110 of the Act, unit-specific reductions could not be achieved within the timeframes provided by the rule for the many reasons outlined in Sections VI and VII above. Furthermore, EPA's Regulatory Impact Analysis confirms that the cost of any reductions that could be achieved would be significantly higher than EPA's preferred limited trading option. These are costs that in most instances would be borne by our customers at a time when they can least afford it - just as they are trying to recover from the worst recession in our nation's history. For all of these reasons, Southern Company urges EPA to reject the direct control alternative. [EPA-HQ-OAR-2009-0491-2864.1, p. 51]
Tennessee Department of Environment and Conservation, Division of Air Pollution Control
Comment on Direct Control Option: We agree with EPA that limited interstate trading is preferable to the direct control option for the reasons stated in the proposed rule.  [EPA-HQ-OAR-2009-0491-0553.1,p.5]
Utility Air Regulatory Group (UARG)
With respect to EPA's Direct Control Remedy Option, the second alternative option on which EPA requests comment in the Proposed Transport Rule, EPA explains that it would regulate individual units directly by assigning emission rate limits to individual units. 75 Fed. Reg. at 45330/1. As discussed above, EPA is without authority to dictate how a state implements section 110(a)(2)(D)(i)(I). As LADCO aptly observed in 2009 in its recommendations to EPA, "unit-specific performance standards go beyond the requirements of section 110 [of the Act] and the scope of the CAIR replacement rule." LADCO Letter, attachment at 5. Indeed, all such matters are reserved to the states in the first instance. See, e.g., Michigan, 213 F.3d at 686 ("section 110 left to the states `the power to [initially] determine which sources would be burdened by regulation and to what extent.'") (quoting Union Elec. Co. v. EPA, 427 U.S. 246, 269 (1976)) (alteration and emphases in original); Virginia, 108 F.3d at 1408 (same). Consistent with those cases, EPA at most can determine what overall emission tonnage level a state must achieve; it may not impose any unit-specific rules or requirements. [EPA-HQ-OAR-2009-0491-2756.1, p.32]
Response: 
EPA decided to finalize the air quality-assured trading programs instead of the direct control option, although we continue to believe that we have authority to impose a direct control remedy.

V.D.4.a. Emission Rate Limits - Data and Methodology

Organization: American Public Power Association (APPA)
Comment: 
American Public Power Association (APPA)
With respect to EPA`s Direct Control Remedy Option, the second alternative option on which EPA requests comment in the Proposed Transport Rule, EPA explains that it would regulate individual units directly by assigning emission rate limits to individual units. 75 Fed. Reg. at 45330/1. As discussed above, EPA is without authority to dictate how a state implements section 110(a)(2)(D)(i)(I). As LADCO aptly observed in 2009 in its recommendations to EPA, "unit-specific performance standards go beyond the requirements of section 110 [of the Act] and the scope of the CAIR replacement rule." LADCO Letter, attachment at 5. Indeed, all such matters are reserved to the states in the first instance. See, e.g., Michigan, 213 F.3d at 686 ("section 110 left to the states `the power to [initially] determine which sources would be burdened by regulations and to what extent.'") (quoting Union Elec. Co. v. EPA, 427 U.S. 246, 269 (1976)) (alteration and emphases in original); Virginia, 108 F.3d at 1408 (same). Consistent with those cases, EPA at most can determine what overall emission level a state must achieve; it may not impose any unit-specific rules or requirements. [EPA-HQ-OAR-2009-0491-2812.1, pp.28-29]
Response: 
As discussed in section VII.A of the preamble, EPA is not finalizing the Direct Control Remedy Option. 
Organization: Lafayette Utilities System
Comment: 
Lafayette Utilities System
Under the Direct Control Alternative, EPA projects that the ozone season NOx rates for Louis Doc Bonin Unit 3, T J Labbe' Unit 1 and Unit 2 and Hargis-Hebert Unit 1 and Unit 2 are significantly higher than actual reported emission rates. However, the emission rates, as distinguished from the mass emissions, should not change from annual to ozone season. [EPA-HQ-OAR-2009-0491-2983.1,p.13]
Response: 
As discussed in section VII.A of the preamble, EPA is not finalizing the Direct Control Remedy Option.
Organization: State of Delaware Department of Natural Resources & Environmental Control
Comment: 
State of Delaware Department of Natural Resources & Environmental Control
In the TSD State Budgets, Unit Allocations, and Unit Emissions Rates, Section 4, Direct Control Rate Limits, EPA indicates that, 'The unit-level rates which sources must comply with under this approach are determined analogously to unit-level allocations - each unit's proposed allocation is divided by the reported or projected heat input associated with that tonnage.' It is not clear that the modeling inputs are adequate to perform a proper evaluation. Further, it appears that the emission rate limits would still be determined primarily on an economic basis, thereby still allowing some units to operate with little or no emission controls. It is Delaware's opinion that this methodology does not adequately evaluate, on a unit- by-unit basis, the technical or economic feasibility of installation of cost-effective emission controls for these units. The methodology therefore may not adequately determine realistic emission rate limits for all of these units. It is Delaware's opinion that unit-by-unit technical evaluations are necessary to properly set such emission rate limits for every EGU in the program. Such evaluations must take into account the unit types, fuel(s) combusted, unit size, unit historic capacity factor, projected additional lifetime, existing emissions controls, commercially available controls for retrofit, etc. [EPA-HQ-OAR-2009-0491-2980.1, p.5]
Response: 
EPA is not finalizing direct control rate limits.

V.D.4.b. [Reserved]

V.D.4.c. Penalties

Organization: Tennessee Department of Environment and Conservation, Division of Air Pollution Control
Comment: 
Tennessee Department of Environment and Conservation, Division of Air Pollution Control
We also note that the penalty provisions of this option are problematic, since individual facilities could face civil penalties regardless of whether they are in compliance with their emission rate limits. [EPA-HQ-OAR-2009-0491-0553.1,p.5]
Response: 
See section VII.F of the preamble.

V.D.4.d. How Direct Control Remedy is Consistent With Court's Opinions

Organization: Edison Electric Institute (EEI)
Comment: 
Edison Electric Institute (EEI)
EPA's proposed option to provide for "direct control" measures is unlawful  
While EEI appreciates EPA identifying alternates to its preferred remedy, EEI believes that EPA cannot require states to impose specific control measures to address interstate transport as it proposes under its alternate direct control option. This is a matter reserved to the states under the CAA. EPA can at most determine what overall emission level a state must achieve. For example, in Michigan v. EPA, the D.C. Circuit stated  
"We held that EPA's approach exceeded its authority under section 110 because each state retains the authority to determine in the first instance the necessary and appropriate control measures needed to satisfy section 110's standards. See Id. at 1407-09 (citing Train v. NRDC, 421 U.S. 60, 78-79 (1975)) . . . As we elaborated in Virginia, 'the Supreme Court decided ... that [section 110] did not confer upon EPA the authority to condition approval of [a state's] implementation plan ... on the state's adoption of a specific control measure.' Virginia, 108 F.3d at 1408."  [EPA-HQ-OAR-2009-0491-2697.1, p.18]
EPA should therefore not finalize this option and should indicate in the final rule that the Agency is prevented, as a matter of law, from finalizing the direct control option. [EPA-HQ-OAR-2009-0491-2697.1, p.18]
Response: 
EPA disagrees with the commenter that the Agency was prevented as a matter of law from finalizing the direct control option. EPA's decision to finalize the limited interstate trading option instead of the intrastate control option or direct control option is explained in the preamble to the final rule.

V.E. Projected Costs and Emissions for Each Remedy Option

Organization: City Utilities of Springfield
Comment: 
City Utilities of Springfield
If the Agency finds it impossible to move the deadline or modify the compliance mechanism, then the supporting database requires substantial editing to account for the actual, inflated control costs that utilities are destined to encounter by this artificial imposition. [EPA-HQ-OAR-2009-0491-2721.1 p.6]
Response: 
EPA believes that the air pollution control retrofit costs utilized in IPM modeling accurately reflect the cost of the air pollution control retrofits projected to be built by 2014.  For more information on the air pollution control retrofit assumptions, including the cost development methodology, please see the IPM documentation.
Organization: Council of Industrial Boiler Owners (CIBO)
Comment: 
Council of Industrial Boiler Owners (CIBO)
B. Highly cost effective analysis is flawed.

EPA's calculation of "highly cost-effective" emissions reductions that sources can achieve (75 FR 45231/1) is based on linear cost per ton assumptions. These assumptions do not reflect the cost of controls that sources will be required to install under several earlier-promulgated EPA regulations. EPA's economic assumptions for the cost impact on the regulated sources is incomplete and therefore, the cost of achieving these emission reductions is not highly cost effective.

In addition, EPA arbitrarily adjusted costs, using "higher and lower cost thresholds, based on the downwind air quality impact of emissions from different groups of states.' 75 FR 45233/2. Based on the charts indicating cost per ton by State, it appears that States that still have fossil-fueled plants are targeted, whereas those that do not seem to escape this cost effective analysis.   [EPA-HQ-OAR-2009-0491-2751.1 p.11]
The compliance period EPA has proposed is unreasonable and will cause costs to dramatically escalate for both EGUs and non- EGUs subject to pollution reduction requirements. [EPA-HQ-OAR-2009-0491-2751.1, p. 12]
Response: 
The calculation of highly cost-effective controls is determined against the appropriate baseline emissions that would exist in each state if EPA did not impost the Transport Rule.  This calculation, and EPA's analysis of the cost impact of the final rule, need not consider the costs of controls already in place and contributing to the baseline. See preamble for further discussion of baseline calculation and highly cost-effective reductions.
EPA determined that it would not be appropriate to assign the same cost threshold to Group 2 and Group 1 states because a significantly lower cost threshold was sufficient to resolve air quality problems at all downwind receptors linked to the Group 2 states.  See preamble section VI.D.1.d.
EPA believes that the air pollution control retrofit costs utilized in IPM modeling accurately reflect the cost of the air pollution control retrofits projected to be built by 2014.  For more information on the air pollution control retrofit assumptions, including the cost development methodology, please see the IPM documentation.
EPA believes that it is feasible for the electric power sector and its APC supply chain to either make most of the projected retrofits in time to meet the 2012 and 2014 compliance deadlines, or to comply by other means.  See preamble for further discussion.
Organization: E.ON U.S.
Four Flags Area Chamber of Commerce
Comment: 
E.ON U.S.
Cost assumptions for control technologies are too low.
EPA's cost assumptions for installation of control technologies are outdated and are too low based on our recent experience in implementing emission control projects, especially in retrofit applications that can impact balance of plant auxiliary systems. In addition, because of the large number of Flue Gas Desulfurization (FGD) and Selective Catalytic Reduction (SCR) controls that will be needed at many utility companies, the cost will almost certainly increase significantly above past costs due to market demand on labor, engineered equipment and raw commodity materials of construction specific to these technologies. The costs are also based on the assumption that CAIR is not in existence or is not a current requirement. [EPA-HQ-OAR-2009-0491-2797.1, p.4]
Four Flags Area Chamber of Commerce
The EPA has not accurately estimated the cost of compliance with this proposal, from the perspective of the cost of installing new equipment as well as the actual equipment needed. [EPA-HQ-OAR-2009-0491-3807, p.1]
Power companies in my state inform me that the costs the EPA used as the basis for designing, permitting, fabricating and installing flue gas desulfurization units are less than half of market rates. Again, the cost of compliance is not accurately reflected in the EPA's estimates. The citizens in my state will have to bear a financial burden that may be unneeded. Now is not the time for expensive government mandates that will provide questionable benefits. [EPA-HQ-OAR-2009-0491-3807, p.2]
Response: 
See IPM 4.10 Documentation and IPM Documentation Supplement for EPA Base Case v.4.10_FTransport - Updates for Final Transport Rule for details on FGD and SCR cost assumptions and considerations in response to comments received on those cost assumptions.  Additionally, EPA notes that it does not project SCR retrofit activity driven by Transport Rule, and the FGD retrofit activity as a consequence of Transport Rule is expected to be less than half of what it was at proposal.
Organization: First Energy
Comment: 
First Energy
Further, many plants do not have rail access to PRB delivery. Those facilities without rail transportation access to PRB supplies will face additional delivery cost, which can make PRB an uneconomical option. Further, the analysis does not take into account the impact of existing long term coal contracts. FE and other similar coal consumers would likely face significant stipulated penalties for each ton not used from an existing contract. There is also a concern that the PRB supply that meets the EPA expected Sulfur levels is limited and may already be completely subscribed. A limited supply of PRB will impact the $/ton assumption the EPA used in the IPM model. The EPA does not account for the increase in PRB rail deliveries to the Eastern United States from the PRB. The analysis must also consider the increased cost of moving rail sets from one privately owned rail line to another privately owned rail line. These rail lines are already running close to capacity. Significantly increased deliveries of PRB to the Eastern United States may not be logistically feasible until additional rail capacity can be constructed. [EPA-HQ-OAR-2009-0491-2657.1 ,p.9; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, pp.8-9 10/15/2010]
Response: 
IPM modeling considers coal access and transportation costs at the plant level, as well as detailed coal reserve availability.  Additionally, IPM incorporates constraints on the growth of PRB coal production due to transportation capacity limits.  See Chapter 9 of IPM documentation.
Regarding long-term contracts, EPA modeling using IPM projects that the rule causes only about 5% of the higher sulfur coal consumed in 2012 in the base case to switch to a lower sulfur coal under the rule.  According to data from the Energy Information Administration (http://www.eia.doe.gov/cneaf/electricity/page/eia906_920.html), contracts for over half of the quantity of coal delivered in July of 2010 when the proposal for this rule was issued will have expired by January of 2012.  EPA believes that this degree of contract turnover is entirely consistent with the level of coal switching projecting in the analysis of this rule.
Organization: Michigan Chamber of Commerce
Comment: 
Michigan Chamber of Commerce
The EPA has not accurately estimated the cost of compliance with this proposal, from the perspective of the cost of installing new equipment, as well as the actual equipment needed. The EPA also has not considered the costs of changing or breaking contracts to meet new requirements and schedules. Our members in the Energy industry inform us that the costs the EPA used as the basis for designing, permitting, fabricating and installing flue gas desulfurization units are well below market rates, past implementation experience and current contracts in hand. Again, the cost of compliance is not accurately reflected in the EPA's estimates. Job providers in Michigan will have to bear a financial burden that may not be needed. Now is not the time for expensive government mandates that will, at best, provide questionable benefits. [EPA-HQ-OAR-2009-0491-2696.1, p.1]
Response: 
EPA has updated the retrofit control costs originally assumed in the proposal.  EPA believes that these updated costs accurately reflect, on average, current market rates.  For more information on emission control retrofit costs see "Documentation for EPA Base Case v.4.10 using the Integrated Planning Model" August 2010 sect. 5.
Absent details on the contracts to which the commenter refers, EPA believes that the IPM retrofit cost methodology is reasonable.
EPA analysis suggests that the impact on electricity rates is negligible.  See preamble section XII.H.
Organization: Michigan Manufacturers Association (MMA)
Comment: 
Michigan Manufacturers Association (MMA)
- The EPA has not accurately estimated the cost of compliance with this proposal, from the perspective of the cost of installing new equipment as well as the actual equipment needed. EPA has not considered the costs of changing or breaking contracts to meet new requirements and schedules. EPA has not considered the availability of the skilled labor necessary to implement a program of this magnitude over a 32 state region. [EPA-HQ-OAR-2009-0491-2762.1, p.2]
Power companies in Michigan and members of MMA have concluded that the costs the EPA used as the basis for designing, permitting, fabricating and installing flue gas desulfurization units are well below market rates, past implementation experience and current contracts in hand. The cost of compliance is not accurately reflected in the EPA's estimates. MMA's members will have to bear a financial burden that may not be needed. Now is not the time for expensive government mandates that will provide questionable benefits, while most definitely adversely affect Michigan's economy. [EPA-HQ-OAR-2009-0491-2762.1, p.3]
Response: 
EPA has updated the retrofit control costs originally assumed in the proposal.  EPA believes that these updated costs accurately reflect, on average, current market rates.  For more information on emission control retrofit costs see "Documentation for EPA Base Case v.4.10 using the Integrated Planning Model" August 2010 sect. 5.
With current unemployment rates, sufficient quantities of engineers and skilled craft exist for Transport Rule implantation.  For the extreme case of local shortages of skilled craft (which is not anticipated), this past challenge was overcome by instituting OJT ("On the Job Training") by either qualified  institutional trainers or master / journeymen craftsmen.  Also, this sector's equipment suppliers are also underutilized since 2010.
EPA analysis suggests that the impact on electricity rates is negligible.  See preamble section XII.H.
Organization: Ohio Manufacturers Association (OMA)
Comment: 
Ohio Manufacturers Association (OMA)
EPA underestimates the cost of complying with the new rule by basing its assessments on equipment and capabilities that in some cases are not yet in place. Already subject to unrealistic deadlines for compliance, power generators will also face much higher implementation costs-costs that they will eventually pass on to our members. [EPA-HQ-OAR-2009-0491-2651.1, p. 1]
Response: 
EPA has updated the retrofit control costs originally assumed in the proposal.  EPA believes that these updated costs accurately reflect, on average, current market rates.  For more information on emission control retrofit costs see "Documentation for EPA Base Case v.4.10 using the Integrated Planning Model" August 2010 sect. 5.  Furthermore, EPA believes that compliance with the Transport Rule is feasible by the compliance deadlines.  See section VII.C.2 of the preamble.

V.E.1. State Budgets/Limited Trading

Organization: American Coalition for Clean Coal Electricity (ACCCE)
Comment: 
American Coalition for Clean Coal Electricity (ACCCE)
COMPLIANCE ALTERNATIVES
Under the proposal, the alternatives to deferring the compliance deadlines would not adequately remedy the problem we have discussed above and would, in some cases, create complications. Below we discuss briefly the four most likely remedies if controls could not be installed by an EGU in time to meet the proposed deadlines. [EPA-HQ-OAR-2009-0491-2874.1 p.5]
Retire or Curtail Coal-Fueled Generation
Fuel-switching to natural gas may not be a viable solution for EGUs that are unable to meet the compliance deadlines. First, sufficient natural gas generating capacity may not be available in areas of the country where it is needed. Second, increasing the use of natural gas may require construction of pipeline infrastructure for delivery of the natural gas to specific electric generating facilities. Third, natural gas historically has been subject to considerable price volatility, making this compliance strategy undesirable for many owners of EGUs and for public utility commissions. For example, over the period from 2002 through May 2010, the average monthly price of natural gas for generating electric power ranged from a low of $2.86/ Mcf to a high of $12.41/Mcf.13 Fourth, greater use of natural gas is likely to increase production of shale gas. As EPA is aware, there are a host of environmental concerns associated with the production of shale gas. In the case of new gas-fired generation and major fuel conversion projects, we do not believe that electric utilities could secure the necessary permits and PUC approvals, nor complete construction in time to ensure a smooth transition over the 2012-2014 period. [EPA-HQ-OAR-2009-0491-2874.1 p.6]
[[Please note the commenter's final docket is missing a page of text. Their numbering skips from page 6 to page 8]]
Response: 
See preamble section VII.C.2
Organization: First Energy
Comment: 
First Energy
EPA Assumed Rate Increases
The EPA also assumes that the cost of controls from utilities will all be passed along to the ratepayer. The assumption that utilities will successfully recoup their pollution control expenditures through each state's utility commission is outlandishly optimistic, and entirely inappropriate for merchant generators like FE. Rather, as discussed above, EPA should incorporate more appropriate financial assumptions in the IPM that reflect the merchant market. [EPA-HQ-OAR-2009-0491-2657.1,p.13]
FE also recommends the EPA provide the public with an annual estimated rate increase for the pollution control projects the EPA imposes for each state. Based on the total SO2 & NOx reductions required for each state, the highest reductions would imply the greatest shift in power prices through rate increases for that state. [EPA-HQ-OAR-2009-0491-2657.1,p.13]
Response: 
IPM modeling projects average wholesale costs for energy and capacity consistent with a least-cost compliance strategy.  EPA's simplified analysis of electricity rate impacts uses these wholesale prices to calculate an average retail electricity price at a regional level.  For the purposes of this analysis, each region is assumed to be either regulated cost of service or fully competitive.  EPA believes that this approximation at the regional level reasonably represents average electricity rates.  Estimating impacts at a sub-regional (e.g., state) level would require information regarding specific future decisions of each individual utility commissions, which would be highly speculative given available information.
Organization: Florida Municipal Electric Association (FMEA)
Comment: 
Florida Municipal Electric Association (FMEA)
EPA's Choice of 2008 and 2009 for the Baseline is Inappropriate. EPA has chosen 2008 and 2009 as baseline years for NOx and SO2 emissions, respectively. These two years do not represent normal operating conditions for many of the units regulated under this rulemaking, and therefore, EPA should allow for the selection of a more representative time period. The units regulated by this rulemaking are also regulated under CAIR, many of which had extended outages in 2008 and 2009 to install SO2 and NOx control equipment. Additionally, in 2008 and further into 2009, the U.S. economy plunged into an economic "crisis," and electricity demand dropped significantly. Therefore, 2008 and 2009 are not representative years for many of the units regulated by this rulemaking. FMEA suggests that EPA utilize an approach similar to CAIR, and use an average capacity of the past five years, or some other period that would accurately represent past performance. [EPA-HQ-OAR-2009-0491-2731.1, pp. 7-8]
Response: 
EPA is finalizing an allocation methodology that establishes a historic baseline, using the highest 3 years of 5 years of heat input data for the years 2006 through 2010.  See preamble section VII.D.
Organization: Indiana Energy Association
Comment: 
Indiana Energy Association
e . The Indiana Utility Group believes that financing of both controls and generating units is now far more difficult than the assumptions used by EPA in its CATR analysis. EPA's singularly focused financial assumptions are arbitrary since commercial lending banks and national credit rating agencies will evaluate a company's credit quality and financing rate based on more than just the single CATR happening in the future planning horizon. Also, materials, commodities, labor availability and other costs can exhibit great volatility both temporally and from state to state as demonstrated over the past five years or so. EPA has failed to include these factors in its singularly deterministic CATR analysis and the Indiana Utility Group urges EPA to do so in a reanalysis with multiple scenarios analyzed for the final CATR. [EPA-HQ-OAR-2009-0491-3711 p.3]
Response: 
EPA believes that the financial assumptions utilized in IPM v.4.10_FTransport modeling are appropriate for system-wide modeling.  For further discussion of EPA's financial assumptions, see IPM documentation.
EPA believes that the air pollution control retrofit costs utilized in IPM modeling accurately reflect, on average, the cost of the air pollution control retrofits projected to be built by 2014.  Given that EPA considers materials, commodities, and labor availability in determining a cost methodology, EPA does not agree that alternate analyses with multiple scenarios would be informative.  For more information on the air pollution control retrofit assumptions, including the cost development methodology, please see the IPM documentation.
Organization: Kentucky Chamber of Commerce
Comment: 
Kentucky Chamber of Commerce
Kentucky is proud to be the fifth leading producer of energy in the country  -  driving significant manufacturing in our state including automotive production and aluminum. We feel that EPA grossly underestimates the cost of compliance and overestimates the economic viability of many of the plants that EPA assumes will continue to operate. The EPA proposal is based on data that does not take into account the significant improvements in air quality that have occurred in the last five years because of compliance with CAIR, which is still in effect.[EPA-HQ-OAR-2009-0491-2760.1 p.1] 
We feel strongly the implementation of the transport rule without additional scientific and economic analysis, research and development will result in significant cost increases for business and consumers. In addition, these costs may cause some plants to close or significantly reduce production, threatening electricity reliability and significantly affecting local economies through reduction in payroll taxes and employment numbers. This rule will jeopardize plant expansions for multinational corporations that are currently located in the United States because they will move their operations to countries with less restrictive air quality requirements. Increased energy costs and decreased electric reliability will have a  significant adverse impact on all sectors of the business community and could potentially force Kentucky businesses to relocate out of the country.  [EPA-HQ-OAR-2009-0491-2760.1 p.1]
Response: 
See preamble section V.B.
EPA projects that the benefits of the final rule far outweigh the costs, and impacts on the manufacturing sector are projected to be minimal.  See RIA Chapter 8.
See section V.D.2.g of Response to Comment document.
Organization: Michigan Department of Natural Resources and Environment
Comment: 
Michigan Department of Natural Resources and Environment
Schedules for Scrubber and Selective Catalytic Reduction Installations
The proposed TR described concerns that there may be other regulatory requirements that could potentially interfere with the installation of controls for the TR by increasing demands on the boilermakers' time. In addition, the EPA requested information regarding alternative postcombustion cost-effective technologies that could reduce S02 and/or NOx emissions. [EPA-HQ-OAR-2009-0491-2774.1 p.10]
The DNRE believes that installation of scrubbers along with newer baghouse technologies could address the reductions needed in S02, along with a co-benefit for reductions in mercury. Michigan has a mercury emission reduction requirement that will allow for multipollutant co-benefits when installing equipment to reduce S02 and NOx. The timeline in Michigan's Part 15 mercury rules could be adversely affected by the timing of the TR or contrarily, could adversely impact the timing of the TR. Michigan's mercury requirements for coal-fired EGUs could place higher demands on control installations. The DNRE believes this could raise the cost of controls for Michigan sources that are required to submit a multipollutant strategy two years prior to the compliance deadline of January 1, 2015. [EPA-HQ-OAR-2009-0491-2774.1 p.10]
Coal Switching
The proposal indicated that coal switching (for example, from higher sulfur to lower sulfur containing bituminous coal) was not a factor in determining capital, operational, or maintenance costs for the cost-of-controls analysis. The EPA indicated that most currently installed electrostatic precipitators (ESPs) could handle the switch without allowing an increase in sulfur dioxide emissions, thus not resulting in an increase of costs. [EPA-HQ-OAR-2009-0491-2774.1 p.10]
The DNRE disagrees with the assumption that coal switching will not impact or increase the cost of controls for sources opting to utilize lower sulfur coals. The EPA is incorrect in assuming that the majority of ESPs could handle such a conversion and failed to consider the availability of the lower sulfur coals. The operational age of an ESP can affect the ability to utilize lower sulfur coals; older units could require major reworking for the unit to be able to use these coals. Additionally, the reliability of delivery is a major concern for sources opting to switch coal. In the recent past, delivery of coal was adversely impacted when one of the two rail lines, used to deliver the coal to the Eastern states, was unavailable. This greatly impacts the economic decisions each source must make and could definitely affect the capital and operational costs of using lower sulfur coals in their units. [EPA-HQ-OAR-2009-0491-2774.1 p.10]
Response: 
EPA is aware of Michigan's Part 15 mercury rule, and has included this rule in IPM modeling.  Given that IPM modeling does not project the installation of scrubbers by 2014 in Michigan for compliance with the final Transport Rule, EPA does not believe that either of these two rules will adversely impact the timing of the other.
See section VII.C.2.c of preamble for a discussion of coal switching.
Organization: Midamerican Energy Holdings Company
Comment: 
Midamerican Energy Holdings Company
The Transport Proposal Punishes Early Emission Reductions and Low-Emitters
As discussed above with respect to MidAmerican's Louisa Generating Station, in certain circumstances, facilities that have already reduced emissions may be expected to further reduce emissions. The same can be said about currently underutilized facilities. Two of CalEnergy's natural gas-fueled facilities are subject to the Transport Rule for annual and seasonal NOx reductions3. These facilities are equipped with SCR and are already low-emitting facilities at which additional NOx reductions would be difficult to achieve. The Cordova Energy Center has historically been underutilized and has, under the preferred alternative, been allocated only two NOx allowances.  [EPA-HQ-OAR-2009-0491-2748.1 p.5]
As implementation of the Transport Rule moves forward and additional air quality regulations and the HAPs MACT are in place, it is likely that some smaller, marginal coal-fueled units will elect not to install controls, but, rather, shut down. Such a scenario is likely to result in increased utilization of previously underutilized, existing facilities such as Cordova Energy Center. However, increased utilization of the Cordova facility which, even though well controlled, and having contributed virtually nothing to the transport of emissions causing or contributing to nonattainment, would have to purchase all of its allowances while facilities with higher emissions, which have historically contributed substantially to transported emissions, will have sufficient allocations of allowances under the state budget cap and would not have to purchase any allowances. Sales of those allowances may be constrained by the trading and variability limitations. Increasing the utilization of the Cordova facility to accommodate shutdowns of coal-fueled generation  -  creating a positive environmental result  -  will result in negative economic consequences to the Cordova facility.  [EPA-HQ-OAR-2009-0491-2748.1 p.5]

As EPA has already recognized, implementation of the Transport Rule is likely to have (and has already had) a significant negative impact on the value of Acid Rain SO2 allowances. While the consequences of the devaluation of SO2 allowances may not be as severe in the East, due to the Transport Rule's requirement to meet state emissions budgets within the 10% variability limit, the consequences in the West are likely to be more severe where many Western utilities had previously utilized Acid Rain allowance sales to offset increases in customer rates and/or install additional controls.  [EPA-HQ-OAR-2009-0491-2748.1 p.7]
In addition, as discussed previously herein, while Western utilities are undertaking efforts to install emission controls necessitated by BART determinations and Regional Haze plans, facilities in the East will be competing for the same labor, equipment and associated resources to install controls to comply with the Transport Rule requirements. Nationwide, the demand for skilled labor and equipment is likely to outpace the level necessitated by the 1990 Clean Air Act Amendments, in a much shorter time frame, without the luxury of paying above-market rates to get equipment in place in order to meet the compliance deadlines. This impact is exacerbated given the challenging economic circumstances faced in the U.S. during a time when utility regulators are loathe to continue to increase electricity rates.  [EPA-HQ-OAR-2009-0491-2748.1 p.7]
Response: 
EPA has decided to base allocations made under the FIPs on historic heat input, subject to a maximum allocation limit to any individual unit based on that unit's maximum historic emissions. Further detail on the implementation of this approach, rationale, and response to comments on the allocation method is provided in Preamble Section VII.D. as well as in the Allowance Allocation Final Rule TSD in the docket for this rulemaking.
The allocation methodology does not consider future rulemakings.  As discussed in section III of the Preamble to this rule, EPA will provide full opportunity for notice and comment on each rule as they are proposed and finalized.   EPA will include the final Transport Rule in its regulatory impact analyses of subsequent rulemakings.
Due to the national basis of the allowance market, EPA does not believe that the devaluation of Acid Rain program allowances disproportionately impacts allowance holders in the West.
EPA believes sufficient labor and equipment is available for timely compliance with the rule.  See section V.C.2 of RTC and VII.C.2 of preamble.  Furthermore, EPA projects that the impact of the Transport Rule on retail electricity rates will be negligible.  See section XII.H of preamble.
Organization: Morgan Stanly Capital Group
Comment: 
Morgan Stanly Capital Group
The program will be particularly problematic for independent power plant operators as they cannot recapture their compliance costs from captive ratepayers, like facilities owned and operated by integrated utilities. [EPA-HQ-OAR-2009-0491-2819.1 P.3]
State-specific emissions caps will, at best, greatly complicate the operation of multistate Independent System Operators ("ISOs"), charged with coordinating the most optimal economic dispatch of generation resources. [EPA-HQ-OAR-2009-0491-2819.1 P.3]
Response: 
Independent power producers retain the opportunity to recover costs from the market, which should incorporate the Transport Rule in the market prices for energy and capacity.
EPA is finalizing a program that incorporates interstate trading with assurance provisions, providing additional regulatory flexibility that promotes the power sector's ability to operate as an integrated, interstate system and to provide electric reliability.  As has occurred under prior market-based regulations, EPA believes that generators will incorporate the market price of emitting SO2 and NOX directly into their dispatch bidding; therefore, independent system operators (ISOs) will factor generator bids into dispatch decisions in the same manner under the Transport Rule as they currently do to operate the grid.
Organization: New Orleans City Council
Comment: 
New Orleans City Council
The Council has concerns regarding the Proposed Rule insofar as it may increase the costs of electricity to retail customers by restricting trading and devaluing emissions credits banked under the Clean Air Interstate Rule ("CAIR") and insofar as it fails to consider transmission constraints in its allocation of emissions allowances to specific units. The Council requests that the Agency revise its Proposed Rule to prioritize the minimization of costs while still protecting the environment and attainment of air quality standards. We further request that the Agency make use of all authority available to it, including a broad use of its powers under Section 126 of the Clean Air Act, to implement the lowest-cost regulations which provide for the attainment of those standards. See 42 U.S.C. § 7426. [EPA-HQ-OAR-2009-0491-2719.1 p.2]
At present, the Proposed Rule sets out three options for the new trading regime. As the Council understands the options, they can be roughly described as limited interstate trading with full intrastate trading, no interstate trading but full intrastate trading, and no trading of any kind. The Agency has not proposed any approach that would permit robust interstate trading on a scale similar or near that which had existed under the prior CAIR rules. We have learned that Agency representatives have suggested publicly that the Agency prefers the "limited interstate trading" option. We also understand the Agency has not yet determined what to do with the existing CAIR credits but that the Agency is actively considering devaluing those credits from their face value. [EPA-HQ-OAR-2009-0491-2719.1 p.3]
The Council therefore requests that the Agency promulgate rules that result in the minimal necessary costs to the ratepayer. In particular, the Council is concerned that the cost of any devaluation of existing CAIR credits may be passed on to ratepayers and, to the extent that trading is constricted, that the compliance costs of purchasing or maintaining allowances will also be passed on to ratepayers without any particular improvement in air quality. [EPA-HQ-OAR-2009-0491-2719.1 p.3]
Response: 
EPA projects that the impact of the Transport Rule on retail electricity rates will be negligible.  See section XII.H of preamble.
EPA does not believe that transmission constraints are relevant in the final allocation methodology, which is based on historic heat input, subject to a maximum allocation limit to any individual unit based on that unit's maximum historic emissions.
Acid Rain Program allowances, which were used in the CAIR SO2 program, will remain in the Allowance Tracking System and will continue to be usable in the Acid Rain Program.  Sources will not be able to use CAIR NOx allowances for compliance with the Transport Rule.  Instead, new allocations are being finalized with the final rule.
Organization: Public Utilities Commission of Ohio
Comment: 
Public Utilities Commission of Ohio
The aggressive nature of the proposed rule, including both the required reduction levels and the implementation schedule, will assuredly impact wholesale power costs, putting upward pressure on customer (ratepayer) bills. A 2012-2014 time frame, as proposed in the rules, will cause early retirement or aggressive, accelerated, and costly plant installations, imposing the necessity of quickly implementing flue gas clean-up technology. These retrofits will undoubtedly have a direct ratepayer impact which may not be capable of being 'phased in' due to the accelerated nature of implementation in the rule. Further, due to timing issues and attempts to avoid rate shock, there may be requests for deferrals, further exacerbating cost concerns and negatively impacting future generations of ratepayers. [EPA-HQ-OAR-2009-0491-2855.1 p.9]
The proposed rule, in concert with anticipated rules, will accelerate the retirement of coal fired electric generating plants. The cost of premature retirements will have a direct impact on rates, not only as a result of necessary amortization and other closure costs, but also due to the fact that the lower-cost, locally available power will be removed from the market, making the marginal unit a higher-priced energy source, and driving the need for additional generating capacity. Compounding this concern is the consideration that many of the electric distribution utilities that may be negatively impacted, as discussed above, serve as the Provider of Last Report (POLR) to our native load customers. The current and foreseeable economic environments indicate that Ohio's ratepayers will be hard-pressed to absorb 'rate shock' due to the overly aggressive implementation schedule advanced in the proposed rule. [EPA-HQ-OAR-2009-0491-2855.1 p.10]
EPA has estimated some costs associated with the proposed rule. EPA utilized the Integrated Planning Model in its analysis. This model provides for very high-level analysis, with unfortunately little granularity. The direct cost estimates presented by EPA are installation and operation of advanced pollution control equipment and fuel switching in the amount of $2.8 billion (in 2006). EPA estimates the societal costs (loss of household utility) borne by consumers due to the regulation to be $2.2 billion annually. This estimate is for the EPA preferred approach and grows substantially with the two alternative approaches, which provide less flexibility in meeting the requirements. [EPA-HQ-OAR-2009-0491-2855.1 p.10]
These estimates do not include the capital costs already incurred for compliance with CAIR. The Regulatory Impact Analysis (RIA) for the proposed rule indicates that the pollution controls that were installed by power plants in order to comply with CAIR were not included in the annual societal cost because the Transport Rule did not lead to their installation. In the RIA, EPA states that it "assumes away" any CAIR reductions achieved its is base case analysis.4 In fact, EPA goes on explain that the 2012 base case shows emissions higher than current levels in some states. We disagree with this approach, as both industry and ratepayers previously expended a significant amount of money in order to comply with EPA's regulation (CAIR). We feel that ignoring previous investments in pollution control technology, i.e., those demanded by CAIR, inaccurately represents the relative cost-effectiveness of this rule as a means to meet the NAAQS. [EPA-HQ-OAR-2009-0491-2855.1 p.11]
We also believe that the cost estimates advanced in the Transport Rule may be low for a number of other reasons. We believe that the cost of pollution equipment installations may be underestimated due to difficult construction scenarios relative to the timeline as well as the geographic configurations. Further, an assumption that any plant can simply switch fuels is unsound. Installations/capital investments that will be necessary to enable fuel switching have not been included in the model, or, alternatively, early retirement costs have not been included. Further, as it explains, EPA admits that the model it has used disregards some transaction costs, institutional barriers, and monitoring and reporting costs, in addition to assuming that utilities have "perfect foresight," thereby understating costs. [EPA-HQ-OAR-2009-0491-2855.1 p.11]
In addition to the statistics delineated above, Ohio is a heavily industrialized state. The current economic situation has brought double digit unemployment rates to our state. Given the global competition in the industrial/manufacturing sector, if the rulemaking with the proposed timeframe were adopted and electricity rates are permitted to soar, Ohio will most certainly lose additional industry and jobs, and it will not be alone. [EPA-HQ-OAR-2009-0491-2855.1 p.12]
We also believe that the information used in the Regulatory Impact Analysis (RIA) to justify cost is, unfortunately, counterintuitive. With regard to coal production assumptions, the inputs used would likely result an increase in off-peak prices and with increased coal-fired energy costs, as use of more marginal units of various types becomes necessary. The pricing information used by EPA is additionally counterintuitive because the gas price forecasted by EIA trends upward in 2011. Due to the effects of the 2008 recession, 2010 price impacts should be utilized. [EPA-HQ-OAR-2009-0491-2855.1 p.12]
Further, EPA projects that 1.2 GW of coal-fired capacity will become uneconomic as a result of the Transport Rule. EPA predicts that power sector coal production will decrease, to the degree of 15% less coal production in our region. Gross Domestic Product and consumption levels will be affected nationally.6 Given, however, the current industrial electricity load in our region, as well as the current economic climate, the effects of the proposed rule will be more seriously more impactful in Ohio than other areas. [EPA-HQ-OAR-2009-0491-2855.1 p.12]
Response: 
EPA analysis, which considers pollution control installation as well as retirements, projects that the impact of the Transport Rule on retail electricity rates will be negligible.  See section XII.H of preamble. 
EPA's analysis both properly considered all capital investments made in response to CAIR and properly recognized that, after CAIR is terminated, the emission limitations imposed by CAIR will cease to exist.  See section V.B. of preamble.
EPA has addressed the comment regarding retrofit costs in section V.C.2 of Response to Comments document.
EPA updated IPM modeling to reflect the comment regarding coal switching.  See IPM Documentation.
EPA projects that the benefits of the final rule far outweigh the costs, and impacts on the manufacturing sector are projected to be minimal.  See RIA Chapter 8.
The final RIA reports that, relative to the base case, coal price is projected to decline slightly, related to the small decrease in coal demand.  EPA does not believe that this price behavior is counterintuitive.  Regarding natural gas price, IPM modeling now incorporates a gas supply model which better reflects current gas supply assumptions.  See Chapter 10 of IPM Documentation.

V.F. Transition from the CAIR Cap-and-Trade Programs to Proposed Programs

Organization: Indiana Cast Metals Association (INCMA)
South Carolina Department of Health and Environmental Control 
Comment: 
Indiana Cast Metals Association (INCMA)
The EPA has not determined the effect that recent actions to comply with the Clean Air Interstate Rule (CAIR) will have on ambient and downwind air quality. Because of actions already taken, the Transport Rule may not be necessary. [EPA-HQ-OAR-2009-0491-2178.1, p.1]
Before the EPA imposes new reductions on sulfur dioxide and nitrogen oxide emissions, it should take into account the progress that the nation has made under CAIR. Though the Rule was remanded by the D.C. Circuit Court of Appeals in 2008, it remains in effect and generation companies have necessarily moved ahead with implementation of compliance measures. Before new rules are imposed on a still-weak economy, it makes more sense to determine what improvements in air quality have already occurred. To ignore the improvement the nation has made to date could impose needless substantial costs on our members and region with limited incremental environmental benefit. As we continue to climb out of recession, the last thing that government should do is create additional costs to the economy without substantiated reasons. [EPA-HQ-OAR-2009-0491-2178.1, p.2]
South Carolina Department of Health and Environmental Control 
DHEC is concerned that the unexpected budgets in the proposed Transport Rule result from the EPA's decision to ignore controls that facilities installed to comply with the CAIR. The EPA makes a few arguments in support of this decision.20 First, the EPA contends that it cannot prejudge which states it would include in Transport Rule modeling, and that the CAIR and the proposed Transport Rule affects different states. DHEC does not see this as a reason to not include controls installed to comply with the CAIR in Transport Rule modeling. The EPA could simply list CAIR-based controls for facilities that installed them, and not list CAIR-based controls for facilities that did not install them, a process that would not affect the inclusion or exclusion of states in the Transport Rule. Second, the EPA contends that because the Court ruled that the CAIR is unlawful, it cannot include CAIR-based controls in modeling. The EPA specifically notes: [EPA-HQ-OAR-2009-0491-2677.1 p.8]
If EPA's base case analysis were to ignore this fact and assume that reductions from CAIR would continue indefinitely, areas that are in attainment solely due to controls required by CAIR would again face nonattainment problems because the existing protection from upwind pollution would not be replaced.21 [EPA-HQ-OAR-2009-0491-2677.1 p.9]
DHEC notes two problems with this line of reasoning. First, the CAIR is in effect. The Court would have to revisit its December 28, 2008, decision22 to remand the CAIR for it not to be in effect. The EPA should assume that the CAIR would remain in effect through the 2012 base year in the proposed Transport Rule modeling. Such an assumption seems more likely than the Court vacating the CAIR and eliminating its public health benefits. We are not suggesting that EPA should rely on the CAIR for longer than the Court would allow. Rather, we are simply suggesting that the CAIR's continued existence is likely enough to warrant inclusion in Transport Rule modeling. The EPA further argues that in a world without the CAIR, the NOX Budget Program would govern NOX emissions, thus limiting the amount by which the Transport Rule modeling would overestimate emissions. DHEC questions this assumption. The emissions trading program under the NOX SIP Call led to the emissions reductions in the NOX Budget Program, and the emissions trading program is no longer in place. In the world that the Transport Rule modeling is assuming, states would have to institute command and control emissions limits in thousands of Title V Operating Permits by 2012 to attain the emissions reductions required by the NOX SIP Call. DHEC argues that this is an untenable assumption. A far more likely scenario to include in the modeling is that the Court would agree to a short extension of the remand period. [EPA-HQ-OAR-2009-0491-2677.1 p.9]
The EPA's final contention in support of its decision to not include CAIR-based controls in the Transport Rule modeling is that in a world without the CAIR, utilities would comply with the less stringent Acid Rain Program, thus limiting the Transport Rule's overestimation of emissions. This contention assumes that the Acid Rain Program is always more stringent than the Transport Rule and this is not the case in South Carolina. Our sulfur dioxide ("SO2") budget under the Acid Rain Program for 2010 and later is 111,342 tons, and our proposed Transport Rule SO2 budget is a less stringent 116,483 tons. [EPA-HQ-OAR-2009-0491-2677.1 p.9] 
DHEC contends that the EPA's modeling should recognize the limits and controls put in place to meet the requirement of the CAIR because utilities are not operating in a world without the CAIR. South Carolina's utilities, and their rate payers, committed considerable resources to installing and operating controls on several coal-fired units to meet the requirements of the CAIR. DHEC predicts that its major utilities will continue to run controls installed to comply with the CAIR, and the EPA's Transport Rule modeling should take into account the operation  of these controls. The EPA also omits controls installed to comply with the NOX SIP Call.23 By making these changes, the EPA can ensure that it develops the Transport Rule based on the best available science. [EPA-HQ-OAR-2009-0491-2677.1 p.10]
Response: 
Preamble section V.B. explains why CAIR reductions are not included in the base case.
Organization: Massachusetts Department of Environmental Protection
Comment: 
Massachusetts Department of Environmental Protection
The transition from CAIR to the Transport Rule will raise a number of reporting, compliance and enforcement issues. EPA notes that certain EGUs that currently monitor and report NOx in the ozone season but are not already reporting annually under in EPA's Acid Rain Program would need to monitor and report NOx and S02 on an annual basis under the proposed Transport Rule. Presumably the majority of these units can simply amend existing Part 75 monitoring plans. It would be helpful for EPA to clarify the details of, and deadline for, these amendments. We recommend a deadline of January 1, 2011 to provide a year's worth of data to ensure all monitoring, recordkeeping and reporting issues have been addressed at these facilities prior to the start of the initial Transport Rule compliance period.  [EPA-HQ-OAR-2009-0491-2787.2 p.7]
Response: 
Please see section VII. H of the preamble.
Organization: Northern Indiana Public Service Company (NIPSCO)
Comment: 
Northern Indiana Public Service Company (NIPSCO)
Should EPA implement NIPSCO's recommended approach to keep CAIR in place for the entire CAIR Phase I period and begin the Transport Rule in 2015, EPA could as an alternate allow states a limited time period in which to develop state-specific rules to implement the Federal Transport Rule. If EPA does not extend CAIR Phase I and rather agrees with a heat input based allocation, due to concerns about the robustness of the trading program it may be necessary to include a transition period or transition provisions during the initial years of the program to ensure all covered sources have a path to achieve compliance. Consistent with the proposed Transport Rule, the objective of the transition period would be to operate existing and planned pollution controls to ultimately meet the state emission budgets. [EPA-HQ-OAR-2009-0491-2747.1 p.5]
Again assuming that EPA proceeds with its proposed FIP approach, as one component of the transition process, NIPSCO recommends that EPA consider use of banked NOx allowances from the CAIR. While NIPSCO recognizes that the Transport Rule is completely replacing the CAIR, the CAIR, nevertheless, has been the applicable regional program requiring reductions of NOx and S02 emissions for the past three years. Regardless of the court's decision in North Carolina, CAIR allowances have been allocated, traded, and surrendered during those years. EPA itself acknowledges that program produced reductions in regionwide NOx and S02 levels that have benefitted nonattainment and maintenance areas in the region. Therefore, to aid in the transition from the CAIR program to the Transport Rule program, NIPSCO suggests that EPA provide for the banking forward of CAIR allowances into the Transport Rule program at full value to allow sources the time to comply with the reduced caps and the addition of variability limits in 2014. [EPA-HQ-OAR-2009-0491-2747.1 p.6]

 
NIPSCO firmly believes that the emission allowance allocation conflicts mentioned above are the result of the premature initiation of the Transport Rule. We believe it would be preferable for CAIR to survive through the entire CAIR Phase I period (until 2015). This approach provides extra time for States to develop their SIPs, allows for better synchronization with the Utility MACT rule, combines the Transport Rule with Transport Rule II for better coordination of the implementation of the revised ozone NAAQS and also avoids the conflicts in the emission allowance allocation process discussed in the preceding paragraphs. [EPA-HQ-OAR-2009-0491-2747.1 p.7]
Response: 
In response to the North Carolina decision, EPA is finalizing a replacement to the Clean Air Interstate Rule as quickly as possible.  Therefore, CAIR will not remain in place for the entire CAIR Phase I period.  EPA has the authority and legal obligation to promulgate the FIPs in this rule.  (See discussion in the preamble to the final rule, the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs Final Rule TSD", and responses to comments in this document, particularly in Section III.A.)
EPA has evaluated the feasibility of the compliance dates in the rule--a discussion can be found in the preamble to the final rule, Section VI.  The final Transport Rule does not allow the banking forward of CAIR allowances--a discussion can be found in the preamble to the final rule, Section IX.
The final allocation methodology does rely on heat input and is described in Section VII of the preamble to the final rule.  Additionally, there are provisions for states to submit SIPs for state allocation of allowances which will allow further specific consideration of other requirements specific to sources in a particular state.  This discussion can be found in the preamble to the final rule, section X.
Organization: Tennessee Valley Authority (TVA)
Comment: 
Tennessee Valley Authority (TVA)
B. Issue: In developing CAIR, EPA set forth its general view of the approach it expected to take in responding to any section 126 petition that might be submitted relying on the same record as CAIR. Under that approach, so long as an upwind state remained on track to comply with CAIR, EPA would defer making the Section 126 findings. In the proposed Transport Rule, EPA does not discuss how petitions under Section 126 will be handled. [EPA-HQ-OAR-2009-0491-2782.1, p. 16]
TVA Comment: Similar to what it did in promulgating CAIR, EPA should set forth a position in the rulemaking record for the Transport Rule that as long as an upwind state remains on track to comply with the Transport Rule, EPA will defer making Section 126 findings. The reason for deferring to make a Section 126 finding would be that the affected State's SIP would fulfill the Section 110(a)(2)(D) requirements, so that there would no longer be any basis for the Section 126 finding with respect to that State. By clearly enunciating its position in this regard, EPA harmonizes the requirements of the Transport Rule and Section 126, provides greater certainty to the regulated community, and avoids the unnecessary expenditure of agency resources in reviewing premature Section 126 petitions. [EPA-HQ-OAR-2009-0491-2782.1, p. 16]
Response: 
EPA does not have an obligation to make a determination under CAA 126 in this rulemaking.  EPA is not making a determination with regard to CAA 126 in this rulemaking.

V.F.1. Sunsetting of CAIR, CAIR SIPs, and CAIR FIPs

Organization: Allegheny Energy
Comment: 
Allegheny Energy
AE believes the existing allowance trading scheme, as established in the Acid Rain Program (ARP) and NOx State Implementation Plan Call (NOx SIP Call) and carried through into CAIR, is effective at achieving EPA's goals as evidenced by the significant reductions actually realized by the electric generating industry since the late 1990's. AE recommends that EPA continue the established trading scheme, but at minimum supports the EPA preferred option retaining at least some limited interstate trading and unlimited intrastate trading. [EPA-HQ-OAR-2009-0491-2605.1, pp.2-3]
Response: 
EPA is finalizing the preferred approach from the proposal.  See Section VII. of the preamble for further details.
Organization: Attorney General of North Carolina
Comment: 
Attorney General of North Carolina
Upon EPA's findings of failure to submit, States, including North Carolina, submitted implementation plans to comply with the interstate transport provisions. North Carolina submitted its CAIR SIP, regarding the 1997 ozone and PM2.5 standards, which was approved. Approval & Promulgation of Air Quality Implementation Plans; N.C.; Clean Air Interstate Rule, 74 Fed. Reg. 62,496 (2009). North Carolina later certified that its existing SIP complied with its requirements under §110(a)(2)(D)(i)(I) regarding the 2006 daily PM2.5 standard as well. Ltr. from B.K. Overcash, Dir., N.C. Div. Air Quality, to A.S. Meiburg, Acting Reg'l Adm'r, EPA Region 4 (Sept. 21, 2009). EPA is now threatening to deny North Carolina's SIP certification on the basis of a guidance memorandum that was issued four days after North Carolina submitted the certification  -  a memorandum that provided absolutely no substantive guidance regarding how to determine whether a State had appropriately evaluated its regulatory structure against the requirements of §110(a)(2)(D)(i)(I). See E-Mail from Joel Huey, EPA Region 4, to Heather Hildebrandt, N.C. Div. Air Quality (Aug. 27, 2010).
It is imperative that EPA reaffirm and work to ensure that, under the Clean Air Act, "air pollution control at its source is the primary responsibility of States and local governments[.]" 42 U.S.C. §7401(a)(3). The Transport FIP rulemaking puts the cart before the horse. Without providing the States any real guidance regarding how to meet their obligations and threatening to deny submissions made in good faith based on existing practices, EPA now plans to impose a one-size-fits all solution before any State has had any real opportunity to address the problem first. This undermines one of Congress' underlying principles of the Clean Air Act.
As indicated, North Carolina respects the need for swift action in this area. The State brought a petition for judicial review of CAIR in part to force EPA to expedite controls to address interstate transport. The hole in which EPA now finds itself is due in large measure to its own promulgation of a "fundamentally flawed" rule, North Carolina, 531 F.3d at 929, and is not the fault of States such as North Carolina that acted on their own to reduce emissions from EGUs significantly even before CAIR was proposed. See N.C. Gen. Stat. §143-215.107D. Accordingly, EPA should commit to prioritizing review of State SIP submittals.
The simplest and most defensible way to effectuate the mandate in §110(a)(2)(D)(i)(I) is for EPA to determine each State's significant contribution level and then allow the State to determine how to reduce its emissions to a level below that. For example, each State should be permitted to decide for itself whether to establish a new unit set-aside and, if so, what the magnitude of that set-aside should be. Again, EPA's ability to promote State-specific solutions before imposing a FIP is hamstrung by the delays engendered by its previous, unlawful attempt to address this issue. Nevertheless, EPA still has not even informed States what their budgets are. First, the State budgets in the Transport FIP are only proposals. Second, it is entirely unclear how a State could develop a compliant SIP. One can infer that EPA would require each State to comply with its State budget without the variability bonus, which is the approach EPA took in the intrastate trading option. However, EPA also claims that variability is "inherent" and "unavoidable . . . ." 75 Fed. Reg. at 45,292/1. If that is the case, then the intrastate trading option may not be an appropriate yardstick for a State developing its own SIP because it fails to take variability into account. A State electing to adopt its own SIP instead of an EPA-run interstate trading program (which presumably EPA will offer as an option to replace the FIP) could never know whether it is forcing its sources to over-control or under-control. A downwind State would likewise never know if the upwind States have done enough.
EPA must promptly develop clear, cogent, and rational guidance for States to develop their own SIPs so States are not forced to adopt EPA's FIP primarily due to EPA's failure in the first instance to promulgate a lawful rule and failure to issue timely and informative guidance. EPA then should commit to expediting review of State SIP submittals to give States every opportunity to implement their own programs before the FIP becomes effective.
Response: 
See preamble section IV, responses to other comments primarily in section III.A. of this document and the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs Final Rule TSD."  Additionally, preamble section X discusses state Transport Rule SIP requirements.
Organization: Kentucky Chamber of Commerce
Comment: 
Kentucky Chamber of Commerce
Companies have already taken steps to comply with CAIR and that makes the Transport Rule premature. The EPA should determine the full impact of CAIR compliance before proposing new rules.  [EPA-HQ-OAR-2009-0491-2760.1 p.2]
Response: 
EPA must replace CAIR in accordance with the North Carolina decision.  Because the Transport Rule will fully replace CAIR, there will be no requirement to meet CAIR provisions when this rule becomes final.  Actions taken under CAIR by sources were carefully considered and are discussed in Section V.B. of the preamble to the final rule.
Organization: National Rural Electric Cooperative Association (NRECA)
Comment: 
National Rural Electric Cooperative Association (NRECA)
The unreasonable and unnecessary proposed compliance deadlines in the proposed CATR present further complications for EPA as the agency attempts to circumnavigate its responsibilities under the CAA Section 110 that clearly requires states be given opportunities to implement Section 110 obligations through the SIP process. NRECA reiterates an earlier comment that CAIR need not be eliminated by the 2012 date certain. Nothing in the North Carolina decisions suggests otherwise. If CAIR would remain in effect until a date after the proposed 2012 deadline, air quality in the proposed CATR 32 state region would continue to improve under its mandates [EPA-HQ-OAR-2009-0491-2723.1, pp.9-10]
The proposal itself recognizes that under Section 110(a)(2) states have three years to submit SIPs to address interstate significant contribution to NAAQS nonattainment. In EPA's view, state SIPs under CAIR do not meet state SIP Section 110 requirements because CAIR was struck down by the court's decision in 2008, even though any state that submitted a SIP approvable under CAIR was doing exactly what EPA dictated it needed to do to comply with the law. In this type of circumstance where EPA itself fails in its obligation to fulfill its CAA responsibility, case law dictates the time period for states to submit SIPs should be extended. EPA has not addressed why it does not intend to restart the clock on time periods for SIP submissions with CATR finalization when the agency itself is responsible for SIP failures. Rational rulemaking dictates that it does so. [EPA-HQ-OAR-2009-0491-2723.1, p.9]
EPA recognizes that under the proposed CATR timelines, states have virtually no time to follow SIP procedures to submit an approvable SIP, but nonetheless contends states rights under the CAA are not legally infringed because a state can submit a SIP that would replace the CATR FIP. Clearly, an after-the-fact SIP is not what the CAA contemplates, and EPA has cited no case law to support this view. Section 110(k)(5) clearly requires states be given a reasonable time to submit SIP revisions. Clearly, a reasonable time cannot be virtually no time. To comply with the CAA, EPA must allow states a reasonable time to meet Section 110(a)(2)(D)(i) mandates. Accordingly, CATR proposal should be re-proposed and amended so as to allow states the option through the SIP process to choose methods for allowance allocations based on state emissions budgets necessary to meet state requirements to address interstate transport. [EPA-HQ-OAR-2009-0491-2723.1, pp.9-10]
Response: 
A discussion of the rationale for compliance deadlines in the Transport Rule can be found in Section IV of the preamble to the final Transport Rule.  As discussed elsewhere in response to a similar comment, EPA has an obligation to replace CAIR expeditiously.  Also addressed in other comments is the justification for not extending SIP deadlines under the provisions of CAA 110(a)(2)(D)(i)(I).  Section X of the preamble to the final rule has specific information on how a state can replace FIP requirements with a SIP at any time in the future.
Organization: NRG Energy
Comment: 
NRG Energy
Excess CAIR allowances should be transitioned to TR markets NRG acknowledges EPA's critical need to maintain the integrity of allowances and believes this can be achieved while transitioning excess CAIR NOx allowances into the TR markets. The turmoil in the CAIR emission markets reflects the uncertainty regarding those allowances as well as the expectation that excess allowances will be worthless in 2012. In 2012, the regulated utilities will face uncertain, nascent markets for both SO2 and NOx. Clearly, Title IV SO2 allowances cannot be used in CATR, but EPA can bring some market stability by transitioning CAIR NOx allowances. An issue remains because these allowances were allocated based on fuel factors, which the District Court rejected in its decision. EPA could provide for continuity in allowance markets and recognize the sunk investment in the CAIR by applying surrender ratios to banked allowances similar to the flow control factor used in the NOx SIP program. NRG suggests that the use of an adjustment factor for CAIR NOx allowances might help reduce the risk of subsequent litigation and stabilize emission markets. [EPA-HQ-OAR-2009-0491-2749.1, p. 4]
Response: 
The final rule does not allow CAIR NOx allowances or Title IV allowances to be used in Transport Rule.  EPA feels that the North Carolina ruling does not allow Title IV allowances cannot be used in the Transport Rule.  EPA carefully considered whether to allow CAIR NOx allowances to be recognized in the final transport rule.  As discussed in preamble Section IX, there are several reasons EPA decided that there would be no carryover of CAIR allowances.  EPA specifically examined whether surrender ratios could be used.  In order to use surrender ratios and allow a portion of the Transport Rule allocations to recognize unused CAIR allowances, a portion of each state budget would not be allocated until after CAIR true up (Spring 2012), which would be highly disruptive to the start up of Transport Rule markets (scheduled now to start in September 2011 when FIP allocations are recorded).  Additionally, large amounts of CAIR allowances are held in general accounts which are not associated with any state.  Therefore, it would be impossible to determine the appropriate amount of allowances to allocate based on a CAIR surrender ratio in any given state.
Organization: PowerSouth Energy Cooperative
Comment: 
PowerSouth Energy Cooperative
State regulatory participation is necessary for successful implementation of any CAIR replacement rule.  EPA has unfairly and unnecessarily usurped the State of Alabama's role in assigning unit allocations.  Alabama and other states have successfully administered state emissions budgets for the NOx State Implementation Plan (SIP) Call and the Clean Air Interstate Rule (CAIR) program and should be allowed to set and administer unit allocations based on the state budget.  PowerSouth sees no compelling reason to circumvent the normal SIP process to rush to implement this Proposal.  CAIR should remain in effect to allow the typical rulemaking and SIP Call process to occur.  EPA should relinquish control of program implementation back to the states, including changing the compliance schedule such that any replacement rule is implemented no sooner than 2015. [EPA-HQ-OAR-2009-0491-2693.1,p.3]
Response: 
EPA has the authority and legal obligation to promulgate al the FIPs in the final rule as described in the preamble to the final rule, the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs Final Rule TSD", and responses to other comments, particularly in Section III. A. of this document.  The timing of the start of the Transport Rule is explained in Section VII C of the preamble to the final rule.
States have the option to replace FIP allocations with State-determined SIP-based allocations beginning as soon as 2013.  A description of these provisions is found in preamble Section X.
Organization: State of Missouri Department of Natural Resources
Comment: 
State of Missouri Department of Natural Resources
Due to the modeling analysis used by EPA to determine significant contribution, Missouri and some other states were not included as states that negatively affect nonattainment or interfere with maintenance in downwind states for the 1997 8-hour ozone standard, and therefore were not listed as ozone states under the Transport Rule. Once the final rule is promulgated, Missouri will no longer have any federal Nitrogen Oxide (NOX) ozone season trading program. The state's ability to meet its NOX State Implementation Plan (SIP) Call budget obligations will be limited, which creates backsliding and emission budget issues not only for Missouri, but also for areas downwind that depend on the budgets that Missouri set through the NOx SIP Call. [EPA-HQ-OAR-2009-0491-3806, p.1]
As you may know, the eastern one-third of Missouri was included in the NOX SIP Call. In addition, when the Clean Air Interstate Rule (CAIR) was promulgated, the entire state of Missouri was included in the ozone season NOX CAIR rule. Currently in Missouri's SIP, the ozone season CAIR rule reverts to the NOx SIP Call ozone season rule if CAIR is voided by federal code, as is proposed in this Federal Register notice . Therefore, the amendments proposed in this Federal Register notice will leave Missouri without a federal ozone season NOx trading program. Missouri and downwind states rely on federal NOX ozone season budgets to attain and maintain the 1997 8-hour ozone standard. [EPA-HQ-OAR-2009-0491-3806, p.1]
The ozone season limits, for which Missouri sources are accountable in the NOx SIP Call, were used in EPA's determination that Missouri does not significantly contribute, to downwind areas in nonattainment or maintenance of the 1997 ozone standard. It should be understood that these limits may no longer be enforceable, when the final Transport Rule is promulgated. [EPA-HQ-OAR-2009-0491-3806, p.2]
Missouri is currently in the process of redesignating the St. Louis area to attainment under the 1997 8-hour ozone standard. Without federally enforceable limits set by a NOx ozone season trading program, whether that be with the NOx SIP Call, CAIR, or the Transport Rule; the state's efforts to redesignate the St. Louis area to attainment would be negatively impacted. [EPA-HQ-OAR-2009-0491-3806, p.2]
Response: 
EPA recognizes that a number of states relied on CAIR or modifications to CAIR to meet the requirements of the NOx SIP Call for large EGUs and large non-EGUs.  Section IX of the preamble to the final Transport Rule contains a discussion of the impacts to NOx SIP Call requirements.  EPA will assist individual states to determine the SIP revisions necessary for continued compliance with the NOx SIP Call.  Modeling conducted for the final rule changes the states for which this is an issue.  For instance, the final modeling shows that Missouri is significantly interfering with nonattainment or maintenance with regard to the 1997 ozone NAAQS.  EPA is addressing this change in a Supplemental Notice of Proposed Rulemaking to the Transport Rule.
Organization: Tennessee Department of Environment and Conservation, Division of Air Pollution Control
Comment: 
Tennessee Department of Environment and Conservation, Division of Air Pollution Control
Comment on CAIR SIP Revisions: It appears that EPA will not require SIP revisions to resolve issues with offsets and automatic penalties for a source that failed to hold sufficient allowances to cover its 2011 control period emissions under CAIR. Since Tennessee used the limited SIP approach to implement CAIR, it also appears that a SIP revision would not be required to sunset the CAIR provisions after December 31, 2011. Please confirm if this is correct. [EPA-HQ-OAR-2009-0491-0553.1, p.5]
Response: 
This is correct.
Organization: Texas Commission on Environmental Quality
Comment: 
Texas Commission on Environmental Quality
The EPA should provide guidance for states whose participation in the Transport Rule program is fundamentally different from their participation in the CAIR program. Texas was previously included only in the CAIR annual S02 and NOx trading program (for interstate pollution from PM2.S), but is now proposed for inclusion in the Transport Rule only for the ozone-season NOx trading program. A number of other states' inclusion has changed from that required in the CAlR. To the extent that states may have relied upon CAIR to address section 110(a)(2)(D)(i)(I) obligations, or to fulfill certain other SIP obligations, the EPA should provide specific guidance, in a timely manner, to address any potentially outstanding SIP obligations. [EPA-HQ-OAR-2009-0491-2857.2, p.16]
Response: 
EPA discusses in the preamble to this final rule several aspects of the impacts of the North Carolina decision on CAIR SIPs and other SIPs that rely on CAIR reductions.  In Section IX, information on the transition from CAIR to the Transport Rule is discussed.  In that same section, there is also information on other SIPs that may have relied on CAIR reductions.  As explained in Section IV, CAIR SIP approvals are being rescinded.  If a state has an approved SIP that fully replaces the CAIR FIP, EPA is taking action to rescind the approval of the SIP.  If the state has an approved SIP that modifies the requirements of the CAIR FIP, also called an abbreviated CAIR SIP, the state is subject to a CAIR FIP.  CAIR FIPs are fully replaced by the Transport Rule.  EPA assist individual states as they work to identify, develop and submit necessary SIP revisions resulting from the replacement of CAIR.
Organization: West Virginia Department of Environmental Protection
Comment: 
West Virginia Department of Environmental Protection
WVDAQ will most likely issue emergency rules in December 2011 to eliminate state CAIR provisions in 2012. However, the CAIR ozone season rule 45CSR40, may continue with a limited scope that carries forth seasonal reduction requirements for NOx SIP Call Phase II sources such as internal combustion engines and cement kilns. West Virginia would not be able to submit a full SIP revision eliminating CAIR until Summer 2013. [EPA-HQ-OAR-2009-0491-2790.1, p. 3]
Response: 
In the final rule, EPA does not require States to make modifications to their CAIR rules.  (See preamble, Section IX. A.)

V.F.2. [Reserved]

V.F.3. Applicability, CAIR Opt-ins and NOx SIP Call Units

Organization: Council of Industrial Boiler Owners (CIBO)
Comment: 
Council of Industrial Boiler Owners (CIBO)
In the Preamble (75 FR 45338) EPA incorrectly claims that, as a group, non-EGU boilers did not make any emissions reductions as a result of the NOx Budget Trading program. This is simply untrue and EPA should correct the record on this point. EPA included non- EGUs as covered sources in the NOx Budget Trading Program. As covered sources, non- EGUs were required to reduce emissions by 60% from their 1995 baseline emission rate. Compliance with the tighter standards was achieved through either installation of emissions controls or the purchase of allowances. Some CIBO members' emissions were reduced through NOx RACT requirements as early as 1994.[EPA-HQ-OAR-2009-0491-2751.1, p.7]
CIBO has members with plants that are directly regulated by this Proposed Rule as EGUs or as EGU/Cogenerators. Therefore, it is important to accurately reflect the emissions reductions achieved by these sources. Since these NOx Budget Plan boilers are still part of the NOx SIP Call, they will be stranded with a non-existent or severely reduced allowance market when EPA orphans them from the related sources under the Transport Rule. EPA has not fully evaluated the impact of this rule on the existing trading programs, nor has the short comment period permitted an adequate analysis by CIBO members of such impacts. [EPA-HQ-OAR-2009-0491-2751.1 p. 7-8]
Response: 
EPA carefully considered the comments on this topic.  While EPA does recognize that some of the units in the non-EGU group have made reductions, the commenter has provided no information on particular plants which EPA could use to compare to the information available to the Agency.  EPA is not allowing expansion of the Transport Rule ozone season program to include non electric generating units that were part of the NOx Budget Program because as a group the non-EGUs did not reduce emissions as a result of the NOx SIP Call or CAIR.  In order to meet the requirements of the NOx SIP Call, a state must address the emissions as a group (or identify other sources from which to achieve equivalent reductions).  Because the group of non-EGU units emits far less than the amount of allowances that could be added to the program and less than the group has ever emitted, no reductions have been achieved.  Allowing this group of non-EGU units to trade with TR-affected units could jeopardize a state's ability to show that it has eliminated its significant contribution to nonattainment or interference with maintenance.  
See also preamble section IX, the TSD regarding non-EGUs that was developed for the proposed rule, and responses to other comments primarily in this section.
Organization: International Paper
Comment: 
International Paper
International Paper was alerted to the fact that its units were listed on Transport Rule Allocation tables associated with the proposed Transport rule. International Paper operates its Augusta Mill under Part 70 Permit 2631-245-0006-V-02-0; Facility AIRS Number 04-13-245-00006 [EPA-HQ-OAR-2009-0491-2784.1 p.1]
Specifically, International Paper-Augusta Mill's Kraft pulping liquor recovery furnaces, RB2A No.2 Recovery Boiler and RB3A No.3 Recovery Boiler, were listed as affected units (ORIS 54358) in Georgia. These units, prior to EPA revising the cogeneration definition on October 19, 2007 72FR59,190, where affected facilities under the CAIR rule. However, based on EPA's current definition RB2A and RB3A are cogeneration units and not subject to CAIR or the Transport rule. [EPA-HQ-OAR-2009-0491-2784.1 p.1]
Augusta Mill's Recovery Boilers meet the definition of cogeneration units with useful power efficiencies consistently in the 100% to 10,000 % range for the RB2 and RB3. The high power efficiencies are a result of the boilers primarily being biomass burners. [EPA-HQ-OAR-2009-0491-2784.1 p.1]
Recovery Boilers at Augusta are not subject to the various sections of the Transport Rule as outlined in the proposed applicability sections (§§ 97.404 and 97.405, 97.504 and 97.505, 97.604 and 97.605, and 97.704 and 97.705-Applicability). Specifically, these units are not applicable unit because they qualify as exempt cogeneration units as outlined in, for example, 97.404(b)(1 )(i). [EPA-HQ-OAR-2009-0491-2784.1 p.1]
We support EPA's applicability definitions. However, please remove the recovery boilers from the applicable units table.' If you would like to contact us, feel free to call or write Jeremy.Pearson@ipaper.com or 706-796-5363. Thank you. [EPA-HQ-OAR-2009-0491-2784.1 p.1]
[[These comments are also posted under section V.D.2.b.i.]]
Response: 
See Section V.D.2.b.i. of this document for the response to this comment.
Organization: Massachusetts Department of Environmental Protection
Comment: 
Massachusetts Department of Environmental Protection
MassDEP recommends that EPA provide states that have been in the CAIR ozone-season control program with the ability to opt-in to the Transport Rule ozone season trading program. We believe that granting states this flexibility will insure continuity and consistency in the application of these programs for both states and their facilities.
Under the proposed Transport Rule, EPA concludes that emissions from Massachusetts sources have an impact on downwind states only with respect to PM2.5. Consequently, Massachusetts will be in the annual program for NOx and S02, but not the ozone season NOx program. (Under CAIR, Massachusetts was determined to contribute to ozone nonattainment, but not PM, so was only in the ozone season CAIR program.) This switch of Massachusetts from the CAIR ozone season program, which EPA proposes to terminate in 2011, to the Transport Rule annual program, starting in 2012, is understandable given that the Transport Rule analysis is based on a number of updated considerations as compared to the CAIR analysis. However, with the issuance of a second Transport Rule to address the anticipated 2010 ozone NAAQS, Massachusetts may be brought back into an ozone season control program. This creates considerable uncertainty for Massachusetts and, we expect, for other states in this situation.
We believe that providing states that have been in the CAIR ozone-season control program with the ability to opt-in to the Transport Rule ozone season trading program will address this issue of dropping in-and-out of CAIR versus Transport Rule trading programs. We urge EPA to provide this flexibility to states in the final Transport Rule FIP and to consider this, and other options, to keep states and sources from dropping in and out of trading programs given the anticipated promulgation of future transport rules and SIP obligations based on trading program requirements.
Exclusion of Certain Massachusetts CAIR Units from Transport Rule
We recommend that EPA allow Massachusetts and other states that have included smaller EGUs in their CAIR trading programs to opt them into the Transport Rule. Under CAIR, fourteen states that were part of the NOx SIP Call were allowed to include in their CAIR ozone season program additional units not covered by EPA's CAIR program but included within the states' NOx Budget Trading Program. This allowed these states to continue to meet the state's State Implementation Plan reduction requirements for these units. 13 As one of these fourteen states, Massachusetts brought into its CAIR program units that burn more than 50% fossil fuel and have a maximum heat input capacity of 250 million British thermal units (MmBtu) or more, or serve a generator with a nameplate capacity of 15 MW or more, whether or not they produce electricity for sale. The proposed Transport Rule does not apply to these units and does not include provisions to allow states to include them. EPA notes in the Transport Rule preamble that states remain obligated for NOx reductions from all EGU and non-EGU units included in the CAIR NOx Ozone Season program. 14 EPA has asked for comment on this approach.
In Massachusetts, the Transport Rule NOx and S02 annual programs are applicable to 64 EGUs as compared to 89 EGUs and non-EGUs under the Massachusetts CAIR regulation, (310 CMR 7.32). Exclusion of these smaller than 25 MWe EGUs and non-EGUs sources from the Transport Rule program will require alternative regulatory approaches to maintain the ozone season NOx reductions from the units that are no longer covered.
For the non-EGUs, we anticipate that EPA will address emissions from this category in the next Transport Rule so that states, like Massachusetts, that have included reductions from these units in their ozone attainment State Implementation Plan, will be able to maintain reductions from these units. However, because EPA has not indicated that it plans to require future reductions from EGUs smaller than the 25 MWe, we recommend that in the final FIP EPA allow Massachusetts and other states that have included these units in their CAIR programs to opt them into the Transport Rule, rather than having the units subject to new Reasonably Available Control Measure (RACT) regulations or single-source State Implementation Plan (SIP) revisions. If EP A brings Massachusetts into the final Transport Rule ozone season program, as we recommend, these smaller-than-25 MWe EGUs should be included in the ozone season program. If EPA leaves Massachusetts in the NOx annual trading program only, we recommend that these units be included in the annual program.   [EPA-HQ-OAR-2009-0491-2787.2 p.6-7]
Response: 
The final rule does not allow a state that has not been identified as a state that significantly contributes to nonattainment or interferes with maintenance in other state to participate in the Transport Rule trading programs.  EPA believes that allowing non-affected states to trade with affected states, elimination of affected states' significant contribution could be compromised.  The additional allowances would be surplus to the budgets that have been determined under this final rule.  EPA cannot predetermine what requirements will be needed to eliminate significant contribution under a revised ozone standard.
Regarding smaller EGUs, as explained in preamble section IX.B., the final rule provides states an option to expand the general applicability provisions of the Transport Rule ozone-season NOX trading program to cover small EGUs, but not other units in the NOX SIP Call.  Specifically, consistent with the comments, EPA determined that it is appropriate to allow states to expand the applicability of the Transport Rule Ozone-Season NOX trading program to include units serving a generator with a nameplate capacity equal to or greater than 15 MWe producing electricity for sale.  This will allow states with NOXSIP Call obligations to meet those requirements with respect to these small EGUs.  These units can be brought into the program through abbreviated or full Transport Rule SIPs.  However, if a state chooses to expand the general applicability provisions, the state Transport Rule Ozone-Season NOX budget cannot be increased.  This option is not available to Massachusetts because Massachusetts is not subject to the requirements of the Transport Rule.
Organization: MeadWestvaco Corporation (MWV)
Comment: 
MeadWestvaco Corporation (MWV)
While we support EPA's decision to exempt industrial boilers from further controls, we believe that EPA does not adequately address the interaction of non-EGU sources with respect to the NOx SIP Call and the Clean Air Interstate Rule (CAIR). We believe that EPA should extend the allowances afforded to these sources under the existing programs and allow those sources to continue to be included in whatever trading mechanisms are finalized. In the preamble EPA incorrectly claims that, as a group, non-EGU boilers did not make any emissions reductions as a result of the NOx SIP Call. MWV spent several million dollars to comply with these requirements. EPA correctly recognized non-EGUs in the CAIR rule in a way that allowed these sources to be rolled into that program without additional controls and allowed them to continue to participate in the trading program authorized by CAIR. Under the proposed Transport Rule, EPA would require additional rulemaking by forcing states to institute SIP revisions to account for non-EGUs. We believe it would be more efficient and consistent for EPA to adopt its previous position under CAIR with respect to these units, allowing non-EGU allowances to roll into the new program. [EPA-HQ-OAR-2009-0491-2650.1, pp. 2-3]
Response: 
EPA carefully considered the comments on this topic.  EPA is not allowing expansion of the Transport Rule ozone season program to include non electric generating units that were part of the NOx Budget Program because as a group the non-EGUs did not reduce emissions as a result of the NOx SIP Call or CAIR.  EPA does recognize that some of the units in the non-EGU group have made reductions.  In order to meet the requirements of the NOx SIP Call, a state must address the emissions as a group (or identify other sources from which to achieve equivalent reductions).  Because the group of non-EGU units emits far less than the amount of allowances that could be added to the program and less than the group has ever emitted, no reductions have been achieved.  Allowing this group of non-EGU units to trade with TR-affected units could jeopardize a state's ability to show that it has eliminated its significant contribution to nonattainment or interference with maintenance.  Additional information can be found in preamble section IX.
Organization: MIT Central Utility Plant
Comment: 
MIT Central Utility Plant
Comment #2: Transition Process for Electric Generating Units Subject to CAIR but not CATR
As mentioned above, the MIT·CUP cogeneration unit is currently regulated under the Massachusetts CAIR program (i.e. 310 CMR 7.32) because the MA CAIR program's applicability criteria includes combustion units that are rated at greater than or equal to 15 MW, which is lower than the Proposed CATR applicability threshold. For this reason, we request that EPA discuss the transition process for combustion units that were subject to CAIR but will not be subject to the CATR. For example, will combustion units like the MIT·CUP cogeneration unit still be required to monitor emissions according to 40 CFR 75 and report quarterly EDRs? [EPA-HQ-OAR-2009-0491-2870.1 p.2]
Response: 
In the final rule, the state of Massachusetts is not subject to the provisions of the Transport Rule.  However, Massachusetts is still subject to the requirements of the NOx SIP Call which requires states to impose Part 75 monitoring requirements on certain sources.  EPA will work with the state of Massachusetts and individual sources, like this commenter, to determine which requirements still apply.  There are requirements that may have come about in response to the NOx SIP Call that are now relied upon for other requirements under the CAA through other SIPs.  For this reason, each state and source needs to be considered on a case-by-case basis.  EPA recommends that sources work primarily through their state air agency to determine which requirements continue to apply, and EPA will assist the state to help make the determinations.
Organization: South Carolina Department of Health and Environmental Control 
Comment: 
South Carolina Department of Health and Environmental Control 
DHEC requests clarification on the applicability of NOX SIP Call requirements to non-EGU sources that South Carolina had brought into the CAIR trading program. The EPA is requiring states to meet NOX SIP Call requirements for large non-EGUs that states had brought into the CAIR Ozone Season Trading Program. The EPA specifically states, "[T]he NBP [NOX Budget Trading Program] states would need to achieve their NOX SIP call emissions reductions another way in order to continue to comply with the NOX SIP call." Does this mean that states would need to ensure that its large non-EGUs (those subject to NBP applicability requirements) do not exceed the state's NBP non-EGU budget? South Carolina's NOX SIP Call plan includes a total non-EGU budget of 32,141 tons, and a total budget of 3,470 tons for large non-EGUs in the trading program.41 Which of these two budgets does the EPA expect South Carolina to meet? [EPA-HQ-OAR-2009-0491-2677.1 p.17]
How does the EPA foresee states meeting their NOX SIP Call budgets? Could states meet the NOX SIP Call requirements for non-EGUs by including NOX emissions limits in affected facilities' Title V Operating Permits? If states are to impose new emissions limits in affected facilities' Title V Operating Permits, under what specific regulatory authority would they do this? Most of 40 CFR 96, Subparts A-I, governs the operation of the NBP. Without the NBP, what independent NOX SIP Call requirements exist for states to cite when amending Title V Operating Permits? [EPA-HQ-OAR-2009-0491-2677.1 p.18]
The EPA further states that if the requirement cited above remains in the final rule, then "any state that allowed these units to participate in the CAIR NOX Ozone Season Program would need to submit a SIP revision to address their NOX SIP Call requirement for the reductions."42 Without the emissions trading schemes of the NBP or CAIR, what sort of SIP revisions is the EPA expecting? Do states need to promulgate new NOX control regulations for non-EGUs? [EPA-HQ-OAR-2009-0491-2677.1 p.18]
The EPA has provided little insight in answering clarifying questions on this, and other sections, of the proposed Transport Rule. EPA staff stated on conference calls with states that this section of the proposed Transport Rule was a rough area, and that the EPA was expecting comments on the proposal. Given the EPA's decision to limit commentary to what is in the proposal, DHEC notes that the EPA should have offered more explanation in the preamble. Without an explanation of how the EPA expects states to meet NOX SIP Call requirements in the proposal, DHEC cannot have meaningful opportunity for comment on this section of the proposal. [EPA-HQ-OAR-2009-0491-2677.1 p.18]
Response: 
See preamble Section IX for a discussion of continuing NOx SIP Call requirements.  The discussion includes information on the requirements and the SIP revision options available to states.
Additionally, there are requirements that may have come about in response to the NOx SIP Call that are now relied upon for other requirements under the CAA through other SIPs.  For this reason, each state and source needs to be considered on a case-by-case basis. 

V.F.4. Early Reduction Provisions

Organization: American Electric Power
Comment: 
American Electric Power
The Transport Rule Drastically Limits the Use of Banked Allowances, Resulting in Higher Than Necessary Costs
In the currently-effective CAIR program, EPA currently incentives power plants to reduce SO2 and NOx emissions more than required in a given year and save or 'bank' these emission allowances for use in a later compliance year. Emissions banking allow companies to comply at a lower overall cost because very high cost reductions and expensive pollution control equipment can be delayed until the most optimal time frame by utilizing banked allowances. More importantly, banking provides a net environmental benefit, because more emission reductions and hence environmental improvement occurs sooner. Under the Proposed Transport Rule, EPA has proposed an entirely new allowance system that would eliminate the use of previously banked Title IV and CAIR SO2 allowances after the end of 2011. As a consequence, the market price of SO2 allowances has dropped to nearly zero and the SO2 market has been effectively eviscerated. In effect, electric companies and their ratepayers and various market participants who have funded extra emission reductions and environmental improvement through advanced pollution control investments over the past several years have been penalized billions of dollars. [EPA-HQ-OAR-2009-0491-2665.1, p.12]
To minimize these adverse impacts, AEP recommends that EPA extend the current CAIR rule for several more years before beginning Phase I of the Proposed Transport Rule and allow for banked allowances to be used during this time period. The use of banked allowances could help smooth the transition to any tighter emission caps under a new Transport Rule, substantially reduce the costs of compliance, and help ameliorate unit retirement and system reliability concerns. Also, the continuation of the CAIR program will ensure progress to attaining the air quality goals under the Clean Air Act. [EPA-HQ-OAR-2009-0491-2665.1,p.12]
This is continued by the fact that the SO2 and NOx reduction levels of the CAIR program were set at levels that EPA determined were appropriate to remedy interstate transport problems for both the ozone and tine particulate matter standards. [EPA-HQ-OAR-2009-0491-2665.1, p.13]
Response: 
See preamble section VII for regarding the 2012 compliance start and preamble section IX regarding the prohibition of the use of CAIR and Title IV allowances in the Transport Rule.
Organization: American Forest & Paper Association (AF&PA)
Comment: 
American Forest & Paper Association (AF&PA)
While we support EPA's decision to exempt these sources from further controls we believe that EPA does not adequately address the interaction of non-EGU sources with respect to the existing NOx SIP Call and CAIR. We believe EPA should roll over the allowances provided to non-EGU sources under the existing NOx SIP Call and CAIR programs and allow these sources to continue to participate in the available trading mechanisms in the final Transport Rule. [EPA-HQ-OAR-2009-0491-2643.1, p.2]
In the preamble (75 FR 45338) EPA incorrectly claims that, as a group, non-EGU boilers did not make any emissions reductions as a result of the NOx SIP Call. This is simply untrue and the record should be corrected. Numerous units within this industry installed NOx controls in an effort to meet the required reductions of the NOx SIP Call. As covered sources, non-EGUs were required to comply with a significantly more stringent NOx standard. Compliance with the tighter standards was achieved through either installation of emissions controls or the purchase of allowances. EPA recognized this in the CAIR rule that allowed these sources to be rolled into that program without additional controls and allow them to continue to participate in the trading program authorized by CAIR. Under the proposed rule, EPA would require additional rulemaking by forcing states to institute SIP revisions to account for these units. We believe it would be simpler for EPA to adopt its previous position under CAIR with respect to these units and allow these sources to roll allowances for non-EGUs into the new program. Finally, these sources should be able to participate in any trading programs, the more robust the better, created under the final Transport Rule. [EPA-HQ-OAR-2009-0491-2643.1, p.3]
Response: 
Keeping non-EGUs out of the Transport Rule does not create additional rulemaking for states.  The Transport Rule FIPs do not directly address NOx SIP call requirements.  States would have to conduct a rulemaking for a SIP revision to address NOx SIP Call requirements whether EPA allowed or did not allow non-EGUs from the NOx SIP Call to be part of the Transport Rule program.  EPA is not allowing these units to be part of the Transport Rule trading program for the reasons given in preamble section IX and responses to other comments particularly in section V.F.3. of this document.
Organization: American Public Power Association (APPA)
Comment: 
American Public Power Association (APPA)
The Proposed Transport Rule properly recognizes the important environmental and economic benefits of allowance banking, a feature of CAIR that was not challenged in the litigation on that rule and that the court`s opinion in no way undermines. The ability of sources to use banked allowances for compliance with the program encourages them to make early emission reductions to the extent that cost-effective early reductions are possible. Unfortunately, the nature and stringency of the proposed rule's emission reduction requirements and its proposed compliance schedule would make it very difficult for most sources to make extra emission reductions during the early years of the program. See sections VI and VIII infra for UARG`s comments (and by incorporation in the APPA comments) on the compliance schedule. Permitting allowance banking in conjunction with an adjustment to the compliance schedule that would allow sources adequate time to comply with the program (and give states adequate time to develop SIPs) could well result in greater amounts of early emission reductions and, most likely, greater emission reductions over the long run. [EPA-HQ-OAR-2009-0491-2812.1, p.11]
Response: 
See preamble section VII for information on Transport Rule banking provisions.
Organization: Attorney General of North Carolina
Comment: 
Attorney General of North Carolina
EPA proposes to allow sources to bank allowances that are allocated under the Transport FIP's SO2, annual NOX, and ozone-season NOX programs. The shifting of emissions from year to year would allow the aggregate emissions in a State to exceed the breakpoint between lawful and unlawful emissions in some, but not all, years. Because downwind attainment is determined using annual (or seasonal) measures, time-shifting the elimination of the significant contribution across years may prejudice downwind areas. Accordingly, without more, banking may violate the Clean Air Act. [EPA-HQ-OAR-2009-0491-2685.1, p. 24]
However, the proposed rule also incorporates variability limits on annual emissions. Although EPA appears to have proposed these variability limits primarily as a brake on interstate trading, they would seem to apply equally to banking. Therefore, the same criticism also applies. Banking may allow sources to build up significant stores of allowances and then to use those banked allowances to fail to reduce emissions for several years running. If this is done, for example, as a strictly financial decision to use less catalyst in a control device because the source has a significant bank of allowances, this would not seem to be the intent of EPA's variability program. EPA must consider further controls on banking and/or use of the variability limits in order to ensure that banked allowances are not used to permit sources to emit in excess of the breakpoint between lawful and unlawful emissions. [EPA-HQ-OAR-2009-0491-2685.1, p. 24]
Finally, 2009 data indicate that emissions from several States are currently below the States' SO2 and/or NOX budgets  -  tens of thousands of tons below in the aggregate. In many, if not most, cases this is due in overwhelming measure to national economic conditions. EPA's proposal to allow sources to bank allowances during this period for use in the Transport FIP would simply permit excess emissions in the control years (2012 and beyond) due to economic conditions that have nothing to do with whether a source is controlled with highly cost effective controls. Even if EPA does not allow the importation of pre-existing allowances, EPA should adjust the budgets as necessary to account for deviations that would provide a windfall of banked allowances to sources based on temporary conditions not related to actual control of emissions. [EPA-HQ-OAR-2009-0491-2685.1, p. 24]
Response: 
See Section VII of the preamble for discussion of banking and assurance provisions.
Organization: Buckeye Power, Inc.
Comment: 
Buckeye Power, Inc.
f. Existing CAIR emission allowances should be incorporated into CATR.
Under the proposed rule, CAIR unused allowances would be eliminated as a means of compliance beginning in 2012. Eliminating the legacy allowances that Buckeye acquired under CAIR and its predecessor programs through allocations and purchases is unfair. Buckeye acquired the allowances as a result of incurring costs of hundreds of millions of dollars to install BACT ahead of when such technology was required. Buckeye also purchased 25 million dollars of allowances on the market to meet its requirements through 2037. Buckeye should not be punished for having taken prudent steps to meet existing environmental requirements through market purchases and early adoption of BACT. These allowances should not be rendered worthless through this rulemaking. Those allowances should be available for use under the CATR. If not, utilities will be discouraged from planning ahead and have little incentive to voluntarily take steps to improve environmental performance beyond the absolute minimum required by law. As a nonprofit operating on a cooperative basis, 100% of the cost of these purchased emission allowances will need to be recovered through rates from the members/‌consumers of Ohio electric cooperatives, if they are rendered useless under CATR. [EPA-HQ-OAR-2009-0491-2710.1, pp.11-12]
Buckeye has installed SCRs on both of its Cardinal Units and a SO2 scrubber on one of the Cardinal Units and is in the process of installing a JBR scrubber on the other of its Cardinal Units at a cost of approximately $1 billion. Now EPA proposes imposing additional reductions on Buckeye while other units have done nothing to install pollution control equipment and will not have to do so until 2014. Buckeye is a small utility which will suffer as a consequence of having placed controls on line prior to being required to do so. Further, EPA's proposal to do away with SO2 and NOx allowances that were obtained prior to the CATR proposal imposes a large financial burden upon Buckeye's consumers in Ohio. They have not only been impacted by the economic recession, but will face additional cost in the loss of these allowances. [EPA-HQ-OAR-2009-0491-2710.1, p.12]
Response: 
See discussion in preamble section IX regarding prohibition of the use of CAIR and Title IV allowances in the Transport Rule.  See also http://epa.gov/airmarkets/business/cairallowancestatus.html, a statement by EPA which gave notice in March of 2009 that CAIR allowances might not have value in the future.
Organization: Citizens Campaign for the Environment (CCE)
Indiana Department of Environmental Management 
Clean Air Task Force
Clean Energy Group
North Carolina Department of Environment and Natural Resources
Maryland Department of Environment (MDE)
Connecticut Department of Environmental Protection
Sierra Club, Georgia Chapter
Comment: 
Citizens Campaign for the Environment (CCE)
Important elements of the proposed Transport Rule that CCE recommends should be maintained in the finalized rule include:
3) Prohibit the use of banked allowances from current program. Under the proposed Transport Rule, dirty power plants cannot use 'banked' excess allowances from the current acid rain program to meet the requirements of the new Transport Rule. Allowing the use of banked allowances from the current program would impair the efficacy of the new Transport Rule. CCE recommends that EPA maintain this prohibition in the final rule. [EPA-HQ-OAR-2009-0491-1937.1, p. 3]
Clean Air Task Force
EPA requests comment on the use of banked allowances from other trading schemes for purposes of compliance with TR requirements. 144 Consistent with the Court's opinion in North Carolina v. EPA, the Agency must not allow the use in the TR of any SO2 or NOx allowances banked or otherwise carried over under the CAIR program or the Title IV acid rain program, and we support EPA's proposal to exclude these allowances for TR compliance. 145 [EPA-HQ-OAR-2009-0491-2738.1, p.26; This comment can also be found at section V.F.4.b & V.G.2 of this comment summary]

Footnote:
144 75 Fed. Reg. at 45339. 
145 75 Fed. Reg. at 45338-39.  
Clean Energy Group
Additionally, many of the Clean Energy Group companies have made significant investments in pollution control equipment, allowing companies to bank Title IV and CAIR NOx allowances. However, as a result of the D.C. Circuit decision, EPA is not able to utilize Title IV allowances in the proposed program and the introduction of a new S02 currency greatly reduces the value of banked Title IV allowances. Although companies that made early investments are effectively penalized, the Clean Energy Group recognizes that EPA's proposal not to use Title IV allowances in the Transport Rule is the only legally-sound approach given the D.C. Circuit's decision. Therefore, we agree that EPA has proposed the only viable alternative with regard to treatment of Title IV allowances. Congressional modification of the Clean Air Act would be necessary to include Title IV allowance banks in the Transport Rule program. [EPA-HQ-OAR-2009-0491-2702.1, pp. 10-11]
Connecticut Department of Environmental Protection
Banking. CTDEP strongly supports EPA's proposal to preclude the use of any banked pre-2012 CAIR allowances in the transport rule NOx programs. CTDEP also strongly supports EPA's proposal to create a new SO2 allowance currency for the new transport rule SO2 program. [EPA-HQ-OAR-2009-0491-2780.1 p.20]
Indiana Department of Environmental Management 
No allowances should be brought in from the Title IV or nitrogen oxide (NOx) budget programs. [EPA-HQ-OAR-2009-0491-2645.1 p.2] 
Maryland Department of Environment (MDE)
Limited Trading
In the proposed Transport Rule, EPA outlines three options as the remedy for transport issues concerning the 1997 ozone and 2006 PM2.5 NAAQS. All three options focus on achieving reductions in NOx and SO2 emissions from EGUs, and all options are based on EPA preferences to preclude the use or inclusion of existing NOx and SO2 allowances as part of the remedy. We strongly support EPA's preference to exclude the existing NOx and SO2 allowance banks in any remedy in the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2639.2, p.14]
North Carolina Department of Environment and Natural Resources
The issue of the banking of allowances arises in two different situations: the use of pre-existing allowances (e.g., title IV and CAIR NOx allowances) and the use of allowances allocated under the Transport FIP.
EPA has proposed not to allow sources to use pre-existing Title IV S02 allowances to meet the compliance requirements of the Transport FIP. For the reasons stated by EPA, 75 Fed. Reg. at 45,338/3, NCDAQ concurs that the importation of banked Title IV allowances into the Transport FIP program would not be consistent with the Clean Air Act. Eliminating the use of the banked Title IV allowances ensures the caps in the FTR are not weakened.
EPA appears less certain regarding the fate of CAIR NOx allowances. NCDAQ suggests that CAIR NOx allowances should be eliminated. NCDAQ is concerned with the fact, as EPA readily concedes, that 'the amounts of the banks are so large that they might significantly reduce the amount of emissions reductions that would otherwise be achieved in the proposed Transport Rule NOx programs, particularly in the earlier years (e.g., 2012 and 2013).' 75 Fed. Reg. at 45,339/1.
EPA has proposed to determine that emissions reductions by 2012 and 2014 are necessary in order to ensure that the reductions are both coordinated with the downwind nonattainment deadlines and achieved 'as expeditiously as practicable,' as required. Therefore, the budgets EPA has proposed in the Transport FIP define the breakpoint between lawful and unlawful emissions. Importing any allowances from outside those calculations, not to mention the concernedly overwhelming bank of allowances remaining from the CAIR NOx program, would allow sources to delay elimination of their unlawful emissions past the point required by the only relevant considerations: downwind attainment deadlines and the associated 'as expeditiously as practicable' mandate. Thus, the importation of any pre-existing allowances violates the §llO(a)(2)(D)(i)(I). Therefore, NCDAQ does not support the continued use of CAIR NOx allowances once the Transport FIP becomes effective. [EPA-HQ-OAR-2009-0491-2767.1 p.3]
Sierra Club, Georgia Chapter
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.98.]
We're pleased that the emissions banking can only be used when emissions reductions go below what is already required.
Response: 
EPA is finalizing the proposed approach of not allowing CAIR allowances to carry over into the Transport Rule programs or to allow the use of Title IV allowances in Transport Rule programs.  See further discussion in Preamble Section IX.
Organization: City of Dover, Delaware
Comment: 
City of Dover, Delaware
Under the proposed Transport Rule existing SO2 and NOx allowances issued under CAIR would have little or no compliance value. The City, in order to ensure reliable and low cost electricity service to its customers, implemented a strategy which includes maintaining an adequate bank of allowances to hedge against future price risks. As with many peaking units, the City's covered units' emissions are highly variable and largely dependent on a variety of factors impacting electricity demand. As such, the City elected to manage their emission allowance accounts in such a way which permits the continued delivery of reliable and affordable electricity service even in years in which their units are required to run more often. [EPA-HQ-OAR-2009-0491-2636.1, p.2]
The City believes that the Transport Rule should allow for some flexibility in allowing existing CAIR allowances to count for compliance with the Transport Rule. The City is aware of the large number of CAIR allowances currently banked system-wide and recognizes the challenges EPA faces in reducing concentrations of air pollutants with allowance banks at high levels. However, in order to ensure a smooth transition from CAIR to the Transport Rule, particularly for units with high levels of variability in their emissions from year to year, the City feels that existing CAIR allowances should have meaningful compliance value in the Transport Rule. [EPA-HQ-OAR-2009-0491-2636.1, p.2]
Response: 
See preamble section IX and a statement issued by EPA in March 2009 regarding future value of CAIR allowances, which was widely disseminated at the time and has remained posted on the CAIR program website continuously since that time, http://epa.gov/airmarkets/business/cairallowancestatus.html.
Organization: Dominion
Comment: 
Dominion
For reasons discussed in detail in Section V of these comments, we believe the initial 2012 compliance requirements as well as the 2014 subsequent reductions for S02 are unrealistic and will be very difficult to achieve. To the extent EPA retains this schedule of reductions, we offer the following recommendations for EPA consideration that would enhance the positive aspects of EPA's preferred approach noted above and provide additional compliance flexibility for affected sources, particularly in the initial years of the program: [EPA-HQ-OAR-2009-0491-2715.1, p.4]
Compliance Deadlines for 2012 and 2014 are Unreasonable [EPA-HQ-OAR-2009-0491-2715.1, p.12]
The 2012 and 2014 compliance deadlines are unreasonable and will be difficult to achieve. This may be especially true in the Group 1 states where electric generating units(EGUs) would need to reduce their S02 emissions by at least 50 percent from current levels by 2014. The proposed Transport Rule establishes new reduction requirements that must be met only 6-12 and 30 months after the final Transport Rule is issued. By contrast, the Phase 1 deadlines for the Clean Air Interstate Rule (CAIR) allowed almost 5 years from promulgation of the final rule until the first compliance year for S02 and almost 4 years for NOx. [EPA-HQ-OAR-2009-0491-2715.1, p.12]
For 2012, EPA generally assumes switching to lower sulfur fuels as a viable compliance option. As noted above in Section III.6, EPA's assumptions concerning the availability of low sulfur coal are outdated and do not reflect recent shifts of coal supply in the Appalachian region and subsequent trends of decreasing supply of low sulfur coal in this region. In addition, the use of low sulfur western PRB coal is not a viable option in the short term for boilers and coal operation and handling systems in the Eastern U.S. designed around the use of eastern coals due to costs and the time often needed to complete needed modifications to coal handling systems and acquire necessary environmental permits. [EPA-HQ-OAR-2009-0491-2715.1, p.12]
We believe EPA is overly optimistic in concluding that all of the necessary retrofits can be completed in time to meet the proposed 2014 compliance deadline. Second, EPA greatly underestimates the amount of time that it takes sources to design, permit, construct and begin operation of retrofit control equipment and assumes that affected units will be able to construct scrubbers and SCRs on a timeline similar to what was accomplished for compliance with the initial phase of CAIR. In fact, EPA relies on the very same information (a now outdated 2005 analysis) used in developing the CAIR rule. While CATR included widespread trading across 28 states, the proposed Transport Rule has less flexibility with deeper reduction requirements and geographic trading constraints (in terms of two distinct trading zones for S02 and limited interstate trading for both S02 and NOx) that will likely require more emission control retrofits. Consequently, sources may not be able to install controls in the timeframe the EPA assumes is reasonable. [EPA-HQ-OAR-2009-0491-2715.1, pp.12-13]
EPA assumes it would take an average of 21 months to install an SCR on a single unit, and about 27 months to install a scrubber. Dominion's experience has shown that the process from planning and engineering to permitting and construction for a major capital project to install emission control technology can take as much as 45 to 58 months. [EPA-HQ-OAR-2009-0491-2715.1, p.13]
[See EPA-HQ-OAR-2009-0491-2715.1, p.13-14 for additional comments pertaining to Compliance Deadlines for 2012 and 2014 are Unreasonable]
To the extent that EPA retains the deadline, it should consider provisions that would allow extensions for situations that indicate a confirmed demonstration of reliability concerns, technical unfeasibility or other extenuating circumstances, or would provide opportunities to offset potential retrofit delays through the establishment of early reduction credits and supplemental allowances as it did in the NOx SIP Call rulemaking. [EPA-HQ-OAR-2009-0491-2715.1, p.14]
Response: 
See preamble Sections Vi and VII for information regarding compliance deadlines.
Organization: Duke Energy
Comment: 
Duke Energy
There are policies that EPA can put in place to encourage the downward trend in EGU emissions to continue under the PTR even if the initial binding compliance date under the rule was not until some years later. One possible approach would be to set "shadow" allowance allocations, using the best data available, for 2012 and each subsequent year until the new program begins. Then, during the period leading up to the new program's initial compliance year, EPA (or, more properly, a state) could credit sources with additional allowances corresponding to the number of tons they emitted below their shadow allowance allocation levels in those years, with those allowances eligible to be banked and used beginning in the first compliance year. The ability to earn allowances -- usable once the new program begins -- for early reductions would give sources a meaningful incentive to reduce their emissions prior to the start of the program, while allowing them the time they need to make the adjustments necessary for compliance.  [EPA-HQ-OAR-2009-0491-2689.1, p.11]
Response: 
The Transport Rule will start in 2012, so the need for the commenter's suggested provisions is not needed.
Organization: Edison Electric Institute (EEI)
Comment: 
Edison Electric Institute (EEI)
[This comment was submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.28.]
and to allow banking of surplus emission reductions.
Response: 
Comment is vague.  Surplus emission reductions may be banked under the Transport Rule (see preamble section VII).  Surplus emission reductions from CAIR may not be used in the Transport Rule (see preamble section IX).
Organization: Environmental Markets Association (EMA)
Comment: 
Environmental Markets Association (EMA)
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.49-50.]
EMA believes that EPA could provide for continuity in allowance markets by electing to apply surrender ratios to banked allowances as it is proposed in the rule. We suggest that it might help to reduce the risk of subsequent litigation if EPA set the fuel factors in a way that would reverse the impact -- if it set the fuel factors in a way that reverse the impact of the original allocation method, for example, if a 100-percent coal-fired company converted its allowances at a higher ratio than a gas-fired company.
EMA supports efforts such as EPA's to promote market-based mechanisms for responding to environmental issues because emissions trading is reducing emissions earlier at lower costs than any other form of regulation.
We encourage EPA to maintain the continuity of existing programs by providing for the convertibility of current period allowances to subsequent trading rule programs.
Response: 
See preamble section IX.
Organization: First Energy
Comment: 
First Energy
CAIR NOx and SO2 Allowances
FE recommends the EPA allow the future use of CAIR allowances as a method to meet the aggressive CATR 2012 & 2014 program timeframe. EPA's proposed approach effectively penalizes sources that have meet CAIR requirements by installing control equipment prior to 2012, and moots the value of the future stream of allowances on which those decisions were made. Banked Title IV SO2 allowances and CAIR NOx allowances should remain in the control of the utility for future use. [EPA-HQ-OAR-2009-0491-2657.1,p.12]
Response: 
See preamble section IX.A. for a discussion of allowances used in the CAIR program.
Organization: Florida Electric Power Coordinating Group, Inc. (FCG)
Comment: 
Florida Electric Power Coordinating Group, Inc. (FCG)
The Proposed Transport Rule properly recognizes the important environmental and economic benefits of allowance banking and that allowance banking as an element of EPA's program was in no way undermined by the court's decision in North Carolina v. EPA. Additionally, the FCG supports approaches that would permit the use of banked CAIR NOx allowances for compliance with the Proposed Transport Rule. Such banking allowances should allow for unlimited banking along with no 'expiration period' attached to the allowances accrued each year. [EPA-HQ-OAR-2009-0491-2658.1, p.12]
Response: 
See preamble section IX regarding the use of CAIR NOx allowances.
Organization: George Washington University Regulatory Study Center
Comment: 
George Washington University Regulatory Study Center
In addition, the Transport rule proposes to restrict the use of banked allowances through the 'assurance provisions' in the proposal and prohibit the transfer of banked allowances from the Title IV SO2 program and from the CAIR NOx programs. The current totals of banked SO2 and NOx allowances under CAIR and the predecessor CAA programs are substantial: 12 million SO2 (Title IV) allowances, 600,000 ozone-season NOx allowances, and 720,000 annual NOx allowances. [EPA-HQ-OAR-2009-0491-2573.1, p.5]
If the proposed Transport Rule is implemented, emissions will likely increase in the short term as emitters must "use or lose" banked allowances and lack an incentive to make early emissions reductions. While it is less certain, it is possible that prohibiting the transfer of banked allowances would result in a reduced level of long-term banking of allowances and a broader loss of buy-in to cap-and-trade systems. The facilities and firms subject to regulation under the Transport Rule's NOx and SO2 provisions participate in other EPA and state emissions trading markets and would likely participate in any such future market for greenhouse gases or other pollutants. Almost all of these markets rely on banked allowances, and as discussed in the next section, regulated firms' (and investors') confidence in those allowances has ramifications that cross the boundaries between programs. [EPA-HQ-OAR-2009-0491-2573.1, p.11]
C. Background: Emissions-Trading Programs and Allowance Banking  
1. Principles of Allowance Banking
As many scholars have identified, creation of property rights is associated with more efficient use of resources. The CAA and EPA regulations explicitly state, however, that the emissions allowances created do not convey property rights. A more useful way to understand emissions allowances is therefore not to consider them to be full-fledged property, but as carrying some (but not all) of the rights in the property bundle. For example, holders can exclude others from using allowances they hold. But the statutory provisions and government agency decisions that create allowances limit allowance holders' rights. [EPA-HQ-OAR-2009-0491-2573.1, p.12]
Because emissions allowances convey certain rights, it is important that emissions-trading programs maintain clear and consistent rules on the use of allowances in order to limit uncertainty and assure a smoothly functioning market.23 After the basic rules for an emissions-trading program are in place, changes by regulators in the rules governing the use of allowances can significantly affect the certainty and credibility of the emissions-trading programs and the value of allowances. Such changes may lead to undesirable market behavior, including an emissions increase as sources use up or dump their banked allowances. In addition, such changes also may undermine the credibility of other trading programs within the jurisdiction of the regulator. [EPA-HQ-OAR-2009-0491-2573.1, p.12]
One key element of an emissions-trading program is the extent to which the program permits the banking of emissions allowances. Banking has advantages and disadvantages. It lets sources reduce emissions in one period and save their unused allowances for future time periods. Banking also encourages early reductions in emissions and early improvements in air quality. [EPA-HQ-OAR-2009-0491-2573.1, p.12]
It further stabilizes allowance markets by providing a pool of allowances that can be used in periods when allowances are relatively scarce and by reducing price differences that would otherwise exist between different allowance vintages. Another advantage offered by systems that allow for banking of allowances is that by giving emitting sources with banked allowances a vested interest in the control program, such systems may more effectively align the interests of regulators and emissions sources. This "buy-in" should contribute to the long-term viability and political acceptability of the control program. [EPA-HQ-OAR-2009-0491-2573.1, p.13]
On the other hand, banked allowances make it possible for emissions in future years to exceed caps set in those years, eliminating the certainty otherwise provided by a cap-and-trade system that emissions levels will not exceed the cap. Environmental advocates, some state environmental agencies, and the EPA itself have expressed significant concerns with allowing banking for this reason. In response to these concerns, a regulator could end the existing emissions-trading program (rendering allowances useless) or limit use of banked allowances (reducing their value). [EPA-HQ-OAR-2009-0491-2573.1, p.13]
2. Banking and Transition
A tension exists between the expectations that underlie the decision to bank allowances and the environmental objectives of these programs. If allowances banked in one version of an emissions-trading system cannot be used in subsequent revisions, or if unanticipated program changes otherwise undermine their value, the basic expectations that support banking will be undermined. Allowances therefore only retain value to the extent that regulators credibly promise not to undermine them. If those that hold allowances no longer believe they will be useful in the future, they will not make continuing early reductions in emissions, and the efficiency benefits of banking will be unrealized even if banking remains a formal part of the program. [EPA-HQ-OAR-2009-0491-2573.1, pp.13-14]
It is even possible that these effects may carry over between different emissions-trading programs with the same repeat players. For example, EPA administers most emissions-trading programs for various pollutants in the United States, and the predominant emissions sources in most of these programs are similar -- large fossil fuel electricity generation plants and some industrial facilities. EPA actions that undermine the value of banked allowances in one program might lead a rational emitter to predict that the EPA will behave similarly with respect to other programs and markets and adjust its trading and banking behavior accordingly. Investors and market makers are similar repeat players. If the EPA discards banked allowances, these actors might be dissuaded from investing in not only the new market, but other existing or future EPA-administered emissions markets. Moreover, all of the EPA's regulatory decisions, including those regarding the value of banked allowances, are public. Participants in future emissions trading markets, even if they have no experience with current or past EPA-administered markets, will make judgments based on this information. If these first-time players observe that the EPA has undermined the expectations of past market participants, their rational response is identical to that for repeat players. In short, the agency's reputation among current or future market participants matters. [EPA-HQ-OAR-2009-0491-2573.1, p.14]
In short, the issue is efficiency -- what is problematic is the potential effect of regulatory decisions on market-participant behavior, along with the political impact of reduced participant buy-in. When participants believe that banked allowances will disappear or lose value in the future, they are less likely to make early reductions and bank credits and more likely to dump allowances already banked in a way that increases emissions. Sources will also be unlikely to make early reductions to smooth the transition from the existing program and provide a cushion of allowances in the first years of the new program. If this happens, a trading program will be less effective in achieving the expected abatement benefits at lowest cost. Spillover effects between repeat players in multiple markets or into future, unrelated markets may extend these adverse effects to other trading programs.[EPA-HQ-OAR-2009-0491-2573.1, p.14]
3. The EPA's Track Record
Since the 1990s, emissions-trading markets -- mainly in the form of cap-and-trade programs regulated by the EPA -- have become a leading federal policy mechanism in the United States for achieving reductions in pollution. For at least a few major air pollutants, most notably NOx and SO2 emissions from fossil fuel power plants, markets have supplemented traditional command-and-control regulation as a major regulatory tool. Cap-and-trade also has been advanced as a likely vehicle for regulating greenhouse gases from a broad range of sources. [EPA-HQ-OAR-2009-0491-2573.1, pp.14-15]
Emissions trading programs, however, do change over time. Caps on emissions generally have been tightened over time as new information about the adverse effects from pollutants has become known or costs of control have declined. The tightening of caps and expansion of programs' geographic scope has resulted in new programs with new sets of rules. Court decisions and broader policy changes also have spurred creation of new programs that supplant or modify existing ones. In all these transitions, treatment of banked allowances has been an issue.  [EPA-HQ-OAR-2009-0491-2573.1, p.15]
An important and underemphasized element of regulatory design during changes in emissions-trading systems is therefore the need to minimize disruption by maximizing confidence among participants that the rights and value embodied by banked allowances will be preserved as much as possible -- that environmental goals will be balanced with expectations about banked allowances. [EPA-HQ-OAR-2009-0491-2573.1, p.15]
A recent paper by the authors examines the several transitions between NOx emissions-trading markets created by EPA regulation: the start-up of the Ozone Transport Commission (OTC) NOx Budget Program, the 2003 transition from the OTC NOx Budget Program to the NOx SIP Call, the 2009 transition from the SIP Call to the seasonal NOx market in CAIR, and the creation in CAIR of a new annual NOx market. In addition, the paper discusses the recent transition in SO2 trading programs between the Title IV program created by Congress to the CAIR program created by the EPA. [EPA-HQ-OAR-2009-0491-2573.1, p.15]
In most of these transitions, the newer markets included stricter emissions caps than their predecessors. This created a fundamental tension between the rights and value associated with banked allowances and the environmental goal of reduced emissions. If banked allowances are used in the new, stricter program, emissions will be greater than desired in the short term until those banked allowances are drawn down. This delay before the new caps "bite" will be perceived as problematic and will create pressure to reduce or eliminate these "excess" allowances. However, a decision to prohibit the transfer of banked allowances to the new program has consequences for the stability and effectiveness of the market (and possibly other markets). [EPA-HQ-OAR-2009-0491-2573.1, p.15]
Striking the right balance is not easy, and the EPA has faced this issue through all the transitions between markets discussed in our recent paper. Though the basic issues have not changed, the EPA's response has not been consistent. When the EPA has restricted exchange of banked allowances, provided information on exchange only after allowances have been banked and expectations created, or when courts have blocked EPA plans for simple transitions, markets have responded with very high and unstable prices for allowances in the future markets and the collapse of allowance prices in the existing program. This past experience indicates that if EPA's handling of transitions in the NOx and SO2 markets leads to uncertainty for regulated entities about the credibility of allowance banking, these actions will adversely affect market behavior in the future, reducing the effectiveness and cost savings of market-based programs. [EPA-HQ-OAR-2009-0491-2573.1, p.16]
Our discussion of the transition between cap-and-trade programs for NOx and SO2 highlights this issue. The decision by the OTC states to "sunset" 1999 vintage NOx allowances, the D.C. Circuit decision to vacate the CAIR rule, and the EPA's recent proposed Transport Rule to replace CAIR have limited -- or in the case of the Transport rule would limit -- the use of banked allowances with the transition between programs, significantly altering their value and introducing a substantial element of uncertainty in the markets for emissions allowances. [EPA-HQ-OAR-2009-0491-2573.1, p.16]
D. Banked Allowances and the Transport Rule: Conclusions
We believe there are two key lessons to take away from our review of the historical experience with the several transitions in EPA-sponsored cap-and-trade programs. [EPA-HQ-OAR-2009-0491-2573.1, p.16]  
One lesson of this history is that transitions to new trading programs can be difficult for markets, as reflected by the high reported prices for allowances in the months preceding the startup of new programs. These high prices were associated with uncertainty within the regulated industry over the availability of allowances. Observers have reported that the initiation of new environmental programs brings some degree of "fear" and "uncertainty" to the regulated community. The transition periods have been characterized by thin markets (i.e., there are relatively few transactions) and little or no mechanism for price discovery. Substantial price volatility in these new markets -- the OTC NOx market (1999), the transition to the NBP (2003), and the CAIR annual NOx market (2009) -- adversely affect trading activity and the overall efficiency of the program. [EPA-HQ-OAR-2009-0491-2573.1, p.16] [[See EPA-HQ-OAR-2009-0491-2573.1, pp.17-18 for a detailed discussion on this issue.]]

23 Governing statutes and EPA regulations make it clear that its emissions-trading programs do not convey formal property rights (see note 22 below and accompanying text). Nevertheless, emissions allowances convey certain rights in terms of complying with an emissions cap and, if banking is allowed, in terms of the use of allowances in future years. Even if these rights are not legally enforceable as full property rights would be, they are the source of the expectations that are at the root of a functional emissions trading market. See Section II.C below.
Response: 
See preamble section IX and responses to other comments primarily in this section.
Organization: Large Public Power Council (LPPC)
Comment: 
Large Public Power Council (LPPC)
IV. COMMENTS ON THE STATUS OF BANKED CAIR AND TITLE IV ALLOWANCES
LPPC believes that the proposed Transport Rule wrongly rejects policy options that would preserve the value of banked CAIR NOx allowances and banked Title IV allowances (which were the compliance currency for the SO2 budgets under CAIR). Substantial reserves of banked allowances exist because EGUs reduced their emissions far beyond Title IV and CAIR requirements, fairly expecting to be able to use these banked allowances for future compliance. Destroying the value of these allowances would discourage EGUs from undertaking similarly aggressive early emission reductions under the Transport Rule or other related programs. Moreover, EGUs will have every reason to "consume" banked allowances by increasing their emissions in through 2011 unless EPA creates some mechanism for preserving the value of banked allowances. 48 To avoid these problems, LPPC proposes to create a market for these banked allowances by allowing EGUs to trade in CAIR and Title IV allowances for a limited quantity of Transport Rule allowances set aside from the proposed state emission budgets. As discussed below, we believe this option both preserves the environmental integrity of the Transport Rule and is consistent with North Carolina. [EPA-HQ-OAR-2009-0491-2667.1, p.15]
Under our proposal, 10% of the allowances allocated under each state's budget would be set-aside for distribution to EGUs that are willing to retire banked CAIR and Title IV allowances. Banked allowances could be traded in for Transport Rule allowances from the set aside at an appropriate predetermined ratio (for example, two Title IV allowances for each Transport Rule SO2 allowance). For purposes of the trade-in, EGUs would be permitted to use their own reserves of banked allowances or purchase banked allowances from third parties. By creating a market for banked CAIR and Title IV allowances, this policy would reward the early emission reductions that took place under those programs and discourage excessive use of banked allowances during 2010 and 2011. [EPA-HQ-OAR-2009-0491-2667.1, pp.15-16]
This alternative would satisfactorily address the two major concerns EPA articulated with regard to proposals to allow the use of banked CAIR and Title IV allowances: (1) that doing so would be inconsistent with the D.C. Circuit's decision in North Carolina and (2) that the volume of banked allowances is such that their continued use would significantly impair the quantity of emission reductions expected under the Transport Rule. LPPC's proposed alternative avoids both concerns. Of course, the proposal would have no impact on the environmental integrity of the proposed Transport Rule, because banked allowances would merely be traded in for allowances set-aside from the state emissions budget. The size of the state emission budgets and variability limits would be unaffected. Furthermore, this alternative would comply with North Carolina because it does not implicate the concerns raised by the D.C. Circuit in that case. [EPA-HQ-OAR-2009-0491-2667.1, p.16]
In North Carolina, the D.C. Circuit reached three holdings that are relevant to the use of banked allowances. First, the D.C. Circuit held that EPA inappropriately used Title IV allowance allocations as the basis for state SO2 budgets under CAIR, arguing that this factor had nothing to do with ensuring that each state eliminated its significant contribution to downwind air quality problems. 49 Under the alternative recommended here, state SO2 budgets (and NOx budgets) would still be based entirely on EPA's method for quantifying significant contributions and interference with maintenance. Although EGUs that hold significant quantities of banked Title IV allowances would be able to claim Transport Rule allowances from the set-aside, this result would not offend the D.C. Circuit's instruction that state budgets conform to Section 110. 50 [EPA-HQ-OAR-2009-0491-2667.1, p.16]
Second, the D.C. Circuit held that EPA improperly used fuel adjustment factors to establish state NOx budgets, because this method allowed coal-dependent states to more easily address their significant contribution at the expense of states with cleaner fuel sources. 51 Section 110, reasoned the D.C. Circuit, requires each state to address its own significant contribution, and not bear a lesser or greater burden than other states based on its energy portfolio. Here again, the LPPC proposal preserves the North Carolina compliant state emission budgets proposed in the Transport Rule. Although sources holding banked allowances would benefit from the trade-in provision, there would be no improper cross-subsidization between states in violation of Section 110. [EPA-HQ-OAR-2009-0491-2667.1, p.16]
Lastly, the D.C. Circuit held that EPA unlawfully burdened the use of Title IV allowances by requiring those allowances to be submitted for compliance with CAIR at a discounted ratio. 52 LPPC's preferred alternative does not pose such a concern, because the trading of Title IV allowances for Transport Rule allowances would be completely voluntary and would not affect their value or legal status under the Acid Rain Program. [EPA-HQ-OAR-2009-0491-2667.1, pp.16-17]

48. 75 Fed. Reg. at 45,339. [EPA-HQ-OAR-2009-0491-2667.1, p.15]
49. 531 F.3d at 916-17. [EPA-HQ-OAR-2009-0491-2667.1, p.16]
50. LPPC does not believe that its proposal would make the Transport Rule legally vulnerable by causing allowance allocations to be "tainted" by the invalidated CAIR program, as EPA suggests. See 75 Fed. Reg. at 45,339. Allowing trade-ins of CAIR allowances does not affect the achievement of the Section 110 mandate that each state prohibit contributions to downwind air quality problems, and is a reasonable policy mechanism for ensuring future early emission reductions and preventing emissions increases in 2010 and 2011. [EPA-HQ-OAR-2009-0491-2667.1, p.16]
51. Id. at 918-21. [EPA-HQ-OAR-2009-0491-2667.1, p.16]
52. Id. at 921-22. [EPA-HQ-OAR-2009-0491-2667.1, p.17]
Response: 
See preamble section IX.  EPA has concluded that, given the expected size of the residual allowance banks, the need to tie reductions to specific states as discussed in the preamble and responses to other comments, and the timing of allowance allocation, CAIR or Title IV allowances cannot be used in the Transport Rule. A 10% set-aside would not be available for distribution until after 2011 CAIR compliance (mid-2012), the turn-in ratios would be very high (diminishing the value of individual allowances), and many allowances are held in general accounts not associated with a particular state.  Multi-state companies would be at a considerable advantage if the 10% set-aside for CAIR allowance trade-in were implemented.  These companies could easily move allowances around to maximize the amount of Transport Rule allowances they receive.  Companies that operate in fewer areas, or only one area, would not have the same opportunities to use numerous unit accounts to maximize their ability to obtain the set-aside allowances.
Organization: Missouri Public Utilities Alliance (MPUA)
Comment: 
Missouri Public Utilities Alliance (MPUA)
2. The final rule must make provisions to allow the use of emission allowances issued earlier which in good faith were managed and banked for long term stewardship of the environment.  To propose a system that ignores previous practices breaks faith with utility companies who have been following the law and the rules established by EPA.  Failure to honor these emission allowances could raise questions about the wisdom of future banking of the new credits. [EPA-HQ-OAR-2009-0491-2785.1, p.2]
Response: 
See preamble section IX.
Organization: Owensboro Municipal Utilities (OMU)
Comment: 
Owensboro Municipal Utilities (OMU)
The Clean Air Interstate Rule (CAIR) program currently allows power plants to reduce SO2 and NOx emissions more than required in a given year, enabling them to use these 'banked' emission allowances in a future compliance year. Banking allowances is very beneficial because it encourages power plants to make early emission reductions, thus reducing emissions to the environment sooner. [EPA-HQ-OAR-2009-0491-2811.1,p.2]
EPA's Proposed Transport Rule does not allow the use of previously banked CAIR allowances. OMU supports a final rule that permits the use of banked allowances to carry over into the final Transport Rule trading program. Elimination of banked SO2 and NOx allowances penalizes utilities like OMU that made early commitments to reduce emissions, while those who relied on purchased allowances will be rewarded. OMU encourages EPA to allow banked emission allowances to carryover into the Transport Rule trading program and never expire. [EPA-HQ-OAR-2009-0491-2811.1,p.2]
Response: 
See preamble section IX.
Organization: Public Interest Law Center of Philadelphia
Comment: 
Public Interest Law Center of Philadelphia
IV. Pre-2012 "Banked" CAIR Title IV Allowances of NOX and SO2 Should Not Be Rolled Over into New Programs Under the Proposed Transport Rule.
Under the CAIR program, the amount of annual NOX and SO2 emissions was significantly reduced. As a result, a large number of unused Title IV allowances were banked in both the NOX and SO2 programs. The EPA has evaluated several methods for converting allowances banked under the CAIR program to be converted to bankable allowances under the Transport Rule. The EPA's proposed approach is simply not to allow any pre-2012 banked credits to transfer into the Transport Rule NOX and SO2 programs. This approach will limit any legal or practical complications involved with the transfer of credits. We agree with the EPA's recommendation that these existing pre-2012 allowances be discarded. [EPA-HQ-OAR-2009-0491-2817.1, p.5]
The EPA should also directly address what is to be done with the additional allowances left under the CAIR program in the time before the new regulations takes effect. If the Transport Rule is passed in the spring of 2011, but does not go into effect 2012, many of the power plants holding additional banked allowances may feel an urgency to either use, or sell, the allowances before they expire. Such a "fire sale" could have an especially adverse effect during the 2001 ozone season (May to September), when ground levels of ozone peak. With no incentive to bank additional allowances, all communities are at an increased risk for increased pollution next summer. [EPA-HQ-OAR-2009-0491-2817.1, p.5]
Response: 
EPA is finalizing the proposed approach of not allowing CAIR allowances to carry over into the Transport Rule programs or to allow the use of Title IV allowances in Transport Rule programs.  See further discussion in Preamble Section IX.  The trend in NOx and SO2 emissions in the first quarter of 2011 compared to 2010 emissions is lower.  Sources have only 6 months to make modifications to emission reduction strategies that would result in increased emissions.  States may take into account the amount of allowances held at the end of 2011 CAIR compliance when making Transport Rule state allocation decisions, so sources may not want to use up the excess as suggested.
Organization: Tennessee Valley Authority (TVA)
Comment: 
Tennessee Valley Authority (TVA)
Even if EPA's assumptions were correct, the agency's approach penalizes early emission reductions under CAIR and thereby seriously undermines confidence in market incentives. Sources invested in controls to make early reductions under CAIR on the faith that those reductions could be banked for future use. The agency's approach under the transport rule penalizes those sources by not allowing these banked allowances to be used after 2011. EPA should eliminate the 2012 compliance deadline in the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2782.1, pp. 4-5]
Response: 
In the final Transport Rule, EPA does not allow the use of CAIR allowances.  State budgets for NOx under CAIR were determined using fuel factors which the court ruled, in the North Carolina decision, was not appropriate.  While CAIR allowances were not necessarily distributed using fuel factors, EPA was concerned that the fuel factors used in the state budgets would be indirectly carried forward into the Transport Rule against the decision of the Court.  The transition between CAIR and the Transport Rule is different than past program transitions.  Generally, EPA would want to maintain value for unused allowances.  EPA gave notice in March 2009 that there was the possibility that CAIR allowances might not have value in the future.  See http://epa.gov/airmarkets/business/cairallowancestatus.html .
Regarding the 2012 compliance deadline, please see preamble section VII.
Organization: Wisconsin Power and Light Company
Comment: 
Wisconsin Power and Light Company
While understanding EPA's concern regarding issuance of a final CATR that can withstand legal challenge, WPL believes that EPA should issue a final rule that does not penalize early reducers of S02 and NOx under the Title IV Acid Rain Program and Clean Air Interstate Rule (CAIR). EPA must continue to provide incentives that promote early action as this has shown historically to achieve greater environmental benefits at reduced costs. It would be short-sighted for the EPA to discourage companies by implementing a policy that would reinforce just in time compliance. EPA must pursue whatever regulatory mechanism possible to preserve and carry-forward the value of Title IV S02 and CAIR NOx allowances as credits for the final CATR. More specifically, WPL supports that EPA allow for all previously banked allowances to be carried forward into the new CATR program at full value. [EPA-HQ-OAR-2009-0491-2844.1 p.4]
Response: 
See preamble section IX.

V.F.4.a. SO2 Allowance Bank/Use of Title IV Allowances

Organization: Air Products and Chemicals, Inc.
Comment: 
Air Products and Chemicals, Inc.
Our comments focus on the proposed rule's impact on 'banked' S02 allowances created under the Clean Air Act's Title IV Acid Rain Program ('Title IV allowances'). Since 1995, Air Products has undertaken aggressive S02 reduction efforts that enabled it to accumulate substantial quantities of Title IV allowances with a significant market value. Like other companies, Air Products saw the prospect of marketing these allowances in the future as a key incentive for achieving these aggressive emission reductions, and a critical way of offsetting their cost. Yet under the proposed Transport Rule, these banked allowances would have drastically diminished marketability - undermining the value of banked allowances as an incentive for 'early reductions' in emissions, and upsetting the reasonable expectations of Air Products and other companies. [EPA-HQ-OAR-2009-0491-2652.1, p. 1]
We believe that the final Transport Rule must include provisions that preserve the value of banked Title IV allowances. At the same time, we appreciate EPA's concern that any such provisions protect the environmental integrity of the Transport Rule and ensure that the final rule is consistent with the D.C. Circuit's opinion in North Carolina v. EPA. In response to EPA's call for comments on the transition to the Transport Rule and treatment of banked Title IV allowances, we outline a policy option that would achieve both objectives. [EPA-HQ-OAR-2009-0491-2652.1, p. 1]
I. Air Products' Banked Title IV Allowances .The issue of banked Title IV allowances is important to Air Products because we relied upon a stable policy framework for Title IV allowances in achieving significant S02 emission reductions. In 1990, Air Products became the General Partner and Operator of Pure Air's Advanced Flue Gas Desulfurization Plant co-located with NIPSCO's Bailly Generating Station (units 7 and 8) in Chesterton, Indiana. The Pure Air facility treats the combined flue gases from two boilers with a total nameplate capacity in excess of 500 MWe, achieving demonstrated removal of more than 95% of the sulfur dioxide emitted from those units. Our unique scrubbing process creates a reusable byproduct, gypsum, which is sold to a third party and manufactured into wallboard products. [EPA-HQ-OAR-2009-0491-2652.1, p. 2]
Since 1995, Air Products has consistently responded to S02 market prices by running the Pure Air scrubbers above the guaranteed removal rate when S02 market conditions were favorable. This practice contributed to faster and deeper reductions in S02 emissions than were initially contemplated under the S02 trading program. At the same time, these emission reductions allowed Air Products to retain valuable Title IV allowances that it expected to be able to sell or use for compliance - an expectation that EPA fostered when it made Title IV allowances the 'currency' of compliance with the S02 limitations in the Clean Air Interstate Rule ('CAIR,,). Under the proposed Transport Rule, however, Title IV allowances would serve no role in demonstrating compliance. As a result, our Title IV allowances are likely to have little or no value if the Transport Rule is promulgated in its present form. [EPA-HQ-OAR-2009-0491-2652.1, p. 2]
It would be both unfair and unwise for the Transport Rule to fail to provide any mechanism for preserving the value of banked Title IV allowances. In any cap-and-trade program, the ability to bank unused allowances encourages owners of emission sources to undertake early and aggressive emission reductions in the hopes of using or selling excess allowances at a later date - just as Air Products did at its Pure Air facility. This feature encourages near-term environmental improvements and optimizes the economic efficiency of the emissions trading program. Moreover, EPA explicitly structured the CAIR rule to retain Title IV allowance values, by requiring Title IV allowances to be submitted to demonstrate compliance with CAIR.5 Companies such as Air Products reasonably expected that their banked allowances would not subsequently be rendered valueless by EPA, especially because (as we point out below) this result was not compelled by the North Carolina decision. If EPA upsets these expectations through regulatory action, emission sources may choose not to rely upon banking under the new Transport Rule or other similar regimes - reducing the environmental effectiveness and economic efficiency of these programs. [EPA-HQ-OAR-2009-0491-2652.1, p. 2]
II. A Proposal for Preserving the Value of Title IV Allowances. For the reasons stated above, it is essential that EPA find a way to ensure that Title IV allowances retain value under the Transport Rule. We propose the following mechanism for doing so in a manner that is environmentally and legally sound. [EPA-HQ-OAR-2009-0491-2652.1, p. 2]
Overview of Proposal. EPA should amend the proposed Federal Implementation Plan (FIP) (and condition approved SIPs that integrate with the Transport Rule's interstate trading program) to allow Title IV allowances to be 'traded in' for a limited quantity of Transport Rule S02 allowances, while retaining all of the other basic features of the State Budgets / Limited Interstate Trading remedy. The essential features of this proposal are as follows: [EPA-HQ-OAR-2009-0491-2652.1, pp. 2-3]
:: In each of the first ten years of the Transport Rule S02 trading program, each state operating under the Transport Rule FIP (or an approved SIP that is integrated with the Transport Rule's interstate trading program) would place 4% of the allowances in its annual S02 budget into an 'Exchange Reserve.' [EPA-HQ-OAR-2009-0491-2652.1, p. 3]
:: Allowances in a state's Exchange Reserve would not be allocated directly to EGUs. Instead, the Exchange Reserve would be made available on an annual basis to entities that are willing to exchange banked Title IV allowances for Transport Rule S02 allowances. Transport Rule S02 allowances obtained from a state's Exchange Reserve would be available for compliance purposes in such state. The traded-in Title IV allowances would be retired. [EPA-HQ-OAR-2009-0491-2652.1, p. 3]
:: The benefits of this provision would be limited to entities that relied on the S02 trading regime under CAIR: a banked Title IV allowance could only be exchanged for a Transport Rule S02 allowance if it was acquired by the holder before the D.C. Circuit issued its opinion in North Carolina (July 11,2008).6 [EPA-HQ-OAR-2009-0491-2652.1, p. 3]
:: Because the number of banked Title IV allowances traded in will substantially exceed the quantity of Transport Rule S02 allowances in the various Exchange Reserves, allowances would not be exchanged at a one-to-one ratio. There are three viable mechanisms for rationing Transport Rule S02 allowances among entities trading in Title IV allowances: [EPA-HQ-OAR-2009-0491-2652.1, p. 3]
1. Reverse auction of Transport Rule S02 allowances. Under this method, each year entities would submit 'bids' that specify both the quantity of Title IV allowances to be traded in and the 'exchange rate' at which they would trade for Transport Rule S02 allowances. Bids would be accepted beginning with those offering the highest exchange rate (i.e., bids that most heavily discounted the Title IV allowances), until the Exchange Reserve is fully claimed.7 [EPA-HQ-OAR-2009-0491-2652.1, p. 3]
2. Pro rata allocation of Transport Rule S02 allowances. Under this method, EGUs would offer Title IV allowances for trade-in each year and would be given a quantity of Transport Rule S02 allowances that corresponds to their share of the total quantity of Title IV allowances traded in for that compliance year (for example, an EGU that contributed 20% of the total quantity of Title IV allowances offered for trade-in would receive 20% of the Transport Rule S02 allowances in the Exchange Reserve). [EPA-HQ-OAR-2009-0491-2652.1, p. 3]
3. Exchange at predetermined ratio. Under this method, EPA would determine an 'exchange rate' in advance. The exchange rate would be set at a level that ensures that the entire bank of pre-North Carolina Title IV allowances is extinguished between 2012 and 2021. [EPA-HQ-OAR-2009-0491-2652.1, pp. 3-4]
Of the three options above, the reverse auction appears preferable because it allows an entity trading in Title IV allowances to have some certainty as to the quantity of Transport Rule S02 allowances it will receive (assuming that the 'bid' is accepted) and avoids the difficult predictions involved in determining the appropriate 'exchange rate' for the Exchange Reserve. [EPA-HQ-OAR-2009-0491-2652.1, p. 4]
:: Depending on the quantity of banked pre-North Carolina allowances that remain and the level of participation in the exchange program, EPA may adjust the size of the Exchange Reserve over the l0-year period of the program to ensure that the exchange ratio of Title IV allowances to Transport Rule S02 allowances remains above 1:1 (or another appropriate minimum). [EPA-HQ-OAR-2009-0491-2652.1, p. 4]
:: EPA should also clarify that in crafting state implementation plans (SIPs) to comply with the Transport Rule, states are free to provide equivalent trade-in mechanisms8 for entities within their own state that hold banked Title IV allowances (even if the SIP does not provide for the state's participation in the interstate trading program established under the Transport Rule). [EPA-HQ-OAR-2009-0491-2652.1, p. 4]
Policy merits. From a policy perspective, our proposal offers several key advantages. First, this proposal would not impair the environmental integrity of the proposed Transport Rule. The proposal merely alters the manner in which Transport Rule S02 allowances would be allocated; it would not allow Title IV allowances to be used directly for compliance or otherwise enable sources covered by the Transport Rule to increase their emissions beyond the proposed state budgets. Second, the proposal would establish a market for Title IV allowances, preserving the credibility of the price signal established under both Title IV and the future Transport Rule program. In doing so, the proposal would give owners of EGUs the confidence in future allowance prices that is necessary to stimulate future long-term investments in early emission reduction. Moreover, the proposal would protect the reasonable expectations of companies who acquired Title IV allowances prior to July 2008 in reliance on explicit policies embedded in the CAlR rule. [EPA-HQ-OAR-2009-0491-2652.1, p. 4]
III. Consistency of the Proposal With North Carolina This proposal is fully consistent with the D.C. Circuit's opinion in North Carolina. In North Carolina, the D.C. Circuit identified two critical flaws with EPA's integration of Title IV allowances into CAlR. First, the D.C. Circuit held that it was improper for EPA to establish state S02 budgets using the Congressionally-mandated allocation of Title IV allowances as a basis. State budgets, reasoned the D.C. Circuit, must ensure that each state eliminates its 'significant contribution' to downwind nonattainment and 'interference with maintenance' of downwind attainment. The D.C. Circuit held that this criterion was unrelated to the allocations made under Title IV of the Clean Air Act, which were intended to address acid rain and were based on antiquated data. Under our proposal, however, state S02 budgets would continue to reflect the quantity of emissions that must be abated to eliminate significant contributions and interference with maintenance. Only the allocation of allowances to EGUs within states would be affected. Thus, unlike CAIR, this proposal would not interfere with the D.C. Circuit's instruction that state S02 budgets comply with the mandate of Section llO(a)(2)(D)(i). [EPA-HQ-OAR-2009-0491-2652.1, p. 4]
Second, the D.C. Circuit held in North Carolina that CAIR unlawfully limited the use of Title IV allowances by requiring those allowances to be submitted for compliance with CAIR at a discounted rate (and requiring states that elected not to join the regional trading program to provide for mandatory retirement of Title IV allowances in their state implementation plans).l0 According to the D.C. Circuit, EPA had no authority to require the termination of Title IV allowances. Because the exchange of Title IV allowances for Transport Rule allowances would be completely voluntary under our proposal, our proposal would not implicate this concern. [EPA-HQ-OAR-2009-0491-2652.1, p. 5]

Footnotes:
5 See 70 Fed. Reg. at 25,258 (noting that EPA decided to require the retirement of Title IV allowances in CAIR in order to avoid 'a significant increase in supply of title IV allowances, the collapse of the price of title IV allowances, the disruption of operation of the title IV allowance market and the title IV S02 cap and trade system, and the potential for increased emissions in all States prior to 2010 ... ')
6 Although the preamble to the Transport Rule indicates that Title IV allowance banks stood at 12 million allowances at the end of 2009, our estimate of the quantity of Title IV S02 allowances banked as of 2008 is between 6 and 6.5 million. This number may have declined in the last two years as pre-2008 allowances were submitted for compliance with CAlR or the Acid Rain Program, or traded to other parties. Thus, our proposal would significantly constrain the quantity of banked Title IV allowances that could be traded in for Transport Rule S02 allowances.
7 For example, a bid offering to trade 1,000 Title IV allowances at an exchange rate of 4:1 would rank higher than a bid offering to trade 2,000 Title IV allowances at an exchange rate of 2: 1. Assuming the quantity of Transport Rule S02 allowances in the Exchange Reserve were equal to 1,250, both bids would be accepted (i.e., the bid offering an exchange rate of 4: 1 would be satisfied first with 250 Transport Rule S02 allowances, and the bid offering an exchange rate of 2: 1 would be satisfied second with 1,000 Transport Rule S0 2 allowances). The auction could be designed either as a 'single price' auction or an 'as bid' auction.
8 To be equivalent, any such trade-in mechanism would be required to be consistent with the Transport Rule's state budget and variability requirements.
Response: 
See preamble section IX and responses to other comments primarily in this section.
Organization: Buckeye Power, Inc.
Comment: 
Buckeye Power, Inc.
Similarly, through its installation of JBR FGD pollution control equipment and purchases of emission allowances, Buckeye acquired Title IV SO2 allowances under the Clean Air Interstate Rule ('CAIR') and other existing and former laws and regulations to comply with existing emission control requirements through 2037. CATR must recognize and reward, rather than punish, Buckeye for its early action on acquiring emission control allowances to comply with existing law. Existing allowances should be accounted for and credited under CATR, not rendered immediately worthless upon the commencement of the new rule. EPA's proposal punishes those, such as Buckeye, who made good faith efforts and long term plans, including the incurrence of substantial costs, to comply with existing law. [EPA-HQ-OAR-2009-0491-2710.1, p.2]
In 2003, SCR equipment was placed in commercial operation on Cardinal Unit No. 2 and Cardinal Unit No. 3, at a total capital cost of approximately $185 million. In 2008, construction of FGD equipment, also known as a sulfur dioxide scrubber, was completed on Cardinal Unit No. 2 and placed into service. The capital cost of Cardinal Unit No. 2 scrubber was approximately $266 million. FGD equipment and associated environmental controls are also being installed on Cardinal Unit No. 3, with construction expected to be completed by December 31,2012, at a capital cost of approximately $489 million. [EPA-HQ-OAR-2009-0491-2710.1, p.4]
Buckeye generates excess NOx emission allowances because of its over-compliance with existing NOx emission limitations based upon its construction and installation of SCR equipment on Cardinal Units Nos. 2 and 3. Buckeye currently sells its excess NOx emission allowances to American Electric Power ('AEP'). [EPA-HQ-OAR-2009-0491-2710.1, p.4]
Buckeye has an unused bank of approximately 260,000 sulfur dioxide emission allowances available to meet its sulfur dioxide emission allowance requirements under CAIR through 2037. A portion of these allowances have been accumulated by Buckeye as a result of the installation of FGD equipment on its Cardinal Unit No. 2 and over-controls with respect to existing emission limitations. Approximately 161,000 of these allowances were purchased by Buckeye at a cost of approximately $25 million. [EPA-HQ-OAR-2009-0491-2710.1, p.4]
Since Buckeye owns two baseload coal-fired generating units at the Cardinal Station and four natural gas-fired peaking units at the Greenville Station, and Buckeye's affiliate, National, owns three natural gas-fired peaking units at the Robert P. Mone Plant, all of which are subject to unit specific allocations of SO2 and NOx emission allowances under EPA's CATR proposal, and because Buckeye has a substantial bank of unused SO2 emission allowances which are subject to loss under EPA's CATR proposal, Buckeye has an interest in this proceeding. [EPA-HQ-OAR-2009-0491-2710.1, p.4]
Response: 
See preamble section IX, responses to other comments and the statement on EPA's website posted continuously since March 2009 http://epa.gov/airmarkets/business/cairallowancestatus.html .
Organization: City Utilities of Springfield
Comment: 
City Utilities of Springfield
If necessary, EPA should find a way to transition to the new program by incorporating the use of Acid Rain allowances as a compliance option  -  perhaps at some premium ratio  -  during the first few years. [EPA-HQ-OAR-2009-0491-2721.1 p.6]
Response: 
As discussed in preamble section IX, EPA does not believe that the North Carolina decision would allow the incorporation of Title IV allowances in any aspect of the final Transport Rule.  The North Carolina decision states that "SO2 petitioners argue EPA lacks the authority to terminate or limit Title IV allowances, either through a trading program under section 110(a)(2)(D), 42 U.S.C. Section 7410(a)(2)(D), or by requiring that SIPs have allowance retirement provisions.  We agree and grant the petition on this issue."
Organization: E.ON U.S.
Comment: 
E.ON U.S.
A mechanism for awarding additional SO2 allowances as Early Reduction Credits should be established. [EPA-HQ-OAR-2009-0491-2797.1, p.9]
The number of Early Reduction Credits (ERC's) should be based on the number of banked SO2 allowances facilities developed under the CAIR SO2 Program (i.e., the number of Title IV allowances issued minus emissions, for each year CAIR is in effect). This would not be using Acid Rain SO2 allowances, which was determined to be unlawful by the Court. Rather, it would base the number of ERC's awarded on how much a company has emitted below its allowable emissions, as measured by the number of banked allowances. This represents reductions in contribution to air quality degradation in downwind states that facilities have already made, ahead of the requirement to do so by the Proposed Transport Rule [EPA-HQ-OAR-2009-0491-2797.1, pp.9-10]
Response: 
As discussed in preamble section IX and in responses to similar comments, EPA cannot terminate or limit title IV allowances.  In order to implement the mechanism suggested by the commenter, EPA would need to require that Title IV allowances be turned in exchange for Transport Rule SO2 allowances.  EPA does not believe such a mechanism is consistent with the North Carolina decision.
Organization: Exelon
Comment: 
Exelon
Finally, the court held that the CAIR trading program impermissibly related the states' SO2 reductions to Title IV allowances. By coordinating each state's SO2 reductions with Title IV allowances, EPA was found to have exceeded its authority under Section 110 by unlawfully tampering with the Title IV trading program. In the proposed rule, EPA would create new Transport Rule SO2 allowance currencies and set state SO2 budgets without regard to the Title IV program. EPA explicitly states that Title IV SO2 allowances could not be used to comply with Transport Rule. Exelon believes that these measures in the proposed Transport Rule remedy the deficiency identified by the court. EPA is continuing to consider using Title IV SO2 allowances banked as of December 31, 2011, as a tool for allocating new Transport Rule SO2 allowances. While this approach might be thought to reward early reductions in SO2 emissions, and to avoid a surge in 2011 SO2 emissions by retaining some value, Exelon believes that EPA should reject this approach. In light of the court's strong condemnation of any linkage between the statutory Title IV program and the regulatory CAIR program, the use of Title IV SO2 allowances even as a tool to allocate a new allowance currency poses an unnecessary litigation risk to the implementation of the Transport Rule. [EPA-HQ-OAR-2009-0491-2666.1, p.11]
Response: 
As discussed in section IX of the preamble to the final rule and in responses to similar comments, EPA is finalizing an allocation methodology that does not rely on title IV allowance holdings.
Organization: Florida Electric Power Coordinating Group, Inc. (FCG)
Comment: 
Florida Electric Power Coordinating Group, Inc. (FCG)
In North Carolina v. EPA. the court prohibited EPA from interfering with the Title IV program or allowance market through this rulemaking. Yet EPA readily admits that the proposed Transport Rule will decimate the value of Title IV allowances, and references an analysis that the Title IV allowance price will be 'nearly zero.' 75 Fed. Reg. 45340. This nearly complete diminution in value substantially interferes with Title IV, and is thus contrary to North Carolina v EPA. EPA fails to provide a reasoned justification for this result. [EPA-HQ-OAR-2009-0491-2658.1, p.5]
Because EPA's proposed action would destroy the value and usefulness of banked allowances, EPA's action would be tantamount to direct appropriation of the banked allowances. The Title IV allowance bank represents early emissions reductions by sources in the Acid Rain Program. Source owners and operators made and implemented early reductions with the reasonable expectation that banked Title IV allowances would continue to have value in the future. EPA's proposed action would clearly interfere with these distinct investment backed expectations, yet EPA fails to adequately provide a reasoned justification for this appropriation and deprivation of Title IV allowance holders' interests in their banked allowances. Simply arguing that allowances are not a 'property interest' does not alter the consequences of EPA's proposal. [EPA-HQ-OAR-2009-0491-2658.1,p.5-6]
Response: 
See preamble section IX.
Organization: Florida Municipal Electric Association (FMEA)
Comment: 
Florida Municipal Electric Association (FMEA)
EPA's failure to craft a proposal that allows the use of banked Acid Rain SO2 allowances and banked CAIR NOX allowances creates distrust in market-based control strategies: EPA could create a mechanism that would permit SO2 Acid Rain allowances to serve as an alternative "currency" for Transport Rule SO2 allowances. In addition, EPA could also adjust banked post- 2012 NOx allowances to remove the CAIR fuel factor adjustment for use in the Transport rule. It is noted that the Court did not completely rule out use of Acid Rain SO2 or NOx allowances for CAIR, just the way EPA did it. FMEA believes that EPA needs to consider the negative long range policy implications of abrogating programs and regulatory provisions that the utility industry has depended upon in making major financial and compliance decisions. [EPA-HQ-OAR-2009-0491-2731.1, p. 11]
Response: 
See preamble section IX.
Organization: George Washington University Regulatory Study Center
Comment: 
George Washington University Regulatory Study Center
Because of concern with the size of the SO2 and NOx banks, the EPA proposes not to allow the transfer of CAIR or Title IV SO2 allowances into the Transport Rule programs at all. For SO2 allowances, the agency cites specific reasons for its legal concerns. The EPA attempted in the CAIR rule to provide a continuing role for existing Title IV allowances in the new CAIR SO2 market by requiring the exchange of two or more Title IV allowances for each ton of SO2 emissions in the CAIR region. The North Carolina v. EPA court rejected this approach, holding that the EPA lacked authority under the CAA to modify the 1:1 relationship between Title IV allowances and tons of SO2 emissions specified in the CAA. Any attempt by the EPA to modify this relationship in the Transport Rule would presumably be deemed illegal as well. This is a somewhat perverse result because the tighter SO2 cap created by the Transport Rule in the states it covers would render Title IV allowances held by emitters largely valueless11 -- seemingly a more significant interference than modifying the statutorily-specified relationship or exchanging Title IV allowances for new Transport Rule allowances would be. Nevertheless, the result of North Carolina appears to be that the EPA has the authority to create a new SO2 trading program but no authority to allow the use of Title IV SO2 allowances in that new program with an exchange ratio that differs from 1:1. [EPA-HQ-OAR-2009-0491-2573.1, p.7]
Altering the exchange ratio of banked Title IV allowances directly is not, however, the only way those allowances could be accounted for in the Transport Rule. Neither the North Carolina decision nor the EPA's legal analysis in the Transport Rule appear to preclude the agency from basing allocation of new Transport Rule SO2 allowances on the volume of banked Title IV allowances held. Such an approach would be conceptually and perhaps practically similar to the Compliance Supplement Pool (CSP) system used in transitions between earlier programs for regulating NOx emissions.12 This would not modify the relationship between Title IV allowances and tons of emissions specified in the CAA since emitters would still hold and use their Title IV allowances, but would preserve the expectations embodied in banked Title IV allowances in a new form for use in complying with tighter Transport Rule emissions caps. [EPA-HQ-OAR-2009-0491-2573.1, pp.7-8]
A counterargument is that such a move would be a too-clever-by-half rebranding of the same meddling with Title IV allowances that the North Carolina court rejected. Nevertheless, it would be a much more modest interference with Title IV allowances than the Transport Rule as written would be. If compliance with the spirit as well as the letter of Title IV is required, such a CSP approach would be problematic, but so would the Transport Rule's treatment of SO2 allowances (or indeed almost any major regulation of SO2 emissions), as EPA projects that Title IV allowances will trade at market prices close to zero after the Transport Rule SO2 market begins. [EPA-HQ-OAR-2009-0491-2573.1, p.8]
We further recommend that EPA investigate the possibility of using a compliance supplement pool to allow crediting of banked Title IV SO2 allowances in allocation of Transport Rule allowances. Doing so would have similar benefits to transition of NOx CAIR allowances. [EPA-HQ-OAR-2009-0491-2573.1, p.32]

11 Title IV allowances might not be entirely without value since those allocated for emissions above the Transport Rule cap amount could be traded to emitters in states not covered by the transport rule.  
12 Specifically, the OTC - NOx SIP Call and SIP Call-CAIR seasonal NOx transitions used compliance supplement pools.
Response: 
See preamble section IX and responses to other comments primarily in this section.
Organization: Massachusetts Department of Environmental Protection
Attorney General of North Carolina
Maryland Department of Environment (MDE)
Adirondack Council
Comment: 
Adirondack Council
With over 12 million SO2 allowances currently in the "bank," it is apparent that our calls for lower caps and ways to reduce the bank are needed immediately. By EPA creating a new scheme and not allowing Title IV SO2 allowances to be used as part of this program, you are rightly correcting a major flaw. [EPA-HQ-OAR-2009-0491-2848.1, p.3]
[These comments were also submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.65.]
Attorney General of North Carolina
a. Pre-existing allowances
EPA has proposed not to allow sources to use pre-existing Title IV allowances to meet the compliance requirements of the Transport FIP. For the reasons stated by EPA, 75 Fed. Reg. at 45,338/3, North Carolina concurs that the importation of banked Title IV allowances into the Transport FIP program would contravene the Clean Air Act as interpreted by the D.C. Circuit in North Carolina. [EPA-HQ-OAR-2009-0491-2685.1]
Maryland Department of Environment (MDE)
Maryland agrees with EPA and its interpretation of the Court's decision, that any approach to use the Title IV SO2 allowances is "...not related to, much less necessary for, implementation of the section 110(a)(2)(D)(i)(I) mandate to eliminate significant contribution and interference with maintenance" (75 FR 45338). We also agree with EPA that the existing NOx allowances banked under either the NOx SIP call or CAIR program should not be used as part of the proposed Transport Rule remedy. Similar to the Title IV SO2 allowances, NOx allowances banked under the NOx SIP Call were designed for a different purpose; i.e., to address transport issues associated with the 1-hour ozone NAAQS. And pre-2012 CAIR allowances are associated with a program that was found inadequate by the Court that is to be replaced by the program in the proposed Transport Rule; when CAIR is replaced any allowances banked under that program should therefore not convey. [EPA-HQ-OAR-2009-0491-2639.2, p.14; This comment can also be found at section V.F.4.b of this comment summary]
Massachusetts Department of Environmental Protection
With respect to the state budgets, EPA has proposed significant SO2 reductions in 2012 and 2014, which we strongly support. We applaud EPA's proposal to prohibit the use of Acid Rain Program SO2 allowances in the Transport Rule annual SO2 programs, which we believe will provide an incentive for power plants to install controls.
Response: 
As explained in Section IX C of the preamble, EPA has created new Transport Rule SO2 allowances rather than allow the use of any title IV allowances in the Transport Rule program.
Organization: Morgan Stanly Capital Group
Gainesville Regional Utilities (GRU)
Comment: 
Gainesville Regional Utilities (GRU)
EPA's Failure to Craft a Proposal that Allows the Use of Banked Acid Rain SO2 Allowances and Banked CAIR NOx Allowances Creates Distrust in Market-based Control Strategies
EPA could create a mechanism that would permit SO2 Acid Rain allowances to serve as an alternative 'currency' for the proposed CATR SO2 allowances. In addition, EPA could also adjust banked post-20l2 NOx allowances to remove the CAIR fuel factor adjustment for use in the proposed CATR. It is noted that the Court did not completely rule out the use of Acid Rain SO2 or NOx allowances for CAIR, just the way EPA did it. GRU believes that EPA needs to consider the negative long range policy implications of abrogating programs and regulatory provisions that the utility industry has depended upon in making major financial and compliance decisions. [EPA-HQ-OAR-2009-0491-2674.1, pp.7-8; this comment can also be found at V.F.4.b of this comment summary]
Morgan Stanly Capital Group
In addition, the Proposed Rule currently does not permit the transfer of banked SO2 allowances from prior emissions trading programs.16 This will adversely impact emissions trading markets where clear and consistent rules are needed to limit uncertainty and assure a smoothly functioning market. Indeed, the Proposed Rule has already resulted in a marked devaluation of emissions credits.17 Such devaluation will discourage market participants from making early emissions cuts and banking credits, and incentivize the use of allowances now being held so as to increase the level of short-term emissions. Thus, banked allowances would not be available to cushion the effects of lower budgets during the transition to operation under the program now described in the Proposed Rule. The new trading program could well be marginalized, and therefore less effective in achieving abatement benefits at a lower cost. [EPA-HQ-OAR-2009-0491-2819.1 p.5]
The Administrator should carry forward all existing allowances on a one-to-one basis under the Proposed Rule. This approach would be consistent with principles of equity and would help to maintain the underlying integrity of the Proposed Rule. Therefore, all unretired allowances issued under prior emissions programs should be fully convertible to the new program's allowances, and distributed on a one-for-one basis before further distribution from the allowance pool. [EPA-HQ-OAR-2009-0491-2819.1 p.9-10]
Response: 
See preamble section IX and responses to similar comments.
Organization: RBS Sempra Commodities
Comment: 
RBS Sempra Commodities
EPA collected revenue from the sale of SO2 allowances in the 2010 SO2 Allowance Auction while at the same time developing proposals to effectively eliminate their value through a rule change. Despite uncertainty about the EPA's response to court rulings related to CAIR, that program remained in effect as the prevailing rule at the time of the auction. Since EPA's actions directly impacted the value of allowances sold in the auction, EPA should develop an exchange mechanism for existing allowances or reimburse participating parties upon surrender of allowances purchased in the 2010 SO2 Allowance Auction. [EPA-HQ-OAR-2009-0491-2862.1 p.1]
The original Acid Rain Program was successful in large part because market participants were confidently able to make forward-looking decisions based on clear rules, forward allocations, and banking provisions. Abandoning CAIR and failing to bank existing allowances will diminish confidence in the environmental markets and thereby counteract efforts to develop a fair and efficient "replacement" market. [EPA-HQ-OAR-2009-0491-2862.1 p.1]
Response: 
While EPA would like to offer the kind of continuity of allowance value described by the commenter, EPA believes that the North Carolina decision is very clear with regard to Title IV allowances.  As discussed in preamble section IX and in responses to other similar comments, EPA does not believe that it is consistent with the Court decision to implement any allocation, allowance exchange or reimbursement for Title IV allowances.  The auction mentioned by the commenter was conducted as required by the CAA for Acid Rain Program requirements.
Do I need to add something about the TR being more stringent and the Acid Rain market reacting to lower future emissions?
Organization: Southern California Edison Company
Comment: 
Southern California Edison Company
Upon review of the proposed CATR, SCE is concerned and disappointed at the extent to which CATR would effectively supplant the Title IV allowance trading program with a new, wholly separate program, greatly devaluing the Title IV SO2 allowances. SCE understands that the value of Title IV allowances is generally projected to be at or close to zero if CATR is adopted. Adoption of CATR would thus mean a significant total impact on SCE's customer base through electric utility rates, and more broadly it would have the effect of penalizing companies (and their customers) that have been most proactive in reducing their SO2 emissions below their allocation levels. SCE also believes this would send an especially unfortunate signal to companies and markets at a time when other emissions cap and trade proposals are under consideration and Title IV has been held up as a model of a successful program. [EPA-HQ-OAR-2009-0491-2852.1 p.1]
In particular, it is unclear to SCE why the CATR program should not allow affected emitters to use Title IV allowances for CATR compliance (on top of all allowances they need to use for Title IV compliance), at least as an optional alternative to use of CATR-created allowances. CATR's establishment of state-specific SO2 budgets would still mean that the same emission reductions in each state are achieved, as far as SCE can determine, despite the availability of another allowance source for CATR compliance. Indeed it is unclear to SCE from the proposed rule and its preamble whether EPA even gave any consideration at all to such a construct. [EPA-HQ-OAR-2009-0491-2852.1 p.2]
This points up another concern of SCE's regarding the CATR proposal, and that is that as far as SCE can tell from the proposal and its supporting materials, EPA gave little or no weight in drafting CATR to the question of the rule's impact on Title IV allowance values, perhaps unduly skewing the rule development process towards an outcome costly to allowance holders. SCE understands that allowance holders do not have a "property rights" interest in their allowances, at least in some respects, but in its rulemakings EPA routinely and properly considers cost impacts that would not amount to impacts on property rights.  [EPA-HQ-OAR-2009-0491-2852.1 p.2] 
Response: 
See preamble Section IX.
Organization: Southern Company
Comment: 
Southern Company
IX. EPA Must Consider Market Continuity as it Transitions from CAIR to the Proposed Transport Rule and Any Future Transport Rules
EPA has requested comment on how the transition from CAIR would occur. One of our main concerns with the proposed transition from CAIR, is the proposed elimination of banked allowances and the uncertainty that such elimination creates for compliance. There are no markets yet for Transport Rule allowances, and those markets will not exist until September 2011, just before the January 2012 compliance date. As discussed in more detail in Section X, the data used to develop unit allocations in the proposed rule are so flawed and will require such substantial revision that industry is essentially blind to potential compliance challenges. Given the limited trading and industry-wide allocation uncertainty, it is unclear whether allowances will be available if needed. And the Transport Rule's proposed tight compliance schedule exacerbates the uncertainty. [EPA-HQ-OAR-2009-0491-2864.1, p. 22]
Southern Company supports an approach that would recognize the value of banked NOx and SO2 allowances. EPA should recognize the potential loss to utilities-and the eventual cost to customers-by devaluing or eliminating a company's allowance inventory. At a minimum, EPA should include a mechanism the conversion of CAIR NOx into the Transport Rule program. This would be technically easy to accomplish since EPA proposes to use the same Allowance Management System that it used for CAIR. The conversion of banked CAIR allowances will ensure market continuity through 2011 and will avoid potential price shocks of resetting three new markets simultaneously in the second half of 2011. Subsequently, market continuity will ensure that reductions achieved under CAIR will continue through 2011 and avoid any incentive to 'use up' CAIR allowances and produce a short-term increase in NOx emissions (the same is also true for Acid Rain S02 allowances). The North Carolina decision found flaw with use of fuel adjustment factors in determining original CAIR NOx allowance allocations, however nothing in the decision prohibits the use of existing banked allowances in a new program. In the event that EPA determines the legal concerns are too great to carry the bank forward at full value, Southern Company could support an alternative approach allowing banked allowance conversion at a discounted value. EPA should design a process that effectively eliminates fuel adjustment factor effects by applying a surrender ratio based on the fuel mix of the surrendering entity. To avoid use of conversion proxies (financial institutions on behalf of utilities), allowances could be converted in rounds, with utilities surrendering in the first round followed by a non-utility surrender round. The second round would receive the highest conversion rate applied in the first round, thereby ensuring incentive for utilities to participate in the first round and not utilize conversion proxies. This discounted conversion approach is not preferable, but would achieve some of the objectives of market continuity outlined above. [EPA-HQ-OAR-2009-0491-2864.1, pp. 22-23]
EPA has stated that future transport rules 'may be needed to address transport under future revised ozone or fine particle health standards.,,2o Subsequent phases of the Transport Rule should ensure market continuity by maintaining a common currency, allowing use of existing allowances from one phase to the next. A market based program cannot be expected to work if the currency is continuously changing and price signals are disrupted on a regular basis. Further, EPA should wait to see the effect of the current rule before promulgating future transport rules.  [EPA-HQ-OAR-2009-0491-2864.1, p. 23]
[The above comments can also be found at Section V.F.4.b. of this comment summary.]
Response: 
See responses to other comments and preamble section IX.
Organization: Tampa Electric Company
Comment: 
Tampa Electric Company
In North Carolina v. Environmental Protection Agency, 531 Fed 3rd 896, 922 (DC Cir. 2008) the Court held that EPA lacked authority to terminate or limit Title IV allowances in this rulemaking. EPA cited this holding in rejecting an alternate allowance allocation scheme proposed by a member of the regulated community in this proceeding. However, it appears that the current proposal, if finalized, will result in the elimination of the value of banked Title IV allowances since compliance with the Transport Rule will adversely impact demand for banked Title IV allowances as emissions decrease. EPA has acknowledged this but provided no explanation or justification for the projected interference with the Title IV Allowance Program (75 FR at 45340 col 2). [EPA-HQ-OAR-2009-0491-2745.1 p.3]
Although the proposed Transport Rule does not directly impact the banked Title IV allowances, the result of this indirect impact on the value by reducing it is the same as if EPA had directly appropriated the allowances. A similar result is expected in the case of CAIR allowances for calendar years 2012 and beyond. These would become worthless as a result of finalization of the proposal in its current form. All of these allowances have value to Tampa Electric Company's customers and EPA has provided no rationale or justification for this interference or the failure to provide a mechanism for compensation for what amounts to a taking in violation of the United States Constitution [EPA-HQ-OAR-2009-0491-2745.1 p.3]
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.73.]
The proposed Transport Rule may not have specifically touched the Acid Rain allowances, but has certainly affected their value and any banking strategies by utilities that have committed to early reductions. These useless allowances are an additional cost born by the rate payers, first for the emissions reduction controls installed and now the inability to recoup fuel cost savings.
Response: 
See preamble section IX.
Organization: Tennessee Valley Authority (TVA)
Comment: 
Tennessee Valley Authority (TVA)
B. Issue: EPA proposes that the Transport Rule provisions not allow the use of Title IV allowances either as the basis for allocating Transport Rule SO2 allowances or directly for compliance with the rule's allowance-building requirements, but invites comment on this matter. [p. 45338-39] [EPA-HQ-OAR-2009-0491-2782.1, p. 13]
TVA Comment: EPA requests comment on whether it could distribute Transport Rule allowances based on the number of Title IV  allowances a source has in its bank at the completion of compliance in the last year of the CAIR SO2 program, thereby incentivizing minimal use, by sources, of Title IV allowance banks and encouraging continued emission control. We believe that any such distribution of allowances would not be consistent with the Court's opinion in North Carolina v. EPA because it places a burden on the use of Title IV allowances. Under such an approach, EPA would be requiring the diversion of Title IV allowances for use in a trading program under Section 110(a)(2)(D). The D.C. Circuit held that "EPA lacks authority to terminate or limit Title IV allowances, either through a trading program under Section 110(a)(2)(D) . . , or by requiring that SIPs have allowance retirement provisions." North Carolina v. EPA, 531 F. 3d 896, 921 The Court found "nothing in . . .[the CAA] granting EPA the authority to remove Title IV allowances from circulation in the Title IV market." Id. EPA also seeks comment on whether it should allow the use of Title IV allowances for use in the trading program under the proposed Transport Rule. Any such voluntary use of the Title IV allowances was not prohibited by the Court in North Carolina v. EPA. It was not the use of Title IV allowances as "currency" in the CAIR market that the court found objectionable. Rather, the court objected to EPA "terminat[ing] the authorization the allowances provide within the Title IV market." Id. at 922-----. Moreover, the allowances in the Title IV bank result both from the emission reductions for Title IV and the early reductions for the CAIR SO2 program. As to the latter (i.e. the early reductions from the CAIR SO2 program), there should be no question as to their use to meet the requirements of the Transport Rule. Of course, the use of any Title IV allowances in meeting the requirements of the Transport Rule would remain subject to the assurance provisions that ensure each state eliminates all significant contributions to nonattainment and interference with maintenance in downwind states. [EPA-HQ-OAR-2009-0491-2782.1, pp. 13-14]
Elimination of the CAIR SO2 allowance banks would be unfair to utilities that installed controls at certain facilities early to bank allowances, and planned, as the CAIR rule allowed, to use these banked allowances to provide for an optimum transition to and time for installation of controls to meet future lower CAIR allocation levels. Eliminating these allowances will also reduce confidence in and hinder implementation of any future cap and trade programs, such as the trading program in the very Transport Rule proposed by EPA as well as those trading programs that have been included in draft legislation for greenhouse gases. Moreover, depressed allowance values prior to 2012 could result in increased emissions. [EPA-HQ-OAR-2009-0491-2782.1, p. 14]
Response: 
See preamble section IX.

V.F.4.b. NOx Allowance Banks/Use of CAIR NOx Allowances

Organization: Adirondack Council
Comment: 
Adirondack Council
The same holds true for nitrogen allowances. We recommend that old allowances not be used as part of the new program. If, however, you decide to allow existing nitrogen credits to be used, we suggest that you establish a discounted rate for banked NOX allowances, either at a 3:1 or 4:1 ratio. [EPA-HQ-OAR-2009-0491-2848.1, p.3]
[These comments were also submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.65.]
EPA requests comment on the proposed approach, the previously-discussed alternative approaches, and any other possible approaches for handling banked pre-2012 CAIR allowances in the Transport Rule NOX programs. (p. 581) The Adirondack Council's preferred option for banked pre-2012 CAIR NOX allowances is to not let them into the Transport Rule program at all. However, if EPA does decided to allow the use of CAIR allowances, we suggest a deeply discounted ratio of either 3:1 or 4:1 in order to help maintain the benefits of the program that EPA has envisioned. [EPA-HQ-OAR-2009-0491-2848.1, p.5]
Response: 
EPA is not allowing CAIR NOx allowances to be used in the Transport Rule.  See preamble section IX.
Organization: Allegheny Energy
Comment: 
Allegheny Energy
Because the proposed rule does not eliminate the ARP, AE assumes it will continue to receive allowances under that allocation program and will continue to surrender ARP allowances on a one to one basis to cover the company's S02 emissions. AE further understands that the proposed rule does replace CAIR in its entirety and that EPA is seeking comment on how to handle the CAIR NOx allowances. AE supports carrying these allowances into the proposed rule and allowing full banking within the proposed rule. Given the extraordinarily short time frames to implement the proposed rule, EGUs will need allowances from the CAIR program to cover NOx emissions across their respective fleets. New NOx controls will be installed in the most economical manner, but every electric generator in the affected 31 states will be vying for the same control equipment and labor to install the control equipment. This will slow the process dramatically. A reasonable bridge will be the use of banked CAIR NOx allowances to cover emissions until such time as the reductions contemplated by the proposed rule can be implemented. [EPA-HQ-OAR-2009-0491-2605.1, p.3]
Response: 
See preamble Section IX.  Also, EPA is confirming that the Acid Rain Program will continue, Title IV allowances will be allocated as provided under that program, and allowances will continue to be required for compliance.
Organization: Ameren Services Company
Comment: 
Ameren Services Company
EPA should also consider allowing all or a portion of CAIR NOx allowances banked prior to 2012 to be used for compliance with the Transport Rule. This would allow more flexibility in meeting the strict limits during Phase I starting in 2012. This is necessary considering the rule as proposed basically allows only 6 months (assuming it is finalized in June 2011) to plan for compliance. [EPA-HQ-OAR-2009-0491-2722.1, p.9]
A portion of CAIR NOx allowances should be carried forward into the Transport Rule.
Many utilities have installed SCR and SNCR to meet the requirements of the CAIR and various state and local requirements. Many of these controls were installed to allow for trading of NOx allowances to support other uncontrolled sources as well as to bank allowances to supply a cushion in case of poor performance or failure of the control device to perform as designed. Additionally, Ameren as well as other utilities has used the NOx allowances banked by installation of SCR or SNCR in their planning processes to allow for an orderly, fiscally responsible plan for compliance. The Transport rule as currently proposed basically nullifies the previous compliance plans and strands a valuable asset. [EPA-HQ-OAR-2009-0491-2722.1, p.10]
Ameren supports carrying CAIR NOx allowances, both for the annual and ozone season programs into the Transport Rule. EPA should give consideration for carrying forward at least a portion of the NOx allowances banked prior to 2012 to aid in the mitigation of lost value from both a planning perspective as well as the loss of valuable assets. [EPA-HQ-OAR-2009-0491-2722.1, p.10]
Response: 
See preamble Section IX.
Organization: American Municipal Power, Inc. (AMP)
Comment: 
American Municipal Power, Inc. (AMP)
Allowance Provisions Should Be Flexible and Fair
AMP encourages EPA to design a final Transport Rule that allows full transfer of banked CAIR allowances into the new trading program. We respectfully disagree with EPA's concern that the CAIR allowance fuel adjustment factors will provide unjust allowance banking by certain units. These CAIR allowances have already been allocated and reliance on the use of the CAIR allowances is certainly reasonable and to be expected as part of long-range planning. Additionally, the Court did not address this issue in its consideration of the existing CAIR program; thus, the Court has not precluded the transfer of the allowances. The maintenance and use of the CAIR allowances is important to municipal generators and will provide increased flexibility in the initial years of the new program. [EPA-HQ-OAR-2009-0491-2678.1, p.3]
Response: 
See preamble section IX and responses to other comments in this section.
Organization: American Public Power Association (APPA)
Comment: 
American Public Power Association (APPA)
APPA also emphasizes, however, that it supports approaches that would permit the use of banked CAIR NOx allowances for compliance with the Proposed Transport Rule. In the final rule, EPA should provide that it will transfer all CAIR NOx annual and ozone season allowances held in each source`s compliance accounts for the final compliance period of CAIR into that source`s compliance accounts for the new program (to the extent the source is subject to the new program`s annual or ozone season NOx requirements, or both). This could readily be accomplished because, for purposes of compliance with the new program, EPA proposes to use the same Allowance Management System ("AMS") that it used for compliance with CAIR. 75 Fed. Reg. at 45312/1. There is no reason not to allow sources to use their CAIR allowances (including allowances that they bought or otherwise acquired from others) for compliance with the new program). [EPA-HQ-OAR-2009-0491-2812.1, pp.11-12]
EPA`s concern that some may view an approach that authorizes sources to use banked CAIR NOx allowances as unfairly permitting some sources a larger share of allowances due to CAIR`s use of fuel adjustment factors, which the North Carolina decision found EPA had not adequately justified, is no basis to bar use of these allowances already allocated. The court`s opinion in no way bars use of these already-allocated allowances, on a banked basis, in a new program. APPA believes that if EPA disallows use of banked CAIR NOx allowances at this juncture, it will be to the detriment of all sources that hold banked CAIR NOx allowances at the time that CAIR expires. It would be far better to allow all sources the benefit of their banked allowances than to render them worthless at the end of the CAIR program. 7 [EPA-HQ-OAR-2009-0491-2812.1, p.12]
Indeed, there are many compelling reasons to allow sources to use their banked CAIR NOx allowances for compliance with the proposed rule. First, as noted above, nothing in the court`s North Carolina opinion precludes -- and in fact, no party challenged -- use of banked CAIR NOx allowances. The only flaw identified by the court with respect to CAIR NOx allowances was the way that the U.S. EPA established NOx allowance budgets. Second, as EPA suggests, permitting use of banked CAIR NOx allowances would promote the continuation in 2010 and 2011 of the reductions that occurred under CAIR. 75 Fed. Reg. at 45339/1. Likewise, it would avoid creating an incentive for sources to "use up" CAIR NOx allowances, thereby potentially increasing their NOx emissions temporarily, because those allowances would -- in the absence of a provision allowing use of banked CAIR NOx allowances in the new program -- have no value after the allowance transfer deadline for the final CAIR annual and ozone season compliance periods. Third, allowing use of banked CAIR NOx allowances would provide a modest degree of increased flexibility for sources during the early years of the new program, an especially important consideration if EPA requires compliance with the Transport Rule according to the unreasonably accelerated schedule set forth in its proposal. [EPA-HQ-OAR-2009-0491-2812.1, p.12]

7. If EPA is concerned that the amount of banked CAIR NOx allowances is so great that it may reduce the amount of emission reductions that would otherwise be achieved under the proposed rule, 75 Fed. Reg. at 45339/1, there are better ways to avoid that outcome than to invalidate the allowances in whole or in part. For example, EPA could allow sources the full benefit of their banked CAIR NOx allowances, but "stagger" the right to use them over time. Under this sort of strategy, EPA could record the number of banked NOx allowances in each source`s account as of the expiration of CAIR and then divide them into parcels and assign each parcel a vintage year. Each year thereafter, for a relatively short period of years, a parcel of allowances would become valid and could be used for compliance with the Proposed Transport Rule in that year (or any subsequent year). This way, sources would get the full benefit of their banked CAIR NOx allowances without running the risk of allowing a large number of banked allowances to enter the system in any one year. [EPA-HQ-OAR-2009-0491-2812.1, p.12]
Response: 
See preamble section IX and responses to other comments in this section.
Organization: Associated Electric Cooperative, Inc. (AECI)
Comment: 
Associated Electric Cooperative, Inc. (AECI)
EPA has proposed to dissolve any remaining CAIR NOx allowances at the onset of the Transport Rule. This action will serve to provide a perverse incentive for utilities to throttle back emissions controls and consume as many CAIR NOx allowances as possible to save reagent cost of ammonia and urea since the CAIR allowances would be effectively turn into "confederate money" as of 2012. The result will be (at least) threefold: 1) a negative impact to air quality in 2011, 2) a penalty to utilities that over controlled and/or banked allowances from early reductions in prior years, and 3) asset uncertainty and price depression due to a fear that EPA may devalue future markets. EPA should allow for portability of banked CAIR NOx allowances into the Transport Rule  -  even if at a reduced rate.   [EPA-HQ-OAR-2009-0491-2845.1 p.8]
CAIR included a compliance supplement pool (CSP) at the onset of the rule. The Transport Rule does not. In the absence of a CSP, utilities should be able to borrow a limited number of allowances from future years at a ratio of less than one allowance per ton of emissions.  [EPA-HQ-OAR-2009-0491-2845.1 p.8]
Request: AECI requests that EPA allow CAIR NOx allowances to be grafted in to the Transport Rule. EPA could use methodology similar to the Progressive Flow Control mechanism of the NOx Budget Program to determine a conversion ratio for transferring allowances from CAIR to the Transport Rule. Allowing the CAIR allowances to survive, even at a reduced rate, would maintain some market integrity and avoid the environmental impact described above.  [EPA-HQ-OAR-2009-0491-2845.1 p.8]
Request: In addition to allowing for portability of CAIR NOx allowances into the transport rule, AECI requests that EPA amend the Transport Rule to allow for using future compliance year allowances at a reduced value.  [EPA-HQ-OAR-2009-0491-2845.1 p.8]
Under CAIR, certain states were required to comply with both an ozone season cap as well as an annual cap for NOx. Some states, such as Missouri, are no longer required to comply with the ozone season cap under the Transport Rule. Most utilities in these states achieved emission reductions greater than what was required under the NOx Budget Program and the CAIR and have banked ozone season NOx allowances. Dissolving these allowances would penalize these companies for making early/additional reductions under these preceding programs.   [EPA-HQ-OAR-2009-0491-2845.1 p.8]
Request: AECI requests that EPA amend the proposed rule to convert a portion of the CAIR ozone season allowances to permanent annual allowances in the Transport Rule. In addition to affording a small (earned) compliance supplement, it would achieve a certain level of market integrity going forward.  [EPA-HQ-OAR-2009-0491-2845.1 p.8]
Response: 
See preamble section IX regarding the CAIR NOx allowances.  Transport Rule allowances are available for use for compliance in the vintage year that is the same or earlier than the compliance period.  Sources may not use future vintage allowances.  The comment is vague and does not specify how far into the future the allowances could be borrowed or at what discount rate.  Such a provision would undermine the design of the Transport Rule which relies on state budgets and assurance provisions to ensure that the required emission reductions are achieved in each state, each year.  A provision such as this would have the effect of providing unlimited budgets; therefore, EPA rejects the comment.
Organization: Attorney General of North Carolina
Comment: 
Attorney General of North Carolina
EPA appears less certain regarding the fate of CAIR NOX allowances. North Carolina submits that the importation of CAIR NOX allowances would also violate the Clean Air Act.
EPA attempts to justify the importation, at some level, of CAIR NOX allowances on the grounds that, allowing pre-2012 CAIR NOX allowances and CAIR NOX ozone season allowances to be used in the proposed Transport Rule NOX programs, and thereby ensuring that the allowances would continue to have some market value in the future, would promote the continuation  -  in 2010 and 2011  -  of the reductions that occurred in 2009 under the CAIR NOX programs. Id. at 45,339/1. However, EPA readily concedes that "the amounts of the banks are so large that they might significantly reduce the amount of emissions reductions that would otherwise be achieved in the proposed Transport Rule NOX programs, particularly in the earlier years (e.g., 2012 and 2013)." Id. [EPA-HQ-OAR-2009-0491-2685.1]
EPA cannot justify any option that allows the importation of any NOX allowances. Under §110(a)(2)(D)(i)(I), States (or in this case EPA) must determine the extent of any "significant contribution" or "interference with maintenance." The timing of the elimination of these unlawful emissions is informed by the attainment requirements for the impacted states, North Carolina, 531 F.3d at 911-12, which are required to attain "as expeditiously as practicable" 22 but no later than certain dates, id. at 911. Accordingly, the upwind sources must eliminate their unlawful emissions "as expeditiously as practicable" and in a manner that is coordinated with the downwind nonattainment deadlines. [EPA-HQ-OAR-2009-0491-2685.1]
EPA has proposed to determine that emissions reductions by 2012 and 2014 are necessary in order to ensure that the reductions are both coordinated with the downwind nonattainment deadlines and achieved "as expeditiously as practicable," as required. Therefore, the budgets EPA has proposed in the Transport FIP define the breakpoint between lawful and unlawful emissions under North Carolina. Importing any allowances from outside those calculations, not to mention the concededly overwhelming bank of allowances remaining from the CAIR NOX program, would allow sources to delay elimination of their unlawful emissions past the point required by the only relevant considerations: downwind attainment deadlines and the associated "as expeditiously as practicable" mandate. Thus, the importation of any pre-existing allowances violates §110(a)(2)(D)(i)(I). See North Carolina, 531 F.3d at 913 (In responding to similar arguments regarding CAIR's compliance supplement pool, "EPA d[id] not argue that it can set a level of emissions that is an upwind state's `significant contribution' and then allow that state to exceed it."). [EPA-HQ-OAR-2009-0491-2685.1]
EPA's suggestion that importing pre-existing CAIR NOX allowances would "would promote the continuation  -  in 2010 and 2011  -  of the reductions that 23 occurred in 2009 under the CAIR NOX programs" also misses the point. Whatever downwind areas gain by preserving CAIR's reductions in the interim will be lost when the CAIR NOX allowances are redeemed in the following years. Under EPA's "first approach," 75 Fed. Reg. at 45,339/1-2, the preservation of the benefits of CAIR in 2010 and 2011 would be offset, on a one-to-one basis, in 2012, 2013 and beyond. And if the trade-in ratio were less than one-to-one, as in EPA's "second approach," id. at 45,339/2, so that more benefits are not foregone in the out years, EPA concedes that less benefit would be realized in the short term, making that option essentially a wash as well. The bottom line is that EPA would just be avoiding a concentrated air quality detriment now and replacing it with a drawn out and unlawful one over the next few years. [EPA-HQ-OAR-2009-0491-2685.1]
North Carolina supports the goal of preserving the environmental benefits of the unlawful CAIR during the transition to its successor. Indeed, North Carolina was the only petitioner in the consolidated CAIR litigation that sought remand without vacatur from the outset. See, e.g., North Carolina, 531 F.3d. at 929. Nevertheless, Congress has not authorized the avoidance of the statutory mandate in order to preserve current benefits. Therefore, North Carolina does not support the continued use of CAIR NOX allowances once the Transport FIP becomes effective. [EPA-HQ-OAR-2009-0491-2685.1]
Response: 
EPA is not allowing CAIR NOx allowances to be used in the Transport Rule.  See preamble section IX.
Organization: Big Rivers Electric Corporation
Comment: 
Big Rivers Electric Corporation
As proposed CAIR unused allowances would be eliminated as a means of compliance beginning in 2012.  For new units, a 3% set aside of CATR state allowance budgets to be shared pro rata in the event of over demand, and no allocation during initial year of start-up provides no assurance that necessary allowances would be available for new units utilizing the best emissions control technologies. [EPA-HQ-OAR-2009-0491-2661.1, p.3]
Response: 
See preamble section VII regarding allocation to new units.
Organization: City of Ames, Iowa
Comment: 
City of Ames, Iowa
18) We would advocate that allowances held by utilities under CAIR, be allowed to be transferred and used under the 'Air Transport Rule'. The logic is that either utilities and generators have either spent a lot of money acquiring them, or they have installed equipment (at great cost) or have operated their units in such a way to accumulate credits. They should not be forced to forfeit what they have already done in good faith to attempt to comply with CAIR. [EPA-HQ-OAR-2009-0491-2769, p.4]
Response: 
See preamble section IX.
Organization: Clean Air Task Force
Clean Energy Group
Comment: 
Clean Air Task Force
EPA requests comment on the use of banked allowances from other trading schemes for purposes of compliance with TR requirements. 144 Consistent with the Court's opinion in North Carolina v. EPA, the Agency must not allow the use in the TR of any SO2 or NOx allowances banked or otherwise carried over under the CAIR program or the Title IV acid rain program, and we support EPA's proposal to exclude these allowances for TR compliance. 145 [EPA-HQ-OAR-2009-0491-2738.1, p.26; This comment can also be found at section V.F.4 & V.G.2 of this comment summary]

Footnote:
144 75 Fed. Reg. at 45339. 
145 75 Fed. Reg. at 45338-39.  
Clean Energy Group
Although CAIR NOx allowances are not similarly explicitly proscribed in the court's decision, EPA should not in any way base the Transport Rule NOx allocations on CAIR allocations, either by allowing the use of previously-banked allowances for compliance or by allowing allowance holders to exchange them for Transport Rule allowances. Because CAIR allowance holdings are based on the fatally-flawed CAIR allocation, any use of these allowances in the new program would jeopardize the entire program. The Clean Energy Group supports EPA creating a new NOx allowance currency to ensure CAIR's flaws do not undermine the Transport Rule. [EPA-HQ-OAR-2009-0491-2702.1, p. 11]
Response: 
EPA is not allowing the use or conversion of CAIR NOx allowances in the Transport Rule.  See preamble section IX.
Organization: Dominion
Comment: 
Dominion
EPA Should Allow the Use of Banked NOx Allowances from CAlR in the Transport Rule
EPA should allow the transfer of unused NOx allowances banked from CAIR annual and ozone season programs on a one-to-one basis into the respective annual and ozone season NOx programs under the Transport Rule. This can be readily accomplished since EPA proposes to use the same Allowance Management System (AMS) that was used in the CAIR programs. To the extent EPA is concerned that the potential amount of banked CAIR NOx allowances would reduce the amount of emission reductions that would otherwise be achieved under the proposed Transport Rule, EPA could stagger their use for compliance during the initial years of the program by assigning specific CATR related annual vintages to the CAlR banked allowances or limit their use to a certain percentage. Although we do not believe it should be necessary to do so, we would prefer such an approach in lieu of invalidating the use of banked CAIR allowances altogether or reducing their value by way of imposing surrender ratios greater than 1-to-1. Prohibiting the ability to transfer banked allowances from CAIR renders their value useless, disadvantages sources that complied with CAIR by installing control technology instead of purchasing allowances. This could impact company decisions concerning early reductions if there is a perception that over-compliance with the initial phase of the Transport Rule may not be rewarded in a subsequent phase of NOx reductions, which EPA has indicated it intends to impose to address its expected revision (tightening) of the ozone standard. Allowing the use of banked CAIR NOx allowances in the new program would provide a modest degree of increased compliance flexibility for sources during the early years of the program and, combined with the unlimited banking of CATR allowances, may further encourage early reductions. [EPA-HQ-OAR-2009-0491-2715.1, pp.4-5]
Response: 
See preamble section IX and responses to other comments, primarily in this section.
Organization: DTE Energy Services (DTEES)
DTE Energy
Comment: 
DTE Energy
DTE supports the use of banked CAIR NOx allowances for compliance with the proposed Transport Rule. The proposed Transport Rule properly recognizes the important environmental and economic benefits of allowance banking, and that allowance banking as an element of EPA's CAIR program was not undermined by the court's remand. [EPA-HQ-OAR-2009-0491-2851.1,p.3]
DTE Energy Services (DTEES)
Use of banked CAIR allowances
DTEES understands that, as described in 75 FR 45339, in light of the North Carolina Court ruling, EPA is limited in how banked pre 2012 CAIR allowances can be used. DTEES fully supports the use of pre 2012 banked CAIR allowances for compliance with the Transport Rule. In particular EPA should not disallow the use of allowances that have been purchased for long term compliance planning purposes. [EPA-HQ-OAR-2009-0491-2699.1,p.2]
Response: 
See preamble section IX and responses to other comments in this section.
Organization: Duke Energy
Comment: 
Duke Energy
EPA Should Allow the Use of Banked Clean Air Interstate Rule ('CAIR") NOx Allowances for PTR Compliance
Duke Energy recommends that EPA permit the use of banked CAIR NOx allowances for compliance with the PTR. In the final rule, EPA should provide that it will transfer all CAIR NOx annual and ozone season allowances held in each source's compliance accounts after the final compliance period of CAIR into that source's compliance accounts for the new PTR programs (to the extent the source is subject to the new program's annual or ozone season NOx requirements, or both). There is no reason not to allow sources to use their CAIR allowances (including allowances that they bought or otherwise acquired from others) for compliance with the PTR NOx programs.  EPA's concern that some may view an approach that authorizes sources to use banked CAIR NOx allowances as unfairly permitting some sources a larger share of allowances due to CAIR's use of fuel adjustment factors, which the North Carolina decision found EPA had not adequately justified, is no basis to bar use of these allowances already allocated. The court's opinion in no way bars use of these already-allocated allowances, on a banked basis, in a new program. Moreover, if EPA disallows use of banked CAIR NOx allowances in the Transport Rule, it will be to the detriment of all sources that hold banked CAIR NOx allowances when CAIR expires. It would be far better to allow all sources the benefit of their banked allowances than to render them worthless at the end of the CAIR program.3 [EPA-HQ-OAR-2009-0491-2689.1, p.4]
There are many compelling reasons EPA should allow sources to use their banked CAIR NOx allowances for compliance with the PTR. First, nothing in the D.C. Circuit's North Carolina opinion precludes -- and in fact, no party challenged -- use of banked CAIR NOx allowances. The only flaw identified by the court with respect to CAIR NOx allowances was the way EPA established NOx allowance budgets. Second, as EPA suggests, permitting use of banked CAIR NOx allowances would promote the continuation in 2010 and 2011 of the reductions that occurred under CAIR. 75 Fed. Reg. at 45339/1. It would also avoid creating an incentive for sources to "use up" CAIR NOx allowances, thereby potentially increasing their NOx emissions temporarily, because those allowances would -- in the absence of a provision allowing use of banked CAIR NOx allowances in the new program -- have no value after the allowance transfer deadline for the final CAIR annual and ozone season compliance periods. Third, allowing banked CAIR NOx allowances to be used for compliance with the PTR would provide a modest degree of increased flexibility for sources during the early years of the new program, an especially important consideration if EPA retains the proposed accelerated compliance schedule and continues to overstate the ability of existing emission controls to reduce emissions. [EPA-HQ-OAR-2009-0491-2689.1, pp.4-5]

Footnote 3: If EPA is concerned that the amount of banked CAIR NOx allowances is so great that it may reduce the amount of emission reductions that would otherwise be achieved under the proposed rule, 75 Fed. Reg. at 45339/1, there are better ways to avoid that outcome than to invalidate the allowances in whole or in part. EPA should allow sources the full benefit of their banked CAIR NOx allowances. If EPA determines that a limitation on the use of those allowances is necessary, EPA should at least permit use of a substantial amount of the allowances over the first few years of the new program, [EPA-HQ-OAR-2009-0491-2689.1, p.4]
Response: 
See preamble section IX.  Particularly, EPA is concerned that allowing the use of CAIR allowances in the Transport Rule will jeopardize states' ability to show that significant contribution to nonattainment and interference with maintenance is achieved.
Organization: E.ON U.S.
Comment: 
E.ON U.S.
Banked CAIR NOx allowances should be usable.
Although the court decision found fault with use of Title IV SO2 allowances to implement CAIR, it did not prohibit use of the newly-created CAIR NOx allowances. Utilities have made investments in control technologies and reduced emissions to comply with CAIR, which presumably have resulted in improved air quality in downwind states. This is the same goal as the Proposed Transport Rule. Any banked CAIR NOx allowances are the result of reductions made after the 2005 baseline year used in the Proposed Transport Rule. Consequently, use of banked CAIR NOx allowances is appropriate. [EPA-HQ-OAR-2009-0491-2797.1, p.9]
Response: 
See preamble section IX.
Organization: Empire District Electric Company (Empire District)
Comment: 
Empire District Electric Company (Empire District)
EPA's preferred approach prohibits the usage of banked Title IV, NOx SIP Call and CAIR NOx allowances.  Empire District has reviewed the DC Circuit's remand and understands the difficulty of incorporating these allowances into the CATR.  However a number of utilities, including Empire District, have installed pollution control equipment to comply with CAIR and reduced emission below their allowance allocations.  The preferred approach proposed by EPA in effect penalizes such utilities by stranding their banked allowances.  Those allowances exist due to over compliance by the affected utilities and therefore represent the additional cost of that over compliance.  If the preferred interstate trading program is finalized as proposed such an approach by EPA would send a negative message regarding over compliance of any future regulation.  We urge EPA to establish a system, with possible flow controls, that would allow utilization of these stranded allowances.  Empire District assumes that a goal of EPA's is to encourage over compliance, not stifle it. [EPA-HQ-OAR-2009-0491-2659.1, p.6]
Response: 
See preamble section IX and responses to other comments primarily in this section.
Organization: Environmental Markets Association (EMA)
Comment: 
Environmental Markets Association (EMA)
EMA is glad to see that the EPA is considering three options for the convertibility of CAIR NOx allowances. Failing to convert banked CAIR NOx allowances largely eliminates the return on investment that was expected as CAIR was implemented. [EPA-HQ-OAR-2009-0491-2727.1, p.1] [These comments were also submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.48-49.]
We fail to understand how "cap-and-trade" policy has been diminished in public debate. Cap & trade has for fifteen years proven essential to achieving these goals earlier and at lower cost than any other form of regulation. To fulfill our compliance obligations by undertaking these significant financial commitments, we feel it is essential to for EPA to restore confidence in achieving environmental objectives that affect the well-being of every American (and indeed, the global citizenry) using a trading market where investors can receive a fair shot at a return on investment. [EPA-HQ-OAR-2009-0491-2727.1, p.2]
Without the environmental certainty of a "cap", none of us can be assured that the desired improvements in human health and air quality will be achieved. Without the regulatory certainty needed to support "trade", risk premiums for emission reduction projects go up, along with the cost of allowances - something that does not benefit the environment or consumers. Cap & trade should be about attracting capital to the highest return projects. The higher the cost of capital, the higher the cost of the projects that get completed, and the greater the resistance to further reductions. [EPA-HQ-OAR-2009-0491-2727.1, p.2]
We know that EPA understands these principles, but we think it is essential for it to take the next step and provide for continuity of current programs by providing for conversion of CAIR NOx allowances. We also appreciate that the Agency is concerned over additional litigation because CAIR NOx allowances were allocated based on fuel factors, which the Court rejected in its decision. [EPA-HQ-OAR-2009-0491-2727.1, p.2] [These comments were also submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.49.]
EMA believes that EPA could provide for continuity in allowance markets by electing to apply surrender ratios to banked allowances, (Option 2 in the Proposed Rule.) We suggest that it might help reduce the risk of subsequent litigation if EPA set the surrender ratios in a way that would reverse impact of the original fuel factor allocation method (e.g., if a 100% coal-fired company converted its allowances at a higher ratio than a gas-fired company.) [EPA-HQ-OAR-2009-0491-2727.1, p.2]
There are a number of issues raised by the discounted CAIR NOx conversion option. If EPA decided to convert allowances based on the original allocation recipient, we would have two classes of allowances, and people would price them differently based on their eventual conversion rate. Under EMA's proposed methodology, we would not tie the reversal of the fuel factors to the original allowances as allocated to recipients, but by the fuel status of the holder of the allowances who offers them for conversion, i.e., no matter where they got them. [EPA-HQ-OAR-2009-0491-2727.1, p.2]
Then there is the issue of a company asking a financial intermediary (which has no fuel position) to convert NOx allowances on their behalf. To discourage use of non-emitting conversion proxies, EPA could require that conversion be completed in rounds, with the first round being restricted to owners of affected sources (with a definable fuel position.) Then in a successor round, EPA could stipulate that financials and other parties could convert the CAIR NOx allowances they hold at the highest conversion rate applied in the first round (so parties with a fuel position would have an incentive to participate in the first round and not utilize a third-party conversion proxy.) [EPA-HQ-OAR-2009-0491-2727.1, p.2]
EMA supports efforts, such as this, to promote market-based mechanisms for responding to environmental issues because emissions trading results in reducing emissions earlier and at a lower cost than any other form of regulation. We encourage EPA to maintain the continuity of existing trading programs by providing for the convertibility of current period allowances into the subsequent Trading Rule programs, and we will be encouraging Congress to provide EPA with sufficient flexibility in the future to avoid the problems that EPA has encountered in trying to maintain a viable emissions trading market. [EPA-HQ-OAR-2009-0491-2727.1, pp.2-3]
Response: 
See preamble section IX and responses to other comments, primarily in this section.
Organization: Exelon
Comment: 
Exelon
The Transport Rule also addresses the North Carolina court's holding that state NOX budgets based on fuel type rather than contribution to nonattainment or interference with maintenance are impermissible. CAIR established a fuel factor of 1.0 for coal-fired units, 0.6 for oil-fired units, and 0.4 for gas-fired units, resulting in higher allowances for coal-fired units which are responsible for the greatest amount of pollutant emissions. The proposed Transport Rule rectifies this issue, and correctly follows the court's analysis, by eliminating the use of fuel factors in determining state emissions budgets. These fuel factors then indirectly influenced the allocation of CAIR allowances (which were based on state budgets), and so are reflected in the CAIR allowances that remain banked today. If banked CAIR NOX allowances were permitted to be used under the Transport Rule, the rule's allowance scheme would be tainted by the same deficiencies that caused the court to reject the use of fuel factors in CAIR. Recognizing this, EPA has proposed that banked CAIR allowances would neither be acceptable for compliance with Transport Rule, nor used as a tool for allocating Transport Rule allowances. Exelon supports EPA's decision to exclude banked CAIR NOX allowances from any role in compliance with Transport Rule or allocation of allowances under the Transport Rule. [EPA-HQ-OAR-2009-0491-2666.1, pp.10-11]
Response: 
The final Transport Rule does not allow the use of CAIR NOx allowances.
Organization: Florida Electric Power Coordinating Group, Inc. (FCG)
Comment: 
Florida Electric Power Coordinating Group, Inc. (FCG)
These same issues arise in the context of CAIR allowances. Because CAIR allowances would not be transferrable into the new program, all CAIR allowances for calendar years 2012 and on would become worthless. Since EPA is responsible for the allowance system, EPA should look to the quantity of allowances held and price for both the Acid Rain and CAIR programs (in Florida and nationally) to clearly understand the value it is eliminating in its proposal.
Accordingly, EPA's proposed interference in the market for Title IV allowances is contrary to North Carolina v EPA, and would be equivalent to a taking and violation of substantive due process protections afforded by the U.S. Constitution. [EPA-HQ-OAR-2009-0491-2658.1, p.6]
Response: 
See preamble section IX.
Organization: Gainesville Regional Utilities (GRU)
Comment: 
Gainesville Regional Utilities (GRU)
EPA's Failure to Craft a Proposal that Allows the Use of Banked Acid Rain SO2 Allowances and Banked CAIR NOx Allowances Creates Distrust in Market-based Control Strategies
EPA could create a mechanism that would permit SO2 Acid Rain allowances to serve as an alternative 'currency' for the proposed CATR SO2 allowances. In addition, EPA could also adjust banked post-20l2 NOx allowances to remove the CAIR fuel factor adjustment for use in the proposed CATR. It is noted that the Court did not completely rule out the use of Acid Rain SO2 or NOx allowances for CAIR, just the way EPA did it. GRU believes that EPA needs to consider the negative long range policy implications of abrogating programs and regulatory provisions that the utility industry has depended upon in making major financial and compliance decisions. [EPA-HQ-OAR-2009-0491-2674.1, pp.7-8; this comment can also be found at V.F.4.a of this comment summary]
Response: 
See preamble section IX.
Organization: George Washington University Regulatory Study Center
Comment: 
George Washington University Regulatory Study Center
Somewhat surprisingly, the EPA also proposes prohibiting any exchange of CAIR NOx allowances for either the seasonal or annual markets. Although the agency also cites some legal concerns, this decision appears to be driven by policy preference, not by legal necessity.13 In the proposed rule, the EPA states that the size "of the banks are so large that they might significantly reduce the amount of emissions reductions that would otherwise be achieved in the proposed Transport Rule NOx programs, particularly in the earlier years.' In response to these concerns, the EPA sets out a predictable set of options for banked allowance exchange: one-to-one exchange, less than one-to-one exchange, and no exchange. The agency selects no exchange as its proposed option.16 [EPA-HQ-OAR-2009-0491-2573.1, p.8]
The agency's reasoning for discarding CAIR NOx allowances is unclear, however. Especially when compared to the transition of banked Title IV SO2 allowances, there are few if any legal barriers to a transition of banked CAIR NOx allowances into the new Transport Rule markets. The EPA claims that discarding banked CAIR NOx allowances would "avoid the legal and practical problems raised by the other approaches," but only one such potential legal issue is raised by the agency in the proposed rule. CAIR NOx allowances were allocated to emissions sources in part based on "fuel adjustment factors"  -  a move that was one of the elements of CAIR struck down by the court in North Carolina. The EPA suggests that "some parties" might claim that this legally-problematic allocation taints CAIR NOx allowances in such a way that transitioning them into the Transport Rule would itself be illegal. We disagree. [EPA-HQ-OAR-2009-0491-2573.1, p.9]
First, as the EPA immediately concedes, this claim is directly undermined by the fact that, under CAIR, states retained discretion to allocate allowances using methods other than fuel adjustment factors. Most states did in fact deviate from the allocation methods used in EPA's model rule; only Minnesota, Pennsylvania, Maryland, and Delaware chose to leave the federal implementation plan in effect, while 24 states chose different allocation methods in state implementation plans approved by the EPA. [EPA-HQ-OAR-2009-0491-2573.1, p.9]
Second, the claim that CAIR NOx allowances are in some way tainted is inconsistent with the North Carolina court's treatment of CAIR itself. While the court found fault with many aspects of CAIR, including the use of fuel adjustment factors in allocation, it ultimately decided to remand the rule and allow it to operate pending revision. CAIR NOx allowances were therefore used, traded, and banked in CAIR markets, with no indication (until a March 2009 letter from the EPA) that these banked allowances would not remain useful. If CAIR NOx allowances are so tainted that they are legally toxic to a new emissions market, they should have been equally toxic to the CAIR market. The North Carolina court rejected this outcome, at least temporarily, by remanding CAIR rather than vacating it. [EPA-HQ-OAR-2009-0491-2573.1, p.9]
Third, the impacts of the allocation decisions in CAIR have been diluted by trading of NOx allowances since their allocation. If a source received an allowance due to fuel adjustment factors but traded it to another emitter who then banked the allowance, it is this trading partner -- not the beneficiary of the improper fuel adjustment allocation -- that suffers as a result of the decision to discard that banked allowance (while many traded allowances were likely used rather than banked, there are many reasons why an emitter might buy allowances and then bank them). Discarding a traded allowance does not reach back and attempt to recover the gains made by beneficiaries of the CAIR allocation since it only affects the current allowance holder. Discarding banked NOx allowances therefore does not -- and cannot -- correct the improper advantage some sources may have received as a result of fuel adjustment factor allocation. Indeed it would only be possible to do so if the beneficiaries of fuel adjustment had uniformly banked these extra allowances. It is difficult and maybe impossible to tell how many of these sources' banked allowances were "excess" fuel-adjustment allowances, but it is certain that many such allowances were traded. Large-scale trading of allowances between sources in states that received more allowances as a result of fuel adjustment factors and sources in those that received fewer was an expected result of the allocation process, something that the North Carolina court recognized and indeed pointed to as the key flaw in that process. It would be truly perverse if the result of the court's finding was further penalization of those sources that CAIR, because of the flawed fuel adjustment allocation, forced to go into the market to buy allowances. [EPA-HQ-OAR-2009-0491-2573.1, pp.9-10]
Fourth, CAIR's allocation of allowances based on fuel-adjustment factors was not the only source of CAIR NOx allowances. Many CAIR allowances were allowances banked in earlier programs (the NOx SIP Call or even the NOx OTC Program) and transitioned into CAIR. These transitioned allowances then allowed new CAIR allowances to be banked rather than used immediately. Discarding banked allowances generally, therefore, penalizes sources that banked allowances in these earlier programs and retained them. Since neither of these programs suffered from the legal flaws of CAIR, such sources did not benefit from any improper allocation. [EPA-HQ-OAR-2009-0491-2573.1, p.10]
Finally, even if it could be established that the only holders of banked CAIR allowances were beneficiaries of fuel-adjustment factors allocation, the burden of discarding those allowances would fall primarily on downwind states, not on those sources. Sources holding a bank of allowances that will be valueless in the future have an incentive to simply emit pollution up to the size of their bank (or sell the allowances at cut-rate prices to other sources who could then do so themselves). If the large CAIR NOx banks are drawn down, this increased pollution would make it more difficult or in some cases impossible for downwind areas to comply in a timely way with the ozone and PM NAAQS. The Transport Rule could therefore in the short term have the opposite of its intended effect -- it could exacerbate, rather than remedy, problems of interference with maintenance or significant contribution to nonattainment. If banked allowances are transitioned into the Transport Rule market, they could of course be used in the future by holders to emit NOx, but they might be held indefinitely. Even if they are used, the emissions would be spread out over time, likely reducing or eliminating their impact on downwind nonattainment. Furthermore, if the EPA chose to transition banked CAIR NOx allowances into the Transport Rule at a reduced exchange ratio, as the agency has done in some past program transitions, the agency might be able to have its cake and eat it too. Long-term emissions would be lower than with a 1:1 exchange ratio, and emitters' incentive to emit now would be much less than under the agency's stated preference of no exchange. [EPA-HQ-OAR-2009-0491-2573.1, pp.10-11]
The EPA does not raise any legal concerns over the transfer of banked NOx allowances other than allocation of CAIR allowances based on fuel adjustment factors. In its brief discussion, it also does not address any of the above objections to that singular legal concern. In fact, the EPA's discussion of a variety of proposed options for transfer of banked CAIR NOx allowances -- only one of which is discarding those allowances -- indicates that the agency's concerns are primarily those of policy, rather than law. The agency's discussion of legal issues surrounding transfer of SO2 allowances -- for which it does believe that North Carolina precludes any transfer -- stands in contrast to its brief and relatively open-ended discussion of the rationale for barring transfer of NOx allowances at any exchange ratio. [EPA-HQ-OAR-2009-0491-2573.1, p.11]
There therefore appears to be no strong legal grounds for discarding CAIR NOx allowances, leaving only policy justifications. But EPA's preferred option is at odds with the agency's traditional position on banked allowances, as illustrated by the other transitions between EPA-administered emissions trading programs. Each successive NOx trading program has included more stringent caps on NOx emissions, but only in the Transport Rule has the EPA deemed allowance banks a sufficient threat to achievement of planned reductions to justify blocking any transfer of allowances. [EPA-HQ-OAR-2009-0491-2573.1, p.11]
First, we recommend that EPA allow the transfer of banked CAIR NOx allowances into the Transport Rule NOx programs at an exchange ratio that balances the agency's environmental concerns with regulated firms' interest in retaining the value of those allowances as secure assets. Doing this will have both environmental and economic benefits. It will encourage firms to retain their banked allowances -- rather than dumping them and emitting NOx -- and to make early emissions reductions to smooth the transition to Transport Rule programs. Transitioning banked allowances also has important positive consequences for the confidence of current and future market participants in EPA-administered emissions trading programs. [EPA-HQ-OAR-2009-0491-2573.1, pp.31-32]

 13 Specifically, the agency points out that the method for allocation of allowances in the Transport Rule would differ from the "fuel-adjustment factors" method used in CAIR and struck down by the D.C. Circuit Court. The EPA claims "some parties" may feel that allowing one-to-one exchange of banked CAIR NOx allowances would advantage those sources who received more allowances under the CAIR allocation method than under the Transport Rule method and who banked substantial numbers of CAIR NOx allowances (primarily coal plants). The agency does not claim that it lacks the legal authority to implement a one-to-one exchange of NOx allowances, however -- whereas it does make such a claim regarding SO2 allowances. See Transport Rule at 45339.  
16 EPA staff provided some advance notice of this policy preference: Sam Napolitano, director of the EPA's Clean Air Markets Division, notified regulated entities via email and the EPA website in March of 2009 that "EPA's continued recording of CAIR NOx allowances does not guarantee or imply that any allowances will continue to be usable for compliance after a replacement rule is finalized or that they will continue to have value in the future." This information may have tempered expectations about the value of allowances banked in 2009 and 2010, but regulated entities had no such warning for CAIR allowances banked before then. EPA, Trading of CAIR Allowances, online at http://www.epa.gov/airmarkt/business/cairallowancestatus.html (accessed August 26, 2010).
Response: 
See preamble section IX in the final Transport Rule, responses to other comments, and the March 2009 notice regarding future expectations for CAIR allowance that has been posted continuously since that time http://epa.gov/airmarkets/business/cairallowancestatus.html.
Regarding the fuel adjustment factors and the point that states changed CAIR allocation methodologies through SIP revisions, approximately two-thirds of the states had some version of the fuel adjustment factors included in the allocation methodology either through FIPs or SIP revisions.  The commenter is correct that few states remained subject to the FIP; however, many of the SIP revisions incorporated the model rule language by reference or codified verbatim or near-verbatim the language into state rules. 
The following table summarizes the basic approaches states used to allocate the majority of their CAIR budgets under the CAIR NOX and CAIR NOX ozone season trading programs.  Additional detail on the precise methodologies can be found in the individual state rules.

Are allocations adjusted for fuel type (including fuel adjustment factors)?
FR Citation
DC
Yes, FIP
71 FR 25328
DE
Yes, FIP
71 FR 25328
MD
Yes, model rule methodology
74 FR 56117
GA
Yes, model rule methodology
72 FR 57202
KY
Yes, model rule methodology
72 FR 56623
MS
Yes, model rule methodology
72 FR 56268
TN
Yes, model rule methodology
72 FR 46388
IN
Yes, model rule methodology
72 FR 59480
OH
Yes, model rule methodology
73 FR 6034
FL
Yes, model rule methodology (plus bonus for certain biomass  -  150%)
72 FR 58016
WV
Yes, model rule methodology (no gas units, so they did not include the gas factor)
72 FR 71576
LA
Yes, model rule-like (including the fuel adjustment factors)
72 FR 55064
IA
Yes, model rule-like (including the fuel adjustment factors), but permanent
72 FR 43539
TX
Yes (coal 0.9; nat. gas 0.5; non-coal non-nat.gas 0.3)
72 FR 41453
SC
Yes (coal 1.0; non-coal 0.6)
74 FR 53167
MI
Yes, model rule-like (including the fuel adjustment factors)
72 FR 72256
IL
Yes, output
72 FR 58528
NY
No, heat input
73 FR 4109
VA
No, heat input
72 FR 73602
AL
No, heat input
72 FR 55659
AR
No, output
72 FR 54556
CT
No, output
73 FR 4105
MA
No, output
72 FR 67854
NJ
No, output
72 FR 55666
PA
No, output
74 FR 65446
WI
No, output
72 FR 58542
MO
No, table in rule
72 FR 71073
NC
No, table in rule
74 FR 62496

The CAIR model rule methodology included fuel adjustment factors for determining allocations (1.0 for coal, 0.60 for oil, and 0.40 for gas or other fuels).  This methodology was also used for allocating under CAIR FIPs.

Seventeen states adjusted allocations based on fuel type (13 of those were either FIP allocations or SIP-based allocations that used the model allocation methodology or a close variation).

Eleven states based allocations on other factors and did not adjust for fuel-type.
Regarding the portion of the CAIR NOx ozone season allowances that were carried over from the NOx Budget (NBP) program, 200,000 allowances were added at the start of that program through a Compliance Supplement Pool (CSP), and additional allowances were available in 2004, the first year of the program.  The NBP had a court-ordered 30 day delay to the start of the program in 2004.  The full 5 month ozone season budget had been allocated and the court made no adjustment to the initial allocation along with the delay.  Therefore, in the first year of the program, sources were responsible for covering 4 months of emissions with 5 months of allowances (a 20% bonus).  The amount of allowances carried into the CAIR NOx ozone season was nearly equivalent to the 200,000 CSP allowances, plus the extra 20% not needed in 2004.  Therefore, overall, there were few "extra" reductions made under the NBP.  Most of those allowances have since been used for compliance in CAIR.
As stated earlier, allowing the use of CAIR NOx allowances for compliance in the Transport Rule programs jeopardizes a state's ability to show that its significant contribution to nonattainment and interference with maintenance in another state has been eliminated. 
Organization: Green Exchange, LLC
Comment: 
Green Exchange, LLC
Green Exchange is glad to see that the EPA is considering three options for the convertibility of CAIR NOx allowances. If market participants are not afforded the opportunity to convert banked CAIR NOx allowances many well-intentioned environmental investments may not be able to provide the return on investment that was expected as CAIR was implemented. [EPA-HQ-OAR-2009-0491-1105.1, p.2]
We know that EPA understands these principles, but we think it is essential for it to take the next step and provide for continuity of current programs by electing to choose one of its three options for conversion of CAIR NOx allowances by imposing variability limits starting in 2012, applying surrender ratios to banked allowances, or including banked allowances in state cap. [EPA-HQ-OAR-2009-0491-1105.1, p.3]
Response: 
See preamble section IX.
Organization: Hoosier Rural Electric Cooperative
Comment: 
Hoosier Rural Electric Cooperative
Currently there are several affected utilities in Indiana that have a bank of NOx allowances obtained through early reduction programs. Hoosier requests that EPA allow the carrying over of those allowances to the CATR.  [EPA-HQ-OAR-2009-0491-2724.1 p.1]
Response: 
See preamble section IX.
Organization: Indiana Energy Association
Comment: 
Indiana Energy Association
f. A number of companies in the Indiana Utility Group have a significant bank of NO, allowances earned through early reduction programs in Indiana. The Indiana Utility Group requests that EPA allow carrying banked allowances into the CATR program. The Indiana Utility Group is significantly concerned that if allocations are tight during 2012, 2013 and 2014, the proposed EPA budget de facto prohibits the trading that the proposed CATR specifically allows . Such a de facto prohibition is both inconsistent with the trading policies of EPA and may result in an unconstitutional taking of allowances. [EPA-HQ-OAR-2009-0491-3711 p.3-4]
Response: 
See preamble section IX.
Organization: JEA
Comment: 
JEA
Additionally, JEA supports approaches that would permit the use of banked CAIR NOx allowances for compliance with the Proposed Transport Rule. Such provisions should allow for unlimited banking along with no 'expiration period' attached to the allowances accrued each year. Because CAIR allowances would not be transferrable into the new program, all CAIR allowances for calendar years 2012 and on would become worthless. [EPA-HQ-OAR-2009-0491-2713.1, p.5]
JEA expended hundreds of millions of dollars installing and operating SCR on two of its coal units with the reasonable expectation that banked CAIR allowances would continue to have value in the future. EPA's proposed action would clearly interfere with these distinct investment backed expectations, yet the proposed rule does not appear to compensate CAIR allowance holders (or otherwise account) for the loss of their assets. [EPA-HQ-OAR-2009-0491-2713.1, p.5]
Response: 
See preamble section IX and responses to other comments, primarily in this section.
Organization: Lakeland Electric
Comment: 
Lakeland Electric
As EPA is aware, many utilities have invested a substantial amount of monies in Acid Rain Program (ARP) and CAIR I allowances, and Lakeland Electric is no exception. Unfortunately, the Transport Rule as proposed does not incorporate either the ARP or CAIR I banked allowances. Lakeland Electric has depended on these banked allowances for planning purposes and the Transport Rule effectively makes both sets of allowances worthless. In addition, Lakeland Electric, being a municipality, is directly accountable to our customers, unlike some investor owned utilities. EPA's action places Lakeland Electric in a very uncomfortable position. Lakeland Electric began reducing its NOx emissions over the past few years in order to accumulate a surplus of CAIR I allowances in order of avoiding any allowance deficiency costs. However, the Transport Rule does not award Lakeland Electric customers for reducing NOx emissions early. [EPA-HQ-OAR-2009-0491-2630.1, p.5]
Response: 
See preamble section IX.
Organization: Manitowoc Public Utilities (MPU)
Comment: 
Manitowoc Public Utilities (MPU)
 MPU supports approaches that would permit the use of banked CAIR NOx allowances for compliance with the Proposed Transport Rule.   [EPA-HQ-OAR-2009-0491-2860.1,p.3]
Utilization of Banked Emission Allowances  
MPU supports approaches to permit the use of banked CAIR NOx allowances for compliance with the Proposed Transport Rule. In the final rule, EPA should provide that it will transfer all CAIR NOx annual and ozone season allowances held in each source's compliance accounts for the final compliance period of CAIR into that source's compliance accounts for the new program (to the extent the source is subject to the new program's annual or ozone season NOx requirements, or both). [EPA-HQ-OAR-2009-0491-2860.1. p.5]
Response: 
See preamble section IX.
Organization: Maryland Department of Environment (MDE)
Comment: 
Maryland Department of Environment (MDE)
Maryland agrees with EPA and its interpretation of the Court's decision, that any approach to use the Title IV SO2 allowances is "...not related to, much less necessary for, implementation of the section 110(a)(2)(D)(i)(I) mandate to eliminate significant contribution and interference with maintenance" (75 FR 45338). We also agree with EPA that the existing NOx allowances banked under either the NOx SIP call or CAIR program should not be used as part of the proposed Transport Rule remedy. Similar to the Title IV SO2 allowances, NOx allowances banked under the NOx SIP Call were designed for a different purpose; i.e., to address transport issues associated with the 1-hour ozone NAAQS. And pre-2012 CAIR allowances are associated with a program that was found inadequate by the Court that is to be replaced by the program in the proposed Transport Rule; when CAIR is replaced any allowances banked under that program should therefore not convey. [EPA-HQ-OAR-2009-0491-2639.2, p.14; This comment can also be found at section V.F.4.a of this comment summary]
Response: 
EPA is not allowing CAIR NOx allowances to be used in the Transport Rule.  See preamble section IX.
Organization: Massachusetts Department of Environmental Protection
Comment: 
Massachusetts Department of Environmental Protection
We strongly urge EPA to prohibit use of the existing NOx allowance bank, which will lead units to install controls rather than allow facilities to purchase these banked allowances to meet their obligations under the proposed Transport Rule programs.  [EPA-HQ-OAR-2009-0491-2787.2 p.2]
Response: 
EPA is not allowing CAIR NOx allowances to be used in the Transport Rule.  See preamble section IX.
Organization: Michigan Department of Natural Resources and Environment
Comment: 
Michigan Department of Natural Resources and Environment
The EPA requested comments on whether to allow banking of CAIR allowances and insight into the differences on how states allocated allowances. [EPA-HQ-OAR-2009-0491-2774.1 p.9]
The TR proposal notes that banking of allowances for use in future years could have adverse repercussions on the impact determinations of a downwind state's nonattainment and maintenance areas. [EPA-HQ-OAR-2009-0491-2774.1 p.9]
The DNRE believes that minimal banking of allowances from the CAIR program to the proposed TR should be allowed. We recommend that CAIR allowances from the 2009 and 2010 years be allowed under the TR. However, these allowances should only be used when the sources are impacted by increased electricity demands and TR allowances are unavailable for trading. In Michigan, the DNRE utilized 'hardship' allowances to address the needs of the small municipalities included in CAIR. These allowances were 'set-aside' from the main pool of allowances and divided among the municipalities based on need. In some cases the use of hardship allocations was the only way these units could continue to meet their obligations to serve their communities. [EPA-HQ-OAR-2009-0491-2774.1 p.9]
Response: 
See preamble Section IX for discussion of why CAIR NOx allowances cannot be used in the Transport Rule programs.  States do have the option of developing state allocations starting in 2013 and could consider the amount of CAIR NOx allowances remaining when deciding how to allocate the state budget, including establishing "hardship" set-asides.
Organization: Oglethorpe Power
Comment: 
Oglethorpe Power
X. Transition from CAIR
Oglethorpe Power also supports the use of banked CAIR NOx allowances for compliance with the Transport Rule, and believes that EPA should provide for transfer of all CAIR NOx allowances held in each source's compliance accounts for the final compliance period of CAIR into that source's compliance accounts for the new program. The use of such allowances would provide greater flexibility in complying with the rule. We believe there is no reason not to allow sources to use the CAIR NOx allowances held in their accounts to comply with the Transport Rule, as the Court's opinions in the CAIR litigation do not bar the use of already-allocated allowances, on a banked basis, in a new program that replaces CAIR. 12  At a minimum, EPA should allow CAIR banked NOx allowances to be used in the first year of the Transport Rule program, to ease the transition. This is especially so given the extremely aggressive compliance schedule set forth in the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2732.1, p.14]

12. As UARG notes in its comments, if EPA is concerned that the amount of banked CAIR NOx allowances is so great that it may reduce the amount of emission reductions that would otherwise be achieved under the proposed rule, there are better ways to avoid that outcome than to completely invalidate the use of such allowances in the Transport Rule. [EPA-HQ-OAR-2009-0491-2732.1, p.14]
Response: 
See preamble section IX.
Organization: Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
Comment: 
Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
OVEC Should Receive One-to-One Credit for its Participation in Early Reduction Programs During the NOx Budget Program and Clean Air Interstate Rule [EPA-HQ-OAR-2009-0491-2779.1, p.9]
OVEC does not see any provision in the Proposed Transport Rule that would allow early reduction NOx credits to be carried over into the Proposed Transport Rule framework. Any attempt by EPA to disallow a one-to-one credit for ozone season and annual NOx allowances should be reconsidered. [EPA-HQ-OAR-2009-0491-2779.1, p.9]
OVEC banked a number of these allocations in good faith by over-controlling and participating in the early reduction programs during the NOx Budget Program and CAIR. To deny the use of those credits confiscates the economic value of good faith compliance with rules in effect at the time, and creates a disincentive for any utility to take proactive steps to make early or extra emissions reductions in the future. Additionally, the cost of losing those credits has not been fully considered or addressed in EPA's analysis of the cost-effectiveness of the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2779.1, p.9]
Response: 
See responses to other comments in this section and preamble section IX.
Organization: PowerSouth Energy Cooperative
Comment: 
PowerSouth Energy Cooperative
Existing CAIR allowances should be recognized under any new rule.  Existing allowances should be carried over and valued in any compliance schemes promulgated to replace CAIR.  To do otherwise, penalizes utilities for planning prudently and relying on EPA's regulatory authority.  In addition, allowing CAIR allowances to carryover bolsters confidence in the cap and trade regulatory mechanism.  More importantly, utilities may voluntarily run air quality control equipment and continue to reduce NOx emissions between now and the implementation of any new regulatory scheme in order to "earn" CAIR allowances.[EPA-HQ-OAR-2009-0491-2693.1,p.3]
Response: 
See preamble section IX.
Organization: PPL Corporation
Comment: 
PPL Corporation
9. Use of CAIR Banked NOx Allowances.
The EPA is soliciting comment on four proposed alternatives for treatment of CAIR banked NOx allowances when CAIR is replaced by the Transport Rule. These alternative approaches are:
:: Allow CAIR banked allowances to be used. Along with this option the assurance provisions specifying that annual emissions could not exceed the state budget by more than the variability amounts would begin in 2012 rather than the proposed 2014.
:: Allow only a portion of the banked allowances to be brought into the program but at a discounted value.
:: Allow the banked allowances to be used, but reduce the state budget accordingly.
:: Do not allow the use of the banked allowances. [EPA-HQ-OAR-2009-0491-2739.1, pp.9-10]
PPL believes that the first option, allowing the use of CAIR banked allowances and starting assurance provisions in 2012 is the best alternative. If CAIR banked allowances are not allowed, it is likely that region-wide NOx emissions would increase before the Transport Rule takes effect as sources start using banked allowances that would become worthless in 2012. Additionally, use of banked allowances would help assure that state budgets could be met in the early years of the program while sources are adjusting to the new interstate trading restrictions. [EPA-HQ-OAR-2009-0491-2739.1, p.10]
Response: 
See preamble section IX.
Organization: Prairie State Generating Company, LLC
Comment: 
Prairie State Generating Company, LLC
7. BANKING FORWARD CAIR ALLOWANCES
The U.S. EPA has proposed not to allow sources to carry the CAIR allowances forward into the Transport Rule Program. p.45336. PSGC suggests that the U.S. EPA reconsider this position and that it provide for the banking forward of the CAIR allowances. [EPA-HQ-OAR-2009-0491-2842.1, p.6]
Like other 'existing' units, at least PSGC Unit I will be subject to the CAIR in 2011 and will be required to surrender the CAIR allowances for its emissions in 2011. PSGC has planned for this requirement and will hold a number of CAIR allowances, likely in excess of the number necessary for compliance in 2011. [EPA-HQ-OAR-2009-0491-2842.1, p.6]
Although the North Carolina court remanded the entirety of the CAIR, the CAIR has, nevertheless, been a viable emissions reduction and trading program and an applicable requirement with which sources have had to comply in the interim between the court's decision and the final promulgation of the Transport Rule. Therefore, the CAIR allowances should have some currency value moving forward under the Transport Rule. [EPA-HQ-OAR-2009-0491-2842.1, p.6]
Moreover, the court did not remand or vacate the NOx Budget Trading Program, 40 CFR 96, Subparts A through I, and NOx Budget Trading Program allowances were banked forward into the CAIR. Complete abandonment of the CAIR allowances also is an inappropriate abandonment of NOx Budget Trading Program allowances. [EPA-HQ-OAR-2009-0491-2842.1, pp.6-7]
Response: 
See preamble section IX and responses to other comments.  Additionally, many CAIR allowances are held in accounts not affiliated with a particular unit or state making it impossible to convert allowances from particular state budgets.
Organization: Progress Energy Service Company
Comment: 
Progress Energy Service Company
The Proposed Transport Rule properly recognizes the important environmental and economic benefits of allowance banking and that allowance banking as an element of EPA's program was in no way undermined by the court's decision in North Carolina v. EPA. Additionally, Progress Energy supports approaches that would permit the use of banked CAIR NOx allowances for compliance with the Proposed Transport Rule.  [EPA-HQ-OAR-2009-0491-2831.1 p.2]
Response: 
See preamble section IX.
Organization: Southern Company
Comment: 
Southern Company
IX. EPA Must Consider Market Continuity as it Transitions from CAIR to the Proposed Transport Rule and Any Future Transport Rules
EPA has requested comment on how the transition from CAIR would occur. One of our main concerns with the proposed transition from CAIR, is the proposed elimination of banked allowances and the uncertainty that such elimination creates for compliance. There are no markets yet for Transport Rule allowances, and those markets will not exist until September 2011, just before the January 2012 compliance date. As discussed in more detail in Section X, the data used to develop unit allocations in the proposed rule are so flawed and will require such substantial revision that industry is essentially blind to potential compliance challenges. Given the limited trading and industry-wide allocation uncertainty, it is unclear whether allowances will be available if needed. And the Transport Rule's proposed tight compliance schedule exacerbates the uncertainty. [EPA-HQ-OAR-2009-0491-2864.1, p. 22]
Southern Company supports an approach that would recognize the value of banked NOx and SO2 allowances. EPA should recognize the potential loss to utilities-and the eventual cost to customers-by devaluing or eliminating a company's allowance inventory. At a minimum, EPA should include a mechanism the conversion of CAIR NOx into the Transport Rule program. This would be technically easy to accomplish since EPA proposes to use the same Allowance Management System that it used for CAIR. The conversion of banked CAIR allowances will ensure market continuity through 2011 and will avoid potential price shocks of resetting three new markets simultaneously in the second half of 2011. Subsequently, market continuity will ensure that reductions achieved under CAIR will continue through 2011 and avoid any incentive to 'use up' CAIR allowances and produce a short-term increase in NOx emissions (the same is also true for Acid Rain S02 allowances). The North Carolina decision found flaw with use of fuel adjustment factors in determining original CAIR NOx allowance allocations, however nothing in the decision prohibits the use of existing banked allowances in a new program. In the event that EPA determines the legal concerns are too great to carry the bank forward at full value, Southern Company could support an alternative approach allowing banked allowance conversion at a discounted value. EPA should design a process that effectively eliminates fuel adjustment factor effects by applying a surrender ratio based on the fuel mix of the surrendering entity. To avoid use of conversion proxies (financial institutions on behalf of utilities), allowances could be converted in rounds, with utilities surrendering in the first round followed by a non-utility surrender round. The second round would receive the highest conversion rate applied in the first round, thereby ensuring incentive for utilities to participate in the first round and not utilize conversion proxies. This discounted conversion approach is not preferable, but would achieve some of the objectives of market continuity outlined above. [EPA-HQ-OAR-2009-0491-2864.1, pp. 22-23]
EPA has stated that future transport rules 'may be needed to address transport under future revised ozone or fine particle health standards.,,2o Subsequent phases of the Transport Rule should ensure market continuity by maintaining a common currency, allowing use of existing allowances from one phase to the next. A market based program cannot be expected to work if the currency is continuously changing and price signals are disrupted on a regular basis. Further, EPA should wait to see the effect of the current rule before promulgating future transport rules.  [EPA-HQ-OAR-2009-0491-2864.1, p. 23]
[The above comments can also be found at Section V.F.4.a. of this comment summary.]
Response: 
See preamble section IX and responses to other comments.
Organization: Southern IL Power Cooperative
Comment: 
Southern IL Power Cooperative
As proposed, unused CAIR allowances would be eliminated as a means of compliance beginning in 2012. For new units, a 3% set aside of CATR state allowance budgets shared pro rata in event of over demand, and no allocation during initial year of start- up provide no assurance that necessary allowances would be available for new units necessarily utilizing best emissions control technologies. EPA has stated that it wholly supports new cleaner fossil fuel generation. Yet this policy would function in opposite of encouraging the newer, cleaner generation. EPA should incorporate unused CAIR allowances into the CATR program and make available to new units to the extent that CATR allowances are not available from the 3% CATR new unit set-side. [EPA-HQ-OAR-2009-0491-2863.1 p.4]
Response: 
See preamble section VII regarding allocation to new units and section IX regarding the prohibition on the use of CAIR allowances in the Transport Rule.
Organization: Tennessee Valley Authority (TVA)
Comment: 
Tennessee Valley Authority (TVA)
A. Issue: EPA's proposal does not allow banked CAIR NOx emission allowances to carry forward into the new Transport Rule trading program, but the agency has requested comments on whether such pre- 2010 NOx CAIR allowances should be carried forward, and on possible approaches for handling these CAIR allowances. [p. 45339] [EPA-HQ-OAR-2009-0491-2782.1, p. 12]
TVA Comment: EPA should allow CAIR NOx emission allowances to carry over into the Transport Rule trading program. Banking was not addressed by the D.C. Circuit's decision in North Carolina v. EPA. EPA can rely on the assurance provisions to ensure that each state continues to eliminate all significant contributions and interference with maintenance. As EPA indicates, the problem with "state budgets using fuel factors," the use of which was reversed in North Carolina v. EPA, could be mitigated by the fact that states had the flexibility to allocate state allowances however they wished. These carried over allowances should continue for an unlimited period of time as would be the case with any program that creates allowances through actual on-the-ground reductions. If EPA is concerned about the potential impact that use of CAIR allowances may have on preserving the reductions achieved by the Transport Rule, it may choose to mitigate this concern by placing an expiration date of 2016 on these allowances. This would help EGUs make the transition from CAIR to the Transport Rule, mitigating the deleterious impacts of the rigorous timeframes imposed by the Transport Rule.
Elimination of the CAIR NOx allowance banks would be unfair to utilities that installed controls at certain facilities early to bank allowances, and planned, as the CAIR rule allowed, to use these banked allowances to provide for an optimum transition to and time for installation of controls to meet future lower CAIR allocation levels. Eliminating these allowances will also reduce confidence in and hinder implementation of any future cap and trade programs, such as the trading program in the very Transport Rule proposed by EPA as well as those trading programs that have been included in draft legislation for greenhouse gases. Moreover, depressed allowance values prior to 2012 could result in increased emissions. [EPA-HQ-OAR-2009-0491-2782.1, p. 13]
Response: 
See preamble Section IX for discussion of why CAIR NOx allowances cannot be used in the Transport Rule programs.  States do have the option of developing state allocations starting in 2013 and could consider the amount of CAIR NOx allowances remaining when deciding how to allocate the state budget.
Organization: Utility Air Regulatory Group (UARG)
Comment: 
Utility Air Regulatory Group (UARG)
UARG also emphasizes, however, that it supports approaches that would permit the use of banked CAIR NOx allowances for compliance with the Proposed Transport Rule. In the final rule, EPA should provide that it will transfer all CAIR NOx annual and ozone season allowances held in each source's compliance accounts for the final compliance period of CAIR into that source's compliance accounts for the new program (to the extent the source is subject to the new program's annual or ozone season NOx requirements, or both). This could readily be accomplished because, for purposes of compliance with the new program, EPA proposes to use the same Allowance Management System ("AMS") that it used for compliance with CAIR. 75 Fed. Reg. at 45312/1. There is no reason not to allow sources to use their CAIR allowances (including allowances that they bought or otherwise acquired from others) for compliance with the new program. [EPA-HQ-OAR-2009-0491-2756.1, p.13]
EPA's concern that some may view an approach that authorizes sources to use banked CAIR NOx allowances as unfairly permitting some sources a larger share of allowances due to CAIR's use of fuel adjustment factors, which the North Carolina decision found EPA had not adequately justified, is no basis to bar use of these allowances already allocated. The court's opinion in no way bars use of these already-allocated allowances, on a banked basis, in a new program. Moreover, if EPA disallows use of banked CAIR NOx allowances at this juncture, it will be to the detriment of all sources that hold banked CAIR NOx allowances at the time that CAIR expires. It would be far better to allow all sources the benefit of their banked allowances than to render them worthless at the end of the CAIR program.8 [EPA-HQ-OAR-2009-0491-2756.1, pp.13-14]
Indeed, there are many compelling reasons to allow sources to use their banked CAIR NOx allowances for compliance with the proposed rule. First, as noted above, nothing in the court's North Carolina opinion precludes -- and in fact, no party challenged -- use of banked CAIR NOx allowances. The only flaw identified by the court with respect to CAIR NOx allowances was the way EPA established NOx allowance budgets. Second, as EPA suggests, permitting use of banked CAIR NOx allowances would promote the continuation in 2010 and 2011 of the reductions that occurred under CAIR. Id. at 45339/1. Likewise, it would avoid creating an incentive for sources to "use up" CAIR NOx allowances, thereby potentially increasing their NOx emissions temporarily, because those allowances would -- in the absence of a provision allowing use of banked CAIR NOx allowances in the new program -- have no value after the allowance transfer deadline for the final CAIR annual and ozone season compliance periods. Third, allowing use of banked CAIR NOx allowances would provide a modest degree of increased flexibility for sources during the early years of the new program, an especially important consideration if EPA requires compliance with the Transport Rule according to the unreasonably accelerated schedule set forth in its proposal. [EPA-HQ-OAR-2009-0491-2756.1, pp.14-15]
Indeed, the issue of use of banked CAIR NOx allowances is one example of the reasons why, EPA should design the transition to the Transport Rule as a seamless regulatory process to ensure that the mechanisms remain in place for continuous compliance and assurance of continued emission reductions. The D.C. Circuit, in its December 2008 decision, determined that CAIR could remain in place while EPA developed a replacement rule, specifically because of concerns that the emission reductions attributable to CAIR would not occur during the transition period if CAIR were vacated. Because the court allowed CAIR to remain in place, it is possible for EPA to retain aspects of CAIR that will assure full compliance and that will promote the effective and seamless transition to the new rule, without the possibility of short-term backsliding. This would also leave in place, for example, the CAIR 2015 phase II control requirements until the Transport Rule can be implemented. This approach will provide additional time for EPA to complete the current rulemaking and permit an adequate compliance schedule under the new rule, even while electric generating companies are required to continue to plan for further emission reductions to meet the CAIR 2015 deadline. [EPA-HQ-OAR-2009-0491-2756.1, p.15]

Footnote 8: If EPA is concerned that the amount of banked CAIR NOx allowances is or will be so great that it may reduce the amount of emission reductions that would otherwise be achieved under the proposed rule, see 75 Fed. Reg. at 45339/1, there are better ways to avoid that outcome than to invalidate the allowances in whole or in part. EPA should allow sources the full benefit of their banked CAIR NOx allowances. If EPA determines that some limitations on use of those allowances are necessary, EPA should at least permit use of a substantial amount of the allowances over at least the first few years of the new program.   [EPA-HQ-OAR-2009-0491-2756.1, p.14]
Response: 
See preamble sections VI, VII and IX, responses to other comments, and http://epa.gov/airmarkets/business/cairallowancestatus.html (link to a notice from EPA posted since March 2009 regarding the future of CAIR allowances). 
The Court ordered EPA to replace CAIR; the Transport Rule is not a successor program.
Organization: Wolverine Power Supply Cooperative
Comment: 
Wolverine Power Supply Cooperative
As proposed, CAIR unused allowances would be eliminated as a means of compliance beginning in 2012. Under the proposed rule, for new units, a 3% set aside of state allowance budgets is to be shared pro rata in event of over demand, with no allocation during the initial year of start-up. The proposal does not provide any assurance that necessary allowances will be available for new units utilizing best emissions control technologies. While EPA has stated that it wholly supports new cleaner fossil fuel generation, the proposed rule would function to discourage newer, cleaner generation since these units can have no assurance that sufficient allowances will be available. EPA should incorporate unused CAIR allowances into the CATR program and make available to new units to the extent that CATR allowances are not available from the 3% CATR new unit set-side. [EPA-HQ-OAR-2009-0491-2825.1 p.5]
Response: 
See preamble section VII regarding allocation to new units and section IX regarding the prohibition on the use of CAIR allowances in the Transport Rule.

V.G. [Reserved]

V.G.1. Title IV Interactions

Organization: Capital Power Corporation
Comment: 
Capital Power Corporation
Further, creating new allowance currencies solves the problem of directly affecting the Title IV program. [EPA-HQ-OAR-2009-0491-2753.1, p.2]
Response: 
EPA agrees.
Organization: Pfeiff, Mike
Comment: 
Pfeiff, Mike
5. Harm to Cap-and-trade - If finalized, the Proposed Transport Rule will cause permanent and irreversible harm to the use of market oriented mechanisms like cap-and-trade as a policy tool to reduce pollution. While the Proposed Transport Rule does claim offer FIPs with a trading component, for all practical purposes they are so restrictive that they are merely cap-and- trade in name only. I recognize the EPA has statutory obligations under the CAA and is further constrained by the judicial findings in North Carolina v. EPA, (DC Cir. 2008). However, the Proposed Transport Rule is tantamount to 'throwing out the baby with the bathwater'. [EPA-HQ-OAR-2009-0491-2742.1, pp.3-4]
If the Proposed Transport Rule is finalized with any of the three proposed FIPs, and by some miracle is able to withstand the certain judicial challenges, the concept of cap-and-trade as a policy tool will be permanently damaged. Emission allowances are not like other traditional commodities in that they have no intrinsic value and their entire value is predicated on the confidence in the government maintaining its commitments to past programs. [EPA-HQ-OAR-2009-0491-2742.1, p.4]
Remarkably the preferred FIP effectively dismantles the Title IV Acid Rain Program (ARP) which was created by act of Congress in 1990, leaving the Title IV allowances practically worthless. This rule is unfairly punitive to market participants that made economic investments predicated on programs established through statute. The net effect of the Proposed Transport Rule is that it will cast a permanent cloud of doubt on EPA's willingness to maintain all future cap-and-trade programs. The Proposed Transport Rule has challenged the EPA's commitment to market oriented pollution reduction policies. As a result, future market oriented cap-and-trade programs market participants will always remain vigilant to the likelihood of the EPA repeating is backdoor dismantling of the Title IV program. Going forward market participants will reasonably apply an extra large 'risk adjustment' that will disconnect the market price of allowance from the true pollution abatement cost. The disparity between the true abatement cost and the markets risk adjusted price will doom future trading programs. [EPA-HQ-OAR-2009-0491-2742.1, p.4]
If the current structure of the Proposed Transport Rule is not abandoned soon, the EPA will not retain sufficient credibility to establish future market oriented cap-and-trade programs to solve future environmental objectives. This would be a grave tragedy. Instead of the signal sent by the Proposed Transport Rule which highlights the EPA's willingness to step backwards the EPA's should instead be sending the market the signal that it is committed to programs established by Congress. I request that the EPA abandon its efforts to finalize the Propose Transport Rule and initiate a new rulemaking process that does not result in a devaluation of Title IV ARP allowances. [EPA-HQ-OAR-2009-0491-2742.1, p.4]
Response: 
See preamble section IX and responses to other comments.

V.G.2. NOx SIP Call Interactions

Organization: Clean Air Task Force
Comment: 
Clean Air Task Force
EPA requests comment on the use of banked allowances from other trading schemes for purposes of compliance with TR requirements. 144 Consistent with the Court's opinion in North Carolina v. EPA, the Agency must not allow the use in the TR of any SO2 or NOx allowances banked or otherwise carried over under the CAIR program or the Title IV acid rain program, and we support EPA's proposal to exclude these allowances for TR compliance. 145 [EPA-HQ-OAR-2009-0491-2738.1, p.26; This comment can also be found at section V.F.4 & V.F.4.b of this comment summary]

Footnote:
144 75 Fed. Reg. at 45339. 
145 75 Fed. Reg. at 45338-39.  
Response: 
EPA agrees; see preamble section IX for further discussion.
Organization: North Carolina Department of Environment and Natural Resources
Kentucky Division for Air Quality
Comment: 
Kentucky Division for Air Quality
Proposed Transport Rule Should Include NOx SIP Call Non-EGU Units Currently in CAIR    
Pursuant to the proposed Transport Rule Preamble Section V.G.2., NOx SIP Call Interactions (75 FR 45340-45341), the Division urges EPA to reconsider its decision not to allow the inclusion of its NOx SIP Call Non-EGUs now in CAIR into the proposed Transport Rule NOx ozone season trading program. Due to the very small emissions budget for the Division's six NOx SIP Call Non-EGUs (64 ozone season (OS) tons) that was added to the CAIR NOx OS budget, Kentucky disagrees with EPA's contention that including these units in the proposed Transport Rule would jeopardize a state's ability to eliminate its part of significant contribution and interference with maintenance that EPA has identified. As EPA has indicated in the preamble, states need a way to continue to meet their NOx SIP Call obligation for Non-EGUs and the Division believes that the transport rule should be that new way. Therefore, given the limited number of subject Non-EGUs and the small amount of their NOx ozone season budget emissions, the Division requests that EPA include the NOx SIP Call Non-EGUs into the proposed Transport Rule. If EPA changes its position to include the NOx SIP Call Non-EGU units, then the Division requests that EPA consult with the Division to ensure that all applicable Kentucky Non-EGUs are properly accounted for in the Transport Rule. [EPA-HQ-OAR-2009-0491-2805.1, p.4]
North Carolina Department of Environment and Natural Resources
On page 45341 EPA explains that because EPA is only covering EGUs under the proposal, any state that brought large non-EGUs into the CAIR NOx ozone season program to meet the NOx SIP Call requirements would need to submit a SIP revision to address their NOx SIP call obligations and that EPA will work with states to ensure those obligations continue to be met. Clarification is needed regarding how EPA envisions states addressing such sources and when related SIP revisions must be submitted to EPA, especially given the amount of time necessary for many states to complete rulemaking processes and the short timeframe between finalizing the TR and sunsetting of CAIR at the end of December 2011. [EPA-HQ-OAR-2009-0491-2767.1 p.7]
Response: 
As discussed in preamble section IX, responses to other similar comments primarily in section V.F. of this document, and in a Technical Support Document to the proposed rule, EPA is not expanding the Transport Rule to include non-EGUs from the NOx Budget Program.

VI. Stakeholder Outreach

Organization: Clean Energy Group
Comment: 
Clean Energy Group
Public Availability of Data to Promote Effective, Technically-Sound Rules
Finally, for future rulemakings, including any companion rules to the Transport Rule, the Clean Energy Group recommends that EPA publicly distribute any information and data that may be used in the rulemaking through an Advance Notice of Proposed Rulemaking to ensure there is sufficient time to verify the information. This process would allow data verification to occur simultaneously to EPA's development of the proposed rule. Through this process, EPA and owners of potentially-covered sources can ensure that the rulemaking is based on the most up-to-date and accurate information, thereby resulting in a more effective and legally-defensible program. [EPA-HQ-OAR-2009-0491-2702.1, p. 9]
Response: 
EPA appreciates this suggestion and agrees that this is an ideal approach.  We will continue to strive to make all data available in the most timely way possible within the constraints of tight schedules as we have done during the Transport Rule process and subsequent Notices of Data Availability.
Organization: Consumers Energy
Comment: 
Consumers Energy
The prudent course for EPA is to retract and rethink this proposal, with more upfront transparency and a greater degree of involvement by the States and affected sources. EPA has neither a Court mandated nor a statutory required date for completion of this rule. Furthermore, EPA has already stated that a proposed revision will be coming out in 2012. Consequently, we recommend that EPA take this opportunity to make the necessary changes. The modeling analyses provided in the comments by MOG show that the air quality and public health benefits that the EPA is targeting can be achieved through existing emissions reductions required by CAIR and other emission reduction requirements. The EPA, the state environmental agencies and the regulated power sector can determine an appropriate schedule for additional emissions reductions that are needed that allows for implementation at a more reasonable cost. We recommend that EPA utilize such a collaborative approach to address issues as they currently exist. [EPA-HQ-OAR-2009-0491-2837.1, p.15]
Response: 
Thank you for your comment.  EPA has reached out broadly over the past several years since the North Carolina decision through listening sessions, webinars, presentations, meetings, public hearings, and comment periods.
EPA conducted substantial stakeholder outreach in developing the Transport Rule, starting with a series of "listening sessions" in the spring of 2009 with states, nongovernmental organizations, and industry.  EPA docketed stakeholder-related materials in the Transport Rule docket (Docket ID No. EPA-HQ-OAR-2009-0491).  The Agency conducted general teleconferences on the rule with tribal environmental professionals, conducted consultation with tribal governments, and hosted a webinar for communities and tribal governments.  EPA continued to provide updates to regulatory partners and stakeholders through several conference calls with states as well as at conferences where EPA officials often made presentations.  The Agency conducted additional stakeholder outreach during the public comment period, including holding three public hearings.  EPA responded to extensive public comments received during the public comment periods on the proposed rule and associated NODAs.  Additional details of stakeholder involvement in our process may be found in the proposal preamble at 75 FR 45341.
This Transport Rule is one of a series of regulatory actions to reduce the adverse health and environmental impacts of the power sector.  EPA is developing these rules to address judicial review of previous rulemakings and to issue rules required by environmental laws.  Finalizing these rules will effectuate health and environmental protection mandated by Congress while substantially reducing uncertainty over the future regulatory obligations of power plants, which will assist the power sector in planning for compliance more cost effectively.  The Agency is committed to providing full opportunity for notice and comment for each rule and appreciates the collaborative input from states, industry, and the environmental and justice communities.
Organization: National Association of Clean of Air Agencies (NACAA)
Comment: 
National Association of Clean of Air Agencies (NACAA)
In the future, we recommend that the agency attempt to include more lead-in time for sources and that the agency work closely with NACAA and its members in fashioning the rule so we can provide detailed feedback prior to the proposed rule. [EPA-HQ-OAR-2009-0491-2771.1, p.6]
Response: 
Thank you for your comments.  The Transport Rule results from the North Carolina court decisions.  As described in the proposal preamble (75 FR 45431) EPA reached out and remained open to stakeholder involvement throughout the regulatory process, as permitted.  EPA sought input from NACAA and other state organizations and considered all suggestions and comments duly. We value our relationship with state organizations and will continue to work collaboratively with them in the future.
Organization: Pfeiff, Mike
Comment: 
Pfeiff, Mike
2. Listening Sessions - The EPA stated that in early 2009, it participated in 'listening sessions'. 75 Fed. Reg. at 45,341. Invitation to these 'listening sessions' was highly selective an in many cases limited to 'members only' government/trade/environmental justice groups. Only through a Freedom of Information Act request was I able to obtain summary notes of the meetings prepared by EPA staff. To my knowledge, the EPA did not even record or transcribe these listening sessions. Further, it is my understanding that these summary notes were withheld from the general public until August 2, 2010 when the EPA submitted them as 'supporting & related materials' as part of the rulemaking record. The EPA, as the manager the Title IV allowance market, which is directly influenced by the Proposed Transport Rule should have recognized that having these 'listening sessions' without making participation open to all market participants was highly inappropriate as it provided certain market participants with asymmetric information. The EPA's failure to publicize those meetings and extend invitation to all stakeholders questions the EPA's ability to manage future rulemaking efforts. Therefore, I request that as part of the Proposed Transport Rule, the EPA include a 'code of conduct' regarding how agency engages the public when communicating information, or facilitating discussions, that directly impact the value of market oriented programs under its supervision. [EPA-HQ-OAR-2009-0491-2742.1, p.3]
3. Meeting Transparency - The EPA should make public a comprehensive list of entities that they have met with or had discussions as part of their efforts to develop the Proposed Transport Rule. In addition, the EPA should make public transcripts of those meetings and any meeting notes and/or summary documents that the EPA prepared describing the content of the discussions. Since these proposed rules effect the market value of the existing Title IV allowances it is crucial that the EPA not give preferential treatment to any market participant. Full transparency is the only way to prevent actual, or the perception of, preferential treatment. I request that the EPA provide me with a comprehensive list of the entities they have met had discussion with regarding the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2742.1, p.3]
4. Meeting Notifications - The EPA should publicize future stakeholder outreach and other meetings to all market participants as defined by the list of contacts of authorized and alternate representatives contained in its Clean Air Markets Division (CAMD) Business System database. The CAMD Business System contains a comprehensive list of allowance holders. The EPA's outreach thus far seems to be limited to industry, trade groups, state organizations, and non-governmental organizations (i.e. environmental groups). However, this method of conducting outreach does not guarantee that all market participants are being reached. I request that at a minimum, invitation to all meetings involving market orientated programs should be made to all existing account owners and their designated representatives. [EPA-HQ-OAR-2009-0491-2742.1, p.3]
Response: 
EPA disagrees with the commenter's statements.  The Title IV allowance market was directly influenced by the DC Court decisions vacating and then remanding the Clean Air Interstate Rule in 2008, not the proposed Transport Rule in 2010.  EPA met with whomever requested a meeting, including a teleconference with the commenter.  EPA has also met with commenter in its offices on at least one other occasion.  EPA also held three public hearings for the proposed Transport Rule, notice of which was published in the Federal Register and provided on our website for the rule.  All materials related to meetings held in conjunction with the Transport Rule are in the docket, and other useful information, including all technical and support data, may be found on our website.  As soon as legally feasible, we strive to make all information fully available to the public through release on our website -- even prior to publication in the Federal Register.
Organization: San Miguel Electric Cooperative, Inc.
Tampa Electric Company
Comment: 
San Miguel Electric Cooperative, Inc.
San Miguel appreciates the efforts the EPA has provided in answering questions on the proposed CATR through the use of webinars and conference calls sponsored by the NRECA and EEI. [EPA-HQ-OAR-2009-0491-2641.1, p.2]
Tampa Electric Company
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.70.]
I would like to take this opportunity to compliment EPA in its effort to post on its website quite a number of the documents used to support the Transport Rule development.
Response: 
Thank you.  EPA strives continually to make its rulemaking process as transparent as possible.
Organization: Southern Company
Comment: 
Southern Company
In the two and half years since the U. S. Court of Appeals for the D.C. Circuit vacated the Clean Air Interstate Rule, EPA has developed the proposed Transport Rule. During that time, the Agency has made no effort to obtain stakeholder input on the underlying data used to develop the proposed rule or on the approach.1 [EPA-HQ-OAR-2009-0491-2864.1, p. 5]
Footnote 1: EPA did hold one series of 'Listening Sessions' in advance of the proposed rule with stakeholder groups in the Spring of 2009. One such session was held with electric utility industry representatives on April 17, 2009. However, at those sessions, EPA provided no insights into its thoughts or plans for the replacement rule. In response to questions at those Listening Sessions (and in other forums as well), EPA refused to provide any information on its proposed rule. Even now, in the context of the NODA, EPA is refusing to provide requested information. Outside of the one 'Listening Session', EPA has offered no opportunity for input from the electric utility industry. [EPA-HQ-OAR-2009-0491-2864.1, p. 5]
Response: 
EPA has purposefully focused on public outreach on the rulemaking to replace the Clean Air Interstate Rule since 2009, and up through proposal.  We held more than a dozen listening sessions prior to promulgation of the proposed Transport Rule, we met with anyone who requested a meeting; we held webinars and conference calls for whomever requested such meetings; we posted all information on our website as soon as legally available; plus made all supporting material available in the docket, including a detailed list of stakeholder meetings.  Regarding the data used to develop the proposed rule or the approach, EPA asked for extensive comments on all data in the proposal as well as publishing 3 NODAs following the proposal, all of which took extensive comment and provided data updates and explanations of our process.

VII. State Implementation Plan Submissions

Organization: Alabama Department of Environmental Management
Comment: 
Alabama Department of Environmental Management
EPA is proposing to implement the transport rule through Federal Implementation Plans (FIPs). ADEM objects to this approach. According to the CAA, EPA has up to two years to promulgate a FIP after EPA either disapproves a SIP submission or finds that a state has failed to make a required submission. EPA has yet to take either action with respect to the transport portion of Alabama's 'infrastructure' SIPs for the 1997 ozone and fine particle NAAQS and the 2006 fine particle NAAQS. EPA should allow states an opportunity and sufficient time to revise their SIPs to address the final transport rule prior to promulgating a FIP. Such an approach would be consistent with the intent of the CAA. The court did not impose a schedule when it remanded CAIR back to EPA. Therefore, it is unclear why there is such an urgency to replace CAIR.  [EPA-HQ-OAR-2009-0491-2616, p.2]
Response: 
See preamble Sections IV and X for a discussion of FIP authority and SIP deadlines.  Additional information can be found in other responses to comments primarily in Section III of this document and in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs Final Rule TSD."
Organization: Buckeye Power, Inc.
Comment: 
Buckeye Power, Inc.
For all of the foregoing reasons, Buckeye Power urges EPA to withdraw its proposed CATR program. If it does proceed, EPA should (4) allow states the opportunity to develop state implementation plans instead of using federal implementation plans. [EPA-HQ-OAR-2009-0491-2710.1, p.13]
Response: 
See preamble sections IV and X for explanation of the need for FIPs and information on state SIP options to replace the FIPs.
Organization: Crouch, Diane
Comment: 
Crouch, Diane
 It also doesn't allow the states enough time to develop and put in place their own regulatory plans. Given the improvements in air quality that are already occurring, I believe the EPA can delay this rule and achieve the same environmental benefit at a much lower cost for utility ratepayers. [EPA-HQ-OAR-2009-0491-3284, p.1]
Please delay the Transport Rule and modify it with longer deadlines that won't increase costs needlessly and that allow states enough time to put in place common sense regulations. [EPA-HQ-OAR-2009-0491-3284, p.1]
Response: 
See preamble sections IV and X for explanation of the need for FIPs and information on state SIP options to replace the FIPs.
Organization: Edison Mission Energy (EME)
Comment: 
Edison Mission Energy (EME)
The Practical Effect of EPA's Proposed Approach will be to Undercut the Trading Scheme EME also believes that the practical effect of EPA's approach will undercut the trading scheme. EPA states in the Transport Rule preamble that there are states (EPA does not specify how many) for which a FIP will not be finalized under the Transport Rule until EPA takes action on a pending SIP submission. [EPA-HQ-OAR-2009-0491-2707.1, p.15]
According to the preamble, these may be states that were included in the 2005 findings of failure to submit and not included in CAIR, and that have since submitted SIP revisions to satisfy the requirements of § 110(a)(2)(D)(i) for the 1997 8-hour ozone and PM2.5 NAAQS. EPA states that those SIP revisions have either been approved or are pending approval. EPA does not specify which states fall under this category, but EPA concludes that it will only finalize the FIP for those states if it determines that the SIP is incomplete, it disapproves the SIP submission, or the state withdraws the SIP revision. Furthermore, as described above, EPA makes a similar statement regarding SIP submissions to satisfy the requirements of § 110(a)(2)(D)(i) for the 2006 PM 2.5 NAAQS. [EPA-HQ-OAR-2009-0491-2707.1, p.16]
By proposing to regulate some states immediately under a FIP while allowing others to issue SIPs, the Transport Rule creates a significant practical obstacle to the implementation of its trading provisions. The success of the interstate trading component of the Transport Rule depends upon the participation of all of the states. If some states are undergoing the implementation of a SIP and others are not, this creates an awkward situation because sources in the latter states would not be available to participate in trading until the SIP process is complete. Since implementation of a SIP takes a minimum of three years, sources in those states would not be prepared to participate in the trading scheme by 2012. This is practically important because the trading scheme will be most effective if all of the affected sources are able to participate on the first date the rule goes into effect. [EPA-HQ-OAR-2009-0491-2707.1, p.16]
Moreover, by imposing a FIP immediately on states that submitted their CAIR SIPs in a timely manner but not on those that submitted their CAIR SIPs late (i.e., those whose SIPs are still pending), EPA has penalized the states that took timely action and allowed those who were late to benefit, because the latter are able to take advantage of the SIP process as part of the Transport Rule. If EPA were to proceed with its proposed approach, despite the fact that it is not consistent with CAA requirements, it should attempt to mitigate, at least partially, the problems created by having some states subject to a FIP immediately while others are allowed to benefit from the SIP process by allowing sources to use existing CAIR allowances thru Phase I of the Transport Rule. 44 [EPA-HQ-OAR-2009-0491-2707.1, pp.16-17]

44 We understand that the Environmental Markets Association ("EMA") will be proposing one mechanism to utilize CAIR allowances during Phase I of the Transport Rule. Under EMA's proposal for CAIR NOx allowance conversion, EPA would apply surrender ratios to banked allowances in a way that would reverse the impact of EPA's original fuel factor allocation method that was rejected by the D.C. Circuit. EMA proposes that reversal of the fuel factor should not be tied to the original allowances as allocated to recipients, but to the fuel status of the holder of allowances offering them for conversion. EMA also proposes that conversions be completed in rounds to discourage use of non-emitting conversion proxies.
Response: 
See preamble sections IV and IX, and responses to other comments primarily in this section.  See also the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs Final Rule TSD."  EPA has evaluated the status of each state's 110(a)(2)(D)(i)(I) SIPs with regard to the 1997 ozone NAAQS, the 1997 PM2.5 NAAQS and the 2006 PM2.5 NAAQS.  On a pollutant basis, all compliance dates in the final rule are the same for all states.  States subject to PM2.5 requirements have a January 1, 2012 compliance date.  States subject to ozone season requirements have a May 1, 2012 compliance date.
Organization: Georgia Department of Natural Resources, Air Protection Branch
Comment: 
Georgia Department of Natural Resources, Air Protection Branch
EPA's approach to establishing FIPs in every state subject to this rule is unjustified and undermines the Federal-State partnership the EPA administrator has said is important to successful implementation of the Clean Air Act. 
On October 9, 2007 EPA published in the Federal Register the approval of Georgia's CAIR SIP. This approval preceded the December 2008 remand of the CAIR by the D.C. Circuit Court. CAIR was remanded to ensure the environmental benefits achieved by that rule remain in effect. Therefore, Georgia EPD strongly disagrees with EPA's conclusion that the Court's decision means EPA's approval of our SIP no longer satisfies the section 110(a)(2)(D)(i) obligation and for that reason EPA's 2005 findings that we had failed to submit such a SIP remains in force. In lieu of a FIP, EPA should retain the CAIR SIP requirements, which continue to achieve significant reductions, until such time Georgia submits and EPA approves a revision implementing the requirements of the final Transport Rule. [EPA-HQ-OAR-2009-0491-2647.1, p.1]
Response: 
See preamble Sections IV, other responses to comments primarily in Section III of this document and the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs Final Rule TSD."
Organization: Maryland Department of Environment (MDE)
Comment: 
Maryland Department of Environment (MDE)
Maryland assumes that EPA views the proposed framework of this rule as an approach that would be used in subsequently issued rules to address transport issues associated with future new NAAQS. Maryland strongly recommends that EPA revise the regulatory framework of the proposed rule to accomplish the following: (1) align the timetable of the transport remedy with the timing of SIPs as required by the CAA; (2) provide a FIPSIP mechanism that allows a state to have discretion in the design of certain aspects of the remedy, e.g., allocation of its own budget of allowances to sources; and (3) mandate upwind states' State Implementation Plans (SIPs) contribute to development of a full remedy if the federal remedy does not achieve elimination of significant contribution and interference with maintenance within the required CAA timeframe. [EPA-HQ-OAR-2009-0491-2639.2, p.2]
2010: Propose NAAQS, Propose SIP Call
2012: EPA designations (2 yr max)
2013: Transport SIP due  -  controls due 2  -  3 yrs later, Final FIP, if no SIP submitted
2015: Attainment SIP due (3 yrs after designation)
2017+: Attainment deadlines [EPA-HQ-OAR-2009-0491-2639.2, pp.2-3]
Maryland believes that these changes will improve the framework of the proposed rule and benefit both the states and EPA in the creation of new transport rules moving forward, as well as achieve notable emissions reductions in a shorter span of time. [EPA-HQ-OAR-2009-0491-2639.2, p.3]
Maryland also advises EPA to consider following the example set in the Clean Air Interstate Rule (CAIR) that allowed a state to submit an abbreviated SIP, in tandem with a FIP that provided for many of the required elements of the remedy. This allows the Federal framework to design the elements of the program that are common to all applicable states, but have the states design certain elements, such as the allocation of the allowance budget, that require the more specific and local knowledge that states have regarding their sources. [EPA-HQ-OAR-2009-0491-2639.2, p.3]
Response: 
See preamble section X regarding state allocation options under the Transport Rule.
As noted in the preamble, EPA believes that the broad framework for evaluating significant contribution and interference with maintenance outlined in this rule is applicable to future NAAQS as well.   However, EPA is not taking any final action at this time to apply this framework to any future NAAQS and additional technical analysis would be necessary to do so.
Organization: Mississippi Department of Environmental Quality
Comment: 
Mississippi Department of Environmental Quality
The rule is proposed as a Federal Implementation Plan rather than requiring State Implementation Plans (SIPs). It is important that a state has the ability to develop and adopt a SIP to address its particular situation and needs. There needs to be definite provisions and guidance for the states to develop and submit a SIP to address the entire rule or certain portions of it, such as the unit level allocation provisions. [EPA-HQ-OAR-2009-0491-2634.1, p.1]
Response: 
See preamble section X.
Organization: National Association of Clean of Air Agencies (NACAA)
Comment: 
National Association of Clean of Air Agencies (NACAA)
EPA Should Provide Guidance on Transport Rule SIP Submittals  -  Particularly for States That Wish to Allocate Allowances Using a Different Mechanism Than Proposed by EPA
NACAA appreciates EPA's attempts to expedite implementation of the Transport Rule by proposing a FIP along with the rule instead of issuing a notice requesting the submission of State Implementation Plans (SIP Call). As EPA well knows, preparing another SIP on top of existing SIP obligations would be a severe strain on already stretched state and local resources. However, NACAA does not believe EPA has provided sufficient guidance to states that may choose to submit a SIP. In particular, a number of NACAA members would prefer to allocate emissions allowances to in-state sources using their own procedures, rather than EPA's. For example, some states may wish to distribute their allowances to in-state sources in a manner that encourages renewable energy and energy efficiency. We believe that this should not affect the approvability of the SIP, since the distribution of allowances within the state does not affect the overall emissions in the state or a source's decision to control or not to control emissions. However, the proposal does not provide guidance on what EPA would consider an acceptable allowance distribution mechanism. Furthermore  -  and critically  -  [EPA-HQ-OAR-2009-0491-2771.1, p.5] NACAA seeks guidance on what criteria state SIPs would need to meet in order for that state's sources to be able to still participate in the interstate trading program. We urge EPA to state that it will quickly approve a state SIP that incorporates the Transport Rule FIP elements and only differs significantly from the FIP with respect to the allowance allocation scheme. [EPA-HQ-OAR-2009-0491-2771.1, p.6]
Response: 
See preamble section X.
Organization: National Mining Association (NMA)
Comment: 
National Mining Association (NMA)
EPA proposes to require compliance with phase one requirements under the proposed rule at the beginning of 2012, just six or so months after EPA anticipates completion of the rule. This is wholly unrealistic. States will not have had an opportunity to examine and understand the final rule and adopt State Implementation Plans (SIPs), and sources will not have had an adequate opportunity to plan for the new requirements. [EPA-HQ-OAR-2009-0491-2868.1, p.15] [[These comments can also be found in Section VII.C.]]
Response: 
See preamble Sections VI and VII for discussion of compliance deadlines.  See preamble Section X for information relating to SIP deadlines.
Organization: Oklahoma Department of Environmental Quality
Comment: 
Oklahoma Department of Environmental Quality
[[2662.1 p.3]]
   I. Oklahoma's Coverage Under the FIP
Oklahoma submitted its 110(a)(2)(D)(i)(I) SIP in May 2007. EPA has yet to fully approve or disapprove that SIP. On September 17, 2010, EPA published in the Federal Register a proposal to approve the PSD portion of the SIP (75 FR 56923); however, the proposal does not address all the elements in the submittal that pertain to prohibiting air pollutants from within Oklahoma from significantly contributing to nonattainment or interfering with maintenance of the relevant NAAQS in downwind states. Under this new Transport Rule, EPA has stated that states will be covered by the FIP only if it either determines that the state's SIP submission is incomplete or disapproves the state's SIP submission. Because our SIP has not been fully acted upon, Oklahoma appears to be in somewhat of a "lame duck" situation. Oklahoma is concerned as to whether it will in fact be covered by EPA's FIP and what, if anything, it needs to do regarding its SIP submittal to ensure coverage under the FIP. 
Response: 
EPA plans to address Oklahoma's significant contribution to nonattainment or interference with maintenance in other states with regard to the 1997 ozone NAAQS under a separate action--a Supplemental Notice of Proposed Rulemaking.  The status of the SIP submittal will be addressed in that action.  This rulemaking finds that Oklahoma does not significantly contribute to nonattainment or interfere with maintenance in other states with regard to the 1997 PM2.5 NAAQS or the 2006 PM2.5 NAAQS.
Organization: Ozone Transport Commission (OTC)
Comment: 
Ozone Transport Commission (OTC)
Finally, earlier in our comments OTC advises EPA to provide that approval decisions on upwind states' SIPs be made contingent upon their resolution of any remaining emission reductions EPA deems necessary to fulfill their obligations under Section 110(a)(2)(D) of the Clean Air Act, in the event the federal remedy does not eliminate significant contribution and interference with maintenance as anticipated.
Response: 
EPA has considered this comment and discusses it in section III. of the preamble to the final rule.
Organization: Pennsylvania Department of Environmental Protection
Comment: 
Pennsylvania Department of Environmental Protection
The DEP supports EPA's approach of proposing a FIP in order to expedite implementation of the Transport Rule. EPA indicates in its preamble that a state may submit a SIP revision in order to implement the Transport Rule. 75 Fed. Reg. at p. 45,342. EPA states that: EPA also notes that, by promulgating these Transport Rule FIPs, EPA would in no way affect the right of states to submit, for review and approval, a SIP that replaces the federal requirements of the FIP with state requirements. In order to replace the FIP in a state, the state's SIP must provide adequate provisions to prohibit NOX and SO2 emissions that contribute significantly to nonattainment or interfere with maintenance in another state or states. [EPA-HQ-OAR-2009-0491-2660.1, p.7]
The final TR should be more explicit in delineating what a SIP revision mayor may not include, provide additional guidance on whether there are any unacceptable allocation mechanisms. In addition, the rule should indicate explicitly that EPA will quickly approve a state SIP that incorporates the FIP elements and only differs in the allocation mechanism. [EPA-HQ-OAR-2009-0491-2660.1, p.8]
Response: 
See preamble section X.
Organization: South Carolina Department of Health and Environmental Control 
Comment: 
South Carolina Department of Health and Environmental Control 
DHEC notes that the proposed Transport Rule does not adequately address SIPs. There are two parts of the SIP discussion in the proposal, the role of transport in infrastructure SIPs, and Transport Rule SIPs. First, states are required to submit SIPs that address CAA section 110(a)(2) three years after the promulgation of a new NAAQS. If states fail to submit SIPs that address section 110(a)(2), then the EPA can issue a Federal Implementation Plan ("FIP"). DHEC addressed transport in SIP submittals for the 1997 Ozone and PM2.5 standards, and the 2006 PM2.5 standard, by citing the CAIR, meaning that South Carolina relied on the CAIR to meet its obligations to control interstate transport of pollutants. [EPA-HQ-OAR-2009-0491-2677.1 p.15]
The proposed Transport Rule offers the following guidance on SIPs: For the states that have now been identified to be contributing significantly to nonattainment or interfering with maintenance under this proposed rule and whose 110(a)(2)(D)(i)(I) SIPs with respect to the 1997 ozone and PM2.5 NAAQS are pending approval, EPA will finalize the FIP included in this proposed rule only if EPA either determines that the SIP submission is incomplete or disapproves the SIP submission. (Alternatively, if a state withdraws its SIP submission, EPA will finalize the FIP.)33 [EPA-HQ-OAR-2009-0491-2677.1 p.15]
The implication of the EPA's statement is unclear. Does the EPA intend to publish disapprovals for SIPs that relied on the CAIR to satisfy the transport provisions of section 110(a)(2) before it publishes a final Transport Rule? On NACAA-hosted conference calls with states on the Transport Rule, EPA staff has stated that EPA regional offices will work with states on SIP-related questions. DHEC would prefer to have the ability to comment on the EPA's strategy for replacing SIPs before the Transport Rule is final. Once a final rule is in place, that rule will bind regional offices' decisions on SIPs. [EPA-HQ-OAR-2009-0491-2677.1 p.15]
In addition to our comment that the proposal lacks explanation on SIPs, DHEC offers the following preferred strategy if the EPA issues a final Transport Rule that retains the problematic modeling approach from the proposal: The EPA should allow regional offices to interpret the parts of previously submitted infrastructure SIPs (including the four prongs associated with 110(a)(2)(D) 2006 PM2.5 NAAQS) such that where states note that the CAIR will meet the interstate transport obligations, so too will the Transport Rule. This is a reasonable interpretation. First, in the infrastructure SIPs, states are noting that they are relying on the current EPA-led program to address interstate transport. When states submitted the SIP, that program was the CAIR. After January 1, 2012, that program would be the Transport Rule. Second, modeling in the proposed Transport Rule found that South Carolina did not significantly contribute to 24-hour PM2.5 nonattainment or interfere with maintenance downwind for the 2006 PM2.5 NAAQS.34 Third, South Carolina's utilities are complying with the CAIR SO2 limits, which are stricter than the proposed Transport Rule limits. [EPA-HQ-OAR-2009-0491-2677.1 p.15]
It seems that the EPA wants states to formally withdraw their previous SIP submittals, and re-submit the entire revisions for the 1997 ozone and PM2.5 NAAQS, with "CAIR" stricken and replaced by "Transport Rule" once it is final. This would be a time-consuming paperwork exercise with little to no actual air quality benefit, process for the sake of process. Including more explanation on this question in the final rule would provide more clarity and consistency than relying on the 10 EPA regions to develop their own guidance. [EPA-HQ-OAR-2009-0491-2677.1 p.16]
Further, in both parts of the SIP discussion, the final rule could include SIP provisions that would have been impracticable for DHEC to have commented on during the comment period because the EPA simply did not include the provisions in the proposal. The importance of SIPs in implementing the Clean Air Act means that the SIP provisions of the Transport Rule are of central relevance to the outcome of the rule. If the EPA alters the SIP guidance significantly from what could be expected from the nebulous language in the proposal, DHEC requests that the EPA re-notice the proposal. [EPA-HQ-OAR-2009-0491-2677.1 p.16]
Response: 
As explained in section X the preamble to the final rule, EPA will work with states that wish to submit SIPs to ensure a smooth integration with the relevant Transport Rule trading programs and intends to provide information and tools to assist states in their rulemaking efforts.  Further, EPA notes that the specific preamble language highlighted by the commenter only applied to states that were not covered by CAIR.  Section IV of the preamble to the final rule, responses to comments in this document (primarily in Section III.A.), and the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs Final Rule TSD" address the CAA 110(a)(2)(D)(i)(I) issues raised in this comment.  The impact of the remand of CAIR is also discussed in the preamble, largely in Section V.B.  EPA also notes that as CAIR addressed the requirements of 110(a)(2)(D)(i)(I) with respect to the 1997 ozone and 1997 PM2.5 NAAQS, EPA could not and has not approved 110(a)(2)(D)(i)(I) SIPs with respect to the 2006 PM2.5 NAAQS which relied on CAIR,  Section X of the preamble to the final rule has information on SIP requirements under the Transport Rule.

VII.A. Section 110 (a)(2)(D)(i) SIPs for the 1997 Ozone and PM2.5 NAAQS

Organization: American Public Power Association (APPA)
Comment: 
American Public Power Association (APPA)
Thus, APPA believes that the three-year deadline for CAA section 110(a)(2)(D)(i)(I) interstate transport SIP submissions for the 1997 NAAQS should be restarted due to EPA's unlawful adoption of CAIR, and should begin to run upon EPA's promulgation of a valid final rule replacing CAIR. [EPA-HQ-OAR-2009-0491-2812.1, pp.27-28]
Response: 
See Section IV of the preamble, responses to other comments particularly those found in section III.A. of this document, and the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs Final Rule TSD."
Organization: City of Dover, Delaware
Comment: 
City of Dover, Delaware
Under the proposed Transport Rule, EPA has indicated that they will utilize Federal Implementation Plans (FIPs) in order to initiate the program by the proposed 2012 start date. The City feels that EPA should allow states to implement the program via State Implementation Plans (SIPs) per the procedures established under the CAA. It appears to the City that EPA is preventing the states from exercising their ability to implement this program as a result of CAIR's deficiencies and not as a result of the States' failure to develop SIPs within the allotted time period or failure by States to implement SIPs consistent with the framework established by EPA - the traditional justifications for utilizing FIPs. For this reason, the City feels that the three-year deadline for SIPs for the 1997 NAAQs should be restarted upon EPA's promulgation of a final rule replace CAIR. [EPA-HQ-OAR-2009-0491-2636.1, p.3]
Response: 
See Section IV of the preamble, responses to other comments particularly those found in section III.A. of this document, and the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs Final Rule TSD."  See also preamble section X for a discussion of state SIPs.
Organization: Louisiana Chemical Association (LCA)
Comment: 
Louisiana Chemical Association (LCA)
LCA also has a number of questions concerning the ability and timing for states to submit SIPs in lieu of the FIPs. For example, if a state wants to use other enforceable measures or propose a NOx allocation scheme that is different than EPA's, the Preamble to the proposed rule gives little guidance as to the requirements. In a June 9, 2009 Federal Register notice, EPA indicated that Louisiana would have until July 9,2012 within which to submit a SIP to address its 'good neighbor' requirements under Section 110 of the Clean Air Act with respect to PM2.5 transport and to obtain approval of that SIP before EPA is required to implement a FIP. Yet, EP A is proposing to make the Transport Rule FIP effective in 2011, with a compliance date beginning January I, 2012. An extension of time is warranted for LCA and its affected members to comment on the relationship between SIPs and FIPs and to suggest alternatives to EPA's approach that better preserves the federalism inherent in the Clean Air Act regulatory scheme. [EPA-HQ-OAR-2009-0491-1925.1, p. 4]
Response: 
See Section IV of the preamble, responses to other comments particularly those found in section III.A. of this document, and the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs Final Rule TSD."  See also Preamble Section X for information on state SIPs, including state allocation options.

VII.B. Section 110 (a)(2)(D)(i) SIPs for the 2006 PM2.5 NAAQS

Organization: American Public Power Association (APPA)
Comment: 
American Public Power Association (APPA)
Likewise, EPA`s explanation that, with respect to the 2006 24-hour PM2.5 NAAQS, it will finalize FIPs for states that have not submitted SIPs and those for which EPA finds the previously-submitted SIPs to be incomplete or inadequate, 75 Fed. Reg. at 45342/2,17 lacks merit and is contradicted by EPA`s own underlying justification for proposing the Transport Rule. In the proposed rule (as in CAIR), EPA plainly takes the position that it has the authority, if not the obligation, to set the overall terms for states` implementation of section 110(a)(2)(D)(i)(I) with respect to any new or revised NAAQS. Given this circumstance, therefore, the affected states` section 110(a)(2)(D)(i)(I) obligation with respect to the 2006 24-hour PM2.5 NAAQS should be deemed to begin to run only upon EPA`s promulgation of a valid final rule setting guidelines (in the form of statewide emission budgets) for the states (e.g., a final CAIR replacement rule that is consistent with the CAA). [EPA-HQ-OAR-2009-0491-2812.1, p.28]
Response: 
See Section IV of the preamble, responses to other comments particularly those found in section III.A. of this document, and the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs Final Rule TSD."
Organization: Louisiana Chemical Association (LCA)
Comment: 
Louisiana Chemical Association (LCA)
EPA Must Allow Louisiana at Least 18 Months to Adopt and Submit a SIP to Address any Alleged Impact of Louisiana Emissions on Downwind Annual PM2.5 NAAQS in Harris Co., Texas, Before Imposing a FIP.
On June 9, 2010, EPA published a finding that Louisiana failed to make a SIP submission to address the good neighbor provisions of the CAA with respect to the 2006 PM2.5 NAAQS revisions. EPA did not make any finding that Louisiana sources or emission activities were actually contributing significantly to nonattainment in another state or were interfering with maintenance in another state. EPA provided in that rulemaking that Louisiana would have two years within which to submit a SIP addressing this deficiency and obtain approval of it, or EPA would enact a FIP. Under the CAA, through a SIP submittal in response to this finding and notice, Louisiana would have the ability to demonstrate that emissions within its geographic jurisdiction do not significantly contribute to nonattainment and do not interfere with maintenance of the PM2.5 annual standard in any other state, and if they do so, Louisiana would have the authority to choose what sources to control, point sources, a subset of point sources, mobile sources, nonroad sources or other types of emissions. [EPA-HQ-OAR-2009-0491-3527.1, p. 39]
EPA did not wait on Louisiana to submit a SIP for this purpose even though the June Federal Register notice purported to allow Louisiana time to do so. In the instant rulemaking, on August 2, 2010, EPA proposed to find that Louisiana emissions are projected to interfere with maintenance of the annual PM2.5 NAAQS at one monitor in one county in Texas. EPA is now proposing its own FIP, to become effective in 2011 (well before the 2 year period stated in the June 2010 finding of failure to submit), with requirements effective as of January 1, 2012. For the reasons stated above, LCA asserts that EPA cannot enact a FIP and make it effective prior to allowing Louisiana the full time period allotted by the Clean Air Act within which to submit a SIP. [EPA-HQ-OAR-2009-0491-3527.1, p. 39-40]
Response: 
See Section IV of the preamble, responses to other comments particularly those found in section III.A. of this document, and the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs Final Rule TSD."
Organization: Nelson Industrial Steam Company (NISCO)
Comment: 
Nelson Industrial Steam Company (NISCO)
EPA did not wait on Louisiana to submit a SIP for this purpose even though the June Federal Register notice purported to allow Louisiana time to do so. In the instant rulemaking, on August 2, 2010, EPA proposed to find that Louisiana emissions are projected to interfere with maintenance of the annual PM2.5 NAAQS at one monitor in one county in Texas. EPA is now proposing its own FIP, to become effective in 2011 (well before the 2 year period stated in the June 2010 finding of failure of Louisiana to submit a SIP), with requirements effective as of January 1, 2012. For the reasons stated above, NISCO asserts that EPA cannot enact a FIP and make it effective prior to allowing Louisiana the full time period allotted by the Clean Air Act within which to submit a SIP. [EPA-HQ-OAR-2009-0491-2813.1, p.11]
Response: 
See Section IV of the preamble, responses to other comments particularly those found in section III.A. of this document, and the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs Final Rule TSD."

VII.C. Transport Rule SIPs

Organization: 8-Hour Ozone State Implementation Plan (SIP) Coalition
Comment: 
8-Hour Ozone State Implementation Plan (SIP) Coalition
State Implementation Plan Alternative.  EPA requests comment on how a state could replace the Transport Rule FIP with a SIP and associated approval criteria.  At page 45,342 of the preamble, EPA states that 'The specific quantity of emissions reductions necessary for a state's SIP would be determined based on the state emissions budgets provided in the final transport rule.' [EPA-HQ-OAR-2009-0491-2736.1, p. 5]
The Coalition objects to EPA's quoted plan on two bases:  first, established law prohibits EPA from mandating any particular mix of precursor reductions for attainment or maintenance of a NAAQS; and second, this plan would lock in the results of EPA's current photochemical modeling without providing the opportunity for a SIP to rely on newer, more refined, or otherwise more informative modeling information. [EPA-HQ-OAR-2009-0491-2736.1, p. 6]
Response: 
As explained in section X. of the preamble to the final rule, a state always has the option of replacing a FIP with a state SIP.  The SIP must include a technical demonstration by the state that emissions in the state that cause significant contribution to nonattainment and interference with maintenance will be eliminated.  The technical demonstration can include modeling done by the state.  EPA would evaluate the SIP revision to ensure that Section 110(a)(2)(D)(i)(I) requirements are met.  Alternatively, a state could submit a SIP revision that relies on EPA modeling to identify the emissions in the state that are contributing significantly to nonattainment or interfering with maintenance in a downwind state and then require that the amount of emissions be eliminated through state requirements.  The state can decide which emissions to eliminate in the amount considered significant.  EPA would evaluate the SIP revision to ensure that Section 110(a)(2)(D)(i)(I) requirements are met.
Organization: Alabama Department of Environmental Management
Comment: 
Alabama Department of Environmental Management
In the preamble for the proposed rule, EPA says that states will be given an opportunity to submit a SIP that replaces the FIP. EPA does not provide sufficient guidance to states regarding the timing or minimum requirements for EPA approval of such SIP submittals. If the transport rule is finalized in the spring of 2011 and implementation begins in 2012, there is little time for states to develop SIPs to replace the FIPs. [EPA-HQ-OAR-2009-0491-2616, p.2]
Response: 
See preamble Section X.
Organization: American Electric Power
Comment: 
American Electric Power
My company(AEP) favors the continued reduction of air emissions, but believes that the EPA should delay this rule for several reasons:

:: The deadline does not provide enough time for states to develop their own implementation plans to comply with the rule.
The EPA should delay the Transport Rule until it sees the latest modeling based on CAIR compliance. At the least, the EPA should extend the compliance deadline to allow companies time to install the needed retrofits and to allow states to develop their own implementation plans.  [EPA-HQ-OAR-2009-0491-1923, p.1]
Furthermore, the six to eight months is a fraction of the time needed for states to develop their own implementation plans and get them approved. State implementation plans are not only the primary and preferred approach under the Clean Air Act, but also especially vital given the huge financial implications and accompanying decisions that will result from these new regulations. [EPA-HQ-OAR-2009-0491-2665.1, p.5] [[This comment can also be found in Section III.A.]]
Response: 
See preamble section IV concerning EPA's FIP authority and obligation.  Additional discussion can be found in responses to comments in Section III.A. of this document.   Preamble sections VI and VII have information on compliance deadlines.
Organization: American Municipal Power, Inc. (AMP)
Comment: 
American Municipal Power, Inc. (AMP)
EPA Should Reconsider Its Determination to Issue a FIP
The Transport Rule is currently designed and structured as a Federal Implementation Plan (FIP) to regulate emissions from EGUs in thirty-two states. AMP is puzzled by EPA's decision in this regard and would ask that EPA reconsider this decision. Specifically, since CAIR remains viable as an interim measure, EPA should not rush the Transport Rule via FIP; rather, the states should be given time to modify State Implementation Plans (SIP) as contemplated by both the express language and spirit of Clean Air Act's requirements and federal-state cooperation tenants. Similarly, unit level allowance allocations should be the responsibility of states per the SIP process rather than allocation by EPA using the flawed Integrated Planning Model. [EPA-HQ-OAR-2009-0491-2678.1, p.2]
Response: 
See preamble Sections IV and X for a discussion of FIP authority and SIP deadlines.  Additional information can be found in other responses to comments primarily in Section III of this document and in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs Final Rule TSD."
Organization: American Public Power Association (APPA)
Comment: 
American Public Power Association (APPA)
5. APPA believes there is no urgency to finalizing the PTR so "getting it right" by taking time to sort out many of the issues brought up in APPA`s comments and those comments submitted separately from UARG is appropriate. In particular, EPA should, consistent with what the Clean Air Act requires, allow time for states to develop SIPs, rather than immediately imposing FIPs. In the  meantime, CAIR would remain in place and would continue to maintain a strong and effective program of emissions reductions pending the initial compliance deadline for the Transport Rule. [EPA-HQ-OAR-2009-0491-2812.1, pp.3-4]
In addition, the proposed rule -- and especially its 2012 first-phase compliance date -- is fundamentally inconsistent with the CAA because it effectively deprives states of the time they need to develop, submit, and receive EPA approval of SIPs before the program begins. See section VII infra. [EPA-HQ-OAR-2009-0491-2812.1, pp.16-17] [[This comment can also be found in Section III.A]]
APPA believes that it would be possible for EPA to encourage early emission reductions beginning in 2012 under the proposed rule even if the initial binding compliance date under the rule was not until some years later. One possible approach would be to set "shadow" allowance allocations, using the best data available, for 2012 and each subsequent year until the new program begins. Then, during the period leading up to the new program`s initial compliance year, EPA (or, more properly, a state) could credit sources with additional allowances corresponding to the number of tons they emitted below their shadow allowance allocation levels in those years, with those allowances eligible to be banked and used beginning in the first compliance year. The ability to earn allowances -- usable once the new program begins -- for early reductions would give sources a meaningful incentive to reduce their emissions prior to the start of the program, while allowing them the time they need to make the adjustments necessary for compliance, and affording states sufficient time to develop and submit SIPs consistent with the Act. [EPA-HQ-OAR-2009-0491-2812.1, p.20]
EPA should take the needed time necessary to correct the many errors in the proposed rule, and allow adequate time for states to develop SIPs and for sources to make the adjustments necessary to comply with the rule, rather than rushing to implementation as it proposes to do. [EPA-HQ-OAR-2009-0491-2812.1, p.20] [[This comment can also be found in Section III.A.]]
Response: 
See preamble, particularly sections IV and X regarding state SIP submittals and SIP revision provisions.  See also responses to other comments particularly in section III.A. of this document and the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs Final Rule TSD."
Organization: ARIPPA
Comment: 
ARIPPA
F. The initial compliance deadline under the proposed FIP does not allow sufficient time for states to develop and implement state-specific programs, or for affected EGUs to develop compliance plans.
Nevertheless, the initial compliance deadline of January 1, 2012, does not provide states adequate time to develop and implement state-specific strategies for achieving their emissions budgets, as authorized under the Proposed Rule. Indeed, EPA clearly states in the Proposed Rule that it "wants to offer states substantial flexibility for addressing the Section 110(a)(2)(D)(i)(I) transport issues though a SIP should they choose to do so." 75 Fed. Reg. 45342. However, affected states would not have sufficient time to develop state-specific regulations and then satisfy all elements of the SIP-revision approval process, and secure EPA approval of the SIP, all before January 1, 2012. See 75 Fed. Reg. 45342 ("The Transport Rule FIPs would be in place in each covered state until a state's SIP was submitted and approved by EPA to replace a FIP.")? 75 Fed. Reg. 45227 (recognizing that "[b]oth EPA and state resources are limited and EPA recognizes the importance of developing requirements that make efficient use of limited EPA and state resources"). [EPA-HQ-OAR-2009-0491-2794.1, p.18]
EPA must recognize that the inability of states to finalize state-specific SIP-based programs for implementing the Transport Rule would not merely postpone transition from a FIP-based to a SIP-based program. Instead, affected sources must pursue compliance options based upon the regulations that will be effective at the earliest time. Sources may not be able to develop and implement a temporary or transitional compliance approach, especially to the extent that the Proposed Rule is ultimately promulgated. Instead, the very restrictive proposed emission limitations that would be imposed upon the ARIPPA facilities through the Proposed Rule would require dramatic measures, if such reductions could even be achieved. These affected facilities would not likely have the option of implementing a transitional approach during the first phase of regulation that could simply be undone and replaced with a longer term strategy once the state SIP is promulgated and approved. For this reason, it is critical that states be afforded a reasonable opportunity to finalize and establish SIPs before affected sources would be subject to the promulgated standards. [EPA-HQ-OAR-2009-0491-2794.1, p.18] [[These comment can also be found in Section III.A.]]
For these reasons, EPA should extend the initial compliance deadline in the Proposed Rule until January 1, 2015 (with the second phase of emissions reductions beginning in January 2017), to allow affected states and EGUs within those states sufficient time to develop and implement approved SIPs and compliance plans, respectively. Specifically, EPA should allow states until January 1, 2015, to develop SIPs and complete the SIP-approval process, and any FIP should not become effective unless the state has failed to implement an appropriate SIP by that date. [EPA-HQ-OAR-2009-0491-2794.1, p.19]
Finally, ARIPPA objects to the compliance deadline under the proposed FIP, on the basis that such deadline does not afford sufficient time for states to develop and implement state-specific programs, or for affected EGUs to develop compliance strategies. Similarly, the January 2012 compliance deadline does not allow affected EGUs adequate time to develop compliance plans to achieve the emissions reductions necessary to meet the applicable standards in the Proposed Rule. [EPA-HQ-OAR-2009-0491-2794.1, p.21]
For these reasons, EPA should extend the initial compliance deadline in the Proposed Rule until January 1, 2015, to allow affected states and EGUs within those states sufficient time to develop and implement approved SIPs and compliance plans, respectively. [EPA-HQ-OAR-2009-0491-2794.1, pp.21-22] [[These comments can also be found in Section V.C.2.]]
Response: 
See preamble Sections IV and X.  See also responses to comments primarily in Section III.A. of this document.
Organization: Associated Electric Cooperative, Inc. (AECI)
Comment: 
Associated Electric Cooperative, Inc. (AECI)
:: Allow states time to develop approvable State Implementation Plans (SIPs) that include unit allocations that better fit the regulated community. The states already have mechanisms developed under the CAIR SIP development for distributing their state budgets to facilities within their borders; [EPA-HQ-OAR-2009-0491-2845.1 p.3] [[This comment is also found in Section III.F.]]
Response: 
See preamble Section X.
Organization: Clean Air Council
Comment: 
Clean Air Council
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.44.]
The Council supports EPA's decision to move the process forward under a Federal Implementation Plan, while providing states with the option of replacing the FIP, the state implementation plan, as long as the SIP achieves the required emission reductions.
Since allowing the state to develop a SIP before imposing a FIP is the more traditional approach under the Clean Air Act, EPA must make clear how a state can move forward with the SIP process.
Response: 
See Section X of the preamble.
Organization: Cleco Corporation
Comment: 
Cleco Corporation
EPA has taken two years to develop this proposed rule and proposes to take another nine months to finalize it. At the same time, it eliminates time for public comment and time on the back end for state SIP development and compliance planning. [EPA-HQ-OAR-2009-0491-2859.1 p.3] [[The comment can also be found in Section V.C.]]
EPA's attempt to impose its one-size-fits-all FIP, without allowing states an opportunity to develop a SIP ignores the fact that state compliance options vary greatly from state to state. By way of example, EPA's multi-sector modeling shows significant differences from state to state with respect to which sectors have the most significant emissions of the precursor pollutants. For example, in Louisiana, EGU emissions represent less than 30% of total anthropogenic SO2 emissions, whereas, in Indiana, EGU emissions represent well over 80% of anthropogenic SO2 emissions.8 Under the proposed rule, states are included in the various programs because of total anthropogenic emissions  -  and not simply EGU emissions. EPA determines that all reductions should come from EGUs based on its macro-level analysis that this sector provides the most cost effective controls. That macro cost-effectiveness analysis does not necessarily hold true at the state level. Thus, under EPA's proposed rule, states are forced  -  via the FIP  -  to obtain all reductions from EGUs regardless of whether other reductions might prove more cost effective. For all of these reasons, each state should be allowed an opportunity to develop a plan for § 110(a)(2)(D)(i) compliance and tailor that plan to the unique challenges and opportunities within that state. [EPA-HQ-OAR-2009-0491-2859.1 p.5]
Response: 
See preamble section IV and X regarding state SIP submittals and deadlines, and SIP revision provisions.
Organization: Commerce Lexington Inc.
Comment: 
Commerce Lexington Inc.
The deadlines in the Transport Rule provide no practical way for power companies to install any needed pollution control equipment or for the states to develop their own state implementation plans (SIPs). SIPs have always been a cornerstone for compliance and enforcement of the Clean Air Act. [EPA-HQ-OAR-2009-0491-2869.1 p.2]
Response: 
See preamble Sections VI and VII for discussion of compliance deadlines.  See preamble Section X for information relating to SIP deadlines. 
Organization: Edison Mission Energy (EME)
Comment: 
Edison Mission Energy (EME)
EPA's aggressive emission reduction timelines are contrary to law. Title I of the Clean Air Act ("CAA") gives states, not EPA, primary responsibility for attaining air standards within their borders. Under Title I, the proper process for implementing measures to attain air quality standards, like the emission reduction contemplated by the Transport Rule, is for EPA to give the states an opportunity to propose a state implementation plan ("SIP") that achieves those goals. Title I does not permit EPA to skip the SIP development process and impose a federal implementation plan ("FIP") on the states first as it has done here, nor does the D.C. Circuit's opinion in North Carolina v. EPA remanding CAIR. By ignoring the cooperative federalism dictates of Title I, the Transport Rule fails to comply with the CAA. [EPA-HQ-OAR-2009-0491-2707.1, pp.2-3] [[These comments can also be found in Section III.A.]]
Response: 
See response in Section III.A. of this document.
Organization: Empire District Electric Company (Empire District)
Comment: 
Empire District Electric Company (Empire District)
Empire District believes that the CATR, as proposed, takes the SIP authority from the states and gives that authority to EPA due to the timing requirement that makes it impossible for many states to develop and submit their SIPs.  This is a disturbing new pattern in EPA rulemaking.  We encourage EPA to reconsider the timing of this regulation as it related to the relationship between EPA and the states. [EPA-HQ-OAR-2009-0491-2659.1, p.2]
Response: 
See preamble Sections IV and X, and responses to other comments primarily in section III of this document.
Organization: Energy Future Coalition
Comment: 
Energy Future Coalition
By promulgating a Federal Implementation Plan, EPA will quickly establish policies to reduce emissions from power plants that significantly contribute to air quality issues in neighboring states. By proceeding in this manner, however, EPA may also reduce the flexibility of states to credit existing efficiency programs or incentivize utilities to make additional investments in efficiency. For that reason, we urge EPA to help states transition from Federal to State air quality plans. EPA will need to provide a model rule and guidance to states to facilitate this process. As written, the CATR does not provide sufficient guidance to states that seek to prepare a SIP that incorporates energy efficiency incentives to reduce regulated emissions from power plants. [EPA-HQ-OAR-2009-0491-2623.1, pp.2-3]
Response: 
See preamble Section X.
Organization: Exxon Mobil Corporation
Comment: 
Exxon Mobil Corporation
EPA SHOULD ALLOW LOUISIANA SUFFICIENT TIME TO SUBMIT A SIP IN LIEU OF THE PROPOSED FIP
The Clean Air Act was intended by Congress to establish a model of cooperative federalism wherein states have the primary responsibility for air pollution control and EPA is to act only in the clear absence of state action. This is not one of those cases. Louisiana has acted to prevent interstate transport of emissions that could affect attainment of NAAQS in downwind states and should be given a reasonable opportunity to submit any necessary SIP improvements. EPA's preemptive action of proposing this FIP does not provide Louisiana with the deference accorded to states under the Clean Air Act. [EPA-HQ-OAR-2009-0491-2841.1,p.9]
Under CAA § 107(a), 42 USC 7407(a), the Act provides that '[e]ach State shall have the primary responsibility for assuring air quality within the entire geographic area comprising such State by submitting an implementation plan for such State which will specify the manner in which national primary and secondary ambient air quality standards will be achieved and maintained ... ' Under CAA §110(a)(1), 42 USC 7410(a), the Act provides that '[e]ach State shall ... adopt and submit to the Administrator, within 3 years (or such shorter period as the Administrator may prescribe) after the promulgation of a national primary ambient air quality standard '' a plan which provides for implementation, maintenance, and enforcement of such primary standard in each air quality control region (or portion thereof) within such State.' [EPA-HQ-OAR-2009-0491-2841.1, p.9]
The jurisprudence supports this primary role for states carved out by the Act. In Train v. Natural Resources Defense Council, Inc., 421 U.S. 60 (1975), the COUl1 had to determine 'whether Congress intended the States to retain any significant degree of control of the manner in which they attain and maintain national [air] standards' Id. at 78. The Court found that the CAA 'plainly' relegates EPA to 'a secondary role in the process of determining and enforcing the specific, source-by-source emission limitations which are necessary if the national standards it has set are to be met.' Id. at 79. 'The Act gives the Agency no authority to question the wisdom of a State's choices of emission limitations.' Id. at 79. As long as the state's plan results in compliance with air quality standards, 'the State is at liberty to adopt whatever mix of emission limitations it deems best suited to its particular situation.' Id. This view was reiterated in Union Elec. Co. v. E.P.A., 427 U.S. 246 (1976) wherein the Court stated: 'Congress plainly left with the States, so long as national standards were met, the power to determine which sources would be burdened by regulation and to what extent.' Id at 269. [EPA-HQ-OAR-2009-0491-2841.1,p.9]
The lower courts have upheld these basic principles enunciated by the Supreme Court. In Bethlehem Steel Corp. v. Gorsuch, 742 F.2d 1028 (7th Cir. 1984), the Court had to reanalyze a prior decision concerning CAA § 110(a) and found that 'The federal government through the EPA determines the ends-the standards of air quality-but Congress has given the states the initiative and a broad responsibility regarding the means to achieve those ends through state implementation plans and timetables for compliance. The Clean Air Act is an experiment in federalism, and the EP A may not run roughshod over the procedural prerogatives that the Act has reserved to the states ... , especially when ... the agency is overriding state policy.' Id. at 1036-37, (citations omitted). The decision in Virginia v. EPA, 108 F.3d 1397 (D.C. Cir. 1997), is particularly relevant here. The court held that EPA can call only for revisions of a SIP 'as necessary' to correct a SIP's inadequacy (i.e., if the state cannot achieve the ambient air quality standard under the terms of its SIP) (1410). It cautioned that EPA cannot condition approval of a SIP on the adoption of source specific regulations that EP A itself mandates. Id. at 1406-15. Specifically, the court stated: 'Congress did not give EPA authority to choose the control measures or mix of measures states would put in their implementation plans.' Instead, as stated in Train, the CAA leaves to the states 'the power to determine which sources would be burdened by regulations and to what extent' and CAA 'did not permit the agency to require the state to pass legislation or issue regulations containing control measures of EPA's choosing.' Id. at 1410. [EPA-HQ-OAR-2009-0491-2841.1,p.10]
Louisiana has adopted SIP provisions to address the good neighbor requirements under the Clean Air Act. On September 27,2006, the Louisiana Department of Environmental Quality (LDEQ) submitted a SIP revision to EPA adopting the CAIR S02 Trading Program to address its 'good neighbor' obligations under CAA Section 1l0(a)(2)(D) with respect to the potential impact of Louisiana emissions on downwind PM2.5 receptors in the State of Alabama. EPA approved this SIP revision on July 20,2007 at 72 Fed. Reg. 39741. On July 12,2007, LDEQ submitted a SIP revision to EPA adopting a SIP for a CAIR NOx Trading Program to address both the 1997 8-hour ozone standard and the 1997 annual PM2.5 standard. EPA approved this SIP revision on September 28, 2007 at 72 Fed. Reg. at 55064. LDEQ submitted amendments to its NOx CAIR SIP on July 1, 2009, which are pending before EPA for decision.  [EPA-HQ-OAR-2009-0491-2841.1,p.10]
EPA has indicated under the proposed CATR and that a CAIR SIP submission is no longer considered all adequate Section 1l0(a)(2)(D)(i)(I) SIP submission. 75 Fed. Reg. 45,341. EPA stated: [EPA-HQ-OAR-2009-0491-2841.1,p.10]
The promulgation of this rule does not affect the right of the states to submit, for review and approval, a SIP that replaces the federal requirements of the FIP with state requirements. To replace the FIP in a state, the state's SIP must provide adequate provisions to prohibit NOx and SO2 emissions that contribute significantly to nonattainment or interfere with maintenance in another state or states. Transport Rule FIP would be in place in each covered state until a state's SIP was submitted and approved by EPA to replace a FIP. Id. EPA taking comment on all aspects of how a state could replace the Transport Rule FIP with a SIP and on what the SIP approval criteria should be. Id. [EPA-HQ-OAR-2009-0491-2841.1, p.11]
Thus, the proposed CATR purports to be a finding of insufficiency of the Louisiana SIP to the extent it is based on CAIR. This finding of insufficiency will not be final until the CATR is final. Despite this, EPA proposes to enact the FIP BEFORE giving Louisiana the full CAA mandated ability to submit its own determination of 'significant contribution' or 'interference with maintenance' and if necessary, any SIP revisions to address the 1997 8-hour ozone NAAQS. EM believes this is contrary to the CAA and asserts that EPA cannot enact a FIP to address any alleged impacts of Louisiana sources on the 8-hour' ozone NAAQS in Texas without first giving Louisiana 18 months from the final date of the CATR finding of insufficiency of its existing CAIR SIP. [EPA-HQ-OAR-2009-0491-2841.1,p.11]
On June 9, 2010, EPA published a finding that Louisiana failed to make a SIP submission to address the good neighbor provisions of the CAA with respect to the 2006 PM2.5 NAAQS revisions. IS EPA did not make any finding that Louisiana sources or emission activities were actually contributing significantly to nonattainment in another state or were interfering with maintenance in another state. EPA provided in that rulemaking that Louisiana would have two years within which to submit a SIP addressing this deficiency and to obtain approval of it, or EPA would enact a FIP. Under the CAA, through a SIP submittal in response to this finding and notice, Louisiana would have the ability to demonstrate that emissions within its geographic jurisdiction do not significantly contribute to nonattainment and do not interfere with maintenance of the PM2.5 annual standard in any other state, and if they do so, Louisiana would have the authority to choose what sources to control, point sources, a subset of point sources, mobile sources, nonroad sources or other types of emissions. [EPA-HQ-OAR-2009-0491-2841.1,p.11]
EPA did not wait on Louisiana to submit a SIP for this purpose even though the June Federal Register notice purported to allow Louisiana time to do so. In the instant rulemaking, on August 2, 2010, EPA proposed to find that Louisiana emissions are projected to interfere with maintenance of the annual PM2.5 NAAQS at one monitor in one county in Texas. EPA is now proposing its own FIP, to become effective in 2011 (well before the 2 year period stated in the June 2010 finding of failure of Louisiana to submit a SIP), with requirements effective as of January 1, 2012. For the reasons stated above, EM asserts that EPA cannot enact a FIP and make it effective prior to allowing Louisiana the full time period allotted by the Clean Air Act within which to submit a SIP. [EPA-HQ-OAR-2009-0491-2841.1,p.11]
Response: 
EPA responds to each of the commenters points in responses to other, nearly identical, comments submitted by other comments.  Most of these responses can be found in Section III.A. of this document.  Additional information can be found in section IV of the preamble and in the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs Final Rule TSD."
Organization: Florida Department of Environmental Protection
Comment: 
Florida Department of Environmental Protection
  The Florida Department of Environmental Protection's (Department) Division of Air Resource Management (Division) appreciates EPA's efforts to address interstate transport issues and provide the flexibility for states to implement this rule through a Federal Implementation Plan (FIP) instead of a State Implementation Plan. With current resource constraints and rulemaking hurdles, it is often more expeditious for the Division to implement a FIP. [EPA-HQ-OAR-2009-0491-2624.1, p.1]
Response: 
EPA is finalizing Transport Rule FIPs for all states identified by the rule.
Organization: Florida Electric Power Coordinating Group, Inc. (FCG)
Comment: 
Florida Electric Power Coordinating Group, Inc. (FCG)
Finally, EPA's unreasonable 2012 date does not allow states time to develop their own SIPs to address interstate transport issues, despite EPA's pledge that states are free to do so. This issue is discussed more fully below.  [EPA-HQ-OAR-2009-0491-2658.1, p.4] [[This comment can also be found in Section III.A.]]
As stated in the proposed rule, EPA intends to issue a final rule by the end of spring 2011, and that states are free to develop their own State Implementation Plan (SIP) to implement the rule. 75 Fed. Reg. 45228. But EPA's schedule would leave regulated states no more than six months to develop, submit and obtain EPA approval of a SIP for regulation under the Transport Rule. This is unreasonable, unachievable, and contrary to law. EPA must respect the rights of individual states to develop and implement their own SIPs if they so choose. EPA does not have the authority to promulgate a FIP without first giving the states this opportunity. The ability to replace federal requirements at some point in the future does not satisfy the requirement that EPA allow states the opportunity to craft their own plans, at the outset of the program, to address interstate transport. [EPA-HQ-OAR-2009-0491-2658.1,p.10]
In addition, EPA should expressly discuss allowing states to demonstrate that as long as its emissions did not contribute significantly to nonattainment, or interfere with maintenance in another state, it would meet its obligation under Section 11 0(a)(2)(D)(i)(I) of the CAA. [EPA-HQ-OAR-2009-0491-2658.1,p.10]
Response: 
See preamble sections IV and X and the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs Final Rule TSD."
Organization: Florida Municipal Electric Association (FMEA)
Comment: 
Florida Municipal Electric Association (FMEA)
EPA's proposed Transport Rule usurps the traditional state role in designing state appropriate compliance plans and uses an inappropriate baseline. The Proposed Transport Rule establishes compliance timelines that make a FIP for the state of Florida unavoidable. State officials in Florida indicate that they cannot meet the State Implementation Plan (SIP) deadline required by the rule. This appears to be the case with all states subject to the Transport Rule. EPA has imposed a federal allowance allocation methodology which in the case of CAIR was appropriately and by Congressional design left to the states to accommodate state-specific circumstances. FMEA is concerned that once a state SIP is finally approved, the state will not be able to change the allocations to suit state needs to facilitate the lowest cost methodology for making required reductions. [EPA-HQ-OAR-2009-0491-2731.1, 2]
Finally, EPA's unreasonable 2012 date does not allow states time to develop their own SIPs to address interstate transport issues, despite EPA's pledge that states are free to do so. This issue is discussed more fully below. [EPA-HQ-OAR-2009-0491-2731.1, 2]
Response: 
States can submit SIP revisions for state allocation starting with 2013 allocations.  See preamble section X concerning provisions for SIP revisions.
See also Preamble section IV concerning EPA's authority and obligation to promulgate Transport Rule FIPs.
Organization: Gainesville Regional Utilities (GRU)
Comment: 
Gainesville Regional Utilities (GRU)
EPA's Proposed CATR Usurps the Traditional State Role in Designing State-Appropriate Compliance Plans and Uses an Inappropriate Baseline.
The proposed CATR establishes compliance timelines that make a FIP for the state of Florida unavoidable. Florida State officials indicate that they cannot meet the SIP deadline required by the rule. This appears to be the case with all states subject to the proposed CATR. EPA has imposed a federal allowance allocation methodology which in the case of CAIR was appropriately, and by Congressional design, left to the states to accommodate state-specific circumstances. GRU is concerned that once a state SIP is finally approved, the state will not be able to change the allocations to suit state needs to facilitate the lowest cost methodology for making the required reductions. [EPA-HQ-OAR-2009-0491-2674.1, p.4]
Response: 
States can submit SIP revisions for state allocation starting with 2013 allocations.  See preamble section X concerning provisions for SIP revisions.
Organization: GE Energy Financial Services (GE EFS)
Comment: 
GE Energy Financial Services (GE EFS)
As an Alternative to Resolving the Errors in IPM or Basing Unit Allocations on Historical Heat Input Data, EPA Could Instead Provide Adequate Time for States to Develop Adequate SIP Revisions Prior to Imposing the Proposed FIPs
In the Proposed Transport Rule, EPA is taking the unusual step of promulgating Federal Implementation Plans ('FIPs') that would become effective before EPA has made the requisite finding that a state had failed to submit an adequate State Implementation Plan ('SIP') or has otherwise taken any action to rescind its earlier approvals of states' CAIR SIP submittals. This would represent a significant departure from the Clean Air Act's clearly established process for addressing nonattainment of the National Ambient Air Quality Standards ('NAAQS'). If EPA does not correct the serious problems with IPM or establish unit-specific allocations based on historic heat input, it could, as an altogether different approach, refrain from promulgation of the proposed FIPs, and instead support states' efforts to submit adequate SIP revisions within a reasonable amount of time. While this might delay implementation of the CAIR's replacement program until after 2012, it would follow the process that EPA and the states have successfully implemented for four decades to address nonattainment of the NAAQS under the Clean Air Act. Moreover, given that the CAIR would remain in effect in the interim and EPA has recognized that most reductions in the 2012-2014 control periods will be achieved through implementation of emissions reductions that are already being achieved or planned for implementation, such a delay would not postpone or interfere with attainment of the NAAQS. Further, any such delay would provide EPA and the states with the opportunity to establish an adequate replacement program for the CAIR that also addressed anticipated revisions of the NAAQS, avoiding an unnecessary and duplicative series of rulemakings and SIP revisions. [EPA-HQ-OAR-2009-0491-2701.1,p .4]
Response: 
See preamble Sections IV for a discussion regarding FIP authority.  See preamble section VII for the final allocation approach.
Organization: Georgia Department of Natural Resources, Air Protection Branch
Comment: 
Georgia Department of Natural Resources, Air Protection Branch
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.95.]
On October 9th, 2007, EPA published in the Federal Register the approval of Georgia's CAIR SIP. This approval preceded the December 2008 remand of CAIR by the DC Circuit Court. CAIR was remanded to ensure that the environmental benefits achieved by that rule remain in effect. Therefore, Georgia EPD strongly disagrees with EPA's conclusion that the Court's decision means EPA's approval of our SIP no longer satisfies the section 110a2di obligation and for that reason, EPA's 2005 findings that we failed to submit such a SIP remains in force.
In lieu of the FIP, EPA should retain the CAIR SIP requirements which continue to achieve significant reductions until adequate time has been provided for Georgia to submit and for EPA to approve a revision.
Response: 
See preamble sections IV and X, responses to comments in section III.A. of this document and the TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) SIPs Final Rule TSD."
Organization: Golden Spread Electric Cooperative
Comment: 
Golden Spread Electric Cooperative
Most of the major problems with this proposal, or action, begin with EPA eliminating requirements under CAIR and "proposing FIPs to immediately implement the emission reduction requirements identified and quantified by EPA in this action." The unreasonable and unnecessary proposed compliance deadlines in the proposed CATR present further complications for EPA as the agency attempts to circumnavigate its responsibilities under the Clean Air Act (CAA) Section 110 that clearly requires states be given opportunities to implement Section 110 obligations through the SIP process. EPA has not explained why it has chosen to accelerate this proposed CAIR replacement or why it finds it necessary to do so based on the courts' decisions in North Carolina v. EPA, 513 F.3d 896, (DC Cir 2008). GSEC recommends that CAIR remain in effect until each state has been given the opportunity to meet the requirements set forth in the CAA Section 110 (a) based on the timetable(s) set forth in Section 110(a)(1).  [EPA-HQ-OAR-2009-0491-2808.1 p.4] [[This comment can also be found in Section III.A.]]
Response: 
See preamble Section IV and responses to comments primarily in section III.A. of this document.
Organization: Griffin Pipe Products, Inc.
Comment: 
Griffin Pipe Products, Inc.
The EPA should delay the Transport Rule until it sees the latest modeling based on CAIR compliance. At the least, the EPA should extend the compliance deadline to allow companies time to install the needed retrofits and to allow states to develop their own implementation plans. [EPA-HQ-OAR-2009-0491-2600, p.1] [[These comments can also be found in Section V.C.]]
Response: 
See sections IV, V, VI, VII, and X of the preamble.
Organization: Holland Board of Public Works
Comment: 
Holland Board of Public Works
This deadline also does not allow our state to develop a State Implementation Plan (SIP) that could be crafted to take in mitigating factors for small municipalities that the EPA's modeling program cannot. [EPA-HQ-OAR-2009-0491-2861.1,p.1] [[This comment is also in Section III.A.]]
Response: 
See preamble Section X.
Organization: Hoosier Rural Electric Cooperative
Comment: 
Hoosier Rural Electric Cooperative
The timeframe allotted to construct scrubbers and selective catalytic reduction systems is not reasonable since companies will be relying on state specific caps versus regional emissions trading that were included in CAIR. It is unclear how EPA determined that each state will be able to comply with the timeframes included in CATR.  [EPA-HQ-OAR-2009-0491-2724.1 p.1] [EPA-HQ-OAR-2009-0491-3758.1_NODA, p.2]
Response: 
See preamble Sections VI and VII.
Organization: Indiana Cast Metals Association (INCMA)
Indiana Builders Association 
Comment: 
Indiana Builders Association 
There is not enough time to develop a state implementation plan, forcing Indiana to rely on the federal implementation plan. This is counter to the spirit of the Clean Air Act and an unneeded and hasty short-circuit of an established regulatory process. [EPA-HQ-OAR-2009-0491-2871.1,p.1] [[These comments are also in Section III.A.]]
Whether intentional or not, you must understand that the proposed Rule's deadlines virtually preclude the development of a state implementation plan. To formulate, post for comment, revise and finalize a credible implementation plan requires at least 12 months. The schedule EPA has proposed effectively federalizes an historical state responsibility. This short-circuits a long-standing compliance process for what appears to be little environmental benefit. The EPA should provide adequate time for affected states to create an implementation plan, post it for comment, review, and issue as final. Adequate time must then be given for power plant operators to develop plans to comply with the state rules and then implement those plans. [EPA-HQ-OAR-2009-0491-2871.1,p.2] [[These comments are also in Section III.A.]]
Indiana Cast Metals Association (INCMA)
Whether intentional or not, you must understand that the proposed Rule's deadlines virtually preclude the development of a state implementation plan. To formulate, post for comment, revise and finalize a credible implementation plan requires at least 12 months. The schedule EPA has proposed effectively federalizes an historical state responsibility. This short-circuits a long-standing compliance process for what appears to be little environmental benefit. The EPA should provide adequate time for affected states to create an implementation plan, post it for comment, review, and issue as final. Adequate time must then be given for power plant operators to develop plans to comply with the state rules and then implement those plans. [EPA-HQ-OAR-2009-0491-2178.1, p.1]
Response: 
See preamble sections IV and X.  See also responses to comments in section III.A. of this document.
Organization: Indiana Department of Environmental Management 
Comment: 
Indiana Department of Environmental Management 
The process of imposing a Federal Implementation Plan (FIP) will allow expedient emission reductions to meet the 1997 air quality standards; however, many states, including Indiana, would prefer to develop their own State Implementation Plan (SIP) to better fit the rule into specific state needs. The proposed Clean Air Transport Rule provides for this, but since there is insufficient time for many states to develop a SIP before the proposed 2012 implementation date, the budgets will already be established for the first five years through a FIP: If a state wishes to realign allowances within the budget through a SIP at a later date, how can this be accomplished when allowances under the FIP have already been made? What criteria do states need to meet that will allow sources to participate in the interstate trading program? How is new budget information integrated into U.S. EPA's accounting system? Should initial allocations be for a shorter time period? U.S. EPA needs to provide guidance to states on how these issues can actually be accomplished and on other under defined implementation details. [EPA-HQ-OAR-2009-0491-2645.1, p.2]
Response: 
See preamble Section X.
Organization: Indiana Manufacturers Association, Inc. (IMA)
Comment: 
Indiana Manufacturers Association, Inc. (IMA)
The proposed Rule's deadlines virtually preclude the development of a state implementation plan. To formulate, post for comment, revise and finalize a credible implementation plan requires at least 12 months. The schedule EPA has proposed effectively federalizes an historical state responsibility. This short-circuits a long-standing compliance process for what appears to be little environmental benefit. The EPA should provide adequate time for affected states to create an implementation plan, post it for comment, review, and issue as final. Adequate time must then be given for power plant operators to develop plans to comply with the state rules and then implement those plans. [EPA-HQ-OAR-2009-0491-1813.1, p. 1]
Response: 
See preamble Section X.
Organization: Indiana Municipal Power Agency
Comment: 
Indiana Municipal Power Agency
There is not enough time to develop a state implementation plan, possibly forcing Indiana to rely on the federal implementation plan. This is counter to the spirit of the Clean Air Act and an unneeded and hasty short-circuit of an established regulatory process. [EPA-HQ-OAR-2009-0491-3057.1,p.1]
Whether intentional or not, you must understand that the proposed Rule's deadlines virtually preclude the development of a state implementation plan. To formulate, post for comment, revise and finalize a credible implementation plan requires at least 12 months. The schedule EPA has proposed effectively federalizes an historical state responsibility. This short-circuits a long-standing compliance process for what appears to be little environmental benefit. The EPA should provide adequate time for affected states to create an implementation plan, post it for comment, review, and issue as final. Adequate time must then be given for power plant operators to develop plans to comply with the state rules and then implement those plans. [EPA-HQ-OAR-2009-0491-3057.1, p.2]
Response: 
See preamble Sections IV and X.
Organization: Indiana Utility Shareholders Association
Comment: 
Indiana Utility Shareholders Association
Whether intentional or not, you must understand that the proposed Rule's deadlines virtually preclude the development of a state implementation plan. To formulate, post for comment, revise and finalize a credible implementation plan requires at least 12 months. The schedule EPA has proposed effectively federalizes an historical state responsibility. This short-circuits a long-standing compliance process for what appears to be little environmental benefit. The EPA should provide adequate time for affected states to create an implementation plan, post it for comment, review, and issue as final. Adequate time must then be given for power plant operators to develop plans to comply with the state rules and then implement those plans. [EPA-HQ-OAR-2009-0491-3845 p.2] [[These comments can also be found in Section III.A.]]
Response: 
See preamble sections IV and X.  See also responses to comments in section III.A. of this document.
Organization: International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers and Helpers (AFL-CIO Boilermakers Union)
Comment: 
International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers and Helpers (AFL-CIO Boilermakers Union)
Second, the proposed 2012 deadline runs contrary to the 'cooperative federalism' policy of the CAA by depriving states of the opportunity to first come into compliance with Section 110 by amending their SIPs. [EPA-HQ-OAR-2009-0491-2672.1, pp.3-4] [[This comment can also be found in Section III.A.]]
As noted above, EPA's 2015 deadline for CAIR was rejected in North Carolina because it was established without any regard for CAA attainment deadlines (or other substantive requirements of Title I of the CAA). If EPA allowed EGUs to prepare for compliance and state permitting authorities the opportunity to revise and submit compliant SIPs (as is Congress' clear preference) the Transport Rule could still achieve 'something measurable" towards assisting downwind states in meeting the earlier attainment deadlines, and would probably have no impact on the achievement of the later attainment deadlines. Our recommended deferral period is therefore consistent with North Carolina while striking an appropriate balance between the attainment deadlines of the CAA, feasibility considerations, and the policy of cooperative federalism. [EPA-HQ-OAR-2009-0491-2672.1, p.10] [[These comments can also be found in Section V.C.]]
Accordingly, the states should not be considered bound by the original three-year deadline provided for meeting the interstate transport requirements of the 1997 PM2.5 and Ozone NAAQS, and the 2006 PM2.5 NAAQS. Instead, EPA should provide a reasonable period from the publication of the final Transport Rule for revision of SIPs to address interstate transport issues. [EPA-HQ-OAR-2009-0491-2672.1, p.10] [[These comments can also be found in Section III.A.]]
Response: 
See preamble sections IV, VII, and X.
Organization: Kentucky Chamber of Commerce
Comment: 
Kentucky Chamber of Commerce
The deadlines in the Transport Rule provide no practical way for power companies to install any needed pollution control equipment or for the states to develop their own state implementation plans (SIPs). SIPs have always been a cornerstone for compliance and enforcement of the Clean Air Act.  [EPA-HQ-OAR-2009-0491-2760.1 p.2] [[These comments can also be found in Section V.C.2.]]
Response: 
See preamble Sections VI, VII, and X.
Organization: Large Public Power Council (LPPC)
Comment: 
Large Public Power Council (LPPC)
Second, the aggressive compliance deadlines overlook legitimate concerns over the ability of the power sector to implement the requisite pollution controls within the contemplated timeframe. [EPA-HQ-OAR-2009-0491-2667.1, p.3] [[This comment can also be found in Section V.C.2.]]
LPPC believes that EPA has discretion under the CAA, and under the D.C. Circuit's opinion in North Carolina, to defer implementation of the Transport Rule for at least one to two years. Such a deferral would provide states adequate time to prepare SIPs that address the significant contributions and interference with maintenance identified in the Transport Rule.[EPA-HQ-OAR-2009-0491-2667.1, p.3] [[This comment can also be found in Section III.A.]]
In addition, LPPC asks EPA to consider that the process of revising SIPs to include permitting authority for greenhouse gas emissions may cause a temporary lapse in state PSD permitting authority. 31  If such a lapse occurs, facilities that are required to obtain PSD permits for pollution control projects may not be able to obtain them by 2012. [EPA-HQ-OAR-2009-0491-2725.1, pp.8-9] [[The SIP comment can also be found in Section VIII.B.]]
Response: 
See preamble Sections IV, VI, VII and X.
Since GHG PSD permitting requirements became applicable on January 2, 2011, no source seeking a GHG PSD permit has encountered any delay resulting from the unavailability of an authorized permitting authority.  For states not under a FIP or a SIP that included GHG PSD permitting authority at appropriate thresholds, and that could not timely receive approval to SIP revisions providing this, EPA has undertaken a series of rulemakings to ensure that sources seeking PSD permits for GHG emissions would have a permitting authority from which to seek such permits.
To date, nearly all states are under either a SIP providing the state with GHG PSD permitting authority, or a FIP that provides EPA - or the state as EPA's delegatee - with GHG PSD permitting authority.  The remaining two permitting districts - Clark County, Nevada and Sacramento, California - have both submitted SIP revisions that include GHG PSD permitting authority that are currently under consideration by EPA.  No sources in these areas have sought a GHG PSD permit, and EPA expects it will approve these SIP revisions before any source in either area must obtain a PSD permit for its GHG emissions.
Organization: Louisiana Energy and Power Authority (LEPA)
Comment: 
Louisiana Energy and Power Authority (LEPA)
LEPA strenuously objects to the January 2012 compliance deadline in the proposed rule. That deadline does not provide sufficient time to permit Louisiana to develop SIPs that would more appropriately consider and account for transmission constraints and reliability concerns in LEPA's service territory. [EPA-HQ-OAR-2009-0491-2700.1, p.3] [[This comment can also be found in Section V.D.2.g.]]
Response: 
See preamble Section X.
Organization: Maryland Department of Environment (MDE)
Comment: 
Maryland Department of Environment (MDE)
It is critical that EPA requires remaining contributing areas to commit to the final remedy in their SIP, before their SIP can be approved. [EPA-HQ-OAR-2009-0491-2639.2, p.3]  
One option would be to have EPA require, through a SIP Call, the additional reduction requirement for each remaining contributing area using modeling and monitoring data in a manner similar to that used to establish VOC shortfalls for many OTC states in the 90s. EPA might also allow remaining contributing areas to participate in a state-led planning process to develop the final remedy as recommended in the September 2, 2009 State Collaborative letter. [EPA-HQ-OAR-2009-0491-2639.2, p.3]  
Another option that EPA could consider is a hybrid of the shortfall and state-led planning options. EPA could use available modeling and monitoring data to establish additional transport reduction requirements for all remaining contributing areas. In this hybrid approach, these reduction requirements would represent a presumptive, environmentally conservative (errs on the side of achieving more reductions than may actually be needed) state reduction, that if committed to in the SIP, would allow that state to satisfy the requirements of Section 110. If the remaining nonattainment area and the remaining contributing areas work together in a state-led planning process that results in different reductions from contributing areas, then this could be used in lieu of the presumptive reduction requirement established by EPA to satisfy Section 110. [EPA-HQ-OAR-2009-0491-2639.2, pp.3-4]
Response: 
See preamble Section III.
Organization: Mass Comment Campaign (245) (American Electric Power)
Pendleton, Mark
Jessee, Robert
Comment: 
Jessee, Robert
There also is no time for states to develop their own implementation plans, submit them for comment and then finalize them. States should have the ability to develop their own implementation plans for this rule, just as they have for other rules enacted as part of the Clean Air Act. [EPA-HQ-OAR-2009-0491-3288, p.1]
Mass Comment Campaign (245) (American Electric Power)
There also is no time for states to develop their own implementation plans, submit them for comment and then finalize them. States should have the ability to develop their own implementation plans for this rule, just as they have for other rules enacted as part of the Clean Air Act.
Pendleton, Mark
There also is no time for states to develop their own implementation plans, submit them for comment and then finalize them. States should have the ability to develop their own implementation plans for this rule, just as they have for other rules enacted as part of the Clean Air Act. [EPA-HQ-OAR-2009-0491-1596, p.1]
Response: 
See Section X of the preamble.
Organization: Massachusetts Department of Environmental Protection
Comment: 
Massachusetts Department of Environmental Protection
EP A has proposed to implement the proposed Transport Rule remedy for addressing transported pollution from EGUs through a Federal Implementation Plan (FIP) that will take effect on January 1, 2012. We appreciate EPA's acknowledgement of the need to insure reductions by 2012 and EPA's rationale that a FIP provides the quickest means of doing so. However, we are concerned about the loss of state's ability to tailor the trading program to meet state policy goals under a FIP, rather than a State Implementation Plan (SIP). Under the proposed FIP, states are not prohibited from adopting a SIP to meet the proposed state NOx and S02 budgets. However, given an anticipated final Transport Rule promulgation date of mid-2011 and a proposed January 2012 FIP implementation date, states will not have time to adopt a SIP prior to the FIP implementation. 
Under CAIR, states had the time to submit a SIP before the CAIR FIP took effect and were given flexibility with respect to allocation methods and inclusion of additional units. Massachusetts took advantage of the flexibility provisions and tailored its CAIR regulation to address important state policy issues, including output-based allocations and inclusion of smaller EGUs and large non-EGU boilers not covered by EPA's CAIR EGU definition. It is unfortunate that the Transport Rule timeframe precludes adoption of a SIP that incorporates these important state policy goals prior to the FIP taking effect. We urge EPA to include in the final FIP a provision that gives states the flexibility to retain output-based allocation methods adopted in state CAIR programs and to include additional units that states may have included in their CAIR regulation. In promulgating a FIP under section 11 O( c) of the Clean Air Act, EPA has the same authority a state would have in promulgating a SIP. EPA should examine whether it can issue a final FIP that grants states the flexibility to address these provisions within the FIP itself, which would provide flexibility to states without requiring us to adopt a SIP. Alternatively, we encourage EP A to specify in the final Transport Rule those program options where states have flexibility to revise the FIP through a subsequent SIP submittal.
 [EPA-HQ-OAR-2009-0491-2787.2 p.2-3]
Response: 
See preamble Section X for a description of the provisions for state SIP options to replace FIPs.
Organization: Metropolitan Washington Air Quality Committee
Comment: 
Metropolitan Washington Air Quality Committee
  While we find that EPA's approach of initially implementing this program through a Federal Implementation Plan (FIP) removes our ability for a traditional state notice and comment process, we understand that this approach may be necessary to ensure reductions occur in a timely manner for NAAQS attainment. We support EPA's proposal to allow states to replace the FIPs with SIPs if they so desire. [EPA-HQ-OAR-2009-0491-2618.1, pp.1-2]
Response: 
See preamble Section X.
Organization: Michigan Department of Natural Resources and Environment
Michigan Manufacturers Association (MMA)
Comment: 
Michigan Department of Natural Resources and Environment
In the proposed TR, the Federal Implementation Plan (FIP) would go into effect immediately after the TR has been finalized and remain in effect for each individual state until a replacement State Implementation Plan (SIP) has been approved by the EPA. According to the preamble, states would not be able to allocate allowances until a SIP has been approved. [EPA-HQ-OAR-2009-0491-2774.1 p.3]
The DNRE requests the implementation of the FIP be delayed until states can finalize an approvable SIP to effectively replace the FIP requirements. Due to the timelines for rulemaking in Michigan, the DNRE believes that the FIP may be in effect for Michigan for a minimum of one and one-half years until such time as our SIP has been promulgated and approved by the EPA. The DNRE has concerns that allowances under the FIP will not match the allowances under a SIP and could create confusion for the sources within the state, especially if the FIP (as proposed) will allocate in a three-year time block for the first allocation time period. [EPA-HQ-OAR-2009-0491-2774.1 p.3]
Michigan Manufacturers Association (MMA)
- EPA is proposing to implement the rule on a schedule that would have the EPA implement a federal implementation plan, first, to be followed by a state implementation plan that would then have to be approved by EPA. The implementation schedule simply does not allow enough time to develop a state implementation plan on the front end. This is counter to the spirit and the letter of the Clean Air Act and an unneeded and hasty short-circuit of an established regulatory process and partnership between the states and EPA. [EPA-HQ-OAR-2009-0491-2762.1, p.1]
Response: 
See preamble Section X.
Organization: Michigan Municipal Electric Association (MMEA)
Comment: 
Michigan Municipal Electric Association (MMEA)
5.) EPA's Rush to FIP Denies States the Ability to Establish Compliant SIPs
The Clean Air Act and the NOx and SO2 market-based trading programs, are based on a system of cooperative federalism in which EPA sets standards, emissions budgets, parameters and rules and States have the opportunity to implement compliance approaches and unit-specific allowance allocations. But the Transport rule sets the January 1, 2012 compliance deadline so close to the expected early-2011 time for finalization of the rule that it will be impossible for States to develop and receive EPA approval for State Implementation Plans. Recently, the officials responsible for air pollution control at the Michigan Department of Natural Resources and Environment conveyed to MMEA that the deadline for compliance did not allow the State to develop a SIP fast enough. Likewise, officials in the EPA Clean Air Markets Division acknowledged to MMEA and its members here that these municipal systems should start preparing to comply with a FIP in 2012 because of the unlikely prospect that Michigan will be able to implement or EPA to approve a SIP prior to the proposed compliance deadline for the Transport Rule. [EPA-HQ-OAR-2009-0491-2828.1, pp.10-11]
And, there is no solace whatsoever for the systems commenting here that receive no allocations or under-allocations for 2012 from the EPA's repeated statements in the proposed Transport Rule that the 2012 compliance requirements are only meant to keep the status quo of installed or planned controls in place (which implies that an EPA unit-specific allocation under a FIP should be fine)  -  because the Transport Rule could result in closure of several of these plants in 2012. [EPA-HQ-OAR-2009-0491-2828.1, p.11]
Given that the Michigan public power communities affected here have depended upon the State of Michigan's implementation of an EPA-approved SIP and the use of "hardship allowances" to comply with NOx SIP Call and CAIR requirements, the shift to an EPA FIP with unit specific allocations that ignores the State's approach will represent an abrupt and unworkable change that our communities will not be able to handle. [EPA-HQ-OAR-2009-0491-2828.1, p.11]
For these reasons, EPA should extend the compliance deadline by sufficient time to allow the State of Michigan and other states to develop and receive EPA approval for a State Implementation Plan that implements the final Transport Rule and avoids harmful, rapid EPA unit-specific allocations. Again, MMEA supports the APPA position that Transport Rule deadlines should come no earlier than 2015. [EPA-HQ-OAR-2009-0491-2828.1, p.11]
Response: 
See preamble section VII for the final allocation methodology, which changed considerably in response to extensive comment on this topic.  States have the option of developing state allocations starting in 2013, including establishing "hardship" set-asides.
See preamble sections VI and VII for information on the compliance deadlines.
Organization: National Mining Association (NMA)
Comment: 
National Mining Association (NMA)
EPA proposes to require compliance with phase one requirements under the proposed rule at the beginning of 2012, just six or so months after EPA anticipates completion of the rule. This is wholly unrealistic. States will not have had an opportunity to examine and understand the final rule and adopt State Implementation Plans (SIPs), and sources will not have had an adequate opportunity to plan for the new requirements. [EPA-HQ-OAR-2009-0491-2868.1, p.15] [[These comments can also be found in Section VII.]]
Response: 
See preamble Sections VI, VII, and X.
Organization: New Jersey Department of Environmental Protection (NJDEP)
Comment: 
New Jersey Department of Environmental Protection (NJDEP)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, p.156.]
There are many positive aspects of the proposed Transport Rule, such as using a Federal Implementation Plan, FIP, for implementing emissions reduction measures quickly
Response: 
The final Transport Rule is being implemented through FIPs in affected states.
Organization: New York State Department of Environmental Conservation
Comment: 
New York State Department of Environmental Conservation
Although states may develop and submit their own State Implementation Plans (SIPs) to deal with transport, the Transport Rule framework does not define a process that allows states to replace the FIP with a SIP in a timeframe that corresponds to the current CAA framework. This proposal fails to describe how SIPs should be developed and the criteria that must be met to show adequacy of the state SIP. Additionally, the process defined in the current proposal is not sufficient because it only addresses this moment in time, and not how the process will move forward. [EPA-HQ-OAR-2009-0491-2730.1, p.4]
Still, each of the options provided for in the proposal can, in fact, assure that the emissions reductions needed to eliminate SC/IM are realized. EPA should give states the option of choosing the program which works best when it proposes its SIP Call to replace the FIP. [EPA-HQ-OAR-2009-0491-2730.1, p.6]
Response: 
See preamble Section X.
Organization: Northeast States for Coordinated Air Use Management (NESCAUM)
Comment: 
Northeast States for Coordinated Air Use Management (NESCAUM)
If EPA finalizes this rule without fully addressing significant transport, then it must clearly indicate as such in order to place the rule, and its new framework, in appropriate context. In addition, it should include a provision that ties State Implementation Plan (SIP) approvals to the resolution of necessary additional emission reductions in upwind states, as specified by EPA, to comply with Clean Air Act section 110(a)(2)(D) requirements where the remedy in the federal transport rule proves insufficient to do so. [EPA-HQ-OAR-2009-0491-2694.1 p.2]
For this proposed rulemaking, EPA uses a Federal Implementation Plan (FIP) as the mechanism to compel states to achieve reductions to reduce significant transport. This approach is more expedient than a SIP call, and warranted in this particular situation in light of states already being on notice under the remanded CAIR that they are significant contributors to downwind nonattainment. EPA's transport framework should make use of all available tools, as appropriate to the situation, to address significant contribution. In cases where EPA is using a FIP, EPA must ensure appropriate flexibility is given to states to ensure that there is no backsliding.
In cases where EPA employs the SIP call process, it must be done in a timely manner, and be backed up with a FIP. When EPA sets or revises a NAAQS, it must concurrently evaluate significant transport, and propose a SIP call at the same time that it promulgates that new NAAQS. Therefore, when a new or revised NAAQS is promulgated, EPA should concurrently determine that a state's current SIP is inadequate in accordance with its significant transport evaluation. EPA should then develop a response that addresses the Clean Air Act requirements as expeditiously as possible. That process should include having a FIP in place for use in cases where states do not submit timely SIPs. EPA should adhere to the following schedule in order to garner timely reductions:
Year 0
o EPA promulgates a new or revised NAAQS o EPA proposes a Transport SIP call for the new or revised NAAQS
o EPA proposes a Transport FIP for the new or revised NAAQS
o EPA releases all modeling and technical information with the proposed Transport SIP call to help inform the process and to assist states in developing their Transport SIPs.
Year 1 o States recommend to EPA NAAQS designations (maximum one year after NAAQS) o EPA finalizes Transport SIP call rule and Transport FIP Year 2 o EPA finalizes NAAQS designations (maximum two years after NAAQS is promulgated) Year 3 o States submit to EPA final Transport SIPs (maximum three years after NAAQS is promulgated) o EPA finalizes transport FIPs for states that do not submit Transport SIPs. This is triggered in any state that fails to submit a complete its Transport SIP on time, and helps ensure that transport is dealt with in a timely manner. Year 5 o States submit attainment SIPs (maximum three years after designations) o Transport SIP/FIP controls are implemented (three years prior to attainment deadlines) Year 7 o Attainment deadline under Clean Air Act Part D, subpart 1 for non-ozone NAAQS Years 8+ o Attainment deadlines for ozone areas under Clean Air Act Part D, subpart 2  
Year 1
o States recommend to EPA NAAQS designations (maximum one year after NAAQS)
o EPA finalizes Transport SIP call rule and Transport FIP
Year 2
o EPA finalizes NAAQS designations (maximum two years after NAAQS is promulgated
Year 3
o States submit to EPA final Transport SIPs (maximum three years after NAAQS is promulgated)
o EPA finalizes transport FIPs for states that do not submit Transport SIPs. This is triggered in any state that fails to submit a complete its Transport SIP on time, and helps ensure that transport is dealt with in a timely manner.
Year 5
o States submit attainment SIPs (maximum three years after designations)
o Transport SIP/FIP controls are implemented (three years prior to attainment deadlines)
Year 7
o Attainment deadline under Clean Air Act Part D, subpart 1 for non-ozone NAAQS
Years 8+
o Attainment deadlines for ozone areas under Clean Air Act Part D, subpart 2 
Response: 
EPA appreciates the comments on suggested approaches for systematically addressing transport as an integral part of the NAAQS publication and implementation process.   We intend to work with states to address CAA transport requirements in a timely manner after any new or revised NAAQS are published.
Organization: Occidental Chemical Corporation (OCC)
Comment: 
Occidental Chemical Corporation (OCC)
We note that EPA has offered, as is consistent with the CAA, to allow states to prepare their own SIPs and control strategies designed to achieve the emissions reductions EPA believes is necessary. However, unlike the CAIR rulemaking, EPA has not provided states, as it did with CAIR, a reasonable time period in which to prepare a SIP before the Transport Rule takes effect on January 1, 2012. We recommend that EPA postpone the effective date of the Transport Rule by at least two years, in order to allow states time to prepare SIPs. [EPA-HQ-OAR-2009-0491-2754.1, pp. 2-3]
Response: 
See preamble sections IV and X.
Organization: Ohio Coal Association
Comment: 
Ohio Coal Association
:: EPA should not implement the Transport Rule via a Federal Implementation Plan (FIP) without providing affected states the opportunity to develop State Implementation Plans. EPA's current FIP action contradicts with the plain language mandates of the Clean Air Act. Similarly, EPA should allow states the opportunity to develop unit level allowance allocations rather than utilizing the flawed Integrated Planning Model. [EPA-HQ-OAR-2009-0491-2743.1, p.2]
Response: 
See preamble sections IV and X.
Organization: Ohio Manufacturers Association (OMA)
Comment: 
Ohio Manufacturers Association (OMA)
The short timeline proposed by EPA virtually guarantees that Ohio will have to use a federal, rather than a state, implementation plan. EPA has historically relied on states to develop implementation plans tailored to their own unique needs, and implementation of the Transport Rule should be no different. Subjecting Ohio, among the states most impacted by more stringent pollution regulations, to a federal implementation plan undercuts long-established regulatory protocol and unfairly harms the state. [EPA-HQ-OAR-2009-0491-2651.1, p. 1]
Response: 
See preamble Sections IV and X.
Organization: Old Dominion Electric Cooperative
Comment: 
Old Dominion Electric Cooperative
The unreasonable and unnecessary proposed compliance deadlines in the proposed Transport Rule present further complications for EPA as the agency attempts to circumnavigate its responsibilities under the CAA S 110 which clearly requires states be given opportunities to implement S 110 obligations through the SIP process. As ODEC previously stated, CAIR does not need to be eliminated by 2012. Nothing in the North Carolina decisions suggests otherwise. lf CAIR would remain in effect until a date after the proposed 2012 deadline, air quality in the proposed Transport Rule region (consisting of the 31 states and the District of Columbia) would continue to improve under its mandates. [EPA-HQ-OAR-2009-0491-2877.1 ,p.6]
The proposal itself recognizes that under S 110(a)(2) states have 3 years to submit SIPs to address interstate significant contribution to NAAQS nonattainment, Id. at 45,341. In EPA's view, state SIPs under CAIR do not meet state SIP S 110 requirements because CAIR was struck down by the court's decision in 2008, even though any state that submitted a SIP approvable under CAIR was doing exactly what EPA dictated for compliance with the law. In this type of circumstance where EPA itself fails in its obligation to fulfill its CAA responsibility, case law dictates the time period for states to submit SIPs should be extended. EPA has failed to address why it does not intend to restart the clock on time periods for SIP submissions with the Transport Rule finalization. [EPA-HQ-OAR-2009-0491-2877.1,p.6]
EPA recognizes that under the proposed Transport Rule timelines states have virtually no time to follow SIP procedures to submit an approvable SIP, but nonetheless contends states rights under the CAA are not legally infringed upon because a state could submit a SIP that would replace the Transport Rule FlP, ld. at 45,342. Clearly, an ex post facto SIP is not what the CAA contemplates, and EPA has cited no case law to support this view. S 110(k)(5) clearly requires states be given a reasonable time to submit SIP revisions. Certainly, the current proposed schedule would not be considered reasonable. To comply with the CAA, EPA must allow states a reasonable time to meet S 110(a)(2)(D)(i) mandates. Accordingly, the Transport Rule should be re-proposed to allow states the option through the SIP process to choose allowance allocations based on specific state emissions budgets necessary to meet state requirements to address interstate transport. [EPA-HQ-OAR-2009-0491-2877.1,p.6]
Response: 
See preamble Sections IV and X and response to other comments primarily in Section III of this document.
Organization: Ozone Transport Commission (OTC)
Comment: 
Ozone Transport Commission (OTC)
OTC also advises EPA to consider following the example set in the Clean Air Interstate Rule
(CAIR) that allowed a state to submit an abbreviated SIP, in tandem with a FIP that provided for many of
the required elements of the remedy. The idea here is to provide within the Federal framework those
elements of the program that are best designed commonly for all states, but allow states to have some
flexibility in the allocation of the allowance budgets to ensure that no backsliding from current controls
occurs and that reductions targeted at eliminating significant contribution and interference with
maintenance are optimized. We elaborate on this issue later in our comments in the section on state
budgets and allocations. [EPA-HQ-OAR-2009-0491-2737.1, p. 7]
Further, OTC also believes that the proposed Transport Rule does not anticipate and address the
possibility that, for reasons of timing of controls or other circumstances, the federal remedy may not
accomplish the elimination of significant contribution and interference with maintenance by the
deadlines stipulated in the Clean Air Act. It is critical that the proposed Transport Rule include a provision
that ties SIP approvals to the resolution of the additional emission reductions in upwind states, as
specified by EPA, necessary to achieve compliance with Section 110(a)(2)(D) requirements where the
remedy in the federal transport rule proves insufficient to do so. Again, more specific details on this
recommendation are outlined in the "remedy options" section of these comments. [EPA-HQ-OAR-2009-0491-2737.1, p. 7]
Response: 
See preamble Sections III and X.
Organization: PPG Industries, Inc.
Comment: 
PPG Industries, Inc.
PPG also needs additional time to meet with the Louisiana Department of Environmental Quality to explore the realistic ability of the state to substitute a SIP for the proposed FIP. Very little discussion is provided in the Preamble to the proposed Transport Rule/FIP to provide guidance on the ability and timing for states to submit SIPs in lieu of the FIP. PPG needs to understand the realistic time and resource constraints of the state in order to develop comments on this issue. [EPA-HQ-OAR-2009-0491-1926.1, p.2]
PPG also requests that EPA allow Louisiana reasonable opportunity, consisting of a full 18 months following a final rulemaking in this docket, within which to submit a SIP in lieu of the proposed FIP. [EPA-HQ-OAR-2009-0491-2763.1, p. 19]
Response: 
See preamble sections IV and X.
Organization: Progress Energy Service Company
Comment: 
Progress Energy Service Company
A later initial compliance date also would allow sufficient time for states to develop State Implementation Plans (SIPs) for implementation of the Transport Rule and therefore avoid the need for EPA to promulgate the rule as a Federal Implementation Program (FIP). The opportunity to replace federal requirements with a state plan at some point in the future does not satisfy the requirement that EPA allow the opportunity for states to craft their own plans, at the outset of the program, to comply with the Transport Rule. EPA's proposal would effectively bypass the states, at least with respect to the first phase of the program. The following section elaborates further on the SIP/FIP process as set forth by Congress. [EPA-HQ-OAR-2009-0491-2831.1 p.3-4] [[These comments can also be found in Section III.A.]]
Response: 
See response in Section III.A of this document.
Organization: Public Utilities Commission of Ohio
Comment: 
Public Utilities Commission of Ohio
The proposed rule allows no time for companies or the states to develop implementation plans. Further, other regulatory steps, such as public utility commission approvals and environmental permitting, unfortunately seem to have been brushed aside in the development of the timetable for implementation of the rule. We urge EPA to take these routine, yet sometimes time-consuming matters into account when revisiting the implementation timeframe. [EPA-HQ-OAR-2009-0491-2855.1 p.14] [[These comments can also be found in Section V.C.2.]]
In conclusion, we urge U.S. EPA to delay implementation of the Transport Rule, and to consider the changes we have recommended above. If EPA chooses to implement the rule as it currently exists, the PUCO strongly recommends implementation of the EPA preferred plan. EPA should, however, extend the rule compliance schedule to allow Ohio, as well as other states, to develop well-considered implementation plans and give our power companies more time to make needed modifications. Extending the compliance schedule will also give our ratepayers more time to adjust, given the current and anticipated economic climate, and the expected job and financial consequences. [EPA-HQ-OAR-2009-0491-2855.1 p.17] [[These comments can also be found in Section X.]]
Response: 
See responses in Sections V.C.2. and X of this document.
Organization: Santee Cooper
Comment: 
Santee Cooper
An extension of the compliance deadline also would provide additional benefits of coordination among the rulemakings facing the power sector. States would have a chance to tailor their SIPs not only to the Transport Rule, but also to the utility MACT and the expected revisions to the ozone and fine particulate matter NAAQS. In addition, states could develop more efficient, tailored policies than the one-size-fits-all approach of the FIP. [EPA-HQ-OAR-2009-0491-2820.1, pp.16-17] [[These comments can also be found in Section XIX.]]
Response: 
See response in Section V.C.2. of this document.
Organization: South Carolina Department of Health and Environmental Control 
Comment: 
South Carolina Department of Health and Environmental Control 
Second, regarding Transport Rule SIPs, DHEC further notes that the EPA is also unclear in its discussion of Transport Rule SIPs, spending less than one half of one page out of a 256 page notice on the topic. DHEC requests more explanation of what these SIPs would be required to include. The EPA offers the following guidance in the proposal: "... [T]he state's SIP must provide adequate provisions to prohibit NOX and SO2 emissions that contribute significantly to nonattainment or interfere with maintenance in another state or states."35 The EPA further notes: "EPA is taking comment on all aspects of how a state could replace the Transport Rule FIP with a SIP and on what the SIP approval criteria should be."36 While DHEC appreciates the EPA's open-minded approach, we recognize that the EPA has significantly more resources than states to devote to the topic of what criteria the EPA plans to use in evaluating SIP submissions, and we recommend that the EPA elaborate on what it expects in Transport Rule SIPs in the final Transport Rule. [EPA-HQ-OAR-2009-0491-2677.1 p.16]
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.87-89.]
Our third comment is that South Carolina's concerned about the Federal Implementation Plan proposal and the lack of a specific state implementation plan or SIP guidance in the proposal. A FIP implies that a state has to meet its obligation and this is just not the case.
South Carolina would prefer the opportunity to implement the requirements through the SIP process. It is unclear why there is such urgency to replace our CAIR program in South Carolina with a less stringent Transport Rule only to have to update this rule to address the soon to be revised ozone and PM 2.5 NAAQS.
Further, there is little specificity in this proposal on how the states would develop an appropriate SIP to replace the transport FIP. As this information has not been included in the proposal, would a reproposal be required before a final rule? 
The EPA has delayed many decisions, including SIP approvals, giving the reason that it could not rely on emission controls installed to comply with remanded yet still in place CAIR. Including more explanation on this question in the final rule is necessary to provide clarity and consistency that the EPA would achieve by relying on the EPA regions to develop their own guidelines.
As a result and considering our earlier comments, South Carolina may wait until the 2011 Transport Rule to incorporate this rule into our SIP. We do not have the resources to continually update our SIP to address these uncoordinated federal actions, particularly where they backslide or don't bring additional air quality improvement. This is yet another example of where EPA could demonstrate its commitment to reforming the SIP process to focus limited resources on air quality improvement and not process for the sake of process.
Response: 
See Section X of the preamble.  The NODA entitled "Notice of Data Availability For Federal Implementation Plans To Reduce Interstate Transport of Fine Particulate Matter and Ozone: Request for Comment on Alternative Allocations, Calculation of Assurance Provisions Allowance Surrender Requirements, New-Unit Allocations in Indian Country and Allocations by States" published on January 7, 2011 (76 FR 1109) provided additional information and opportunity for comment on this issue.
Organization: Southern Company
Comment: 
Southern Company
The proposed compliance schedule is problematic since most states, if not all, will not have time to develop a SIP alternative to replace the FIP proposed by this rule; utilities will be faced with the extremely difficult task of developing and implementing several entirely new allowance strategies from unknown new allowance markets; implementation of fuel switching or the installation of new emission controls will be difficult if not impossible; and the compliance dates are uncoordinated with expected EPA regulations and are disruptive to compliance planning. [EPA-HQ-OAR-2009-0491-2864.1, p. 6] [[The SIP comment can also be found in Section V.C.2.]]
The January 1, 2012 compliance date is only a mere 6 months after the anticipated issuance of the final Transport Rule. Most states, if not all, will not have time to develop a SIP to replace the PIP proposed by this rule; utilities will be faced with the extremely difficult task of developing and implementing several entirely new allowance strategies in unknown new allowance markets [EPA-HQ-OAR-2009-0491-2864.1, pp. 8-9] [[These comments can also be found in Section V.C.]]; and even implementing fuel switching or installing low NOx burners at a facility will be virtually impossible. Furthermore, coal procurement strategies, fuel inventory levels, and the system dispatch procedures, which are carefully planned over the long term, may be negatively impacted and may not be able to be adjusted in such a short time frame. [EPA-HQ-OAR-2009-0491-2864.1, pp. 8-9] [[These comments can also be found in Section V.C.2.]]
A later compliance date (no earlier than 2015) will allow states to exercise their right to develop their own SIP, something many states, including Alabama, Mississippi, and Georgia have expressed a desire to do. [EPA-HQ-OAR-2009-0491-2864.1, p. 9][[This comment can also be found in Section V.C.2.]]
Response: 
See response in Section V.C.2. of this document.  See also preamble Section X.
Organization: Southern Environmental Law Center
Comment: 
Southern Environmental Law Center
SELC acknowledges that EPA's foremost concern is to expedite implementation of the Transport Rule and relieve states and localities of significant workload by means of proposing a Federal Implementation Plan ('FIP') in lieu of issuing a notice for State Implementation Plans ('SIPs') through the SIP Call process. As noted in the Transport Rule, under a FIP the EPA allocates emission allowances directly to individual sources. This may limit the possibilities for incorporating energy efficiency in the final Transport Rule. For that reason, we urge EPA to help states transition from the federal plan. EPA should provide a model rule and guidance to states to facilitate this process. The proposed Transport Rule does not provide enough guidance to states that seek to prepare a SIP that incorporates energy efficiency incentives to reduce regulated emissions from power plants. [EPA-HQ-OAR-2009-0491-2801.1, p.3]
SELC strongly urges EPA to provide timely and detailed guidance to states so they can opt to submit a SIP incorporating energy efficiency approaches that are consistent with Transport Rule. Taking advantage of the flexibility under the SIP provisions, states may use their own procedures, rather than EPA's, to allocate emissions allowances to in-state sources. Such allocation procedures could recognize energy efficiency as a means to reducing regulated pollutant emissions by including set-asides for energy efficiency and renewable energy ('EERE') measures. EPA should clearly communicate to states what EPA would accept as allowance distribution approaches or mechanisms, and should identify criteria that state SIPs would have to meet to allow applicable emission sources in a state to participate in the interstate emissions trading program. We urge EPA to provide adequate guidance to facilitate the expeditious approval of state SIPs that incorporate FIP components, but only differ in terms of allowance allocation mechanisms. [EPA-HQ-OAR-2009-0491-2801.1, p.3]
Targeted EPA guidance is critical. SELC understands that those states that incorporated EERE set-asides under the Clean Air Interstate Rule required significant technical assistance from EPA, the Department of Energy, and outside consultants and struggled to determine EPA-acceptable SIP parameters, including the need to ensure that credit is only given for new efficiency reductions, rather than those that would have occurred anyway; enforceability concerns; evaluation, measurement and verification ('EM&V) ) issues, and the types of energy efficiency measures that could be eligible for set-asides. EPA's 2004 guidance document, 'Guidance on State Implementation Plan Credits for Emission Reductions from Electric-Sector Energy Efficiency and Renewable Energy Measures' was of limited utility to state and local air quality agencies seeking to incorporate EERE set-asides into their programs because it did not provide sufficient detail to help states make the necessary decisions in crafting their SIPS. [EPA-HQ-OAR-2009-0491-2801.1, pp.3-4]
EPA should not underestimate the role it can play in reducing emissions through increased energy efficiency. The necessary investments in cost-effective energy efficiency will not happen absent appropriate policies, and EPA's guidance to states regarding transport SIPs will provide a crucial foundation for implementing those policies. SELC urges the EPA to provide greater guidance and technical assistance to states, including model rules and advice on how to measure eligibility, EM&V, and other parameters that must be met for EPA acceptance of a SIP incorporating EERE set-asides or other energy efficiency provisions. [EPA-HQ-OAR-2009-0491-2801.1, p.4]
Response: 
EPA explains, in preamble section IV, a TSD entitled "Status of CAA 110(a)(2)(D)(i)(I) and in responses to other comments primarily in section III.A. of this document, the specific FIP authority for each state.
EPA will work with states to craft SIP revisions providing for state allocation of allowances.  The final rule contains criteria for SIP revisions which are discussed in preamble section X, including information on state allocation methodologies.
Organization: Southern IL Power Cooperative
Comment: 
Southern IL Power Cooperative
EPA's proposed FIP is contrary to the Clean Air Act (CAA) because it does not give states the opportunity to submit SIPs conforming to the proposed CATR's overall state reduction mandates. States have up to 3 years to submit SIPs to remedy interstate transport, in this case to meet proposed CATR reduction mandates. (Section 110(a)) This period should begin to run when EPA issues a final CATR, since CAIR, the original transport rule, has been determined to be invalid by the court. The clean air act does not allow EPA to determine source or unit obligations, only to determine statewide reduction levels. [EPA-HQ-OAR-2009-0491-2863.1 p.4]
Response: 
See Section IV of the preamble and responses to comments in Section III.A. of this document.
Organization: State of Louisiana, Department of Environmental Quality
Comment: 
State of Louisiana, Department of Environmental Quality
FEDERAL IMPLEMENTATION PLANS:
Comment: EPA should work closer with states to provide flexibility in rule implementation by promoting and supporting state specific emission reduction strategies. The rule as proposed does not provide states enough opportunity to address their unique air quality situations; therefore, EPA should revisit this area of the proposed rule and provide more flexibility to state and local programs. [EPA-HQ-OAR-2009-0491-2655.1, p.2]
During the time the Clean Air Interstate Rule (CAIR) was being implemented, EPA worked closely with states to arrive at the best possible rule garnering the most emission reductions. Federal Implementation Plans (FIPs) were implemented while states worked on State Implementation Plan (SIP) submittals containing rulemakings and distribution of allowances. LDEQ believes that EPA should once again work closely with the states to develop SIPs rather than resorting to the proposed FIP. This will allow states to distribute allocations to facilities within its jurisdiction as was done under CAIR. States can work more quickly and efficiently to develop these SIPs while working with the EPA regional offices. This model also allows states more flexibility when combining this control strategy with those used to regulate other criteria pollutants. [EPA-HQ-OAR-2009-0491-2655.1, p.2]
Response: 
See preamble Section X.
Organization: Tennessee Valley Authority (TVA)
Comment: 
Tennessee Valley Authority (TVA)
In the event that EPA promulgates a Transport Rule that requires the level of emission reductions set out in the proposal, the compliance date should be no earlier than 2016. As indicated in our other comments, utilities will need time at least until 2016 to install the controls necessary to achieve these reductions. Equally important, this additional time provides states the opportunity to develop SIPs and have them approved using the three-year deadline for CAA § 110(a)(2)(D)(i)(I) interstate transport SIP submissions. [EPA-HQ-OAR-2009-0491-2782.1, pp. 4-5] [[This comment can also be found in Section V.C.2.]]
Response: 
See response in Section III.A.
Organization: Texas Commission on Environmental Quality
Comment: 
Texas Commission on Environmental Quality
The TCEQ requests that prior to finalization of the criteria by which states may replace the proposed FIP with state implementation plans, the EPA provide notice of its proposed specific criteria and provide an opportunity for public comment. [EPA-HQ-OAR-2009-0491-2857.1, p.3]
Transitions from CAIR to Transport Rule
The EPA requests comment (75 FR 45342) on all aspects of how a state could replace the Transport Rule FIP with a state implementation plan (SIP) and on what the SIP approval criteria should be. While the TCEQ appreciates the opportunity to provide suggestions for SIP criteria, the TCEQ urges the EPA to allow public comment on the specific SIP criteria it plans to consider prior to finalization. In proposing to allow states to submit a SIP to replace Transport Rule FIPs, the EPA requests comment concerning how such a replacement should occur and on the specific SIP approval criteria the EPA should use. While the TCEQ is free to provide comment on its own preferred approach, it is impracticable to provide comment on the unknown preferred approaches of other commenters (or on the unidentified preferred approach of the EPA). If the EPA were to select SIP approval criteria from comments received during the proposed Transport Rule comment period and finalize such criteria with the finalization of the proposed Transport Rule, it would do so without adequate notice and without offering the opportunity to provide comment on the EPA's intended approach. The TCEQ agrees that this type of stakeholder input would be beneficial to the public, regulated entities, and for all states, and urges the EPA to allow for meaningful public participation in this manner. If the EPA intends to finalize criteria by which states may replace the Transport Rule FIP with SIPs along with finalization of the proposed Transport Rule, the TCEQ requests that the EPA propose specific criteria and provide notice and the opportunity for comment on said criteria. [EPA-HQ-OAR-2009-0491-2857.2, pp.15-16]
Response: 
See Section X of the preamble.  The NODA entitled "Notice of Data Availability For Federal Implementation Plans To Reduce Interstate Transport of Fine Particulate Matter and Ozone: Request for Comment on Alternative Allocations, Calculation of Assurance Provisions Allowance Surrender Requirements, New-Unit Allocations in Indian Country and Allocations by States" published on January 7, 2011 (76 FR 1109) provided additional information and opportunity for comment on this issue.
Organization: U.S. Congressman Pete Hoekstra
Comment: 
U.S. Congressman Pete Hoekstra
This deadline also does not allow our state to develop a State Implementation Plan (SIP) that could be crafted to take in mitigating factors for small municipalities that the EPA's modeling program cannot. [EPA-HQ-OAR-2009-0491-3662,p.2]
Response: 
See Section X for information on mechanisms for states to submit SIPs to replace the Transport Rule FIPs.
Organization: Utility Air Regulatory Group (UARG)
Comment: 
Utility Air Regulatory Group (UARG)
EPA should take the time necessary to correct the many errors in the proposed rule, as described in these comments, and allow adequate time for states to develop SIPs and for sources to make the adjustments necessary to comply with the rule, rather than rushing to implementation as it proposes to do. [EPA-HQ-OAR-2009-0491-2756.1, p.24] [[These comments can also be found in Section V.C.]]
In light of this, EPA should decide not to call for the steep additional emission reductions demanded by the PTR because, as discussed elsewhere in these comments, such additional reductions are not needed to reduce significant regional contributions to downwind nonattainment and interference with maintenance. In the alternative, EPA should extend the PTR's emission reduction deadlines by at least a two-year period beyond the proposed 2014 compliance date (plus an additional interval of time that reflects (i) any additional time that EPA takes to complete this rulemaking beyond mid-2011 and (ii) the reasonable period of time needed by states to implement emission budgets through SIP revisions after final promulgation of EPA's rule). The following subsections of this part of UARG's comments provide more detailed information on the unreasonableness of the emission reduction requirements that EPA has proposed.  [EPA-HQ-OAR-2009-0491-2756.1, pp.35-36] [[These comments can also be found in Section V.C. and XVIII.C.]]
Section V.A provides an overview of the many steps that power plant owners must follow in order to retrofit their power plants with control equipment like FGD and SCR units. A more detailed discussion of these steps is provided in a separate report, which is attached hereto as Attachment I, and is incorporated by reference herein: Cichanowicz, J.E., "Implementation Schedules for Selective Catalytic Reduction (SCR) and Flue Gas Desulfurization (FGD) Process Equipment" (Oct. 1, 2010) (hereinafter "Implementation Schedules Report"). The Implementation Schedules Report was prepared by J. Edward Cichanowicz, who has been involved in -- and has first-hand knowledge of the challenges that can be posed by -- the design, permitting, and construction of FGD and SCR retrofits at many power plants throughout the United States. Next, section V.B of these comments directly addresses the few examples and arguments that EPA has made in support of its highly abbreviated compliance deadlines. Then sections V.C and V.D of these comments provide a broad range of more current examples of FGD and SCR retrofits, respectively. These examples demonstrate the complexity and time-consuming nature of the retrofit installation processes at most sites. EPA's failure to understand this has led the Agency to systematically underestimate the length of time it now takes to retrofit FGD and SCR systems at power plants. [EPA-HQ-OAR-2009-0491-2756.1, pp.35-36] [[See Docket Number EPA-HQ-OAR-2009-0491-2756.1, pp.104-146 for Attachment I.]] [[These comments can also be found in Section XVIII.C.]]
Footnote 16: According to LADCO, a fundamental assumption for this state-by-state analysis was a July 2012 start date for the planning, engineering, and construction of any new NOx or SO2 controls, reflecting a January 2011 promulgation date for the final Transport Rule and another 18 months for adoption of SIPs. See id. at 1, attachment at 4. Thus, LADCO properly recognized that a substantial amount of time would be necessary after promulgation of EPA's final rule for states to develop SIPs and submit them to EPA for approval. [[These comments can also be found in Section XVIII.C.]]
Response: 
These comments are addressed in other sections of this document.  See Section V.C and XVIII.C of this document.
Organization: Virginia Independent Power Producers
Comment: 
Virginia Independent Power Producers
Establishment of State Implementation Plans (SIPs) is Preferable To Federal Implementation Plans (FIPs).
State environmental regulatory agencies, operating with delegated authority from USEPA. arc best prepared to implement the Transport Rule. [EPA-HQ-OAR-2009-0491-2640.1, p.4]
State regulators, by definition, are more closely attuned to the needs, desires and particular circumstances of citizens and the regulated community. Thus, they are in a better position to formulate and implement fine tunings and exceptions to a broader and more comprehensive regulatory scheme. This would include allocating emission allowances in accordance with a particular states goals and objectives to comply with EPA's state-specific control budgets. [EPA-HQ-OAR-2009-0491-2640.1, p.4]
Given that states, operating with delegated authority from USEPA, will be held accountable to comply with the federal rule, there is no risk to the public in providing opportunities for state implementation plans that accommodate particular or unusual local circumstances, and there is the potential for great benefit. [EPA-HQ-OAR-2009-0491-2640.1, p.4]
Response: 
See preamble Section X.
Organization: West Virginia Department of Environmental Protection
Comment: 
West Virginia Department of Environmental Protection
The proposed Transport Rule does not provide a mechanism for replacing the Transport Rule FIP with a SIP, and the action of EPA issuing a FIP with no SIP mechanism wrongly implies that states have intentionally failed to comply with Clean Air Act requirements. [EPA-HQ-OAR-2009-0491-2790.1, p. 3]
Response: 
See preamble Section X for information on the mechanism for replacing Transport Rule FIPs with SIPs.  See preamble Section IV and responses to other comments primarily in Section III of this document for information on EPA's action under the Transport Rule as it relates to CAA 110(a)(2)(D)(i)(I).
Organization: West Window Corp.
Comment: 
West Window Corp.
The deadline does not provide enough time for states to develop their own implementation plans to comply with the rule, which has previously been a cornerstone of EPA compliance. [EPA-HQ-OAR-2009-0491-2386, p.1] [[This comment can also be found in Section III.A.]]
Response: 
See preamble Section X for a discussion of SIP deadlines.

VIII. Permitting

Organization: Minnesota Power 
Comment: 
Minnesota Power 
State regulatory action time for permitting.  EPA needs to confirm that there is adequate time and resources in state regulator offices to turn around state implementation planning or adopt the EPA FIP in unit operating permits before the dates of required Transport Rule compliance.   [EPA-HQ-OAR-2009-0491-2750.1, p.10]
Response: 
See sections X (concerning SIPs) and VII.I (concerning permits) of the preamble.

VIII.A. Title V Permitting

Organization: Florida Department of Environmental Protection
Comment: 
Florida Department of Environmental Protection
  Finally, the Division is concerned about workload on both permitting and rule development staff. Several years ago, the Division opened-for-cause all Title V permits for sources subject to the Clean Air Interstate Rule (CAIR). Florida had close to 100 Title V permits that had to be opened for this purpose and this was a burden on already strained resources. I understand EPA's proposed Transport Rule to again require Title V revisions to include the Transport Rule's applicable requirements. As proposed, the Transport Rule would require approximately 76 Title V major modifications. The Division encourages EPA to use the same approach for the Transport Rule as it did for the Greenhouse Gas Reporting Rule; that is, do not make the Transport Rule a Title V applicable requirement that triggers the reopening-for-cause provisions of the Title V program. In the alternative, for sources currently subject to CAIR, EPA could allow states to include these Transport Rule requirements at the next Title V revision or renewal or via the 502(b)(10) notice-and-go provisions on the basis that the Transport Rule replaces CAIR and is not a new applicable requirement. [EPA-HQ-OAR-2009-0491-2624.1, pp.1-2]
Response: 
See section VII.I of the preamble.  CAA section 502(b)(10) is not applicable to the Transport Rule, which, while replacing CAIR, imposes different requirements than CAIR, such as different emission reduction requirements and state budgets and new assurance provision requirements. 
Organization: Texas Commission on Environmental Quality
Comment: 
Texas Commission on Environmental Quality
The TCEQ requests that the EPA, at a minimum, provide permitting guidance, with opportunity for public participation, regarding the transition from the Clean Air Interstate Rule (CAIR) to the Transport Rule, and ideally, provide proposed rule language for the permit transition. The EPA should also provide guidance for states whose participation in the Transport Rule program is fundamentally different from their participation in the CAIR program. [EPA-HQ-OAR-2009-0491-2857.1, p.3]
The EPA should, at a minimum, provide permitting guidance regarding transition from CAIR to the Transport Rule and ideally, provide proposed rule language for the permit transition. The proposed rule does not address transition of existing Title V permits from CAIR to CATR at all. EPA's failure to propose rule language regarding the permitting transition mechanism provides no opportunity for the public to participate in the implementation of this program. [EPA-HQ-OAR-2009-0491-2857.2, p.16]
Response: 
EPA rejects commenter's claims that the final rule does not include language addressing permitting with regard to the Transport Rule trading programs under the Transport Rule and that additional rule language is necessary in order to provide an opportunity for public comment on permitting.  The final rule explains that the existing, generally applicable title V permitting rules, which have already gone through notice and public comment, apply to the requirements of the Transport Rule trading programs.   See section VII.I of the preamble.  This approach was presented in the proposed Transport Rule, and EPA provided an opportunity for submission of public comment (including this commenter's comment).   

VIII.B. New Source Review (NSR)

Organization: Utility Air Regulatory Group (UARG)
American Electric Power
Tennessee Department of Environment and Conservation, Division of Air Pollution Control
National Rural Electric Cooperative Association (NRECA)
Edison Electric Institute (EEI)
North Carolina Department of Environment and Natural Resources
Council of Industrial Boiler Owners (CIBO)
State of Ohio Environmental Protection Agency (Ohio EPA)
Florida Electric Power Coordinating Group, Inc. (FCG)
San Miguel Electric Cooperative, Inc.
Dominion
RRI Energy, Inc.
Buckeye Power, Inc.
E.ON U.S.
Florida Municipal Electric Association (FMEA)
Progress Energy Service Company
Alcoa Power Generating Inc. - Warrick Power Plant
Big Rivers Electric Corporation
Associated Electric Cooperative, Inc. (AECI)
Old Dominion Electric Cooperative
Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
Ameren Services Company
American Coalition for Clean Coal Electricity (ACCCE)
Class of '85 Regulatory Group
Duke Energy
EquiPower Resources Corp.
International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers and Helpers (AFL-CIO Boilermakers Union)
Large Public Power Council (LPPC)
Tennessee Valley Authority (TVA)
Wolverine Power Supply Cooperative
Ohio Utility Group (OUG)
State of Louisiana, Department of Environmental Quality
Comment: 
Alcoa Power Generating Inc. - Warrick Power Plant
EPA asserts that collateral increases in NSR-regulated pollutants from the use of NOx and SO2 controls for CATR will not be high enough to trigger a NSR, citing for support its 'Technical Support Document for the Rule to Reduce Interstate Transport of Fine Particulate Matter and Ozone' (TSD). 75 FR 45344. In the memo and in the proposed Rule, EPA concludes that there will not be a significant enough increase in conventional air pollutants to trigger NSR permitting: 'New Source Review (NSR) requirements would not significantly impact the construction of controls that are installed to comply with the proposed transport rule.' 75 FR 45343. In these discussions, EPA has not described the associated emissions increase in sulfuric acid emissions that results after the installation of a SCR with sufficient catalyst layers to provide the NOx reductions that . would be required by the proposed rule. [EPA-HQ-OAR-2009-0491-3648,pp.3-4]
APGI found that, for Warrick 4, it was necessary to install a reagent injection system between its SCR and electrostatic, in order to avoid triggering NSR, due to a sulfuric acid emission increase equal to or in excess of 7 tons/yr. In its discussions of NOx control technology, EPA needs to include the anticipated concurrent impact of the addition of reagent injection, in order to avoid NSR for sulfuric acid. [EPA-HQ-OAR-2009-0491-3648,p.4]
Regarding NSR and GHG emissions, EPA similarly concludes that 'it is very unlikely that pollution control projects would cause GHG increases that would exceed the 75,000 tons per year threshold. Consistent with EPA's previous analysis and EPA's conclusions for GHG, EPA does not believe that there are significant impacts from NSR for any pollution control projects resulting from the proposed rule such as low-NOX burners; S02 scrubbers, or SCR.' 75 FR 45344. EPA provides no substantiation of these conclusions, other than an analysis in the TSD for CAIR, with respect to conventional pollutants only. In addition. EPA has not addressed the parasitic load that must be overcome, due to the installation of the required control equipment, and the accompanying increase in heat input and GHG emissions. EPA needs to address parasitic load increases, and otherwise substantiate these conclusions in the final rule. [EPA-HQ-OAR-2009-0491-3648,p.4]
Ameren Services Company
In December 2005 the D.C. Circuit vacated the pollution control project exclusion (PCP). Prior to 2005 projects that installed environmental control equipment did not trigger the new source review preconstruction permitting process because such projects were subject to PCP. Today each SCR, Low NOx Burner and FGD project must be evaluated for any increase in a regulated pollutant. This necessitates the use of individuals to develop permit applications and follow up with regulatory agencies that prior to this decision was not required. [EPA-HQ-OAR-2009-0491-2722.1, p.7]
EPA's analysis using IPM version 3.02 in the allocation of S02 allowances includes installation of FGDs at Joppa and Meredosia Boiler 5 by 2014 [EPA-HQ-OAR-2009-0491-2722.1, p.9]
American Coalition for Clean Coal Electricity (ACCCE)
EPA's 2002 analysis suggests that 17 months are necessary to obtain construction and operating permits for any new pollution control project. This schedule does not take into account the possibility - if not the likelihood - of delays resulting from Federal and state permitting requirements, including the federal New Source Review (NSR) permitting process. NSR was not a consideration in 2002 because of an exclusion for pollution control projects that has since been invalidated by a court decision. The NSR regulations require EGUs to notify permitting authorities prior to initiating pollution control projects and to demonstrate that NSR permits are not required. This means that EGUs will not be able to begin actual construction of the pollution control project until after the permitting authority has determined that NSR does not apply to that project. Further construction delays would result if the project triggers NSR because of a significant net increase in emissions. [EPA-HQ-OAR-2009-0491-2874.1 p.4]
American Electric Power
PSD Permitting
EPA concludes in the proposed rule that it is 'very unlikely' that pollution control projects would cause greenhouse gas (GHG) emission increases in excess of the PSD emission thresholds in the Agency's June 2010 GHG Tailoring Rule. AEP disagrees with this assessment. As an example, the use of limestone wet FGD systems will increase CO2 emissions through the plant stack as CO2 is liberated during the conversion of limestone to calcium sulfate or calcium sulfate. In addition, parasitic load requirements associated with the wet FGD operation (about 3% of output) will further increase GHG emissions levels per unit output. Without a pollution control exemption, a scrubber project could be deemed a non-routine physical or method of operation change for which a detailed emission increase and causation assessment could be necessary. Moreover, such scrubber projects could trigger PSD due to the likely increase in GHG emissions resulting from the scrubber conversion process and increased coal used to generate the extra electricity necessary to operate the scrubber, even assuming the unit operated at existing production levels. In addition, a higher unit dispatch associated with more favorable market economics after an FGD installation could be potentially used as another basis for evaluating the PSD implications of the proposed project. Even if an electric utility can document that the scrubber project has not resulted in a significant GHG emissions increase (which will likely not be a straightforward task), it may be necessary to notify the permitting authority of the proposed project and demonstrate to permitting authorities satisfaction that PSD will in fact not be triggered pursuant to the 'reasonability possibility' requirements of existing PSD regulations. Viewed in this context and given the nascent nature of this PSD process as applied to GHG emissions, the permitting timeline for new FGD installations could be greatly extended and subsequently push out the time period in which new controls can actually be installed. [EPA-HQ-OAR-2009-0491-2665.1, pp.17-18]
There are multiple ways EPA can craft an appropriate PSD/NSR exclusion for Transport Rule-driven emission control projects. EPA could provide a special definition of baseline actual emissions for such projects (such as the product of maximum actual hourly emission rates for any regulated pollutant multiplied by the maximum actual 12-month heat input for the electric generating unit in question) or a causation detennination tied specifically to the Transport Rule (that the Transport Rule rather than the measures undertaken to comply with it are the predominant and relevant cause, for NSR nonapplicability purposes, of any emission increases associated with such compliance measures). EPA also has discretion to interpret the term 'stationary source' in the definition of 'modification' in Section 110(a)(4) of the Clean Air Act that does not impede compliance with timeframes and targets in the Transport Rule. [EPA-HQ-OAR-2009-0491-2665.1, p.18]
Associated Electric Cooperative, Inc. (AECI)
The proposed rule presumes that installing pollution controls under the proposed CATR would not trigger New Source Review (NSR) concerns. The technical documentation EPA relies on to conclude NSR will not be triggered by pollution control projects (PCPs) is general in nature and doesn't address potential greenhouse gas emissions from the control devises or supporting functions. Of course, the NSR process is time consuming and any unit undergoing this process would not be able to meet the emissions control deadlines of which unit allocations are based under EPA's already compressed time schedules. [EPA-HQ-OAR-2009-0491-2845.1 p.10]
Request: Associated requests that EPA provide a "variance" for CATR PCPs that trigger NSR. To the extent the unit emissions exceed the unit's CATR allocation, the variance should provide relief for compliance with the allowance cap until the NSR review is completed and the unit is equipped with the necessary controls. [EPA-HQ-OAR-2009-0491-2845.1 p.10]
Big Rivers Electric Corporation
The proposed rule does not allow enough time to address permitting issues including Prevention of Significant Deterioration (PSD) and New Source Review (NSR) associated permit modifications to install or modify control equipment or to meet compliance. [EPA-HQ-OAR-2009-0491-2661.1, p.3]
The permitting process must first be completed.  The permitting process alone can easily take one full year to complete, depending on the effects on PSD or NSR. [EPA-HQ-OAR-2009-0491-2661.1, p.2]
Buckeye Power, Inc.
The issue of New Source Review (''NSR'') must also be addressed. NSR should not be triggered with respect to greenhouse gases in connection with a facility's actions to comply with CATR. The installation of NOx and SO2 emission control technologies will necessarily increase auxiliary power requirements thereby increasing greenhouse gas emission rates and potentially triggering NSR. It is unfair and unreasonable that a utility's actions to comply with CATR should result in triggering NSR with respect to other emissions. [EPA-HQ-OAR-2009-0491-2710.1, p.2]
It unfairly and unreasonably requires emissions of NOx and SO2 to be reduced substantially by 2014, only four years from now, and could possibly trigger New Source Review for greenhouse gasses as a result of actions required of utilities to comply with CATR. [EPA-HQ-OAR-2009-0491-2710.1, p.4]
7. Non-NSR trigger assumptions.
The proposed CATR presumes that the required installation of pollution controls would not trigger new source review ('NSR') but is taking comment on the issue particularly regarding greenhouse gases which, according to EPA regulations, will be subject to NSR beginning in 2011. P. 35344. The technical documentation EPA relies on to conclude that NSR is not triggered is general in nature and does not address the fact that required emission control equipment under CATR will have auxiliary power requirements thereby increasing greenhouse gas emission rates and potentially triggering NSR for greenhouse gasses as a result of mandated actions under CATR. It is unfair for NSR to be triggered as a result of actions required by EPA to meet CATR. [EPA-HQ-OAR-2009-0491-2710.1, p.12]
Furthermore, the NSR process is time consuming and any unit undergoing this process would not be able to meet the emissions control deadlines under CATR. Thus, in the event that NSR is triggered as a result of required actions under CATR, EPA should provide a 'variance' to the unit from its allowance obligations under CATR (to the extent that unit emissions exceed its allocated allowances) until the NSR review is completed and the unit is equipped with necessary controls and meets any other NSR obligations. [EPA-HQ-OAR-2009-0491-2710.1, p.12]
For all of the foregoing reasons, Buckeye Power urges EPA to withdraw its proposed CATR program. If it does proceed, EPA should (9) exempt utilities from NSR requirements for greenhouses gasses to the extent NSR for greenhouse gasses would otherwise be triggered by the installation of pollution control equipment required to comply with CATR. [EPA-HQ-OAR-2009-0491-2710.1, p.13]
Class of '85 Regulatory Group
Prior to undertaking a conversion from bituminous to sub-bituminous coal, a source would be required to consider whether any of the projects trigger nonattainment new source review ('NNSR'), prevention of significant deterioration ('PSD') or New Source Performance Standard ('NSPS') permitting requirements. 40 CFR § 52.21(b)(2)(iii)(e)(1) provides an exemption from the definition of physical change or change in the method of operation for use of an alternative fuel or raw material which the source was capable of accommodating before January 6, 1975, unless such change would be prohibited under any Federal enforceable permit conditions. EPA has stated that a unit is 'capable of accommodating' a fuel if 'the company [can] show not only that the design (i.e., constructive specifications) for the source contemplated the equipment, but also that the equipment actually was installed and still remains in existence.'  The Class of '85 believes that a unit designed to bum coal is 'capable of accommodating' any other type of coal despite any required physical changes to the plant.  However, OECA and certain state permitting agencies have taken the opposite position.  Additionally, OECA and various environmental groups recently have taken the position that descriptions of the types of coals used at an EOU that are contained in Title V, PSD or state permits (and any associated permit applications) constitute enforceable permit conditions. Under this interpretation of § 52.21 (b)(2)(iii)(e)(1), switching to a lower sulfur coal would not be exempt from NSR or PSD review if an EGU's permit or permit application includes a description of the higher sulfur coal currently burned at the unit. To avoid a potential citizen suit or enforcement action, EGUs that want to switch to a lower sulfur coal to comply with the Proposal may have to undertake an NNSR analysis and/or obtain a PSD permit prior to changing coals. These units would not be able to complete this process and make any necessary physical changes prior to the 2012 compliance deadline.21 [EPA-HQ-OAR-2009-0491-2854.1, pp.8-9]
EGUs are obligated to consider any NNSR or PSD obligations that may arise from the installation of a scrubber or SCR even though the controls are designed to reduce emissions of certain pollutants. For example, installation of an SCR to control NOx may cause an increase in sulfuric acid mist emissions that triggers permitting requirements? If a source determines that installation of a scrubber or SCR triggers NNSR or PSD requirements, it would have to obtain those permits before commencing construction. It is the experience of many Class of '85 members that it can take from six months to two years to obtain a final construction permit from a local permitting agency.23  [EPA-HQ-OAR-2009-0491-2854.1, p.10]

21. It is notable that sources that cannot switch to a lower sulfur coal by the 2012 deadline would need to purchase allowances as a compliance mechanism, further raising demand past the level anticipated by EPA in the Proposal. [EPA-HQ-OAR-2009-0491-2854.1, p.9]
23. The Group is concerned that initiation of permitting requirements for greenhouse gas emissions in 2011 will further tax limited state resources and substantially prolong the permitting process as best available control technology options ('BACT') for greenhouse gases are debated and possibly litigated. [EPA-HQ-OAR-2009-0491-2854.1,p.10]
Council of Industrial Boiler Owners (CIBO)
EPA asserts that collateral increases in NSR-regulated pollutants from the use of NOx and SO2 controls will not be high enough to trigger a NSR, citing for support its 'Technical Support Document for the Rule to Reduce Interstate Transport of Fine Particulate Matter and Ozone' (TSD). 75 FR 45344. In the memo and in the Proposed Rule, EPA concludes that there will not be a significant enough increase in conventional air pollutants to trigger NSR permitting: "New Source Review (NSR) requirements would not significantly impact the construction of controls that are installed to comply with the proposed transport rule." 75 FR 45343. Regarding NSR and GHG emissions, EPA similarly concludes that "it is very unlikely that pollution control projects would cause GHG increases that would exceed the 75,000 tons per year threshold. Consistent with EPA's previous analysis and EPA's conclusions for GHG, EPA does not believe that there are significant impacts from NSR for any pollution control projects resulting from the Proposed Rule such as low-NOx burners, SO2 scrubbers, or SCR." 75 FR 45344. EPA solicits comments on this issue.
CIBO is concerned that EPA has oversimplified their analysis of this issue. Most EGUs are already major for PSD and relatively small changes in conventional pollutants would trigger modification provisions under PSD since most units are not operated at full capacity on an annual basis, and because emission increases are based on past actual to future potential emissions since utilities must protect their ability to operate at constructed and permitted capacity levels. While we believe triggering PSD is more likely for conventional pollutants, it is possible that even with the higher GHG thresholds promulgated by EPA for underutilized units, PSD could be triggered for GHGs. . CIBO urges EPA to conduct a more thorough analysis than done in the TSD which considers the above factors to either substantiate their conclusions of limited impact in the final rule, or to more accurately assess the implications of permitting requirements related to this rule in order to provide greater certainty to regulated sources that must carry out projects to comply with this Proposed Rule.   [EPA-HQ-OAR-2009-0491-2751.1 p.10-11]
Dominion
EPA Needs to Justify its Assertion that it is 'Very Unlikely' that Pollution Control Projects Would Cause GHG Emission Increases in Excess of the PSD Emission Thresholds in the Agency's June 2010 GHG Tailoring Rule
EPA bases its conclusion that the proposed Transport Rule will not significantly affect new source review (NSR) permitting on an analysis it conducted following the D.C. Circuit's decision in New York v. EPA, 413 F.3d 3 (D.C. Cir. 2005), which vacated the pollution control project exclusion in EPA's NSR regulations. According to EPA, that analysis indicated that the court's decision would not affect the assumptions underlying EPA's determination that CAIR was cost-effective and feasible. EPA states simply that it believes that the same is true for the Proposed Transport Rule. Although EPA's CAIR analysis did not address GHGs because they were not regulated CAA pollutants at that time, EPA concludes in the Proposed Transport Rule on pages 45343-4 that it is `very unlikely' that pollution control projects would cause GHG emission increases in excess of the NSR emission thresholds in EPA's June 2010 GHG Tailoring Rule. EPA provides no justification for this assumption. EPA must, at a minimum, provide an analysis and explanation to support its assertion. [EPA-HQ-OAR-2009-0491-2715.1, p.16]
Duke Energy
Consider, for example, the increased complexity involved in getting a Clean Air Act new source review ("NSR") preconstruction permit to cover "increased emissions" from the installation of SCR and FGD systems. Such a permit may be needed because even though the operation of SCR and FGD units will significantly reduce emissions of NOx and SO2, respectively, the operation of that pollution control equipment may sometimes result in a "collateral increase" in the emission rate of a pollutant other than NOx or SO2. Thus, the operation of wet scrubbers and SCR -- while reducing SO2 and NOx emissions -- may in some cases increase sulfuric acid mist by more than insignificant amounts. FGD installation projects may also require air permitting for ancillary support facilities including limestone processing and in some case, changes to coal handling to accommodate changes in fuel that will be implemented for the most effective operation of the boiler with the FGD installed. Those ancillary facilities may trigger PSD review related to fugitive emissions from the extensive material handling operations. Permitting is also further complicated by the recent PSD requirements for evaluation of greenhouse gas emissions. [EPA-HQ-OAR-2009-0491-2689.1, pp.56-57] 
In short, NSR preconstruction permitting requirements can be triggered by projects that will result in a significant net emissions increase of one or more regulated pollutants. Prior to late 2005, sources that installed control equipment did not thereby trigger the time-consuming NSR preconstruction permitting process because such projects were subject to the pollution control project exclusion ("PCP" exclusion) in EPA's NSR rules. In December 2005, a D.C. Circuit decision vacated the PCP exclusion. See New York v. EPA, 413 F.3d 3 (D.C. Cir. 2005). As a result, the NSR permitting process may be triggered by a project to install an FGD, SCR, or LNB system if the operation of that control system may result in the increase of a pollutant other than the pollutant being controlled by the FGD, SCR, or LNB equipment. And an obligation to apply for and obtain an NSR permit, even if the permit itself does not require any further emission controls, would delay installation of the new control system because of the elaborate procedures associated with NSR permitting. The process of obtaining an NSR permit before beginning construction for FGD or SCR units can consume between 6 and 12 months. Although this was not a problem faced when installing pollution control projects in the first part of the last decade (due to the existence of the PCP exclusion), it is a problem now. If a complete review is needed (perhaps to evaluate emissions of greenhouse gases once the NSR process is scheduled to start applying to greenhouse gas emissions in early 2011), that could add a year or more to the entire process. [EPA-HQ-OAR-2009-0491-2689.1,p.57] 
There is another "permit-related" point to keep in mind: On site construction may not be started until at least some of the above-listed authorizations are obtained. In particular, this is the case where FGD and SCR installations are subject to the requirements of the NSR preconstruction permitting program. The NSR program limits the activities that source owners can do on-site prior to getting their final NSR permits. Thus, even though it may be possible to take some of the EPA-listed installation steps concurrently, some stages of the process --including getting some of the needed regulatory approvals -- must be completed before work can begin on subsequent installation steps. [EPA-HQ-OAR-2009-0491-2689.1,pp.58-59]
E.ON U.S.
In addition, EPA has failed to consider the timeframe for acquiring a Prevention of Significant Deterioration (PSD) permit. Without the Pollution Control Project exemption, an SCR project will likely require a PSD permit due to increases in sulfuric acid mist emissions and an FGD project will potentially exceed the CO2 PSD trigger level. The environmental permitting will result in additional workload and time for state agencies and EPA regional offices to review PSD permit applications (or make PSD applicability determinations), revised compliance assurance monitoring (CAM) plans, monitoring plans, public comments, and may involve challenges from third parties.  [EPA-HQ-OAR-2009-0491-2797.1, p.5]
Additional New Source Review Concerns.
EPA states that it does not expect New Source Review (NSR) to be a significant issue with retrofit of pollution control equipment. This assumption is totally unrealistic for even a small unit burning medium to high sulfur coal. The Proposed Transport Rule will require some facilities to install FGD's. It is likely that many of these facilities will use higher sulfur fuels in an effort to reduce fuel cost. With these higher sulfur fuels, triggering NSR for sulfuric acid mist (SAM) is very likely. Installation of SCR's may also trigger NSR for SAM. Installation of FGD's may require installation of PM monitors, resulting in additional cost and time. The additional cost of SAM controls needs to be added to the control costs and as mentioned above additional time from final rule to implementation must be considered. EPA also needs to consider that facilities that install FGD's on multiple units at a plant site may trigger NSR for CO2. As part of the SO2 scrubbing process using limestone, CO2 is released. For large units this could exceed the current 75,000 tons/year NSR trigger level. In addition, as EPA reduces this CO2 trigger level, additional units installing FGD's will be subject to NSR considerations. Because of all of the uncertainty of required CO2 BACT controls and anticipated challenges from third parties, significant delays in the installation of FGDs could occur and there certainly would be additional cost for the CO2 BACT controls. Many of these issues are beyond utilities' control. All of these cost and additional time requirements should be included in EPA's analyses. [EPA-HQ-OAR-2009-0491-2797.1, p.7]
Edison Electric Institute (EEI)
EPA Should Justify its Assertion that it is "Very Unlikely" that Pollution Control Projects Would Cause GHG Emission Increases in Excess of the PSD Emission Thresholds in the Agency's June 2010 GHG Tailoring Rule   
EPA bases its conclusion that the proposed Transport Rule will not significantly affect new source review (NSR) permitting on an analysis it conducted following the D.C. Circuit's decision in New York v. EPA, 413 F.3d 3 (D.C. Cir. 2005), which vacated the pollution control project exclusion in EPA's NSR regulations. According to EPA, that analysis indicated that the court's decision would not affect the assumptions underlying EPA's determination that CAIR was cost-effective and feasible. 5 EPA states simply that it believes that the same is true for the proposed Transport Rule.  [EPA-HQ-OAR-2009-0491-2697.1, p.20]
Although EPA's CAIR analysis did not address GHGs because they were not regulated CAA pollutants at that time, EPA concludes in the proposed Transport Rule that it is "very unlikely" that pollution control projects would cause GHG emission increases in excess of the NSR emission thresholds in EPA's June 2010 GHG Tailoring Rule. 75 Fed. Reg. 45343-4. EPA provides no justification for this assumption. EPA should, at a minimum, provide an analysis and explanation to support its assertion. [EPA-HQ-OAR-2009-0491-2697.1, p.10)]
EquiPower Resources Corp.
Moreover, although EPA claims that FGD (and SCR) installation will not trigger PSD permitting, the Agency offers no analysis or justification for that conclusion. [EPA-HQ-OAR-2009-0491-2704.1, pp.28-29]
Florida Electric Power Coordinating Group, Inc. (FCG)
EPA bases its conclusion that the Proposed Transport Rule will not significantly affect new source review (NSR) permitting on an analysis it conducted following the D.C. Circuit's decision in New York v. EPA, which vacated the pollution control project exclusion in EPA's NSR regulations. According to EPA, that analysis indicated that the court's decision would not affect the assumptions underlying EPA's determination that CAIR was cost-effective and feasible. EPA states simply that it believes that the same is true for the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2658.1,p.10]
Further, although EPA's CAIR analysis did not address greenhouse gases (GHGs) because they were not regulated CAA pollutants at that time, EPA concludes in the proposed Transport Rule that it is 'very unlikely' that pollution control projects would cause GHG emission increases in excess of the NSR emission thresholds in EPA's June 2010 GHG Tailoring Rule. Thus, EPA concludes that NSR impacts are not likely with respect to emission control projects required to satisfy the proposed Transport Rule. EPA provides no justification for this assumption, expressly regarding installation of SCRs, FGDs, and switching to lower sulfur coals (with different heat and ash contents). If EPA is confident in its conclusion, it should provide an express exemption in the rule. If EPA is incorrect, the implications for NSR permitting will be enormous. FCG requests that EPA, at a minimum, provide an analysis and explanation to support its assumption. [EPA-HQ-OAR-2009-0491-2658.1,pp.10-11]
Florida Municipal Electric Association (FMEA)
EPA Fails to Justify its Assumption that Pollution Control Projects would not trigger GHG PSD Requirements. EPA bases its conclusion that the Proposed Transport Rule will not significantly affect new source review (NSR) permitting on an analysis it conducted following the D.C. Circuit's decision in New York v. EPA, which vacated the pollution control project exclusion in EPA's NSR regulations. According to EPA, that analysis indicated that the court's decision would not affect the assumptions underlying EPA's determination that CAIR was cost-effective and feasible. EPA states simply that it believes that the same is true for the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2731.1, p. 9]
Further, although EPA's CAIR analysis did not address greenhouse gases (GHGs) because they were not regulated CAA pollutants at that time, EPA concludes in the proposed Transport Rule that it is "very unlikely" that pollution control projects would cause GHG emission increases in excess of the NSR emission thresholds in EPA's June 2010 GHG Tailoring Rule. Thus, EPA concludes that NSR impacts are not likely with respect to emission control projects required to satisfy the Proposed Transport Rule. EPA provides no justification for this assumption, expressly regarding installation of SCRs, FGDs, and switching to lower sulfur coals (with different heat and ash contents). If EPA is confident in its conclusion, it should provide an express exemption in the rule. If EPA is incorrect, the implications for NSR permitting will be enormous. FMEA requests that EPA, at a minimum, provide an analysis and explanation to support its assumption. [EPA-HQ-OAR-2009-0491-2731.1, p. 9]
International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers and Helpers (AFL-CIO Boilermakers Union)
Without a pollution control exemption, low-NO, burners and other such emissions control projects are viewed as a non-routine change for which a detailed new source review (NSR) assessment could be necessary. Even if an electric utility can document that the pollution control project has not resulted in a significant ORO emissions increase (which will most likely not be a straightforward task), it may be necessary to notify the permitting authority of the proposed project and demonstrate to permitting authorities satisfaction that NSR will in fact not be triggered under existing NSR regulations. Viewed in this context and given the nascent nature of this NSR process as applied to ORO emissions, the permitting timeline for pollution control projects could be greatly extended and subsequently push out the time period in which new controls can actually be installed. [EPA-HQ-OAR-2009-0491-2672.1, p.4]
EPA concludes in the proposed rule that it is 'very unlikely' that pollution control projects would cause GHG emission increases in excess of the NSR emission thresholds in the Agency's June 2010 GHG Tailoring Rule. This assessment does not correspond to reality. As an example, the use of limestone wet FGD systems will increase CO2 emissions through the plant stack as C02 is generated during the conversion of limestone to calcium sulfate. In addition, parasitic load requirements associated with the FGD operation (about 3% of output) will further increase GHG emissions levels per unit output. Without a pollution control exemption, a SO2 scrubber project is a non-routine change for which a detailed legal assessment could be necessary. Moreover, such scrubber projects could trigger NSR due to the likely increase in GHG emissions resulting from the scrubber conversion process and increased coal used to generate the extra MWhs that are necessary to operate the scrubber. In addition, a higher unit dispatch associated with more favorable market economics after an FGD installation could be potentially used as another basis for evaluating the NSR implications of the proposed project. Even if an electric utility can document that the scrubber project has not resulted in a significant GHG emissions increase (which will likely not be a straightforward task), it may be necessary to notify the permitting authority of the proposed project and demonstrate to permitting authorities satisfaction that NSR permitting will in fact not be triggered. All of this means that the permitting timeline for new FGD installations could be greatly extended and subsequently push out the time period in which new controls can actually be installed. 10 [EPA-HQ-OAR-2009-0491-2672.1, pp.6-7]
Large Public Power Council (LPPC)
Lastly, the preamble to the Transport Rule casually glosses over the potential impact of the PSD permitting process on the feasibility of implementing pollution control measures by 2012 and 2014. 29 LPPC does not share EPA's optimistic view that PSD permitting will not be required for facilities that must undertake retrofits to comply with the Transport Rule. Indeed, the five-year old study that EPA relies upon in drawing this conclusion found that certain configurations of equipment could trigger New Source Review thresholds for other regulated pollutants, such as sulfuric acid. 30 Moreover, state construction and operating permits are usually necessary in order to undertake pollution control projects, even when New Source Review permitting is not required. LPPC therefore asks EPA to prepare a more comprehensive and updated study of permitting processes associated with the Transport Rule. [EPA-HQ-OAR-2009-0491-2725.1, pp.8-9]
In addition, LPPC asks EPA to consider that the process of revising SIPs to include permitting authority for greenhouse gas emissions may cause a temporary lapse in state PSD permitting authority. 31  If such a lapse occurs, facilities that are required to obtain PSD permits for pollution control projects may not be able to obtain them by 2012. [EPA-HQ-OAR-2009-0491-2725.1, pp.8-9] [[The SIP comment can also be found in Section VII.C.]]
National Rural Electric Cooperative Association (NRECA)
The presumption that unit changes needed by the proposal to reduce emissions will not trigger new source review (NSR) is unsubstantiated, based only on generalized supposition. Any unit triggering NSR review because of required changes to reduce emissions should be waived from allowance obligations or be provided with extra allowances until the NSR review is complete. [EPA-HQ-OAR-2009-0491-2723.1, pp.1-2]
The proposal glosses over the possibility that unit necessary changes under the proposal could trigger NSR review and surmises that it is not a problem, needing only little consideration. It is noteworthy EPA has not supplied any technical information or analysis in the proposed CATR or within the docket to support its contention. NRECA has deep concerns with EPA's cavalier approach to a potentially significant problem.  [EPA-HQ-OAR-2009-0491-2723.1, p.16]
The NSR process involves case-by-case review. As EPA knows, each individual coal generating unit has very individual and distinct operating and emission characteristics. Even if the engineering designs are identical this is the case. It is therefore impossible based on generalizations to conclude that on an individual unit basis equipping with additional pollution controls or switching fuels would not trigger an NSR significant emissions increase and review. Moreover, what analysis EPA has performed, referenced but not included in the docket, did not consider greenhouse gases (GHGs) that EPA has decided to regulate as an NSR pollutant. EPA dismisses the possibility of unit GHG emissions triggering NSR based on its CAA statutory theory contained in the so called Tailoring Rule: To whit that the CAA statutory major source trigger of 100 tons is really 75,000 or 100,000 tons, as the case may be, for purposes of GHG NSR. [EPA-HQ-OAR-2009-0491-2723.1, p.16]
If EPA non NSR supposition is wrong, units will have to undergo a review process that takes an indeterminable amount of time. Historically, the NSR review process can take years and not months, during which time unit changes would be on hold. This being the case, EPA has offered no remedy in the CATR proposal to placate unit owners or operators who may be forced to operate the units without additional allowances needed to cover extra emissions during NSR review. NRECA believes EPA must address this potential problem in either one of two ways. Grant unit variances in allowance deficiencies to the extent that extra emissions exceed unit allocations, or by utilizing unused CAIR allowances to cover extra emissions. [EPA-HQ-OAR-2009-0491-2723.1, p.17]
North Carolina Department of Environment and Natural Resources
Operation of FGD can generate large amounts carbon dioxide (one of the six gases defined as GHG). For example, a coal-fired EGU with a generating capacity of 800 MWe can emit approximately l1S,OOO tons/yr of CO, solely due to operation of a flue gas desulphurization system (FGD), thus, exceeding the PSD significance threshold of 75,000 tons/yr CO2e. Therefore, such EGU with a FGD is required to obtain a PSD permit starting July 1, 2011; assuming that the facility's premodification status is 'major' for GHG emissions (i.e., 100,000 tons/yr CO2e for GHG) separately, the impacts on PSD permitting due to operation of low-NOx burners, SGl.s, etc. on traditional pollutants (non-GHG) cannot be underestimated. For example, emissions can occur at high levels  due to operation of these controls and can exceed their respective significance thresholds. [EPA-HQ-OAR-2009-0491-2767.1 p.8]
Ohio Utility Group (OUG)
Second, EPA failed to consider the practical implications raised by assuming that all units can make the fuel switch. Many of the units operated by the Utilities cannot run on the softer, low-sulfur coal without making major modifications, which would require permitting under New Source Review. The Utilities urge EPA to consider the substantial costs and additional time required to comply. [EPA-HQ-OAR-2009-0491-2679.1, p.6]
Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
C. EPA Should Exempt the Installation of Emission Control Equipment from New Source Review Requirements
As noted above, the proposed deadlines to reduce emissions provide insufficient time to design, procure, and install control equipment. That insufficiency becomes substantially greater, and the need for longer deadlines more acute, if the installation of controls is subjected to new source review (NSR) permitting requirements. If the pollution control projects necessary to meet Proposed Transport Rule budget allocations for an electric generating unit, such as retrofit of FGD and SCR controls and equipment for handling alternative coal supplies, require NSR permits, such permits will need to be issued before construction can commence, and may require design or business planning changes. The time requirements for processing NSR permits will vary from jurisdiction to jurisdiction and project to project. Permitting times are difficult to predict, but cannot . be less than 12 months as a matter of law and can easily take more than twice that time. The emission control retrofits expected by the Proposed Transport Rule must either be excluded from NSR permitting requirements, or the deadlines for constructing those controls must be extended to allow time for NSR permitting. There are multiple ways EPA can craft an appropriate NSR exclusion for Transport Rule-driven emission control projects. EPA could provide a special definition of baseline actual emissions for such projects (such as the product of maximum actual hourly emission rates for any regulated pollutant multiplied by the maximum actual 12-month heat .input for the electric generating unit in question) or a causation determination tied specifically to the Transport Rule (that the Transport Rule rather than the measures undertaken to comply with it are the predominant and relevant cause, for NSR non-applicability purposes, of any emission increases associated with such compliance measures). EPA also has discretion to interpret the term 'stationary source' in the definition of 'modification' in Section 111 (a)(4) of the Clean Air Act that does not impede compliance with timeframes and targets in the Transport Rule. [EPA-HQ-OAR-2009-0491-2803.1, p.12]
Old Dominion Electric Cooperative
In the proposed Transport Rule, EPA presumes that the previous analysis regarding impacts of vacating the pollution control project exclusion on CAIR is 'still current and relevant' and continues to hold that NSR program requirements will not significantly impact that schedule for installation of projected controls, ld. at 45,343. It is noteworthy that EPA has not supplied any additional technical information or analysis in the Transport Rule docket to support its contention. ODEC has concerns with EPA's approach to a potentially significant problem. [EPA-HQ-OAR-2009-0491-2877.1,p.10]
The NSR process involves case by case review. As EPA knows, each individual coal generating unit has very individual and distinct operating and emission characteristics. It is therefore impossible based on generalizations to conclude that, on an individual unit basis, installation of additional pollution controls or switching fuels would not trigger an NSR significant emissions increase threshold and review. Moreover, what analysis EPA has performed, referenced but not included in the docket, did not consider greenhouse gases (GHGs) that EPA has decided to regulate as an NSR pollutant. EPA dismisses the possibility of unit GHG emissions triggering NSR based on its CAA statutory theory contained in the so called Tailoring Rule: To which the CAA statutory major source trigger of 100 tons is really 75,000 or 100,000 tons, as the case may be, for purposes of GHG NSR. [EPA-HQ-OAR-2009-0491-2877.1,pp.10-11] 
lf EPA's supposition is wrong, units will have to undergo a review process that takes an indeterminable amount of time. This being the case EPA has offered no remedy in the Transport Rule proposal to placate unit owners or operators who may be forced to operate the units without additional allowances needed to cover extra emissions during NSR review. ODEC believes EPA must address this potential problem in either one of two ways. Grant unit variances in allowance deficiencies to the extent that extra emissions exceed unit allocations, or utilize unused CAIR allowances to cover extra emissions. [EPA-HQ-OAR-2009-0491-2877.1,p.11]
Progress Energy Service Company
EPA Should Provide Justification for Its Assertion that It Is 'Very Unlikely' that Pollution Control Projects Would Cause GHG Emission Increases in Excess of the PSD Emission Thresholds in the Agency's June 2010 GHG Tailoring Rule
EPA bases its conclusion that the proposed Transport Rule will not significantly affect new source review (NSR) permitting on an analysis it conducted following the D.C. Circuit's decision in New York v. EPA (D.C. Circuit Court of Appeals 2005), which vacated the pollution control project exclusion in EPA's NSR regulations. According to EPA, that analysis indicated that the court's decision would not affect the assumptions underlying EPA's determination that CAIR was cost·effective and feasible. If EPA states simply that it believes that the same is true for the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2831.1 p.6]
Further, although EPA's CAIR analysis did not address greenhouse gases (GHGs) because they were not regulated CAA pollutants at that time, EPA concludes in the proposed Transport Rule that it is 'very unlikely' that pollution control projects would cause GHG emission increases in excess of the NSR emission thresholds in EPA's June 2010 GHG Tailoring Rule. Thus, EPA concludes that NSR impacts are not likely with respect to emission control projects required to satisfy the proposed Transport Rule. EPA provides no justification for this assumption. If EPA is incorrect, the implications for NSR permitting will be enormous. Progress Energy requests that EPA, at a minimum, provide an analysis and explanation to support its assertion. [EPA-HQ-OAR-2009-0491-2831.1 p.7]
RRI Energy, Inc.
The preamble to the proposed CATR noted that "consistent with EPA's previous analysis and EPA's conclusions for GHG, EPA does not believe that there are significant impacts from NSR for any pollution control projects resulting from the proposed rule such as low-NOX burners, SO2 scrubbers, or SCR. EPA requests comment on this issue." In general, RRI concurs with EPA's assessment. However, it has been RRI's unfortunate experience that many state / local agency personnel are misinformed and / or inexperienced with the complex NSR regulations. An unfortunate outcome of this situation is the establishment of emissions and other limitations (based primarily on retrospective and prospective emissions analyses) that are unsupported by the regulations. Because of the complexity of the NSR regulations and decreased availability of resources within many state / local agencies, RRI suggests that EPA establish a procedure to help resolve questions concerning NSR applicability for pollution control projects if the permit applicant and applicable agency are unable to resolve disputes within a reasonable time period (e.g., NJ DEP's proposed Office of Dispute Resolution). [EPA-HQ-OAR-2009-0491-2717.1 p.6]
San Miguel Electric Cooperative, Inc.
 The presumption that unit changes needed to meet the proposal to reduce emissions will not trigger NSR is unsubstantiated, based only on generalized supposition. Any unit triggering NSR review because of required changes to reduce emissions should be waived from allowance obligations or be provided with extra allowances until the NSR review is complete.   [EPA-HQ-OAR-2009-0491-2641.1, p.6]
State of Louisiana, Department of Environmental Quality
The permitting process may be particularly involved if installation of NOx control equipment such as low NOx burners results in PSD-significant collateral increases in CO emissions. [EPA-HQ-OAR-2009-0491-2655.1, p.5]
State of Ohio Environmental Protection Agency (Ohio EPA)
7. Ohio EPA has concerns regarding the potential for New Source Review to significantly impact the implementation schedule. There is not sufficient time built into the current schedule to address New Source Review requirements for Greenhouse Gas emissions and U.S. EPA should correct this deficiency. [EPA-HQ-OAR-2009-0491-2793.2, p. 7]
In the notice, U.S. EPA provides a short discussion stating its belief that the installation of air pollution control equipment such as S02 scrubbers, SCR, or low NOx burners will not increase emissions for criteria pollutants above the significance thresholds to require a Prevention of Significant Deterioration (PSD) permit. The notice refers to a document prepared in 2005 that provides technical information that a PSD/New Source Review (NSR) permit will not be necessary for criteria pollutants. This document does not, however, address the emissions of greenhouse gases (GHG) that are scheduled to come under the U.S. EPA PSD permitting system starting January 2, 2011. The Federal Register states:
'Once the PSD requirements take effect, major sources that· undergo a modification, including the addition of pollution control equipment, will trigger PSD requirements for their emissions of GHG if such emissions increase by at least 75,000 tons per year of CO2 , equivalent. EPA believes it is very unlikely that pollution control projects would cause GHG increases that would exceed the 75,000 tons per year threshold.' [75 FR 45344] [EPA-HQ-OAR-2009-0491-2793.2, p. 7]
Apparently, U.S. EPA does not have a technical analysis to support this statement. Ohio EPA believes that, for some of the larger power plants, this is simply inaccurate, and U.S. EPA should not gloss over the permitting issue with a simple line in the Federal Register notice. [EPA-HQ-OAR-2009-0491-2793.2, p. 7]
For example, based on information from U.S. EPA's Clean Air Markets Division website, the Alabama Power Gaston plant in Alabama. had 102,980 tons of S02 per year. The installation of a limestone scrubber with 95% emissions control would produce approximately 69,166 tons per year of CO2. CO2emissions are currently 8,859,466 tons per year. A 2% increase in parasitic load needed to operate the scrubber would produce an additional 177,189 tons per year of CO2. The installation of an S02 scrubber, in this example, would produce a total of 240,355 tons of CO2 per year. This value is well above the 100,000 tons of CO2 per year value needed to trip PSD by itself. [EPA-HQ-OAR-2009-0491-2793.2, p. 7]
It would be no small administrative matter to obtain a PSD permit for the scrubber installation. Consequently, Ohio EPA urges U.S. EPA to consider and adopt one of two options: a. Add at least another 12 months to the time allotted for facilities to comply in order to obtain the PSD permit needed to install the scrubber, or b. Provide another limited exemption in the PSD/NSR rules for a pollution control exemption. [EPA-HQ-OAR-2009-0491-2793.2, pp. 7-8]
U.S. EPA cannot intend to put utility plant owners in the position of having to violate U.S. EPA's own regulations in order to comply with the Transport Rule and, therefore, must provide adequate time for PSD permitting. [EPA-HQ-OAR-2009-0491-2793.2, p. 8]
(Please note that the calculations did not include any increases as a result of the facility being used more as a result of a lower emission rate of S02. This would cause additional C02 emissions that may need to be considered in the PSD calculation.) [EPA-HQ-OAR-2009-0491-2793.2, p. 8]
Ohio EPA will provide a supplemental document that details the GHG emissions calculation for the example plant. [EPA-HQ-OAR-2009-0491-2793.2, p. 8]
[See EPA-HQ-OAR-2009-0491-2793.1 which is used to support Ohio EPA's comments above related to the need for PSD permits for the installation of sulfur dioxide scrubbers.]
Tennessee Department of Environment and Conservation, Division of Air Pollution Control
Comment on New Source Review: The 2005 reconsideration noted above by EPA states the following:
"The NOX removal efficiency for each type of combustion control used in EPA's analysis for CAIR was estimated as an average of the reported efficiencies for a large number of units equipped with these controls. In a unit equipped with both low-NOX burner (LNB) and overfire air (OFA) technologies, LNB provides a greater part of the overall NOX removal reduction. Since the NOX removal efficiencies used in EPA's analysis are not aggressive, it is believed that the units installing combustion controls can opt for moderate levels of OFA flow rates and still achieve the NOX reduction levels projected in EPA's analysis, without causing significant increases in the CO and unburned carbon emissions." [emphasis added] [EPA-HQ-OAR-2009-0491-0553.1,p.5]
EPA needs to be sure that the 2005 analysis is adequate. Our impression is that for sources that do not install add-on NOX controls, the level of NOX removal required for the Transport Rule will be more aggressive than was required under CAIR. Therefore, there is greater concern that increased CO emissions will trigger NSR under the proposed rule. Adoption of low sulfur coal could raise similar concerns, since the sulfur content of the ash affects ESP performance. Low sulfur coal addition could also require physical changes at some facilities. [EPA-HQ-OAR-2009-0491-0553.1,p.5]
Tennessee Valley Authority (TVA)
Since the Paradise FGD was completed and TVA's expert report finalized, the pollution control project exclusion in EPA's NSR regulations was vacated by the United States Court of Appeals for the D.C. Circuit in New York v. EPA, 413 F.3d 3 (D.C. Cir. 2005). This vacatur adds additional pre-construction air permitting requirements for those air pollution control projects that may result in significant emission increases of regulated pollutants. Based on its analysis in a Technical Support Document (TSD) prepared in the course of the CAIR rulemaking in 2005 ("Impact on CAIR Analyses of D.C. Circuit Decision in New York v. EPA), EPA concludes that the NSR requirements will not impact the construction of TR controls. The 2005 analysis in the TSD was limited to conventional pollutants. For GHG emissions, EPA believes, without providing any analysis, that it is very unlikely that pollution control projects (PCP) would cause GHG increases that exceed the 75000 tons per year threshold. [pp. 45343-44] If EPA is wrong, the implications for NSR permitting will be enormous, making it even more difficult for EGUs to meet the stringent timetable for compliance with the Transport Rule. [EPA-HQ-OAR-2009-0491-2782.1, p. 4]
Utility Air Regulatory Group (UARG)
Contrary to EPA's Assumption, Permitting Requirements Cannot Be Expected To Be Met in Time To Satisfy the Proposed Transport Rule's Compliance Schedule.
EPA asserts, based on an analysis that it conducted following the D.C. Circuit's decision in New York v. EPA, which vacated the PCP exclusion in EPA's NSR regulations, that NSR permitting requirements "[will] not significantly impact the construction of controls that are installed to comply with the proposed transport rule." 75 Fed. Reg. at 45343/3. EPA vastly underestimates the complexity of this issue in the proposed rule. As explained above in section V.A.2, although the operation of SCR and FGD units will reduce emissions of NOx and SO2, in many cases operation of these controls may be thought to result in an increase in emissions of other pollutants by more than insignificant amounts. Contrary to the assumptions that EPA made in its 2005 analysis, experience has shown that NSR permitting requirements will significantly impact the construction of controls. See section V.A.2 supra (noting that NSR permitting can be expected to add many months to over a year to the process of adding FGD or SCR units). [EPA-HQ-OAR-2009-0491-2756.1, p.90]
EPA must take a realistic view, based on real-world, practical experience, regarding the implications of NSR permitting requirements for the installation of controls required under the proposed rule, taking into account the effect that the court's vacatur of the PCP exclusion has had on NSR permitting. Such a realistic view would reveal that the impact of NSR permitting requirements on the construction of controls required under the proposed rule is likely to be significant. [EPA-HQ-OAR-2009-0491-2756.1, pp.90-91]
EPA Should Provide Justification for Its Unsupported Assertion that It Is "Very Unlikely" that Pollution Control Projects Would Cause GHG Emission Increases in Excess of the PSD Emission Thresholds in the Agency's June 2010 GHG Tailoring Rule.
According to EPA, the analysis referred to above in section IX.A, conducted following the D.C. Circuit's decision in New York v. EPA, indicated that the court's decision on the PSP exclusion issue would not affect the assumptions underlying EPA's determination that CAIR was cost-effective and feasible. EPA states simply that it believes that the same is true for the Proposed Transport Rule. 75 Fed. Reg. at 45343/3. [EPA-HQ-OAR-2009-0491-2756.1, p.91]
Although EPA's CAIR analysis did not address greenhouse gases ("GHGs") because they were not regulated CAA pollutants at that time, EPA concludes in the Proposed Transport Rule that it is "very unlikely" that pollution control projects would cause GHG emission increases in excess of the NSR emission thresholds in EPA's June 2010 GHG Tailoring Rule. 75 Fed. Reg. at 45344/1. At least in part for this reason, EPA concludes that NSR impacts are not likely with respect to emission control projects required to satisfy the Proposed Transport Rule. 75 Fed. Reg. at 45344/1. EPA provides no justification for this assumption. If EPA is wrong, the implications for NSR permitting -- and for the necessary compliance schedule for implementation of any rule such as the Proposed Transport Rule -- will be substantial. EPA must, at a minimum, provide an analysis and explanation to support its assertion and make that analysis and explanation available for public comment before it proceeds further with this rulemaking. [EPA-HQ-OAR-2009-0491-02756.1, p.91]
Wolverine Power Supply Cooperative
EPA has made a flawed assumption that installation of the necessary pollution control projects will not require Federal New Source Review (NSR) permitting that requires 9 to 18 months, on the average, to obtain before any construction can commence. In our state, Michigan, all major emission control configurations being designed to meet CAIR reductions are undergoing NSR review at this time, and EPA has even initiated enforcement against coal-fired units that have installed emission controls without a full NSR permit. EPA's recently finalized Tailoring Rule virtually guarantees that all SO2 and NOx control projects will need to go through NSR permitting for Greenhouse Gases. [EPA-HQ-OAR-2009-0491-2825.1 p.3]
Response: 
See preamble section VII.I.2.  

IX. What Benefits are Projected for the Proposed Rule?

Organization: Citizens Campaign for the Environment (CCE)
Oren, Craig N.
Comment: 
Citizens Campaign for the Environment (CCE)
Economic Benefits The estimated cost to the power generating sector to comply with the proposed Transport Rule is approximately $2.8 billion, while the societal cost for compliance is estimated at $2.2 billion/annually. EPA estimates the projected benefits to compliance at $190 billion - $290 billion / annually, thus significantly outweighing the costs of compliance. [EPA-HQ-OAR-2009-0491-1937.1, p. 2]
Oren, Craig N.
Another reason to tighten the rule is that benefits exceed costs by so much. This makes me believe that further cuts can be made without costs beginning to exceed benefits. The nature of the health effects also makes me believe that EPA should err on the side of public health, and require more stringent reductions than are called for in the proposed rule. [EPA-HQ-OAR-2009-0491-2644-cp, p.1]
Response: 
EPA agrees that the estimated monetized benefits of this rule exceed the estimated costs by a significant margin. 
As described in the final Transport Rule preamble, EPA's authority for the Transport Rule exists under Clean Air Act section 110(a)(2)(D)(i)(I).  This section requires the elimination of upwind state emissions that significantly contribute to non-attainment or interfere with maintenance of a NAAQS in another state.  As such, the level of SO2 and NOX emission reductions under the Transport Rule were determined based on elimination of significant contribution.  Requiring more or less stringent reductions would not be consistent with the authority provided under 110(a)(2)(D)(i)(I).
Organization: Clean Air Task Force
Comment: 
Clean Air Task Force
A. Public Health Impacts
The link between power plant emissions and human health has been documented in an extensive body of scientific research drawing on multiple lines of epidemiological and toxicological evidence, including several rigorous, long-term multi-city epidemiological studies, one of which was conducted over nearly two decades in 150 U.S. metropolitan areas. That body of literature has been reviewed and summarized by the U.S. Environmental Protection Agency (EPA) in its 2009 Integrated Scientific Assessment for Particulate Matter. [EPA-HQ-OAR-2009-0491-2738.1, p.9; for additional comments pertaining to Power Plant Emissions Seriously Endanger Public Health and Welfare, Public Health Impacts, & Public Welfare Impacts see pages 8-12 of this comment]
EPA's analysis demonstrates that the TR will produce important public health and environmental benefits and will be dramatically cost-effective. According to EPA, by 2014 the proposed rule will annually prevent approximately 14,000 to 36,000 premature deaths, 22,000 heart attacks, and about 1.8 million work days lost to illness. A stronger rule could save many more lives and prevent many more health problems. In fact, we describe in Section V, infra, an analysis of an Alternate Control Scenario projecting that more stringent emission caps similar to the ones we propose here would save an additional 3600 to 9250 lives in 2015. [EPA-HQ-OAR-2009-0491-2738.1, p.6; Alternate Control Scenario can be found at EPA-HQ-OAR-2009-0491-2738.1, p.26] 
Response: 
As described in the final Transport Rule preamble, EPA's authority for the Transport Rule exists under Clean Air Act section 110(a)(2)(D)(i)(I).  This section requires the elimination of upwind state emissions that significantly contribute to non-attainment or interfere with maintenance of a NAAQS in another state.  As such, the level of SO2 and NOX emission reductions under the Transport Rule were determined based on elimination of significant contribution.  Requiring more or less stringent reductions would not be consistent with the authority provided under 110(a)(2)(D)(i)(I).
Organization: Environmental Law & Policy Center
Comment: 
Environmental Law & Policy Center
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.76-77.]
The benefits of implementation of this rule are astounding for 9 million children in the United States who suffer from asthma.
With the implementation of this rule, we will avoid thousands of premature deaths and thousands of hospitalizations.
The number of missed workdays and schooldays will decrease, and, as a result, collectively our society will save billions of dollars in avoided healthcare costs, and we will gain billions of dollars in increased productivity.
So this rule is an important first step.
Response: 
EPA agrees that the estimated benefits of the proposed Transport Rule are substantial, and that populations highly susceptible to air pollution-related illnesses--particularly asthmatics--would receive substantial improvements in air quality. 

IX.A. [Reserved]

IX.B. Human Health Benefit Analysis

Organization: Citizens Campaign for the Environment (CCE)
Comment: 
Citizens Campaign for the Environment (CCE)
Human Health Benefits The USEPA estimates that every year, 10,000 Americans lose their lives prematurely due to power plant emissions. Hence, significant reductions in emissions will benefit human health. In addition, the Transport Rule calls for twenty-six states to reduce NOx during hot summer months, thus reducing ground level ozone caused by a reaction between NOx and volatile organic compounds. Scientific studies have linked ground level ozone to an array of respiratory ailments and permanent lung damage. Measures taken to reduce emissions of NOx and SO2 will also have the co-benefit of reducing mercury emissions from power plants. EPA studies have shown that human consumption of fish contaminated with mercury lead to health problems such as neurological disorders and birth defects. [EPA-HQ-OAR-2009-0491-1937.1, p. 2]
Response: 
EPA agrees that the estimated human health benefits of the proposed Transport Rule are substantial and that NOx reductions will reduce the formation of ground-level ozone. 
Organization: E.ON U.S.
Comment: 
EPA's analyses of health benefits is flawed.
We support the goals of the Clean Air Act to protect human health. However, studies by the Electric Power Research Institute (EPRI) indicate that claims of health effects attributed to particulate matter sulfates are questionable, while other components of PM2.5 (fine particulates), such as elemental carbon and organic carbon have a more important role in impacting human health. As such, further reductions in sulfur dioxide emissions may not result in the health benefits used in EPA's cost-benefit analysis. EPRI has also raised questions about EPA's premature mortality assumptions. Finally, it appears EPA intends to assume this same health benefit for multiple rulemakings (e.g., CATR, Ozone NAAQS and PM2.5 NAAQS). This approach results in triple-counting the health improvements and significantly overstating each regulatory program's benefit. [EPA-HQ-OAR_2009-0491-2797.1, p.6]
Response: 
Recent epidemiological studies suggest the possibility that PM mixtures with higher concentrations of black carbon and specific metals might be more potent than the average PM2.5 mixture, however, the overall evidence continues to show that all PM2.5 components contribute to observed health effects. Consistent with advice received from the Health Effects Subcommittee (HES) of the EPA Science Advisory Board, we estimated PM-related mortality resulting from reductions in exposure to total PM mass. According to the HES, "...the evidence base at this time does not current support" an assessment of attributing PM-mortality risk to specific precursors.
EPA disagrees that it over-counts the benefits of air quality rules. The Regulatory Impact Analyses accompanying the National Ambient Air Quality Standards (NAAQS) hypothesize, but do not predict, the control strategies that States may choose to enact when implementing a NAAQS. The setting of a NAAQS does not directly result in costs or benefits, and as such, the NAAQS RIAs are merely illustrative and are not intended to be added to the costs and benefits of other regulations that result in specific costs of control and emission reductions. However, some portion of the air quality improvement, costs and benefits estimated in this RIA may account for the same air quality improvements, costs and benefits estimated in the illustrative NAAQS RIA's. For this reason, the benefits and costs estimated in NAAQS RIA's and this RIA are not additive; EPA indicates this clearly in its NAAQS RIA's.
Organization: Edison Electric Institute (EEI)
Tennessee Valley Authority (TVA)
Minnesota Power 
Comment: 
As previously stated, building upon the Acid Rain Program, CAIR and with the proposed Transport Rule, power generation SO2 emissions in the 31 states and D.C. affected by this rule would be reduced 80-90 percent in general. Electric power companies will continue to work with EPA to reduce emissions and to focus upon actions to efficiently and economically generate electricity and reduce environmental impacts.  [EPA-HQ-OAR-2009-0491-2697.1, p.19]
However, many EEI member companies believe that EPA should acknowledge more directly that the purported health benefits of the proposed Transport Rule and other air quality regulations are less certain that EPA implies. EPA has relied upon particulate matter co-benefits to drive its NAAQS cost-benefit justifications in its recent SO2 NAAQS decision, to a large degree in the current ozone NAAQS proceeding, and in this Proposed Rule. Yet, the Electric Power Research Institute (EPRI) has implemented state-of-the-air studies, including ARIES, which indicate that some claims regarding health effects attributed to particulate matter sulfates are questionable, while other components in the PM mass such as elemental carbon and organic carbon are more important than previously assumed. 4 [EPA-HQ-OAR-2009-0491-2697.1, p.19]

Footnote 4: EPRI in a February 2009 document entitled "PM2.5 Reductions and Impact on Premature Death: An EPRI Perspective Issue Brief" concludes, regarding estimates of premature mortality attributed to particulate matter, that "A more appropriate way to express potential health impacts would be to use a range. Since some models in some studies do not find a statistically significant effect of PM2.5 on mortality, the effects range could even include zero." EPRI in a document entitled Particulate Matter Toxicology (September 2008) asks "What have we learned through toxicology about the relative toxicity of different PM components?" and concludes regarding our current state of knowledge on the health effects attributable to different PM components: "Sulfate and acid aerosols: There is little evidence for sulfate-related health effects except at high concentrations (in the mg/m3 range, several orders of magnitude higher than ambient air concentrations), where some effects on pulmonary function have been noted.." EPRI in a December 2009 document entitled "Air Quality Health Effects Research: Current Status", concludes that: 1) "Substantial progress has been made in understanding the effects of air pollution. EPRI research has helped to lead the way in demonstrating that all PM components are not equally toxic, and today there is a growing consensus that elemental carbon (EC) is one of the most important components in explaining health responses to PM. 2) EPRI's research has also made it clear that the focus cannot only be on PM; pollutant gases are also tied to health responses and could explain some of the responses that have been attributed to PM. In particular, the organic gases (i.e., volatile or semi-volatile organic compounds; VOCs and SVOCs) need to be considered more comprehensively."
Issue: The proposed Transport Rule would reduce fine particulate and ozone levels by reducing SO2 and NOx emissions from EGU's in the eastern U.S. Over 90% of the total monetized benefits of this rule are derived from reduced estimates of premature mortality associated with fine particulates. However, recent epidemiological research by the Electric Power Research Institute (http://www.atmosphericresearch. com/PDFs/ARIES/ARIES%20Web%20Page_Summary%20of%20Findings.pdf) concludes that mortality is most strongly associated with species of particulate matter other than sulfate. Furthermore, a recent article in InsideEPA (April 13, 2010) indicates that EPA's own advisors, members of the Clean Air Scientific Advisory Committee, and outside specialists are concerned that a PM-2.5 mass standard is becoming less supportable as evidence accumulates that specific chemical constituents of PM-2.5 are more strongly associated with adverse health effects than the sulfates and nitrates addressed by this rule. [EPA-HQ-OAR-2009-0491-2782.1, p. 16]
TVA Comment: The health benefits attributed to this rule may be over-estimated, since other chemical components of particulates may be more strongly associated with mortality than sulfates and nitrates. Considerable debate appears to be ongoing within EPA and the research community as to the propriety of a constituent-specific particulate standard in favor of the current mass-based particulate standard. The need for more information on this issue is another reason for EPA to eliminate the 2012 compliance date in the Proposed Transport Rule. TVA is collecting PM-2.5 speciation data at the Look Rock monitoring site in the Great Smoky Mountains National Park in order to contribute to PM-2.5 research efforts. [EPA-HQ-OAR-2009-0491-2782.1, p. 17]
Revisit EPA's sulfate health impact analysis considering health impacts from fine particle constituents.  EPA should further examine their basis for assigning health impacts against sulfate emissions, recognizing that air quality analysis correlated with hospital visits and mortality is showing that a zero sulfates impact is among the range of health study results that break out specific pollution components in fine particles separately.  Electric Power Research cosponsored analysis is indicating that the health impacts being assigned by EPA against sulfate emissions may be more correctly assigned to motor vehicle emissions of elemental carbon and volatile organic compounds.  EPA's emphasis on further driving down residual sulfate emissions due to perceived health effects may prove to be unsupported when fine particulate constituents are broken out separately for health impact consideration.  This is especially important when consideration is given to how limited public resources applied to diminishing return sulfate emission reductions may be better applied towards reducing emissions from sources emitting carbon and volatile organic compounds.  [EPA-HQ-OAR-2009-0491-2750.1, pp.5-6]  
Particle component speciation.  EPRI has affirmed that a more robust health study focus on individual components in PM2.5 rather than particles in the aggregate show that sulfates can have no statistically significant contribution to morbidity and mortality, in contrast to carbonaceous components which do. The Transport Rule does not provide for reductions of carbonaceous particles, which source from motor vehicles, but does require an expensive expansion of sulfate emission reduction requirements, citing health benefits as justification.   [EPA-HQ-OAR-2009-0491-2750.1, p.8]
Response: 
Recent epidemiological studies suggest the possibility that PM mixtures with higher concentrations of black carbon and specific metals might be more potent than the average PM2.5 mixture, however, the overall evidence continues to show that all PM2.5 components contribute to observed health effects. Consistent with advice received from the Health Effects Subcommittee (HES) of the EPA Science Advisory Board, we estimated PM-related mortality resulting from reductions in exposure to total PM mass. According to the HES, "...the evidence base at this time does not currently support" an assessment of attributing PM-mortality risk to specific precursors.
Organization: Environmental Defense Fund (EDF)
Comment: 
Environmental Defense Fund (EDF)
a. The substantial health burden of emissions of sulfur dioxide and nitrogen oxides demonstrates the need for stronger standards.
It has been substantiated in the peer-reviewed scientific and epidemiological literature that serious human health effects can be attributed to emissions of sulfur dioxide (SO2) and nitrogen oxides (NOx), largely as a result of their contribution to downwind concentrations of suspended fine particulate matter (PM) and tropospheric ozone. An independent technical analysis prepared for EDF using 2009 facility-specific emissions data for electricity generating facilities from EPA's Clean Air Markets Data and Maps website confirms the high health costs of the SO2 and NOx emissions discharged from eastern power plants focusing on the fine particulate health effects. These emissions are associated with 23,000 to 60,000 deaths, 3.1 million lost work days, 800,000 cases of lower and upper respiratory symptoms, and over 18 million cases of acute respiratory symptoms each year (see Table 1 below). [EPA-HQ-OAR-2009-0491-2834.1 p.2]
Perhaps the most significant health impact of SO2 and NOx emissions is the increase in adult premature mortality, reported in the last two lines of Table 1. We have used two prominent studies to bracket the estimated impacts of particulate matter: the American Cancer Society study (Pope et al., 2002) and the Six Cities Study (Laden et al., 2006). This approach is consistent with the current literature. For example, a forthcoming analysis by EPA of the costs and benefits of the 1990 Clean Air Act uses a distribution of values with an interquartile range lying between the two studies used here.1 Our approach is also informed by a recent expert elicitation study conducted by EPA, in which many of the experts surveyed estimated mortality effects greater than the Pope et al. estimates.2 Additionally, many of the experts expressed greater confidence in the relationship between fine particulate exposure and premature mortality. Ten of the 12 experts responded that the probability of a causal relationship between PM exposure and premature mortality was at least 90 percent.  [EPA-HQ-OAR-2009-0491-2834.1 p.3]
A 2007 analysis prepared for the South Coast Air Quality Management District by Leland Deck and Lauraine Chestnut of Stratus Consulting also comports with the findings of the expert elicitation study. The Stratus analysis used the weighted average of the Pope et al. estimates (50 percent), the Jerrett et al. 2005 study (25 percent), and the Laden et al. study (25 percent) to estimate premature mortality from fine particulate matter.3 The 2005 Jerrett et al. study concluded that actual chronic health impacts associated with fine particulate matter were greater than those reported in the American Cancer Society study.4 The Laden et al. premature mortality estimates constitute the top of the range EPA uses in its analysis. This weighted average approach emphasizes that many experts estimate premature mortality effects at levels well above the Pope et al. study.  [EPA-HQ-OAR-2009-0491-2834.1 p.3]
As noted in the American Lung Association's State of the Air 2010 report, researchers from Harvard University5 recently "tripled the estimated risk of premature death [from particle pollution] following a review of the newer evidence from fine particle monitors in 27 U.S. cities."6 The American Lung Association also noted that the California Air Resources Board estimated annual deaths from particle pollution, just in California, to be in the range of 5,600 to 32,000, representing a tripling of their previous estimate.  [EPA-HQ-OAR-2009-0491-2834.1 p.3]
As noted in the American Lung Association's State of the Air 2010 report, researchers from Harvard University5 recently "tripled the estimated risk of premature death [from particle pollution] following a review of the newer evidence from fine particle monitors in 27 U.S. cities."6 The American Lung Association also noted that the California Air Resources Board estimated annual deaths from particle pollution, just in California, to be in the range of 5,600 to 32,000, representing a tripling of their previous estimate. The study evaluated changes in residents' life expectancy and air pollution in 51 U.S. cities from 1980 - 2000. The researchers found that every 10 mg/m3 reduction in particulate pollution yielded life expectancy increases of approximately seven months. This study demonstrates that actions to reduce particulate pollution have already yielded measurable improvements in Americans' health and will continue to do so.  [EPA-HQ-OAR-2009-0491-2834.1 p.3]
As it stands, the emission limits in the proposed Transport Rule will make important progress in saving lives, avoiding lost work days, and preventing cases of lower and upper respiratory symptoms. However, given the statutory mandate to carry out the prohibition on interstate air pollution in accordance with the requirement to attain the NAAQS "as expeditiously as practicable" as well as the serious health impacts of SO2 and NOx emissions, strengthened standards to further protect public health are imperative.  [EPA-HQ-OAR-2009-0491-2834.1 p.4]
[These comments were also submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.75-76.]
b. The substantial economic burden of SO2 and NOx emissions demonstrates the need for stronger standards.
The economic burden of the health impacts from SO2 and NOx is substantial. Work loss days attributable to all emissions from eastern power plants cost approximately $392 million in 2009. The 18 million cases of acute respiratory symptoms cost over $1 billion in 2009. The 16,600 nationwide cases of chronic bronchitis cost an estimated $8.2 billion in 2009. The technical analysis prepared for EDF indicates that the total monetized health harms associated with today's pollution levels from eastern power plants exceed $200 billion annually and could be as much as $500 billion annually (see Table 2 below). Mortality effects constitute the bulk of the cost of emissions. As stated above, there is a range of estimates for the mortality effects of particulate matter and the Pope et al. estimate is at the lower end of the range. For this reason, EDF believes it is appropriate to look at a range of economic impacts that reflect a more fulsome examination of the serious health risks reflected in the body of scientific research.  [EPA-HQ-OAR-2009-0491-2834.1 p.4]
[[Table here]]
The proposed Transport Rule would make headway in reducing these damages, but further emission reductions are achievable and necessary to help attain the NAAQS, including the 8-hour ozone NAAQS promulgated in March 2008, "as expeditiously as practicable," and secure further health and costs savings. EPA's own analysis indicates that the benefits of reducing SO2 and NOx emissions outweigh the costs of providing the reductions by at least 40:1 and potentially by over 100:1. Furthermore, EPA's health benefit estimate of $120 - 290 billion is for 2014; the emission reduction requirements for 2012 exceed those required for 2014 and EPA anticipates that the total benefits in 2012 will exceed those in 2014.8  [EPA-HQ-OAR-2009-0491-2834.1 p.5]
The economic benefit of reducing these emissions vastly outweighs the cost, both in total and marginal terms.
:: Experience with the Clean Air Act provides a real-world demonstration of the net benefits available from regulating air pollutants such as SO2 and NOx. The estimated net benefits of the 1990 Clean Air Act run into the trillions of dollars, while the benefit-cost ratio is more than 30 to 1.9.  [EPA-HQ-OAR-2009-0491-2834.1 p.5]
:: Peer-reviewed work in the economics literature estimates marginal benefits of reducing SO2 and NOx emissions that outweigh the marginal costs estimated by EPA for the proposed Transport Rule. In a 2004 study conducted in the context of the Clean Air Interstate Rule, researchers at Resources for the Future estimated marginal benefits of $2,180 to $5,690 per ton of SO2 and $850 to $1,450 per ton of NOx reductions.10 These figures are significantly larger than EPA's estimated marginal costs of $300 to $1,100 for SO2 and $500 for NOx.11  [EPA-HQ-OAR-2009-0491-2834.1 p.5]
:: Finally, EPA's Regulatory Impact Analysis (RIA) for the proposed Transport Rule shows that requiring deeper reductions than those proposed would yield significant net benefits. Specifically, EPA estimates additional benefits of $2 to $7 billion, but an increase in costs of only $0.2 billion ($200 million). The additional SO2 reductions required in the more stringent scenario as compared to the Proposed Rule are 200,000 tons. This implies that on a per-ton basis, the incremental benefits ($10,000 to $35,000 per ton) outweigh the incremental costs ($1,000 per ton) (or that marginal benefits are greater than marginal costs in the Proposed Rule). This is strong evidence that increasing the stringency of the program would result in increased net benefits.  [EPA-HQ-OAR-2009-0491-2834.1 p.5]
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.75.]
EDF technical analysis on health effects attributable to emissions of SO2 and NOX demonstrates the need for Health Protective Standards. Independent technical analysis prepared for EDF used 2009 facility specific emissions data for electricity generating facilities and from EPA's Clean Air Markets Data and Maps website. The analysis estimates that the SO2 and NOX emissions discharged from eastern power plants are associated with 23,000 to 60,000 deaths, 3.1 million lost work days, 800,000 cases of lower and upper respiratory symptoms and over 18 million cases of acute respiratory symptoms each year.
Response: 
EPA agrees that the estimated human health benefits of the proposed Transport Rule are substantial, and that reductions in NOx and SO2 will be beneficial to states as they demonstrate attainment with the National Ambient Air Quality Standards for these two criteria pollutants. 
Organization: Exelon
Comment: 
Exelon
EPA estimates that implementation of the proposed Transport Rule will provide  between $120 and $290 billion in healthcare cost savings and other benefits in 2014 by reducing the incidence and severity of air pollution-related disease. As reflected in the report of Dr. Charles J. Cicchetti, titled The True Cost of Harmful Pollution to Downwind Families and Business (attached hereto as Exhibit 2 [See p. Exh- p.1 of this comment summary]), EPA's cost benefit analysis likely understates the benefits of implementing the proposed Transport Rule and overstates the likely costs to industry. Even the most conservative estimates of the health benefits of the Transport Rule dwarf the costs of compliance for the regulated community. [EPA-HQ-OAR-2009-0491-2666.1, p.3; see pp.3-5 for additional comments pertaining to impact of proposed Transport Rule on human health]
[This comment was also submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.35.]
THE COSTS TO PUBLIC HEALTH AND THE ENVIRONMENT OF POOR AIR QUALITY FAR OUTWEIGH THE COSTS ASSOCIATED WITH POLLUTION CONTROL.
EPA HAS USED APPROPRIATE AND CONSERVATIVE METHODSFOR DETERMINING COSTS AND BENEFITS, WHICH LIKELY UNDERSTATE THE BENEFITS AND OVERSTATE THE COSTS.
Exelon strongly supports EPA's efforts to enhance the quality of life of all citizens by tightening emissions limitations in the states subject to the Transport Rule. The focus of EPA and public policy makers needs to be on maximizing the benefit to public health and the environment, not on minimizing the capital costs imposed on industry. This is particularly true in the case of the Transport Rule, which is intended to address ongoing interference with the attainment of health-based air quality standards. [EPA-HQ-OAR-2009-0491-2666.1, p.12]
As established in the Regulatory Impact Analysis ("RIA") for the proposed Transport Rule, the benefits of the Transport Rule compared to the costs are staggering. Using a 3% discount rate, EPA estimates that in 2014, the public health benefits of the Transport Rule will be between $118 and $288 billion, which dwarfs the estimated private industry compliance costs of $3.7 billion in 2012 and $2.8 billion in 2014. The significant health benefits attributable to the Transport Rule include avoiding approximately 14,000 to 36,000 premature deaths, 22,000 non-fatal heart attacks, 11,000 hospitalizations for respiratory and cardiovascular diseases, 1.8 million lost work days, 100,000 school absences and 10 million days of restricted activity. While the Transport Rule is also believed to contribute to ancillary welfare benefits (i.e., visibility improvements), the true driver of public benefit is health. With such tremendous, tangible benefits to public health, the comparatively small projected private and social costs of the Transport Rule are well worth the price. [EPA-HQ-OAR-2009-0491-2666.1, p.13-14]
As reflected in Dr. Cicchetti's report, the assumptions and methodology that EPA used were appropriate. Moreover, the analysis understated the benefits of the Transport Rule and likely overstated its costs. As described by Dr. Cicchetti, the health-related economic impact from air pollution imposes a multi-billion dollar burden on the Chicago and Philadelphia economies served by Exelon. In contrast, Exelon's analysis of the impacts of the proposed Transport Rule on system reliability has shown that, among other things, EPA's original analysis overstated the cost of switching from high pollution coal to lower pollution gas-fired unit and, therefore, overstated the costs of compliance, as reflected in Comment 4, below. [EPA-HQ-OAR-2009-0491-2666.1, p.14]
Response: 
EPA agrees that the estimated human health benefits of the proposed Transport Rule are substantial and that its methods for assessing the monetized benefits and health impacts of air pollution reductions reflect the current state of the science.
Organization: Fond du Lac Reservation
National Tribal Air Association (NTAA)
Comment: 
Fond du Lac Environmental Program
Benefits Analysis
By failing to include Indian tribes in the above technical analysis, the EPA ends up making false claims about how the Rule will benefit the health and welfare of such tribes. Specifically, the Agency claims that the vast majority of communities in areas covered by the Rule, which includes tribal communities, will see significant improvements in air quality and resulting improvements in health. The problem is that according to the EPA, the Rule does not include tribes nor does it have any direct implications to them. As such, the Agency cannot justifiably make any claims, positive or negative, with respect to tribes in relation to the Rule. [EPA-HQ-OAR-2009-0491-3707, p.3]
Before it can claim any benefits accruable to Indian tribes as a result of the Transport Rule, the Band recommends that the EPA conduct a benefits analysis which fully assesses the Rule 's impacts on tribal air quality and health. In addition, the Agency should conduct a risk assessment that considers the cultural and subsistence lifestyles of such tribes and the impact of the Rule's implementation on these lifestyles. This recommendation is also not unreasonable considering that air pollution knows no boundaries and tribes are often the tailpipe of upwind emissions generated on state lands. [EPA-HQ-OAR-2009-0491-3707, p.3]
National Tribal Air Association (NTAA)
Benefits Analysis
By failing to include Indian Tribes in the above technical analysis, the EPA ends up making a false claim about how the Rule will benefit the health and welfare of such Tribes. Specifically, the Agency claims that the vast majority of communities in areas covered by the Rule, which includes Tribal communities, will see significant improvements in air quality and resulting improvements in health. The problem is that according to the EPA, the Rule does not include Tribes nor does it have any direct implications to them. As such, the Agency cannot justifiably make any claims, positive or negative, with respect to Tribes in relation to the Rule. [EPA-HQ-OAR-2009-0491-2778.1, p.3]
Before it can claim any benefits accruable to Indian Tribes as a result of the Transport Rule, the NTAA recommends that the EPA conduct a benefits analysis which fully assesses the Rule's impacts on Tribal air quality and health. In addition, the Agency should conduct a risk assessment that considers the cultural and subsistence lifestyles of such Tribes and the impact of/he Rule's implementation on these lifestyles. Our organization's recommendation is also not unreasonable considering that air pollution knows no boundaries and Tribes are often the tailpipe of upwind emissions generated on state lands. [EPA-HQ-OAR-2009-0491-2778.1, p.3]
Response: 
EPA assessed the health and welfare benefits of improvements in PM2.5 and ozone air quality due to the proposed Transport Rule within the Continental U.S., including areas of Indian  country.
Organization: George Washington University Regulatory Study Center
Comment: 
George Washington University Regulatory Study Center
D. Valuation of Premature Mortality  
In its RIA, EPA reports that reductions in the risk of premature mortality account for 85 to 95 percent of total monetized benefits. The value placed on the reduction in mortality risks is, therefore, also a potentially important source of uncertainty in the benefits analysis. EPA uses a central estimate of $630 per 1/10,000 change in the risk of premature mortality based on a Weibull distribution fitted to 26 published estimates. [EPA-HQ-OAR-2009-0491-2573.1,pp.29-30]
EPA's estimate for the value of a reduction in the risk of premature mortality was developed in the 1990's based on a literature available circa 1990. Most of the studies underlying EPA's estimate are based on hedonic wage studies (i.e., labor market studies) -- 21 of the 26 studies are hedonic wage studies and the remaining 5 are stated preference studies. There has been a substantial expansion of this literature since 1990. There are other, more recent studies providing combined estimates across studies for this literature, including $200 per 1/10,000 (Mrozek and Taylor [2002]), $540 per 1/10,000 (Kochi, et al.[2006]), and $730 per 1/10,000 (Viscusi and Aldy [2003]) (see Table 2). There is also a better understanding of the differences and shortcomings of the hedonic wage approach versus stated preference approaches. Stated preference studies yield lower estimates for the reduction in premature mortality risk. From their analysis combining estimates from across studies, Kochi, et al. report a mean value for stated preference studies of $280 per 1/10,000 change in risk while the mean value for hedonic wage studies is $960 per 1/10,000. Use of the stated preference estimate from Kochi, et al. (2006) as arguably the preferred approach would reduce estimated benefits by a factor of two relative to EPA's current estimate.72 [EPA-HQ-OAR-2009-0491-2573.1,p.30]
Another difference in the valuation of mortality risk is whether to adjust valuation to reflect differences in age across the affected population. This difference is important in the context of the Transport Rule because most of the mortality associated with exposure to fine PM occurs in the population over 65 years in age. EPA's approach places the same value on mortality risks for all ages. In their recent AER article, Muller and Mendelsohn (2009) adopted a "base case" estimate of $200 per 1/10,000 reduction in premature mortality risk to reflect differences in  the remaining years of life expectancy. This approach would reduce estimated benefits by a factor of three as compared to EPA's current estimate. [EPA-HQ-OAR-2009-0491-2573.1,pp.30-31]
E. Summary for EPA's Health Benefits Analysis  
Depending on model choice, then, health benefits estimates for the Transport Rule could be overstated by an order of magnitude. To the extent that EPA presents a quantitative treatment of uncertainty in its RIA, the analysis focuses on the concentration-response relationship and largely fails to address the uncertainty associated with other key elements in the benefits analysis, such as the estimated change in emissions and exposure, including air quality modeling. EPA should develop a more comprehensive quantitative uncertainty analysis that covers the major sources of uncertainty in its estimates. Doing so would provide a better characterization of the EPA estimates and their uncertainty and provide a greater confidence in EPA's benefits analysis. [EPA-HQ-OAR-2009-0491-2573.1,p.31]

72 There are a variety of reasons for systematic differences in estimates form hedonic wage (HW) and stated preference (contingent valuation or choice experiment) studies (SP). These SP studies address different risks and populations; HW studies address an accident risk-wage tradeoff in the labor market, which means generally healthy working age adults, while SP studies address a wide variety of health and accident risks to the general population or subpopulations particularly at risk, such as the elderly from air pollution. The potential sources of bias also differ -- measurement errors and omitted variables may introduce bias for HW studies while SP studies may be subject to hypothetical bias. Stated preference methods may provide the researcher greater control than HW studies by allowing the researcher to control the context for respondents and to use tests, like "scope" tests, to test the validity of responses and debriefing questions to test for understanding of information and acceptance of the scenario. Finally, there is an extensive stated preference literature now available -- as compared to the studies available in the early 1990's when EPA's estimate was developed -- providing estimates of the value for small reductions in premature mortality risks. On balance, an estimate based on stated preference studies would be preferred for benefit transfer for the Transport Rule because these studies better represent the affected populations and risks and avoid the measurement and omitted variable issues associated with HW studies.
Response: 
EPA's current approach to estimating the economic value of changes in premature mortality risk has been reviewed by several Science Advisory Boards (SAB), most recently in the context of the section 812 cost-benefit analysis of the Clean Air Act Amendments of 1990. The EPA Office of Policy recently requested an EPA SAB review of its white paper "Valuing Mortality Risk Reductions for Environmental Policy." This paper assesses the Agency's approach to valuing changes in mortality risk based on hedonic wage and stated preference studies and solicits the SAB's recommendations on changes to the Agency's methods for valuing mortality risk. Consistent with advice received from previous SAB panels, EPA applies a constant value to all populations experiencing a change in risk of premature mortality, irrespective of age.  
Organization: Gomez, Rose
Comment: 
Gomez, Rose
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.86-87.]
For example, 14,000 to 36,000 premature deaths, 21,000 cases of bronchitis.
And we can go on, 23,000 nonfatal heart attacks, 26,000 hospital and emergency room visits.
Besides the benefits that we would incur, it's the right thing to do, and there is no cost that could make up the possibility of not worrying about having to breathe dirty air.
There is nothing that surpasses the benefits of being able to breathe clean air.
Response: 
As described in section VI.A of the final Transport Rule preamble, EPA believes that it is appropriate to consider both cost and air quality metrics when quantifying each state's significant contribution.  For example, considering cost takes into account the extent to which existing plants are already controlled as well as the potential for, and relative difficulty of, additional emission reductions.  The appropriateness of considering costs when quantifying significant contribution was supported by the D.C. Circuit Court determination Michigan, 213 F.3d at 679.
Organization: Green America
Pennsylvania Department of Environmental Protection
Sierra Club, Arkansas, Little Rock Office
Sierra Club, Oklahoma Chapter
Clean Air Council
St. Louis University
National Resources Defense Council (NRDC)
American Lung Association
Sierra Club
Jones, Tiffini Eugene
Geogians for Smart Energy Coalition
Mellinger-Birdsong, Anne
Clean Air Task Force
Adkins, Frederick
Conover, Barbara
Cummings, Katherine
Locker, Robert
Ritz, Aaron
Chung, Dr. Esther K.
Bucic, Sarah
Comment: 
Adkins, Frederick
The proposed rule will produce at least $100 billion, and possibly up to $290 billion, in public health savings, and it will prevent at least 23,000 heart attacks, 26,000 hospital visits and 240,000 asthma attacks, according to EPA estimates. In contrast, delaying action could result in up to 36,000 deaths related to dirty air. Like the highly successful acid rain program, the rule sets final clean air requirements but gives coal plants flexible options to achieve those requirements. The areas with the most cleanup to do will also realize significant benefits so that no state will bear an unfair burden. [EPA-HQ-OAR-2009-0491-0596, p.3]
American Lung Association
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.60-61.]
In 2014, the Rule as proposed will decrease sulfur dioxide pollution by 72 percent and nitrogen oxide pollution by 52 percent.
Here are just a few of the ways those reductions will benefit public health:
14,000 to 36,000 lives saved each year. 23,000 heart attacks avoided each year. 26,000 visits or admissions to the emergency room avoided each year. And children will have 230,000 fewer asthma attacks each year.
Let me emphasize. I say each year.
These benefits repeat over and over again year after year.
Just taking the proposed rule as is, the benefits far outweigh the costs, as EPA estimates for both show.
By 2014, the benefits of the lives saved as well as the benefits of the medical care avoided, days not missed at work and school, total between 120 and $290 billion a year.
By contrast, annual costs in 2014 will be many times less. Estimated to be $2.8 billion per year.
That makes the benefits more than 40 to over 100 times greater than the cost.
In fact, with benefit-cost ratios like that, EPA can and should require even more reductions.
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.10.]
As proposed, this rule will save between 14,000 and 36,000 lives each year. The reductions are projected to prevent 23,000 non-fatal heart attacks and 240,000 asthma attacks in children each year.
Bucic, Sarah
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.203.]
The emission reductions from this proposed rule would lead to significant annual health benefits. In 2014, this rule would protect public health by avoiding 14,000 to 36,000 premature deaths, 21,000 cases of acute bronchitis, 23,000 nonfatal heart attacks, 26,000 hospital and emergency room visits, 1.9 million days when people miss work or school, 240,000 cases of aggravated asthma, and 440,000 upper and lower respiratory symptoms.
Chung, Dr. Esther K.
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.187.]
The Transport rule would result in $290 billion in annual cost savings related to health. There would be an estimated fewer 240,000 cases of asthma attacks and 1.9 million fewer days of missed work and school.
By reducing air pollution from coal-burning plants, the Transport Rule will result in reductions in associated diseases, including asthma, chronic obstructive pulmonary disease or COPD, lung cancer, cardiac arrhythmias, congestive heart failure, heart attacks and stroke. With growing evidence to show that coal emissions are associated with higher rates of infant mortality and congenital heart defects, including ventricular sepal defects, we can impact poor health outcomes even among newborns and infants.
Clean Air Council
The effect of full implementation of the Rule will be stunning: reputable analysis relied upon by EPA indicates 14,000-36,000 lives will be saved annually by the pollution reductions from this rule. (75 FR 45346) Thousands of Pennsylvanians will no longer face premature death from air pollution exposure, and tens of thousands will be spared serious non-fatal health impacts. [EPA-HQ-OAR-2009-0491-2804.1, p.1]
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.42-43.]
By EPA's own estimates this proposed rule will result in $120 to $290 billion dollars in benefits for a program that will cost industry, according to the EPA, about 2.8 billion dollars. The benefits we are talking about are mostly public health related. That is, the benefit is in reduced human suffering.
I want to be clear. To most of us, EPA's Transport Rule is not about protecting visibility in public parks. That is important, but to most of us, it is about protecting public health.
Always remember that this rule is about public health, when you are subjected to the anguished cries from those utilities that have refused to invest in modern pollution controls, as Exelon already has done, and are now complaining of the costs or the short compliance time.
Clean Air Task Force
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.106.]
EPAs analysis also shows that the proposed rule will reduce thousands of premature deaths and will provide benefits of at least 50 times costs. A stronger rule could save many more lives and provide far more benefits.
Conover, Barbara
By your own scientist's calculations, this rule will prevent: 14,000 to 36,000 premature deaths, 21,000 cases of acute bronchitis, 23,000 nonfatal heart attacks, 26,000 hospital and emergency room visits, 1.9 million days when people miss work or school, 240,000 cases of aggravated asthma, and 440,000 cases of upper and lower respiratory symptoms. This is your mandate: not capitulating to industry's desires of short-term profits. [EPA-HQ-OAR-2009-0491-0917, p.2]
Cummings, Katherine
Cleaning up dirty power plants is essential to protect health, since the particle pollution and ozone smog they produce can kill. The new EPA rule will require companies to install modern pollution control technology to reduce harmful pollutants caused by coal power plants. Specifically by 2014 the new EPA rule will have enormous public health benefits. The reduced pollution will:
:: Save 14,000  -  36,000 lives each year
:: Prevent 26,000 hospital and ER admissions each year
:: Prevent 240,000 asthma attacks each year [EPA-HQ-OAR-2009-0491-0968, p.2]
Geogians for Smart Energy Coalition
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.63.]
The new EPA rule would have enormous public health benefits and the reduced pollution would save 36,000 lives each year and prevent 26,000 hospital admissions and ER visits every year.
The benefits of cleaning up these pollutants, especially the public health benefits, far outweigh the costs and by 2014, the annual benefits will be between 42 to 103 times greater than the cost according to your estimates. Any parent will tell you that this is a small price to pay to insure that children can get exercise and happily run across a soccer field or a backyard and are protected from health risks as a result of the dangerous coal plant pollutants.
Green America
As the EPA pointed in your Transport Rule presentation, this new rule would provide significant health benefits for Americans, as well as help to minimize possible costs. The possible prevention of 14,000 to 36,000 premature deaths, as well as the prevention of 21,000 cases of bronchitis, 23,000 non-fatal heart attacks, 440,000 cases of respiratory symptoms, and 240,000 cases of aggravated asthma, provides enough reason alone to approve the new Transport rule. In addition, the estimation that the new rule would provide up to $290 billion in public health benefits, with only $2.8 billion in compliance costs, demonstrates that approving this rule is the correct action to take. [EPA-HQ-OAR-2009-0491-2611, p.3]
Jones, Tiffini Eugene
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.28-29.]
The Transport Rule is important because millions of people continue to breathe unhealthy air that does not meet our National Ambient Air Quality Standards. More emissions reductions are needed to protect public health and the environment from air pollution.
It is estimated by the EPA that in 2014 11 million cases or days of restricted recreational activity can be avoided with the proposed implementation rule, 1.9 million days of missed work and school can be avoided, and 440,000 cases avoided of upper and lower respiratory symptoms.
Notably, since the proposed rule expedites installation of pollution controls in 2012 that were formerly happening by 2014, the benefits of the Transport Rule in 2012 are actually even greater at the outset of the program.
The proposed rule will yield more than 120 to 290 billion in annual health and welfare benefits in 2014. This far outweighs the estimated annual costs of $2.8 billion.
Locker, Robert
The proposed rule will produce at least $100 billion, and possibly up to $290 billion, in public health savings, and it will prevent at least 23,000 heart attacks, 26,000 hospital visits and 240,000 asthma attacks, according to EPA estimates. I would like to know that the CDC's position is in tune with prevailing science. Though I am not sure, I believe 'We The People' there [EPA-HQ-OAR-2009-0491-1050, p.2]
In contrast, delaying action could result in up to 36,000 deaths related to dirty air. Like the highly successful acid rain program, the rule sets final clean air requirements but gives coal plants flexible options to achieve those requirements. The areas with the most cleanup to do will also realize significant benefits so that no state will bear an unfair burden. [EPA-HQ-OAR-2009-0491-1050, p.2]
Mellinger-Birdsong, Anne
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.74.]
Estimates of the benefits of the proposed Transport Rule are that it would prevent about 25,000 premature deaths every year with a range of 14 to 36,000, prevent about 26,000 hospital and ER admissions every year, and prevent about 240,000 asthma exacerbations every year.
There is also the indirect benefits of fewer work days missed, fewer school absences, and increased learning and productivity from people who are not sick.
National Resources Defense Council (NRDC)
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.40-41.]
First, EPA's Transport Rule is necessary because air quality in coal plant emissions contributes to tens of thousands of premature deaths each year, and states such as Illinois cannot accomplish the needed improvements in air quality acting alone.
Pollution emitted from coal-fired power plants, including sulfur dioxide and nitrogen oxide contributes to a wide range of human health impacts, including respiratory illness, bronchitis, heart attacks, asthma attacks and premature death.
Based on the number of studies EPA has projected that the proposed Transport Rule will reduce premature mortality annually by 14,000 to 36,000, as well as preventing approximately 26,000 hospital admissions and emergency room visits and 240,000 asthma attacks each year.
Pennsylvania Department of Environmental Protection
Transported ozone and PM2.5 precursor emissions endanger the health of the Commonwealth's citizens, particularly the very young and elderly, and cause lung damage, respiratory illness, and premature mortality. Based on the DEP analysis, the proposed Transport Rule would reduce SO2 emissions from EGUs in Pennsylvania by approximately 84 percent from 2005 levels; annual NOx emissions would be reduced by an estimated 40 percent from 2005 levels. The estimated emission reductions under the proposed Transport Rule would annually result in significant improvements in the public health and welfare of the citizens of Pennsylvania, when fully implemented in 2014. [EPA-HQ-OAR-2009-0491-2660.1, p.2]
The DEP commends EPA for the substantial ozone and PM2.5 health-related benefits expected in Pennsylvania and other states as a result of the Transport Rule. In particular, the residents of Pennsylvania would benefit substantially from the reduced transport of precursor emissions from sources in upwind areas. By 2014, EPA projects that 1,400 to 3,600 PM2.5-related premature mortalities would be avoided in Pennsylvania; other health benefits include lower rates of heart attacks, bronchitis, aggravated asthma, and other respiratory symptoms. In this Commonwealth, the estimated health-related cost savings would be between $12 billion and $29 billion dollars annually. In the final TR and supporting documentation, EPA should provide state-by-state breakdowns of the health benefits so that states and the general public fully understand the magnitude of the individual health benefits that will be provided in the final rule. Overall, the Transport Rule is expected to yield more than $122 to $294 billion in annual health and welfare benefits in 2014. At an estimated compliance cost of $2.8 billion, the benefits-to-cost ratio range from 44-to-1 up to 100-to-1-clearly, the benefits of the rule would greatly exceed the incremental compliance costs. [EPA-HQ-OAR-2009-0491-2660.1, p.2]
Ritz, Aaron
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.174-175.]
The rule will produce at least $100 billion dollars, and possibly up to $290 billion, in public health savings. The Good Neighbor rule will prevent at least 23,000 heart attacks, 26,000 hospital visits and 240,000 asthma attacks, according to EPA estimates.
These health benefits translate not only to a better quality of life, but to hard savings of $120 to $290 billion. A delay in action could result in up to 36,000 deaths related to dirty air.
Sierra Club
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.83-84.]
EPA projects that without this 'good neighbor' rule air pollution from power plants would result in 14 to 36,000 additional deaths.
Savings in health costs are estimated to be between 100 to $250 billion.
The cost for implementing is a mere fraction of the savings. Every dollar that is spent on cleaning up, retiring, repowering or replacing coal plants has a direct benefit for human health.
Coal plants emit millions of tons of air pollutants each year that cause serious health problems.
The pollution does not stop at the state line. This is a national problem that needs national attention.
It is time that coal plants in 31 states clean up their act. It is the right thing to do. It is the necessary thing to do. It will protect the health and welfare of millions of people, and there's a cost-effective way to achieve true pollution reduction.
Sierra Club, Arkansas, Little Rock Office
It is comforting to know that the Air Pollution Transport Rule will produce at least $100 billion dollars and possibly more in public health savings, and consumers will see very little increase on their energy bills. Since currently millions of people breathe air that doesn't meet basic clean air standards it is encouraging to know that the rule will lead to a better quality of life along with health savings. Preventing at least 23,000 heart attacks, 26,000 hospital visits and 240,000 asthma attacks, is something I can stand behind. The health of Oklahoma communities is a top priority. [EPA-HQ-OAR-2009-0491-2853, p.2]
Sierra Club, Oklahoma Chapter
It is comforting to know that the Air Pollution Transport Rule will produce at least $100 billion dollars and possibly more in public health savings, and consumers will see very little increase on their energy bills. Since currently millions of people breathe air that doesn't meet basic clean air standards it is encouraging to know that the rule will lead to a better quality of life along with health savings. Preventing at least 23,000 heart attacks, 26,000 hospital visits and 240,000 asthma attacks, is something we can stand behind. The health of Oklahoma communities is a top priority. [EPA-HQ-OAR-2009-0491-2792, p.1]
St. Louis University
I live in a city with some of the worst air quality and highest rates of childhood asthma in the country. I see and feel the consequences air pollution resulting from transportation everyday and thus I strongly support the proposed clean air plan to cut sulfur dioxide and oxides of nitrogen from eastern smokestacks. And I urge the EPA to strengthen its standards to secure greater health and environmental benefits. [EPA-HQ-OAR-2009-0491-3604, p.1]
Your proposed rules to cut pollution from fossil fuel-fired power plants would reduce power plant sulfur dioxide (SO2) emissions by 71% from 2005 levels and nitrogen oxide (NOx) by 52% from 2005 levels. [EPA-HQ-OAR-2009-0491-3604, p.1]
EPA's plan to clean up this smokestack pollution would protect public health by avoiding:
14,000 to 36,000 premature deaths,
21,000 cases of acute bronchitis,
23,000 nonfatal heart attacks,
26,000 hospital and emergency room visits,
1.9 million days when people miss work or school,
240,000 cases of aggravated asthma, and
440,000 upper and lower respiratory symptoms.
And EPA's Rule would yield benefits of more than $120 to $290 billion annually in 2014, compared to the estimated annual costs of $2.8 billion. [EPA-HQ-OAR-2009-0491-3604, p.1]
Response: 
EPA agrees that the estimated human health benefits of the proposed Transport Rule are substantial, and that the monetized benefits outweigh the costs by a significant margin.  
Organization: Mass Comment Campaign (38) (unknown organization)
Comment: 
Mass Comment Campaign (38) (unknown organization)
The power plant rule proposed by the agency is designed to cut deadly sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions from coal-fired power plants in 31 states. If implemented as proposed, it is estimated that each year these rules would save 14,000 to 36,000 lives and prevent 240,000 asthma attacks and 26,000 hospital and emergency room admissions. [EPA-HQ-OAR-2009-0491-3616_Mass, p.1]
Response: 
EPA agrees that the Transport Rule will improve air quality and provide significant public health benefits in the form of avoided premature deaths, asthma attacks and hospital and emergency room visits. 
Organization: Province of Ontario, Canada
Comment: 
Province of Ontario, Canada
Due to the great impact on our citizens, Ontario has actively participated in the recent U.S. process to set air quality standards for ozone. First, Ontario filed formal comments with the U.S. EPA in the September 2007 Ozone NAAQS rulemaking. Second, when the previous U.S. Administration promulgated a Rule not based on science, Ontario participated as amicus curiae in support of New York and other states in State of Mississippi v. EPA, the legal challenge to the Rule filed in 2008. Third, the Honourable John Gerretsen, my predecessor, wrote to you in August 2009 and specifically requested that the U.S. EPA strengthen the Ozone NAAQS Rule. Fourth, Ontario filed formal comments on March 22, 2010 in the reconsideration of the Ozone NAAQS Rule and urged the U.S. EPA to set the primary ozone standard at a level at least as stringent as the existing Canadian standard of 0.065 ppm. [EPA-HQ-OAR-2009-0491-2610.1, p.2]
We are pleased that the new U.S. Administration is committed to a vigorous environmental and energy agenda. History demonstrates that U.S. actions to combat air pollution can have positive impacts in Ontario. As Assistant Administrator Regina McCarthy stated in her July 9,2009 remarks before the Subcommittee on Clean Air and Nuclear Safety, 'the Acid Rain Program was - and is ... protecting millions of Americans and Canadians from harmful effects of fine particles'. Similarly, U.S. EPA not.es (Federal Register at page 45351) that the proposed Transport Rule will bring substantial health and environmental benefits to Canadians. We agree, and we urge the U.S. EPA to finalize the Transport Rule and implement it without delay. [EPA-HQ-OAR-2009-0491-2610.1, p.2]
Response: 
EPA agrees that the proposed Transport Rule will yield substantial air quality and human health benefits to populations both within the U.S. and those located near the U.S.-Canadian border.
Organization: Sierra Club, Pennsylvania Chapter
Comment: 
Sierra Club, Pennsylvania Chapter
Specifically by 2014 the new EPA rule will have enormous public health benefits. The reduced pollution will:
:: Save 14,000  -  36,000 lives each year. [EPA-HQ-OAR-2009-0491-3482.1, p.5]
:: Prevent 26,000 hospital and ER admissions each year
:: Prevent 240,000 asthma attacks each year [EPA-HQ-OAR-2009-0491-3482.1, p.6]
The benefits of cleaning up these pollutants -- especially the public health benefits -- far outweigh the costs. By 2014, the annual benefits will be between 42 to 103 times greater than the costs. EPA estimates the annual benefits at $120 to $290 billion, while the annual compliance costs are $2.8 billion, using 2006 dollars. The benefits include thousands of lives saved. [EPA-HQ-OAR-2009-0491-3482.1, p.6]
By 2014, the rule will decrease sulfur dioxide pollution by 72 percent and nitrogen oxide pollution by 52 percent. These two particles bypass the human body's natural defenses and can lodge deep within the lungs, causing harm to human health. [EPA-HQ-OAR-2009-0491-3482.1, p.6]
However, EPA can and should do even more. EPA should set a much tighter national limit on sulfur dioxide and nitrogen dioxide emissions, requiring even greater clean up with proven control technology that is widely available and effective. The investment in maximizing clean up will give us greater benefits, including more lives saved each year, especially those who are part of our most vulnerable populations. [EPA-HQ-OAR-2009-0491-3482.1, p.6]
An interesting and related development in medical research released on August 23, 2010 illustrates why we need these reductions. This study describes work done in Vienna Austria surrounding ozone smog and seasonal allergies. This research supports the urgency of our efforts to reduce coal fired power plant pollution, and illustrates its connection to changes in climate that we see today. Press release, "Aug 23, 2010  -  Ozone affects pollen allergens: at ozone levels typical of photochemical smog, more allergens are formed in pollen. This connection has been demonstrated in the rye plant and is now being published in the prestigious Journal of Allergy Clinical Immunology. The project funded by the Austrian Science Fund FWF shows that elevated ozone levels during maturation increase the protein and allergen contents of rye pollen. This points to a relationship between current environmental problems due to climate change and the rise in allergies. [EPA-HQ-OAR-2009-0491-3482.1, p.6]
It's on everyone's lips, especially during the summer months when photochemical smog engulfs the world's cities. Environmental pollution and climate change both contribute to the increasingly frequent incidences observed. While this is a major health problem in itself, there are now indications that elevated ozone levels also raise the allergen content of pollen. The team from the Medical University of Vienna and the Austrian Institute of Technology have investigated the reasons for this phenomenon." [EPA-HQ-OAR-2009-0491-3482.1, pp.6-7]
Response: 
EPA agrees that the proposed Transport Rule will yield substantial human health and welfare benefits. 

IX.C. Quantified and Monetized Visibility Benefits

Organization: Ritz, Aaron
Comment: 
Ritz, Aaron
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.175.]
Reducing air pollution will significantly improve visibility in our national parks and wilderness areas. These improved views are worth $3.4 billion in increased tourism and recreational opportunities. Sulfur dioxide and nitrogen oxides, main contributors to acid rain, will be cut by more than half under this rule.
Response: 
EPA agrees that the proposed Transport Rule will yield significant improvements to visibility in Class I areas.

IX.D. [Reserved]

IX.E. How Do the Benefits Compare to the Costs of This Proposed Rule?

Organization: Ameren Services Company
Comment: 
Ameren Services Company
'The proposed rule would yield more than $120 to $290 billion in annual health and welfare benefits in 2014, including the value of avoiding 14,000 to 36,000 premature deaths. This far outweighs the estimated 2014 annual costs of $2.8 billion.' [EPA-HQ-OAR-2009-0491-0083, p.1]

EPA estimates the annual benefits from the proposed rule range between $120-$290 billion (2006 $) in 2014. 

- Most of these benefits are public health-related.

- $3.4 billion are attributable to visibility improvements in areas such as national parks and wilderness areas.

- Other nonmonetized benefits include reductions in mercury contamination, acid rain, eutrophication of estuaries and coastal waters, and acidification of forest soils. [EPA-HQ-OAR-2009-0491-0083, p.1]

EPA estimates annual compliance costs at $2.8 billion in 2014.

:: Modest costs mean small effects on electricity generation. EPA estimates that in 2014:

- Electricity prices increase less than 2 percent. [Ameren has already sought and had approved a 3+% increase in its electricity rates in Missouri alone during 2010 based on 2008-09 added costs!]

- Natural gas prices increase less than 1 percent. [ Ditto here: I believe the 1% increase is totally unrealistic ]

- Coal use is reduced by less than 1 percent.' [EPA-HQ-OAR-2009-0491-0083, p.1]

The emissions reductions from this proposed rule would lead to significant annual health benefits. In 2014, this rule would protect public health by avoiding:

:: 14,000 to 36,000 premature deaths,

:: 21,000 cases of acute bronchitis,

:: 23,000 nonfatal heart attacks,

:: 26,000 hospital and emergency room visits,

:: 1.9 million days when people miss work or school,

:: 240,000 cases of aggravated asthma, and

:: 440,000 cases of upper and lower respiratory symptoms. [EPA-HQ-OAR-2009-0491-0083, p.1]

On what basis and upon what supportive detail was this savings and the detailed benefits (fewer premature deaths, heart attacks, missed school/work days, etc.) derived? I see pg. 14 of your 'Overview presentation' listing the no. of cases of each health effect but don't see how these numbers were derived and linked to SO2 or NOX generated from power plants (?). Does the EPA have detailed documentation to share to support this claim and if so, how can the citizenry obtain a copy? [EPA-HQ-OAR-2009-0491-0083, p.2]
Response: 
The Regulatory Impact Analysis for the proposed Transport Rule details the methods and results of the human health benefits analysis for this rule. The RIA may be found at: http://www.epa.gov/ttn/ecas/regdata/RIAs/proposaltrria_final.pdf
Organization: American Lung Association
Comment: 
American Lung Association
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.10]
This rule will also help the economy. For example, it will keep workers on the job and children in school for the 1.9 million days a year that they would have missed because of illness. But imagine the lives saved, the families protected, the economic benefits if we stopped even more pollution.  
The benefits of this rule far outweigh the costs. EPA's estimates of the benefits range from $120 billion to $290 billion in 2014. EPA estimates that the annual cost of securing those benefits is $2.8 billion. That means the benefits outweigh the cost by over 40 to 100 to one. With the benefits so high, EPA can and should set tighter limits on power plant emissions. 
Response: 
EPA agrees that the estimated health benefits of the proposed Transport Rule are substantial and that the benefit-cost ratio is very favorable. 
Organization: Clean Energy Group
Nederhand, Frank
Cummings, Katherine
Gardner, Robert
Ritz, Aaron
Bucic, Sarah
Greater Philadelphia Chamber of Commerce
Comment: 
Bucic, Sarah
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.203.]
This proposed rule would yield more than $120 to $290 billion in annual benefits in 2014. This far outweighs the estimated annual costs of $2.8 billion.
The price of reducing emissions may be high for companies, but I ask those who oppose this rule to consider the price of the health related problems that emissions cause to people's lives and the health related costs these impose on our society.
Clean Energy Group
The net economic benefits of the proposed rule are expected to be substantial and well in excess of projected costs. For example, EPA estimates the annual benefits of the proposed rule would range from $120 to $290 billion in 2014 (2006 $), with estimated costs of$3.7 billion in 2012 and $2.8 billion in 2014. The lower bound of the annual benefit estimates exceeds the estimated 2012 costs by nearly 32 times; the higher by nearly 80 times. [EPA-HQ-OAR-2009-0491-2702.1, p. 2]
Cummings, Katherine
The benefits of cleaning up these pollutants -- especially the public health benefits -- far outweigh the costs. By 2014, the annual benefits will be between 42 to 103 times greater than the costs. EPA estimates the annual benefits at $120 to $290 billion, while the annual compliance costs are $2.8 billion, using 2006 dollars. The benefits include thousands of lives saved. We can't afford NOT to do this. [EPA-HQ-OAR-2009-0491-0968, p.2]
Gardner, Robert
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.147.]
The proposed rule would yield more than $120 to $290 billion in annual health and welfare benefits in 2014, including the value of avoiding 14,000 to 36,000 premature deaths. The cost effectiveness of this pollution reduction is consistent with the record of the Clean Air Act, which has provided benefits that are 42 times greater than the estimated costs of reducing industry pollution.
Greater Philadelphia Chamber of Commerce
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.206-207.]
In this case, EPA estimates that the annual cost of compliance will be about $2.8 billion in 2014, while annual benefits will range between $120 and $290 billion in that same timeframe. Most of these benefits will be health related and could result in less lost time and increased productivity for businesses of all types. These estimates seem to strike a reasonable balance.
Nederhand, Frank
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.127.]
A few things that we talked about today were the costs of this rule. We know that the rule will produce at least $100 billion and possibly up to $290 billion dollars in public health savings. Those are the savings. So what are the costs?
The costs on rate payers for this Transport Rule would be an average of less than one percent according to the EPA analyses that I've read. This is not a major rate hike that we're talking about here. The cost of the benefits greatly outweigh the costs.
Some of the solutions to those costs that we've talked about are installing scrubbers. And, again, I would just like to state for the record that the cheapest scrubber is no scrubber at all. So by investing in energy efficiency and renewables, no scrubbers would need to be purchased by major utilities.
Ritz, Aaron
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.174.]
The areas with the most cleanup to do will also realize the most benefits so that no state will bear an unfair burden. These significant pollution reductions will cost consumers very little on their energy bills on average a dollar or two a month.
Response: 
EPA agrees that the estimated human health and welfare benefits of the proposed Transport Rule greatly outweigh the estimated costs. 
Organization: Illinois Student Environmental Coalition
National Association of Clean of Air Agencies (NACAA)
Comment: 
Illinois Student Environmental Coalition
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.74-75.]
They also want to see economic benefits from this rule. The information that has been provided by this rule shows very clear economic benefit, that whatever costs that would have to be incurred to put in these pollution controls are far outweighed by the benefits.
National Association of Clean of Air Agencies (NACAA)
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.106.]
Controlling these sources is highly cost effective. EPA's own analysis shows a 40 to 1 and up to a 100 to 1 benefit-to-cost ratio for the power plant controls in the Transport Rule.
Response: 
EPA agrees that the estimated health benefits of the proposed Transport Rule are substantial, and that the benefit-cost ratio is very favorable. 
Organization: Sierra Club, New Jersey Chapter
Comment: 
Sierra Club, New Jersey Chapter
Last but certainly not least, I am pleased that information provided in Table III.A-5 shows the results of the cost and benefits analysis for the proposed and alternate remedies, and that further discussion of these results is contained in preamble section XII-A and in the Regulatory Impacts Analysis. It is far too infrequent that people in highly developed areas of the U.S. have a chance to understand the health impacts of breathing polluted air and their personal risk of developing some type of respiratory disease such as asthma or emphysema, or heart disease. [EPA-HQ-OAR-2009-0491-3649, p.2]
Response: 
EPA agrees that the estimated health benefits of the proposed Transport Rule are substantial.

IX.F. What are the Unquantified and Unmonetized Benefits of the Transport Rule Emissions Reductions?

Organization: Citizens Campaign for the Environment (CCE)
Comment: 
Citizens Campaign for the Environment (CCE)
Benefits to Buildings The new rule will aid historic preservation by reducing acid and particulate deposition that damages cultural monuments, buildings, and other materials. [EPA-HQ-OAR-2009-0491-1937.1, p. 2]
Response: 
EPA agrees that, though not quantified in the RIA, this rule will reduce household soiling and materials damage. 

IX.F.1. What are the Benefits of Reduced Deposition of Sulfur and Nitrogen to Aquatic, Forest, and Coastal Ecosystems?

Organization: Citizens Campaign for the Environment (CCE)
Pennsylvania Department of Environmental Protection
Comment: 
Citizens Campaign for the Environment (CCE)
Ecological benefits The benefits to the ecological health of New York, Connecticut, and the entire Northeast will be very significant. The proposed rule will reduce the airborne deposition of nitrogen to watersheds, where nitrogen contributes to crop damage and eutrophication of water bodies like the Long Island Sound and Chesapeake Bay. Pollutants emitted from power plants also contribute to decreased visibility throughout different parts of the eastern United States. The rule will significantly increase visibility, including in the Great Smoky Mountains and the Adirondacks. The reductions in NOx and SO2 will significantly improve the health of our lakes and forests. Reductions in pollutants will benefit the health of sugar maple forests and significantly reduce the amount of chronically acidic lakes in the Adirondacks and throughout the Northeast. [EPA-HQ-OAR-2009-0491-1937.1, p. 2]
Pennsylvania Department of Environmental Protection
In addition to substantial reductions in ambient concentrations of ozone and PM2.5, NOx and SO2 emission reductions from EGUs in the Transport Rule region will improve visibility and reduce vegetation impairment, acidic deposition, and sulfur and nitrogen deposition to waterways, including the Chesapeake Bay. Nitrate deposition from air pollution in the Chesapeake Bay Watershed is a significant cause of the environmental damage to the Bay. According to DEP's Draft Chesapeake Bay Watershed lmplementation Plan, deposition from the out of state transport of NOx contributes 11 million pounds of nitrates to Pennsylvania's total nitrate load to the Bay. The TR would also reduce mercury methylation and greenhouse gases (GHG); CO2 emissions from EGUs would be reduced annually by approximately 15 million metric tons (75 Fed. Reg. 45,347- 45,351, August 2, 2010). [EPA-HQ-OAR-2009-0491-2660.1, p.3]
Response: 
EPA agrees that, though not quantified in this RIA, the ecological benefits attributable to the proposed Transport Rule would be significant. 

X. Economic Impacts

Organization: American Electric Power
Comment: 
American Electric Power
The Transport Rule could cause AEP and other power companies to prematurely close some coal-fired power plants in order to meet these aggressive compliance deadlines. Plant closings will throw more people out of work and could severely affect the communities in which these plants are located  -  all for little environmental gain. [EPA-HQ-OAR-2009-0491-1120, p.1]
EPA's Economic Analysis is Flawed and Deficient in Justifying the New Transport Rule
As a general matter, EPA's analysis fails to account for the impact of multiple uncoordinated rules and policies on the investment decisions being made at coal-fired power plants. As noted earlier in this statement, in addition to the proposed Transport Rule, coal-fired power plants face a yet to be determined set of additional S02 and NOx reductions to meet new ozone and fine particulate standards, future mercury and hazardous air pollutant rules, recently proposed ash disposal rules, possible water rules and of course the prospects of the regulation of greenhouse gases under either existing Clean Air Act authorities or federal climate change legislation. [EPA-HQ-OAR-2009-0491-2665.1, p.19]
Response: 
In implementing these rules, emission controls may lead to reductions in ambient PM2.5 and ozone below the National Ambient Air Quality Standards (NAAQS) for PM and ozone in some areas and assist other areas with attaining these NAAQS. Because the PM and ozone NAAQS RIAs also calculate PM and ozone benefits, there are important differences worth noting in the design and analytical objectives of each RIA. The NAAQS RIAs illustrate the potential costs and benefits of attaining a new air quality standard nationwide based on an array of emission control strategies for different sources. In short, NAAQS RIAs hypothesize, but do not predict, the control strategies that States may choose to enact when implementing a NAAQS. The setting of a NAAQS does not directly result in costs or benefits, and as such, the NAAQS RIAs are merely illustrative and are not intended to be added to the costs and benefits of other regulations that result in specific costs of control and emission reductions. However, some costs and benefits estimated in this RIA account for the same air quality improvements as estimated in the illustrative PM2.5 and ozone NAAQS RIA.
By contrast, the emission reductions for the Transport rule are from a specific class of well-characterized sources (EGUs). In general, EPA is more confident in the magnitude and location of the emission reductions for these rules. Emission reductions achieved under these and other promulgated rules, including other rules for the electric power sector, will ultimately be reflected in the baseline of future NAAQS analyses, which would reduce the incremental costs and benefits associated with attaining the NAAQS. EPA remains forward looking towards the next iteration of the 5-year review cycle for the NAAQS, and as a result does not issue updated RIAs for existing NAAQS that retroactively update the baseline for NAAQS implementation. For more information on the relationship between the NAAQS and rules such as analyzed here, please see Section 1.2.4 of the SO2 NAAQS RIA.
Organization: Calhoun, Ed
Comment: 
Calhoun, Ed
Where I work now electrical power is a major expense for our facility. I fear any additional rate increases in electrical power will drive our production to Mexico or England where we already have small facilities. We as a country cannot compete globally when similar environmental laws are not enforced. How can we continue to exist as a nation when the number of employed taxpaying citizens is reducing daily? Rome was not built in a day and the power facilities cannot become compliant to these potential new rules in a day either. I also want a clean environment for myself and my kids but I need a job also. [EPA-HQ-OAR-2009-0491-1888-cp, p.1]
Response: 
The increase in electricity rates resulting from the Transport Rule is expected to be no more than 2.5% on average nationwide in 2012 and 1.5% on average nationwide in 2014.    Allowing power companies to trade emissions allowances intrastate and interstate (with limits) will help them meet these requirements in a cost-effective fashion.  
Organization: City of Springfield, Illinois, Office of Public Utilities
Comment: 
City of Springfield, Illinois, Office of Public Utilities
CWLP will be directly affected by the proposed Transport Rule, and as a municipal utility, the costs will be directly borne by the citizens and businesses of Springfield, at an economic time when it can be least afforded, and when other (costly) USEPA rules on coal-combustion units will also be taking effect. [EPA-HQ-OAR-2009-0491-2635.1, p.1]
Another reason for CWLP's objection to the proposed Rule is that it is based upon inaccurate and dated information, including regarding the sources it seeks to limit. One concern with USEPA's reliance upon inaccurate information and assumptions is that the Rule may likely result in needless economic harm, or may penalize utilities that have already implemented significant controls, without concomitant benefit to air quality. In that regard, at the request of the Illinois Environmental Protection Agency ('Illinois EPA'), CWLP developed the attached exhibit, identifying what appears to be inaccuracies in the information on which USEPA's Transport Rule proposal is based, specific to CWLP. The exhibit ;s self-explanatory and references the source information available to USEPA on which our corrections are based. [EPA-HQ-OAR-2009-0491-2635.1, p.2]
Response: 
The Agency reviewed the attached exhibit, and considered the information in the exhibit as part of the analyses to be done for the final rule.  The Agency revised its data for CWLP as part of an extensive revision to existing data and inclusion of new unit-level data in the analytical platform utilized in the final rule.  Such revisions incorporate the information included in the CWLP exhibit, other public comments on the rule, and data offered by commenters on three different Notices of Data Availability (NODAs) that was submitted subsequent to the proposal of the Transport Rule.  Such revisions will increase the accuracy of estimates generated by the Integrated Planning Model (IPM), the model used by the Agency to analyze cost, emissions, and other impacts of remedy alternatives prepared in support of the Transport Rule.
Organization: Clean Energy Group
Comment: 
Clean Energy Group
Additionally, by removing impediments to achieving attainment in downwind areas, EPA is addressing an important economic disadvantage to industrial facilities and power plants in nonattainment areas. A nonattainment designation imposes many substantial costs, including Section 185 fees and acquiring offsets for new facilities, regardless of whether an area's nonattainment status is the result of local or transported pollution. As a result, without the provisions of the Transport Rule, the costs of operating in nonattainment areas would continue to incentivize shifting industrial production and electric generation from nonattainment areas to other regions, including those upwind areas actually generating the pollution that is contributing to the nonattainment status. [EPA-HQ-OAR-2009-0491-2702.1, p. 2]
Response: 
We thank the commenter for their comment.  The main intent of the Transport Rule is to reduce emissions from upwind areas to improve the air quality (for PM2.5 and ozone) in downwind areas where contributions of upwind to downwind areas for attainment purposes are significant.  The Transport Rule will thus have the effect of evening out differences (positively) in air quality between these areas, as is referred to in the preamble.  
Organization: Commerce Lexington Inc.
Comment: 
Commerce Lexington Inc.
Combined with other EPA regulations, the Transport Rule will likely mean the early retirement of eastern coal-fueled generation, resulting in the premature loss of jobs, and hundreds of millions of dollars in wages and taxes annually that today support communities where well-paid jobs are scarce. [EPA-HQ-OAR-2009-0491-2869.1 p.2]
Response: 
According to the Agency's analysis found in the Regulatory Impact Analysis (RIA) for the proposed Transport Rule, a relatively small amount of coal-fired capacity, about 1.2 GW (0.3% of all coal-fired capacity and 0.1 % of all generating capacity nationally), is projected to be uneconomic to maintain in 2014.  In practice units projected to be uneconomic to maintain according to the Agency's analysis may be "mothballed," retired, or kept in service to ensure transmission reliability in certain parts of the grid.  For the most part, these units are small and infrequently used generating units that are dispersed throughout the proposed Transport Rule region.  Coal production for use in the power sector is projected to decrease by 0.3 % in 2012 and by 0.8 % by 2014, and we expect greater coal production in Appalachia and the West and somewhat less production in the Interior coal regions of the country with the proposed Transport Rule.
As part of implementing rules such as the Transport Rule, emissions controls may lead to reductions in ambient PM2.5 and ozone below the National Ambient Air Quality Standards (NAAQS) for these pollutants and assist other areas in meeting these standards.  Because the PM and ozone NAAQS RIAs also calculate PM and ozone benefits, there are important differences worth noting in the design and analytical objectives of each RIA. The NAAQS RIAs illustrate the potential costs and benefits of attaining a new air quality standard nationwide based on an array of emission control strategies for different sources. In short, NAAQS RIAs hypothesize, but do not predict, the control strategies that States may choose to enact when implementing a NAAQS.
The setting of a NAAQS does not directly result in costs or benefits, and as such, the NAAQS RIAs are merely illustrative and are not intended to be added to the costs and benefits of other regulations that result in specific costs of control and emission reductions. However, some costs and benefits estimated in the Transport Rule RIA account for the same air quality improvements as estimated in the illustrative PM2.5 and ozone NAAQS RIA.
By contrast, the emission reductions for the Transport Rule are from a specific class of well-characterized sources. In general, EPA is more confident in the magnitude and location of the emission reductions for such rules and in the estimates of costs associated with the controls required to obtain these emission reductions.  Emission reductions achieved under these and other promulgated rules will ultimately be reflected in the baseline of future PM and ozone NAAQS analyses, which would reduce the incremental costs and benefits associated with attaining those NAAQS. EPA remains forward looking towards the next iteration of the 5-year review cycle for the NAAQS, and as a result does not issue updated RIAs for existing NAAQS that retroactively update the baseline (which includes all promulgated rules and other finalized Federal programs, State rules, etc.) for NAAQS implementation. 
Organization: Consumers Energy
Comment: 
Consumers Energy
Such an action would mandate schedule changes and budget increases because the advantage of scheduled outages would be lost, and the cost of replacement power would have to be renegotiated. Current contracts for equipment, services and/or coal supplies would have to be renegotiated and or cancelled - a business fact of life that EPA staff acknowledged was not considered, during a webinar hosted by EEI on September 22, 2010.  [EPA-HQ-OAR-2009-0491-2837.1, pp.8-9]
To start implementation of a revised spending plan based only on a proposed rule will place Consumers Energy in a position that can be considered imprudent by the Michigan Public Service Commission. That regulatory reality, in turn, carries with it an enormous rate recovery risk. [EPA-HQ-OAR-2009-0491-2837.1, p.9]
We respectfully comment that our spending and construction plans to implement a final and enforceable EPA regulation, CAIR, have relevance that must be considered as the EPA makes its projections and proposals to revise this final and enforceable regulation. [EPA-HQ-OAR-2009-0491-2837.1, p.9]
Response: 
The commenter's concern will be taken under consideration.  
Organization: Council of Industrial Boiler Owners (CIBO)
Comment: 
Council of Industrial Boiler Owners (CIBO)
The costs of this rule, if promulgated as proposed, would be excessive to utility companies, and would thus be passed on to consumers, which would have a significant impact on industrial energy consumers, including CIBO members. EPA acknowledges this fact: 'we believe the electric power industry will pass along most of the costs of the rule to consumers, so that the costs of the rule will largely fall upon the consumers of electricity.' 75 FR 45352. EPA estimates costs for the proposed reductions to range from $3.7-$4.3 billion in 2012 and $2.7-$3.4 billion in 2014. 75 FR 45352. [EPA-HQ-OAR-2009-0491-2751.1]
A. The benefits EPA uses to balance the costs have already been used to balance the costs of at least four other rules.
EPA attributes the benefits of this rule to the reduction of PM2.5. EPA asserts that those benefits justify EPA's projected costs of the rule. However, EPA is relying on those same PM2.5 emission reduction benefits to justify the tens of billions of dollars of costs for at least four other recent rules: Boiler MACT, SO2, NO2, and the Ozone NAAQS. In order to conduct an accurate cost-benefit analysis, EPA would need to sum the costs of all these rules, and weigh that total cost against the benefits of the PM2.5 emission reductions achieved through the addition of control equipment, projected plant closures and other available means of reducing emissions. [EPA-HQ-OAR-2009-0491-2751.1]
The costs of this rule, if promulgated as proposed, would be excessive to utility companies, and would thus be passed on to consumers, which would have a significant impact on industrial energy consumers, including CIBO members. EPA acknowledges this fact: 'we believe the electric power industry will pass along most of the costs of the rule to consumers, so that the costs of the rule will largely fall upon the consumers of electricity.' 75 FR 45352. EPA estimates costs for the proposed reductions to range from $3.7-$4.3 billion in 2012 and $2.7-$3.4 billion in 2014. 75 FR 45352. [EPA-HQ-OAR-2009-0491-2751.1]
A. The benefits EPA uses to balance the costs have already been used to balance the costs of at least four other rules.

EPA attributes the benefits of this rule to the reduction of PM2.5. EPA asserts that those benefits justify EPA's projected costs of the rule. However, EPA is relying on those same PM2.5 emission reduction benefits to justify the tens of billions of dollars of costs for at least four other recent rules: Boiler MACT, SO2, NO2, and the Ozone NAAQS. In order to conduct an accurate cost-benefit analysis, EPA would need to sum the costs of all these rules, and weigh that total cost against the benefits of the PM2.5 emission reductions achieved through the addition of control equipment, projected plant closures and other available means of reducing emissions. [EPA-HQ-OAR-2009-0491-2751.1]
Response: 
EPA has estimated the increase in retail electricity price that is associated with the Transport Rule proposal and has presented it in the Regulatory Impact Analysis (RIA) for the proposal.   Retail electricity prices are projected to increase nationally by an average of 2.5 % in 2012 and 1.5 % in 2014.  These price increases range from 1 to 3% by region in 2014. 
The benefits of this rule are estimated based on emissions inputs that are solely the incremental emission reductions associated with the implementation of the rule.  All control programs in place, including Federal and State rules and other programs such as consent decrees, as of February 2009 are in the baseline.    There is no overlap or double-counting of emission reductions from other programs in our analysis, such as those mentioned by the commenter.  
Organization: Crouch, Diane
Comment: 
Crouch, Diane
While I understand and support the idea of being good stewards of the earth we live on, I also know that it does no good to have clean air, water and land if you don't have jobs and money. Many of the current regulations imposed on utilities, as well as new proposed regulations, are simply going to raise costs to those utilities and further raise costs to customers. When will it end? At what point are we 'green' enough? [EPA-HQ-OAR-2009-0491-3284, p.1]
The trickle down affect of regulations could look like this: 1) Utilities spend $$ to meet standards; 2) Increased costs to the utilities are passed on to commercial and residential customers; 3) Increased costs to commercial customers get passed on to their customers (us).....so average citizens end up bearing most all of the costs. Again, where does it end? [EPA-HQ-OAR-2009-0491-3284, p.1]
And if regulations include things like the discontinuation of coal fired power plants, the results are even worse!!! Folks who mine coal will lose their jobs. Businesses who sell their products to the mines no longer have customers, thus their employees are in jeopardy of job losses. What good does it do to have a cleaner environment when no one has a job or income? [EPA-HQ-OAR-2009-0491-3284, p.1]
I applaud the agency's efforts to improve air quality, but believe that it must be done in a realistic, cost-effective way that will not cause utility ratepayers to incur unnecessary costs. [EPA-HQ-OAR-2009-0491-3284, p.1]
Response: 
According to the Agency's analysis as found in the Regulatory Impact Analysis (RIA) for the proposed Transport Rule, a relatively small amount of coal-fired capacity, about 1.2 GW (0.3 percent of all coal-fired capacity and 0.1 % of all generating capacity nationally), is projected to be uneconomic to maintain.  In practice units projected to be uneconomic to maintain according to the Agency's analysis may be "mothballed," retired, or kept in service to ensure transmission reliability in certain parts of the grid.  For the most part, these units are small and infrequently used generating units that are dispersed throughout the proposed Transport Rule region.  Coal production for use in the power sector is projected to decrease by 0.3 % in 2012 and by 0.8 % by 2014, and we expect greater coal production in Appalachia and the West and somewhat less production in the Interior coal regions of the country with the proposed Transport Rule.
In addition, retail electricity prices faced by consumers are projected to increase nationally by an average of 2.5 % in 2012 and 1.5 % in 2014 with the proposed Transport Rule, with a range of increases of 1 to 3 percent by 2014.  Thus, electricity rate-payers will face a small increase in electricity prices by 2014, but these same rate-payers will experience the benefit of improved air quality as reflected in the benefits estimate for the rule ($120-290 billion in 2014, shown in 2006 dollars). 
Organization: DoubleTree Hotel Roanoke and Conference Center
Comment: 
DoubleTree Hotel Roanoke and Conference Center
The rule would accelerate the closing of some generating plants and deprive many communities of jobs, taxes and revenues at a time when many residents/communities are still suffering from the economic downturn. [EPA-HQ-OAR-2009-0491-2142, p.1]
Response: 
In the Agency's analysis as shown in the Regulatory Impact Analysis (RIA) for this rule, a relatively small amount of coal-fired capacity, about 1.2 GW (0.3 percent of all coal-fired capacity and 0.1% of all generating capacity), is projected to be uneconomic to maintain.  In practice units projected to be uneconomic to maintain, according to the Agency's modeling, may be "mothballed," retired, or kept in service to ensure transmission reliability in certain parts of the grid.  For the most part, these units are small and infrequently used generating units that are dispersed throughout the proposed Transport Rule region.  Coal production for use in the power sector is projected to decrease by 0.3% in 2012 and by 0.8% by 2014, and we expect greater coal production in Appalachia and the West and somewhat less production in the Interior coal regions of the country with the proposed Transport Rule.  Retail electricity prices are projected to increase nationally by an average of 2.5 % in 2012 and 1.5 % in 2014 with the proposed Transport Rule.  The range of retail electricity price changes at a regional level is from 1 to 3%.   Increase in the retail electricity price in the region including Virginia is 1% in 2014, as shown in section 7.9 of the RIA.   Thus, the Agency believes the economic impacts of the proposed rule are relatively low, and should not impact most communities negatively in 2014. 
Organization: Environmental Council of States (ECOS)
Comment: 
Environmental Council of States (ECOS)
ECOS and state environmental agencies have discussed a number of categories of state implementation costs as a result of implementing new rules with the United States Environmental Protection Agency's (EPA) Office of Policy (formerly the Office of Policy, Economics, and Innovation). For each new EPA rule, states may incur slightly different implementation costs. Cost categories may differ from state to state depending on unique legislative and regulated community differences as we ll. States ask that EPA consider state costs for a wide range of implementation startup and recurring activities in its implementation cost estimation for this rule. as well as for other rules, as appropriate and using the attached checklist. ECOS requests EPA consider this full range of implementation cost items in its estimations for this rule before the final rule takes effect. ECOS also requests that EPA seek to secure federal funding for the states to cover the customary portion of the costs associated with the state implementation of this federal rule and consider the availability of funding support in its planning for new rule adoption schedules and other implementation activities following new rule issuance. [EPA-HQ-OAR-2009-0491-2599.1, p.1]
 Start-up and recurring implementation costs to the states as a result of this rule are detailed in the attachment to this letter and may include. for example, obtaining additional delegated authority, attending EPA training. developing a system for monitoring affected entities, purchasing new equipment to enforce the new regulation, providing compliance assistance, conducting ongoing public outreach and education programs (to the regulated communities) on how to comply with the state agency's implementation of the rule, collecting and reviewing data from monitoring. recording and storing data, and conducting enforcement inspections and follow-up actions. [EPA-HQ-OAR-2009-0491-2599.1, p.1]
ECOS appreciates that air rules are issued based on their public heal01 benefit and not the costs in accordance with the Clean Air Act. Our view is that we do not necessarily object to the issuance of the rule, but the costs discussed here are those for a government agency, whether federal, state, or local, to implement and enforce the rule, and that no matter which level of government implements the rule, costs will have to be addressed. We seek to make sure here that all pertinent costs are included in any estimate the agency produces. Failure to include an accurate assessment of the implementation costs may result in a rule that is not implemented properly or in a timely manner, which may adversely affect human health. [EPA-HQ-OAR-2009-0491-2599.1, p.2]
Response: 
The Agency's analysis of the impacts on States and other government entities can be found in section 9.2 of the RIA.  We thank the commenter for its letter with information on start-up and recurring implementation costs. 
Organization: Exelon
Comment: 
Exelon
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.35-37.]
But beyond  healthcare impacts, we support EPA because  these upwind state emissions slow economic  development in our service areas and hinder  our ability to build replacement generation.
The PECO and ComEd zones are among the most severely affected regions of the country. Without the Transport Rule, these areas will be unable to meet the current air quality standards for fine particulate and ozone and are likely to continue in nonattainment status, even after the rule is implemented.
As a result, all new economic development in our operating areas must meet the heightened environmental standards that exist for nonattainment areas. Under the NSR Program, for example, major emission sources, are required to purchase emission reductions offsets credits, when they construct or expand their business in nonattainment areas.
Depending on the size of the proposed project, ERC purchase requirements may represent millions of dollars of incremental cost, as compared to costs in attainment areas. As an example, ERCs to support development of a 600 megawatt combined cycle gas plant in the Southeastern Pennsylvania nonattainment area would exceed $5 million.
So, in effect, dirty generation in one part of the country actually hinders the development of new clean generation in another part of the country. Not only must businesses in nonattainment areas purchase ERCs for new or expanded operations, but also they face ongoing risks to their operations under the Clean Air Act if the nonattainment area in which they locate fails to meet federal air quality standards by the required deadline. Each of these adverse economic impacts deters businesses from locating in nonattainment areas with resulting negative tax consequences for state and local governments.
Response: 
EPA believes the implementation of the Transport Rule will ensure reductions in areas downwind of polluting areas and will lead to improved ability for such areas to meet the existing PM2.5 and ozone NAAQS as shown in the RIA and air quality TSD for the proposed rule.   With this increased ability to attain the NAAQS, businesses may see a reduction in barriers to locating in current areas in nonattainment with the NAAQS. 
Organization: Four Flags Area Chamber of Commerce
Comment: 
Four Flags Area Chamber of Commerce
This rule could cause the premature closure of some coal-based generation plants in my state, which will have severe economic consequences for my citizens, my communities and my state's revenues. [EPA-HQ-OAR-2009-0491-3807, p.1]
In addition to the costs to comply, there is the economic harm my state will incur if some coal-fired power plants are forced to retire prematurely. Each plant supports hundreds of good paying often in rural jobs, areas where there are few comparable employment opportunities. Closing these plants early will only lengthen the time needed for this nation to recover from the recession and will exacerbate a growing state budget problem through lost income tax revenues. [EPA-HQ-OAR-2009-0491-3807, p.2]
Response: 
According to the Agency's analysis as found in the Regulatory Impact Analysis (RIA) for the proposed rule, a relatively small amount of coal-fired capacity, about 1.2 GW (0.3 percent of all coal-fired capacity and 0.1 % of all generating capacity) nationally, is projected to be uneconomic to maintain by 2014.  In practice units projected to be uneconomic to maintain according to EPA's modeling may be "mothballed," retired, or kept in service to ensure transmission reliability in certain parts of the grid.  For the most part, these units are small and infrequently used generating units that are dispersed throughout the proposed Transport Rule region.  Coal production for use in the power sector is projected to decrease by 0.3 % in 2012 and by 0.8 % by 2014, and we expect greater coal production in Appalachia and the West and somewhat less production in the Interior coal regions of the country with the proposed Transport Rule.
Thus, the Agency believes that the amount of coal-fired power capacity that may close prematurely is relatively low, and that the economic impacts are low relatively to the benefits nationally from improved air quality (benefits of $120-290 billion in 2006 dollars).
Organization: Greater Philadelphia Chamber of Commerce
Comment: 
Greater Philadelphia Chamber of Commerce
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.205-206.]
Economic development is affected by the increased cost of compliance through more stringent permitting requirements, increased costs on motor fuels and the jeopardy placed on federal highway funds.
Often, the cost of compliance becomes a major issue for businesses when seeking to address environmental issues. We have always stated that any legislation or regulation must balance the needs of the environment and the economy. Cost to business is a critical concern in an increasingly competitive economy.
Response: 
The Agency understands the concerns of the commenter.  EPA provides an analysis of the impacts of the Transport Rule proposal on affected firms in the Regulatory Impact Analysis (RIA).  That analysis shows that the costs to businesses, including increases in retail electricity prices, is relatively low.  As shown in the chapter 7 of the RIA, retail electricity prices will increase from 1 to 3 percent across the U.S. by 2014, with the highest increases in the East.  The Agency believes, as stated in the preamble, that the use of emissions trading as prescribed in the rule will allow businesses to comply with the rule requirements in a cost-effective manner. 
Organization: Green America
Comment: 
Green America
The EPA has also, through the mechanisms set out in the Transport Rule, minimized the possible economic impact of implementing the rule for the average consumer, with minimal electricity price increases. This provides even more evidence that the benefits of this new rule far outweigh the possible costs. [EPA-HQ-OAR-2009-0491-2611, p.3]
Response: 
We thank the commenter for this comment.  EPA has proposed a remedy to reduce the targeted pollutants (SO2 and NOx) by an emissions trading scheme.  Such a scheme will reduce pollutant to a certain cap as a least-cost strategy and will minimize electricity price increases to consumers.  In addition, the benefits of the proposed remedy well exceed the costs as shown in the RIA for the proposal.
Organization: Green Exchange, LLC
Comment: 
Green Exchange, LLC
To help achieve the important environmental goals of the proposed Transport Rule, companies will need to make significant investments. For companies fulfilling their compliance obligations by undertaking major financial commitments, we feel it is essential for EPA to restore market confidence. Market confidence will help encourage investments that will enable the achievement of environmental objectives that affect the well being of every American. Supporting trading, where investors can receive a fair shot at a return on investment, helps provide market capital and tools to enable lower cost solutions to provide maximum environmental benefit. Market confidence can be greatly enhanced by ensuring clear caps and an environment that gives compliance entities the confidence in regulatory certainty coupled with flexibility to support trading of obligations. [EPA-HQ-OAR-2009-0491-1105.1, p.2]
Without the environmental certainty of a cap, none of us can be assured that the desired improvements in human health and air quality will be achieved. Regulatory certainty is needed to support trade; otherwise risk premiums for emission reduction projects go up, along with the cost of allowances.[EPA-HQ-OAR-2009-0491-1105.1, p.3]
Green Exchange supports efforts, such as this, to promote market-based mechanisms for responding to environmental issues because emissions trading results in reducing emissions earlier and at a lower cost than any other form of pollution regulation. We encourage EPA to maintain the continuity of existing trading programs by providing for the convertibility of current period allowances into the subsequent Transport Rule programs, and we would encourage Congress to provide EPA with sufficient flexibility in the future to avoid the problems that EPA has encountered in trying to maintain a viable emissions trading market. [EPA-HQ-OAR-2009-0491-1105.1, p.3]
Response: 
The Agency thanks the commenter for the comment.  The remedy in the proposed Transport Rule does include emissions trading (intrastate trading and limited interstate trading) to the extent we believe is legally permissible.   Emissions trading for rule compliance provides a less expensive way to meet the compliance requirements of this rule as EPA shows in the preamble and in chapter 7 of the RIA. 
Organization: Indiana Cast Metals Association (INCMA)
Comment: 
Indiana Cast Metals Association (INCMA)
This rule could cause the premature closure of some coal-based generation plants in my state, which will have severe economic consequences for our members, our communities and our local revenues. [EPA-HQ-OAR-2009-0491-2178.1, p.1]
In addition to the costs to comply, there is the economic harm my members will incur if some coal-fired power plants are forced to retire prematurely. Each plant supports hundreds of good paying jobs, at a time when there are few comparable employment opportunities. Closing these plants early will only lengthen the time needed for this nation to recover from the recession and will exacerbate a growing state and local budget problem through lost income tax revenues. [EPA-HQ-OAR-2009-0491-2178.1, p.2]
Response: 
According to the Agency's analysis as found in the Regulatory Impact Analysis (RIA) for the proposed rule, a relatively small amount of coal-fired capacity, about 1.2 GW (0.3 percent of all coal-fired capacity and 0.1 % of all generating capacity) nationally, is projected to be uneconomic to maintain by 2014.  In practice units projected to be uneconomic to maintain according the Agency's modeling may be "mothballed," retired, or kept in service to ensure transmission reliability in certain parts of the grid.  For the most part, these units are small and infrequently used generating units that are dispersed throughout the proposed Transport Rule region.  Coal production for use in the power sector is projected to decrease by 0.3 % in 2012 and by 0.8 % by 2014, and we expect greater coal production in Appalachia and the West and somewhat less production in the Interior coal regions of the country with the proposed Transport Rule.
Thus, the Agency believes that the economic impact of the proposed rule should be relatively low, especially when compared to the estimated benefits from improved air quality ($120-290 billion in 2014, in 2006 dollars). 
Organization: Indiana Manufacturers Association, Inc. (IMA)
Comment: 
Indiana Manufacturers Association, Inc. (IMA)
This rule could cause the premature closure of some coal-based generation plants in Indiana, which could have severe economic consequences. [EPA-HQ-OAR-2009-0491-1813.1, p. 1]
In addition to the costs to comply, economic harm may be incurred if some coal-fired power plants are forced to retire prematurely. Each plant supports hundreds of good paying jobs, often in rural areas where there are few comparable employment opportunities. Closing these plants early will only lengthen the time needed for this nation to recover from the recession and will exacerbate a growing state budget problem through lost income tax revenues. [EPA-HQ-OAR-2009-0491-1813.1, p. 2]
Response: 
According to the Agency's analysis as found in the Regulatory Impact Analysis (RIA) for the proposed rule, a relatively small amount of coal-fired capacity, about 1.2 GW (0.3 percent of all coal-fired capacity and 0.1 % of all generating capacity) nationally, is projected to be uneconomic to maintain by 2014.  In practice units projected to be uneconomic to maintain according to the Agency's modeling may be "mothballed," retired, or kept in service to ensure transmission reliability in certain parts of the grid.  For the most part, these units are small and infrequently used generating units that are dispersed throughout the proposed Transport Rule region.  Coal production for use in the power sector is projected to decrease by 0.3 % in 2012 and by 0.8 % by 2014, and we expect greater coal production in Appalachia and the West and somewhat less production in the Interior coal regions of the country with the proposed Transport Rule.
Thus, the Agency believes that the economic impact of this rule is relatively low as a whole. 
Organization: Indiana Municipal Power Agency
Comment: 
Indiana Municipal Power Agency
This rule could cause the premature closure of some coal-based generation plants in this region, which could cause severe economic consequences for IMP A members, communities and revenues. All of IMPA's jointly owned units are equipped with SO2 scrubbers and SCRs but this rule creates uncertainty to the units' viability with its restrictive trading program. [EPA-HQ-OAR-2009-0491-3057.1,p.1]
In addition to the costs to comply, there is the economic harm our customers will incur if some coal-fired power plants are forced to retire prematurely. Each plant supports hundreds of good paying jobs, at a time when there are few comparable employment opportunities. Closing these plants early will only lengthen the time needed for this nation to recover from the recession and will exacerbate a growing state and local budget problem through lost income tax revenues. Now is not the time for expensive government mandates that will provide questionable benefits. [EPA-HQ-OAR-2009-0491-3057.1, p.2]
Response: 
According to the Agency's analysis found in the Regulatory Impact Analysis (RIA), a relatively small amount of coal-fired capacity, about 1.2 GW (0.3 percent of all coal-fired capacity and 0.1 % of all generating capacity) nationally, is projected to be uneconomic to maintain in 2014.  In practice units projected to be uneconomic to maintain according to the Agency's analysis may be "mothballed," retired, or kept in service to ensure transmission reliability in certain parts of the grid.  For the most part, these units are small and infrequently used generating units that are dispersed throughout the proposed Transport Rule region.  Coal production for use in the power sector is projected to decrease by 0.3 % in 2012 and by 0.8 % by 2014, and we expect greater coal production in Appalachia and the West and somewhat less production in the Interior coal regions of the country with the proposed Transport Rule.  Thus, we believe the premature closure of coal-fired production capacity associated with the rule will be quite low.  
In addition, the Agency's preferred remedy in the rule allows for the maximum amount of emissions trading that is legally permissible as detailed in the preamble.
Organization: Indiana Utility Shareholders Association
Comment: 
Indiana Utility Shareholders Association
In addition to the costs to comply, there is the economic harm my state will incur if some coal-fired power plants are forced to retire prematurely. Each plant supports hundreds of good paying jobs, often in rural areas where there are few comparable employment opportunities. Closing these plants early will only lengthen the time needed for this nation to recover from the recession and will exacerbate a growing state budget problem through lost income tax revenues. [EPA-HQ-OAR-2009-0491-3845 p.2]
Response: 
According to the Agency's analysis found in the Regulatory Impact Analysis (RIA) for the proposed rule, a relatively small amount of coal-fired capacity, about 1.2 GW (0.3% of all coal-fired capacity and 0.1% of all generating capacity) nationally, is projected to be uneconomic to maintain.  In practice units projected to be uneconomic to maintain according to the Agency's analysis may be "mothballed," retired, or kept in service to ensure transmission reliability in certain parts of the grid.  For the most part, these units are small and infrequently used generating units that are dispersed throughout the proposed Transport Rule region.  Coal production for use in the power sector is projected to decrease by 0.3 % in 2012 and by 0.8 % by 2014, and we expect greater coal production in Appalachia and the West and somewhat less production in the Interior coal regions of the country with the proposed Transport Rule.
Thus, the Agency believes the economic impact associated with the rule is relatively low. 
Organization: International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers and Helpers (AFL-CIO Boilermakers Union)
Comment: 
International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers and Helpers (AFL-CIO Boilermakers Union)
Faced with these deadlines, many EGUs may have to suspend operations or permanently retire, harming employment and economic recovery in many communities where our members live and work. [EPA-HQ-OAR-2009-0491-2672.1, p.3]
C. The 2012 interim deadline and deep 2014 emissions reduction requirements could trigger shutdowns that will unnecessarily eliminate jobs.
While EPA predicts that the overall economic impacts of the proposed Transport Rule will be 'modest" the Boilermakers Union is concerned that EPA underestimated the number of units that could be retired or 'mothballed,' and failed to assess the employment impacts of these proposed regulations. Thus, the comparison of costs and benefits in the proposed Transport Rule is incomplete and potentially misleading. In these difficult economic times, where retention of well-paying jobs that help improve air quality (e.g. retrofitting boilers with pollution control technology) should be a top priority, it is crucial that EPA at least equip itself with some sense of the impact that the proposed Transport Rule will have on domestic employment so that the proposed implementation program can be structured in such a way that does not unnecessarily eliminate jobs. [EPA-HQ-OAR-2009-0491-2672.1, pp.8-9]
The assessment of costs and benefits conducted by EPA paints an incomplete picture of how American workers would be affected by the proposed Transport Rule. EPA fails to assess the costs associated with the retirement of smaller or less efficient EGUs (including job losses), and also fails to assess the impact of 'employment shifts' as workers are retrained or 're-employed elsewhere in the economy." Of particular concern to the Boilermakers Union is EPA's refusal to examine the employment effects of the proposed Transport Rule in industries providing pollution control equipment. [EPA-HQ-OAR-2009-0491-2672.1, p.9]
Even if just 1.2 GW of coal-fired EGUs are 'uneconomic to maintain' due to implementation of the proposed Transport Rule, as EPA predicts, there will be substantial employment impacts. However, as noted earlier (see supra III.A and III.B), the assumed cost-effectiveness for various facility owners to meet emissions reduction requirements through retrofit rather than retirement is based on numerous invalid assumptions about the financial, technical and regulatory feasibility of implementing the proposed Transport Rule. Thus, the actual amount of EGU capacity that will be taken out of service due to implementation of the proposed Transport Rule could be much higher than 1.2 GW. Each unit that could have been cost-effectively retrofit by Boilermakers under a less aggressive compliance timeline but was retired instead will represent a lost opportunity for the EPA to have preserved employment opportunities while protecting the environment. [EPA-HQ-OAR-2009-0491-2672.1, p.9]
In light of the challenges facing American workers at this time, EPA's incomplete analysis of the employment impacts of implementation of the proposed Transport Rule and its underestimation of EGU retirements likely to result from implementation of the proposed Transport Rule, the International Boilermakers strongly encourages EPA to conduct a more complete and accurate assessment of the employment impacts prior to publishing its Final Rule. [EPA-HQ-OAR-2009-0491-2672.1, p.9]
D. EPA should establish a more reasonable alternative timeline for achieving SO2 and NOx reductions that maintains consistency with CAA requirements while minimizing unnecessary employment impacts. [EPA-HQ-OAR-2009-0491-2672.1, pp.9-10]
Response: 
The Agency has provided an analysis of the employment impacts associated with the Transport Rule as part its analyses included in the RIA (chapter 9 and Appendix D) for the final rule.  This analysis includes industries that provide pollution control equipment and related services to the extent possible.
Organization: Jessee, Robert
Comment: 
Jessee, Robert
I am especially concerned about the economic impact of this rule, which could cause the premature retirement of some coal-fired generating units and subsequent loss of jobs, maybe even mine. I ask you to reconsider, for now is not the time to enact new regulations that will take away jobs in a portion of our country that is already economically challenged. [EPA-HQ-OAR-2009-0491-3288, p.1]
We need time to address air quality concerns in a way that allows our nation to preserve jobs, provides customers with cheap reliable electricity and not cause them to needlessly pay more for a product that is so essential for all of our lives, allow adequate time to install the necessary equipment that is needed, and that allows our states to develop their own regulatory plans. [EPA-HQ-OAR-2009-0491-3288,p.1]
Response: 
According to the Agency's analysis as found in the Regulatory Impact Analysis (RIA) for the proposed Transport Rule, a relatively small amount of coal-fired capacity, about 1.2 GW (0.3% of all coal-fired capacity and 0.1 % of all generating capacity nationally), is projected to be uneconomic to maintain by 2014.  In practice units projected to be uneconomic to maintain may be "mothballed," retired, or kept in service to ensure transmission reliability in certain parts of the grid.  For the most part, these units are small and infrequently used generating units that are dispersed throughout the proposed Transport Rule region.  Coal production for use in the power sector is projected to decrease by 0.3 % in 2012 and by 0.8 % by 2014, and we expect greater coal production in Appalachia and the West and somewhat less production in the Interior coal regions of the country with the proposed Transport Rule.
In addition, the Agency has shown in technical support documents (TSDs) in the docket for this rulemaking that there will be sufficient time for companies to install pollution control equipment if needed to meet the requirements for this rule, particularly by 2014.
Organization: Kentucky Chamber of Commerce
Comment: 
Kentucky Chamber of Commerce
Combined with other EPA regulations, the Transport Rule will likely mean the early retirement of eastern coal-fueled generation, resulting in the premature loss jobs and hundreds of millions of dollars in wages and taxes annually that today support communities where well-paid jobs are scarce. [EPA-HQ-OAR-2009-0491-2760.1 p.2]
Response: 
According to the Agency's analysis found in the Regulatory Impact Analysis (RIA) for the proposed Transport Rule, a relatively small amount of coal-fired capacity, about 1.2 GW (0.3 percent of all coal-fired capacity and 0.1 % of all generating capacity), is projected to be uneconomic to maintain.  In practice units projected to be uneconomic to maintain may be "mothballed," retired, or kept in service to ensure transmission reliability in certain parts of the grid.  For the most part, these units are small and infrequently used generating units that are dispersed throughout the proposed Transport Rule region.  Coal production for use in the power sector is projected to decrease by 0.3 % in 2012 and by 0.8 % by 2014, and we expect greater coal production in Appalachia and the West and somewhat less production in the Interior coal regions of the country with the proposed Transport Rule.
As to our ability to estimate impacts of combined regulations, the emissions controls such as those in this proposed rule will lead to reductions in ambient PM2.5 and ozone below the National Ambient Air Quality Standards (NAAQS) for these pollutants and assist other areas in meeting these standards.  Because the PM and ozone NAAQS RIAs also calculate PM and ozone benefits, there are important differences worth noting in the design and analytical objectives of each RIA. The NAAQS RIAs illustrate the potential costs and benefits of attaining a new air quality standard nationwide based on an array of emission control strategies for different sources. In short, NAAQS RIAs hypothesize, but do not predict, the control strategies that States may choose to enact when implementing a NAAQS.
The setting of a NAAQS does not directly result in costs or benefits, and as such, the NAAQS RIAs are merely illustrative and are not intended to be added to the costs and benefits of other regulations that result in specific costs of control and emission reductions. However, some costs and benefits estimated in the Transport Rule RIA account for the same air quality improvements as estimated in the illustrative PM2.5 and ozone NAAQS RIA.
By contrast, the emission reductions for the Transport Rule are from a specific class of well-characterized sources (power plant boilers). In general, EPA is more confident in the magnitude and location of the emission reductions for such rules and in the estimates of costs associated with the controls required to obtain these emission reductions.  Emission reductions achieved under these and other promulgated rules will ultimately be reflected in the baseline of future PM and ozone NAAQS analyses, which would reduce the incremental costs and benefits associated with attaining those NAAQS. EPA remains forward looking towards the next iteration of the 5-year review cycle for the NAAQS, and as a result does not issue updated RIAs for existing NAAQS that retroactively update the baseline (which includes all promulgated rules and other finalized Federal programs, State rules, etc.) for NAAQS implementation. 
Organization: Mass Comment Campaign (245) (American Electric Power)
Comment: 
Mass Comment Campaign (245) (American Electric Power)
I am also concerned about the economic impact of this rule, which could cause the premature retirement of some coal-fired generating units and subsequent loss of jobs. Now is not the time to enact new regulations that will take away jobs in a portion of our country that is already economically challenged. It would make more sense to provide adequate time to address our air quality issues in a way that preserves jobs, provides adequate time for power companies to install the equipment they need, and that allows states to develop their own regulatory plans.
Response: 
According to the Agency's analysis as found in the Regulatory Impact Analysis (RIA) for the proposed rule, a relatively small amount of coal-fired capacity, about 1.2 GW (0.3% of all coal-fired capacity and 0.1 % of all generating capacity) nationally, is projected to be uneconomic to maintain by 2014.  In practice units projected to be uneconomic to maintain according to EPA's analysis may be "mothballed," retired, or kept in service to ensure transmission reliability in certain parts of the grid.  For the most part, these units are small and infrequently used generating units that are dispersed throughout the proposed Transport Rule region.  Coal production for use in the power sector is projected to decrease by 0.3 % in 2012 and by 0.8 % by 2014, and we expect greater coal production in Appalachia and the West and somewhat less production in the Interior coal regions of the country with the proposed Transport Rule.
Thus, the Agency believes the economic impact of this rule should be low given the relatively low amount of estimated premature closures for coal-fired capacity.  Also, the Agency believes that there is sufficient time for companies to install needed pollution control equipment as shown in technical support documents (TSDs) prepared by EPA and included in the docket for this rulemaking.
Organization: Michigan Chamber of Commerce
Comment: 
Michigan Chamber of Commerce
The results of this could lead to significant electric rate increases which could damage the potential for economic recovery in Michigan. [EPA-HQ-OAR-2009-0491-2696.1, p.1]
In addition, the rule could cause the premature closure of some coal-based generation plants in Michigan. Each plant supports hundreds of good-paying jobs, often in rural areas where there are few comparable employment opportunities. These older plants often provide low-cost energy to the market place. Replacing these plants will likely lead to rate increases for residents and job providers. Closing these plants early will only lengthen the time needed for Michigan to recover from the recession and will exacerbate a growing state budget problem through lost income tax revenues. [EPA-HQ-OAR-2009-0491-2696.1, p.2]
Response: 
According to the Agency's analysis found in the Regulatory Impact Analysis (RIA) for the proposed Transport Rule, a relatively small amount of coal-fired capacity, about 1.2 GW (0.3% of all coal-fired capacity and 0.1% of all generating capacity), is projected to be uneconomic to maintain in 2014.  In practice units projected to be uneconomic to maintain according to the Agency's analysis may be "mothballed," retired, or kept in service to ensure transmission reliability in certain parts of the grid.  For the most part, these units are small and infrequently used generating units that are dispersed throughout the proposed Transport Rule region.  Coal production for use in the power sector is projected to decrease by 0.3 % in 2012 and by 0.8 % by 2014, and we expect greater coal production in Appalachia and the West and somewhat less production in the Interior coal regions of the country with the proposed Transport Rule. 
In addition, retail electricity prices are projected to increase nationally by an average of 2.5 % in 2012 and 1.5 % in 2014 with the proposed Transport Rule, and the range of increases regionally is about 1 to 3%, with a 3% increase expected in the region including Michigan that is part of the Agency's analysis in the RIA.
Organization: Michigan Manufacturers Association (MMA)
Comment: 
Michigan Manufacturers Association (MMA)
- This rule will cause the premature closure of some coal-based generation plants in Michigan, which will have severe economic consequences for the state. [EPA-HQ-OAR-2009-0491-2762.1, p.2]
In addition to the costs to comply, there is new economic harm that Michigan will incur if some coal-fired power plants are forced to retire prematurely. Each plant supports hundreds of good paying jobs, often in rural areas where there are few comparable employment opportunities. All indications are that the cost of replacement power will be more expensive and potentially less reliable. Closing these plants early will only lengthen the time needed for Michigan to recover from the recession and will exacerbate a growing state budget problem through lost income tax revenues. [EPA-HQ-OAR-2009-0491-2762.1, p.3]
Response: 
According to the Agency's analysis found in the Regulatory Impact Analysis (RIA) for the proposed Transport Rule, a relatively small amount of coal-fired capacity, about 1.2 GW (0.3% of all coal-fired capacity and 0.1 % of all generating capacity nationally), is projected to be uneconomic to maintain in 2014.  In practice units projected to be uneconomic to maintain according to the Agency's analysis may be "mothballed," retired, or kept in service to ensure transmission reliability in certain parts of the grid.  For the most part, these units are small and infrequently used generating units that are dispersed throughout the proposed Transport Rule region.  Coal production for use in the power sector is projected to decrease by 0.3 % in 2012 and by 0.8 % by 2014, and we expect greater coal production in Appalachia and the West and somewhat less production in the Interior coal regions of the country with the proposed Transport Rule. 
Organization: Ohio Coal Association
Comment: 
Ohio Coal Association
:: The Transport Rule's stringent requirements and expeditious deadlines will force retirement of existing base load generation. Such forced retirement will result in power reliability concerns, increased costs to consumers and long-term market instability. [EPA-HQ-OAR-2009-0491-2743.1, p.2]
Response: 
According to the Regulatory Impact Analysis for the proposed Transport Rule, a relatively small amount of coal-fired capacity, about 1.2 GW (0.3 percent of all coal-fired capacity and 0.1 % of all generating capacity) nationally, is projected to be uneconomic to maintain.  In practice units projected to be uneconomic to maintain may be "mothballed," retired, or kept in service to ensure transmission reliability in certain parts of the grid.  For the most part, these units are small and infrequently used generating units that are dispersed throughout the proposed Transport Rule region.  Coal production for use in the power sector is projected nationally to decrease by only 0.3 % in 2012 and by 0.8 % by 2014, and we expect greater coal production in Appalachia and the West and somewhat less production in the Interior coal regions of the country with the proposed Transport Rule.  
The increase in retail electricity price from the proposed Transport Rule is also found in the RIA.  The Agency estimates that Retail electricity prices are projected to increase nationally by an average of 2.5 % in 2012 and 1.5 % in 2014 with the proposed Transport Rule.   Increases in retail electricity price in a regional level range from 1 to 3% in 2014.   Increases in region including Ohio are about 3% by 2014.  Analysis of the impacts of the proposed rule on reliability indicate that these impacts should be relatively limited in the Midwest and other regions of the country, and these impacts are disclosed in a technical support document (TSD) that is in the docket for this rulemaking.
Organization: Ohio Manufacturers Association (OMA)
Comment: 
Ohio Manufacturers Association (OMA)
As proposed, the Transport Rule will likely cause power generators to prematurely retire some coal-fired generation plants, a disproportionate amount of which are located along the Ohio River. Such retirements would threaten grid stability by taking a significant amount of capacity out of the system, raise costs, and lead to job losses in predominantly rural communities still reeling from the economic downturn.[EPA-HQ-OAR-2009-0491-2651.1, pp. 1-2]
Response: 
According to the Agency's analysis found in the Regulatory Impact Analysis (RIA) for the proposed Transport Rule, a relatively small amount of coal-fired capacity, about 1.2 GW (0.3% of all coal-fired capacity and 0.1 % of all generating capacity nationally), is projected to be uneconomic to maintain in 2014.  In practice units projected to be uneconomic to maintain according to the Agency's modeling may be "mothballed," retired, or kept in service to ensure transmission reliability in certain parts of the grid.  For the most part, these units are small and infrequently used generating units that are dispersed throughout the proposed Transport Rule region.  Coal production for use in the power sector is projected to decrease by 0.3% in 2012 and by 0.8% by 2014, and we expect greater coal production in Appalachia and the West and somewhat less production in the Interior coal regions of the country with the proposed Transport Rule. Retail electricity prices will increase by 2.5% in 2012 and 1.5% on average nationally in 2014.  Thus, while there will be small increases in electricity prices and a small amount of coal-fired capacity that is projected to retire as a result of this proposal, the impacts are relatively low.  In addition, the grid stability (or reliability) in the Midwest should not be impacted substantially as a result of this rule according to a technical support document (TSD) prepared by EPA and available in the docket for this rule.
Organization: Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
Comment: 
Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
The S02 Emission Targets for OVEC Could Force OVEC to Default on Local Coal Contracts [EPA-HQ-OAR-2009-0491-2779.1, p.8]
OVEC also objects to EPA's overly stringent S02 emissions caps because they interfere with OVEC's existing business relationships. EPA's proposed caps are so stringent that OVEC could be forced to change coal- even after the scrubbers are in service. In fact, EPA encourages this result. See 75 Fed Reg. at 45,273. OVEC currently has two contracts for local Ohio coal for use at Kyger Creek: one set to expire at the end of 2012 and the other at the end of 2017. Kyger Creek's scrubbers were designed to burn higher sulfur coal and to comply with the emission allocations under CAIR while burning the contracted local coals. [EPA-HQ-OAR-2009-0491-2779.1, p.8]
Even with the scrubbers operating - which will not be the case for all units before 2012- if the scrubbers cannot be operated at the extremely high removal efficiencies demanded by EPA's proposed S02 caps, OVEC would be forced to purchase lower sulfur coal to meet the limitations. That could mean defaulting on the long term local coal contracts it already has in place. Clearly, EPA has not fully considered the economic impact of the overly stringent and almost immediate emissions reductions proposed in the Transport Rule. EPA should not implement any rule until it has fully assessed those impacts and how they affect the 'cost-effectiveness' of the proposed reductions. [EPA-HQ-OAR-2009-0491-2779.1, p.8]
D. The Emission Reductions Required by the Proposed Plan are Unattainable through the Installation of Control Equipment, and thus Require Discontinuance of the Use of Locally or Regionally Available Coal Contrary to Congressional Policy Declared in Section 125 of the Act
Section 125 provides that a Governor or the President may, by rule or order, prohibit a fuel burning source from 'using fuels other than locally or regionally available coal' so as to prevent local economic disruption. The Proposed Transport Rule implementation plan imposes such deep emission reductions that affected sources may have no choice but to discontinue use of local coal. EPA should not disregard national policy on this point without fully evaluating whether NAAQS can be attained in the downwind states without imposing such disruption on upwind states and fully explaining the results of its evaluation. EPA has not done so prior to issuing this proposal, which apparently rests on the misassumption that local or regional coal may still be used by affected sources, or worse, deliberately seeks to mandate a fuel switching strategy without regard to the attendant unemployment and local and regional economic disruption. EPA should withdraw its proposed plan and fully evaluate this very serious issue. [EPA-HQ-OAR-2009-0491-2803.1, p.13]
Response: 
EPA believes its economic impact analysis, summarized in section X of the preamble and included in detail in chapters 7 and 8 the RIA, is an extensive assessment of impacts for the compliance years of the rule (2012 and 2014).   Given that the proposed rule calls for emissions trading to the extent permissible (intrastate and limited interstate trading), EPA believes the needed reductions can take place in a cost-effective way. 
Organization: Pendleton, Mark
Comment: 
Pendleton, Mark
I am also concerned about the economic impact of this rule, which could cause the premature retirement of some coal-fired generating units and subsequent loss of jobs. Now is not the time to enact new regulations that will take away jobs in a portion of our country that is already economically challenged. It would make more sense to provide enough time to address our air quality issues in a way that preserves jobs, provides adequate time for power companies to install the equipment they need, and that allows states to develop their own regulatory plans. [EPA-HQ-OAR-2009-0491-1596, p.1[EPA-HQ-OAR-2009-0491-1596]]
Response: 
The economic impact of this rule is provided in chapter 7 of the RIA.  Retail electricity prices are projected to increase nationally by an average of 2.5 % in 2012 and 1.5 % in 2014 with the proposed Transport Rule.  The effects of the proposed rule on natural gas prices and the power-sector generation mix is also small, with a 1.7 percent or less increase nationally in delivered gas prices projected in 2012 and 0.5 % in 2014.  
A relatively small amount of coal-fired capacity, about 1.2 GW (0.3 percent of all coal-fired capacity and 0.1 % of all generating capacity), is projected to be uneconomic to maintain.  In practice units projected to be uneconomic to maintain according to the Agency's modeling may be "mothballed," retired, or kept in service to ensure transmission reliability in certain parts of the grid.  For the most part, these units are small and infrequently used generating units that are dispersed throughout the proposed Transport Rule region.  Coal production for use in the power sector is projected to decrease by 0.3 % in 2012 and by 0.8 % by 2014, and we expect greater coal production in Appalachia and the West and 15 % less production in the Interior coal regions of the country with the proposed Transport Rule.
These impacts will not be fully felt until 2014, and technical support documents (TSDs) in the docket for this rulemaking indicate that firms will have sufficient time and labor capacity to meet these control requirements, and the requirements may actually stimulate construction labor demand to a small degree in the next few years. 
Organization: Public Utilities Commission of Ohio
Comment: 
Public Utilities Commission of Ohio
In conclusion, we urge U.S. EPA to delay implementation of the Transport Rule, and to consider the changes we have recommended above. If EPA chooses to implement the rule as it currently exists, the PUCO strongly recommends implementation of the EPA preferred plan. EPA should, however, extend the rule compliance schedule to allow Ohio, as well as other states, to develop well-considered implementation plans and give our power companies more time to make needed modifications. Extending the compliance schedule will also give our ratepayers more time to adjust, given the current and anticipated economic climate, and the expected job and financial consequences. [EPA-HQ-OAR-2009-0491-2855.1 p.17] [[These comments can also be found in Section VII.C.]]
Response: 
Please see Section V.C.2. of the preamble.
Organization: Vettrus, Greg
Comment: 
Vettrus, Greg
I read your new proposed transport rule to require significant changes in emission requirements by 2014 from the power plant companies. You cited an unpublished study by only eight utility companies indicating it will 'not hurt the reliability of the grid'. You also cite statistics with no proof that we will save $120 billion to $290 billion annually by spending $2.8 billion to enforce the new standards. You do not mention what will happen to the cost of electricity to comply with these regulations for both consumers and businesses. When you adopted the clean fuel act which required utilities to move to natural gas and away from coal, the cost of natural gas to business and consumers increased by 3 to 4 times from the baseline. This created a severe hardship on lower and middle class families and on businesses that rely on natural gas for fuel. [EPA-HQ-OAR-2009-0491-2593, p.1]
As a citizen, I would like to know what will happen to rates for both businesses and consumers over the next ten years due to this ruling- How was this factored in your savings calculations? Also, how many businesses will use this rule as an additional factor in exporting more jobs to other countries? Did you count that cost in your assessment? [EPA-HQ-OAR-2009-0491-2593, p.1]
I do not believe in your funny math that includes 'soft' undocumented savings. Why are you not using tax credits as an incentive to reduce these emissions versus regulations which have costs that are passed on to the end consumer? [EPA-HQ-OAR-2009-0491-2593, p.1]
We have lost enough jobs to other countries! We need more creative approaches to keep the cost to the end consumer (business or home consumer) stable. I am strongly opposed to this regulation as written.[EPA-HQ-OAR-2009-0491-2593, p.1]
Response: 
The Agency prepared a technical support document (TSD) that is in the docket for this proposed rulemaking that addresses concerns with power reliability, and it concluded there was little reason to believe that there would be significant impacts on reliability from efforts by power plants to comply with the Transport Rule.   As to the benefits of the rule, they are presented and discussed in detail in chapter 5 of the Regulatory Impact Analysis (RIA) for the proposed rule.   The RIA is available in the docket for this rulemaking. Details of how the benefits of $120 to 290 billion (2006 dollars) are estimated are shown there, and references to explain further how the Agency estimates benefits for rules such as these are cited. 
The Agency did provide estimates of how retail electricity price, or the price of electricity that consumers face, changes in reaction to the Transport Rule.  These estimates are presented in chapter 7 of the RIA, and are presented by region and nationally.  Retail electricity prices are expected to increase by 1 to 3 percent across the U.S., with a national average increase of 1.5 percent by 2014.  Given that the final compliance year for firms for this proposal is 2014, we did not estimate impacts beyond that year.
The economic impacts are relatively low in comparison to the benefits of the proposal. 
Organization: West Window Corp.
Comment: 
West Window Corp.
The Transport Rule could cause power companies to prematurely close some coal-fired power plants in order to meet these aggressive compliance deadlines. Plant closings will force more people out of work and will deprive many communities of jobs, taxes and revenues at a time when these areas of our country are still suffering from the economic downturn  -  all for little environmental gain. [EPA-HQ-OAR-2009-0491-2386, p.1]
Response: 
As found in chapter 7 of the RIA for the proposed rule, a relatively small amount of coal-fired capacity, about 1.2 GW (0.3 % of all coal-fired capacity and 0.1 % of all generating capacity), is projected to be uneconomic to maintain by 2014.  In practice units projected by EPA's modeling to be uneconomic to maintain may be "mothballed," retired, or kept in service to ensure transmission reliability in certain parts of the grid.  For the most part, these units are small and infrequently used generating units that are dispersed throughout the proposed Transport Rule region.  Coal production for use in the power sector is projected to decrease by only 0.3 % in 2012 and by only 0.8 % by 2014, and we expect greater coal production in Appalachia and the West with somewhat lower production in the Interior coal regions of the country with the proposed Transport Rule.   Thus, the economic impacts of the proposal nationally, including the amount of prematurely closed coal-fired power capacity, are relatively small, and the benefits from the rule nationally are quite large in comparison ($120-290 billion as shown in the RIA). 
Organization: Western Business Roundtable
Comment: 
Western Business Roundtable
1. Federal Regulatory Bodies -- Including EPA -- Are Avoiding Full Cumulative Economic Impacts Analysis of Regulatory Programs
The Transport Rule is a good example of a troubling trend we see across the federal family: a circumvention of full cumulative impact requirements under federal law to overstate the value of erecting regulatory hurdles against the use of domestic fossil fuel resources. [EPA-HQ-OAR-2009-0491-2746.1 [EPA-HQ-OAR-2009-0491-2746.1 p.2]
In January, 2010, the Obama EPA issued a series of priorities, including development of "a comprehensive strategy for a cleaner and more efficient power sector."1 As the Agency states in the Transport Rule, "[i]n furtherance of this priority goal, and to respond to statutory and judicial mandates, EPA is undertaking a series of regulatory actions over the course of the next 2 years that will affect the power sector in particular."2 [EPA-HQ-OAR-2009-0491-2746.1 p.2]
These EPA rulemakings include:
 ? National Ambient Air Quality Standards ("NAAQS") for sulfur dioxide ("SO2") and nitrogen dioxide ("NO2");
? Proposed new ozone NAAQS and new PM2.5 NAAQS;
? Proposed Transport Rule and expected additional transport rules for the 1997 ozone NAAQS, the currently proposed new ozone NAAQS, soon-to-be-proposed new PM2.5 NAAQS; ? Soon-to-be-proposed MACT standards for electric generating units ("EGUs");
? EPA's greenhouse gas ("GHG") regulation under the Prevention of Significant Deterioration ("PSD") program;
? Soon-to-be-proposed New Source Performance Standards for EGUs (including GHG NSPS);
? Best Available Retrofit Technology ("BART") standards for EGUs;
? Proposed regulations for coal combustion residues; and
? Soon-to-be-proposed water quality regulations for cooling intake structures and soon-to-be-proposed effluent guidelines for discharges from power plants.
EPA is using these various rulemakings to effectuate a restructuring of the U.S. power sector. The implications of such a restructuring are huge. Yet, EPA has been very careful to limit its economic impact analyses  -  such as it is -- to the four corners of each proposed regulation. This approach treats each rulemaking as though it has no connection to the rest of EPA's regulatory agenda and as though the impacts of the decisions have no cumulative effect. [EPA-HQ-OAR-2009-0491-2746.1 p.3]
The Roundtable is not alone in our concern regarding how economic analysis is being done. A number of voices are expressing alarm. Striking is the Administration's response to questions from Members of Congress. For example, Ranking Energy and Commerce Committee Member Joe Barton has repeatedly asked agencies of the federal government  -  including EPA  -  to provide economic analyses detailing the impact of their proposed regulations on economic growth and job creation. Agencies' responses have been startling.
 "In November, 2009, we [E&C Minority] asked the Administrator of the Environmental Protection Agency (EPA) for any evaluations of overall job losses and/or shifts of employment in the United States that may occur as a result of the agency's endangerment finding and EPA's proposed greenhouse gas regulations, which have the potential to be the most complex, costly and burdensome in EPA's history. In January, 2010, EPA advised us that it had no responsive documentation analyzing potential job losses...."
 "In June, 2010, we [E&C Minority] asked the EPA Administrator whether the agency had prepared any analyses of job impacts of its proposed new national ozone standards, which EPA estimates would result in implementation costs ranging from $19 - $90 billion annually. We specifically requested any analyses of the employment impacts, potential relocation of production facilities outside the U.S. and impacts on small business. In August, 2010, we were advised by EPA that it `did not analyze the potential employment impacts of the proposed standards" or the potential relocation of facilities outside the U.S. and that it was not required to and had not conducted an analysis of the impacts on small businesses of the proposed standards...." [EPA-HQ-OAR-2009-0491-2746.1 p.3]
In March, 2010, we [E&C Minority] asked the Chair of the White House Council on Environmental Quality, who serves as the President's principal environmental policy advisor, whether any economic or jobs analyses were done in connection with its proposed climate change National Environmental Policy Act guidance for federal agencies regarding climate change analyses for federal actions. The draft guidance appears to create additional regulatory hurdles for new infrastructure and other large projects, including for obtaining federal financing, grants, permits, licenses, rights-of-way and other necessary regulatory approvals for projects anticipated to cause 25,000 metric tons or more of carbon dioxide equivalent emissions annually. In August, 2010, we were advised by CEQ that no economic analysis of the new guidance was required. We also asked CEQ whether the Administration is taking any actions to ensure that economic and jobs impacts are considered and evaluated before the Administration promulgates new environmental regulations and received no response." 3 [EPA-HQ-OAR-2009-0491-2746.1 p.3]
Unfortunately, we see little evidence in this proposed rule that EPA has deviated from its minimalist approach on evaluating the economic impacts of its actions. [EPA-HQ-OAR-2009-0491-2746.1 p.4]
Response: 
In implementing these rules, emission controls may lead to reductions in ambient PM2.5 and ozone below the National Ambient Air Quality Standards (NAAQS) for PM and ozone in some areas and assist other areas with attaining the PM NAAQS. Because the PM and ozone NAAQS RIAs also calculate PM and ozone benefits, there are important differences worth noting in the design and analytical objectives of each RIA. The NAAQS RIAs illustrate the potential costs and benefits of attaining a new air quality standard nationwide based on an array of emission control strategies for different sources. In short, NAAQS RIAs hypothesize, but do not predict, the control strategies that States may choose to enact when implementing a NAAQS. The setting of a NAAQS does not directly result in costs or benefits, and as such, the NAAQS RIAs are merely illustrative and are not intended to be added to the costs and benefits of other regulations that result in specific costs of control and emission reductions. However, some costs and benefits estimated in this RIA account for the same air quality improvements as estimated in the illustrative PM2.5 and ozone NAAQS RIA.
By contrast, the emission reductions for the Transport rule are from a specific class of well-characterized sources (EGUs). In general, EPA is more confident in the magnitude and location of the emission reductions for this rule than for NAAQS RIAs, and also the cost and benefit analyses for this rule.  Emission reductions achieved under these and other promulgated rules (including other rules for the power sector) will ultimately be reflected in the baseline of future NAAQS analyses, which would reduce the incremental costs and benefits associated with attaining the NAAQS as well as providing a more credible set of cost and benefits analyses for those NAAQS. EPA remains forward looking towards the next iteration of the 5-year review cycle for the NAAQS, and as a result does not issue updated RIAs for existing NAAQS that retroactively update the baseline for NAAQS implementation. For more information on the relationship between the NAAQS and rules such as analyzed here, please see Section 1.2.4 of the SO2 NAAQS RIA (U.S. EPA, 2010h).

XI. Incorporating End-use Energy Efficiency Into the Proposed Transport Rule

Organization: Connecticut Department of Environmental Protection
Comment: 
Connecticut Department of Environmental Protection
No incentives for energy efficiency. The proposed Transport Rule does not encourage energy efficiency. Clearly, the most cost effective emissions reductions are attributable to reduced operation of power plants. On the supply side, state budgets must be stringent enough so that every source subject to the Transport Rule will take steps to ensure they operate as efficiently as possible. Unfortunately, the proposed Transport Rule does little to incentivize demand-side energy efficiency investments in the absence of strong pre-existing state energy efficiency policies. EPA should view electricity as a product and recognize that it is influenced by both demand and supply side economics. [EPA-HQ-OAR-2009-0491-2780.1 p.20]
Response: 
See preamble section VIII.D.2. 
Organization: Energy Future Coalition
Comment: 
Energy Future Coalition
The Transport Rule takes important steps to improve public health and reduce US dependence on coal-fired power by mandating substantial reductions in NOx and SOx emissions. Studies from McKinsey and others demonstrates that energy efficiency can meet our energy demand more cleanly, quickly and cost-effectively than any other available supply option and that the "supply" of energy efficiency is extremely large. For instance, McKinsey has found that the United States could reduce greenhouse gas emissions in 2030 by 3 to 4.5 gigatons using existing and emerging technologies at costs less than $50 per ton. McKinsey further notes that projected costs would be far lower "if the nation can capture sizable gains from energy efficiency." In fact, as much as 40 percent of the potential reductions would come from distributed technologies, including end-user energy efficiency. Energy efficiency reduces the cost of making the reductions required by the Rule. It offers a bridge between the conventional fossil fuel-based power of today and the clean power of tomorrow. Indeed, energy efficiency boosts the economy, creates jobs, and helps the environment at half the cost of building new power plants. Unfortunately, necessary investments will not happen absent appropriate policies. As McKinsey recognizes, "the potential for energy efficiency is real and large, but without a change in policy or approach, this potential will remain out of reach." The CATR provides an opportunity to change the rules to incentivize energy efficiency to make it the first fuel of choice. [EPA-HQ-OAR-2009-0491-2623.1, pp.1-2]
Response: 
See preamble section VIII.D.2.

XI.A. How Does Energy Efficiency Contribute to Cost-effective Reductions of Air Emissions from EGUs?

Organization: Council of NAIMA
Comment: 
Council of NAIMA
EPA identifies energy efficiency improvements in homes, buildings, and industry as an important component of achieving reduction of NOx and SO2 emissions. 75 Fed. Reg. at 45,352. Indeed, this is critical since buildings are the largest users of energy. [EPA-HQ-OAR-2009-0491-2765.1 p.4]
In recent testimony before the Subcommittee on Energy and Air Quality of the Committee on Energy and Commerce of the U.S. House of Representatives, William Fay, Executive Director of the Energy Efficient Codes Coalition, stated that "homes and commercial buildings are this nation's largest sector of energy use and  -  because of the close relationship between greenhouse gases and energy consumption  -  also the largest US source of anthropogenic greenhouse gases. Suffice it to say that buildings  -  and particularly residences  -  represent one of the last great frontiers of wasted energy." [EPA-HQ-OAR-2009-0491-2765.1 p.4]
Since homes and commercial buildings consume the majority of the nation's energy, these structures must become an integral part of any successful effort to improve energy efficiency. The U.S. Department of Energy, along with various other federal and state governmental bodies, put installation of insulation at the top or in the top five suggestions for energy savings. Why? Cost-effectiveness and immediate availability. These two attributes are discussed in greater detail below. [EPA-HQ-OAR-2009-0491-2765.1 p.4-5]
Thermal insulation products promote energy efficiency and prevent pollution by reducing pollutants, specifically fine particulates, NOx and SO2 emissions. Reductions of toxic air pollutants can also be achieved, such as mercury, which can be emitted during coal combustion. By reducing the demand for energy, thermal insulation products help conserve non-renewable fuel supplies and reduce the amount of pollutants that are released into the atmosphere through the burning of fossil fuels. That increased use of insulation products can help EPA achieve its reduction of NOx and SO2 emissions is substantiated by two studies conducted at the Harvard School of Public Health. [EPA-HQ-OAR-2009-0491-2765.1 p.6-7]
The Harvard Studies Document the Benefits of Improving Efficiency and Reducing NOx and SO2 
Two studies conducted by the Harvard School of Public Health (the "Harvard Studies") analyzed the benefits of increased insulation and projected resultant reductions of the following pollutants: PM2.5, NOx, and SO2. These numbers were acquired using a model designed to predict emissions reductions of fine particulate matter and its precursors, nitrogen dioxide and sulfur dioxide. These studies were conducted in 2002 and 2003 and discuss the benefits of the IECC Standards, but in reality, today's current energy code would deliver even higher savings and greater emissions reductions. [EPA-HQ-OAR-2009-0491-2765.1 p.7]
An estimated 45 million homes in the U.S. lack the proper levels of insulation according to 2003-2004 energy code standards. Moreover, it is important to recognize that there are many millions of additional homes that do not meet current EPA/DOE R-value recommendations. Current codes are the MINIMUM that must be installed in new construction. That minimum is much less than what really should be installed per DOE recommendations.11 At the time of the 2003 Harvard study, an estimated 1.2 million new single family homes were built each year, but varying energy codes in each region meant that many of those homes would not be insulated to the then internationally accepted minimum standard  -  2003 IECC with 2004 IECC Supplement. Most commercial and industrial buildings similarly were under-insulated. [EPA-HQ-OAR-2009-0491-2765.1 p.7]
The Harvard Studies, however, have determined that improving energy efficiency of homes not only saves energy and reduces environmental air pollution, but also has a significant, immediate, positive impact on public health. Improving the energy efficiency of commercial and industrial buildings will provide these benefits as well. [EPA-HQ-OAR-2009-0491-2765.1 p.7]
The Harvard Studies demonstrate that properly insulated buildings significantly reduce the release of sulfur oxide, nitrous oxide, and fine particulate matter. With every Btu (British thermal unit) of energy produced from fossil fuel combustion, harmful gases such as nitrous oxide and sulfur oxide are released into the air, causing pollution in our communities. But a well-insulated home, commercial building, or industrial facility reduces the amount of energy required to maintain a comfortable living or working environment. Reducing energy consumption means power plants burn less fossil fuel to produce the energy and the result is a reduction in polluting gases emitted into our communities. Each Btu saved through energy-efficiency technologies such as insulation means cleaner air and improved public health. [EPA-HQ-OAR-2009-0491-2765.1 p.7]
Harvard researchers stated that the "magnitude of the economic and public health benefits indicates that creative public policies to encourage" increased insulation "may be warranted."12 Harvard researchers concluded that "[t]his approach allows us to quantify the benefits of energy efficiency on a national scale not seen before, which takes us far beyond energy savings and energy security. Now, it is clear that improving energy efficiency not only helps us as a nation, but also has an immediate, positive impact on us, as individuals, and our families." [EPA-HQ-OAR-2009-0491-2765.1 p.8]
Specific Findings  -  Existing Homes
As reported by the Harvard School of Public Health, bringing all existing homes up to merely the 2003 IECC with 2004 IECC Supplement codes would reduce PM2.5 by 31,000 tons, would reduce NOx by 100,000 tons per year, and would reduce SO2 by 190,000 tons per year: [EPA-HQ-OAR-2009-0491-2765.1 p.8]
According to our calibrated energy model, increasing residential insulation in the 46 million existing homes where insulation retrofits are necessary would save approximately 800 TBTU per year  -  17 MMBTU . . . per household per year. . . . Given these energy savings, the aggregate emission reductions from residential fuel combustion and power plants include approximately 31,000 fewer tons per year of PM2.5, 100,000 fewer tons per year of NOx, and 190,000 fewer ton per year of SO2.  [EPA-HQ-OAR-2009-0491-2765.1 p.8]
That likely is equally true of commercial and industrial buildings.  [EPA-HQ-OAR-2009-0491-2765.1 p.8]
The Harvard Study is careful to point out that the majority of emissions are linked to power plants and a significant share of pollution reduction achieved from increased insulation would be from power plants.  [EPA-HQ-OAR-2009-0491-2765.1 p.8]
The reduction of pollutants through increased insulation identified by Harvard shows substantial regional variations in emissions intensity. Interestingly, the largest reduction in pollutants through increased insulation can be achieved in non-attainment areas.   [EPA-HQ-OAR-2009-0491-2765.1 p.8]
CNAIMA stresses the significant reduction of not only PM2.5, but even more dramatic reduction of SO2 and NOx achieved through higher levels of insulation. The reduction of SO2 and NOx is particularly relevant in light of EPA's objective of reducing SO2 and NOx in order to achieve our nation's air quality goals. EPA-HQ-OAR-2009-0491-2765.1 p.9]
Existing Findings  -  New Homes
According to the second Harvard Study, insulating new homes to even the modest 2000 IECC levels would over ten years save 300 billion Btus  -  28 supertankers of crude oil or 300 billion cubic feet of natural gas.17 Based on this volume of energy savings, Harvard researchers estimate the following reduction of pollutants: EPA-HQ-OAR-2009-0491-2765.1 p.9] 
First focusing on the aggregate emission reductions, the 300 TBTU energy savings is associated with reduced emissions of approximately 1,000 tons of PM2.5, 40,000 tons of SO2, and 30,000 tons of NOx during the 10-year period. . . . On a per-unit basis, the emission reductions in PM2.5 are fairly similar across regions (ranging between 0.02 kg/year in the Midwest and 0.01 kg/year in other regions). Patterns are similar for NOx with the South and Midwest having the greatest per-unit emission reductions. At the state level, Texas had the greatest reduction of PM2.5, and Virginia had the greatest reductions of NOx and SO2, all of which were largely related to substantial electric space heating. EPA-HQ-OAR-2009-0491-2765.1 p.9]
Table 2:19 Consistent with EPA's stated commitment to reduce NOx and SO2 emissions, CNAIMA urges EPA to give weight in its analysis to the tremendous benefit that installed thermal insulation products offer to the environment  -  facilitating significant energy savings which, in turn, reduces the emissions of pollutants. [EPA-HQ-OAR-2009-0491-2765.1 p.10]
Response: 
See preamble section VIII.D.2.
Organization: Environmental Defense Fund (EDF)
Comment: 
Environmental Defense Fund (EDF)
a. Energy efficiency programs are a cost-effective method to reduce energy use and emissions. 
Energy efficiency programs reduce the amount of electricity needed, resulting in multi-pollutant reductions from traditional generating sources and avoiding the need to build more power plants or transmission lines  -- all while saving money. [EPA-HQ-OAR-2009-0491-2834.1 p.11]
A 2009 study by the American Council for an Energy-Efficient Economy (ACEEE) found that energy efficiency programs implemented by the utility sector cost one-third less than investing in new generation of any type.34 The study examined energy efficiency programs in 14 states35 and found that the cost of these programs ranged from 1.6 - 3.3 cents per kWh, with an average cost of 2.5 cents per kWh. ACEEE notes that electricity produced with pulverized coal costs 7 - 14 cents per kWh in 2008, with natural gas costs 7 - 10 cents per kWh. Additionally, projections of electricity resource costs from the Energy Information Administration indicate that the cost of energy efficiency, if it remains at current levels, will be one-third to one-fourth the cost of supply-side resources in 2020 (see figure from ACEEE below). A report by Synapse Energy Economics reinforces this finding. The report found that among utilities leading in energy efficiency, the highest cost per kWh saved through energy efficiency was 3 cents, compared to the national average price of 9 cents per kWh of delivered electricity.36 [EPA-HQ-OAR-2009-0491-2834.1 p.11]
Levelized Electricity Resource Cost Estimates for 2020
[[Chart Here]]
The Synapse Report also found that some utilities and states, that are leaders in energy efficiency, are reducing their energy needs by 1 -  3 percent through implementation of cost-effective energy efficiency measures. On the economic side, these measures are saving 1 percent or more in annual sales where they are implemented. [EPA-HQ-OAR-2009-0491-2834.1 p.12]
EPA Assistant Administrator Regina McCarthy noted in her testimony before the U.S. Senate Subcommittee on Clean Air and Nuclear Safety Subcommittee of the Environment and Public Works Committee in July 2009 that a recent auction to purchase future electricity resources in ISO New England resulted in 2,900 megawatts of demand-side resources sold. This sale further indicates the cost-effectiveness of instituting energy efficiency measures compared with the major investments associated with building and operating new generation. [EPA-HQ-OAR-2009-0491-2834.1 p.12]
ACEEE completed a study in 2005 on energy efficiency in multi-pollutant cap and trade policies that examined the emission reduction benefits of energy efficiency in several proposed policies. ACEEE found that energy efficiency could achieve 35 percent of the SO2 reduction requirements proposed in the Clear Skies Act of 2003.37 [EPA-HQ-OAR-2009-0491-2834.1 p.12]
EPA has recognized the inherent environmental value of incorporating energy efficiency as a compliance mechanism for electric generating units (EGUs) in prior rulemakings. The NOx Budget Trading Program included an energy efficiency and renewable energy (EERE) set-aside option for states to reward energy efficiency and renewable energy projects with NOx allowances from their emissions budget. In 2004, EPA produced "Guidance on State Implementation Plan Credits for Emission Reductions from Electric-Sector Energy Efficiency and Renewable Energy Measures," which was designed to assist states in quantifying emission reductions from energy efficiency and renewable energy and incorporating these reductions into their SIP.38 EDF urges EPA to provide greater detail on how states can quantify and incorporate emission reductions from energy efficiency and renewable energy in their SIPs and to provide greater technical assistance and guidance to states. [EPA-HQ-OAR-2009-0491-2834.1 p.12-13]
Response: 
See preamble section VIII.D.2.  In addition, EPA has released a draft document that provides additional detail on how states can account for the emission impacts of their energy efficiency and renewable energy policies and programs in their SIPs.  For more information, see: http://www.epa.gov/airquality/eere.html.
Organization: Greenpeace Washington, DC
Comment: 
Greenpeace Washington, DC
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, p.36 and pp.38-39.]
The proposed Transport Rule can also help promote energy efficiency as a cost-effective alternative to lifelines for filthy plants by raising the bar for pollution control technology.
With respect to energy efficiency, I think one of the key issues here is the issue of capacity markets and what's being done to address a lot of these plants, especially merchant plants who are really operating on the open market. They're not serving utility territories.
And, as such, they're a little more slippery than your traditional plants that serve utility territories.
So I think working with the ISOs is going to be key in determining how -- I think ISO in New England has been fairly successful in using efficiency to bid into some of these capacity markets, whether it's demand-side response, demand-side management, efficiency mechanisms even, even air conditioning side cleaning.
So I think some of those things can help to, for one, reduce the capacity prices that some of these utilities are receiving as subsidies from the rate trade and help to put some of that money back into the pockets of people as they're trying to meet their energy needs in an affordable way that also reduces emissions.
Response: 
See preamble section VIII.D.2.
Organization: Massachusetts Department of Environmental Protection
Comment: 
Massachusetts Department of Environmental Protection
Further, we encourage EPA to work with states and local agencies, and the electric system operators, to incorporate projections for energy demand that include the contribution from energy efficiency measures over the next 5-10 years. These efforts are significant across the Regional Greenhouse Gas Initiative (RGGI) region, and in other areas of the U.S. Energy efficiency is expected to significantly reduce the demand for electricity as EPA notes in the proposal, and therefore, should be considered when EPA determines the budgets and allocations in the next transport rule it intends to issue. For example, EPA should consider developing an allocation scheme in the next transport rule that rewards states, like Massachusetts, that have invested in energy efficiency. We stand ready to work with EPA to develop this idea, and others that will reward energy efficiency. [EPA-HQ-OAR-2009-0491-2787.2 p.11-12]
Response: 
See preamble section VIII.D.2.  EPA agrees that states, including many of the states participating in the RGGI, have adopted EE policies that are projected to yield energy savings over the next decade.  In recognition of this, EPA has released a draft document that provides additional detail on how states can account for the emission impacts of their energy efficiency and renewable energy policies and programs in their SIPs.  For more information, see: http://www.epa.gov/airquality/eere.html 
Organization: Southern Environmental Law Center
Comment: 
Southern Environmental Law Center
Moreover, the ability of end-use energy efficiency to reduce emissions of NOx and SO2 from electric generation presents a special opportunity in the Southeast, where implementation of energy efficiency measures has typically lagged behind other regions. This is why SELC works to promote aggressive energy efficiency policies and programs throughout our focus states. Energy efficiency in our region can reduce pollution, in addition to flattening an otherwise growing energy consumption curve, conserving billions of gallons of fresh water, decreasing energy bills and creating jobs. [EPA-HQ-OAR-2009-0491-2801.1, p.2]
SELC commends EPA for recognizing that end-use energy efficiency can be a key component of a cost-effective strategy to reduce SO2 and NOx emissions from electrical generation. As stated in the Transport Rule, 'EPA believes that achievement of energy efficiency improvements in homes, buildings, and industry is an important component of achieving emissions reductions from the power sector while minimizing associated compliance costs. By reducing electricity demand, energy efficiency avoids emissions of all pollutants associated with electricity generation, including emissions of NOx and SO2 targeted by this rule.' [EPA-HQ-OAR-2009-0491-2801.2]
This is no more true than in the South. According to the most recent State Energy Efficiency Scorecard issued by the American Council for an Energy-Efficient Economy ('ACEEE'), on a scale of 1 to 50, with California scoring the highest at 44.5, the six SELC states averaged 9. The non-SELC states that EPA's air quality modeling also identified as significantly contributing to nonattainment or interfering with maintenance in one or more SELC states did little better, averaging a score of 12. 9 There is much that can done through energy efficiency to clean the air in the Southeast. [EPA-HQ-OAR-2009-0491-2801.1, pp.2-3]

9. Those states are: IL, IN, KY, OH, FL, PA, WV, MS, MI, and MO. U.S. EPA, Technical Support Document ('TSD') for the Transport Rule-Air Quality Modeling, July 2010, Appendix D. We note that with one exception the biggest out-of-state contributor to nonattainment/maintenance receptor sites in SELC states is another SELC state. Without exception, though, the in-state contribution dwarfs, in most instances many times over, the highest out-of-state contribution. [EPA-HQ-OAR-2009-0491-2801.1, p.3]
Response: 
See preamble section VIII.D.2.

XI.B. How Does the Proposed Rule Support Greater Investment in Energy Efficiency?

Organization: Alliance for Industrial Efficiency
Comment: 
Alliance for Industrial Efficiency
A poll by The Alliance for American Manufacturing reveals that loss of US manufacturing is among voters' top concerns and that the vast majority (86 percent) of voters support government efforts to revitalize the manufacturing sector.4 By dramatically reducing electric power demand (and related energy costs) for industrial sources, combined heat and power and waste-heat recovery can help make US manufacturing more competitive. For instance, the ArcelorMittal steel facility in East Chicago, Indiana reports $100 million in annual electricity savings from waste-energy recovery.5 What's more, by lowering emissions from Electric Generating Units (EGUs), combined heat and power and waste-heat recovery can reduce compliance costs of the Proposed Rule. [EPA-HQ-OAR-2009-0491-2682.1 p.1]
Industrial CHP facilities can use the money they save on energy to expand labor and production. Take, for example, West Virginia Alloy, the country's largest silicon producer. This facility plans to capture hot gases from its silicon furnaces to generate more than 60 megawatts of electricity. It will use the money saved on electricity to finance an additional silicon furnace and increase its workforce by 20 percent. Indeed, CHP can fuel job creation nationwide. A study by the Oak Ridge National Laboratory finds that a robust investment in CHP could create nearly 1 million new, highly-skilled technical jobs across the country.6 These workers would be responsible for the construction, installation and maintenance of CHP equipment  -  as energy recycling equipment is manufactured right here in the United States. The potential boost to manufacturing jobs is critical, with the Bureau of Labor Statistics reporting a national unemployment rate approaching 10 percent.7 [EPA-HQ-OAR-2009-0491-2682.1 p.2]
And these energy savings come with enormous environmental benefits. The CHP expansion envisioned in the Oak Ridge report would reduce carbon dioxide emissions by more than 800 million metric tons per year  -  the equivalent of removing more than half of the current passenger vehicles from the road. [EPA-HQ-OAR-2009-0491-2682.1 p.2]
Despite these clear economic and environmental benefits, CHP investments fall short of their potential. While the Oak Ridge National Laboratory projects that CHP could provide 200,000 megawatts of clean electric power, or 20 percent of US electricity demand by 2030,9 current levels are less than half that amount. The Proposed Transport Rule does little to facilitate this needed growth. To promote the "significant opportunity ... for energy efficiency improvements in businesses, homes, and industry,"10 we recommend EPA strengthen the proposed rules by taking three steps: [EPA-HQ-OAR-2009-0491-2682.1 p.2]
Response: 
See preamble section VIII.D.2.
Organization: Energy Future Coalition
Comment: 
Energy Future Coalition
We are gratified to see that EPA recognizes the importance of end-use efficiency in the proposed rule. EPA, however, should not merely acknowledge the benefits of efficiency, but provide incentives to encourage electric generating units to invest in energy efficiency. Currently, most utilities make their money by building power plants and selling electricity, not by investing in energy efficiency. By encouraging states to provide incentives for utilities to invest in energy efficiency, however, the CATR could help to change that paradigm by reducing the need to generate as much electricity  -  causing a concomitant reduction in all regulated pollutants. EPA recognizes these benefits in the proposed rule. [EPA-HQ-OAR-2009-0491-2623.1, p.2]
Response: 
See preamble section VIII.D.2.  In addition, EPA recognizes that state utility regulatory policy has an important impact on a utility's motivation to promote customer investments in EE.  EPA, in partnership with DOE, has facilitated consideration of these issues; for example, see: http://www.epa.gov/cleanenergy/energy-programs/suca/index.html.  EPA has also performed analysis to highlight the potential benefits of policies that increase investments in EE in the context of EPA's air rules; for example, see the "EE sensitivity" that is part of EPA's proposed rule for mercury and air toxics standards: http://www.epa.gov/airquality/powerplanttoxics/actions.html.

XI.C. How EPA and States Have Previously Integrated Energy Efficiency Into Air Regulatory Programs?

Organization: Energy Future Coalition
Comment: 
Energy Future Coalition
Many states have already adopted innovative energy efficiency measures that are changing the basic business model of utilities. Three policies are key: decoupling, Energy Efficiency Resource Standards, and utility incentives. The Energy Future Coalition's own analysis (attached) shows that approximately 39 states and the District of Columbia have adopted at least one of these policies aimed at improving energy efficiency in their electrical systems. Moreover, forward capacity markets in the Northeast and mid-Atlantic power pools are driving further investment in energy efficiency. Where these state and regional programs exist, EPA should establish a process whereby a Governor can easily alert EPA that the agency had miscalculated the state's budget by failing to account for these existing energy efficiency investments. These energy efficiency programs would thus serve as an "alternative compliance mechanism" to the controls that are established in the FIP and the state's emissions budget would be adjusted accordingly. [EPA-HQ-OAR-2009-0491-2623.1, p.2]
Historically, states that have incorporated energy efficiency and renewable energy set-asides in their SIPs have required substantial technical assistance from EPA and others. The states will require technical support to help quantify potential emissions reductions from these programs and to avoid double-counting. For instance, although the 2004 EPA "Guidance on State Implementation Plan (SIP) Credits for Emission Reductions From Electric-Sector Energy Efficiency and Renewable Energy Measures" notes that states must show that any NOx reductions from energy efficiency and renewable energy measures are surplus to those that would occur in the absence of the measures,  it does not provide sufficient detail to help states make this determination. In fact, such determinations are often very technical and site-specific. For this reason, the Energy Future Coalition urges EPA to provide technical support to states that wish to include energy efficiency provisions in their SIPs. EPA asserts its availability to provide such support in helping states "quantify[ ] the reduction in compliance costs ... that can be realized through effective energy efficiency policies and programs"; however, the Agency will also have to provide substantial support to help states (and regulated entities) develop such policies and programs in the first place. [EPA-HQ-OAR-2009-0491-2623.1, p.3]
Response: 
See preamble Section VIII.D.2.  EPA agrees that many states have adopted policies to encourage investment in EE.  EPA views these policies as complements to traditional air pollution regulations, with both types of policies helping to achieve air quality objectives.  In the context of this rule, EPA views the energy savings resulting from the state EE policies as part of an overall suite of potential actions (e.g., installation of pollution controls) that help achieve the emission budgets established here and not as an "alternative compliance mechanism" that justifies adjusting state budgets.
In addition, EPA has released a draft document that provides additional detail on how states can account for the emission impacts of their energy efficiency and renewable energy policies and programs in their SIPs.  For more information, see: http://www.epa.gov/airquality/eere.html.  EPA is also available to provide technical assistance to states that wish to include EE policies and programs in their SIPs.  EPA has also developed resources to help states design EE policies and programs; for example, see: http://www.epa.gov/cleanenergy/energy-programs/index.html.

XI.D. Incorporating End-use Energy Efficiency Into the Transport Rule

Organization: Alliance for Industrial Efficiency
Comment: 
Alliance for Industrial Efficiency
Third, EPA should immediately begin working with interested states to adopt approaches that encourage industrial efficiency. States will require technical assistance from EPA to help them reallocate allowances appropriately and EPA should launch efforts to help provide that as quickly as possible. [EPA-HQ-OAR-2009-0491-2682.1 p.3]
Response: 
See preamble section VIII.D.2. 
Organization: Alliance to Save Energy
Comment: 
Alliance to Save Energy
The Alliance commends the EPA for recognizing the benefits of end-use energy efficiency as a means to reduce pollutant emissions from electrical generation not only in the current Notice of Proposed Rulemaking (NOPR)1 but also in the previous Clean Air Interstate Rule (CAIR) and associated guidance.2, 3 As stated in the NOPR, 'EPA believes that achievement of energy efficiency improvements in homes, buildings, and industry is an important component of achieving emissions reductions from the power sector while minimizing associated compliance costs. By reducing electricity demand, energy efficiency avoids emissions of all pollutants associated with electricity generation, including emissions of NOx and S02 targeted by this rule.'4 [EPA-HQ-OAR-2009-0491-2800.1 p.1]
The Alliance appreciates that the EPA wishes to expedite implementation of the CATR and relieve states and localities of significant workload by means of proposing a Federal Implementation Plan (FIP) in lieu of issuing a notice for State Implementation Plans (SIP Call). However, the Alliance believes that the EPA does not provide sufficient guidance for states that may opt to submit a SIP, including SIPs that may recognize energy efficiency approaches to reduce regulated pollutant emissions. [EPA-HQ-OAR-2009-0491-2800.1[EPA-HQ-OAR-2009-0491-2800.1 p.1]
The EPA may find useful resources on energy efficiency options, programs, deployment, M&V, and other pertinent issues in the work conducted through the National Action Plan for Energy Efficiency (NAPEE) and the ongoing State Energy Efficiency (SEE) Action Network.5 Further, a number of states affected by CATR have existing electric utility energy efficiency programs and requirements that have addressed questions of defining and determining energy savings, M&V, additionality, and other issues that may be useful in the development of SIPs acceptable to the EPA. The SEE Action Network also could serve as a vehicle for providing guidance and technical assistance to the states on EERE set-asides. [EPA-HQ-OAR-2009-0491-2800.1 p.3]
Response: 
See preamble section VIII.D.2.
Organization: Council of NAIMA
Comment: 
Council of NAIMA
In the Proposed Transport Rule, EPA repeatedly identifies the importance and value of having a cost-effective solution for reducing NOx and SO2 (75 Fed. Reg. at 45,214, 45,222, 45,223-224, 45,226-227, 45,229, passim). "EPA chose the standard of `highly cost-effective' in order to assure state flexibility in selecting control/strategies to meet the emissions reduction requirements of the rulemaking." 75 Fed. Reg. at 45,231. Insulation represents arguably the most cost-effective and readily-available tool for energy efficiency. If EPA wants cost effectiveness, installation of insulation should be at the top of EPA's list of end-use energy efficiency tools. [EPA-HQ-OAR-2009-0491-2765.1 p.5]
Energy efficiency is a resource. Indeed, insulation products are resources. In fact, energy efficiency, including insulation, has been deemed the greatest untapped resource available to address the current energy crisis and climate change.5 Unlike other energy efficiency measures, such as energy efficient appliances or energy saving light bulbs, insulation, once installed, requires no additional energy to save energy. [EPA-HQ-OAR-2009-0491-2765.1 p.5]
Therefore, increasing energy efficiency through insulation is very cost effective. In The Ecology of Commerce, Paul Hawken asserts that "ceiling insulation and double glazed windows can produce more oil than the Arctic National Wildlife Refuge at its most optimistic projections; at about one-twentieth the cost, with four times the employment per unit of energy conserved versus the energy consumed by burning oil." [EPA-HQ-OAR-2009-0491-2765.1 p.5]
EPA gives weight to cost effectiveness in identifying emissions reductions because a cost effective measure does not present the usual impediments to implementation of an action plan.7 Rather, cost effective measures help meet goals and objectives expeditiously without overburdening budgets. [EPA-HQ-OAR-2009-0491-2765.1 p.5]
In "A Cost Curve for Greenhouse Gas Reduction," the McKinsey Quarterly reports "that almost a quarter of possible emission reductions would result from measures (such as better insulation in buildings) that carry no net life cycle cost  -  in effect they come free of charge."9 As the graphic from the above-referenced article demonstrates, no other efficiency measure is as cost effective as building insulation. [EPA-HQ-OAR-2009-0491-2765.1 p.5]
From a pragmatic perspective, insulation is easily installed and the materials are immediately available. As evidenced by the McKinsey report cited above and the Harvard studies discussed below, insulation delivers significant reduction in pollutants, specifically NOx, SO2, and greenhouse gases. [EPA-HQ-OAR-2009-0491-2765.1 p.6]
Both the EPA and DOE websites state that up to 30 percent savings on heating and cooling energy can be saved through increased insulation. (http://www.energy.gov/ insulationairsealing.htm; www.epa.gov/region1/eco/energy/heatingefficiency.html). Air sealing, an important companion to insulation, is also critical for achieving the maximum energy savings and shortest payback period. [EPA-HQ-OAR-2009-0491-2765.1 p.6]
INCENTIVES FOR MORE INSULATION
In addition to direct utility funding of large-scale residential retrofit projects, EPA should also encourage affected utilities to pursue more effective incentives to encourage higher levels of residential energy efficiency. [EPA-HQ-OAR-2009-0491-2765.1 p.11]
CNAIMA offers below measures that will encourage individual and corporate decisions to improve energy efficiency and provide incentives to improve insulation in all types of buildings. Typically building owners will not have the resources to quickly implement the energy efficiency improvements needed to accomplish pollution reduction goals. This unfortunate fact is even more relevant in today's economy, which includes declining real estate values in both the residential and commercial markets. Therefore, strong incentives and attractive assistance programs are badly needed. CNAIMA offers the following as specific suggestions for incentive programs:  [EPA-HQ-OAR-2009-0491-2765.1p.11]
:: In several Canadian Provinces, the provincial governments have declared a sales tax holiday on all purchases of insulation products. A well publicized campaign about tax free insulation products certainly offers consumers and building owners added incentive to upgrade insulation.
:: A tax credit for the installation of insulation products in homes or other buildings, new or existing, has also proven to be an effective motivating factor in getting insulation upgrades in newly constructed homes and buildings and existing residences and businesses. These tax credits should be extended on the federal level and newly created in states without such an incentive.
:: Local governments could offer incentive programs that encourage increased insulation in residential, commercial, or industrial buildings and processes, such as offering free home energy audits.
:: States and local governments should be urged to adopt the most current residential and commercial energy codes promulgated by the International Code Council ("ICC") and the American Society of Heating, Refrigerating, and Air-Conditioning Engineers ("ASHRAE").
:: States could offer incentives for local governments to adopt a more stringent building energy code or sponsor code training programs to insure adequate enforcement of existing codes.
:: States could also help publicize or give recognition to utilities that offer customers a loan program to increase insulation or purchase some other energy savings device.
:: As an alternative to utility loan programs or in conjunction with these local power providers' programs, states could also create a loan program through an appropriate government entity. Such loan programs generally attract consumers if they are interest free or if a low interest rate is offered.
:: Another variation on loan programs might have the utility funding the immediate insulation upgrade or improvement with the building/home owner repaying the costs of the improvements through their monthly utility bills over an agreed upon time period.
:: States could sponsor training programs on weatherization. In addition, states could construct a generic weatherization plan for residences throughout its jurisdiction and promote it through websites and other media.
[EPA-HQ-OAR-2009-0491-2765.1 p.12]
That such incentives are warranted for insulation products is illustrated by CNAIMA's comments. As CNAIMA's comments demonstrate, energy conservation in buildings offers the most significant opportunity for savings and pollution reduction. Moreover, insulation is cost effective, and, perhaps even more appealing, insulation is a practical and immediately available resource. In other words, insulation and similar energy efficiency measures provide expeditious results. In fact, such improvements as insulation upgrades should be encouraged for immediate implementation, but if that is not feasible, perhaps a requirement that all existing homes re-sold must substantiate that the home being sold meets or exceeds existing energy code requirements. [EPA-HQ-OAR-2009-0491-2765.1 p.12]
Response: 
See preamble section VIII.D.2. 
Organization: Public Utilities Commission of Ohio
Comment: 
Public Utilities Commission of Ohio
Yet another reason for extending the timetable for implementation of the Transport Rule is that potential exists for utilizing the energy efficiency efforts of utilities as a compliance mechanism for the Transport Rule. The potential for using energy efficiency efforts toward compliance with such pollution control regulations has only recently arisen in Ohio, with the advent of implementation of energy efficiency portfolio plans for our utilities. The model used in developing the Transport Rule incorporates no demand response, energy efficiency, or price elasticity, while assuming a constant demand.7 We believe these programs may provide significant contributions toward the goals of the Transport Rule, and extending the timeframe would allow Ohio, as well as other states, the opportunity to explore the potential of these programs as compliance methods. [EPA-HQ-OAR-2009-0491-2855.1 p.16]
Response: 
See preamble section VIII.D.2.  EPA is not proposing to allow energy efficiency as a direct compliance mechanism for this rule.  EPA disagrees that allowing states time to explore EE is an appropriate justification for delaying the implementation, and the corresponding health and environmental benefits, of this rule.  Many states have already adopted EE policies that will deliver significant energy savings that will support least cost compliance with this rule.  Others are in a position to act similarly, independent of the timing of this rule.

XI.D.1. Options That Could be Used to Incorporate Energy Efficiency Into Allowance Based Programs

Organization: Alliance for Industrial Efficiency
Comment: 
Alliance for Industrial Efficiency
Second, EPA should provide a roadmap for states by proposing a model rule that shows how they can reduce emissions by incorporating industrial efficiency provisions such as Combined Heat and Power and recycled energy in their own State Implementation Plans, should they choose to adopt them. One approach would be to allow states to set aside allowances for industrial CHP generators. In fact, there is Agency precedent for favoring energy efficiency technologies.12 Notably, under the Clean Air Interstate Rule (which the Transport Rule will replace) states were allowed to set aside allowances for energy efficiency and renewable energy, based on an EPA list of qualifying technologies. A 2004 EPA Guidance likewise allows states to put aside a set amount of allowances for qualifying efficiency projects.13 [EPA-HQ-OAR-2009-0491-2682.1 p.3]
Response: 
See preamble section VIII.D.2.  In addition, EPA has released a draft document that provides additional detail on how states can account for the emission impacts of their energy efficiency and renewable energy policies and programs in their SIPs.  For more information, see: http://www.epa.gov/airquality/eere.html.
Organization: Council of NAIMA
Comment: 
Council of NAIMA
LARGE-SCALE, UTILITY-FUNDED RESIDENTIAL RETROFIT PROJECTS AND NEW CONSTRUCTION BEYOND CODE SHOULD BE ENCOURAGED AS A COST-EFFECTIVE MEANS OF ACHIEVING EMISSIONS REDUCTIONS
Especially in the present weak economy, many homeowners do not have the ready capital to substantially upgrade their energy efficiency to achieve the DOE estimated 20 to 30 percent reduction in heating and cooling demand that results with air sealing and additional insulation. While some homeowners could borrow the money for an energy-efficiency upgrade, they frequently do not have access to sufficient amounts of low-cost capital to achieve a reasonable pay-back period. Current energy efficiency tax credits under Section 25C of the Internal Revenue Code are set to expire on December 31, 2010, and, in any event, homeowners must wait until well into the year following the insulation purchase to enjoy the cost savings from the tax credit. Property-assessed clean energy ("PACE") funding is essentially no longer available after objections were lodged by federal mortgage regulators.  [EPA-HQ-OAR-2009-0491-2765.1 p.10]
Instead, the utilities affected by EPA's Proposed Transport Rule should be encouraged to directly fund and implement large-scale (literally utility-scale) residential retrofit projects. Utilities should also be encouraged to directly fund energy efficiency beyond current code during new construction when air sealing and installing additional insulation is especially cost effective. [EPA-HQ-OAR-2009-0491-2765.1 p.10]
Such projects could be undertaken promptly by using off-the-shelf insulation and air sealing technology. Such residential retrofits are likely the cheapest and quickest way to achieve significant emissions reductions of all pollutants, including the pollutants targeted under the Proposed Transport Rule. 
[EPA-HQ-OAR-2009-0491-2765.1 p.11]
Because such large-scale residential retrofit projects would assist utilities in providing low-cost and reliable service to their customers, state Public Utility Commissions are likely to approve utility retrofit expenditures as an appropriate  -  if not preferred  -  means of compliance with the Proposed Transport Rule. This should especially be the case considering the side benefits of residential retrofit projects, which include at least the following:
:: Reduction in home heating and cooling costs to consumers, which could also help consumers deal with higher rates that could come from switching to higher cost fuels;
:: Increased in-home-occupant health and comfort;
:: Creation of new jobs to complete the many retrofit projects (retrofit is much more labor-intensive than either new generation equipment or pollution abatement equipment, both of which tend to be capital-intensive);
:: Increase in affordability of home ownership;
:: Increase in home values;
:: Reduction in dependence on foreign sources of fuel;
:: Increase in reliability of electricity grid; and :: Enhancement of energy security and, hence, national security.  
[EPA-HQ-OAR-2009-0491-2765.1 p.11]
Response: 
See preamble section VIII.D.2.  EPA agrees that there are large opportunities for improved energy efficiency in the buildings sector and that ratepayer-funded EE programs are an important mechanism available to states to address the opportunity.  EPA has worked to highlight this opportunity in its analysis (e.g., see "EE sensitivity" of the Proposed Mercury and Air Toxics Standards, available at: http://www.epa.gov/airquality/powerplanttoxics/actions.html) and communications with stakeholders, including state Public Utilities Commissions. 
Organization: Environmental Defense Fund (EDF)
Comment: 
Environmental Defense Fund (EDF)
b. Opt-In for Functionally Equivalent Energy Efficiency Measures
To secure the multipollutant benefits and cost-savings opportunities associated with energy efficiency, we recommend EPA consider creating an option for states to rely on energy efficiency in complying with a specifically delineated portion of the emissions budgets. This voluntary opt-in would require notification by the Governor of the affected state. The Gubernatorial opt-in request would need to be accompanied with a "functional equivalency" demonstration showing the scope of the emissions reductions to be achieved together with enforceable, verifiable energy efficiency measures that are functionally equivalent to enforceable emission limitations at affected EGUs or other emissions sources. The energy efficiency opt-in could be carried out in a number of ways including EPA action making an appropriate diminution in the required emissions reductions for the affected state or a federal delegation of authority to the state under the FIP to carry out these delineated measures, analogous to the architecture of the federal delegation in 40 CFR 52.21(u) under the PSD permit program FIP provisions. [EPA-HQ-OAR-2009-0491-2834.1 p.13]
In taking final action on the Transport Rule, EPA should also take public comment on the proposed policy design and mechanism under the Transport Rule SIPs for states to carry out their obligations through energy efficiency measures. By proposing such action contemporaneous with final action on the Transport Rule, EPA would smooth the transition to state implementation of the FIP and enable at the outset of state implementation of the program expansive state reliance on energy efficiency measures to achieve compliance. [EPA-HQ-OAR-2009-0491-2834.1 p.13]
Finally, we respectfully recommend the Agency and state air regulators begin a focused dialogue on the opportunities for incorporating energy efficiency into the Transport Rule and other clean air programs to enable the nation to realize in practice the considerable environmental and economic benefits that energy efficiency promises. The promise of energy efficiency will be unavailing if the nation does not work together to pursue this path forward or is misguided in its efforts to carry out these measures. [EPA-HQ-OAR-2009-0491-2834.1 p.13]
Response: 
See preamble section VIII.D.2.  EPA is not creating an option for states to rely on EE in complying with a specifically delineated portion of the emissions budget.  In the context of this rule, EPA views the energy savings resulting from the state EE policies as part of an overall suite of potential actions (e.g., installation of pollution controls) that help achieve the emission budgets established here at least cost to consumers and not as an "alternative compliance mechanism" that justifies adjusting state budgets.  In addition, EPA has released a draft document that provides additional detail on how states can account for the emission impacts of their energy efficiency and renewable energy policies and programs in their SIPs.  For more information, see: http://www.epa.gov/airquality/eere.html.
Organization: Massachusetts Department of Environmental Protection
Comment: 
Massachusetts Department of Environmental Protection
In the preamble to the proposed Transport Rule EPA states: 'Policies that will promote efficient use of electric power can be an integral, highly cost-effective component of power companies' compliance strategies. Reducing demand for electricity can in itself achieve large emissions reductions and public health benefits, while enhancing the reliability of the grid. It can also lower the cost of emissions reductions for consumers of electricity and for the power industry, as investments are avoided in unnecessary infrastructure.' EPA has requested comment on whether it has the authority to, and whether it would be appropriate for, it to consider energy efficiency in developing the Transport Rule allowance allocation methodology. [EPA-HQ-OAR-2009-0491-2787.2 p.11]
We believe EPA has the authority to incorporate energy efficiency measures in the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2787.2 p.11]
In addition, MassDEP has also sought to encourage energy efficiency through the use of combined heat and power (CHP) as in our engine and turbine regulation (310 CMR 7.26(40- (45)). We recommend that EPA consider a CHP energy efficiency incentive in the upcoming Phase II Transport Rule, especially for ICI boilers. [EPA-HQ-OAR-2009-0491-2787.2 p.11-12]
Response: 
See preamble section VIII.D.2.
Organization: Recycled Energy Development
United States Clean Heat & Power Association (USCHPA)
Comment: 
Recycled Energy Development
Fifth, EPA should provide technical assistance to states, helping them develop and implement actions that enhance industrial efficiency. The agency, for instance, can help the states effectively reallocate allowances in ways that encourage efficiency and reduce pollution. [EPA-HQ-OAR-2009-0491-2601.1, p.2]
RED is particularly pleased the Environmental Protection Agency's (EPA's) proposed rule recognizes the benefits of end-use efficiency. Responding to the agency's request for suggestions to stimulate energy efficiency, we encourage EPA to focus on the industrial sector, which is the largest consumer of energy and the source of substantial demand-side and generation-side efficiency opportunities. [EPA-HQ-OAR-2009-0491-2601.1, p.1]
To appreciate those opportunities, consider a pending RED project at a silicon manufacturer in West Virginia. Within electric arc furnaces, the facility melts quartz rock at very high temperatures in order to produce silicon. It long has been spending millions of dollars to cool down the hot exhaust gases so they do not bum up the bag house. RED will redesign the furnaces and capture the heat in order to generate more than 60 megawatts of clean power, all without burning any incremental fuel or emitting any additional pollution. The facility will reduce greenhouse-gas emissions by 485,000 tons per year. Yet in addition to these environmental benefits, the recycled-energy project will reduce the silicon manufacturer's costs and increase its productivity, allowing it to substantially expand output and jobs. [EPA-HQ-OAR-2009-0491-2601.1, p.1] 
According to 2005 study by the Oak Ridge National Laboratory, CHP projects could supply 20 percent of the nation's power by 2030 (200,000 megawatts of capacity). Such investments would create someone million good-paying jobs across the country, as well as reduce carbon dioxide emissions by more than 800 million metric tons per year, equal to removing from the roads more than half the nation's passenger cars. [EPA-HQ-OAR-2009-0491-2601.1, p.1]
Fourth, EPA should propose a model rule that helps states incorporate industrial efficiency provisions within their State Implementation Plans (SIPs). There is an agency precedent. The Clean Air Interstate Rule, which is being replaced by the Transport Rule), allows states to set aside allowances for energy efficiency and clean energy technologies. EPA Guidance from 2004, moreover, allows states to store allowances for qualifying efficiency projects. RED, therefore, recommends EPA allow states to set aside allowances for efficient CHP and clean recycled energy projects that reduce pollution and increase industrial productivity. [EPA-HQ-OAR-2009-0491-2601.1, p.2]
United States Clean Heat & Power Association (USCHPA)
USCHPA is pleased that the Environmental Protection Agency's (EPA) proposed rule recognizes the benefits of end-use efficiency. However, we are concerned that the benefits from an efficient CHP system are not sufficiently recognized given the fact that they are covered under this rule and subject to compliance obligations. Responding to the agency's request for suggestions to stimulate energy efficiency, we encourage EPA to focus on two sectors with regard to CHP: 1) the industrial sector, which is the largest consumer of energy and the source of substantial generation-side efficiency opportunities, and 2) the commercial sector, which deploys electricity generated from CHP facilities that are larger than the 25 megawatt limit. [EPA-HQ-OAR-2009-0491-2823.1, p. 1]
CHP is unique in that it generates two products -- heat and power -- from fuel, and thus increases efficiency and reduces greenhouse gas emissions. This reduction in emissions can be 35 percent or more compared with the more common method of obtaining power from distant conventional electric utility facilities and making heat on-site. A part of the regulatory challenge specific to CHP is that it displaces a GHG-intensive remote power source with a low-GHG local power source. This enables a net reduction in global GHG emissions, but can add GHG emissions to a point source close to the load. As many existing environmental regulations are focused on locally relevant criteria pollutants (NOx, SOx, etc.), they are not naturally set up to contemplate or quantify "indirect" reductions in emissions that occur outside of the facility boundaries. When facilities use CHP systems, emissions from the central station power plant are displaced, since the plant no longer needs to burn fuel to generate power for the CHP facility's load. The European Union (EU) created unique environmental rules specific to CHP in order to ensure that the overall GHG benefits from CHP are recognized and rewarded by their climate change regulations. CHP systems in the U.S. should be accorded the same consideration. [EPA-HQ-OAR-2009-0491-2823.1, p. 1]
According to the 2008 study by the Oak Ridge National Laboratory, with the support of incentives that recognize the energy and environment benefits of the technology, CHP projects have the potential to supply 20 percent of the nation's power by 2030 (200,000 megawatts of capacity). Such investments would create some one million good-paying jobs across the country, as well as reduce carbon dioxide emissions by more than 800 million metric tons per year, equivalent to removing from the roads more than half the nation's passenger cars. [EPA-HQ-OAR-2009-0491-2823.1, pp. 1-2]
EPA's Transport Rule could help achieve those benefits.
Fourth, EPA should propose a model rule that helps states incorporate efficiency provisions within their State Implementation Plans (SIPs). There is an agency precedent. The Clean Air Interstate Rule (CAIR), which is being replaced by the Transport Rule, allows states to set aside allowances for energy efficiency and clean energy technologies. EPA Guidance from 2004, moreover, allows states to store allowances for qualifying efficiency projects. EPA should allow states to set aside allowances for efficient CHP and recycled energy projects that reduce pollution and increase productivity. [EPA-HQ-OAR-2009-0491-2823.1, p. 2]
Response: 
See preamble section VIII.D.2.  In addition, EPA and the Department of Energy (DOE) each provide technical assistance to states and to industry to support improvements in industrial efficiency; see, for example: http://www.energystar.gov/index.cfm?c=business.bus_index and http://www1.eere.energy.gov/industry/.

XI.D.2. Why EPA Did Not Propose These Options?

Organization: Council of Industrial Boiler Owners (CIBO)
Alcoa Power Generating Inc. - Warrick Power Plant
Comment: 
Alcoa Power Generating Inc. - Warrick Power Plant
EPA seeks comment on 'whether EPA has authority to and whether it would be appropriate for EPA to consider energy efficiency considerations in developing the allowance allocation methodology.' 75 FR 45353. [EPA-HQ-OAR-2009-0491-3648, p.6]
EPA does not have authority as part of its implementation of NAAQS standards under the Clean Air Act to require sources to adopt energy efficiency measures. [EPA-HQ-OAR-2009-0491-3648,p.6]
Council of Industrial Boiler Owners (CIBO)
EPA seeks comment on "whether EPA has authority to and whether it would be appropriate for EPA to consider energy efficiency considerations in developing the allowance allocation methodology." 75 FR 45353.
EPA does not have authority as part of its implementation of NAAQS standards under the Clean Air Act to consider energy efficiency in its allowance allocation methodology or any aspect of its rulemaking proposal. No provision of the CAA provides EPA with the free-ranging authority to consider energy efficiency at a regulated source. It is quite possible that an energy efficiency measure could cause increased pollutant emissions from systems affiliated with or served by the regulated boiler. In instances where energy consumption adjustments could cause adverse consequences at the source, increasing efficiency would actually disserve EPA's stated goals of its Proposed Rule. In any event, the CAA imposes significant obligations on EPA regarding pollutant emissions, none of which directs EPA to judge the performance of regulated sources' energy efficiency.   [EPA-HQ-OAR-2009-0491-2751.1 p.14]
Response: 
See preamble section VIII.D.2.
Organization: Northeast States for Coordinated Air Use Management (NESCAUM)
Comment: 
Northeast States for Coordinated Air Use Management (NESCAUM)
Given this Administration's commitment to energy efficiency, we are disappointed at the lack of energy efficiency provisions in the proposal. EPA indicates that it did not incorporate end-use energy efficiency because of its use of the FIP as the implementation mechanism. "This means, among other things, that EPA allocates the emission allowances directly to individual sources. In contrast, when allowance based programs are implemented through SIPs, states may have significant flexibility to determine the methodology used to allocate or auction allowances" (75 FR 45343). Such reasoning is short-sighted.  It should also include energy-efficiency set-aside provisions in the final rule. EPA should work with the states and consult with energy offices to ensure that there are sufficient energy efficiency incentives or regulatory options provided in the final rule.   [EPA-HQ-OAR-2009-0491-2694.1 p.8]
Response: 
See preamble section VIII.D.2.
Organization: State of Ohio Environmental Protection Agency (Ohio EPA)
Comment: 
State of Ohio Environmental Protection Agency (Ohio EPA)
0hio EPA supports the use of energy efficiency improvements. U.S. EPA should incorporate energy efficiency incentives into the final Transport Rule. [EPA-HQ-OAR-2009-0491-2793.2, p. 11]
In the proposal, U.S. EPA emphasized the importance of energy efficiency improvements. Ohio EPA agrees that energy efficiency projects will reduce emissions in a cost-effective manner. U.S. EPA ultimately decided not to incorporate such programs in this proposal. Ohio EPA believes U.S. EPA should reconsider this decision and provide a workable way energy efficiency efforts at utilities can be used as a compliance mechanism for the Transport Rule. [EPA-HQ-OAR-2009-0491-2793.2, p. 11]
Response: 
See preamble section VIII.D.2.  In the context of this rule, EPA views the energy savings resulting from the state EE policies as part of an overall suite of potential actions (e.g., installation of pollution controls) that help achieve the emission budgets established here at least cost and not as an "alternative compliance mechanism" that justifies adjusting state budgets.

XII. [Reserved]

XII.A. Executive Order 12866: Regulatory Planning and Review

Organization: National Mining Association (NMA)
Comment: 
National Mining Association (NMA)
Cumulative Analysis is Legally Required
Cumulative analysis does not just make good regulatory sense; it is legally required. Two separate authorities require cumulative analysis here. [EPA-HQ-OAR-2009-0491-2868.1,p.10]
1. Executive Order 12866
Executive Order 12866 specifically requires cumulative analysis as follows:
Each agency shall tailor its regulations to impose the least burden on society, including individuals, businesses of differing sizes, and other entities (including small communities and governmental entities), consistent with obtaining regulatory objectives, taking into account, among other things, and to the extent practicable, the costs of cumulative regulations.  [EPA-HQ-OAR-2009-0491-2868.1, p.10]
This requirement for cumulative analysis stems from the regulatory philosophy of Executive Order 12866 that the need for and effects of government regulatory actions should not be examined in isolation but instead on an overall and coordinated basis. The preamble to the Order found that the then current regulatory system did not work in a way that produced efficient results or regulations that were "effective, consistent, sensible, and understandable." The first objective of the Order, therefore, was to "enhance planning and coordination with respect to both new and existing regulations." In that vein, the main administrative provisions of the Order -- an interagency Planning Mechanism, the requirement that each agency produce a Unified Regulatory Agenda and develop a Regulatory Plan, the requirement for a Regulatory Working Group and the provision for quarterly Conferences among OIRA and state, local and tribal governments --  were all included to enhance coordination of any specific regulation proposed by an agency with that agency's other existing and contemplated regulations, with other regulations of other agencies, and with the President's overall regulatory priorities. [EPA-HQ-OAR-2009-0491-2868.1,pp.10-11]
The Statement of Regulatory Philosophy and Principles in Executive Order 12866 also stressed the need for coordination. This Statement provides that "[i]n deciding whether and how to regulate, agencies should assess all costs and benefits of available regulatory alternatives." Agencies are instructed to "examine whether existing regulations (or other law) have created, or contributed to, the problem that a new regulation is intended to correct and whether those regulations (or other law) should be modified to achieve the intended goal of regulation more effectively"; to "base its decisions on its best reasonably obtainable scientific, technical, economic, and other information concerning the need for, and consequences of, the intended regulation"; and to "avoid regulations that are inconsistent, incompatible, or duplicative with its other regulations or those of other Federal agencies." Indeed, the preamble to the Executive Order states that "[t]he objectives of this Executive order are to enhance planning and coordination with respect to both new and existing regulation...." [EPA-HQ-OAR-2009-0491-2868.1,p.11]
This requirement for coordinated government action based on coordinated and cumulative analysis built on the same requirement in Executive Order 12291, the predecessor order to Executive Order 12866 and the Order which first required agencies to prepare Regulatory Impact Analyses. Executive Order 12291 required agencies, in promulgating new regulations, to "tak[e] into account the condition of the particular industries affected by regulations . . . and other regulatory actions contemplated for the future." [EPA-HQ-OAR-2009-0491-2868.1, pp.11-12]
The Executive Order 12866 requirements for coordinated and cumulative analysis apply with particular force to EPA's efforts to remake the power sector and its apparent effort to reduce coal usage throughout the economy. As shown above, each individual regulation that EPA promulgates in this area, including the Transport at issue here, is part of a single overall program with cumulative consequences. [EPA-HQ-OAR-2009-0491-2868.1, p.12]
Moreover, EPA cannot say that cumulative analysis is not "practicable" within the meaning of section 1(b)(11) of Executive Order 12866. EPA obviously has very sophisticated modeling techniques at its disposal. If in any one rulemaking EPA believes that it cannot anticipate and therefore assess the effects of future rulemakings, EPA can assess a range of possible future regulation. Certainly, the fact that EPA has indicated that it has an overall program in furtherance of one of the Agency's seven priorities suggests that EPA has a fairly concrete idea of the range of regulatory outcomes that it anticipates. Alternatively, EPA can delay any particular rulemaking until it has better information about future regulatory requirements that it intends to impose. What EPA cannot do, however, is to follow its current regulatory course, where the Agency analyzes individual rulemaking effects in isolation, as if there is no overall regulatory context. [EPA-HQ-OAR-2009-0491-2868.1,p.12]
Response: 
As part of implementing rules such as the Transport Rule, emissions controls may lead to reductions in ambient PM2.5  and ozone below the National Ambient Air Quality Standards (NAAQS) for these pollutants and assist other areas in meeting these standards.  Because the PM and ozone NAAQS RIAs also calculate PM and ozone benefits, there are important differences worth noting in the design and analytical objectives of each RIA. The NAAQS RIAs illustrate the potential costs and benefits of attaining a new air quality standard nationwide based on an array of emission control strategies for different sources. In short, NAAQS RIAs hypothesize, but do not predict, the control strategies that States may choose to enact when implementing a NAAQS.
The setting of a NAAQS does not directly result in costs or benefits, and as such, the NAAQS RIAs are merely illustrative and are not intended to be added to the costs and benefits of other regulations that result in specific costs of control and emission reductions. However, some costs and benefits estimated in the Transport Rule RIA account for the same air quality improvements as estimated in the illustrative PM2.5  and ozone NAAQS RIA.
By contrast, the emission reductions for the Transport Rule are from a specific class of well-characterized sources. In general, EPA is more confident in the magnitude and location of the emission reductions for such rules and in the estimates of costs associated with the controls required to obtain these emission reductions.  Emission reductions achieved under these and other promulgated rules will ultimately be reflected in the baseline of future PM and ozone NAAQS analyses, which would reduce the incremental costs and benefits associated with attaining those NAAQS. EPA remains forward looking towards the next iteration of the 5-year review cycle for the NAAQS, and as a result does not issue updated RIAs for existing NAAQS that retroactively update the baseline (which includes all promulgated rules and other finalized Federal programs, State rules, etc.) for NAAQS implementation. 

XII.B. Regulatory Flexibility Act (RFA)

Organization: City of Tallahassee
Comment: 
City of Tallahassee
Including Only Units Serving Generators Greater Than 25 Megawatts Is Consistent with EPA's RFA and UMRA Analysis [EPA-HQ-OAR-2009-0491-2669.1, p.3]
Excluding small utilities and/or small municipal entities from the Transport Rule is consistent with EPA's obligation to minimize average regulatory impacts on small entities. Both the RFA (as amended by SBREFA) and the UMRA require EPA to consider the specific burdens rules will place on these small entities. These entities often experience diseconomies of scale, lack the ability to spread extensive capital costs over large customer bases, and have different emissions considerations than larger units, making it appropriate to regulate them differently from larger units. [EPA-HQ-OAR-2009-0491-2669.1, p.3]
EPA determined that a regulatory flexibility analysis was not required under the RFA because EPA certified that the rule would not have a significant economic impact on a substantial number of small entities. 75 Fed. Reg. at 45355. A major justification for this finding was that the 25 megawatt threshold exempted approximately 600 small businesses from the proposed Transport Rule. See id.; U.S. EPA, REGULATORY IMPACT ANALYSIS FOR THE PROPOSED FEDERAL TRANSPORT RULE at 235 (June 2010) ("RIA"). Similarly, EPA found that small government entities would not be significantly affected under UMRA, as the 25 megawatt threshold exempted 380 small state and municipal utilities from the proposed rule. 75 Fed. Reg. at 45356. [EPA-HQ-OAR-2009-0491-2669.1, p.3]
Changing the applicability threshold to include small utilities serving generators 25 megawatts or less would bring all of these entities back into the fold of the proposed rule, requiring a new analysis under both the RFA/SBREFA and the UMRA. This major analytical change would, in turn, delay promulgation of a final rule and likely require that EPA re-propose the Transport Rule. Such a course of action is unjustified, as EPA lacks data demonstrating that these smaller units are significant contributors to non-attainment and non-maintenance of NAAQS in downwind states. [EPA-HQ-OAR-2009-0491-2669.1, p.3]
Response: 
Similar to the proposal, the final Transport Rule does not apply to generating units smaller than 25 MW.  See preamble for the final rule for more details on applicability and the SBREFA/ UMRA analysis.
Organization: Council of Industrial Boiler Owners (CIBO)
Comment: 
Council of Industrial Boiler Owners (CIBO)
'EPA estimates that 30 of the 81 identified small entities will have annualized costs greater than 1 percent of their revenues, and the other 51 are projected to incur costs less than 1 percent of revenues. While there are costs greater than 1 percent of revenues for a number of small entities, EPA is certifying No SISNOSE for several reasons.' 75 FR 45355/2.
EPA's conclusion that no significant economic impact on a substantial number of small entities will occur is incorrect. First, EPA admits that some small entities will face annualized costs greater than 1 percent of revenues. Such sources include small independent power producers that sell power under fixed-price long term contracts. These sources cannot pass through to customers the cost of participating in EPA's proposed program. These entities are among those that EPA disregards in drawing its SISNOSE conclusion. Second, EPA makes a flawed assumption that a small entity is affected only if annualized costs are greater than 1 percent of its revenues. For fixed-price contract power producers, 1 percent of revenues may represent an unacceptably high proportion of its operating income. Pass through will lag regulatory financial impact by at least five years.   [EPA-HQ-OAR-2009-0491-2751.1 p.14]
Response: 
In the final RFA analysis, EPA found that there would not be an economic impact greater than 1% on a substantial number of entities meeting the definition of "small" for the purposes of this rulemaking. EPA certified No SISNOSE for this action for a number of reasons outlined in the preamble and RIA.  This comment does not provide evidence to refute the number of small entities affected, nor the magnitude of the impact.  EPA has not changed its finding based on the fact that the number of small entities affected is not zero.  To certify No SISNOSE, there must not be a significant impact on a substantial number of small entities according to the guidance on the executive order.
Organization: Michigan Municipal Electric Association (MMEA)
Comment: 
Michigan Municipal Electric Association (MMEA)
8.) EPA's SBREFA Analysis About the Impact of the Rule on Small Public Power Entities is Not Correct, Given the Potential for Major Negative Impacts from the Proposed Rule  In its required SBREFA analysis, EPA finds that small municipal utility units will not experience significant problems because they "are not expected to make operational changes as a result of this rule (e.g., install control equipment or switch fuels)." 3  However, given the problems with EPA's proposed allowance allocation methodology and unit-specific allocations outlined above, this SBREFA finding is not valid, as the several of the Michigan public power units commenting here will be required to either install very expensive pollution controls immediately, or consider shutting the units because of the Transport Rule. Transport Rule at p. 43,355. It is arbitrary and capricious for EPA to assume no impacts on small municipal utilities, and not even model those impacts, but then impose them on units through under-allocations of allowances, unless EPA intends to close or severely constraints these critical units. [EPA-HQ-OAR-2009-0491-2828.1, p.15]
7.) Revisit EPA's obligations under the Small Business Regulatory Enforcement Fairness Act to assess and attempt to avoid disproportionate impacts on small entities, like Michigan public power utilities. [EPA-HQ-OAR-2009-0491-2828.1, p.16]

3. Likewise, in its IPM base case model for the Transport Rule, EPA explains that it doesn't even model coal-fired EGUs under 100 MW capacity retrofitting SCR for NOx or FGD for SO2 removal, because "FGD or SCR retrofits to such small units are very costly in any case . . ." See Small Unit Retrofit Options Present in Policy Case Model Runs in both v. 3.02 and 4.10 of the IBM Base Case technical support documentation. [EPA-HQ-OAR-2009-0491-2828.1, p.15]
Response: 
EPA did conduct analysis on all small entities, including municipal utilities to satisfy both the SBREFA and UMRA executive order requirements and has made the results available in Chapter 9 of the RIA. EPA certified No SISNOSE for this action for a number of reasons outlined in the preamble and RIA. In the final RFA analysis, EPA found that there would not be an economic impact greater than 1% on a substantial number of entities meeting the definition of "small" for the purposes of this rulemaking.  This comment does not provide evidence to refute the number of small entities affected, nor the magnitude of the impact.  EPA has not changed its finding based on the fact that the number of small entities affected is not zero. To certify No SISNOSE, there must not be a significant impact on a substantial number of small entities according to the guidance on the executive order.
In response to a number of comments on allowance allocations, EPA has modified the allowance allocation methodology for the final Transport Rule.
EPA also notes that it received less than a handful of comments on its SBREFA analysis and determination out of thousands of public comments submitted.  The minimal number of comments indicates that EPA fulfilled its obligations and that it's finding is reasonable.
Finally, with regard to the assurance provision penalty, EPA has finalized that determinations are made at the common designated representative level.  Entities-- large or small-- may share a common DR to provide more operational flexibility and lower the penalty risk for any single unit that exceeds its allocation.

XII.C. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments

Organization: Fond du Lac Reservation
Comment: 
Fond du Lac Reservation
Tribal Consultation
Apart from the impact that the Transport Rule could have on Indian tribes, and the need for ways to incorporate them under the Rule, the Band finds that the EPA failed to adequately consult with tribes. [EPA-HQ-OAR-2009-0491-3707, p.6]
In reference to Executive Order ('EO') 131375, Consultation and Coordination with Indian Tribal Governments, the EPA indicates that the Transport Rule 'will not have substantial direct effects on tribal governments, on the relationship between the Federal government and Indian tribes, or on the distribution of power and responsibilities between the federal government and Indian tribes, as specified in Executive Order 13175.' Such a statement flies in the face of reason as Indian tribes have to live with the consequences of how the Agency chooses to reduce NOx and SO2, and its subsequent impacts to tribal peoples and their environment. [EPA-HQ-OAR-2009-0491-3707, p.6]
EPA's finding concerning the Transport Rule's impact on Indian tribes is also contrary to the intent of the EO which requires the EPA to develop an accountability process that ensures 'meaningful and timely input by tribal officials in the development of regulatory policies that have tribal implications.' In addition, EPA's Indian Policy requires the Agency to fulfill its trust responsibility to tribes and conduct Tribal consultation on a government-to-government basis. In the case at hand, the EPA has failed to follow the edicts of both the EO and Agency's Indian Policy, and has therefore failed to fully protect and preserve federal treaty trust resources important to tribes such as hunting and fishing rights, with such rights considered integral to many tribes' continued existence. Furthermore, informing tribal representatives about the Rule as part of a conference call of NTAA members 14 does not satisfy EPA's responsibility of consulting with tribes on a government-to-government basis. [EPA-HQ-OAR-2009-0491-3707, pp.6-7]
This lack of consultation is especially disappointing in light of the EPA's Draft Tribal Consultation Policy. While this policy has not yet been finalized, the existence of the Draft Policy clearly shows that the EPA believes its current policy to be in need of improvement. After holding a number of conference calls with tribes regarding this policy and receiving comment letters, the Band hoped that the EPA would do the right thing and conduct proper consultation on this rule, even though not technically required to do so. [EPA-HQ-OAR-2009-0491-3707, p.7]
The Band therefore recommends that the EPA conduct meaningful consultation with the nation's tribes regarding the Transport Rule. [EPA-HQ-OAR-2009-0491-3707, p.7]
Response: 

Since this letter was received, EPA has offered and participated in consultation with interested tribes regarding the Transport Rule and its potential impacts on tribes.  EPA also addressed tribal concerns and provided opportunity to comment in the January 7, 2011 Notice of Data Availability for Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone: Request for Comment on Alternative Allocations, Calculation of Assurance Provision Allowance Surrender Requirements, New-Unit Allocations in Indian Country, and Allocations by States.  EPA has undertaken appropriate consultation regarding the Transport Rule.
Organization: National Tribal Air Association (NTAA)
Comment: 
National Tribal Air Association (NTAA)
Furthermore, it is also important the EPA understands that interactions with the organization do not substitute for government-to-government consultation which can only be achieved through direct communication between the federal government and Indian Tribes. [EPA-HQ-OAR-2009-0491-2778.1, p.1]
Tribal Consultation
Apart from the impact that the Transport Rule could have on Indian Tribes, and the need for ways to incorporate them under the Rule, the NTAA finds that the EPA failed to adequately consult with Tribes. [EPA-HQ-OAR-2009-0491-2778.1, p.6]
In reference to Executive Order (EO) 131375, Consultation and Coordination with Indian Tribal Governments, the EPA indicates that the Transport Rule 'will not have substantial direct effects on tribal governments, on the relationship between the Federal government and Indian tribes, or on the distribution of power and responsibilities between the federal government and Indian tribes, as specified in Executive Order 13175.' To make such a statement flies in the face of reason as Indian Tribes have to live with the consequences of how the Agency chooses to reduce NOx and SO2, and its subsequent impacts to Tribal peoples and their environment. [EPA-HQ-OAR-2009-0491-2778.1, pp.6-7]
EPA's finding concerning the Transport Rule's impact on Indian Tribes is also contrary to the intent of the EO which requires the EPA to develop an accountability process that ensures 'meaningful and timely input by tribal officials in the development of regulatory policies that have tribal implications.' In addition, EPA's Indian Policy requires the Agency to fulfill its trust responsibility to Tribes and conduct Tribal consultation on a government-to-government basis. In the case at hand, the EPA has failed to follow the edicts of both the EO and Agency's Indian Policy, and has therefore failed to fully protect and preserve federal treaty trust resources important to Tribes such as hunting and fishing rights, with such rights considered integral to many Tribes' continued existence. Furthermore, informing Tribal representatives about the Rule as part of a conference call of NTAA members, as was done in cooperation with our organization, does not satisfy EPA's responsibility of consulting with Tribes on a government-to- government basis. [EPA-HQ-OAR-2009-0491-2778.1, p.7]
The NTAA therefore recommends that the EPA conduct meaningful consultation with the nation's Tribes regarding the Transport Rule. Our organization is also pleased to offer any assistance that it can provide the Agency in meeting this obligation of consultation on its part. [EPA-HQ-OAR-2009-0491-2778.1, p.7]
Response: 
Since this letter was received, EPA has offered and participated in consultation with interested tribes regarding the Transport Rule and its potential impacts on tribes.  EPA also addressed tribal concerns and provided opportunity to comment in the January 7, 2011 Notice of Data Availability for Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone: Request for Comment on Alternative Allocations, Calculation of Assurance Provision Allowance Surrender Requirements, New-Unit Allocations in Indian Country, and Allocations by States.  EPA has undertaken appropriate consultation regarding the Transport Rule.
XII.D. Executive Order 13211: Actions That Significantly Affect Energy Supply, Distribution, or Use

Organization: American Electric Power
Comment: 
American Electric Power
The impact of investments and additional operating costs that are needed to comply with all of these EPA rules and regulations in addition to the proposed Transport Rule is substantial and should be factored in, specifically when considering the retrofit pollution control versus retirement or conversion to gas decision. It is evident that EPA did not do this. In fact, EPA only predicts an additional 1.2 Gigawatts of retirements across the United States due to this rule. AEP alone projects it may have more retirements than EPA's projection for the U.S. in the 2014-2015 time frame. [EPA-HQ-OAR-2009-0491-2665.1, p.19]
Response: 
As discussed in section III of the Preamble to this rule, EPA will provide full opportunity for notice and comment on each rule as they are proposed and finalized.   EPA will include the final Transport Rule in its regulatory impact analyses of subsequent rulemakings.
EPA does not believe this rule negatively impacts grid reliability.  See section V.D.2.g of Response to Comment document.
Organization: Consumers Energy
Comment: 
Consumers Energy
As proposed, the rule would significantly affect the planning, spending and operations of Consumers Energy, as well as those for all utilities within the Transport Rule region. Our company's planning includes capital expenses and scheduling built around the final and still enforceable CAIR to create and maintain a balanced energy portfolio. As proposed, EPA's Transport Rule would force acceleration of spending and construction schedules (if even possible) and, in all likelihood, increase costs for capital expenditures that Consumers Energy currently projects to total in excess of one billion dollars The likely cost increases, coupled with accelerated retirements of units throughout the proposed Transport Rule region, including Michigan, have also caught the attention of the Michigan Public Service Commission (MPSC) which serves to protect the ratepayers in Michigan. [EPA-HQ-OAR-2009-0491-2837.1, p.3]
Consumers Energy's comments address issues that are specific to our company, while highlighting issues that are raised in greater detail by UARG, EEI and others. We believe that this proposed rule is seriously flawed and must be modified to effectuate the intent of the Clean Air Act and protect the ratepayers throughout the proposed Transport Rule region. [EPA-HQ-OAR-2009-0491-2837.1, p.3]
All of the changes and increased costs will drive up costs and have a negative impact on our customers. [EPA-HQ-OAR-2009-0491-2837.1, pp.8-9]
Response: 
EPA believes it is feasible for the electric power sector to meet the 2012 and 2014 compliance deadlines.  Furthermore, EPA projects that the impact of the Transport Rule on retail electricity rates will be negligible.  See sections VII.C.2 and XII.H of preamble.
Organization: DoubleTree Hotel Roanoke and Conference Center
Comment: 
DoubleTree Hotel Roanoke and Conference Center
I agree with the efforts made to reduce the environmental impact of using coal to generate electricity, but regulations need to be rational. As proposed, this goes beyond what is needed, will cause customers to needlessly pay more for our electricity that is essential for our businesses, homes and will negatively impact the economies of the states that we live. [EPA-HQ-OAR-2009-0491-2142, p.1]
Response: 
EPA projects that the impact of the Transport Rule on retail electricity rates will be negligible.  See section XII.H of preamble.
Organization: Louisiana Public Service Commission
Comment: 
Louisiana Public Service Commission
Matters affecting the costs of power generation for all of these EGUs, such as those included in the proposed CATR, have direct bearing on the Commission's constitutional charge to ensure that rates are fair, just, and reasonable. While the LPSC is not the state's environmental regulator, its decisions have direct bearing on the development and operation of the state's regulated EGUs and their use of natural resources. Likewise, decisions made by environmental regulators such as the EPA and the Louisiana Department of Environmental Quality (LDEQ) can have direct impacts on the utilization of EGUs in the state. Thus, the LPSC frequently monitors and provides input on certain environmental regulations that impact the delivery of safe, reliable, and economic power to Louisiana citizens. As a general matter, the LPSC Staff is concerned that the proposed CATR will create unnecessary rate impacts and have negative implications for Louisiana energy costs and the state's overall economic development with little to no corresponding improvement in environmental quality, given the tenuous and questionable impacts stated in the proposed rule. Further, ramping down power generation at units identified as problematic in the proposed CATR, could likely lead to serious reliability issues. Adopting regulatory policies that run the risk of dramatically increasing costs and/or reducing power system reliability, is simply unacceptable. [EPA-HQ-OAR-2009-0491-2670.1, p.3]
The following comments of the LPSC Staff are offered to the EPA to express its position and concerns about the proposed CATR. The LPSC Staffs comments are limited to three general areas: (1) policy and implementation issues associated with the proposed rule; (2) capital investment bias created by the proposed rule; and (3) the baseline data and allocation methodology associated with the proposed rule. The LPSC Staff's silence on other issues or components of the proposed rule should not be . interpreted as support or concurrence with those provisions. Other Louisiana stakeholders from municipal governments, to industrial generators and users, to IPPs, and even utilities themselves, are offering comments on many of the provisions left unaddressed by the LPSC Staff's comments. To the extent that other parties such as the Louisiana Department of Environmental Quality (LDEQ) and the Louisiana Chemical Association (LCA) provide comments suggesting that Louisiana should not regulated hereunder, the LPSC fully supports and adopts the arguments of those parties. [EPA-HQ-OAR-2009-0491-2670.1, pp.3-4]
Response: 
EPA projects that the impact of the Transport Rule on retail electricity rates will be negligible.  See section XII.H of preamble.
See section V.D.2.g of Response to Comment document.
Organization: Mass Comment Campaign (221) (American Electric Power)
Comment: 
Mass Comment Campaign (221) (American Electric Power)
I applaud the agency's efforts to improve air quality, but believe that it must be done in a realistic, cost-effective way that will not cause utility ratepayers to incur unnecessary costs. [EPA-HQ-OAR-2009-0491-3528_Mass, p.1]
Response: 
EPA projects that the impact of the Transport Rule on retail electricity rates will be negligible.  See section XII.H of preamble.
Organization: Ohio Manufacturers Association (OMA)
Comment: 
Ohio Manufacturers Association (OMA)
The OMA, the largest advocacy organization for Ohio's manufacturers, strongly urges EPA to delay implementation of the Transport Rule as it is proposed. As drafted, the current proposal threatens to seriously harm our members, representing the largest sector of Ohio's economy, and with them, Ohio's still-fragile economy. We have serious concerns about numerous aspects of the proposed rule. [EPA-HQ-OAR-2009-0491-2651.1, p. 1]
OMA believes that the reductions sought in the Transport Rule can be achieved in a much more cost-effective manner that does not threaten Ohio's manufacturing sector and the economy as a whole. There is evidence that CAIR is already accomplishing what the Transport Rule aims to accomplish, and at a lower cost. Before EPA takes further action on the Transport Rule, OMA would like to see additional collaboration between EPA, the state environmental agencies and power generators to determine a more realistic reduction schedule that can be implemented at a more reasonable cost. [EPA-HQ-OAR-2009-0491-2651.1, p.2]
Response: 
EPA projects that the benefits of the final rule far outweigh the costs, and impacts on the manufacturing sector are projected to be minimal.  See RIA Chapter 8.
Through the regulatory development process, EPA has collaborated with interested parties as discussed in section III of the preamble to the final Transport Rule, and is finalizing a rule which EPA believes follows a realistic schedule with minimal cost impacts.  As described in preamble section VI.D, the D.C. Court of Appeals rejected the state budgets in CAIR as arbitrary and capricious and not consistent with CAA section 110(a)(2)D)(i)(I) (North Carolina, 531 F.3d  918 and 921) and remanded CAIR to EPA to promulgate a new rule (the Transport Rule) replacing CAIR and consistent with the Court's decision (North Carolina, 550 F.3d 1178).  
Organization: Reynolds, W. Roscoe
Comment: 
Reynolds, W. Roscoe
Today, I was given a special alert from the Appalachian Power Virginia External Affairs Team. This alert was given to me by email.
I am sending you a copy of the email. I represent the 20' Senatorial District in the Virginia General Assembly. Most of the people that I represent are customers of Appalachian Power.
Since 2006, people I represent who are Appalachian customers have seen the cost of a kilowatt hour of electricity increase by more than 60%. This has had a devastating effect on many businesses, local governments, and individual consumers.
Appalachian Power is saying to me that the EPA's proposed Transport rule will have negative financial impacts on electricity costs.
The people that I represent who are Appalachian customers cannot pay any more for electricity than they are presently paying. Please take no action by regulation or otherwise that will result in the cost to consumers in  kilowatt hour of electricity increasing. Increases in costs of electricity to the people that I represent. the businesses that I represent and the local governments will be very harmful. I am also sending this message by United States Mail. [EPA-HQ-OAR-2009-0491-2512, p. 1]
Response: 
EPA believes the benefits of this rule far outweigh the costs.  Moreover, EPA projects that the impact of the Transport Rule on retail electricity rates will be negligible.  See section XII.H of preamble.
Organization: Texas Commission on Environmental Quality
Comment: 
Texas Commission on Environmental Quality
The TCEQ requests that the EPA address the effects of this rule on energy consumers. If adopted, the strong disincentives for coal-fired power production will likely have far reaching economic effects beyond the obvious impacts on energy consumers. This economic 'ripple effect' on overall consumer prices and production does not appear to have been fully considered by the EPA, nor made available for full public review and comment. [EPA-HQ-OAR-2009-0491-2857.1, p.3]
Response: 
EPA fully considered macroeconomic impacts of the rule.  See Chapter 8 of the RIA.

XII.E. Executive Order 12898: Federal Actions to Address Environmental Justice (EJ) in Minority Populations and Low-Income Populations

Organization: American Lung Association of the Mid Atlantic
Comment: 
American Lung Association of the Mid Atlantic
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.32-33.]
EPA must also codify science-based Environmental Justice protections to ensure that these advantages are not won on the backs, and in the lungs of those most vulnerable and least empowered to protect themselves.
Response: 
As noted in section XII.J of the preamble to the final Transport Rule, EPA is confident that the most vulnerable and sensitive individuals - children, the elderly, and people with existing heart and lung diseases, including asthma - will receive the largest benefits from implementation of this rule. Through this rule and other actions we take, including the proposed mercury and air toxics standards for power plants, toxics standards for other types of sources, emissions standards for cars, trucks, and other vehicles, and national ambient air quality standards for ozone and fine particles, EPA is committed to ensuring that the most vulnerable Americans receive the benefits of breathing cleaner air.
Organization: Exelon
Comment: 
Exelon
Although some areas may see increases in generation costs, these rules will likely increase equity. Those whose costs may increase are located in areas of the country that have historically enjoyed lower electricity costs while the pollution and health impacts from that low cost electricity have fallen on downwind areas further burdened by higher electricity costs. As evidenced by Dr. Cicchetti's report, these rules will alleviate disincentives to investment in our nation's downwind urban centers and promote environmental justice by lightening the pollution burden imposed on disadvantaged urban populations.10 ([EPA-HQ-OAR-2009-0491-2666.1, p.13)  [[See Docket Number EPA-HQ-OAR-2009-0491-2666.1, pp.84-151 for Dr. Cicchetti's report.]]

10. Environmental justice is one of the EPA's highest priorities and one of the seven guiding principles in EPA's strategic plan. See Memorandum from Stephen L. Johnson, EPA Administrator, Reaffirming the U.S. Environmental Protection Agency's Commitment to Environmental Justice (Nov. 4, 2005).
Response: 
EPA agrees with the commenter that this rule will reduce transport of upwind pollution to downwind states and that this will benefit the health and welfare of people living in downwind areas. Further, EPA agrees that our assessment of the benefits of the rule does not fully account for every aspect of every potential or likely benefit. EPA did conduct an assessment of the environmental justice effects of this rule that included some distributional analyses. This assessment is included in section XII.J of the final rule preamble. Based on the environmental justice assessment, EPA has determined that the rule will provide substantial benefits to environmental justice communities in the area affected by the rule.
Organization: Greenpeace Washington, DC
Pilsen Environmental Rights and Reform Organization (PERRO)
Layer, Harrison
Pennsylvania Department of Environmental Protection
American Lung Association
American Lung Association of Georgia
Clean Air Task Force
Rizzo, M.D., Albert A.
Sierra Club, Pennsylvania Chapter
White, Dr. Yolanda
Comment: 
American Lung Association
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp. 8-13.]
As usual, those who are most vulnerable bear the greatest burden. They are children and teens whose lungs are still growing, our seniors who have breathed pollution for their entire lives, and those who suffer from disease such as asthma, chronic obstructive pulmonary disease or COPD, cardiovascular disease, and diabetes. You can add families from low-income areas to that list because they, too, are hurt disproportionately. But even healthy adults who work or exercise outdoors can be harmed by breathing these noxious fumes.
American Lung Association of Georgia
These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010. See Docket Number EPA-HQ-OAR-0491-1939, pp.56-59.
We are all aware that a smog alert is forecasted for today in Atlanta. Children, seniors, people with chronic lung diseases like asthma, people with cardiovascular disease and diabetics, as well as people who live in poverty face greater risks from these pollutants.
Clean Air Task Force
In 2000, 2004 and again in 2010, Clean Air Task Force commissioned Abt Associates to develop estimates of health impacts using a well-established and extensively peer-reviewed methodology that has been approved by both the U.S. Environmental Protection Agency's (EPA's) Science Advisory Board and the National Academy of Sciences (NAS). In fact, the same methodology has provided the basis for regulatory impact analyses in the context of recent EPA rulemakings. As noted earlier, Abt Associates' analysis finds that fine particle pollution from existing coal plants is expected to cause approximately 13,000 deaths in 2010. Additional impacts include more than 20,000 heart attacks per year. The total monetized value of these adverse health impacts adds up to more than $100 billion per year. This burden is not distributed evenly across the population. Adverse impacts are especially severe for the elderly, children, and those with respiratory disease. In addition, the poor, minority groups, and people who live in areas downwind of power plants are likely to be disproportionately exposed to the health risks. However, between the 2004 and 2010 studies, over 130 flue gas desulfurization scrubbers were installed on power plants across the U.S. and, as a result, sulfur dioxide emissions and atmospheric sulfate levels have nearly declined by half over that short period. Consequently premature deaths have also declined from approximately 24,000 to 13,000 in 2010. As we discuss later, this clearly demonstrates the effectiveness of regulatory programs to address power plant emissions. Nonetheless, there is still a long way to go to fully remedy the problem. [EPA-HQ-OAR-2009-0491-2738.1, p. 11]
Greenpeace Washington, DC
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.37-38.]
I would also add that there are a variety of plants, especially in the Midwest in Region 5, especially Lake Shore and Bay Shore and Cleveland and Toledo, there's River Rouge in Michigan and Valley Plant and South Oak Creek Plant in Milwaukee, all of these plants have a large number of people living within a 3-mile radius, and many of them also have high levels of poverty and EJ communities within those areas.
Layer, Harrison
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.76-79.]
The next issue I bring up is one of environmental justice. Over 25 percent of Early County's population lives below the poverty line and half of the county's population consists of communities of color. Why should low-income communities with disproportionate numbers of historically disenfranchised people receive the environmental burden of providing power to the growing number of people in the Atlanta 6 metropolitan area? The people in Early County might be receiving jobs, but getting these jobs 8 would sacrifice the integrity of their air, soil, water and overall health.  
Pennsylvania Department of Environmental Protection
Additionally, the Transport Rule must not encourage emission leakage to smaller, dirty generators. These units may have a disproportionate impact on urbanized or minority communities near areas of load constraints. [EPA-HQ-OAR-2009-0491-2660.1, p.6]
Pilsen Environmental Rights and Reform Organization (PERRO)
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.44-48.]
You asked earlier about EJ communities in the areas around these power plants. I'm from one of them, so I can tell you about it.
I'm from the Pilsen community. Pilsen is a low income or working class Latino, primarily Latino community in Chicago here on the southwest side.
We have located right in our neighborhood the Fisk power plant, literally across the street from a park, down the street from three schools, across the street from numerous apartment buildings.
There's also the Crawford plant in Little Village, which is a neighboring neighborhood to ours. It's very similar to ours, Latino population, primarily low income.
I think for Pilsen the last I checked the median income was about 26,000 a year, so we're definitely one of the lower-income communities in Chicago, and all the communities that surround us that are within half mile, mile, mile and a half from both Fisk and Crawford would be similar communities, either Latino or mostly Latino, African-American, mostly low income.
So when you talk about communities, you're talking communities that I live and I come from.
We are in the midst of a major effort right now to try to pass an ordinance in Chicago that would try to clean up these plants.
What's disturbing to us is that we know for these two plants alone there's about 40 premature deaths a year and about 2,800 asthma attacks a year from just Fisk and Crawford.
So it's disturbing to hear that even if we were successful in passing an ordinance locally here in Chicago to reduce those health effects that we'd still be getting pollution from nearby states, and that you're talking tens of thousands when you add in all those other plants.
Unfortunately, communities like Pilsen and Little Village rarely get their voices heard on these matters.
Pilsen is a place that's impacted by multiple pollution sources so, you know, dealing with a problem like this, our number one pollution problem, would be a huge step forward in terms of improving the health of our communities.
We work very closely with the Allejo Medical Center which is a medical center in our neighborhood which has told us that they have incredibly high rates of asthma compared to other parts of the state, other parts of the city, so this is obviously a very big concern to us.
Rizzo, M.D., Albert A.
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010. See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.15-20.]
Making our mission more imperative is the fact that these problems affect all of us but some more than others. The most vulnerable people include children, teens, seniors, people with lung disease, and people with diabetes. The burden also falls hard on people with low incomes who suffer disproportionately from the pollutants they breathe often because of where they tend to live. Healthy adults who work or exercise outdoors aren't left out either, as studies show that their lungs are measurably affected by inhaling these toxic pollutants.
Sierra Club, Pennsylvania Chapter
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010. See Docket Number EPA-HQ-OAR-2009-0491-1938, pp. 133-136]
Lower income communities and communities of color suffer proportionately from the health impacts of bad air. Air pollution is a Civil Rights issue and an economic justice issue. We need to keep that in mind.
White, Dr. Yolanda
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010. See Docket Number EPA-HQ-OAR-0491-1939, pp.65-71.]
Children, pregnant women, the elderly, and African-Americans are most vulnerable to the adverse health effects of air pollutants, as well as those with pre-existing lung and/or heart disease.
African-Americans, already victim to health disparities, have both disproportionate exposures to air pollution and disproportionate adverse health and developmental outcomes. African-Americans make up 13 percent of the population and are responsible for 20 percent fewer greenhouse gas emissions than whites per capita, Yet 71 percent live in counties that violate federal air pollution standards, 78 percent live within 30 miles of a coal-fired power plant, and are three times more likely to be hospitalized or die from asthma and respiratory illness linked to air pollution.
Response: 
EPA agrees with the commenters that people living near power plants and other sources, some of whom are poor or members of minority racial or ethnic groups, may be exposed to air pollution at levels that cause concern. See the preamble for the final rule, section XII.J, for EPA's analysis of the Transport Rule's effects on environmental justice communities, as well as other sensitive and vulnerable populations, and how those stakeholders were engaged in the development of the final rule. In addition, section III of the preamble includes a discussion of additional EPA rules beyond this final Transport Rule that are also likely to benefit people living in areas affected by pollution from power plants, including people living near power plants.
Organization: National Mining Association (NMA)
Peabody Energy Company
Comment: 
National Mining Association (NMA)
These costs fall particularly hard on low incomes families, the elderly and the disabled. The Low Income Home Energy Assistance Program (LIHEAP) and similar governmental agencies are chronically overwhelmed with requests for support for utility bills when home heating costs surge. Millions of families cannot sustain the escalating electric rates and home heating costs caused by high and volatile natural gas prices: 21 percent of LIHEAP recipients are families with children under five years of age, 37 percent are elderly, and 50 percent are disabled. [EPA-HQ-OAR-2009-0491-3732.1_NODA, p. 8]
Peabody Energy Company
But the unresolved questions relating to shale gas are so profound and far-reaching that any EPA action that leads to an increase in dependence on gas for power generation opens the door to not only markedly higher costs of electricity, but also substantial increases in the price of natural gas for families and businesses. [EPA-HQ-OAR-2009-0491-3762.1_NODA, pp. 4-5]
Response: 
EPA is sensitive to the impact of costs of pollution control on low-income individuals, families and businesses and strives to design our policies and programs to achieve environmental goals in a cost-effective manner. As described in section VII.A of the rule preamble, EPA believes that the use of the limited interstate trading remedy in this final Transport Rule is the most cost-effective and practical way of eliminating significant contribution from upwind states to downwind nonattainment and maintenance areas within the requirements of the Clean Air Act. While EPA agrees that some consumers are less able to afford increases in electricity or natural gas costs than others, as noted in the preamble EPA estimates that the price effects will be modest. The final Transport Rule is estimated to increase residential electricity prices in 2014 less than $1/month. EPA also projects that electric power sector-delivered natural gas price will increase by about 0.3% over the 2012-2030 timeframe and that natural gas use for electricity generation will increase by approximately 200 billion cubic feet (BCF) by 2014.  Both of these increases are generally less than what occurs as a result of fluctuating fuel prices and other respective market factors (see section XII.H. of the preamble). In addition, the total costs (approximately $800 million) are much smaller than the health benefits (estimated at more than $110 billion) that will accrue to the same consumers, including less risk of premature death, fewer heart attacks, fewer asthma attacks, fewer hospitalizations, and the recovery of millions of days when people miss work or school due to pollution-related symptoms. Overall, EPA estimates that for every dollar in costs to comply with this rule, consumers will receive as much as $350 in health and quality of life benefits.
Organization: New Orleans City Council
Florida Municipal Electric Association (FMEA)
Louisiana Energy and Power Authority (LEPA)
Comment: 
Florida Municipal Electric Association (FMEA)
EPA has provided a cursory assessment and explanation of the impacts of its Proposed Transport Rule on the utility sector. But EPA has not attempted to analyze the combined impact of this proposal with other rules it has either recently promulgated, or is actively developing. Each of these rules individually will have a significant impact on the cost of electricity generation and transmission; combined, EPA's initiatives could have a crippling and irreparable impact. Nor has EPA attempted to assess the Proposed Transport Rule's impact, or the impact of all relevant rules combined, on electric system reliability, our national economy (especially given these sensitive and volatile economic times), or the disproportionate impact on lower socio-economic groups and individuals. [EPA-HQ-OAR-2009-0491-2656.1, pp.6-7]
Louisiana Energy and Power Authority (LEPA)
While EPA ostensibly considered the health and environmental impacts of reduced air emissions on low income, minority, and Native American populations, the EPA does not appear to have accounted for the fact that those populations in LEPA's control area, as well as other areas affected by the proposed rule, could be left without power because of the Transport Rule. [EPA-HQ-OAR-2009-0491-2700.1, pp.14-15]
New Orleans City Council
New Orleans has struggled to rebuild itself after the devastation of Hurricanes Katrina, Rita, Gustav and Ike. Many in the city still struggle with daily life. As of October 2009, approximately 62,400 of ENO's 112,000 (or roughly 55%) residential customers fell into the U.S. Department of Housing and Urban Development's low income classification. These customers simply cannot afford increases in their utility bills, and the Council has been fighting to keep utility bills as low as possible as the city rebuilds. [EPA-HQ-OAR-2009-0491-2719.1, p.2.]
Response: 
EPA shares commenters' concerns regarding potential economic costs of the Transport Rule, especially for low-income individuals and communities. EPA also recognizes that these same individuals and communities already bear large costs associated with the effects of air pollution on their health and quality of life. As a result, EPA was careful to design the Transport Rule in a way that provides significant public health benefits while keeping any electricity price or reliability impacts to a minimum. For example, as noted in sections VI and VII of the preamble, EPA considered the costs of pollution control and the emission reductions possible at those costs within the given timeframe in setting the budgets for each state. EPA also designed the rule with some flexibility, including limited interstate emissions trading and variability and assurance provisions, that will allow sources to accommodate shifts in power generation without affecting environmental protection or energy reliability.
The projected costs of the final rule are not likely to be excessively burdensome even for low-income groups or individuals. EPA projects a very small increase in electricity price as a result of this rule of approximately $1/month in 2014. Furthermore, the data are clear that the benefits of this rule, especially for those most vulnerable to the health effects of air pollution, greatly exceed the costs: the Transport Rule provides as much as $350 in benefits for every dollar in costs.
Organization: Public Interest Law Center of Philadelphia
Comment: 
Public Interest Law Center of Philadelphia
The fundamental problem with emissions trading is the increased localized pollution burden it creates for communities situated near plants who purchase the additional allowances. Because of historic plant-siting decisions, these negatively affected communities are very likely to consist of minority and poor populations who already suffer disproportionately from increased rates of asthma, heart disease, and other health challenges that are exacerbated by the very air pollutants that CATR seeks to control. The EPA identifies these areas as Environmental Justice ("EJ") communities and seeks to promote the "fair treatment and meaningful involvement of all people regardless of race, color, national origin, or income with respect to the development, implementations, and enforcement of environmental laws, regulations, and policies." Office of Envtl. Justice, U.S. EPA, Environmental Justice 2000 Biennial Report, at vii (2000). To achieve this goal, and to adhere to the requirements of Title VI of the Civil Rights Act of 1964 and the amendments thereto, the EPA must be cognizant not to create disparate impacts from environmental policies such as emissions trading. More specifically, the Agency must examine the possibility that the Transport Rule may impact EJ communities disproportionately by creating incentives that could lead to worsened local air quality conditions, thus depriving residents of EJ areas of many, if not all, of the overall benefits the regulation is designed to achieve at the state and regional levels. [EPA-HQ-OAR-2009-0491-2817.1, p.3]
If the Transport Rule is implemented in any of its current proposed forms (all of which include either some form of emissions trading or in-state company-level averaging), we would suggest the EPA simultaneously implement programs aimed at protecting EJ communities that may suffer disproportionate harms as a result of locally unfavorable emissions imbalances created by intrastate or limited interstate emissions trading. [EPA-HQ-OAR-2009-0491-2817.1, p.4]
Specifically, we would suggest rules that limit the number of emission allowances available to affected power plants in close proximity to EJ communities and/or automatically escalate, through a weighting formula, the costs of emissions allowances for such affected sources in close proximity to EJ communities. This would prevent, or at least decentivize, such sources from perpetuating or even increasing levels of localized pollution in the areas that are most susceptible to the negative health consequences of NOX and SO2 emissions. [EPA-HQ-OAR-2009-0491-2817.1, p.4]
Regardless of the approach the Agency ultimately selects, the Agency should also implement programs to measure and monitor the effects of NOX and SO2 emissions allowance trading in EJ communities. If these studies reveal continued poor air quality or a decrease in air quality over time, the EPA should use its authority under the Clean Air Act to designate  -  even under the preferred approach or the intrastate trading approach  -  an individual emissions cap on the plant. Through this safety valve mechanism, the Agency can prevent local EJ communities from bearing a disproportionate burden of a state's pollution allowance. [EPA-HQ-OAR-2009-0491-2817.1, p.5]
If the Proposed Transport Rule is to be promulgated as a final rule in any of the three proposed formats, the EPA must conduct a detailed environmental justice analysis of the adverse health and environmental effects of emissions trading between plants, and the full report of that study should be made part of this rule making docket and should be made available to the public. If the goal of the Transport Rule is to promote cleaner air quality for millions of Americans, the EPA needs to ensure that residents of EJ communities do not suffer the paradoxical result of decreased air quality and increased adverse health impacts while communities that are more affluent and more white enjoy the full benefits of cleaner air that the Transport Rule is designed to return. [EPA-HQ-OAR-2009-0491-2817.1, p.6]
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.123-127.]
Under any of the Transport Rule proposals, then, environmental justice communities may suffer a perverse fate. Take Pennsylvania, a covered state for both nitrogen oxide and sulfur dioxide, as an example. A facility located in the less populous part of the state that achieves more than its required reductions might then trade its extra allowances to a power plant located close to one or more environmental justice communities in the more populous southeast part of the state. 
Although the overall state emission budget might thus be met, the power plant located near the environmental justice communities would, thanks to trading, be allowed to continue emitting pollutants at higher levels. The same result could occur under Alternative Two, which allows company-level averaging. 
Because local pollution would remain high, the nearby environmental justice communities would not receive the same public health and environmental benefits under the Transport Rule as the communities surrounding the facility on the other end of the trade. Indeed, the disproportionate imposition of environmental burdens on vulnerable communities would be perpetuated. 
If EPA's nascent focus on environmental justice under Administrator Jackson is to be seen as something other than mere lip service, the agency must ensure that the Transport Rule is consistent with its environmental justice obligations. If there is to be allowance trading, whether intrastate or interstate, it must be controlled in a manner that offers true protection to the environmental justice communities who would otherwise bear the pollution burdens.
Environmental justice communities are, to borrow the memorable words of civil rights activist Fannie Lou Hamer, 'sick and tired of being sick and tired.' EPA should not, in promulgating a Transport Rule that can provide so many public health and environmental benefits to all, leave open the possibility that vulnerable communities of color and of poverty will continue to be subjected to unequal treatment, based solely on the vicissitudes of power sector variability. 
Response: 
EPA has assessed the environmental justice effects of the Transport Rule, including its limited interstate trading provisions. This analysis was included in the proposed Transport Rule for public comment; it was updated and improved based on new data and modeling that became available in section XII.J of the final Transport Rule. This analysis included a structural analysis of the rule as well as analyses of emissions, air quality, and health benefits, and opportunities for public participation. All of these analyses indicate large health and environmental benefits for these communities; none show evidence of adverse effects. As a result, EPA concludes that we do not expect any disproportionate or adverse human health or environmental effects on minority, low-income, or tribal populations in the United States as a result of implementing this final Transport Rule.
During the comment period, EPA received several comments suggesting different types of restrictions on emissions trading or use of trading ratios to weight emission reductions in some areas more heavily than others. EPA's response to these comments is in section VII.A of the preamble to the final Transport Rule. 
EPA and the states do maintain a nationwide network of ozone and fine particulate monitoring stations that can be used to assess changes in air quality as a result of this Transport Rule and other actions to improve air quality. These data are publically available to communities, state representatives, and anyone else who is interested in assessing changes in air quality over time. 
It is important to note that EPA's authority for this rule is limited to eliminating emissions from upwind states that "significantly contribute" to nonattainment or interfere with maintenance of a national ambient air quality standard in a downwind state. Air quality at any location is a combination of pollution from local sources and pollution that is transported from more distant sources; as a result, large reductions in emission from far away sources can significantly improve air quality even if a local source does not reduce its emissions. 
In addition, this rule is only one of several tools that EPA, states, and communities are using to improve air quality in the nation's most polluted areas. Other actions include implementation of the Mercury and Air Toxics standards to reduce toxic emissions from power plants, emissions standards for cars, trucks, and other vehicles, and actions states take to attain and maintain the national ambient air quality standards. In addition, it is important to note that nothing in this final rule allows sources to violate their title V permit or any other federal, state, or local emissions or air quality requirements.

XIII. Regulatory Impact Analysis

Organization: American Clean Skies Foundation (ACSF)
Comment: 
American Clean Skies Foundation (ACSF)
The generating sector has the ability to accommodate additional fuel switching without compromising reliability. Under the current CATR proposal, EPA has projected that by 2014 approximately 1.2 GW of current coal-fired generation will be uneconomic to maintain. This is only 0.1% (l/10th of 1%) of the nation's generation capacity and about the size of a single, large coal-fired power plant. Greater reductions in coal-fired generation can be accommodated by the grid to meet the goals of the CAA and the Proposed Rule. Indeed, recent analysis by M.J. Bradley & Associates demonstrates that at least 10 to 20 GW of gas-fired generation could be substituted without threatening electric reliability and would 'help millions of Americans breathe easier, live healthier." [EPA-HQ-OAR-2009-0491-2759.1, pp.7-8]
Key assumptions in the proposed rule were based on EIA's Annual Energy Outlook (AEO) 2008. AEO 2008 contains significantly outdated information. Indeed, EPA itself recognizes the need to consider the AEO 2010 analysis. [EPA-HQ-OAR-2009-0491-2759.1, p.9]
5. EPA makes misstatements regarding natural gas generation that should be corrected.
EPA makes various misstatements regarding natural gas generation that should be corrected. [EPA-HQ-OAR-2009-0491-2759.1, p.9]
EPA overlooks the ability of clean-burning natural gas to provide base-load generation. EPA says that coal power plants 'typically supply 'base-load' electricity, the portion of electricity loads which are continually present, and typically operate throughout the day,' and that gas-fired generation 'is more often used to meet the variable portion of the electricity load and typically supplies 'peak' power." This fails to recognize the role that modem, base-load, high efficiency combined cycle power plants now play in the nation's generation portfolio. [EPA-HQ-OAR-2009-0491-2759.1, pp.9-10]
EPA also erroneously 'projects that most future growth in electric demand will be met with a combination of new natural gas- and coal-fired capacity." This projection conflicts with more current information that shows natural gas and renewables dominating new capacity additions. For instance, the Energy Information Agency AEO 2010 projects that most new capacity additions will use natural gas or renewable energy. [EPA-HQ-OAR-2009-0491-2759.1, p.10]
Response: 
EPA agrees with the commenter that electric reliability will not be threatened or affected by the implementation of the Transport Rule.  Our TSD on reliability, which is in the public docket for this rule, provides evidence to this statement. EPA has updated the EIA data to be used for the Transport Rule analyses to be based on AEO 2010 from AEO 2008.  This has the effect of addressing the commenter's concerns regarding EPA's statements on natural gas and base-load generation, and the amount of new electric power capacity that is projected to come from natural gas-fired units.
Organization: George Washington University Regulatory Study Center
Comment: 
George Washington University Regulatory Study Center
Executive order 12866 requires that major regulatory actions such as the Transport Rule be accompanied by a Regulatory Impact Analysis (RIA) that details the estimated costs and benefits associated with the proposed regulation. EPA has prepared an RIA for the Transport Rule, and goes into significant detail regarding the estimated health and welfare benefits associated with the Rule's required emissions reductions, and the economic costs of those reductions. While EPA presents some analysis of the uncertainty in the estimates of the concentration-response relationship for health effects (especially for the premature mortality risks associated with exposure to fine PM), the EPA's treatment of uncertainty in the Transport Rule RIA is problematic in several ways. In particular, the RIA lacks a more complete quantitative analysis that includes the major sources of uncertainty in its health benefits analysis. Without such an analysis, there is insufficient information in the RIA to make valid conclusions about the expected value of the benefits associated with the Transport Rule -- and therefore to make a fully-informed assessment of the Rule as a whole. The third section of these comments discusses these issues. [EPA-HQ-OAR-2009-0491-2573.1, p.6]
IV. The Treatment of Uncertainty in EPA's Analysis of Health Benefits  
As required by Executive Order 12866, the EPA includes an extensive RIA with the proposed Transport Rule. While the RIA provides some analysis of the uncertainty in the benefits estimates, its treatment of uncertainty falls short in several ways. Thus, the Transport Rule does not provide the necessary assessment of the quality and certainty of the estimates presented in the RIA. This issue is not limited to the Transport Rule -- recent EPA RIAs have all generally suffered from the absence of an adequate uncertainty analysis. As a result, the EPA should conduct and document a robust, quantitative analysis of uncertainty not only in the final version of the Transport Rule, but in other future rules as well. [EPA-HQ-OAR-2009-0491-2573.1,p.25]  
A. Quantitative Analysis of Uncertainty in EPA Rules
In a 2002 report titled Estimating the Public Health Benefits of Proposed Air Pollution Regulations, the National Research Council (NRC) of the National Academy of Sciences raised specific and detailed concerns with the EPA's treatment of uncertainty in the health benefits analysis for its RIAs.53, 54 While previous recommendations varied regarding the best way to address uncertainty, the 2002 report was unequivocal in recommending that EPA conduct a more comprehensive quantitative assessment of uncertainty in its primary regulatory analysis.55 The NRC report specifically called on EPA to conduct probabilistic, multiple-source uncertainty analyses present it in a clear and transparent way to decision makers and other interested readers. We agree with the NRC's criticisms and believe that the Transport Rule illustrates the shortcomings in EPA's recent RIAs. [EPA-HQ-OAR-2009-0491-2573.1, pp.25-26]
Analysis of benefits for EPA air rules typically requires a complex chain of analyses, including establishment of baselines such as the demographics and health status of the exposed population, estimates of the change in emissions with regulatory action, the effect of emissions changes on air quality, the resulting changes in the exposure of the population, and the resulting effect of changes in exposure on health. Because of the potential compounding of high-end or low-end assumptions in developing benefits estimates, EPA's approach generally masks the extent of the actual uncertainty in benefits estimates, giving policymakers and the public a misleading picture about the characteristics of the estimates presented in the analysis and their overall uncertainty. Without a quantitative uncertainty analysis, it is not possible to know whether the range of results that EPA presents in an RIA are within the ballpark of likely effects -- particularly where conservative assumptions or defaults are used -- or instead represent an overstatement or understatement of the likely outcomes. Thus, EPA's approach does not provide sufficient information about the expected value of net benefits or the expected value of benefits generally -- two variables that are key to judging whether expected benefits outweigh expected costs. [EPA-HQ-OAR-2009-0491-2573.1,p.26]
EPA's basic approach to presenting the uncertainty in its health benefits estimates in the Transport Rule RIA suffers from the same flaws as the approach critiqued in the 2002 NRC report. EPA has largely focused on the concentration-response relationship between exposure to air pollution and the associated health outcomes. EPA continues to develop a primary analysis presenting incidence estimates based on concentration-response functions from selected studies (or groups of studies). These estimates include "95th percentile confidence intervals" based on the standard errors of the effect estimates taken from the selected studies for each of the health endpoints. EPA uses Monte Carlo methods to generate the confidence intervals around the health incidence estimates and the monetized benefit estimates.58 [EPA-HQ-OAR-2009-0491-2573.1,p.26]
The problem with EPA's use of Monte Carlo analysis is that other key elements in the analysis -- for example, projected reductions in emissions and exposure -- are treated as known without any uncertainty.59 Thus, in discussing this approach, the NRC report found that "...no estimate can be considered best if only one of the large number of uncertainties is included in the analysis producing that estimate" (NRC 2002, 138). Further, the committee also found the intervals between the 5th and 95th percentiles of the distributions should not be interpreted as "90 percent credible intervals," or interpreted as a range within which "the true benefit lies with 90 percent probability" -- both of which labels the EPA has used in RIAs. [EPA-HQ-OAR-2009-0491-2573.1, p.27]
In response to concerns raised by the 2002 NRC report, EPA's Office of Air and Radiation (OAR) completed an expert elicitation study in 2006 -- the one significant response to the 2002 NRC report -- to better characterize the concentration-response relationship between fine PM exposure and premature mortality. However, EPA's Transport Rule RIA continues to provide only a qualitative discussion for many of the sources of uncertainty in the analysis, even though outside panels and studies continue to call for improved quantitative uncertainty analysis. Without a more comprehensive quantitative uncertainty analysis that addresses the important sources of uncertainty, it is difficult to know whether the resulting health benefit estimates reflect expected values or where these estimates fall within their associated probability distributions. To paraphrase the NRC report, no estimate can be considered best until the quantitative analysis includes the major sources of uncertainty in the analysis producing that estimate. And if estimates of health benefits do not reflect expected values, then there should be little reason to have any confidence in claims that benefits exceed the costs of a particular regulatory action. By developing probability distributions for each of the key components and combining these for the primary estimate, a quantitative uncertainty analysis would place EPA's estimates of benefits in the context of a comprehensive probability distribution. This would provide a better characterization of the EPA estimates and their uncertainty. [EPA-HQ-OAR-2009-0491-2573.1,p.27]
The following discussion illustrates this concern with EPA's benefits estimates and -- given the uncertainties in EPA's analysis -- suggests that there could potentially be a substantial bias in the benefits estimates. [EPA-HQ-OAR-2009-0491-2573.1, p.28]
B. Air Quality Modeling  
One critical area is the development of a quantitative uncertainty analysis for the exposure assessment, including the underlying air quality modeling. The 2002 NRC report stated that "...it is difficult to know how much confidence to place in the predictions ..." without evaluating the uncertainty in air quality modeling (NRC 2002, 6). As an illustration of the potential importance of this uncertainty, the recent NRC report on the Hidden Cost of Energy provides estimates of the benefits per ton associated with controlling emissions of SO2, NOx, and fine PM from coal-fired power plants that are substantially smaller than EPA's recent estimates (in some cases an order of magnitude smaller; see Table 3). Although a portion of this difference is attributable to a difference in the threshold assumption for the concentration-response, much of the difference in the estimates arises from differences in the air quality modeling used in the NRC report and by EPA63 (NRC 2009b, 73). Such differences could significantly alter estimated benefits by accounting for a difference of at least a factor of five in effect estimates. (See Figure 1.)  [EPA-HQ-OAR-2009-0491-2573.1, p.28]
We have argued above that EPA needs to develop a quantitative uncertainty analysis to support its estimates of the extent to which individual states contribute and/or interfere with maintenance in the non-attainment areas of neighboring states. This analysis is also a critical element to a quantitative uncertainty analysis for the RIA analysis of health benefits. [EPA-HQ-OAR-2009-0491-2573.1,p.28]
C. Alternate Concentration Response Functions  
EPA's draft Transport Rule RIA presents a "primary" or "core" estimate with "confidence intervals" for the estimated health effects based on the standard error in the effect estimates from the selected health studies. The health benefits of reducing the risk of premature mortality dominate the health effects estimate -- as reflected by the co-primary estimates developed from the most recent epidemiological-based estimates from the American Cancer Society study and from the Laden "six-city" study. [EPA-HQ-OAR-2009-0491-2573.1,p.28]
Differences in modeling the concentration-response relationship may account for a difference of at least a factor of five in effect estimates. Laden et al. (2006), in an update of the Six City study, provide estimates of the concentration response relationship that are 2.5 times greater than the effect estimates from the American Cancer Society study. In addition, a recent expert elicitation study of the fine PM-mortality relationship using European experts -- a part of the Harvard Kuwait public health project -- developed a combined estimate across experts for the concentration-response relationship for fine PM. (See Figure 2.) The ranges for the combined estimates (between the 5th and 95th percentile) are substantially greater than the ranges reported for the 2002 Pope and 2006 Laden studies. This wider range reflects the view among the experts that the published confidence intervals developed by EPA from the Pope (2002) and Laden (2006) studies -- confidence intervals based on the standard error for the effect estimates -- significantly understate the uncertainty of the fine PM-mortality relationship. [EPA-HQ-OAR-2009-0491-2573.1,p.29]
The Harvard-Kuwait study also explored the experts' views on the toxicity of the various components of fine PM. While they expressed uncertainty given the limited emerging literature on this issue, the experts viewed fine PM emitted directly from combustion processes as likely to be more toxic than the ambient mix of PM. In addition, they all viewed sulfate, nitrate, and crustal fine particulates as less toxic than the ambient mixture. The combined median estimates for long-term mortality associated with exposure to the least toxic component were less than half of the updated 2002 Pope estimate and comparable to the lower end 5th percentile estimate from that stud. (See Figure 2) In addition, the estimate from the 2006 Laden study is at the upper end (or even beyond) the range identified by the experts for low toxicity components in the Harvard-Kuwait study. Use of the combined expert estimate for lower toxicity components from the Harvard-Kuwait study would reduce estimated benefits by at least a factor of two. [EPA-HQ-OAR-2009-0491-2573.1,p.29]
F. Uncertainty in EPA's Cost Estimates  
EPA does not develop a quantitative uncertainty analysis for its cost estimates. The RIA only provides a point estimate of the cost of the Transport Rule. The RIA also provides a qualitative discussion with a concluding statement that in EPA's judgment the cost estimates are likely to overstate future costs. The reasons for a quantitative uncertainty analysis with regard to health effects also apply with equal force to the importance of performing such an analysis for the regulatory cost analysis. Addressing uncertainty for health effects without equivalent efforts in these other areas is akin to having only "one hand clapping."  [EPA-HQ-OAR-2009-0491-2573.1,p.31]
Third, we recommend that EPA undertake further efforts to develop a quantitative uncertainty analysis for its Transport Rule RIA. We believe that it is particularly important to develop such an analysis for the air quality modeling component of the RIA. Taking these steps would make the cost-benefit analysis in the RIA more robust, transparent, and defensible. [EPA-HQ-OAR-2009-0491-2573.1,p.32]

53 Earlier NRC reports raised similar concerns. These earlier reports found that proper characterization of uncertainty is essential and most have expressed the concern that analyses of health benefits understate associated uncertainties and leave decision makers with a false sense of confidence in the health benefits estimates.  
54 While the 2002 NRC report focused its attention on the uncertainty in the analysis of health benefits of air pollution regulations, the report recommended that EPA should also perform a similar quantitative uncertainty analysis for the valuation of health benefits and for the regulatory cost analysis. (NRC 2002, 127 and 148).  
55 Throughout this discussion, the term "uncertainty" refers to both "variability" that reflects the statistical variation in estimates as well as to the uncertainty associated with a more fundamental lack of knowledge. Variability comes from the fact that there is variation within a population in terms of differences in exposure and in susceptibility. Variability cannot be reduced, but it can be better characterized with better data. Uncertainty results from a lack of knowledge about key elements or processes in the risk assessment. It can be represented by quantitative analysis -- and can be reduced with additional research -- but cannot be eliminated. One element of uncertainty is that which exists about the variability of a population estimate -- and thus the analyst often cannot be precise about the extent of variability. (For a more complete discussion, see NRC 2009a, 93-99.)
58 Monte Carlo analysis involves the random sampling from the probability distribution functions for the various elements that comprise a "model" (in this case relating changes in emissions to health outcomes like increased risk of mortality). This process generates thousands of possible outcomes that allow the development of a probability distribution function for the outcome of interest (for example, mortality). EPA also uses the health effects distributions for the individual health end-points in conjunction with a distribution of the value of reducing the risks of these effects in a Monte Carlo analysis to generate a distribution for monetized benefit estimates.
59 Note that it is possible to construct a platform for calculating benefits that would incorporate uncertainty for each of the components in the benefits analysis. For example, the Fast Environmental Regulatory Evaluation Tool (FERET) allows the user to represent the emissions profile as a distribution in addition to developing distributions for health effects and for their valuation. See Farrow, Scott, Eva Wong, Rafael Ponce, Elaine Faustman, and Richard Zerbe, Facilitating Regulatory Design and Stakeholder Participation: The FERET Template with an Application to the Clean Air Act. In Improving Regulation: Cases in Environment, Health, and Safety. Washington, D.C.: Resources for the Future Press, 429-442.
63 The NRC report reports that its estimates of premature mortality differ from EPA's by a factor of four (NRC 2009, 73). Krupnick et al. (2006) examined the effect of adopting alternative source-receptor models and reported that there was a 3.5 fold difference in the mean benefit estimates for the two air quality models evaluated in that study (97).
Response: 
EPA has provided an extensive characterization of uncertainty for the benefits analysis in the Transport Rule.  Such a characterization is found in the RIA for the proposed rule, and applies the findings of the 2006 PM2.5 expert elicitation study.   This characterization builds on previous uncertainty characterizations prepared for previous RIAs (e.g., PM2.5 NAAQS RIA in 2006, ozone RIA in 2008), and is among the responses the Agency has prepared in response to the 2002 NRC report.  The RIA also includes the Agency's basis for how it derives the "core" estimate of benefits for the Transport Rule.  Finally, a listing of the uncertainties in the cost estimates is presented in the RIA, though this is not a full characterization of uncertainty in the cost estimates. 
Organization: National Mining Association (NMA)
Comment: 
National Mining Association (NMA)
EPA Must Produce a Cumulative Impact Analysis of Its Regulatory Program Affecting the Use of Coal
As discussed in more detail below, NMA believes that the regulatory analysis supporting the proposed Transport Rule is fatally flawed because it fails to take into account the cumulative impact of all of EPA's now-numerous completed, pending and expected rulemakings that are intended to and will have the effect of substantially reducing the usage of coal in the United States.1 These rulemakings include those affecting the use of coal for electric generation, where EPA is implementing a coordinated program to create, in its words, a "clean, efficient, and completely modern power sector," those affecting the use of coal for industrial, commercial and institutional purposes, such as the two rules specifically at issue here, and those directly affecting coal mining. [EPA-HQ-OAR-2009-0491-2868.1, p.2]
All of these rulemakings together will produce a dramatic and cascading series of effects not only in the coal industry but throughout the economy. There will be direct effects on coal employment and indirect effects on employment generally in the economy as a result of higher energy prices. Higher energy prices will also affect GDP and economic activity generally. American competitiveness will also be affected, as higher prices undermine the ability of American business to compete, with resulting off-shoring of American business and jobs. [EPA-HQ-OAR-2009-0491-2868.1,p.2]
Impact analysis performed by EPA now proceeds on a rulemaking-by-rulemaking basis, as if one rulemaking is unconnected to the next and as if the regulatory consequences are not cumulative. As a result, EPA's impact analyses mask the cumulative effect of the Agency's overall regulatory program. Individual-regulation impact analyses often predict limited effects, when in truth the overall program may produce extremely large consequences. [EPA-HQ-OAR-2009-0491-2868.1,p.2]
This balkanized approach to impact analysis impairs the public's right to notice and comment regarding EPA regulation. For instance, EPA's Regulatory Impact Analysis for the proposed Transport Rule shows relatively minor effects, which might lead the public to believe that the rule is relatively innocuous. Cumulative analysis, on the other hand, could lead to a far different conclusion -- that coal usage will decline dramatically as a result of the combined effect of numerous EPA rulemakings with attendant serious economic consequences. Armed with that information, the public would likely provide significantly different comment on the rule. [EPA-HQ-OAR-2009-0491-2868.1,p.2]
Cumulative impact analysis is not just good policy, it is required by law, both by Executive Order 12866 and the notice and comment rulemaking provisions of the Clean Air Act ("CAA"). NMA therefore urges EPA to defer final action on the two rules at issue here until the necessary cumulative impact assessment is produced. The specific type of analysis that NMA recommends is set forth as an attachment to these comments. [EPA-HQ-OAR-2009-0491-2868.1, p.3]
The effect of each EPA individual rule affecting coal, including the rules at issue here, cannot be understood without a cumulative analysis
Given EPA's intent to transform the power sector from what it is today into something different and given its efforts to reduce coal use throughout the economy, EPA must produce a cumulative and economy-wide assessment of this program. As EPA has proposed and finalized each individual regulation, including the proposed Transport Rule, EPA's impact analysis has been limited to the effect of the specific regulation in question. However, to understand the effect that all the rules together will create, it is necessary to study the effect of that program in toto. [EPA-HQ-OAR-2009-0491-2868.1,p.7]
These effects could be extremely large. For instance, EPA projects the annual cost of the SO2 NAAQS to be $2.9 billion to $3.0 billion in 2020, with most of those costs associated with the power sector13; the annual cost of the Transport Rule (all in the EGU sector) to be $3.7 billion in 2012 and $2.8 billion in 2014, with another $2 billion in 2020 and 2025; the annual cost of the ozone standard to be $32  -  44 billion, again with much of that cost in the EGU sector; and the total costs of the coal combustion residue rule to be over $8 billion under the Subtitle D option and over $20 billion with the Subtitle C option. Despite the request from NMA and others for EPA to assess the cost of its GHG regulatory program, EPA has refused to do so, and so that cost is unknown but could be very substantial as well. The other programs identified above will also add significant cost, with the new EGU MACT standards expected to have a potentially a very large impact. [EPA-HQ-OAR-2009-0491-2868.1, pp.7-8]
But these estimates, as large as they are, mask the overall effect of the regulations when considered cumulatively. The proposed Transport Rule is an example. EPA's draft Regulatory Impact Analysis ("RIA") for this proposed rule envisions relatively small impacts to coal usage. EPA projects that EGUs can meet the requirements of the rule by switching from high sulfur to low sulfur coal and by installing pollution control equipment, with the result that EPA estimates the retirement of only 1.2 GW of "small and infrequently used" coal-fired generating units by 2014.18 Based on the foregoing, EPA projects additional cost to the utility industry of $3.7 billion in 2012 and $2.8 billion in 2014 ($2006). [EPA-HQ-OAR-2009-0491-2868.1, p.8]
This EPA projection of almost no impact to the coal industry, however, is not meaningful because it is based on an analysis of the Transport Rule in isolation. Thus, even if EPA's projected assessment of the effect of the Transport Rule on coal is correct, that assessment assumes that there are no other forthcoming EPA regulations that will affect the use of coal, an assumption that is clearly wrong. The control options that the Transport Rule RIA envisions appear to exhaust (and likely go beyond exhausting) the ability of the power sector to absorb EPA regulation without large-scale closings of coal plants. The next regulation following the Transport Rule that adds cost to coal-fueled electric generation therefore will force plant closings, but it is incorrect to say that it was that next regulation and not the Transport Rule that causes the plant closings. Both rules and indeed the entire program cause that effect. [EPA-HQ-OAR-2009-0491-2868.1,pp.8-9]
EPA itself recognizes the need for cumulative analysis in an analogous situation. EPA requires that EPA reviewers of Environmental Impact Statements ("EISs") under the National Environmental Protection Act ("NEPA") take cumulative impacts into account, including consideration of "impacts that are due to past, present, and reasonably foreseeable actions." According to EPA, in assessing environmental impacts, it is necessary to assess "[t]he combined, incremental effects of human activity" rather than just the impacts of the particular action for which federal approval is sought. This is based on the recognition that individual actions "may be insignificant by themselves," but that cumulative impacts accumulate over time, from one or more sources and these cumulative effects must be taken into consideration. [EPA-HQ-OAR-2009-0491-2868.1, p.9]
The Council on Environmental Quality ("CEQ") also requires cumulative impact analysis in EISs. CEQ regulations require that agencies considering major actions that could affect environmental quality consider the "overall, cumulative impact of the action proposed (and of further actions contemplated)."23 [EPA-HQ-OAR-2009-0491-2868.1,p.9]
EPA's and CEQ's reasons for requiring cumulative impact analysis in EISs apply with equal force to economic analysis that EPA performs of its regulations. Where effects of a proposed action accumulate with those of other related actions, examining the effects of the proposed action in isolation will mask the overall effect of the action. That is as true for EPA's regulatory efforts to reduce coal usage as it is for environmental analysis in the NEPA context. To again cite the proposed Transport Rule as an example, as stated, EPA concludes that the rule will not materially affect the use of coal for electric generation. But under the rationale of CEQ's NEPA regulations, cumulative impact analysis should be conducted because "[c]umulative impacts can result from individually minor but collectively significant actions taking place over a period of time." [EPA-HQ-OAR-2009-0491-2868.1,p.10]
Cumulative impact analysis is also legally required under the rulemaking provisions of the CAA where, as here, EPA has undertaken coordinated and comprehensive regulation of the power and coal sectors through a series of related rulemakings. The purpose of these CAA rulemaking provisions is both to ensure good regulatory outcomes and to protect the public's right to have adequate notice of the need for and effect of EPA regulatory action so that the public can provide meaningful comment. [EPA-HQ-OAR-2009-0491-2868.1, p.12]
In this context, section 307(d)(3) of the CAA requires that a rule be accompanied by a statement of its basis and purpose, including "the major legal interpretations and policy considerations underlying the proposed rule."For the reasons discussed above, an underlying policy consideration of the Transport rule at issue here is EPA's overall intent to incent reductions in coal usage and increases in resources that EPA considers to be "clean." That being the case, EPA must provide an analysis of the consequences of this policy so that the public can comment adequately. As stated, the coal industry and public at large might have an entirely different view of these proposed rules if EPA produced a cumulative assessment rather than the narrow assessment reflected in the RIA. [EPA-HQ-OAR-2009-0491-2868.1,pp.12-13]
The U.S. Court of Appeals for the D.C. Circuit has stated that "[i]t is not consonant with the purpose of a rulemaking proceeding to promulgate rules on the basis of inadequate data, or on data that, [in] critical degree, is known only to the agency." Unless the public knows the overall consequences of EPA's regulations in context of other related regulations, the public's right to provide adequate comment is compromised. [EPA-HQ-OAR-2009-0491-2868.1,p.13]
Additional support for cumulative analysis is found in section 318 of the CAA, which requires that the Administrator undertake an analysis of the cost of complying with various EPA actions, including rulemakings under section 111(d). Under section 318(d), such analyses "shall be as extensive as practicable" consistent with the standards set forth in that provision. [EPA-HQ-OAR-2009-0491-2868.1,p.13]
NMA believes that the cumulative impact assessment should examine the following factors. [EPA-HQ-OAR-2009-0491-2868.1,p.13]
:: Overall impacts on the economy. Specifically, the effect on GDP and jobs. In this regard, some of EPA's regulations (in particular, the NAAQS) will not just affect energy but will affect other sectors of the economy as well both directly (for example, through direct regulation of manufacturing sources) and indirectly (for example, through increased energy costs). EPA should examine all reasonably foreseeable effects of its regulations on the overall economy. [EPA-HQ-OAR-2009-0491-2868.1,p.13]
:: Energy. This part of the analysis should include impacts on energy production and usage, energy costs, including fuel costs and retail electricity prices, and energy employment should be determined. Changes in the energy mix in the United States should be shown over time, including electric capacity additions and reductions by fuel type. Employment and energy cost impacts should be estimated for each energy sector. [EPA-HQ-OAR-2009-0491-2868.1, p.13]
:: Competitiveness. This part of the analysis should include impacts on industrial and manufacturing production and competitiveness. EPA should determine the impacts of regulation on cost of production and employment in the relevant sectors, and the extent to which production and jobs will be reduced as a result of higher costs and foreign competition. [EPA-HQ-OAR-2009-0491-2868.1, p.14]
:: Study design. Scenarios should be constructed for a business-as-usual case (without adoption of the contemplated regulations) and a case where EPA adopts the contemplated regulations. Additional scenarios may be included to test the findings under different appropriate assumptions. Where EPA regulation does not directly regulate but instead requires states to adopt regulations meeting EPA standards (for instance, EPA regulation under the NAAQS program and NSR/PSD program), EPA should estimate state regulatory responses, using a range if necessary. All assumptions, analytical methods and underlying data (or appropriate citations to data sources) should be provided. All impacts should be broken down on a state-by-state basis. Regulations included in the study should not be limited to just those listed in NMA's comments but should include any other EPA regulations that EPA believes will affect the nation's economy, production and usage of energy and manufacturing. [EPA-HQ-OAR-2009-0491-2868.1,p.14]

2. The draft RIA is fundamentally flawed for another reason as well. On September 1, 2010, EPA published a Notice of Data Availability (NODA) indicating that EPA had changed the assumptions it used in its modeling in support of the proposed rule, with one of the principal changes being changed natural gas supply and price assumptions. EPA, however, did not publish a new draft RIA that reflects the new modeling assumptions. At this point, therefore, the public does not know exactly what the regulatory impacts of the rule will be. NMA will address this point in more detail in its comments on the NODA. [EPA-HQ-OAR-2009-0491-2868.1, p.2]
23. 35 Fed. Reg. 7390, 7391 (1970). It should be emphasized that CEQ does not distinguish between cumulative analysis of environmental impacts and of socioeconomic impacts. Under CEQ regulations, agencies must examine the effect of the proposed action on the "human environment." 40 C.F.R. § 1508.14 states that "[h]uman environment" shall be interpreted comprehensively to include the natural and physical environment and the relationship of people with that environment." While "economic or social effects are not intended by themselves to require preparation of an environmental impact statement," "[w]hen an environmental impact statement is prepared and economic or social and natural or physical environmental effects are interrelated, then the environmental impact statement will discuss all of these effects on the human environment." This applies to cumulative analysis: where socioeconomic effects accumulate from multiple actions, they must be assessed cumulatively, just as environmental effects must be assessed cumulatively. Thus, cumulative analysis is as relevant for examining socioeconomics as it is for analyzing environmental impacts. [EPA-HQ-OAR-2009-0491-2868.1 ,pp.9-10]
Response: 
In implementing these rules, emission controls may lead to reductions in ambient PM2.5 and ozone below the National Ambient Air Quality Standards (NAAQS) for PM and ozone in some areas and assist other areas with attaining these NAAQS. Because the PM and ozone NAAQS RIAs also calculate PM and ozone benefits and costs, there are important differences worth noting in the design and analytical objectives of each RIA. The NAAQS RIAs illustrate the potential costs and benefits of attaining a new air quality standard nationwide based on an array of emission control strategies for different sources. In short, NAAQS RIAs hypothesize, but do not predict, the control strategies that States may choose to enact when implementing a NAAQS. The setting of a NAAQS does not directly result in costs or benefits, and as such, the NAAQS RIAs are merely illustrative and are not intended to be added to the costs and benefits of other regulations that result in specific costs of control and emission reductions. However, some costs and benefits estimated in this RIA account for the same air quality improvements as estimated in the illustrative PM2.5 and ozone NAAQS RIA.
The setting of a NAAQS does not directly result in costs or benefits, and as such, the NAAQS RIAs are merely illustrative and are not intended to be added to the costs and benefits of other regulations that result in specific costs of control and emission reductions. However, some costs and benefits estimated in this RIA account for the same air quality improvements as estimated in the illustrative PM2.5 and ozone NAAQS RIA.
By contrast, the emission reductions for the Transport rule are from a specific class of well-characterized sources. In general, EPA is more confident in the magnitude and location of the emission reductions for these rules. It is important to note that emission reductions anticipated from these rules do not result in emission increases elsewhere (other than potential energy disbenefits). Emission reductions achieved under these and other promulgated rules will ultimately be reflected in the baseline of future NAAQS analyses, which would reduce the incremental costs and benefits associated with attaining the NAAQS. EPA remains forward looking towards the next iteration of the 5-year review cycle for the NAAQS, and as a result does not issue updated RIAs for existing NAAQS that retroactively update the baseline for NAAQS implementation.
The Agency in this RIA did provide an estimate of early retirements of coal-fired units that may occur in reaction to the implementation of the proposed Transport Rule.   EPA estimated that relative to the base case for our analysis, about 1.2 GW of coal-fired capacity is projected to be uneconomic to maintain operation (less than 1 percent of all coal-fired capacity in the Transport Rule states, and thus less than 1 percent of all such U.S. coal-fired capacity) by 2014. Thus, few closings of coal-fired units are estimated based on EPA modeling.  Uneconomic units, for the most part, are small and infrequently used generating units that are dispersed throughout the states covered in the Transport Rule.  In practice, units projected to be uneconomic to maintain may be "mothballed," retired, or kept in service to ensure transmission reliability in certain parts of the grid, and our modeling is unable to distinguish between these potential outcomes. 
Organization: Western Business Roundtable
Comment: 
Western Business Roundtable
2. EPA and Other Agencies Employ Selective Approaches on Cumulative Impacts Analysis
Federal agencies only employ this narrow analytical approach when it comes to economic impacts. Environmental impacts analyses tend to draw broad and deep conclusions of predicted cumulative impacts. [EPA-HQ-OAR-2009-0491-2746.1 p.4]
The Council on Environmental Quality ("CEQ") requires cumulative environmental impact analyses in EISs. CEQ regulations require that agencies considering major actions that could affect environmental quality consider the "overall, cumulative impact of the action proposed (and of further actions contemplated)."4 [EPA-HQ-OAR-2009-0491-2746.1 p.4]
EPA requires its review of NEPA Environmental Impact Statements to take cumulative impacts into account, including consideration of "impacts that are due to past, present, and reasonably foreseeable actions."5 According to EPA, in assessing environmental impacts, it is necessary to assess "[t]he combined, incremental effects of human activity" rather than just the impacts of the particular action for which federal approval is sought.6 [EPA-HQ-OAR-2009-0491-2746.1 p.4]
Yet, NEPA was enacted to "promote efforts which will prevent or eliminate damage to the environment and biosphere and stimulate the health and welfare of man."7 Thus, NEPA requires federal agencies to balance protection of the environment against the needs of people. Because neither of the purposes is stated as predominant over the other, it is logical to conclude that NEPA envisions a balancing test, whereby any imposition of standards, denial of permits, or other regulatory actions taken on behalf of the environment must be balanced against the impacts (including health and economic) of those actions on the people affected. 8 [EPA-HQ-OAR-2009-0491-2746.1 p.4]
Agencies can balance those equities only by conducting a full, transparent and rational cost/benefit analysis which takes into account both environmental concerns and the economic and other issues that impact citizens' welfare. [EPA-HQ-OAR-2009-0491-2746.1 p.4]
3. Cumulative Impact Analysis is Required by Law and Regulation
What is most concerning about the approach being taken by federal agencies is the fact that it flies in the face of explicit federal requirements. [EPA-HQ-OAR-2009-0491-2746.1 p.4]
Executive Order 12866:
Executive Order 12866 specifically requires cumulative analysis as follows:
 "Each agency shall tailor its regulations to impose the least burden on society, including individuals, businesses of differing sizes, and other entities (including small communities and governmental entities), consistent with obtaining regulatory objectives, taking into account, among other things, and to the extent practicable, the costs of cumulative regulations."9 [EPA-HQ-OAR-2009-0491-2746.1 p.4]
 "[I]n deciding whether and how to regulate, agencies should assess all costs and benefits of available regulatory alternatives."10 [EPA-HQ-OAR-2009-0491-2746.1 p.4]
[An Agency is to] "base its decisions on its best reasonably obtainable scientific, technical, economic, and other information concerning the need for, and consequences of, the intended regulation."11
Moreover, EPA cannot say that cumulative analysis is not "practicable" within the meaning of the Order. The federal government obviously has very sophisticated modeling techniques at its disposal. In fact, agencies use predictive modeling all the time to evaluate and estimate future environmental impacts, including the potential future impacts of climate change. [EPA-HQ-OAR-2009-0491-2746.1 p.5]
Here, EPA has laid out a series of explicit steps it intends to take to reach a particular outcome. If an action by EPA in furtherance of that objective is so unformed as to defy economic impacts analysis, EPA needs to delay rulemaking until it has better information on the requirements it wants to impose. [EPA-HQ-OAR-2009-0491-2746.1 p.5]
Clean Air Act (CAA):
Cumulative impact analysis is also legally required under the rulemaking provisions of CAA Section 307(d)(3) requires that a rule be accompanied by a statement of its basis and purpose, including "the major legal interpretations and policy considerations underlying the proposed rule."12 [EPA-HQ-OAR-2009-0491-2746.1 p.5]
Here EPA is clearly undertaking a broad restructuring of the power sector through an already defined set of rulemakings. The Transport Rule is one of that set of rulemakings. Thus, EPA must provide a full analysis of the overall "policy" implications. [EPA-HQ-OAR-2009-0491-2746.1 p.6]
Section 318 of the CAA is also relevant to this discussion. It requires that the Administrator undertake an analysis of the cost of complying with various EPA actions, including rulemakings under section 111(d). Under section 318(d), such analyses "shall be as extensive as practicable" consistent with the standards set forth in that provision.13 [EPA-HQ-OAR-2009-0491-2746.1 p.6]
We have noted this elsewhere in these comments, but it bears repeating. NEPA requires a full, transparent and rational cost-benefit analysis that takes into account both environmental concerns and the economic and other issues that impact citizens' welfare.14 [EPA-HQ-OAR-2009-0491-2746.1 p.6]
Response: 

In implementing rules such as the Transport Rule, emission controls may lead to reductions in ambient PM2.5 and ozone below the National Ambient Air Quality Standards (NAAQS) for PM and ozone in some areas and assist other areas with attaining these NAAQS. Because the PM and ozone NAAQS RIAs also calculate PM and ozone benefits and costs, there are important differences worth noting in the design and analytical objectives of each RIA. The NAAQS RIAs illustrate the potential costs and benefits of attaining a new air quality standard nationwide based on an array of emission control strategies for different sources. In short, NAAQS RIAs hypothesize, but do not predict, the control strategies that States may choose to enact when implementing a NAAQS. The setting of a NAAQS does not directly result in costs or benefits, and as such, the NAAQS RIAs are merely illustrative and are not intended to be added to the costs and benefits of other regulations that result in specific costs of control and emission reductions. However, some costs and benefits estimated in this RIA account for the same air quality improvements as estimated in the illustrative PM2.5 and ozone NAAQS RIA.
The setting of a NAAQS does not directly result in costs or benefits, and as such, the NAAQS RIAs are merely illustrative and are not intended to be added to the costs and benefits of other regulations that result in specific costs of control and emission reductions. However, some costs and benefits estimated in this RIA account for the same air quality improvements as estimated in the illustrative PM2.5 and ozone NAAQS RIA.
By contrast, the emission reductions for the Transport rule are from a specific class of well-characterized sources. In general, EPA is more confident in the magnitude and location of the emission reductions for these rules. Emission reductions achieved under these and other promulgated rules will ultimately be reflected in the baseline of future NAAQS analyses, which would reduce the incremental costs and benefits associated with attaining the NAAQS. EPA remains forward looking towards the next iteration of the 5-year review cycle for the NAAQS, and as a result does not issue updated RIAs for existing NAAQS that retroactively update the baseline for NAAQS implementation.
The Agency in this RIA did provide an estimate of early retirements of coal-fired units that may occur in reaction to the implementation of the proposed Transport Rule.   EPA estimated that relative to the base case for our analysis, about 1.2 GW of coal-fired capacity is projected to be uneconomic to maintain operation (less than 1 percent of all coal-fired capacity in the Transport Rule states, and thus less than 1 percent of all such U.S. coal-fired capacity) by 2014. Thus, few closings of coal-fired units are estimated based on EPA modeling.  Uneconomic units, for the most part, are small and infrequently used generating units that are dispersed throughout the states covered in the Transport Rule.  In practice, units projected to be uneconomic to maintain may be "mothballed," retired, or kept in service to ensure transmission reliability in certain parts of the grid, and our modeling is unable to distinguish between these potential outcomes.  This analysis was the most detailed the Agency could provide as practicable.
XIV. Regulatory Text

Organization: Duke Energy
Comment: 
Duke Energy
Comments on EPA's Proposed Transport Rule Regulatory Text.  
EPA has not proposed regulatory language for the intrastate trading and direct control alternative remedy programs. If EPA decides to finalize a Transport Rule based on either of those alternatives, which Duke Energy does not support, it will be necessary for EPA to publish proposed regulatory language for public comment.  The following citations refer to the NOx annual program specifically, but the same comments apply to the ozone season and annual SO2 control programs. [EPA-HQ-OAR-2009-0491-2689.1, p.64]
Response: 
The final rule does not adopt the intrastate trading and direct control remedies.  See section VII.A of the preamble.
Organization: North Carolina Department of Environment and Natural Resources
Comment: 
North Carolina Department of Environment and Natural Resources
The NCDAQ appreciates the fact that all four subsections are structurally similar. This assists in ease of understanding the applicable requirements and implementation for regulators, the regulated the community and the public. [EPA-HQ-OAR-2009-0491-2767.1 p.8]
Response: 
See section XI of the preamble.

XIV.A. Part 97

Organization: Attorney General of North Carolina
Comment: 
Attorney General of North Carolina
1. The use of the term owner's share in proposed rules 40 C.F.R. §§97.402, .502, .602 and .702 to refer to two different concepts is confusing. Definition no. 1 appears to refer simply to the owner's emissions for a single control period. Definitions 2 and 3 appear to refer to the owner's portion of the budget for that control period. The use of a single term with two entirely different definitions is unnecessarily confusing. Moreover, the three definitions are then followed by three separately numbered "provided" clauses and it is not clear whether these clauses are meant to apply to all of the definitions. Using a term such as owner's emissions for definition no. 1 would provide better clarity.   [EPA-HQ-OAR-2009-0491-2685.1 p.35]
There appears to be a cross reference error in the rule text. Section 97.412(b) refers to "paragraph (a)(4) of this section . . . ." 75 Fed. Reg. at 45,377/3. There does not appear to be any paragraph (a)(4) in §97.412. The cross reference was likely intended to be to paragraph (a)(3) instead. This error appears to have been made in the analogous language in §§97.512, 97.612 and 97.712.   [EPA-HQ-OAR-2009-0491-2685.1 p.36]
Response: 
The term "owner's share" is not used or defined in the final rule.  In the final rule, the assurance provisions are implemented on a common-designated-representative basis, rather than on an owner basis.  The term "common designated representative's share" is used in the final rule, and the definition is much simpler than that of "owner's share" in the proposed rule.  See sections VII.E and XI of the preamble.
Proposed sections 97.412, 97.512, 97.612, and 97.712 are revised in the final rule. 
Organization: City of Tallahassee
Comment: 
City of Tallahassee
EPA HAS APPROPRIATELY RELIED ON NAMEPLATE CAPACITY TO IDENTIFY UNITS SUBJECT TO THE TRANSPORT RULE [EPA-HQ-OAR-2009-0491-2669.1, p.5]
The proposed Transport Rule only applies to any "stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine serving . . . a generator with a nameplate capacity of more than 25 MWe producing electricity for sale." 75 Fed. Reg. at 45372. "Nameplate capacity" is defined as "the maximum electrical generating output (in MWe) that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings) . . . as specified by the manufacturer of the generator . . . ." 75 Fed. Reg. at 45370 (emphasis added). EPA's definition of nameplate capacity is consistent with definitions promulgated by other regulatory agencies heavily involved with the electric utility industry, including the Energy Information Administration ("EIA"). The EIA defines generator nameplate capacity as the "maximum rated output of a generator . . . under specific conditions designated by the manufacturer." U.S. Energy Information Administration, Glossary http://www.eia.doe.gov/glossary/index.cfm?id=G (last visited Sept. 27, 2010)(emphasis added)). [EPA-HQ-OAR-2009-0491-2669.1, p.5]
Nameplate capacity is the appropriate measure of generator capacity and should continue to set the threshold for applicability of the Transport Rule. Nameplate capacity provides a bright-line test for operators and regulators to determine whether a unit is subject to regulation under the Transport Rule. Unlike instantaneous peaks in generation that represent only a snapshot in time, nameplate capacity represents the generating capacity the unit is designed to sustain for a period of time. This is a more accurate and consistent measure of capacity because generating units designed to operate at a steady state may vary significantly for short periods. Using generator nameplate capacity to distinguish between units subject to the Transport Rule and those that are not in the final rule will avoid uncertainty and ensure units are accurately and appropriately categorized for the life of the unit (unless and until the design capacity is modified and the manufacturer acknowledges a change to the nameplate capacity). [EPA-HQ-OAR-2009-0491-2669.1, p.5]
Response: 
See sections VII.B and XI of the preamble.
Organization: City Utilities of Springfield
Comment: 
City Utilities of Springfield
Issue: The preamble states that EPA proposes to define a "New Unit" as: "Any covered EGU not listed in the table in Appendix A of the trading rule applicable to that program; any unit listed in Appendix A whose allocation is subject to the requirement that the Administrator not record the allocation or that the Administrator deduct the amount of the allocation (see previous discussion in footnote), or any unit listed in Appendix A that stopped operating for three allowances as an existing unit, but resumes operation (page 45310, column 1)"  [EPA-HQ-OAR-2009-0491-2721.1 p.3-4]
However, that definition does not appear in the Definition sections at §97.402, 97.502, 97.602, or 97.702. Instead, the term is operationally defined within the context of the language applicable to the new unit set-aside program. We believe it is important to include the definition of "New Unit" as stated in the preamble, as this appeared to be a point of considerable confusion in the prepublication rule text. [EPA-HQ-OAR-2009-0491-2721.1 p.4]
Response: 

The final rule revised the description of the categories of units (i.e., "new units") eligible for allocations from the new unit set-aside.  Because the units eligible for such allocations are described in detail in the final Transport Rule trading program rules and the term "new unit" itself is not used in these rules except as part of a section title and as part of the term "new unit set-aside," EPA does not believe that it is necessary to include, and define, the term in the definitions sections of these rules.   See section VII.D.2 of the preamble. 
Organization: Duke Energy
Comment: 
Duke Energy
75 Fed. Reg. at 45368.  
The definition of "biomass" in subparagraph (1) would appear to exclude any whole trees or other agricultural products unless those were grown specifically for use as fuel. These crops have multiple uses within the agricultural/forest products market. While there is ongoing public discourse concerning what sources may be counted as biomass in terms of renewable energy, that discussion is not relevant to the Proposed Transport Rule, and this rulemaking is not the appropriate arena to settle that issue. For purposes of the Proposed Transport Rule, biomass should be considered any organic material or agricultural/forest product that may be harvested and used as a fuel, in addition to the definitions for biomass byproducts and segregated materials for energy recovery as defined in subparagraphs (2) and (3). [EPA-HQ-OAR-2009-0491-2689.1,p.64]
75 Fed. Reg. at 45369.  
The definitions include both the terms "commence commercial operation" and "commence operation." It is not clear how these different terms are used within the regulation. A search of the rule does not show any instances where "commence operation" is used. This latter definition is very broad, and includes essentially any minor operation whether or not any fuel is being combusted. Depending on the intended use of that term, the definition of "commence operation" may not be appropriate. [EPA-HQ-OAR-2009-0491-2689.1, pp.64-65]
75 Fed. Reg. at 45369.  
[Do we care? Do we prefer that a non-fossil unit (i.e. a biomass unit) should be under the TR rather than some later industrial Transport Rule???] The definition of "fossil fuel-fired" states that any amount of fossil fuel combusted in 1990 and later will qualify a unit as a fossil fuel-fired unit. Fossil fuels in de minimis amounts related to startup or combustion stabilization should not define a unit as fossil-fired. Similar to NSPS classification for utility and non-utility steam generating units, a cut-off of 10% fossil fuel may be more appropriate for defining a unit as fossil fuel-fired. [EPA-HQ-OAR-2009-0491-2689.1,p.65]
75 Fed. Reg. at 45370  
The definition of "nameplate capacity" should also include a reduction in capacity following any repowering project that would result in a lower rating for the electric generating unit. For example, repowering a fossil-fired unit to burn biomass may result in a substantial reduction in capacity. [EPA-HQ-OAR-2009-0491-2689.1,p.65]
75 Fed. Reg. at 45374.  
Response: 
The definition of "biomass" in the final Transport Rule trading programs includes, among other things, "[a]ny organic material grown for the purpose of being converted to energy".  EPA does not interpret this definition as excluding whole trees or other agricultural products grown for multiple uses, one of which is for conversion to energy.  This interpretation applies only to this definition and may or may not apply to other definitions of "biomass" in other contexts.
The final rule does not use or define the term "commence operation".   The term "commence commercial operation" is used and defined in the final rule.  See section XI of the preamble.
The final rule defines "fossil-fuel-fired" as combusting any amount of fossil fuel in 2005 or later.  EPA rejects, for several reasons, the commenter's approach of excluding so-called "de minimis" amounts of fossil fuel use.  The approach in the final rule is consistent with the approach used in prior EPA trading programs covering the electric generation industry, e.g., the Acid Rain Program, the NOx Budget Trading Program, and the CAIR trading programs.  The commenter did not provide any basis for using different approach in the Transport Rule trading programs covering the same industry or specifically for using a suggested level of 10% of total fuel use as the cut-off for what would constitute "de minimis" fossil fuel use in these programs.   As noted by the commenter, the NSPS regulations refer to a 10% level of fossil fuel use in connection with certain NOx (but not SO2) emission requirements for certain types of units.  However, the exemption from NOx emission requirements based on the unit having annual capacity factor for coal, oil, and natural gas of 10% or less is limited to industrial, commercial, and institutional steam generating units and does not apply to electric utility steam generating units.    Compare  40 CFR 60.44Da (setting NOx emissions standard for electric utility steam generating units, without any exemption for units with 10% or less fossil fuel use) and 60.44b (setting NOx emissions standards for industrial, commercial, and institutional steam generating units, with an exemption for units with 10% or less fossil fuel use).  The use of the 10% cutoff in a different set of regulations applicable to a different category of units does not support the commenter's claim that the 10% level should be used to exempt units from the Transport Rule emission reduction requirements.  Moreover, the commenter failed to specify, much less justify, any period of time during which fossil fuel use would have to be less than 10%.  If the applicability of the Transport Rule trading programs were to depend on exceeding a specific level of fossil fuel use, a unit's regulatory status could change during the course of the year.  Specifically, a unit's fossil fuel use can vary, depending on, among other things, changes in unit operation and fuels.  As noted by the commenter, some units use fossil fuel for startup and combustion stabilization, and so fossil fuel use can vary depending on the frequency of startups and shutdowns and on factors (such as the moisture content and other characteristics of the other fuels being combusted) affecting the need for combustion stabilization.  A unit that was excluded from the Transport Rule trading programs because of its "de minimis" fossil fuel use would not report fuel use to EPA, and so determination of which units were subject to the trading programs, and assurance of compliance, would be problematic.  
EPA rejects the commenter's suggestion of including in the definition of "nameplate capacity" language that would include reductions in capacity due to derating due to a change in fuel.  This suggested language would have the effect of allowing owners and operators to remove a unit from coverage by the Transport Rule trading programs by changing the fuel combusted.  The final Transport Rule trading programs do not specify either an emission level for specific units or specific emissions controls for specific units, but instead give owners and operators the flexibility to adopt the compliance strategies (including changing fuels) that they determine to be appropriate.  In light of this flexibility, EPA takes the approach in the final Transport Rule that once a unit is subject to the trading programs, the unit remains subject, regardless of the compliance strategy adopted by the owners and operators.  Moreover, if a unit were removed from the trading programs because of a change in fuel, the owners and operators would not report future fuel use to EPA and so determination of which units were subject to the trading programs, and assurance of compliance, would be problematic.
Organization: Eco Power Solutions (USA) Corp.
Comment: 
Eco Power Solutions (USA) Corp.
Finally, the proposed rule wisely provides the Agency with flexibility to adapt monitoring strategies to new technology. That flexibility should be retained in any final rule. [EPA-HQ-OAR-2009-0491-2692.1, p. 2]
In the proposed rule EPA has preserved for itself flexibility to consider petitions under Sec. 75.66 to approve alternatives to conventional continuous monitoring systems (See Sec. 97.435 as to the NOx Annual program, Sec. 97.535 as to the NOx Seasonal program, Sec. 97.635 as to the SO2 Group 1 program, and Sec 97.735 as to the SO2 Group 2 program). That flexibility is essential in adjusting to new technologies that, among other things, may use different chemical reactions than conventional technologies and therefore may need to be monitored differently. [EPA-HQ-OAR-2009-0491-2692.1, p. 11] [See 2692.1, p. 11 for further discussion of flexibility.]
Response: 
See sections H and XI of the preamble. 
Organization: Shell Chemicals
Comment: 
Shell Chemicals
The Proposal at 40 CFR § 97 .404 (75 FR 45372) addresses applicability with respect to this rule. Under 40 CFR 97.404(a)1, the rule applies to, 'Any stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine . . . producing electricity for sale' (emphasis added). As discussed in the FERC filing for this facility: [EPA-HQ-OAR-2009-0491-2572, pp.1-2]
'None of Shell, the Owner/Lessor, the Beneficiary, the trustee, or ALAC (i) is directly or indirectly engaged in the generation or sale of electric energy other than as QFs, foreign utilities, exempt wholesale generators (EWGs), or self-generation ; or (ii) owns or operates any electric facilities other than QFs, foreign utilities, eligible facilities of EWGs, or self-generation facilities. Therefore, none of Shell, the Owner/Lessor, the Beneficiary, the trustee, or ALAC is an electric utility, electric utility holding company, or any person owned by either within the meaning of section 292 .206 of the Commission's regulations and the Commission's implementing precedent .' [EPA-HQ-OAR-2009-0491-2572, p.2]
As established through the certification provided in this FERC filing, Shell's Cogens do not qualify as units, ' . . .producing electricity for sale .' However, as is indicated in the QF filing, based on Shell's manufacturing energy demand, the company anticipated an average of 20% of the power generated may be available for sales. [EPA-HQ-OAR-2009-0491-2572, p.2]
The proposed rule addresses the potential for energy sale within its applicability regulations. According to 40 CFR § 97.404(b), a unit is not subject to the rule if it qualifies a s a Cogeneration Unit, and provided that the unit does not supply, '. . .in any calendar year more than one-third of the unit's potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale.' As provided above, the FERC filing for the Cogens at Shell mentioned an anticipated target of about 20% of energy being available for sale, which is below the typical limit of one-third. A review of Cogen operation since startup indicates that the actual exported energy (i.e., that portion that can said to be sold) has never exceeded 30% (average of 27%) of the total energy produced (about 25% compared to potential output) . In addition, the total exported energy has consistently fallen well below the value of 219,000 MWh when calculated on an annual basis (average approximately 180,000 MWh). [EPA-HQ-OAR-2009-0491-2572, p.2] 
Response: 
See section VII.B of the preamble.
Organization: South Carolina Department of Health and Environmental Control 
Comment: 
South Carolina Department of Health and Environmental Control 
a) The word 'operation' in the definition of 'commence operation' on page 45369 is not in italics.
a) In the sentence, 'The written approve will state the unit's baseline heat input and baseline NOx emission rate,' did the EPA intend to use 'approval' instead of 'approve?' 
[EPA-HQ-OAR-2009-0491-2677.1 p.23]
Response: 
EPA has corrected all typographical errors of which it is aware. 

XV. Air Quality Modeling Technical Support Document (TSD)

Organization: George Washington University Regulatory Study Center
Comment: 
George Washington University Regulatory Study Center
In addition, the Technical Support Document for air quality modeling suggests that there is substantial variability in the estimates of downwind fine PM concentrations. Appendix A of the Air Quality Modeling Technical Support Document for the Transport Rule (AQMTSD) reports a broader range of performance statistics for air quality model performance than reported in the preamble to the Transport proposal. [EPA-HQ-OAR-2009-0491-2573.1, pp.21-22]
Response: 
EPA has completed an expanded model performance evaluation using the predictions from the updated 2005 base year CAMx simulation conducted for the final Transport Rule.   This evaluation provides additional spatial and temporal performance results in response to comments.  The model performance results can be found in Appendix A of the Final Transport Rule Air Quality Modeling Technical Support Document.
Organization: Georgia Department of Natural Resources, Air Protection Branch
Comment: 
Georgia Department of Natural Resources, Air Protection Branch
Air Quality Model Performance Evaluation 
Georgia EPD has reviewed the air quality model performance for the modeling that is the basis of the Transport Rule (Transport Rule Air Quality Modeling Technical Support Document - Appendix A). We were shocked to find that the complete documentation consists of only 6 pages. Georgia EPD's modeled performance documentation that was submitted as part of the Atlanta PM2.5 SIP covered nearly 150 pages. The EPA model performance documentation included two summary tables. Table A-2 covers 8-hour ozone by month across the entire modeling domain. Table A-3 covers speciated PM2.5 data (IMPROVE, CSN, and CASTNet) by season across the entire modeling domain. These high level summary calculations can hide poor model performance by allowing positive and negative bias to cancel. Before modeling is used for regulatory applications, a more rigorous evaluation must be performed. Georgia EPD requested the station-by-station model and measurement files used to perform the model performance evaluation from EPA OAQPS, but the files were never sent. [EPA-HQ-OAR-2009-0491-2647.1, p.5]
Response: 
EPA has completed an expanded model performance evaluation using the predictions from the updated 2005 base year CAMx simulation conducted for the final Transport Rule.   This evaluation provides additional spatial and temporal performance results in response to comments.  The model performance results can be found in Appendix A of the Final Transport Rule Air Quality Modeling Technical Support Document.
Organization: Iowa Department of Natural Resources (IDNR)
Comment: 
Iowa Department of Natural Resources (IDNR)
Improving the Photochemical Modeling Performance Evaluation
Many of the technical assessments used in support of the Transport Rule are directly related to methods used in attainment demonstrations. As EPA has developed guidance which specifically applies to attainment demonstrations we believe it would be appropriate for EPA to follow the associated guidance recommendations that are related to conducting a model performance evaluation. In order to make the 2005 base year performance evaluation more robust and more consistent with existing guidance, we recommend EPA supplement the Air Quality Modeling Technical Support Document by considering and implementing the following: [EPA-HQ-OAR-2009-0491-2609.1, p.5]
1) The statistics provided are averaged over spatial and temporal scales which are too large. A statistical performance evaluation should be provided by state or other appropriate regional spatial scales. As averaging times increase statistics and plots tend to look better. Sub-seasonal averaging times are needed to properly interpret the information. Statistics should be provided on a daily (as related to particulate matter related) or hourly (as related to ozone) basis. [EPA-HQ-OAR-2009-0491-2609.1, p.5]
2) At a minimum adding the following three plot types, for at least the sites identified as nonattainment or maintenance areas in the 2012 basecase modeling (for site specific plots), would provide valuable information related to assessing model performance:
a. Time series of observed and predicted concentrations on a hourly or daily basis.
b. Scatter plots of predicted and observed concentrations.
c. Daily tile plots of predicted concentrations across the modeling domain with observations as an overlay. [EPA-HQ-OAR-2009-0491-2609.1, p.5]
There are additional performance evaluation methodologies that could be considered, such as inclusion of "soccer goal" plots, "bugle plots", box plots, and methods associated with a diagnostic evaluation. To the extent these methods would provide useful insights into the performance evaluation we encourage EPA to consider their inclusion. [EPA-HQ-OAR-2009-0491-2609.1, p.5]
Photochemical modeling is recognized as a useful tool and we have suggested expanding its use in previous comments. Such recommendations necessarily assume certain conditions are met. Principal among these assumptions is that acceptable level of model performance has been established.  It is difficult to determine that model performance is acceptable based purely on the available statistics which are averaged over the entire 12 km domain and entire seasons. We agree this is information that is useful as one component to the operational evaluation, but is not sufficient by itself.  By following the above suggestions we believe EPA can provide additional metrics, plots, and graphics needed to fully ascertain the adequacy of model performance and enhance existing technical support documentation. [EPA-HQ-OAR-2009-0491-2609.1,pp. 5-6]
Response: 
EPA has completed an expanded model performance evaluation using the predictions from the updated 2005 base year CAMx simulation conducted for the final Transport Rule.   This evaluation provides additional spatial and temporal performance results in response to comments.  The model performance results can be found in Appendix A of the Final Transport Rule Air Quality Modeling Technical Support Document.
Organization: Kansas Department of Health and Environment
Comment: 
Kansas Department of Health and Environment
Model performance is discussed for both ozone and PM2.5 in the air quality modeling TSD. Unfortunately, this performance evaluation covers the entire modeling domain. There are many differences (emissions, meteorology, etc.) between the Midwest and the remaining eastern portion of the country that could have a significant impact on model performance. KDHE recommends a regionally based model performance assessment that would allow a reader to understand the model performance in their region of interest. This is particularly important for PM2.5 due to the relatively large ammonia emissions in the Midwest. [EPA-HQ-OAR-2009-0491-2606.1, p.7]
As outlined in the current model performance discussion, there are some fairly large errors in sulfate and nitrate estimates. Although the model is being used in a relative sense, these errors could still impact a 'linkage' assessment for a specific region, especially with the linkage assessment threshold only being 1% of the NAAQS and including all anthropogenic emissions from a state. In addition, it would be useful if PM2.5 impacts for a state could be broken out by species component in order to answer the question, for example, is the Kansas contribution to PM2.5 dominated by either sulfate or nitrate? [EPA-HQ-OAR-2009-0491-2606.1, p.8]
Response: 
EPA has completed an expanded model performance evaluation using the predictions from the updated 2005 base year CAMx simulation conducted for the final Transport Rule.   This evaluation provides additional spatial and temporal performance results in response to comments.  The model performance results can be found in Appendix A of the Final Transport Rule Air Quality Modeling Technical Support Document.
The approach used for calculating contributions includes (1) averaging model predictions across multiple days and across different seasons depending on the temporal patterns of observed exceedances and (2) the use of model predictions in a relative sense applied as calibrations to ambient measurements.   This approach is intended to mitigate the effects of biases in absolute model predictions.
Contributions to PM2.5 component species of sulfate and nitrate are provided in the docket for this rule [placeholder for docket number.]
 

XVI. Other Comments

Organization: Class of '85 Regulatory Group
East Kentucky Power Cooperative

Comment: 
Class of '85 Regulatory Group
CAIR States Not Covered by CATR. The Proposal uses an entirely different methodology than was used in CAIR to determine whether a state interferes with attainment or maintenance in a downwind state. Under the new methodology, certain areas that were subject to CAIR do not 'contribute significantly' to downwind states' nonattainment of both the ozone and PM2.5 NAAQS and will be subject to fewer requirements under CATR.30 There is no reason for continuing to subject these areas to CAIR requirements until the effective date of the final CATR. The Group urges the Agency to state that these areas no longer have to meet CAIR requirements as of the date EPA publishes the final CATR. [EPA-HQ-OAR-2009-0491-2854.1,pp.14-15]

East Kentucky Power Cooperative
Further, EKPC requests that EPA clarify in the rule that should the Clean Air Transport Rule ('CATR') become final, the Clean Air Interstate Rule('CATR') will be terminated. EKPC also requests that EPA clarify the date by which CATR will take effect in relation to NOx. Should CATR become effective for NOx in2014 and should CAIR be terminated upon the effective date of CATR, then EPA should clarify the status of annual and ozone NOx limits in 2012 and2013. EPA should also clarify whether new units would be required to comply with the rule, and, if so, when compliance would be required and how new units would be calculated into state budgets. [EPA-HQ-OAR-2009-0491-2776.1, p.1]

Response:
 Despite the promulgation of the Transport Rule, all CAIR requirements related to the 2011 compliance period remain legally binding and fully enforceable, and sources are still required to submit CAIR allowances for the 2011 compliance period by March 2012.  The Transport Rule covers compliance for 2012 and beyond.  As such, all sources are legally required to comply with CAIR throughout the entire 2011 compliance period, irrespective of the Transport Rule promulgation timeframe.  This transition is consistent with the D.C. Circuit's December 23, 2008 opinion which permitted CAIR to remain in effect to "temporarily preserve the environmental values covered by CAIR" while EPA worked to remedy its flaws.  For more detailed information on the transition from CAIR to the Transport Rule, please see section IX.A in the preamble.  For more information on Transport Rule compliance deadlines, please see section VII.C of the preamble.
Organization: Big Rivers Electric Corporation
Comment: 
Big Rivers Electric Corporation
The uncertainty of available allowances makes it impossible to plan on generation to meet the forecasted future customer electrical needs and maintain compliance with EPA regulations.[EPA-HQ-OAR-2009-0491-2661.1, p.4]
Response: 
EPA thanks the commenter for their feedback regarding this Rule.  EPA is working as expeditiously as possible and within the full extent of its authority, under  Section 110(a)(2)(d) of the Clean Air Act, to ensure improved human health for all Americans through reductions in interstate transport of pollutants within the Transport Rule's 27 states.  For more information on the Transport Rule's allocations methodology, please see Section VII.D in the Preamble.
Comment:
Connecticut Department of Environmental Protection
Adopt stronger national rules for source categories identified by the Ozone Transport Commission. These national rules should cover:
o Performance standards for all electric generating units;
o Light and medium duty vehicles;
o Industrial, Commercial and Institutional (ICI) Boilers;
o Cement Kilns;
o Locomotive Engines; and
o Marine Engines
[EPA-HQ-OAR-2009-0491-2780.1 p.7]

Response:
Please refer to section VI.1 of the preamble for an explanation as to why the Agency chose to only regulate EGUs (stationary sources) in this rulemaking.
Organization: Consumers Energy
Comment: 
Consumers Energy
D. EPA's Proposed Milestone Dates Are Unrealistic and Disregard for the Planning, Procurement, Permitting, and Installation Efforts that Must Take Place to Implement the Proposal
Consumers Energy is in the process of implementing a strategic plan that will comply with the final CAIR, which still remains in effect and remains enforceable. This plan will incur costs in excess of $1 billion. A conference call to discuss the proposed rule was hosted by UARG, on August 30, 2010. During a discussion regarding industry plans compared to the schedule in the proposed rule, an EPA staff member casually opined that the industry's plans, based upon prior EPA rulemaking, have no relevance to this proposed rule. We respectfully disagree.[EPA-HQ-OAR-2009-0491-2837.1, p.7]
1. 2012 Implementation Date for Consumers Energy Consumers Energy continues to analyze the voluminous proposed Transport Rule and offers these comments on how it may attempt to comply with the rule as currently proposed. Consumers Energy reserves the right to modify any proposed compliance plan or strategy at its discretion. Consumers has three likely options for compliance with the 2012 emission caps as currently in the proposed Transport Rule:
:: Install low NOx burners.
:: Increase our fuel blend to higher percentages of low-sulfur sub-bituminous coal.
:: Shutdown units or some combination of these three options. [EPA-HQ-OAR-2009-0491-2837.1, p.7]
None of these options can be implemented in the approximate six month time frame between issuance of the final rule, currently estimated to be June 2011, and the proposed compliance date of January 1,2012. In order for our actions to be regarded as prudent by the MPSC, issuance of the final rule is necessary. This would provide Consumers with the level of certainty, both in the rule making process and rate recovery, needed to proceed with any of the above described options. To be perfectly clear, none of the options could be completed by January 1, 2012 even if Consumers started work today. [EPA-HQ-OAR-2009-0491-2837.1, p.7]
:: It took 1.5 years to engineer, permit, procure and install low NOx burners on two of Consumers Energy's units. [EPA-HQ-OAR-2009-0491-2837.1, p.8]
2. 2014 Implementation Date for Consumers Energy
Similarly, implementation of the proposed rule by 2014 is not realistic and is fraught with logistical and regulatory difficulties. Consumers Energy is currently implementing a spending plan, costing well in excess of $1 billion, based on the final and still enforceable CAIR. Our company has moral ethical and regulatory obligations to install and operate equipment in the most cost effective, practical, and prudent manner for the benefit of its ratepayers. Therefore, Consumers Energy has put forth every effort to design the most efficient budget and schedule by utilizing scheduled outages and considering craft labor, site congestion, and the normal time to procure, design, fabricate, ship, and install pollution control equipment. [EPA-HQ-OAR-2009-0491-2837.1, p.8]
In order to have any possibility of achieving compliance by 2014, Consumers Energy would have to immediately modify our Strategic Plan - based solely on a proposed rule. All of the preceding discussion points assume that we will be able to procure all materials and secure the necessary skilled labor in a multi-state region where every other utility is undertaking the same work, at the same time. [EPA-HQ-OAR-2009-0491-2837.1, pp.8-9]
3. Comments Relative to the Electric Generating Utility Industry
Consumers Energy notes that in a September 10,2009, letter to Administrator Jackson, the Lake Michigan Air Directors Consortium (LADCO) strongly recommended that any CAIR replacement rule include an initial compliance date no earlier than 2017 for any significant additional emission reduction requirements. LADCO is a cooperative organization that supports the States of Wisconsin, Illinois, Indiana, Michigan and Ohio in matters relative to air regulatory policy. LADCO explained in its recommendations to EPA that it had conducted a state-by-state analysis that indicated that installation of significant new NOx and S02 controls, specifically, installation of selective catalytic reduction systems (SCRs) and flue gas desulfurization systems (FGDs or scrubbers) would not be possible in LADCO states before 2017. Moreover, despite EPA's suggestions to the contrary, promulgation of compliance dates later than those that EPA proposes would not result in increased emissions. CAIR remains in place and will continue to maintain a strong and effective program of emission reductions pending the initial compliance deadline for the Transport Rule - which is final and enforceable. [EPA-HQ-OAR-2009-0491-2837.1, p.9]
UARG has commissioned a broader study of the industry and the ability to comply with the 2012 and 2014 milestone dates contained in the proposed rule. Based on the actual track record of the industry, equipment suppliers and skilled labor required for installation, UARG has reached a conclusion that complements those made by LADCO and follow suit with the actual experience of Consumers Energy and many other electric generating utilities. EPA's implementation dates are unrealistic and unattainable. Consumers Energy endorses UARG's findings. We refer you to UARG's comments for the detailed analysis. [EPA-HQ-OAR-2009-0491-2837.1, p.9]
:: EPA uses its choices of emissions inventory and ambient air quality monitoring data to propose an implementation schedule that is considerably more ambitious than the schedule in the rule it is designed to replace, CAIR. For reasons described in our comments and those of the UARG, EPA's schedule is impossible for the industry to meet. [EPA-HQ-OAR-2009-0491-2837.1, p.15]
Response: 
Several commenters stated that the Transport Rule goes well beyond the scope of CAIR and creates significant and additional uncertainties for the power generation sector.  In fact, the Transport Rule does create certainty by the fact that it will be replacing CAIR, which the Court ruled unlawful.
Please see section VII.C in the preamble for more information on EPA's rationale for the 2012 and 2014 compliance deadlines.
Many commenters criticized EPA's timeframe for issuing and implementation of the Transport Rule.  Although the Court did not specify a definitive date by which EPA should promulgate the Transport Rule, it did not give the Agency an infinite stay on CAIR and did, in fact, indicate that the Transport Rule was to be completed in a timely manner.  Section 307(d)(5) of the CAA requires the Administrator to give an opportunity for written or oral comments.  The Act does not specify the length of time, other than the record must be open 30 days after holding public hearings - with which EPA complied.
EPA posted the signed version of the Proposed Transport Rule to the web when it was signed on July 6, 2010.  The proposal was published in the Federal Register on August 2, 2010, and the public comment period closed on October 1, 2010.  This provided a 60 day comment period (or 90 days from the date posted to the web).
EPA posted the signed version of the first Transport Rule Notice of Data Availability (NODA) (IPM) to the web when it was signed on August 25, 2010.  The first NODA was published in the Federal Register on September 1, 2010, and the public comment period closed on October 15, 2010.  This provided a 45 day comment period (or 52 days from the date posted to the web).  EPA posted the signed version of the second Transport Rule NODA (emissions inventories) to the web when it was published in the Federal Register on October 27, 2010.  The public comment period closed on November 26, 2010, which provided a 30 day comment period.  EPA posted the signed version of the third Transport Rule NODA (allocations and related matters) to the web when it was signed on December 30, 2010.  The third NODA was published in the Federal Register on January 7, 2011.  The public comment period closed on February 7, 2011, which provided a 30 day comment period (or 38 days from the date posted to the web).
Given the timeframe EPA provided to the public for submission of comments, and indicative of the fact that the Agency received several hundred substantive comments, commenters did, in fact, have sufficient time to submit their comments for consideration. 
Organization: Duke Energy
Dynegy, Inc.
DTE Energy
Comment: 
DTE Energy
EPA contends the emission levels required by the 2012 compliance deadline reflect only the emission reductions that would occur in the absence of the Transport Rule. EPA's suggestion that already achieved emission reductions would be lost without this deadline is incorrect. With the loss of the pollution control exemption, most projects are permitted with corresponding emission limitations and will be operated even without this onerous deadline. Additionally, many of these post-combustion systems are not installed with a bypass, which means if the EGU is operating, the control equipment is operational. Furthermore, if EPA allows banking provisions for future compliance, the incentive to optimize operation of existing control technologies is increased. [EPA-HQ-OAR-2009-0491-2851.1,p.4]
Duke Energy
In sum, the fact that EPA's proposal to set an initial compliance deadline of January 1, 2012, is so burdened with uncertainty is a stark illustration of the ill-advised nature of this attempt to force implementation of such a complex and demanding rule in only six months. EPA should take the time necessary to correct the many errors in the proposed rule, and allow adequate time for sources to make the adjustments necessary to comply with the rule, rather than rushing to implementation as it proposes to do.  [EPA-HQ-OAR-2009-0491-2689.1, pp.11-12]
Dynegy, Inc.
First, as recognized by EPA, 'emissions reductions from scrubbers by 2012 or 2013 can only reasonably be achieved if that scrubber either exists today, or if it is currently under construction.' 75 Fed. Reg. at 45273. Scrubbers that have already been installed and those that are currently being installed are, almost without exception, already needed to meet enforceable emission reduction requirements, including state regulatory programs and NSR consent decrees or new source performance standards. As such, those existing or under construction scrubbers will be operated, as designed, to reduce SO2 emissions even without a Transport Rule taking effect in 2012. Similarly, the selective catalytic reduction (SCR) NOX control systems that have already been installed and those that are currently being installed are needed to meet enforceable emission reduction requirements or performance standards. Thus, the bulk of the emission reductions and attendant health benefits expected to be achieved by the proposed Transport Rule will occur in 2012-2013 regardless of whether the rule takes effect before 2014.  [EPA-HQ-OAR-2009-0491-2698.1,p.2]
Response: 
EPA thanks the commenters for their comments and feedback.  EPA is working as expeditiously as possible and within the full extent of its authority, under  Section 110(a)(2)(d) of the Clean Air Act, to ensure improved human health for all Americans through reductions in interstate transport of pollutants within the Transport Rule's 27 states.  EPA is under a timeframe to promulgate the Transport Rule as expeditiously as practicable, as per the remand of CAIR by the Court to the Agency for development of the current Transport Rule.
Some commenters had concerns regarding the EPA's baseline analysis used and with the Agency's rationale for the 2012 compliance deadline.  For more detailed information regarding the Agency's baseline analysis, please see Section V.B of the Preamble.  For more detailed information regarding the Agency's rationale for the 2012 compliance deadline, please see Section VII.C in the Preamble.
Organization: Edison Electric Institute (EEI)
Comment: 
Edison Electric Institute (EEI)
Achieving the substantial SO2 reductions to meet the proposed SO2 limit will be a difficult task in the timeframe proposed and additional time may be needed. Further additional tightening of the SO2 budget in the future may simply not be technically feasible. [EPA-HQ-OAR-2009-0491-2697.1, p.8]
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.51-52.]
This proposed rule requires substantial additional sulfur dioxide, SO2, emissions reductions. SO2 emissions for power plants in Georgia already have been reduced 70 percent during the period of 1990 to 2009. The transport Rule would reduce SO2 emissions for power plants in Georgia by another two thirds by 2014. And the state's power plant SO2 budget would be reduced by 90 percent in 2014 compared to 1990 emission levels.
Response: 
EPA thanks the commenter for their comments and feedback.  EPA is working as expeditiously as possible and within the full extent of its authority, under  Section 110(a)(2)(d) of the Clean Air Act, to ensure improved human health for all Americans through reductions in interstate transport of pollutants within the Transport Rule's 27 states.  EPA is under a timeframe to promulgate the Transport Rule as expeditiously as practicable, as per the remand of CAIR by the Court to the Agency for development of the current Transport Rule.
The commenter seems to have concerns regarding the achievement of substantial SO2 reductions proposed by the Agency.  For more detailed information regarding SO2 reductions under the Transport Rule, please see Sections V and VI in the Preamble.
Organization: Environmental Council of States (ECOS)
Comment: 
Environmental Council of States (ECOS)
ECOS requests that EPA concurrently publish implementation guidance for this rule to states at the time of new rule issuance. Timely issuance of implementation guidance would facilitate state adoption of the new rule as well as increase state and EPA staff resource efficiency in completing activities related to new rule adoption. [EPA-HQ-OAR-2009-0491-2599.1, p.2]
Response: 
EPA intends to provide states with Transport Rule implementation guidance.
Organization: Florida Electric Power Coordinating Group, Inc. (FCG)
Florida Municipal Electric Association (FMEA)
First Energy

Comment: 
First Energy
FE strongly recommends that EPA take the additional necessary time to get this rule right as it is under no Court ordered deadline to address a CAIR remedy. EPA should utilize the upcoming revisions of Ozone and PM 2.5 NAAQS, and more recent emissions data and power sector estimates to develop a revised rule. EPA will achieve the stated health benefits (through continued air quality improvements via established and revised standards) and develop a much more defensible and cost effective rule. [EPA-HQ-OAR-2009-0491-2657.1, p.2; This comment can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.2 10/15/2010]
Florida Electric Power Coordinating Group, Inc. (FCG)
Given the extensive changes that EPA must make to its August 2 initial proposal, EPA must publish a second proposal in the Federal Register before the rule is finalized. As explained below, EPA's proposal contains numerous material factual errors in its data, and flawed assumptions and predictions in its modeling. The correction of these extensive errors will necessarily change the compliance obligations of every state, company and unit, and affected parties must be given an opportunity to review and comment as to whether EPA has corrected its mistakes, and parties can meet their new compliance obligations. Accordingly, EPA is obligated to publish a second proposal to provide the public an opportunity to review and comment on the accuracy and achievability of EPA's corrected approach before this rule is finalized. [EPA-HQ-OAR-2009-0491-2658.1,p.2]
EPA's abbreviated and insufficient comment period underscores EPA's obligation to publish an additional proposal prior to finalizing this rule.  [EPA-HQ-OAR-2009-0491-2658.1,p.2]
Moreover, emission reductions beyond those required by CAIR are not necessary. EPA's data show that existing controls are working to reduce emissions -- emissions of S02 and NOx have declined steadily in recent years. See, e.g., EPA Report titled 'Clean Air Interstate Rule: 2009 Emission, Compliance and Market Analysis,' September 28,2010. The D.C. Circuit's opinion in North Carolina v. EPA did not hold that the overall levels of reductions required under CAIR were less than the levels necessary to comply with CAA section 110(a)(2)(D)(i)(I), nor did the court include in its opinion a mandate that the replacement rule for CAIR include a compliance date in 2012 or within any period of time as short as six months after final rule promulgation. [EPA-HQ-OAR-2009-0491-2658.1,p.3]
Florida Municipal Electric Association (FMEA)
EPA Should leave CAIR in place through Phase I. EPA's imposition of a 2012 compliance obligation is unreasonable and unrealistic, particularly since EPA intends to finalize the rule less than six months before it becomes effective. EPA attempts to dismiss this burden, however, by claiming that the emission levels required in 2012 generally reflect only the emission reductions that would occur even in the absence of the Transport Rule, primarily in compliance with CAIR. However, in a number of cases EPA has made incorrect assumptions regarding emission reductions that will occur at units by 2012. In addition, the approach set forth in the Proposed Transport Rule penalizes early emission reductions under CAIR and seriously weakens market incentives. [EPA-HQ-OAR-2009-0491-2731.1, p. 5]
without the Proposed Transport Rule, a presentation given by EPA in July indicated that the proposal would reduce SO2 emissions by an additional one million tons per year (TPY) in 2012 beyond what the Clean Air Interstate Rule would have accomplished: from a level of 5.1 million TPY under CAIR to 4.1 million TPY under the proposed rule. In fact, during a meeting held shortly after the proposed rule was issued, the Director of EPA's Clean Air Markets Division acknowledged that the 2012 state budgets in the Proposed Transport Rule would reduce SO2 emissions by 1.2 million TPY, from 5.1 million TPY under CAIR to 3.9 million TPY under the Proposed Transport Rule. EPA must explain this apparent discrepancy and how over a million tons of emissions would be eliminated by relying on controls already in use. [EPA-HQ-OAR-2009-0491-2731.1, p. 5]
EPA has also substantially underestimated the time required for facilities to install emission controls, meaning that additional emission reductions will take much longer to achieve than EPA has assumed. EPA's erroneous assumption is that it takes 27 months to design, permit and build an FGD system, and 21 months to design, permit and build an SCR. EPA's timeline apparently only considered the time needed to actually build the system, and disregarded the critical time necessary to design and permit the equipment. Substantial recent experience reveals the actual time needed. Specifically, the Southern Company recently installed 15 FGD systems and 15 SCRs. The average time needed for an FGD system was 54 months (the range was 40-69 months), and for an SCR was 36 months (the range was from 28-42 months). Progress Energy recently installed nine FGD systems and nine SCRs, and it took approximately 44 months for an FGD system, and 38 months for an SCR. In addition, utilities typically put emission control projects out for competitive bid, which adds several months to the process to help ensure that the most cost-effective expenditure is being made. Also, the resolution of other environmental issues takes time, including water use and discharge permitting, and ash and gypsum management. A recent control project in Florida was installed, and yet delayed several months to address such issues. None of these factors appear to have been considered by EPA. EPA must correct its control-installation timeline assumptions to match reality. [EPA-HQ-OAR-2009-0491-2731.1, pp. 5-6]
Moreover, emission reductions beyond those required by CAIR are not necessary. EPA's data show that existing controls are working to reduce emissions -- emissions of SO2 and NOx have declined steadily in recent years. See, for example, the EPA Report titled "Clean Air Interstate Rule: 2009 Emission, Compliance and Market Analysis," September 28, 2010. The D.C. Circuit's opinion in North Carolina v. EPA did not hold that the overall levels of reductions required under CAIR were less than the levels necessary to comply with CAA section 110(a)(2)(D)(i)(I), nor did the court include in its opinion a mandate that the replacement rule for CAIR include a compliance date in 2012 or within any period of time as short as six months after final rule promulgation. [EPA-HQ-OAR-2009-0491-2731.1, p. 6]
Response: 
Several commenters stated that the Transport Rule goes well beyond the scope of CAIR and creates significant and additional uncertainties for the power generation sector.  In fact, the Transport Rule does create certainty by the fact that it will be replacing CAIR, which the Court ruled as unlawful.  Although the Court did not specify a definitive date by which EPA should promulgate the Transport Rule, the Court did not give the Agency an indefinite stay on replacing CAIR and did, in fact, indicate that the Transport Rule was to be completed in a timely manner.  Please see the Transport Rule Preamble section VII.C for more detailed information.
Organization: Hoppy's Lures
American Public Power Association (APPA)
Adirondack Mountain Club
Maryanski, Joseph
Conover, Barbara
Greisch, Edward
Locker, Robert
Public, Jean
Boudart, Jan
Hansen, Gordon
Ritz, Aaron
Comment: 
Adirondack Mountain Club
New York also has a direct stake in the proposed Mercury Rule. Like NOX and SO2, mercury can be transported hundreds of miles from its source. Across the country, more than 12 million acres of lakes and 473,000 miles of rivers are contaminated by mercury. Forty-four states and territories have issued advisories urging people to avoid or limit consumption of fish due to high levels of mercury. In 2002, New York State alone had posted thirty-two health warnings for mercury covering 59,228 acres of our lakes. In fact, of the approximately 200 water bodies tested in New York, 38 have fish populations that are unsafe to eat because of mercury contamination. [EPA-HQ-OAR-2009-0491-2761, p.3]
Mercury is a highly toxic chemical with effects on the central nervous system comparable to those of lead, especially for unborn fetuses and very young children whose brains are still developing. Children and fetuses exposed to mercury can suffer poor attention span and language development, impaired memory and vision, problems processing information, and impaired fine motor coordination. [EPA-HQ-OAR-2009-0491-2761, p.3]
A recent study by the Centers for Disease Control and Prevention estimates that 1 in 12 women of childbearing years in the U.S. have unsafe levels of mercury in their blood. This means that approximately 300,000 children are born each year with a heightened risk for neurological and developmental problems related to mercury exposure. Even more recently, EPA's scientists stated that this is an underestimate of mercury exposure and that as many as 630,000 children may be born each year with unhealthy levels of mercury in their blood. [EPA-HQ-OAR-2009-0491-2761, p.4]
Evidence continues to mount that mercury causes reproductive problems in wildfowl populations, such as loon and mallard ducks. A recent study by the BioDiversity Research Institute (BRI) and the U.S. Fish & Wildlife Service found that 17 percent of loons sampled in the Adirondacks had mercury levels high enough to affect their reproductive success and behavior. Due to its neurotoxic effects, mercury causes behavioral changes in loons, making them lethargic and decreasing normal activities such as foraging and incubation. Adult birds incubate and feed their young less, while chicks feed less and ride on their parents' backs less, making them more susceptible to predation and chilling. [EPA-HQ-OAR-2009-0491-2761, p.4]
Electric power plants are the largest industrial source of mercury, emitting approximately 48 tons of mercury each year (approximately 30% of the country's mercury emissions). Amazingly, power plants are the only major mercury polluters yet to be regulated under federal clean air standards. Thus, in large part, our nation's mercury problem is due to the fact that while other sources must meet strict emission limits, power plants continue to spew unlimited quantities of mercury into our air, where the rain and snow wash it into our rivers, lakes and oceans, and, ultimately, into our food chain. [EPA-HQ-OAR-2009-0491-2761, p.4]
In December 2000, EPA said that mercury is the hazardous air pollutant (HAP) of greatest concern and determined that "...regulation of HAP emissions from coal- and oil-fired steam generating units under Section 112 (c) of the CAA is appropriate and necessary." Listing of power plants under 112 (c) triggers regulation under Section 112 (d), which requires that all HAPs from sources listed be regulated using a "maximum achievable control technologies" (MACT) standard. [EPA-HQ-OAR-2009-0491-2761, p.4]
In 2001, EPA's scientists said that existing coal-fired power plants could achieve an average of 90 percent mercury reductions under a MACT standard, regardless of the type of power plant or the type of coal burned. A more recent report from the Northeastern States for Coordinated Air Use Management also concluded that 90 percent mercury reductions are feasible. Up to 98 percent reductions have been observed in tests of other kinds of mercury controls. It has also been found that reductions can be accomplished very cost-effectively (on the order of 1/50th of a penny per KWh). According to the EPA, estimated costs for mercury control are similar to the costs associated with technologies currently used at power plants to control nitrogen oxide pollution. In 1999, in its multi-pollutant benefit report, EPA estimated that it would cost $2.7 billion to install mercury-specific control technologies on all plants without scrubbers, resulting in mercury emissions reductions of 70-90 percent. EPA estimates that those costs could decline by an additional 40 percent. This cost is a mere fraction of the $250 billion in revenue generated by the utility industry. [EPA-HQ-OAR-2009-0491-2761, p.4]
The lack of regulation put forward by the EPA our environment in danger of mercury pollution for far too long. Although EPA expects mercury reductions as an indirect result of the emissions controls of NOX and SO2, of which this rule directly addresses. [EPA-HQ-OAR-2009-0491-2761, p.4]
Under a cap and trade system, industry would essentially be given the option to decide which plants to clean up. Instead of determining where mercury needs to be reduced on the basis of science and environmental sensitivity, such determinations will be based on market dynamics. As it is, New York is downwind of Midwest plants that utilize the cheapest fuel -- high sulfur, bituminous coal. These plants can operate fifty percent cheaper than plants utilizing natural gas or low-sulfur coal. Unfortunately, the cheapest fuel is also the dirtiest and the combustion of such fuel releases significant amounts of mercury into the atmosphere. Since these Midwest power plants have no incentive to switch to cleaner fuel sources, it would seem that the only way to limit harmful emissions from these plants is to require them to install mercury control technologies. However, ADK fears this will be slowed under a free market cap and trade system. Plants would be able to avoid making mercury emissions reductions by buying credits from plants in other geographic locations that emit less than the standard. The bottom line is that market dynamics and the economics of fuel would lead to hot spots in New York. New York would continue to get mercury in levels that pose serious health and ecological threats. [EPA-HQ-OAR-2009-0491-2761, pp.4-5]
ADK suggests mercury budgets for each state be based on science and that the EPA restrict trading of emissions based on the upwind and downwind "linkages" as reported in CATR. [EPA-HQ-OAR-2009-0491-2761, p.5]
American Public Power Association (APPA)
APPA "real world" examples of pollution control installation timing:
- Holland, MI: Holland Board of Public Works (a municipally owned public utility in Holland, Michigan) has Unit 5, which is 27 MW, installed 1969, already with low NOx burners, has the capability to fire natural gas. As a result of this Regional Transport Rulemaking, this utility informs APPA that Holland will probably switch to natural gas rather than try to install further pollution controls, as the installation cost/ton NOx or SO2 reduced is way above the EPA's guidelines for reasonable cost. [EPA-HQ-OAR-2009-0491-2812.1, p.31]
APPA believes that the concerns about natural gas infrastructure (carrying capacity of the natural gas pipeline system to accommodate the possible fuel switching or conversions from coal to gas in 31 states and the storage concerns of that pipeline (especially in the Northeastern states) is significant. APPA believes it would take at least six years to expand the pipeline system in the 31 RT states. Further, APPA notes that many hearings have been held in California and in Washington, D.C. regarding the safety of the existing natural gas pipeline system after the tragic accident in San Bruno, California in September 2010. APPA is not qualified to know whether the existing pipeline system needs any retrofits or safety enhancements or if that accident was a single event. Regardless, if a significant portion of the electric utility sector would be pushed to natural gas conversions in the 31 Regional Transport states -- supply and infrastructure issues for natural gas delivery much be seriously considered. This natural gas pipeline and storage alone may justify additional time to make the deadlines no earlier than 2015. APPA encourages the U.S. EPA and Office of Management and Budget to consider these natural as issues. Please also see the New York Times story along with the references/link in that story indicating that there are other U.S. governmental agencies looking at the natural gas pipeline infrastructure and safety issues. On September 28, 2010 the U.S. Senate Committee on Commerce, Science, and Transportation held a hearing on pipeline safety. APPA encourages the EPA to consider the hearing results and other agency reviews of safety issues when looking at the deadlines for the Regional Transport rule. [EPA-HQ-OAR-2009-0491-2812.1, p.33]
Boudart, Jan
The Bush Administration refused to take action against arsenic in water even after its danger was understood. Now we have an administration that not only believes in science, but also believes in protecting its most important resource its people. WE MUST CHANGE THE ATTITUDE PERPETRATED BY THE GEORGE W. BUSH ADMINISTRATION! [EPA-HQ-OAR-2009-0491-3228, p.2]
And about 40 years ago, European governments took action against their citizens' exposure to lead as soon as its dangers were known. But in the U.S., the influence of paint manufacturers and corporations prevented action to the great suffering of many Americans. [EPA-HQ-OAR-2009-0491-3228, p.2]
You will notice that we have heard from several sheet-rock manufacturers and the representatives from their associations and coalitions. Did you notice who we are not hearing from? The laborers and workers who deal with the raw materials of sheet rock and Portland cement. They have not been mentioned as victims of unregulated handling of fly-ash and clinkers. Regulating coal ash will have a minor effect on the industrial uses. Factory owners will have to keep records, take measures to protect their workers and be subject to inspections. But they will still have access to what may be the cheapest raw material imaginable the coal ash. A waste product we want to get rid of. [EPA-HQ-OAR-2009-0491-3228, p.2]
Now we have another opportunity to place coal ash in a special category under subtitle C of the Resource Conservation and Recovery Act. If it is classified as hazardous, regulations will automatically go into effect. [EPA-HQ-OAR-2009-0491-3228, p.2]
We must act decisively to protect your born and unborn children and all the citizens of our Country. [EPA-HQ-OAR-2009-0491-3228, p.2]
Conover, Barbara
I note that 'EPA anticipates that power plants may use the following to achieve emission reductions: operate already installed control equipment more frequently, use low sulfur coal, or install control equipment such as low NOx burners, Selective Catalytic Reduction, or scrubbers (Flue Gas Desulfurization).' I >strongly encourage you to amend the proposed Rule to discourage attainment through low sulfur coal! This usually imported coal increases our dependence on fossil fuels from unstable regions and perpetuates our dependence on this the dirtiest of fossil fuels. EPA should write the rule so that it encourages transition off coal.[EPA-HQ-OAR-2009-0491-0917, p.2]
Greisch, Edward
Coal contains: URANIUM, ARSENIC, LEAD, MERCURY, Antimony, Cobalt, Nickel, Copper, Selenium, Barium, Fluorine, Silver, Beryllium, Iron, Sulfur, Boron, Titanium, Cadmium, Magnesium, Thorium, Calcium, Manganese, Vanadium, Chlorine, Aluminum, Chromium, Molybdenum and Zinc. There is so much of these elements in coal that cinders and coal smoke are actually valuable ores. We should be able to get all the uranium and thorium we need to fuel nuclear power plants for centuries by using cinders and smoke as ore. Unburned Coal also contains BENZENE, THE CANCER CAUSER. We could get all of our uranium and thorium from coal ashes and cinders. The carbon content of coal ranges from 96% down to 25%, the remainder being rock of various kinds. [EPA-HQ-OAR-2009-0491-1015, p.1]
If you are an underground coal miner, you may be in violation of the rules for radiation workers. The uranium decay chain includes the radioactive gas RADON, which you are breathing. Radon decays in about a day into polonium, the super-poison. [EPA-HQ-OAR-2009-0491-1015, p.1]
Chinese industrial grade coal is sometimes stolen by peasants for cooking. The result is that the whole family dies of arsenic poisoning in days, not years because Chinese industrial grade coal contains large amounts of arsenic. [EPA-HQ-OAR-2009-0491-1015, p.1]
Yes, that ARSENIC is getting into the air you breathe, the water you drink and the soil your food grows in. So are all of those other heavy metal poisons. Your health would be a lot better without coal. Benzene is also found in petroleum. If you have cancer, check for benzene in your past. See: http://www.ornl.gov/ORNLReview/rev26-34/text/coalmain.html for most of the above. [EPA-HQ-OAR-2009-0491-1015, p.1]
Hansen, Gordon
PROPOSAL FOR A NATIONAL SOLAR HOT WATER HEATING LOAN PROGRAM PAYS FOR ITSELF AND WILL:
- Create thousands of new companies
- Create hundreds of thousands green jobs
- Save homeowners up to one-third energy bills
- Save the nation's homeowners $45 billion each year
- Save 500 billion pounds CO2 pollution each year -
- Offset power consumed by over 30 million homes
- Offset 80 one billion watt power plants
- Reduce global warming [EPA-HQ-OAR-2009-0491-1955, p.2]
All this can start very quickly through existing technology with no homeowner up-front money required because of a simple federal no-interest loan.[EPA-HQ-OAR-2009-0491-1955,p.2]
Hoppy's Lures
Fishing in the South as well as the rest of this country is not just a sport, but a way of life. The ban that the EPA is trying to put on lead for fishing would be devastating not only to a sport but to the economy. It would have a snowballing effect on just about everything from manufacturing, sporting good stores, marinas, hotels, motels and convention centers, restaurants, airlines, gasoline sales, printing etc. etc. etc. It would do away with thousands of jobs and have a tremendous effect on a already struggling economy. In a bad economy it is an inexpensive pastime for people that are already out of work. This would have a huge effect on so many people. And would produce little to no results in what they are trying to achieve. [EPA-HQ-OAR-2009-0491-1812, p.1]
Locker, Robert
I recently learned that at least 52 conventional coal fired power plants are scheduled to move forward toward completion without technology to sequester Carbon. Though proponents of such wasteful polluting industries say they are leaving room in the Infrastructure of these new monstrosities, they are not expecting the technology to be developed until 2020. Each year coal plants pour millions of tons of harmful pollution into our air. This pollution doesn't stop at state lines, and as a result people throughout the country are forced to breathe unhealthy air. [EPA-HQ-OAR-2009-0491-1050, p.2]
I like this idea though I do hope that the 52 dirty coal power plants already in the works are properly encouraged to drop DEAD coal technology in favor of more sustainable technology involving microbial life forces and intensive use of OUR waste stream to produce Biogas, and use decentralized Micro-Turbine heat, cooling, and electric power generation technology to power communities where bio-waste is initially processed. Almost everything taken to a transfer station can be used as a bio-fuel, or can be reused in some other purposeful way. Use of DIRTY DEAD COAL is the BIGGEST WASTE of our national time, treasure, and effort. Stop it NOW please? [EPA-HQ-OAR-2009-0491-1050, p.2]
This is a national problem that needs a national solution, and I urge the EPA to quickly finalize this common sense approach to protect public health and help states efficiently and cost-effectively clean up their air. The Supreme Court has ruled that the EPA has the authority to control carbon emissions. Please continue to build in a commonsense way the sticks and carrots approach to get Dirty Energy OUT OF THE PICTURE as soon as possible. 'We The People' of the US of America will benefit beyond measure, as will 'We The People' of the world. [EPA-HQ-OAR-2009-0491-1050, p.2]
Maryanski, Joseph
I also firmly believe that more must be done to convince fleet operators to move away from diesel engines wherever possible especially for delivery type vehicles, school and other buses.. Modern emission controls seem currently ineffective at reducing the soot, particulate and fowl odors that can cause asthma and other breathing maladies . Until I heard of 'fracking' I thought that natural gas would be our salvation in this regard but now enlightened by the horror of 'fracking' I am not so sure. [EPA-HQ-OAR-2009-0491-0505, p.2]
I am also scared to hell of nuke plants (tombs is more apt term) which are aging and more prone to disrepair and neglect by profit hungry utility companies, especially the likes of Excelon (Oyster Creek, Lacy Twp, NJ) which thumbs its nose at the public and regulators over Tritium leaks and bay warming and degradation. No further nuke plants should be considered until every avenue of renewable energy has been exhausted. Lastly, renewable energy needs equal funding on par with fossil fuel subsidies and tax breaks. Fossil fuel subsidies MUST be eliminated along with all tax breaks to the point of equaling our current or adjusted investment into renewable energy. Every effort must be made to encourage (but not force except by control of the limits of the offending emission) alternative type renewable energy known to be successful like solar, wind, geo, hydro and I expect in a decade or less wave and water current... [EPA-HQ-OAR-2009-0491-0505, p.2]
Public, Jean
all state and federal government agencies that burn up vegetation in any way need to be regulated by EPA. it is clear that the massive collaboration to burn up land for various purposes being done by bureau of land management, national park service, forest service, new jersey division fish & game, and private sources like the duke farms in NJ leads to terrible air pollution of fine particulate matter. such fine particulate matter leads to lung cancer, heart attacks, strokes, allergies, asthma and pneumonia, causing much spending on health care by taxpayers in this nation. the health effects of burning vegetation, which releases mercury as well with its horrible health effects, needs to be stopped. [EPA-HQ-OAR-2009-0491-0132, p.1]
EPA has been in charge of pollution for past 70 years and is not doing enough to protect health. it has gone way past the time to act for health's sake. NJ is a recipient of dirty air from the flow across this country, but its state agencies burn for frivolous reasons. for example NJ div fish & game wants to burn to grow birds so they can kill them. that burning for this stupid reason shows how stupid govt agencies can get. the health effects of this burning are tremendous and cost billions. [EPA-HQ-OAR-2009-0491-0132, p.1]
all forest fire burning permits of 'controlled burns' need to be stopped and banned. Health officials need to also be part of any burning anywhere at any time. In NJ, we have new jersey division fish & wildlife burning, NJ park service, NJ forest fire service, NJ green acres and the private rich foundation of duke farms being allowed to burn, all releasing fine particulate matter and mercury into the air, causing people to die and be injured. this needs to stop. we need EPA to stop this out of control burning. sometimes fire officials want to burn for extra pay and extra overtime salaries. all of this burning needs to be stopped. [EPA-HQ-OAR-2009-0491-0132, p.1]
Ritz, Aaron
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.175.]
Accordingly to the EPA one in six women already has enough mercury in her body to put her baby at risk of developmental problems. This rule would indirectly help lower that exposure.
The rule will also reduce mercury contamination. Already 47 states have warnings not to eat the fish from their waters because of unsafe mercury levels.
Response: 
EPA thanks commenters for sharing their views and opinions regarding the welfare of the environment.  The purpose of the Transport Rule is to reduce emissions of PM2.5, SO2, and NOX.  The Transport Rule is not about the regulation of mercury, natural gas, arsenic, coal, lead in fish, diesel fuel, nuclear energy, burning of vegetation, nor the use of solar hot water generation.  The Transport Rule's purpose is not to dictate what fuels to use nor how.  The fuel options for use are completely up to the owners/operators of the power sector.  For more information on the Transport Rule, please see the Preamble.
Organization: Midamerican Energy Holdings Company
Comment: 
Midamerican Energy Holdings Company
EPA has indicated that certain errors had been made in the original state emission budgets, based on a variety of factors, and that the final state emissions caps will be subject to further review and revision. Likewise, EPA has proposed three options to implement the Transport Rule provisions. MidAmerican believes that, to comply with the Administrative Procedures Act, EPA would be required to re-notice and issue for public comment any significant changes to the proposed rule. Nonetheless, MidAmerican does not waive and specifically reserves the right to raise additional issues associated with changes to the state or individual facility emissions budgets and/or in the event that the final rule is significantly more restrictive than EPA's current preferred option. [EPA-HQ-OAR-2009-0491-2748.1 p.6-7]
Response: 
EPA thanks the commenter for their comments and feedback.  EPA is working as expeditiously as possible and within the full extent of its authority, under  Section 110(a)(2)(d) of the Clean Air Act, to ensure improved human health for all Americans through reductions in interstate transport of pollutants within the Transport Rule's 27 states.  EPA is under a timeframe to promulgate the Transport Rule as expeditiously as practicable, as per the remand of CAIR by the Court to the Agency for development of the current Transport Rule.
For more detailed information on the Agency's final allocations methodology, please see Section VII.D of the Preamble.  For other general information about the rule, please see the Preamble.
Organization: Minnesota Power 
Comment: 
Minnesota Power 
Exclude Minnesota from the final Transport Rule.  Minnesota should not be included as a Transport Rule affected state when EPA finalizes the rule. EPA has already indicated that Minnesota has provided for comparable emission reductions without the imposition of further requirements from the Transport Rule.  [EPA-HQ-OAR-2009-0491-2750.1, p.5] 
Extend the Minnesota Administrative stay.  If EPA ultimately decides that Minnesota should be a Transport Rule affected state in the final rule, Minnesota Power requests that EPA also extend the existing Administrative Stay of the Clean Air Interstate Rule in Minnesota indefinitely and that EPA establish Minnesota Transport Rule, Group 2 state annual budget requirements no earlier than for calendar year 2015 (the first full calendar year that follows a three year planning period for controls deployment after EPA's projected mid-2011 Transport Rule finalization). Minnesota Power anticipates that such a time extension can be justified for most if not all Transport Rule affected states. [EPA-HQ-OAR-2009-0491-2750.1, p.6]
Response: 
Minnesota is included in the Transport Rule Region for fine particles only.  For further information on the analysis done to determine downwind air quality and upwind state emissions, please see Section V of the Preamble.  For further information on the quantification of state emission reductions required, please see Section VI of the Preamble.
The Court ruled that CAIR was unlawful, thereby necessitating the development of the Transport Rule.  Although the Court did not specify a definitive date by which EPA should promulgate the Transport Rule, the Court did not give the Agency an infinite stay on CAIR and did, in fact, indicate that the Transport Rule was to be completed in a timely manner.
Organization: Pfeiff, Mike
Comment: 
Pfeiff, Mike
20. Transport Rule Vacatur Scenario - The EPA should provide guidance to stakeholders about what set of market rules would be in place if the Proposed Transport Rule was vacated during judicial review.
I request that the EPA provide the market with a explanation of the implications under a scenario where the Proposed Transport Rule is vacated. [EPA-HQ-OAR-2009-0491-2742.1, p.14]
Response: 
EPA has undertaken a very thorough analysis and rulemaking development effort, as per the guidelines of the Courts remand of CAIR to the Agency.  Due to the Agency very strictly following the legal guidance of the Court in development of the Transport Rule, EPA does not believe this rulemaking will be vacated by the Court.
Organization: South Carolina Department of Health and Environmental Control 
Ripple, Steven
Comment: 
Ripple, Steven
The following is a list of things that I would do as EPA Administrator (in no specific order):
(1) Ban mercury emissions from all sources (not to mention countless others). [EPA-HQ-OAR-2009-0491-1611, p.2]
(2) Ban PVC. There is nothing good about PVC, and you should already know all about it. [EPA-HQ-OAR-2009-0491-1611, p.2]
(3) Ban the use of or inclusion (direct or indirect) of formaldehyde, aldehyde, chlorine, PVC, ABS, bromine, xylene, toluene, other dangerous solvents, ozone, HCFCs, HFCs, ethylene glycol, biocides, and the list goes on and on and on (you get the point) in any form in the manufacture of all consumer and commercial products, especially building products, construction products, and buildings themselves. Through the use of safe and/or renewable plastics - like polyethylene and polypropylene - and natural, renewable, recycled, and truly sustainable products we can begin to make the indoor air quality of our homes and workplaces finally better than the air quality outside. Set new minimums and rules for recycling practices and recycled content. [EPA-HQ-OAR-2009-0491-1611, p.2]
(4) Set limits on or the amount of or in some instances ban altogether non-renewable plastics, as well as setting new industry standards for VOCs (including doing away with exempt solvents and other exempt chemicals, as this is of the highest degree of ignorance). [EPA-HQ-OAR-2009-0491-1611, p.2]
(5) Work with the Dept of Agriculture to ban the use of toxic pesticides, herbicides, and chemical fertilizers that are all contributing to the pollution of our groundwater, aquifers, streams, rivers, lakes, and oceans, as well as contributing heavily to countless diseases and global warming. Set better regulations for organic farming and eventually phase out non-organic farming practices. Without non-organic farming, there would be no need to certify organic. In the meantime organic certification should be priced on a sliding scale based on a farm's or company's size or profit margin. [EPA-HQ-OAR-2009-0491-1611, p.2]
(6) Work with the Dept of Agriculture to overhaul our nation's meat industry. Set new safety and animal welfare standards for farming practices, limit the use of antibiotics to life-saving instances, ban growth hormones, ban feeding livestock anything unnatural or unsanitary, and set better regulations for organic farming and eventually phase out non-organic farming practices. Without non-organic farming, there would be no need to certify organic. In the meantime organic certification should be priced on a sliding scale based on a farm's or company's size or profit margin. [EPA-HQ-OAR-2009-0491-1611, pp.2-3]
(7) Work with the Dept of Agriculture, the FCC, the FTC, and the Dept of Commerce to make it illegal to falsely advertise a product as green, sustainable, and/or renewable without passing a strict set of guidelines. This will make it easier for the public to choose truly green products and impossible for companies to deceive people into buying dirty ones. [EPA-HQ-OAR-2009-0491-1611, p.3]
(8) Work with the Environmental Working Group's Skin Deep Cosmetics Database - http://www.cosmeticsdatabase.com/ - to ban the use of all dangerous chemicals in our health and beauty products. Also ban the use of such chemicals in laundry, dish, and car detergents. Basically ban the use of these chemicals for anything that will end up in our water, air, or soil supply!! There are too many chemicals to list here. [EPA-HQ-OAR-2009-0491-1611, p.3]
(9) Work with the Dept of Commerce to ban the import of any goods to this country that are produced with any banned chemicals I've listed above, plus countless more.  [EPA-HQ-OAR-2009-0491-1611, p.3]
(10) Ban the hydraulic fracturing methods that is poisoning our water, food, animals, grasslands, soil, streams, rivers, and aquifers (see Gasland the documentary here: http://gaslandthemovie.com/. [EPA-HQ-OAR-2009-0491-1611, p.3]
(11) Ban mountaintop removal. [EPA-HQ-OAR-2009-0491-1611, p.3]
(12) Ban falsely sustainable ethanol from corn. Sugar ethanol is the only ethanol that is truly sustainable. [EPA-HQ-OAR-2009-0491-1611, p.3]
(13) Set new minimums for truly sustainable and renewable energy sources including widely unrecognized and ignored ones like Waste Heat, Geothermal, and Landfill Methane. While CO2 sequestration seems to be a suitable short-term solution to CO2 emissions, requiring more CO2-free or low-CO2 energy is a much better long-term solution. Cap and trade is not a viable long-term solution either. Sequestration and cap and trade aim to treat the symptoms of our planet's (and inhabitants') diseases rather than treating the causes. [EPA-HQ-OAR-2009-0491-1611, p.3]
(14) While setting mpg standards and emission standards for cars is a good start, we need a push to utilize the technology used by vehicle manufacturers such as Think - http://www.thinkev.com/ . The Chevy Volt just doesn't go far enough - the technology is entirely too limited. [EPA-HQ-OAR-2009-0491-1611, p.3]
(15) Work with the Dept of Energy to unveil brand new basic federal requirements as well as new Energy Star requirements. The Energy Star requirements of now should be the new federal minimums, and the new Energy Star requirements should be set so that at least 80% of all current Energy Star labeled products are no longer considered Energy Star. [EPA-HQ-OAR-2009-0491-1611, p.3]
(16) And finally, any home that was built or worked on during the period of 1930 and 1980 may have asbestos in just about every area: http://www.asbestosresource.com/asbestos/products.html. With the incentives out there for remodeling and retrofitting, I think there needs to be a new campaign to raise asbestos awareness for contractors, homeowners, and home inhabitants. There also needs to be a push for low-cost asbestos testing. When a homeowner budgets for a remodel, he likely doesn't budget for testing each wall, ceiling, and floor for asbestos. If the project is done without testing, and asbestos fibers pollute the home, the contractor and the home's inhabitants will likely suffer extremely unnecessary and dire consequences. [EPA-HQ-OAR-2009-0491-1611, p.3]
Thank you for taking the time to read this. I fully expect to hear back from you regarding these ideas. They are not new, but they should be implemented to the fullest extent possible as soon as possible, and I'd love to hear your reaction to them as well as your explanation of why they haven't been implemented yet, whether or not you plan to implement them, and if you do, when? [EPA-HQ-OAR-2009-0491-1611, pp.3-4]
South Carolina Department of Health and Environmental Control 
Section 105 grants are the federal funds authorized by the Clean Air Act to support the core functions of state and local air pollution planning and control programs. 57 The EPA describes these grants in its 2011 Budget in Brief document: These funds provide resources to multi-state, state, local, and Tribal air pollution control agencies for the development and implementation of programs for the prevention and control of air pollution and for the implementation of National Ambient Air Quality Standards (NAAQS) set to protect public health and the environment.58 [EPA-HQ-OAR-2009-0491-2677.1 p.22]
The EPA withholds funds from its Section 105 grants to fund the operation of the NOX SIP Call and CAIR trading systems. For fiscal year 2010, the EPA subtracted $66,500 from its Section 105 grant to South Carolina, and $665,665 from EPA Region 4 states and local governments, to support the NOX SIP Call and CAIR trading systems. [EPA-HQ-OAR-2009-0491-2677.1 p.22]
DHEC requests that if the EPA issues a final rule with a FIP, then it should not use Section 105 grants to fund the federal Transport Rule trading program and all future funding from 105 funds for the trading program should cease. An alternative funding option would be for the EPA to charge a small fee for transactions in the trading system. The transaction costs in current EPA trading programs are currently low,59 and the market could withstand a small fee without inhibiting trading. Such a funding source would be more reasonable than using state and local grant money intended for core air quality programs to support an EPA operation, especially in this period of state budgetary contraction. [EPA-HQ-OAR-2009-0491-2677.1 p.22]
Response: 
EPA thanks the commenters for their feedback and suggestions.  EPA is working as expeditiously as possible and within the full extent of its authority, under  Section 110(a)(2)(d) of the Clean Air Act, to ensure improved human health for all Americans through reductions in interstate transport of pollutants within the Transport Rule's 27 states.  The purpose of the Transport Rule is to reduce emissions.  The list of suggested Agency actions to be performed and the suggestion that the Agency not use Section 105 grant money for implementation of the Transport Rule are outside the scope of this rulemaking.  Section 105 grant money is not related to this rulemaking.
Organization: Headington, Maureen
Comment:
Headington, Maureen
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.136-137.]
I didn't know about this hearing except that someone from one of the lung association's two days ago sent me something, and 'Oh, oh. I have to do this.' This is so important.
I wish these things would be broadcast on every radio station, on every television station because metro Chicago, it is just unfathomable what we've had to endure.

Response:
On August 2, 2010, EPA gave public notice on the Agency's Transport Rule website (http://epa.gov/airquality/transport/actions.html) indicating that three public hearings would be held on August 19[th] (Chicago, IL), August 26[th] (Philadelphia, PA), and September 1[st]  (Atlanta, GA) of 2010 to allow the public ample opportunity to share their views and comments with the Agency.
Organization: Kentucky Division for Air Quality
Comment:
Kentucky Division for Air Quality
Timely guidance from EPA is extremely critical to implementation of the final Transport Rule. This guidance should be issued concurrent with finalization of the rule. [EPA-HQ-OAR-2009-0491-2805.1, p.1]
Response:
EPA understands that individual states have unique circumstances regarding implementation of the Transport Rule and will be working with individual states, through the Agency's regional offices, to ensure that each affected state will meet the Transport Rule requirements.
Organization: Recycled Energy Development
Comment:
Recycled Energy Development
First, and most important, EPA should adopt output-based emissions standards in the Federal Plan. Rather than base pollution limits on the amount of fuel consumed, standards based on each unit of electricity (and thermal energy) produced would encourage efficiency. As a result, pollution would be prevented and emissions reduced. [EPA-HQ-OAR-2009-0491-2601.1, p.2]
Response:
Please see section VII of the preamble for a detailed explanation on the Agency's allocations methodology used in the Transport Rule and why it is not using an output-based allocations methodology.
Organization: Synthesis Foundation
Province of Ontario, Canada
Wabash Valley Power
Rodman, Margaret
New Jersey Department of Environmental Protection (NJDEP)
Anderson, Sally
Ameren Services Company

Comment: 
Ameren Services Company
Emissions reductions will begin to take effect very quickly, in 2012 - within one year after the rule is finalized. By 2014, the rule and other state and EPA actions would reduce power plant SO2 emissions by 71 percent over 2005 levels. Power plant NOx emissions would drop by 52 percent.' [EPA-HQ-OAR-2009-0491-0083, p.2]
Anderson, Sally
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.162-163.]
Air pollution can directly affect animals exactly the same way it does humans, only their systems, their lungs and everything are more sensitive because they're much smaller.
Without implementation to control pollution, our animals and our wild life and the plants around us can seriously be compromised.
New Jersey Department of Environmental Protection (NJDEP)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.156-157.]
disconnecting the SO2 reductions from the Acid Rain Program
Province of Ontario, Canada
However, MOE scientists believe that even with the significant reductions in the emission of NOx and SO2 required by the Rule, Ontario will continue to experience exceedances of our air quality standards, notably Canada's ozone standard (0.065 ppm), because of trans boundary air pollution from the U.S. The reductions required by the Rule will likely reduce the degree of exceedances in Ontario, and their frequency, but the Transport Rule alone will not eliminate them. [EPA-HQ-OAR-2009-0491-2610.1, p.1]
Accordingly, we are pleased that the U.S. EPA will augment the Transport Rule with other initiatives to reduce air pollution and protect human health and the environment. These initiatives include the reconsideration of the National Ambient Air Quality Standards (NAAQS) for Ozone, an additional regulation related to utility boilers, a second Transport Rule, and a revised PM NAAQS. We urge the U.S. EPA to move forward with these initiatives as expeditiously as possible. [EPA-HQ-OAR-2009-0491-2610.1, p.2]
As we have explained in other submissions, Ontario shares its southern border with eight U.S. states, and its airshed with many more. Because of proximity to the U.S., Ontario is profoundly affected by air pollution from U.S. sources. Excessive levels of air pollution cause thousands of premature deaths each year in Ontario, and are responsible for tens of thousands of additional hospital admissions and emergency room visits annually. We cannot meet our own air quality standards without significant reductions in trans boundary air pollution from the U.S., particularly ozone and its precursors. [EPA-HQ-OAR-2009-0491-2610.1, p.2] 
Even if Ontario were to reduce its own sources of air pollution to zero, we would still experience exceedances of our ozone standards at most of our monitoring stations because of air pollution from the U.S. Conversely, if no air pollution from the U.S. flowed into Ontario, we would easily meet our ozone standards at all of our monitoring stations. [EPA-HQ-OAR-2009-0491-2610.1,p.2]
In Ontario, we are determined to fight climate change, improve air quality, develop renewable energy sources, and transition to a strong green economy. Since the McGuinty Government was elected in 2003 (and re-elected in 2007), we have taken aggressive action on multiple fronts to meet these goals, including: [EPA-HQ-OAR-2009-0491-2610.1,p.2]
Phasing out coal-fired electricity generation. Ontario is phasing out coal-fired electricity generation by the end of 2014. The largest generating plant in the Toronto area closed in 2005. Ontario has announced the phase-out of four more coal-fired units by the end of 2010, with the balance phasing out by the end of 2014. Ontario's coal phase-out initiative will eliminate NOx and SO2 emissions from these units, and will reduce provincial emissions by 12% and 24%, respectively, and greenhouse-gas emissions by up to 30 million tonnes per year. [EPA-HQ-OAR-2009-0491-2610.1, p.3]
Replacing coal-fired electricity with renewable energy. Since October 2003, the McGuinty Government has secured contracts representing more than 5,000 megawatts (MW) of new renewable energy supply from large and small-scale projects across Ontario. More than 1,400 MW of these projects have reached commercial operation and are generating clean electricity from wind, water, sun and bio-based resources. Ontario's Green Energy Act, enacted in 2009, created a Feed In- Tariff program that allows individuals and companies to sell renewable energy at favourable rates. The legislation is expected to create 50,000 green energy jobs over the next three years.  [EPA-HQ-OAR-2009-0491-2610.1, p.3]
Reducing energy demand. Between 2004 and 2007, Ontario reduced its peak electricity demand by 5% (1,350 MW). To further reduce energy use, by the end of 2010 every home and small business in Ontario will have a Smart Meter with electricity prices that vary by time of day and year to more accurately reflect the market price for electricity. By 2012, new Building Code standards will improve the energy efficiency of new homes by 35%. [EPA-HQ-OAR-2009-0491-2610.1, p.3]
Reducing NOx and S02 emissions from Ontario power plants. Ontario regulates NOx and SO2 through mandated emissions caps from large electricity generating units. Ontario reduced nitrogen dioxide emissions from large power plants in the pollution emission management area (PEMA) to 58% below the cap of 39 kilotonnes in 2009. This cap was set under the Ozone Annex in the Canada-U.S. Air Quality Agreement. [EPA-HQ-OAR-2009-0491-2610.1, p.3]
Public transit is a priority for Ontario. In spring 2009, the government announced that Ontario is moving ahead with over $9 billion in priority rapid transit projects. This initiative will reduce air pollution and greenhouse gas emissions from the transportation sector.  [EPA-HQ-OAR-2009-0491-2610.1, p.3]
Setting ambitious greenhouse-gas reduction targets.  We are committed to reducing greenhouse-gas emissions to 6% below 1990 levels by 2014, 15% below by 2020, and 80% below by 2050.  [EPA-HQ-OAR-2009-0491-2610.1, p.3]
Rodman, Margaret
My husband and I attended the meeting from 9 a.m. until 11:00 a.m. and listened to comments made by American Lung Association, Southern Alliance for Clean Energy, Environmental Market Assoc., Edison Electric Industries, CA Smart Energy, and a young Georgia State University Student, whom had recently taken up 'bicycling' as a mode of transportation, and several physicians. [EPA-HQ-OAR-2009-0491-2594, p.1]
We did not speak at the meeting, but approached Tim Smith at the 11 :00 a.m. recess to relay our concerns. Neither my husband nor I are scientists or engineers. The Transport Rule is a most formidable document at 1,364 pages. I attempted to read the whole document but was 'overwhelmed'. [EPA-HQ-OAR-2009-0491-2594, p.1]
We do know the following facts: The monopolistic energy industry has had 40 years to adapt to the needs of our country under an initial mandate by President Jimmy Carter. The mandate was and continues to be ignored. Change is never easy, but the lack of change is devastating to the public's health and our environment. As I write this letter, Atlanta is under another 'Code Orange Air Alert' . At the time of this writing the Georgia Department of Natural Resources site states that Georgia has had 136 Code Yellow Days, 32 Code Orange Days and 1 Code Red Day in 2010. How are we to live under these conditions? The 'Big Red Spot' sits over Metro Atlanta on the Air Quality Forecast Guidance more often than not. [EPA-HQ-OAR-2009-0491-2594, p.1]
Georgia is the 9th most polluted state in our country . Georgia has 46 coal-fired energy plants. These plants are listed on the Department of Energy site. Georgia also has 28 petroleum plants, 34 natural gas plants, 32 hydroelectric plants, 2 nuclear plants (Edwin Hatch & Vogtle which is being expanded at great expense to the public), 10 Wood & Wood Derived plants, 4 Pumped Storage, and 4 Other Biomass plants. [EPA-HQ-OAR-2009-0491-2594, p.1]
The power companies say Georgia needs more new power plants : Washington Plant in Sandersville, Georgia, Longleaf in Early County, Georgia, and Ben Hill Plant in Ben Hill, Georgia. Our state is home to some of the 'dirtiest' coal-fired plants. In 2006, Plant Bowen (a newer plant), in Bartow County, had the largest emission of Sulfur Dioxide on record. [EPA-HQ-OAR-2009-0491-2594, p.2]
Power plants self-regulation/monitoring has not worked in Georgia. On September 29, 2009, I emailed John White, the AIR Now Program Manager, with concerns that there was missing data from air reporting stations in Georgia. His response was courteous: he copied AIRNow Data Management Center. He informed me that AIRNow is a 'voluntary program'. Georgia usually reports, so something must have happened. Shortly after that, the site was terminated. On October 27, 2009, I emailed Michael Hamlin @epa.gov/ttn/airaqs/contacts.htm and asked why the State Transportation Department of Georgia would control the CleanAirProgram in Georgia. I compared this to `allowing the fox to guard the hen house', since Georgia has not been in compliance with Federal Standards for many years. I did not hear back from Michael Hamlin. [EPA-HQ-OAR-2009-0491-2594, p.2]
When Katrina hit the Gulf Coast five years ago, Governor Sonny Perdue allowed the use of the less refined diesel fuel for Georgia trucks as an emergency measure. I have been unable to find out if the cleaner diesel fuel has been reinstated, and if so, when was it reinstated. [EPA-HQ-OAR-2009-0491-2594, p.2]
There has been a pervasive attitude by our government to not do their job and this must stop. The Environment Protection Agency is the empowered guardian of air, land and water for our nation. The lack of oversight has left the nation with seemingly insurmountable effects of polluted air, polluted land, and polluted water (fresh and salt). [EPA-HQ-OAR-2009-0491-2594, p.2]
[Enclosures can be found on pages 3-13 of this comment.]
Synthesis Foundation
This rule change is too lenient.
Jim Rogers & his cohorts & Cinnergy & now Duke made a decision 10+ years ago to violate the new source requirements in the Clean Air Act. The results, according to USEPA data & the American Lung Association are that a lot of people became ill & many others died prematurely in this Region.
In Cincinnati, about 1/2 the fine particulate pollution comes from Duke's Coal burning plants along the Ohio River. USEPA data tells us that there are 4,000-5,000 deaths per year in Ohio (about 400-500 in our region ~Cincinnati) from this pollutant alone.
Are we interested in allowing this to continue. Not on your life. USEPA needs to shut these plants down (the utilities have already written the costs off on their books) in favor of cleaner alternatives, read natural gas & clean energy.
Further, these deaths were premeditated. Rogers and his cohorts decided 10 years ago to kill 1,000's of people more than the law allowed them. If the law is to mean anything then these mass murderers should be brought to justice. Of course they won't be because these killings were done from a board room.
Letting the companies use scrubbers is not the best available control technology & it ignores the fact that industry tends to turn off their scrubbers and not maintain them.
Finally, I would point out that when Duke is making over bloated claims about their view of the cost of this rule that Jim Rogers CEO of Duke has already received almost a 1/4 BILLION $'s from local rate payers for his retirement. In addition Duke has written down some $600 million in costs from its shareholders in the last year alone to update their current equipment. [EPA-HQ-OAR-2009-0491-0139, p.1]
Wabash Valley Power
Lawrence County and Vermillion Stations: 
WVPA owns a minority interest in the Lawrence County and Vermillion Stations. These are simple cycle natural gas-fired peaking stations. WVPA supports the comments filed by the majority owners for these facilities. [EPA-HQ-OAR-2009-0491-2627.1,p.6]
Utility Air Regulatory Group: 
Lastly, WVPA is a member of the Utility Air Regulatory Group (UARG), a voluntary, not-for-profit group of electric utilities, other electric generating companies, and national trade associations. UARG's purpose is to participate on behalf of its members, collectively, in EPA rulemakings under the Clean Air Act ('CAA' or 'Act') and other proceedings that affect the interests of electric generators and in related litigation. WVP A has reviewed and supports the detail [EPA-HQ-OAR-2009-0491-2627.1 ,p.6]
Response: 
EPA thanks the commenters for their support of this Rule.  EPA is working as expeditiously as possible and within the full extent of its authority, under  Section 110(a)(2)(d) of the Clean Air Act, to ensure improved human health for all Americans through reductions in interstate transport of pollutants within the Transport Rule's 27 states.  EPA is under a timeframe to promulgate the Transport Rule as expeditiously as practicable, as per the remand of CAIR by the Court to the Agency for development of the current Transport Rule.
Organization: Texas Commission on Environmental Quality
Comment: 
Texas Commission on Environmental Quality
Additionally, the TCEQ respectfully requests that the EPA hold an additional public hearing for the proposed rule at a location in Texas. Texas's ozone season nitrogen oxides allocations make up a significant portion of the proposed total budget. A public hearing in Texas would thus provide the opportunity for participation to a large number of stakeholders. Also, Texas's participation' in the proposed rule is substantively different from that required in the Clean Air Interstate Rule program. The change from required participation solely in a cap and trade program addressing fine particulate matter (PM2.5) transport to required participation solely in a cap and trade program addressing ozone transport includes a relatively unique challenge for the numerous stakeholders in Texas. That the EPA is requesting comment on Texas's potential inclusion in the PM2.5 cap and trade program only adds to such a challenge and further supports a request for an additional public hearing in the state. [EPA-HQ-OAR-2009-0491-0129.1, pp.1-2]
Response: 
Although the Court did not specify a definitive date by which EPA should promulgate the Transport Rule, it did not give the Agency an infinite stay on CAIR and did, in fact, indicate that the Transport Rule was to be completed in a timely manner.  Section 307(d)(5) of the CAA requires the Administrator to give an opportunity for written or oral comments.  The Act does not specify the length of time, other than the record must be open 30 days after holding public hearings - with which EPA complied.
EPA posted the signed version of the Proposed Transport Rule to the web when it was signed on July 6, 2010.  The proposal was published in the Federal Register on August 2, 2010, and the public comment period closed on October 1, 2010.  This provided a 60 day comment period (or 90 days from the date posted to the web).
EPA posted the signed version of the first Transport Rule Notice of Data Availability (NODA) (IPM) to the web when it was signed on August 25, 2010.  The first NODA was published in the Federal Register on September 1, 2010, and the public comment period closed on October 15, 2010.  This provided a 45 day comment period (or 52 days from the date posted to the web).  EPA posted the signed version of the second Transport Rule NODA (emissions inventories) to the web when it was published in the Federal Register on October 27, 2010.  The public comment period closed on November 26, 2010, which provided a 30 day comment period.  EPA posted the signed version of the third Transport Rule NODA (allocations and related matters) to the web when it was signed on December 30, 2010.  The third NODA was published in the Federal Register on January 7, 2011.  The public comment period closed on February 7, 2011, which provided a 30 day comment period (or 38 days from the date posted to the web).
Given the timeframe EPA provided to the public for submission of comments, and indicative of the fact that the Agency received several hundred substantive comments, commenters did, in fact, have sufficient time to submit their comments for consideration.

XVII. Extension of the Comment Period

Organization: Texas Commission on Environmental Quality
Dynegy, Inc.
Utility Air Regulatory Group (UARG)
Southern Company
Class of '85 Regulatory Group
Duke Energy
NextEra Energy, Inc.
Georgia Department of Natural Resources, Air Protection Branch
8-Hour Ozone State Implementation Plan (SIP) Coalition
American Electric Power
Prairie State Generating Company, LLC
Consumers Energy
Texas Chemical Council
National Rural Electric Cooperative Association (NRECA)
Florida Electric Power Coordinating Group, Inc. (FCG)
Louisiana Chemical Association (LCA)
Midwest Ozone Group
Florida Municipal Electric Association (FMEA)
Westar Energy, Inc.
PPG Industries, Inc.
Louisiana Public Service Commission
Independence Power & Light (IPL)
New York University School of Law, Institute for Policy Integrity
Kansas City Board of Public Utilities (BPU)
American Petroleum Institute (API)
Missouri Public Utilities Alliance (MPUA)
Virginia Department of Environmental Quality (VDEQ)
Consolidated Asset Management Services (CAMS)
Clean Energy Group
West Virginia Department of Environmental Protection
City of Springfield, Illinois, Office of Public Utilities
Lakeland Electric
Seminole Electric Cooperative Inc.
Council of Industrial Boiler Owners (CIBO)
State of Ohio Environmental Protection Agency (Ohio EPA)
State of Louisiana, Department of Environmental Quality
Occidental Chemical Corporation (OCC)
State of Missouri Department of Natural Resources
Capital Power Corporation
Indiana Energy Association
South Carolina Department of Health and Environmental Control 
Northern Indiana Public Service Company (NIPSCO)
Tampa Electric Company
Xcel Energy Inc.
Minnesota Power 
Nebraska Public Power District
City of Tallahassee
Buckeye Power, Inc.
Louisiana Energy and Power Authority (LEPA)
E.ON U.S.
First Energy
Sunflower Electric Power Corporation
Florida Municipal Power Agency (FMPA)
PowerSouth Energy Cooperative
Cleco Corporation
Omaha Public Power District
Kansas City Power and Light Company (KCP&L)
Santee Cooper
Exxon Mobil Corporation
National Mining Association (NMA)
Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
American Public Power Association (APPA)
Ohio Coal Association
JEA
Luminant
Pfeiff, Mike
DTE Energy
Comment: 
8-Hour Ozone State Implementation Plan (SIP) Coalition
The Coalition requests that EPA grant a 90-day extension to the comment deadline for the CATR.  The Coalition intends to submit detailed comments on the proposed new rule.  However, meaningful comments must be based on a thorough review of the underlying emissions inventory, modeling, and other assumptions for Texas sources.  This review is particularly important for Texas sources due to the large potential impact of this rulemaking on these sources.  Additionally, due to the volume, complexity, and the significant differences from previous versions of the rule this review and analysis cannot be completed by October 1, 2010, the original proposed comment deadline.  [EPA-HQ-OAR-2009-0491-0353.1, p.1]
The 8-Hour Ozone SIP Coalition, (the Coalition) along with numerous other organizations and states, requested an extension of the comment period for this rulemaking.  The sixty days provided in the proposal has not proven sufficient to fully analyze the underlying technical materials associated with this rule, nor the potential impact on our members, particularly with the addition on September 1, 2010 of revised technical data supporting the underlying modeling assumptions.  Therefore, we present a brief suite of comments on the proposed rule.  We request that EPA allow affected parties to provide supplemental technical information.[EPA-HQ-OAR-2009-0491-2736.1, p. 2]
American Electric Power
This letter is requesting an extension of the public comment period by 60 days, to November 30, 2010. AEP is a member of the Utility Air Regulatory Group and we also endorse their request for a 60-day extension to the public comment period. [EPA-HQ-OAR-2009-0491-0552.1, p.1]
The proposed Transport Rule will significantly affect the electric utility industry. Therefore, AEP is reviewing this rule with great interest. The proposed rule's length and complexity, along with the many technical documents and data files that EPA has developed and relied upon to draft this proposed rule make preparing and submitting meaningful comments extremely difficult in the time allotted in the published notice. Review of this proposed rule's hundreds of pages (collectively including the proposed rule and technical support documents) and the impact the assumptions used to develop this proposal has on future environmental control requirements and unit operation are very important to AEP and the utility industry as a whole. [EPA-HQ-OAR-2009-0491-0552.1, p.1]
On September 1, US EPA issued a Notice of Data Availability (NODA) surrounding new data and modeling to be used in conjunction with promulgation of the final Transport Rule. The AEP system, consisting of AEP Texas Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma, and Southwestern Electric Power Company, operates in eleven states, all of which are impacted by this program. Thus, the operating companies of the AEP system will be directly affected by the Proposed Transport Rule applicable to the electric generating unit (EGU) source category. This letter supplements our letter dated August 27 and requests an extension of the public comment period to November 30, 2010 for both the proposed rule and the supplemental data. AEP is a member of the Utility Air Regulatory Group and we also endorse their original and supplemental requests for an extension to the public comment period to November 30, 2010. [EPA-HQ-OAR-2009-0491-1811.1, p.1]
AEP is concerned that the proposal rule is based on inaccurate assumptions, especially with regard to incorrect assumptions about installed emission controls. The proposal incorrectly assumed higher FOD removal rates for Gavin Units 1 and 2 and assumed the installation of FOD controls on Muskingum River Unit 5 will occur in 2011, among others. AEP requests a 60-day extension of the public comment period, to November 30, 2010. The new deadline will allow the company to prepare detailed comments that may be useful to the agency to advance this rule. [EPA-HQ-OAR-2009-0491-0552.1, p.2]
As stated above, on September 1, US EPA issued a NODA surrounding new data and modeling to be used in conjunction with promulgation of final Transport Rule. The new data includes an updated National Electric Energy Data System (NEEDS) file, which provides operating parameters for electric generators, as well as an updated version of the Integrated Planning Model (IPM) which is used to model electric sector output and emissions. Since the Transport Rule is fundamentally based on results from NEEDS and IPM modeling efforts, any changes to NEEDS and/or IPM will result in different outcomes within the final Transport Rule. While EPA is providing the data, EPA has not indicated how exactly the data and modeling changes will affect the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-1811.1, p.2]
The proposed Transport Rule will significantly affect the electric utility industry. Therefore, AEP is reviewing this rule with great interest. The proposed rule's length and complexity, along with the many technical documents and data files that EPA has developed and relied upon to draft this proposed rule make preparing and submitting meaningful comments extremely difficult in the time allotted in the published notice. EPA issuance of new data and modeling indicates that EPA has acknowledged they used a flawed and outdated data source in development of the proposed rule. EPA should reevaluate the results caused by these changes and the evaluation should be placed in the rulemaking docket so the general public can understand the ramifications of the NODA information. Previously developed comments regarding data and modeling of the Transport Rule will now have to be completely reevaluated in light of the new data sel. An extension to the comment deadline will allow the company to prepare detailed comments that may be useful to the agency to advance this rule. [EPA-HQ-OAR-2009-0491-1811.1, p.2]
For these reasons, AEP respectfully renews its request for an extension of the public comment period on the Proposed Transport Rule to November 30, 2010, and requests also that EPA extend the comment period on the NODA from October 15 to November 30, 2010. [EPA-HQ-OAR-2009-0491-1811.1, p.2]
American Petroleum Institute (API)
  API requests that EPA grant a 90-day extension to the comment deadline for the Transport Rule (TR). API intends to submit detailed comments on the proposed new rule. However, meaningful comments must be based on a thorough review of the underlying emissions inventory, modeling, cost/benefit analyses and other assumptions. This review is particularly important for our members, as petrochemical and refining sources are affected by several provisions contained in this rulemaking, and will be significantly affected by EPA's future rulemaking on non-EGUs planned for proposal in 2011. Additionally, due to the volume of technical material, complexity of the analysis, and the significant differences from previous versions of the rule this review and analysis cannot be completed by October 1, 2010, the original proposed comment deadline. [EPA-HQ-OAR-2009-0491-2519.1, p.1]
 API, and numerous other states and organizations, requested an extension of the comment period. The sixty days provided in the proposal has not proven sufficient to fully analyze the underlying technical materials associated with this rule, nor the potential impact on our members, particularly with the addition on September 1, 2010 of revised technical data supporting the underlying modeling assumptions. A sufficient comment period would have allowed time for stakeholders, implementing states, and affected facilities to thoroughly examine the photochemical modeling inputs and outputs, allocation tables, IPM runs, cost/benefit analyses, and purported air quality benefits, as well as rule language itself. The time provided was insufficient to harness the scientific, technical and legal expertise needed to analyze these diverse issues. This analysis is critical on important rule proposals, not just because stakeholders must analyze this information to effectively comment about the rulemaking, but also because thorough public analysis often identifies errors, and allows affected stakeholders to present corrections or alternatives to infeasible rulemaking. In the absence of a sufficient comment period, we therefore must present only a brief suite of comments on the proposed rule. We request that EPA allow affected parties to provide supplemental technical information. [EPA-HQ-OAR-2009-0491-2649.1, pp. 1-2]
American Public Power Association (APPA)
APPA submits these comments against a background of Agency decisions that has made participation in this proceeding exceedingly difficult. Specifically, on September 1, 2010, EPA published a separate Notice of Data Availability ("NODA") for the Proposed Transport Rule. 75 Fed. Reg. 53613. The NODA announces additional EPA modeling runs and other information that "EPA proposes to use to support the final rule," as well as "a list of further planned updates to support the final rulemaking." Id. EPA announced a separate comment period for the NODA, extending until October 15, 2010 (and may have separate comment periods for other subsequently posted information), but refused to extend the comment period for the underlying proposal. APPA requested a deadline extension, through its participation in Utility Air Regulatory Group (UARG). EPA`s decision to maintain two separate deadlines for public comments -- one on the Proposed Transport Rule and the information posted in the docket contemporaneously with it, and another for the information released pursuant to the NODA -- makes it extraordinarily challenging to provide comprehensive comments on EPA`s proposal. In addition, EPA on September 10, 2010, denied UARG`s August 19, 2010, request for an extension of the currently inadequate comment period on the Proposed Transport Rule to November 30, 2010, and the EPA has not granted the September 10, 2010 UARG (and APPA indirectly) request for a comment deadline extension to November 30, 2010. This request for the extension was submitted by UARG for both the proposed rule and the NODA. [EPA-HQ-OAR-2009-0491-2812.1, pp.4-5]
In light of the significant differences between the data on which EPA based the proposed rule and the data EPA released later pursuant to the NODA, EPA should withdraw the Proposed Transport Rule, revise it using whatever data EPA deems most appropriate and accurate, and republish it for public comment with an adequate comment period. APPA believes there is no urgency to finalizing the PTR so "getting it right" by taking time to sort out many of the issues brought up in APPA's comments and those from UARG is appropriate. [EPA-HQ-OAR-2009-0491-2812.1, p.5]
The extremely tight implementation schedule that EPA proposes is in effect made even tighter by the fact that EPA is already changing the terms of the proposed rule. As discussed above, on September 1, 2010, midway through the public comment period on the proposed rule, EPA published its NODA, announcing information that in effect will result in substantial changes to the proposed rule and noting that further changes are to come. Among other things, the NODA announced the release of (i) an updated version of the National Electric Energy Data System ("NEEDS"), which provides the unit-level EGU characteristics used as inputs for the Integrated Planning Model ("IPM"), (ii) results of new base case and policy case modeling runs using an updated version of IPM, and (iii) results of new base case and policy case modeling runs using an updated version of IPM and including data from the Energy Information Administration`s Annual Energy Outlook 2010 natural gas resource assumptions. 75 Fed. Reg. at 53614/2-3. It also announces the release of "[a] summary of other planned input updates to be implemented in the final rulemaking." 75 Fed. Reg. at 53614/3. The data released in connection with the NODA will, when applied by EPA, change substantially the statewide budgets and allowance allocations for 2012 and the allowance allocations for 2014,9 and there will presumably be additional changes leading up to promulgation of a final rule based on the planned input updates that EPA says will be implemented later. [EPA-HQ-OAR-2009-0491-2812.1, pp.15-16]
The scope of the impact that the new data will have is clear at a glance. For example, the parsed file that EPA released in connection with the proposed rule, showing the initial IPM run, indicates that IPM projected about 23,723 MW of new coal generation from unidentified plants yet to be built in 10 different states. See IPM Run File "TR SB Limited Trading", available at http://www.epa.gov/airmarkets/progsregs/epa-ipm/transport.html. The updated parsed file that EPA added to the docket in connection with the NODA appears to indicate that IPM projected only about 2,001 MW of new coal generation from unidentified plants yet to be built in four states. See Document No. EPA-HQ-OAR-2009-0491-0312, available at http://www.regulations.gov/search/Regs/home.html#docketDetail?R=EPA-HQ-OAR-2009-0491. This is likely to be merely one indicator of the substantial changes in EPA`s proposal that will result from use of the NODA information, and the impact of the future changes that EPA anticipates remains to be seen. Clearly, there is no way for sources to begin planning for compliance based on the information that EPA has provided in the docket. [EPA-HQ-OAR-2009-0491-2812.1, p.16]
In sum, the fact that EPA`s proposal to set an initial compliance deadline of January 1, 2012, is complex, difficult and uncertainty is a clear illustration of the ill-advised nature of this attempt to force implementation of such a complex and demanding rule in only six months. [EPA-HQ-OAR-2009-0491-2812.1, p.20]
Buckeye Power, Inc.
We wish to begin by lodging our objection as to the October 1,2010 comment period deadline. This deadline does not allow a meaningful opportunity to evaluate the methodology, modeling, and other information that ultimately led to the formation of the CATR rulemaking. Nevertheless, we offer these comments and urge EPA to reconsider the CATR proposal. [EPA-HQ-OAR-2009-0491-2710.1, p.1]
We understand that EPA submitted supplemental data to update its methodology and modeling, and that there is an October 15, 2010 comment date on the supplemental data. Buckeye plans to submit separate comments on the supplemental data by the October 15,2010 deadline. [EPA-HQ-OAR-2009-0491-2710.1, p.1]
Capital Power Corporation
The comment period was inadequate, particularly in light of simultaneous comment periods for other complex rules and the recent publication of revised data on this rule, with a separate, simultaneous comment period. Sixty days is inadequate to comment on a proposal of such scope and complexity that will regulate all electric generation in two-thirds of the nation and affect every other sector of the economy and every individual energy consumer in the nation. Also, EPA is requesting comments on an inordinately large number of issues within the rule that have implications and effects on other components of the rule. These issues must be carefully considered and their implications thought through to arrive at a consistent and logical position. The 60 days allowed is insufficient to accomplish all these with resources most companies have available to them. [EPA-HQ-OAR-2009-0491-2753.1, p.2]
Companies that operate industrial, commercial and institutional (ICI) boilers are especially negatively affected by EPA's failure to provide an adequate comment period. During the entire first half of the comment period for this rule, those sources were fully engaged in analyzing and developing comments on the four interrelated Boiler MACT rulemakings, which EPA estimates will have tens of billions of dollars of impact on ICI boilers. Therefore, those companies directly and immediately affected by this proposed rule have effectively had 30 days to assess its ramifications and develop comments. The technical resources of regulated sources are finite, especially personnel with the technical expertise to analyze the implications of EPA's long and complex regulatory proposals. Those resources were fully deployed during the very short comment period for the four complex Boiler MACT rules, and could not have simultaneously conducted an in-depth analysis of the long and complex Transport Rule. [EPA-HQ-OAR-2009-0491-2753.1, p.2]
City of Springfield, Illinois, Office of Public Utilities
CWLP's initial objection is to the October 1, 2010, deadline to provide comment on the Rule, which will have a significant impact on CWLP's electric power production, our planning, rates and operations. The proposed Rule is voluminous and complex, was proposed or published near the same time as other significant rulemakings impacting coal-fired operations, and is supported by over 150 documents posted by US EPA, many of which are highly technical. Moreover, as late as September 1, 2010. USEPA published its 'Notice of Data Availability Supporting Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone ('NODA') which includes 'an updated version of the power sector modeling platform' accompanied by a later deadline to comment. USEPA acknowledges that this NODA is proposed to be used to support the final Rule, but also changes the projections relied upon in its initial Transport Rule proposal. As a relatively small not-for-profit, municipally-owned utility, it is difficult for CWLP to effectively evaluate, in such a short time frame, the applicability and potential impacts to CWLP of either the proposed Rule, or of new information in the NOOA. Given the short time to comment and that the underlying background documentation has changed, CWLP concurs with others who have commented that the rule making record would benefit from a single set of comments addressing all matters raised regarding the proposed Transport Rule. Accordingly, CWLP yet requests that additional comments on this Transport Rule be allowed until October 15, 2010, when comments on the NODA are also due. [EPA-HQ-OAR-2009-0491-2635.1. pp.1-2]
City of Tallahassee
Insufficient Time to Develop Comments
The City of Tallahassee has serious concerns with the aggressive implementation schedule and specific electric generation unit (EGU) reduction requirements proposed in the Clean Air Transport Rule (CATR) aka the Transport Rule. Given the amount of extremely technical and complex documents that comprise the Technical Support Documents, numerous modeling files and spreadsheets, and the three distinct regulatory alternatives, it nigh impossible for any utility to devote extensive resources on developing significant comments on the impact of the rule, nor catch significant errors within these documents, within the 60 day timeframe.  If EPA continues to hold fast to the 60-day comment deadline, EPA has effectively precluded meaningful public involvement. [EPA-HQ-OAR-2009-0491-2669.1, p.1-2]
Class of '85 Regulatory Group
On behalf of the Class of ' 85 Regulatory Response Group ('Class of ' 85' or 'Group'), I am writing to request a 60-day extension of the comment period on the proposed 'Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone,' published in the Federal Register on August 2, 2010, at 75 Fed. Reg. 45210 ('Proposal'). The Proposal is one of the most far-reaching and complicated rules ever proposed under the Clean Air Act ('CAA'). The current 60-day comment period is inadequate to allow potentially affected sources and States to review and analyze the Proposal and respond to the Agency's specific requests for comments. Accordingly, the Group requests that EPA extend the deadline for submitting comments on the Proposal from October 1,2010 to November 30,2010. [EPA-HQ-OAR-2009-0491-0325.1, p.1]
Members of the Class of '85 are electric generating companies from around the country, the majority of which are located within potentially regulated states, and will be directly affected by any final rule issued by EPA. The regulatory scheme finalized by EPA will have a significant impact on every aspect of the generating industry - including long-term business planning, the determination of consumer rates, and the day-to-day operation of electric generating units. It is of the utmost importance that Group members are given adequate time to analyze the Proposal and provide the Agency with meaningful feedback on the proposed regulatory schemes. [EPA-HQ-OAR-2009-0491-0325.1, p.1]
The Proposal and supporting materials are too complex and lengthy to review and analyze in 60 days. The Proposal alone consumes 250 pages of the Federal Register. In addition, EPA has posted over 150 supporting materials and documents in the rulemaking docket, most of which consist of highly technical data. Review of these materials constitutes a massive undertaking. Although the Agency made many of these materials available at the time the Proposal was signed, and before the Proposal was published in the Federal Register, the additional time offered for review is insufficient to thoroughly analyze the data. Already, based on an initial review, the Group has identified a number of inaccuracies in the data underlying the Proposal, including mistakes regarding emissions controls or operations at certain electric generating units. If they are not fully identified and corrected, inaccuracies such as these will undermine the foundation of any regulatory scheme promulgated by EP A and result in an ineffectual program that will impair the reliable generation and transmission of electricity throughout the country. Group members face the daunting task of processing the available information,1 evaluating the feasibility of implementing each of the three regulatory schemes set forth in the Proposal, and providing EPA with constructive feedback through detailed comments. [EPA-HQ-OAR-2009-0491-0325.1, pp.1-2]
EP A has the discretion to extend the comment period for the Proposal, and doing so would benefit the Agency, States, and the regulated community. Providing adequate time for meaningful public participation in the rulemaking process will help ensure that the final rule comports with the CAA and effectively addresses concerns related to the interstate transport of air pollutants. [EPA-HQ-OAR-2009-0491-0325.1,p .2]
The Proposal is one of the most far-reaching and complicated rules ever proposed under the CAA. The Proposal alone consumes 250 pages of the Federal Register. In addition, EPA has posted over 150 supporting materials and documents in the rulemaking docket, most of which consist of highly technical data. 2 Review of these materials constitutes a massive undertaking. Although the Agency made many of these materials available at the time the Proposal was signed, and before the Proposal was published in the Federal Register, the additional time offered for review is insufficient to thoroughly analyze the data. Despite requests· from the Class of '85 and a number of other members of the regulated community, EPA has refused to extend the comment period for the Proposal. The Group believes the Agency's position is inconsistent with its actions in other less extensive rulemakings. Within the last six months alone, EPA has extended the comment period on no less than four rulemakings. The U.S. Court of Appeals for the District Court declined to issue a schedule for EPA to promulgate the Proposal because it recognized the magnitude of the task facing the Agency. [EPA-HQ-OAR-2009-0491-2854.1,p.2]
The Proposal will have a significant effect on electric generation throughout the country and EPA should provide additional time for stakeholders to verify the accuracy of EPA's data and operational assumptions. Many of the flaws and concerns that the Class of ' 85 expresses throughout these comments could be addressed and resolved by such additional time for comments. [EPA-HQ-OAR-2009-0491-2854.1,p.2]

Footnote 1: The Group believes that a more detailed explanation of the integrated planning model inputs and results and the air quality modeling results would assist States and industry with their review of the Proposal.
Clean Energy Group
Need for Re-Proposal of the Rule
As discussed above, the Clean Energy Group recommends that EPA release a Supplemental Notice of Proposed Rulemaking and/or revised NODA to allow verification of data. This release would not require EPA to re-propose the rule itself for further public comment before adopting the final Transport Rule. EPA could allow comment on the data through a Supplemental Notice of Proposed Rulemaking and/or revised NODA while, at the same time, working to finalize the rule itself. For the reasons set forth above, this process will be particularly important if EPA proceeds with allocating allowances based on projected emissions. [EPA-HQ-OAR-2009-0491-2702.1, pp. 11-12]
Cleco Corporation
A. EPA's Proposed Compliance Schedule Is Unreasonable.
EPA proposes to issue a final Transport Rule approximately six months before the proposed January 2012 compliance date. As discussed in more detail below, six months is not enough time for affected sources to take any action necessary to comply with this rule. To make matters worse, EPA's NODA effectively stymies compliance planning efforts by changing the data and modeling expected to underlie allowance allocations but failing to provide revised state budgets and unit allocations. [EPA-HQ-OAR-2009-0491-2859.1 p.2]
The January 2012 compliance date does not provide sufficient time to install controls, switch fuels or even begin securing allowances. In the event the final allocations are insufficient to cover a company's projected SO2 and/or NOx emissions, the company would be unable to install controls on any of its units in time to comply with the Transport Rule, unless those projects are already well underway. In the proposed rule, EPA significantly underestimates the time to install new controls. Capital retrofit projects for controlling SO2 and NOx emissions require long lead times to plan, design, construct and start up  -  anywhere from two to four years, depending on the unit and type of control project. Based on our experience, not including time for environmental permitting by the Louisiana Department of Environmental Quality and rate recovery review by the Louisiana Public Service Commission, low NOx burners and SNCR systems take approximately two years from engineering and design to commercial operation and SCR and FGD systems take approximately four years. [EPA-HQ-OAR-2009-0491-2859.1 p.2]
The January 2012 compliance date also precludes fuel switching as a compliance option. Most utilities, including Cleco, contract for fuel and fuel transportation well in advance, and as a result, a substantial percentage of the anticipated fuel needed for 2012  -  2014 is already under contract. Cleco has as much as 50% of its solid fuel under long term contracts and the other 50% under medium to short term contracts. Dolet Hills, a mine-mouth lignite plant, has 100% of its fuel already under contract, which precludes any fuel switching at those units. [EPA-HQ-OAR-2009-0491-2859.1 p.2]
While Cleco has attempted a full review and analysis of this proposed rule within the time provided, it has found it almost impossible to do so given the voluminous and complex nature of the proposal and supporting documentation. This is an important rule, and EPA expects it will form the basis for future transport rules. Yet EPA's processes and methodologies are in many cases unclear and in other cases are lost within the thousands of pages of preamble and technical support documents. [EPA-HQ-OAR-2009-0491-2859.1 p.9]
Furthermore, given the many errors we have identified thus far and EPA's release just four weeks ago of new data and modeling runs which will form the basis of revised unit allocations yet to be provided, the proposal is not sufficiently developed for meaningful public comment. We urge the Agency to issue a supplemental proposal that provides the revised data which will form the basis of the final rule and revised unit allocations for review and comment before finalizing this rule. In doing so, EPA will produce a better, more effective product that can inform future rules, decrease the scope and extent of legal challenges, and improve the likelihood that the rule will survive such challenges. Furthermore, the electric power industry, the fuel industry and the transportation industry all involve massive, complex operations with long term planning horizons (with respect to financing, integrated resource planning etc.). The rule as proposed gives these industries little to no indication of what might be required in the final rule, no time to plan, and almost no time to comply. EPA simply has not allowed sufficient opportunity for public review and comment. Given the importance of this rule, the Agency should take the additional time necessary to issue a supplemental proposal. [EPA-HQ-OAR-2009-0491-2859.1 p.9]
Consolidated Asset Management Services (CAMS)
Due to the nature of the proposed TR we request an extension of time to review all the applicable documents and fully craft detailed comments on our recommendations to enhance the TR and bring forth issues that we view could negatively influence the power generation industry, the intent of the TR, and the reliability of the Bulk Electric System. [EPA-HQ-OAR-2009-0491-2612.1, p.1]
Consumers Energy
The purpose of this letter is to request that the public comment period for the Transport Rule be extended by 60 days, to November 30, 2010. [EPA-HQ-OAR-2009-0491-1890.1, p.1]
EPA's proposed Transport Rule is one of the most extensive and complicated rules that EPA has ever proposed under the Clean Air Act. As proposed, the rule would significantly affect the planning and operations of Consumers Energy, as well as those for all utilities within the Transport Rule region. Our Company's planning includes capital expenses and scheduling built around the final CAIR As proposed, EPA's Transport Rule would accelerate schedules and, in all likelihood, increase costs for our capital expenditures that Consumers Energy currently projects to total in excess of one billion dollars The likely cost increases, coupled with accelerated retirements of units throughout the proposed Transport Rule region, including Michigan, have also caught the attention of the Michigan Public Service Commission. [EPA-HQ-OAR-2009-0491-1890.1, p.2]
As proposed, the Transport Rule's length and complexity have made it extremely difficult to review and analyze within the 60-day comment period. We are very concerned about the accuracy of information used by EPA in the proposal, as well as our ability to provide accurate information back to EPA during the comment period. The proposed schedule would have our company committing to initiate projects, on accelerated timelines, without knowing what will be contained within a final rule. [EPA-HQ-OAR-2009-0491-1890.1, p.2]
A. EPA Has Not Allowed Sufficient Time for Public Comment
As several other entities have pointed out, EPA is subject to neither a statutory nor court-ordered timetable to complete this rulemaking. The extended comment deadlines would provide Consumers Energy, as well as any other affected and interested organizations, a reasonable opportunity to prepare detailed, meaningful comments that may be useful to the Agency in resolving in an appropriate way the many legal, policy, and technical issues raised by the Proposed Transport Rule and, now, by the NODA as well. [EPA-HQ-OAR-2009-0491-1890.1, p.3]
As proposed, the Transport Rule's length and complexity have made it extremely difficult to adequately review and analyze within the current 60-day comment period. We are very concerned about the accuracy of information used by EPA in the proposal, as well as our ability to provide accurate, complete and coherent information back to EPA during the comment period. The proposed schedule of implementation in the proposed Transport Rule would have our company committing to initiate numerous projects at multiple locations, on accelerated timelines, based on a proposed rule, without the certainty of knowing what will be contained within the final rule. [EPA-HQ-OAR-2009-0491-2837.1, p.4]
Council of Industrial Boiler Owners (CIBO)
Sixty days is inadequate to comment on a proposal that will regulate all electric generation in two thirds of the nation. A rule of this scope does not only affect the directly regulated sources, but every other sector of the economy and every individual energy consumer in the nation. The time EPA allotted for comment for a rule of this complexity, broad application and economic impact failed to constitute the reasonable opportunity for public comment guaranteed by the Clean Air Act and the Administrative Procedures Act. 42 U.S.C. § 7607(h) (2006). Under basic principles of due process and administrative law, EPA must provide the public with a reasonable opportunity to comment on proposed rules. This comment period deprives sources of a means to adequately protect their interests and rights in the administrative and judicial processes. The complexity and breadth of applicability of this Proposed Rule requires a greater comment period than that provided, especially in light of multiple other EPA proposed rules with simultaneous comment periods. 
CIBO members, and others that operate industrial, commercial and institutional (ICI) boilers, are especially negatively affected by EPA's failure to provide an adequate comment period. During the entire first half of the comment period for this rule, those sources were fully engaged in analyzing and developing comments on the four interrelated Boiler MACT rulemakings, which even EPA estimates will have a financial impact on ICI boilers exceeding $10 billion.
Therefore, although CIBO members are directly and immediately affected by this Proposed Rule, they effectively have had 30 days to assess its ramifications and develop comments. The technical resources of regulated sources are finite, especially personnel with the technical expertise to analyze the implications of EPA's long and complex regulatory proposals. Those resources were the same technical experts deployed during the very short comment period for the four complex Boiler MACT rules, and could not have simultaneously conduct an in-depth analysis of the long and complex Transport Rule.
In addition, on September 1, 2010, EPA issued a Notice of Data Availability, in which it updated the NEEDS (the National Electric Energy Data System) data. This imposes yet another simultaneous EPA rulemaking comment period on the same community of sources, with comments on the huge addition of information in the NODA due October 15, 2010. In the NODA, EPA published new model runs of data, the review of which requires a significant amount of engineering staff and management review. The NODA addresses some critical definitional elements that lay the foundation for other highly consequential aspects of the rule, including defining the availability of plants. A cursory review shows data for at least one CIBO member indicates flawed availability conclusions, which in practical terms will mean that the facility will not be able to obtain the allowances necessary to meet its contractual obligations regarding its availability.
Clearly, EPA's data will require close inspection and analysis by affected sources, and all such data affects the implementation of the Proposed Rule. EPA should extend the comment period on the Proposed Rule to permit sources to comment on the Rule and related NODA as a single exercise.  [EPA-HQ-OAR-2009-0491-2751.1 p.2-3]
DTE Energy
EPA has made participation in this rulemaking difficult because of the unreasonable time to review a complex rulemaking, then exacerbating the situation by subsequently releasing new data which should significantly influence EPA conclusions in the CATR rulemaking, without allowing additional time for stakeholders to adequately review and comment. [EPA-HQ-OAR-2009-0491-3714.1_NODA,p.2]
Duke Energy
Duke Energy Business Services ("Duke Energy") intends to file comments in the above-referenced rulemaking docket on the proposed "Federal Implementation Plans To Reduce Interstate Transport of Fine Particulate Matter and Ozone," as published by EPA on August 2, 2010 (the "Proposed Transport Rule"). 75 Fed. Reg. 45210. EPA announced a 60-day public comment period on the proposed rule, requiring comments to be submitted by October 1, 2010. Id. The purpose of this letter is to request an extension of the public comment period by 60 days, to November 30, 2010. [EPA-HQ-OAR-2009-0491-0313.1, p.1]
Duke Energy, one of the largest electric power companies in the United States, supplies and delivers electricity to approximately 4 million U.S. customers and natural gas service to approximately 520,000 customers in its regulated jurisdictions. The company has approximately 35,000 net megawatts of electric generating capacity in the Midwest and the Carolinas, and natural gas distribution services in Ohio and Kentucky. [EPA-HQ-OAR-2009-0491-0313.1,p.1]
The Proposed Transport Rule is one of the most extensive and complicated rules EPA has ever proposed under the Clean Air Act. The Proposed Transport Rule's length and complexity make it virtually impossible to complete a comprehensive review and analysis of the proposed rule and the many technical supporting documents and data files that EPA has developed for this rulemaking, and then to prepare and submit meaningful, detailed comments on the proposed rule, in the period EPA has allowed. The proposed rule and its preamble alone fill over 250 three column pages of the Federal Register. In addition, EPA's technical support documents total several hundred additional pages in length, and EPA's modeling documentation and output information are also quite lengthy. Given the nature and method of presentation of the information in the Federal Register notice and the support documents, commenters must undertake a time-consuming review even to begin to understand how that information may support, or does not support, various elements of EPA's proposal. [EPA-HQ-OAR-2009-0491-0313.1, pp.1-2]
Duke Energy notes that EPA took two years to develop the Proposed Transport Rule following the July 2008 decision of the D.C. Circuit Court of Appeals that EPA had promulgated the Clean Air Interstate Rule unlawfully and must replace it through new rulemaking regarding interstate transport. Duke Energy does not refer to this fact to suggest in any way that EPA was dilatory; on the contrary, the length of time EPA took is a reflection of the extent, importance, and complexity of the many issues EPA had to address in preparing a proposed rule for public review and comment. Given the challenges it has faced, EPA should be all the more ready to recognize that parties preparing comments on these important and complex issues likewise face particularly time-consuming tasks and must be given a longer comment period if they are to have a meaningful comment opportunity. [EPA-HQ-OAR-2009-0491-0313.1,p.2]
Duke Energy therefore respectfully requests a 60-day extension of the public comment period, to November 30, 2010. That deadline would still leave at least six months before EPA's target date of June 2011 for completion of the rulemaking, which in any event is subject to no statutory or court-ordered timetable. The extended comment deadline would permit Duke Energy and others to prepare detailed comments that may be useful to the Agency in resolving in an appropriate way the many legal, policy, and technical issues raised by the proposed rule. [EPA-HQ-OAR-2009-0491-0313.1, p.2]
The significant number of errors in the proposal, the fact that EPA has already issued one Notice of Data Availability with fundamental changes to what it proposed just a month earlier, and EPA's indication that there are more changes to come, suggest to us the possibility that significant changes to the original proposal could be made, rendering the comments contained herein, and by all respondents to this proposal, incomplete. Therefore, Duke Energy recommends that EPA incorporate the many comments it will receive regarding data errors in the PTR, rerun its analysis and issue a new proposal for public comment before issuing a final rule. This action will by necessity require that the implementation date for the rule be extended beyond 2012. EPA should eliminate the 2012 implementation date and push back the 2014 requirements. Further, that will address the serious concerns about the faulty assumptions EPA has made about how quickly additional controls can be installed. Because the Clean Air Interstate Rule will remain in place until the final rule is implemented, states have adequate assurance that emission reductions will continue to take place as needed to reduce or eliminate significant impacts from upwind states. [EPA-HQ-OAR-2009-0491-2689.1, p.2]
Additionally, much of the modeling and unit specific assumptions that EPA used to develop the proposed rule are flawed. EPA must resolve and correct these many problems, and either withdraw the proposed rule and reinitiate the rulemaking with a new proposal or issue a supplemental notice of proposed rulemaking for public comment that includes new state budgets and unit-level allowance allocations that reflect the corrections. Under these circumstances, a rulemaking could not be completed before the beginning of 2012. [EPA-HQ-OAR-2009-0491-2689.1, pp.6-7]
The tight implementation schedule that EPA proposes is in effect made even tighter by the fact that EPA is already changing the terms of the proposed rule. On September 1, 2010, midway through the public comment period on the proposed rule, EPA published its NODA, announcing information that in effect will result in substantial changes to the proposed rule and noting that further changes are to come. Among other things, the NODA announced the release of (i) an updated version of the National Electric Energy Data System ("NEEDS"), which provides the unit-level EGU characteristics used as inputs for the Integrated Planning Model ("IPM"), (ii) results of new base case and policy case modeling runs using an updated version of IPM, and (iii) results of new base case and policy case modeling runs using an updated version of IPM and including data from the Energy Information Administration's Annual Energy Outlook 2010 natural gas resource assumptions. 75 Fed. Reg. at 53614/2-3. It also announces the release of "[a] summary of other planned input updates to be implemented in the final rulemaking." 75 Fed. Reg. at 53614/3. The data released in connection with the NODA will, when applied by EPA, change substantially the statewide budgets and allowance allocations for 2012 and the allowance allocations for 2014, and there will presumably be additional changes leading up to promulgation of a final rule based on the planned input updates that EPA says will be implemented later. [EPA-HQ-OAR-2009-0491-2689.1, pp.7-8]
The scope of the impact that the new data will have is clear at a glance. For example, the parsed file that EPA released in connection with the proposed rule, showing the initial IPM run, indicates that IPM projected about 23,723 MW of new coal generation from unidentified plants yet to be built in 10 different states. See IPM Run File "TR SB Limited Trading", available at http://www.epa.gov/airmarkets/progsregs/epa-ipm/transport.html. By contrast, the updated parsed file that EPA added to the docket in connection with the NODA appears to indicate that IPM projected only about 2,001 MW of new coal generation from unidentified plants yet to be built in four states. See Document No. EPA-HQ-OAR-2009-0491-0312, available at http://www.regulations.gov/search/Regs/home.html#docketDetail?R=EPA-HQ-OAR-2009-0491. This is likely to be merely one indicator of the substantial changes in EPA's proposal that will result from use of the NODA information, and the impact of the future changes that EPA anticipates remains to be seen. Clearly, there is no way for sources to begin planning for compliance based on the information that EPA has provided in the docket. [EPA-HQ-OAR-2009-0491-2689.1, p.8] 
Dynegy, Inc.
Dynegy Inc. (Dynegy) respectfully requests an extension of the public comment period on the EPA's proposed 'Federal Implementation Plans To Reduce Interstate Transport of Fine Particulate Matter and Ozone' (Proposed Transport Rule), as published at 75 Fed. Reg. 45210 (Aug. 2, 2010). EPA announced a 60-day public comment period on the proposed rule, requiring comments to be submitted by October 1, 2010. By this letter, Dynegy requests an extension of the public comment period by 60 days, to November 30, 2010. [EPA-HQ-OAR-2009-0491-0138.1, p.1]
Through its subsidiaries, Dynegy produces and sells electric energy, capacity and ancillary services in key U.S. Markets. Dynegy's power generation portfolio consists of approximately 12,500 megawatts of baseload, intermediate and peaking power plants fueled by a mix of natural gas, coal, and fuel oil.[EPA-HQ-OAR-2009-0491-0138.1, p.1]
The Proposed Transport Rule is one of the most extensive and complicated rules EPA has ever proposed under the Clean Air Act. Given the extent, importance, and complexity of this proposed rulemaking, as well as the proposal's length (i.e., over 250 pages in the Federal Register and hundreds of pages of technical support documents and modeling information), interested parties face a particularly time-consuming challenge in understanding the proposed rule and its enormous environmental and energy implications, and in identifying potentially incorrect or otherwise unrealistic assumptions with respect to specific electric generating units and other critical factors upon which the proposed rule is based. Dynegy believes that a 60-day comment period is not adequate to allow interested parties to identify and prepare meaningful comments on the numerous and significant policy, legal, technical and other substantive issues raised by the proposed rule. [EPA-HQ-OAR-2009-0491-0138.1, pp.1-2]
Moreover, many of the same Dynegy personnel analyzing the Proposed Transport Rule are simultaneously involved in the extensive efforts needed to respond to several other concurrent EPA rulemaking activities, including analyzing and preparing comments on EPA's proposed rule regarding disposal of coal combustion residuals, 75 Fed. Reg. 35127 (comment deadline currently September 20, 2010), responding to comprehensive Information Collection Requests regarding effluent limitations guidelines for the steam electric power generating industry (due September 18,2010 and October 15, 2010), and responding to Information Collection Requests regarding Hazardous Air Pollutant emissions from electric utility steam generating units (due in early September 2010). The confluence of responding to these rulemaking activities in the same time period will needlessly limit and strain the finite resources available to devote to each of these significant efforts. [EPA-HQ-OAR-2009-0491-0138.1, p.2]
Dynegy therefore respectfully requests a 60-day extension of the public comment period on the Proposed Transport Rule, to November 30, 2010. Importantly, that deadline would still leave at least six months before EPA's target date of June 2011 for completion of the rulemaking, which is not subject to a statutory or court-ordered deadline. The extended comment deadline also would permit affected electric generators and interested parties to prepare meaningful, detailed comments that may assist the Agency in resolving many of the issues raised by the proposed rule. [EPA-HQ-OAR-2009-0491-0138.1, p.2]
E.ON U.S.
EPA should correct the inaccurate data, resulting analyses, state budgets, and unit allocations, and reissue the rule for public comment as a Supplemental Notice of Proposed Rulemaking. [EPA-HQ-OAR-2009-0491-2797.1, p.10]
The Proposed Transport Rule is a very complex proposal. EPA spent approximately a year and a half on its development and there are many detailed aspects that need to be reviewed by the public, particularly by affected entities. Accompanying the rule are numerous large data files, modeling assumptions, and documentation of methodologies. Further, on September 1, 2010, EPA published the separate NODA for the Proposed Transport Rule, which included revisions and updates to the previously provided large data files, which formed the basis for allowance allocations. Although EPA has provided a 45-day comment period on this notice (15 days beyond the comment period for the Proposed Transport Rule), EPA has not provided an updated allocation table or other detailed files which would naturally follow from the revised data. As such, key information is missing and the rule cannot be adequately evaluated. Further, because correction of key information used in EPA's analyses, state budgets, and unit allocations will change company requirements, EPA should reissue the rule as a Supplemental Notice of Proposed Rulemaking. [EPA-HQ-OAR-2009-0491-2797.1, p.10]
Exxon Mobil Corporation
EM would like to express extreme concern over EPA's denial of the LCA and LPSC requests for extension to the comment period. EM has been working with the LCA to formulate both individual and group comments. The time period allotted by EPA precluded meaningful public review and comment considering the length and complexity of the proposed rule (1361 pages) and numerous technical support documents posted on the EPA website in support of the proposed rule. Many of these documents in turn referenced other documents. There was lack of consistency in presentation of data, with different support documents using different metrics and even different identification of EGUs. [EPA-HQ-OAR-2009-0491-2841.1,p.15]
The proposed TR/FIP is one of the most complex, data intensive rules EPA has ever proposed. In addition, EPA is using a proprietary model administered by a third party contractor as the primary basis for the rule. Associated with this rule are hundreds of pages of technical supp011 documents, data spreadsheets and other related documentation. EM believes EPA should not propose a rule so dependent upon voluminous data without publishing a notification of data availability (NODA) and allowing sufficient comment period on the data itself to ensure models are using data only from affected units and that the data are complete and accurate. [EPA-HQ-OAR-2009-0491-2841.1,p.15]
Although EPA indicated a need for acting quickly on this rulemaking citing the court's desire to replace CAIR, there is not a court ordered deadline to finalize this rulemaking. EPA's purported reason for not allowing a limited 60-90 day extension of the comment period cites the need to 'develop a final rule in time to obtain needed emissions reductions'. EPA does not need to rush this rule at the expense of defensibility in order to obtain needed emissions reductions. As noted in the IPM v.3.02 and v. 4.10, there will be substantial reductions ofPM2.5 and ozone precursors - even without the TRJFIP - by 2012. In many states, including Louisiana, these projections appear to be enough to eliminate any significant contribution or interference with attainment. Further, recent data readily available to EPA shows that air quality conditions for ozone and PM2.5 have improved much more rapidly than EPA has predicted, with a number of counties/parishes now clearly in attainment. The court remand of the CAIR rule leaves CAIR and its associated emission reductions in place through the year 2014 while EPA is developing the TRJFIP. Given this state of affairs, EM believes it was arbitrary and capricious for EPA to deny an extension of the comment period and urges EP A to reopen the comment period. [EPA-HQ-OAR-2009-0491-2841.1,pp.15-16]
First Energy
This is an extremely sophisticated rulemaking, over 250 pages in length, incorporating complex modeling and very detailed model inputs and technical support documents totaling several thousands of additional pages. The regulated community needs more time to adequately review, identify discrepancies and comment on the proposed rulemaking. The additional two weeks to review the NODA v4.10 data released by EPA on September 1, 2010 is appreciated, but insufficient. [EPA-HQ-OAR-2009-0491-2657.1, p.2]
Florida Electric Power Coordinating Group, Inc. (FCG)
On behalf of the members of the FCG Environmental Committee (hereafter referred to as FCG), we request an extension of 90 days to the public comment period on the proposed Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone (hereafter referred to as 'Transport Rule'). [EPA-HQ-OAR-2009-0491-1686.1, p.1]
The proposed Transport Rule included a 60-day comment period, which officially ends on October 1, 2010. As explained below, this is an insufficient amount of time to fully evaluate this complicated rule. Accordingly, FCG respectfully requests that the comment period be extended by 90 days from October 1 (i.e., to December 31,2010) to allow for a more thorough review of the proposed rule, and development of more meaningful comments. [EPA-HQ-OAR-2009-0491-1686.1, p.1]
I. Complexity of the Rule
Due to the complexity of the proposed Transport Rule and the multiple issues associated with the rule making, additional time is necessary to review and properly evaluate all three regulatory options proposed by EPA. In addition to the three EPA proposed regulatory options, each of which must be reviewed and commented on, EPA also requested comment on more than 90 other issues in the proposed Transport Rule. In order to fully vet all issues and develop comments that are thorough and meaningful, per EPA's request, FCG needs more time than the timeline provided by EPA. [EPA-HQ-OAR-2009-0491-1686.1, pp.1-2]
II. Multiple Proposed Options
Moreover, FCG notes it takes time to understand EPA's approach for each option. In order to respond to EPA, FCG must have sufficient time to understand how the proposed rule was developed and how it may impact all aspects of current and future generation needs within the state of Florida. Given the number of issues in which EPA is requesting comment, the complexity of the analysis performed, the occasional lack of clarity in describing this complex analysis, and the fact that EPA has provided three possible regulatory approaches, it is essential that EPA allow enough time for stakeholder review. [EPA-HQ-OAR-2009-0491-1686.1, p.2]
III. Volume of Technical Support Documents
FCG's ongoing review of the technical support documents and EPA's modeling for the proposed Transport Rule thus far suggests that EPA's assumptions and modeling techniques may have several flaws. Because there are more than 20 Technical Support Documents describing EPA's regulatory approach and numerous modeling files, it will be impossible for FCG to complete our review in the allotted time period. EPA has already identified that a number of data errors exist in the model. These errors can have potentially dramatic impacts on the results of the model. For example, units at the same generating facility which are identically sized and controlled have substantial differences in their respective emission budgets. [EPA-HQ-OAR-2009-0491-1686.1, p.2]
Although EPA has made much of the underlying data available, it has not provided sufficiently clear examples of each calculation. In order for FCG to offer adequate comments on the rule, FCG must understand how EPA arrived at its calculations. In order to understand how EPA arrived at its calculations, FCG needs to either have the actual calculations or sufficiently clear examples of the calculations. [EPA-HQ-OAR-2009-0491-1686.1, p.2]
IV. Timing of Technical Support Documents
Throughout the current comment period EPA has continued to upload Technical Support Documents to its website, some as recent as September 1, 2010. It took EPA two years to develop this complex rule. It is unreasonable to assume that FCG would be able to review and develop the inputs, assumptions and calculations contained within EPA's model. [EPA-HQ-OAR-2009-0491-1686.1, p.2]
FCG understands that EPA is under a self imposed timeline to develop a replacement rule for the Clean Air Interstate Rule (CAIR) remand; however, this does not preclude the fact that stakeholder input should have been both encouraged and considered. Had EPA provided greater transparency of its modeling plans, this issue may have been avoided. [EPA-HQ-OAR-2009-0491-1686.1, pp.2-3]
Based on the information identified above, FCG urges EPA to extend the proposed rule's comment period by 90 days from October 1 (i.e., to December 31,2010). [EPA-HQ-OAR-2009-0491-1686.1, p.3]
EPA published its proposed Transport Rule in the Federal Register on August 2,2010, and provided a 50-day comment deadline of October 1,2010. This proposal is extremely technical and complex, requiring 255 pages of the Federal Register, more than 20 Technical Support Documents and numerous modeling files and spreadsheets. EPA proposed three distinct regulatory alternatives, and requested comment on more than 90 other issues. Even after the August 2 proposal, EPA continues to publish further refinements and make additional data available. And during the 50-day comment period, many of the affected parties were actively responding to EPA's burdensome utility MACT Information Collection Request, and thus did not have the additional personnel available to devote to reviewing the proposal. Finally, EPA failed to allow for, much less encourage or consider, stakeholder input during its development of this rule. [EPA-HQ-OAR-2009-0491-2658.1, pp.1-2]
Accordingly, the FCG and several other entities requested an extension of the comment period. EPA has neglected to even respond to the FCG's request, even after a follow-up phone call and email. The FCG is aware, however, of EPA's refusal to grant an extension of another request on grounds related to a self-imposed promulgation schedule, state attainment schedules, and claims that the rule was released prior to its publication. Each of EPA's grounds are hollow: the court did not mandate a promulgation schedule, CAIR remains in effect to assist attainment goals, and the proposal is incomprehensible without the supporting documents, many of which EPA did not post until August 2, and which EPA has continued to update. Accordingly, EPA has effectively precluded meaningful public involvement by only affording a sixty-day comment period, and refusing to grant any of the numerous requests for an extension. [EPA-HQ-OAR-2009-0491-2658.1, p.2]
Florida Municipal Electric Association (FMEA)
The proposed Transport Rule is extremely complex and our member utilities are finding significant areas of concern as they attempt to review and understand the impact of the rule on their utility operations, cost to consumers and reliability of their energy supply. It is noted that technical support documents are continuing to be add to the EPA website as late as September 1, 2010. A check with our members indicate that additional time is needed to fully understand this rule and EPA's underlying modeling and technical assumptions as well as to allow FMEA to make constructive comments that will provide more useful information to EPA. For these reasons, FMEA respectfully requests that the comment period for this rule be extended an additional 90 days until December 31, 2010. [EPA-HQ-OAR-2009-0491-1922.1, p.1]
Florida Municipal Power Agency (FMPA)
A. Sufficient Time has not been Provided to Develop Comments
FMPA reiterates the argument asserted by others that sufficient time has not been provided to review and provide meaningful input on the Proposed Transport Rule. The Proposed Transport Rule was published in the Federal Register on August 2, 2010, and allows a 60 day comment period. 1 However, the Proposed Transport Rule suggests broad changes to the previous Clean Air Transport Rule ("CAIR"). In support of the Proposed Transport Rule, EPA has provided a large amount of data and technical documents, upon which numerous assumptions have been made by EPA. Given the breadth of the Proposed Transport Rule, the vast amount of data and technical documents, and the limited resources of public power entities such as FMPA, we believe that EPA's 60 day comment period is unreasonable and should be extended for an additional 60 days period, or, in the alternative, an additional comment period should be allowed following the instant comment period and prior to the publication of a Final Rule. [EPA-HQ-OAR-2009-0491-2725.1, p.2]

1. FMPA recognizes that EPA made the proposed rule and some of the supporting documentation available on July 6, 2010, before the rule was formally published in the Federal Register on August 2, 2010. However, even after having taken advantage of this limited amount of additional review time, we still believe the total review time was insufficient. [EPA-HQ-OAR-2009-0491-2725.1, p.2]
Georgia Department of Natural Resources, Air Protection Branch
The Georgia Environmental Protection Division (EPD) respectfully requests an extension of the public comment period on the EPA's proposed Federal Implementation Plans To Reduce Interstate Transport of Fine Particulate Matter and Ozone; Proposed Rule, as published at 75 Fed. Reg. 45210 (August 2, 2010). EPA announced a 60-day public comment period on the proposed rule, requiring comments to be submitted by October 1, 2010. EPD is requesting an extension of the public comment period by 60 days, to November 30, 2010. [EPA-HQ-OAR-2009-0491-0326.1, p.1]
The amount of information contained in the preamble, the rule and the technical support documents is substantial, and 60 days is not an adequate amount of time to conduct a thorough review. Some concerns we have identified on a very cursory review of the information so far include, the inclusion of non-EGU's, incorrect emissions modeled for both 2012 and 2014, and reductions scheduled to occur in 2015 are actually modeled as occurring at the beginning of 2014. All of these issues may lead to incorrect decisions regarding Georgia's contribution to the receptors EPA has linked us to, the amount of reductions that will actually need to be made, and what group we are placed in for SO2 reductions. It should be of utmost importance to EPA to get this rule right, and given the fact that CAIR is still in place we do not believe the environment will be harmed by allowing an additional 60 days for a proper review of the technical information and the development of meaningful constructive comments on how to improve the proposal. [EPA-HQ-OAR-2009-0491-0326.1, p.1]
EPD is currently devoting significant resources evaluating and implementing a number of new and proposed air quality rules, including multiple revisions to the National Ambient Air Quality Standards, new rules implementing Greenhouse Gas permitting requirements and new Maximum Achievable Control Technology standards. These same resources are also the ones that would be looked to provide the detailed analysis and provided meaningful constructive comment on this proposal, therefore an extension of the public comment period is essential. [EPA-HQ-OAR-2009-0491-0326.1, p.1]
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.91 and 92.]
Georgia EPD will officially be requesting an extension of the comment period. The amount of information contained in the preamble, the rule, and the technical support documents is substantial and 60 days is not an adequate amount of time to conduct a thorough review.
It should be of the utmost importance to EPA to get this rule right. And given the fact that CAIR is still in place, we do not believe the environment would be harmed by allowing an additional 60 days for a proper review of the technical information and the development of meaningful, constructive comments on how to improve the proposal.
Independence Power & Light (IPL)
On behalf of Independence Power and Light ('IPL'), this letter is to request an extension of time to provide comments on the 'Clean Air Transport Rule,' 75 Fed. Reg. 45,210, and on the 'Notice of Data Availability,' 75 Fed. Reg. 53,613. Currently, comments on the Rule are due October 1, and comments on the NODA are due October 15. We request an extension to allow the filing of a single set of comments on both aspects of the rulemaking, to and including November 30, 2010. [EPA-HQ-OAR-2009-0491-1940.1, p.1]
As noted in the docket, the proposal for rulemaking is based on complicated modeling as to the upwind sources that are contributing significantly or interfering with the maintenance of downwind sites. The proposed rules will have significant service, cost, logistical, construction, and operational impacts on IPL and affected electric generating units (EGUs). IPL is currently working to understand the full significance of the proposed rule to IPL and other EGUs in the state of Missouri. [EPA-HQ-OAR-2009-0491-1940.1, p.1]
For these reasons, IPL respectfully requests an extension of the comment period so that it may fully understand the implications of the proposed rule. The proposed rule's length and complexity, along with the many technical documents and data files that EPA has developed and relied upon to draft this proposed rule make preparing and submitting meaningful comments extremely difficult in the time allotted in the published notice. [EPA-HQ-OAR-2009-0491-1940.1, p.2]
IPL respectfully requests an extension of the public comment period on the Proposed Transport Rule to November 30, 2010. [EPA-HQ-OAR-2009-0491-1940.1, p.2]
IPL respectfully requests also that EPA extend the comment period on the NODA from October 15 to November 30, 2010. [EPA-HQ-OAR-2009-0491-1940.1, p.2]
THE NODA FAILS TO PROVIDE FOR MEANINGFUL COMMENT AND ISTHUS PREJUDICIAL TO THE PARTIES
The new data placed in the record with the NODA contained computer files that were corrupted or otherwise unusable. Although EPA has cooperated in providing usable files to replace the corrupted and unusable ones, the delay caused an already aggressive schedule for review of the newly introduced additional data to become completely unworkable. It is our understanding that the last corrected file related to the NODA data did not become available until September 25. It follows that September 25 was the first date on which any examination or analysis of the new data could be initiated. EPA initially provided 45 days (September I data availability with an October 15 comment deadline) for comment on the NODA data. Thus, it appears EPA believed that a minimum of 45 days was required to allow for meaningful comment on the NODA data. Consequently, EPA should grant an extension of the comment deadline to November 10 to maintain the same amount of time from when usable NODA data actually become available to the deadline for comments. [EPA-HQ-OAR-2009-0491-2741.1, p.6]
In any event, the introduction of new pivotal data this late in the rulemaking process prejudices parties seeking to provide meaningful comment in violation of 5 U.S.C. § 553(c). As the NODA makes clear, the newly available data concerns the database showing 'unit level characteristics of the electric generating units (EGUs) included in the IPM modeling' as well as the new base case modeling runs that address compliance issues and the preferred policy options. 75 FR at 53614/2. All of those are critical components of the rulemaking analysis, and changes to any of them could affect the scope and reach of the final rule. Where EPA 'provides entirely new information critical to [its] determination,' Community Nutrition Inst. v. Block, 749 F.2d 50, 57-58 (D.C. Cir. 1984), EPA must provide the opportunity for meaningful comment. Portland Cement Ass'n v. Ruckelhaus, 486 F.2d 375, 393 (D.C. Cir. 1973). This requirement is mandatory 'to ensure that agency regulations are tested through exposure to public comment, to afford affected parties an opportunity to present comment and evidence to support their positions, and thereby to enhance the quality of judicial review.' Chamber of Commerce v. SEC, 443 F.3d 890, 900 (D.C. Cir. 2006)(citation omitted). [EPA-HQ-OAR-2009-0491-2741.1, pp.6-7]
The present situation, which for all practical purposes gives no more than 20 days from the time uncorrupted and usable data files were made available to the October 15 deadline for comments, does not allow for the 'genuine interchange' that notice-and-comment rulemaking is designed to achieve. Conn. L & P Co. v NRC, 673 F.2d 525, 530 (D.C. Cir. 1982). Even accepting arguendo EPA's view that the 45-day period set in the NODA was adequate, the actual time for analysis and comment after usable files finally became available of less than half that period is grossly inadequate.[EPA-HQ-OAR-2009-0491-2741.1, p.7]
The parties are prejudiced by the inadequate comment period as well as by the indication 'additional information used to support the final transport rulemaking may be placed in the docket' at unspecified future date(s). 75 FR at 53615/1. As the NODA encapsulates, the new data relate to key databases and modeling runs, id. at 53614/2, and could produce different results from those contained in the Rule. It is possible that the new data will alter the results for individual States or EGUs, but that cannot be determined until the new data are analyzed, which might not happen until after October 15. Parties must be allowed to determine whether such differences are present, and what effect they have on the various aspects of proposed rule. See Small Refiner Lead Phase-Down Task Force v. EPA, 705 F.2d 506, 540-41 (D.C. Cir. 1983) (prejudice requires specific showing of the 'portions of the documents [a party] objects to and how it might have responded if given the opportunity'). [EPA-HQ-OAR-2009-0491-2741.1, pp.7-8]
Meaningful comment in this context thus means the ability to determine what documents (new data tiles) raise objections and what response is appropriate to those objections. Here, that process could not even begin until the corrupted computer files were purged and replaced with usable files, which took the better part of a month to accomplish. Assuming that all the necessary computer f1les have been made available, the modeling runs involved in replacing the original data with these new data take considerable time and effort. Only at that point can the process of determining objections and developing responses begin. Given the amount of data, the complexity of the issues, and the consequences related to the model results, far more time than the 45-day period set in the NODA, Or the actual 20-day period after the data were finally made available in usable form, would be needed to permit meaningful comment. EPA's failure to provide adequate time prejudices the parties by not allowing them to present specific comments on pivotal matters, and therefore is arbitrary and capricious. See Appalachian Power Co. v. EPA, 249 F.3d 1032, 1059 (D.C. Cir. 2001)(agency action is arbitrary and capricious where agency 'has failed to respond to specific challenges that are sufficiently central to its decision'). [EPA-HQ-OAR-2009-0491-2741.1, p.9]
Indiana Energy Association
a. The Indiana Utility Group believes that the EPA CATR analysis is fatally flawed because of errors in assumed pollution control equipment costs and removal efficiencies, fuel switching assumptions, and implementation dates . In addition, the recently published EPA CATR NODA conflicts with many of the CATR assumptions EPA included in its CATR analysis. Additional examples of the impact of these errors are provided below. As a matter of technical accuracy, fairness and to result in a rule that is reasonable and not arbitrary, the Indiana Utility Group believes that these errors are so significant that the CATR must be reassessed and reproposed using corrected data received during this comment period and the final publicly reviewed NODA data. [EPA-HQ-OAR-2009-0491-3711 p.2]
g. The Indiana Utility Group submits that the regulated community has not had adequate time to review and comment on the proposed CATR. EPA has organized the record so that a regulated entity must delve into several files that are not in the published rule in order to determine unit specific allocations and assumed controls . The files requisite for any technical analysis are in the Docket but not in the rule, making it extremely difficult and time consuming for a regulated entity to find the relevant files. The Indiana Utility Group believes that EPA used a 'screening tool' to determine significant impact. The EPA source apportionment modeling does not break down on a sector specific basis. Rather, the EPA analysis provides only aggregate state emissions. The regulated community is neither able to discern which group of sources that EPA concluded has the most impact on nonattainment, nor determine which specific sources are implicated . Given the errors extant in the EPA CATR assumptions, the Indiana Utility Group expects that allocations and unit control requirements will need to be revised. The Indiana Utility Group therefore urges that EPA revise and reissue the CATR for public comment as a SNPR. [EPA-HQ-OAR-2009-0491-3711 p.4] 
JEA
EPA Did Not Provide Sufficient Time to Develop Comments
The Transport Rule was published in the Federal Register on August 2,2010 with a comment deadline of October 1, 2010, leaving interested parties 60 days to review the proposed regulation (75 FR 45210), albeit the announcement and initial text of the proposed rule came out on July 6, 2010, this is precisely the timeframe that many of the entities regulated by this proposal were performing Part Three Emissions Testing for EPA's Utility MACT Information Collection Request (ICR). Subsequently, multiple regulated entities were entering the ICR data into EPA's database spreadsheets during this proposal period and were not afforded the luxury of the full proposal time period to analyze the rule and its technical support documents. EPA should recognize the burden that they have placed on certain regulated entities' staff and acknowledge this burden by extending the initial comment period or allowing for an additional notice and comment period. [EPA-HQ-OAR-2009-0491-2713.1, p.3]
Kansas City Board of Public Utilities (BPU)
On behalf of Kansas City Board of Public Utilities ('BPU'), this letter is to request an extension of time to provide comments on the 'Clean Air Transport Rule,' 75 Fed. Reg. 45,210, and on the 'Notice of Data Availability,' ('NODA') 75 Fed. Reg. 53,613. Currently, comments on the Rule are due October 1, and comments on the NODA are due October 15. We request an extension to allow the filing of a single set of comments on both aspects of the rulemaking to November 30,2010. [EPA-HQ-OAR-2009-0491-2194.1, p.1]
As noted in the docket, the proposal for rulemaking is based on complicated modeling as to the upwind sources that are contributing significantly or interfering with the maintenance of downwind sites. Because the proposed rules will have significant service, cost, logistical, construction, and operational impacts on BPU and affected electric generating units (EGUs), BPU has undertaken to analyze the modeling used in the rulemaking. [EPA-HQ-OAR-2009-0491-2194.1, p.1]
BPU and other EGU s in states identified for the first time by EPA as subject to the proposed Air Transport Rule face an especially difficult burden to prepare and file comments as to the potential impacts that the Rule will have on them. In contrast to EGUs in states previously subject to clean air transport rules, BPU and other EGUs in 'first time states' have no historical basis on which to ground their analyses, nor were they invited to 'listening sessions' as to what direction EPA proposed to take in the rulemaking docket to which other stakeholders from states previously subject to clean air transport regulations were invited. [EPA-HQ-OAR-2009-0491-2194.1, p.2]
BPU is currently working to understand the full significance of the proposed rule to BPU and other EGUs in the State. Through EPA's docket, BPU has obtained and is reviewing EP A's background documentation including modeling information. [EPA-HQ-OAR-2009-0491-2194.1, p.2]
As proposed, the rule would significantly affect the planning and operations of BPU. As a public utility, BPU must go through a lengthy and time-consuming process to obtain funding for emissions controls required by the proposed rule. Assuming BPU could obtain funding, this process often takes over a year to complete in addition to construction time for the new controls. This would be an almost impossible task to complete by 2014. We do not want to rush to conclusions about the best option for BPU and its customers without all of the data available for review. [EPA-HQ-OAR-2009-0491-2194.1, p.2]
These issues have created an impossible situation for BPU to respond in a full and meaningful manner by the current October 1 and October 15 deadlines, particularly given BPU's and Kansas' status as 'first time state' affected by the proposed rule. In addition, the rulemaking record would be better served by a single set of comments that address comprehensively the new and old data. To assure a full and meaningful comment period consistent with statutory and regulatory intent, additional time to comment is appropriate. Accordingly, BPU ,requests that EPA replace the current comment dates and grant an extension to and including November 30,2010 for a single set of comments to address all matters raised by the original Notice and the NODA. [EPA-HQ-OAR-2009-0491-2194.1, p.2]
On behalf of Kansas City Board of Public Utilities ('BPU'), this letter is to request an extension of time to provide comments on the 'Clean Air Transport Rule,' 75 Fed. Reg. 45,210, and on the 'Notice of Data Availability,' ('NODA') 75 Fed. Reg. 53,613. Currently, comments on the Rule are due October 1, and comments on the NODA are due October 15. We request an extension to allow the filing of a single set of comments on both aspects of the rulemaking to November 30,2010. [EPA-HQ-OAR-2009-0491-2194.1, p.1]
The publication of the NODA has severely impacted that analysis. Since EPA did not conduct modeling in support of the NODA, any attempt to understand how the NODA will impact the conclusions that EPA reached prior to the NODA requires the input of the NODA data set into the modeling. Due to the complexity of the modeling, inputting and analyzing that new data and its impact will take a matter of weeks to complete. In addition, other new data was received from EPA on September 14, correcting a corrupt model-ready emissions file. Currently, and despite BPU's best efforts, it appears that it will be extremely unlikely, if not impossible, to incorporate the new data into the modeling in a timely fashion that will allow BPU to file comprehensive and meaningful comments which should be considered by EPA. [EPA-HQ-OAR-2009-0491-2194.1, pp.1-2]
As a result of the new information in the NODA, these efforts have been hampered by creating a 'moving target' that impedes these efforts to evaluate the applicability and potential impacts of the proposed rules in Kansas and BPU. [EPA-HQ-OAR-2009-0491-2194.1, p.2]
Accordingly, BPU, requests that EPA replace the current comment dates and grant an extension to and including November 30,2010 for a single set of comments to address all matters raised by the original Notice and the NODA. [EPA-HQ-OAR-2009-0491-2194.1, p.2]
THE NOTICE OF DATA AVAILABILITY FAILS TO PROVIDE FOR MEANINGFUL COMMENT AND IS THUS PREJUDICIAL TO THE PARTIES
The new data placed in the record with the NODA contained computer files that were corrupted or otherwise unusable. Although EPA cooperated in providing usable files to replace the corrupted and unusable ones, the delay caused an already aggressive schedule for review of the newly introduced additional data to become completely unworkable. It is our understanding that the last corrected file related to the NODA data did not become available until September 25. It follows that September 25 was the first date on which any examination or analysis of the new data could be initiated. EPA initially provided 45 days (September I data availability with an October 15 comment deadline) for comment on the NODA data. Thus, it appears EPA believed that a minimum of 45 days was required to allow for meaningful comment on the NODA data. Consequently, EPA should grant an extension of the comment deadline to November 10 to maintain the same amount of time from when usable NODA data actually become available. [EPA-HQ-OAR-2009-0491-2740.1, p.6]
In any event, the introduction of new pivotal data this late in the rulemaking process prejudices parties seeking to provide meaningful comment in violation of 5 U.S.C. § 553(c). As The NODA makes clear, the newly available data concerns the database showing 'unit level characteristics of the electric generating units (EGUs) included in the IPM modeling' as well as the new base case modeling runs that address compliance issues and the preferred policy options. 75 FR at 53614/2. All of those are critical components of the rulemaking analysis, and changes to any of them could affect the scope and reach of the final rule. Where EPA 'provides entirely new information critical to [its] determination,' Community Nutrition Inst. v. Block, 749 F.2d 50,57-58 (D.C. Cir. 1984). EPA must provide the opportunity for meaningful comment. Portland Cement Ass'n v. Ruckelhaus, 486 F.2d 375, 393 (D.C. Cir. 1973). This requirement is mandatory 'to ensure that agency regulations are tested through exposure to public comment, to afford affected parties an opportunity to present comment and evidence to support their positions, and thereby to enhance the quality of judicial review.' Chamber a/Commerce v. SEC, 443 F.3d 890, 900 (D.C. Cir. 2006)(citation omitted). [EPA-HQ-OAR-2009-0491-2740.1, pp.6-7]
The present situation, which for all practical purposes gives no more than 20 days from the time uncorrupted and usable data files were made available to the October 15 deadline for comments, does not allow for the 'genuine interchange' that notice-and-comment rulemaking is designed to achieve. Conn L & P Co. v NRC, 673 F.2d 525, 530 (D.C. Cir. 1982). Even accepting arguendo EPA's view that the 45-day period set in the NODA was adequate, the actual time for analysis and comment after usable files finally became available of less than half that period is grossly inadequate. [EPA-HQ-OAR-2009-0491-2740.1, p.7]
The parties are prejudiced by the inadequate comment period as well as by the indication 'additional information used to support the final transport rulemaking may be placed in the docket' at unspecified future date(s). 75 FR at 53615/1. As the NODA encapsulates, the new data relate to key databases and modeling runs, id. at 53614/2, and could produce different results from those contained in the Rule. Parties must be allowed to determine whether such differences are present, and what effect they have on the various aspects of proposed rule. See Small Refiner Lead Phase-Down Task Force v. EPA, 705 F.2d 506, 540-41 (D.C. Cir. 1983) (prejudice requires specific showing of the 'portions of the documents [a party] objects to and how it might have responded if given the opportunity'). [EPA-HQ-OAR-2009-0491-2740.1, p.7]
Meaningful comment in this context thus means the ability to determine what documents (new data files) raise objections and what response is appropriate to those objections. Here that process could not even begin until the corrupted computer files were purged and replaced with usable tiles, which took the better part of a month to accomplish. Assuming that all the necessary computer files have been made available, the modeling runs involved in replacing the original data with these new data take considerable time and effort. Only at that point can the process of determining objections and developing responses begin. Given the amount of data, the complexity of the issues, and the consequences related to the model results, far more time than the 45-day period set in the NODA, or the actual 20-day period after the data were finally made available in usable form, would be needed to permit meaningful comment. EPA's failure to provide adequate time prejudices the parties by not allowing them to present specific comments on pivotal matters, and therefore is arbitrary and capricious. See Appalachian Power Co. v. EPA, 249 F.3d 1032, 1059 (D.C. Cir. 2001)(agency action is arbitrary and capricious where agency 'has failed to respond to specific challenges that are sufficiently central to its decision'). [EPA-HQ-OAR-2009-0491-2740.1, p.8]
Kansas City Power and Light Company (KCP&L)
4. EPA should withdraw the Proposed Transport Rule, revise it using whatever corrected data EPA deems most appropriate, and republish it for public comment with an adequate comment period. A new comment period is necessary to allow appropriate review of the new input data, model results, and resulting emission allowance allocations. [EPA-HQ-OAR-2009-0491-2709.1, p.3] [EPA-HQ-OAR-2009-0491-3757.1_NODA, p.3]
Conclusions
For the reasons stated previously, the Proposed Transport Rule is seriously flawed from both a policy and a technical standpoint. EPA should withdraw the proposed rule and propose a new rule that addresses the deficiencies identified by the court in North Carolina v. EPA. A reproposed rule, with a sufficient comment period, would allow regulated sources time to properly review and analyze the technical data supporting the rule as well as EPA's methodology and rationale used in setting state budgets. A revised rule should include a compliance schedule that allows sufficient time for states to develop approvable SIPs as well as for the regulated community to install controls or develop other economically sound compliance strategies.[EPA-HQ-OAR-2009-0491-2709.1, p.11]
Lakeland Electric
Lakeland Electric requests an extension to the initial comment period for an additional 60 days. Lakeland Electric environmental personnel are in the process of performing EPA's Utility MACT ICR and EPA's Effluent Guidelines ICR, while concurrently reviewing EPA's Transport Rule. Lakeland Electric has not had enough time to review the multiple TSDs EPA has posted on the docket, and has not had the opportunity to fully understand EPA's modeling formulas or review EPA's units' parameters databases. Therefore, Lakeland Electric requests that EPA extend the initial comment period an additional 60 days. [EPA-HQ-OAR-2009-0491-2630.1,p.5]
Lakeland Electric requests an additional comment period(s) regarding the Transport Rule. EPA has stated on many teleconferences with regulated entities that EPA is looking asking for comments on EPA's assumptions and modeling theories. However, this is very difficult when industry has not had substantial time to study the modeling data (e.g., IPM, etc.). Lakeland Electric has many concerns as cited above regarding the accuracy of EPA's database regarding our units' parameters. Lakeland Electric would prefer EPA make any correction needed and give Lakeland Electric an additional comment period in order to review any correction needed. This is a basic request, and this procedural due process appeal should not be ignored in order that EPA can make some arbitrary internal final rulemaking deadline. Therefore, Lakeland Electric urges EPA to allow for an additional notice and comment period after EPA has made changes after reviewing these initial comments. [EPA-HQ-OAR-2009-0491-2630.1,p.6]
Louisiana Chemical Association (LCA)
We respectfully request that the Environmental Protection Agency grant a sixty to ninety day extension of time for public comment on the proposed Clean Air Transport Rule and associated Federal Implementation Plan ('FIP'). The current deadline for comment does not provide us with sufficient time to comment on the myriad of important issues raised by the proposed rule. [EPA-HQ-OAR-2009-0491-1925.1, p.1]
LCA has been diligently working to review the numerous technical support documents and underlying data upon which the proposed rule is based. However, due to the proposal confusing presentation of data, analysis and step-by-step work, it has been difficult for us to obtain information to confirm the basis for EPA's inputs to its emission inventory estimates and other model inputs, as well as to obtain data from official Louisiana and Texas sources to verify factual information. We have spent a great deal of resources and time reviewing these issues and obtaining necessary data, but need additional time to prepare factual information to submit to EP A for the record as well as to adequately comment on policy choices for which EPA requests comment. [EPA-HQ-OAR-2009-0491-1925.1, p. 2] 
Due to the complexities of the above issues, LCA, has not had sufficient time to review and research many other critical issues raised by the proposed Transport Rule for which EPA requested comment. We have concern with the basic EPA methodology for determining significant impact and interference with maintenance and desire to comment on such methodology. Because EPA proposes to us such methodology for all future SIP reviews with respect to potential interstate transport issues, it is important to thoroughly evaluate different policy options on such methodologies. EP A has not allowed sufficient time to do this, or for LCA to adequately present alternatives to such methodology. [EPA-HQ-OAR-2009-0491-1925.1, p. 4]
In short, given the complexity of the proposed rule, the significant number of technical support documents that must be reviewed, and the important policy choices that must be considered, LCA needs additional time to adequately prepare comments. EPA took over a year to put this proposal together and should allow more than 60 days for comment, particularly when EPA did not precede the proposal with a Notice of Data Availability on critical inputs. Further, because the CAIR rule remains in place, the extension of time does not present the risk of significant harm to the environment. Please let me know as soon as possible whether EPA will grant this extension through an email response or return letter. [EPA-HQ-OAR-2009-0491-1925.1, p. 4]
LCA believes that the amount of time allowed for public comment on this proposal was completely insufficient given the broad impact, potential costs, failure to precede the rule with a Notice of Data Availability, and significant amount of technical support information requiring review. LCA requested extension of the public comment period and reiterates that request. Due to time constraints, LCA is submitting as detailed comments as reasonably possible, but was not able to address all of the underlying data and policy issues for which EPA requested comment. LCA will continue to submit comments and requests that EPA consider these and publish a revised proposal prior to adoption of a final rule. [EPA-HQ-OAR-2009-0491-3527.1, p. 2]
Louisiana Energy and Power Authority (LEPA)
The process by which EPA developed the proposed transport rule and the unit allocations contained in that rule was seriously deficient and prevented interested and affected persons from submitting meaningful comments. [epa-hq-oar-2009-0491-2700.1, p.9; for additional comments pertaining to the process by which EPA developed the proposed transport rule and the unit allocations contained in that rule was seriously deficient and prevented interested and affected persons from submitting meaningful comments, see pp.9-11]
In light of the significant differences between the data on which EPA based the proposed rule and the data EPA released later pursuant to the NODA, EPA should withdraw the proposed Transport Rule, revise it using whatever data EPA deems most appropriate, and republish it for public comment with an adequate comment period that allows the opportunity for meaningful involvement. 'In many cases, rulemaking will make some interests in society better off than others, but those who end up 'losing' should at least be able to understand why government reached the decisions it did and to appreciate that their interests were considered fairly and treated with respect.'  This rulemaking process does not and cannot achieve that result. [EPA-HQ-OAR-2009-0491-2700.1, p.11]
LEPA and its members face potential disruptions in electric service and huge cost increases as a result of the Proposed Rule. Yet LEPA was not afforded a meaningful opportunity to participate in the development of the proposed rule. The EPA should have sought input from LEPA, NERC, Louisiana state regulators, and the SPP Reliability Coordinator in developing its proposed rule. The EPA should have gathered, considered and addressed as much information as it could regarding transmission constraints, must-run units and reliability concerns before promulgating its proposed rule. The ability to make after-the-fact comments in rush fashion on a rule that has already been published and papered with inscrutable studies is no replacement for meaningful participation in the development of the rule. [EPA-HQ-OAR-2009-0491-2700.1, p.11]
CONCLUSION
LEPA urges the EPA to withdraw the proposed Transport Rule, revise it using appropriate data, and republish it with a comment period that allows for meaningful involvement. [EPA-HQ-OAR-2009-0491-2700.1, p.21; for additional comments pertaining to CONCLUSION see pp.20-21]
Louisiana Public Service Commission
The Louisiana Public Service Commission Staff('LPSC Staff') respectfully requests that the Environmental Protection Agency ('EPA') grant a sixty to ninety day extension of time for public comment on the proposed Clean Air Transport Rule and associated Federal Implementation Plan ('FIP'). The current deadline for comment does not provide the LPSC Staff with an adequate amount of time to closely analyze, and comment upon, the wide range of important conceptual and empirical issues that are likely to have considerable impacts on Louisiana's power generators, and ultimately, our utility ratepayers. [EPA-HQ-OAR-2009-0491-1928.1, p.1]
The LPSC Staff thanks the EPA for considering this request for an extension of time to prepare comments. As you know, the proposed rule has important implications for air quality, as well as electricity rates, for a broad range of stakeholders in the eastern U.S., including Louisiana. The LPSC Staff needs the additional time to prepare thoughtful and well-reasoned comments and important local information and operational data for the EPA to consider in the development of a final proposed rule. [EPA-HQ-OAR-2009-0491-1928.1, p.2]
The LPSC Staff is particularly concerned about the expedited nature of the proposed rule's comment period. The proposed rule was not published in the Federal Register until August 2, 2010. Although Even if the comment period began July 6, 2010, when the proposed rule was posted on the EPA's website, which is denied, the nature and scope of the proposed changes, and the modeling and documentation supporting those changes, go far beyond 90 days of analysis. Furthermore, the EPA has continued to update data and assumptions and provide clarifying comments throughout the course of the comment period, making it even more burdensome for parties to fully analyze the data and fully understand the implications of the proposed rule. And finally, the EPA does not seem to have taken the time, care and caution required to yield reasonable results when taking on the complex exercise of modeling regional power markets, and the impact of sweeping environmental regulations. [EPA-HQ-OAR-2009-0491-2670.1, pp.4-5]
The LPSC expended considerable time and effort in developing recommendations to the LDEQ for the implementation of the proposed CATR's predecessor rule, the Clean Air Interstate Rule ('CAIR'). The CAIR recommendations recognized the complex nature of Louisiana's power grid and generation resource mix, and the needs of various stakeholder groups, as well as the Commissions directive to ensure the resulting recommendations would lead to fair, just, and reasonable rates. [EPA-HQ-OAR-2009-0491-2670.1, p.5]
The Commission's review, baseline data verification, modeling, and evaluation process for CAIR started in February 2006, and culminated with a recommendation that included a set of baseline data to be used for allowance purposes; a general methodology for allocating allowances; and a specific set of allowances. This recommendation was officially transmitted from the Commission to LDEQ in October 2006. In all, the analysis, comment, and review period totaled nine months, not 90 days. The EPA should reconsider its approach and timing for solicitation of stakeholder comments and input to regulations of the importance and magnitude of the proposed CATR. The LPSC Staff recommends that the EPA utilize a longer and more meaningful comment period for follow up comments and analyses for the revised rule likely to be generated from this initial expedited comment period. [EPA-HQ-OAR-2009-0491-2670.1, p.5]
Luminant
Luminant also requests additional time or opportunity to be able to comment on the proposed CATR from August 2nd the NODA that was released just 30 days ago, in a comprehensive manner with an adequate amount of time for comment. [EPA-HQ-OAR-2009-0491-2729.1, p.8]
Midwest Ozone Group
On behalf of the Midwest Ozone Group ('MOG'), I am writing to request an extension of the public comment period from October 1, 2010, to October 15,2010, on the proposed rule titled 'Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone; Proposed Rule,' that was published in the Federal Register on August 2, 2010 (75 Fed. Reg. 45,210 (the 'Transport Rule'). An extension to October 15, 2010, would harmonize the deadline for comments on the proposed Transport Rule with the deadline for comments on the recently announced 'Notice of Data Availability Supporting Federal Implementation Plans To Reduce Interstate Transport of Fine Particulate Matter and Ozone' that was published September I, 2010 (75 Fed. Reg. 53,613) (the 'NODA''). [EPA-HQ-OAR-2009-0491-1921.1, p.1]
Minnesota Power 
Comment preparation time.  Review time for both the Proposed Transport Rule and Notice of Data Availability has been short, relative to the extensive record that needs to be researched.   [EPA-HQ-OAR-2009-0491-2750.1, p.8]
Missouri Public Utilities Alliance (MPUA)
However, despite excellent control technology, this proposed rule appears to have significant impact on our cities ratepayers and our generating capacity. The proposed Transport Rule is extremely complex and our member utilities are struggling to understand its implications for their own operations especially as it relates to cost and reliability.  [EPA-HQ-OAR-2009-0491-2523.1, p.1]
Because EPA continues to provide additional technical support documents as late as three weeks ago, additional time is sorely needed to fully understand the rule, to review the technical information being added, and to comprehend the assumptions that went into developing and validating the agency's modeling software.  [EPA-HQ-OAR-2009-0491-2523.1, p.1]
In order for our members and the Alliance to have time to make knowledgeable comments, we respectfully request that the comment period be extended for 60 days to November 30,2010. [EPA-HQ-OAR-2009-0491-2523.1, p.1]
We have inadequate data and inadequate time to evaluate the accuracy of the results of the model.  However, it appears from anecdotal review that the model appears to produce unsubstantiated conclusions as the size of the generator moves from 100 MW to 25 MW.  We renew our request for additional time to review the model.  Additionally we ask for greater specificity on the weighting and interrelation of the data to the computations.  We also suggest that perhaps there needs to be more than one model depending on the size of the generator. [EPA-HQ-OAR-2009-0491-2785.1, p.3]
National Mining Association (NMA)
EPA Has not Provided an Adequate Opportunity for Comments
Apart from the cumulative impact assessment issue, EPA has made it very difficult, indeed impossible, to provide meaningful comments on the proposed rule. In the first place, EPA's intention to begin phase one of the proposed rule in 2012 resulted in an insufficient time for comments, only sixty days despite the extraordinarily complex nature of the proposed rule and the underlying analysis that supports the rule. NMA counts more than 20 Technical Support Documents as well as numerous modeling files in the record. In particular, the modeling and the assumptions underlying the modeling drive all facets of the rule, including the air quality analysis and the determination of individual state significant contributions to downwind nonattainment or interference with maintenance, and this in turns drives calculation of state budgets and whether states are classified as group 1 or group 2 states. Sixty days is not enough time to analyze and understand this material. [EPA-HQ-OAR-2009-0491-2868.1,p.14]
The Agency should not provide an inadequate amount of time to comment because of a self-imposed and impractical deadline to begin regulation. But the 2012 deadline is not feasible -- and its extension would provide the collateral benefit of allowing the public more time to understand this complex rulemaking and to provide useful comment to the Agency. [EPA-HQ-OAR-2009-0491-2868.1,p.14]
The insufficient time to comment is compounded by EPA's September 1, 2010 Notice of Data Availability (NODA), which indicates that EPA has made fundamental changes to the assumptions used in the modeling to support the rule. These changes evidently are sufficient to change EPA's air quality analysis and cost-effectiveness analysis and therefore the emission budgets and even potentially whether states are classified in group one or two. Indeed, even at this point EPA has not fully explained how its proposal has been changed by the new modeling assumptions, as EPA says that the state budgets "have not been modified to account for any changes that the modeling might suggest." [EPA-HQ-OAR-2009-0491-2868.1, pp.14-15]
In essence, the comments that EPA has called for as of October 1, 2010 pertain to an obsolete proposal, one that is different from the one that EPA is now considering and one that still has not been fully explained. But since the public has not yet had an opportunity to examine and fully understand the NODA, the public cannot be sure in exactly what ways the original proposal on which it is now commenting may or may not remain valid. [EPA-HQ-OAR-2009-0491-2868.1,p.15]
In these circumstances, it would have been far better for EPA to have delayed the entire comment period so that the public had at least an additional sixty days to comment on the entire rule after publication of the NODA. But with phase one of the rule nearing, EPA evidently concluded that there was insufficient time to do so. This problem could have been solved had EPA proposed the Transport Rule sooner and, when it did so, the Agency had completed its underlying analysis, and therefore the proposal itself. The problem can still be solved if EPA will delay the phase one requirements, a course it should do anyway given the lack of feasibility of the phase one requirements. [EPA-HQ-OAR-2009-0491-2868.1,p.15]
National Rural Electric Cooperative Association (NRECA)
  For reasons stated below, NRECA is requesting a 60-day extension of the public comment period to expire on November 30, otherwise set to expire on October 1.  As you know, the proposed CATR is in response to the court's overturning of the Clean Air Interstate Rule (CAIR). At the time, CAIR was described as the largest regulation ever proposed and implemented by the agency. EPA has now proposed the CATR as the CAIR substitute. The proposal is enormous, complex, and utilizes several atmospheric and economic models and extensive electric utility unit operational and emissions control information to produce four separate electric utility cap and limited trading programs. Although a pre-published proposal was available in early July of this year, EPA added significant portions of the technical support documentation to the CATR Docket around the CATR's August 2 publication.  On September 1, EPA provided through a Notice of Data Availability (NODA) an updated version of EPA's power sector modeling platform, among other technical support additions to the CATR docket, which according to the NODA, will affect the final rule. Moreover, according to the proposed CATR, the final rule will dictate essentially permanent unit compliance obligations and emissions allowances, while providing only extremely limited opportunities for unit allowance reconciliations.   [EPA-HQ-OAR-2009-0491-1901.1, pp.1-2]
Many of NRECA's members will be affected greatly by the final CATR that portends notable changes in business practices and substantial cost outlays with resulting significant rate impacts on vast portions of the nation's electric cooperative consumers. Thus, NRECA and many of our members intend to comment on it. However, considering the CATR complexities as described above, NRECA and the electric cooperatives affected by the CATR simply need more than 60 days from the CATR August 2 publication date to study the proposal, understand its underlying assumptions and rationale, evaluate the relevant data for accuracy, determine the proposal's overall impact on the affected generating units, and submit comprehensive comments. [EPA-HQ-OAR-2009-0491-1901.1,p .2]
NRECA is not criticizing agency efforts at this stage. As stated previously, the proposal is huge and involves the complex manipulation of voluminous data. Moreover, much of the underlying support information relevant to electric cooperative generating unit obligations appears to be in error or contains erroneous assumptions. To complicate matters further, information supplied under the NODA would logically result in different projected compliance obligations and allowance apportionments than that contained in the August 2 CATR proposal. [EPA-HQ-OAR-2009-0491-1901.1, p.2]
To summarize, the enormity and complexity of this proposal, the vastness of the underlying support documentation that must be understood and evaluated on a unit by unit basis, the many apparent errors and inconsistencies contained in this documentation that must be analyzed so as to effectuate meaningful comment, and the finality of unit decisions within the final CATR mandate that the public comment period should be extended 60 days to November 30 of this year. [EPA-HQ-OAR-2009-0491-1901.1, p.2]
Nebraska Public Power District
1) Additional Modeling and Technical Analysis Needed to Fix TR Flaws. Given the massive amount of information contained in the proposed rule and preamble, supporting documents, and supporting databases, the comment period of 60 days following proposed rule publication is wholly inadequate. For purposes of preparing these comments, NPPD has focused on issues of greatest concern to its interests, but it was not practical to complete a thorough review of the material in the allotted 60 days. NPPD believes that additional time should be provided to complete our analysis and submit comments on the rule as currently proposed. [EPA-HQ-OAR-2009-0491-2711.1, p.1]
New York University School of Law, Institute for Policy Integrity
The Institute for Policy Integrity requests an extension of 30 days to submit comments on EPA's efforts to reduce interstate transport of emissions of fine particulate matter and ozone. Given the complex and significant nature of this proposed regulation, the additional time is necessary to ensure adequate comments on the proposed regulation. [EPA-HQ-OAR-2009-0491-2056.1, p.1]
Further, given the Notice of Data Availability (NODA) supporting the proposed regulation, which was published in the Federal Register on September 1, 2010, 75 Fed. Reg. 53,613, the additional 30 days is warranted.  [EPA-HQ-OAR-2009-0491-2056.1, p.1]
NextEra Energy, Inc.
On behalf of NextEra Energy, Inc., I am writing to request a 60-day extension of the comment period on the proposed 'Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone,' published in the Federal Register on August 2, 2010, at 75 Fed. Reg. 45210 ('Proposal'). The Proposal is one of the most far-reaching and complicated rules ever proposed under the Clean Air Act ('CAA'). The current 60-day comment period is inadequate to allow potentially affected sources and States to review and analyze the Proposal and respond to the Agency's specific requests for comments. Accordingly, NextEra Energy requests that EPA extend the deadline for submitting comments on the Proposal from October 1, 2010 to November 30, 2010. [EPA-HQ-OAR-2009-0491-0298.1, p.1]
NextEra Energy operates electric generating units in 10 of the states covered under the Proposal and, therefore, will be directly affected by any final rule issued by EPA. The regulatory scheme finalized by EPA will have a significant impact on every aspect of NextEra Energy's business - including long-term business planning, the determination of consumer rates, and the day-to-day operation of electric generating units. It is of the utmost importance that NextEra Energy is given adequate time to analyze the Proposal and provide the Agency with meaningful feedback on the proposed regulatory schemes. [EPA-HQ-OAR-2009-0491-0298.1, p.1]
The Proposal and supporting materials are too complex and lengthy to review and analyze in 60 days. The Proposal alone consumes 250 pages of the Federal Register: In addition, EPA has posted over 150 supporting materials and documents in the rulemaking docket, most of which consist of highly technical data. Review of these materials constitutes a massive undertaking. Although the Agency made many of these materials available at the time the Proposal was signed, and before the Proposal was published in the Federal Register, the additional time offered for review is insufficient to thoroughly analyze the data. Already, based on an initial review, NextEra Energy has identified a number of inaccuracies in the data underlying the Proposal, including mistakes regarding operations at certain affected electric generating units. If they are not fully identified and corrected, inaccuracies such as these will undermine the foundation of any regulatory scheme promulgated by EPA and result in an ineffectual program tl1at will impair the reliable generation and transmission of electricity throughout the country. NextEra Energy faces the daunting task of processing the available information, evaluating the feasibility of implementing each of the three regulatory schemes set forth in the Proposal, and providing EPA with constructive feedback through detailed comments. [EPA-HQ-OAR-2009-0491-0298.1, p.1]
EPA has the discretion to extend the comment period for the Proposal and doing so would benefit the Agency, States, and the regulated community. Providing adequate time for meaningful public participation in the rulemaking process will help ensure that the final rule comports with the CAA and effectively addresses concerns related to the interstate transport of air pollutants. [EPA-HQ-OAR-2009-0491-0298.1,p .2]
Northern Indiana Public Service Company (NIPSCO)
EPA has made the process of making meaningful comments on this rule very difficult by the issuance of the Notice of Data Availability ('NODA') on September 1, 2010, two months after the final proposed rule was posted on EPA's website and a month after the proposal was published in the Federal Register. Review of the data included in the NODA is critical to companies' thoughtful and complete analysis of the proposal, which is necessary for companies to determine the accuracy of the data and to inform EPA as to their corrections of the data and their overall views of the proposed rule. The proposed Transport Rule includes a large set of complex technical support documents that provide the entire basis for the Transport Rule control program, including emission allowance allocations. The NODA essentially provides a complete replacement for the original data and modeling with technical support with the important exception of providing the unit specific emission allowance allocation, which is the most critical component for companies to evaluate. Companies need the opportunity to make meaningful comments on the entire package, including emission allowance allocations, and EPA needs to consider providing additional necessary information for comment prior to finalizing the rule. [EPA-HQ-OAR-2009-0491-2747.1 p.2]
Since the NODA information could impact state and unit-specific allowance budgets, NIPSCO recommends that prior to finalizing the Transport Rule, EPA release, as soon as possible, a Supplemental Notice of Proposed Rulemaking and/or NODA that allows owners of covered units to verify the data underlying the allocations in the final rule and to provide any necessary comments to correct the data. For example, if EPA decides to retain the proposed allocation methodology, we recommend that EPA release the updated assumptions and modeling results used as the basis for the modified allocations, along with revised unit-specific allowance allocations, prior to finalizing the rule and to provide a comment period of at least 30 days. Such a process would ensure the final data underlying the rule is as accurate as possible by providing stakeholders with an opportunity to submit additional corrections. As part of this process, EPA should provide sufficient time for meaningful review of the data. This effort could occur while EPA is drafting other provisions of the final rule and thus would not necessarily delay release of the final rule in early 2011. [EPA-HQ-OAR-2009-0491-2747.1 p.2]
Occidental Chemical Corporation (OCC)
Occidental Chemical Corporation ('OCC') hereby requests and strongly recommends that the U.S. Environmental Protection Agency ('EPA') extend the public comment period for 90 days, through December 30, 2010, for the proposed Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone, 75 Fed. Reg. 45210 (August 2,2010) ('Proposed Rule'). [EPA-HQ-OAR-2009-0491-1893.1, p.1]
OCC manufactures a variety of diverse organic and inorganic chemicals at over 20 domestic locations. OCC operates large-scale cogeneration facilities co-located with three OCC-owned and operated chemical manufacturing plants in Taft, Louisiana; Ingleside, Texas; and LaPorte, Texas. The total combined power output of these units is nearly 1,500 MW. These units supply all of the electrical and steam requirements of the adjacent chemical plants, with any excess electrical generation being sold to the local utility or into the wholesale market. [EPA-HQ-OAR-2009-0491-1893.1, p.1]
The proposed rule, if adopted in its current form, could have a significant negative impact on our new, highly-efficient natural gas-fired cogeneration facility in Taft, Louisiana. This facility, which was started-up in 2002, is equipped with ultra-low NOx burners and, on average, emits approximately 500 tons of NOx per year However, the proposed rule provides annual allowances to this facility totaling only 26 tons of NOx per year beginning in 2012. OCC has significant concerns about the assumptions used in the Integrated Planning Model EPA used to develop overall emissions allowances and the methodology EPA employed to allocate allowances to individual units. [EPA-HQ-OAR-2009-0491-1893.1, pp.1-2]
We are carefully reviewing the Proposed Rule and are trying to gain a better understanding of the allocation methodology and its impact on OCC's cogeneration facilities. The proposal and supporting technical documents are voluminous and complex. In order to ensure an adequate and complete review of the proposal and the preparation of relevant comments and recommendations, we respectfully request that EPA extend the public comment deadline for 90 days, until December 30, 2010. [EPA-HQ-OAR-2009-0491-1893.1, p.2]
We also realize that EPA has supplemented the record to the Proposed Rule with additional information relevant to the rulemaking, including an updated modeling platform, updated unit level input data and model results, and detailed documentation of the updated model and user guides to input assumptions and model outputs. 75 Fed. Reg. (Sept. 1, 2010) (the 'NODN'). EPA proposed to accept comments on these specific new data until October 15, 2010. As a result of the NODA, OCC must discard the analysis it conducted in August and start over with its effort to understand and apply the Proposed Rule and the interrelated supporting technical documents, while still being expected to submit critical comments on the bulk of the Proposed Rule by October 1, 2010. Given the amount of information to be reviewed and assessed, this is an unreasonable schedule, further complicated by the supplementation of critical data half-way into the comment period. Accordingly, we respectfully request that EPA extend the comment period for both the Proposed Rule and the related NODA to December 30, 2010. [EPA-HQ-OAR-2009-0491-1893.1,p.2]
As set forth in the Notice of Data Availability published on September 1, 2010 ('NODA'), EPA supplemented the docket for the proposed rule with a significantly revised and updated modeling platform that constitutes a substantial portion of the technical basis supporting the proposed rule. EPA is accepting comments on the revised modeling platform through today, October 15, 2010. Despite the fact that revisions to the complex modeling platform were not made public until half-way into the 60-day comment period on the proposed rule, EPA denied our request for an extension of time to provide comments on the proposed rule. We reiterate our request for an additional 90 days to review and submit substantive comments on the proposed rule and revised modeling platform. [EPA-HQ-OAR-2009-0491-3796.1, pp. 1-2]
Ohio Coal Association
:: EPA has not provided adequate time for parties to review and comment. The Transport Rule and its associated materials are voluminous and very detailed. In addition, EPA issued a Notice of Data Availability (NODA) in September that contemplated yet additional technical support. 75 Fed. Reg. 53613. Ohio Coal requests that EPA extend the comment period until sixty days after EPA completes its technical record. [EPA-HQ-OAR-2009-0491-2743.1, p.2]
Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
Again, OVEC does not believe that there is any justification for EPA to have developed and issued such a massive and complicated rule with such a short period of time for analysis and comment considering the significant impacts it will have on the effected entities. The comments above are some of the most obvious problems directly affecting OVEC, and the costs and impossibility of provisions of the Proposed Transport Rule clearly show that EPA must take a step back and reassess the true adverse effect the Proposed Transport Rule will have on the industry. [EPA-HQ-OAR-2009-0491-2779.1, p.9]
Omaha Public Power District
Given the massive amount of information contained in the proposed rule and preamble, supporting documents, and supporting databases, the comment period of 60 days following proposed rule publication is wholly inadequate. For purposes of preparing these comments, OPPD has focused on issues of greatest concern to its interests, but it was not practical to complete a thorough review of the material in the allotted 60 days. Furthermore, because of serious errors in EPA's emissions inventory as outlined below and needed revisions to the 'significant contribution' procedures, EPA should allow additional time for Nebraska sources to review and comment on the effects of these errors, and for EPA to revise its modeling analysis.[EPA-HQ-OAR-2009-0491-2680.1, p. 1]
Pfeiff, Mike
1. Public Comment Period Extension - The EPA should extend the sixty day comment period for the following reasons:
a. The EPA required over two years to prepare the Proposed Transport Rule as a replacement to the Clean Air Interstate Rule (CAIR) which was vacated by DC Circuit Court of Appeals on July 11, 2008.
b. The Proposed Transport Rule alone consumes of 256 pages of the Federal Register. In addition, at the time of this comment submittal, the EPA has provided at least 21 separate documents consisting of over 951 pages of highly technical documents describing the EPA's analysis and rational the proposed rule. Additionally, many of the supporting documents contain data files with hundreds of thousands of individual records.
c. The lengthy duration time required by the EPA to construct and officially publish the Proposed Transport Rule along with the voluminous quantity of technical supporting documents is evidence of the highly complex nature of the proposed rule. [EPA-HQ-OAR-2009-0491-2742.1, p.2]
d. The EPA only recently made available key data necessary for commenter's to fully understand the Proposed Transport Rule. It wasn't until September 1, 2010 with the publication of the Notice of Data Availability Supporting Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone (the 'NODA') did the EPA make available key modeling data necessary for the public to understand the Proposed Transport Rule. 75 Fed Reg. 5613 (Sept 1, 2010). This release of data is extremely voluminous. The modeling data funs alone consist of over 27 megabytes of zipped (i.e. compressed) data. The modeling documentation alone consists of 509 pages of highly technical information with another 15 megabytes of appendix data. Further the NODA released a 1.3 megabyte zipped database containing 37,182 records of the EGU design and operating parameters assumptions. This information is highly relevant to the public's ability to understand and provide meaningful comments about the Proposed Transport Rule. How can the public be reasonably expected to comment on the Proposed Rule when they haven't even had all the facts for 30 days? [EPA-HQ-OAR-2009-0491-2742.1, pp.2-3]
For these reasons, I respectfully request and extension of the public comment period of the Proposed Transport Rule and the NODA by 90 days to January 1, 2011.[EPA-HQ-OAR-2009-0491-2742.1, p.3]
PowerSouth Energy Cooperative
I am writing on behalf of PowerSouth Energy Cooperative (PowerSouth), to request a 60-day extension of the comment period on the proposed "Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone," published in the Federal Register on August 2, 2010, at 75 Fed. Reg. 45210 ("Proposal").  The Proposal is one of the most far-reaching and complicated rules ever proposed under the Clean Air Act ("CAA").  The current 60-day comment period is inadequate to allow PowerSouth to review and analyze the Proposal and respond to the Agency's specific requests for comments.  Accordingly, PowerSouth requests that EPA extend the deadline for submitting comments on the Proposal from October 1, 2010 to November 30, 2010. [EPA-HQ-OAR-2009-0491-1936.1, p. 1]
The regulatory scheme finalized by EPA will have a significant impact on every aspect of  PowerSouth's business including long-term planning, the determination of member rates, and the day-to-day operation of electric generating units.  It is of the utmost importance that PowerSouth is given adequate time to analyze the Proposal and the voluminous amount of supporting materials to provide the Agency with meaningful feedback on the proposed regulatory schemes. [EPA-HQ-OAR-2009-0491-1936.1, p. 1]
The Proposal comes at a time of unprecedented regulatory activity in all media (air, water, coal combustion residuals, security issues, etc), all of which require time and resources to evaluate and respond to appropriately.  The Proposal and supporting materials are too complex and lengthy to review and analyze in 60 days.  The Proposal alone consumes 250 pages of the Federal Register.  In addition, EPA has posted over 150 supporting materials and documents in the rulemaking docket, most of which consist of highly technical data.  Review of these materials constitutes a massive undertaking.  Although the Agency made many of these materials available at the time the Proposal was signed, and before the Proposal was published in the Federal Register, the additional time offered for review is insufficient to thoroughly analyze the data.  PowerSouth faces the daunting task of processing the available information, evaluating the feasibility of implementing each of the three regulatory schemes set forth in the Proposal, and providing EPA with constructive feedback through detailed comments. [EPA-HQ-OAR-2009-0491-1936.1, pp. 1-2]
EPA has the discretion to extend the comment period for the Proposal and doing so would benefit the Agency, States, and the regulated community.  Providing adequate time for meaningful public participation in the rulemaking process will help ensure that the final rule consistent with the CAA and effectively addresses concerns related to the interstate transport of air pollutants.  [EPA-HQ-OAR-2009-0491-1936.1, p. 2]
PPG Industries, Inc.
On behalf of PPG, we respectfully request that the Environmental Protection Agency grant a sixty to ninety day extension of time for public comment on the proposed Clean Air Transport Rule and associated Federal Implementation Plan ("FIP"). The current deadline for comment does not provide PPG with sufficient time to comment on important issues raised by the proposed rule. [EPA-HQ-OAR-2009-0491-1926.1, p.1]
PPG also needs additional time to comment on whether NOx reductions are even justified under the proposed Transport Rule/FIP. Until publication of the proposed rule, there was no basis to believe that Louisiana emissions were projected to interfere with annual PM 2.5 maintenance in any area of Texas. This was not a finding under the modeling performed for the CAIR program. [EPA-HQ-OAR-2009-0491-1926.1, p.2]
PPG would like to express extreme concern over EPA's denial of the PPG request for extension to the comment period dated September 17, 2010. PPG has expended considerable effort in reading the proposed rule (1361 pages) and the hundreds of pages of technical support documents posted on the EPA website in support of the proposed rule. In addition PPG has contacted EPA directly and also with industry group conference calls with the goal of understanding the proposed allocations discrepancies. Even with all the time and resources expended, EPA was not able to provide PPG with an adequate understanding of the allocation process under the proposed FIP, particularly in reference to the Integrated Planning Model used by EPA to make allocations based on predicted future operations. Without adequate understanding of the underlying assumptions and the process, PPG is severely limited in its ability to provide substantive comments. Since PPG RS Cogen units have only been allocated 5% of the allowances currently allocated under CAIR, the proposed CATR will have a direct and costly impact to PPG operations if finalized as proposed. By not providing sufficient information and allowing sufficient time to comment on the proposed rule, EPA is penalizing PPG's RS Cogen operations without justification. [EPA-HQ-OAR-2009-0491-2763.1, p. 18]
The proposed CATR is one of the most complex, data intensive rules EPA has ever proposed. In addition, EPA is utilizing a proprietary model administered by a third party contractor to project specific units operation in order to provide allocations. Associated with this rule are hundreds of pages of technical support documents, data spreadsheets and other related documentation. PPG believes EPA should not propose a rule so dependent upon voluminous data without publishing a notification of data availability (NODA) and allowing sufficient comment period on the data itself to ensure models are utilizing data only from affected units and that the data are complete and accurate. PPG believes EPA's failure to follow the conventional NODA procedure will ultimately make the rule less defensible and therefore more likely to be litigated. [EPA-HQ-OAR-2009-0491-2763.1, p. 18]
Another consideration with the limited comment period and the significant problems with unit specific data is that PPG has been required to expend so many resources on researching unit specific data discrepancies, PPG has not had sufficient time to consider the proposed CATR on a broader basis. This limits PPG's ability to comment on the proposed trading methodologies and other issues on which EPA has requested comments.  [EPA-HQ-OAR-2009-0491-2763.1, p. 18]
Prairie State Generating Company, LLC
Determining the appropriate level of allocation is a complex exercise at this point in time, since PSGC Unit 1 has no operational history. Yet determining the appropriate level of allocation is extremely critical to PSGC. PSGC will likely submit comments on additional topics of particular concern, as well. Therefore, PSGC respectfully requests that EPA extend the comment period for approximately 60 days, to December 1, 2010, in order for PSGC to provide EPA with the most thoughtful and appropriate proposal for an allocation level for Unit 1 as well as its other comments.  [EPA-HQ-OAR-2009-0491-1026.1, p.1]
Santee Cooper
Finally, Santee Cooper requests that EPA provide an extension of the comment period. The amount of information contained in the preamble, the proposed rule, and technical support documents is substantial and 60 days is not an adequate amount of time to conduct a thorough review and provide meaningful comments. One area for which Santee Cooper needs additional time is the methodology (including data and assumptions) that EPA used for allocating allowances to affected EGUs under the Transport Rule. Although Section III of the Santee Cooper comments provides an initial discussion of our concerns, Santee Cooper needs additional time to provide a full evaluation of the proposed allowance allocation methodology. [EPA-HQ-OAR-2009-0491-2820.1, p.3]
Seminole Electric Cooperative Inc.
Given the extensive changes that EPA must make to its August 2 initial proposal, EPA must publish a second proposal in the Federal Register before the rule is finalized. As explained below, EPA's proposal contains numerous material factual errors related to Seminole's operations, and Seminole is aware that many other entities have identified similar fundamental flaws in EPA's data and modeling results. The correction of these extensive errors will necessarily change the compliance obligations of every state, company and unit, and affected parties must be given an opportunity to review and comment as to whether EPA has corrected its mistakes and parties can meet their new compliance obligations. Accordingly, EPA is obligated to publish a second proposal to provide the public an opportunity to review and comment on the accuracy and achievability of EPA's corrected approach before this rule is finalized. [EPA-HQ-OAR-2009-0491-2632.1, pp.1-2]
EPA's Transport Rule is an extremely technical and complex proposal, requiring 255 pages of the Federal Register, more than 20 Technical Support Documents and numerous modeling files and spreadsheets. EPA proposed three distinct regulatory alternatives, and requested comment on more than 90 other issues. And even after the August 2 proposal, EPA continues to publish further refinements and make additional data available. EPA failed to allow for, much less encourage or consider, stakeholder input during its development of this rule. EPA has effectively precluded meaningful public involvement by only affording a sixty-day comment period, and refusing to grant any of the numerous requests for an extension. [EPA-HQ-OAR-2009-0491-2632.1, p.2]
This abbreviated and insufficient comment period underscores EPA's obligation to publish an additional proposal, incorporating comments submitted on the August 2 proposal, prior to finalizing this rule. [EPA-HQ-OAR-2009-0491-2632.1, p.2]
South Carolina Department of Health and Environmental Control 
a) DHEC requests that the EPA extend the comment deadline for the proposed Transport Rule from October 1, 2010, to November 30, 2010. The current comment period for the proposed Transport Rule is too short to offer meaningful comments, and the proposal documents are too voluminous and complex to review in only 60 days. The proposed rule as published in the Federal Register is 265 pages long, and the supporting material totals thousands of pages. Reviewing such information is time and resource intensive. Administrator Jackson, in her 2010 EPA Priorities memo, stresses the EPA's commitment to transparency.4 DHEC notes that transparency involves more than posting thousands of pages of complex documents in the cumbersome Regulations.gov docket. Transparent rulemaking involves publishing supporting documents that are coherent and accurate, and providing the public enough time to understand these documents. [EPA-HQ-OAR-2009-0491-2677.1 p.2]
DHEC also requests that the EPA extend the comment deadline for the September 1, 2010, Notice of Data Availability ("NODA")5 from October 15, 2010, to November 30, 2010. The NODA announced that the EPA had added new model runs to the Transport Rule docket, including a new version of the Integrated Planning Model ("IPM") and National Electric Energy Data System ("NEEDS"). The new data takes up thousands of pages of spreadsheets, and the supporting document that explains how to interpret this new data is 487 pages long.6 Review of this material is especially confusing because the scope of the material on which the EPA is accepting comment until October 15 is unclear. The revised IPM and NEEDS data affect other parts of the Transport Rule, which are ostensibly not open for comment in the NODA. This ambiguity on what DHEC can comment on further confounds the already short comment periods for both the Transport Rule proposal and the NODA. [EPA-HQ-OAR-2009-0491-2677.1 p.2]
The EPA could have prevented this problem by publishing an Advance Notice of Proposed Rulemaking ("ANPRM") that published key parts of the proposal, such as the modeling framework. Without the ANPRM, the public must review all parts of the rule in the brief comment period for the proposed rule. DHEC recommends that the EPA, in future iterations of the Transport Rule, publish ANPRMs when appropriate to allow input on the EPA's proposed approach, to include modeling protocols.  [EPA-HQ-OAR-2009-0491-2677.1 p.3]
DHEC acknowledges that the EPA published the signed version of the Transport Rule on July 6, 2010, adding 27 days for the public to review the proposal. The EPA cites this as a reason for not extending its comment period in a web-posting, dated September 17, 2010, made in response to requests for an extension of the comment period, noting: EPA has received and declined several requests to extend the comment period for the proposed Transport Rule. The comment period on this rule will end on October 1, 2010. The proposed rule and much of the key supporting documentation was posted on our website on July 6, 2010 and the rule was formally published in the Federal Register on August 2, 2010.7 [EPA-HQ-OAR-2009-0491-2677.1 p.3]
There are four problems with the EPA's statement. First, the document released on July 6, 2010, was 1,361 pages long. A 27-day head start on reading such a long and complex document, though helpful, does not mean that the public has ample time to review the proposal. Second, the EPA's July 6 document was inaccurate. The pre-publication document, and the subsequent August 2, 2010, Federal Register version included an error on the acceptability of opt-in units. The documents erroneously stated in the preamble that the EPA was not allowing opt-in units. Though EPA addressed this in a September 14, 2010, Federal Register correction notice,8 DHEC spent time in the comment period resolving the discrepancy that it would have otherwise had to read and understand other parts of the proposal. Third, the EPA has added documents the Transport Rule docket throughout the comment period, including detailed spreadsheets September 28, 2010, three days before the end of the comment period.9 Fourth, the EPA's rejection of the requests for an extended comment period ignores the way that the NODA fundamentally skewed the comment process for the Transport Rule as a whole, which we discuss in the next section. [EPA-HQ-OAR-2009-0491-2677.1 p.4]
a) DHEC Has General Concerns with the Modeling in the Proposed Transport Rule Many parts of the EPA's methodology for defining "significant contribution" and "interference with maintenance" raise prima facie questions. DHEC will focus on these general questions in part because of the short comment period. We cannot divert our modeling staff to review the Transport Rule, thus we do not offer alternate modeling options. Additionally, states and local governments do not have teams of economists, nor the budgets to hire contractors, with the necessary skills to fully evaluate the cost models on which the EPA has made the "significant contribution" and "interference with maintenance" determinations. The cost models are of central relevance because they directly affect which states are subject to the rule. In sum, the complexity of the modeling in the proposed rule has swamped the public's ability to understand it in 60 days and offer meaningful comments. [EPA-HQ-OAR-2009-0491-2677.1 p.5]
b) The NODA May Render the Central Portions of DHEC's Comments Futile
The new information that the EPA published in the NODA is so fundamental to the Transport Rule that it may render nugatory DHEC's review of central portions of the proposal. The EPA assumes that there is a clear line demarcating the NODA information from the non-NODA information in the Transport Rule docket. This assumption is flawed because the IPM and NEEDS data affect the Budgets and Allocations Spreadsheet, which includes state emissions budgets and unit-level allowance allocations.10 State budgets and unit-level allocations are fundamental to the emissions reductions from the proposal, and are thus of central relevance to the outcome of the rule.11 EPA staff stated on a September 22, 2010, National Association of Clean Air Agencies ("NACAA") conference call that the new NODA data may affect the Budgets and Allocations Spreadsheet, but the EPA will not publish an updated version of the spreadsheet until it publishes the final Transport Rule. Additionally, the September 22, 2010, clarification leaves the public with only eight days to review the data with a proper understanding of its accuracy. Even with that understanding, DHEC is basing its comments on the budgets and allocations based on a spreadsheet that will likely change in the final rule. This flaw in the comment process makes it impracticable for DHEC to raise an objection to budgets and allocations during the comment period. Again, budgets and allocations are of central relevance to the outcome of the rule. [EPA-HQ-OAR-2009-0491-2677.1 p.5]
Further, DHEC based its oral testimony at the September 1, 2010, Atlanta Public Hearing in part on the Budgets and Allocations Spreadsheet. On the same day as this hearing, the EPA published information in the NODA that undermines the Budgets and Allocations Spreadsheet, and 22 days later clarified that the public will not see an update Budgets and Allocations Spreadsheet until the EPA publishes the final rule. If the final rule includes new state budgets and unit-level allocations, then DHEC would have wasted the public hearing opportunity, along with the time and resources it takes to attend the hearing, by offering testimony on data that we thought was open for comment, but, as of September 1, was already out-of-date. DHEC retains its comments on budgets and allocations, with reasonable specificity, in this letter, but we note that our comments are based on the Budgets and Allocations Spreadsheet that the NODA undermines. [EPA-HQ-OAR-2009-0491-2677.1 p.5]
DHEC notes that the NODA potentially rendered the comment period for the proposed Transport Rule irrelevant. The new IPM and NEEDS data affect the Budgets and Allocations Spreadsheet in the docket, which includes state emissions budgets and unit-level allowance allocations. The EPA however did not update the Budgets and Allocations Spreadsheet with publication of the NODA, so DHEC will not know the state budgets and unit-level allocations until publication of the Final Rule. State budgets and unit-level allocations are of central relevance to the outcome of the proposed Transport Rule, yet because of the EPA's midstream revisions to the technical foundation of the proposed Transport Rule, the public will not be provided the opportunity to review and provide meaningful comments to this major rule. Further, the new IPM and NEEDS data may influence the EPA's determination of which downwind states that South Carolina affects, and if the EPA does not re-notice the proposal, DHEC would not have opportunity to participate in the comment process on this important question.   [EPA-HQ-OAR-2009-0491-3718.1_NODA, p.1]
Southern Company
Southern Company respectfully requests that the comment period be extended by 60 days (120-day comment period ending on November 30,2010) to allow for a more thorough review of the proposed rule. Southern Company is also a member of the Utility Air Regulatory Group (UARG) and fully supports UARG's request for an extension of the public comment period. [EPA-HQ-OAR-2009-0491-0237.1, p.1]
1. Because of the Complexity of the Proposed Transport Rule and the Many Issues Addressed, Additional Time is Necessary to Review the Proposal and All 3 Regulatory Options.
Not only did EPA propose 3 Regulatory Options, each of which must be reviewed and commented on, but EPA also requested comment on more than 90 issues in the proposed Transport Rule. Southern Company intends to review these issues and provide comments to EPA, but will be unable to provide thorough and meaningful comments during the limited time provided. [EPA-HQ-OAR-2009-0491-0237.1, p.2]
Moreover, Southern Company notes that understanding EPA's approach for each option takes time. In order to respond to EPA, we must have sufficient time to understand how the proposed rule was developed and how it may impact Southern Company's subsidiaries. Given the amount of issues in which EPA is requesting comment, the complexity of the analysis performed, the occasional lack of clarity in describing this complex analysis, the difficulty we are experiencing in replicating EPA's results, and the fact that EPA has provided 3 possible regulatory approaches, it is essential that EPA allow enough time for stakeholder review. [EPA-HQ-OAR-2009-0491-0237.1, p.2]
2. Additional Time is Necessary to Review the More than 20 Technical Support Documents and to Understand and Replicate EPA's Methodology.
Our ongoing review of the technical support documents and EPA's modeling for the proposed Transport Rule thus far suggests that EPA's assumptions and modeling techniques may have several flaws. Because there are more than 20 Technical Support Documents describing EPA's regulatory approach and numerous modeling files it will be impossible for us to complete our review in the allotted time period. Although EPA has made the underlying data available, it has not provided sufficiently clear examples of each calculation. For example, the Air Quality Assessment Tool (A QAT) has not been made available to the public, although the underlying data is available. In order for Southern Company to comment on the rule, we must understand how EPA arrived at its calculations. In order to understand how EPA arrived at its calculations, we need either the actual calculations or sufficiently clear examples of the calculations. It took EPA two years to develop this complex rule. Likewise, it will take us more than 60-days to review and develop an understanding of EPA's assumptions and modeling and make meaningful comments on the proposed rule. [EPA-HQ-OAR-2009-0491-0237.1, p.2]
Much of this review could have been conducted before the rule was proposed, if EPA had allowed input to the modeling assumptions and underlying data during the developmental stages of the proposed rule. Southern Company understands that EPA was under a self imposed timeline to get a proposed rule out in response to the Clean Air Interstate Rule (CAIR) remand; however, this does not obviate the fact that stakeholder input should have been both encouraged and considered. Had EPA provided greater transparency of its modeling plans, this issue may have been avoided. [EPA-HQ-OAR-2009-0491-0237.1, p.2]
Given the complexity of EPA's approach and the amount of technical support documents and modeling files and assumptions, we believe additional time is necessary to perform a thorough review of EPA's IPM modeling, the Air Quality modeling, and the methodology to determine significant contribution and emissions allocations. Southern Company believes that it is in the best interest of all parties to ensure that the underlying data and assumptions used in the rulemaking are of the highest quality possible. [EPA-HQ-OAR-2009-0491-0237.1, p.3]
In conclusion, Southern Company requests that EPA extend the public comment period of the proposed Transport Rule by 60 days. Southern Company understands that EPA has a target date of June 2011 to issue the final rule. However, EPA is not under a statutory or court-ordered deadline to issue a final rule and EPA can be assured that emission reductions are currently occurring under CAIR. EPA can and should extend the date of the final Transport Rule to allow stakeholders the opportunity to fully review EPA's proposal and underlying assumptions and analysis. [EPA-HQ-OAR-2009-0491-0237.1, p.3]
The proposed rule is voluminous, complex, and opaque, traits which have made commenting on this proposed rule exceedingly difficult. Although the lengthy proposed rule, the accompanying massive amounts of technical supporting information, and the omission in EPA's description of its methodology for developing the provisions of the proposal clearly warrant a comment period longer than 60 days, EPA nevertheless denied our request for a comment period extension. EPA's failure to provide the public with a meaningful opportunity to comment on the proposed Transport Rule is a clear violation of Clean Air Act Section 307(d). Furthermore, EPA recently added new data to the docket, issued a Notice of Data Availability (NODA)2, and declared that the final rule will be based on the new data in the NODA. However, with the NODA, EPA has provided only a portion of the data needed to evaluate its implications and has declined to illustrate how it will affect the final rule. EPA has provided a proposed rule with an inadequate comment period and a proposed rule which contains 1) numerous factual and methodological flaws and 2) provisions which do not reflect the newly revised information upon which EPA intends to rely, yet EPA has indicated it will not release this revised information for comment. Providing meaningful comments on such a 'moving target' is problematic. [EPA-HQ-OAR-2009-0491-2864.1, p. 5]
II. EPA Deprived the Public of a Meaningful Opportunity to Comment on the Proposed Transport Rule, a Clear Violation of Clean Air Act Section 307(d)
On August 26, 2010 after working diligently to review the proposed transport rule, Southern Company requested an extension of the public comment period from October 1 to November 30. [See [EPA-HQ-OAR-2009-0491-2864.1, Attachment A for Southern Company's request for extension of public comment period.] Because of the complexity and lack of clarity on many aspects of the proposed rule and the many issues addressed, we found that 60 days was inadequate to thoroughly understand the rule, reproduce EPA's calculations, and provide meaningful comments. Southern Company noted in our request that reviewing EPA's 3 proposed regulatory options, the more than 20 technical support documents, the more than 90 issues that EPA requested comment on, and the numerous modeling files required more than 60 days. EPA denied our extension request on September 10. [EPA-HQ-OAR-2009-0491-2864.1, pp. 6-7]
Clean Air Act section 307(d) sets out detailed procedures that EPA must follow in conducting certain Clean Air Act rulemakings, including the ongoing rulemaking to adopt the regional transport rule proposed on August 2,2010. In particular, section 307(d) rulemakings impose on EPA's Administrator the obligation to accompany any proposed rule with a 'statement of its basis and purpose.' The statement of basis and purpose must also include information on (a) the factual data on which the proposed rule is based; (b) the methodology used in obtaining the data and in analyzing the data; and (c) the major legal interpretations and policy considerations underlying the proposed rule. See section 307(d)(3). Lacking this information, it is difficult for members of the public to understand what they are being asked to comment upon, and if they do not understand it, then they are essentially deprived of a meaningful opportunity to comment on an EPA proposed rule. [EPA-HQ-OAR-2009-0491-2864.1, p. 7]
When EPA proposed its transport rule on August 2, 2010, it presented a mountain of information: the rule itself covers 256 pages of the Federal Register, and EPA posted numerous additional background documents on its website. Quantity of information, however, does not equate to quality of information. And the section 307(d) criteria are not met if the Agency's explanation for its proposed rule is confusing and overly complicated, prompting numerous inquiries as to the methodology that the Agency used and policy choices the Agency made before arriving at the approach it took in its proposal. [EPA-HQ-OAR-2009-0491-2864.1, p. 7]
In the case of the Proposed Transport Rule, EPA has failed to meet its Clean Air Act section 307(d) obligation to provide to the public a clear statement of the methodology that the Agency used and policy choices it made in developing its proposal. Specifically, in order for Southern Company to be able to comment meaningfully on EPA's proposal, it was necessary for us to not only to review the proposal and supporting documentation but also to have at least eight, sometimes lengthy, conversations with Agency personnel and to devote over IOO-person hours in analyzing and developing an adequate understanding of the Agency's documentation to be able to replicate their methodology, on just the so-called Air Quality Assessment Tool alone, not to mention the effort required to understand and replicate EPA's emissions allocation methodology. This Tool is crucial for reproducing the derivations of the provisions of the rule, yet EPA would not release a copy of the Tool. While we sincerely appreciate the assistance we obtained from EPA staff to obtain the underlying data sets and to explain the methodology, such extraordinary efforts should not be required of public commenters in order to begin the process of understanding the Agency's methodology. Yet it took this extraordinary effort and individual attention before Southern Company could begin making the calculations needed to prepare the extensive spreadsheets that in turn allowed us to prepare a coherent -- and much shorter -explanation of the methodology that EPA appears to have used to both develop its proposal and then choose between the numerous policy alternatives. In essence, Southern Company had to spend an inordinate amount of time to re-create the AQAT and replicate EPA's methodology. And it was only at that point in the process that it was possible for Southern Company to begin to be able to provide a meaningful response to EPA's proposal, including recommendations for alternative approaches that might achieve virtually the same results in a more cost-effective way. [EPA-HQ-OAR-2009-0491-2864.1, pp. 7-8]
The short comment period offered for comments on the Agency's extremely complex proposal means that Southern Company is unable to offer today as detailed an analysis as it would like of the Proposed Transport Rule. And we believe that if it was this difficult for us to parse through all the data in order to start to figure out the true basis for the Agency's proposal, then it was likely more difficult for those that do not have the resources that Southern Company has. With that in mind, Southern Company is submitting key parts of its analysis in the comments it is filing today, including draft versions of its background analysis and spreadsheets (see Attachments D, E, and F, filed separately due to file size limitations). Southern Company will subsequently submit to EPA cleaned-up versions (e.g., fixing labeling errors) of these background analysis and spreadsheets -- both to get EPA feedback on whether the spreadsheets reflect accurately the methodology that EPA followed and to provide a good illustration of the tremendous efforts that had to be taken in order to begin to understand EPA's unwieldy proposal. [EPA-HQ-OAR-2009-0491-2864.1, p. 78]
Now that Southern Company believes it is finally coming to understand the Agency's methodology in developing the Proposed Transport Rule, Southern intends to continue to evaluate and provide additional comments on a broader range of approaches that EPA could have -- and should have -- offered for comment. Southern Company urges EPA to make more of this information available to others and to allow a formal and more extensive comment period upon the methodology that the Agency used and policy choices the Agency made before arriving at the approach it is now taking in its Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2864.1, p. 8]
Southern Company will also be submitting comments on EPA's Notice of Data Availability (NODA) and the underlying data that EPA made available through the NODA, which are due October 15. Because EPA has provided only a portion of the new data needed to evaluate its implications to the final rule and has declined to illustrate how it will affect the final rule, Southern Company's comments will not be complete. EPA must issue a supplemental proposed rule-with an adequate time for public comment-that includes the data and assumptions EPA plans to rely on in the final rule. [EPA-HQ-OAR-2009-0491-2864.1, p. 8]
State of Louisiana, Department of Environmental Quality
In addition, due to data and modeling issues that EPA recognized early in the Transport Rule proposal, they issued a Notice of Data Availability (NODA) for the Proposed Transport Rule, Docket ID No. EPA-HQ-OAR-2009-0491. It is unclear why EPA has been so adamant about not extending the comment period on the Transport Rule when the comment period on the NODA will run until October 15, 2010. Information gathered during the NODA comment period is expected to have a significant impact on the model results and ultimately the final form of the Transport Rule. [EPA-HQ-OAR-2009-0491-2655.1, p.6]
State of Missouri Department of Natural Resources
On September 1, 2010, U.S. Environmental Protection Agency (EPA) issued a Notice of Data Availability with new data and modeling to be used in the Transport Rule when it is finalized. Missouri requests an extension of the public comment period to at least November 30, 2010 for both the proposed rule and supplemental data. [EPA-HQ-OAR-2009-0491-3806, p.1]
State of Ohio Environmental Protection Agency (Ohio EPA)
Ohio EPA is still reviewing the corrected data from U.S. EPA's September 1, 2010, 'Notice of Data Availability Supporting Federal Implementation Plans To Reduce Interstate Transport of Fine Particulate Matter and Ozone' [75 FR 53613] and will submit additional comments by the October 15,2010 deadline. Ohio EPA has already identified a number of concerns and errors related to assumptions in the latest modeling platform. In its Notice, U.S. EPA acknowledges that these changes resulting from the updated model could impact the final rulemaking in a number of ways, including changing the emission projections that were used to determine which downwind areas have air quality concerns, which states contribute to those problems, and/or changing cost and emission projections used in the multi-factor test to determine the amount of emissions that represent significant contribution. In turn, these changes will likely impact budget allocations. Ohio EPA is extremely concerned that given these data changes, additional concerns may arise when the final rule is promulgated, albeit with no meaningful opportunity for comment. Ohio EPA requests U.S. EPA to provide additional opportunities for notice and comment on the final data changes, including state budgets and allocations to specific units, prior to finalizing the Transport Rule. [EPA-HQ-OAR-2009-0491-2793.2, pp. 11-12]
Lastly, this proposal is undoubtedly one of the most technically extensive proposals U.S. EPA has produced to date. We recognize it has taken significant resources and . time for U.S. EPA to develop this proposal in an attempt to address the court remand of CAIR. However, Ohio EPA has found it difficult to sift through the thousands of pages of documentation in the time provided for comment. Furthermore, much of the documentation is not transparent. For example, we have found documentation that states that a specific approach was used in developing part of this proposal (e.g., allocation methods) but then find when viewing the results that the specified approach was not, in fact, used. The basis for unit specific allocations, NEEDS V3.02, was updated mid-way through this comment period, to NEEDS V4.10, yet it is still riddled with errors that make it difficult to understand the methodology used and to provide meaningful comments. We urge U.S. EPA to not rush this rule process but to develop a well thought out and workable approach based on accurate data obtained by working with the states and regulated entities. [EPA-HQ-OAR-2009-0491-2793.2, p. 12]
This proposal is undoubtedly one of the most technically extensive proposals U.S. EPA has produced to date. We recognize it has taken significant resources and time for U.S. EPA to develop this proposal. But similarly, it is taking significant resources and time for those affected to also review the proposal. Ohio EPA has been working diligently on our review in order to provide meaningful comments. Ohio EPA has already identified a number of concerns and errors related to assumptions in the latest modeling platform, all of which will impact Ohio's overall comments regarding the August 2 proposal and the September 1 notice. However, additional time is needed to be able to provide those meaningful comments. We are therefore requesting that the deadline for comments be extended to October 15, 2010 for the entire Proposed Transport Rule. Ohio EPA does not believe this extension, for such an important issue, will unreasonably delay U.S. EPA's issuance of a final rulemaking. [EPA-HQ-OAR-2009-0491-3706,pp.1-2]
Sunflower Electric Power Corporation
The scope of the proposed rule is so extensive and so intricate that the time allowed by the Notice is legally and factually inadequate to provide for a full and fair review and comment by the public. EPA regulatory process, by its own description, is to be: 1) based on sound and verifiable scientific and engineering evidence; 2) provide adequate opportunity for public input which is then to be thoroughly and appropriately considered; and 3) fully and completely documented so that the basis for the rule and record is "clear and transparent". The present circumstances violate those principles in every respect. [EPA-HQ-OAR-2009-0491-2833.1 p.2]
The proposed rule covers 32 states and represents substantial changes in the regulatory construct based on extremely complex and newly developed modeling which was not even made available for review until August 2, 2010. That data was then significantly modified by the NODA issued on September 1, 2010 (75 Fed. Reg. 53,613), which also served to address some, but certainly not all, of the errors in the data on which the initial modeling, and thus the rule itself, is based. [EPA-HQ-OAR-2009-0491-2833.1 p.3]
EPA has received and denied without reasoned basis a number of requests for extension of the comment period to afford concerned parties the opportunity to fully review and consider the proposed rule and the assumptions on which it is founded. Comment 1 above is one small example of the type of errors found in the modeling on which the agency relies. [EPA-HQ-OAR-2009-0491-2833.1 p.3]
Tampa Electric Company
On behalf of Tampa Electric Company, I am writing to request that the comment period on the proposed Federal Implementation Plans to Reduce Interstate Transportation of' Fine Particulate Matter and Ozone published in the Federal Register on August 2, 2010, at 75 Fed. Reg. 45,210 be extended. Tampa Electric Company requests that the comment period be extended by not less than sixty (60) days, and preferably for ninety (90) days. The extension is necessary to ensure that all interested parties have an opportunity to review and evaluate the 256 page proposal and the extensive body of supporting information and data posted on the EPA docket for this rule making, including the extensive information posted and announced on September 1, 2010, which results, among other things, in a change in the version of the model upon which the final rule is to be based. [EPA-HQ-OAR-2009-0491-3710 p.1]
This rule making is among the most complex that EPA has ever undertaken. To understand the potential impacts and ramifications of the rule proposal, it has been necessary to review and analyze a substantial amount of data and to project the long term and short term consequences of this rule making on the ability of Tampa Electric Company and other utilities to provide electric power in a cost effective and efficient manner, as required by Florida law. Because a significant number of disciplines are involved in this undertaking, it has not been possible to conduct this in-depth analysis in the time provided. [EPA-HQ-OAR-2009-0491-3710 p.1]
It is within the discretion of EPA to grant the additional time for comment. An extension may ultimately result in a reduction in the overall time that will be necessary to complete the rule making by providing the regulated community with an opportunity to fully understand the impacts thereby potentially avoiding unnecessary comments which may have to be analyzed by EPA and potentially time consuming litigation. [EPA-HQ-OAR-2009-0491-3710 p.2]
Tampa Electric Company appreciates your favorable consideration of this request and looks forward to continuing to participate in this important endeavor. Should you have any questions concerning this request for an extension of the comment period, please contact me at 813-228-4858. [EPA-HQ-OAR-2009-0491-3710 p.2]
Despite EPA's efforts to provide technical support documents that would allow impacted parties to evaluate EPA's methods and procedures for developing the rule, the documents are not adequate to conduct a reasonable analysis and determine whether or not the foundation and results of EPA's conclusions are correct. There are apparent errors (examples cited below) that could have material impact to EPA's conclusions, but despite discussions with EPA technical staff, Tampa Electric is unable to conduct reasonable evaluations necessary to provide adequate feedback and comments to EPA in the time allotted by EPA. On September 24, 2010, Tampa Electric submitted a request for an extension of time to file comments, but have not received a response from EPA.  [EPA-HQ-OAR-2009-0491-3710 p.3]
We recognize that EPA has expressed a sense of urgency in completing the rulemaking due to concerns about the litigation in the United States Court of Appeals for the District of Columbia Circuit over the Clean Air Interstate Rule ('CAIR') and concerns relating to the attainment schedule that states are facing for the PM2.5 and ozone National Ambient Air Quality Standards ('NAAQS'). Nevertheless, as Administrator Lisa Jackson pointed out in a September 28, 2010 letter to Senator Mary L. Landrieu concerning another rulemaking, the most important task is to make sure that the final standards are right. [EPA-HQ-OAR-2009-0491-3710 p.3]
This is an enormously complex proposal covering 256 pages in the Federal Register. The docket is packed with technical information that requires analysis and some of that information has only recently been released. The analysis of the various proposals and the alternatives and the potential impacts on the Tampa Electric Company system and its customers requires input from a large number of disciplines and many man hours. Tampa Electric Company simply has not been able to perform all of the required tasks within the time allotted due to the complexity and volume of materials to be reviewed, the press of other duties and the need to respond to other regulatory undertakings.  [EPA-HQ-OAR-2009-0491-3710 p.3]
To ensure that all involved have a full and fair opportunity to thoroughly consider and analyze the proposals and to effectively comment on the proposals, and to allow a full opportunity for the regulated community to assist EPA in this effort, we request that EPA reconsider its earlier position and extend the comment period for 60 to 90 days. Since CAIR remains in place this modest extension should create no issues.  [EPA-HQ-OAR-2009-0491-3710 p.3]
Texas Chemical Council
  TCC respectfully requests that EPA grant a ninety (90) day extension of the public comment period on the proposed Clean Air Transport Rule and associated Federal Implementation Plans. Many TCC members have cogeneration facilities that will be impacted by the rule, and TCC is analyzing the complexities of the proposal, including the technical support documents, the allocation table and the recently released modeling. TCC intends to file formal comments on the rule proposal, but requests a 90-day extension in light of its complexity and length. [EPA-HQ-OAR-2009-0491-1891.1,p.1]
Texas Commission on Environmental Quality
At this time, the TCEQ respectfully requests that the EPA grant a ninety (90) day extension of the public comment period on the proposed rule. TCEQ staff is analyzing technical support documents, reviewing the allocation table provided, and comparing lists of electricity generating units (EGU) from the integrated planning model runs to ensure accurate accounting for Texas EGUs. The TCEQ intends to provide formal comment on the proposed rule at a future date; however, the length and complexity of the proposal and the technical support information will require additional time for review in order to assess specific impacts for Texas and provide meaningful comment regarding the program and the proposed alternatives. [EPA-HQ-OAR-2009-0491-0129.1, p.1]
The TCEQ is currently devoting considerable resources to the evaluation and implementation of a number of new air quality rules, including the multiple National Ambient Air Quality Standard revisions. In order to allow for high quality work on all such projects, as well as to provide the EPA with valuable analysis and comment on this important air quality initiative, a comment period extension is essential. [EPA-HQ-OAR-2009-0491-0129.1, p.1]
First and foremost, the TCEQ believes this rule and the assessment of its applicability to Texas are fundamentally flawed, as indicated in the following comments. However, in light of the unreasonable timeline that the EPA is now implementing through its failure to propose this rule in a reasonable timeframe to allow for full and meaningful public participation and transparency, the TCEQ anticipates that the EPA will proceed with the promulgation of this rule. Therefore, the TCEQ offers specific comments to improve the understandability, purpose, transparency, usability, and legality of any final transport rule. [EPA-HQ-OAR-2009-0491-2857.1, p.1]
The TCEQ reiterates its August 3, 2010, request for a 90-day extension of the comment period to ensure adequate review of this complex, lengthy proposal and to ensure meaningful detailed comments [EPA-HQ-OAR-2009-0491-2857.1, p.1]
The EPA should extend the comment period for the proposed Transport Rule by at least 90 days. The 60-day comment period is insufficient to provide thorough and meaningful comments based on an in-depth review and analysis of the proposed Transport Rule. The Federal Register publication (75 FR 45210) of the proposed rule is 257 pages, with over 900 pages of technical support documents, and an additional 31.5 MB of Excel data files. Given the complexity and volume of relevant materials and the multiple program areas affected, it is impracticable for the EPA to expect detailed specific comments (and the necessary quality assurance review) within the extremely limited comment period provided. The 60-day comment period allows only a very cursory review of the proposed Transport Rule, leads to a less-than-desirable level of transparency and peer review, and undermines confidence in the process. Consequently, at this time, the Texas Commission on Environmental Quality (TCEQ) is only able to provide preliminary comments based on a cursory review. If the EPA seeks detailed and meaningful public input and technical comments, the comment period should, at a minimum, be extended at least 90 days past the October 1, 2010, deadline to allow stakeholders to perform a more detailed review of the volumes of relevant information and to comment on problematic issues associated with the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2857.2, p.1]
The EPA has not provided adequate notice or time for the states to develop proper information to accurately account for local non-EGU controls. The EPA indicates that whether any local non-EGU controls are included in the final rule depends on the SIP revisions made available and the control measures being provided to the EPA in a manner that EPA can apply to its inventories (Emissions Inventory Technical Support Document, page 11, Docket ID No. EPA-HQ-OAR-2009-0491-0050). A 60-day comment period is inadequate for states to develop control files that match to the EPA's emissions inventory or to complete the spreadsheet provided by the EPA for states to input local controls. Since the EPA is not proposing to regulate the non-EGU sector with this rulemaking, the EPA should not bind states to the comment period restriction of the Transport Rule proposal. [EPA-HQ-OAR-2009-0491-2857., p.13]
Utility Air Regulatory Group (UARG)
The purpose of this letter is to request, on behalf of UARG, an extension of the public comment period by 60 days, to November 30, 2010. [EPA-HQ-OAR-2009-0491-0168.1, p.1]
UARG is a voluntary, not-for-profit group of electric utilities, other electric generating companies, and national trade associations. UARG's purpose is to participate on behalf of its members collectively in EPA's rulemakings under the Clean Air Act and other proceedings that affect the interests of electric generators and in related litigation. [EPA-HQ-OAR-2009-0491-0168.1, p.1]
The Proposed Transport Rule is one of the most extensive and complicated rules EPA has ever proposed under the Clean Air Act. As proposed, the rule would significantly affect the electric generating industry. Accordingly, UARG and its members have been reviewing the proposed rule with great interest. [EPA-HQ-OAR-2009-0491-0168.1,p.1]
The Proposed Transport Rule's length and complexity make it virtually impossible for UARG and its members to complete a comprehensive review and analysis of the proposed rule and the many technical supporting documents and data files that EPA has developed for this rulemaking, and then to prepare and submit meaningful, detailed comments on the proposed rule, in the period EPA has allowed. The proposed rule and its preamble alone fill over 250 three-column pages of the Federal Register. In addition, EPA's technical support documents total several hundred additional pages in length, and EPA's modeling documentation and output information are also quite lengthy. Given the nature and method of presentation of the information in the Federal Register notice and the support documents, commenters must undertake a time-consuming review even to begin to understand how that information may support, or does not support, various elements of EPA's proposal. [EPA-HQ-OAR-2009-0491-0168.1,p .2]
Moreover, based on their review thus far, UARG and its members are concerned that in developing the proposed emission control requirements, EPA may, for example, have made inaccurate or ill-founded assumptions and determinations with respect to certain individual electric generating units or categories of such units, and unrealistic or otherwise incorrect assumptions about emission controls and other critical factors. Understanding these issues and problems and their importance in the rulemaking, and then preparing meaningful comments on them -- as well as comments on broadly applicable issues such as the asserted legal basis for and structure of the proposed rule -- will require significantly more time than EPA has allowed in the current comment period. [EPA-HQ-OAR-2009-0491-0168.1, p.2]
UARG notes that at least some of the problems that appear to underlie key aspects of the proposed rule might have been avoided or mitigated if, in advance of publication of a proposed transport rule, EPA had (1) issued an advance notice of proposed rulemaking for public comment and (2) allowed stakeholder and public review of EPA's modeling plans and analyses. At the 'listening session' that EPA held with electric utility industry stakeholders on April 17, 2009, UARG specifically recommended that EPA take both of these steps. See CAIR Remand Issues: Principles that Should Guide EPA's Upcoming Rulemaking -- The Perspective of the Utility Air Regulatory Group, at 2 (Apr. 17,2009). Although UARG appreciated the opportunity at that time to offer its views on procedural and substantive matters concerning development of a proposed transport rule, it is disappointing -- and especially so in light of the apparent problems with the proposed rule as published -- that EPA neither granted UARG's request nor provided any other opportunity for utility industry review of and input on EPA's development of unit and emissions data and other information for the proposed rule. [EPA-HQ-OAR-2009-0491-0168.1,p.2]
UARG also notes that EPA took two years to develop the Proposed Transport Rule following the July 2008 decision of the D.C. Circuit Court of Appeals that EPA had promulgated the ' Clean Air Interstate Rule unlawfully and must replace it through new rulemaking regarding interstate transport. UARG does not refer to this fact to suggest in any way that EPA was dilatory; on the contrary, the length of time EPA took is a reflection of the extent, importance, and complexity of the many issues EPA had to address in preparing a proposed rule for public review and comment. Given the challenges it has faced, EPA should be all the more ready to recognize that parties preparing comments on these important and complex issues likewise face particularly time-consuming tasks and must be given a longer comment period if they are to have a meaningful comment opportunity. [EPA-HQ-OAR-2009-0491-0168.1, p.3]
UARG therefore respectfully requests a 60-day extension of the public comment period, to November 30, 2010. That deadline would still leave at least six months before EPA's target date of June 2011 for completion of the rulemaking, which in any event is subject to no statutory or court-ordered timetable. The extended comment deadline would permit electric utilities and others to prepare detailed comments that may be useful to the Agency in resolving in an appropriate way the many legal, policy, and technical issues raised by the proposed rule. [EPA-HQ-OAR-2009-0491-0168.1,p .3]
On August 19, 2010, I wrote to you on behalf of the Utility Air Regulatory Group ('U ARG') to request a 60-day extension of the public comment period, from October 1, 2010, to November 30, 2010, on EPA's proposed 'Federal Implementation Plans To Reduce Interstate Transport of Fine Particulate Matter and Ozone' (the 'Proposed Transport Rule'). 75 Fed. Reg. 45210 (Aug. 2, 2010). This letter reiterates and supplements UARG's August 19 request in light of EPA's publication, on September 1,2010, of a Notice of Data Availability Supporting Federal Implementation Plans To Reduce Interstate Transport of Fine Particulate Matter and Ozone (the 'NODA'). 75 Fed. Reg. 53613 (Sept 1,2010). [EPA-HQ-OAR-2009-0491-1109.1, p.1]
The NODA announces EPA's placement in the docket of this rulemaking numerous new documents and computer runs that bear directly on the Proposed Transport Rule. For example, the NODA announces EPA's placement in the docket of information on a new version of the Integrated Planning Model (IPM v4.10) that EPA is now using in this rulemaking; extensive modeling results from use of that new version; new emission inventory information; and new information on key cost and other assumptions in EPA's rulemaking analysis. The new information totals over 3,000 pages of documentation. The NODA provides a 45-day comment period, until October 15,2010, on the new information but states, without explanation, that the comment period on the Proposed Transport Rule is not extended beyond the existing October 1, 2010 comment deadline. [EPA-HQ-OAR-2009-0491-1109.1, pp.1-2]
The purposes of this letter are to request that EPA extend the comment period on the NODA to November 30,2010, as well. The new emissions inventory, new IPM modeling, new cost information, and other new data announced in the NODA are both highly complex and inextricably linked to the Proposed Transport Rule itself. These circumstances call for an extension of the comment period to November 30. In any event, it is unreasonable for EPA not to extend the comment period for the Proposed Transport Rule to be coextensive with that for the NODA. [EPA-HQ-OAR-2009-0491-1109.1, p.2]
The purposes of this letter are (1) to renew UARG's request that EPA extend the public comment period on the Proposed Transport Rule to November 30,2010. [EPA-HQ-OAR-2009-0491-1109.1,p.2]
The new information placed in the docket on September 1,2010, is of central relevance to commenters' assessment of the Proposed Transport Rule on such critically important matters as state emission budgets, unit allowance allocations, and state air quality 'linkages.' EPA acknowledges as much by stating in the NODA that the new information could affect the final rule by, among other things:
1. Changing emission projections that were used to determine which downwind areas have air quality concerns (i.e., non-attainment or maintenance) absent this rulemaking and to determine which States contribute to those problems.
2. Changing cost and emission projections used in the multi-factor test to determine the amount of emissions that represent significant contribution. [EPA-HQ-OAR-2009-0491-1109.1,p.2]
75 Fed. Reg. at 53614. Any such changes should be evaluated by EPA, and the results of EPA's evaluation should be placed in the rulemaking docket, so that UARG, its members, and the general public can understand the ramifications of the NODA information. In any event, emission sources, states, and others should not be expected to comment in a bifurcated fashion on these extraordinarily complex, interrelated matters, and certainly should not be expected to do so on such a highly compressed schedule as is represented by EPA's current October 1 and October 15 comment deadlines. [EPA-HQ-OAR-2009-0491-1109.1, pp.2-3]
For these reasons, UARG respectfully requests also that EPA extend the comment period on the NODA from October 15 to November 30,2010. As UARG noted in its August 19 letter, a November 30 comment deadline would still leave at least six months before EPA's target date of June 2011 for completion of the rulemaking, which in any event is subject to no statutory or court-ordered timetable. The extended comment deadlines would give UARG, UARG members, and others a reasonable opportunity to prepare detailed, meaningful comments that may be useful to the Agency in resolving in an appropriate way the many legal, policy, and technical issues raised by the Proposed Transport Rule and, now, by the NODA as well. [EPA-HQ-OAR-2009-0491-1109.1,p.3]
UARG respectfully renews its request for an extension of the public comment period on the Proposed Transport Rule to November 30,2010. [EPA-HQ-OAR-2009-0491-1109.1, p.3]
UARG submits these comments against a background of Agency decisions that has made participation in this proceeding exceedingly difficult. Specifically, on September 1, 2010, EPA published a separate Notice of Data Availability ("NODA") for the Proposed Transport Rule. 75 Fed. Reg. 53613. The NODA announces additional EPA modeling runs and other information that "EPA proposes to use to support the final rule," as well as "a list of further planned updates to support the final rulemaking." Id. EPA announced a separate comment period for the NODA, extending until October 15, 2010 (and may have separate comment periods for other subsequently posted information), but refused to extend the comment period for the underlying proposal. EPA's decision to maintain two separate deadlines for public comments -- one on the Proposed Transport Rule and the information posted in the docket contemporaneously with it, and another for the information released pursuant to the NODA -- makes it extraordinarily challenging to provide comprehensive comments on EPA's proposal. In addition, EPA on September 10, 2010, denied UARG's August 19, 2010 request for an extension of the comment period on the Proposed Transport Rule to November 30, 2010, and did not respond to a September 10, 2010 UARG request for a comment deadline extension to November 30, 2010, for both the proposed rule and the NODA. In light of the significant differences between the data on which EPA based (or says it based) the proposed rule and the data EPA released later pursuant to the NODA, EPA should withdraw the Proposed Transport Rule, revise it using whatever data EPA deems most appropriate (and addressing the proposed rule's many other deficiencies as discussed in these comments) and republish it for public comment with an adequate comment period. [EPA-HQ-OAR-2009-0491-2756.1, pp.6-7]
UARG notes that it plans to file additional comments on EPA's September 1, 2010 NODA and on any subsequently published EPA updates to support the final rulemaking. Because the information in the NODA is inextricably linked with information in the PTR, some of UARG's comments on the PTR necessarily relate to information associated with the NODA and UARG's comments on the NODA will be relevant to the PTR. [EPA-HQ-OAR-2009-0491-2756.1, pp.8-9]
Virginia Department of Environmental Quality (VDEQ)
VDEQ requests that the comment periods for both the proposed Transport Rule and for the NODA be extended until November 30, 2010. The amount of information provided by EPA in support of the draft Transport Rule is unprecedented, and the methodology for allocation allotment is significantly different than that used in either the NBTP or the CAIR. Reviewing the methodology for each unit within a State is time consuming but is necessary to ensure that each unit has appropriate emissions and allocations assigned in future years. Final Transport Rule requirements will affect States' ability in the near future to demonstrate compliance with important new health based NAAQS, and it will set a framework for future regulations designed to limit downwind contributions by States to other nonattainment and maintenance areas. State personnel resources have been stretched very thin due to budgetary constraints and to the volume of analytical and planning work that is currently taking place. Additional time to review and provide comment on the information will allow EPA to model future contributions using the best available data and will help ensure that the Transport Rule reduces downwind impacts in the most efficient way possible. [EPA-HQ-OAR-2009-0491-2595.1, p.3]
VDEQ requests that the comment periods for both the proposed Transport Rule and for the NODA be extended until November 30, 2010. The amount of information provided by EPA in support of the draft Transport Rule is unprecedented, and the methodology for allocation allotment is significantly different than that used in either the NBTP or the CAIR. Reviewing the methodology for each unit within a State is time consuming but is necessary to ensure that each unit has appropriate emissions and allocations assigned in future years. Final Transport Rule requirements will affect States' ability in the near future to demonstrate compliance with important new health based NAAQS, and it will set a framework for future regulations designed to limit downwind contributions by States to other nonattainment and maintenance areas. State personnel resources have been stretched very thin due to budgetary constraints and to the volume of analytical and planning work that is currently taking place. Additional time to review and provide comment on the information will allow EPA to model future contributions using the best available data and will help ensure that the Transport Rule reduces downwind impacts in the most efficient way possible. [EPA-HQ-OAR-2009-0491-2595.1, p.3]
West Virginia Department of Environmental Protection
The West Virginia Department of Environmental Protection (WV DEP) respectfully requests an extension of the public comment period on EPA's proposed Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone ; Proposed Rule, as published at 75 FR 45210, 02 AUG 2010. EPA announced a 60-day public comment period on the proposed rule, requiring comments to be submitted by October 1, 2010. WV DEP is requesting an extension of the public comment period by 60 days, to November 30, 2010. [EPA-HQ-OAR-2009-0491-2057, p.1]
West Virginia believes that because the amount of information contained in the preamble, the rule and the technical support documents is both voluminous and complex, the original 60 day comment period is a totally inadequate amount of time to conduct a thorough review. The WV DEP has begun this daunting process and has encountered great difficulty in reconstructing EPA's methodology. Moreover, we have already discovered several significant errors in the proposed allocations which indicates that other substantive problems remain undiscovered in documentation that we have yet to review.  [EPA-HQ-OAR-2009-0491-2057, p.1]
The length and complexity of the proposed Transport Rule, in conjunction with the numerous technical documents and data files that EPA has developed and relied upon to develop the proposal, make preparing and submitting meaningful constructive comments in the allotted time frame virtually impossible. An extension of the comment deadline will allow the WV DEP to prepare detailed constructive comments that may be useful to the EPA in finalizing this rule. [EPA-HQ-OAR-2009-0491-2057, p.2]
WV DEP and other state agencies are currently devoting significant resources to evaluating and implementing many new and proposed air quality rules, including multiple revisions to the NAAQS, new rules implementing GHG permitting requirements and new MACT standards. These same resources are also the ones that would be utilized to provide the detailed analyses and provide constructive comment on this proposal, therefore an extension of the comment period is essential. [EPA-HQ-OAR-2009-0491-2057,p.2]
Given that the Clean Air Interstate Rule (CAIR) is still in place, we do not believe there will be any environmental harm caused by extending the comment period on the proposed Transport Rule and the NODA until November 30, 2010, to allow for a proper review of the technical information and the development of constructive comments for how the proposal can be improved . We urge EPA to grant this extension and provide adequate time for meaningful feedback. [EPA-HQ-OAR-2009-0491-2057, p.2]
West Virginia believes that because the amount of information contained in the proposed Transport Rule preamble, proposed rule text, and technical support documents are both voluminous and complex, the sixty day comment period is an inadequate amount of time to conduct a thorough review. WVDAQ has encountered difficulty in reconstructing EPA's allocation and budget methodology. Moreover, we have discovered several significant errors in the proposed allowance allocations which may be an indicator that other substantive problems may remain undiscovered in documentation that has yet to be thoroughly reviewed. [EPA-HQ-OAR-2009-0491-2790, pp. 7-8]
Subsequent to the proposed Transport Rule, EPA released a Notice of Data Availability (NODA), which contains a substantial amount of additional information directly related to the proposed Transport Rule. EPA allowed only forty-five days for review of the NODA, thirty days of which are concurrent with the review of the proposed Transport Rule. The length and complexity of the proposed Transport Rule, in conjunction with the numerous technical documents and data files that EPA has relied upon to develop the proposal, make preparing and submitting detailed and constructive comments in the allotted time difficult. The issuance of the NODA (which contains new data and modeling results) demonstrates that EPA has acknowledged inaccurate or flawed data in the initial development of the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2790, pp. 7-8]
WVDAQ believes that EPA should evaluate and summarize the new data contained in the NODA, and the updated evaluation and summary should be placed in the rule-making docket so that states, affected sources and the general public can better understand the ramifications of the new information. It is apparent that comments prepared by states regarding data and modeling for the Transport Rule may need reevaluation in light of the new data contained in the NODA. [EPA-HQ-OAR-2009-0491-2790, pp. 7-8]
In a letter dated September 21,2010, WVDAQ requested an extension of the comment deadline on the proposed Transport Rule and the NODA until November 30, 2010 to allow for a more thorough review of new technical information and development of detailed, constructive comments that may be useful to EPA in finalizing the proposed rule. Because EPA has not extended the comment deadline, WVDAQ will submit time-constrained comments on the Transport Rule Notice of Data Availability by October 15,2010. [EPA-HQ-OAR-2009-0491-2790, pp. 7-8]
Westar Energy, Inc.
On behalf of Westar Energy, Inc., this letter is to request an extension of time to provide comments on the 'Clean Air Transport Rule,' 75 Fed. Reg. 45210, and on the 'Notice of Data Availability,' 75 Fed. Reg. 53613. Currently, comments on the Rule are due October 1, and comments on the NODA are due October 15. We request an extension to allow the filing of a single set of comments on both aspects of the rulemaking, to and including November 30, 2010. [EPA-HQ-OAR-2009-0491-1924.1, p.1]
As noted in the docket, the proposal for rulemaking is based on complicated modeling as to the upwind sources that are contributing significantly or interfering with the maintenance of downwind sites. Because the proposed rules will have significant service, cost, logistical, construction, and operational impacts on Westar and affected electric generating units (EGUs), We star has undertaken to analyze the modeling used in the rulemaking. The publication of the NODA has severely impacted that analysis. Since EPA did not conduct modeling in support of the NODA, any attempt to understand how the NODA will impact the conclusions that EPA reached prior to the NODA requires the input of the NODA data set into the modeling. Due to the complexity of the modeling, inputting and analyzing that new data and its impact will take a matter of weeks to complete. In addition, other new data was received from EPA on September 14, correcting a corrupt model-ready emissions file. Currently, and despite Westar's best efforts, it appears that it will be extremely unlikely, if not impossible, to incorporate the new data into the modeling in a timely fashion that will allow Westar to file comprehensive and meaningful comments which should be considered by EPA. [EPA-HQ-OAR-2009-0491-1924.1, pp.1-2]
Westar and other EGUs in states identified for the first time by EPA as subject to the proposed Air Transport Rule, face an especially difficult burden to prepare and file comments as to the potential impacts that the Rule will have on them. In contrast to EGUs in states previously subject to clean air transport rules, Westar and other EGUs in 'first time states' have no historical basis on which to ground their analyses, nor were they invited to 'listening sessions' as to what direction EPA proposed to take in the rulemaking docket to which other stakeholders from states previously subject to clean air transport regulations were invited. [EPA-HQ-OAR-2009-0491-1924.1, p.2]
We star is currently working to understand the full significance of the proposed rule to Westar and other EGUs in the State. Through EPA's docket, Westar has obtained and is reviewing EPA's background documentation including modeling information. As a result of the new information in the NODA, these efforts have been hampered by creating a 'moving target' that impedes these efforts to evaluate the applicability and potential impacts of the proposed rules on Kansas and Westar. [EPA-HQ-OAR-2009-0491-1924.1, p.2]
These issues have created an almost impossible situation for We star to respond in a full and meaningful manner by the current October 1 and October 15 deadlines, particularly given We star's and Kansas' status as 'first time state' affected by the proposed rule. In addition, the rulemaking record would be better served by a single set of comments that address comprehensively the new and old data. To assure a full and meaningful comment period consistent with statutory and regulatory intent, additional time to comment is appropriate. Accordingly, Westar requests that EPA replace the current comment dates and grant an extension to and including November 30,2010 for a single set of comments to address all matters raised by the original Notice and the NODA. [EPA-HQ-OAR-2009-0491-1924.1, p.2]
COMPLEXITY OF THE MODELING DATA AND DATA GAPS FAILS TO PROVIDE FOR MEANINGFUL COMMENT AND IS THUS PREJUDICIAL TO THE PARTIES [EPA-HQ-OAR-2009-0491-2757.1, p.5]
The modeling that EPA conducted in support of the Rule was complex and involved a significant number of processing steps which generated a large amount of electronic data. While much of the electronic data was made available upon request shortly following publication of the Rule, the data provided was not sufficient to conduct a full data verification analysis of EPA's modeling effort. The data contained some corrupt or otherwise unusable files and did not contain all of the files needed for a full review. EPA did not place all of its modeling information in the docket or make the information readily accessible in a form which enabled Westar and other affected parties to perform a full verification analysis of the data which EPA relied upon for the Rule, or verify the accuracy of EPA's statements in the Rule regarding the findings and conclusions from the modeling. Only after repeated requests to EPA did Westar obtain electronic information in EPA's possession that made it possible to do a verification analysis. Although EPA cooperated in providing usable files to replace the files which were corrupted or unusable, and also provided additional files needed for a full data verification of EPA's work when requested, the delay caused an already aggressive comment period deadline to become even more aggressive and unworkable. This failure by EPA to provide a comprehensible explanation of its modeling decisions and results, and the piecemeal disclosure of information relevant to the modeling is not consistent with applicable law. In addition, the late entry of the NODA data and EPA's failure to use the NODA date to perform a new analysis of important decisions including the applicability modeling, analysis of the elimination of the significant contribution of each state, or modeling of control cases and other factors important to the outcome of which states are to be included in the Rule and which EGUs are to reduce emissions, create an impossibility in understanding the impact of the Rule on Westar and other parties. [EPA-HQ-OAR-2009-0491-2757.1, pp.5-6]
In any event, the introduction of new pivotal data this late in the rulemaking process without providing a reasonable extension to allow parties time to respond to the new information prejudices parties seeking to provide meaningful comment in violation of 5 U.S.C. § 553(c). As the NODA makes clear, the newly available data concerns the database showing 'unit level characteristics of the electric generating units (EGUs) included in the IPM modeling' as well as the new base case modeling runs that address compliance issues and the preferred policy options. 75 FR at 53614/2. All of those are critical components of the rulemaking analysis, and changes to any of them could affect the scope and reach of the final rule. Where EPA 'provides entirely new information critical to [its] determination,' Community Nutrition Inst. v. Block, 749 F.2d 50,57-58 (D.C. Cir. 1984), EPA must provide the opportunity for meaningful comment. Portland Cement Ass 'n v. Ruckelhaus, 486 F.2d 375,393 (D.C. Cir. 1973). This requirement is mandatory to ensure that agency regulations are tested through exposure to public comment, to afford affected parties an opportunity to present comment and evidence to support their positions, and thereby to enhance the quality of judicial review.' Chamber of Commerce v. SEC, 443 F.3d 890,900 (D.C. Cir. 2006)(citation omitted). [EPA-HQ-OAR-2009-0491-2757.1, pp.6-7]
The present situation does not allow for the 'genuine interchange' that notice-and-comment rulemaking is designed to achieve. & P Co. v NRC, 673 F.2d 525, 530 (D.C. Cir. 1982). Even accepting arguendo EPA's view that the 45-day period set in the NODA was adequate, the actual time for analysis and comment after usable files finally became available of less than half that period is grossly inadequate. [EPA-HQ-OAR-2009-0491-2757.1, p.7]
The parties are prejudiced by the inadequate comment period as well as by the indication 'additional information used to support the final transport rulemaking may be placed in the docket' at unspecified future date(s). 75 FR at 53615/1. As the NODA encapsulates, the new data relate to key databases and modeling runs, id. at 53614/2, and could produce different results from those contained in the Rule. Parties must be allowed to determine whether such differences are present, and what effect they have on the various aspects of proposed rule. See Small Refiner Lead Phase-Down Task Force v. EPA, 705 F.2d 506, 540-41 (D.C. Cir. 1983)(prejudice requires specific showing of the 'portions of the documents [a party] objects to and how it might have responded if given the opportunity'). [EPA-HQ-OAR-2009-0491-2757.1, p.7]
Meaningful comment in this context thus means the ability to determine what documents (new data files) raise objections and what response is appropriate to those objections. Here, that process could not even begin until the corrupted computer files were purged and replaced with usable files, which took the better part of a month to accomplish. Assuming that all the necessary computer files have been made available, the modeling runs involved in replacing the original data with these new data take considerable time and effort. Only at that point can the process of determining objections and developing responses begin. Given the amount of data, the complexity of the issues, and the consequences related to the model results, far more time than the 45-day period set in the NODA, or the actual 20-day period after the data were finally made available in usable form, would be needed to permit meaningful comment. EPA's failure to provide adequate time prejudices the parties by not allowing them to present specific comments on pivotal matters, and therefore is arbitrary and capricious. See Appalachian Power Co. v. EPA,249 F.3d 1032, 1059 (D.C. Cir. 2001) (agency action is arbitrary and capricious where agency has failed to respond to specific challenges that are sufficiently central to its decision'). [EPA-HQ-OAR-2009-0491-2757.1, p.8]
Xcel Energy Inc.
3. EPA should reissue the rule for public comment as a Supplemental Notice of Proposed Rulemaking after completing additional modeling.
Xcel Energy strongly suggests that EPA allow a second comment period once EPA incorporates this round of comments and promulgates the next allocations in early 2011. If, as appears to be the case, the new modeling runs lead to substantially different state budgets and company impacts, EPA should reissue the rule for public comment as a Supplemental Notice of Proposed Rulemaking. [EPA-HQ-OAR-2009-0491-2728.1, p.12]
Response: 
EPA would like to thank commenters for their feedback and suggestions.  Many commenters criticized EPA's timeframe for issuance and implementation of the Transport Rule.  Although the Court did not specify a definitive date by which EPA should promulgate the Transport Rule, it emphasized the importance of completing the rule to replace CAIR in a timely manner. 
EPA complied with all requirements relating to the length of the comment period for this action.  This rule is subject to the requirements of section 307(d) of the Clean Air Act as it is "the promulgation or revision of an implementation plan by the Administrator under section 7410(c) of this title."  42 U.S.C. § 307(d)(1)(B).    Section 307(d)(5) of the CAA requires the Administrator to allow any person to submit written comments, data, or documentary information and to give all interested persons an opportunity to present their views orally.  In addition section 307(d)(5)  requires that, when a public hearing is held, EPA keep the record for the rule open for thirty days after completion of the public hearing. EPA complied with all such requirements and provided at least 15 days notice of the public hearings which is deemed sufficient pursuant to section 1508 of the Federal Register Act.  44 U.S.C. § 1508. 
EPA posted the signed version of the Proposed Transport Rule to the web when it was signed on July 6, 2010.  The proposal was published in the Federal Register on August 2, 2010.  EPA held three public hearings on the rule on August 19, 2010 (Chicago, IL), August 26, 2010 (Philadelphia, PA), and September 1, 2010 (Atlanta, GA) and the public comment period closed on October 1, 2010.  The comment period was thus open for 60 days from the date of publication in the Federal Register and 90 days from the date the rule was widely disseminated to the public via publication on the web.  EPA posted the signed version of the first Transport Rule Notice of Data Availability (NODA) (IPM) to the web when it was signed on August 25, 2010.  The first NODA was published in the Federal Register on September 1, 2010, and the public comment period closed on October 15, 2010.  The comment period was open for 45 days from the date of publication in the Federal Register and 52 days from the date the NODA was widely disseminated to the public via publication on the web on August 25, 2010.  The second NODA (addressing emissions inventories) was published in the Federal Register on October 27, 2010 and the public comment period closed on November 26, 2010.  The comment period was open for 30 days from the date of publication in the Federal Register (and was widely disseminated to the public via publication on the web at the same time).  The third NODA (allocations and related matters) was published in the Federal Register on January 7, 2011 and the public comment period closed on February 7, 2011.  The comment period was open for 30 days from the date of publication in the Federal Register and 38 days from the date the NODA was widely disseminated to the public via publication on the web on December 30, 2010.  These comment periods for the Proposed Transport Rule were equivalent to the comment periods provided by EPA for other major rules (Proposed Clean Air Interstate Rule and Proposed Mercury and Air Toxics Rule - each with 60-day comment periods).
EPA provided an adequate opportunity for public comment on the proposal and all three NODAs.  As noted above, EPA complied with all statutory requirements regarding the length of the comment period.  EPA also received several hundred substantive comments during the comment period.  Many of these contained detailed data and analyses.   The volume and depth of the comments received suggests that the opportunity for public comment was adequate.  The fact that more comments could have been provided had the comment periods been extended, does not establish that the comment period was inadequate or not consistent with the procedural requirements of section 307(d).    EPA is mindful both of its obligation to provide an opportunity for public comment and of its obligation to proceed with this rule in a timely manner.
EPA disagrees with the comments to the extent they challenge EPA's overall regulatory approach.  The rational for the approach selected is explained in detail in the preamble to the final rule, specifically in section VII, explains the design of the Agency's overall regulatory approach and section XII.A of the preamble explains how the Transport Rule will impact the power generation sector (e.g., utility rate payers).  Section VII.D of the preamble explains the methodology for allocating allowances used in the final rule. 

XVIII. [Reserved]

XVIII.A. [Reserved]

XVIII.B. [Reserved]

XVIII.C. Approach to Future EGU (Power Sector) Emission Projections

Organization: American Electric Power
Comment: 
The MOG commissioned Alpine Geophysics to perform regular CAMx simulations that examined a 2008 base case along with as business as usual cases for 2014 and 2018. In this exercise, the business as usual case follows the D.C. Circuit's determination in the North Carolina case to keep the current CAIR program fully in effect as promulgated until such time as EPA corrects the errors the court found in that rule. That modeling shows similar or better results than the Proposed Transport Rule results in terms of attaining and maintaining the 1997 ozone and PM-2.5 and 2006 PM-2.5 NAAQS, using essentially similar emission inventories. [EPA-HQ-OAR-2009-0491-2665.1, p.3]
The MOG modeling shows that by 2018 nearly all areas will be in attainment with the current ozone standard of 75 ppb, not the 85 ppb level used by EPA, with the exception of areas that are part of or adjacent to highly urbanized areas (Bucks County, Pennsylvania, Suffolk County, New York, and Harford County, Maryland). The same can also be shown for PM-2.5 where all but two monitors (Allegheny County, Pennsylvania and Brooke County, West Virginia) that have significant local source impacts are also shown to meet the 35 ug/m3 standard by 2014 and several other monitors that are close to the limit are significantly impacted by urban emission and have a signature indicative of local source impact (high organic carbon levels) and will not be significantly aided by the reductions from these rules. AEP urges EPA to provide a properly-formulated analysis that demonstrates to the D.C. Circuit that emissions' trading in a regional transport solution is technically supported. The modeling submitted by MOG provides a technical demonstration, absent from the record before the court in the North Carolina case, that the emissions trading in the currently-effective CAIR program meets the transport mitigation goals of section 110(a)(2)(D)(i)(l) of the Clean Air Act. [EPA-HQ-OAR-2009-0491-2665.1, p.3]
Flawed Methodology - The bottom-up methodology used to analyze the impacts of the rules and to determine the degree to which reductions are needed at specific power plants is seriously flawed. At a minimum, EPA must consider the impact of reductions under already existing programs on air quality and not rely on outdated studies of air quality effects to determine necessary actions. Further, EPA must accurately evaluate the cost-effectiveness of controls on utility power plants considering the actual remaining lifetimes of many units is much less than 20-30 years assumed by EPA. EPA must also consider alternative reduction options from industrial and transportation sources which will likely achieve much greater and more cost -effective air quality improvements (both per ton reduced, and even more so per ppb of ozone or PM-2.5 reduced). [EPA-HQ-OAR-2009-0491-2665.1, p.4]
Comparison Modeling Supports Attainment using the existing CAIR Regulations
MOG and its Industrial Modeling Coalition commissioned Alpine Geophysics to perform regular CAMx simulations that examined a 2008 base case along with as business as usual case for 2014 and 2018. In this exercise, the business as usual case takes the correct legal interpretation of the final order of the DC Circuit Court of Appeals in the CAIR case that the rule is still fully in effect as promulgated until such time as USEPA corrects the errors the court found in that rule. In examining that modeling, the results show similar or better results than the Proposed Transport Rule results, with essentially similar emission inventories based on different base years. [EPA-HQ-OAR-2009-0491-2665.1, pp.14-15]
USEPA has also failed to recognize that its existing rules and programs for interstate nonattainment areas apply to several of the previously referenced counties that are shown to not reach attainment. These processes, which have been in existence for at least 20 years call for the states directly involved in the nonattainment area to work together to solve the issue. A transport rule helps these areas be assured that the problem is indeed local, and the analysis above shows that this criteria is met. [EPA-HQ-OAR-2009-0491-2665.1, p.15]
The MOG modeling shows that by 2018 nearly all areas will be in attainment with the current ozone standard of 75 ppb, not the 85 ppb level used by USEPA, and with the exception of areas that are part of or adjacent to highly urbanized areas (Bucks County, Pennsylvania, Suffolk County, New York, and Harford County, Maryland) or have known local issues (Allegheny County, Pennsylvania and Brooke County, West Virginia) demonstrates that the CAIR pathway with its unfettered trading, that the court ruled was not sufficiently justified, works equally well as the far more costly program proposed by USEPA in the Transport Rule. AEP supports providing a properly formulated analysis similar to that developed by MOG that would demonstrate to the Court that its concern about emissions trading in a regional transport solution is not well founded. The modeling submitted by MOG should offer a foundation for such a demonstration. [EPA-HQ-OAR-2009-0491-2665.1, p.15]
Response: 
See the Transport Rule preamble for an explanation of why EPA did not consider CAIR in its baseline, why EPA established compliance deadlines of 2012 and 2014, and why it is not considering non-EGU sources in this rulemaking.  See "Documentation Supplement for EPA Base Case v.4.10_FTransport  -  Updates for Final Transport Rule" for an explanation on why the 30 year life assumption for emission control retrofits was retained.  With respect to air quality modeling conducted by MOG, EPA's evaluation of this modeling can be found in section V.C.2 of the preamble for the final Transport Rule.
Organization: Arkansas Department of Environmental Quality
Comment: 
In Section IIl.e - Anticipated Rules Affecting Power Sector: Regional Haze Rule/Best Available Retrofit Technology ('BART') is included in the category of 'anticipated rules' when, in fact, the Regional Haze Rule and the BART Rule are already federally promulgated and state enforceable. These rules contain specific compliance deadlines that have been delayed by EPA's inability or reluctance to approve states', including Arkansas's, Regional Haze SIPs. Many of the pollutants associated with regional haze are also associated with ozone. Required reductions associated with Arkansas's Regional Haze SIP should have been taken into account for Transport Rule modeling purposes but do not appear to have been. [EPA-HQ-OAR-2009-0491-2676.2, p. 2]
EPA appears to have dismissed the quantity and effectiveness of emission reductions associated with the Best Achievable Retrofit Technology (BART) provisions of the federal Regional Haze Rule when conducting the modeling associated with the Transport Rule. ADEQ did not rely on the 'CAIR = BART' approach when establishing the BART reductions contained in the State of Arkansas Regional Haze Rule SIP. Once fully implemented, reductions in NOx, S02 and PM10 from Arkansas BART facilities will be substantial. If these reductions were taken into account in the EPA modeling, it is possible that Arkansas might not have been included in the list of states causing or contributing to downwind ozone nonattainment. For these reasons, the Transport Rule's conclusion that Arkansas significantly contributes to nonattainment or interferes with maintenance in downwind states is specious. [EPA-HQ-OAR-2009-0491-2676.2, p. 2]
Response: 

Thank you for your comments.
Organization: Midwest Ozone Group
Comment: 
2. EPA arbitrarily removed the Clean Air Visibility Rule from its 2005 base case. Although the Clean Air Visibility Rule (CAVR) was published July 6, 2005 (70 Fed. Reg. 39104), EPA removed the CAVR from its base case modeling for the proposed CATR. See TSD IPM EPA Base Case v.3.02 EISA at 13 available on the Internet at:http://www.epa.gov/airquality/transport/tech.html ("The Clean Air Visibility Rule(CAVR)...[was] removed from the baseline...."). EPA seeks to justify the removal of the CAVR, summarily stating that: "In June 2005, EPA finalized guidelines for States to use in determining which facilities must install controls and the type of controls the facilities must use to satisfy Best Available Retrofit Technology (BART) requirements to address regional haze(also known as the CAVR). Because of uncertainty regarding the precise measures and requirements States will adopt, the specific CAVR power sector assumptions that were formerly modeled in IPM have been removed."). EPA's modeling analyses use assumptions because they lack "precise measures and requirements". While some states do not yet have approved regional haze state implementation plans (SIPs), some states do. For those states that have submitted regional haze SIPs, including regulations, EPA needs to include the measures and requirements those states have adopted. Significantly the D.C. Circuit in NC v. EPA, 550 F.3d 1176, 1178(D.C. Cir. 2008) did not address the CAVR. In addition, EPA's previous regulatory determination that the CAIR satisfies EGU BART requirements was upheld by the DC Circuit in UARG v. EPA (471 F. 3d 1333, D.C. Cir. 2006). EPA's failure to include these controls in its analysis is another illustration of arbitrary and capricious assumptions in the proposed CATR. [EPA-HQ-OAR-2009-0491-2809.1, pp.4-5] 
d) Mercury controls See Emissions Inventories TSD at 12 ("[EPA] did not include Hg in our future year modeling...."). e) Aerosol Coatings: National Volatile Organic Compound Emission Standards: Final Amendments (74 Fed. Reg. 29,595, June 23, 2009). See http://www.epa.gov/ttn/oarpg/t1pfpr.html (last visited September 28, 2010). This rule reduces VOC emissions contributing to ozone formation. Id. at 29,596/3. [EPA-HQ-OAR-2009-0491-2809.1, pp.8-9]
Response: 

See IPM documentation for a list of state rules included in the IPM modeling used for the Transport Rule.  
Organization: Nederhand, Frank
Comment: 
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.128.]
Frank brings up two points that we've talked about and that's not only the scrubber technology, but it's the type of coal that's purchased. I believe that EPA has noted that importing coal from western states would be lower in sulfur and, therefore, recommended by this rule.
Frank states that the Transport Rule really needs to include the emissions reductions and the emissions and environmental impact of transporting that coal from the Powder River Basin in Wyoming. While you increase the transportation of coal from western states, what you're doing is just eliminating the cost of that. So we're paying for it because of raised fuel costs, but the utilities aren't covering the costs. So I'd like to encourage EPA to look at the transportation costs associated with hauling in this low-sulfur fuel.
Response: 
EPA IPM modeling does reflect the transportation costs of supplying coal to each modeled generator.  This is explained in the IPM documentation which describes the coal transportation network, the methodology used to assign costs to the links in the network, and a discussion of the geographic,infrastructure and regulatory considerations that come into play in developing specific rail, barge and truck transport rates.

 Organization: State of Missouri Department of Natural Resources

Comment: 
Future emissions from EGUs from Mexico and Canada need to be accounted for and not be held constant. EPA should show contribution from this sector to nonattainment and maintenance areas. [EPA-HQ-OAR-2009-0491-3806, p.3]
Response: 
EPA lacks sufficiently detailed information to determine "trends" in Canadian or Mexican emissions beyond the inventory data used in the Transport Rule air quality analyses.  EPA used the latest comprehensive available data from Canada and Mexico.  EPA does not have access to any similarly detailed and consistent emission forecasts for Canada or Mexico that EPA could integrate into the Transport Rule air quality projections.  EPA believes this rule's air quality analysis reflects the most accurate information available to account for the role of foreign emissions in air quality outcomes at the state level in the context of the Transport Rule.  EPA also believes this analytic approach allows the Agency to accurately assess each U.S. state's contributions to air quality in another U.S. state, which is necessarily the focus of the relevant Clean Air Act requirements.
 Organization: Texas Commission on Environmental Quality
Virginia Department of Environmental Quality (VDEQ)
Edison Electric Institute (EEI)
Allegheny Energy
Tennessee Department of Environment and Conservation, Division of Air Pollution Control
New York State Department of Environmental Conservation
Oklahoma Department of Environmental Quality
Electric Energy, Inc. 
we energies
Wabash Valley Power
Southern Company
NRG Energy
Environmental Energy Alliance of New York, LLC
Boston Generating
Exelon
Peabody Municipal Light Plant
Florida Electric Power Coordinating Group, Inc. (FCG)
East Texas Electric Cooperative
San Miguel Electric Cooperative, Inc.
Northern Indiana Public Service Company (NIPSCO)
PSEG Services Corporation
Ameren Services Company
Xcel Energy Inc.
Dominion
South Carolina Department of Health and Environmental Control 
Indiana Energy Association
PPL Corporation
Nebraska Public Power District
Buckeye Power, Inc.
East Kentucky Power Cooperative
E.ON U.S.
Madison Gas and Electric Company (MGE)
AES Corporation (AES)
Oglethorpe Power
Progress Energy Service Company
Sunflower Electric Power Corporation
Wisconsin Power and Light Company
Westar Energy, Inc.
EquiPower Resources Corp.
Florida Municipal Power Agency (FMPA)
Big Rivers Electric Corporation
Empire District Electric Company (Empire District)
Omaha Public Power District
Ohio Utility Group (OUG)
Prairie State Generating Company, LLC
Associated Electric Cooperative, Inc. (AECI)
Louisiana Public Service Commission
Marquette Board of Light and Power
Giarmarco, Mullins & Horton, P.C.
City of Ames, Iowa
Santee Cooper
TransCanada
Consumers Energy
Piney Creek LP
Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
Mirant Corporation
American Public Power Association (APPA)
Nelson Industrial Steam Company (NISCO)
George Washington University Regulatory Study Center
Four Flags Area Chamber of Commerce
Pfeiff, Mike
Minnesota Power 
PPG Industries, Inc.
Gulf Coast Lignite Coalition
National Mining Association (NMA)
Cleco Corporation
Duke Energy
Council of Industrial Boiler Owners (CIBO)
Northern Star Generation LLC
First Energy
Georgia Department of Natural Resources, Air Protection Branch
Luminant
Michigan Manufacturers Association (MMA)
Edison Mission Energy (EME)
DTE Energy
Indiana Builders Association 
Indiana Cast Metals Association (INCMA)
Indiana Manufacturers Association, Inc. (IMA)
Utility Air Regulatory Group (UARG)
Tennessee Valley Authority (TVA)
Comment: 
AES Corporation (AES)
EPA's assumptions regarding current unit operation and new control technology projects may be inaccurate. If such EPA assumptions are incorrect, it could make compliance difficult or impossible. Inaccurate factual inputs into the Integrated Planning Model (IPM) and erroneous modeling assumptions raise questions about the foundation of the Proposed Transport Rule. For example, EPA has made incorrect assumptions regarding individual EGUs, including in the NEEDS data base (e.g., incorrectly describing pollution control retrofits), and IPM modeling run outputs in some cases are erroneous (e.g., incorrectly projecting the fuels to be used, retirements, etc.). [EPA-HQ-OAR-2009-0491-2791, p.3] [EPA-HQ-OAR-2009-0491-3793.1_NODA, p.4]
 
For example, the AES Somerset facility is allotted NOx allowances for the NOx Annual and Ozone Season Program based upon a continuous NOx rate of 0.05 lb/mmBtu. Somerset installed an SCR in 1999 and it is evident that it will be difficult or impossible to develop and implement technology that can achieve the new, more restrictive budgets. Existing SCR technology may not allow for this limit to be met. Load following and cycling of the units during on-peak and off-peak periods requires the SCR to be taken out of service to avoid damage to equipment. Minimum flue gas operating temperatures are required to prevent fouling of the SCR catalyst and downstream equipment, especially air preheaters. Further, as more intermittent assets are introduced to the electric energy grid, the need for rapid ramp rates and flexible minimum/maximum operating levels on existing baseload facilities will become more important to supplement intermittent resources and to maintain system reliability. [EPA-HQ-OAR-2009-0491-2791, p.3][EPA-HQ-OAR-2009-0491-3793.1_NODA, p.4]

EPA assumptions include FGD retrofits and/or fuel switching to lower sulfur coal at the AES Warrior Run facilities. CFB boilers use limestone in the operation to reduce SO2 emissions and are not contemplating FGD retrofits and fuel specification changes. The allocation must be corrected to reflect actual operations and accurate emission baselines. [EPA-HQ-OAR-2009-0491-2791, p.4] [EPA-HQ-OAR-2009-0491-3793.1_NODA, p.4]

The NEEDS model assumes a NOx Policy rate of 0.06 lb/mmBtu for the AES Greenidge and AES Westover facilities. These facilities have been retrofitted with multi-pollutant control technology including baghouses, SCR and dry scrubbers but will not allow for this limit to be met. Load following and cycling of the units during on-peak and off-peak periods requires the SCR to be taken out of service to avoid damage to equipment. Minimum flue gas operating temperatures are required to prevent fouling of the SCR catalyst and downstream equipment, especially air preheaters. [EPA-HQ-OAR-2009-0491-2791, p.4] [EPA-HQ-OAR-2009-0491-3793.1_NODA, p.5]

The allocations provided for the AES Thames facility in Connecticut do not reflect reality, perhaps because AES Thames, as a Qualifying Facility (QF), is not an Acid Rain source. According to the Unit Allocation Table in the Administrative Record, the source of the SO2 data for AES Thames is reported data and the source for the NOx data is projected. Neither allocation makes sense in light of the true base case emissions for AES Thames. First, AES Thames was allocated 847 SO2 allowances in 2012 supposedly based operational data despite the fact that AES Thames reported 2298 tons of SO2 emissions in 2009. The AES Thames units already have stringent SO2 controls (flue gas desulfurization accomplished by in-bed injection of limestone reagent into the boilers for a minimum 75% SOx control efficiency), so further controls should not be required for these units for the small incremental reduction. Second, the IPM projection-based allocation for NOx is also well below historic operating levels. Actual reported emissions of NOx for the two AES Thames units was 455 tons in 2009, but the proposed allocation for the two units in 2012 is only 371 tons of NOx. Since the units are operated pursuant to contracts to sell both electricity and steam to an adjacent cardboard recycling plant beyond 2012, there is no reason to expect emissions to be significantly lower in 2012 than in prior years. Excerpts from the AES Thames emission reports for 2009 and from the facility's contracts to sell electricity and steam are attached as exhibits to this letter. [EPA-HQ-OAR-2009-0491-2791, p.4] [EPA-HQ-OAR-2009-0491-3793.1_NODA, pp.5-6]
Similar allocations are given to other contract facilities that have obligation to operate with no provision to recoup any of the additional cost for compliance [EPA-HQ-OAR-2009-0491-2791, p.4] [EPA-HQ-OAR-2009-0491-3793.1_NODA,p.6]

f. The unit level detail has several other mistakes with respect to facility details. Following are some examples and are not exhaustive. 
i. AES Ironwood shows the third unit as consuming gas, however, the third unit is the combined cycle steam turbine generator for the heat recovery from the two gas turbines. This generator does not consume fuel. This same unit is shown to have DLNB and produce emissions. The accompanying units Combustion Turbine (CT) 1 and 2 show only DLNBs but actually have SCR and CO Catalyst as well. 
ii. AES Red Oak has identical errors as the Ironwood facility above, however, Red Oak has Three CTs and one steam turbine generator.
iii. AES Greenidge Units 4 and 5 are shown to have Cold-side ESP + Cyclone + SCR + Dry Scrubbers. Only Unit 6 has this configuration. Units 4 and 5 had Cold-side ESP + Cyclone and are retired. 
iv. AES Deepwater is shown to have Cold-side ESP + Wet Scrubber. AES Deepwater actually has Cold-side ESP (Wet and Dry) + Wet Scrubber +_LNBO + SCR. [EPA-HQ-OAR-2009-0491-2791, p.4] [EPA-HQ-OAR-2009-0491-3793.1_NODA,p.6]

The fuel usage is changed for some facilities in the IPM Base case from 2012 to 2014 and other cases (positive and negative) without explanation. For instance, AES Ironwood is a gas plant in PA and shows fuel use is lowered by 36% in the base case. AES Beaver Valley is a coal plant in PA and shows an increase in fuel use by 36% in the base case. AES Deepwater is a pet coke facility in TX and shows an increase of 7% in the base case. All three changes are unlikely. Other facilities sampled show no changes in fuel use. [EPA-HQ-OAR-2009-0491-2791, p.5] [EPA-HQ-OAR-2009-0491-3793.1_NODA, pp.6-7]
Allegheny Energy
If such errors and discrepancies exist for other generating companies subject to this proposed rule, EPA's estimates of what reductions can be achieved by 2012 are significantly overstated. AE, therefore, recommends that EPA correct the errors and discrepancies in the NEEDS database, rerun the IPM, and conduct a new analysis to determine if any adjustments to implementation dates or state allowance budget allocations are warranted. Due to the significance of this data in the proposed rule, this will necessitate the rule then be re-proposed for more informed comment by affected industry. This is also driven by EPA's updating of technical support documents to the proposed rule as recently as September 1, 2010. [EPA-HQ-OAR-2009-0491-2605.1, p.6]
Ameren Services Company
Fuel switching even between lower sulfur coal within coal ranks may not be easily accomplished [EPA-HQ-OAR-2009-0491-2722.1, p.7]
Based on the allocation table supplied by EPA, the S02 emissions for Ameren's Labadie plant are reduced by 15,634 tons from 2012 to 2014. Since IPM assumes no additional add on controls and no reduction in utilization of the Labadie plant in 2014 IPM must assume a reduction in sulfur content of the coal that Labadie plant uses. This is problematic for a couple of reasons. [EPA-HQ-OAR-2009-0491-2722.1, p.7]
1) Labadie currently burns coal in the 0.7 lb S02/mmBtu range. Meeting the reduction required in 2014 would require switching to a 0.5 lb S02/mmBtu coal. There currently exist 2 mines in the Powder River Basin that can meet this low sulfur requirement, Antelope and North Antelope Rochelle Mines. However these mines are currently sold out as they have limited production. Ameren has tested lower sulfur coals from Colorado but has been unsuccessful in burning these fuels due to boiler fouling. [EPA-HQ-OAR-2009-0491-2722.1, p.7]
2) Given there is a limited supply of these lower sulfur coals and assuming there would be some availability of such coals additional costs would likely be incurred. While the exact cost of a lower sulfur coal is unknown at this time Ameren's fuel buyers estimate that there could be a surcharge as high as $5 per ton of coal received. This would mean an additional cost of $50,000,000 per year in increased operating expenditures for the Labadie plant. [EPA-HQ-OAR-2009-0491-2722.1, p.8]
3) In order to help minimize costs and keep electric rates low utilities will negotiate long term coal contracts to lock in pricing. These contracts can span up to 5 to 10 years in length. As part of these long term contracts utilities must give some assurance that they will buy a certain amount or pay a penalty. While this penalty will vary EPA has not included this potential cost adder in its IPM modeling. [EPA-HQ-OAR-2009-0491-2722.1, p.8]
EPA has apparently also ignored that going to a lower sulfur fuel may require system modifications to accommodate this fuel. For example: [EPA-HQ-OAR-2009-0491-2722.1, p.8]
1) Precipitator modifications or flue gas conditioning may be require to be installed to assure compliance with opacity and particulate standards. [EPA-HQ-OAR-2009-0491-2722.1, p.8]
2) Coal handling systems may need to be modified to handle the different coals. This could include additional dust controls as well as increased capacity to handle lower BTU coal. Based on the above issues EPA should take a closer look at the costs of fuel switching. [EPA-HQ-OAR-2009-0491-2722.1, p.8]
Use of IPM to assign allocations on a unit by unit basis is inappropriate.
IPM should not be used for the allocation of allowances on a unit basis as it is not an appropriate tool for this purpose. While IPM is a useful planning tool for looking at different control scenarios it does not contain sufficient information on each utility company and unit to make reasonable assumptions about controls or operation. Rather on a system or regional basis it can produce reasonable results. A good example of this is how it has treated Ameren's Joppa plant under the scenarios EPA has modeled. Joppa located in Massac County Illinois under the IPM 3.02 TR SB Limited Trading case is assumed to install an FGD on each unit. Under IPM 4.10 TR SB Limited Trading case IPM labels these same units as Coal Early Retirement. And under IPM 4.10 TR SB Limited Trading AEO gas case no controls are assigned and none of the units are retired. Which of these is most representative of Joppa's future destiny? [EPA-HQ-OAR-2009-0491-2722.1, p.10]
Considering how this would affect allowance allocation, under the first IPM scenario Joppa would be issued limited allowances, as IPM assumes an FGD is installed. In the second case it would be issued no allowances, as IPM is projecting Joppa to be retired. And in the third case Joppa would be issued allowances based on no controls. Based on these drastic variations in IPM results for the Joppa plant it is absurd to believe that this model has any skill for determining what the fate of Joppa's units will be under the Transport Rule as proposed. [EPA-HQ-OAR-2009-0491-2722.1, p.11]
Rather than using IPM to assign allowance allocations on the unit level EPA should consider using the units past utilization as has been done with the NOx SIP Call rule and CAIR. This is the best estimate of future utilization and produces a fair and equitable distribution of allowances. Ameren suggests in the allocation of allowances that heat input be used as this was used in the NOx SIP Call and CAIR and created a generally fair and equitable distribution of allowances. [EPA-HQ-OAR-2009-0491-2722.1, p.11]
B. Current 2007-2009 8-hour ozone design values show major inconsistencies with the results of EPA's analysis for the Transport Rule.
Table 1 below [See p.12 of this comment summary for Table 1 entitled, Summary of Current Design Values versus EPA 2014] shows a comparison of 2007-2009 8-hour ozone design values and EPA's 2014 control case for selected monitors in the eastern United States. As is evident from the table many monitors in the Midwest (i.e. Chicago, S1. Louis) and on the East Coast are already lower than what EPA predicts for its 2014 control case. Attachment A [See p.28 of this comment summary for Attachment A] contains an analysis of current air quality performed by Environ and states' ...over 80% of the sites predicted by EPA to be in nonattainment of the ozone or PM2.5 standards in 2012 are already in attainment as of 2009...'. EPA by overestimating the impact of states on downwind nonattainment and maintenance areas will tend to increase the level of control perceived to be required to meet the desired goals. This will lead to the installation controls that in reality may not be needed. EPA's base case selection and control assumptions are fatally flawed and need be re-analyzed using a more recent and relevant information. [EPA-HQ-OAR-2009-0491-2722.1, pp.11-12]
C. Current 8-hour design values show attainment of the 1997 standard [EPA-HQ-OAR-2009-0491-2722.1, p.13]
Table 2 [See p.14 of this comment summary for Table 2 entitled, Designated 1997 8-hour Ozone Nonattainment Areas 2004-2009 Design Values] below shows the design values for the current 1997 8hour ozone designated nonattainment areas included in EPA's Transport Rule analysis. [EPA-HQ-OAR-2009-0491-2722.1, p.13]
As is evident from the table all but 5 nonattainment areas in the eastern United States based on the 2007-2009 design values are attaining the 1997 8-hour standard. Out of the 5 areas in the Eastern US not currently attaining the 1997 8-hour ozone standard 1 area is at 88 ppb, 2 are at 87 ppb and 2 are at 86 ppb. [EPA-HQ-OAR-2009-0491-2722.1, p.16]
A regional transport rule over and above CAIR is not required considering the small number of areas still not attaining the 1997 8-hour ozone standard. Ozone design values for 2007-2009 at these sites are barely above the standard. [EPA-HQ-OAR-2009-0491-2722.1, p.16]
D. Modeling performed by the Midwest Ozone Group shows attainment of the 8-hour ozone standard [EPA-HQ-OAR-2009-0491-2722.1, p.16]
The Midwest Ozone Group has performed air quality modeling of 8-hour ozone levels (see comments submitted by the Midwest Ozone Group, October 1, 2010) using 2008 as the base case year. In addition the Midwest Ozone Group performed modeling for the future years of 2014 and 2018 assuming on-the-books controls and CAIR in place. [EPA-HQ-OAR-2009-0491-2722.1, p.16]
The results for 8-hour ozone modeling for 2014 and 2018 along with the actual measured 2008 (i.e. 2007-2009) design values are shown in Figure 1 [See p.18 of this comment summary for Figure 1 entitled, 2008 Design Values versus 2014 and 2018 Modeled 8-hour Ozone] for monitors exhibiting the highest 8-hour ozone concentrations. All monitors attain the 1997 8-hour ozone standard in 2014 and all but 3 attain the current 2008 standard of 75 ppb by 2018. [EPA-HQ-OAR-2009-0491-2722.1, pp.16-17]
A regional transport rule is not required as on-the-books control and full implementation of CAIR results in all but 3 monitors attaining the 2008 standard of 75 ppb. The 3 monitors that aren't as of 2018 attaining the 2008 standard are within a couple of ppb of attaining that goal. [EPA-HQ-OAR-2009-0491-2722.1, p.17]
E. Modeling performed by the Midwest Ozone Group shows attainment of the PM25 annual standard [EPA-HQ-OAR-2009-0491-2722.1, p.18]
The Midwest Ozone Group has performed air quality modeling (see comments submitted by the Midwest Ozone Group, October 1, 2010) of the PM25 annual levels using 2008 as the base case year. In addition the Midwest Ozone Group performed modeling for the future years of 2014 and 2018 assuming on-the-books controls and CAIR in place. [EPA-HQ-OAR-2009-0491-2722.1, p.18]
Figure 2 [See p.20 of this comment summary for Figure 2 entitled, 2008 Design Values versus 2014 and 2018 Modeled Annual PM25] shows the results of this modeling for the annual PM25 standard for 2014 and 2018 as well as the 2008 (Le. 2007-2009) design values for the highest PM25 annual concentration monitors. Figure 2 is a comparison of the 2008 measured annual PM25 design values and the 2014 and 2018 modeled design values. As is evident from the figure all but one monitor attains the current PM25 annual standard. Review of the individual component data for this monitor indicates that almost half of the annual concentration is from organics (see comments submitted by the Midwest Ozone Group, October 1,2010) meaning this monitor is dominated by local sources. Attainment at this monitor will only be achieved with the implementation of local controls on organic emissions or its precursors.  [EPA-HQ-OAR-2009-0491-2722.1, p.19]
The Transport Rule will not aid in attainment at this monitor and is not needed. The implementation of CAIR is sufficient to meet the current PM25 standards.  [EPA-HQ-OAR-2009-0491-2722.1, p.19]
F. Modeling performed by the Midwest Ozone Group shows attainment of the PM25 24-hour standard
The Midwest Ozone Group has performed air quality modeling (see comments submitted by the Midwest Ozone Group, October 1, 2010) of the PM25 24-hour levels using 2008 as the base case year. In addition the Midwest Ozone Group performed modeling for the future years of2014 and 2018 assuming on-the-books controls and CAIR in place. 
Figure 3 [See p.22 of this comment summary for Figure 3 entitled, 2008 Design Values versus 2014 and 2018 Modeled 24-hour PM25] shows the modeled results for the 24-hour PM25 2014 and 2018 modeled design values with the actual measured 2008 (i.e. 2007-2009) design values for the highest PM25 concentration monitors. Both the results from 2014 and 2018 show all but 2 of the monitors attain the current PM25 24-hour standard. Review of the individual component data for the 2014 and 2018 modeled design values indicate these monitors are dominated by organics as was shown for the annual exceeding monitor discussed above. For example for the 2018 simulation the Allegheny Pennsylvania monitor exhibited a large contribution (35.5 ugm-3) from organics while the Brooke West Virginia monitor was similar at 10.8 ugm-3 from organics. Generally organic emissions are local in nature thus reducing PM25 levels at these monitors will require implementation of local controls on organic emissions or their precursors. [EPA-HQ-OAR-2009-0491-2722.1, pp.20-21]
As is evident from the results of this modeling the Transport Rule is not needed. The implementation of CAIR is sufficient to meet the current PM25 standards along with local controls at the offending monitors. [EPA-HQ-OAR-2009-0491-2722.1, p.21]
G. EPAs analysis looks only at state wide contributions but considers only EGU controls [EPA-HQ-OAR-2009-0491-2722.1, p.22]
In its modeling EPA considered a state's total impact on nonattainment and maintenance areas but proposes applying controls only to electric generating units (EGU). If EPA is only going to consider controls on EGUs then it should consider the impacts only EGUs have on the maintenance and nonattainment areas rather than statewide emission impacts. Currently because of the NOx SIP Call and CAIR, EGU NOx emissions are only a small portion of the total NOx emissions in the Eastern U.S. Figure 4 [See p.24 of this comment summary for Figure 4 entitled Midwest Region NOx Emission Trends 1999-2009] shows the distribution of NOx emissions for the Midwestern states of Wisconsin, Michigan, Illinois, Indiana and Ohio. This information was assembled from EPA's National Emission Inventory and Trends Websites by Alpine Geophysics under contract to MOG. The NOx emission trends show actual emissions of NOx from 1999 thru 2009. For the EGUs actual Continuous Emissions Monitoring data as reported to EPA was used. As is evident from the figure emissions of NOx from EGUs is less than 20% of the total NOx emitted for these states. Similar and somewhat smaller results were found for the Northeast States as well as the Southeast States. All other source categories (Highway and Off-highway are the largest contributors) contribute more than 80% of the NOx emissions. [EPA-HQ-OAR-2009-0491-2722.1, pp.22-23]
As you are aware Ozone is formed from the interaction of Volatile Organic Compounds and NOx in the presence of sunlight. Considering that EGUs emit less than 20% of the available NOx the impact of these emissions is most likely considerably diminished from what the total state impact would be. EPA needs to investigate the actual impacts EGUs are having and demonstrate that the EGUs themselves are significantly contributing to nonattainment and maintenance areas. [EPA-HQ-OAR-2009-0491-2722.1, p.23]
Use of IPM to assign allocations on a unit by unit basis is inappropriate. [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.2]
IPM should not be used for the allocation of allowances on a unit basis as it is not an appropriate tool for this purpose. While IPM is a useful planning tool for looking at different control scenarios it does not contain sufficient information on each utility company and unit to make reasonable assumptions about controls or operation. Rather on a system or regional basis it can produce reasonable results. A good example of this is how it has treated Ameren's Joppa plant under the scenarios EPA has modeled. Joppa located in Massac County Illinois under the IPM 3.02 TR SB Limited Trading case is assumed to install wet flue gas desulfurization (FGD) on each unit. Under IPM 4.10 TR SB Limited Trading case IPM labels these same units as Coal Early Retirement. And under IPM 4.10 TR SB Limited Trading ABO gas case no controls are assigned and none of the units are retired. Which of these is most representative of Joppa's future destiny? [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.2]
Considering how this would affect allowance allocation, under the first !PM scenario Joppa would be issued limited allowances, as IPM assumes an FGD is installed. In the second case it would be issued no allowances, as IPM is projecting Joppa to be -retired. And in the third case Joppa would be issued allowances based on no controls. Based on these drastic variations in the IPM results for the Joppa plant it is absurd to believe that this model has any skill for determining what the fate of Joppa's units will be under the Transport Rule as proposed. [EPA-HQ-OAR-2009-0491-3739.1_NODA, pp.2-3]
Rather than using IPM to assign allowance allocations on the unit level EPA should consider using the units past utilization as has been done with the NOx SIP Call rule and the Clean Air Interstate Rule (CAIR). This is the best estimate of future utilization and produces a fair and equitable distribution of allowances. Ameren suggests in the allocation of allowances that heat input be used as this was used in the NOx SIP Call and CAIR and created a generally fair and equitable distribution of allowances. [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.3]
American Public Power Association (APPA)
4. APPA believes that the EPA must consider the implications of fuel switching for the many states where budgets will be inadequate for SO2 and NOx. [EPA-HQ-OAR-2009-0491-2812.1, p.3]
6. APPA believes that failure to have realistic dates and state budgets for coal fired power plants will result in 'the dash to gas.' It is tempting for the U.S. EPA to view any fuel switching to gas away from coal as a success because of reductions in SO2, NOx (and CO2) perhaps even more quickly than under this proposed rule. However, APPA strongly believes that fuel switching to gas presumes available infrastructure for natural gas delivery that is inadequate in many of the 31 RT covered states. APPA strongly encourages the U.S. EPA to read APPA's study on natural gas ("Implications of Greater Reliance on Natural Gas for Electricity Generation," http://www.appanet.org/files/PDFs/ImplicationsOfGreaterRelianceOnNGforElectricityGeneration.pdf) to better understand the inadequate infrastructure for gas storage and delivery. APPA does not question that there is an adequate source or supply of natural gas (considering conventional and shale based formations). APPA provides this natural gas study for review under SBREFA, Executive Order 12866 and the Unfunded Mandates Reduction Act (UMRA). [EPA-HQ-OAR-2009-0491-2812.1, p.4]
The PTR`s compliance schedule is wholly unreasonable, particularly its imposition of a January 1, 2012, initial compliance deadline that will fall only a few months after EPA plans to take final action in this rulemaking. [EPA-HQ-OAR-2009-0491-2812.1, p.7]
Many of the flaws in the Proposed Transport Rule, described in the sections that follow, could be resolved or at least somewhat ameliorated by deferring the initial 2012 compliance date. It is unreasonable and unrealistic to expect emission reductions required by the proposal to be achieved by January 1, 2012, barely six months after the date on which EPA expects to issue a final Transport Rule. [EPA-HQ-OAR-2009-0491-2812.1, p.14]
An initial compliance deadline of January 1, 2012, will not allow sufficient time for sources to make the adjustments necessary to comply with the rule. For example, a compliance deadline of 2012, following a mid-2011 date for final promulgation of the rule, would not allow enough time for sources to install low NOx burners, and in many cases, does not allow sufficient time for sources to switch to burning lower sulfur coal. See section VIII infra. Additionally, much of the modeling that EPA used to develop the proposed rule is flawed, due to the approach that EPA adopted, as well as many of the assumptions EPA made with respect to issues such as the emission controls that will be installed on, and retirement of, specific units by 2012. EPA must resolve and correct these problems, and either withdraw this proposed rule and reinitiate rulemaking with a new proposal or issue a supplemental notice of proposed rulemaking for public comment. See sections VII and IX infra. Under these circumstances, rulemaking could not be completed before the beginning of 2012. [EPA-HQ-OAR-2009-0491-2812.1, pp.14-15]
The U.S. EPA has provided absolutely no reasonable justification for its proposal to require a compliance date as early as 2012. According to statements by EPA representatives, the emission levels required in the 2012 phase for the most part reflect the emission reductions that would occur even in the absence of the Transport Rule. However, as noted above, in a number of cases, EPA has made incorrect assumptions regarding emission reductions that, in the absence of this new rule, would occur at units by 2012. See section VIII.A infra. [EPA-HQ-OAR-2009-0491-2812.1, p.17]
APPA believes that the EPA should not adopt the 2012 compliance deadline in the Proposed Transport Rule and should not consider any compliance date earlier than 2015.13 If EPA promulgates a Transport Rule that, like this proposed rule, includes requirements more stringent than CAIR, the compliance deadline should reflect the degree of stringency of those requirements. [EPA-HQ-OAR-2009-0491-2812.1, p.19]
APPA and UARG are not alone in its concern regarding the initial compliance date. Last year, for example, the Lake Michigan Air Directors Consortium ("LADCO") strongly recommended that any CAIR replacement rule include an initial compliance date no earlier than 2017 for any significant additional emission reduction requirements. See Letter from LADCO to Administrator Jackson (Sept. 10, 2009) ("LADCO Letter") at 1. LADCO explained in its recommendations to EPA that it had conducted a state-by-state analysis that indicated that installation of significant new NOx and SO2 controls -- specifically, installation of selective catalytic reduction systems ("SCRs") and flue gas desulfurization systems ("FGDs" or "scrubbers") -- would not be possible in LADCO states before 2017. Id. at 1, attachment at 4-5.  [EPA-HQ-OAR-2009-0491-2812.1, pp.19-20] 
In materials prepared to explain its Proposed Transport Rule, EPA made the following assumptions about how low SO2 and NOx emission levels would be as a result of (a) the implementation of CAIR and other on-the-books regulations, and (b) the implementation of the Proposed Transport Rule:  [EPA-HQ-OAR-2009-0491-2812.1, p.29]
[Table V-1 can be found on page 30 of this comment.]
Table V-1 demonstrates that EPA expects its PTR to achieve substantial additional reductions beyond those that have been (or would be) achieved through implementation of CAIR. Despite how much EPA expects its PTR to accomplish in terms of achieving additional emission reductions, however, EPA proposes to give affected sources very little time to achieve those additional reductions. [EPA-HQ-OAR-2009-0491-2812.1, p.30]
Specifically, EPA assumes that affected EGUs will be able to reduce their SO2 emissions from 5.1 million tons per year to 4.1 million tons per year between mid-2011 (when EPA expects to take final action on the PTR19) and January 1, 2012. This reduction, says EPA, can be accomplished if affected companies (a) just complete the installations of FGD units or "scrubbers") that are already underway, and (b) supplement the emission reductions from those controls by switching some of their units to burning lower sulfur fuels. See 75 Fed. Reg. at 45273/2. Then, relying in large part on information from a March 2005 study,20 EPA takes pieces of information from retrofit experiences at two power stations and uses those negligible data to conclude that it is possible for owners of EGUs to reduce their emissions even further (down to 3.3 million tons annually) by January 1, 2014, through the installation of additional FGD units, which -- EPA claims -- can be designed, permitted, and constructed in just 27 months. Id. at 45273/1. For installations of pollution controls of this magnitude, many public power utilities would likely fuel switch to natural gas instead. [EPA-HQ-OAR-2009-0491-2812.1, pp.30-31]
APPA "real world" examples of pollution control installation timing:
- See CPS Energy letter in Appendix B [[See Docket Number EPA-HQ-OAR-2009-0491-3041.3 for Appendix B.]]
Similarly, EPA assumes power plant owners will be able to reduce their EGUs` annual and seasonal NOx emissions by substantial amounts by January 1, 2012, by completing already-in-the-pipeline projects to install SCR reactors and by constructing more low NOx burner ("LNB") systems that -- according to EPA -- can be installed in the few months between the time that the PTR is scheduled to be finalized in mid-2011 and January 1, 2012. And if any additional NOx reductions are needed (although EPA`s projections as summarized in Table V-1 above suggest that no such additional NOx reductions will be needed), then affected utility companies can install additional SCR units by January 1, 2014, because -- according to EPA (again relying on its 2005 Report) -- it takes only "approximately 21 months" to design, permit, and construct SCR units. Id. at 45273/1. [EPA-HQ-OAR-2009-0491-2812.1, pp.31-32]
In the alternative, EPA should extend the PTR`s emission reduction deadlines by at least one year in the case of NOx and two years in the case of SO2. [EPA-HQ-OAR-2009-0491-2812.1, p.32]
EPA has substantially overestimated the number of SCR and FGD installations that are now under construction and can be operational by January 1, 2012. The EPA has greatly underestimated the number of FGD and SCR installations that affected utilities would have to undertake between mid-2011 and January 1, 2014, to meet the PTR`s requirements. Even worse than this, though, EPA has vastly underestimated the amount of time that it takes utilities to design, permit, construct, and start up new FGD and SCR units. It will take longer than 30 months -- in some cases significantly longer than 30 months -- for affected EGUs to retrofit FGD and SCR units at existing EGUs. Thus, it will not be possible for affected EGUs to achieve all the SO2 and NOx emission reductions that -- under the terms of the PTR -- must be achieved by that rule's January 2012 and 2014 deadlines. [EPA-HQ-OAR-2009-0491-2812.1, p.32]
APPA, as a member of UARG, recognizes that UARG`s comment provide more details on the unreasonableness of the emission reduction requirements that EPA has proposed. APPA seeks to incorporate the submittal by UARG and incorporates that significant section submitted by UARG by reference herein: Cichanowicz, J.E., "Implementation Schedules for Selective Catalytic Reduction (SCR) and Flue Gas Desulfurization (FGD) Process Equipment" (Oct. 1, 2010) [EPA-HQ-OAR-2009-0491-2812.1, p.32] 
Associated Electric Cooperative, Inc. (AECI)
Reference: IPM Constraint Name: #2 - State Level Cap - SO2 Annual Constraint (MO) Constraint #: 570 [EPA-HQ-OAR-2009-0491-2845.1 p.11]
EPA assumes the following (total) heat input for the state of Missouri:
TBtu (years)
755.0 ('12-'13)
772.4 ('14-'17)
780.1 ('18-'22)
783.4 ('23-'27)
795.3 ('28-'35)
[EPA-HQ-OAR-2009-0491-2845.1 p.12]
Actual (CAMD) heat input for the state during the years 2005 - 2009 is as follows:
TBtu (year)
813.7 (2005)
812.5 (2006)
800.6 (2007)
770.3 (2008)
761.6 (2009)
[EPA-HQ-OAR-2009-0491-2845.1 p.12]
Average CAMD heat input over the period 2005-2009 was 792.0
TBtu Maximum CAMD heat input over the period 2005-2009 was 813.7
TBtu Minimum CAMD heat input over the period 2005-2009 was 761.6
TBtu Observations:
:: Missouri's lowest CAMD heat input for the years 2005-2009 (761.6 TBtu) is higher than EPA's 2012/2013 assumption for the state;
:: Missouri's average CAMD heat input for the years 2005-2009 (792.0 TBtu) is not matched by EPA's assumptions until 2028;
:: EPA's heat input assumptions for the state are too low and it appears as if Missouri is being shorted.   [EPA-HQ-OAR-2009-0491-2845.1 p.12]
Big Rivers Electric Corporation
The proposed rule relied on information from EPA's Integrated Planning Model (IPM) to make assumptions regarding the ability of a utility to further reduce emissions.  The model does not take into account the required engineering analysis needed to reduce emissions on each generation unit as well as possible impacts to the overall generation station site to achieve those reductions. [EPA-HQ-OAR-2009-0491-2661.1, p.2]
Specific Comments to EPA's Technical Information Documents regarding BREC units: [EPA-HQ-OAR-2009-0491-2661.1, p.3]
Reid Combustion Turbine ORIS # 1383. The data utilized by the TR does not include any heat input or emissions for this unit. [EPA-HQ-OAR-2009-0491-2661.1, p.3]
Reid Unit 1 ORIS # 1383. The NOx emission rate estimated in the TR for the Reid Unit 1 cannot be achieved without the installation of additional NOx control equipment and the additional control equipment cannot be installed by 2012. [EPA-HQ-OAR-2009-0491-2661.1, p.3]
Henderson Station Two, Units 1 and 2 ORIS # 1382. The data utilized in the model (0.16 lbs/MMBTU) for the 2012 SO2 allocations cannot be achieved without a significant fuel switch.  [EPA-HQ-OAR-2009-0491-2661.1, p.3]
The NOx emission rate and heat input data utilized by EPA for the Ozone Season allocations is high by a factor of 10. [EPA-HQ-OAR-2009-0491-2661.1, p.3]
The parsed data files for both 2012 and 2014 show 0 TBtu for the D.B. Wilson Station for both the summer and total.  Perhaps this is due to a fuel listing of "petroleum coke".  The actual fuel that has been utilized over the last several years at this plant is a blend of bituminous coal and petroleum coke.   In future years, we are planning for potential petroleum coke blending; however, our primary fuel is forecasted to be bituminous coal for both summer and total. [EPA-HQ-OAR-2009-0491-2661.1, pp.3-4]
Boston Generating
EPA proposes zero NO, and SO, allocations for the Mystic Generating Station, Unit ID 7. It appears that this is because the !PM model does not project the unit to operate in 2012, which is an unfounded assumption. The unit could and has continued to profitably operate on pipeline natural gas with a mix of some residual oil (sulfur content 1.0%, wt). The following table summarizes unit variability over the past three years based on data reported to the EPA Clean Air Markets Division. [EPA-HQ-OAR-2009-0491-3804.1 p.1]
[[Next entry in docket is a table of EGU characteristics]]
The facility has no plans to shut down the unit in the foreseeable future, even in light of the potential economic burden of the Clean Air Transport Rule. The boiler is equipped with low NO, burners to minimize NO, formation and an electrostatic precipitator for PM capture. It is not reasonable to expect the unit to install add-on NO, or SO, controls by the year 2012. The cost of CATR SO, allowances may weigh into the facility's decision to bum natural gas instead of oil. This is because operating on natural gas yields minimal SO, emissions, certainly not enough to assume the unit will not operate. However, it is important for the unit to retain a cost effective alternative to natural gas in the event of a natural gas shortage, curtailment or emergency situation impacting the North Eastern Management Area (NEMA). [EPA-HQ-OAR-2009-0491-3804.1 p.1]
In light of this information, the facility proposes a 2012 NO, allocation of 357 tons and an SO, allocation of 1,034 tons, equivalent to the average actual emissions from a 3-year look back period. [EPA-HQ-OAR-2009-0491-3804.1 p.1-2]
Buckeye Power, Inc.
In addition, factual errors in the data EPA proposes to use in its CATR emission control allowance methodology and modeling should be corrected, as such errors relate to Buckeye's electric generating units. For example, Buckeye's Cardinal Unit No. 3 scrubber will be in place by the end of 20l2 rather than in 2010 or 2011 as contemplated by EPA's CATR modeling. [EPA-HQ-OAR-2009-0491-2710.1, p.3]
Finally, for Buckeye's natural gas-fired peaking units, specifically National Power Cooperative, Inc.'s Robert P. Mone Plant, and Buckeye's Greenville Electric Generating Station, they have been allocated no NOx emission allowances, in the case of the Mone Plant, and 14 NOx emission allowances, in the case of the Greenville Station, which are less than required to operate these natural-gas fired peaking units. These units, by the very nature of peakers, only operate when needed to support grid reliability at times of peak load, therefore, baseline emissions are not easily established. Because baseline emissions are difficult to establish for peaking power plants, and because these units are critical to grid reliability and are classified as minor sources (contributing little to overall NOx - and greenhouse gas - emissions), they should receive allocations equal to the lesser of actual or permitted emission limits. [EPA-HQ-OAR-2009-0491-2710.1, p.3]
b. EPA's allocation methodology and modeling contains numerous errors.
It appears that EPA utilized existing modeled emissions as the basis for establishment of baseline SO2 emissions. Once baseline emissions were calculated, EPA then ratcheted these baseline emissions down based on erroneous assumptions regarding the installation of additional control equipment or some presumed ability to fuel switch. With respect to Buckeye, for example, and as mentioned above, EPA shows that the Cardinal Unit No. 3 scrubber will be on line in the 2010-2011 time period. In fact, even following an aggressive installation schedule, without the sort of unforeseen circumstances that are inherent in large construction projects such as a scrubber installation, this scrubber is unlikely to be online until early 2012. EPA's proposed scheme will result in Buckeye having a deficiency in necessary allowances for 2012, since it will be allocated allowances for 2012 based upon the mistaken assumption that a scrubber will be installed on Cardinal Unit No. 3 prior to 2012. Allowance allocations for Cardinal Unit No. 3 will not be sufficient in 2012 even though it bums low sulfur coal. Fairness dictates that, if emission levels are utilized for allowance allocations, Buckeye's baseline should reflect a December 31, 2012 installation of this technology and not a 2011 installation. [EPA-HQ-OAR-2009-0491-2710.1, p.8]
G. Before Relying Upon IPM Projections For Allocation of Allowances, EPA Must Both Revise IPM to Accurately Project Dispatch of Contracted Facilities and Use the Correct Inputs for Linden Cogen
Before EPA can rely upon IPM projections as the basis for NOx allocations in New Jersey, EPA must revise the model so that it accurately predicts the dispatch of facilities such as Linden Cogen that operate to supply power pursuant to long-term power sales agreements and are required to run to provide steam to a cogeneration host. Understanding that any modeling exercise involves some degree of simplification, EPA must endeavor to capture the often complex terms governing dispatch of facilities in long-term contracts, before it relies upon the model results as the basis for allocations of emissions allowances. If EPA cannot make adjustments to IPM so that it can incorporate and reflect these real-world assumptions governing dispatch and, as a consequence, provide a reliable prediction of contracted facilities' actual dispatch, then EPA cannot continue to rely upon the model results, but must resort instead to the historic dispatch data it has already deemed a better predictor of future dispatch than IPM's projections. [EPA-HQ-OAR-2009-0491-2710.1, pp.18-19]
Linden Cogen's long-term contracts practically assure that it will be operated as frequently as demonstrated by historical operating data. If IPM cannot accommodate the numerous complex contractual terms governing dispatch of Linden Cogen's units, then EPA must at the very least establish some set of rules within IPM, which effectively 'force' the model to predict dispatch of Linden Cogen and other contracted facilities at heat input levels representative of historic operations. EPA also must incorporate Linden Cogen's correct plantwide heat rate into the model and reflect dispatch of Units 1 through 5 consistent with their service of the NYC region through dedicated transmission lines. Additionally, EPA must apply the correct FOM assumptions (12.6 $/kW/yr) for each of Linden Cogen's generating units. It also must apply VOM and fuel costs no greater than assumed for a similar facility located in New Jersey (AES Red Oak) (2.75 to 3.02 mill/kWh for VOM costs and 32.55 to 44.09 mill/kWh for fuel costs). [EPA-HQ-OAR-2009-0491-2710.1, p.19]
As the court held in the section 126 litigation, '[w]hile courts routinely defer to agency modeling complex phenomena, model assumptions must have a 'rational relationship' to the real world.' Appalachian Power 1,249 F.3d 1032 (internal citations to Chemical Mfrs. Ass'n v EPA, 28 F.3d at 1265). Accordingly, EPA has an obligation to incorporate real-world expectations for contracted facilities into its model. Further, EPA cannot inflexibly apply its model when it has been demonstrated to have a 'poor fit' with reality. Chemical Mfrs. Ass'n v EPA, 28 F.3d at 1265. ('The more inflexibly the agency intends to apply the model, however, the more searchingly will the court review the agency's response when an affected party presents specific detailed evidence of a poor fit between the agency's model and that party's reality.') Finally, in the face of data and real world information demonstrating that the assumptions used by EPA are false and the results are simply implausible, EPA must provide sources the opportunity to correct those assumptions. See, e.g., Columbia Falls Aluminum Co. v. EPA, 139 F.3d 914, 923 (D.C. Cir 1998) (vacating and remanding a rule for reliance upon 'a test [the EPA] knew to be inaccurate.'). If the model cannot accommodate real-world assumptions, EPA must abandon the model. [EPA-HQ-OAR-2009-0491-2710.1, p.19]
H. If EPA Cannot Revise IPM To Accurately Predict Dispatch of Facilities in New Jersey, EPA Should Apply the Same Methodology It Used to Establish New Jersey's Budget and Rely Upon Historical Data Instead of IPM's Projections
If EPA cannot make appropriate change to IPM so that it would accurately predict the dispatch of facilities in New Jersey such as Linden Cogen, EPA should instead base NOx allocations in New Jersey on reported data. In setting state budgets (except for the 2014 802 budgets for group 1 states), EPA reportedly relied on reported data, as augmented by assumptions about operation of existing and planned emissions controls. See 75 Fed. Reg. at 45291. Thus, if IPM cannot be revised to produce reliable results for New Jersey or for contracted facilities such as Linden Cogen, EPA should adopt the same approach it used to develop the proposed state budgets and base the unit allocations on reported data, augmented by assumptions concerning the operation of emissions controls. This would make true EPA's statement in the preamble that its proposed allocation methodology 'allocat[es] down to the individual unit level using all of the same assumptions used in developing the proposed budgets.' 75 Fed. Reg. at 45311. For New Jersey, using those same assumptions would require that EPA not rely upon IPM projections for either the annual or ozone season NOx allocations, but instead base those allocations upon historic data, as augmented by assumptions about existing and planned controls. [EPA-HQ-OAR-2009-0491-2710.1, pp.19-20]
I. Basing Allocations on Reported Data Rather Than Projected Dispatch Is Not At All Inconsistent With the Court's Decision in North Carolina v. EPA
Basing unit allocations for New Jersey on historic data is not at all inconsistent with the principles articulated by the D.C. Circuit in North Carolina v. EPA, 531 F.3d 896 (DC Cir. 2008). Indeed, EPA has already proposed to base unit allocations on historic data for any state in which 2009 emissions were lower than IPM's projected 2012 emissions. Thus, assuming EPA cannot fix the errors in IPM that have resulted in wildly inaccurate projections of dispatch in New Jersey and for Linden Cogen in particular, EPA could adopt the same approach for allocating allowances that it says it adopted in setting statewide budgets: It could base each unit's allocation on historic data, which EPA has concluded are more representative of actual operations than IPM's projections. [EPA-HQ-OAR-2009-0491-2710.1, p.20]
J. EPA Should Establish Allocations Based Upon a More Representative Period of Time Than One Year
Assuming EPA cannot modify IPM to accurately predict dispatch of contracted facilities in New Jersey and should therefore decide to base NOx allocations for New Jersey on reported data, EPA should base emissions allocations for individual units, not upon data from only one year, but on a facility's average heat input over a longer period of time. Once each facility's representative baseline has been established, EPA should add together all facilities' baseline emissions, compare the resulting sum with the state budget and then reduce each facility's allocation by whatever percentage is needed for the total statewide emissions (plus the 3% set aside for new facilities) to fit within the budget. [EPA-HQ-OAR-2009-0491-2710.1, p.20]
Using only one year's data as the baseline for allocations would unfairly prejudice facilities that might have experienced reduced dispatch in 2008 or 2009. In particular, it could penalize facilities that had lower emissions in 2008 or 2009 because they were down for an extended period of time to install controls in advance of CAIR. Furthermore, as EPA has acknowledged upon adjusting reported heat input and emissions rates to reflect unusually low utilization in 2009 15, 2009 data represented significantly lower utilization due to the global recession. As a consequence, 2009 data cannot be deemed representative and EPA should more equitably account for anomalously low utilization during the recession by using a longer-term average as the basis for establishing allocations. [EPA-HQ-OAR-2009-0491-2710.1, pp.20-21]

15. See supra nt. 4. [EPA-HQ-OAR-2009-0491-2710.1, p.20]
City of Ames, Iowa
It seems that U.S. EPA believes that an alternative to compliance with this rule is for coal-fired generation to convert over to natural gas. While there may be enough natural gas reserves to support more electric generation, the natural gas infrastructure (pipeline system) to deliver natural gas adequately for electric generation is not in place and may never be in place. The City of Ames does not have access to natural gas resources sufficient to support conversion of our coal-fired generation over to natural gas. Moreover, natural gas is not a reliable resource for electric generation during extreme winter weather conditions due to the demand for natural gas for residential space heating to support life. This author has had at least two personal career experiences in Wisconsin where use of natural gas for electric generation was curtailed (prohibited) during extreme winter weather in order to preserve and maintain natural gas for residential space heating. Even with curtailment, in one case the demand on the natural gas pipeline for space heating was so great that the gas pressure failed to support furnace and water heater pilot lights. [EPA-HQ-OAR-2009-0491-2769, p.2]
Cleco Corporation
We appreciate the opportunity to submit these comments, but we are very concerned about the process by which this rule was developed and the lack of opportunity for meaningful review, especially of the data associated with the NODA. The D.C. Circuit identified the fundamental flaws in the Clean Air Interstate Rule ("CAIR") in July 2008. The proposed rule is voluminous and complicated, and EPA intends this rule to be the model for future transport rules. Yet EPA has allowed only sixty days (or less) for public review and comment and has denied modest requests for extensions from multiple stakeholders. We have worked very hard to evaluate this rule within the time allowed, but sixty days is simply not enough time to prepare the thorough comments this rule requires. In addition, EPA's Notice of Data Availability (NODA), issued in the middle of the public comment period, impacts literally every aspect of this proposed rule. The timing and the short comment period have significantly strained our limited resources to provide for meaningful and thorough evaluation of the significant impacts this rule could have on Cleco Midstream's wholesale operations. We urge EPA to issue a more refined supplemental rule to allow us an opportunity to better evaluate the proposal and submit more meaningful public comments. [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.2]
EPA's Most Recent IPM Projections Penalize Low Emitting, Efficient Units [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.2]
Under EPA's most recent IPM projections (Version 4.10), natural gas-fired units that are very efficient (heat rates below 8,000 btu/kw) and low emitting (equipped with NOx reduction technology such as SCR) are projected to have very low utilization levels. Cleco Midstream's Evangeline Power Station illustrates this effect. [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.2]
Evangeline Power Station's Forecasted Heat Input Is Too Low [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.2]
Evangeline Power Station is a 775 MW combined cycled generating station (CCGT). In 2000, the facility abandoned two existing boilers and repowered two steam turbines with F-Class combustion turbine technology. The facility now consists of Unit 6, a 1x1 CCGT, and Unit 7, a 2x1 CCGT. The IPM 4.10 parsed file shows that EPA forecasts the annual heat input for this facility to be 4.5 trillion British thermal units (tBtu) in 2012. IPM Version 3.02 projected 11.24 tBtu. This represents a 60% reduction in the forecasted heat input for the facility from Version 3.02 to Version 4.10. It is inconceivable that a state-of-the-art combined cycle generating unit will be effectively limited to an equivalent 8.6 percent capacity factor over the longer term. While the projected heat input from IPM Version 3.02 is more reasonable by comparison, Cleco Midstream is still concerned about the impacts of effectively ascribing a 21.5 percent capacity factor to this facility, as Version 3.02 does. As discussed below, because these units already have state-of-the art controls, a severe under-allocation of allowances based on these heat input projections could negatively impact the facility's future marketing opportunities, especially given that it is a wholesale generator. [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.2]
EPA Misuses IPM Projections in this Rulemaking [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.4]
Cleco Midstream recognizes that the EPA, in addition to other state air regulatory agencies, utilities and public and private sector clients, have used IPM for various air regulatory analyses, market studies, strategy planning, and economic impact assessments. And although IPM is a well established model of the electric power sector for strategic and other planning tools, it in no way should be used as the sole basis for designing and constructing a specific environmental rule such as the Clean Air Transport Rule (CATR). The IPM model is useful as a tool in the user's arsenal of tools for capacity planning, compliance planning, wholesale price forecasting, and asset valuation; however, it is only one of several tools used to make such critical decisions. In addition, the IPM is not a static, one time analysis that is run once. It is updated on a continuing basis with key data from energy markets, fuel markets, emission markets, and electricity markets. In contrast, the proposed CATR is designed whereby allowances are issued now to facilities on a long term basis, similar to the Acid Rain Program and there are essentially no provisions for future changes in the key model inputs mentioned above. [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.4]
Transport Rule II [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.6]
In section V of the preamble to the proposed Transport Rule, EPA states that for future ozone and PM 2.5 NAAQS, EPA intends to quantify the amount of emission reductions needed to satisfy the requirements of 110 (a) (2) (D) (i) (I) with respect to those NAAQS. EPA states that it has not made any determinations regarding whether reductions from source categories other than EGU's will be needed to achieve the necessary reductions in each state. However, EPA has verbally mentioned that it is likely that other source categories will be required to reduce SO2 and NOx emissions to eliminate significant contribution or interference with maintenance of the 1997 PM NAAQS. Given that this IPM modeling methodology will form the basis for allowance allocations and will set a precedent going forward, how does EPA expect to address other source categories with similar performance modeling tools? Cleco Midstream isn't aware of any such IPM models for all other source categories, and EPA has had the luxury of developing these rules with data from a heavily regulated industry that is required to report inputs and outputs much more rigorously than most other source categories. It seems that by using this projected modeling methodology for EGU's, EPA will find itself allocating allowances to other source categories on a different basis and will thus be faced with many challenges on future versions of the Transport Rule due to inequitable allowance allocations. [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.6]
EPA's Proposed Rule Is Insufficient for Public Comment [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.6]
While Cleco has attempted a full review and analysis of this proposed rule within the time provided, it has found it almost impossible to do so given the voluminous and complex nature of the proposal and supporting documentation. This is an important rule, and EPA expects it will form the basis for future transport rules. Yet EPA's processes and methodologies are in many cases unclear and in other cases are lost within the thousands of pages of preamble and technical support documents. [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.6]
Furthermore, given the many errors we have identified thus far and EPA's release just weeks ago of new data and modeling runs which will form the basis of revised unit allocations yet to be provided, the proposal is not sufficiently developed for meaningful public comment. We urge the Agency to issue a supplemental proposal that provides the revised data which will form the basis of the final rule and revised unit allocations for review and comment before finalizing this rule. In doing so, EPA will produce a better, more effective product that can inform future rules, decrease the scope and extent of legal challenges, and improve the likelihood that the rule will survive such challenges. The electric power industry, the fuel industry and the transportation industry all involve massive, complex operations with long term planning horizons (with respect to financing, integrated resource planning etc.). The rule as proposed gives these industries little to no indication of what might be required in the final rule, no time to plan, and almost no time to comply. EPA simply has not allowed sufficient opportunity for public review and comment. Given the importance of this rule, the Agency should take the additional time necessary to issue a supplemental proposal. [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.6]
EPA Must Not Establish State Budgets and Unit Allocations Based on Projected Data. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.4]
As noted in our comments on the proposed rule, we oppose EPA's sole reliance, in some cases, on projected data to set state budgets and unit allocations.1 In our initial comments we noted that there is too much variability in EPA's projections  -  and in projected data generally  -  to determine state budgets and to allocate to the unit-level. We also noted that EPA's projections simply do not reflect reality. Having more fully evaluated EPA's numerous projections (e.g., IPM 3.02, IPM 4.10, and IPM 4.10 (AEO)) and having compared those projections with our own, we are confident that EPA's sole reliance on its best guess work to establish allocations and state budgets is arbitrary and capricious. Model outputs vary too much, between various models or versions of the same model and with minor adjustments to key assumptions, to support precise state budget and unit allocation development, and EPA's model outputs prove this point by predicting unrealistic results. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.4]
Projections Have Too Much Variability to Support Allocations and State Budgets. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.4]
Numerous state budgets and unit allocations are based solely on EPA's IPM projections. Essentially, EPA guesses how units will run in the future and then based on those guesses allocates allowances to units and establishes state budgets. This is an inappropriate use of IPM projections. In recognition of modeling limitations, industry and agencies rely on modeled/projected data for very limited purposes. Here, EPA proposes to rely on projected data from the IPM to set detailed, long-term, unit-level, allocations. But the IPM is not a static, onetime analysis. IPM and other model analyses are updated on a continuing basis with key data from energy markets, fuel markets, emission markets, and electricity markets. As a result, the IPM is not a suitable tool for establishing unit allocations that will be federally enforceable for the foreseeable future. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.4]
As an initial matter, there is simply too much variation in projections from one model to the next. Less than a month after publishing the proposed rule  -  based on IPM 3.02  -  EPA proposed a newer model  -  IPM 4.10. This simple switch from one version to the next leads to dramatic changes in the most critical predicted outputs. For Louisiana EGUs alone, EPA's new version 4.10 predicts a 12% decrease in summer fuel use, an 8% decrease in total fuel use, a 29% decrease in ozone season NOx emissions, a 25% decrease in total NOx emissions and an 18% decrease in total SO2 emissions.2 With the NODA, simply by converting from one IPM version to the next, EPA projects NOx and SO2 emission reductions from Louisiana EGUs that far exceed the emissions the August 2 Transport Rule alleged were Louisiana's significant contribution and interference with maintenance. See Table 1 below [See p.5 of this comment summary for Table 1 entitled, Comparison of Emission Reductions Required for Louisiana EGUs under the Proposed Transport Rule with Projected Emission Reductions Resulting from EPA's Switch from IMP Version 3.02 to IPM Version 4.10]. In short, from one month to the next the Agency's predictions bear no resemblance to one another. Yet EPA proposes to establish federally enforceable reduction requirements based on similar modeling yet to be provided. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.4]
To further illustrate this point, we have compared 2012 heat input projections from EPA's IPM versions 4.10 and 3.02 with 2012 heat input projections from two of the modeling programs we use  -  again for limited purposes. This comparison is included as Attachment "A" [See p.11 of this comment summary for Attachment A entitled, CONFIDENTIAL BUSINESS INFORMATION REDACTED] and is claimed as confidential business information in accordance with 40 C.F.R. Part 2. The comparison demonstrates two important points. First, projected heat input varies widely depending on the model selected. And second, with limited exceptions, both EPA projections underestimate heat input for 2012 as compared to the two models we use. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.5]
In addition to the wide variation in important outputs from one model to the next, minor adjustments to some key assumptions will similarly lead to significant variations in the outputs from a single model. Take for example the natural gas fuel price assumptions. For 2012, EPA has proposed three different gas fuel price assumptions: $6.76 (IPM 3.02), $4.27 (IPM 4.10) and $5.19 (AEO). EPA's best guess in September of this year (IPM 4.10) is 37% lower than its best guess in August (IPM 3.02). Thus from one month to the next EPA adjusted its fuel price assumptions by 37%. This underscores the difficulty and uncertainty in predicting just one of the inputs for EPA's model. Natural gas fuel prices are volatile. They are also one of the most significant assumptions with respect to projected outputs (e.g., projected NOx emissions). Yet EPA proposes to establish state budgets and unit allocations based in large part on its assumptions of natural gas prices. This is wholly inappropriate, and, given the legal import EPA proposes to place on these modeled outputs, it is arbitrary and capricious. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.5]
Because of the significant limitations of modeling noted above, the wide variations in outputs and volatility of key inputs, EPA's proposal to rely solely on general modeling projections from IPM to set the most significant federally enforceable limits in the rule is arbitrary and capricious. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.5]
Errors, Mistaken Assumptions and Methodology Flaws [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.7]
In the time permitted for review and comment, we have identified the following apparent errors, mistaken assumptions and methodology flaws. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.7]
Errors in NEEDS [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.7]
Teche 3 (1400_B_3). EPA correctly notes in NEEDS that this unit can burn distillate fuel oil. Its ability to burn fuel oil, however, is typically reserved for emergency situations when natural gas is unavailable. By way of example, it has not burned any fuel oil in the last three years, and burned only de minimis amounts in the two years before that. It is unclear to us, whether and how, EPA accounts for such limitations on the use of alternative fuels. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.7]
Rodemacher 1 (6190_B_1). Like Teche 3, Rodemacher 1 is permitted to burn alternate fuels and typically does so only in emergency situations (distillate fuel oil and residual fuel oil). Over the last three years this unit has not burned any fuel oil and before that used distillate in de minimus amounts, except for a period of time following Hurricane Katrina when natural gas was unavailable. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.7]
Dolet Hills (51_B_1). EPA correctly notes in NEEDS that this unit can burn subbituminous coal. While the unit can physically burn subbituminous, it is a minemouth plant. It is connected by conveyor to a nearby lignite mine and has no facilities for accepting shipment by rail. Based on our review of the available IPM runs under 3.02 and 4.10, it appears that EPA correctly projects that Dolet Hills will burn 100% lignite fuel.5 As noted, however, EPA has not made available the results of numerous other IPM runs. To the extent that EPA has modeled or plans to model use of any fuel at Dolet Hills other than lignite, we object on the basis that this is a mine mouth facility that is fully contracted to burn lignite coal. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.7]
Dolet Hills (51_B_1). EPA erroneously assumes that this facility's scrubber efficiency is 88%, presumably on a continuous basis. Dolet Hills is a NSPS Subpart D facility. The historical removal efficiency has ranged from 50% to 70%. A more accurate efficiency would be 60%, which represents the annual average. Because EPA is developing an annual SO2 emission reduction program, the Agency should focus on annual average removal efficiencies which take into account variability in operations, fuel sulfur and other parameters over the course of the relevant compliance period. Sulfur content of the lignite fuel, in particular, varies greatly depending on the particular vein being mined. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.7]
Errors in IPM Inputs and Assumptions [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.7]
Teche 4 (1400_B_4). EPA has not included Teche 4 in the proposed rule. Teche 4 is planned to commence commercial operation prior to January 1, 2012 and has broken ground and received approval from the Louisiana Public Service Commission.6 It is a permitted facility natural gas fired combustion turbine with a name plate rating of 35MW. Accordingly, it should be included as an existing unit (to the extent EPA's proposed Transport Rule ultimately applies to Louisiana) and should receive an allowance allocation as an existing unit. [EPA-HQ-OAR-2009-0491-3726.1_NODA, pp.7-8]
Rodemacher 1 (6190_B_1). The NOx combustion control input (NOx Comb Cont) for this unit indicates it has flue gas recirculation, low NOx burner technology and overfire air. The unit does not have flue gas recirculation, low NOx burner technology or overfire air. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.8]
Rodemacher 2 (6190_B_2). The NOx combustion control input (NOx Comb Cont) for this unit indicates it has an overfired air system. The unit has both an overfired air system and low NOx burner technology. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.8]
Rodemacher 3 (6190_B_3a and 6190_B_3b). The Hg EMF input for these units indicates cold side ESP with a fabric filter and SNCR. Neither unit has a cold side ESP. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.8]
EPA Erroneously Assumes Controls Are Dispatchable, Ignoring LAC 33:III.905. EPA makes adjustments to reported NOx emissions for several facilities in Louisiana to reflect EPA's assumption/preference that NOx controls operate year round.8 These adjustments are in error, because Louisiana law requires units to operate installed controls year round. "When facilities have been installed on a property, they shall be used and diligently maintained in proper working order whenever any emissions are being made which can be controlled by the facilities, even though the ambient air quality standards in affected areas are not exceeded."9 Thus, the adjustments EPA made for Louisiana facilities with SCR or SNCR installed before 2009 are in error and are based on the mistaken assumption that NOx controls are not operated year round in Louisiana. They are. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.8]
Methodology Flaws (Emission Rates) [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.8]
EPA's use of the various emission rates from NEEDS in the IPM is unclear. EPA appears to use a maximum allowable "SO2 permit rate" for modeling SO2 emissions in the IPM and one of four NOx rates (the controlled base rate, the uncontrolled base rate, the controlled policy rate, or the uncontrolled policy rate). Where these rates are derived from and how they are used is unclear to us. We request that EPA explain the rates and how they are used, before issuing a final rule, so that we can provide meaningful comment. Until that time, we offer the following comments on these rates. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.8]
SO2 Permit Rates. EPA should not use a maximum allowable SO2 permit rate and should instead use rates based on past actual annual emission rates. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.9]
Teche 3 (1400_B_3). The Teche 3 SO2 permit rate in NEEDS is 4.94 lbs/mmBtu. As explained above, Teche 3 burns natural gas (with exceptionally rare use of distillate fuel oil when natural gas is unavailable). [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.9]
Rodemacher 1 (6190_B_1). The Rodemacher 1 SO2 permit rate is 1.4 lbs/mmBtu. As explained above, Rodemacher 1 burns natural gas (with exceptionally rare use of fuel oil when natural gas is unavailable). [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.9]
These SO2 rates are unreasonable, and EPA should use the default SO2 emission rate of 0.006 lbs/mmBtu prescribed for gas units in 40 C.F.R. Part 75. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.9]
NOx Rates. EPA should explain these four rates in more detail. From what we have been able to tell so far these NOx rates do not resemble the historical actual NOx rates for many units. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.9]
EPA's Complex Methodologies May Bias Future Transport Rules Towards EGU Emission Reductions. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.9]
Having worked through EPA's proposed methodologies for defining significant contribution and interference with maintenance and setting state budgets and unit allocations, we find that for EPA's complex methodologies to work they require extraordinary amounts of data about electricity demand, fuel cost, fuel content, control technology cost and efficiency, emissions, etc. That quantity of information is simply not available to the Agency for any other emission source category. Accordingly, we are concerned that EPA's proposed methodology is too complex and is unworkable for other source categories. The approach thus biases future transport rules towards EGU reductions. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.9]
[See EPA-HQ-OAR-200-0491-3726.1_NODA, p.11 for Attachment A: Projected Total Heat Input Comparison of Various Models (Contains Confidential Business Information, p.12 for Attachment B: State of Louisiana Department of Environmental Quality, Part 70 Operating Permit Significant Modification, CLECO Power, LLC, Teche Power Station, Baldwin, St. Mary Parish, Louisiana, Permit No. 2660-00007-V1 (November 6, 2009). And Cleco Power, LLC, Teche Power Station, Title V and Acid Rain Monitor Modification Application, Agency Interest No. 2432, prepared by Providence Engineering and Environmental Group LLC (December 2008)., p.104 for Attachment C: Louisiana Administrative Code 33:III.905.
Consumers Energy
E. EPA's Proposal Is Based On Numerous Errors and Assumptions In the Data Bases Used With Respect to Consumers Energy Units
In the EPA's table of unit specific allowance allocations and direct control emission rates we found several flaws:
:: There appears to be an assumed retirements at the following units:
o B C Cobb Units 1,2, 3
o DEKarn Units 3, 4
o Thetford Units 1, 2, 3, 4
At this time Consumers Energy has no plans to retire any of these units. [EPA-HQ-OAR-2009-0491-2837.1, pp.9-10]
[For additional comments pertaining to EPA's Proposal Is Based On Numerous Errors and Assumptions In the Databases Used With Respect to Consumers Energy Units, see page 10.]
G. Modeling Based on Current Emissions Inventories and Ambient Ail' Quality Indicates that EPA's Proposal is Not Necessary to Achieve the Desired Air Quality Improvements
Consumers Energy is aware of the air quality modeling effort that has been conducted by the Midwest Ozone Group (MOG). MOG conducted an independent analysis which utilizes a more recent base year, 2008, and alternate business as usual (BAU) future year scenario for 2014 and 2018 to develop a residual ozone and particulate matter nonattainment picture for a l2km domain over the Midwestern and northeastern United States. MOG also relies upon ambient air quality monitoring data collected through the most recent year that has been quality assured and reported by EPA, 2009. [EPA-HQ-OAR-2009-0491-2837.1, p.14]
The objective of this work was to perform technically credible photochemical modeling analyses, including the EPA attainment test, for three key years: 2008, 2014, and 2018. Modeling for year 2008 served the important function of providing a recent 'typical baseline' year for the purpose of calculating relative reduction factors (RRFs). Most importantly, moving to 2008 takes direct advantage of recent reductions in 8-hr design values measured across the modeling region. Results of this work clarify when the effects of the BAU state and federal control programs would begin to significantly lower the 8-hr ozone and annual and daily PM design values at key monitors in the modeling domain. [EPA-HQ-OAR-2009-0491-2837.1, p.14]
Consumers Energy notes, with interest, that even the updated emissions inventory and ambient air quality monitoring data result in a model that over predicts 2014 PM2.5 design values for Michigan. MOG's analysis indicates that a monitor in Wayne County, presumably the Dearborn monitor, will exceed the 24-hour 2006 PM25 NAAQS in 2014. The model predicts attainment in 2018. As of 2009, the Dearborn monitor has the 3-year data set that demonstrates measured attainment for both the 1997 and 2006 PM2.5 NAAQS. [EPA-HQ-OAR-2009-0491-2837.1, p.14]
The limited comment period for this proposed rule has not permitted adequate time for Consumers Energy to fully critique MOG's efforts. We will continue to do so on our own, and with the MDNRE, and with LADCO. [EPA-HQ-OAR-2009-0491-2837.1, p.14]
We are confident that MOG's effort shows that, at a minimum, EPA's proposed rule is based on incorrect assumptions that result in a control program that is too extreme. MOG's effort may go so far as to demonstrate that EPA's proposed rule is not even required to reach attainment of the 1997 ozone NAAQS and the 2006 PM2.5 NAAQS. If MOG's analysis holds true, then, to put it bluntly, EPA has elected to go back in time, to a world that no longer exists, to find solutions for problems that are already being solved. [EPA-HQ-OAR-2009-0491-2837.1, p.14]
In either case, Consumers Energy believes the prudent course for EPA is to retract and rethink this proposal, with more upfront transparency and a greater degree of involvement by the States and affected sources. [EPA-HQ-OAR-2009-0491-2837.1, p.14]
:: It has been developed using emissions inventory data that has no relevance to the situation that exists today. EPA ignores the major reductions that are in place and on the book through the ongoing implementation of CAIR, which remains in effect and is enforceable. EPA ignores the reductions that are in place and on the books that have been incorporated into consent orders that are in effect and enforceable. EPA also ignores the reductions that have resulted from the permanent shutdowns of major sources that contribute to the pollutants and standards addressed by the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2837.1, p.15]
:: EPA's choices of emissions inventory and ambient air quality monitoring data result in allowance totals that will be inadequate to support even a limited emissions trading program. [EPA-HQ-OAR-2009-0491-2837.1, p.15]
:: EPA must work with the states and affected sources to correct the numerous errors and assumption, with respect to source emissions, control plans and decommissioning plans contained within the proposed rule. [EPA-HQ-OAR-2009-0491-2837.1, p.16]
Council of Industrial Boiler Owners (CIBO)
Assumptions regarding emission rates of SO2 and NOx fail to account for key features of some units [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.6]
The total heat input is used to determine allocations of allowances. However, allocations are based on the premise that the plants will be able to achieve a lower emission rate for SO2 and NOx than they currently emit. In the case of waste coal plants using circulating fluidized bed (CFB) technology, the projected reduced emission rates cannot easily be achieved and may not be achievable.
SO2 and NOx emission rates are based on EPA's definition of highly cost effective controls -  made not on a plant basis but on a model plant basis. In regard to the waste coal plants, the assumptions in the documents refer to bituminous coal, not waste coal from anthracite or bituminous operations. Because waste coal plants utilize CFB combustion and inject limestone to control SO2 emissions, the incremental costs for controlling SO2 by adding a scrubber (wet or dry) is higher than what is projected. In many cases, the CFB unit cannot simply add more limestone to obtain 95% to 98% reduction in SO2. Assuming the concept is to reduce emissions by simply increasing limestone, this is problematic for several reasons: [EPA-HQ-OAR-2009-0491-3754.1_NODA, pp.6-7]
increased limestone means increased fuel usage to calcine the limestone, increasing the total heat input to the boiler; [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.7]
the amount of limestone required to achieve a 95% to 98% emission reduction from current emission levels is not linear, but exponential; and [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.7]
while the emission rate on a lbs/mmBtu basis may be lowered, the heat rate is increased and the projected total reduction of SO2 would not be achieved. [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.7]
In regard to NOx reductions, several complications arise: [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.7]
as limestone consumption is increased (and more fuel with more sulfur goes to the boiler), and total heat input to the boiler increases, NOx, mercury and CO2 emissions increase; and [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.7]
increased uncontrolled NOx cannot necessarily be rectified by increasing ammonia usage, because the amount of ammonia that can be utilized is limited by permitted levels of ammonia slip (5ppm). [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.7]
Spinoff problems from these unaccounted for-variables make the base case assumptions even more irrational. CFB plants have experienced visible plumes when injecting larger amounts of ammonia to control NOx resulting in ammonia slip approaching its permit levels; in this way, overly steep emission reductions could result in opacity violations. The costs to reduce emissions per plant vary significantly and in many cases exceed the EPA projections in terms of costs per ton of reduction. A related fundamental problem is that many of the existing add-on systems used for the model plant cannot be simply 'bolted on' to waste coal CFB units (and most of the coal-fired CFB units) due to the actual parameters that are required for their operation. The engineered design of operation of SCRs and some post-combustion wet scrubbers, combined with the existing back-pass thermal efficiency devices already installed, restrict the operation of both. To graft additional partial-flow devices into existing systems will require major redesign of the existing thermal designs, if it can be done at all. These additions will exacerbate the concern noted above, by increasing the already underestimated heat rates used for waste coal CFBs. [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.7]
These issues are not accounted for in EPA's model unit approach to allocating allowances. EPA needs to evaluate actual unit operation in order to achieve an equitable distribution of allowances, and one that reflects other longstanding priorities such as encouraging the use of CFB and other low-emitting technologies for the production of power. [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.7]
Dominion
First, EPA has over estimated the number of retrofit installations that are either already under construction or will be completed in the 2012 to 2014 timeframe. [EPA-HQ-OAR-2009-0491-2715.1, pp.12-13]
Model/Allocation Inaccuracies
EPA has indicated that its intent in setting the state emission budgets for 2012 was to reflect a level of emissions representative of pollution controls that were already in place or what companies had already announced or committed to install by 2012 in order to comply with existing federal and state rules. However, inaccuracies in EPA assumptions used to establish the proposed state emission budgets and individual unit allocations (through the use of its Integrated Planning Model- IPM) raise serious questions about the proposed rule. These inaccuracies include (1) erroneous assumptions about existing and future/planned installation of pollution control equipment - for example, EPA has assumed pollution controls exist or would be installed for certain facilities by 2012 where controls have not been implemented to date and there are no such plans to install equipment or where installations are not expected/planned until after 2012; (2) inaccurate assumptions of early retirement for some units or assumptions that certain units (especially oil-fired units) would not operate in the future (even for units with exiting capacity supply commitments); (3) inaccurate assumptions regarding fuel switching and the availability of lower-sulfur fuels as a viable compliance option; and (4) inaccuracies in the National Electric Energy Data System (NEEDS) database. These inconsistencies, if uncorrected, will result in overly stringent state emission budgets and significant gaps in allowance allocations to many units that will render compliance with the proposed reduction requirements extremely difficult and very costly. To the extent allowances are not available, curtailments could be necessary. [EPA-HQ-OAR-2009-0491-2715.1, p.6]
We provide the following detailed descriptions of assumption errors and issues specific to Dominion facilities and electric generating units: [EPA-HQ-OAR-2009-0491-2715.1, p.6]
[See EPA-HQ-OAR-2009-0491-2715.1, pp.6-10 for detailed descriptions of assumption errors and issues specific to Dominion Facilities and electric generating units]
DTE Energy
Even more problematic is the fact that EPA has made incorrect assumptions regarding emission reductions that will occur at units by 2012. The vast majority of DTE's fossil-fired EGUs (all but 2%) have been retrofitted with combustion controls for NOx emission reductions. DTE coal-fired EGUs all fire the maximum blend of low sulfur subbituminous within their capability. [EPA-HQ-OAR-2009-0491-2851.1, p.4]
Duke Energy
A Compliance Deadline in 2012 Is Neither Necessary Nor Appropriate.
EPA has provided no reasonable justification for its proposal to require a compliance date as early as 2012. To begin with, according to statements by EPA representatives, the emission levels required in the 2012 phase for the most part reflect the emission reductions that would occur even in the absence of the Transport Rule. However, in a number of cases, EPA has made incorrect assumptions regarding emission reductions that, in the absence of this new rule, would occur at units by 2012. [EPA-HQ-OAR-2009-0491-2689.1, p.8]
The NOx Emission Rates of Duke Energy Units With Currently Operating SNCR Should Not Be Further Reduced By 35% to Account for SNCR Operation. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.10]
When EPA updates the emission rates for Duke Energy units with SNCR to the 2009 rates, it should not apply an additional 35% reduction factor to account for SNCR operation because the 2009 rates already reflect year round SNCR operation. The following Duke Energy units have SNCR that were in service for the entire year of 2009 for North Carolina Clean Smokestack Act, CAIR annual NOx and CAIR ozone season NOx compliance. The 2009 NOx rates for these units should therefore be used without further adjustment, and should be considered the controlled rates and the rates used in the IPM modeling. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.10]
[See p.10 of this comment summary for a table listing: Plant name, Units, ORISPL]
For Units with an Existing SCR or SNCR, EPA Should Update Reported Unit NOx Emission Rates to Reflect 2009 Data and Use Separate Ozone Season and Non-Ozone Season Emission Rates to Represent a Unit's NOx Emissions Over the Course of a Year. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.17]
As a general statement, EPA's use of a 0.06 lb/mmBtu NOx emissions rates ceiling for SCR controlled units is inconsistent with how SCR controlled units actually work. The key element of SCR performance is the condition and amount of catalyst used. SCR reactors are fixed in size at their time of construction and units do not have the capability to add additional catalyst layers beyond what was included in their original design. Where SCR has been installed on existing units, in general these have been shoe-horned into very tight spaces. Even where there may be some marginal additional room, the structural steel is a custom design for the specific size and weight of the SCR, and the design will not allow for any enlargement without completely replacing the system. In addition, while in operation, catalyst ages as it is poisoned by materials in the flue gas and steadily degrades in its performance. Once its performance reaches an unacceptable level, it must be replaced. Catalyst replacement is expensive and can only be performed during a unit shutdown of sufficient length. Because of these factors, units will have significant differences in the levels of NOx removal performance when catalyst is new, and then just before it is replaced. An uninformed response to the issue of catalyst degradation would be to call for more frequent catalyst replacement. Clearly this is not an option because it would require frequent unit shutdowns, and scrapping expensive catalyst prematurely which would also increase the amount of waste materials. The marginal costs for the incremental reductions that would result would wildly exceed the $500 per ton cost breakpoint. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.17-18]
Duke Energy recommends that EPA use separate ozone season and non-ozone season NOx emission rates for units with an existing SCR instead of using a unit's ozone season emission rate to represent its emissions over the entire year because a unit's ozone season NOx emission rate is not representative of its non-ozone season emission rate, and therefore is not representative of a unit's capability over an entire year (a review of 2009 ozone season and non-ozone season NOx emission rates for units with SCRs operating year around shows that the ozone season NOx emission rates are typically lower than the non-ozone season rates). EPA cannot ignore the fact that there is a demonstrated difference in performance of SCR between ozone season operation and operation across the entire year. Therefore, applying a unit's ozone season NOx emission rate to the non-ozone season under predicts a unit's annual NOx emissions, the state budgets, and the unit allowance allocations. The fact that the ozone season NOx emission rate is not representative of the non-ozone season emission rate is due to many factors, including the following: 1) most units have the fewest number of outages during the ozone season which results in the most continuous period of SCR operation, whereas outside of the ozone season, most units experience the bulk of planned and maintenance outage activity. This results in higher occurrences of unit start-up and shut-down when emission rates are higher than during continuous operation. 2) Lower ambient temperatures in the winter season generally result in a higher propensity for ammonium bisulfate formation in the air heaters and downstream ductwork on SCR units, resulting in air heater and ductwork pluggage, and the need to reduce NOx removal to maintain unit output capacity. Generating units do this by reducing the level of ammonia feed and/or regulating the temperature of the gas entering the SCR. 3) Many units tend to have catalyst replacement outages in the spring outage season, resulting in peak SCR removal capability during the ozone season immediately following the outage. This "brand new" catalyst will show the best overall performance for the next several months immediately following the outage, and thus lower average ozone season emissions may be influenced by SCR catalyst outage schedules. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.18-19]
Upon making these recommended adjustments to NOx emission rates, EPA should rerun the critical IPM model runs that are the basis for developing state budgets and unit allocations. Because EPA needs to make dramatic technical changes to its calculations, EPA should then repropose the budgets and allocations for public review and comment. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.19]
The following table presents 2009 unit level ozone season and non-ozone season NOx emission rates that Duke Energy recommends EPA use for each of the listed Duke Energy units equipped with an SCR. In each case, the SCR was operated to the maximum extent possible in 2009, given the operating conditions of the units. In each case, it would require extensive and costly upgrades to each SCR to get it to perform at or below 0.06 lb/mmBtu at a $/ton cost far in excess of $500/ton. In addition, it would not be possible to complete an upgrade by January 1, 2012. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.19-20]
When a unit's 2009 emission rate is below 0.06 lbs/mmBtu, Duke Energy recommends using the 0.06 lbs/mmBtu floor rate consistent with using 0.06 lbs/mmBtu as a floor. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.20]
[See p.20 of this comment summary for a table listing Duke Energy's Plants, the plant's unit, ORISPL, 2009 Ozone Season NOx Emission Rate, and 2009 Non-Ozone Season NOx Emission Rate]
E.ON U.S.
Comments Associated with EPA's NEEDS Database and IPM Modeling [EPA-HQ-OAR-2009-0491-2797.1, p.10]
Some NOx allocations are based on incorrect unit control equipment information. [EPA-HQ-OAR-2009-0491-2797.1, p.10]
The information in EPA's NEEDS database provided with the notice of proposed rulemaking (NEEDS v3.02) contains the following incorrect information: For E.W. Brown Unit 3, it shows an existing SCR in "post combustion control", although "SCR_Online_Year" field is blank, and it shows "Controlled NOx Base Rate" of 0.06 lb/mmBtu, reflecting existence of SCR in the Base Case. E.W. Brown 3 is under a Consent Decree to install an SCR by December 31, 2012. The compliance date is an aggressive deadline that resulted from extensive negotiations between EPA, the Department of Justice, and KU. KU anticipates completing the installation of the SCR on the Brown 3 unit near the end of 2012. It is infeasible to revise the schedule to achieve an expedited installation and thus the SCR will not be operating for most of 2012. EPA's updated NEEDS database v4.10 has corrected E.W. Brown 3 information; e.g., no SCR shown in "post combustion control" and a "Controlled NOx Base Rate" of 0.31 lb/mmBtu, which is reasonable. However, EPA has not to our knowledge provided updated allocations to reflect this. As such, EPA has provided incomplete information on which to comment. [EPA-HQ-OAR-2009-0491-2797.1, pp.10-11]
For Ghent unit 2, NEEDS v3.02 shows an SCR in "post combustion control" and SCR_Online_Year of 2009. The unit does not have an SCR and none is planned. It also shows a "Controlled NOx Base Rate" of 0.06 lb/mmBtu, reflecting existence of SCR in Base Case. The unit does not have an installed SCR and the company has no current plans to install one. EPA's updated NEEDS database v4.10 still has incorrect information for Ghent 2. [EPA-HQ-OAR-2009-0491-2797.1, p.11]
The incorrect information on both of these units resulted in very significantly incorrect unit allocations for these KU generating units and the overall state budgets in the proposed rule. [EPA-HQ-OAR-2009-0491-2797.1, p.11]
EPA has corrected Brown 3 post-combustion control information in its updated NEEDS database v4.10, but the most recent database is still incorrect in showing post-combustion control at KU Ghent Unit 2. The allocations for both units should be revised to reflect correct unit control equipment information. [EPA-HQ-OAR-2009-0491-2797.1, p.11]
There is inconsistency between data in the NEEDS database and that used for IPM modeling provided in the NODA. As examples, in NEEDS v4.10, Ghent unit 2 is shown to have a NOx emission rate of 0.03 lb/mmBtu, but IPM data shows that a rate of 0.06 lb/mmBtu was used.12For Ghent unit 4, NEEDS shows a rate of 0.06 lb/mmBtu, while the IPM modeling shows a rate of 0.03 was used. [EPA-HQ-OAR-2009-0491-2797.1, pp.11-12]
Discussions with other utility companies reveal that there were numerous other errors in basic information about units and control equipment that formed the basis of EPA's analyses. Correction of these errors will lead to revised modeling results, revised allocation values, and continued uncertainty regarding the actual requirements of the rule until it is finalized, which is expected to be mid-2011  -  only six months before the 2012 compliance date. [EPA-HQ-OAR-2009-0491-2797.1, p.12]
EPA should correct the inaccurate data, resulting analyses, state budgets, and unit allocations, and reissue the rule for public comment as a Supplemental Notice of Proposed Rulemaking. [EPA-HQ-OAR-2009-0491-2797.1, p.12]
NOx projected emissions for many KU and LG&E units are based on unrealistically low NOx emission rates. [EPA-HQ-OAR-2009-0491-2797.1, p.12]
EPA states that it assumes SCR's can achieve 90% removal, down to a floor of 0.06lb/mmBtu. However, EPA's projections include units achieving much lower rates (as low as 0.03 lb/mmBtu). EPA has clarified that the floor of 0.06 lb/mmBtu is only for new SCR's, and that lower emission rates were used for existing SCR's that temporarily achieved lower rates. Analysis of the historic data shows that EPA is assuming these lower rates based on a very limited time frame. Their TSD methodology uses emission rates based on historic ozone season emission rates. However, this is not representative of an achievable annual average emission rate. Units generally operate at high capacity levels during the summer ozone season, resulting in atypically low emission rates. During lower electricity demand periods when units operate at lower capacity levels, SCR's may not be operable due to low boiler exit combustion gas temperatures to the SCR. [EPA-HQ-OAR-2009-0491-2797.1, p.12]
Also EPA must consider degradation of catalyst reactivity over time, variations in unit design, and other factors which make it impossible for a unit to repeat its best short-term performance on a year after year basis. Our experience with year round operation (2009) and at units with relatively new catalyst layers indicates emission rates not lower than 0.05513lb/mmBtu. And even these low rates were only achieved at units equipped with economizer bypass which allowed SCR operation at an extended (lower) operating range. [EPA-HQ-OAR-2009-0491-2797.1, pp.12-13]
Unnamed new unit in Trimble County, Kentucky. [EPA-HQ-OAR-2009-0491-2797.1, p.13]
There is a unit in the allocation table designated "TVAK_KY_Coal Steam Unit 1." The "TVA" portion of the name appears to refer to the region, rather than the utility company. Other information indicates it is a 732 MW unit located in Trimble County. Since no other generating units are similar to the description, this suggests that the reference is to the 760MW Trimble County plant Unit 2. However, it has a different plant ORIS code than the Trimble County plant (ORIS 6071) and is called unit 1. [EPA-HQ-OAR-2009-0491-2797.1, p.13]
The allowance allocation table shows an SO2 allocation for 2012, but zero allowances allocated for 2014. [EPA-HQ-OAR-2009-0491-2797.1, p.13]
In the updated NEEDS database (v4.10), the unit information has been revised to list the unnamed unit with the county as "unknown" and with capacity of 750 MW. [EPA-HQ-OAR-2009-0491-2797.1, p.13]
Trimble County Unit 2 commenced commercial operation, as defined in the proposed rule, in 2010. Accordingly, it should receive an allocation for both 2012 and 2014 as an "existing unit" as defined in the proposed regulations. [EPA-HQ-OAR-2009-0491-2797.1, p.13]
4) SO2 projected emissions are unrealistically low. EPA appears to be assuming that even older FGD's can achieve 95% removal. LG&E's Cane Run and Mill Creek FGD's were among the first built in the U.S. in the late 1970's and early 1980's. They were designed to meet their emission limit of 1.2 lb/mmBtu and historical data shows that they are achieving approximately 90% removal efficiency. It is unrealistic to assume such units can reduce their emissions in half without substantial costs. For SO2 in Kentucky, EPA based 2012 allocations on "actual" recent emissions, with downward adjustments as deemed appropriate. The selected actual emissions are typically the first 3 quarters of 2009 and the fourth quarter of 2008. This period was not only the heart of the recent economic downturn, but ambient temperatures were milder than normal. Summer temperatures in the Midwest were over 25% below the 30-year average. Therefore, this period had significantly reduced electric generation and is unrepresentative of normal operations. Indeed, EPA's Base Case heat input projections for Kentucky are 17% higher than this time period. The low historic emissions combined with the higher projected heat input results in unrealistically low emission reduction targets; i.e., utilities in Kentucky would have to reduce emission rates by approximately 17% to meet the allocations for 2012. This is contrary to EPA's assertion that the 2012 reductions can be achieved without significant new equipment. [EPA-HQ-OAR-2009-0491-2797.1, pp.13-14]
East Kentucky Power Cooperative
EKPC Concerns Regarding EPA's Underlying Technical Data  [EPA-HQ-OAR-2009-0491-2776.1, p.2]
There are inconsistencies in the underlying technical data reviewed by EKPC that indicates the need to revisit the rule. For instance, EPA calculated the 2014 S02 allocation for EKPC's Spurlock Unit 1 to be 0.067lb/MMBTU and also calculated the 2014 allocation for EKPC's Spurlock Unit 2 at 0.093 lb/MMBTU. Both units have the same S02 emissions controls, thus a reason cannot be discerned for the differing allocations. The heat input 'assumed' for 2012 and 2014 at EKPC's Spurlock Unit 1 is listed at 17,179,025 (this represents a 56% capacity factor) for 2012 and 22,244,000 (this represents a 72.5% capacity factor) for 2014. [EPA-HQ-OAR-2009-0491-2776.1, p.2]
Moreover, EPA should not expect the same total heat input for nonscrubbed units to be a predictor of future emissions, emission allocations, electric demand and dispatch. A non-scrubbed unit can become a scrubbed unit that reduces the S02 emissions. A unit can be modified to accept a Selective Catalytic Reactor that reduces nitrous oxide. The total heat input of a unit and dispatch order will change once the unit receives the additional pollution controls, (i.e. from unscrubbed to scrubbed). Because the unit has lowered its emissions, the dispatch pecking order may change, thereby enhancing the number of hours operated in a calendar year, and thus increasing its total heat input and capacity factor. (Capacity Factor is a term that calculates the unit's utilization on a calendar year basis.) The Methodology of using the 2009 total heat input as a predictor of the future total heat input for 2012 and 2014 is incorrect. This approach can actually hinder usage of the lowest emitting units to meet demand.  [EPA-HQ-OAR-2009-0491-2776.1, p.2]
EKPC Practical and Technical Concerns [EPA-HQ-OAR-2009-0491-2776.1, p.5]
In drafting the rule, EPA appears to rely heavily on the ability of utilities to utilize lower sulfur coal. However, EPA should consider that, from a technical perspective, as sulfur is removed from coal, typically through scrubbing, the removal efficiency declines as a lower sulfur coal is utilized. Therefore, the efficiencies gained from using lower sulfur coal are not likely to be as great in practicality as in theory. [EPA-HQ-OAR-2009-0491-2776.1, p.5]
From a compliance perspective, EKPC requests EPA to acknowledge that often several units will share a common stack. For example, at its Dale Station, Units 1 and 2 have a common stack and Units 3 and 4 also share a common stack. Cooper Station has a common stack for Unit 1 and Unit 2 as well. Such technical realities may pose compliance issues. Technically speaking, it would be difficult for EKPC or any utility to determine which unit was not in compliance under the CATR rules since two units are tied to a common stack. CATR does not address how compliance will be determined, measured or verified on either a state or federal level. [EPA-HQ-OAR-2009-0491-2776.1, p.5]
East Texas Electric Cooperative
III. NELSON 6
Roy S. Nelson Unit 6 is a 550 MW PRB coal-fired unit located in Westlake, Louisiana. The unit's majority owner and operator is Entergy Gulf States. ETEC has concluded that Nelson 6 has been allocated adequate CATR seasonal and annual NOx allowances to permit continued operation without restriction. However, by choosing Nelson 6 SO2 emissions from the fourth quarter of 2008 and the first three quarters of 2009 as a baseline for determining CATR SO2 allowance allocations, the EPA has severely reduced the number of allowances from the level that would have been available had a longer baseline period been used. The nature of prudent coal unit operations and maintenance practices, where scheduled maintenance hours can vary by a factor of four from year to year makes it entirely unreasonable to select a single year for allowance allocation purposes. As shown below, during the four quarters selected by EPA (the most recent four quarters available at the time the Rule was developed) Nelson 6 emissions were significantly below those for any recent year and nearly 5% below those for most recent three year average (2007-2009). [EPA-HQ-OAR-2009-0491-2770.1 p.3]
[[Data table here]]
This anomaly was driven largely by a series of furnace tube leaks in October and November 2008 which resulted in an average forced outage rate of over 25% in those two months and a scheduled outage in February  -  April 2009 which extended to over 1,640 hours (nearly 10 weeks). In contrast, generation (directly tied to emissions) for the fourth quarter of 2009 was 15% higher than that recorded in the fourth quarter of 2008, and the average Nelson 6 scheduled outage time for 2005-2008 was less than 875 hours. The period chosen by EPA for its SO2 emissions baseline does not accurately reflect historical Nelson 6 operations and will not produce an allowance allocation that is consistent with the CATR seasonal NOx policy objectives. [EPA-HQ-OAR-2009-0491-2770.1 p.3]
IV. INDEPENDENCE UNIT 2
 Independence Unit 2 is an 842 MW PRB coal-fired unit located near Newark, Arkansas. ISES-2 is operated by Entergy Arkansas. Located in Arkansas, ISES-2 is subject only to CATR seasonal NOx emission limitations. By choosing ISES-2 heat input from the fourth quarter of 2008 and the first three quarters of 2009 as a baseline for determining CATR SO2 allowance allocations the EPA has severely reduced the number of allowances from the level that would have been available had a longer baseline period been used. As noted above, the nature of prudent coal unit operations and maintenance practices, where scheduled maintenance hours can vary by a factor of four from year to year makes it entirely unreasonable to select a single year for allowance allocation purposes. As shown below, during the 2008 ozone season selected by EPA ISES-2 heat input was significantly below that for any recent year and 18% below the average for the three most recent ozone seasons (2007-2009). [EPA-HQ-OAR-2009-0491-2770.1 p.3]
[[Data table here]]
This anomaly was largely driven by an abnormally high number (320 hours) of equivalent forced outage hours during June and July of 2008 and the commencement of scheduled maintenance in September 2008. The incident which caused the June outage and the majority of the forced outage hours  -  the failure of a low pressure turbine rotating blade (L-1 row)  -  required a summer outage lasting more than 264 hours (11 days) to remove the affected blade section and the blade section opposite the damaged section on the turbine shaft. The average number of forced outages hours during the 2005, 2006, 2007, and 2009 ozone seasons was less than 112. Entergy also removed ISES-2 from service for 385 hours (16 days) for scheduled maintenance. That event is the only time in the last five years that ISES-2 has been removed from service for scheduled maintenance for more than a week during the May-September ozone season. It is therefore very clear that the period chosen by EPA for its heat input baseline is not representative of typical ISES-2 operation. [EPA-HQ-OAR-2009-0491-2770.1 p.4]
The allowance allocation impacts of EPA selecting a single ozone season, particularly the 2008 season, upon its ISES-2 CATR seasonal NOx allowance allocation are demonstrated in the table above. [EPA-HQ-OAR-2009-0491-2770.1 p.4]
V. SAN JACINTO COUNTY AND HARDIN COUNTY PEAKING FACILITIES
ETEC wholly owns and contracts for the operation of the San Jacinto County Peaking Facility (SJCPF) located near Cleveland, Texas and the Hardin County Peaking Facility (HCPF) located near Lumberton, Texas. Each facility contains two GE Frame 7EA combustion turbine generators (CTGs). All four CTGs were relocated from a generating facility Warren County (near Vicksburg) Mississippi which rarely operated. Since entering commercial operation in Texas in July 2009 (SJCPF) and January 2010 (HCPF) these units have been operated extensively to support the reliability of the western reaches of Entergy's electric transmission and distribution system. Despite ETEC's timely notification of both the EPA and EIA, these units are still listed as being located in Mississippi in the EPA CATR allocation table. Seasonal NOx emissions for both plants are shown in the table below. An update with September 2010 data will be provided upon receipt of CEMS output for the month. [EPA-HQ-OAR-2009-0491-2770.1 p.4]
[[Data table here]]
ETEC solely wishes to ensure that the EPA recognizes that the SJCPF and HCPF generating units have been relocated from Mississippi to Texas and that they have operated extensively since their relocation. ETEC leaves it to EPA's discretion to determine from what pool of allowances and to what extent CATR seasonal NOx allowances should be fairly allocated to these facilities.  [EPA-HQ-OAR-2009-0491-2770.1 p.5]
Edison Electric Institute (EEI)
Many companies will report in their comments on the Proposed Rule that EPA has made incorrect assumptions regarding individual EGUs, including in the NEEDS data base (e.g., incorrectly describing pollution control retrofits), and that IPM modeling run outputs in some cases are erroneous (e.g., incorrectly projecting the fuels to be used, retirements, etc.). [EPA-HQ-OAR-2009-0491-2697.1, p.10]
New EGU information supplied by companies, combined with changes to the NEEDS database and the IPM identified in EPA's Transport Rule NODA, will lead to new model runs and state budgets supporting the final Transport Rule. If the new modeling runs lead to substantially different state budgets and company impacts, EPA may need to reissue the Proposed Rule for public comment as a Supplemental Notice of Proposed Rulemaking. [EPA-HQ-OAR-2009-0491-2697.1, p.12]
Edison Mission Energy (EME)
EPA's aggressive emission reduction timelines are also technically infeasible. EPA's claim that compliance with the Phase I emissions caps will only require electric generating units ("EGUs") to operate their existing controls year-round is simply incorrect. It is based on inaccurate assumptions by EPA about the control efficiency provided by existing controls (e.g., EPA assumed that existing SCRs will achieve a NOX emissions rate of 0.058 lbs/mmBtu, even though industry experiences suggests that 0.1 lbs/mmBtu is more appropriate for SCRs installed over the last decade). [EPA-HQ-OAR-2009-0491-2707.1, p.3]
EPA's Phase I NOx and SO2 Caps Are Premised On Incorrect Assumptions About The Level Of Emissions Controls Actually Achieved By Existing Emission Controls [EPA-HQ-OAR-2009-0491-2707.1, p.18]
As noted above, the Proposed Rule assumes that compliance with the Phase I deadline will be relatively easy because it will only require EGUs to either: (i) operate emissions controls year-round that are currently operated less frequently, such as NOx controls that have, until 2009,only been operated during the summer ozone season (May 1st  -  September 30th), and (ii)complete the installation of proposed controls that are scheduled to go online by 2012. Using these assumptions about the emission controls which will be in place by 2012, the Agency developed emissions estimates for each affected EGU based on its assumptions about the level of NOx and SO2 removal provided by those controls. For example, under the Proposed Rule, EPA assumed that existing SCRs will achieve a NOx removal efficiency of 90%, resulting in an emissions rate of 0.058 lbs/mmBtu. EPA may presume this assumption is reasonable for newly installed NOx controls operating under ideal conditions (e.g., at peak load, with fresh catalyst, and not accounting for start-up and shut down periods; see below). However, EME does not believe EPA's assumption is accurate for existing SCR systems that may only achieve approximately a 0.1 lbs/mmBtu NOx emissions rate. [EPA-HQ-OAR-2009-0491-2707.1, pp.18-19]
EME submits that the EGUs covered by the Proposed Rule will not be able to comply with the emission caps proposed in either Phase I or Phase II of the Rule. With respect to Phase I, EPA claims to have set those caps based on emissions reductions that are obtainable using existing controls that are currently available, or will those that will be installed by 2012. 59  [EPA-HQ-OAR-2009-0491-2707.1, pp.27-28]
However, EPA's assertion with respect to the feasibility of the 2012 deadline relies exclusively on its assumptions about the emissions rate reductions that will be achieved by those "existing controls." As explained above, EME has concluded that EPA relied on unrealistic assumptions about the control rates obtained by controls that have been installed over the last decade, and therefore has overstated the emission reductions that can be obtained by 2012. EME does not object to the premise that sources should be required to obtain by 2012 the maximum level of emission reductions that can be achieved using existing controls; EME simply believes that EPA has overstated the level of achievable reductions by assuming control efficiencies that are not supported by the available data. EME submits that EPA should recalculate the 2012emissions caps to reflect the emissions reductions that are actually available based on existing controls. Data on the performance of these controls is readily available as all sources affected by the Transport Rule monitor their emissions using CEMs. EME believes that any reanalysis will result in an increase the emissions budgets during the Transport Rule's Phase I compliance period. [EPA-HQ-OAR-2009-0491-2707.1, p.28]
Footnote 46: 75 Fed. Reg. at 45273. However, EPA may be greatly underestimating the controls required to meet the Transport Rule caps. For example, recent investment company research suggests that in order to comply with the Transport Rule and Utility MACT caps, companies will need to invest in approximately 40 GW of scrubbers. See UBS Investment Research, E&C and Utilities Call with ICF on EPA Regulations 1 (Sept. 16, 2010). Other investment company research suggests that meeting the Transport Rule's 2014 target for SO2 emissions will require the installation of SO2 scrubbers at 6% of U.S. coal fired power plants that generate 118 million MWh. See Bernstein Research, U.S. Utilities: EPA Announces Its Proposed Transport Rule to Replace CAIR; How Will the Coal Fleet Be Affected? 2 (July 7, 2010). [EPA-HQ-OAR-2009-0491-2707.1, p. 18]
Footnote 59: EME notes that EPA is not in the best position to know precisely for each EGU the types of controls in place, how they are performing, what additional controls are contemplated, and the timeline for installing such controls. Such information gathering and generation is better left to the states, which have a much closer connection to the actual sources themselves because they are dealing with a smaller universe of potential sources. In addition to the concerns above, EME is concerned that in bypassing the State SIP development process, EPA may have relied on assumptions about available controls that are not supported by real world conditions because the Agency did not have the most current or accurate data. EME anticipates that other groups, such UARG, will provide examples of such omissions/errors, and therefore endorses any concerns raised by those comments. [EPA-HQ-OAR-2009-0491-2707.1, p. 28]
Electric Energy, Inc. 
While the IPM model may be a useful planning tool for looking at different control scenarios it does not contain sufficient information on each Utility company and unit to make reasonable assumptions about controls or operation. For example in the IPM V 3.02, Joppa was shown as having FGD's on all six units by 2014. The IPM V 4.10 TR SB Limited Trading case shows these same units as 'Coal Early Retirement. And under IMP 4.10 TR SB Limited Trading AEO Gas no controls are assigned and none of the units are retired. These are vastly different outcomes with the likelihood of different allowance allocations from three separate runs of the IPM model. [EPA-HQ-OAR-2009-0491-2628.1, p.2]
Empire District Electric Company (Empire District)
The IPM data used as the base case to develop CATR is flawed due to the fact that it uses 2005 information which does not account for current pollution control equipment installed since 2005 as well as accurate projected emissions for 2012.  Corrected data should be utilized in all modeling platforms that EPA used to develop the CATR including IPM, SMOKE, and CAMx modeling.   Once all the modeling is completed revisions to CATR, if any, should be made and CATR revised. [EPA-HQ-OAR-2009-0491-2659.1, p.3]
In the 2012 and 2014 IPM Parsed data Empire District's Riverton units 12, 39 and 40; Energy Center units 1, 2, 3 and 4; State Line units 1, 2-1 and 2-2 were incorrectly modeled with zero emissions.  In addition, the 2014 IPM Parsed data indicates retrofit controls for Riverton units 39 and 40, State Line units 2-1, 2-2, and 2-3 as "early retirement" of these units.  Empire District routinely evaluates its generation resources, existing and future, as part of its Integrated Resource Plan.  This Integrated Resource Plan is officially submitted to the state regulatory authorities having jurisdiction over Empire District once every three years.  Empire District submitted its most recent Integrated Resource Plan to the Missouri Public Service Commission in early September 2010.  In this filed report, all of the aforementioned units are reflected as operational in the 2012 and 2014 timeframe; in other words, Empire District's analysis shows that these units are still viable units to serve our customers in an economic and reliable manner under our current regulations and assumptions. [EPA-HQ-OAR-2009-0491-2659.1, pp.3-4]
Because of these reasons Empire District believes that the IPM parsed modeling data should be revised to correctly reflect the operation of these units in the years 2012 and 2014.  Empire District has provided in a separate electronic submittal to EPA's Rulemaking Gateway, Appendix C data file and cover letter.  This separate submittal contains information which we believe reflects the 2012 and 2014 operation of the emission units that Empire District owns and has an interest in ownership. [EPA-HQ-OAR-2009-0491-2659.1, p.4; for additional comments pertaining to corrections to the IPM data, see pp.4-5 of this comment summary]
Environmental Energy Alliance of New York, LLC
  EPA's Transport Rule analysis does not recognize the reductions already made in New York State. New York State implemented Part 237 and Part 238 to reduce acid deposition in New York State by limiting emissions of NOx from fossil fuel-fired electricity generating units during the non-ozone season and SO2 over the entire year starting on October 1, 2004 for NOx and January 1, 2005 for SO2. Both of these regulations were budget trading programs but because the programs were essentially limited to New York they required reductions within the State. Although at first glance it seems that the emissions in 2005 should reflect full implementation of the rules, there were early reduction credits that eased the transition into the program. Table 1 lists New York EGU EPA CAMD website emissions for all programs from 2002 to 2009 and includes the Transport Rule Q4 2008 to Q3 2009 emissions. As shown in the table, by 2007 the Part 237 and 238 programs had reduced the state-wide NOx emission rate and mass by 37% and SO2 rate and mass by 66% over the average emissions between 2002 and 2004. There was another round of reductions in New York State in response to the Clean Air Interstate Rule (6NYCRR Parts 243, 244 and 245) that are not fully reflected in the Transport Rule's Quarter 4 2008 to Quarter 3 2009 twelve month emissions; the NOx emission rates for calendar years 2008 and 2009 as well as the year-to-date 2010 are all lower. [EPA-HQ-OAR-2009-0491-2638.1, pp.1-2] [[See Docket Number EPA-HQ-OAR-2009-0491-2638.1, p.2 for Table 1.]]
The Alliance believes that the observed reductions in New York NOx and SO2 emissions shown in Table 1 are not correctly reflected in the Transport Rule base case. It is therefore, important that individual data used in EPA's analysis be corrected. One issue that has been raised is SO2 emission rate in oil/gas boilers when burning gas  -  it is not clear if a gas rate is used. The EEANY member companies will be submitting unit-specific comments to correct the input data. [EPA-HQ-OAR-2009-0491-2638.1, pp.2-3]
Our concerns with respect to the current modeling approach are illustrated in Table 1 which is a comparison of the 2012 base case projections for two different IPM modeling runs with recent historical data in Table 1 illustrate our concerns about the approach used. In response to issues raised with IPM V3.02 modeling results summarized in May 2010, another modeling analysis, V4.10 summarized in August 2010, was run. The Alliance believes that the average of the last three years of historical data is a good representation of typical conditions. The 2007 to 2009 average heat input of all New York sources reporting to CAMD was 653,403,662. The original IPM run was very close to that heat input but IPM V4.10 was only 478,786,000, a 27% decrease. Therefore, the more recent IPM analysis is projecting significantly less frequent operations than recent information and NY company projections would indicate. Although IPM V4.10 projects annual SO2 emissions very close to the recent historical data, the SO2 rate is 34% higher than observed. Nonetheless this is a huge improvement because the original run had the SO2 mass and rate 148% higher. The Alliance is especially concerned that both IPM runs project significantly lower NOx rates than observed. IPM V4.10 projects a 44% reduction in NOx rate from the observed 2007 to 2009 average of 0.106 to 0.059 as the 2012 base case. [EPA-HQ-OAR-2009-0491-2638.1, p.3]
The Alliance is primarily concerned that the Transport Rule rule-making process has increased the reliance on modeling analyses to determine not only the state allocations but also unit-specific allocations. The Transport Rule used the Integrated Planning Model to forecast future emissions in both a base case and a control scenario that provide the primary basis for the proposed rule-making. However, IPM predictions vary widely depending upon the assumptions (e.g., fuel price and control technology price and availability) used in a particular modeling run and there are inevitably site-specific discrepancies caused by the modeling approach which cannot be expected to consider every constraint at every facility. [EPA-HQ-OAR-2009-0491-2638.1, pp.3-4]
The Eastern Regional Technical Advisory Committee (ERTAC) is taking a different approach to develop and improve the emissions inventories used for projecting future emissions. ERTAC is evaluating an approach which grows base hourly EGU emissions into future projection years. It is expected that this approach will be more realistic and robust for this kind of analysis. The Alliance agrees that this is a preferable approach and encourages EPA to re-do this analysis with that approach or something else that does not rely on IPM for all future projections. [EPA-HQ-OAR-2009-0491-2638.1, p.4]
Therefore the Alliance recommends the following:
-That the process be revised to insure IPM base case modeling compares well with actual observed information. This is particularly indicative here because the Alliance believes that the base case modeling may not compare well with recent, actual observations and, thus, may not be a reliable representation of projected New York operations and emissions and cannot provide the basis for an appropriate control case;  
-Incorporate steps to correct errors discovered in unit-specific information (member companies will be submitting specific comments in this regard);  [EPA-HQ-OAR-2009-0491-2638.1, p.4] 
EquiPower Resources Corp.
EPA acknowledges the potential limitations on trading created by the Transport Rule's assurance provisions in the Rule's preamble, but dismisses them as not being an issue because "more units are likely to have allocations close to their [actual] emissions." However, this assertion is premised on the assumption that EPA's allocations were based on accurate information about a source's potential emissions. As explained in more detail in Section V.B below, EPA's unit-level allocations are not based on accurate assumptions; indeed, in many instances the assumptions are: (i) not readily apparent from the Agency's supporting documentation, (ii) directly at odds with other regulatory requirements, and/or (iii) simply incorrect. Therefore, EPA's assertion that sources will "have allocations close to their emissions" cannot be supported  -  and, in any event, relies on the unsupported assumption that unit utilization will remain static over time, as discussed above. For example, EPA has adjusted Phase I state-wide emissions, and by extension unit-level allocations, by its assumptions about the level of emissions control that individual EGUs achieve using existing controls or those that the Agency believes will be available by 2012. EquiPower does not believe that the Phase I caps reflect the level of emission reductions that are actually obtainable using existing controls or those that will be available by 2012. This is due to two types of erroneous assumptions made by EPA when making those budget adjustments. [EPA-HQ-OAR-2009-0491-2704.1, p.7]
First, EPA made assumptions about the level of control provided by existing controls which assumed that older, but still effective controls, obtained emissions rates that were equal to rates obtained by newly installed controls even though the Agency had (and should have used) data showing the actual level of performance achieved by those existing controls. The practical effect of this assumption is to penalize sources with older controls that have achieved substantial emissions reductions, but do not obtain the peak control rates that EPA assumes to be feasible. Moreover, EquiPower does not believe that EPA's assumed control rates for new controls are necessarily achievable on a sustained basis because they only reflect the level of control obtained when a unit is operating at peak capacity and do not reflect the level of control obtained during periods of start-up, shutdown, or non-peak operation that occurs throughout the year at most sources. [EPA-HQ-OAR-2009-0491-2704.1, p.7]
Second, and more glaringly, because of EPA's FIP approach, the Agency's allocations make inaccurate assumptions about existing controls or when new controls will be available. Most notably for sources in New England, and Massachusetts in particular, EPA has adjusted the 2012 SO2 budget for Unit 3 at Dominion's Brayton Point Power Plant by assuming that the unit's FGD will be online in 2012. However, EquiPower understands that construction of that FGD is not scheduled to begin until April 2011, and therefore that the FGD will not be in operation until sometime between the fall of 2013, at the earliest, and the first quarter of 2014. Unit 3 is the largest unit at Brayton Point, which in turn is the largest coal-fired power plant in New England. As a result, the Agency has seriously understated the level of emissions that will be produced by Brayton Point in 2012, and as a result has under-allocated its (and by extension, the entire state's) allowances. As a result, Brayton Point will likely buy up all of the excess SO2 allowances available in New England during Phase I to meet its needs, leaving no allowances for other sources that might need them. [EPA-HQ-OAR-2009-0491-2704.1, pp.7-8]
EPA Should Correct Errors In Its Allocations [EPA-HQ-OAR-2009-0491-2704.1, p.18]
The subsections below identify a number of erroneous assumptions about unit-specific characteristics in the Transport Rule that result in errors in both unit- and state-level SO2 and NOX allowance allocations. As explained below, these errors in EPA's data and assumptions with respect to EquiPower's facilities prejudice its unit-level allocations. Moreover, these errors show that EPA's data and assumptions are not in compliance with EPA's guidelines highlighting the Agency's "responsibility to ensure that the information is, and remains, accurate and credible." EquiPower requests that these comments regarding specific errors be considered a Request for Correction pursuant to EPA's Information Quality Guidelines, § 8.5. [EPA-HQ-OAR-2009-0491-2704.1, pp.18-19]
The Transport Rule's state emissions budgets and unit-level allowance allocations were based on the results of modeling which was intended to show the level of reductions required to assure that upwind sources of SO2 and NOX do not interfere with downwind attainment of specific air quality standards. Inputs into this modeling include assumptions about the (i) performance of new and existing controls and the resultant emissions reductions, (ii) projected capacity for individual units during Phase I and Phase II,(iii) type of fuel burned, and (iv) the maximum costs on a per ton basis for the required reductions. (For the Proposed Rule, EPA's cost thresholds were $2,000 and $500 per ton for SO2 and NOX, respectively).At the outset, EquiPower notes that the modeling tables provided by EPA are not transparent, making it difficult to track what assumptions have been made with respect to which units. Nevertheless, based on the assumptions that could be confirmed, EquiPower believes that EPA's allocation approach has not resulted in state budgets or unit-level allocations that are obtainable using either existing controls or those that EPA expressly identifies as being required based, in part, on flawed assumptions employed by the Agency. As explained above, EPA would have avoided these problems had it charged states with the responsibility of allocating allowances, as it is required to do under Title I of the CAA. In addition to these legal concerns, EquiPower believes that EPA has to make the following corrections to the assumptions it made with respect to EquiPower's facilities. [EPA-HQ-OAR-2009-0491-2704.1, p.19]
EPA Made Erroneous Assumptions about Unit Capacity Factors [EPA-HQ-OAR-2009-0491-2704.1, p.19]
Based on EquiPower's review of the available data, there appears to be a hidden unit capacity factor that EPA used in its state budget and unit-level allowance allocation calculations. Unfortunately, because of a lack of transparency in EPA's modeling tables, it is not possible to identify with precision the capacity factors used for specific units. Based on EquiPower's review of the allocations for its units, the Agency's capacity factor appears to have had a huge impact on the allocations for those units and has led to some readily apparent anomalies in the allowance allocations for each unit. [EPA-HQ-OAR-2009-0491-2704.1, p.19; for additional comments pertaining to EPA Made Erroneous Assumptions about Unit Capacity Factors, see pp.19-22]
EPA Made Inaccurate And Inconsistent Assumptions About The Performance Of Existing Controls At Different Units [EPA-HQ-OAR-2009-0491-2704.1, p.24]
In addition to the capacity factor errors and failure to account for dual fuel operations, EPA's modeling also contained inaccurate and inconsistent assumptions about the performance of emissions controls at EquiPower's facilities and at other facilities in New England. The most notable example of this kind of omission is EPA's error with respect to Brayton Point 3's FGD. As explained above, EPA assumed that the FGD would be available in 2012 to meet the Phase I emission caps; however, EquiPower understands that construction of that FGD will not start until 2012 and that it will not be available until 2013 or later. Because of the size of the Brayton Point plant and EPA's chosen methodology for calculating state budgets and allocating allowances, this error has a material impact on sources in New England and will necessarily constrain the availability of SO2 allowances in New England. A fundamental error like this must be corrected before the Proposed Rule is finalized and could have been avoided had states been charged with establishing allocations as required by the CAA. [EPA-HQ-OAR-2009-0491-2704.1, p.24]
In addition to these basic errors, EPA appears to apply its assumptions inconsistently. For example, EquiPower's Lake Road Facility in Connecticut is functionally identical to another facility located in Connecticut (Milford Power); both units have the same capacity, use the same equipment and provide roughly the same heat input based on data reported by sources to EPA. However, EPA's allocations for the two units are materially different. Despite their similarities, the Lake Road Facility's allocations are basically half of Milford Power's. The basis for this disparity in allocations appears to be EPA's application of a much less stringent emissions rate assumption on the Milford Power facility. See Table 6. [See p.24 of this comment summary for Table 6] Given that these facilities are identical, the Milford Power facility's allocations should track those at the Lake Road Facility. [EPA-HQ-OAR-2009-0491-2704.1, p.24]
In Addition To The Various Unit-Level Errors, EPA Also Has To Correct Its State-Level Emission Budgets [EPA-HQ-OAR-2009-0491-2704.1, p.25]
EquiPower believes that the errors identified above call into question EPA's assumptions and modeling. For example, according to the Agency, the reductions required during Phase I of the Transport Rule are only supposed to require that the status quo be maintained (i.e., the Phase I reductions are those that are available from emissions controls that either currently exist  -  e.g., running current SCRs year round  -  or those that are in the pipeline and will be available by 2012). Based on the errors identified above, it is unclear how that can be the case because the Agency's modeling does not capture the status quo accurately. As a result, EquiPower believes that the Agency needs to correct the various unit-level errors identified above, or raised by any other party, and then revisit its state-level emissions budgets so that they too can be corrected. [EPA-HQ-OAR-2009-0491-2704.1, p.25]
Exelon
Exelon has reviewed relevant technical support documents relating to EGU emissions and allowance allocations, and has the following additional comments on specific issues regarding Exelon's facilities. [EPA-HQ-OAR-2009-0491-2666.1, p. 44; for additional comments on specific issues regarding Exelon's facilities in the Technical support documents, see pp.44-45 of this comment summary]
Exelon recognizes that EPA continues to refine its modeling and will continue to refine its allowance allocations. Indeed, Exelon urges EPA to adopt an allowance methodology that avoids issues such as these that arise from modeling exercises, and instead to adopt the allocation methodology discussed above. In the event that EPA does not adopt a more verifiable allocation methodology, Exelon urges EPA to correct the allocations of allowances to these units, based on the information provided herein. Exelon continues to investigate various anomalies in EPA's IPM modeling and emission allocations to certain types of units and in certain states. This discussion may provide further basis for additional technical comments, which Exelon may submit in connection with the NODA. [EPA-HQ-OAR-2009-0491-2666.1, p. 45]
First Energy
In support of the comments above, please see Appendices A and C [See p.12 (Appendix A) and 24 (Appendix C) of this comment summary] for details regarding the modeling completed by Alpine Geophysics on behalf of MOG. [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.2]
Construction Assumptions & Time Schedules
The EPA has extremely aggressive assumptions built into their control equipment construction timelines that FE believes to be so extremely optimistic that they are infeasible. Specifically, the EPA referenced construction and installation schedules for a scrubber at 27 months and an SCR at 21 months. FirstEnergy just completed a complex scrubber and SCR retrofit project at our Sammis Plant earlier this year, driven by an aggressive schedule in a Consent Decree with the EPA. This scrubber and SCR installations at the Sammis Plant required 58 months from initiation of project engineering to construction completion. See Appendix B for two pictures that will illustrate the magnitude and complexity of this retrofit project. [EPA-HQ-OAR-2009-0491-2657.1,p.5] [[See Docket Number EPA-HQ-OAR-2009-0491-2657.1, p.27 for Appendix B.]]
Additionally, the 27 month scrubber installation assumption does not accommodate a coordinated schedule to site, permit and construct a landfill to accept the waste generated by the scrubber. FirstEnergy needed nearly five years to site, permit and construct a landfill to allow Sammis Plant scrubbers to begin operation. Likewise, FE has also recently installed SNCR's which required from 12 months to 18 months, compared to EPA's unrealistic assumption. Actual, recent experience by FE invalidates the EPA's schedule assumptions for control equipment installations. [EPA-HQ-OAR-2009-0491-2657.1, p.5]
Additionally, the number of major construction projects required by CATR will stress the capability and capacity of 1) architect/engineering firms, 2) shop space for major components, and 3) the skilled labor force required over the duration of a major construction project. FE experienced skilled labor shortages during the R.E. Burger SNCR installation in May 2008. Scrubber outages within AEP and FE impacted the available supply of certified welders at R.E. Burger. Granted this was a small project relative to scrubber and SCR installations, but it highlights the potential labor impact if utilities immediately ramp up major construction projects between 2012 and 2014. Couple the unavoidable increase in project construction for CATR compliance with the likely compliance requirements for the EGU MACT, and the available resources necessary for project completion will vanish. Given the potential impact of prolonged construction schedules, FE recommends that, at a minimum, EPA include a mechanism for compliance delay approvals in CATR. [EPA-HQ-OAR-2009-0491-2657.1, pp.5-6]
EPA needs to modify its very aggressive and unrealistic assumptions to reflect actual experience at real-world retrofit locations, which suggests that the Phase 2 deadline in CATR  -  if the rule is indeed still needed - should be pushed out until at least 2016. [EPA-HQ-OAR-2009-0491-2657.1,p.6]
Low NOx Burners (LNB)
The EPA assumes the engineering, modeling, procurement, and installation of low NOx burner (LNB) technology can be completed within six (6) months. Individual burner design is highly site specific and it is incorrect to assume that LNB manufacturers have an abundant supply of universal LNB's available for utilities to purchase off the shelf. FE has installed LNB's on a broad cross-section of its boilers. Following initial design and procurement which typically take 4 months, the duration between awarding the project until the material arrives on site is typically 8-9 months. Burner installation then needs to be coordinated with a scheduled boiler outage, which typically has a 6 to 8 week duration. Based on the duration of these activities, a typical LNB installation is 18 months  -  assuming it can be lined up with an appropriately timed boiler outage. [EPA-HQ-OAR-2009-0491-2657.1,p.6]
Finally, prudence dictates that a Company will not commit to a major capital improvement like a LNB, scrubber or SCR installation until final rules are issued. Therefore if the CATR is issued as a final rule in June of 2011, this leaves only 30 months to complete a significant number of complex capital projects across a large number of facilities before the proposed Phase 2 deadline of January 1, 2014. As stated earlier, there are also the very real physical and logistical limitations on resources including engineering, materials, shop space and skilled labor which - based on past experience  -  limit the capacity of the industry to complete multiple projects in the same region simultaneously. [EPA-HQ-OAR-2009-0491-2657.1, p.6]
Cost Assumptions
FE does not agree with EPA's capital cost assumptions ($/kW) for scrubber installations. FE capital cost experience at WH Sammis for a 2005-2010 Scrubber installation with a multi unit configuration (2-vessels, 840 GMW/vessel) was between $340 and $360/kW. The remaining WH Sammis scrubber for Sammis Units 1-4 (192 GMW each) was between $470 and $490/kW. The EPA data unrealistically assumes a cost range of similar scrubber size from $182 to $215/kW. This understates the capital cost by as much as 250%. Similarly, the EPA unrealistically assumed O&M costs ($/kW) that are only half of FE's actual O&M cost. Since model outputs are based on these incorrect EPA assumptions, FE recommends the EPA correct the IPM input data to reflect real world installation and operating costs. The EPA should re-run the IPM model cost curves, re-determine each state's "Significant Contribution," revise state allocation totals for NOx and SO2, and correct the individual unit allowance database. [EPA-HQ-OAR-2009-0491-2657.1, pp.6-7]
FE also does not agree with EPA's capital cost assumptions ($/kW) for SCR installations. FE capital cost experience at WH Sammis for a 2005-2010 SCR installation for WH Sammis Units 6&7 was between $220 and $250/kW. The EPA data unrealistically assumes a cost range on a similarly sized unit at $169/kW. [EPA-HQ-OAR-2009-0491-2657.1,p.7]
General NOx reduction assumptions relative to industry and FE units
The 90% SCR NOx reduction applied to the NEEDS data by the EPA does not reflect typical industry experience. A 90% removal efficiency is exceedingly difficult and rare to achieve on a long term annual basis as performance degrades due to SCR fouling, catalyst deactivation and system reliability. Based on 2009 CAMD data from 224 units, SCR NOx removal efficiency for the industry averages just over 80%. [EPA-HQ-OAR-2009-0491-2657.1,p.7]
Control equipment performance and removal efficiency assumptions need to account for actual individual unit performance under day-to-day operating conditions, not a performance guarantee removal efficiency provided by a vender based on one-time short term tests conducted immediately after a control device is commissioned. For pre-CAIR SCR's, typical performance assumptions were designed to and based on seasonal operation, not annual operation. EPA's SCR NOx reduction assumption does not reflect real world operation where SCR's foul and catalyst deactivates resulting in control equipment performance degradation over time. [EPA-HQ-OAR-2009-0491-2657.1, p.7; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.6 10/15/2010]
Likewise, deeply staging combustion with low NOx burners to drive down furnace NOx results in a reducing atmosphere in the furnace, significantly shortening boiler tube life and increasing outage O&M and capital costs. Operating in an oxygen deficient atmosphere to reduce NOx also has the side effect of increasing carbon content in the ash and soot emissions from the boiler, resulting in a very difficult balancing act between minimizing NOx emissions and maintaining particulate compliance. This fact does not appear to be addressed in the EPA's analysis. [EPA-HQ-OAR-2009-0491-2657.1,p.7; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.6 10/15/2010]
Sergeant and Lundy SNCR Cost Estimate data sheets for NEEDS referenced a 25% NOx reduction for their cost model. The EPA uses a 35% reduction in the utility NEEDS data which is not representative of real world performance over the boiler operating range. In order to improve the data accuracy, the SNCR removal efficiency assumptions should be corrected from 35% to 25%. [EPA-HQ-OAR-2009-0491-2657.1,p.7]
Fuel Switching Assumptions
Fuel switching is an alternative identified by the EPA to reduce SO2 without installing Flue Gas Desulfurization (FGD). The EPA states in the preamble to the rule that particulate emissions will likely increase due to the increased use of low sulfur, Powder River Basin (PRB) fuel. Increasing emissions is directly related to the electrostatic precipitator's decreased collection efficiency relative to the sulfur content of the PRB along with the increased volume of flue gas. The EPA should include the capital investment required to maintain good ESP performance in the cost assumptions. ESP's that will underperform with low sulfur fuel may require flue gas conditioning systems, upgraded power supplies, and/or total rebuild of the particulate control equipment. These costs are highly variable by unit and installation, but are typically in the $25-50/kW range. [EPA-HQ-OAR-2009-0491-2657.1,pp.8-9; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.7 10/15/2010]
The EPA further assumes any unit capable of burning a blend of PRB can burn 100% PRB without issue. This assumption is grossly inaccurate. In is FE's experience that units switching to 100% PRB are invariably assigned a fuel derate. A unit may be able to blend PRB with bituminous fuel to achieve NDC, but each boiler would have a unique blending level and derate. Typically, the derate is related to the significant drop in Btu's in the PRB fuel vs. typical eastern fuel (approximately 30% less Btu's in PRB) and limitations with increasing the volume of fuel feed and air flow to make up for the lower heat content of the PRB substitute. [EPA-HQ-OAR-2009-0491-2657.1, p.9]
On the other hand, the IPM model should also account for improved NOx emissions on units switching to 100% PRB. Typical PRB fuel bound nitrogen is ~0.8% while bituminous fuel bound nitrogen is ~1.0 to 1.2%. IPM should also account for the improved NOx emissions when considering fuel switching as an option to control SO2 emissions. [EPA-HQ-OAR-2009-0491-2657.1,p.9]
The EPA's assumption that multiple units can switch to 100% PRB without significant capital cost at a facility does not account for the necessary fire protection, dust suppression, mill adjustments and coal pile reconfiguration required to accommodate firing PRB fuel. [EPA-HQ-OAR-2009-0491-2657.1, p.9]
Appendix 3-3 New Source Review (NSR) Settlements in EPA Base Case v.4.10
On page 3-3.7, the statement made regarding the Ohio Edison Consent Decree (CD) for a NOx limit on Sammis Unit 6 & 7 `Operate to the minimum extent practical' is incorrect. The Sammis NOx rate in the Sammis CD is 0.100 lb/mmBtu on a 30-day rolling average (Page 18 of the Consent Decree). Additionally, the CD requires NOx emissions reductions from Eastlake Unit 5 and Burger Boiler 7&8. Eastlake Unit 5 must accumulate an 11,000 ton reduction from 2003 levels. Burger 7&8 must accumulate a 1,400 ton reduction from 2003 levels (Page 13&14). These additional reduction requirements would have an impact to the IPM runs since they require continuous operation of the installed pollution controls. Additionally, Eastlake 5 & Burger 7&8 have a reduction requirement based on Heat Input. Modeled heat input reductions on EL5 and/or Burger 7&8 would make compliance with the CD difficult. [EPA-HQ-OAR-2009-0491-2657.1, p.11; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.11 10/15/2010]
In general, the EPA makes assumptions that do not relate to required operations on specific Units. FE recommends the EPA correct ALL utility data to reflect accurate model inputs. [EPA-HQ-OAR-2009-0491-2657.1,p.12; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.11 10/15/2010]
Florida Electric Power Coordinating Group, Inc. (FCG)
EPA's imposition of a 2012 compliance obligation is unreasonable and unrealistic, particularly since EPA intends to finalize the rule less than six months before it becomes effective. EPA attempts to dismiss this burden, however, by claiming that the emission levels required in 2012 generally reflect only the emission reductions that would occur even in the absence of the Transport Rule, primarily in compliance with CAIR. However, in a number of cases EPA has made incorrect assumptions regarding emission reductions that will occur at units by 2012. In addition, the approach set forth in the proposed Transport Rule penalizes early emission reductions under CAIR and seriously weakens market incentives. [EPA-HQ-OAR-2009-0491-2658.1, p.2]
FCG members have noticed multiple errors in EPA's 'Unit Characteristic' spreadsheet and other spreadsheets which were utilized to base future reductions per this rulemaking, e.g., unit pollution control equipment in place and operating. In some cases, the pollution control device which is not listed in the spreadsheet has been installed for multiple years and is required to operate in order to meet State permit specific emission limits. [EPA-HQ-OAR-2009-0491-2658.1,p.9]
As stated above, FCG members will be sending comments on an entity-specific basis regarding the needed changes to EPA during this comment period. The FCG, however, is concerned that it will be deprived of an opportunity to comment after EPA makes the necessary corrections to their dataset. In sum, EPA will need to perform additional modeling and calculations after corrections have been made to many regulated units, and such changes will be substantial enough to warrant an additional notice and comment period. The correction of these extensive errors will necessarily change the compliance obligations of every state, company and unit, and affected parties must be given an opportunity to review and comment as to whether EPA has corrected its mistakes, and parties can meet their new compliance obligations. [EPA-HQ-OAR-2009-0491-2658.1,p.10]
Florida Municipal Power Agency (FMPA)
5. In EPA's proposed allowance Allocation Table, Cane Island (ORIS Code 7238) Units 2 and 2A have improperly received separate allowance allocations, as have Cane Island Units 3 and 3A. In EPA's Technical Support Document "State Budgets, Unit Allocations, and Unit Emissions Rates", EPA states, "In cases where one unit with reported emissions matched to multiple units in the IPM/NEEDS inventory, emissions were divided equally." Cane Island Units 2A and 3A are the bypass stacks for Cane Island Units 2 and 3, respectively. Prior to EPA's adoption of XML format reporting for 40 CFR 75 Electronic Data Reports (EDR's), these units reported emissions separately for the main and bypass stacks. This is probably why they are listed as separate units in the IPM/NEEDS inventory, which led to EPA's dividing of the emissions. Reporting of emissions at the overall unit level has been required since EPA changed to the XML EDR format in first quarter 2009, therefore, reported emissions from Units 2 and 3 now include the emissions from bypass stacks 2A and 3A. In order to align RTR allowance allocations with 40 CFR 75 reporting requirements for these units, FMPA recommends that the sum of the allowances allocated to Units 2 and 2A and the sum of the allowances allocated to Units 3 and 3A be allocated to Units 2 and 3, respectively. [EPA-HQ-OAR-2009-0491-2725.1, p.7]
Four Flags Area Chamber of Commerce
The modeling the EPA used to determine the Rule's compliance requirements is out of date and/or inaccurate. The EPA based its assessments on equipment and capabilities that in some cases are not yet in place. In order for generation companies to comply with the emissions targets, they will have to install equipment that the EPA has mistakenly indicated is already operational or will be in service soon. This error underestimates the cost of compliance and exacerbates another inaccuracy in the EPA's compliance assumptions - the time and cost needed to design, permit, fabricate and install control equipment. [EPA-HQ-OAR-2009-0491-3807, p.2]
George Washington University Regulatory Study Center
Second, there is also likely model uncertainty associated with developing these estimates. For example, EPA uses its Integrated Planning Model (IPM) to develop projections of baseline emissions in 2012. EPA also used IPM modeling in the 2005 CAIR rule to project future emissions through 2015. As it turns out, emission reductions since CAIR was published in 2005 have exceeded the IPM projections for the CAIR rule. As the EPA puts it, "Substantial emissions reductions have occurred as a result of the CAIR programs. These reductions are greater than were expected when the rule was promulgated." [EPA-HQ-OAR-2009-0491-2573.1, p.23]
Georgia Department of Natural Resources, Air Protection Branch
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.92.]
A specific example is that EPA has modeled approximately 551,000 tons of SO2 in 2012, while the modeling inventory for our PM 2.5 SIPs that have been submitted to EPA use approximately 233,000 tons of SO2 in 2012. Clearly more than doubling the emissions would grossly misrepresent Georgia's impact on non-attainment or maintenance areas in other states.
Giarmarco, Mullins & Horton, P.C.
Below, MCV provides information to address what it believes to be incorrect emissions model assumptions resulting in erroneous unit-specific projections generated by the IPM model in support of the Proposed Rule and as contained in the 'Budget and Allocations - Detailed Unit-Level Data' spreadsheets. This information was reviewed in conjunction with EPA's Notice of Data Availability dated September 1,2010 and may be further commented on by MCV as allowed under that notice. [EPA-HQ-OAR-2009-0491-2766.1, pp1-2]
- The 2008 Reported Annual Heat Input figures appear to be accurate when observed collectively, however specific unit figures do not match MCV reported records. In particular, the heat input values for Units GT8, GT9 and GT3 are 50% of the values reported by MCV. EPA then appears to account for the 50% shortfall of Units GT8, GT9 and GT3, by assigning an equivalent value to BP15, ST1, and ST2. MCV believes that Units BP15, ST1, and ST2 should be zero. [EPA-HQ-OAR-2009-0491-2766.1, p.2]
- The 2009 Reported Annual Heat Input figures appear to be accurate when observed collectively, however specific unit figures do not match MCV reported records. In particular, the heat input values for Units GT8, GT9 and GT3 are 50% of the values reported by MCV. EPA then appears to account for the 50% shortfall of Units GT8, GT9 and GT3, by assigning an equivalent value to BP15, ST1, and ST2. MCV believes that Units BP15, ST1, and ST2 should be zero. [EPA-HQ-OAR-2009-0491-2766.1, p.2]
- MCV believes that the balance of all reported unit-specific heat input and mass data as reflected on the 'Reported Data' spreadsheet, suffers from the same errors identified in the preceding two paragraphs. Use of this data appears to produce erroneous IPM modeling results throughout the MCV data set as exemplified in the allocation of emission allowances to the two steam turbines. [EPA-HQ-OAR-2009-0491-2766.1, p.2]
- The projected emissions and corresponding heat input values appear to be the result of incorrect assumptions that MCV gas-fired units are operated relatively infrequently as peaker units. This is incorrect, as MCV operates its unit as a base load plant. MCV believes that the projected ozone total is 100X less than its expected use. Further, MCV believes the projected annual total is at least 20X less than expected use. [EPA-HQ-OAR-2009-0491-2766.1, p.2]
- MCV is unable to determine the genesis of the 'adjusted for controls and heat input figures assigned to all of its units. [EPA-HQ-OAR-2009-0491-2766.1, p.2]
- The projected annual and ozone NOx emission rates are inconsistent with expected emissions. The identified ozone NOx emission rates appear to be overstated by a factor of 10X, while the annual NOx emission rates appear to be understated by a factor of 10X. [EPA-HQ-OAR-2009-0491-2766.1, p.2]
Gulf Coast Lignite Coalition
EPA Should Rely on Historical Data Rather than the Integrated Planning Model (IMP). [EPA-HQ-OAR-2009-0491-3744.1_NODA, p.2]
The IPM inputs are based on flawed assumptions regarding the electric generating units' fuel sources, ability to switch fuels, and operational longevity. GCLC questions how allowance allocations and emission budgets can be based on speculative assumptions rather than historical data. [EPA-HQ-OAR-2009-0491-3744.1_NODA, p.2]
To prevent any public notice concerns and the promulgation of a final Transport Rule based on flawed assumptions, the EPA should issue a Supplemental Proposed Transport Rule based on historical data, and issue a revised Regulatory Impact Analysis, allowing the public an opportunity to comment, before promulgating a final Transport Rule. [EPA-HQ-OAR-2009-0491-3744.1_NODA, p.2]
Indiana Builders Association 
The EPA has not accurately estimated the cost of compliance with this proposal, from the perspective of the cost of installing new equipment as well as the actual equipment needed. [EPA-HQ-OAR-2009-0491-2871.1, p.1]
Power companies in Indiana inform us that the costs the EPA used as the basis for designing, permitting, fabricating and installing flue gas desulfurization units are less than half of market rates. Again, the cost of compliance is not accurately reflected in the EPA's estimates. The home builders in our membership will have to bear a financial burden that may be unneeded. Now is not the time for expensive government mandates that will provide questionable benefits. [EPA-HQ-OAR-2009-0491-2871.1,p.2]
The modeling the EPA used to determine the Rule's compliance requirements is out of date and/or inaccurate. The EPA based its assessments on equipment and capabilities that in some cases are not yet in place. In order for generation companies to comply with the emissions targets, they will have to install equipment that the EPA has mistakenly indicated is already operational or will be in service soon. This error underestimates the cost of compliance and exacerbates another inaccuracy in the EPA's compliance assumptions  -  the time and cost needed to design, permit, fabricate and install control equipment. [EPA-HQ-OAR-2009-0491-2871.1, p.2]
Indiana Cast Metals Association (INCMA)
The EPA has not accurately estimated the cost of compliance with this proposal, from the perspective of the cost of installing new equipment as well as the actual equipment needed. [EPA-HQ-OAR-2009-0491-2178.1, p.1]
Power companies in Indiana inform us that the costs the EPA used as the basis for designing, permitting, fabricating and installing flue gas desulfurization units are less than half of market rates. Again, the cost of compliance is not accurately reflected in the EPA's estimates. The foundries in our membership will have to bear a financial burden that may be unneeded. Now is not the time for expensive government mandates that will provide questionable benefits. [EPA-HQ-OAR-2009-0491-2178.1, p.2]
The modeling the EPA used to determine the Rule's compliance requirements is out of date and/or inaccurate. The EPA based its assessments on equipment and capabilities that in some cases are not yet in place. In order for generation companies to comply with the emissions targets, they will have to install equipment that the EPA has mistakenly indicated is already operational or will be in service soon. This error underestimates the cost of compliance and exacerbates another inaccuracy in the EPA's compliance assumptions  -  the time and cost needed to design, permit, fabricate and install control equipment. [EPA-HQ-OAR-2009-0491-2178.1, p.2]
Indiana Energy Association
b. An example of the technical errors in the EPA CATR analysis is that EPA assumes that since EGUs have been able to construct scrubbers and SCRs in a specific number of months in the past, that schedule will work for future controls at all plants . While that assumption may have technically worked for CAIR controls, CAIR included widespread regional emissions trading and multistate emission caps. The proposed CATR has state-specific caps resulting in companies being more reliant on in-state focused compliance and therefore making emissions trading far less likely and marginally more costly . That means that many sources in individual states will not be able to install controls in the timeframe the EPA has assumed is reasonable . EPA has provided no technical analysis for each individual state supporting its conclusion that individual state sources will be able to meet the required pollution control installation implementation dates. This is especially true in a state like Indiana, which is more dependent on coal-fired generation than virtually any other CATR state and where units have multiple characteristics that are not similar to other states in which a few large units have been able to construct controls . The Indiana Utility Group therefore believes that, in order to reflect the real world of EGU operations, each state's potentially affected sources will have to be analyzed separately for the final rule in order to determine a realistic compliance schedule for units in each state . [EPA-HQ-OAR-2009-0491-3711 p.2]
Indiana Manufacturers Association, Inc. (IMA)
The modeling the EPA used to determine the Rule's compliance requirements is out of date and/or inaccurate. The EPA based its assessments on equipment and capabilities that in some cases are not yet in place. In order for generation companies to comply with the emissions targets, they will have to install equipment that the EPA has mistakenly indicated is already operational or will be in service soon. [EPA-HQ-OAR-2009-0491-1813.1, p. 1]
The IMA encourages the EPA to delay implementation of the Transport Rule as it is proposed. The current proposal has several shortcomings that will result in needless economic harm to Indiana. [EPA-HQ-OAR-2009-0491-1813.1, p.1]
Reasons to delay include: The EPA has not accurately estimated the cost of compliance with this proposal, from the perspective of the cost of installing new equipment as well as the actual equipment needed. [EPA-HQ-OAR-2009-0491-1813.1, p. 1]
Power companies in Indiana estimate the costs the EPA used as the basis for designing, permitting, fabricating and installing flue gas desulfurization units are less than half of market rates. Again, the cost of compliance is not accurately reflected in the EPA's estimates. Industry in Indiana will have to bear a financial burden that may be unneeded. [EPA-HQ-OAR-2009-0491-1813.1, p. 2]
Louisiana Public Service Commission
The LPSC Staff believes that the baseline generation data and modeling utilized by the EPA in formulating its NOx allocations is flawed and leads to results entirely inconsistent with the current and anticipated dispatch of Louisiana's EGUs. The expedited time period for analysis and comment has restricted the LPSC Staff's ability to develop a strong item-by-item critique of the EPA's baseline data and assumptions, much less the dispatch modeling and its underling algorithms. [EPA-HQ-OAR-2009-0491-2670.1, p.7]
The LPSC Staff first notes that a fundamental shortcoming in the EPA dispatch analysis rests with its assumption that no regional transmission constraints exist. Anyone familiar with the bulk power system in South Louisiana understands that the state's unique geography, coupled with limited transmission capacity along certain strategic transmission line segments, results in a number of transmission bottlenecks in the area west of the Atchafalaya Basin ('WOTAB'), as well as the area leading into the greater New Orleans area. 1 There are also considerable constraints limiting the flow of power from north of WOTAB into the greater Acadiana region of the state. During certain periods of the year, the constraints in the central part of the state limit the use of base load generation that can be transported from the coal units subjected to the CATR to the loads in greater Lafayette region. [EPA-HQ-OAR-2009-0491-2670.1, p.7]
Bulk power systems are generally operated and 'optimized' on a principle of 'economic dispatch' subject to reliability constraints. In other words, least cost generators are utilized in any given hour to meet load requirements, provided those units can be dispatched economically and reliably, and the capacity to transport that capacity is available. Transmission constraints however, can necessitate the utilization of higher cost, more localized units to replace (not displace) lower cost generation blocked by the constraint. Commonly constrained areas are often referred to as 'load pockets,' and the uneconomic dispatch required to serve the loads in these load pockets is referred to as 'out-of-order' dispatch. The localized units used to meet these requirements are referred to as 'regulatory must-run' ('RMR') generators. [EPA-HQ-OAR-2009-0491-2670.1, p.8]
RMR generators are often utilized in Louisiana to overcome transmission constraints in the state's three main load pockets. RMR units can also be used to meet voltage, balancing, and regulation support (generally, 'reactive power' requirements) that are important in maintaining system stability and reliability. The EPA model entirely ignores the challenges of Louisiana's bulk power system and as such, leads to a variety of erroneous allocations for individual EGUs. [EPA-HQ-OAR-2009-0491-2670.1, p.8]
Allocations Not Consistent with CAIR. The LPSC Staff has provided a number of preliminary analyses comparing the allocations provided for under CAIR, and those provided for under the CATR. The comparisons are incremental to CAIR, and should not be interpreted as the total cost of compliance with overall NOx and SO2 compliance costs. Schedule LPSC-2 provides a summary comparison of the NOx allocations under CAIR and CATR by major EGU operator and fuel type, while Schedule LPSC-3 provides a unit-specific comparison of NOx allocations. Schedule LPSC-4 provides similar high-level comparisons for SO2 allocations for major EGU operator and fuel type, while Schedule LPSC-5 provides comparable information on a per EGU basis. [EPA-HQ-OAR-2009-0491-2670.1, pp.8-9]
[For additional comments pertaining to this topic, see pages 9-13 of this comment.]
The LPSC Staff appreciates the opportunity to comment on the proposed CATR. The LPSC Staff has serious reservations about the approach, methods and data that EPA utilized in determining its recommended NOx allocations for Louisiana's EGUs. The LPSC Staff is exceptionally concerned that EPA's current proposals could create considerable negative rate impacts for many Louisiana utility customers. The LPSC Staff recommends that the EPA revise its modeling and analysis and submit a revised rule with a meaningful comment period that provides parties with sufficient time to review the policy proposals and the empirical support underlying those proposals. However, if the EPA continues to move forward with its current proposals, the LPSC Staff recommends a NOx allocation based on the same per-unit proportions that was created under CAIR. This allocation has been provided in Schedule LPSC-7. [EPA-HQ-OAR-2009-0491-2670.1, p.15]
[Schedules can be found at the end of the comment.]

1. Referred to as the Amite South transmission control region. [EPA-HQ-OAR-2009-0491-2670.1, p.7]
Luminant
The baseline modeling for ozone does not appear to include EGU emission reductions in the Houston area, which may affect the outcome on Baton Rouge predictions. [EPA-HQ-OAR-2009-0491-2729.1, p.2]
Madison Gas and Electric Company (MGE)
We have reviewed the Proposed Rule along with the Technical Support Documents, including the proposed unit allocations, and have the following comments regarding proposed allocations to MGE-owned units. [EPA-HQ-OAR-2009-0491-2664.1, p.1]
:: There is a plant named 'Diesel Generators' in the Allocation Table with Office of Regulatory Information Systems (ORIS) No. 56070, which is listed as a combustion turbine having a capacity of 44.1 megawatts (MW). This entry refers to 54 separate diesel generators owned by MGE, with capacities ranging from 878 to 2,500 kilowatts (kW) each. Although no allocations were given to the Diesel Generators, this entry should be removed from the Allocation Table and any subsequent analysis to be completed for the Final Transport Rule. [EPA-HQ-OAR-2009-0491-2664.1, p.1]
:: Fitchburg Generating Station, Units 1 and 2, with ORIS No. 3991 are included in the Allocation Table even though the capacities of each unit are less than 25 MW. Although no allocations were given to either unit, they should be removed from the Allocation Table. [EPA-HQ-OAR-2009-0491-2664.1, p.1]
:: West Campus Cogeneration Facility (WCCF) units listed as Unit 1, CT2, and STG1 with ORIS No. 7991 are included in the Allocation Table and should be removed because WCCF meets the exemption for cogeneration facilities. WCCF is not currently subject to the Clean Air Interstate Rule and will continue to meet the criteria for exemption from the Transport Rule. Each unit was given a small number of nitrogen oxide allocations in the proposed Allocation Table. [EPA-HQ-OAR-2009-0491-2664.1, p.1]
Marquette Board of Light and Power
Inaccurate Project Control Technology
The EPA inaccurately projected that an SNCR would be installed on Shiras Unit 3 to meet the requirements of the Clean Air Interstate Rule (CAIR). However, due to the already low average NOx emission rate of 0.150 lb/mmBtu, the projected control technology to be installed is more highly efficient low NOx burners that would have achieved the Phase 2 CAIR requirement of 0.125 lbs/mmBtu. The estimated cost to install an SNCR on Shiras Unit 3 is approximately $2,000,000. To achieve the approximate 100 ton reduction required by the Transport rule would amount to spending $20,000/ton of NOx removed. This is well above the EPA established average cost-effectiveness of $2,000/ton of NOx removed (pg 45231 of Federal Register). By not taking into account facilities that already have much lower than average emission rates, this rule offers a competitive advantage to high NOx emitters while ensuring low emitters will be captive to either a market trading system or forced to offset emissions with smaller (less efficient and a higher emitter of pollutants) combustion units with less stringent emission controls. [EPA-HQ-OAR-2009-0491-2764.1, p.2]
Michigan Manufacturers Association (MMA)
Third, EPA based its assessments on equipment and capabilities that in some cases are not yet in place. In order for generation companies to comply with the emissions targets, they will have to install equipment that the EPA has mistakenly indicated is already operational or will be in service soon. This error underestimates the cost of compliance and exacerbates another inaccuracy in the EPA's compliance assumptions  -  the time and cost needed to design, permit, fabricate and install control equipment. [EPA-HQ-OAR-2009-0491-2762.1, p.3]
Minnesota Power 
Unit level data and budget calculation discrepancies. Several Minnesota generating units are presented by EPA with little or no budget allocations. It was noted in the Minnesota Power Transport Rule comments that the M.L. Hibbard Energy Center Units 3 and 4 were not included in EPA's unit allocations listing. The Taconite Harbor Energy Center Unit 3 budget calculation and IPM modeling emissions appear to reflect controls not scheduled for installation until after EPA approves the Minnesota regional haze SIP, BART eligible unit measures. Minnesota Power also observes that EPA formula calculations that consider historic and permitted emission rates do not appear to be applied consistently from unit to unit.  There are apparent discrepancies between actual permitted emission rates, NEEDS posted permitted emission rates and emission rates selected by EPA for unit level budget allocations that might be explained by variations in reference year timing but that is not certain.  EPA needs to provide information that explains the basis for budget allocations and emission projections on a unit specific basis such that a regulated party can replicate the calculation using consistently and clearly defined measures.  This is needed to allow parties proposed for regulation to develop a sense of proposed control obligations suitable for providing EPA with comments or to cite the need for corrections.  [EPA-HQ-OAR-2009-0491-3742.1_NODA, p.4]    
Correction review time before rule finalization. If EPA corrections in proposed Transport Rule data inputs or modeling design are made, as EPA indicates will be the case, EPA should offer those changes for public review and comment for technical correctness before EPA finalizes the Transport Rule. [EPA-HQ-OAR-2009-0491-3742.1_NODA, p.4]
Access to emission allowances needed for compliance.  The IPM model appears to presume that a unit in operation will be able to obtain emissions allowances necessary for compliance by paying EPA's model estimated allowance price.  EPA has not clarified what a unit operator is to do to continue operations if their budget allocations are insufficient to support designed or intended electricity production and no Transport Rule allowances are available for purchase.  All units accredited for dispatch should have a means by which they can provide for compliance with their Transport Rule budget. [EPA-HQ-OAR-2009-0491-3742.1_NODA, p.4]
Mirant Corporation
3. In any event, it is inappropriate to use the Integrated Planning Model (IPM) as a basis for issuing allowances to individual units. Although IPM is an impressive and useful analytical tool, it was not designed to serve this purpose and has been shown to be inaccurate in making unit-level projections. [EPA-HQ-OAR-2009-0491-2843.1, p.2]
4. Regardless of how IPM is used, it contains a number of inaccuracies that must be corrected before it can be used for decision-making. Among other things, it appears that IPM does not properly incorporate the requirements of the Healthy Air Act and does not reflect what actually happens with relatively high-cost units that serve a key role in many markets. [EPA-HQ-OAR-2009-0491-2843.1, p.2]
III. It is Inappropriate and Unnecessary to Use the Integrated Planning Model (IPM) as a Basis for Issuing Allowances to Individual Units
The Integrated Planning Model (IPM) is a macro-level modeling tool that was not designed to predict emissions from particular emission units. In the proposed rule, however, EPA has used the results of IPM modeling runs not only to predict unit-specific emissions, but also to allocate very valuable emissions allowances to specific units. This is puzzling when there are well-accepted methods for making allocation decisions based on heat input. Although the CAIR court was troubled by the fuel adjustment factor that EPA used in CAIR, the Court certainly said nothing to suggest that it was not proper to use heat input. Again, Mirant urges EPA to make allowance decisions based on historic heat input, which is well-known for each unit, rather than modeling runs of projected future emissions  -  projections that are highly uncertain at the unit level. [EPA-HQ-OAR-2009-0491-2843.1, p.8]
EPA describes IPM as 'a multi-regional, dynamic, deterministic linear programming model of the U.S. electric power sector. It provides forecasts of least-cost capacity expansion, electricity dispatch, and emission control strategies for meeting energy demand and environmental, transmission, dispatch, and reliability constraints. Among the factors that make IPM particularly well suited to model multi-emissions control programs are (1) its ability to capture complex interactions among the electric power, fuel, and environmental markets; (2) its detail-rich representation of emission control options encompassing a broad array of retrofit technologies along with emission reductions through fuel switching, changes in capacity mix and electricity dispatch strategies; and (3) its capability to model a variety of environmental market mechanisms, such as emissions caps, allowances, trading, and banking.' EPA website, http://www.epa.gov/airmarkt/progsregs/epa-ipm/historicalmultip.html. [EPA-HQ-OAR-2009-0491-2843.1, p.9]
Although IPM is certainly detail-rich with respect to emission control options, it is not detail-rich with respect all the individual EGUs in the country. In the proposed Transport Rule, EPA has translated the market predictions within IPM into hundreds of millions of dollars worth of allowances. It is inappropriate and unnecessary to use IPM for this purpose. [EPA-HQ-OAR-2009-0491-2843.1, p.9]
Mirant is aware of several examples of the problems created by EPA's proposed approach, although it is not clear whether these problems were created by the model itself or by model inputs. First, Mirant operates two large coal-fired units at its Morgantown plant. They are sister units built at the same time, and they were both retrofitted with identical scrubbers that began operating in December 2009. Yet IPM predicts that Morgantown Unit 1 will operate with an SO2 rate of 0.068 lbs/mmBtu, and Unit 2 will operate with an SO2 rate of 0.141 lbs/mmBtu. As a result, Unit 1 receives only 1,482 SO2 allowances, whereas Unit 2 receives 3,004 allowances. [EPA-HQ-OAR-2009-0491-2843.1, p.9]
Even more troubling is the disparate treatment of the two Morgantown units compared to Constellation's two Brandon Shores units, which also have scrubbers that were installed in response to the HAA and started operating about a month or two later than the Morgantown scrubbers. The projected SO2 emission rates for, and the corresponding SO2 allowances that would be given to, each of the units is shown below:
[The table pertaining to the SO2 units can be found on page 9 of this comment.] [EPA-HQ-OAR-2009-0491-2843.1, p.9]
The projected NOx emission rates are also unexpectedly different  -  both Brandon Shores units are at 0.08 and both Morgantown units are at 0.06. Under the proposed rule, the units with the higher predicted rates would be rewarded with more NOx allowances as well. Mirant does not understand what gives rise to these projected differences among similarly situated units. [EPA-HQ-OAR-2009-0491-2843.1, p.10]
We recently identified another puzzling anomaly involving the way that NOx allowances would be allocated to small units in Southeastern Massachusetts under the proposed Transport Rule, as shown in the following table.
[This table can be found on page 10 of this comment.] [EPA-HQ-OAR-2009-0491-2843.1, p.10]
Although it involves a relatively small number of allowances, we do not understand why Kendall Square 4 would receive less than 1/10th of the number of allowances given to nearby units that appear to be very similar. This example again raises the question of why EPA's proposed approach ends up treating similar units so differently. We again point out that such anomalies would be eliminated simply by using measured heat input as a basis for issuing allowances, rather than trying to use IPM predictions about future emissions at the unit level. [EPA-HQ-OAR-2009-0491-2843.1, p.10]
IV. Regardless of how IPM is used, it contains a number of inaccuracies and incorrect assumptions that must be corrected before it can be used for decision-making
A. IPM Does Not Properly Incorporate the HAA
As noted above, there are a number of anomalies in the way that IPM predicts future emission rates from EGUs located in Maryland  -  anomalies that simply do not square with the investments that companies have made to meet the HAA. Based on conversations between Mirant and EPA staff, Mirant believes that the HAA requirements are not accurately incorporated as constraints in IPM. In particular it is important to understand the system-wide compliance approach adopted by the State Legislature. See COMAR 26.11.27.04(e) (System-Wide Compliance Determinations) and 26.11.27.01(B)(3) (defining system as 2 or more EGUs owned or operated by the same person). Each of the three major companies essentially has a hard cap that covers all the units that it owns in the state. Before making any decisions based on IPM, EPA needs to ensure that the model properly deals with the HAA. [EPA-HQ-OAR-2009-0491-2843.1, pp.10-11]
B. IPM Does Not Accurately Predict the Operation of Higher Cost Peaking Units
IPM contains certain simplifying assumptions that make it unsuitable for projecting how individual units are operated (and will continue to be operated) in the real world. For example, it is our understanding that, if a 1000 MW unit has an average capacity factor of 85 percent, the model assumes that this unit is actually an 850 MW unit that is available all the time. If this were true, then power prices would be much more predictable and stable than they actually are in the real world. The following table, based on day ahead price data from 2007 through September 2010, shows the extent and frequency of price spikes in the three zones where Mirant operates plants covered by the Transport Rule: PEPCO, Hudson Valley, and Southeast Massachusetts.
[This table can be found on page 11 of this comment.] [EPA-HQ-OAR-2009-0491-2843.1, p.11]
Thus, in the PEPCO Zone, 13 percent of the time, hourly prices are more than 50 percent higher than the monthly average, and 2 percent of the time they are more than 100 percent higher. This is enormously important in the real world. IPM projects that a number of higher cost plants will not run under the Transport Rule and, as a result, they receive no allowances. In fact, however, they play an important role in individual markets. [EPA-HQ-OAR-2009-0491-2843.1, p.11]
Although IPM believes these relatively higher cost plants to be uneconomic, the market finds them to be quite valuable  -  as evidenced by the capacity payments that are made to ensure that these units are available when they are needed. For example, IPM predicts that oil-fired plants will not operate, but the following tables show otherwise. [EPA-HQ-OAR-2009-0491-2843.1, pp.11-12]
The first table shows that substantial amount of oil burn at Mirant's dual-fuel units. The second table shows that the units are not just summer peaking but run substantially through the year . The third table contains Confidential Business Information (CBI) and is not included in these public comments. In accordance with EPA regulations, it has been submitted separately. It shows the aggregate volume of fuel burned at each unit to provide an appreciation of the scale of operations.
[The first two tables can be found on page 12 of this comment. [As explained on page 12 of this comment, the third table includes CBI and has been submitted separately, in accordance with EPA regulations.] [EPA-HQ-OAR-2009-0491-2843.1, p.12]
Not surprisingly, it appears that IPM is particularly ill-suited for modeling dual fuel units, i.e., units capable of burning either natural gas or oil. Of the 493 dual fuel units in the NEEDS database, IPM predict that, in the 2014 limited trading control strategy, only 34 units would burn oil as the primary fuel. EPA proposes to allocate SO2 allowances to only 8 of these 34 units. This result ignores the reality that many dual-fuel units do regularly burn oil for some part of the year, due to a variety of real-world factors, including natural gas supply limitations, price factors, or facility-specific constraints. The mere fact that the IPM may project that it will be more economical to run these units on natural gas than on oil does not mean that the real-world factors that lead to combustion of oil at these units simply disappear. These factors include the mismatch between electricity and gas markets (as gas markets close at 6 pm and do not open again until 10am); gas pipeline constraints (gas demand for heating is high on very cold days); many if not most units are on "interruptible" gas; requirements to take gas ratably in equal 24 hour installments when electricity demand has a different profile; natural disasters that affect the amount of gas available. [EPA-HQ-OAR-2009-0491-2843.1, pp.12-13]
Finally, IPM (and thus the proposed allocation scheme) simply does not address local circumstances in many areas, including areas with specific load pockets and transmission constraints. For example although recent transmission upgrades allow more distant plants to serve Cape Cod, Mirant's Canal plant is the only generation on Cape Cod. IPM views this plant as uneconomic and predicts that it will no longer operate, but again, this is contrary to the facts on the ground. The Canal plant serves and important purpose in this area and should receive allowances based on historic heat input rather than predictions from an overly simplified model that was not designed to deal with individual units. [EPA-HQ-OAR-2009-0491-2843.1, p.13]
C. There are Obvious Factual Errors Related to Mirant Units
It appears that EPA has made a mistake in how it treated the scrubbers at Morgantown Units 1 and 2 and Dickerson Units 1, 2, and 3. The Agency apparently assumed that they would be built in the future in response to the Transport Rule. In fact, they were designed and built in response to the HAA, and came on line in December 2009. We have been informed by EPA staff that, in the parsed file, the Morgantown and Dickerson scrubbers should have been listed in column O for existing equipment. [EPA-HQ-OAR-2009-0491-2843.1, p.13]
To ensure that EPA has correct information about Mirant's scrubbed units, Mirant provides the following information about the actual SO2 rates that have been achieved year to date since the scrubbers were installed in response to the Maryland HAA:
[The information can be found on pages 13-14 of this comment.] [EPA-HQ-OAR-2009-0491-2843.1, p.13]
It also appears that there is an input problem with all EGUs in Maryland. The ozone-season NOx emission rates for all Maryland units appear to be too high by approximately a factor of 10. It appears that there may have been an effort to correct this problem by reducing the heat input for each unit by approximately a factor of 10. It is unclear, however, whether these errors fully cancel each other out or whether they are somehow propagated throughout the model. It would be preferable to use the correct data for ozone-season NOx emissions rates and heat input. [EPA-HQ-OAR-2009-0491-2843.1, p.14]
National Mining Association (NMA)
NMA understands that utility industry commenters will provide significant information showing that EPA has made factual errors in the modeling inputs that were used to demonstrate that the phase one emission reduction reductions could be achieved by the beginning of 2012. For instance, NMA understands that this information will show that EPA has overstated the number of scrubbers that are under construction and will be operational by 2012. If EPA's information is wrong, then the only way the 2012 budgets can be met are by closing units or ramping down production, a result that would fundamentally change the cost-effectiveness of the rule. [EPA-HQ-OAR-2009-0491-2868.1,p.16]
If Shale Gas Claims Prove to be Too Optimistic, High Natural Gas Prices and Price Volatility Will Return, Hurting All Consumers [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.6]
Natural gas historically has been considerably more expensive than coal. Increased natural gas generation has led to higher electric rates across the nation, from 6.81 cents/kWh in 2000 to 10.02 cents/kWh in 2009. For all consumers, natural gas for power generation will remain more expensive than coal-based generation. [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.6] 
Electricity price volatility adversely impacts consumers and manufacturing alike. Further, a wide variety of manufacturing firms utilize natural gas in the production process -- often as an essential feedstock. The impact of natural gas price volatility on these companies is far-reaching. According to Edward Stones, in testimony for Dow Chemical Co. before the U.S. Senate in 2009, '[s]ince 1997, there have been five natural gas price spikes.... These price spikes have significantly contributed to the U.S. manufacturing sector losing over 3.7 million jobs. In a 'peer-reviewed scientific paper in Environmental Science and Technology, Professor Jay Apt and Adam Newcomer at Carnegie Mellon University concluded that, with the cancellation of new coal generation, 'the amount of time that natural gas generators set the market price of electricity would increase substantially, and other industries that use natural gas may be priced out of the market.' [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.7]  
Natural gas prices and increased volatility of those prices over the past decade have severely affected families. In 2000, for example, residential gas prices started at $6.37/mcf but escalated to $13.74 in 2004. They then jumped to $20.24 in 2008 but dropped to $11.25 by the end of 2009. Upwards of 60 percent of the homes in the United States are heated with natural gas. Many of these homes are concentrated in the Midwest and Mid-Atlantic states. During the winter their dependence on natural gas is virtually total since most lack alternative sources of heating. And, of course, during the summer many states are highly dependent upon gas-fired generation to meet peaking cooling demand. In total, 33 states are vulnerable to natural gas price volatility because of heavy reliance on gas for heating and/or electricity generation. [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.7]  
Nebraska Public Power District
Furthermore, because of serious errors in EPA's emissions inventory for Nebraska as outlined below and major deficiencies with the "significant contribution" procedures, EPA must redo the modeling analysis that was used for identifying Nebraska as a State that is subject to the annual SO2 and NOx reduction requirements under the TR. In so doing, EPA also should allow additional time for NPPD and other interested parties in Nebraska to provide further technical input on the effects of these errors, as well as all measures that EPA may take to correct these fundamental flaws with the modeling analysis that it has used for identifying those states that are included in the Transport Rule. [EPA-HQ-OAR-2009-0491-2711.1, p.1]
Conclusion. While EPA proposed 2012 EGU emission budgets in Nebraska approximately equal to 2009 emissions, it modeled greatly inflated base-case 2012 SO2 emissions for Nebraska. It is clear that these base case projections do not correspond to historic operation of the coal-fired EGU units and are not representative of future SO2 performance of these units. This conclusion is particularly underscored given that the Nebraska EGU units are currently not subject to CAIR and EPA has not identified any changed circumstances that could justify this steep increase in SO2 emissions under the 2012 base case. [EPA-HQ-OAR-2009-0491-2711.1, p.6]
5) Nebraska EGU NOx Emissions Inventory. Similar to the problem outlined in Item 4 [page 3 of this comment], NOx emissions from EGUs are overstated. The two new coal-fired units described above are very well controlled, and with low-NOx burner projects being required under the Regional Haze program, total EGU emissions of NOx are likely to decrease between 2005 and 2014, rather than increase slightly as forecast by EPA. [EPA-HQ-OAR-2009-0491-2711.1, p.6]
[For additional comments pertaining to Nebraska EGU NOx Emissions Inventory, see p.6 of this comment]
6) Importance of Fixing Flaws in Nebraska Emissions Inventory. Given the several major emissions inventory problems identified in Items 2-5 above [pages 1-6 of this comment], EPA should therefore correct its modeling analysis for Nebraska based on accurate base case projections for EGUs and other source categories. Failure to do will result in EPA including Nebraska in the TR based on major flaws in the emissions inventory data. Emissions inventory problems of lesser magnitude in Minnesota, for the prior CAIR rule modeling analysis, resulted in the issue being remanded to EPA for further study (D.C. Circuit of the U.S. Court of Appeals, in North Carolina v. EPA, decided July 11, 2008). [EPA-HQ-OAR-2009-0491-2711.1, pp.6-7]
Nelson Industrial Steam Company (NISCO)
EPA's approach for projected emissions inventories eliminated the consideration of any reductions required by CAIR, due to the fact that the CAIR rule was overturned in North Carolina v. EPA, 531 F.3d 896, 901 (D.C. Cir. 2008). However, this results in overly conservative projections. The CAIR rule was remanded, but not vacated. Many regulated public utilities already invested in capital projects for reduction that were approved by their regulatory bodies and/or ratepayers. In most cases, legal obstacles would prevent the undoing of these projects. In addition, each physical project undertaken for purposes of CAIR: reductions was of necessity permitted under an enforceable Title V permit. Those projects and permit limits cannot be relaxed without the facilities triggering Prevention of Significant Deterioration (PSD) rules. Triggering PSD would involve imposition of Best Available Control Technology, which, in most cases, would mean that the facilities would have to keep the pollution control equipment they installed for CAIR, or would have to meet even more stringent requirements. EPA should have undertaken a much more rigorous analysis for projecting what steps EGUs would take if CAIR were vacated completely, with no replacement. EPA has tools to easily accomplish this, such as a Clean Air Act Section 114 request for information. In short, EPA overestimated Base Case emissions for both 2012 and 2014 by eliminating all CAIR control requirements. [EPA-HQ-OAR-2009-0491-2813.1 , p.6]
NISCO supports use of the updated IPM for use in making screening decisions to assist in making findings of 'significant contribution' or 'interference with maintenance' under Clean Air Act Section 110(d). NISCO urges EPA, however, to make certain updates to the assumptions and inputs for IPM v. 4.10 as discussed in these comments. Further, as indicated in NISCO's original comments, the IPM Base Case, whether premised on v. 3.02, v. 4.10 or some future version, should only be a screening tool for indications of potential 'significant contribution' or 'interference with maintenance'. The IPM is simply not accurate enough and is dependent upon too many uncertain assumptions and imprecise inputs to make binding decisions of 'significant contribution' or 'interference with maintenance.' EPA should always place great weight on empirical data to modify projected model conclusions when making these determinations. [EPA-HQ-OAR-2009-0491-3789.1_NODA, p.2]
The significant difference between the results of the v. 3.02 and v. 4.10 Base Case show the imprecision of the IPM model. Due to this imprecision and the uncertainties attendant to the many assumptions made for the IPM modeling, NISCO believes that an IPM projected impact of less than 2 ppb from an upwind to a downwind state should never be used as a level indicating 'significant contribution' or 'interference with maintenance' under the 'good neighbor' provisions of the Clean Air Act,_42 U.S.C. 7410(a)(2)(D). At most, the IPM should be used as a screening tool for making rebuttable presumptions for 'significant contribution' or 'interference with maintenance' determinations if a value above 2 ppb contribution is modeled. However, such presumptions should be always subject to a reasonable opportunity for rebuttal by empirical evidence and a weight of evidence approach used to determine if there is actually such contribution or interference. NISCO urges EPA to adopt this 2 ppb rule as a bright-line cut-off for screening. If the modeled contribution is 2 ppb or below, then no contribution or interference should be presumed. If the modeled contribution is above 2 ppb, then there could be a rebuttable presumption of contribution or interference. [EPA-HQ-OAR-2009-0491-3789.1_NODA, p.4]
New York State Department of Environmental Conservation
Future year 2012 and 2014 base case EGU emissions used for the air quality modeling runs that predicted ozone and PM2.5 were obtained through the use the IPM model. This model is a proprietary model that was applied to analyze its EGU strategies which was fed with proprietary control cost databases. The use of proprietary databases and models is inappropriate. To be able to assess the manner in which the model was applied, the public should be able to review all of the algorithms and all of the data that EPA used in the IPM model and not just a summary. [EPA-HQ-OAR-2009-0491-2730.1, p.9]
Northern Indiana Public Service Company (NIPSCO)
NIPSCO, as well as numerous other utility companies that would be subject to the proposed rule, have identified a number of incorrect assumptions and unrealistic results in EPA's modeling assumptions and results. Specifically, for NIPSCO units, the following EPA assumptions are impractical. [EPA-HQ-OAR-2009-0491-2747.1 p.4]
EPA needs to reexamine the set of IPM assumptions for NOx emission control reductions, if currently installed NOx control equipment is used to determine emission allowance allocations. Use of an unrealistically high level of emission control results in an allocation of allowances that are correspondingly insufficient for a controlled source and leads to the need to supplement emission allowance holdings on an emission unit equipped with an SCR. The table below illustrates the problems mentioned above. Michigan City Unit 12 and R. M. Schahfer Unit 14 are examples of boilers controlled by SCR which have not demonstrated the ability to achieve the emission rates assumed in the IPM over an extended period of time. Both units are cyclone fired boilers that have high uncontrolled NOx baseline rates that are not properly reflected in the presumed rates in IPM. NIPSCO believes that the assumption within IPM that all SCRs achieve a 90% reduction on a long term basis with a floor of 0.06 lb/mmBtu is not appropriate for high NOx baseline units such as cyclone-fired boilers. [EPA-HQ-OAR-2009-0491-2747.1 p.4]
[[Data Table Here]]
Additionally, there appears to be an error in the application of flue gas desulfurization ('FGD') at the R. M. Schahfer Station Units 17 and 18. These NIPSCO generating units have had FGD installed and removing sulfur dioxide ('S02') at a rate just above 90% since the units began operating in the 1980's. Yet, in spite of operating FGD as shown in Table 2 below, Units 17 and 18 are further subject to additional reductions significantly beyond what is presently capable from these FGD systems. Within the last year NIPSCO upgraded both Units 17 and 18 FGD systems to improve the S02 removal capability; however, the units are not capable of achieving reductions assumed in EPA's emission allocation methodology. NIPSCO requests a correction of this error. [EPA-HQ-OAR-2009-0491-2747.1 p.5]
[[Data Table Here]]
NIPSCO believes inaccuracies and incorrect assumptions for our units individually, and in combination with similar inaccuracies and projections across the domain of states included in the Transport Rule, lead to incorrect characterization of emissions that affect the air quality impacts and subsequent conclusions regarding the necessity and scope of controls. [EPA-HQ-OAR-2009-0491-2747.1 p.5]
If EPA proceeds with its proposed FIP approach,2 NIPSCO proposes that EPA consider basing the unit allocations on a unit's proportion of its state's historic heat input (i.e., million British thermal units, mmBtu). The historic heat input should be based on the maximum annual heat input for units during a baseline period that should include a period of five years and at a minimum the three year period covering calendar years 2007 through 2009. The EPA should consider a longer baseline period because of the unusual weather conditions in 2008 and 2009 and the economic downturn that occurred at the same time, in order to ensure that the period provides for representative production levels. We recommend using the annual maximum on a unit specific basis of the reported data during the baseline period rather than the average of the baseline period in order to ensure an unusual year does not dramatically alter the allocation (e.g., an extended boiler outage).  [EPA-HQ-OAR-2009-0491-2747.1 p.5]
Northern Star Generation LLC
comments on the FIP, both as a company and as part of the trade association ARIPPA. In our comments we have strongly objected to EPA's use of modeled future unit dispatch as the basis for allowance allocations under the Transport Rule. It is our recommendation that EPA return to the historic approach of using historic heat input as the most equitable basis for allowance allocation under this cap and trade program. However, in the event that EPA intends to utilize modeled unit dispatch projections and projected emissions as the basis for allowance allocation, we feel that it is extremely important that EPA use accurate data on plant availability, heat rate, and fuel cost in the model. [EPA-HQ-OAR-2009-0491-3728.1_NODA, p.1]
NRG Energy
Natural gas prices based on EIA's Annual Energy Outlook (AEO) NRG is concerned that allocations, through the projected heat input, are sensitive to natural gas price assumptions. Natural gas price assumptions can affect the IPM results on a state-by-state basis. For example, the total heat input (tBTU) by state varies from 1% to 12% when comparing the TR base case V.4.10 2012 run to the TR Base AEO Gas V.4.10 2012 run. For determining the state-level budgets and unit-level allocations, NRG recommends EPA use EIA's Annual Energy Outlook natural gas resource assumptions because the AEO has a set of assumptions that is widely used and trusted by the energy industry. [EPA-HQ-OAR-2009-0491-2749.1, pp. 3-4; see p. 4 for related table.]
Oglethorpe Power
It is unclear as to why EPA failed to use 2008 heat input date for SO2 as it did for NOx. This is especially so, given that 2009 was, as EPA admits, an 'unusually low year' for utility operations. It seems apparent that anyone year, especially one where operations were unusually depressed (due to a rather severe recession) should not serve as a time period upon which to base historical operations for use in allocation calculations. Here, allocations of S02 and NOx allowances should be based on a similar if not identical baseline, unless EPA can justify disparate treatment of the two pollutants. 2009 is not a representative year, given the recession and corresponding depressed (and not wholly realistic) demand for electricity experienced in virtually all the states in the Transport Region. Whatever the reason EPA used 2008 instead of 2009 data for only one pollutant, EPA failed to make a similar adjustment for unit-reported SO2 emissions. EPA does not provide any explanation for this differential treatment of the baselines for the two pollutants. EPA should clarify and explain more fully why it chose not to use 2008 (which is certainly a more representative year for utility operations instead of 2009) data for SO2 (as it did for NOx). [EPA-HQ-OAR-2009-0491-2732.1, p.4]
III. Unit Allocations
Several of the unit annual NOx allocations for units owned and/or operated by Oglethorpe Power determined by EPA appear to be in error. The table below summarizes these errors, caused by missing data, broken out by unit. [EPA-HQ-OAR-2009-0491-2732.1, p.5]
[The table can be found on pages 5 and 6 of this comment.]
The 'X' entries in the above table indicate missing data (specifically with regard to 2008 annual heat input and NO, emissions for the four most recent quarters). The missing heat input and/or emissions data prevents the assigning of NOx annual allowances to the units listed above. Note that these units do receive seasonal allocations under the Transport Rule. Annual allocations should be at least equal to the seasonal allocations in all cases. EPA should revisit its annual NOx allocations for these units and true up its determinations as needed. Based upon Oglethorpe Power's analysis, Oglethorpe Power should receive 80 additional NOx annual allowances corresponding to the units listed above. [EPA-HQ-OAR-2009-0491-2732.1, p.6]
[For additional comments pertaining to 2014 SO2 allocations, see page 6 of this comment]
It is unreasonable and inequitable to base allocations on anyone year's (or four quarters') worth of heat input, given the vagaries of any EGU's operating performance in a given year, especially a year where a scheduled outage for extensive maintenance falls or a forced outage of any appreciable length of time occurs. The problem is exacerbated where EPA picks a year of severe depressed economic conditions, here the last part of 2008 and the remainder of 2009, where generation was unusually depressed due largely to the national recession. The recession was particularly hard on Georgia, where all of the Corporation's generation assets are located. Unemployment has been higher in Georgia than the rest of the southern U.S. (10.0% versus 9.3% in August of 2009) and remains higher today (10% versus 9.2% in August 2010), while 2009 per capita income was for 2009 some 6% lower in Georgia as compared to the southeast as a whole ($33,980 versus $36,033). 7 [EPA-HQ-OAR-2009-0491-2732.1, p.7]
A plethora of CWA-related rulemakings and programs, like CAIR, the Clean Air Mercury Rule ('CAMR'), 8 regional haze, new source review, and ever-tightening NAAQS have resulted in lengthy scheduled outages required for installation of controls needed for compliance. A more equitable and reasonable approach in the Transport Rule would be to use a number of years as the historical basis for determining the allowance allocation from the state budgets to covered units, to account for the operational variations that could negatively skew allocations to the individual units by using a timeframe of only one year (or four quarters). This is especially true where the Agency is adopting permanent allocation programs of the type contemplated in this rulemaking. [EPA-HQ-OAR-2009-0491-2732.1, p.7]
It is also unreasonable and arbitrary to base unit allocations on EPA computer model projections of both future individual unit utilization and emission reduction capability, especially where such model fails to consider all of the variables (many of which are today unknown) that will determine utilization and control in upcoming years. Regardless of the purported sophistication of EPA's IPM, it does not and cannot accurately forecast how each and every fossil fuel-fired unit in the Transport Rule's 32 state trading areas will be utilized, or what the future costs and results will be in meeting the emission reduction obligations dictated by the model. The model cannot account for the myriad of future business decisions Oglethorpe Power and its 39 member systems will make that will affect the source and mix of generation assets to meet its ever increasing demand, the details of numerous power supply agreements (many of which have not yet even been created), upcoming negotiations and resulting agreements for transportation and ever-changing variable costs (like fuel), all of which will directly affect the manner and costs of supplying wholesale power to the 39 member systems Oglethorpe Power is obligated to serve. While EPA may think that trading will smooth out any uneven playing field created by erroneous, inaccurate, incomplete or incorrect assumptions that are critical inputs to the IPM, it is fantasy to believe that trading (which will be severely limited at best in any scenario proposed by the Agency) will be able to provide any meaningful relief for any substantial errors made in the unit allocations. This is especially true if EPA makes the allocations permanent. [EPA-HQ-OAR-2009-0491-2732.1, pp.7-8]
Here, if EPA bases any of its allocations on 2009 data, the derived allocations will prejudice Oglethorpe's units at Plant Scherer, both of which had scheduled outages of substantial lengths in 2009 to install controls triggered by state rulemakings to implement a CAMR SIP. Other Oglethorpe Power units that did not run (because they were not needed) during the recession last year (in this case during the 2009 ozone season) are also unfairly hurt if 2009 is used as the sole operational baseline tor determining unit allocations. [EPA-HQ-OAR-2009-0491-2732.1, p.9]

7. U. S. Bureau of Labor Statistics, Economic News Release - Regional and State Employment and Unemployment - August 2010 (September 21, 2010) and U.S. Bureau of Economic Analysis, Per Capita Personal Income (SAI-3) from the Regional Economic Information System (September 2010). [EPA-HQ-OAR-2009-0491-2732.1, p.7]
8.  Even though CAMR was vacated by the U.S. Court of Appeals for the District of Columbia Circuit, SIPs adopted as part of state rulemakings to submit an approvable CAMR SIP could result in enforceable State obligations independent of the CAMR, which continue unabated despite the CAMR vacatur. Exactly that situation has occurred in Georgia, which adopted specific control requirements (flue gas desulfurization scrubbers, SCRs and, in some case, baghouses, all on prescribed schedules), in part to control emissions of mercury from coal-fired EGUs. [EPA-HQ-OAR-2009-0491-2732.1, p.7]
Ohio Utility Group (OUG)
The Proposed Transport Rule is Based Upon Inaccurate Data and Flawed Methodology [EPA-HQ-OAR-2009-0491-2679.1, p.4]
EPA has proposed to find that emissions of S02 and NOx contribute significantly to non attainment or interfere with maintenance in one or more downwind states with respect to at least one of the following air quality standards: 1) the annual average PM2.5 NAAQS; 2) the 24-hour average PM2.5 NAAQS; and 3) the ozone NAAQS. The Utilities object to the data and methodology EPA used to determine a state's 'significant contribution' and to finalize state budgets. [EPA-HQ-OAR-2009-0491-2679.1, p.4]
In an attempt to correct the deficiencies of previous rules enacted pursuant to section 11O(a)(2(D)(i)(I)8, EPA proposed a 'state specific methodology' to identify specific reductions that individual states must make to eliminate their significant contributions to nonattainment in downwind states.9 EPA's methodology will require an initial set of emissions reductions in 2012, followed by a second set in 2014. To facilitate implementation, EPA developed state emissions budgets derived from an analysis of cost thresholds and state-specific emissions data. EPA determined that a state's emissions budget 'is the quantity of emissions that would remain in that state from covered sources after elimination of that portion of each state's significant contribution, before accounting for the inherent variability in power system operations.' [EPA-HQ-OAR-2009-0491-2679.1, p.4]
The Utilities object to the imposition of these budgets on several grounds. Most notably, as the individual member Utilities are concerned, EPA's proposed state budgets were based on incorrect assumptions and inaccurate data. The Utilities assert that the modeling data EPA used is out of date and inaccurately assumes the existence of equipment that has not been installed and, thus, capabilities that have not been reached. [EPA-HQ-OAR-2009-0491-2679.1, p.4]
If EPA insists on pursuing unit-by-unit controls, the data must be accurate. Otherwise complying with allocations becomes untenable. Inaccurate assumptions were made with respect to members of the OUG. For example, AEP Cardinal Unit 3 and OVEC's Kyger Creek Units 1-5 were assumed to have wet scrubbers that, due to construction delays, will not be operable by the proposed January 1,2012 deadline. OVEC is still working on resolving the issues and does not expect Kyger Creek to be fully retrofitted until mid-2012. OVEC also highlights that all of its units are equipped with wet-bottom boilers. EPA previously acknowledged that units with wet-bottom boilers are inherently higher NOx emitters than dry-bottom boilers. Accordingly, wet-bottom boilers were provided with almost twice the NOx allowances. I I Yet, EPA inexplicably ignores those differences in the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2679.1, p.4]
Faulty assumptions made about DP&L's Stuart and Killen stations have detrimental effects. CAIR provided Killen with 3,326 annual NOx allowances in 2009. The Transport Rule provides only 1,127 annual NOx allowances, a 66% reduction. Similarly, CAIR provided Stuart with 11,190 NOx allowances per year in 2009, whereas the proposed rule provides only 4,512. [EPA-HQ-OAR-2009-0491-2679.1, p.5]
The Utilities' objection to the modeling data should not come as a surprise as EPA has already begun to reevaluate the data it applied in the proposed rule. On September 1, 2010, EPA issued a Notice of Data Availability Supporting Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone ('NODA,,).12 The NODA supplemented the proposed Transport Rule with more recent emissions inventory data, new cost information, and an updated Integrated Planning Model. The information in the NODA has a direct effect on determining a state's 'significant contributions,' state emissions budgets, and unit allocations. While EPA has not yet re-calculated state budgets, the fact that EPA took the time to incorporate a substantial amount of data into the record is an indication that EPA appreciates the importance of applying accurate data. The Utilities maintain that if current budgets are applied without being reevaluated, states will be forced to accept inadequate budgets, ultimately resulting in a substantial number of units failing to comply with budget allocations. [EPA-HQ-OAR-2009-0491-2679.1, p.5]
The Expectations Under The Proposed Rule Are Unreasonable [EPA-HQ-OAR-2009-0491-2679.1, p.5]
EPA's actions are unreasonable. The Utilities' objections thus far have expressed concern about the required emissions reductions in terms of amount of actual reductions. The Utilities conclude by expressing concern with respect to the timing and economic requirements under the proposed rule. In light of EPA's reliance on the faulty assumptions and inaccurate data mentioned above, the proposed rule requires emissions reductions that are not feasible and will ultimately result in unforeseen consequences. In this final section, the Utilities provide real world examples supporting the notion that EPA's expectations are entirely unrealistic. Finally, the Utilities will demonstrate that such stringent emissions reductions are unnecessary. [EPA-HQ-OAR-2009-0491-2679.1, p.5]
The Utilities anticipate major complications if facilities are forced to switch coal. Based on the recently released IPM runs in conjunction with the NODA, emissions rates for AEP's Muskingum River units 1-4 were as low as 1.42 lb-S02/mmBtu based on the modeled emissions and heat input. In previous runs used to support the Transport Rule, the emissions rates were a slow as 1.011b- S02/mmBtu. As these are uncontrolled units, the emissions rate is largely indicative of the sulfur content of the underlying fuel. However, low sulfur eastern fuel(s) are not compatible with these wet-bottom boilers due to ash fusion and ESP limitations. These units are currently limited to coal(s) with an S02 content of 4.0 lb/mmBtu or above. Similarly, OVEC's Kyger Creek scrubbers were designed to bum higher sulfur coal. [EPA-HQ-OAR-2009-0491-2679.1, p.6] 
The assumed coal switch also has significant economic repercussions. EPA's modeling does not take into account long-term coal purchase contract obligations and the ability to quickly ramp production up and down. The IPM model allowed full switching to low sulfur coal in 2012, but in the real world this could not occur. If the final model would ultimately push DP&L to switch coals, DP&L would be forced to shift sourcing millions of tons of coal per year at a cost near $50 Million per year. OVEC currently has two contracts for local Ohio coal for use at Kyger Creek: one set to expire at the end of 2012 and the other at the end of 2017. Like DP&L, OVEC may be forced to purchase lower sulfur coal to comply with the strict limitations, possibly causing OVEC to default on its long-term local coal contracts. [EPA-HQ-OAR-2009-0491-2679.1, pp.6-7]
B. No data base or modeling platform can be accurate without assuming the control technology installed, and air quality improvements realized, under CAIR
If the information in the NODA contains 'updated' versions of the NEEDS database and IPM platform, why do these new versions still fail to consider CAIR? The Utilities commented on the appropriateness and necessity of including the control technologies and air quality improvements resulting from the CAIR program.  As such, the Utilities will not go into great length repeating what has already been said. However, the inclusion of CAIR is fundamental to the final Transport Rule and cannot go unmentioned in these comments. [EPA-HQ-OAR-2009-0491-3761.1_NODA, p.6]
Twice now, EPA has acknowledged the advancements in air quality made in recent years as a result of CAIR. In the proposed Transport Rule, EPA stated that 'a great deal of the improvement in PM2.5 and 24-hour concentrations in the eastern U.S. can be attributed to EGU reductions achieved due to the CAIR.'  From this, EPA recognized that the final Transport Rule must use more recent data to account for these improvements. 'EPA intends to update the NOx rates for fossil-fuel fired units in the final rule to reflect the more recent 2009 data ... The updated NOx rates will more accurately portray the unit level control installations that have occurred at power plants during the past several years.,, The significance of EPA's intentions is not clear. Will these updated NOx rates require assuming CAIR, at least in part? If CAIR is being assumed for one aspect of the Transport Rule, logically, CAIR must be assumed for the entire rule. [EPA-HQ-OAR-2009-0491-3761.1_NODA, p.6]
One thing is certain - no database or modeling platform is sufficiently 'updated' unless it assumes CAIR. Modeling analysis performed by Midwest Ozone Group ('MOG') demonstrates that Ohio NOx and S02 caps similar to the caps developed under CAIR, accounting for the control measures installed to comply with CAIR, are adequate to eliminate Ohio's 'significant contribution' to downwind non attainment in almost all areas by 2014 - before the NAAQS attainment deadlines. MOG's modeling presents an entirely different picture than that performed by EPA. EPA's rationale for excluding CAIR in the proposed Transport Rule is unfounded. Therefore, the Utilities respectfully request that EPA assume all air quality improvements and emissions controls under the CAIR program. [EPA-HQ-OAR-2009-0491-3761.1_NODA, p.6]
Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
OVEC owns and operates two coal-fired electric generating plants (the OVEC Units) located on the Ohio River. OVEC's Kyger Creek plant is located in Gallia County, Ohio, and the Clifty Creek plant is located in Jefferson County, Indiana. OVEC is submitting these comments to correct several factual mistakes EPA made when inputting data for the OVEC Units, most significantly EPA's assertion that all eleven OVEC Units will be equipped with Flue Gas Desulfurization (FGD) before January 1,2012. OVEC also demonstrates why the Proposed Transport Rule's overly aggressive and unjustified emission reduction targets and timetables are unreasonable and not feasible for OVEC. [EPA-HQ-OAR-2009-0491-2803.1, pp.1-2]
Incorrect Factual Inputs EPA's Modeling [EPA-HQ-OAR-2009-0491-2803.1, p.3]
EPA has made several factual errors about the OVEC Units that must be corrected before finalizing any rule regarding electric generating unit (EGU) emissions allocations. Briefly, those mistakes are: [EPA-HQ-OAR-2009-0491-2803.1, p.3]
Clifty Creek will not be fully retrofitted with FGD as of January 1, 2012 [EPA-HQ-OAR-2009-0491-2803.1, p.3]
Kyger Creek will not be fully retrofitted with FGD as of January 1,2012 [EPA-HQ-OAR-2009-0491-2803.1, p.3]
All of the OVEC Units are wet-bottom boilers, and cannot meet the proposed NOx targets even with EPA's assumed NOx controls [EPA-HQ-OAR-2009-0491-2803.1, p.3]
The NOx Emission Targets for OVEC are Unreasonable and Unachievable. [EPA-HQ-OAR-2009-0491-2803.1, p.5]
OVEC first addresses EPA's NOx allocations for the eleven OVEC Units. EPA has clearly stated on numerous occasions that the 2012 emission reduction requirements in the Proposed Transport Rule are based on emission control equipment that is currently or scheduled to be in place by January 1, 2012. In fact, on the surface, it appears that EPA correctly assumes that the current NOx controls at the OVEC Units - ten SCRs and eleven units equipped with OFA - will be in place in 2012. However, the emission targets that EPA incorrectly assumes can be met with those controls are well below anything reasonably attainable. [EPA-HQ-OAR-2009-0491-2803.1, p.5]
Never once, taking the last five years of historical operation into account, has OVEC ever achieved the NOx emission levels required of it by 2012 under the Proposed Transport Rule. The table below shows OVEC's ozone season and annual NOx emissions historically for each plant [EPA-HQ-OAR-2009-0491-2803.1, p.5; see pp.5-6 for Table 2 entitled, Historical NOx Emissions at OVEC Units]
Under EPA's Proposed Transport Rule, OVEC would be required to achieve the same NOx emissions in 2012 as 2014. However, based on actual, historical operating data, it is impossible for the OVEC Units to comply either with the seasonal or annual NOx emissions limitations EPA has proposed: [EPA-HQ-OAR-2009-0491-2803.1, p.6; see p.6 for Table 3 entitled, Comparing estimated ozone season NOx emissions at historic heat Inputs to Proposed Transport Rule allocations; see pp.6-7 for Table 4 entitled, Comparing estimated annual NOx emissions at historic heat inputs to Proposed Transport Rule allocations]
The SO2 Emission Targets for the OVEC Units are Unreasonable [EPA-HQ-OAR-2009-0491-2803.1, p.7]
OVEC also takes issue with the overly aggressive and arbitrary SO2 emissions reductions proposed for the Kyger Creek and Clifty Creek plants. Again, EPA has clearly stated that the 2012 emission reduction requirements in the proposed rule are based on emission control equipment that is currently or scheduled to be in place by January 1, 2012. The first problem, as discussed above, is that due to the extreme economic recession - the deepest and longest since World War II that has hit the Midwest particularly hard - and serious design problems with the FGDs, neither plant will be fully equipped with FGD by January 1, 2012. The vacatur and then remand of CAIR has also impacted the economics of FGD retrofit schedules. The very basic factual inputs that EPA used are incorrect. [EPA-HQ-OAR-2009-0491-2803.1, p.7]
The problems with the SO2 emission reduction targets for OVEC's units are not limited to the incorrect factual inputs for retrofit completion dates. OVEC has analyzed its historical operating data, the guarantees in its FGD vendor contracts, its coal contracts, and industry experience with the type of FGD it is installing to assess the feasibility of complying with the proposed SO2 emission caps. Attempted SO2 compliance with the Proposed Transport Rule in its current form is unreasonable and infeasible. [EPA-HQ-OAR-2009-0491-2803.1, p.7]
For example, if Kyger Creek uses the locally based Ohio coal with the sulfur content the scrubbers are designed for, the scrubbers would have to operate at or above a 98% removal efficiency year-round to even come close to achieving the SO2 emission reductions proposed by EPA in 2012. A change in removal efficiency of less than one percent would cause the units to exceed the proposed cap. There is very little industry operating experience with Chiyoda Jet Bubbling Reactors, and none that suggest they could achieve this level of performance with no equipment or learning curve problems. The scrubbers will not be started up and optimized until after the 2012 initial reduction date, and they cannot reasonably be expected to constantly achieve maximum peak operational performance from the first day the scrubbers are turned on. [EPA-HQ-OAR-2009-0491-2803.1, pp.7-8]
The 2014 SO2 emissions caps are even more stringent. Assuming that all of the scrubbers will be operating at peak performance by 2014 (which is by no means certain), OVEC would have to operate the scrubbers at a removal efficiency that may not even be achievable, and do so without a single equipment problem year-round. [EPA-HQ-OAR-2009-0491-2803.1, p.8]
Factual Errors about the OVEC Units [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.2]
EPA's NEEDS database does not reflect the factual circumstances for the two coal-fired electric generating plants that OVEC owns and operates (the OVEC Units), and the outputs published by EPA are internally inconsistent, and inconsistent with OVEC's planned retrofits. [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.2]
Kyger Creek [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.2]
First, EPA failed to correct the NEEDS database to reflect that Kyger Creek does not have Flue Gas Desulfurization (FGD or scrubber), nor will it before mid-2012 at the earliest. The NEEDS database still incorrectly lists a scrubber in place as of 2010. OVEC has already supplied information demonstrating that the scrubber at Kyger Creek is currently not anticipated to be fully operational until mid-2012, absent unforeseen disruptions. The fact that EPA issued 'updated' data inputs before it ever received comments on its first set of incorrect facts contributes to the confusion and inability to fully assess the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.2]
Second, EPA's modeling outputs are inconsistent with their inputs and with themselves. Despite incorrectly assuming a scrubber is in place at Kyger Creek in 2010, EPA's published model outputs show the scrubber disappearing in 2012. The emission rates and heat rate information in the parsed files state that Kyger Creek will be burning 100% bituminous coal with no scrubber in 2012. Further confusing the matter, the scrubbers 'reappear' in the 2014 parsed file, albeit with no indication of the projected removal efficiency. As OVEC has already stated in its PTR comments: Kyger Creek burns a blend of bituminous and subbituminous (PRB) coal, and will continue to do so until it is fully retrofitted with FGD. Therefore none of the data EPA has published about Kyger Creek regarding SO2 is correct. OVEC cannot resolve EPA's inconsistencies, and cannot provide meaningful further comment until EPA resolves its own inconsistencies and corrects its factual mistakes. [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.2]
EPA also makes mistakes at Kyger Creek about NOx emission rates. EPA once again lists 'baseline' rates below that which Kyger Creek has been able to achieve based on historical, actual operation. (See PTR Comments). [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.2]
Finally, as we discuss below, EPA has not updated any of its SO2 or NOx allocations, so OVEC has no way of knowing how these factual errors will eventually affect the centrally relevant unit allocations, and whether EPA will continue to set overly restrictive and unreasonable targets for the OVEC Units. [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.3]
Clifty Creek [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.3]
At Clifty Creek, EPA correctly changed the factual inputs to reflect that Clifty Creek does not currently have any installed FGD. However, it mistakenly assumed that Clifty Creek is currently burning 100% bituminous coal. As explained in its PTR Comments, OVEC spent almost $80 million in connection with switching to a blend of bituminous and subbituminous coal at Clifty Creek. The NEEDS database must be updated to reflect accurate facts. [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.3]
Another serious error in EPA's 2014 parsed file is the assumption that Clifty Creek will be burning 100% subbituminous coal. This is not only at odds with the fact that all units at Clifty Creek are currently scheduled to be retrofitted with FGD by mid-2013, but is a completely unreasonable assumption for the Clifty Creek units. As stated in its PTR Comments, Clifty Creek can burn up to 75% subbituminous coal. Wet-bottom boilers which all of the OVEC Units are - experience numerous operating problems even at a 75% blend of subbituminous coal. Even if it were possible for Clifty Creek to burn 100% subbituminous coal - an assumption OVEC believes is not feasible - burning 100% subbituminous coal would result in a significant derate of the units. 1 EPA has either ignored this or failed to consider it by not changing the assumed gross capacity - 217 MW/unit - an impossible rating if the units could burn 100% subbituminous coal. EPA also fails to explain whether it considered the inevitable operational difficulties resulting from burning high ratios of subbituminous coal in its reliability analysis, because a wet bottom boiler burning 100% subbituminous coal would likely suffer a large loss of reliability. EPA has not considered the enormous costs of capacity derating and reduced availability associated with its 100% subbituminous assumption for Clifty Creek. [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.3]
Apart from the flawed assumption that Clifty Creek could burn 100% subbituminous coal EPA failed to account for the fact that OVEC is constructing a scrubber for all units at Clifty Creek. As indicated in its PTR Comments, the current schedule for completion of the Clifty Creek scrubbers is mid-2013. There is no basis that OVEC can see why EPA assumed away Clifty Creek's scrubber in its entirety - particularly when the scrubber is already approximately 35% complete. This illogical and uneconomical 'result' from the modeling demonstrates the need for EPA to take the necessary time to fully consider its inputs and the reasonability of its outputs before imposing massive restrictions on the industry. [EPA-HQ-OAR-2009-0491-3734.1_NODA, pp.3-4]
EPA also makes mistakes at Clifty Creek about NOx emission rates. EPA listed baseline rates below that which Clifty Creek has been able to achieve based on historical, actual operation (see PTR Comments). EPA then includes 'policy' emission rates for NOx, which in most cases are close to the incorrect 'actual' base rates listed. For Clifty Creek Unit 6, however, EPA inexplicably cuts the 'actual' base rate in half for its 'policy' emission rate and uses the policy rate to estimate total emissions. EPA does not list any additional controls, or other emission reduction methods that would explain how or why Clifty Creek Unit 6 could suddenly reduce its emission rate by over 49%. As OVEC explained in its PTR Comments, there is no reason for EPA to issue a rule that is riddled with mistakes and unexplained assumptions. EPA should take a step back and take whatever amount of time is needed to correctly assess and address the impacts of this proposed rule. [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.4]
Additional Assumptions in the Model have not been Corrected [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.4]
There are additional incorrect assumptions built into EPA's model that have not been corrected by the NODA. One glaring example is that EPA still assumes that new scrubber installations will achieve 98% removal of SO2. The reality, as discussed in OVEC's PTR Comments, is that this percentage is much higher than the rate likely to be achievable on a consistent year-round basis with no equipment problems. EPA has not corrected a basic assumption that will greatly affect allocations. [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.4]

1 It is also worth noting that the total amount of subbituminous coal usage for the Clifty Creek units is less than the total coal usage listed in the 2014 parsed file and significantly less than the total coal usage listed in the 2012 parsed file. There is no rationale for assuming that less coal would be used in 2014 as compared to 2012, particularly when a higher heat rate is expected with subbituminous coal as compared to bituminous coal. These types of errors further illustrate the need to re-evaluate the supporting data and conclusions for the Proposed Transport Rule.
Oklahoma Department of Environmental Quality
Further, the modeling results should be used only as a guideline, not a pinpoint target. This particular model is based on guesswork regarding the price of coal and natural gas in future years, in addition to trying to predict the economic condition of the nation in the future. The IPM model run results are very erratic, retiring both coal and natural gas facilities that have no plans to retire, increasing and decreasing electricity production at various facilities, and adding solar power to Oklahoma when none has been planned. It seems that drawing conclusions based on such imprecise data is not a good practice when those conclusions will have such a substantial impact, i.e. requiring the installation of costly controls. [EPA-HQ-OAR-2009-0491-2662.1, p. 1]
Omaha Public Power District
In evaluating whether Nebraska should be included in the proposed TR, EPA modeled 2005 total emissions, purported to be from all sources, as a baseline case. EPA cites a Nebraska 2005 baseline total sulfur dioxide (S02) emission inventory of 121,589 tons/year in the preamble of the proposed TR. Of this total amount, the so-called 'nonpoint' portion modeled by EPA is 29,575 tons/year. Review of the detailed emission inventory (http://www.epa.gov/ttn/chiefinetl2005inventory.html#inventorydata ) reveals that this 'nonpoint' inventory includes S02 emissions from industrial and commercial/institutional boilers of almost 29,000 tons/year. Such boilers would really not be nonpoint sources. Most of this amount is attributed in the inventory database to subbituminous or bituminous coal usage from such boilers. In reality, EPA's TR modeling has already accounted for 'non-EGU' point source S02 emissions at 6,429 tons/year, which at least appears to be in the right ballpark, based on our review of facility-by-facility emissions included in the NEI database. This is also confirmed by the US Department of Energy, Energy Information Administration (EIA) on-line data, which shows recent (calendar years 2007 and 2008) industrial and commercial boiler coal usage in Nebraska in the range of 400-500 thousand tons/year. Based on typical sulfur levels in the Powder River Basin coal burned in virtually all of Nebraska, this is generally consistent with the 'non-EGU' emission level cited above. Thus, it appears there are approximately 29,000 tons/year of nonexistent S02 emissions (nearly 25% of the Nebraska 2005 baseline inventory) in EPA's modeled 2005 S02 inventory for Nebraska and this incorrect amount is then carried forward in EPA's analysis of the 2012 and 2014 base cases. [EPA-HQ-OAR-2009-0491-2680.1, p. 2]
The EGU 2005 base case Nebraska S02 emissions for EOUs appear to be reasonable, at 74,995 tons/year. Industry data (EPA Clean Air Markets Division, on-line Acid Rain database) indicate these emissions had increased slightly to approximately 76,000 tons/year in 2009. A new, well-controlled 663 MW coal-fired unit, Nebraska City Station Unit 2, came on line early in 2009, and may have helped produce the slight increase. A new, well-controlled 220 MW unit known as Whelan Energy Center Unit 2 is expected to come on-line in 2011, with maximum potential-to-emit for S02 of 1162 tons/year. No other proposed new Nebraska coal-fired EGUs are either permitted or under construction that would come on-line by 2014. Thus, it is very puzzling why EPA forecast Nebraska EGU 802 emissions of 120,790 tons/year in 2012 and 115,695 tons/year in 2014. These are very substantial increases above current and expected levels and are not credible. The existing units included in the 2005 inventory are mostly base-loaded and near capacity. Growth in generation over the next few years will be provided via the two new units more recently coming on-line as listed above. Because these new units are very well controlled for 802, they will contribute relatively little (approximately 3,000 tons/year) to statewide 802 emissions.  [EPA-HQ-OAR-2009-0491-2680.1, pp. 2-3]
For 'Group 2' states such as Nebraska, EPA states in the preamble (FR, Aug. 2, 2010, page 45290):
'These states are only required to make 502 reductions that could be made through (1) the operation of existing scrubbers, (2) scrubbers that are expected to be built by 2012 and (3) the use of low sulfur coal. Because those strategies were already being applied in most states covered by this rule in 2009, EPA believes that the actual performance units achieved in 2009 is more representative of expected emissions than what EPA modeled using IPM. This is because real data takes into account actual unit by unit information that is represented at a more aggregate level in IPM.' [EPA-HQ-OAR-2009-0491-2680.1, p. 3]
In Nebraska, there are only two units with scrubbers, those being for the two new units described above, which are subject to stringent Best Available Control Technology (BACT) limits. Thus, there will be no 802 reductions due to Items 1) and 2) listed in the EPA preamble paragraph above. Regarding Item 3), the use of low sulfur coal, all the EGUs in Nebraska have used low-sulfur Powder River Basin (Wyoming) coal for many years, and plan to continue to do so. Coal delivery routes and purchase agreements in place are expected to facilitate the continued use of PRB coal for all the Nebraska units for the foreseeable future. Therefore, there is no justification for projecting the substantial increase for the 2012 and 2014 base cases, whether using IPM or some other projection tool or assumption. [EPA-HQ-OAR-2009-0491-2680.1, p. 3]
Furthermore, the preamble text above says EPA believes the 2009 'actual performance' is more representative of expected emissions than what EPA modeled using the Integrated Planning Model (IPM). This is supported by Attachment 1, which shows a plot of average coal sulfur (in pounds/million Btu) for Nebraska EGUs for the period 1998 through 2009, along with the values EPA used for its 2012 and 2014 impact projections. The historical values range from approximately 0.57 to 0.68 lb/mmBtu over this period, nowhere near the almost 0.9lb/mmBtu values used for EPA's 2012 and 2014 analyses in the TR proposal. [EPA-HQ-OAR-2009-0491-2680.1, p. 3, see 2680.1, p. 8 for Attachment 1]
So while EPA proposed 2012 EGU emission budgets in Nebraska approximately equal to 2009 emissions, it modeled greatly inflated base-case 2012802 emissions for Nebraska. It is not clear if the 2012 base-case S02 emissions modeled for Nebraska were based on IPM, but if they were, this seems to contradict EPA's stated intent as indicated in the preamble language cited above. [EPA-HQ-OAR-2009-0491-2680.1, pp. 3-4]
Similar to the problem outlined in Item 4, NOx emissions from EGUs are overstated. The two new coal units described above are very well controlled, and with low-NOx burner projects being required under the Regional Haze program, total EGU emissions of NO x are likely to decrease between 2005 and 2014, rather than increase slightly as forecast by EPA. [EPA-HQ-OAR-2009-0491-2680.1, p. 4]
Given the several major emissions inventory problems identified in Items 2-5 above, EPA should therefore correct its modeling analysis for Nebraska. Emissions inventory problems of lesser magnitude in Minnesota, for the prior CAIR rule modeling analysis, resulted in the issue being remanded to EPA for further study (D.C. Circuit of the US Court of Appeals, in North Carolina v. EPA, decided July 11,2008) [EPA-HQ-OAR-2009-0491-2680.1, p. 4]
Peabody Municipal Light Plant
EPA proposes zero NOx allocations for Waters River Unit 2 even though actual annual baseline emissions were determined by EPA to be 3.2 tons. It appears that this is because the IPM model does not project the unit to operate in 2012, which is an unfounded assumption. The lack of transparency with how the IPM model predicted that Unit 2 was not going to operate in 2012 makes it difficult to comment on any false IPM model inputs and/or assumptions. [EPA-HQ-OAR-2009-0491-3730.1 p.1]
Pfeiff, Mike
12. Base Case Year - A key step in the process of developing the Proposed Transport Rule is the Air Quality Modeling. The Air Quality Modeling process begins with analyzing existing emissions (i.e. the 'Base Case') to determine which states significantly contribute to downwind nonattainment and maintenance areas. 75 Fed. Reg. 45233. However, unlike other modeling inputs used to support the Proposed Transport Rule, which in most circumstances are based on more recent and relevant data (i.e. 2009 or even 2010), the existing emissions data, arguably the single most important data input, is based on 2005 data. The EPA cites, 'The modeling for 2005 was used as the base year for projecting air quality data for each of the 3 future year scenarios'. 75 Fed. Reg. at  42338. [EPA-HQ-OAR-2009-0491-2742.1, p.9]
In order to prevent prejudicing the results and avoided the perception of 'cherry-picking' a base year that provides a higher likelihood of achieving underlying political objectives, the EPA should use more recent emissions data. The EPA's Clean Air Markets Division produces Progress Reports each year that provide an inventory of SO2 and NOx emissions. These reports represent a summary of the unit level emissions data that in many cases is provided to the EPA at the hourly frequency. The EPA's web page currently list progress reports through 2009. (http://www.epa.gov/airmarkt/progress/progress-reports.html). [EPA-HQ-OAR-2009-0491-2742.1, p.9]
[For additional comments pertaining to Base Case Year, see pages 9-11 of this comment.]
13. Natural Gas Price Assumption - In the United States, natural gas sets the marginal cost of electricity for a very high proportion of the hours each year. In many regions of the United States natural gas already sets the marginal price of electricity in excess of 90% of time. By its very nature it is easy to see how if the Proposed Transport Rule is finalized it will increase the proportion of hours where natural gas sets the margin price of electricity across the country. In essence, the Proposed Transport Rule will make the United States more dependent on Natural Gas as a fuel for generating electricity relative to Coal. This dynamic makes the modeling results highly sensitive to the price of natural gas. Given the voluminous nature of the supporting documents there has not yet been a reasonable time period to fully read and understands the assumptions especially since the EPA only released the full Integrated Planning Model (IPM) modeling results on September 1, 2010. However my initial review of those results have revealed some troubling issues. [EPA-HQ-OAR-2009-0491-2742.1, p.11]
First, it appears that the EPA has recently shifted to a new (or substantially revised) model as part of its effort to analyze the potential effects of Proposed Transport Rule. While there nothing inherently wrong with utilizing new modeling techniques. However, I do have concerns that shifting modeling applications for a proposal of this magnitude is extremely risky. At the very minimum, the EPA should perform the analysis with the previous version of the model in parallel and make available the inputs and results of both sets of modeling to allow the public to benchmark the differences. [EPA-HQ-OAR-2009-0491-2742.1, p.11]
Second, it appears that the new modeling process is a departure from the past where EPA obtained energy commodity price inputs from the Department of Energy's (DOE) Annual Energy Outlook (AEO) which serves as US Government's official energy forecast. Instead, it appears the many of the key modeling assumptions embedded in the in the IPM that were used to evaluate the Proposal came from a 3rd party energy consulting firm commissioned by the EPA. This raises the following questions:
a. Why did the EPA choose to populate the IPM with inputs from 3rd party consultants instead of utilizing inputs that were sourced from, or at least internally consistent with, the DOE's official and most recent AEO?
b. Do 3rd party consultants who are commissioned by the EPA have an unavoidable bias to skew the inputs in a way that supports the EPA's political objectives?
c. Has the EPA at least worked obtained a certification from the DOE that any and all energy related inputs that were obtained from 3rd party consultants are consistent with the DOE's official forecast. [EPA-HQ-OAR-2009-0491-2742.1, p.11]
d. Why does the American taxpayer fund the DOE if even a sister agency of the United States Government like the EPA looks to 3rd party consultant for key energy related assumptions?
e. Why does the DOE, our countries experts on energy, not 'own' the energy related modeling aspects of the Proposed Transport Rule?
I request the EPA that obtain a 'certification of reasonableness' for all energy related assumptions from the Department of Energy. [EPA-HQ-OAR-2009-0491-2742.1, p.12]
14. Coal EGU Retirements - The EPA estimates that under the provisions of the Proposed Transport Rule approximately 1,200 MW of coal-fired generation may be removed from operation by 2014.75 Fed Reg. at 45357. This estimate is significantly lower than the estimates calculated by notable blue-chip energy consulting firms. Because of confidentiality issues that prevent the disclosure of proprietary analysis, I am unable to convey the specific results of their analysis as part of these comment since these comments will be made part of the public record. However, I will comment that the range of estimated coal EGU retirements provided blue-chip energy consulting firms through 2015 ranges from 30,000 100,000 MW. I urge the EPA to challenge the validity of their estimate. [EPA-HQ-OAR-2009-0491-2742.1, p.12]
I request that the EPA commission a independent review of their estimated number of retirements for at least three blue-chip energy consulting firms. [EPA-HQ-OAR-2009-0491-2742.1, p.12]
15. Control Efficiency Assumptions - The EPA makes inconsistent assumptions about the control efficiencies of existing control equipment compared to similar control equipment which is expected to be constructed. For example, some existing SO2 control equipments is being modeled assuming control efficiencies as high as 98% while expected new scrubbers are being modeled at 95%. Because of the variation in existing control equipment and across states and the expectations of future control equipment, this inconsistency bias the methodology for determining individual state allowance budgets. [EPA-HQ-OAR-2009-0491-2742.1, p.12]
I request that the EPA make uniform internally consistent assumptions about the control efficiencies of all SO2 control equipment to prevent biasing existing control equipment any future allowance allocation budgets. [EPA-HQ-OAR-2009-0491-2742.1, p.12]
17. Oklahoma Inclusion in Seasonal Ozone Region -- The EPA contents that base on its state by state contribution analysis Oklahoma had one 'linkage' where it contributed 0.8 ppm or more to downwind 8-hour nonattainment in Tarrant County Texas. 75 Fed. Reg. 45269. The EPA also contends that ozone emission from Oklahoma is linked to maintenance issues in 3-counties including Dallas TX. Dallas TX, and Tarrant TX. The Proposed Transport Rule goes on to define ozone season as May through September. 75 Fed. Reg. 45214. A review. An analysis of climatologically data from the National Climate Data Center ('NCDC') challenges the validity of EPA's linkage of Oklahoma to non-attainment or maintenance issues in Texas. Based on actual wind direction data from the NCDC from 2000-2009 for the aggregate months of May through September. The pervading wind measured at the Tulsa International Airport (TIA) and Will Rogers (OKC) averages from the south 71.4% and 72.4% of the time, respectively. Further, in the traditionally higher ozone months of July the proportion of time that the prevailing wind is from the south as measured TIA and OKC is higher measuring 78.1% and 80.6%. For August, the proportions for TUL and OKC are 74.8% and 77.1%. Given these patterns it is hard to imagine that Oklahoma has a downwind impact on Texas. [EPA-HQ-OAR-2009-0491-2742.1, p.13]
I request that the EPA provide a explanation as to how Oklahoma is supposedly creating downwind problems for Texas during the May-Sep Ozone season when during that time of year the prevailing wind direction is from the South. [EPA-HQ-OAR-2009-0491-2742.1, p.14]
18. International Transport of Emissions - There is recent scientific research that indicates increasing emissions from Asia that are being transported through the atmosphere to the United States are outpacing domestic emission reductions. Did the EPA attempt to estimate these international emissions and remove (i.e. normalize) them from the air quality modeling prior to estimating states significant contribution? Downwind states should not be held responsible for reducing emissions that come from another country.
I request the EPA provide documentation about how the attempted to quantify the impact of emission that are transported from countries outside the United States. [EPA-HQ-OAR-2009-0491-2742.1, p.14]
Piney Creek LP
The modeled fuel costs are more than twice the costs experienced by Piney Creek and exceed the current actual fuel costs for five representative Anthracite Region Independent Power Producer Association (ARIPPA) plants cost which averages $1.48/mmBtu. This average is actually somewhat inflated insofar as it includes, on some cases, costs not directly attributable to the cost of fuel, including ash disposal. [EPA-HQ-OAR-2009-0491-2849.1 p.1] [EPA-HQ-OAR-2009-0491-3809.1_NODA, p.1]
The Proposed Rule's reliance on fuel cost as the primary basis for projecting future generating rates fails to adequately account for numerous other factors affecting generating rates. For example, in Pennsylvania, electricity distribution facilities and suppliers are required to supply a certain percentage of energy from Tier I or Tier II renewable energy sources, irrespective of electricity prices. Therefore, distribution of the generation of electricity will not strictly adhere to lowest cost of generation, as other operative criteria dictate distribution. Because waste coal-generated electricity qualifies as a renewable energy source, waste coal-fired sources such as Piney Creek will operate at a higher generating rate than cost alone would suggest. [EPA-HQ-OAR-2009-0491-2849.1 p.1] [EPA-HQ-OAR-2009-0491-3809.1_NODA, pp.1-2]
EPA's estimated heat input also does not take into account Piney Creek's long term ( through 2017) Power Purchase Agreement (PPA) with First Energy. Piney Creek is contractually required to operate as a base loaded plant, subject to certain allowances for maintenance and downtime, regardless of relative costs of generation. [EPA-HQ-OAR-2009-0491-3809.1_NODA, p.2]
PPG Industries, Inc.
PPG supports use of the updated IPM for use in making screening decisions to assist in making findings of 'significant contribution' or 'interference with maintenance' under Clean Air Act Section 110(d). PPG urges EPA, however, to make certain updates to the assumptions and inputs for IPM v. 4.10 as discussed in these comments. Further, as indicated in PPG's original comments, the IPM Base Case, whether premised on v. 3.02, v. 4.10 or some future version, should only be a screening tool for indications of potential 'significant contribution' or 'interference with maintenance'. The IPM is simply not accurate enough and is dependent upon too many uncertain assumptions and imprecise inputs to make binding decisions of 'significant contribution' or 'interference with maintenance.' EPA should always place great weight on empirical data to modify projected model conclusions when making these determinations. [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.2]
The significant difference between the results of the v. 3.02 and v. 4.10 Base Case show the imprecision of the IPM model. Due to this imprecision and the uncertainties attendant to the many assumptions made for the IPM modeling, PPG believes that an IPM projected impact of less than 2 ppb from an upwind to a downwind state should never be used as a level indicating 'significant contribution' or 'interference with maintenance' under the 'good neighbor' provisions of the Clean Air Act, 42 U.S.C. 7410(a)(2)(D). At most, the IPM should be used as a screening tool for making rebuttable presumptions for 'significant contribution' or 'interference with maintenance' determinations if a value above 2 ppb contribution is modeled. However, such presumptions should be always subject to a reasonable opportunity for rebuttal by empirical evidence and a weight of evidence approach used to determine if there is actually such contribution or interference. PPG urges EPA to adopt this 2 ppb rule as a bright-line cut-off for screening. If the modeled contribution is 2 ppb or below, then no contribution or interference should be presumed. If the modeled contribution is above 2 ppb, then there could be a rebuttable presumption of contribution or interference. [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.4]
PPG believes, for the reasons stated in the comments of the staff of the Louisiana Public Service Commission (LPSC) on the proposed CATR/FIP, that the IPM fails to adequately consider transmission constraints within Louisiana. PPG believes this is a deficiency in both the IPM v. 3.02 and v. 4.10. PPG urges EPA to carefully consider the comments of the LPSC staff. [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.7]
PPL Corporation
Additionally, allocating allowances based on future unit-specific emission rates modeled by IPM penalizes units whose future operation and emission rates are inaccurately characterized by a model that may form a basis for forecasting statewide conditions, but realistically cannot be expected to accurately characterize each unit individually. [EPA-HQ-OAR-2009-0491-2739.1, cover letter]
PPL believes that EPA's proposed approach is not legally defensible. A sounder and more equitable approach is an alternative for which the EPA is seeking comment. It would allocate portions of the state budget to each unit within the state based on each unit's proportional share of the state's total heat input from all affected electrical generation units. PPL requests that EPA adopt this alternative approach. [EPA-HQ-OAR-2009-0491-2739.1, cover letter]
[See page 1 of this comment, EPA-HQ-OAR-2009-0491-2739.1, for a table listing EGUs with a MW capacity of over 25 MW that are affected by the rule.]
PPL understands EPA's desire to reduce interstate transport to help bring downwind states into attainment of the PM2.5 and ozone NAAQS. We believe this should be done in an equitable manner and one that provides sources with the greatest degree of flexibility to comply with the rule. Our comments address the following: [EPA-HQ-OAR-2009-0491-2739.1, p.2]
:: EPA's approach toward allocating allowances to individual units
:: Allocations for Martins Creek Units 3&4 and LMBE
:: Apparent errors in the 2012 allocations listed in the proposed rule for PPL's Montour Units 1&2 and Lower Mount Bethel Energy
:: Allocations for Shutdown Units
:: Future Allocations
:: Opt-in Requirements
:: Implementation schedule
:: Support of EPA's preferred, limited interstate trading option
:: Use of CAIR banked NOx allowances
:: Banked allowances under the proposed rule [EPA-HQ-OAR-2009-0491-2739.1, p.2]
Finally, EPA's use of the IPM model to predict unit utilization as a means of allocating allowances is unreasonable and unfair. [EPA-HQ-OAR-2009-0491-2739.1, p.3]
Allocations Based on Assumed Utilization
PPL understands that the EGU allocations were calculated from a combination of recent data and projections by the Integrated Planning Model (IPM). The allocations for most of the units in Pennsylvania are listed as having been based on projections, so, apparently, the emission rates assigned for these units are based on results from IPM runs. IPM is a linear programming model that can project capacity utilization and emissions control strategies based on a least-cost optimization of constraints such as demand, environmental requirements, fuel, transmission capabilities, reliability, control technologies, the dynamics of the allowance market and dispatch strategies. [EPA-HQ-OAR-2009-0491-2739.1, p.4]
PPL agrees with the use of IPM as a tool for projections of overall utilization and costs. We believe that it is valuable for projections of statewide emissions that would be smoothed or averaged over all units. But, to be assumed to be accurate for each individual unit is expecting too much of the model. [EPA-HQ-OAR-2009-0491-2739.1, p.4]
It is hard for PPL to understand why EPA would rely on unit-specific IPM output, which obviously has error bars around it concerning individual unit projections, to allocate specific emission rates to individual units. In addition to it being inequitable to assign different emission rates to different units, to do this with a model subject to uncertainty makes this even more inappropriate. [EPA-HQ-OAR-2009-0491-2739.1, p.4]
2. Allocations for Martins Creek Units 3&4 and LMBE
PPL's Martins Creek Units 3&4 are 850 MW natural gas and residual oil-fired units that were installed in the 1970's. They presently operate at less than 10 percent annual capacity factors. The IPM model projects in its projected base case that they will not be operating in the future and they are not provided an allocation. However, PPL plans to keep operating these units into the future. [EPA-HQ-OAR-2009-0491-2739.1, p.5]
PPL understands that EPA does not want to grant allocations to units that do not operate and may in their view be permanently shutdown. However, PPL believes that the Martins Creek units and other units in similar situations should receive an allocation based on recent operation until it is demonstrated with actual operating data that they, in fact, cease to operate. [EPA-HQ-OAR-2009-0491-2739.1, p.5]
[For additional comments pertaining to Allocations for Martins Creek Units 3&4 and LMBE, see p.5 of this comment]
The following table lists the annual amounts that these units would be allocated if their base year operating levels and emission rates as presented in the draft Transport Rule data were used rather than the IPM projected operating levels. An even better alternative would be to assign and adjust the allocation based on updated three-year average heat inputs similar to the approach of the NOx SIP Call (as we discuss in Comment 5 below). In the following table PPL provides recommended SO2 allocation levels for LMBE, a natural gas only fired facility. If EPA decides to exclude natural gas-fired units from the SO2 program, as PPL recommends in Comment 1 above, there would be no need for those SO2 allocations. [[EPA-HQ-OAR-2009-0491-2739.1, p.5] [See page 6 of this comment for the table.]]
3. Apparent Errors in the 2012 Allocations Listed in the Proposed Rule for PPL's Montour Units 1&2 and Lower Mount Bethel Energy.
Under EPA's proposal for allocating allowances to individual EGUs, there appear to be errors in the allocation for PPL's Montour generating units (ORIS Code 3149). As PPL discussed in Comment 1 above, PPL does not believe that this proposed approach is equitable and recommends that EPA select an alternative approach. Nevertheless, PPL wants to identify the apparent errors. [EPA-HQ-OAR-2009-0491-2739.1, p.6]
[For additional comments on Montour and Lower Mount Bethel Energy units annual NOx allocation, see pp.6-7 of this comment.]
Prairie State Generating Company, LLC
Prairie State Generating Company, LLC ('PSGC') is a new, mine-mouth, coal-fired electric generating station located in Washington County, Illinois . PSGC has 'planned units' as described in footnote 85 of the proposed Transport Rule at 75 Fed. Reg. 45309 (August 2, 2010). The power station consists of two coal-fired supercritical steam boilers . This facility is planned and fully funded with construction well under way and will produce approximately 1750 GMWe when operational. The PSGC units will be equipped state of the art air pollution control technology, including low NOx burners and selective catalytic reduction to control emissions of nitrogen oxides, dry and wet electrostatic precipitators to control particulate emissions, and wet flue gas desulfurization to control emissions of sulfur dioxide. Upon review of the NEEDS v4.10 data presented in the Notice of Data Availability (75 Fed. Reg. 53613), PSGC has been unable to locate data for its units (PC 1 and PC2).
PSGC has included an enclosure with this letter which provides data to be added to the NEEDS database for appropriate consideration of PSGC's two coal steam boilers .
The link to the PSGC PSD Construction Permit is as follows :
http://yosemite epa gov/r5/inpermt nsf/6f1ebc583aad45448625763fI)053e08e/4332eb42380489a286257 7a4004aaa43/$FILE/ATTB513Z/O 1 100065.pdf
[EPA-HQ-OAR-2009-0491-3712 p.1]
In addition, the U.S. EPA has failed to account for the improvements which have occurred in air quality in recent years. For example, in the case of Illinois, the IPM projects that multiple counties will violate or that maintenance will be compromised for the 1996 and 2006 PM2.5 standards without (and, in one instance, with) the Transport Rule in place, yet based on 2007-2009 data, all monitoring sites in the state meet both the 35 ug/m[3] 24-hour standard and the 15 ug/m[3] annual standard with 2010 continuing this trend. The U.S. EPA designated the entire state attainment for the 2006 24-hour PM2.5 standard. 74 Fed. Reg. 58688 (November 30, 2009). The U.S. EPA has also found that air quality in the Chicago area attains the 1997 PM2.5 standard. 74 Fed. Reg. 62243 (November 27, 2009). PSGC understands that the U.S. EPA plans to issue the same finding for the Metro-East area in the near future. Using design values based on ozone data through 2009 would yield far different results from the model. The fact that using more current data would provide very different results should be ample reason for the U.S. EPA to revise its modeling. The U.S. EPA's projected results do not comport with the attainment situation based on current data in Illinois and elsewhere in the region. [EPA-HQ-OAR-2009-0491-2842.1, pp.10-11]
By not using more recent data in the entire region, Illinois is penalized for downwind impacts which are not occurring, and in turn, the U.S. EPA has set Illinois' state-wide budget at too low a level. Using more current information will significantly change the conclusions that the U.S. EPA has drawn from its analysis. [EPA-HQ-OAR-2009-0491-2842.1, p.11]
15. NEEDS DATABASE
Enclosure 1 provides the data necessary for the U.S. EPA to update the NEEDS database with PSGC's current information. This data was submitted under separate cover to this docket and to the Clean Air Markets Division by letter dated September 28, 2010.
[Enclosure 1 can be found on page 12 of this comment.]
Progress Energy Service Company
EPA proposes to set state emission budgets for annual and ozone season NOx and for S02 based on the quantity of emissions that remain after elimination of significant contribution to nonattainment and interference with maintenance, but before accounting for variability. In its technical support document (TSD) addressing state budgets, EPA explains that it calculated state budgets using a combination of emissions and heat input data reported to EPA as of 2009 and projections by the Integrated Planning Model ('IPM') for 2012, each adjusted to reflect emissions control equipment projected to be in place by 2012. See 'State Budgets, Unit Allocations, and Unit Emissions Rates' TSD at 3, 5. [EPA-HQ-OAR-2009-0491-2831.1 p.6]
In that TSD, EPA notes that in creating the state budgets for annual and ozone season NOx, it 'rebased' annual and ozone season NOx emissions for units reporting emissions data to EPA by using 2008 rather than 2009 heat input. According to EPA, this adjustment was made 'to account for unusually low utilization in 2009.' However, EPA did not make a similar adjustment for unit-reported S02 emissions. EPA does not provide an explanation for this differential treatment between the two pollutants. Progress Energy requests that EPA clarify and explain more fully why it chose to use 2008 instead of 2009 data for Ox and explain why it did not do the same for S02 data reported to EPA. In addition, many utilities, including Progress Energy, burned more natural gas in their units in 2008 than in many other years. A longer baseline period, such as a 5-year average, would be more appropriate to address the year-la-year fluctuations in fuel use and associated emissions.  [EPA-HQ-OAR-2009-0491-2831.1 p.6]
lPM-Modeled Outcomes Often Do Not Reflect Actual Source Operations
IPM predicted that the vast majority of dual-fuel units would run exclusively on natural gas. Therefore, EPA did not allocate S02 allowances to many dual-fuel units. Apparently, IPM concluded that it was most 'economical' to run these units on natural gas and failed to consider seasonal constraints on natural gas supply (e.g., shortage of supply during the winter months). The reality is that many of these units burn oil for significant parts of the year.  [EPA-HQ-OAR-2009-0491-2831.1 p.7]
IPM assumed early retirement for many units by 2014 based on a prediction that these plants would not be economical to run. However, other constraints such as system reliability make this assumption inaccurate in many cases. [EPA-HQ-OAR-2009-0491-2831.1 p.7]
Based on comments and corrections received, Progress Energy urges EPA to revise and re· perform the modeling analysis and, if necessary, re·propose the Transport Rule. This very significant and entirely new regulatory program is much too important and has too many far-reaching implications for the electric sector and the economy as a whole to rely on hastily completed modeling analyses. As stated earlier in this letter, the court did not establish a schedule for EPA to complete a revision to the CAIR. The Agency can and should take the necessary time in order to assure that the Transport Rule is established on a solid factual foundation.  [EPA-HQ-OAR-2009-0491-2831.1 p.7-8]
PSEG Services Corporation
PSEG also supports EPA's use of Integrated Planning Model ("IPM") to set state budgets for 2014 Group 1 SO2 emissions using pollution control cost thresholds. PSEG understands and supports that this methodology would be the basis for establishing any revised state budgets necessary to comply with future NAAQS. [EPA-HQ-OAR-2009-0491-2627.1, p.5]
PSEG recommends that EPA modify the unit allocation methodology. [EPA-HQ-OAR-2009-0491-2627.1, p.5]
Given the nature of what an allocation represents to emission units, the allocation methodology is understandably one of the most complex and controversial aspects of the proposed Transport Rule. To ensure EPA's methodology is defensible on legal and policy grounds, we recommend that EPA develop an allocation method that is based on an approach that is legally defensible, effective, promotes market dynamics to reveal the cost of pollution and engages market pressure to decreasing emissions. [EPA-HQ-OAR-2009-0491-2627.1, p.5]
While PSEG supports the proposed methodology for developing state budgets, it does not support the proposed methodology for allocating allowances to units. PSEG does not support the use of projected emissions from the IPM modeling as the basis for unit-level allocations in 2012 or 2014. The IPM does not consider a range of non-economic factors that influence a company's decision to operate a unit or for the ISO to call upon a unit. As a result, allocating allowances to emission units on the basis of IPM results creates unrealistic scenarios such as running natural gas combined cycle units at higher utilization than can be accommodated by the natural gas pipeline network or not running oil-fired units that are required to operate to meet reliability and capacity requirements. These distortions of the electricity market are masked when data are aggregated at the state level for setting state budgets but result in inequities when used at the unit level to allocate allowances. As we note above, PSEG believes it is important for EPA to propose a rule that withstands, and preferably forestalls litigation and that can be implemented as quickly and smoothly as practicable. We are concerned that using modeled projections for the emission unit allocation is inherently complex and has the potential for significant flaws that the rulemaking process cannot appropriately address for the rule to be implemented by January 2012. [EPA-HQ-OAR-2009-0491-2627.1, p.6]
Therefore, PSEG recommends that EPA modify the unit allocation scheme. As EPA recognizes in its approach for the 2014 Group 1 SO2 program, there is no strong policy reason, and no legal reason, that the methodology for determining state budgets and the methodology for distributing allowances to units need to be the same. Below, PSEG proposes an alternative emission unit allocation approaches that is consistent with the D.C. Circuit court's decision because it does not alter the state budgets, which are based on each state's significant contribution. Additionally, PSEG's proposed approach is fuel neutral and would not raise the concerns similar to those identified by the court regarding CAIR's use of fuel adjustment factors. The court rejected the fuel adjustment factors because they placed a disproportionate burden on downwind sources compared to the upwind sources contributing to the nonattainment problems. [EPA-HQ-OAR-2009-0491-2627.1, p.6]
We strongly recommend that EPA consider basing the unit allocations on a unit's proportion of its state's historic heat input (i.e., million British thermal units, mmBtu). The historic heat input should be based on the maximum annual heat input for units during the period of calendar years 2007 through 2009. We recommend using the annual maximum of reported data during the three year period rather than the average of those three years in order to ensure an outlier year does not dramatically affect the allocation (e.g., the unusually low utilization in 2009 related to the economic downturn). In cases where an owner has not reported heat input data for one or all of the years, we propose that EPA allow the owner to submit such data for consideration. [EPA-HQ-OAR-2009-0491-2627.1, pp.6-7]
Such an allocation methodology would address many of PSEG's concerns with EPA's preferred approach. Most significantly, it would not be based on modeled future emissions and it is based on data EPA already has from companies. Additionally, it would correct the proposed methodology that disadvantages early actors that EPA acknowledged in the preamble to the proposed rule. It is important to note that PSEG is proposing this approach with the ultimate goal of having the rule be implemented by January 1, 2012. Thus, we would welcome the opportunity to discuss and provide feedback on any additional allocation approaches suggested in other stakeholders' comments. However, PSEG would strongly oppose an allocation approach that was based solely on historic emissions as that approach would again penalize early actors, and their customers, that are already paying for the installation of control technologies. Emissions-based allocations, similar to the fuel adjusted heat input-based allocation rejected by the D.C. Circuit, reward higher emitting facilities at the expense of early actors and discourage future early action by companies. Penalizing early actors and rewarding high emitters is exactly the wrong signal EPA should send to industry as the Agency works to develop and implement the multiple regulations for the electric sector and other industries. [EPA-HQ-OAR-2009-0491-2627.1, p.7]
If EPA finalizes the allocation methodology approach using the preferred option, PSEG recommends that EPA revise specific aspects to support EPA's ability to implement the rule by January 1, 2012. [EPA-HQ-OAR-2009-0491-2627.1, p.8]
PSEG is concerned that EPA's proposed methodology disadvantages natural gas peaking units relative to other higher emitting units. Because these units have low annual emissions and typically are only run at times of high demand, the IPM model projects SO2 emissions of less than 0.5 tons. Based on the proposed methodology, EPA would round these allocations to zero when calculating the unit's allowance allocations. If EPA retains the preferred allocation methodology, PSEG recommends that EPA at least round-upward each of these units' allocations to one ton so as not to discourage use of cleaner fuels during periods of electric peak demand. [EPA-HQ-OAR-2009-0491-2627.1, p.8]
San Miguel Electric Cooperative, Inc.
2) The following correction to the IPM Parsed files of the TR base case, SB limited trading case, SB intrastate trading case and Direct control case runs are required:  
-The SCR needs to be deleted as a retrofit in each of the Transport Rule model runs.   [EPA-HQ-OAR-2009-0491-2641.1,p.3]
-The heat input should indicate a base load unit. If San Miguel were allocated allowances based on the current IPM model TR Base Case, San Miguel would be operating only during the ozone season and at reduced capacity of approximately 61.3%. As stated above San Miguel is a low cost unit to our members and is operated as a base load unit.   [EPA-HQ-OAR-2009-0491-2641.1, p.4]
Santee Cooper
The unreasonableness of the EPA allocation scheme is further evidenced by EPA's decision to base allowance allocations to existing units on projected emissions from these units after eliminating significant contribution and interference with maintenance. Specifically, EPA proposes to project each unit's emissions based on the Integrated Planning Model (IPM), which may be a useful analytic tool for forecasting region wide trends, but is highly unreliable for forecasting how specific units will actually operate in the future. Chart V [See p. 24 of this comment summary for Chart V] illustrates the coal system emission rates utilized by the IPM for allowance allocation. Again, Santee Cooper receives allowances at rates far below the other South Carolina utilities and far below what its consent decree limits require. [EPA-HQ-OAR-2009-0491-2820.1, pp.23-24]
At best, projecting future emissions for any particular unit based on IPM analyses can forecast on only how that unit could perform based on a range of assumptions and other data input - much of which may not ultimately have a close correspondence to actual conditions and circumstances. IPM modeling, for example, must make assumptions on a wide range of factors, including electricity demand, fuel prices, use of specific coal type, control costs, resource mix (both among fossil and non-fossil generation), marginal cost of power, timing and type of capacity additions. Further, the IPM model does not consider transmission constraints or variations in demand growth on the state or sub-regional level. Transmission constraints playa large role on dispatch decisions, particularly at times of high demand. Variations in demand growth are very important in South Carolina where certain service territories of some electric utilities are expected to experience high growth, while the electric demand of other electric utility service territories may remain flat or have low growth. As part of its integrated resource plan (IRP), Santee Cooper undertakes extensive modeling of economic growth and electricity demand at multiple areas within the state. Even accounting for the current economic downturn, Santee Cooper serves some of the most rapidly developing areas of South Carolina. These include the growing suburban areas outside of Charleston, Columbia, Aiken, and North Augusta as well as the coastal areas of Myrtle Beach and the Grand Strand, Hilton Head Island, Kiawah Island, and Seabrook Island. [EPA-HQ-OAR-2009-0491-2820.1, pp.24-25]
It is unrealistic to expect that even the most reasonable assumptions will prove to be accurate to make reasonable projections on how specific units will actually operate and what their emissions levels will be.  [EPA-HQ-OAR-2009-0491-2820.1, p.25]
At worst, the IPM analyses are based on arbitrary assumptions and erroneous data that further distorts the accuracy of projected emissions levels, particularly at the unit specific levels. As discussed in subsection C below, the assumptions and data used for the IPM analyses contain significant errors and inaccuracies with respect to operation and performance of the affected units within Santee Cooper system.  [EPA-HQ-OAR-2009-0491-2820.1, p.25]
For these reasons, Santee Cooper believes that IPM modeling is an inappropriate methodology for allocating allowances to existing affected units under the Transport Rule. The use of theoretical models like IPM will- by definition - have arbitrary, random, and illogical results that - among other things - will penalize electric utilities that have made the capital investments to control their emissions. If, however, EPA decides to allocate allowances based on projected emissions levels, EPA must greatly improve the quality of modeling inputs, including the assumptions and data used in the IPM modeling. Subsection C below briefly describes the faulty assumptions and inaccurate data that need to be corrected in the IPM analysis for the Santee Cooper system units. [EPA-HQ-OAR-2009-0491-2820.1, p.25]
THE ASSUMPTIONS AND DATA USED FOR THE IPM ANALYSES NEED TO BE CORRECTED FOR UNITS WITHIN THE SANTEE COOPER SYSTEM. [EPA-HQ-OAR-2009-0491-2820.1, p.25]
The principal analytical tool on which EPA relied in developing the unit allowance allocations and statewide emission budgets in the Proposed Transport Rule is IPM. As explained in a technical support document for the proposed Transport Rule, the IPM 'provides forecasts of least-cost capacity expansion, electricity dispatch, and emission control strategies for meeting electricity demand, environmental, transmission, dispatch, and reliability constraints." Notwithstanding the considerable analytic power of the IPM, there are important limitations on the accuracy and usefulness of the model. One important limitation is the quality of the inputs to the model. Among the most critical inputs to IPM are the emission inventory and unit-level characteristics and operating parameters. The primary source for unit-level emission information for IPM is the National Electric Energy Data System (NEEDS), which provides the unit-level EGU characteristics used as input for the IPM. The NEEDS database is fraught with significant errors, as illustrated below with respect to the Santee Cooper system. In addition, other inputs can be used for, and limitations placed on, IPM analyses to reflect particular, unique situations such as state-specific regulations of EGU emissions and NSR settlements that may limit those emissions. IPM refers to such inputs as 'constraints.' The discussion below also details various errors in the 'constraints' EPA placed on the IPM model runs with respect to the Santee Cooper system. [EPA-HQ-OAR-2009-0491-2820.1, p.26]
Finally, the outputs from EPA's IPM runs, when compared to actual unit-specific data and individual companies' plans, are inaccurate and unrealistic. The validity of a given set of outputs from an application of any modeling tool is brought into question when the modeled results do not reflect real-world conditions. The discussion below provides specific examples of inconsistencies between EPA's IPM projections and Santee Cooper's plans for its units. [EPA-HQ-OAR-2009-0491-2820.1, p.26]
Santee Cooper has compared projected heat inputs with data assumptions for the Santee Cooper system in the EPA-HQ-OAR-2009-0491-0074 1 data sheets. Heat inputs for Cross 2, Grainger Units I and 2, Jefferies Units 3 and 4, and Winyah Units 1,2, and 3 are not indicative of normal or future projected operation levels. The following are discrepancies so far identified: [EPA-HQ-OAR-2009-0491-2820.1, p.27]
Heat input for Cross Unit 2 is significantly lower in the data sheet when compared to expected operation of Cross Unit 2 in 2012 and 2014. [EPA-HQ-OAR-2009-0491-2820.1, p.27]
Heat input levels for Grainger Units 1 and 2 are lower in the data sheet when compared to expected operation of these units in 2012. [EPA-HQ-OAR-2009-0491-2820.1, p.28]
Heat input levels for Jefferies Units 3 and 4 are much lower in the data sheet when compared to expected operation of these units in 2012 and 2014. [EPA-HQ-OAR-2009-0491-2820.1, p.28]
Heat input for Winyah station is lower in the data sheet when compared to the expected operation of these units in 2012. [EPA-HQ-OAR-2009-0491-2820.1, p.28]
One reason for the heat input shortfall is that the IPM projections only reflect native load demands and do not include off-system sales. Once off-system sales are factored into future load projections, heat input levels for the Santee Cooper's system increase by almost an additional 5 percent - much of which will be concentrated in the higher-emitting Grainger and Jefferies units.' [EPA-HQ-OAR-2009-0491-2820.1, p.28]
These discrepancies further demonstrate that allowance allocations under the Transport Rule should not be based on the results of the IPM projections for individual units. However, even if this method is used, the use of unit emission rates and other operating data from a single year (2009) is unrepresentative and therefore will by definition have arbitrary effects. Among other things, one year's emission rates are not a reasonable indicator of unit performance due to control equipment degradation and maintenance cycles as well as variations in the sulfur content of coal. At the very least, EPA should base allocation based on a multi-year average of IPM projections if EPA insists on using this approach. [EPA-HQ-OAR-2009-0491-2820.1, p.28]
Finally, IPM projection errors of this sort appear to be a function of inherent limitations of IPM and EPA's limited knowledge of certain local factors. IPM is a least-cost economic model designed to predict operations at a fairly broad regional level. In many instances, EPA lacks sufficient information about local issues such as transmission constraints, capacity commitments, fuel-contract commitments, and other cost-related considerations that have not been input to the IPM model. EPA's insufficient information, coupled with the limitations of the regional IPM model, result in inherently unreliable and arbitrary projections at the unit-specific level that are inappropriate for use in allocating allowances to affected units under Transport Rule. [EPA-HQ-OAR-2009-0491-2820.1, p.28]
South Carolina Department of Health and Environmental Control 
It is important that the EPA use appropriate modeling tools and assumptions in the final Transport Rule, since it will use this same modeling approach in future iterations of the Transport Rule. Also, the EPA is relying on IPM as the sole solution in determining budgets and allocations. DHEC has encountered problems with IPM while modeling for regional haze with VISTAS, the Visibility Improvement State and Tribal Association of the Southeast. The problems included mistaken control efficiencies and missing information. We found similar problems in the Transport Rule supporting data, though, because of time constraints, we are unsure that we have caught every problem. Under the NOX SIP Call and CAIR, states and the EPA based allocations on actual usage data from the EPA Clean Air Markets Division (CAMD) database, a much more transparent and reliable process than uncertain IPM projections. IPM, a registered trademark of the ICF Corporation, is a proprietary system, and we do not have the opportunity to review all of its assumptions. With IPM making many of the regulatory determinations, it is important to ensure its assumptions are correct and its use within the Transport Rule is sound. [EPA-HQ-OAR-2009-0491-2677.1 p.5]
Southern Company
1. EPA Made Significant Errors in the Base Case Emissions Inventory As discussed previously, EPA attempted to remove the existence of CAIR from the base case emissions. This is not a correct assumption, because in the absence of a final Transport Rule, emission reductions from CAIR and state rules will continue. Thus, even if the Transport Rule were not promulgated in 2012, CAIR would remain in place. In removing CAIR from the base case, EPA made numerous unreasonable assumptions. For Georgia, in particular, the IPM modeling projects unreasonably high S02 emissions from several coal units in the 2012 base case. [EPA-HQ-OAR-2009-0491-2864.1, p. 39]
IPM projects 2012 base case emissions for seven Georgia Power units to be nearly three times their historical emissions (See table below). The over-projection by IPM is so large that it is equivalent to the entire 2012 Transport Rule budget for Georgia. Using our replicated version of the AQAT, we found if EPA used appropriate emissions for Georgia in the 2012 base case, Georgia would not be linked to the Baltimore City, MD, monitor and would, therefore, not be classified as a Group 1 state. Furthermore, as is documented in Section X of these comments and in comments submitted by others, including UARG and the FCG, IPM made erroneous 2012 emissions projections for a number of other states as well.  [EPA-HQ-OAR-2009-0491-2864.1, p. 39]
2. EPA's Methodology Did Not Adequately Consider Emissions Reductions That Are Required By Other Rules
Because of flaws in the 2012 base case that have been discussed in previous sections, EPA should not have used those emissions in their current form for determining which states are included in the Transport Rule. The state of Georgia, in an effort to address transport issues, local nonattainment issues, and hazardous air pollutants, developed its own Multi-pollutant Rule. The Multipollutant rule requires the installation of specific control technologies at all of the larger coal-fired power plants in the state. As a result, Georgia Power is in the midst of a massive construction program installing NOx and S02 controls on many of its coal-fired units. By 2012, over 50 % of the coal generation operated by Georgia Power will be scrubbed. By 2014 that number will grow to over 70% and by 2015 nearly 90% of Georgia Power's coal generation will be scrubbed. These emissions controls are reflected in the 2014 IPM modeling for the Transport Rule (see Figure XI-3 below) [See EPA-HQ-OAR-2009-0491-2864.1, p. 41 for the Figure]. The 2012 $0 per ton emissions used for the significant contribution test were extremely high. Had EPA evaluated the contribution from Georgia to downwind nonattainment and maintenance monitors in 2014 at $0 per ton of S02, they would have found that Georgia was not linked to nonattainment or maintenance issues at the Baltimore City, MD, monitor. In fact, the only monitors that Georgia is linked to at $0 per ton in 2014 are the two Birmingham monitors, both of which are impacted by local sources. Birmingham has demonstrated monitored attainment for the daily standard and is projected to achieve attainment of the annual standard by 2012 in the Birmingham PM2.5 SIP through reductions achieved by the local sources and CAIR. [EPA-HQ-OAR-2009-0491-2864.1, p. 40]
Sunflower Electric Power Corporation
EPA has received and denied without reasoned basis a number of requests for extension of the comment period to afford concerned parties the opportunity to fully review and consider the proposed rule and the assumptions on which it is founded. Comment 1 above is one small example of the type of errors found in the modeling on which the agency relies. [EPA-HQ-OAR-2009-0491-2833.1 p.2]
EPA analysis did not take into consideration federally enforceable emissions reductions that have already been recently achieved with major Kansas EGUs. The revised analysis, presented separately for all Kansas utilities by Trinity Consultants, a copy of the cover letter for which is attached as Exhibit A, clearly shows that the revised levels of NOX emissions, which have already been achieved by the indicated Kansas sources , reduces the determined impact level below that determined by EPA to be significant. [EPA-HQ-OAR-2009-0491-2833.1 p.2]
Sunflower respectfully requests that EPA remove Kansas for the list of States determined to make a significant ozone contribution to downwind states. [EPA-HQ-OAR-2009-0491-2833.1 p.2]
Tennessee Department of Environment and Conservation, Division of Air Pollution Control
Comment #1 on 2012 Baseline Emissions for Tennessee: The baseline analysis considers emissions reductions associated with the implementation of all federal rules promulgated by December 2008 and assumes that CAIR is not in effect. The following numbers were used for Tennessee: [[See Docket Number OAR-2009-0491-0553.1, p.3 for the table]].
EPA appears to have omitted the SO2 emission limit established at TVA Cumberland in the Regional Haze SIP. Rule 1200-03-23-.03 of the Tennessee Air Pollution Control Regulations (TAPCR)
Upon mutual agreement of the owner or operator of any source and the Technical Secretly, operating hours, process flow rates, or any other operating parameters may be established as a binding limit(s). The mutually acceptable limits shall be stated as a special condition(s) for any permit or order concerning the source. [EPA-HQ-OAR-2009-0491-0553.1, p.3]
BART permit 061875H was issued for TVA Cumberland on March 31, 2008, and submitted to EPA as part of the Regional Haze SIP on March 31, 2008. A copy of this permit is attached (see Attachment #2) [[See Docket Number OAR-2009-0491-0553.1, pp.6-7 for Attachment 2]]. This permit establishes an SO2 BART limit (non-CAIR) of 0.5 lb/mmBtu for regional haze compliance. The permit requires TVA to comply "as expeditiously as possible", but no later than 5 years after approval of TN Regional Haze SIP. [EPA-HQ-OAR-2009-0491-0553.1,p.3]
Our recent discussions with EPA Region 4 indicate that the Agency is in the process of issuing a conditional approval of the non-CAIR portions of Tennessee's Regional Haze SIP. Since TVA Cumberland has existing controls that would allow the facility to meet the 0.5 lb/mmBtu SO2 requirement, we believe that TVA's requirement to meet the BART limit "as expeditiously as possible" at Cumberland by 2012.2 We therefore believe that this limit should be included in Tennessee's 2012 baseline SO2 emissions. [EPA-HQ-OAR-2009-0491-0553.1, p.3]
Assuming a BART limit (non-CAIR) of 0.5 lb/mmBtu SO2 for TVA Cumberland, baseline SO2 emissions for Tennessee would decrease from 596,987 tons to 268,629 tons, as follows:
Existing 2012 Tennessee Baseline: 596,987 tons
Existing 2012 Baseline for TVA Cumberland: 370,891 tons
Revised 2012 Baseline for TVA Cumberland: 42,533 tons
Revised 2012 Tennessee Baseline: 268,629 tons (596,987 tons  -  370,891 tons + 42,533 tons) [EPA-HQ-OAR-2009-0491-0553.1,p.3]
EPA should revise Tennessee's 2012 baseline SO2 emissions from 596,987 tons to 268,629 tons. [EPA-HQ-OAR-2009-0491-0553.1, p.3]
Comment #2 on 2012 Baseline Emissions for Tennessee: The baseline analysis considers all known controls required under consent decrees and other enforceable binding commitments through 2014. We note that "other enforceable binding commitments" appears to include the U. S. District Court decision in North Carolina vs. TVA, since the 2012 baseline includes add-on SO2 and NOX controls at Bull Run, John Sevier, and Kingston fossil plants. That decision was overturned by the 4th Circuit Court of Appeals on July 26, 2010, and EPA may need to adjust the 2012 baseline emissions for Bull Run, Kingston, and John Sevier fossil plants. Adjustments to the baseline emissions for these facilities would increase the baseline emissions above the 268,629 tons indicated in the previous comment. [EPA-HQ-OAR-2009-0491-0553.1, p.3]

Footnote 2: Because the permit language for TVA Cumberland states that TVA must comply with the BART limit "as expeditiously as practicable, but in no event later than five (5) years after publication in the Federal Register of U.S. EPA's approval of Tennessee's Regional Haze State Implementation Plan revision," it could be argued that compliance with the BART limit would not be required prior to 2015. While this assertion may be true for sources that are not using existing controls to comply with BART, we note that, since TVA Cumberland is currently operating below 0.5 lb/mmBtu SO2 using existing controls, the requirement to comply with this limit "as expeditiously as practicable" could be applicable upon approval of Tennessee's Regional Haze SIP. We also note that this limit would be enforceable by EPA upon approval of the Regional Haze SIP (i. e., prior to incorporation of the BART limit into the Title V permit), since the BART permit was submitted to EPA as part of the SIP.
Tennessee Valley Authority (TVA)
TVA Comment: TVA believes it is unreasonable to expect emission reductions by January 2012; a mere 6 months after the date EPA plans to finalize the Transport Rule. EPA explains the establishment of this short deadline on the basis that emission reduction required in 2012 would occur even in the absence of the Transport Rule. As explained above, EPA has made incorrect assumptions about the emission reductions that will occur by 2012. [EPA-HQ-OAR-2009-0491-2782.1, pp. 4-5]
Texas Commission on Environmental Quality
The TCEQ finds that the basic information about the current state of NOx control for EGUs in Texas that the EPA used in the Integrated Planning Model (IPM) runs has substantial errors, which results in unreliable assumptions and predictions produced by the IPM modeling. For this reason, the TCEQ objects to the use of the IPM results in regulatory decision making. [EPA-HQ-OAR-2009-0491-2857.1, p.2]
The basic information about the current state of NOx control for EGUs in Texas that EPA used in the IPM modeling runs has substantial errors. Therefore, the assumptions and predictions produced by the IPM modeling are unreliable and should not be used for regulatory decisions. The TCEQ has found significant errors in the EPA's basecase IPM modeling files that call into question the results of the IPM runs. Units that EPA predicts to be making significant NOx reductions, to a NOx pound per million British thermal units (lb/mmBtu) control level the TCEQ finds to be likely beyond low NOx burner technology, are actually already at that control level from the installation of SCR required by state permit or rule. Yet the IPM basecase model files show only basic NOx controls like low NOx burners or no controls at all. The following are just a few examples of sites where the IPM data files have inaccurate information about the base case NOx control level and the facilities are actually already at SCR NOx control levels: Colorado Bend Energy Center; South Texas Electric Coop (Sam Rayburn); Midlothian Energy Center; Hays Energy Facility; Cottonwood Energy Company; and SRW Cogeneration. Since the EPA obviously does not have an adequate understanding of the current NOx control level for the EGUs in Texas, the EPA should not be rushing forward with rulemaking based on fundamentally flawed data and modeling. Additionally, the TCEQ finds it unreasonable for the EPA to expect that states to correct these errors within the limited time provided. In response to the TCEQ's (and others') requests for time to adequately review this rule, the EPA stated 'We believe the comment period provided is sufficient for interested parties to review the rule, prepare and submit input.' The EPA is misleading the public and itself about the quality of information used to form the cornerstone of the Transport Rule and should allow sufficient comment time to review and correct this clearly flawed data. [EPA-HQ-OAR-2009-0491-2857.2, pp.11-12]
TransCanada
Comment 2: Errors with the National Electric Data System (NEEDS) Data Have Caused Inaccurate Emission Allocation for EGUs and the New York State Budget
There are numerous errors with The National Electric Data System ("NEEDS"), which was used in the proposed Transport Rule to determine each state's significant contribution and interference with maintenance of downwind states. These errors have resulted in inaccurate data and the inappropriate allocation of allowances to New York State and individual units, such as Ravenswood. The SO2 and NOx emission data contained in the proposed Transport Rule's spreadsheets are not consistent with actual emissions data reported and, therefore, should not be used to allocate allowances to New York State or to individual units. [EPA-HQ-OAR-2009-0491-2827.1, p.2]
The inaccurate data has resulted in potential overestimates or underestimates in the proposed Transport Rule's unit specific and state budget allocation process. Since the state budgets for SO2, annual NOx, and ozone season NOx are based on the measurement of each state's significant contribution and interference with maintenance of downwind states, the impact of the inaccuracies in NEEDS may significantly impact EGUs in New York State, such as Ravenswood, by not allocating the appropriate amount of allowances to some units. [EPA-HQ-OAR-2009-0491-2827.1, p.2]
EPA should, therefore, correct the errors and inaccuracies in the data, document the source of the data, account for variability and recalculate the unit specific and state budget allocations. [EPA-HQ-OAR-2009-0491-2827.1, p.2]
Utility Air Regulatory Group (UARG)
The PTR's compliance schedule is wholly unreasonable, particularly its imposition of a January 1, 2012 initial compliance deadline that will fall only a few months after EPA plans to take final action in this rulemaking. [EPA-HQ-OAR-2009-0491-2756.1, p.9]
Many of the flaws in the Proposed Transport Rule, described in the sections that follow, could be resolved or at least somewhat ameliorated by deferring the initial 2012 compliance date and having CAIR's allowance trading and enforcement mechanisms remain in effect pending implementation of the Transport Rule. It is unreasonable and unrealistic, for example, to expect emission reductions required by the proposal to be achieved by January 1, 2012, barely six months after the date on which EPA expects to issue a final Transport Rule. [EPA-HQ-OAR-2009-0491-2756.1, pp.16-17]
An initial compliance deadline of January 1, 2012, will not allow sufficient time for sources to make the adjustments necessary to comply with the rule. For example, a compliance deadline of 2012, following a mid-2011 date for final promulgation of the rule, would not allow enough time for sources to install low NOx burners ("LNBs"), and in many cases, would not allow sufficient time for sources to switch to burning lower sulfur coal. See section V infra. [EPA-HQ-OAR-2009-0491-2756.1, p.17]
Additionally, much of the modeling that EPA used to develop the proposed rule is flawed, due to the approach that EPA adopted, as well as many of the assumptions EPA made with respect to issues such as the emission controls that will be installed on, and retirement of, specific units by 2012. EPA must resolve and correct these problems, and either withdraw the proposed rule and reinitiate rulemaking with a new proposal or issue a supplemental notice of proposed rulemaking for public comment. Under these circumstances, rulemaking could not be completed before the beginning of 2012. [EPA-HQ-OAR-2009-0491-2756.1, p.17]
In any event, EPA has provided no reasonable justification for its proposal to require a compliance date as early as 2012. To begin with, according to statements by EPA representatives, the emission levels required in the 2012 phase for the most part reflect the emission reductions that would occur even in the absence of the Transport Rule. However, as noted above, in a number of cases, EPA has made incorrect assumptions regarding emission reductions that, in the absence of this new rule, would occur at units by 2012. See section VIII.A infra. [EPA-HQ-OAR-2009-0491-2756.1, pp.19-20]
UARG is not alone in its concern regarding the initial compliance date. Last year, for example, the Lake Michigan Air Directors Consortium ("LADCO") strongly recommended that any CAIR replacement rule include an initial compliance date no earlier than 2017 for any significant additional emission reduction requirements. See Letter from LADCO to Administrator Jackson (Sept. 10, 2009) ("LADCO Letter") at 1. LADCO explained in its recommendations to EPA that it had conducted a state-by-state analysis that indicated that installation of significant new NOx and SO2 controls -- specifically, installation of selective catalytic reduction systems ("SCRs") and flue gas desulfurization systems ("FGDs" or "scrubbers") -- would not be possible in LADCO states before 2017. Id. at 1, attachment at 4- 5. 16 [EPA-HQ-OAR-2009-0491-2756.1, p.22]
Moreover, EPA ignores the fact that many electric generating companies are not in a position to undertake fuel switching in the near term because of binding fuel contracts. Many electric generating companies may also face capital-access or other constraints that would prevent them from undertaking emission control projects, except perhaps at prohibitively high interest rates, in the near term. In addition, electric generating companies have fiduciary obligations that prevent them from making commitments to capital projects while the nature and scope of emission reductions remain uncertain. As described above in section III.A, the scope of emission reductions that will ultimately be required under the Transport Rule is far from certain. [EPA-HQ-OAR-2009-0491-2756.1, pp.22-23]
In sum, the fact that EPA's proposal to set an initial compliance deadline of January 1, 2012, is so fraught with difficulty and uncertainty is a stark illustration of the ill-advised nature of this attempt to force implementation of such a complex and demanding rule in only six months. [EPA-HQ-OAR-2009-0491-2756.1, p.24]
The January 2012 and January 2014 Compliance Deadlines Set Forth in the Proposed Transport Rule Are Unreasonable and Unrealistic.
In materials prepared to explain its Proposed Transport Rule, EPA made the following assumptions about how low SO2 and NOx emission levels from EGUs would be as a result of (a) the implementation of CAIR and other on-the-books regulations, and (b) the implementation of the Proposed Transport Rule:
Table V-1 demonstrates that EPA expects its PTR to require substantial additional EGU emission reductions beyond those that have been (or would be) achieved through implementation of CAIR. Despite how much EPA expects its PTR to accomplish in terms of achieving additional emission reductions, however, EPA proposes to give affected sources very little time to achieve those additional reductions. [EPA-HQ-OAR-2009-0491-2756.1, pp.32-33] [[See Docket Number EPA-HQ-OAR-2009-0491-2756.1, p.33 for Table V-1]]
Specifically, EPA assumes that affected EGUs will be able to reduce their SO2 emissions from 5.1 million tons per year to 4.1 million tons per year between mid-2011 (when EPA expects to take final action on the PTR22) and January 1, 2012. This reduction, says EPA, can be accomplished if affected companies (a) just complete the installations of FGD units that are already underway, and (b) supplement the emission reductions from those controls by switching some of their units to burning lower sulfur fuels. See 75 Fed. Reg. at 45273/2. Then, relying in large part on information from a March 2005 study, EPA takes pieces of information from retrofit experiences at two power stations and uses those scant data to conclude that it is possible for owners of EGUs to reduce their emissions even further (down to 3.3 million tons annually) by January 1, 2014, through the installation of additional FGD units, which -- EPA claims -- can be designed, permitted, and constructed in just 27 months. Id. at 45273/1. [EPA-HQ-OAR-2009-0491-2756.1, pp.33-34]
Similarly, EPA assumes power plant owners will be able to reduce their EGUs' annual and seasonal NOx emissions by substantial amounts by January 1, 2012, by completing already in- the-pipeline projects to install SCR reactors and by constructing more LNB systems that -- according to EPA -- can be installed in the few months between the time that the PTR is scheduled to be finalized in mid-2011 and January 1, 2012. And if any additional NOx reductions are needed (although EPA's projections as summarized in Table V-1 above suggest that no such additional NOx reductions will be needed), then affected electric generating companies can install additional SCR units by January 1, 2014, because -- according to EPA (again relying on its 2005 Report) -- it takes only "approximately 21 months" to design, permit, and construct SCR units. Id. at 45273/1. [EPA-HQ-OAR-2009-0491-2756.1, p.34]
As discussed in greater detail in other portions of these comments and in the comments being filed by individual UARG members, EPA has substantially overestimated the number of FGD and SCR installations that are now under construction and can be operational by January 1, 2012. Therefore, the Agency has greatly underestimated the number of FGD and SCR installations that affected utilities would have to undertake and complete between January 1. 2012, and January 1, 2014, to meet the PTR's requirements. [EPA-HQ-OAR-2009-0491-2756.1, pp.34-35]
Even worse than this, though, EPA has vastly underestimated the amount of time that it takes utilities to design, permit, construct, and start up new FGD and SCR units. It will take longer than 30 months -- in some cases significantly longer than 30 months -- for companies to retrofit FGD and SCR units at existing EGUs. For all of these reasons, it will not be possible for affected EGUs to achieve the substantial SO2 and NOx emission reductions that -- under the terms of the PTR -- must be achieved by that rule's January 2012 and January 2014 deadlines. [EPA-HQ-OAR-2009-0491-2756.1, pp.34-35]
Section V.A provides an overview of the many steps that power plant owners must follow in order to retrofit their power plants with control equipment like FGD and SCR units. A more detailed discussion of these steps is provided in a separate report, which is attached hereto as Attachment I, and is incorporated by reference herein: Cichanowicz, J.E., "Implementation Schedules for Selective Catalytic Reduction (SCR) and Flue Gas Desulfurization (FGD) Process Equipment" (Oct. 1, 2010) (hereinafter "Implementation Schedules Report"). The Implementation Schedules Report was prepared by J. Edward Cichanowicz, who has been involved in -- and has first-hand knowledge of the challenges that can be posed by -- the design, permitting, and construction of FGD and SCR retrofits at many power plants throughout the United States. Next, section V.B of these comments directly addresses the few examples and arguments that EPA has made in support of its highly abbreviated compliance deadlines. Then sections V.C and V.D of these comments provide a broad range of more current examples of FGD and SCR retrofits, respectively. These examples demonstrate the complexity and time-consuming nature of the retrofit installation processes at most sites. EPA's failure to understand this has led the Agency to systematically underestimate the length of time it now takes to retrofit FGD and SCR systems at power plants. [EPA-HQ-OAR-2009-0491-2756.1, pp.35-36] [[See Docket Number EPA-HQ-OAR-2009-0491-2756.1, pp.104-146 for Attachment I.]] [[These comments can also be found in Section VII.C.]]
EPA places all FGD and SCR installation activities into one of essentially three broad overlapping categories: (1) conducting an engineering review of the facility and awarding a procurement contract; (2) obtaining a construction permit; and (3) installing the control technology. EPA, "Engineering and Economic Factors Affecting the Installation of Control Technologies for Multipoint Strategies" (2002) at 7-8, 20, available at www.epa.gov/clearskies/pdfs/multi102902.pdf (hereinafter "2002 EPA Report"). Categorizing the numerous activities involved in installing FGD and SCR systems in such a general way, however, tends to mask the overall complexity of the numerous steps that electric generating companies must actually follow in order to design, permit, and construct FGD and SCR systems at their power stations. The following is a more detailed discussion of all the steps that power plant owners typically take when they retrofit FGD and SCR systems at their stations. [EPA-HQ-OAR-2009-0491-2756.1, pp.36-37]
Step One Requires More Than Conducting an Engineering Review. [[See Docket Number EPA-HQ-OAR-2009-0491-2756.1, pp.27-39 for a detailed discussion on this issue.
A Construction Permit Is Only One of the Many Authorizations that Affected Plant Owners May Need. [[See Docket Number EPA-HQ-OAR-2009-0491-2756.1, pp.39-42 for a detailed discussion on this issue.]]
The Actual Construction of FGD and SCR Systems at Existing Sites Will Take Longer than EPA Suggests. [[See Docket Number EPA-HQ-OAR-2009-0491-2756.1, pp.42-43 for a detailed discussion on this issue.]]
EPA Relies Upon Incomplete and Outdated Information in Concluding that FGD and SCR Retrofits Can Be Installed in a Total of Less than 30 Months. [[See Docket Number EPA-HQ-OAR-2009-0491-2756.1, pp.43-45 for a detailed discussion on this issue.]]
FGD Installations: Real-World Examples Demonstrate that EPA Has Substantially Underestimated How Long It Typically Takes To Retrofit FGD Systems at Power Plants.  [[See Docket Number EPA-HQ-OAR-2009-0491-2756.1, pp.46-49 for a detailed discussion on this issue.]]
SCR Installations: Real-World Examples Demonstrate that EPA Has Substantially Underestimated How Long It Typically Takes To Retrofit SCR Systems at Power Plants. [[See Docket Number EPA-HQ-OAR-2009-0491-2756.1, pp.49-51 for detailed discussion on this issue.
Summary and Conclusions.
Solid information from individual UARG members and detailed information in the Implementation Schedules Report demonstrate that it now takes longer -- often much longer -- than 21 and 27 months to complete retrofits of SCR and FGD equipment, respectively. There are many reasons why FGD and SCR installations take as long as they do, including the complicated physical constraints posed by the sites at which the equipment will be installed (retrofits at any "simple" sites have likely already been done); the complexities of the overall permitting/authorization process that plant owners face today; and the high demand now for the skilled labor force needed to undertake these projects. The extensive amount of information presented in these comments and in the attached report, as well as information in comments from individual UARG members, refute any EPA claim that FGD and SCR installations can generally be conducted and completed in a total of less than 30 months. [EPA-HQ-OAR-2009-0491-2756.1, p.51]
There is also no basis for any suggestion that electric generating companies could cut installation times by 30% to 50% if only they had the will to do so. Such a "field of dreams" approach (something akin to "demand it and it will happen") does not apply to the construction of FGD and SCR systems. If electric generating companies could build such systems in less than 30 months, they would. For these companies, time is money, and the longer it takes to build a mandated project, the more it will cost. Electric generators may not -- and should not -- undertake FGD and SCR retrofits until it is clear that such installations are required and are prudent and consistent with fiduciary obligations to undertake. Once the companies commit to such projects, however, they are highly motivated to complete them quickly in order to minimize costs. [EPA-HQ-OAR-2009-0491-2756.1, pp.51-52]
In summary, EPA has greatly underestimated the amount of time that it takes electric generating companies to design, permit, construct, and start up new FGD and SCR units. It will take longer than 30 months -- in many cases, considerably longer than 30 months -- for companies to complete the retrofits of FGD and SCR units at existing EGUs. Thus, it will not be possible for affected EGUs to achieve all the SO2 and NOx emission reductions that -- under the terms of the PTR -- must be achieved by EPA's proposed January 2012 and January 2014 deadlines. [EPA-HQ-OAR-2009-0491-2756.1, p.52]
In light of this, EPA either should decide not to call for the steep additional emission reductions demanded by the PTR -- because such reductions are not, for reasons discussed in these comments and in comments of individual UARG members, necessary to reduce significant regional contributions to downwind nonattainment and interference with maintenance -- or should extend the PTR's compliance schedule by at least a two-year period beyond the proposed 2014 compliance date (plus an additional interval of time that reflects (i) any additional time that EPA takes to complete this rulemaking beyond mid-2011 and (ii) the reasonable period of time needed by states to implement emission budgets through SIP revisions after final promulgation of EPA's rule). [EPA-HQ-OAR-2009-0491-2756.1, p.52]
EPA's Analysis Significantly Understates the Amount of Electric Generating Capacity that Would Have To Undergo FGD and SCR Retrofits in the 2012-2014 Period and the Associated Demands on Resources; Constraints on Labor Resources Make Compliance With the PTR's Timeline Impossible.
Marchetti, et al., evaluated the likely operational dates for new FGD and SCR projects during this period. They used owner-announced dates where available (as they were for a minority of the projects). For other projects, they used an assumed project-start date of the third quarter of 2011 to reflect EPA's projected date of final promulgation of the PTR, and then assigned implementation schedules for the retrofit installations, applying information derived from the Implementation Schedules Report, as discussed in the previous section of these comments. The analysis shows that the majority of the projects could not be completed until well after January 2014; the largest number of FGD and SCR projects are projected to become operational at various dates between early 2015 and mid-2016. [EPA-HQ-OAR-2009-0491-2756.1, p.54]
This analysis then examined a key resource constraint considered by EPA in the CAIR proceeding, i.e., the demand for boilermaker labor for retrofit installations. The analysis found that boilermaker demand for FGD and SCR installations can be accommodated if the realistic installation schedules applied from the Implementation Schedules Report are assumed. In contrast, if the retrofit projects were somehow otherwise able to be accomplished by 2014, as EPA assumes (a scenario that the Implementation Schedules Report shows is infeasible), then the resulting "logjam" of retrofit projects would require an amount of boilermaker hours that is far in excess of the boilermaker labor supply that was called on for EGU control retrofits in the 2008- 2010 period. Thus, even if EPA's proposed compliance schedule could otherwise be met (and it cannot), there is no basis for concluding that a sufficient supply of skilled labor would be available to do the work necessary to meet the schedule. [EPA-HQ-OAR-2009-0491-2756.1, p.54]
Accordingly, EPA should recognize that under the PTR, the 2012-2014 period could be expected to involve far more FGD and SCR retrofits than its statement in the PTR preamble would suggest. Given the demands that will be imposed on retrofit resources, such as boilermaker labor, due to the congestion of control project installations during this highly compressed period, requiring the PTR's 2014 emission budgets to be met by accelerating retrofit projects that cannot realistically be projected to be completed by that year would both (1) be inconsistent with documented installation schedules (as described in the Implementation Schedules Report and in the previous section of these comments) and (2) be infeasible in any event in light of the available labor, and perhaps other resources, needed to accomplish these retrofits. [EPA-HQ-OAR-2009-0491-2756.1, pp.54-55]
Footnote 15: Nothing in these comments should be construed as suggesting that a compliance date as early as 2015 is necessarily appropriate or could be justified.
Footnote 16: According to LADCO, a fundamental assumption for this state-by-state analysis was a July 2012 start date for the planning, engineering, and construction of any new NOx or SO2 controls, reflecting a January 2011 promulgation date for the final Transport Rule and another 18 months for adoption of SIPs. See id. at 1, attachment at 4. Thus, LADCO properly recognized that a substantial amount of time would be necessary after promulgation of EPA's final rule for states to develop SIPs and submit them to EPA for approval. [[These comments can also be found in Section VII.C.]]
Footnote 22: In presenting the schedule that affected source owners would face in making the additional emission reductions that the final Transport Rule will impose, EPA implies throughout the PTR preamble that the appropriate time for source owners to initiate work on any emission controls that are needed to meet the rule's requirements is when the Transport Rule is finalized. For example, at 75 Fed. Reg. at 45273/1, EPA makes "mid-2011 (when the Agency anticipates finalizing this rule)" the start of the time period in which source owners are to design and construct additional FGD and SCR systems at their plants. EPA is correct in taking this approach. It would be entirely inappropriate for EPA either to require affected source owners to initiate serious work on additional control systems, or to assume that source owners will voluntarily start such efforts, before the Transport Rule is final. Indeed, it would be imprudent for regulated sources, and inconsistent with fiduciary obligations for any affected electric generator, to start making in the near term any major investments in the design and construction of controls that may or may not be needed depending on the terms of the final Transport Rule and the terms of other emission control rules that are scheduled to be published by EPA in the near future and that could affect the control options faced by power plant owners. This is particularly so given the uncertainty as to the outcome of the present rulemaking that EPA has created by publishing the NODA and indicating that the emission budgets and allowance allocations in the final Transport Rule could be very different from those that EPA has proposed.
Virginia Department of Environmental Quality (VDEQ)
VDEQ staff has reviewed several spreadsheets and Technical Support Documents included in the proposed Transport Rule and the NODA, as well as the draft allocations of NOx and SO2 allowances under the preferred option in the rule. This review has highlighted a number of issues I would like to bring to your attention, a number of baseline premises that are obsolete or incorrect, and a number of Unit specific assumptions that should be updated. This information is provided so that EPA can use the best, most representative data and the most accurate future predictions for units in Virginia when modeling downwind impact and when calculating future year allocations. [EPA-HQ-OAR-2009-0491-2595.1, p.3]
VDEQ believes that no facility or unit should have modeled downwind contributions based on future year emissions that are in excess of federally enforceable limits on potential to emit. Modeling excessively high emissions rates may show downwind impacts where none actually occur, thereby inappropriately penalizing states and units by subjecting them to potential Section 126 petitions and additional controls. Accordingly, allocations should also reflect federally enforceable limits. Copies of relevant permits with such federally enforceable limits may be found on VDEQ~s website at http://www.deg.virginia.gov/air/permitting/Mirant.html and at http://www.deq.virginia.gov/info/vchecPermits.html. [EPA-HQ-OAR-2009-0491-2595.1, p.3]
Wabash Valley Power
Notwithstanding the specific errors previously noted, it would seem that the EPA modeling run does not account for the almost certain and substantial increase in operation of natural gas-fired combined cycle units. The myriad of EPA regulations will reduce the economic vitality of smaller and older coal units. With the retirement of these aging small coal units, demand will likely be met by increased utilization of gas-fired facilities. [EPA-HQ-OAR-2009-0491-2627.1,p.6]
we energies
We Energies review of the data inputs used by EPA has uncovered numerous errors, missing values, and other data issues with respect to EGUs that we operate. Unfortunately, the proposed rule has assigned nonattainment and maintenance contributions and made facility-specific allocations based on this erroneous data. EPA must perform a complete data review and use the correct data in its impact and allocation modeling. [EPA-HQ-OAR-2009-0491-2629.1, p.3]
Westar Energy, Inc.
EPA'S MODEL PRODUCES RESULTS THAT OVERSTATE KANSAS EMISSIONS LEVELS [EPA-HQ-OAR-2009-0491-2757.1, p.11]
Besides EPA overstepping its legal bounds by effectively subjecting Kansas to the requirements of the new rule prior to the time authorized by the CAA, the modeling on which the proposed rule relies over estimates the significant contribution and interference of maintenance in identified nonattainment areas that can be attributed to Kansas. See 75 FR at 45262 (24-hour PM2.5 list shows three Milwaukee, WI sites); at 45266 (24-hour PM2.5 list shows Muscatine, IA and Milwaukee, WI sites for maintenance); at 45269 (8-hour ozone shows Dallas, TX site for maintenance). The pre-NODA emission rates used as the basis for the modeling, although identifying NOx and SO2 controls that have been installed on Kansas EGUs, does not incorporate emissions levels that are already being achieved or that must be achieved by 2012 under enforceable permits and agreements. This failure leads to an overstatement of Kansas projected 2012 emissions levels used to identify States that are to be included in the rule. [EPA-HQ-OAR-2009-0491-2757.1, pp.11-12]
When the appropriate EGU emissions level adjustments are made, as shown in the attached Trinity Consultants Report ('Trinity Report') [See p.28 of this comment summary for the Trinity Report], the most significant change relates to the supposed linkage between Kansas' downwind emissions and a nonattainment site in Dallas.3 After the appropriate adjustments are made, downwind modeling at the Dallas site shifts from being above to falling below the 'single 'bright line' threshold for ozone that is one percent of the 1997 8-hour ozone standard of 0.08 ppm,' making the threshold 'a value of 0.8 ppb.' 75 FRat 45237/3. Consequently, the properly adjusted modeling no longer supports a finding that Kansas emissions meet the threshold for contributing to interference with maintenance at the Dallas site. As this is the only site to which Kansas is linked for 8-hour ozone maintenance, 75 FR at 45269, it follows that Kansas should be removed from the list of States subject to the proposed 8-hour ozone rule. [EPA-HQ-OAR-2009-0491-2757.1, p.12]
[See EPA-HQ-OAR-2009-0491-2757.1, pp.11-14 for additional comments pertaining to EPA'S MODEL PRODUCES RESULTS THAT OVERSTATE KANSAS EMISSIONS LEVELS]
Besides EPA overstepping its legal bounds by effectively subjecting Kansas to the requirements of the new rule prior to the time authorized by the CAA, the modeling on which the proposed rule relies overestimates the significant contribution and interference of maintenance in identified nonattainment areas that can be attributed to Kansas. See 75 FR at 45262 (24-hour PM2.s lists shows three Milwaukee, WI sites); at 45266 (24-hour PM2.5 lists shows Muscatine, IA and Milwaukee, WI sites for maintenance); at 45269 (8-hour ozone shows Dallas, TX site for maintenance). The pre-NODA modeling used for those projections, although identifying NOx and S02 controls that have been installed on certain Kansas EGUs, does not incorporate emissions levels that are already being achieved or that must be achieved under enforceable permits and agreements by 2012 and 2014. [EPA-HQ-OAR-2009-0491-2757.1, p.23]
This failure leads to an overstatement of projected Kansas' emissions levels, and thus its significant contribution and interference with maintenance, in the above-identified downwind nonattainment sites. When the appropriate EGU emissions level adjustments are made, as shown in the attached Trinity Consultants Report ('Trinity Report') [See p. 28 of this comment summary for the Trinity Report], Kansas' downwind emissions at the identified sites fall below the minimum levels necessary to support a finding that Kansas emission constitute significant contribution and interference with maintenance at the sites. It follows that Kansas should be removed from the list of States subject to the proposed rule. As explained more fully in the Trinity Report, the affected Kansas EGUs include Westar's Jeffrey Energy Center, Units 1-3 and Kansas City Power & Light's LaCygne Unit 1. EPA's pre-NODA modeling identifies both S02 and NOx controls installed on these EGUs, but does not include the actual emissions levels that are currently being achieved or expected to be achieved by these controls by 2012. [EPA-HQ-OAR-2009-0491-2757.1, p.24]
EPA'S DATA SUPPLEMENT DOES NOT REFLECT IMPORTANT REDUCTIONS IN EMISSIONS IN KANSAS AND DOES NOT ACCURATELY INCORPORATE THE LATEST SCIENTIFIC KNOWLEDGE [EPA-HQ-OAR-2009-0491-3737.1_NODA, p.2]
Westar and other significant emission sources in Kansas are subject to recently executed federally enforceable requirements for emissions reductions which require substantial reductions in both NOx and SO2 in the timeframe addressed by the Rule. EPA should have included this information in formulating the predictions about future emission levels on which its decision-making is made, but has not. For example, Westar's Jeffrey Energy Center Units 1 - 3, are subject to a Consent Decree with EPA, effective March 26, 2010 ('Consent Decree'), which requires a thirty-day rolling average unit emission rate for NOx of no greater than 0.180 lb/mmBtu, beginning December 31, 2011. This rate will apply continuously throughout each year. EPA's initial IPM computer analysis and 2009 CAMD rates should be adjusted to reflect emission reductions resulting from these controls. EPA's IPM computer runs and 2009 CAMD rates for Units 1 and 2 should be adjusted to reflect the emission limits required by 2012. EPA should also note that the 2009 rates for Units 1 and 2 do not yet reflect the limits on these units that will be required by 2012. [EPA-HQ-OAR-2009-0491-3737.1_NODA, p.2]
These federally enforceable emission reductions have been recognized by the Kansas Department of Health and Environment (KDHE). As shown in KDHE's letter of September 29, 2010, to the Honorable Lisa Jackson, Administrator, EPA, these federally enforceable requirements will result in emissions of NOx and SO2 by Westar that are significantly less than EPA's projections. KDHE notes and Westar agrees that EPA's 2012 IPM estimates do not accurately reflect control equipment installed or to be installed on Westar's units as required under the Consent Decree. As a result, Westar's future emissions are overstated by EPA and should be reevaluated and calibrated to match real world emissions prior to issuance of any final rulemaking. [EPA-HQ-OAR-2009-0491-3737.1_NODA, pp.2-3]
As noted, the Consent Decree provides a limit of 0.180 lb/mmBtu for NOx, for all three units. The units are similar to each other in design, construction and physical characteristics, and will have similar emission control systems, as already installed or as required by the schedule under the Consent Decree. Emission control systems have recently been installed on Units 1 and 3. As KDHE has suggested, Unit 2 should not be modeled higher than the Consent Decree limit of 0.180 lb/mmBtu. [EPA-HQ-OAR-2009-0491-3737.1_NODA, p.3]
For SO2, the Consent Decree requires all three Jeffrey Units to be limited to 6,600 tons total SO2 on a rolling twelve month basis. The Consent Decree also limits the units to 0.070 lb/mmBtu SO2. New scrubbers have been installed on all three Jeffrey units and all three units are operating with scrubbers. [EPA-HQ-OAR-2009-0491-3737.1_NODA, p.3]
In addition, KDHE has correctly pointed out that Kansas City Power & Light Company's La Cygne Unit 1 operates at an annual NOx rate of 0.11 lb/mmBtu. This level is based upon two years of actual operations with a selective catalytic reduction control system (SCR) in operation. Westar notes the recommendation of KDHE for the purposes of modeling that the 2009 average NOx rate of 0.11 lb/mmBtu be used in conjunction with projected 2012 IPM heat input to estimate emissions from La Cygne Unit 1 in 2012. [EPA-HQ-OAR-2009-0491-3737.1_NODA, p.3]
ANY FINAL DETERMINATION BY EPA OF THE INCLUSION OF KANSAS AS A CLEAN AIR TRANSPORT RULE STATE SHOULD BE BASED ON THE LATEST SCIENTIFIC INFORMATION [EPA-HQ-OAR-2009-0491-3737.1_NODA, p.3]
In setting rules, EPA is obliged to rely on the latest available data. See 42 U.S.C. Sec. 7408(a)(2). NAAQS must 'accurately reflect the latest scientific knowledge.' Information submitted in Westar's comments on the Clean Air Transport Rule ('CATR') already demonstrates that Kansas should not be included as a CATR state. EPA has proposed to include Kansas, based upon EPA's predicted impact of emissions from Kansas on ozone at monitors in Dallas, Texas. Westar's October 1 submittal to EPA included the Trinity Consultants' 'Clean Air Transport Rule: Review of EPA's CAMx Modeling That Is The Basis for Kansas Inclusion,' ('Trinity Report. ') The Trinity Report is based on revised emission projections, including federally enforceable reductions in NOx and SO2 at Westar's Jeffrey Energy Center and other Kansas generating sites, thus recognizing Westar's Consent Decree and other federally enforceable requirements. These corrected data inputs were incorporated into CAMx, and were included in a full repeat of EPA's modeling analysis by Trinity. [EPA-HQ-OAR-2009-0491-3737.1_NODA, pp.3-4]
After those adjustments were made, Trinity concluded that Kansas does not make a significant contribution to ozone concentration at Dallas, Texas, as projected by EPA, and Kansas should not be included in the Transport Rule for ozone season NOx allocations. Similar information has been provided to EPA by Westar, KDHE and other interested parties, and is available for EPA in its final decision on whether Kansas should be included in the Transport Rule as a contributor to ozone in Dallas. Failure of EPA to rely upon the best available scientific information would be inconsistent with its obligations under the Clean Air Act and constitute arbitrary and capricious action. Further, the reductions of NOx and SO2 through the Westar Consent Decree and the other federally enforceable requirements on emission sources in Kansas as noted by Westar and KDHE will also reduce Kansas' predicted contribution to PM2.5 in areas including Muscatine, Iowa and Milwaukee, Wisconsin. These reductions in emissions from Kansas are significant and should be taken into account in any final decision by EPA. [EPA-HQ-OAR-2009-0491-3737.1_NODA, p.4]
FAILURE TO REVIEW AND REVISE EPA'S MODEL WILL RESULT IN UNREASONABLE RELIANCE UPON A LIMITED MODELING TOOL [EPA-HQ-OAR-2009-0491-3737.1_NODA, p.5]
EPA has relied upon CAMx, which knowledgeable experts recognize as having limited reliability at ranges beyond 200 kilometers. (See Westar submittal, October 1,2010) In addition to the limited reliability of CAMx, as KDHE noted, EPA's IPM assessment tool assumes a linear relationship between the NOx emission reductions in Kansas, and, the state's contribution to downwind ozone levels. This approach is flawed and unreliable because ozone formation is a non-linear process, and any reliable modeling would need to take into consideration photochemical modeling and non-linear variables. EPA described its rationale for the use of CAMx as its selected modeling tool in the August 2, 2010, proposal, 75 C.F.R. 45238-9, but has not addressed the limitations of CAMx and IPM as stated on the record by KDHE, Westar and others. As KDHE has stated, the approach EPA uses to assess the effect NOx reductions will have on downwind ozone is 'fundamentally flawed.' Similar concerns apply to SO2 assessments by EPA. These concerns need to be addressed in any final action by EPA. [EPA-HQ-OAR-2009-0491-3737.1_NODA, p.5]
As suggested by KDHE, Westar supports use of the modeling done by EPA through CAMx and the IPM as a tool to inform more sophisticated analysis taking into account varying responses to emission changes based on source receptor proximity, sources of emission reductions and additional factors, prior to any final determination, not as the final predictors of what those levels would be. [EPA-HQ-OAR-2009-0491-3737.1_NODA, p.5]

3 The text of the Trinity Report is attached [See p.28 of this comment summary for the Trinity Report]. In addition, detailed analysis and computer files of the Trinity Report was submitted to the docket by Trinity Consultants through its overnight letter and enclosed DVD, dated September 30, 2010. The DVD contains approximately 150mb of information. Trinity has been advised by EPA that this size is too large to be accepted by the electronic docket filing system, so the DVD has been submitted by overnight delivery addressed to the docket, per EPA's directions. The entire Trinity Report is adopted and made part of this submittal. As explained in Sec. II, above, EPA did not allow adequate time for review of EPA's modeling data and inputs. Trinity has made a good faith effort to analyze EPA's modeling analysis supporting of the Rule, but has not had sufficient time to complete its full data verification analysis following EPA's production of additional data to correct corrupt or otherwise unusable files, and has not completed its full data verification analysis.
Wisconsin Power and Light Company
EPA's approach for S02 of using the lower of actual emissions versus projected emissions for 2012 allocations creates unrealistic results that could require construction of scrubbers by 2012. For example, WPL's fleet in Wisconsin would require a 50% reduction in S02 emissions in 2012 compared to 2009 actual emissions under EPA's proposed CATR. The IPM projections used to determine these allocations are illogical results that do not account for our company's requirement to supply reliable power service to our customers. For example, WPL operates two identical EGUs at the Columbia Energy Center (ORIS 8023). The IPM results would have the Columbia Unit I running at significantly lower utilization (less than half) as compared to Columbia Unit 2. Yet these are both base load units in WPL's fleet that have historically and will continue operate at capacity in order to supply reliable power to our customers. Similarly, the model indicates that Edgewater Unit 3 (ORIS 4050) would not operate and does not assign it any S02 allowances, which is contradictory to historical information that clearly demonstrates this unit does routinely run. [EPA-HQ-OAR-2009-0491-2844.1 p.5]
Xcel Energy Inc.
2. Xcel Energy is concerned that the computer simulation modeling analysis underpinning the CATR creates a number of risks that are not addressed in the proposal.
Xcel Energy has a number of concerns about the modeling analysis. First, the modeling system used is new, untested, and updated in many critical areas including emission control inputs, natural gas markets, demand and price-demand response parameters, and energy efficiency assumptions. EPA should provide the proposed unit allocations and other modeling output from this new modeling system for public review and comment prior to finalization of the CATR. Second, the combination of very low electric demand growth and low natural gas prices results in a baseline forecast of very slow growth in air emissions. This low baseline emission growth makes air regulations appear to be more cost-effective than they would be in a higher baseline emissions scenario. EPA should account for this risk and consider modeling scenarios in which both electric demand and natural gas prices are higher; because this combination of critical factors is historically unprecedented, more detailed comparative analysis and risk assessment should be provided. Third, natural gas units appear to dispatch at unrealistically low levels in the model. This should be investigated and either justified or corrected. Finally, coal unit retirements appear to be very low in EPA's modeling and this also warrants further analysis given the critical role of coal generation for economic and reliable electric supply in several regions of the nation. [EPA-HQ-OAR-2009-0491-2728.1, pp.8-9]
Response: 
Many of the above comments are centered around concerns with EPA's modeling, and the subsequent use of that modeling to determine state budgets and unit level allocations.  EPA took significant action to respond to these concerns in its final Transport Rule. 
First, EPA changed its allocation methodology to be based on historic heat input and emissions data that is generally reported by the sources' DR who testifies to its accuracy and completeness.  This was done in response to comments that expressed concern/disagreement about the IPM unit level projected emissions on which the proposed allocations were based.  By switching to a historic data based methodology, the degree to which any discrepancy between a unit's actual future operation and its projected future operation would impact the unit's allocation is greatly diminished.  EPA recognizes that IPM is a dynamic linear programming model that generates optimal decisions under the assumptions of perfect foresight and results in a least cost method of meeting demand.  However, invariably, there will be discrepancies between IPM unit level projections and a unit's actual future operations due to non-economic or other variables that IPM does not capture.  At the state and regional level, the discrepancies are small and random and thus do not result in biases.  However, their impact at the unit level may be significant and this was one of the drivers behind switching to an allocation method based on historic data. For more information on the allocation method, see Preamble Section VII D.
Second, EPA reviewed the comments and has made significant updates to its IPM v.3.02 modeling used at proposal.  These updates include changes to both the more general IPM assumptions (e.g., gas price assumptions) and specific unit level assumptions (e.g., that current retrofit status at a unit).  These updates were made to the IPM model, and the updated version (EPA IPM v.4.10) was used for all the final rule analysis.  In regards to unit specific adjustments, EPA did not manually adjust projected unit level modeling outputs, but it did make unit level updated to its NEEDS database used as a model input that impacted the unit level model outputs.   Some of the most frequent general IPM comments noted above that were addressed in the updates are: FGD removal efficiency was adjusted for new retrofits, and for existing retrofits it was indexed to historic performance at the unit.  Additionally, many of the above comments were focused on a sources ability to switch coals.  EPA modified its modeling to better reflect the cost and feasibility of switching and blending coals.  State Rule and consent decrees were updated according to comments.  Additionally, there were more than 1000 unit specific modeling changes made in response to corrections provided by the commenter.  For more detailed discussion of EPA IPM v.4.10 assumptions and assumption updates, see the EPA IPM v.4.10 documentation and the "Transport Rule IPM Assumptions Response to Comments" in the Appendix
These two adjustments, updates to the modeling and updates to the allocation methodology, work in concert to comprehensively address many of the concerns expressed by commenters on their unit level projections and allocations.
In regards to state budgets, many commenters objected to the use of model projections to determine unit level allocations noting that it may not account for certain non-economic factors that influence and Independent Service Operator (ISO) to call upon specific unit.  They noted this could result in IPM projecting unrealistic scenarios for particular units because it does not reflect these non-economic factors.  EPA's change to the final TR allocation methodology noted above and in section VII.D of the TR preamble addresses this concern.  Some commenters proceeded to note that while modeling projections were note reasonable for use of unit level allocations, they are reasonable to use for state and/or regional budgets.  Other commenters noted that model projections should not be used for state budgets for the same reason that they are inappropriate for unit level allocations.  Those supporting the use of model projections for determining state level budgets noted that discrepancies at the unit level are typically mitigated at the state level when the unit level data is aggregated.
EPA does use IPM projections to determine state level budgets.  As described in section VI of the preamble, state budgets are set equal to the projected state level emissions once significant contribution has been eliminated.  EPA believes that it is reasonable to use IPM for determining state budgets.  While there is significant potential variation at the unit level which commenters highlighted and served as part of EPA's rationale for finalizing a different allocation methodology, this variation is diminished and/or eliminated as unit level data is aggregated to get the state totals.  That is, potential variation between projected results and observed results is reduced as data is aggregated.  The well documented law of large numbers theorem indicates that the average results from a trial or sample will more closely approximate the actual value as the number of trials or samples increases.  While the unit level projection constitutes a sample or trial of just 1, the average # of modeled units within a Transport Rule state is approximately 370.  Because of the large number of units (e.g., samples) that comprise the state level total, the average variation at the state level is significantly less than it is at the unit level. 
In the final Transport Rule, EPA does not use historic emissions data to set the Transport Rule state budgets, but instead relies on projected emissions data under the marginal cost thresholds selected to define significant contribution and interference with maintenance.  EPA uses the same budget-setting methodology in the final rule on all pollutants analyzed (including ozone-season NOx, annual NOx, and SO2).  EPA believes this budget-setting methodology is more clear and easier to understand in connection with the Agency's modeling projections.  EPA believes the state budgets set under the final Transport Rule are an accurate reflection of its modeling of the removal of emissions identified as significant contribution and interference with maintenance from the states controlled.  For a discussion of this method and its results, please refer to section VI of the preamble for the final Transport Rule as well as the Significant Contribution and State Emissions Budgets Final Rule Technical Support Document.
In regards to the timing of the compliance deadlines, EPA chose the 2012 and 2014 dates to coordinate with the NAAQS attainment deadlines and to assure that reductions are made as expeditiously as practicable.  The Preamble discusses how the compliance deadlines address the Court's concern about timing.  See more in Section VII.C for more discussion on compliance deadline.
Many commenters expressed concern regarding unit level compliance and making the operating or investment decisions suggested in EPA's modeling projections.  EPA's adjustment to the final allocation methodology to delink unit level allocations from model projections largely address this concern.  Additionally, EPA notes that the Transport Rule does not impose unit level compliance strategies.  While IPM may project a particular least cost compliance strategy, sources have the flexibility to comply with the state budgets through a variety of mechanisms (e.g., control installation, fuel switching, efficiency improvements, dispatch changes, allowance purchase, etc.)
Organization: Vectren Corporation 
Louisiana Chemical Association (LCA)
Kansas City Board of Public Utilities (BPU)
Kansas Department of Health and Environment
Louisiana Energy and Power Authority (LEPA)
Cogen Technologies Linden Venture, LP
Kansas City Power and Light Company (KCP&L)
Gainesville Regional Utilities (GRU)
Exxon Mobil Corporation
Comment: 
Cogen Technologies Linden Venture, LP
II. DISCUSSION    
Linden Cogen is a combined-cycle plant consisting of six (6) natural gas-fired combustion turbines and three (3) steam turbines. It provides 645 MW of capacity to Consolidated Edison ('ConEd') pursuant to a power purchase agreement. It also provides 169 MW of electricity and 1.09 million lbs per hour of steam to ConocoPhillips' Bayway Refinery, which is the largest refinery operated on the East Coast. Linden Cogen's operation is governed by long-term contracts, which have historically resulted in its dispatch as a baseload plant. [EPA-HQ-OAR-2009-0491-2712.1, p.5]    
Linden Cogen objects to EPA's proposed allocations of annual and ozone season NOx for Linden Cogen because the proposed allocations are wholly inconsistent with the facility's historic dispatch and fail to account for the fact that the facility is operated pursuant to long-term power sales and steam sales agreements. These erroneous projections are also due to several errors in the data set relied upon by IPM, as described below. Linden Cogen does not believe EPA can rely upon IPM's projected dispatch and emissions as the basis for any allocations in New Jersey, unless EPA makes changes to IPM so that it accurately predicts the operation of contracted facilities such as Linden Cogen. EPA also must correct the inputs for Linden Cogen's heat rate, FOM costs, VOM costs and fuel costs before re-running the model. If EPA cannot make these corrections to IPM, Linden Cogen believes NOx allocations in New Jersey should instead be based on historical data, as augmented by assumptions concerning operation of existing and planned controls, but using a more representative baseline than just one year's data. [EPA-HQ-OAR-2009-0491-2712.1, p.5]    
A. EPA Has Proposed to Allocate Allowances to Linden Cogen Representing Only a Fraction of Its Historic Capacity    
EPA's proposed NOx allocations for Linden Cogen would provide allowances for only a small fraction of the plant's historic operating capacity. A comparison of EPA's proposed allocations and Linden Cogen's historic actual emissions is shown in the following Table 1. [EPA-HQ-OAR-2009-0491-2712.1, p.5]    
[Table 1 can be found on page 6 of this comment. This table includes footnotes 1, 2, and 3.]    
As indicated by Table 1, EPA's proposed allocations for annual and ozone season NOx would respectively represent approximately only 10% and 19% of historic emissions, as reported during the four most recent calendar quarters. These proposed allocations would also represent only a fraction of the allocations made for Linden Cogen by the New Jersey Department of Environmental Protection ('NJDEP') under the CAIR, as also shown by Table 1 above. Furthermore, in comparison to average historic emissions over the past seven calendar years, as shown by Tables 3 and 4 below, EPA's proposed allocations amount to approximately only 9% and 16% of historic annual and ozone season NOx emissions, respectively. [EPA-HQ-OAR-2009-0491-2712.1, p.6]    
As illustrated by Tables 2 and 3, annual and ozone season NOx emissions were substantially lower in 2009 than the historic average due to lower dispatch levels caused by the recession. In the Technical Support Document, 'State Budgets, Unit Allocations, and Unit Emissions Rates,' EPA expressly acknowledged the impacts of the recession on 2009 dispatch and emissions levels and adjusted reported NOx emissions to account for these impacts.- As described below in Section U.K, EPA should not base allocations on data for only one year, but should instead base allocations on a representative baseline established over a longer period of time. Basing allocations on a long-term average would assure that allocations are based on the most representative data concerning historic emissions and not impacted drastically by circumstances that may have resulted in lower than average dispatch during 2008 or 2009, when facilities may not have been operated at typical levels due to the recession or extended outages related to the installation of controls needed to comply with the CAIR. [EPA-HQ-OAR-2009-0491-2712.1, pp.7-8]    
[Tables 2 and 3 can be found on page 7 of this comment.]    
EPA's proposed allocations - 41 tons of annual NOx and 30 tons of ozone season NOx - would only provide enough allowances for operation of one of Linden Cogen's six combustion turbines consistent with Linden Cogen's historic operating rates. This gross discrepancy between Linden Cogen's historic NOx emissions and EPA's proposed NOx allocations in the Proposed Transport Rule is based on EPA's projected utilization of Linden Cogen at significantly lower rates than has historically been the case. According to the results of EPA's IPM, annual and ozone season heat input for Linden Cogen are expected to be significantly lower than the historic heat input values for the four most recent calendar quarters and ozone season, as shown by Table 4 below: EPA's projections amount to only 12.88% of historic annual heat input and only 21.57% of historic ozone season heat input. Further, if a more representative baseline than 2009 data were used instead, EPA's IPM projections would amount to an even smaller fraction of historic heat input. [EPA-HQ-OAR-2009-0491-2712.1, p.8]    
[Table 4 can be found on page 8 of this comment. This table includes footnotes 5 and 6.]    
In sum, IPM has projected that Linden Cogen will operate at only a fraction of its historic operating capacity, which has been greater than 68% on average over the past three calendar years for each of Linden Cogen's six combustion turbines, as illustrated by Table 5 below. In essence, IPM has erroneously predicted dispatch of Linden Cogen as a peaking plant, rather than a baseload generating station. [EPA-HQ-OAR-2009-0491-2712.1, p.8]    
[Table 5 can be found on page 9 of this comment.]    
B. IPM Wrongly Projects Dispatch of Linden Cogen at Only a Fraction of Its Historical Capacity Because It Arbitrarily Ignores the Impact That Long-Term Contracts Have on Dispatch    
IPM's projections of Linden Cogen's dispatch at levels so drastically below its historic operating levels wholly fail to account for the fact that Linden Cogen is operated pursuant to long-term power sales and steam sales agreements, which practically assure that Linden Cogen's future dispatch will be consistent with historic dispatch levels while the contracts remain in effect. Further, the provisions governing dispatch of both Linden Cogen and other facilities subject to long-term contracts are often highly complex and prescribe very specific dispatch instructions. While ConEd controls the dispatch of Linden Cogen's Units 1 through 5, the terms of the power sales agreement require dispatch at certain minimum percentages of the baseline dispatch level and for certain minimum lengths of time. As an example, ConEd can dispatch Units 1 through 5 at 47% of the baseline dispatch level; but, if it does, ConEd is obligated to run Units 1 through 5 for at least 50 hours, with one exception per year. In modeling least-cost dispatch, IPM completely fails to capture the complexities of such long-term contractual obligations. [EPA-HQ-OAR-2009-0491-2712.1, p.9]    
Because EPA has failed to account for the existence of long-term contracts within IPM and the specific dispatch requirements prescribed by those contracts, its model results have no basis in reality. By using IPM's projections for dispatch as the basis for NOx allocations in New Jersey, EPA's proposed allocations would run afoul of the principles articulated by the D.C. Circuit in the two prior instances when it rejected EPA's reliance upon projections of future utilization generated by IPM, which were unsupported by 'the best information available to the Agency' and 'flatly inconsistent' with 'real world observations' concerning future demand and dispatch. See Appalachian Power 1,249 F.3d at 1053-54 (remanding 'EPA's use of growth rates generated by IPM for 2001-2010 to estimate facility utilization growth for the period of 1996-2007' in light of EPA's failure to address 'what appear to be stark disparities between its projections and real world observations'); see also Appalachian Power II, 251 F.3d at 1034-35 (remanding EPA's reliance without explanation upon 'IPM to generate growth assumptions for 1996-2001, as well as to generate state-by-state EGU utilization estimates for 2007', 'that generated seemingly implausible results'). [EPA-HQ-OAR-2009-0491-2712.1, p.9]    
C. IPM Wrongly Projects Dispatch of Linden Cogen at Only a Fraction of Its Historical Capacity Because It Relies Upon an Erroneously High Heat Rate and Erroneously High Fixed and Variable Operating Costs and Fuel Costs    
Linden Cogen has examined EPA's IPM output files and the underlying assumptions to attempt to explain how the projected dispatch for Linden Cogen could depart so dramatically from historical and anticipated dispatch. Our examination has identified several errors in EPA's modeling inputs that appear to have resulted in IPM's projected dispatch of the facility at only a fraction of its historic capacity: [EPA-HQ-OAR-2009-0491-2712.1, p.10]    
:: The heat rate appearing within the NEEDS database for each of Linden Cogen's generating units is incorrect: It is reported in the NEEDS database as 9173 Btu/kWh, when, in fact, the average heat rate for the entire plant is approximately 7965 btu/kWh. A heat rate above 9000 Btu/kWh is not at all consistent with a highly efficient combined cycle natural gas-fired cogeneration plant, but is more typical of a simple-cycle unit. The inaccurate assignment of such a high heat rate to Linden Cogen in IPM appears to have resulted in dramatically reduced projections of the plant's future dispatch that in no way approximate the current operations of the facility. [EPA-HQ-OAR-2009-0491-2712.1, p.10]    
:: EPA appears to have incorrectly assigned fixed operating and maintenance ('FOM') costs to Linden Cogen's three steam turbines as though they were separately fired steam generating units and not part of a combined-cycle plant. At Linden Cogen's request, EPA provided the 'model plant' codes for each of Linden Cogen's generating units, as well as for a number of other facilities in New Jersey. This enabled Linden Cogen to compare the cost data assigned to the various model plants through reference to the IPM output files. For six of Linden Cogen's generating units (presumably its six combustion turbines), the IPM output files, 'TR_SB_Limited_Trading.tac', indicate that EPA has applied the correct FOM cost assumption of $12.6 per kilowatt hour-generated per year ('$/kW/yr') for combined cycle gas/oil plants. See Table 6 attached as Attachment 1; see also Documentation for EPA Base Case v.4.10, 4-11, Table 49. However, for three of its generating units - presumably its three steam turbines, which have no separate fuel source and are not a source of emissions EPA has wrongly applied an assumption of FOM costs of 23.57 $/kW/yr. See Table 6. This incorrect assumption would appear to correlate with the assumed FOM costs for either an MSW/landfill gas plant, which are 23.6 $/kW/yr, or an 30-40 year-old oil & gas-fired steam turbine equipped with SCR, which are 23.2 $/kW/yr. See Documentation for EPA Base Case v.4.10, 4-11, Table 4-9. EPA cannot apply the assumed FOM costs for either an MSW/landfill gas plant or a 30-40 year-old oil & gas-fired steam turbine to any of Linden Cogen's units. [EPA-HQ-OAR-2009-0491-2712.1, p.10]    
[Table 6 can be found on page 25 as Attachment 1 of this comment.]    
:: Linden Cogen objects to the variable operating and maintenance costs ('VOM') assumed by EPA for the model plants associated with Linden Cogen's generating units. According to EPA's model output files, VOM costs for Linden Cogen are between 7.5 and 7.54 mill/kWh for each of its nine generating units. See Table 6 at Attachment 1. The range of VOM for combined cycle plants with SCR is, according to EPA, 2.75 to 7.79 mill/kWh. See Documentation for EPA Base Case v.4.10, 4-9, Table 4-8. In contrast, YOM costs for a similarly-sized gas-fired combined-cycle plant in New Jersey, AES Red Oak LLC, are between 2.75 and 3.02 mill/kWh. See Table 6. EPA has provided no explanation or support for why it has assigned significantly higher VOM costs to Linden Cogen than to a substantially similar facility located in the same state. Linden Cogen is aware of no explanation for this difference and believes it has no basis in fact. [EPA-HQ-OAR-2009-0491-2712.1, pp.10-11]    
:: Linden Cogen also objects to the fuel costs EPA has assumed for the model plants associated with Linden Cogen's generating units. According to EPA's model output files, fuel costs for Linden Cogen are between 47.9 and 66.46 mill/kWh. See Table 6. In contrast, for the model plant associated with AES Red Oak, LLC, fuel costs range between 32.55 and 44.09 mill/kWh. [d. Linden Cogen is unaware of any basis for assuming that its fuel costs are so much greater than for a similar combined cycle facility located in New Jersey. [EPA-HQ-OAR-2009-0491-2712.1, p.11]    
:: According to the model plant names assigned to Linden Cogen's units, all such units were modeled as serving the Legacy Mid-Atlantic Area Council - East ('MACE'), when, in fact, Linden Cogen Units I through 5 are fully contracted to ConEd to provide power to New York City ('NYC'). Thus, although Units I through 5 are physically located in New Jersey and were modeled as part of MACE, they serve NYC through dedicated transmission lines. While IPM is equipped to model certain inter-regional transmission capabilities, it would be plainly inconsistent with both the physical and contractual limitations governing dispatch of Linden Cogen to model delivery of power from Units 1 through 5 to NYC as an inter-regional transfer or to apply any 'Wheeling Charge' related to such delivery, as suggested by the Documentation for EPA Base Case v.4.10. 7 [EPA-HQ-OAR-2009-0491-2712.1, p.11]    
In light of our understanding of how IPM models which units will be dispatched given certain operating constraints and assumptions, we believe the foregoing errors have resulted in IPM's projected dispatch of Linden Cogen at only a small fraction of its historic generating capacity, a scenario that is belied by the facility's contractual obligations to provide steam and power to its steam host and power to the critical New York and PJM power markets. The net result of these errors is that the IPM projections EPA relied upon in establishing unit-by-unit allocations wrongly conclude that Linden Cogen will only operate at a small percentage of its actual capacity and with a fraction of its actual NOx emissions. These projections are erroneous and cannot establish the basis for unit allocations. [EPA-HQ-OAR-2009-0491-2712.1, p.11]    
The D.C. Circuit has twice previously thrown-out EPA's reliance upon IPM's projected future utilization rates, where IPM 'generated seemingly implausible results' and no attempt was made to explain 'what appear to be stark disparities between its projections and real world observations.' See Appalachian Power 1,249 F.3d at 1035; Appalachian Power II, 251 F.3d at 1054. While 'courts routinely defer to agency modeling of complex phenomena, model assumptions must have a 'rational relationship' to the real world.' Appalachian Power I, 249 F.3d at 1053 (citing Chemical Mfrs. Ass'n v. EPA 28 F.3d 1259, 1265 (D.C. Cir. 1994)). Accordingly, before relying upon IPM results as the basis for allocating allowances, EPA must assure that it has relied upon appropriate assumptions and must explain its reliance upon assumptions that appear to have no basis in fact. [EPA-HQ-OAR-2009-0491-2712.1, pp.11-12] 
E. EPA Should Not Rely Upon IPM Projections to Establish Unit-by-Unit Allocations When It Has Rejected Those Projections as Less Reliable Than Actual Data in Setting Statewide Budgets    
For those states in which the IPM projection of total statewide emissions in 2012 was lower than actual emissions in 2009, EPA relied upon the unit-specific IPM projections as the basis for the proposed unit allocations, even though it rejected those projections in setting the statewide budgets in favor of more accurate historic emissions data, as augmented by assumptions about the operation of existing and planned emissions controls. It is simply illogical to make unit-specific allocations based on the IPM, when that model has been demonstrated to generate wildly inaccurate projections. This is doubly true when EPA has itself acknowledged that the model does a relatively poor job of making unit-level projections, concluding that using ''the actual performance units achieved in 2009 is more representative of expected emissions than what EPA modeled using IPM.' Proposed Transport Rule, 75 Fed. Reg. at 45290 (emphasis added). Accordingly, basing the unit allocations on IPM results would represent an arbitrary decision. [EPA-HQ-OAR-2009-0491-2712.1, p.14]    
1. Although New Jersey NOx Allocations Were Based on IPM Projections, the Corresponding Budgets Were Based on Historic Data, Augmented by Assumptions about Operation of Existing and Planned Controls    
In setting the unit allocations, 'EPA proposes that, for 2012, each existing unit in a given state receives allowances commensurate with the unit's emissions reflected in whichever total emissions amount is lower for the state, 2009 emissions or 2012 base case emissions projections.' 75 Fed. Reg. at 45309. However, in setting the 2012 802 budgets, EPA did not rely upon IPM projections (as it did in establishing the 2014 budgets for the group 1 states), but 'took a different approach', as explained by the preamble to the Proposed Transport Rule: [EPA-HQ-OAR-2009-0491-2712.1, p.14]    
These states are only required to make 802 reductions that could be made through (1) the operation of existing scrubbers, (2) scrubbers that are expected to be built in 2012 and (3) the use of low sulfur coal. Because those strategies were already being applied in most states covered by this rule in 2009, EPA believes that the actual performance units achieved in 2009 is more representative of expected emissions than what EPA modeled using IPM. This is because real data takes into account actual unit by unit information that is represented at a more aggregate level in IPM.    
75 Fed. Reg. at 45290 (emphasis added). [EPA-HQ-OAR-2009-0491-2712.1, p.14]    
Additionally, in setting the annual and ozone season NOx budgets for all states, 'EPA used the same general methodology for all states that was used for the group 2 states for SO2.' Id. As EPA explained in the preamble to the Proposed Transport Rule, 'EPA believes that instead of defining the budgets based on IPM projections of what will happen when SCR units are turned on, it is better to use real data, therefore EPA has developed budgets based on a combination of historical heat input, historical emissions rates, and, where new SCR units are expected between now and 2012, projected emissions rates for those new SCR units.' 75 Fed. Reg. at 45291 (emphasis added). 13 [EPA-HQ-OAR-2009-0491-2712.1, p.15]    
Thus, for all but the 2014 SO2 reductions required of group 1 SO2 states, EPA based the state budgets on actual reported data, augmented by expectations about how existing and planned controls will be dispatched, rather than IPM projections. Similarly, for both annual and ozone season NOx budgets, EPA relied upon historic data, along with certain assumptions about how existing and planned controls will be dispatched, rather than IPM projections. [EPA-HQ-OAR-2009-0491-2712.1, p.15]    
2. IPM's Projections for Dispatch in New Jersey Are Wildly Inaccurate Linden Cogen believes that reliance upon IPM projections as the basis for allocations within a state, when EPA has disregarded those projections as the basis for setting the overall state budget, represents a poor policy choice that is susceptible to production of arbitrary and inconsistent results. While discrepancies in the data set might not be expected to impact the overall model results on a statewide basis, such errors can lead to grossly aberrant outcomes at the unit level. As illustrated by Table 7 (attached as Attachment 2), IPM has yielded wildly inaccurate results in predicting the future dispatch of combined-cycle facilities in New Jersey, in comparison to their historic reported dispatch (heat input) levels. [EPA-HQ-OAR-2009-0491-2712.1, p.15]    
[Table 7 can be found on page 26 as Attachment 2 of this comment.]    
:: For Linden Cogen's six combustion turbines, which are all already operated with SCR controls, IPM projections for annual heat input ranged from only 8.6% to 33.71% of reported heat input during the most recent four calendar quarters. Similarly, for the ozone season, IPM's projections for the six combustion turbines ranged from 14.43% to 54.57% of reported fuel usage in the 2009 ozone season. [EPA-HQ-OAR-2009-0491-2712.1, p.15]    
:: Even greater deviations from historic fuel usage can be observed in the IPM results for other combined cycle facilities in New Jersey: For the Bergen Generating Station, IPM has predicted dispatch of its turbines at heat inputs representing as little as 3.59% of historic capacity. At the other extreme, for the PSEG Linden Generating Station, IPM has predicted dispatch of one of the generating units at 5,144.06% of its historic annual heat input and 11,367.89% of its ozone season heat input. [EPA-HQ-OAR-2009-0491-2712.1, pp.15-16]    
Given these aberrant results, it is easy to understand why EPA jettisoned IPM projections as the basis for the 2012 SO2 budgets and all NOx budgets because, as EPA stated in the preamble to the Proposed Transport Rule, 'EPA believes that the actual performance units achieved in 2009 is more representative of expected emissions than what EPA modeled using IPM.' 75 Fed. Reg. at 45290. 'This is because real data takes into account actual unit by unit information that is represented at a more aggregate level in IPM.' Id. [EPA-HQ-OAR-2009-0491-2712.1, p.16]    
3. EPA Cannot Rely Upon a Model Known to Generate Arbitrary and Inaccurate Results When More Reliable Data Is Available    
For EPA to acknowledge that IPM is not as reliable as actual data at predicting how units will be dispatched, but then rely upon IPM's projected results as the basis for unit-specific allocations would reflect a poor policy choice that is both arbitrary and capricious. In the case of Linden Cogen, it would result in a significantly lower allocation than similar facilities in New Jersey. [EPA-HQ-OAR-2009-0491-2712.1, p.16]    
The D.C. Circuit has made clear that while 'courts routinely defer to agency modeling of complex phenomena, model assumptions must have a 'rational relationship' to the real world.' Appalachian Power L 249 F.3d at 1053-55 (citing Chemical Mfrs. Ass'n v. EPA, 28 F.3d 1259, 1265 (D.C. Cir. 1994). Certainly, '[m]odels need not fit every application perfectly.' Columbia Falls Aluminum Co. v. EPA, 139 F.3d 914, 923 (D.C. Cir 1998). However, EPA cannot rely upon an application of IPM 'that generates apparently arbitrary results'. See Appalachian Power 11,251 F.3d at 1035. This error is only 'compounded by the fact that more representative ... estimates [are] available.' Id., at 1034. [EPA-HQ-OAR-2009-0491-2712.1, p.16]    
Here, EPA concedes in setting the statewide budgets that IPM is not as representative as the actual historical performance data (except in the case of the 2014 SO2 budgets for group 1 states). If actual performance data are more accurate and representative at the statewide level, they certainly should be deemed more accurate and representative for predicting the dispatch and emissions of individual units. Indeed, the reason EPA jettisoned IPM's projections as the basis for setting state budgets, in favor of historic data augmented by such operating assumptions, is because 'real data takes into account actual unit by unit information that is [only] represented at a more aggregate level in IPM.' Proposed Transport Rule, 75 Fed. Reg. at 42390. [EPA-HQ-OAR-2009-0491-2712.1, p.16]    
This is not the first time that the IPM has produced nonsensical projections. In fact, the D.C. Circuit has previously remanded IPM projections of future utilization because they were 'flatly inconsistent' with actual operational data and implied negative growth in several states from 1998-2007. Appalachian Power 1, 249 F.3d at 1051. 'This, on its face, raises questions about the reliability of the EPA's projections.' Id. Without an explanation for 'why results that appear arbitrary on their face are, in fact, reasonable determinations', the court remanded that portion of the section 126 rulemaking to EPA. Id. at 1055. The 2000 'NOx SIP Call' also was remanded due to 'stark disparities between [IPM's] projections and real world observations' absent a full explanation from EPA. Appalachian Power II, 251 F.3d at 1035. There, the court could not 'excuse the EPA's reliance upon a methodology that generates apparently arbitrary results particularly where, as here, the agency has failed to justify its choice.' Id. [EPA-HQ-OAR-2009-0491-2712.1, pp.16-17]    
Here again, IPM's projections of future dispatch of facilities in New Jersey are flatly inconsistent with observed operational data from Linden Cogen. As discussed above, IPM has projected dispatch of Linden Cogen at only one-tenth of its historical capacity and nowhere near the levels at which Linden Cogen is contractually obligated to operate under its long-term contracts. As a consequence, under IPM's projections for future dispatch, a highly efficient combined cycle baseload cogeneration facility has been modeled to operate as infrequently as a simple-cycle peaking plant. While all modeling exercises involve some degree of imprecision, these results are entirely implausible and illustrative of the 'poor fit between the agency's model and [ ] reality' that has resulted in remand of prior EPA rulemakings. See Chemical Mfrs. Ass 'n v. EPA, 28 F.3d at 1265. The implausibility of these results makes clear that, while appropriate for predicting energy market behavior at a broader level and supporting policy-making decisions, EPA has simply no reasonable basis for using IPM to predict the behavior of and allocate allowances to individual units. [EPA-HQ-OAR-2009-0491-2712.1, p.17]    
Finally, EPA has provided no rationale for rejecting IPM projections as the basis for establishing statewide budgets (for all but the 2014 SO2 budgets for group 1 states), but then relying upon those same projections as the basis for unit-specific allocations. This apparent and unexplained contradiction alone would provide a basis for remand of the resulting rule. See New York v. EPA, 413 F.3d 3,35-36 (D.C. Cir. 2005) (remanding a rule in part because the EPA contradicted its own rationale in its responses to comments). Given the acknowledged limitations of IPM at predicting accurately how actual units will be dispatched, it would be wholly illogical for EPA to rely upon IPM projections as the basis for establishing unit allocations, when it specifically declined to adopt those projections as the basis for statewide budgets. [EPA-HQ-OAR-2009-0491-2712.1, p.17]  
G. Before Relying Upon IPM Projections For Allocation of Allowances, EPA Must Both Revise IPM to Accurately Project Dispatch of Contracted Facilities and Use the Correct Inputs for Linden Cogen  
Before EPA can rely upon IPM projections as the basis for NOx allocations in New Jersey, EPA must revise the model so that it accurately predicts the dispatch of facilities such as Linden Cogen that operate to supply power pursuant to long-term power sales agreements and are required to run to provide steam to a cogeneration host. Understanding that any modeling exercise involves some degree of simplification, EPA must endeavor to capture the often complex terms governing dispatch of facilities in long-term contracts, before it relies upon the model results as the basis for allocations of emissions allowances. If EPA cannot make adjustments to IPM so that it can incorporate and reflect these real-world assumptions governing dispatch and, as a consequence, provide a reliable prediction of contracted facilities' actual dispatch, then EPA cannot continue to rely upon the model results, but must resort instead to the historic dispatch data it has already deemed a better predictor of future dispatch than IPM's projections. [EPA-HQ-OAR-2009-0491-2712.1, pp.18-19]  
Linden Cogen's long-term contracts practically assure that it will be operated as frequently as demonstrated by historical operating data. If IPM cannot accommodate the numerous complex contractual terms governing dispatch of Linden Cogen's units, then EPA must at the very least establish some set of rules within IPM, which effectively 'force' the model to predict dispatch of Linden Cogen and other contracted facilities at heat input levels representative of historic operations. EPA also must incorporate Linden Cogen's correct plantwide heat rate into the model and reflect dispatch of Units 1 through 5 consistent with their service of the NYC region through dedicated transmission lines. Additionally, EPA must apply the correct FOM assumptions (12.6 $/kW/yr) for each of Linden Cogen's generating units. It also must apply VOM and fuel costs no greater than assumed for a similar facility located in New Jersey (AES Red Oak) (2.75 to 3.02 mill/kWh for VOM costs and 32.55 to 44.09 mill/kWh for fuel costs). [EPA-HQ-OAR-2009-0491-2712.1, p.19]  
As the court held in the section 126 litigation, '[w]hile courts routinely defer to agency modeling complex phenomena, model assumptions must have a 'rational relationship' to the real world.' Appalachian Power 1,249 F.3d 1032 (internal citations to Chemical Mfrs. Ass'n v EPA, 28 F.3d at 1265). Accordingly, EPA has an obligation to incorporate real-world expectations for contracted facilities into its model. Further, EPA cannot inflexibly apply its model when it has been demonstrated to have a 'poor fit' with reality. Chemical Mfrs. Ass'n v EPA, 28 F.3d at 1265. ('The more inflexibly the agency intends to apply the model, however, the more searchingly will the court review the agency's response when an affected party presents specific detailed evidence of a poor fit between the agency's model and that party's reality.') Finally, in the face of data and real world information demonstrating that the assumptions used by EPA are false and the results are simply implausible, EPA must provide sources the opportunity to correct those assumptions. See, e.g., Columbia Falls Aluminum Co. v. EPA, 139 F.3d 914, 923 (D.C. Cir 1998) (vacating and remanding a rule for reliance upon 'a test [the EPA] knew to be inaccurate.'). If the model cannot accommodate real-world assumptions, EPA must abandon the model. [EPA-HQ-OAR-2009-0491-2712.1, p.19]  
H. If EPA Cannot Revise IPM To Accurately Predict Dispatch of Facilities in New Jersey, EPA Should Apply the Same Methodology It Used to Establish New Jersey's Budget and Rely Upon Historical Data Instead of IPM's Projections  
If EPA cannot make appropriate change to IPM so that it would accurately predict the dispatch of facilities in New Jersey such as Linden Cogen, EPA should instead base NOx allocations in New Jersey on reported data. In setting state budgets (except for the 2014 802 budgets for group 1 states), EPA reportedly relied on reported data, as augmented by assumptions about operation of existing and planned emissions controls. See 75 Fed. Reg. at 45291. Thus, if IPM cannot be revised to produce reliable results for New Jersey or for contracted facilities such as Linden Cogen, EPA should adopt the same approach it used to develop the proposed state budgets and base the unit allocations on reported data, augmented by assumptions concerning the operation of emissions controls. This would make true EPA's statement in the preamble that its proposed allocation methodology 'allocat[es] down to the individual unit level using all of the same assumptions used in developing the proposed budgets.' 75 Fed. Reg. at 45311. For New Jersey, using those same assumptions would require that EPA not rely upon IPM projections for either the annual or ozone season NOx allocations, but instead base those allocations upon historic data, as augmented by assumptions about existing and planned controls. [EPA-HQ-OAR-2009-0491-2712.1, pp.19-20]  
I. Basing Allocations on Reported Data Rather Than Projected Dispatch Is Not At All Inconsistent With the Court's Decision in North Carolina v. EPA  
Basing unit allocations for New Jersey on historic data is not at all inconsistent with the principles articulated by the D.C. Circuit in North Carolina v. EPA, 531 F.3d 896 (DC Cir. 2008). Indeed, EPA has already proposed to base unit allocations on historic data for any state in which 2009 emissions were lower than IPM's projected 2012 emissions. Thus, assuming EPA cannot fix the errors in IPM that have resulted in wildly inaccurate projections of dispatch in New Jersey and for Linden Cogen in particular, EPA could adopt the same approach for allocating allowances that it says it adopted in setting statewide budgets: It could base each unit's allocation on historic data, which EPA has concluded are more representative of actual operations than IPM's projections. [EPA-HQ-OAR-2009-0491-2712.1, p.20]  
J. EPA Should Establish Allocations Based Upon a More Representative Period of Time Than One Year  
Assuming EPA cannot modify IPM to accurately predict dispatch of contracted facilities in New Jersey and should therefore decide to base NOx allocations for New Jersey on reported data, EPA should base emissions allocations for individual units, not upon data from only one year, but on a facility's average heat input over a longer period of time. Once each facility's representative baseline has been established, EPA should add together all facilities' baseline emissions, compare the resulting sum with the state budget and then reduce each facility's allocation by whatever percentage is needed for the total statewide emissions (plus the 3% set aside for new facilities) to fit within the budget. [EPA-HQ-OAR-2009-0491-2712.1, p.20]  
Using only one year's data as the baseline for allocations would unfairly prejudice facilities that might have experienced reduced dispatch in 2008 or 2009. In particular, it could penalize facilities that had lower emissions in 2008 or 2009 because they were down for an extended period of time to install controls in advance of CAIR. Furthermore, as EPA has acknowledged upon adjusting reported heat input and emissions rates to reflect unusually low utilization in 2009 15, 2009 data represented significantly lower utilization due to the global recession. As a consequence, 2009 data cannot be deemed representative and EPA should more equitably account for anomalously low utilization during the recession by using a longer-term average as the basis for establishing allocations. [EPA-HQ-OAR-2009-0491-2712.1, pp.20-21]  
III. CONCLUSION  
Linden Cogen objects to EPA's proposed NOx allocations for New Jersey because they are based upon projections of utilization generated by IPM, which have no basis in reality and fail to reflect Linden Cogen's long-term contractual obligations. Due to several other errors in the model inputs, IPM has erroneously modeled Linden Cogen as though it would only be dispatched as infrequently as a simple cycle peaking plant, although both historical data from Linden Cogen and its long-term contractual obligations clearly demonstrate that it is a baseload cogeneration facility. EPA's error in relying upon IPM projections as the basis for New Jersey NOx allocations is compounded by the fact that EPA rejected these projections as an appropriate basis for setting the statewide budgets, finding instead that actual historical data were more reliable than IPM's predicted dispatch patterns. [EPA-HQ-OAR-2009-0491-2712.1, p.23]  
Before relying upon IPM projections as the basis for allocating allowances, EPA must fix the model, so that it accurately predicts dispatch of facilities subject to long-term contractual obligations, such as Linden Cogen. EPA must also re-run the model to reflect the correct heat input and FOM, VOM and fuel costs for Linden Cogen. [EPA-HQ-OAR-2009-0491-2712.1, p.23]  
If EPA cannot revise IPM so that it provides a reasonable and accurate projection of facility dispatch in New Jersey, EPA should base NOx allocations in New Jersey on historical data, as augmented by assumptions about the operation of existing and planned emissions controls. Further, rather than rely upon only one year's data to establish a facility's heat input, EPA should base the allocations on historical heat input over a longer period of time. Such an allocation would be more representative and fairer to facilities that may have experienced reduced utilization during 2008 or 2009 because of the recession or to install emissions controls in advance of the CAIR. [EPA-HQ-OAR-2009-0491-2712.1, p.23]  
If EPA does not either correct the serious problems with IPM that have resulted in its erroneous projections of dispatch or establish unit-specific allocations based on historic heat input, it could, as an altogether different approach, refrain from promulgation of the proposed FIPs and instead support states' efforts to submit adequate SIP revisions within a reasonable amount of time. [EPA-HQ-OAR-2009-0491-2712.1, p.23]  
As conveyed by Linden Cogen's comments submitted on the Proposed Transport Rule, Linden Cogen objects to EPA's proposed allocations of allowances for nitrogen oxides ('NOx') for New Jersey because they are based upon projections of utilization generated by EPA's Integrated Planning Model ('IMP'), which have no basis in reality and fail to reflect Linden Cogen's long-term contractual obligations. Due to several other errors in the model inputs. lPM has erroneously modeled Linden Cogen as thought it would only be dispatched as infrequently as a simple cycle peaking plant, although both historical data from Linden Cogen and its long-term contractual obligations clearly demonstrate that it is a baseload cogeneration facility ('cogen'). [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.1]   
As argued by our comments on the Proposed Transport Rule, EPA cannot rely upon IPM projections as the basis for allocating allowances. unless it revises IPM so that the model accurately predicts dispatch of facilities subject to long-term contractual obligations such as Linden Cogen. For cogeneration facilities, which are operated to provide both power and steam to their cogeneration hosts and power to the grid, Linden Cogen believes that the only way IPM can be modified to avoid such erroneous projections of dispatch is to incorporate the specific contractual obligations governing operation of cogen units into IPM. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.2]
However, Linden Cogen understands from conversations with EPA representatives that EPA intends to use only publicly available information in IPM and, as a consequence, has no current intention of incorporating the requirements of cogenerators' contracts into the model. This approach would support Linden Cogen's conclusion that IPM may not be able to effectively model the often highly complex contractual provisions governing dispatch of cogens, Although Linden Cogen does not believe EPA should limit the inputs to IPM to publicly available information, Linden Cogen has attempted to determine whether a methodology could be developed for modeling cogenerators that relies solely on publicly reported data. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.2]
To develop such a methodology, EPA would need, at a minimum, information on the minimum operating levels that cogenerators must maintain to supply adequate steam and power to their cogeneration hosts, as well as the incremental heat rates to be applied to dispatch of their additional capacity. If such information were contained within publicly available databases, EPA could, in theory, develop certain model plant types for cogenerators that could then be applied to individual cogenerators based upon reported data. The model would assume operations of cogenerators at certain minimum operating levels and then solve for dispatch of additional capacity above such operating levels. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.2]
However, Linden Cogen has determined that public databases (EPA and Energy Information Administration ('EIA')) are inadequate and do not provide sufficiently detailed information concerning the operation of cogens to enable such a modeling exercise. Therefore. if EPA wants to continue to rely upon IPM results as the basis for allocating allowances to individual units, Linden Cogen believes EPA must set the dispatch module for cogenerators within IPM at a level equivalent to their historic heat input and then let the model solve for the dispatch of other electric generating facilities. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.2]
As conveyed by Linden Cogen' s comments on the Proposed Transport Rule, if EPA cannot modify IPM so that it provides a reasonable and accurate projection of Linden Cogen and other facilities subject to long-term contractual obligations, EPA should base NOx allocations in New Jersey on historical data, as augmented by assumptions about the operation of existing and planned emissions controls. Alternatively, EPA could refrain from promulgation of the proposed Federal Implementation Plans ('FIPs')and instead support states' efforts to submit adequate State Implementation Plan ('SIP') revisions within a reasonable amount of time. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.2]
Before EPA Relies Upon IPM Results as the Basis for Allocating Emissions Allowances to Individual Units, EPA Must Adopt an Approach for Modeling of Cogens That Accurately Reflects Their Obligations to Provide Both Power and Useful Thermal Output to Their Cogeneration Hosts and Electricity to the Grid [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.4]
Representatives of Linden Cogen have spoken with EPA staff responsible for maintenance and development of the IPM. Linden Cogen understands from these conversations that EPA recognizes that there are problems associated with modeling the future dispatch of cogeneration facilities. In addition, in our preliminary review of comments filed on the Proposed Transport Rule, we noted several other owners of cogeneration facilities who identified similarly erroneous projections of dispatch for their units. EPA must resolve these problems, before relying upon IPM results as the basis for allocating emissions allowances under the Proposed Transport Rule. Further, EPA should resolve these problems to assure that any future application of IPM in agency planning and decision-making is rooted in an accurate understanding of how cogens operate. With these goals in mind, Linden Cogen provides the following supplemental comments on how EPA might develop a sound technical approach for modeling of cogens in IPM. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.4]
Cogens typically have certain minimum 'must run' operating levels established by contract with their cogeneration host, at which they must be operated at all times to provide a base level of steam sales and/or to satisfy contractual obligations in the power and steam sales contract. Thus, to model cogens' operation, Linden Cogen believes that, at a minimum, EPA would need to incorporate these minimum 'must run' operating levels into IPM. EPA would also need to apply an appropriate 'incremental' heat rate for dispatch above such minimum operating levels. This incremental heat rate is often substantially lower than the actual heat rate for the plant because it only reflects the additional fuel needed to increase generating capacity, once the plant is already operating to satisfy the minimum steam and power requirements of the cogeneration host and/or the requirements of the long-term contract. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.4]
In addition, as suggested by our October 1,2010 Comments, EPA also would need to incorporate the specific contractual terms governing dispatch of facilities like Linden Cogen into the model because some contracts may have requirements that differ from a 'typical' cogeneration contract. Contracts for sale of power and steam often include detailed provisions that mandate operation at certain minimum load levels or for specific minimum durations. For example, while dispatch of Linden Cogen Units 1 through 5 is controlled by ConEd, ConEd cannot dispatch Units 1 through 5 at a lower load than 303 MW. Additionally, once ConEd has dispatched the plant above 303 MW for only one hour, it must operate the plant at a load of at least 379 MW for no less than fifty consecutive hours. Moreover, as pointed out in our October 1, 2010 Comments, Linden Units 1- 5 dispatch into New York City, and not into the PJM grid. See October 1, 2010 Comments, 11. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.4]
Given these contractual obligations, if EPA wanted to accurately reflect the operation of Linden cogen, Units 1 through 5 would need to be modeled with a minimum 'must run' operating level of 303 MW. The heat rate assigned to this must run component of Units 1 through 5 operations would be substantially higher than the overall plant rate, since it also accounts for the production of dispatch from Units 1 through 5, dispatch would need to be modeled at an incremental heat rate that the plant's contractual requirements. Further, even if EPA were to make these changes, IPM still may provide grossly unrealistic projections for dispatch of Units 1 through 5, unless the model could also accommodate the fifty hour-minimum dispatch requirement. In reality, Linden Cogen's annual capacity factor has ranged from 62% to 75%  under the ConEd power sales agreement. and the quarterly capacity factors have been as high as 80%. See id.. 9, The power sales agreement for Linden Units I through 5 significantly differs from that of a typical cogeneration facility because it reflects unique contractual arrangements to supply ConEd with power for sale into the New York City market. [EPA-HQ-OAR-2009-0491-3743.1_NODA, pp.4-5]
In the same fashion. but more consistent with a 'typical' cogen's operation, dispatch of Linden Cogen Unit 6 would need to be modeled with a minimum 'must nm' operating level of 134 MW due to Linden Cogen's contractual obligations to provide a base level of electric load to ConocoPhillips. This 'must run' component of Unit 6's operations would need to be modeled with a substantially higher heat rate than the plant's overall heat rate, since it also accounts for the fuel needed to generate such steam; the additional 36 MW of capacity from Unit 6 would need to be modeled with an incremental heat rate that is significantly lower. Linden Cogen provides this example merely for purposes of illustration of how real-world assumptions concerning the operation of cogeneration facilities might possibly be incorporated into IPM. It also is intended to illustrate the complexity of the contractual terms governing the dispatch of cogens, both for sale of steam to their thermal host and for generation of electricity to the grid. As described by our October 1, 2010 comments, EPA cannot rely upon IPM as the basis for allocating allowances unless it fixes several errors in the model and underlying assumptions and adapts IPM to accommodate the often complex requirements governing dispatch of facilities subject to long-term contracts. See October l, 2010 Comments, 18-19. As we previously stated, '[if] IPM cannot accommodate the numerous complex contractual terms governing dispatch of Linden Cogen' s units, then EPA must at the very least establish some set of rules within IPM, which effectively 'force' the model to predict dispatch of Linden Cogen and other contracted facilities at heat input levels representative of historic operations.' Id., 19 [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.5]
As EPA has recognized, cogeneration represents a highly efficient solution to meeting our nation's demand for power, while reducing emissions. According to the U.S. Clean Heat and Power Association, cogeneration systems currently comprise almost 8% of the U.S. power sector, resulting in a net reduction of  NOx and sulfur dioxide ('SOx') emissions of 0.4 and 0.9 million tons per year, respectively, when compared to emissions that would result if the needs being met by these cogeneration systems were met by conventional generating sources instead. Moreover, an even greater percentage of new generating capacity built since the 1990's consists of cogens. Thus, cogens represent a significant, highly efficient and dean component of the electric generating sector. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.5]
For these reasons, EPA cannot and should not rely upon model results that fail to account for the tremendous benefits achieved by cogeneration, either as the basis for allocating allowances under the Proposed Transport Rule or in support of broader agency policy and planning objectives. To do so would not only prejudice individual cogens, which will need to purchase allowances to operate under the Proposed Transport Rule, but would frustrate the goal articulated by the Administrator upon proposing the Transport Rule of fostering investments in compliance that represent the most efficient and forward-looking expenditure of investor, shareholder, and public funds, resulting, in turn, in the creation of a dean, efficient, and completely modem power sector.' 75 Fed. Reg at 45227.
Because EPA Intends to Rely Only Upon Publicly Available Information in IPM and Linden Cogen Does Not Believe EPA Can Accurately Model Cogens Based Solely on Public Information, EPA Should Set the Dispatch of Cogens Within IPM at Their Historic Heat Input and Then Let IPM Solve for Dispatch of All Other Generating facilities [EPA-HQ-OAR-2009-0491-3743.1_NODA, pp.5-6]
Linden Cogen understands from conversations with EPA representatives that, in revising IPM to reflect more realistic and accurate assumptions based upon comments it has received on the Proposed Transport Rule, EPA currently intends to rely only upon publicly available information. As a consequence, EPA does not intend to make any effort to incorporate non-public information, such as the requirements of specific contracts, into IPM. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.6]
Acknowledging that any modeling exercise involves some degree of simplification, Linden Cogen believes that limiting IPM to publicly available information would represent an arbitrary restriction, particularly given the wildly inaccurate results that IPM has generated for cogens and the fact that no effort has been made within IPM to reflect cogens' generation of power and useful thermal output to meet the demand of their thermal hosts. Further, it is ironic that EPA has expressed its intention to rely only upon publicly available information in future iterations of IPM, when IPM is itself a proprietary model, about which EPA has revealed only limited information due to restrictions imposed by the model's developer. As suggested by our October 1, 2010 Comments, Linden Cogen believes EPA has an obligation to incorporate contractual obligations into IPM to the greatest extent possible, before relying upon IPM results as the basis for allocating allowances to individual units. See October 1, 2010 Comments, 9. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.6]
Nevertheless, Linden Cogen reviewed publicly available databases to assess whether and to what extent EPA could obtain information on how cogens are operated from such databases that could then be incorporated into IPM to produce more accurate results for cogens, without relying upon the specific contractual provisions governing dispatch of actual plants. As suggested by the example concerning Linden Cogen presented above, at a minimum, EPA would need at least two pieces of information concerning operation of cogens to successfully model their operations with IPM: [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.6]
(1) The percentage of capacity that represents 'must run' operations; and [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.6]
(2) The incremental heat rate to be applied to generation of additional capacity, above the minimum 'must run' operating levels. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.6]
If such information were publicly available, EPA might, in theory, develop certain generic cogeneration plant types within IPM (e.g., those with minimum "must run" operations representing less than 50% of their annual capacity and those over 50% of capacity) and then assign individual cogens to one of these plant types by reference to information reported to the EPA or EIA. EPA would also need to develop appropriate incremental heat rates for different categories of generating units based on their size, configuration in combined-cycle, and year of construction. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.6]
However, based on our review of databases of historic operating data compiled from EIA 920 (Combined Heat and Power Plant Report) and EIA 923 (Power Plant Operations Report), as wells as private subscriber databases that compile data reported to EPA into a more usable format. we do not believe that the information needed to perform such a modeling exercise is publicly available. None of these databases captures data on cogens' minimum operating levels and the incremental heat rates applicable to generation of additional capacity above those minimum operating levels. Accordingly, we do not believe EPA can develop a methodology that would result in realistic and reliable projections of dispatch for cogens, unless IPM can accommodate the specific contractual terms governing dispatch of actual plants. [EPA-HQ-OAR-2009-0491-3743.1_NODA, pp.6-7]
Moreover. the contractual provisions governing dispatch of plants subject to long-term contracts are often highly complex and may not be amenable to modeling within IPM. Thus, without undertaking a major overhaul of the IPM itself, we are doubtful that EPA could feasibly incorporate the relevant contractual dispatch parameters into IPM. even if such parameters were already known to EPA. The fact that EPA currently intends to rely only upon publicly available information further supports our conclusion that IPM is unsuitable for modeling of cogens. In light of this, we must conclude that, assuming EPA cannot incorporate the long-term contract parameters governing dispatch of Linden Cogen and other cogens into the model. EPA must set the dispatch for cogens within IPM at historic heat input levels using readily available information from EPA databases, and then let IPM solve for the dispatch of other electric generating facilities. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.7]
Because most cogeneration facilities were built after 1990, they are less likely than other facilities to be operated without emissions controls. As a consequence, historic dispatch information is more likely to be representative of future dispatch for cogenerators than it is for older facilities, which may need to either curtail their operations or install additional emissions controls to comply with the Transport Rule. For this reason. Linden Cogen does not believe that setting the dispatch of cogens at their historic heat inputs should result in an unrealistic representation of their future operations. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.7]

4. Technical Support Document, State Budgets, Unit Allocations, and Unit Emissions Rates, EPA Office of Air and Radiation, July 20 I0, at 9 ('Reported annual and ozone season NOx emissions are adjusted to account for unusually low utilization in 2009.') ('Because 2009 was an unusually low year, rebasing emissions on 2008 heat input in this way typically results in larger annual NOx emissions.'). [EPA-HQ-OAR-2009-0491-2712.1, p.7]  
7. See Documentation for EPA Base Case v.4.10, 4-9, Table 3-4. [EPA-HQ-OAR-2009-0491-2712.1, p.11]    
13. These preamble statements are inconsistent with other statements appearing in the Technical Support Document, where EPA said that statewide budgets (other than the 2014 SO2 budgets for group 1 states) were based on 'the lower of the recent actual emissions or projected base case emissions, at the state level.' Technical Support Document, State Budgets, Unit Allocations, and Unit Emissions Rates, 9-11. Thus, the Technical Support Document suggests that statewide budgets were set the same way as unit allocations (by taking the lower of IPM projections or actual reported data), while the preamble to the Proposed Transport Rule indicates that EPA disregarded IPM projections as the basis for setting state-wide budgets because IPM projections are not as accurate as actual emissions data in predicting how individual units will be operated. [EPA-HQ-OAR-2009-0491-2712.1, p.15]  
15. See supra nt. 4. [EPA-HQ-OAR-2009-0491-2712.1, p.20]  
Exxon Mobil Corporation
6. EPA overestimated Louisiana emissions inventory used for making the projections, in both the IPM v. 3.02 and v. 4.10 models; thus, even the minimal contributions by Louisiana are likely grossly overstated. The primary reasons the inventories were overstated are:  [EPA-HQ-OAR-2009-0491-2841.1, p.5]
2. EPA's projections of significant contribution and reasonable interference at the HGB and DFW monitors were based on the IPM v. 3.02 Base Case modeling for 2012. On September 1,2010, EPA published a Notice of Data Availability for the IPM v. 4.10 modeling, including a revised TR Base Case 2012 scenario. Under the revised modeling, projected emissions of ozone season NOx are 6,061 tpy less than projected under the IPM v. 3.02 version. Based on this factor alone, it is believed that any revised air quality analysis based on the IPM v. 4.10 modeling will demonstrate no impact whatsoever on ozone design values in the HGB or DFW areas. As noted, while EM has reservations about some of the other inputs to the IPM model, as discussed herein, EM believes that the v. 4.10 estimates rely upon a more accurate forecasting of natural gas prices and that version should be used to determine, at least as a screening mechanism, the potential for significant contribution or interference with maintenance of a NAAQS. [EPA-HQ-OAR-2009-0491-2841.1, p.7]
4. Due to the inherent uncertainty in the IPM modeling, as unmistakably illustrated by the material differences between IPM v. 3.02 and v. 4.10 projections, a projected impact of less than 2 ppb based on modeling should never be used as a level indicating 'significant contribution' or 'interference with maintenance' from an upwind to a downwind state under the 'good neighbor' provisions of the Clean Air Act, 42 U.S.c. 7410(a)(2)(D). At most, the IPM should be used as a screening tool for making rebuttable presumptions for 'significant contribution' or 'interference with maintenance' determinations. However, such presumptions should be always subject to a reasonable opportunity for rebuttal by empirical evidence. [EPA-HQ-OAR-2009-0491-2841.1,p.8]
5. EPA overestimated Louisiana emissions inventory used for making the projections, in both the IPM v. 3.02 and v. 4.10 models for the reasons stated in Section II.A, above; thus, even the minimal contributions of ozone season NOx by Louisiana emissions to Texas are likely grossly overstated. [EPA-HQ-OAR-2009-0491-2841.1,pp.8-9]
EM supports use of the updated IPM for use in making screening decisions to assist in making findings of 'significant contribution' or 'interference with maintenance' under Clean Air Act Section 110(d). EM urges EPA, however, to make certain updates to the assumptions and inputs for IPM v. 4.10 as discussed in these comments. Further, as indicated in EM's original comments, the IPM Base Case, whether premised on v. 3.02, v. 4.10 or some future version, should only be a screening tool for indications, of potential 'significant contribution' or 'interference with maintenance'. The IPM is simply not accurate enough and is dependent upon too many uncertain assumptions and imprecise inputs to make binding decisions of 'significant contribution' or 'interference with maintenance.' EPA should always place great weight on empirical data to modify projected model conclusions when making these determinations. [EPA-HQ-OAR-2009-0491-3736.1_NODA, p.2]
The significant difference between the results of the v. 3.02 and v. 4.10 Base Case show the imprecision of the IPM model. Due to this imprecision and the uncertainties attendant to the many assumptions made for the IPM modeling, EM believes that an IPM projected impact of less than 2 ppb from an upwind to a downwind state should never be used as a level indicating 'significant contribution' or 'interference with maintenance' trader the 'good neighbor' provisions of the Clean Air Act, 42 U.S.C. 7410(a)(2)(D). At most, the IPM should be used as a screening tool for making rebuttable presumptions for 'significant contribution' or 'interference with maintenance' determinations if a value above 2 ppb contribution is modeled. However, such presumptions should be always subject to a reasonable opportunity for rebuttal by empirical evidence and a weight of evidence approach used to determine if there is actually such contribution or interference. EM urges EPA to adopt this 2 ppb rule as a bright-line cut-off for screening. If the modeled contribution is 2 ppb or below, then no contribution or interference should be presumed. If the modeled contribution is above 2 ppb, then there could be a rebuttable presumption of contribution or interference. [EPA-HQ-OAR-2009-0491-3736.1_NODA, p.4]
EM believes, for the reasons stated in the comments of the staff of the Louisiana Public Service Commission (LPSC) on the proposed CATR/FIP, that the IPM fails to adequately consider transmission constraints within Louisiana. EM believes this is a deficiency in both the IPM v. 3.02 and v. 4.10. EM urges EPA to carefully consider the comments of the LPSC staff. [EPA-HQ-OAR-2009-0491-3736.1_NODA, p.6]
Gainesville Regional Utilities (GRU)
EPA Has Set Unachievable Emission Limits for GRU's Main Generating Unit In response to the CAIR rule emission caps, GRU committed more than $140,000,000 to add an SCR, a dry circulating SO2 scrubber, and a fabric filter to the Deerhaven Generating Station Unit #2 (DH#2). Those systems are installed and are operating. To take advantage of the fuel flexibility allowed by the SO2 scrubber, the design allows for the combustion of up to 2.5% sulfur coal. The guaranteed SO2 emission rate for the scrubber while combusting the 2.5% sulfur coal is 0.10 lb/mmBtu. Recent performance tests for the unit indicate that significant reductions below the guaranteed emission rate are not likely. As can be seen from the table below design limits and performance test results are significantly more than the proposed limit of 0.07 lb/mmBtu for the EPA second alternative compliance option. We believe it is unreasonable to set an SO2 limit for DH#2 that is well below the normal design and capability of the unit. [EPA-HQ-OAR-2009-0491-2674.1, p.2]
[Table 1 can be found on page 2 of this comment.]
EPA Modeling for Determining Significant Interstate Transport Maybe Flawed
GRU is concerned that the modeling done to determine an upwind state's significant contribution to a downwind state's non-attainment with a NAAQS may be flawed. Further, it is not appropriate to model EGU emissions based on pre-CAIR 2005 emissions since the CAIR reductions for many states, including Florida, may be real and enforceable under existing state permits. In addition, the model projections of significant impacts appear to defy common sense. For example, it is very unlikely that Florida emissions could result in a significant impact on non-attainment on Texas. [EPA-HQ-OAR-2009-0491-2674.1, pp.6-7]
Kansas City Board of Public Utilities (BPU)
EPA'S MODEL PRODUCES RESULTS THAT OVERSTATE KANSAS EMISSIONS LEVELS
Besides EPA overstepping its legal bounds by effectively subjecting Kansas to the requirements of the new rule prior to the time authorized by the CAA, the modeling on which the proposed rule relies overestimates the significant contribution and interference of maintenance in identified nonattainment areas that can be attributed to Kansas. See 75 FR at 45262 (24-hour PM25 list shows three Milwaukee, WI sites); at 45266 (24-hour PM25 list shows Muscatine, IA and Milwaukee, WI sites for maintenance); at 45269 (8-hour ozone shows Dallas, TX site for maintenance). The pre-NODA emission rates used as the basis for the modeling, although identifying NOx and SO2 controls that have been installed on Kansas EGUs, does not incorporate emissions levels that are already being achieved or that must be achieved by 2012 under enforceable permits and agreements. This failure leads to an overstatement of Kansas projected 2012 emissions levels used to identify States that are to be included in the rule. [EPA-HQ-OAR-2009-0491-2740.1, pp.11-12]
When the appropriate EGU emissions level adjustments are made, as shown in the attached Trinity Consultants Report ('Trinity Report'), [See p. 25 of this comment to see comments pertaining to the Trinity Report] the most significant change relates to the supposed linkage between Kansas' downwind emissions and a nonattainment site in Dallas. After the appropriate adjustments are made, downwind modeling at the Dallas site shifts from being above to falling below the 'single 'bright line' threshold for ozone that is one percent of the 1997 8-hour ozone standard of 0.08 ppm,' making the threshold 'a value of 0.8 ppb.' 75 FR at 45237/3. Consequently, the properly adjusted modeling no longer supports a finding that Kansas emissions meet the threshold for contributing to interference with maintenance at the Dallas site. As this is the only site to which Kansas is linked for 8-hour ozone maintenance, 75 FR at 45269, it follows that Kansas should be removed from the list of States subject to the proposed 8-hour ozone rule. [EPA-HQ-OAR-2009-0491-2740.1, p.12]
[See pp. 12-14 of this comments for additional comments pertaining to EPA's Model Produces Results That Overstate Kansas Emission Levels]
Kansas City Power and Light Company (KCP&L)
2. Due to the identification of numerous inaccuracies in the unit-level data, EPA changes to the NEEDS database, as well as changes to the IPM model itself, regulated entities will remain in a state of uncertainty until the final Transport Rule is published in mid-2011. The new modeling runs will likely lead to substantially different state budgets and may even change the number of states affected. For these reasons, EPA should reissue the rule for public comment as a Supplemental Notice of Proposed Rulemaking. [EPA-HQ-OAR-2009-0491-2709.1, p.3] [EPA-HQ-OAR-2009-0491-3757.1_NODA, p.2]
While the IPM emission projections were intended to account for emission reductions that would be required by 2012, a review of the IPM projections shows that emission reductions required by 2012 for NOx and SO2 at Westar Energy's Jeffrey Energy Center were not accounted for. [EPA-HQ-OAR-2009-0491-2709.1, p.3]
6. KCP&L disagrees with the way EPA adjusted reported NOx emission by using 2008 heat input with the most recent four quarters of emissions rate data. EPA's assumption that utilization was unusually low in 2009 for all units is incorrect. For some units, 2008 annual heat input was lower than Q4 2008 through Q3 2009, and the 2008 ozone season heat input was lower than the 2009 ozone season. Since EPA's goal in adjusting the data was to calculate "typically" larger NOx emissions, it should use the larger of the two heat input rates (i.e., 2008 vs. the most recent four quarters for annual heat input and 2008 vs. 2009 ozone season heat input), combined with the most recent four quarters or ozone season emission rate (lb/mmBtu) data. EPA did not explain why it made this correction for NOx, but not for SO2. [EPA-HQ-OAR-2009-0491-2709.1, p.4]
2. There are errors in adjustments made when calculating unit level allowances, based on review of the data contained in the Budgets and Allocations  -  Detailed Unit-Level Data TSD and the IPM TR SB Limited Trading 2014 parsed file. [EPA-HQ-OAR-2009-0491-2709.1, p.5]
a. The Hawthorn Unit 5A (ID 2079_B_5A) annual NOx emissions were incorrectly adjusted downward by 30.4 tpy. According to the State Budgets, Unit Allocations, and Unit Emissions Rates TSD (page 5), "... reported and projected emissions for annual NOx are adjusted to account for the year-round operation of post-combustion controls which may only have operated during the ozone season." Hawthorn Unit 5A has a permit limit of 0.08 lb/mmBtu (30-day rolling average). Compliance with this limit requires year-round operation of the SCR. A downward adjustment based on the 2009 ozone season emission rate is therefore inappropriate. The annual NOx allowances for this unit should be based on the emission rate over the most recent four quarters of reported data without additional adjustment for the post-combustion control. [EPA-HQ-OAR-2009-0491-2709.1, p.5]
b. The La Cygne Unit 1 (ID 1241_B_1) annual NOx emissions were incorrectly adjusted downward by 761.6 tpy. According to the State Budgets, Unit Allocations, and Unit Emissions Rates TSD (page 5), "... reported and projected emissions for annual NOx are adjusted to account for the year-round operation of post-combustion controls which may only have operated during the ozone season." La Cygne Unit 1 has a current permit limit of 0.15 lb/mmBtu (12-month rolling average). Compliance with this limit requires year-round operation of the SCR. A downward adjustment based on the 2009 ozone season emission rate is therefore inappropriate. The annual NOx allowances for this unit should be based on the emission rate over the most recent four quarters of reported data without additional adjustment for the post-combustion control. [EPA-HQ-OAR-2009-0491-2709.1, p.5]
c. The time period used for reported NOx emissions for Iatan Unit 1 is incorrect. The Iatan Unit 1 SCR came online in Q1 2009. The unit was off line for parts of Q4 2008 and Q1 2009 for the installation of the SCR and other emission controls and the reported heat input was well below what it would have been under normal operating conditions. It is therefore not appropriate to use those two quarters in calculating the reported annual NOx rate. Appropriate quarters for the annual heat input and unadjusted emission rate would be Q2 2009 through Q1 2010 (post- SCR). Note that to comply with its NOx emission limit of 0.09 lb/mmBtu (30- day rolling average), this unit must operate its SCR year-round. Therefore any downward adjustments to the reported data to account for the SCR would be inappropriate. The available post-installation data should be used without adjustment. [EPA-HQ-OAR-2009-0491-2709.1, p.6]
d. The Hawthorn Unit 5A 2014 SO2 allowances are based on an emission rate of 0.06 lb/mmBtu. The basis for this rate is not clear, as it does not appear to originate from the IPM data. Regardless, it is beyond the capability of the existing dry scrubber and the unit already burns low sulfur coal. The BACT determined limit for this unit, as stated in its current Title V operating permit, is 0.12 lb/mmBtu. [EPA-HQ-OAR-2009-0491-2709.1, p.6]
e. Reported data for Lake Road Unit 6 appears on two separates lines in the spreadsheet. The reported values from the two lines should be added together and included as a single entry. [EPA-HQ-OAR-2009-0491-2709.1, p.6]
3. General comments on the use of IPM 2014 projected SO2 emissions to determine allowances. [EPA-HQ-OAR-2009-0491-2709.1, p.6]
a. Unit level allocations are a proportional share of the state's budget based on projected SO2 emissions in the TR SB Limited Trading IPM run as apportioned in the 2014 parsed file. It is not clear from the documentation provided by EPA how allowances were allocated based on the IPM emissions prediction. It is also not clear how the heat inputs used to calculate 2014 SO2 allowances were determined. Clearly there is a disconnect between the 2014 IPM emission rates and the 2014 SO2 allocations that is not explained by EPA's inadequate documentation. Overall in Missouri, when compared at the unit level, allocations range from 0.5 to 3.6 times the IPM emission rate. These discrepancies illustrate why reductions would be more appropriately addressed through a SIP rather than a FIP. [EPA-HQ-OAR-2009-0491-2709.1, p.6]
i. The 2014 IPM heat inputs for Montrose Units 1, 2, and 3 (ID 2080_B_1, 2, and 3) are 44% below the 2012 heat inputs with no explanation given. The 2014 SO2 state budget for Missouri (154,000 tpy) is 91% of the 2014 IPM Limited Trading scenario emissions (168,911 tpy). However, the ratio of 2014 IPM modeled SO2 emissions to allowances for Montrose Units 1-3 ranges from 55 to 59%. It is not clear why those units received a much smaller portion of the 2014 IPM predicted emission rate. [EPA-HQ-OAR-2009-0491-2709.1, p.6]
ii. The 2014 heat input predicted by IPM for Sibley Unit 2 is 19% below the 2012 value with no explanation given. This unit is not anticipated to operate less in 2014 than it does currently or in 2012. [EPA-HQ-OAR-2009-0491-2709.1, p.6]
4. IPM predicts changes in operation regarding individual units that are inaccurate. [EPA-HQ-OAR-2009-0491-2709.1, p.7] [EPA-HQ-OAR-2009-0491-3757.1_NODA,p.5]
a. Sibley Units 1 and 3 are projected for "early coal retirement" and therefore do not receive any 2014 SO2 allowances. This modeled outcome is incorrect. There is no intention of retiring those units in that time frame and they should receive allowances. KCP&L has recently invested significant capital in NOx controls on both of these units (SCR on Unit 3 and SNCR on Unit 1) and retirement by 2014 would not allow for an acceptable return on that investment. In addition, operation of these units is necessary during periods of transmission curtailment elsewhere in the system. [EPA-HQ-OAR-2009-0491-2709.1, p.7] [EPA-HQ-OAR-2009-0491-3757.1_NODA,p.5]
b. Northeast Units 11-18 (ID 2081_G_11  -  2081_G_18) are projected for "early CT retirement" in the 2014 Limited Trading IPM run and therefore do not receive any 2014 SO2 allowances. This modeled outcome is incorrect. There is no intention of retiring those units in that timeframe. In fact, even if they are not economical to operate, their occasional operation is vital to grid stability. They contribute to grid stability by providing volt amp reactance (VAR) when necessary, and are used during periods of transmission curtailment elsewhere in the system. As oil-fired units, they can also provide power during periods of natural gas curtailment. [EPA-HQ-OAR-2009-0491-2709.1, p.7] [EPA-HQ-OAR-2009-0491-3757.1_NODA, pp.5-6]
c. Lake Road Unit 5 (ID 2098_G_5) is projected for "early CT retirement" and Lake Road Unit 6 is projected for "early coal retirement" in the 2014 Limited Trading IPM run. This modeled outcome is incorrect. There is no intention of retiring these units in that timeframe. In fact, even if this unit is not economical to operate, occasional operation is vital to grid stability. These units contribute to grid stability by providing volt amp reactance (VAR) when necessary, and can be used during periods of transmission curtailment elsewhere in the system. As an oil-fired unit, Lake Road Unit 5 can also provide power during periods of natural gas curtailment. [EPA-HQ-OAR-2009-0491-2709.1, p.7] [EPA-HQ-OAR-2009-0491-3757.1_NODA, p.6]
d. Hawthorn Units 6 and 9 (ID 2079_G_6 and 2079_G_9) are projected for "CC early retirement" in the 2014 Limited Trading IPM fun. This modeled outcome in incorrect. There is no intention of retiring those units in that timeframe. In fact, even if they are not economical to operate, their occasional operation is vital to grid stability. They contribute to grid stability by providing volt amp reactance (VAR) when necessary, and are used during periods of transmission curtailment elsewhere in the system. [EPA-HQ-OAR-2009-0491-2709.1, p.7] [EPA-HQ-OAR-2009-0491-3757.1_NODA, p.6]
Kansas Department of Health and Environment
During our review of the rule we have identified several inconsistencies in the emissions modeling inputs that we believe could lead to a significant overestimation of contribution to nonattainment from Kansas sources. Specifically, emissions from several electric utility generation units in the state are overestimated in the 2012 base year used for the contribution assessment. This appears to occur due to the use of older data, which EPA has stated it intends to correct in the Notice of Data Availability (NODA) that was published in the Federal Register on September 1, 2010. KDHE encourages EPA to follow through and use the latest available data for both emission rates and heat inputs for the electric utility sector. [EPA-HQ-OAR-2009-0491-2606.1, p.2]
In sum, these are very significant reductions in overall NOx emissions that have not been properly accounted for, and if counted, would likely remove the currently modeled Kansas 'linkage' with Dallas, TX monitors for ozone. In addition, the NOx and S02 reductions that have not been accounted for will also reduce the modeled Kansas contribution to PM2.5 in all areas of the country. [EPA-HQ-OAR-2009-0491-2606.1, p.5]
Louisiana Chemical Association (LCA)
2. Our review thus far indicates that EPA may have significantly overestimated the emissions inventory for Louisiana for both S02 and NOx and that the modeled projections resulting from these errant emissions are likewise overestimated. [EPA-HQ-OAR-2009-0491-1925.1, p. 2]
Louisiana Energy and Power Authority (LEPA)
THE PROPOSED TRANSPORT RULE FAILS TO ALLOCATE EMISSION ALLOWANCES TO UNITS THAT MUST RUN TO SERVE LOAD DURING PEAK HOURS BECAUSE EPA'S METHODOLOGY DOES NOT ACCOUNT FOR TRANSMISSION CONSTRAINTS AND ASSOCIATED OPERATIONAL REQUIREMENTS. [EPA-HQ-OAR-2009-0491-2700.1, p.12]
EPA's methodology for developing the state budgets and unit level allocations is set forth in the Technical Support Document entitled State Budgets, Unit Allocations, and Unit Emissions Rates. According to that document, state budgets, unit allocations and direct control rate limits are '[e]ach derived from a combination of recent emissions and heat input data and electric power sector projections from the Integrated Planning Model (IPM) affecting an inventory of fossil-fuel fired EGUs of more than 25MW capacity. Specifically, each state's budget was constructed from a combination of data and IPM projections for the EGUs in that state, and each EGU's contribution to the budget formed the basis of its allocation and direct control rate limit calculations.' Unit allocations thus apparently were set primarily based on projections on how much each EGU would run as determined by the IPM. [EPA-HQ-OAR-2009-0491-2700.1, p.12; for additional comments pertaining to THE PROPOSED TRANSPORT RULE FAILS TO ALLOCATE EMISSION ALLOWANCES TO UNITS THAT MUST RUN TO SERVE LOAD DURING PEAK HOURS BECAUSE EPA'S METHODOLOGY DOES NOT ACCOUNT FOR TRANSMISSION CONSTRAINTS AND ASSOCIATED OPERATIONAL REQUIREMENTS, see pp.12-14]
Vectren Corporation 
EPA's assumptions regarding Vectren's control technology are inaccurate. [EPA-HQ-OAR-2009-0491-2654.1, p. 6]
EPA's NEEDS database inaccurately reflects not only the actual S02 permit limits for the Vectren units, but EPA's control efficiency assumptions do not adequately take into account the efficiency levels of the scrubbers for Vectren's AB Brown units 1 and 2.
EPA's NEEDS database lists the SO2 Permit Rates for Vectren's units as the following: [EPA-HQ-OAR-2009-0491-2654.1, p. 6]
FB Culley Unit 3-0.25 lb/mmBtu
AB Brown Unit 1-0.69 lb/mmBtu
AB Brown Unit 2-0.12 lb/mmBtu
The permit limit assumptions are inaccurate, The actual S02 permit limits for the Vectren units, as included in the source's applicable Title V operating permit, are the following: [EPA-HQ-OAR-2009-0491-2654.1, pp. 6-7]
FB Culley Unit 3-Scrubber to be operated at all times that unit is in operation at 95% removal efficiency.
AB Brown Unit 1-1.2 lb/mmBtu
AB Brown Unit 2-0.69 lb/mmBtu
As indicated above, the actual S02 permitted limits for the two Brown units are virtually double what is assumed in EPA's modeling runs. In addition, EPA's assumptions around the efficiencies of an FOD scrubber system fail to take into account that the scrubbers on AB Brown Units I and 2 are the original scrubbers constructed with the units (I 979 and 1986, respectively). The two AB Brown scrubbers are the only remaining dual alkali scrubbers currently in operation (to our knowledge), and they are not capable of achieving the efficiency assumptions ascribed to scrubbed units in the model. In reality, the dual alkali scrubbers at AB Brown Units I and 2 are capable of achieving an average S02 removal efficiency of 80-85%, instead of the assumed efficiencies of 87.7% (AB Brown Unit I) and 95.3% (AB Brown Unit 2) in the NEEDS database.  [EPA-HQ-OAR-2009-0491-2654.1, p. 7]
Response: 
EPA reviewed the comments and has made significant updates to its IPM v.3.02 modeling used at proposal.  These updates include changes to both the more general IPM assumptions (e.g., gas price assumptions) and specific unit level assumptions (e.g., that current retrofit status at a unit).  These updates were made to the IPM model, and the updated version (EPA IPM v.4.10) was used for all the final rule analysis.  In regards to unit specific adjustments, EPA did not manually adjust projected unit level modeling outputs, but it did make unit level updated to its NEEDS database used as a model input that impacted the unit level model outputs.  
Some of the most frequent general IPM comments noted above that were addressed in the updates are: FGD removal efficiency was adjusted for new retrofits, and for existing retrofits it was indexed to historic performance at the unit.  Additionally, many of the above comments were focused on a sources ability to switch coals.  EPA modified its modeling to better reflect the cost and feasibility of switching and blending coals.  State Rule and consent decrees were updated according to comments - among others, there were updates made to state rules and/or consent decrees impacting sources in Kansas and Louisiana as highlighted by the commenters above.  EPA also made significant updates to its modeling of cogeneration units to address concerns expressed by commenters.  Additionally, there were more than 1000 unit specific modeling changes made in response to corrections provided by the commenter.  For more detailed discussion of EPA IPM v.4.10 assumptions and assumption updates, see the EPA IPM v.4.10 documentation and the "Transport Rule IPM Assumptions Response to Comments" in the Appendix

XVIII.C.1. NPR: EGU Projections Using IPM/NEEDS V.3.02EISA

Organization: American Electric Power
Comment: 
American Electric Power
Incorrect Data - The NEEDS database lists certain units with inaccurate emission controls. Additionally, the IPM model structure does not take into account all necessary unit specific operating constraints, specifically those relating to fuel suitability. Furthermore, EPA's data on purportedly 'actual' costs of scrubbers and SCRs are lower than actual industry and AEP-specific experience. [EPA-HQ-OAR-2009-0491-2665.1, p.4]
AEP has output driven comments from both versions of IPM, as we remain unsure which underlying errors might have been corrected in the modeling update process. Many of our concerns are directly related to how underlying unit limitations are factored into the modeling, specifically as ultimate allocation and/or potential emission rate limits are proposed to be tied directly to modeled emissions and performance. Furthermore, AEP requests that EPA produce modeling outputs disaggregated and reported at the unit level. It is highly unclear from the parsed data files provided exactly what coal types are being utilized and what constraints individual units are tied to. This level of data is needed to ensure that a proper third-party review can be conducted of the runs used to support the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2665.1, pp.20-21] [[These comments can also be found in XVIII.C.2.]]
At a minimum, EPA should correct the data and assumption issues identified, remodel the air quality impacts assuming a continuation of CAIR-like standards, revise the compliance dates based on reasonable timelines for environmental controls and rerun the economics and subsequent allocations that would result from these changes. A supplemental Transport Rule should then be proposed for comment. [EPA-HQ-OAR-2009-0491-2665.1, p.21] [[These comments can also be found in XVIII.C.2.]]
Response: 
EPA has made significant updates to its IPM v.3.03 modeling used in the proposal.  The final EPA IPM v.4.10 modeling used for the Final Transport Rule reflects both general and unit level assumption updates based on comments.  See IPM v.4.10 documentation for more details on the final modeling, assumptions, and updates to assumptions in response to comments.  Additionally, the "Transport Rule IPM Assumptions Response to Comments" in the RTC Appendix contains a detailed list of unit level changes.  Subsequent to these changes, EPA remodeled air quality impacts on the updated base case modeling.  The preamble and TSDs explain the results of the updated modeling and the compliance deadlines for Final Transport Rule.
Organization: Cogen Technologies Linden Venture, LP
Comment: 
Cogen Technologies Linden Venture, LP
K. Basing Allocations on Each Facility's Share of Projected Heat Input Would Not Avoid the Arbitrary and Inaccurate Results Generated by IPM
Linden Cogen does not support the alternative allocation methodology described by EPA in the preamble, wherein each facility would be allocated allowances based on its 'share of projected heat input.' 75 Fed. Reg. at 45311. As presented, this alternative allocation methodology would not resolve the serious problems associated with allocating allowances based on IPM's projected dispatch of facilities such as Linden Cogen, which are subject to contractual obligations that will mandate their operation, irrespective of IPM's erroneously low projections. While this alternative allocation methodology would generally favor clean units such as Linden Cogen, it would still base unit allocations on IPM's wildly inaccurate projections and, as a consequence, would fail to avoid the arbitrary results of EPA's proposed allocations. However, if EPA can successfully resolve the errors in IPM that resulted in its erroneously low projections for dispatch of Linden Cogen or if EPA's proposal were instead to allocate allowances based on each source's share of historical statewide heat input, irrespective of IPM's projections for same, Linden Cogen agrees that this would be a fair and equitable approach. [EPA-HQ-OAR-2009-0491-2712.1, p.21]
Response: 
EPA's response to Linden Cogen's concern is three fold
1) EPA changed its general approach to modeling cogeneration units in IPM
2) EPA changed the IPM heat rate specific to Linden Cogen unit which results in more dispatch
3) EPA changed the unit level allocation methodology.  It is no longer based on projected emissions, but was finalized to be based on historic data.  See preamble section VII.D
For changes to IPM noted in 1 & 2 above, see "Transport Rule IPM Assumptions Response to Comments" in RTC Appendix.
Organization: Dominion
Comment: 
Dominion
Low-Sulfur Fuel Availability Issues
It appears that EPA modeled projections for several of Dominion's coal-fired units assume the availability of low sulfur fuel as a viable compliance option going forward. However, over the last several years, Dominion has observed a steady increase in the sulfur content and a steady decrease in the higher heating value (HHV) for the coal burned at many of our facilities (i.e., South American or Central Appalachian-CAPP). As an example, at one of our facilities, we used primarily South American coal from 2006 to 2009 at an average S02 rate of O.7 lb/mmBtu and a HHV of 11,600 Btu/lb. In 2010, with the same coal supplier, the average S02 emission rate is approximately 0.9 lb/mmBtu and a HHV of 11,300 Btu/lb. This represents an approximate 20 percent increase in fuel sulfur content. We understand from our coal suppliers that in general the lower sulfur / high Btu coal has been mined and is no longer available. The coal suppliers have had to move to different seams of the coal mines that contain higher sulfur content. It is our understanding that this trend will continue in the future. [EPA-HQ-OAR-2009-0491-2715.1, p.10]
In addition, there has also been a dramatic decline in the amount of CAPP coal currently being produced. CAPP production dropped by approximately 50 million tons from 2008 to 2010 forecast and is expected to continue to decline. The EIA Annual Energy Outlook 2010 report states that 'Total production of Appalachian coal declines from current levels, as output shifts from the extensively mined, lower cost reserves of Central Appalachia to higher cost supplies from the Interior region and the northern part of the Appalachian basin.' Figure 88 of the same report shows that the Appalachia coal production is projected to steadily decline over the next few decades by about 25% from 2008 levels. This shift in the coal supply agrees with the general trend of increased sulfur contents as the northern Appalachian coals typically have S02 emission rates of approximately 3.5 to 6.0 lb/mmBtu. [EPA-HQ-OAR-2009-0491-2715.1, p.10]
Dominion bums lower sulfur western Powder River Basin (PRB) coal at its State Line (Indiana) and Kincaid (Illinois) facilities. However, this is not a viable option for our eastern coal fleet. Switching fuels for a boiler designed for CAPP coal to a western PRB coal presents several technical issues. A typical PRB coal has a S02 rate of 0.5 to 0.8 lb/mmBtu and a HHV of 8,300 to 8,800 Btu/lb. Converting a boiler designed for CAPP coal to PRB coal would result in de-rating the unit by approximately 30 to 40 percent. It would also require significant upgrades to the coal handling equipment in order to safely handle the more volatile PRB coal. The coal handling upgrades required to safely handle the PRB coal would more than likely require environmental permitting which would only add to the project's timeline. The coal handling upgrades can take a significant amount of time to complete because the schedule for the upgrades has to be balanced against the plant being able to continue to operate which requires using the same coal handling system to be upgraded. Dominion performed coal handling upgrades at our Salem Harbor Station (Massachusetts) and that project took approximately 2 years to complete. Therefore, a switch to lower-sulfur PRB coal poses significant technical, scheduling and economical concerns for Dominion. [EPA-HQ-OAR-2009-0491-2715.1, pp.10-11]
For these reasons, EPA should not assume that the use of lower sulfur coals in the 0.6 to 0.8 lb/mmBtu range that were used in the past and are represented in the NEEDS Version 3.02 EISA database (which reflects EPA-ETS 2006 boiler level emissions, fuel characteristics and pollution control equipment) are a readily available and technically or economically viable option for achieving significant S02 emission reductions going forward, particularly in the short-term. [EPA-HQ-OAR-2009-0491-2715.1, p.11]
EPA Should Justify Its Use of a Single Year Baseline and Explain Its Complex Methodology Used to Determine 2012 State Budgets [EPA-HQ-OAR-2009-0491-2715.1, p.15]
In the Technical Support Document (TSD) addressing the state budgets, EPA indicates that the 2012 budgets were calculated using a combination of reported emissions and heat input data (actual historical data) as of 2009 and IPM projections for 2012 for individual electric generating units, each adjusted to reflect emission control equipment projected to be in place by 2012. The budget for each state is established based on either the aggregate of the individual unit emissions based on the reported data or the projected IPM data, whichever is lower. We have several concerns with this approach: [EPA-HQ-OAR-2009-0491-2715.1, p.15]
It is not clear why two different approaches were used that resulted in the use of budgets based exclusively on reported (actual data) in some states, based solely on IPM projections in other states and a combination (actual data for S02 and reported data for NOx or visa-versa) in yet others. EPA should provide a more detailed explanation for this mixed and confusing methodology. [EPA-HQ-OAR-2009-0491-2715.1, p.15]
It is questionable why state budgets were determined using a baseline of only a single year of emissions and heat inputs. Under the NOx SIP call and CAIR rulemakings, EPA more appropriately used data averaged over a multi-year period to account for year-to-year variability and assure a more accurate representation of utilization for electric generating units. [EPA-HQ-OAR-2009-0491-2715.1, p.15]
EPA further notes that for NOx, 2008 data were used to 'account for unusually low utilization [or heat input] in 2009', while 2009 data were used for S02. While we agree with EPA's conclusion that 2009 was an unusual and unrepresentative year with respect to utilization and that, to the extent a single year of data is used, 2008 is more representative (than 2009), we question why EPA used 2009 data for S02 instead of 2008. EPA should provide an adequate explanation for its decision to use 2009 data for determining state S02 budgets. [EPA-HQ-OAR-2009-0491-2715.1, p.15]
Response: 
EPA modeling includes assumptions regarding coal depletion over time.  EPA has based coal quality estimates on the most recent available information.  EPA IPMv4.10 documentation explains this in more detail.  EPA also notes that model unit level projections are not intended nor serve as unit level compliance requirements.
In regards to State budgets, EPA received significant comment during the Transport Rule public comment period and has revised its approach for determining state budgets.  The final Transport Rule process for determining state budgets is explained in preamble section VI.D and further discussed in the "Significant Contribution and State Emissions Budgets Final Rule TSD". 
Organization: Duke Energy
Comment: 
Duke Energy
EPA's NEEDSv3.02_Database Incorrectly Shows Duke Energy's W H Zimmer Scrubber at a 98% Removal Efficiency.
In its modeling, EPA incorrectly assumed that the existing Zimmer (ORISPL 6019) Unit 1 FGD system ("scrubber") is capable of a 98% SO2 removal efficiency. This unit cannot average 98% removal and EPA should use a lower assumed removal percentage for setting the Ohio state SO2 budgets and allocating SO2 allowances. Duke Energy strongly recommends a removal efficiency of no greater than 95%. The Zimmer Station Unit 1 scrubber was designed in the late 1980's. As an NSPS unit, it was permitted and constructed at that time to meet a 91% removal requirement. Its scrubber tower size and configuration was designed to use a magnesium enhanced lime process which places significant restrictions on its performance. This unit has a much smaller tower height compared to limestone scrubbers and is limited to a much lower liquid to gas ratio. These physical limitations coupled with the process's chemical reaction kinetics make 98% removal efficiency unattainable. If Zimmer's scrubber were intended to achieve 98% removal, it would have been designed and constructed very differently. These changes cannot be retrofitted into the existing unit.  [EPA-HQ-OAR-2009-0491-2689.1, pp.39-40]
Duke Energy projects that this unit at best can achieve a 95% removal, but even this level of performance has not been demonstrated on a sustained basis. Achieving even this level exceeds the scrubber's original design envelope and operating outside the air permit's specification to operate with installed spare equipment. As another example, to prevent pluggage due to scaling, the mist eliminators in each module must undergo regular cleaning. This requires that one of the six modules is almost always out of service an any given time. This necessity was reflected in the original facility air permit. For these reasons, Duke Energy therefore recommends that EPA assume a removal efficiency of no more than 95% for Zimmer's scrubber. [EPA-HQ-OAR-2009-0491-2689.1, p.40]
Duke Energy's Miami Fort Units 7 and 8 Have Very Limited Capability to Burn Subbituminous Coal.
The NEEDSv3.02 database shows that Duke Energy's Miami Fort (ORISPL 2832) units 7 and 8 are capable of burning both bituminous and subbituminous coal. These units are capable of burning up to a 20% blend of subbituminous coal. Significant capital investment would be required to allow the unit to safely handle and burn this fuel type in blends higher than 20%, such as fuel handling upgrades, dust suppression, mill modifications and fire protection, boiler tube surface changes, sootblower additions, etc. However, Miami Fort Station does not have a coal handling system that would allow for the controlled blending of bituminous and subbituminous coals, and these units cannot burn straight subbituminous coal (such as with alternating the fuel types). Therefore, EPA must include the cost of an on-site coal blending system (approximately $55 million for the two units), or increase the cost of the delivered fuel to account for off-site blending cost premiums (approximately $10 to $14 per ton of blended coal from terminals on the Ohio River) in any consideration of subbituminous coal at these units. [EPA-HQ-OAR-2009-0491-2689.1, pp.40-41]
Response: 
In response to concerns such as those expressed above, EPA updated its modeling to better reflect the removal efficiencies of existing scrubbers and the ability of units to switch coals.  See EPA IPM v.4.10 documentation for a complete explanation of these updates and others.  FGD removal efficiencies were indexed to historic performance for the unit - this resulted in the Zimmer unit's removal efficiency being adjusted to 95% as suggested by commenter.
Organization: Edison Electric Institute (EEI)
Comment: 
Edison Electric Institute (EEI)
In the proposed Transport Rule, EPA asserts that the vast majority of 2012 compliance actions are already in the pipeline, which some EEI member companies believe to be the case. Other EEI member companies have expressed concern that EPA's assumptions regarding their current unit operation and new control technology projects may be inaccurate and that they will have difficulty achieving the initial 2012 compliance deadlines. If such EPA assumptions are incorrect, it could make compliance difficult or unrealistic for some companies. Examples of such concerns are presented in the next section of these comments.  [EPA-HQ-OAR-2009-0491-2697.1, p.9]
Some examples of the types of inaccuracies that companies are concerned about include:
-American Electric Power (AEP) (in a written statement submitted to the Senate Environment & Public Works Committee hearing on July 22, 2010) stated that "EPA assumed that AEP will have scrubbed its 585 MW Muskingum River Unit No. 5 in Ohio by January 1, 2011 or only 6 months from now. However, while preliminary engineering was begun several years ago, there is no ongoing construction activity associated with this retrofit project. Even if engineering and construction recommenced today, the actual in-service date for the scrubber would still be at least three years from now." AEP also stated that "
EPA assumes that the AEP Muskingum 1-4 units (830 MW) are able shift to lower sulfur coals in its analysis (1.0-1.4 lb-SO2/mmBtu). However, these units are wet bottom / cyclone-fired boilers, which cannot tolerate most low-sulfur Eastern coals due to their high ash fusion temperatures. Thus, this is a very unrealistic assumption."    [EPA-HQ-OAR-2009-0491-2697.1, p.11]
-Empire District Electric has identified discrepancies which it will ask EPA to correct, such as: "In the TSD "State Budgets, Unit Allocations, and Unit Emissions Rates" some units in Missouri (Iatan, Lake Road, New Madrid 2, and Thomas Hill) are to receive an increase in the number of SO2 allowances in 2014 compared to 2012. The company also notes that a new coal unit, Iatan 2, constructed by KCP&L that will be on-line before 2012 is not included in the Missouri data in the TSD "State Budgets, Unit Allocations, and Unit Emissions Rates".   [EPA-HQ-OAR-2009-0491-2697.1, p.11]
-Consumers Energy will report numerous company-specific issues with EPA assumptions, such as the fact that "There appears to be an assumed retirements at the following units, which at this time Consumers has no plans to retire: B C Cobb Units 1, 2, 3; D E Karn Units 3, 4; and Thetford Units 1, 2, 3, 4. Also, Consumers Energy observes that "It is assumed that J H Campbell Unit 2 will have an SCR operational in 2012, which it will not." Finally, the company will comment that "There appears to be an assumption that Consumers will be fuel switching to an extremely low sulfur coal on the following units in 2012: B C Cobb Units 4, 5; and J R Whiting Units 1, 2, 3. This option is not feasible due to the limited time constraints and outstanding coal, rail-line, vessel and rail-car contracts."   [EPA-HQ-OAR-2009-0491-2697.1, p.12]
-Tampa Electric, in testimony at EPA's public hearings on the Proposed Rule in Philadelphia, observed that: "Just within our mid-sized electric generation fleet, a number of model input assumption errors have been identified. Examples of the type of errors include: allocating different emission budgets to identically sized and controlled units, or dispatching the same unit differently for estimated NOx and SO2 future emissions and consequential downwind effects."  [EPA-HQ-OAR-2009-0491-2697.1, p.12]
-Dominion Resources notes that EPA assumes the installation of a wet scrubber at the Brayton Point Power Station Unit 3 by 2012. Instead, under a state-approved Emission Control Plan, a dry scrubber will be installed on Brayton Point Unit 3 that will commence operation in 2014. The company also finds that EPA has not allocated NOx emissions to Salem Harbor Units 1 and 2 even through the IPM model for the base case 2012 run predicts these units will operate. [EPA-HQ-OAR-2009-0491-2697.1, p.12]  
Response: 
In response to concerns such as those expressed by the commenter, EPA has taken two actions for this final Transport Rule
1) It has updated its IPMv.4.10 model used in the final Transport Rule from that used in the proposed Transport Rule.  These updates capture and correct many of the unit level discrepancies highlighted by commenters.  For example, the IPM base case no longer assumes a scrubber at Muskingham River un 5 by 2011, instead it is projected to occur in 2014 and the timing is much more consistent with those installation dates imposed by consent decrees impacting the unit.  For a more detailed description of the IPM v.4.10 platform, assumptions, and updates to assumptions, see the IPMv.4.10 documentation.  Also, the "Transport Rule IPM Assumptions Response to Comments" in the Appendix further describes some of the unit level changes that were made.
2) EPA also finalized an allocation methodology that relies on historic data instead of projected data.  By relying on historic data, many of the comments that expresses concerns over the direct impact that IPM unit level projections had on their unit's allocation are addressed.  The final allocation methodology is based on historic data that is reported by the source's DR who has testified to its accuracy and completeness.
Organization: Edison Mission Energy (EME)
Comment: 
Edison Mission Energy (EME)
With respect to the first assumption, EPA states in the preamble that the reductions required during Phase I of the Transport Rule represent those NOx and SO2 emissions reductions that can be obtained using existing controls that are already in place and those controls that EPA believes will be installed and available by 2012. The Agency's assumption about the level of control that will be obtained by existing controls relies on unrealistic assumptions about the level of performance that can be obtained by those controls, calling into question the feasibility of meeting the Phase I cap (see Section III.B.1). [EPA-HQ-OAR-2009-0491-2707.1, p.17]
Response: 
EPA has modified its removal assumptions for existing controls.  See "Transport Rule IPM Assumptions Response to Comments" in Appendix for details on how existing FGD removal rates have been indexed to historic performance.  Furthermore, EPA does not believe that compliance with Transport Rule Budgets hinges on any one specific technology or compliance strategy, nor does it require one.  As discussed in section VII.C of the preamble, there are multiple compliance options available to sources to collectively comply with their state budget.
Organization: Entergy Services, Inc.
Comment: 
Entergy Services, Inc.
Entergy Supports The Integrated Planning Model (IPM) Results to Determine State Budgets, With Qualifications
Results from the IPM market simulation tool played a significant role in developing the budgets EPA has proposed for the Transport Rule.  As a result, the EPA's IPM input assumptions have a significant impact on the nature and stringency of the proposed Transport Rule.  One such key assumption is natural gas resources, as gas price projections have the potential to strongly affect the dispatch of generating units.  In the original Base Case (v3.02), natural gas input assumptions produced gas prices that differ considerably from forward market projections (used to represent an objective "industry view").  For example, Henry Hub gas prices average about $7.25/mmBtu from 2012-2015 in the original Base Case (v.3.02), whereas the current futures for that timeframe average approximately $5.75/mmBtu.  Entergy agrees with EPA's use of the IPM in determining the NOx emissions budgets of the affected states and believes that with the right assumptions, IPM adequately depicts future demand needs at regional and state levels.  However, Entergy encourages EPA to use the Energy Information Administration's Annual Energy Outlook natural gas resource forecast contained in v4.10_AEO Gas in the final rule, as these assumptions more accurately predict market futures based on current information.  [EPA-HQ-OAR-2009-0491-2847.1,p.2]
Response: 
EPA has made significant changes to its proposed IPM modeling.  These changes are reflected in the EPA IPM v.4.10 that was used for the final Transport Rule.  Among the updates made, natural gas input assumptions were modified from those used in the proposed modeling.  See EPA IPM v.4.10 documentation for more explanation on the final model, assumptions, and updates to assumptions.
Organization: Exxon Mobil Corporation
Comment: 
Exxon Mobil Corporation
EPA's original modeling, using the IPM version 3.02 for the Base Case, projected that Louisiana emissions may interfere with maintenance of the annual PM2.5 NAAQS in 2012, by contributing only 0.34 ug/m3 to the annual PM2.5 values at the Clinton Drive monitor in Houston, Harris Co., TX. Of that total, EPA projected that 0.33 ug/m3 is from sulfate emissions and only 0.004 ug/m3 from nitrate emissions. The projected design value for the Clinton Drive monitor in 2012 was 14.74 ug/m3 average and 15.14 ug/m3 maximum compared to the 15.0 NAAQS ug/m3. The 2008 PM2.5 annual average at Clinton Drive was 14.0 ug/m3, even when exceptional event days are included. The annual average PM2.5 in 2009 was only 12.8 ug/m35 and from January 1 through August 29, 2010, the average is 12.72 ug/m3. 6 The design value dropped to 14.4 ug/m3 for the 2007-2009 period and is expected to drop to a value of approximately 13.2 ug/m3 further this year due to 2007 dropping out of the 3-year average. 7 So, it is clear that Louisiana emissions now are not interfering with maintenance of the NAAQS in any way.
EPA also projected, under the IPM version 3.02 Base Case, that Louisiana emissions will significantly contribute to nonattainment with the 1997 8-hour ozone NAAQS at certain monitoring sites in the Houston-Galveston-Brazoria ('HGB') and the Dallas-Ft. Worth ('DFW') Areas of Texas in 2012. EPA has projected that Louisiana emissions will interfere with maintenance of that NAAQS at other monitoring sites in the HGB and the DFW Areas of Texas in 2012. But, again, real data cast doubt on these projections. All monitors in the HGB Area are currently in attainment with the 1997 8-hour ozone NAAQS and have been since 2008 (based upon the 2006-2008 monitoring data). All of the DFW monitors that EPA projected were adversely impacted by Louisiana emissions, save one, are also currently in attainment with that NAAQS. The design value at that one monitor at issue in DFW is 86 ppb, just 2 ppb above the standard.

6 Texas Commission on Environmental Quality, CAMS 403, PM-2.5 (Local Conditions) Acceptable Summary for 2010, http://www.tceq.state.tx.us/cgi-bin/compliance/monops/vearlv_summary.pl (last visited Sep. 21, 2010).
7 Texas Commission on Environmental Quality, PM2.5 Data: Soot, Dust, Particulate Matter, (last visited Oct. 1, 2010)
Response: 
EPA has updated its IPM modeling and EGU emissions inventories in response to comments on the IPM version 3.02 for the base case.  As a consequence, the base case EGU emissions for states have changed.  EPA conducted its final air quality modeling off the updated base case.  In the final Transport Rule, Louisiana is no longer subject to Transport Rule annual PM2.5 programs.  However, the updated IPM and air quality modeling indicate the state is still "linked" to Texas receptors sites at Brazoria and Harris for 8-hour ozone.  See section V.D of the preamble for more details.  Additionally, see IPM documentation,  "Documentation Supplement for EPA Base Case v.4.10_FTransport  -  Updates for Final Transport Rule" and "Transport Rule IPM Assumptions Response to Comments" for details regarding IPM updates and assumptions in the v.4.10 used in the final Transport Rule.
Organization: Florida Department of Environmental Protection
Comment: 
Florida Department of Environmental Protection
  The Division has reviewed the IPM model results that were used to generate the emissions for 2012 and 2014. Because the IPM model results do not appear to reflect actual Florida generation dispatch, the proposed allocations, especially for NOx, are very different than 2009 actual emissions, or what we anticipate emissions will be in 2012 and 2014. We were not able to actually replicate the NOx unit allocations and we would like to see an explicit accounting of these calculations to understand how they were derived. However, probably due to the combination of the use of the IPM model and incorrect current emissions, the NOx allocations seem to be random and will result in a great deal of intrastate trading to more closely align allocations with actual emissions in 2012. [EPA-HQ-OAR-2009-0491-2624.1, p.1]  
In reviewing Florida-specific source attribution, we are concerned that the emissions from Gulf Power's Crist facility were dramatically overestimated. For example, the NOx emissions were modeled at approximately twice the allowable federally enforceable limits. Since Florida's only linkage to downwind nonattainment of ozone is to Harris and Tarrant counties in Texas, it is critical that Gulf Power's emissions be accurately reflected in the modeling. In fact, since Florida's impact was 0.8 ppb, which is the threshold for significance, and the Crist facility is the furthest westward facility in Florida, it is possible Florida may have no significant impact if the correct emissions were modeled. [EPA-HQ-OAR-2009-0491-2624.1, p.1]
Response: 
EPA response to FL DEP is threefold
1) In response to concerns such as those expressed above, EPA has modified its allocation methodology to be based on historic data.  Furthermore, the approach chosen limits any units allocation to an amount less than or equal to its historic maximum emissions.  EPA is no longer relying on the IPM model, as it did in the proposal to determine allowance allocations
2) In response to these concerns, EPA has also updated its model.  As a result the 2012 and 2014 generation dispatch for the state have changed.  See "EPA's IPM Base Case v.4.10 documentation", "Documentation Supplement for EPA Base Case v.4.10_FTransport  -  Updates for Final Transport Rule", and "Transport Rule IPM Assumptions Response to Comments" for more details on updates to IPM.
3) In regards to the NOx emissions modeled for the Crist facility, EPA has made a series of updates that are covered in the sources documented above.  The final TR base case has emissions for the Crist facility that are significantly less than those in the proposal.  The air quality modeling for the final rule was conducted on these updated model values.
Organization: Florida Municipal Electric Association (FMEA)
Comment: 
Florida Municipal Electric Association (FMEA)
EPA Must Give Affected Sources an Opportunity to Participate in Additional Modeling Before the Rule Is Finalized. FMEA members have noticed multiple errors in EPA's "Unit Characteristic" spreadsheet and other spreadsheets which were utilized to base future reductions per this rulemaking, e.g., unit pollution control equipment in place and operating. In some cases, the pollution control device which is not listed in the spreadsheet has been installed for multiple years and is required to operate in order to meet State permit specific emission limits. [EPA-HQ-OAR-2009-0491-2731.1, p. 9]
As stated above, FMEA members will be sending comments on an entity-specific basis regarding the needed changes to EPA during this comment period. FMEA, however, is concerned that it will be deprived of an opportunity to comment after EPA makes the necessary corrections to their dataset. In sum, EPA will need to perform additional modeling and calculations after corrections have been made to many regulated units, and such changes will be substantial enough to warrant an additional notice and comment period. The correction of these extensive errors will necessarily change the compliance obligations of every state, company and unit, and affected parties must be given an opportunity to review and comment as to whether EPA has corrected its mistakes, and parties can meet their new compliance obligations. [EPA-HQ-OAR-2009-0491-2731.1, p. 9]
EPA modeling for determining significant interstate transport may be flawed: FMEA is concerned that the modeling done to determine an upwind state's significant contribution to a downwind state's non-attainment with a NAAQS may be flawed. Further, it is not appropriate to model EGU emissions based on pre-CAIR 2005 emissions. Since the CAIR reductions for many states, including Florida, may be real and enforceable under existing state permits, it is incorrect to model state impacts based on pre-CAIR emissions. [EPA-HQ-OAR-2009-0491-2731.1, pp. 9-10]
Response: 
EPA issued updated modeling (EPA IPMv.4.10) and gave commenters a chance to review and comment on the data in its September 1, 2010 NODA.  EPA reviewed comments submitted and updated the modeling based on new input received from stakeholders.  EPA used the updated modeling in its final Transport Rule modeling to determine the appropriate Transport Rule Geography.  See section V of the preamble.  The preamble also discusses why CAIR was not included in the base case modeling.  In regards to reductions that are enforceable because of existing permit rates, those are reflected in the base case modeling and EPA made updates to this field indicator based on comments.
Organization: Kansas Department of Health and Environment
Kansas City Power and Light Company (KCP&L)
Comment: 
Kansas City Power and Light Company (KCP&L)
1. There are errors in the unit information contained in the NEEDS Version 3.02 database.
a. Iatan Unit 1 (ID 6065_B_1)  -  The wet scrubber and SCR are not included. The PM control is incorrectly specified as an ESPC; it should be a baghouse. The wet scrubber, SCR, and baghouse became operational in Q1 2009. The SO2 permit rate should be 0.07 lb/mmBtu, per the current Title V operating permit, instead of 1.2 lb/MmBtu.
b. Lake Road Unit 6 (ID 2098_B_6)  -  The SO2 permit rate should be 1.43 lb/mmBtu, per the current Title V operating permit, instead of 8.6 lb/mmBtu.
c. Sibley Units 1 and 2 (ID 2094_B_1 and 2094_B_2)  -  SNCR is not included as post-combustion NOx control. The SNCR systems came online in Q2 2008.
d. Sibley Unit 3 (ID 2094_B_3)  -  The SCR is not included as post-combustion NOx control. The SCR came online in Q1 2009.
e. Iatan Unit 2 is not included in the database. [EPA-HQ-OAR-2009-0491-2709.1, p.5]
3. There are errors in the IPM 2012 Base model data.
a. The La Cygne Unit 1 NOx emission rate in the IPM 2012 Base model of 0.06 lb/mmBtu is incorrect. Correction of the Mode 4 rate to 0.094 lb/mmBtu, as discussed in 2.d.iv(1) above will resolve this inconsistency. However, modeling a rate based on the assumption that every SCR can achieve 90% control is not appropriate and represents a flaw in EPA's methodology. The SCR on this unit was designed to achieve the reductions necessary for compliance with its BACT-based construction permit limit of 0.15 lb/mmBtu. The IPM base case would yield more relevant results if units were modeled at their permitted emission rates, rather than an unachievable rate based either on 90% reduction or a floor of 0.06 lb/mmBtu. [EPA-HQ-OAR-2009-0491-2709.1, p.9][EPA-HQ-OAR-2009-0491-3757.1_NODA,p.5]
Comments Iatan Unit 2
Iatan Unit 2 is not included in the NEEDS 3.02 database. It may be represented by facility "SPPN_MO_Coal Steam" (ID 82710_B_1), but it is not clear what the data are based on. Because it is not included in the NEEDS 3.02 database, it did not receive any emissions allowances under the proposed rule. [EPA-HQ-OAR-2009-0491-2709.1, p.10]
The NEEDS v.4.10 database does not contain Iatan Unit 2 as an individual unit. According to the Documentation for EPA Base Case v.4.10, any units online or scheduled to come online between 2007 and the end of 2011 should be included as planned-committed units. While it is assumed Unit 2 is included in the aggregated record with similar units, it is not possible to verify any of its model input data. It can also only be assumed that Unit 2 will receive emissions allowances under the final rule; however it is not clear how planned-committed units will be able to verify the calculation of unit-level allowances. [EPA-HQ-OAR-2009-0491-2709.1, p.10][EPA-HQ-OAR-2009-0491-3757.1_NODA,p.6]
Details of Iatan Unit 2 are provided below.
- Iatan Unit 2 has a heat input capacity of 8,100 mmBtu/hr with a nominal gross generation capacity of 930 MW firing subbituminous coal. It includes an SCR, wet scrubber, baghouse, and ACI injection for mercury control.
- Construction permit issued January 31, 2006
- Acid Rain Program Permit Amendment filed to include Iatan Unit 2 on April 18, 2008. On June 16, 2009 the renewal of the Iatan Acid Rain Program five-year permit was filed, which included Unit 2 as "under construction".
- A Title V Operating Permit amendment application to include Unit 2 was filed on September 30, 2009.
- On February 3, 2010, the MDNR issued an Acid Rain Program Permit that included Unit 2 as "under construction". [EPA-HQ-OAR-2009-0491-2709.1, p.10][EPA-HQ-OAR-2009-0491-3757.1_NODA,pp.6-7]
- Unit 2 achieved start-up on July 20, 2010. The EPA and MDNR were notified of this by a letter dated July 23, 2010. [EPA-HQ-OAR-2009-0491-2709.1, p.11] [EPA-HQ-OAR-2009-0491-3757.1_NODA, p.7]
Kansas Department of Health and Environment
KDHE has compared the projected 2012 emissions estimates with actual emissions for our EGU sector. Figures 2 and 3 provide comparisons of recent actual emissions at the unit level with EPA 2012 estimates for NOx and SO2, respectively. These comparisons were made with the original IPM estimates. We have left the original IPM numbers in, since it is unclear how these NODA revisions will impact final allocations. Appendix A contains tables comparing historic unit level emissions with projected IPM emissions and proposed allocations. [EPA-HQ-OAR-2009-0491-2606.1, p.2] [[See Docket Number EPA-HQ-OAR-2009-0491-2606.1, pp.9-11 for Appendix A.]]
For NOx, Figure 2 clearly indicates the projected 2012 emissions are much higher than recent historic actual emissions. This is an indication that the 2012 IPM estimates don't accurately reflect control equipment installed on Kansas EGUs. [EPA-HQ-OAR-2009-0491-2606.1, p.2] [[See Docket Number EPA-HQ-OAR-2009-0491-2606.1, p.3 for Figure 2.]]
For SO2, Figure 3 indicates the recent actual SO2 emissions are very close to the future IPM emissions. While the future SO2 estimates appear close to likely actual emissions, a detailed unit-level look at the future emissions estimates indicates that further reductions need to be accounted for. These reductions are discussed in detail below with KDHE recommendations. [EPA-HQ-OAR-2009-0491-2606.1, p.3] [[See Docket Number EPA-HQ-OAR-2009-0491-2606.1, p.3 for Figure 3.]]
Based on these comparisons, KDHE believes several significant differences in the 2012 emissions estimates EPA is using will result in an overestimate of our modeled contribution to downwind nonattainment areas. These overestimates may be large enough that if corrected would remove Kansas from the list of ozone-contributing states. Specifically, the 2012 NOx estimates for KCP&L's La Cygne Unit 1 were too high in the original version of the IPM run and did not account for the SCR that is currently installed and operating on this unit. This appears to have been corrected in the latest version of the IPM run, possibly even being overcorrected. In addition, 2012 emission estimates for Westar Energy's Jeffrey Units 1-3 do not take into account the recent consent decree this company entered into with the United States Department of Justice (USDOJ) that will require NOx and SO2 reductions by 2012. This problem appears in both IPM runs. [EPA-HQ-OAR-2009-0491-2606.1, p.4]
La Cygne Unit 1 currently has a 2009 Clean Air Markets Division (CAMD) annual NOx rate of 0.11 lb/mmBtu. This is also the average rate for two years of actual operations with its SCR in operation. KDHE recommends for purposes of modeling that the 2009 average NOx rate of 0.11 lb/mmBtu be used in conjunction with the projected 2012 IPM heat input to estimate the emissions for La Cygne Unit 1 in 2012. KDHE believes this rate will be reflective of future operations for this control equipment. This recommended 0.11 lb/mmBtu rate is higher than the latest IPM rate of 0.06 lb/mmBtu, which appears to KDHE to be too optimistic based on historic operations of the SCR. La Cygne Unit 1 is required to continually operate this SCR for NOx control. The requirement for this unit to operate the SCR is included in a state construction permit issued by KDHE on November 18,2005. This permit limits this unit to 0.15 lb/mmBtu annually for NOx emissions. This permit condition will continue to apply in 2012 and thereafter. In addition to the construction permit, KCP&L has signed an agreement incorporating the 0.15 lb/mmBtu limit that will be submitted to Region 7 for incorporation in the Kansas State Implementation Plan (SIP) in the near future. This agreement is intended to ensure 'SIP enforceable' limits. The limits for the two coal-fired units at this facility will be further strengthened with upcoming BART controls as part of the Regional Haze Program, once approved by EPA. These BART control requirements will occur after the 2012 timeframe, however. The SCR construction permit and agreement for La Cygne Unit 1 is included in Appendix B. [EPA-HQ-OAR-2009-0491-2606.1][EPA-HQ-OAR-2009-0491-2606.1, p.4] [[See Docket Number EPA-HQ-OAR-2009-0491-2606.1, pp.12-16 for Appendix B.]]
For Jeffrey Units 1-3, a consent decree between the USDOJ and Westar Energy went into effect on March 26th , 2010, that requires substantial reductions in both NOx and SO2. For NOx the consent decree requires a 30-day rolling average unit emission rate for NOx of no greater than 0.180 lb/mmBtu beginning on December 31, 2011, and continuing thereafter. This rate applies to all three units at all times of the year. The new IPM runs and 2009 CAMD rates should therefore reflect emissions for Unit 3 with controls. However, the 2009 rates for Units 1 and 2 do not yet reflect the limits that will be required on these units by 2012. [EPA-HQ-OAR-2009-0491-2606.1, p.4]
KDHE recommends using the average 2010 CAMD emission rates of Units 1 and 3 for a proxy of the 2012 emission rate of Unit 2. For Unit 1 we recommend using the 2010 CAMD average rate. We make these recommendations based on the similar characteristics of the units' design and controls and the fact that all three units are subject to the same limits in the consent decree. Because these controls have just recently been installed, 2010 CAMD data is a more accurate estimate of future emission rates for Unit 1. Unit 2 does not currently have the controls to meet the limit but will by 2012, thus the average of like unit rates with controls should be a good estimate for this unit. At a minimum, Unit 2 should not be modeled higher than the consent decree limit of 0.18 lb/mmBtu. [EPA-HQ-OAR-2009-0491-2606.1, pp.4-5]
For SO2 at Jeffrey, the consent decree limits the three Jeffrey units to 6,600 tons total SO2 on a rolling 12-month basis. The agreement also limits the units to 0.07 lb/mmBtu SO2. These units all recently had scrubber rebuilds and all units are now operating with scrubbers. KDHE recommends that 2009 CAMD SO2 emission rates for Units 1 and 3 be used to reflect 2012 emission rates. For Unit 2, KDHE recommends the average emission rate in 2010 be used as this unit's flue gas desulfurization was not operational until 2009. [EPA-HQ-OAR-2009-0491-2606.1, p.5]
The Westar Energy consent decree can be found at: http://www.epa. gov/compliance/resources/decrees/civil/caa/westarenergy-cd.pdf.  [EPA-HQ-OAR-2009-0491-2606.1, p.5]
Emissions from EGUs in the Kansas City area are subject to a Kansas NOx emissions reduction rule, K.A.R. 28-19-713a. This rule will impact the emissions of two units in the Kansas City area. The units are Kansas City BPU's Nearman Creek Unit 1 (N1) and BPU Quindaro Unit 2 (Q2). The rule limit requirements are identified below. [EPA-HQ-OAR-2009-0491-2606.1, p.5]
28-19-713a. Emission limitation requirements. No owner or operator subject to K.A.R. 28-19-713 shall allow any emission unit to emit nitrogen oxides in excess of the following emission limitations based on a 30-day rolling average: (a) From electric generating units, for the purposes of K.A.R. 28-19-713 through K.A.R. 28-19-713d, the following: (l) 0.26 pounds per million British thermal units (lbs/ mmBtu) for unit 1, a turbo wall-fired Riley Stoker boiler located at the Nearman Creek power station in Kansas City, Kansas; and (2) 0.20 lbs/mmBtu for unit 2, a wall-fired Riley Stoker boiler located at the Quindaro power station in Kansas City, Kansas; and (b) from flat glass furnaces, 7.0 pounds per ton of glass produced. (Authorized by K.S.A. 2009 Supp. 65-3005; implementing K.S.A. 65-3010; effective June 25, 2010.) [EPA-HQ-OAR-2009-0491-2606.1, p.5]
In the original IPM runs N1 had an emission rate of 0.46 lb/mmBtu, while in the new version of IPM the rate is 0.441 lb/mmBtu. Both of these rates are higher than permitted in the rule above. Q2 has an emission rate of 0.304 lb/mmBtu in the original IPM run, while the new IPM run has a rate of 0.281 lb/mmBtu. Both of these rates are higher than permitted in the rule above. KDHE recommends a rate of0.26 lb/MmBtu for N1 and a rate of 0.20 lb/MmBtu for Q2 for the 2012 modeling. Using total heat input values in the new 2012 IPM runs of 13,801,240 MmBtu for N1 and 7,146,396 MmBtu for Q2 gives emissions reductions of 1290 tons and 289 tons, respectively. While the N1 reductions are not required by Jan 1, 2012, they will come into effect during the 2012 ozone season and KDHE believes they should be accounted for. [EPA-HQ-OAR-2009-0491-2606.1, p.5]
IPM modeling and cost curves appear to give unrealistic results for Kansas. One example is Table 1-1 in the TSD for significant contribution. This table indicates that, according to IPM modeling, annual NOx emissions from the Kansas EGU sector would be 33,000 tons (a decrease of 37,915 tons from the assumed 2012 base case without controls) if a marginal control cost of $500/ton is applied across the state. This large decrease seems very suspect using a $500/ton marginal cost, however, since as marginal control costs are increased (i.e., there is more spending on controls), the projected annual emissions increase rather than decrease in Kansas. If Kansas EGUs can get to 33,000 tons of reductions at a marginal cost of $500/ton, at a minimum they will also get to 33,000 tons of reductions (presumably even more reductions) at a marginal cost of $1,250/ton. To have the modeled emissions increase at a marginal control cost 2.5 times higher seems unlikely even when accounting for system-wide costs and demand. Perhaps these emission results can be explained by additional load being exported out of state under the higher control cost scenarios. If this is the case, it should be included so readers can better understand these results. At a minimum, this counterintuitive result of emissions increasing with increasing marginal costs of controls needs to be better described. [EPA-HQ-OAR-2009-0491-2606.1, p.7]
Response: 
EPA carefully reviewed and updated its IPM modeling based on unit specific comments for these sources as well as broader modeling assumptions (i.e., state rules, consent decrees) based on comments provided.  It then used the updated EPA IPMv.4.10 modeling to analyze contribution to nonattainment and interference with maintenance, see section V of the preamble for a discussion of the air quality modeling results.  EPA updated its model to reflect unit specific comments - for example the SCR and SNCRs at the Sibley units are reflected in the updated 4.10 model version.  EPA also updated its constraints to reflect the Westar Consent Decree and the Kansas Rule K.A.R. 28-19-713a.
In regards to an observed emissions increase at higher cost thresholds, EPA notes that SO2 emissions in this final rule are only examined at the $500/ton cost threshold level.  Examination of higher SO2 cost thresholds for the state is not necessary because Kansas is a Group 2 state and its significant contribution to nonattainment and interference with maintenance is eliminated at this cost threshold.  Therefore, in this final rule, there are no emission results from higher SO2 cost thresholds for the state of Kansas to which the $500/ton cost thresholds emission levels would be compared to.  However, it is worth noting that the final cost curves reflect the appropriate cost thresholds for all covered states and covered pollutants simultaneously to best reflect how industry faces the cost and compliance requirement simultaneously.  As cost thresholds increase in Group 1 states, but stay constant in Group 2 states - there can be some generation re-balancing in the model optimization that results in an emissions increase in a Group 2 state.  This occurs because the generating resources in those states become more cost competitive relative to generating resources in Group 1 states with increasing cost thresholds.  Even as cost thresholds increase equally among of group of states, there may still be some generation shifting as low emission-rate sources in one state become increasingly cost competitive to higher emission-rate sources in another state.  Therefore, EPA notes that, while not common, it is possible to observe slightly higher emissions in a particular state at a higher cost threshold.
Organization: Louisiana Chemical Association (LCA)
Comment: 
Louisiana Chemical Association (LCA)
3. Further, we believe that other errors were made in EPA's modeled projections of operating scenarios for various units. [EPA-HQ-OAR-2009-0491-1925.1, p. 2]
Failure to Include Reductions from Louisiana NOx RACT EPA failed to include NOx emission reductions that occurred in 2005 and since 2005 as a result of the LDEQ NOx RACT rule in LAC 33:III.Chapter 22 and reductions due to amendments to that rule. In the documentation of IPM v. 3.02, there is no mention of this rule at all. [EPA-HQ-OAR-2009-0491-3527.1, p. 27; see pp. 27-29 for extensive discussion of this issue.]
EPA's original modeling, using the IPM version 3.02 for the Base Case, projected that Louisiana emissions may interfere with maintenance of the annual PM2.5 NAAQS in 2012, by contributing only 0.34 ug/m3 to the annual PM2.5 values at the Clinton Drive monitor in Houston, Harris Co., TX. Of that total, EPA projected that 0.33 ug/m3 is from sulfate emissions and only 0.004 ug/m3 from nitrate emissions. The projected design value for the Clinton Drive monitor in 2012 was 14.74 ug/m3 average and 15.14 ug/m3 maximum compared to the 15.0 NAAQS ug/m3. The 2008 PM2.5 annual average at Clinton Drive was 14.0 btg/m3, even when exceptional event days are included. The annual average PM2.5 in 2009 was only 12.8 ug/m3 and from January 1 through August 29, 2010, the average is 12.72 ug/m3. 8 The design value dropped to 14.4 ug/m; for the 2007-2009 period and is expected to drop to a value of approximately 13.2 ug/m3 further this year due to 2007 dropping out of the 3-year average. 9 So, it is clear that Louisiana emissions now are not interfering with maintenance of the NAAQS in any way These Louisiana emissions are projected by EPA to drop even farther without the CATR/FIP. [EPA-HQ-OAR-2009-0491-3790.1_NODA, pp.2-3]
EPA also projected, under the IPM version 3.02 Base Case, that Louisiana emissions will significantly contribute to nonattaimnent with the 1997 8-hour ozone NAAQS at certain monitoring sites in the Houston-Galveston-Brazoria ('HOB') and the Dallas-Ft. Worth ('DFW') Areas of Texas in 2012. EPA has projected that Louisiana emissions will interfere with maintenance of that NAAQS at other monitoring sites in the HOB and the DFW Areas of Texas in 2012. But, again, real data cast doubt on these projections. All monitors in the HGB Area are currently in attainment with the 1997 8-hour ozone NAAQS and have been since 2008 (based upon the 2006-2008 monitoring data). All of the DFW monitors that EPA projected were adversely impacted by Louisiana emissions, save one, are also currently in attainment with that NAAQS. The design value at that one monitor at issue in DFW is 86 ppb, just 2 ppb above the standard. [EPA-HQ-OAR-2009-0491-3790.1_NODA, p.3]

8 Texas Commission on Environmental Quality, CAMS 403, PM-2.5 (Local Conditions) Acceptable Summary for 2010, http://www.tceq.state.tx.us/cgi-bin/compliance/monops/yearly_summarv.pl (last visited Sep. 21, 2010).
9 Texas Commission on Environmental Quality, PM2.5 Data: Soot, Dust, Particulate Matter, (last visited Oct. 1, 2010).
Response: 
EPA has updated its IPM modeling and EGU emissions inventories in response to comments on the IPM version 3.02 for the base case.  As a consequence, the base case EGU emissions for states have changed.  EPA conducted its final air quality modeling off the updated base case.  In the final Transport Rule, Louisiana is no longer subject to Transport Rule annual PM2.5 programs.  However, the updated IPM and air quality modeling indicate the state is still "linked" to Texas receptors sites at Brazoria and Harris for 8-hour ozone.  See section V.D of the preamble for more details.  Additionally, see IPM documentation,  "Documentation Supplement for EPA Base Case v.4.10_FTransport  -  Updates for Final Transport Rule" and "Transport Rule IPM Assumptions Response to Comments" for details regarding IPM updates and assumptions in the v.4.10 used in the final Transport Rule.  Also, EPA notes that the 2012 base case used in air quality modeling represents power sector operations in the absence of CAIR.  Both the proposal and final rule preamble explain why this is necessary.  Therefore, comments suggesting that 2012 base case emissions data and receptor status in the final Transport Rule are incorrect simply because they do not reflect recent emissions data and receptor status observed once the CAIR rule was final are misguided, as EPA has clearly stated that the base case represents a world without CAIR.
Organization: Massachusetts Department of Environmental Protection
Comment: 
Massachusetts Department of Environmental Protection
We encourage EPA to rigorously review the input files and assertions made in several technical support documents found in the proposed Transport Rule regulatory docket that appear to need additional quality assurance of internal and external data sources. MassDEP and other OTC member states collaborated in the review of IPM documentation, including the Technical Support Document, Updates to EPA Base Case v3.02 EISA Using the Integrated Planning Model, and other materials and found common concerns and issues. A number of Massachusetts facilities have indicated that they have concerns with the quality and accuracy of the technical support documentation that mirror those of MassDEP and other states.
In addition to questions related to data accuracy, we have concerns about the assumptions in the IPM input files and documentation and, as a consequence, with the IPM outcomes. MassDEP, like other States, is concerned with the lack of transparency in the proprietary IPM and its anomalous modeling results. 17 For example, under the proposed Transport Rule allocations, the Massachusetts residual oil-and natural gas-fired steam (oil/gas steam) units receive no allocations of S02 allowances (although the same units do receive NOx allocations). We believe that certain assumptions built into the IPM analysis are contributing to a bias in the S02 allocation that favors the coal-fired units in Massachusetts. We urge EPA to closely review recent trends in the capacity factors and dispatch trends of regional transmission organizations for certain plant types, particularly oil/gas steam units and gas/oil combined cycle units in ensure that the appropriate units are being allocated allowances.
We note IPM technical documentation identifies 'turndown assumptions that prevent coal and oil/gas steam units from operating strictly as peaking units, which would be inconsistent with their operating capabilities.' 1 8 While the original operational parameters for these oil/gas steam units did not contemplate their utilization as peaking units, operators have responded to changing market conditions. Examining peak demand episodes between 2005 and 2008 in New England, ISO-NE has observed an increased utilization of oil/gas steam units in the dispatch of the last 500 MW decrement during high energy demand episodes. 19 In Massachusetts and other New England States, oil/gas steam units are being utilized as peaking assets during high energy demand episodes; this contradicts the IPM turndown assumptions that prohibit modeling of these market conditions.
We urge EPA to more closely review actual operational behavior of individual plant type units in regional power pools rather than relying so heavily on the IPM macro assumptions, which do not incorporate evolving market conditions in projecting future operations. IPM assumptions, inventories, and output results should be re-examined so that Massachusetts final budget for S02 and NOx reflect the continued operation of, and emissions from, oil/gas steam and gas/oil combined cycle units. We believe the present IPM output results are inconsistent with existing and projected market trends that I80-NE considers most likely in their regional system reliability planning.
We understand that the IPM treatment of combined cycle units reflects an allocation methodology based upon historical heat input and multiplying that against the S02 pipeline natural gas emission factor of 0.0006 lb/mmBtu. Since the IPM module builds out the model combined cycle units across the four quarters, and S02emissions are between 2-4 tons for the largest combined cycle units in Massachusetts, IPM appears to be calculating quarterly emissions at less than 0.5 tons and then rounding down to 0 tons. Hence the units are allocated zero 802 allowances. EPA should modify the application of the rounding convention to extremely low emitting base-load and intermediate-load following combined cycle units to allow rounding up to a level that will reflect the historical emissions level on an adjusting three-year rolling average.
Response: 
EPA has made substantial updates to the IPM v.3.02 modeling used in the proposal.  The final EPA IPMv.4.10 modeling reflects updates to unit level and macro level assumptions.  See EPA IPMv.4.10 documentation for further details.  In addition, EPA notes that it changed its allocation methodology from one based on projected data to one based on historic data.  This, in concert with the IPM modeling updates, address many of the concerns expressed above.  Additionally, EPA notes that Massachusetts is not covered under the final Transport Rule geography.
Organization: Minnesota Power 
Comment: 
Minnesota emission reductions.  Minnesota utility sources are already providing for SO2 and NOx reductions under the Northeast Minnesota Regional Emission Reduction Program filed as part of Minnesota's Regional Haze State Implementation Plan (SIP) currently before EPA for approval.  These emission reductions combine with the effect of the Minnesota Renewable Energy Performance Standard which requires delivery of up to 25% of Minnesota retail energy sales from qualifying renewable energy resources by 2025.  Collectively, these Minnesota initiated measures are delivering reductions in emissions comparable to the EPA Transport Rule Group 2 State requirements.  The impact from both state and regional renewable energy performance standards should be included in EPA's modeling analysis and it is not clear from review of EPA technical support documentation that the effects of state mandated renewable energy have been included.    [EPA-HQ-OAR-2009-0491-2750.1, p.8]
Response: 
In EPA Base Case modeling, the state Renewable Portfolio Standards (RPS) are represented at a regional level utilizing the aggregate regional representation of RPS requirements that is implemented in AEO 2010, as shown in Appendix 3-6.  This appendix shows the RPS requirements that apply to the NEMS (National Energy Modeling System) regions used in AEO. The RPS requirement for a particular NEMS region applies to all IPM regions that are predominantly contained in that NEMS region.
Organization: National Grid
Allegheny Energy
Tennessee Valley Authority (TVA)
Council of Industrial Boiler Owners (CIBO)
Dayton Power and Light Company (DP&L)
Consolidated Edison Company of New York, Inc, (CECONY)
Wabash Valley Power
Utility Air Regulatory Group (UARG)
NextEra Energy, Inc.
RRI Energy, Inc.
First Energy
Progress Energy Service Company
Kentucky Chamber of Commerce
Comment: 
Allegheny Energy
Two errors, covering multiple AE stations, in the IPM results are identified below:
1] Two units at AE's Fort Martin power station in West Virginia and one unit at the Hatfield's Ferry power station in Pennsylvania have SNCR listed as control devices with an assumed year-round 35% removal efficiency. These SNCR's are single point injection (identified as SNCR-trim) that are only capable of 10% to possibly 15% reductions.
2) Year round selective catalytic reduction (SCR) controls are assumed at AE's Harrison and Pleasants power stations located in West Virginia at NOx rates (as low as 0.04 - 0.05 lb/mmBtu) that were established during the first few years of operation during the ozone season (May 1 to September 30) only. Subsequently, AE has found that these NOx rates cannot be sustained during year round operation as the catalyst ages and operational anomalies arise. In fact, AE's experience indicates that annual NOx rates on the order of 0.09 - 0.11 lb/mmBtu are more realistically achievable for year round SCR operation. [EPA-HQ-OAR-2009-0491-2605.1, p.5]
Three discrepancies in IPM's results are identified below:
1] The IPM results presume scrubbers on two units at AE's Armstrong power station in Pennsylvania and one unit at Willow Island in West Virginia. For the record, AE does not currently have plans to install scrubbers on these stations by 2014.
2] The IPM results retire AE's Rivesville power station's two units and one unit at Willow Island power station, both located in West Virginia, by 2014. For the record, AE has no current plans to retire these units by that date.
3] Fuel switches are assumed in the IPM results at three units at AE's Albright power station in West Virginia and two units at AE's R. Paul Smith power station located in Maryland before 2014. For the record, AE has no current plans to make fuel switches at these units by that date. [EPA-HQ-OAR-2009-0491-2605.1, p.5]
Consolidated Edison Company of New York, Inc, (CECONY)
Recommended Changes to 'Parsed File_TR Base Case_2012'
The Company understands that the data file entitled 'Parsed File TR Base_ Case_2012' (hereinafter, 'Base Case file') is intended to represent the IPM model's projection of which units within the United State's electrical system are likely to run in the first year of the proposed rule's applicability, 2012. The output is provided on both an ozone season basis and an annual basis. In the comments below, the Company presents a data element from the Base Case file, and offers an alternative outcome. The reasons supporting the alternative outcome are provided with each item. [EPA-HQ-OAR-2009-0491-2653.1, p.8; See EPA-HQ-OAR-2009-0491-2653.1, pp.8-1 for comments pertaining to Recommended Changes to 'Parsed File_TR Base Case_2012; See EPA-HQ-OAR-2009-0491-2653.1, pp.8-11 for tables: Data Issue No. B-1 (ozone season) fuel use, Data Issue No. B-2: Total Fuel Use, Data Issue No. B-3: Summer (ozone season) NOx Emissions, Data Issue No. B-4: Total NOx Emissions, and Data Issue No. B-5: Total SO2 Emission (MTon]
Recommended Changes to 'Parsed File_TR SB Limited TradinV014'
Data Issue No. C-l: All Columns Identified in Section B The Company notes that the incorrect modeling assumptions that led to inappropriate results for the output file described in Section B (above) are also incorrect in this output file. Specifically, Summer Fuel Use (column U), Total Fuel Use (column V), Summer NOx Emission (column AC), Total NOx Emission (column AD), Total C02 Emission (column AF) and Total Mercury Emission (column AG) have all be incorrectly characterized or calculated. [EPA-HQ-OAR-2009-0491-2653.1, p.11]
Council of Industrial Boiler Owners (CIBO)
Many other concerns are raised by EPA's analysis including: [EPA-HQ-OAR-2009-0491-2751.1 p.9; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, p.5, 10/15/2010]
The IPM Model does not account for past operating experiences and represents a snapshot in time.  these comments also appeared in [EPA-HQ-OAR-2009-0491-2751.1 p.9; EPA-HQ-OAR-2009-0491-3754.1_NODA, p.5, 10/15/2010]
The assumptions made and inputted by EPA determine winners and losers. EPA should be tying the facilities' heat input to historical operation and historical heat inputs. EPA's approach provides units that EPA is determining to be losers (lower availability and lower total heat inputs) and provides others with higher availability and higher heat inputs. The result is the facility receives its allowances based on the heat input. This does not provide the opportunity for those facilities based on past operating conditions a chance to make independent economic decisions to run.  [EPA-HQ-OAR-2009-0491-2751.1 p.9; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, p.5, 10/15/2010]
EPA has tied the model to electric output, but there are numerous cases where plants continue to operate and supply VARS rather than MWs. Also, the model does not account for contracts for energy, capacity, Renewable Energy Credits, or cogeneration contracts to supply heat and steam or other financial obligations.  [EPA-HQ-OAR-2009-0491-2751.1 p.9; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, p.5, 10/15/2010]
The NEEDs data bases (used for v3.02 and v4.10 of the IPM Model runs) are significantly different. One area of this difference is tied to the facilities' heat rate. Lowering the heat rate (as occurs for some plants in comparing v3.02 and v4.10 data) leads to lower total heat input and will most likely result in lower allowances for these plants. The availability information prepared by EPA does not recognize plants that may have had extended forced outages, resulting in EPA lowering the normal availability rates for some plants below their typical historical availability.  [EPA-HQ-OAR-2009-0491-2751.1 p.9; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, pp.5-6, 10/15/2010]
There are numerous factors regarding dispatch. Fuel costs and fuel supply curves specifically for waste coal are inaccurate and not reflective of the fuels costs for waste coal plants. Further, States divided into different model regions further complicates the issues dealing with projecting future operations and thus increased heat inputs.  [EPA-HQ-OAR-2009-0491-2751.1 p.9; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, p.6, 10/15/2010]
EPA's failure to consider the impact on units that must meet contractual or other obligations is significant. Some units must supply VARS (Volt  - Amps-Reactive) to maintain grid reliability rather than actual energy in MWs. Long runs of conductors and many industrial motor loads tend to resist actual power flow. This condition is called Inductive Reactance and generally makes current flow lag voltage. This condition increases as the distance from the generation site increases. To counteract this effect, distributed generation units in remote areas often produce both MWs and VARs.  Doing so inhibits the actual MW output of the facility, but restores the quality of the grid system. The current rule does not recognize this reality, basing analysis entirely on MW loading. [EPA-HQ-OAR-2009-0491-2751.1 p.10; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, p.6, 10/15/2010]
Many small generation units are PURPA plants that operate under a long term contract. The contracts normally include a requirement that each year, peak generation must be at least a high percentage of the last three year average peak generation, or the facility may be charged a fee as well as the cost of any replacement power. Currently in Pennsylvania, waste coal power is a Tier II source and has RECs associated with those operations that are owned by the Transmission and Distribution company that purchases the power. T & D companies are required to produce various amounts of alternate energy annually, or purchase credits. If all waste coal generation is capped through inaccurate heat input data, they will not be able to obtain these credits as the credits will not be created. [EPA-HQ-OAR-2009-0491-2751.1 p.10; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, p.6, 10/15/2010]
EPA's analysis reflects no consideration and accommodation of these critical elements and is therefore not rational. [EPA-HQ-OAR-2009-0491-2751.1 p.10; these comments also appeared in EPA-HQ-OAR-2009-0491-3754.1_NODA, p.6, 10/15/2010]]
Dayton Power and Light Company (DP&L)
Necessary Corrections Should Be Made
DP&L appreciates and commends the EPA for requesting that utilities provide it with any incorrect assumptions that EPA is using in the modeling associated with this proposal. Although DP&L is not aware of all the assumptions used by EPA, the following items have been identified for correction: [EPA-HQ-OAR-2009-0491-2637.1, p. 7]
1. The EPA proposal appears to be based on the assumption that DP&L's Stuart and Killen Stations are capable of burning sub-bituminous coal. Please note that combustion of sub-bituminous coal would violate the Title V permits for Stuart and Killen Stations, which specify the use of bituminous coal. Additionally, these stations have a 25+ year history of burning only bituminous coal, DP&L has no operating experience with subbituminous coal. DP&L has no plans to burn sub-bituminous coal. Accordingly, the EPA model should be adjusted to the extent it includes an erroneous assumption that Killen or Stuart Stations have the option to burn sub-bituminous coal. [EPA-HQ-OAR-2009-0491-2637.1, p. 7]
2. The EPA IPM model appears to include an assumption that DP&L's Stuart and Killen Stations can shift coal sourcing from higher sulfur coals to lower sulfur coals without incurring additional cost. Cost differentials between coal regions are substantial and widely recognized. For example, the price spread between Central Appalachian coals and Illinois Basin coals has averaged $16/ton over the past five years (and generally in the range of $1 0-$20/ton when the highly volatile 2008 history is excluded). There is nothing in the past, present or future market prices for CAPP and ILB to support a belief that differences in their costs are minimal or likely to shrink. DP&L notes these additional facts can be verified from utility FERC reports and data available from the Energy Information Administration. A shift of coal sourcing at DP&L could have a financial impact approaching $50 million per year. EPA's model should be adjusted to reflect an appropriate level of change in costs. [EPA-HQ-OAR-2009-0491-2637.1, p. 7]
3. EPA assumptions appear to include that FODs are capable of an S02 removal rate of 95% on a sustained basis. In reality, the removal rate varies. Bypassing is occasionally required, start-up has lower efficiencies, malfunctions occur, and other factors result in an annual average removal rate that may be lower than the 95% level assumed by EPA. It is inappropriate for EPA to model the removal rates for FODs as if start-ups and malfunctions never occur. [EPA-HQ-OAR-2009-0491-2637.1, p. 7]
First Energy
FE believes the NEEDS v3.02 data generated inaccurate model outputs, which are then the basis for setting flawed state allocations. [EPA-HQ-OAR-2009-0491-2657.1, p.4]
FE strongly suggests the EPA rerun all model data since the inputs to the model have changed between NEEDS v3.02 and NEEDS v4.10, to accurately reflect the current economic conditions and database updates and generate reliable and accurate model outputs. Not to do so would be internally inconsistent with EPA's admission that the original database was flawed enough to require correction with NEEDS v4.10, and would represent flawed regulatory development. Following remodeling and issuance of updated results, if would be appropriate to provide the public with an additional 60 days for the public to review and comment on the corrected IPM outputs. [EPA-HQ-OAR-2009-0491-2657.1,p.4] [[This comment can also be found in Section XVIII.C.2.]]
Unit Availability Data
The NEEDS database dramatically understates FE generating unit availability and must be corrected.[EPA-HQ-OAR-2009-0491-2657.1, p.7]
The average unit availability for the FE system in NEEDS for the period 2001-2005 is 72.5%, versus the actual availability of 82% as reported to GADS. For the period 2005- 2009, the average availability for the FE system rose to 84%. As FE understands the operation of the IPM model, this erroneous assumption on unit availability translates directly into an under-allocation of allowances to FE of at least 10%. This error must be corrected, and consistent with our earlier comments, we urge EPA to use the most recent, most accurate data available. [EPA-HQ-OAR-2009-0491-2657.1, p.8]
Further, FE's Bruce Mansfield plant was assigned an annual availability of 67.4% based on EPA referenced NERC GADS data from 2001-2005. It appears the EPA selected a 67% availability reported for a single unit at Bruce Mansfield in 2001 and applied that value to the entire plant. The availability data used by the EPA is clearly in error, and therefore translates directly into significantly lower allocations than appropriate. FE reported the following 5-year average unit availability from 2001-2005 for Bruce Mansfield: 83.2% for Unit 1, 86.4% for Unit 2, and 88.4% for Unit 3. The 5-year average availability from 2005-2009 for Bruce Mansfield Unit 1 is 83.5%, Unit 2 was 86.3% and Unit 3 was 92.9%. As FE understands the operation of the IPM model, these erroneous assumptions on unit availability at Bruce Mansfield translate directly into an under-allocation of allowances to the FE Bruce Mansfield Plant of at least 30%. This error must be corrected, and consistent with our earlier comments, we urge EPA to use the most recent, most accurate data available.  [EPA-HQ-OAR-2009-0491-2657.1, p.8; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.7 10/15/2010]
NERC GADS data is reported voluntarily and is not QA/QC'd, unlike the data reported into the Clean Air Market Division. A more accurate way to determine availability for a unit would have been to use QA/QC'd CAMD data. [EPA-HQ-OAR-2009-0491-2657.1, p.8]
In general, the EPA should correct all incorrect control equipment assumptions placed into the IPM model through the inaccurate NEEDS data. The IPM model should be rerun to reflect the correct baseline model inputs. Correcting this information will improve the accuracy and reliability of the model outputs. [EPA-HQ-OAR-2009-0491-2657.1,p.10]
RE Burger Plant (Boiler 7&8)
NEEDS v3.02 reports Burger as being scrubbed in 2010. This assumption is in error. FE has not installed a scrubber at RE Burger and has no plans to do so. The RE Burger Plant (BU7&8) will convert to biomass by 12/31/2012 under a Consent Decree. Per the Consent Decree, the boilers will be capable of burning up to 20% sub-bituminous coal with the biomass. In order to improve data accuracy, please correct the NEEDS v3.02 database and IPM model assumptions to reflect the BU7&8 biomass project.  [EPA-HQ-OAR-2009-0491-2657.1, p.10]
Eastlake Unit 5 (EL5)
The EL5 SNCR online year is incorrect in v3.02 & v4.10. The SNCR installation year should be 2007 not 2000. EL5 is required to operate and meet reduction targets per a Consent Decree. The SNCR driven NOx reductions reflected in the 2007-2009 emissions from EL5 represents the controlled NOx emission rate for NEEDS v4.10 reported as Mode 1, but this should be Mode 4 for a controlled rate. The NEEDS v3.02 EL5 Mode 1 rate is in line with typical uncontrolled NOx emissions from EL5. The EPA incorrectly assumes the EL5 uncontrolled NOx rate (Mode1) to be 0.29 in NEEDS v4.10. This is actually the controlled rate. EPA uses 0.29 as their uncontrolled Mode 1 then incorrectly applies a 35% SNCR NOx reduction to this controlled 0.29 rate. The application of the SNCR removal efficiency to the 0.29 SNCR controlled rate applies additional 35% removal efficiency on top of the actual removal efficiency from EL5's operating SNCR. This error not only double-counts the control efficiency, but also assumes the overstated rate of 35% reduction, as discussed earlier. This is clearly in error and must be corrected. [EPA-HQ-OAR-2009-0491-2657.1 ,p.11] [[This comment is also in Section XVIII.C.2.]]
WH Sammis
Units 1-5 are listed as dry scrubbed, but a wet FGD was placed in service in 2010. The FGD for Sammis 6&7 was online in 2010, not 2011. [EPA-HQ-OAR-2009-0491-2657.1 ,p.11] [[This comment is also in Section XVIII.C.2.]]
The reported NOx rates for Sammis Uncontrolled MODE 1 & 3 are representative of the typical controlled NOx rates. The Sammis SNCR's operate annually per the Consent Decree so the data used to project the uncontrolled rate is actually representative of the controlled rate. As in the case of Eastlake 5 above, the application of the SNCR removal efficiency to the SNCR controlled rate on the Sammis Units applies additional overstated 35% removal efficiency on top of the actual removal efficiency by all operating SNCR's. This is clearly in error and must be corrected. [EPA-HQ-OAR-2009-0491-2657.1 ,p.11] [[This comment is also in Section XVIII.C.2.]]
NEEDS v3.02 is missing the Sammis 6&7 SCR installation in 2010. The SNCR installation dates for Sammis SNCR's should also be corrected. The correct dates are: SA1-2006, SA2-2000, SA3-2000 then upgraded in 2006: SA4-2006: SA5-2006: SA6- 2005: SA7-2003. The correction of installation dates for NEEDS v4.10 is the same as above except the SA6 SNCR installation date is missing for Sammis 6. [EPA-HQ-OAR-2009-0491-2657.1 ,p.11] [[This comment is also in Section XVIII.C.2.]]
Kentucky Chamber of Commerce
Additionally, EPA's analysis of the proposed rule includes emissions control equipment that is not currently installed, and therefore inaccurately minimizes the number of retrofits and the cost of achieving the additional emission reduction levels. [EPA-HQ-OAR-2009-0491-2760.1 p.1]
National Grid
In the original IPM model run, a review of the TR _ SB Limited Trading Parsed File raises questions as to why the model has run Northport and Port Jefferson on oil in this case. The six units at those facilities are all dual fuel capable and it is expected that the majority of projected run time would be on natural gas. Some uneconomic firing on oil may occur either during times when there are constraints on the gas supply (typically on very cold winter days when the gas heating load gets preference) or during times of very high electric demand when NYS reliability rules require oil firing. The IPM model should be revised to more accurately represent operation of gas/oil fired units. Furthermore, EPA has incorrectly identified SCR installations on Northport (ORIS 2516) Units 2 and 4, which appear to have been corrected in the NODA IPM version 4.10 model results. [EPA-HQ-OAR-2009-0491-2583.1, p.3]
NextEra Energy, Inc.
Inaccuracies identified in the NEEDS database and EPA's modeling assumption for NextEra Energy's EGUs need to be corrected
Upon reviewing EPA's modeling assumptions and results, including data the Agency relied on from the NEEDS database, NextEra Energy has noted a number of incorrect assumptions/data associated with EGUs operated by its FPL subsidiary. These inaccuracies in EPA's modeling assumptions/data are identified in the attached spreadsheet (Appendix A). [EPA-HQ-OAR-2009-0491-2718.1, p.6]
In addition to the corrections for FPL generating units identified in Appendix A, the most recent IPM projections show gas only operation for FPL's dual fuel-fired fossil steam generating units. With respect to the FPL units which IPM projects operation for in 2012, we have calculated that there would be a potential system demand for natural gas use in excess of 132,125 MmBtu/hr. FPL currently has under contract a maximum daily demand of 1,596,000 MmBtu/day for both Gulfstream and FGT pipelines which is an equivalent hourly demand of 66,374 MmBtu/hr. FPL also has under contract a 2011 expansion of FGT capacity of an additional 400,000 MmBtu/day, which would give FPL a total hourly pipeline capacity of approximately 83,040 MmBtu/hr. Currently there is only 210,000 MmBtu/day), of unsubscribed pipeline capacity in 2010, or roughly an additional 8,750 MmBtu/hr that could be available. Even if FPL could obtain all of the available pipeline capacity we would have only 69% of the gas needed to meet system demand under the natural gas unit operations that the IPM model is projecting for FPL's units. [EPA-HQ-OAR-2009-0491-2718.1, p.6]
A review of the IPM model and its assumptions shows that EPA relies on adjusted price curves to address fuel supply and does not model physical constraints resulting from limited pipeline capacity for electric generation. While other utilities have identified issues with the IPM not modeling of their "must run' units at designated load constraint areas, NextEra Energy has not identified any of the FPL units being designated as such. We believe that the only units in our system that might be designated as must run on oil would be the Turkey Point fossil steam units where gas availability constraints would likely prohibit operation on oil during times of system peak demand. [EPA-HQ-OAR-2009-0491-2718.1, pp.6-7]
During a July 7, 2010 EPA briefing hosted by the Edison Electric Institute (EEl), EPA staff acknowledged that IPM has difficulty handling dual-fuel units because there are non-economic reasons that a company must run such units that are not considered by the model such as grid stability considerations, contractual generation commitments, reliability must-run requirements and fuel availability constraints. NextEra Energy strongly encourages EPA to correct this modeling limitation through adjustments to the model or through post-modeling adjustments to unit emissions.[EPA-HQ-OAR-2009-0491-2718.1, p.7]
Progress Energy Service Company
There Are Inaccurate Data Inputs to the IPM Modeling
The NEEDS Emission Inventory, which constituted the primary emissions input to IPM, contains numerous errors for individual units. For example, the NEEDS database omitted a unit at one of Progress Energy's coal·fired power plants in North Carolina, Cape Fear Unit S. Cape Fear Unit 6, which is a very similar unit at the plant, was included in the database and received allowance allocations. Cape Fear Unit 5, which was omitted, inexplicably received a NOx allocation but no S02 allocation. The NEEDS database contains numerous errors regarding existing units and emission rates for both S02 and NOx that likely make the (PM runs inaccurate. [EPA-HQ-OAR-2009-0491-2831.1 p.7]
RRI Energy, Inc.
RRI has reviewed the future SO2 and NOx emission rates predicted by IPM. Comments to selected RRI units are as follows:
[[Data Table Here]]
[EPA-HQ-OAR-2009-0491-2717.1 p.7-10]
Tennessee Valley Authority (TVA)
A. Issue: EPA states that the use of lower sulfur coals to reduce SO2 emissions is achievable by 2012. [p. 45281] EPA's projected SO2 emission rates indicate switches to lower sulfur coals for several TVA units by 2012. TVA Comment: TVA has been switching to low sulfur coal on units without scrubbers since 1995 for compliance with the 1990 Clean Air Act Amendments. Over that time, TVA has incrementally exhausted all reasonably cost-effective means of achieving low sulfur coal fuel switches on its unscrubbed units. [EPA-HQ-OAR-2009-0491-2782.1, p. 1]
For most of TVA's unscrubbed units, Powder River Basin (PRB) sub-bituminous coal is both the lowest sulfur coal available and the lowest cost low sulfur coal available. Therefore, TVA has already maximized the use of PRB coal on all unscrubbed units wherever feasible. Most TVA units cannot accommodate 100% PRB coal; only Gallatin routinely burns 100% PRB coal. Allen routinely burns a blend of around 80% PRB coal, and units 1-6 at Johnsonville can burn 75% PRB coal. All other unscrubbed units generally burn 0-30% PRB coal with a few units on occasion increasing their PRB burn rate by 20% when the coal system can economically accept some capacity derates. Over these 15 years, TVA has increased the use of low sulfur coals wherever possible each year, and has not reverted back to burning medium or high sulfur coals (until units are scrubbed). [EPA-HQ-OAR-2009-0491-2782.1, p. 2]
Extensive equipment changes at significant cost would be required for TVA to significantly further reduce emission levels through increased use of lower sulfur coals. This is contrary to EPA's assumption that "switching from bituminous to sub-bituminous has no cost or schedule impact" [p. 45273]. These equipment changes include those that would have to be made to the coal handling and processing equipment (pulverizers, feeders, etc.), as well as the particulate control equipment. Making such expensive changes for just a few years before scrubber installations are potentially required for implementing hazardous air pollutant regulations, SIPs for achieving revised fine particulate ambient air quality standards, or other regulations promulgated under the CAA does not make economic or practical sense. The expected time for test burns, environmental review, permitting, design, procurement and construction of such fuel switch projects is approximately 48 months. Outages would need to be staggered to ensure reliability. With the final Transport Rule expected in mid-2011, the soonest most of these fuel switch changes could be implemented is mid-2015. Some changes would likely require additional time. [EPA-HQ-OAR-2009-0491-2782.1, p. 2]
Utilities, including TVA, contract long term for a significant portion of their coal supplies. Upon final release of the Transport Rule near mid 2011, utilities would have to renegotiate some fuel contracts, cancel others, and enter into some new fuel contracts. Any sudden shift to lower sulfur coals has the potential to cause major contractual and coal supply disruptions that would affect both coal companies and utilities in 2012. Such shifts in coal supply without a two to three year notice are not reasonable under existing contracts. EPA should not expect significant coal switches to begin before mid-2013 where extensive equipment changes are not required. [EPA-HQ-OAR-2009-0491-2782.1, p. 2]
A. Issue: EPA's analysis projects emission rates incorrectly as it assumes all TVA units can readily switch to very low sulfur sub-bituminous coal by 2012 (see I.A above) [See [EPA-HQ-OAR-2009-0491-2782.1, pp. 1-2 for TVA section I.A]. Data in the NEEDs Version 3.02 database indicates that all sub-bituminous coals have very low SO2 rates around 0.58 lb/MM-Btu. [EPA-HQ-OAR-2009-0491-2782.1, p. 6]
TVA Comment: EPA's use of 0.58 lb SO2/MM-Btu for sub-bituminous coals is unrealistically low. Most sub-bituminous coals used by TVA over the last 15 years have an average SO2 rate of just under 0.8 lb/MM-Btu. [EPA-HQ-OAR-2009-0491-2782.1, p. 6]
As explained above (paragraph I.A), most uncontrolled TVA units are incapable of burning 100% subbituminous coals, however bituminous and sub-bituminous coal blends are common. Appropriate modeling should include blends of bituminous and sub-bituminous coals. [EPA-HQ-OAR-2009-0491-2782.1, p. 6]
E. Issue: EPA's NEEDS Version 3.02 Emission Inventory for TVA units has numerous errors in installed controls, emission rates, heat rates, and new TVA coal unit additions, which do not exist and are not planned. [EPA-HQ-OAR-2009-0491-2782.1, p. 9]
TVA Comment: Instead of providing comments to Version 3.02 of the NEEDS database which has been replaced by the September 1 NODA release of Version 4.10 of that database, TVA defers all comments for this area of response to October 15th. [EPA-HQ-OAR-2009-0491-2782.1, p. 9]
Utility Air Regulatory Group (UARG)
As noted above, EPA states in the preamble to the PTR that it "expects about 14 GW of FGD and less than 1 GW of SCR capacity to be retrofit for Phase 2 of this rule [i.e., by January 1, 2014]." 75 Fed. Reg. at 45273/1. This projection omits the very substantial amounts of FGD and SCR retrofits that will be undertaken as part of the baseline when CAIR requirements are included in the baseline (as they should be, for reasons discussed elsewhere in these comments). In addition, because, as discussed in the preceding section of these comments, EPA has significantly underestimated the amount of time it takes to install these controls, a substantial number of retrofit projects that EPA assumes will be accomplished by the beginning of 2012 will in fact not be completed until the critical 2012-2014 period (while, for the same reason, some of the retrofit projects EPA predicts will be completed after January 1, 2012, but before January 1, 2014, will in fact not be completed until after the latter date). [EPA-HQ-OAR-2009-0491-2756.1, p.53]
According to estimates prepared by UARG's consultants James Marchetti, J. Edward Cichanowicz, and Michael C. Hein, a total of approximately 25 new GW of installed FGD capacity -- far higher than EPA's assumed 14 GW -- would be needed to meet the PTR's 2014 emission reduction requirements. [[See Docket Number EPA-HQ-OAR-2009-0491-2756.1, pp.147-168 for Attachment II.]] In addition, their report projects that a total of about 8.2 new GW of installed SCR capacity would need to be installed by 2014. These numbers include emission control projects that will be needed under the 2014 base case, including CAIR. These 2014 numbers do not include retrofit capacity that would be installed by 2012. [EPA-HQ-OAR-2009-0491-2756.1, p.53]
EPA's Use of Inaccurate Inputs and Assumptions for -- and Unrealistic Outputs from -- EPA's Use of the Integrated Planning Model Makes the Proposed Transport Rule Inadequate for Public Comment.
The principal analytical tool on which EPA relied in developing the unit allowance allocations and statewide emission budgets in the Proposed Transport Rule is IPM. The results of EPA's numerous IPM runs provide the Agency with substantially all of the key data points to make its decisions on these critical elements of the PTR. As EPA explains in its TSD discussing its use of IPM, that model provides forecasts of least-cost capacity expansion, electricity dispatch, and emission control strategies for meeting electricity demand, environmental, transmission, dispatch, and reliability constraints. IPM can be used to evaluate the cost and emissions impacts of proposed policies to limit emissions of sulfur dioxide (SO2), nitrogen oxides (NOx), carbon dioxide (CO2) and mercury (Hg) from the electrical power sector and is used extensively by EPA to support regulatory activities. [EPA-HQ-OAR-2009-0491-2756.1, pp.80-81]
A fundamental limitation on the accuracy of any model is the quality of the inputs to the model. Among the most critical inputs to IPM are the emission inventory and unit-level characteristics and operating parameters. The primary source for unit-level emission information for IPM is the NEEDS database. The NEEDS database is fraught with significant errors, as illustrated in section VIII.A below. In addition, other inputs can be used for, and limitations placed on, IPM analyses to reflect particular, unique situations such as state-specific regulations of EGU emissions and NSR settlements that may limit those emissions. IPM refers to such inputs as "constraints." Section VIII.A below also details various errors in the "constraints" EPA placed on the IPM model runs. [EPA-HQ-OAR-2009-0491-2756.1,p.81]
Moreover, the outputs from EPA's IPM runs, when compared to actual unit-specific data and individual companies' plans, are inaccurate and unrealistic. The validity of a given set of outputs from an application of any modeling tool is brought into question when the modeled results do not reflect real-world conditions.49 The second subsection below provides specific examples of inconsistencies between EPA's IPM projections and individual companies' plans for their units. The following examples are an illustrative, but by no means an exhaustive, list of problems in the NEEDS database and EPA's application of IPM to support the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2756.1, p.81]
Many of the IPM Inputs for Individual Units Are Inaccurate.
Errors in the NEEDS database identified by UARG members generally fall into three categories: (1) emission controls that were assumed to exist currently but do not; (2) overestimated emission control efficiencies of existing control equipment; and (3) failure to account for emission controls or limits that do exist. Examples of pollution controls that were assumed to exist but do not include the following: [EPA-HQ-OAR-2009-0491-2756.1, p.82]
:: NEEDS reports that PM scrubbers are already installed and operational at the Harrison power plant in West Virginia. PM scrubbers do not exist at that plant.
:: NEEDS reports that selective non-catalytic reduction ("SNCR") is already installed and operational at two units at the Armstrong power plant in West Virginia. SNCR does not exist at these two units.
:: NEEDS reports that FGD is to be installed at unit 4 at the Scherer power plant in Georgia in 2011. The current target installation date is August 2012.
:: NEEDS reports that SNCR is to be installed at units 4 and 5 at the Jack Watson power plant and units 1 and 2 at the Daniel power plant in Mississippi. No SNCRs exist or are planned for these units.
:: NEEDS reports that a wet scrubber will be installed at unit 3 at the Brayton Point power plant in Massachusetts by 2012. Under a state-approved Emission Control Plan, a dry scrubber will be installed and will commence operation in 2014.
:: NEEDS data indicate that an SCR on unit 3 at the E.W. Brown power plant in Kentucky is to be installed by the beginning of 2012. An SCR is under construction at that unit but will not be completed until the end of 2012.
:: NEEDS data indicate that an SCR exists on unit 2 at the Ghent power plant in Kentucky as of 2009. SCR neither exists nor is planned for this unit. [EPA-HQ-OAR-2009-0491-2756.1, p.82]
Examples of overestimation by NEEDS of removal efficiency of controls that currently exist: [EPA-HQ-OAR-2009-0491-2756.1, p.82]
:: NEEDS reports the FGD control efficiency at the Mitchell power plant in West Virginia at 99.9% -- an impossible figure to achieve. The actual average removal efficiency is 97%.
:: NEEDS reports the FGD control efficiency at the Pleasants power plant in West Virginia at 97%. The actual average removal efficiency is 95%. Examples of emission controls that do exist but were not included:
:: NEEDS fails to account for FGD systems at the Harrison power plant in West Virginia.
:: NEEDS fails to account for FGD systems at three units at the Hatfield's Ferry power plant in West Virginia
:: NEEDS fails to account for FGD systems at two units at the Fort Martin power plant in West Virginia.
:: NEEDS fails to account for a state SO2 emission limitation on the Cumberland power plant in Tennessee of 0.5 lb/mmBtu and instead reports SO2 emissions at that plant at a rate of 5.0 lb/MmBtu.  [EPA-HQ-OAR-2009-0491-2756.1, p.83]
In addition, errors in IPM constraints and inputs appear to be related to inaccurate interpretation of state regulations and NSR settlements, and there are other errors as well. Examples include:
:: IPM assumes (in the 2014 base case) that units 1 and 2 at the Harllee Branch power plant in Georgia will each have an FGD and SCR in place by 2014 (presumably, January 1, 2014). The Georgia Multi-pollutant Rule instead requires that these be in place by December 31, 2014. 
 IPM assumes (in the 2014 base case) that unit 4 at the Harllee Branch power plant in Georgia will have an FGD and SCR in place by 2014 (presumably, January 1, 2014). The Georgia Multi-pollutant Rule instead requires that these be in place by June 1, 2014.
:: IPM assumes (in the 2014 base case) that units 6 and 7 at the Yates power plant in Georgia will each have an FGD and SCR in place by 2014 (presumably, January 1, 2014). The Georgia Multipollutant Rule instead requires that these be in place by June 1, 2015.
:: IPM assumes (in the 2014 base case) that unit 1 at the Scherer power plant in Georgia will have an FGD and SCR in place by 2014 (presumably, January 1, 2014). The Georgia Multi-pollutant Rule instead requires that these be in place by December 31,  2014. [EPA-HQ-OAR-2009-0491-2756.1, pp.83-84]
 :: IPM assumes that FGD retrofits at the Kyger Creek and Clifty Creek power plants in Ohio are complete and operational. These retrofits are not complete, and construction is currently suspended.
:: IPM assumes that one of the primary units of the Cumberland power plant in Tennessee has an SO2 emission rate of 5.0 lbs/mmBtu. The unit is currently regulated by and is complying with a state regulation that limits its SO2 emissions to 0.5 lbs/mmBtu.
:: IPM assumes that the Maryland Healthy Air Act allows for limited interstate trading and/or intrastate trading, depending on the proposed remedy, and IPM appears to treat similar sources in Maryland very differently, judging from the IPM-based allowance allocations for units. The Maryland Healthy Air Act in fact only allows for intra company trading of allowances and the unit-specific allowances established in the Maryland Healthy Air Act appear to have been ignored.  [EPA-HQ-OAR-2009-0491-2756.1, p.84]
 EPA's IPM Outcomes Do Not Reflect Actual Source Operations
UARG members have found many inconsistencies between EPA's IPM-projected operating scenarios for units in 2012 and 2014 and their own plans and projections. While EPA may argue that IPM accounts for the impact of the proposed controls and that generators are not capable of appreciating the influence of the proposed controls on their future operations, UARG members believe that their economic models, as well as their understanding of their operations, supply capabilities, and energy demand forecasts are more accurate than outputs of EPA's proprietary IPM. IPM was not designed for this level of specificity -- it is a regional-scale model. IPM often does not reflect real-world operations with respect to a number of key factors, including unit availability. Generators have years of experience with a greater level of specificity that allows them to understand the real-world constraints and demands on individual units and to better predict which units will run, how often they will run, and how long they will continue to run. [EPA-HQ-OAR-2009-0491-2756.1, p.85]
The inaccurate IPM projections fall into four categories: (1) inaccurate assumptions of emission controls; (2) inaccurate estimates of emission control efficiencies; (3) inaccurate assumptions of early retirement of particular units; and (4) inaccurate assumptions regarding fuel switching at particular units. [EPA-HQ-OAR-2009-0491-2756.1 , p.85]
Examples of inaccurate assumptions of emission controls include the following:
:: IPM projects FGD installations at the Armstrong power plant in Pennsylvania by 2014. No such installations are planned by the company.
:: IPM projects FGD installation at the Willow Island power plant in West Virginia by 2014. No such installation is planned by the company.
:: IPM projects SCR installation at unit 2 at the J.H. Campbell power plant in Michigan by 2012. No such installation is planned by the company.
:: IPM projects installation and operation of LNBs with overfire air -- based on the listed emission rate -- at the J. R. Whiting power plant (units 1-3) in Michigan. The owner of the units does not believe such controls are viable options at these units due to operational and configuration constraints.
:: IPM projects FGD installation and operation at unit 2 at the Muskingum River power plant in Ohio by 2011. Although a preliminary engineering study was conducted for unit 2, there is no ongoing construction and it would take at least three years to permit and build an FGD even if construction began immediately.
:: IPM has not allocated NOx emission allowances to units 1 and 2 at the Salem Harbor power plant even through the IPM model for the 2012 base case predicts that these units will operate. This appears to be the result of erroneous adjustments made to projected IPM emissions to account for annual operation of each unit's SNCR. No adjustment was necessary. Actual emissions already represent annual operation of SNCR -- both SNCRs have been operating on a year-round basis since October 2005 to comply with a stationwide NOx limit in accordance with a state Administrative Consent Order. [EPA-HQ-OAR-2009-0491-2756.1, p.86]
Examples of inaccurate estimates of emission control efficiencies include the following:
:: IPM projects an annual 35% NOx removal efficiency for two units at the Fort Martin power plant in West Virginia and one unit at the Hatfield's Ferry power plant in Pennsylvania. In fact, however, these units have only single-point injection controls capable of roughly 10% to 15% removal efficiency.
:: IPM projects annual NOx emission rates at the Harrison power plant and the Pleasants power plant in West Virginia from SCR as low as 0.04 to 0.05 lb/mmBtu. Such low rates were periodically achievable when the SCR was initially installed, but representative operation of the controls demonstrates that such rates are not sustainable on a long-term basis and as the effectiveness of the SCR reduces as the catalyst ages. [EPA-HQ-OAR-2009-0491-2756.1, p.86]
Examples of inaccurate assumptions of early retirement of particular units include the following:
:: IPM projects early retirement of two units at the Rivesville power plant and one unit at the Willow Island power plant in West Virginia by 2014. No retirements by 2014 are planned by the company.
:: IPM projects early retirement -- by 2014 -- of units 1 and 2 at the McManus power plant in Georgia, and of units 1 and 3 at the Watson power plant, and units 1 and 2 at the Sweatt power plant, both in Mississippi. There are no plans by the company to retire these units by 2014.
:: IPM projects early retirement of nine units in Michigan (B. C. Cobb units 1-3; D. E. Karn units 3 and 4; and Thetford units 1-4). There are no plans by the company to retire these units by 2014. [EPA-HQ-OAR-2009-0491-2756.1, p.87]
Examples of inaccurate assumptions regarding fuel switching for particular units include the following:
:: IPM projects fuel switching from coal to natural gas for three units at the Albright power plant in West Virginia and for two units at the R. Paul Smith power plant in Maryland. These fuel switches are not planned by the company.
:: IPM projects fuel switching from coal to natural gas for the McManus power plant in Georgia. This fuel switching is not planned by the company.
:: IPM projects fuel switching from higher sulfur coal to 100% Powder River Basin coal by 2012 at units 4 and 5 at the B.C. Cobb power plant and units 1-3 at the J. R. Whiting power plant in Michigan. Such a fuel switch is not feasible due to the limited timeframe and outstanding coal, rail-line, and rail-car contracts.
:: IPM projects fuel switching to low-sulfur Eastern coals at units 1-4 of the Muskingum River power plant in Ohio. These units are wet bottom/cyclone-fired boilers that, historically, do not tolerate such coal because of its high ash-fusion temperatures. [EPA-HQ-OAR-2009-0491-2756.1, p.87]
In addition to these facility-specific errors, EPA's application of IPM reveals certain systemic errors in the analysis supporting the PTR. Perhaps most notable is IPM's treatment of dual-fuel units, i.e., units capable of burning either natural gas or oil. Of the 493 dual-fuel units in the NEEDS database, IPM predicted in the 2014 limited trading control strategy that 34 units would burn oil as the primary fuel. EPA proposes to allocate any SO2 allowances to only 8 of those 34 units. This result ignores the reality that many dual-fuel units do regularly burn oil for some part of the year, whether due to natural gas supply limitations, price factors, or facility-specific constraints. The mere fact that the IPM analysis may project that it will be more economical to run these units on natural gas than on oil does not mean that the real-world factors that lead to combustion of oil at these units simply disappear. [EPA-HQ-OAR-2009-0491-2756.1, pp.87-88]
IPM projection errors of this sort appear to be a function of inherent limitations of IPM and/or EPA's limited knowledge of certain local factors. IPM is a least-cost economic model designed to predict operations at a fairly broad regional level. In many instances, EPA lacks sufficient information about local issues such as transmission constraints, capacity commitments, fuel-contract commitments, and other cost-related considerations that have not been input to the IPM model. EPA's insufficient information, coupled with the limitations of the regional IPM model, result, for example, in inaccurate projections for oil-fired units and dual-fuel units. When IPM predicts natural gas is less expensive than oil or that burning oil at an oil-fired unit is for some reason not "economical" within the terms of IPM's protocol, no SO2 emissions are projected from -- and thus no SO2 allowances are allotted to -- that unit. [EPA-HQ-OAR-2009-0491-2756.1, p.88]
EPA must recognize the limitations of IPM and must consider local issues and allow UARG members, other generators, and other members of the public to comment on EPA's adjustments to address those issues. For example, it should be self-evident that particular units that have burned oil in the past, and that continue to burn oil, can be expected to burn oil in the future and should receive allowance allocations; the presumption should be in such cases that allowance allocations to those units are appropriate in the absence of compelling reasons to the contrary. At a minimum, EPA should not blindly insist that IPM's projections for these types of units are accurate and should instead make adjustments to the allocation determinations for these types of units, based on comments of companies with interests in those units. [EPA-HQ-OAR-2009-0491-2756.1, pp.88-89]
Another systemic error involves the heat input rates listed in the "BADetaileddata.xls" spreadsheet associated with the proposed direct control alternative remedy. Heat input is overstated by a factor of 10 in this spreadsheet. Because of the absolute tonnage cap in the direct control case, these artificially high heat input levels are essentially meaningless in this context. Nonetheless, these types of errors draw into further question the accuracy and validity of the NEEDS database and IPM modeling runs. [EPA-HQ-OAR-2009-0491-2756.1, p.89]
Accordingly, EPA should correct the errors in the NEEDS database and correct the erroneous and inaccurate IPM inputs and then rerun the critical IPM model runs, to the extent EPA continues to use IPM modeling as a basis to develop state budgets. Given the serious limitations in IPM's capabilities as discussed above, EPA should develop for public review and comment alternative methods of calculating unit allowance allocations (for example, alternative methods that use appropriate measurements of units' historical heat input, as EPA did in the NOx SIP Call rule and CAIR). EPA should then publish revised proposed budgets and allocations for public review and comment. However, any proposed allocations should at most be "model" allocations for consideration by the states; for the reasons discussed elsewhere in these comments, EPA has an obligation to allow each state to make -- and to give each state adequate time to make -- any emission control decisions for sources within the state and to incorporate those decisions in SIPs. [EPA-HQ-OAR-2009-0491-2756.1, pp.89-90]
Footnote 49: Another problem with the outputs from IPM results from the fact that IPM does not perform a probabilistic analysis. IPM outputs give the illusion that they are precise even though they are not. It would be more realistic for EPA to consider a range of projected data than to treat a single data point from IPM as a precise data point for purposes of calculating budgets and allowance allocations.
Wabash Valley Power
WVPA has reviewed the data input tables used in EPA's technical and financial modeling for the proposed Transport Rule as well as the modeled projections of unit operation. We noted several instances in which the data appear to be in error for WVPA's generation units. [EPA-HQ-OAR-2009-0491-2627.1, p.2]
Holland Energy Facility:
EPA lists the Holland facility as having two (2) combustion turbines, CTG 1 and CTG2, each with a capacity of 147 MW, and a steam turbine with a capacity of 155 MW. We would like to point out that the capacity of these units changes based on ambient weather conditions. More specifically, CTG 1 and CTG2 each have a capacity of 172 MW at ISO conditions while the STG 1 has a nominal capacity of 343.3 MW. [EPA-HQ-OAR-2009-0491-2627.1, p.2]
Additionally, EPA's preferred option base case for 2012 shows the units operating only in the summer months and projects a total heat input for the plant of 0.526 TBtu. It should be noted that this facility is a two-on-one natural gas fired combined cycle facility equipped with natural gas fired duct burners in each of the two heat recovery steam generator (HRSG) units. The plant operates as an intermediate load resource and has been dispatched in every quarter since its construction; not solely limited to summer operation as EPA's model suggests. WVPA's forecast for 2012 shows a projected heat input to the two combustion turbines of 2.8572 TBtu. As such, the EPA's projection for 2012 is roughly 18.4% of WVPA's anticipated consumption. [EPA-HQ-OAR-2009-0491-2627.1, p.2]
Similarly, in 2014, EPA's preferred option base case again shows the Holland facility running only in the summer months with a total heat input for the plant of 1.2354 TBtu. WVPA's 2014 forecast projects a heat input to the two combustion turbines alone of 4.9724 TBtu. As such, the EPA projection for 2014 is less than 25% of that of WVPA's. [EPA-HQ-OAR-2009-0491-2627.1, p.2]
Furthermore, WVP A believes that its own forecast may be conservative (low) as it does not reflect increased demand for gas-fired generation due to the anticipated retirement of small, older coal units as a result of this rule. [EPA-HQ-OAR-2009-0491-2627.1, p.2]
We also note that EPA's BADetailedData spreadsheet lists NOx emission rates for CTG 1, CTG2, and STG 1 of 0.025, 0.014, and 0.025 lb NOx/mmBtu respectively. Upon review of the data, EPA appears to have redistributed heat input values and total mass emissions associated with CTG 1 by evenly dividing them between CTG 1 and the STG 1 (steam turbine). We believe that the same was done with respect to the NOx emission rate. Based on 2009 EDR submissions, the NOx rate for CTG1 is 0.05 lb NOx/mmBtu and 0.017 lb NOx/mmBtu for CTG2. However, EPA's spreadsheet lists 0.025 lb NOx/mmBtu for CTG 1 and STG 1. While it generally does not cause a problem to evenly divide and redistribute mass emissions among the units, the same is not true for a concentration based emission rate. As a result we are concerned that EPA may have made an error which will negatively impact our NOx allowance allocations. [EPA-HQ-OAR-2009-0491-2627.1, p.3]
Wabash River Unit 1 and 1A:
This former coal fired unit was repowered in 1994 as an Integrated Gasification Combined Cycle (IGCC) facility. WVPA acquired controlling interest in the gasification facility in 2005 and subsequently purchased the associated combined cycle facility from Duke Energy in 2008. EPA's Wabash River Unit 1 d~signati6n is the repowered 85 MW steam turbine and the Unit 1A designation represents the nominal 192 MW (incorrectly listed at 189 MW) combustion turbine. Being IGCC, the removed sulfur is > 99% pure and is sold for reuse. Furthermore, as sulfur is removed before combustion, there is no need and little benefit to installing a post-combustion FGD system. EPA also incorrectly lists this unit as needing a 97% FGD removal rate. This is an IGCC facility and has no FGD. The gasification facility is permitted to gasify either coal or petroleum coke. The gasification process treats the resulting syngas to remove particulate and sulfur prior to utilizing the syngas as a fuel in .the combustion turbine. EP A has incorrectly classified this facility as a coal facility. The electrical generation (combined cycle) portion of the facility is fueled solely by syngas or natural gas. EPA incorrectly lists existing NOx control as nitrogen diluent injection (NDI). The combustion turbine is equipped with steam injection for NOx control. [EPA-HQ-OAR-2009-0491-2627.1, p.3]
We also note that EPA's BADetailedData spreadsheet lists an annual NOx emission rate of 0.068 lb/mmBtu for Units 1 and 1A. This facility can not currently meet this limit. As stated above, the combined cycle portion of this IGCC facility does utilize steam injection to control NOx emissions. However, due to other differences in the IGCC process, conventional application of an SCR is not viewed as a viable technical solution for achieving additional NOx reductions. [EPA-HQ-OAR-2009-0491-2627.1, p.3]
Response: 
EPA's response to these comments in the final Transport Rule is multi-faceted:
First, EPA changed its allocation methodology to be based on historic heat input and emissions data that is generally reported by the sources' DR who testifies to its accuracy and completeness.  This was done in response to comments that expressed concern/disagreement about the IPM unit level projected emissions on which the proposed allocations were based.  By switching to a historic  data based methodology, the degree to which any discrepancy between a units actual future operation and its projected future operation would impact the unit's allocation is greatly diminished.  EPA recognizes that IPM is a dynamic linear programming model that generates optimal decisions under the assumptions of perfect foresight and results in a least cost method of meeting demand.  However, invariably, there will be discrepancies between IPM unit level projections and a unit's actual future operations due to non-economic or other variables that IPM does not capture.  While at the state and regional level, the discrepancies are small and random and thus do not result in biases.  However, their impact at the unit level may be significant and this was one of the drivers behind switching to an allocation method based on historic data.
Second, EPA reviewed the comments and has made significant updates to its IPM v.3.02 modeling used at proposal.  These updates include changes to both the more general IPM assumptions (e.g., gas price assumptions) and specific unit level assumptions (e.g., that current retrofit status at a unit).  These updates were made to the IPM model, and the updated versions (EPA IPM v.4.10) was used for all the final rule analysis.  In regards to unit specific adjustments, EPA did not manually adjust projected unit level modeling outputs, but it did make unit level updated to its NEEDS database used as a model input that impacted the unit level model outputs.  .  Some of the most frequent general IPM comments noted above that were addressed in the updates are: FGD removal efficiency was adjusted for new retrofits, and for existing retrofits it was indexed to historic performance at the unit.  Additionally, many of the above comments were focused on a sources ability to switch coals.  EPA modified its modeling to better reflect the cost and feasibility of switching and blending coals.  For more detailed discussion of EPA IPM v.4.10 assumptions and assumption updates, see the EPA IPM v.4.10 documentation and the "Transport Rule IPM Assumptions Response to Comments" in the Appendix
These two adjustments, updates to the modeling and updates to the allocation methodology, work in concert to comprehensively address many of the concerns expressed by commenters on their unit level projections and allocations.
Additionally, some commenters noted small discrepancies between the universe of units allocated allowances, and the universe of units included in the IPM modeling.  The EGUS reflected in the modeling are a comprehensive list of existing and planned units and are a reasonable proxy of the existing EGU fleet.  There is the possibility of some units being allocated to that are not included in the modeling projections (e.g., a unit that is planning on retiring in 2011), additionally there could likewise be some units that the IPM modeling list as two units (i.e., one plant with a combustion turbine and steam turbine - each 30 MW), but where the source actually reports as one 60 MW unit.
Organization: Nebraska Public Power District
Comment: 
2) Nebraska Non-point SO2 Emissions Inventory. In evaluating whether Nebraska should be included in the proposed TR, EPA modeled 2005 total emissions, purported to be from all sources, as a baseline case. EPA cites a Nebraska 2005 baseline total SO2 emission inventory of 121,589 tons/year in the preamble of the proposed TR. Of this total amount of SO2 emissions for the State, the so-called "nonpoint" portion modeled by EPA is 29,575 tons/year. Review of the detailed emission inventory 1 reveals that this "nonpoint" inventory includes SO2 emissions from industrial and commercial/ institutional boilers of almost 29,000 tons/year. Such boilers would really not be nonpoint sources. While certain industrial and commercial/institutional boilers not inventoried as specific point sources can be classified as nonpoint sources, EPA appears to grossly overestimate the contribution of such boilers to the nonpoint emissions inventory for Nebraska. [EPA-HQ-OAR-2009-0491-2711.1, pp.1-2]
Most of the nearly 29,000 tons of SO2 emissions attributed to nonpoint industrial and commercial/institutional boilers in the inventory database are attributed to subbituminous or bituminous coal usage. While EPA's TR modeling "non-EGU" point source SO2 emissions inventory for Nebraska -- 6,429 tons/year -- appears to be a reasonable estimate based on our review of facility-by-facility emissions included in the NEI database, and Energy Information Administration (EIA) data, EPA's estimate that noninventoried boilers in Nebraska account for 450% more SO2 per year than point source boilers appears to be so inaccurate that a modeling mistake may have been made. EIA coal consumption data for 2007 and 2008 show that, industrial and commercial/ institutional boiler usage of coal in Nebraska was less than 432,000 short tons per year (EIA's "Other Industrial" end user category accounts for small amounts of coal consumed by sources other than boilers). Based on typical sulfur levels in the Powder River Basin coal (~0.5% sulfur by weight) burned in virtually all of Nebraska, this is generally consistent with the "non-EGU" emission level cited above. While EIA's consumption data excludes smaller sources (end users that consume less than 1,000 short tons of coal per year) that may fall within the nonpoint source category, we find it extremely improbable that these smaller, non-inventoried sources account for approximately 29,000 tons per year of SO2 emissions (nearly 25% of the Nebraska 2005 baseline inventory) for EPA's modeled 2005 SO2 inventory for Nebraska. EPA compounds this apparent error by carrying forward this incorrect estimate as the basis of the 2012 and 2014 base case emissions inventories. [EPA-HQ-OAR-2009-0491-2711.1, p.2]
3) Nebraska Non-point NOx Emissions Inventory. As with the SO2 emissions overestimation described in Item 2, the NOx emissions for "non-point" Nebraska sources appears to be significantly overstated by EPA, because approximately half the reported non-point NOx total in the 2005 baseline inventory is listed in the database as being associated with fossil fuel combustion in industrial, commercial and institutional coal boilers. If EPA made the same error in estimating nonpoint industrial and commercial/‌institutional coal boiler NOx emissions as it did for the SO2 inventory, then EPA's 2012 and 2014 NOx base case emissions inventories for Nebraska are also improperly inflated, reflecting the inaccurate 2005 NOx baseline. [EPA-HQ-OAR-2009-0491-2711.1, p.2]
4) Nebraska EGU SO2 Emissions Inventory Overview. EPA has grossly overestimated the amount of SO2 emissions from EGUs for purposes of establishing the 2012 base case for Nebraska. As discussed below, NPPD estimates that EPA has inflated the Nebraska SO2 base case by about 40,000 tons of SO2. This amounts to a 50% overestimation in SO2 emissions and it will increase the Nebraska EGU emissions for SO2 from about 80,000 tons to over 120,000 tons. Furthermore, EPA has provided no explanation that can justify such a steep increase in EGU SO2 emissions. Rather, EPA relies on Integrated Planning Model (IPM) projections that are intended to forecast EGU SO2 emissions for Nebraska and other States without the regulatory constraints of the Clean Air Interstate Rule (CAIR). In support of this approach, EPA states: "without the CAIR SO2 program, emission requirements in many areas would revert to the comparatively less stringent requirements of the Title IV Acid Rain Program" and that as a result affected utilities would comply with the Acid Rain Program "without the operation of existing scrubbers through use of readily available, inexpensive Title IV allowances."2 While NPPD generally agrees with this approach in the case of those states subject CAIR, the EPA approach is entirely unnecessary for States, like Nebraska, that are not subject to the CAIR program. [EPA-HQ-OAR-2009-0491-2711.1, p.3]
Furthermore, EPA has used inaccurate and erroneous IPM modeling assumptions to project the 2012 base case EGU emissions. The modeling assumption of greatest concern relates to the sulfur content of coal that Nebraska EGUs will burn during the 2012 base case. As explained below, all coal-fired Nebraska EGUs have historically consumed low-sulfur subbituminous coal and thereby have collectively achieved an average annual SO2 emissions rate ranging from 0.57 to 0.69 lb/MmBtu during the last decade. Notably, the Nebraska coal-fired EGUs have continuously used this low-sulfur subbituminous coal and achieved these low annual SO2 emissions rates before and during the Acid Rain program. In addition, they have done so while not being subject to the CAIR program. [EPA-HQ-OAR-2009-0491-2711.1, p.3]
Viewed in this context, EPA must provide specific technical support that can plausibly justify why the Nebraska coal-fired EGUs would suddenly deviate from this longstanding practice and start using coals with a higher sulfur content that would greatly increase the average SO2 emissions for all Nebraska coal units to almost 0.9 lb/MmBtu. To put in other words, EPA cannot rely on IPM projections to claim such a radical departure in the SO2 emissions levels for Nebraska coal-fired EGUs values without identifying changed circumstances that can credibly explain this departure under the IPM modeling. [EPA-HQ-OAR-2009-0491-2711.1, p.3]
[For additional comments pertaining to Nebraska EGU SO2 Emissions Inventory, see pp. 3-5 of this comment. Attachments 1-3 can be found on pp. 10-12 of this comment.]

1. See http://www.epa.gov/ttn/chief/net/2005inventory.html#inventorydata. [EPA-HQ-OAR-2009-0491-2711.1, p.2]
2. 75 Fed. Reg. at 45,234. [EPA-HQ-OAR-2009-0491-2711.1, p.3]
3. 75 Fed. Reg. at 45,290 (emphasis added). [EPA-HQ-OAR-2009-0491-2711.1, p.4]
Response: 
In regards to EGU emissions inventories, EPA reviewed comments received on the Transport Rule proposal and subsequent NODA for the EPA IPMv.4.10 model.  EPA made significant updates to both unit level and macro level assumptions in its modeling based on these comments.  This updated modeling was then used to conduct the air quality modeling anew for the final Transport Rule.  Nebraska's inclusion in the final Transport Rule geography for the PM2.5 NAAQS is based on this final rule air quality modeling of their 2012 base case emissions from the final rule power sector modeling, which includes a substantial reduction compared to the proposal's base case modeling of Nebraska's base case SO2 emissions from EGUs. Notwithstanding these revised results, the final rule's air quality modeling continued to support EPA's conclusion that Nebraska should be included in the Transport Rule's programs for addressing significant contribution to nonattainment and interference with maintenance in downwind states for the PM2.5 NAAQS assessed in this rulemaking.
Organization: Nelson Industrial Steam Company (NISCO)
Comment: 
Nelson Industrial Steam Company (NISCO)
EPA's original modeling, using the IPM version 3.02 for the Base Case, projected that Louisiana emissions may interfere with maintenance of the annual PM2.5 NAAQS in 2012, by contributing only 0.34 ug/m3 to the annual PM2.5 values at the Clinton Drive monitor in Houston, Harris Co., TX. Of that total, EPA projected that 0.33 ug/m3 is from sulfate emissions and only 0.004 ug/m3 from nitrate emissions. The projected design value for the Clinton Drive monitor in 2012 was 14.74 ug/m3 average and 15.14 ug/m3 maximum compared to the 15.0 NAAQS ug/m3. The 2008 PM2.5 annual average at Clinton Drive was 14.0 ug/m3, even when exceptional event days are included. The annual average PM2.5 in 2009 was only 12.8 ug/m3 and from January 1 through August 29, 2010, the average is 12.72 ug/m3. 5 The design value dropped to 14.4 ug/m3 for the 2007-2009 period and is expected to drop to a value of approximately 13.2 ug/m3 further this year due to 2007 dropping out of the 3-year average. 6 So, it is clear that current Louisiana emissions are not interfering with maintenance of the NAAQS in any way. These Louisiana emissions are projected by EPA to drop even further without the CATR/FIP. [EPA-HQ-OAR-2009-0491-3789_NODA, p.2]
EPA also projected, under the IPM version 3.02 Base Case, that Louisiana emissions will significantly contribute to nonattainment with the 1997 8-hour ozone NAAQS at certain monitoring sites in the Houston-Galveston-Brazoria ('HGB') and the Dallas-Ft. Worth ('DFW') Areas of Texas in 2012. EPA has projected that Louisiana emissions will interfere with maintenance of that NAAQS at other monitoring sites in the HGB and the DFW Areas of Texas in 2012. But, again, real data cast doubt on these projections. All monitors in the HGB Area are currently in attainment with the 1997 8-hour ozone NAAQS and have been since 2008 (based upon the 2006-2008 monitoring data). All of the DFW monitors that EPA projected were adversely impacted by Louisiana emissions, save one, are also currently in attainment with that NAAQS. The design value at that one monitor at issue in DFW is 86 ppb, just 2 ppb above the standard. [EPA-HQ-OAR-2009-0491-3789.1_NODA, pp.2-3]

5 Texas Commission on Environmental Quality, CAMS 403, PM-2.5 (Local Conditions) Acceptable Summary for 2010, http://www.tceq.state.tx.us/cgi-birdcompliance/monops/yearly_summarv.pl (last visited Sep. 21, 2010).
6 Texas Commission on Environmental Quality, PM2.5 Data: Soot, Dust, Particulate Matter, (last visited Oct. 1, 2010)
Response: 
EPA has updated its IPM modeling and EGU emissions inventories in response to comments on the IPM version 3.02 for the base case.  As a consequence, the base case EGU emissions for states have changed.  EPA conducted its final air quality modeling off the updated base case.  In the final Transport Rule, Louisiana is no longer subject to Transport Rule annual PM2.5 programs.  However, the updated IPM and air quality modeling indicate the state is still "linked" to Texas receptors sites at Brazoria and Harris for 8-hour ozone.  See section V.D of the preamble for more details.  Additionally, see IPM documentation,  "Documentation Supplement for EPA Base Case v.4.10_FTransport  -  Updates for Final Transport Rule" and "Transport Rule IPM Assumptions Response to Comments" for details regarding IPM updates and assumptions in the v.4.10 used in the final Transport Rule.  Also, EPA notes that the 2012 base case used in air quality modeling represents power sector operations in the absence of CAIR.  Both the proposal and final rule preamble explain why this is necessary.  Therefore, comments suggesting that 2012 base case emissions data and receptor status in the final Transport Rule are incorrect simply because they do not reflect recent emissions data and receptor status observed once the CAIR rule was final are misguided, as EPA has clearly stated that the base case represents a world without CAIR.
Organization: NRG Energy
Comment: 
NRG Energy
Correction for EPA Database: NRG Units that should not be in the TR NRG's Cos Cob Units 13 and 14 (Cos Cob) appear in the EPA Allocation Table; however, they are not included in the results of the Integrated Planning Model (IPM) work. The proposed Transport Rule states that affected units are included in Appendix A; however, a draft Appendix A is not published on the website. It is assumed that the draft Allocation Table is the draft Appendix A. It is unclear if the Cos Cob units will be included in the Rule. The Cos Cob units are combustion turbines operational in June 2008 that were initially listed as each unit having a nameplate capacity of 25 MW. Each unit is in actuality a 20 MW unit and therefore should not be included in CATR. A copy of the New Unit Exemption form as filed with the Connecticut Department of Environmental Protection and the EPA is attached to this document as Attachment 3. [EPA-HQ-OAR-2009-0491-2749.1, p. 6; see p. 11-17 for New Unit Exemption form.]
Correction for EPA Database: NRG Units that Should be in the TR EPA has included in its IPM work generating units that exist or are expected to be operational by January 1, 2012. Missing from the database are eight new units in Connecticut that are or will be operational prior to January 1, 2012. [EPA-HQ-OAR-2009-0491-2749.1, p. 6]
GenConn Devon LLC ("GenConn Devon") is the owner of the four 50 MW simple-cycle combustion turbines (CTs) that were deemed commercial between June and August 2010. The four CTs are located at Devon Station in Milford, Connecticut. Devon Power LLC (DPL), a wholly owned subsidiary of NRG, is the operator of the turbines, pursuant to an Operations and Maintenance Agreement between GenConn Devon and DPL. [EPA-HQ-OAR-2009-0491-2749.1, p. 6]
There are four existing CTs owned by DPL (Units 11, 12, 13 and 14) located at Devon Station that are in EPA's current database. GenConn Devon's four new units are designated as Units 15, 16, 17, and 18 (Units 15 -18), are designed to combust natural gas or ultra-low sulfur distillate oil, and are equipped with a Selective Catalytic Reduction (SCR) system. The specific data needed to model these units will be submitted in NRG's comments on the Notice of Data Availability (NODA). [EPA-HQ-OAR-2009-0491-2749.1, p. 6]
GenConn Middletown LLC (GenConn Middletown) is the owner of the four, 50 MW simple-cycle combustion turbines (CTs) currently being constructed at Middletown Station located in Middletown, Connecticut. The GenConn Middletown CTs will be commercial by June 1, 2011. Middletown Power LLC (MPL), a wholly owned subsidiary of NRG, will be the operator of the turbines, pursuant to an Operations and Maintenance Agreement between GenConn Middletown and MPL. [EPA-HQ-OAR-2009-0491-2749.1, p. 6]
GenConn Middletown's four new units are designated as Units 12, 13, 14 and 15 (Units 12-15) and are identical to the GenConn Devon units. The specific data needed to model these units will be submitted in NRG's comments on the NODA. [EPA-HQ-OAR-2009-0491-2749.1, p. 6]
Response: 
See Transport Rule final allocation tables and final IPM modeling parsed outputs for unit level details.  Cos Cob is included in the modeling, but not included in the final allocation tables as Connecticut is not covered under the final Transport Rule geography.
EPA IPMv.4.10 modeling was also updated between proposal and final to reflect the Devon and Middletown units mentioned in the comment.
Organization: PPG Industries, Inc.
Comment: 
PPG Industries, Inc.
EPA's original modeling, using the IPM version 3.02 for the Base Case, projected that Louisiana emissions may interfere with maintenance of the annual PM2.5 NAAQS in 2012, by contributing only 0.34 ug/m3 to the annual PM2.5 values at the Clinton Drive monitor in Houston, Harris Co., TX. Of that total, EPA projected that 0.33 ug/m3 is from sulfate emissions and only 0.004 ug/m3 from nitrate emissions. The projected design value for the Clinton Drive monitor in 2012 was 14.74 ug/m3 average and 15.14 ug/m3 maximum compared to the 15.0 NAAQS ug/m3. The 2008 PM2.5 annual average at Clinton Drive was 14.0 ug/m3, even when exceptional event days are included. The annual average PM2.5 in 2009 was only 12.8 ug/m34 and from January 1 through August 29, 2010, the average is 12.72 ug/m3. 5 The design value dropped to 14.4 ug/m3 for the 2007-2009 period and is expected to drop to a value of approximately 13.2 ug/m3 further this year due to 2007 dropping out of the 3-year average.6 So, it is clear that Louisiana emissions now are not interfering with maintenance of the NAAQS in any way. [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.2]
EPA also projected, under the IPM version 3.02 Base Case, that Louisiana emissions will significantly contribute to nonattainment with the 1997 8-hour ozone NAAQS at certain monitoring sites in the Houston-Galveston-Brazoria ('HGB') and the Dallas-Ft. Worth ('DFW') Areas of Texas in 2012. EPA has projected that Louisiana emissions will interfere with maintenance of that NAAQS at other monitoring sites in the HGB and the DFW Areas of Texas in 2012. But, again, real data cast doubt on these projections. All monitors in the HGB Area are currently in attainment with the 1997 8-hour ozone NAAQS and have been since 2008 (based upon the 2006-2008 monitoring data). All of the DFW monitors that EPA projected were adversely impacted by Louisiana emissions, save one, are also currently in attainment with that NAAQS. The design value at that one monitor at issue in DFW is 86 ppb, just 2 ppb above the standard. [EPA-HQ-OAR-2009-0491-3735.1_NODA, pp.2-3]

5 Texas Commission on Environmental Quality, CAMS 403, PM-2.5 (Local Conditions) Acceptable Summary for 2010, http://www.tceq.state.tx.us/cgi-bin/compliance/monops/yearly summary.pl (last visited Sep. 21, 2010).
6 Texas Commission on Environmental Quality, PM2.5 Data: Soot, Dust, Particulate Matter, (last visited Oct. 1, 2010)
Response: 
EPA has updated its IPM modeling and EGU emissions inventories in response to comments on the IPM version 3.02 for the base case.  As a consequence, the base case EGU emissions for states have changed.  EPA conducted its final air quality modeling off the updated base case.  In the final Transport Rule, Louisiana is no longer subject to Transport Rule annual PM2.5 programs.  However, the updated IPM and air quality modeling indicate the state is still "linked" to Texas receptors sites at Brazoria and Harris for 8-hour ozone.  See section V.D of the preamble for more details.  Additionally, see IPM documentation,  "Documentation Supplement for EPA Base Case v.4.10_FTransport  -  Updates for Final Transport Rule" and "Transport Rule IPM Assumptions Response to Comments" for details regarding IPM updates and assumptions in the v.4.10 used in the final Transport Rule.  Also, EPA notes that the 2012 base case used in air quality modeling represents power sector operations in the absence of CAIR.  Both the proposal and final rule preamble explain why this is necessary.  Therefore, comments suggesting that 2012 base case emissions data and receptor status in the final Transport Rule are incorrect simply because they do not reflect recent emissions data and receptor status observed once the CAIR rule was final are misguided, as EPA has clearly stated that the base case represents a world without CAIR.
Organization: Southern Company
Comment: 
Southern Company
X. EPA Used Many Inaccurate Inputs and Assumptions for-and Unrealistic Outputs from-EPA's Integrated Planning Model (IPM)
Note that while EPA made numerous errors in assumptions on emission rates, control technologies and other parameters, we are not including comprehensive specific comments on those errors since EPA has already proposed new data through the NODA. Some of the errors identified to date are listed below. [EPA-HQ-OAR-2009-0491-2864.1, p. 23]
A. EPA Made Many Assumptions in NEEDS 3.02 Regarding Individual Units that Are Inaccurate
Our review has found that EPA incorrectly characterized a number of the existing dispatchable FGDs for some of Alabama Power Company's units as not existing until 2012. [See EPA-HQ-OAR-2009-0491-2864.1, pp. 23-25 for list of individual units.] [EPA-HQ-OAR-2009-0491-2864.1, p. 23]
B. EPA Made Many Assumptions in IPM Regarding Individual Units that Are Inaccurate Below are errors identified in the IPM Modeling Inputs. Most of the errors we have found in IPM model files are related to the Georgia Multipollutant Rule (see Attachment A) and timing of controls. [See EPA-HQ-OAR-2009-0491-2864.1, p. 25 for list of individual units.] [EPA-HQ-OAR-2009-0491-2864.1, p. 25]
Although not explicitly explained, IPM predicted that the vast majority of dual fuel units would run exclusively on natural gas. Therefore, EPA did not allocate any S02 allowances to dual fuel units. Apparently, IPM concluded that it was most 'economical' to run these units on natural gas and failed to consider seasonal constraints on natural gas supply (e.g., shortage of supply during the winter months). For example, IPM modeling assumes the Plant McManus will burn natural gas in 2014, and yet we have no plans to do so. Plant McManus is not currently permitted to bum natural gas and does not even have a current gas supply. Also, the 'preferred' remedy IPM cases for 2012 and 2014 show Plant McManus not operating at all (e.g., no heat input and no emissions). Georgia Power conducted a study on conversion to natural gas thirty years ago that found that while an existing natural gas line was near the plant site, the supply from that line would not be adequate for the plant. The study has not been updated recently. Suppliers also generally ask for a commitment to consume a certain amount of natural gas, which we may be unable to do considering McManus is a peaking facility. Conversion to natural gas would also involve building a gas lateral from the supplier's lines, which we may or may not be able to accomplish quickly. Additional cost and schedule considerations involved in building a gas lateral include acquiring right-of-way property and potential permitting activities. In summary, there are no plans to convert McManus to natural gas by 2014 and, because of potential regulatory permitting and technical limits of the existing pipeline, it is unlikely that it is possible to do so in that timeframe. [EPA-HQ-OAR-2009-0491-2864.1, pp. 25-26]
Below are additional errors identified in the IPM-Modeled outcomes
IPM assumes as a control strategy 'early retirements' for McManus (1 & 2), Watson (1 & 3), and Sweatt (1 & 2). The 'preferred' remedy IPM case in 2012 and 2014 does not project that any of these will operate (e.g., no heat input and no emissions). Retirement of any unit is a complex decision based on projected need, transmission requirements, reliability requirements, and cost. An assumption by IPM of an early retirement of a unit may be greatly flawed and should not dictate future allocations for that unit. The Company currently has no plans to retire these units.  [EPA-HQ-OAR-2009-0491-2864.1, p. 26]
-When compared to recent historical data, there appear to be some assumptions for switching to lower sulfur coals within grade for certain units in the 2012 base case. We will defer our detailed comments for the NODA comment period. However, in particular, the S02 emission rates for Plant Yates Unit 2-7 all appear to be much lower than recent actual S02 emission rates and may indicate a switch to lower sulfur coal within grade (or may be due to incorrect fuel assignment of 'Coal Steam' in NEEDS). Some other units, such as Kraft and McIntosh also appear to have lower S02 rates than recent actual, although the differences are less drastic than Yates. As noted earlier, even simple coal switches can take years to implement. The emission rates assumed for these three plants imply an average bituminous coal sulfur content in the 0.6-0.7% range, for which such considerations as coal availability and supply reliability, transportation availability, and cost become extremely important. [EPA-HQ-OAR-2009-0491-2864.1, p26-27]
Furthermore, EPA erred in assuming that units 4, 5, 6 and 7 at Plant Crist in Escambia County, Florida, and units 4 and 5 at Plant Crystal River in Citrus County, Florida, have dispatchable wet FGDs that would not operate in the 2012 base case. In fact, the operation of these wet FGDs are required by the state of Florida (see construction permits No. 0330045-023-AC (Crist) (Attachment C) and No. 0170004-019-AC (Crystal River), both of which are being incorporated in their Title V permits) and would reduce the total combined Florida EGU (> 25 MW) S02 emissions by almost 40% from the 2012 base case. Had EPA properly accounted for a) the reduction in local emissions in the Birmingham area and b) emissions reductions from Florida sources in the base case, that analysis would almost certainly have found that Florida did not interfere with maintenance of the annual PM2.5 standard in Birmingham, AL. Therefore, Florida should not be considered for inclusion as a Group 1 state. [EPA-HQ-OAR-2009-0491-2864.1, p. 43]
Response: 
First, EPA changed its allocation methodology to be based on historic heat input and emissions data that is generally reported by the sources' DR who testifies to its accuracy and completeness.  This was done in response to comments that expressed concern/disagreement about the IPM unit level projected emissions on which the proposed allocations were based.  By switching to a historic  data based methodology, the degree to which any discrepancy between a units actual future operation and its projected future operation would impact the unit's allocation is greatly diminished.  EPA recognizes that IPM is a dynamic linear programming model that generates optimal decisions under the assumptions of perfect foresight and results in a least cost method of meeting demand.  However, invariably, there will be discrepancies between IPM unit level projections and a unit's actual future operations due to non-economic or other variables that IPM does not capture.  At the state and regional level, the discrepancies are small and random and thus do not result in biases.  However, their impact at the unit level may be significant and this was one of the drivers behind switching to an allocation method based on historic data. For more information on the allocation method, see Preamble Section VII D.
Second, EPA reviewed the comments and has made significant updates to its IPM v.3.02 modeling used at proposal.  These updates include changes to both the more general IPM assumptions (e.g., gas price assumptions) and specific unit level assumptions (e.g., that current retrofit status at a unit).  These updates were made to the IPM model, and the updated versions (EPA IPM v.4.10) was used for all the final rule analysis.  In regards to unit specific adjustments, EPA did not manually adjust projected unit level modeling outputs, but it did make unit level updated to its NEEDS database used as a model input that impacted the unit level model outputs.   Some of the most frequent general IPM comments noted above that were addressed in the updates are: FGD removal efficiency was adjusted for new retrofits, and for existing retrofits it was indexed to historic performance at the unit.  Additionally, many of the above comments were focused on a sources ability to switch coals.  EPA modified its modeling to better reflect the cost and feasibility of switching and blending coals.  State Rule and consent decrees were updated according to comments.  Additionally, there were more than 1000 unit specific modeling changes made in response to corrections provided by the commenter.  For more detailed discussion of EPA IPM v.4.10 assumptions and assumption updates, see the EPA IPM v.4.10 documentation and the "Transport Rule IPM Assumptions Response to Comments" in the Appendix
Organization: State of Wisconsin, Department of Natural Resources
Comment: 
State of Wisconsin, Department of Natural Resources
At a minimum EPA needs to consider critical fixes to the IPM model which address several basic assumptions and parameters for individual units. One such assumption is that EPA needs to consider that equipment installations typically require approval from several state agencies which adds to installation timeframes. The IPM model also backslides on S02 emissions for individual units by providing for allowances up to permitted emission rates several times higher than actual emission rates. Corrections are also provided for existing and committed emission rates and addition of missing generation units. Other issues include facilities that have dedicated service loads such as Valley, Milwaukee County Power Plant and Presque Isle which must be considered in both scheduling outages and overall operation in setting emission budgets and allowing for modeled retirement. Specific comments to the IPM model and Wisconsin units, compiled to date, are provided in Appendix B [See EPA-HQ-OAR-2009-0491-2829.3, p.6 for comments pertaining to Appendix B]. An updated version of these fixes will be submitted in comment to the EPA's NODA request for the Transport Rule. [EPA-HQ-OAR-2009-0491-2829.2, p.13] [See EPA-HQ-OAR-2009-0491-2829.2, pp.14-18 for figures 1-5: Figure 1: Total Heat Input to EGU Generation - 9 States, Figure 2: NOx Mass (Annual Tons) - Historic & Projected Programs in 9 states, Figure 3: Average Annual EGU NOx Emission Rate Trend 2002 and 2005-09 in 9 States compared to TR 2014, Figure 4: SO2 Mass (Annual Tons) - Historic & Projected Programs in 9 States, Figure 5: Average Annual EGU SO2 Emission Rate Trend 2002 and 2005-09 in 9 States compared to TR 2014]
From an inventory perspective, EPA had to project baseline uncontrolled and FIP-controlled future EGU inventories in order to assess contribution and remedy impacts, but the Agency places too much weight on the projection of EGU regional loading patterns and emissions controls exclusively using the IPM model. The model uses a perfect foresight approach to EGU sector operation and controls investment algorithms. (This concern is more fully addressed in comments below dealing with the setting of EGU program budgets to fully address EGU contribution.) [See EPA-HQ-OAR-2009-0491-2829.2, p.7 for comments pertaining to the setting of EGU program budgets to fully address EGU contributions; See EPA-HQ-OAR-2009-0491-2829.2, pp.6-7]
Response: 
EPA changed its allocation methodology to be based on historic heat input and emissions data that is generally reported by the sources' DR who testifies to its accuracy and completeness.  This was done in response to comments that expressed concern/disagreement about the IPM unit level projected emissions on which the proposed allocations were based.  By switching to a historic  data based methodology, the degree to which any discrepancy between a units actual future operation and its projected future operation would impact the unit's allocation is greatly diminished.  EPA recognizes that IPM is a dynamic linear programming model that generates optimal decisions under the assumptions of perfect foresight and results in a least cost method of meeting demand.  However, invariably, there will be discrepancies between IPM unit level projections and a unit's actual future operations due to non-economic or other variables that IPM does not capture.  At the state and regional level, the discrepancies are small and random and thus do not result in biases.  However, their impact at the unit level may be significant and this was one of the drivers behind switching to an allocation method based on historic data. For more information on the allocation method, see Preamble Section VII D.
EPA reviewed the comments and has made significant updates to its IPM v.3.02 modeling used at proposal.  These updates include changes to both the more general IPM assumptions (e.g., gas price assumptions) and specific unit level assumptions (e.g., that current retrofit status at a unit).  These updates were made to the IPM model, and the updated versions (EPA IPM v.4.10) was used for all the final rule analysis.  In regards to unit specific adjustments, EPA did not manually adjust projected unit level modeling outputs, but it did make unit level updated to its NEEDS database used as a model input that impacted the unit level model outputs.   Some of the most frequent general IPM comments noted above that were addressed in the updates are: FGD removal efficiency was adjusted for new retrofits, and for existing retrofits it was indexed to historic performance at the unit.  Additionally, many of the above comments were focused on a sources ability to switch coals.  EPA modified its modeling to better reflect the cost and feasibility of switching and blending coals.  State Rule and consent decrees were updated according to comments.  Additionally, there were more than 1000 unit specific modeling changes made in response to corrections provided by the commenter.  For more detailed discussion of EPA IPM v.4.10 assumptions and assumption updates, see the EPA IPM v.4.10 documentation and the "Transport Rule IPM Assumptions Response to Comments" in the Appendix
EPA notes that while its final allocation methodology does not directly consider emission limits at a source due to permit rates or consent decrees, it does, however, indirectly factor in these requirements to the extent they are reflected in the source's historic baseline emissions that used to determine final allocations.  The maximum historic emissions over the baseline period serve as a ceiling on the total allocation to any particular source.  Therefore, if the permit rate limits or consent decree requirements are reflected in the historic baseline emissions that form the basis of this ceiling on allocations, then they are indirectly factored into the final allocations.  Furthermore, regardless of the initial allocation to a source under a Transport Rule FIP, it by no means changes that source's legal responsibility to comply with pre-existing permit or consent decree limits regarding its emissions.  The allocation to any particular source does not allow for "backsliding".  
As discussed in section VII.D, the state budget is determined independently of the allowance allocation, and therefore the allocation methodology has no bearing on whether a state fully eliminates its significant contribution and interference with maintenance to downwind states.  Such elimination is assured by the imposition of the state budgets.
Organization: Virginia Department of Environmental Quality (VDEQ)
Comment: 
Virginia Department of Environmental Quality (VDEQ)
EPA should review the NEEDS inputs and IPM outputs for Mirant-Potomac River (ORIS Code 3788). All units as this facility have been retrofitted with sorbent injection for S02 control. Copies of the relevant permits for this facility may be found at the above websites. This control does not appear to be reflected in the NEEDS input for the units. IPM outputs for the limited trading case for this facility indicate that SNCR may be installed in future years on units 1 and 2. This conclusion by IPM is quite puzzling since 1 and 2 are smaller, older units than 3, 4, or 5. VDEQ knows of no plans for this facility to install additional NOx control devices beyond those listed in the facility's permits. [EPA-HQ-OAR-2009-0491-2595.1, p.4]
Response: 
SO2 control is reflected for units at the Mirant-Potomac River Facility in the final IPM modeling.  In addition the updated IPM modeling does not reflect SNCR installation on units 1 & 2.
Organization: Xcel Energy Inc.
Comment: 
Xcel Energy Inc.
4. Xcel Energy has identified errors in the NEEDS database and the IPM input files.
Xcel Energy has conducted a detailed analysis of EPA's modeling to ensure all inputs are correct and has found several errors. A complete listing of these errors is shown in Appendix A [see page A-1 of this comment for Appendix A]. A few main points about these errors are summarized below. [EPA-HQ-OAR-2009-0491-2728.1, p.10]
- EPA has indicated in the IPM 3.02 runs that the Jones Unit 1, Plant x Units 1, 2, 3 and 4 will have SCR retrofits in 2012. These units are currently gas fired units used for load following and peaking purposes. Xcel Energy has no plans at this time to install SCR on these units. EPA also indicates that these units as well as Moore County Unit 3 will be retired in 2014. Xcel Energy does not plan to retire Jones Unit 1, nor Plant X Unit 3, nor Plant X Unit 4 by 2014. Plant X Units 1 and 2 as well as Moore County Unit 3 are planned to be retired by 2014. [EPA-HQ-OAR-2009-0491-2728.1, p.10]
- In its documentation EPA indicates there was unusually low utilization of generation facilities in 2009, so the Agency used 2008 data to adjust NOx allocations. Some of Xcel Energy's facilities had higher utilization in 2009 than 2008. This affects Black Dog Units 3 and 5; Sherburne County Units 1, 2 and 3; Blue Lake Units 2 and 4; and Inver Hills Unit 3; Bay Front Units 1 and 2; French Island Unit 3; and Wheaton Unit 5. EPA should use the higher of the heat inputs from 2008 or 2009 rather than automatically using 2008 data. This would better capture both the impact of economic downturns and scheduled outage activities that affected utilization in both years. [EPA-HQ-OAR-2009-0491-2728.1, p.10]
- Some peaking units had no projected heat input from IPM, and therefore no projected NOx or SO2 emissions. According to the protocols set forth in the CATR, EPA would then have used actual data to determine allocations. Unfortunately, some of these peaking units did not have four quarters of actual data, which results in the zeroing of emissions over these years instead of the summation of the data within this time period. This resulted in the elimination of NOx allocations for Blue Lake Units 1 and 3; Inver Hills Units 2, 4 and 5; French Island Units 3 and 4; and Wheaton Units 5 and 6. EPA should use the sum of the available emissions data from the greater of 2008 or 2009 rather than zeroing out these emissions. [EPA-HQ-OAR-2009-0491-2728.1, pp.10-11]
- For facilities with a SCR installed, EPA adjusted the allocations from actual data by applying the most recent NOx ozone season rate to 2008 heat input instead of using actual annual emissions data. This effectively decreased the number of allocations for King (1330 vs. 1478). EPA did this to account for facilities which do not run their SCR year-round or at full capacity. Since we do not bypass the SCR at any facility, or run SCRs at less than their capability, EPA should use unadjusted data for King. [EPA-HQ-OAR-2009-0491-2728.1, p.11]
- In general, IPM v3.02 tends to either not dispatch combustion turbine ('CT') / combined cycle ('CC') units (e.g., Blue Lake Units 1 through 4 and Inver Hills Units 1 through 6) or greatly underpredict generation as compared to internal forecast models (e.g., Black Dog Unit 5; High Bridge Units 7 and 8), thus depriving these facilities of some or all NOx allocations. EPA should examine the IPM model to determine whether this is a consistent outcome on a national basis or a regional one impacting only Minnesota. If EPA finds this to be a national issue, EPA should correct the IPM model to more accurately reflect actual operation of these units. [EPA-HQ-OAR-2009-0491-2728.1, p.11]
Response: 
In response to the concerns expressed above,
EPA first modified its allocation methodology from one based on projected data, to one based on historic data.  This addresses many of the concerns that commenter expresses above regarding allocations to specific units.  As a result of the allocation methodology change, allocations to specific units have changed as well.  See section VII.D of the preamble for more discussion on this, and the Technical Support Document on allocations and the allocation tables themselves for a listing of the revised allocations under the FIP.  Furthermore, EPA has made significant changes to its IPM modeling based on concerns such as those expressed above.  The IPM modeling has been updated, and these changes are reflected in the final EPA IPM v.4.10.  The IPM documentation and supplemental documentation describes changes and assumptions in the final model version.  See Appendix to RTC for "Transport Rule IPM Assumptions Response to Comments".  Generally speaking, EPA did not make direct modifications to IPM projections in response to unit level comments.  It did however make modifications to modeling inputs that reflect the current status of generating resources.  These modifications often do impact the unit level projections for the units.  However, EPA notes that IPM is a dynamic linear programming model that generates optimal decisions under the assumptions of perfect foresight and least cost.  EPA acknowledges that there may be instances where unit level projections under such a model are different than the sources actual future operating patterns (e.g., IPM projects a unit not to operate, but the unit does operate for potential non-economic or other factors that the model does not capture).  This, in part, was one of the drivers for switching to a historic data based approach for allocations.  Doing so, minimizes any direct monetary impact that a discrepancy between projections and future unit operation would have on a source.

XVIII.C.2. September 1, 2010 NODA: EGU Projections Using IPM/NEEDS V.4.10

Organization: America's Natural Gas Alliance
Comment: 
America's Natural Gas Alliance
In that regard, ANGA welcomes the Agency's decision to use the updated IPM power sector modeling platform (VA.10), including integrating natural gas modeling directly into the IPM. As discussed in the Agency documentation of IPM Base Case VA10, the new natural gas module contains several improvements over prior base cases which were developed outside of the IPM.2 For the first time, natural gas supply dynamics will be directly modeled into the base case, ensuring that the most accurate, up-to-date information is used in the development of this critical program. ANGA does suggest that it would be appropriate to use the model results from the updated IPM VA.10 runs to modify the State-level caps, both from a good science and good clean air policy perspective. Finally, ANGA encourages EPA to revise the allowance allocation methodology proposed in the CATR, both with respect to the fundamental methodology and the issue of subsequent updating of the inventory.  [EPA-HQ-OAR-2009-0491-3748.1_NODA, p.2]
Given the importance of this rulemaking and the opportunity to make the CATR as effective as it can be in reducing NOx and SO2 emissions and the impact of interstate transport of those emissions, ANGA believes that modeling used to support the final CATR must use the most current, accurate and up-to-date information and assumptions. In that regard, we concur with the Agency that 'the assumptions regarding natural gas resources in the primary IPM v4.10 base case are the appropriate ones to use.' EPA also suggests in the NODA and in information available in the docket, that it is considering another option regarding gas price assumptions. EPA specifically requests comment on: [P]erforming an additional set of reference and policy runs with a gas scenario that starts with the resources assumptions in the EPA primary case but limits production of those resources due to uncertainties affecting their development. These uncertainties include still to be resolved environmental and land use issues affecting shale development. [EPA-HQ-OAR-2009-0491-3748.1_NODA, p.3]
ANGA submits that this option should not be developed and run. As stated above, we believe that the EPA Base Case VA.10, which was run using a resource base that reflects economically recoverable resources using current technology under existing regulatory frameworks, utilizes the correct set of assumptions regarding the natural gas market. The Agency has not indicated with any degree of specificity the manner in which it would seek to, or the assumptions it would use to, change the assumptions to limit production of natural gas. In the absence of any such information in either the proposed CATR or in the NODA, we cannot comment on what production limitation assumptions the Agency might consider using in the model the Agency ultimately decides to deploy and, as a result, we do not believe that the Agency can consider this third option in the CATR. [EPA-HQ-OAR-2009-0491-3748.1_NODA, p.3]
The Agency also indicates that 'during the comment period, EPA will accept comments on both the specific data that EPA is placing in the docket as well as any potential impacts of that data on the Proposed Transport Rule.  In terms of the potential impact of using the new IPM VA.10 runs to support the CATR, ANGA believes that the Agency should in fact modify the State-level caps that were modeled using the old IPM in the proposed CATR to reflect changes that the new modeling may suggest and, as we discuss in more detail below, adjust the allocation methodology. [EPA-HQ-OAR-2009-0491-3748.1_NODA, p.3]
Specifically, ANGA suggests that the significantly higher gas demand and significantly lower gas prices in the Agency's preferred resource assumptions result in significantly greater incentives for companies with coal-fired generation that is uncontrolled (or under-controlled) and/or close to the end of its useful life to switch fuels to natural gas. Models run using this higher demand and lower gas prices would therefore reflect more rapid and extensive fuel switching, and the resulting changes that the modeling would suggest could in turn result in lower State-level caps going forward. These models would then reflect more accurately overall emission reductions and improved air quality that result from earlier and more frequent fuel switching. [EPA-HQ-OAR-2009-0491-3748.1_NODA, pp.3-4]
In addition, depending on the methodology utilized to allocate emissions, use of new State-level caps based on the updated IPM V.l0 modeling may serve to reduce the level of allocations to coal plants in individual states, thus helping to promote fuel switching from coal to gas in those states. [EPA-HQ-OAR-2009-0491-3748.1_NODA, p.4]
Unit Level Allocation Method and Periodic Updating [EPA-HQ-OAR-2009-0491-3748.1_NODA, p.4]
The issues raised in the NODA also underscore ANGA's concerns with the Agency's proposed approach to allocating emission allowances to individual units based on modeled or historic actual emissions. Allocating allowances to high emitting units, based on their historical emissions of the pollutants that the Agency is seeking to reduce, essentially subsidizes the continued operation of older, uncontrolled (or undercontrolled) high emitting units. On the other hand, allocation methodologies utilizing historic output (megawatt-hour) or input (heat such as million British thermal units) provide incentives for utilizing cleaner, more efficient sources, such as natural gas-fired units. Historic energy output or heat input methods also promote the early adoption of control technologies, which would be discouraged under an emissions-based allocation. [EPA-HQ-OAR-2009-0491-3748.1_NODA, p.4]
Accordingly, ANGA suggests that that the Agency consider the use of either an output-based unit level allocation methodology (similar to that deployed in Massachusetts' NOx cap and trade program) or an input-based methodology (similar to the methodology employed by the Agency in the NOx SIP Call and in the Clean Air Interstate Rule, but without the fuel-adjustment factors that were explicitly rejected by the U.S. Court of Appeals for the District of Columbia Circuit). These unit level allocation methodologies will ensure that the CATR sends the right economic signals to achieve the purpose of the rule - cleaner air. [EPA-HQ-OAR-2009-0491-3748.1_NODA, p.4]
Energy output and heat input methodologies also reduce the risk of legal challenges and their attendant delay. Energy output and heat input provide a clear, simple way to allocate emissions, while modeled future emissions are complex and likely to generate a number of errors that could be considered arbitrary and capricious. [EPA-HQ-OAR-2009-0491-3748.1_NODA, p.4]
Finally, assuming the Agency were to allocate allowances on either an output or input basis, ANGA also suggests that the Agency reverse its decision to allocate allowances to existing units once, and to periodically update allowance allocations going forward. to As increased fuel switching continues to result in greater use of natural gas in the power generating sector, it is good environmental policy to periodically update the allocation of allowances, as doing so would both avoid imposing a defacto penalty on companies that switch to cleaner burning fuels and provide greater incentive for fuel switching at existing coal-fired units. [EPA-HQ-OAR-2009-0491-3748.1_NODA, pp.4-5]
ANGA recognizes that there needs to be some degree of predictability in allowance allocation for purposes of ensuring a robust and stable allowance trading market; however, we suggest that the Agency consider updating the allocation system every three years to allow the allowance market to take into consideration modernization of the power generating sector. [EPA-HQ-OAR-2009-0491-3748.1_NODA, p.5]
Response: 
EPA finalized an allocation methodology based on heat input, as suggested by the commenter.  See section VII.D of the preamble for a description of the finalized allocation methodology.  Additionally, see EPA IPMv.4.10 documentation for a discussion on the gas assumption used in the final rule analysis.
Organization: City Utilities of Springfield
Comment: 
City Utilities of Springfield
Specific issues: [EPA-HQ-OAR-2009-0491-3733.1_NODA, p.1]
The data table contains known errors regarding our Southwest Power Station. [EPA-HQ-OAR-2009-0491-3733.1_NODA, p.1]
Issue: The NEEDS 4.10 database indicates that the Southwest Power Station has a wet FGD in place. As we have indicated in our EIA Form 860 filings and our revised monitoring plan under the Acid Rain Program, the FGD at this facility had to be decommissioned and removed due to severe scaling, corrosion, and structural integrity concerns. Southwest Power Station now complies with all federal and state SO2 requirements by burning compliance coal from the Powder River Basin. This correction in the NEEDS database would materially impact the cost efficiency of additional SO2 control at the Southwest Station and the resulting state budget for Missouri. [EPA-HQ-OAR-2009-0491-3733.1_NODA, pp.1-2]
Recommendation: The NEEDS database must be corrected to reflect actual baseline conditions at the Southwest Power Station. The economics of additional (Phase 2) SO2 control at Southwest requires recalculation and Appendix A adjusted accordingly. [EPA-HQ-OAR-2009-0491-3733.1_NODA, p.2]
The data table contains errors regarding control equipment on combustion turbines at our McCartney Generating Station and James River and Southwest Power Station. [EPA-HQ-OAR-2009-0491-3733.1_NODA, p.2]
Issue: NEEDS 4.10 indicates that our McCartney Generating Station Units 1 and 2 (ORIS 7903; MGS1 and MGS2) are equipped with water injection and SCR for NOx control. In actuality the turbines only have water injection. There are no SCR controls on the McCartney units. Further, NEEDS 4.10 does not indicate usage of water injection to control NOx emissions for our James River Power Station Gas Turbine 1 (ORIS 2161; **GT1) and Southwest Power Station Combustion Turbines (ORIS 6195; CT1 and CT2). [EPA-HQ-OAR-2009-0491-3733.1_NODA, p.2]
Recommendation: The NEEDS database must be corrected to remove the SCR designation and include water injection controls for the listed combustion turbines. [EPA-HQ-OAR-2009-0491-3733.1_NODA, p.2]
The data table appears to underestimate the future operation of combustion turbines at our Southwest, James River, and McCartney Stations. [EPA-HQ-OAR-2009-0491-3733.1_NODA, p.2]
Issue: The draft version of Table A included with the pre-publication version of the Transport Rule allocated zero allowances to combustion turbines located at our James River, Southwest, and McCartney generating stations. Presumably, this was a result of the IPM model result indicating that the combustion turbines will cease to operate following promulgation of this rule. However, we are unable to trace this result from the information provided in the NODA. In actuality, combustion turbines will continue to be a valuable generating asset for City Utilities and other Missouri municipal utilities. Our internal PROSYM modeling indicates that we will continue to run these units for hundreds of hours per year well into the future. These units not only provide rapid response to peak demand in ways that our steam units are unable, but also represent spinning reserve capacity required by electric reliability regulators. These factors presumably were not considered in the cost-based IPM modeling analysis. [EPA-HQ-OAR-2009-0491-3733.1_NODA, p.2]
Recommendation: The Appendix A allocation table should be corrected to reflect expected operating scenarios for affected combustion turbines owned by City Utilities and other Missouri utilities. As a starting point, all turbines should be assumed to operate up to 1,500 hours per year. [EPA-HQ-OAR-2009-0491-3733.1_NODA, p.3]
The data table does not include our Southwest Unit 2, scheduled to come on line on or about January 1, 2011. [EPA-HQ-OAR-2009-0491-3733.1_NODA, p.3]
Issue: The NEEDS 4.10 database does not contain an entry or a placeholder for our Southwest Unit 2, a 300 MW coal-fired unit permitted in late 2004. This unit should have been included as a "Planned-committed" resource in the IPM 4.10 model run. As we indicated in comments to the rule proper, Southwest 2 appears to fall in with a handful of new units that will be placed in regulatory Neverland with respect to the new rule. Our earlier comments requested clarification in the Transport Rule definitions that this unit would be eligible for allocation from the New Unit pool. However, it might be more appropriate to list them in the database, assign a permanent allocation, and avoid confusion and administrative costs in the future. If this approach is taken, City Utilities would be prepared to provide additional data concerning the Southwest 2 project. [EPA-HQ-OAR-2009-0491-3733.1_NODA, p.3]
Recommendation: Confirm that Southwest Unit 2 was included in the IPM model run and allocate Appendix A allowances accordingly. [EPA-HQ-OAR-2009-0491-3733.1_NODA, p.3]
Response: 
EPA appreciates the commenters correction data and its response is twofold:
1) EPA adjusted its IPMv.4.10 NEEDS database to reflect the comments.  For example, the Southwest Power Station no longer is listed as having an FGD in place, as suggested by commenter.  Also, the McCartney Generating Station is no longer listed as having SCR controls.
2) These unit level corrections suggested by commenter were linked to concerns expressed about unit level allocations.  EPA has finalized an allocation approach that is based on historic, not projected data, which also addresses the concern that a unit level discrepancy between the model and a unit would have a large impact on the unit's allocation.
Organization: Consumers Energy
Louisiana Chemical Association (LCA)
PPG Industries, Inc.
National Grid
Electric Energy, Inc. 
Edison Electric Institute (EEI)
Allegheny Energy
Consolidated Edison Company of New York, Inc, (CECONY)
Massachusetts Department of Environmental Protection
American Electric Power
Occidental Chemical Corporation (OCC)
Capital Power Corporation
DTE Energy Services (DTEES)
PSEG Services Corporation
Dominion
PPL Corporation
Buckeye Power, Inc.
Cogen Technologies Linden Venture, LP
First Energy
Southern IL Power Cooperative
West Virginia Department of Environmental Protection
Northern Star Generation LLC
Marquette Board of Light and Power
Lafayette Utilities System
International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers and Helpers (AFL-CIO Boilermakers Union)
San Miguel Electric Cooperative, Inc.
Coal Utilization Research Council
Louisiana Energy and Power Authority (LEPA)
Exxon Mobil Corporation
Gulf Coast Lignite Coalition
National Mining Association (NMA)
Cleco Corporation
DTE Energy
Exeter Energy Limited Partnership
Big Rivers Electric Corporation
South Carolina Department of Health and Environmental Control 
Duke Energy
Seminole Electric Cooperative Inc.
Florida Municipal Power Agency (FMPA)
Council of Industrial Boiler Owners (CIBO)
Clean Air Task Force
State of Louisiana, Department of Environmental Quality
Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
Ameren Services Company
Florida Electric Power Coordinating Group, Inc. (FCG)
Oglethorpe Power
Institute of Clean Air Companies (ICAC)
Dairyland Power Cooperative
National Rural Electric Cooperative Association (NRECA)
Louisville Gas and Electric Company (LG&E) and Kentucky Utilities Company (KU)
Old Dominion Electric Cooperative
Peabody Energy Company
Mirant Corporation
Nelson Industrial Steam Company (NISCO)
Ohio Utility Group (OUG)
AES Corporation (AES)
Comment: 
AES Corporation (AES)
Additionally and most importantly, this comment period does not allow time for complete review of all NODA data, NEEDS data and additional errors are likely to commiserate with the many other company inaccuracy notices. [EPA-HQ-OAR-2009-0491-3793.1_NODA,p.8]
Allegheny Energy
The NEEDS V4.10 (NEEDS) database (released September 1, 2010 as an update to NEEDS V3.02) used by EPA contains errors relative to AE power stations. These errors when used as input data for the IPM can propagate errors in modeling results which in turn could skew EPA's regulatory analysis. Specifically, the NEEDS errors identified by AE are:
1) Cold side electrostatic precipitators with flue gas conditioning and wet scrubbers are listed as a control device for particulate matter (PM) on the three units at AE's Harrison power station located in West Virginia. Harrison power station does not have PM scrubbers.
2) Selective non-catalytic reduction controls are listed for the two units at AE's Armstrong power station in Pennsylvania. These units had Mobotech Rotamix systems installed in 2003, but they have since been removed because of operating problems.
3) AE's Mitchell power station in Pennsylvania has a FGD scrubber S02 removal efficiency listed as 99.9%. Actual scrubber removal efficiency at Mitchell power station averages 97%. [EPA-HQ-OAR-2009-0491-2605.1, p.4]
4) The FGD scrubber S02 removal efficiency for AE's Pleasants power station in West Virginia is listed at 97%. Actual scrubber removal efficiency at Pleasants power station for 2008 - 2009 averages 95%. [EPA-HQ-OAR-2009-0491-2605.1, p.5]
Ameren Services Company
The NODA continues to assume that CAIR is not in place [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.3]
In 2008 the U.S. Court of Appeals for the D.C. Circuit found the Clean Air Interstate Rule (CAIR) to be 'fundamentally flawed,' initially vacating and remanding it to EPA See North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008). However some months later in December, the D.C. Circuit Court of Appeals remanded the CAIR without vacatur, North Carolina v. EPA, 550 F.3d 1176 (D.C. Cir. 2008), instead, leaving CAIR in place until EPA cured the flaws in CAIR. Therefore CAIR is a viable rule and utilities must currently comply with the stringent nitrogen oxide (NOx) and sulfur dioxide (SO2) limits prescribed by the rule. [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.3]
EPA has assumed in this NODA as in the original analysis (IPM 3.02) that the CAIR program is not in place and that affected sources are not complying with the rules. This assumption is in error. By not including compliance with CAIR in its assumptions, the EPA analyses have over stated the impact of these sources prior to the imposition of the proposed transport rule considered here. This assumption completely invalidates EPA's analysis and the results produced. EPA should redo the analysis assuming that CAIR is fully in place and the affected sources are complying with the regulations. EPA should view CAIR as the valid control program that it is and allow sources to smoothly transition to the future rules to be promulgated, just as was done between the NOx SIP Call trading program and the CAIR. [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.3]
EPA bas not supplied all the information necessary to properly review the NODA and its affect on the Transport Rule [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.3]
EPA in the NODA has admitted that the IPM 4.10 information will be used for but not limited to: [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.3]
'Changing emission projections that were used to determine which downwind areas have air quality concerns (i. e., non-attainment or maintenance) absent this rulemaking and to determine which States contribute to those problems. [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.3]
Changing cost and emission projections used in the multi-factor test to determine the amount of emissions that represent significant contribution.' [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.4]
These changes are far ranging and could affect many aspects of the final rule. EPA needs to supply additional information on how this IPM 4.10 modeling will affect the final Transport Rule. For example consider the following [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.4]
The difference in using AEO 2008 and AEO 2010 projections for utilization is dramatic. In Ameren's case projected heat input for 2014 for Ameren Illinois units in the IPM 4.10 case is 32% less than that projected in the IPM 3.02. This most likely will have an effect on the allocation of NOx and SO2 allowances and this information has not been given. It is critical that EPA provide information how the incorporation of this new generation forecast, along with changes in other assumptions will impact 2012 and 2014 unit allocations. [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.4]
EPA has not provided information on how the IPM 4.10 modeling will affect the air quality projections used to identify non-attainment and maintenance areas and the significant impacts various states have on these areas. EPA needs to redo the air quality modeling analysis using emissions and monitored air quality data representative of the conditions represented in the AEO 2010 modeling. Specifically EPA needs to use more recent base case emissions and meteorology and monitored air quality data. Only after EPA conducted the additional analyses needed and has given the proper public notice and opportunity for public comment can EPA finalize the Transport Rule. [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.4]
Too many inconsistencies in the projections produced by IPM 4.10 similar to those found in IPM 3.02. [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.4]
As mentioned above in section I. the projections produced by IPM 4.10 are not in line with Ameren's projections for these units. Consider the following, [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.4]
Ameren has no plans to retire or made any commitment to install SO2 scrubbers on the Joppa units. The SO2 emission rates shown in the 2014 AEO gas case of 0.295 lb/mmBtu are not achievable without some additional controls and none are shown for this scenario in the IPM 4.10 modeling. Ameren has not committed to install SO2 controls for the Joppa units at this time. [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.4]
Ameren's Duck Creek plant currently has operating selective catalytic reduction (SCR) and FGD systems. However the IPM 4.10 modeling exhibits a change in SO2 emissions rates from the IPM 3.02 rates. These rates for IPM 3.02 and IPM 4.10 are 0.133 lb/mmBtu and 0.295 lb/mmBtu respectively. This change in rates seems unexplainable. Is IPM changing fuels, the control efficiency of the FGD or something else? [EPA-HQ-OAR-2009-0491-3739.1_NODA, pp.4-5]
Ameren Illinois' Newton plant has submitted a permit application to construct a wet flue gas desulfurization (FGD) on each of the two units at Newton to meet the Illinois mercury rule and CAIR requirements for SO2. The IPM 4.10 modeling apparently assigns significantly different SO2 lb/mmBtu rates to each of these units. These FGDs have the same design criteria and are on boilers of similar design. This difference makes no sense. For example, since there is no flue gas bypass in the design of these FGD systems the units cannot operate without the scrubbers in service or risk destruction of the FGD. [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.5]
In both of the NODA TR_SB_Limited Trading and TR_SB_Limited Trading ABO Gas IPM 4.10 model simulations Newton Unit 2 is assumed to install an SCR. There are currently no plans to install an SCR on Newton Unit 2 or as described in Ameren's comments on the Transport Rule sufficient time to design, permit and construct one. [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.5]
The Union Electric d/b/a Ameren Missouri Labadie and Rush Island plants are shown in the IPM 4.10 modeling to have SO2 rates around 0.55 lb/mmBtu and no SO2 controls are assumed. These plants currently are averaging in the 0.7Ib/mmBtu range. As mentioned in Ameren's previous comments on the Transport Rule and the IPM 3.02 modeling this would require a change in fuel which may not be possible based the on the projected limited availability of this lower sulfur fuel and other balance of plant issues. [EPA-HQ-OAR-2009-0491-3739.1_NODA, p.5]
American Electric Power
In reviewing the various sensitivity cases run using both the older and new version of IPM, AEP is often confused by the resulting model outputs as it pertains to the operation of our generating fleet. For example, in the updated 2012 base case (new IPM v.4.10 Runs) SCRs were listed as installed at Pirkey, Welsh 2-3 and Rockport 1-2 units. While AEP does face some NOx constraints at Rockport due to the NSR Consent Degree with EPA, it is not projecting additional SCR installations in the near-term. Additionally, Pirkey and Welsh are not subject to any existing NOx emission constraints and it is unclear why the model would be selecting SCRs as economic control technologies under a business as usual scenario. Furthermore, these SCRs do not appear to be achieving 90% removal in the policy runs, so it is unclear why they are being added. Additionally, the IPM v.4.1 0 results show SCR installations at Kammer 2-3 and Clinch River 1-3 in the 2014 policy case which are also puzzling. AEP requests that EPA look into the full rationale behind these illogical modeling results and correct any underlying data or modeling errors. These modeling and/or input errors ultimately manifest themselves in the budget development process. As a result, within the proposed Rule, projected base case SCR installations resulted in the NOx budgets for several AEP units being arbitrarily reduced. [EPA-HQ-OAR-2009-0491-2665.1, p.13] [EPA-HQ-OAR-2009-0491-3719.1_NODA, pp.7-8]
AEP has output driven comments from both versions of IPM, as we remain unsure which underlying errors might have been corrected in the modeling update process. Many of our concerns are directly related to how underlying unit limitations are factored into the modeling, specifically as ultimate allocation and/or potential emission rate limits are proposed to be tied directly to modeled emissions and performance. Furthermore, AEP requests that EPA produce modeling outputs disaggregated and reported at the unit level. It is highly unclear from the parsed data files provided exactly what coal types are being utilized and what constraints individual units are tied to. This level of data is needed to ensure that a proper third-party review can be conducted of the runs used to support the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2665.1, pp.20-21] [[These comments can also be found in XVIII.C.1.]]
At a minimum, EPA should correct the data and assumption issues identified, remodel the air quality impacts assuming a continuation of CAIR-like standards, revise the compliance dates based on reasonable timelines for environmental controls and rerun the economics and subsequent allocations that would result from these changes. A supplemental Transport Rule should then be proposed for comment. [EPA-HQ-OAR-2009-0491-2665.1, p.21] [[These comments can also be found in XVIII.C.1.]]
NEEDS Emission Rates
Several of AEP's units are projected to have NOx rates in NEEDS v.4.l0 scenarios which are inconsistent with either historical or projected operations. The following units should be corrected as listed in the recommended rates below. The recommended control rates are based on AEP's experience operating these units. [EPA-HQ-OAR-2009-0491-2665.1, p.21] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.3][[See Docket Number EPA-HQ-OAR-2009-0491-3719.1_NODA,p.3 for table of units.]]
NEEDS Existing Controls
There are several instances where wet scrubbers are incorrectly listed at AEP owned/operated units within the NEEDS v.4.l 0 database. Kammer Units I & 2 are listed as having had a wet scrubber installed in 2007 though no such controls were added or are planned to be added. Additionally there are incorrect references to wet scrubber installations at John E. Amos Unit 1 (2008), Cardinal Unit 3 (2010) and Kyger Creek Units 1-5 (2010). These are projected to have wet scrubber systems come online within the next few years, but not by the dates assumed in the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2665.1, p.21] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.3]
NEEDS FGD Removal Assumptions
EPA's IPM v.4.10 modeling assumed that all new wet FGD systems average 98% S02 removal with a floor of 0.06 lb/mmBtu. Additionally, its appears all units with FGD controls installed in 2005 or later were defaulted to the 98% removal criteria based on the lack of more recent data availability within the EIA-767 database. While many new wet FGD systems might be able to achieve 98% removal or higher on an intermittent basis, 98% S02 removal is very difficult, if not impossible, to achieve on most units on a year-round basis due to operational upsets and operating variability. AEP recommends revising the assumptions to show 96.5% SO2 removal for all new(er) FGD systems. [EPA-HQ-OAR-2009-0491-2665.1, pp.21-22] [EPA-HQ-OAR-2009-0491-3719.1_NODA, pp.3-4]
For other units operating with older FGD systems, targeted SO2 removal performance based on current operation or design basis is different than the scrubber efficiency listed within the NEEDS database. Scrubber efficiency at Gavin Units 1 &2 should be revised to 94.5% and Dolet Hills Unit 1 revised to 70%. Additionally, the most recent information from Duke Energy on the co-owned Zimmer unit indicates a scrubber efficiency of 93% and should be revised. [EPA-HQ-OAR-2009-0491-2665.1, p.22] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.4]
NEEDS Missing Units
Two operational AEP units are currently missing from the NEEDS database, the Philip Sporn Unit 5 in Mason County, WV and the Conesville Unit 3 in Coshocton County, OH. EPA should refer to EIA for unit characteristics and incorporate these units into the NEEDS database for purposes of further modeling and allocations. [EPA-HQ-OAR-2009-0491-2665.1, p.22] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.4]
IPM Environmental Retrofit Capital Costs
AEP is appreciative of the efforts EPA undertook to update the IPM study with new numbers to better reflect the current costs of procuring and constructing pollution controls. While these updated costs are more accurate, they still underestimate cost of controls for many units due to other factors not currently considered within the cost structure. [EPA-HQ-OAR-2009-0491-2665.1, p.22] [EPA-HQ-OAR-2009-0491-3719.1_NODA,p.5]
The ability to retrofit control technologies remains a major issue at some units due to plant layout and design. Most of the newer and easier to retrofit units have already been retrofitted. As such, the next round of units required to retrofit are likely to be significantly more difficult and costly than previous experience would suggest. Between similarly sized units, costs could vary by two times or more based on unit-specific constraints. AEP recommends EPA include unit-specific multiplier as an IPM input parameter to adjust retrofit costs versus perceived difficulty. [EPA-HQ-OAR-2009-0491-2665.1, p.22] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.5]
It is also apparent that landfill costs were included only as a variable cost within the cost structure for new FGD installations. However, construction of new landfill space to support FGD byproduct disposal are almost always undertaken on-site and require significant capital to be deployed. As such, the initial landfill development cost should be factored into the capital cost of the FGD installation as well as the ongoing variable cost of operation. Landfill development costs are approximately $5 to $40 per kW and should be factored into the model as a capital cost. These costs could increase substantially as a result of the coal combustion residuals rule EPA proposed on June 21, 2010. [EPA-HQ-OAR-2009-0491-2665.1, p.22] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.5]
Because of the low projected capital costs of environmental retrofits, the model is biased in the direction of retrofit versus retire for emissions reductions on uncontrolled units. However, AEP feels that the actual economics, in conjunction with capital requirements to address other forthcoming environmental liabilities, will favor retirement on most uncontrolled units. This will have a definite impact on cost and reliability outcomes. [EPA-HQ-OAR-2009-0491-2665.1, p.23] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.5]
IPM Financial Assumptions
AEP has concerns with how capital recovery factors are calculated for use within IPM as they pertain to retrofit decisions on older coal units. Specifically, the model assumes that these retrofit investments would have a book life of 30 years and a debt and depreciation life of 20 years. However, as the majority of uncontrolled units are older less efficient units, an additional 20-30 years of life expectancy is not guaranteed or even likely. Furthermore, uncertainty as it pertains to additional future EPA regulations means that these investment decisions must clear an even higher hurdle of prudency, which would likely result in the investment needing to be recovered over a 10-15 year time horizon. [EPA-HQ-OAR-2009-0491-2665.1, p.23] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.5]
A similar risk adjustment is already present in the IPM model as investments in new coal are subject to a 'Capital Cost Adder for Climate Change Uncertainty' which results in 3% added to the cost of equity and debt. Old coal is not likely to be treated any different than new coal under climate and other EPA regulations and thus any investment in coal technology should be subject to either an adder or an accelerated timeframe for capital recovery. [EPA-HQ-OAR-2009-0491-2665.1, p.23] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.6]
IPM Coal Suitability
AEP has significant concerns about how various coal types are selected and utilized within the IPM model, ultimately leading to an inaccurate portrayal of the economics and viability of emission reductions through coal switching. In using the parsed IPM output files to back into unit emission rates, it was determined that several of AEP's units are burning coals which they cannot physically use without significant operational limitations or the addition of major capital equipment not currently considered in IPM. [EPA-HQ-OAR-2009-0491-2665.1, pp.23-24] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.6]
One set of concerns relates to the apparent lack of a minimum coal sulfur content model parameter. Many coal-fired boilers are limited to a minimum specification for coal sulfur content due to their boiler configuration, and their electrostatic precipitator (ESP) and/or air permit limitations. For example, wet-bottom boilers capture the majority of their ash in a molten form within the boiler and require coals with low ash fusion temperatures. For eastern bituminous coal, this property is generally correlated with high sulfur fuels. Other limitations due to ESP performance are also found on both wet and dry-bottom units that were initially designed to utilize higher sulfur coals. Lower sulfur coals do not have the same electrical resistivity properties as higher sulfur coals and thus the ash is harder to collect. Therefore use of low sulfur coals at some units could cause opacity to exceed permitted limits. Given these unit specific operational limitations, the NEEDS database and IPM model structure should be updated to reflect these actual limitations. AEP offers two examples of where the lack of fuel constraints resulted in a modeled operating situation that is not currently feasible. [EPA-HQ-OAR-2009-0491-2665.1, p.24] [EPA-HQ-OAR-2009-0491-3719.1_NODA,p.6]
1. In the recently released IPM runs in conjunction with the NODA, emission rates for the Muskingum River units 1-4 were as low as 1.42 lb-SO2/MmBtu based on the modeled emissions and heat input. In previous runs used to support the Transport Rule the emission rates were as low as 1.01 lb- SO2/MmBtu. As these are uncontrolled units, the emission rate is largely indicative of the sulfur content of the underlying fuel. However, low sulfur eastern fuel(s) are not compatible with these wet-bottom boilers due to ash fusion and ESP limitations. These units are currently limited to coal(s) with an S02 content of 4.0 lb per mmBtu or above. [EPA-HQ-OAR-2009-0491-2665.1, p.24] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.6]
2. A similar concern was observed when viewing the model outputs for Kammer Units 1-3. While these units can bum coal with slightly lower S02 content than Muskingum River Units 1-4 due to an ability to blend limited portions of PRB, they similarly cannot burn very low sulfur coal. In new NODA IPM runs, one Kammer Unit was exhibiting an emission rate of 1.34 lb- SO2/MmBtu. In earlier IPM runs the emission rate was as low as 0.95 lb- SO2/MmBtu. With current blend capability, AEP is only able to achieve emission rates slightly below 2.0 lb S02/MmBtu. [EPA-HQ-OAR-2009-0491-2665.1, pp.24] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.6]
An additional concern related to fuel suitability is based on how the IPM model treats units that can burn subbituminous coal. Many boilers are flagged within the model as having the ability to bum subbituminous coal based on past utilization. While keeping this designation within the model structure is important, not all units that can burn subbituminous coal have demonstrated the ability to burn exclusively subbituminous coal. Many units utilize subbituminous coal for a portion of their coal, but not all of their coal, due to boiler limitations. [EPA-HQ-OAR-2009-0491-2665.1, p.24] [EPA-HQ-OAR-2009-0491-3719.1_NODA, pp.6-7]
For example, AEP-operated Rockport Units 1&2 and Tanners Creek Unit 4 all currently bum a percentage of subbituminous coal due to combination of economics and emission limitations. However, as the boilers were originally designed to burn bituminous coal, 100% subbituminous coal cannot be used without significant changes to unit output and operation. (Generally speaking, we have already pushed the subbituminous portion as high as these boilers will allow). As subbituminous coal has lower energy and higher moisture content than bituminous coal, a larger boiler design is typically needed to produce the same thermal and electrical output. Thus, burning 100% sub bituminous coal in a boiler designed for bituminous coal will result in a unit having to be derated, or limited in electrical output. Also, units switching to 100% subbituminous coal will have to undergo more frequent outages related to slag formation and boiler maintenance given the physical properties of subbituminous coal. IPM runs indicating uncontrolled emission rates below 0.60 for Rockport Units 1 & 2 and Tanners Creek Unit 4 suggest that these units are exclusively utilizing very-low sulfur subbituminous coals, as this coal type is the only one capable of meeting this low emission rate. Therefore, output constraints regarding the use of 100% subbituminous fuel and/or maximum blend percentages for the use of subbituminous in boilers currently utilizing blends need to be incorporated in EPA's modeling for the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2665.1, pp.24-25] [EPA-HQ-OAR-2009-0491-3719.1_NODA, p.7]
Coal Procurement
In addition to coal limitations, AEP is also concerned about coal flexibility as it pertains to short term shifts in supply. The IPM model was able to optimize coal selection based on relative economics of different coals. However, the modeling does not take into account long-term coal purchase contract obligations and the ability to quickly ramp production up and down. The IPM model allowed full switching to low sulfur coal in 2012, but in the real world, this could not occur. Given that this rule is not going to be finalized until spring 2011, it will be too late to switch coal contracts. Generally, almost all of AEP's coal (like other electric generators) is contracted more than one year in advance. Thus, the IPM model should be recalibrated and constrained to make sure that transitions in coal type occur over a reasonable period. [EPA-HQ-OAR-2009-0491-2665.1, p.25]
Amount of information does not allow the public adequate time for comprehensive and meaningful comments: AEP requested twice, once for the original proposed rule and again when the NODA was published, to have the comment period extended at least 60 additional days, to November 30. The Proposed Transport Rule 60-day comment period did not allow an in-depth review of the sheer number of pages of technical data that supported the development of the rule. That was compounded by EPA publishing an additional 3500 pages of data in the NODA that changed some of the model costs and corrected some unit specific information. Along with not allowing adequate time for the public to understand and evaluate the work by EPA, the information provided in these published notices and used as a basis for the modeling is incorrect. When connected, the models will need to be rerun and may result in changes to the significance determination, the allocation budgets, and different operating scenarios for the many utility boilers affected by this rule. We request that EPA take the comments from the public, correct the inaccuracies of the inputs to the models, rerun the models then use that information to develop and publish as a supplemental notice a rule that meets the requirements of the court and continues to utilize the CALR budgets and timing to attain the goal of controlling emission transport that may affect the NAAQS.[EPA-HQ-OAR-2009-0491-3719.1_NODA, p.2]
Data and Assumption Comments
The NODA does not provide enough information for companies to properly evaluate how the changes will affect the allowance allocation budgets nor do they provide information on whether there are any changes to the significant contribution evaluation performed in the original proposed rule. Furthermore, AEP believes that some data in the NEEDS v4.10 database is incorrect. The NEEDS database lists certain units with inaccurate emission controls. Additionally, the IPM model structure does not take into account all necessary unit specific operating constraints, specifically those relating to fuel suitability and unit availability. Furthermore, EPA's data on purportedly 'actual' costs of scrubbers and SCRs are lower than actual industry and AEP-specific experience. While the agency attempted to provide an updated NEEDS database along with sample IPM runs using the new data and model structure, the use of incorrect data and lack of documentation as to how the proposed rule will be affected does not provide the public with any meaningful results. [EPA-HQ-OAR-2009-0491-3719.1_NODA,p.3]
Big Rivers Electric Corporation
NEEDS Data Issues 
-Modeled fuel for Wilson is Petroleum Coke only.  Wilson has burned a combination of Southern Illinois Basin bituminous coal and petroleum coke.
-The Wilson permitted emission rate for SO2 is listed at 0.6 lbs/mmBtu.   The actual permit limit is 1.2 lbs/mmBtu.
-The HMP&L Station Two Henderson units (H1 and H2) and the Kenneth C Coleman unit (C1, C2, and C3) all include Wet Scrubbers.  This fact was not included in the Hg EMF Inputs.
-The SCR for the D B Wilson unit (W1) is shown to have come online in 2001.  It came online in 2004.
-The SCR for the HMP&L Station Two Henderson unit (H1) is shown to have come online in 2002.  It came online in 2004.
-The SCR for the HMP&L Station Two Henderson unit (H2) is shown to have come online in 2002.  It came online in 2004. [EPA-HQ-OAR-2009-0491-3720.1_NODA, p.2]
Parsed Data Issues 
-The D B Wilson unit shows zero (0) bituminous fuel use.   The unit in fact burns either a combination of Southern Illinois Basin bituminous coal and petroleum coke or Southern Illinois Basin bituminous coal only.
-The Robert A Reid combustion turbine (Gen2) shows zero (0) NOx and SO2 emissions indicating they will not be utilized.   The unit is necessary to meet our forecasted demand and will be utilized into the future.  [EPA-HQ-OAR-2009-0491-3720.1_NODA, p.2]
Buckeye Power, Inc.
3. Data and input errors should be corrected.
We plan to submit comments on the NODA that will further address data and input errors present in the additional and updated data and modeling, which EPA provided with the NODA. Buckeye notes the following, however, with respect to the initial data and modeling EPA provided with the CATR proposal: [EPA-HQ-OAR-2009-0491-2710.1, p.6]
a. Cardinal Unit No. 2, Brilliant, Ohio.
Cardinal Unit No. 2's capacity is incorrectly listed as 590.1 MW. In fact, it is 600 MW (similar to Cardinal Unit No. 1). In addition, Cardinal Unit No. 2 was included in a NSR Consent Decree and therefore should be classified as a non-dispatchable scrubber. [EPA-HQ-OAR-2009-0491-2710.1, p.6]
b. Cardinal Unit No. 3, Brilliant, Ohio.
Cardinal Unit No. 3's capacity is incorrectly listed as 619.6 MW. In fact, it is 630 MW.
In addition, Buckeye's Cardinal Unit No. 3 SO2 scrubber is not required to be completed until the end of 2012, rather than in 2010 or 2011 as EPA's model estimates. Furthermore, Buckeye's Cardinal Unit No. 3 scrubber is not scheduled to be completed until early 2012, and it could be delayed if there are problems in the construction process. Accordingly, EPA's modeling and methodology should assume a December 31,2012 installation date for Buckeye's Cardinal Unit No. 3 SO2 scrubber.
The Cardinal Unit 3 FGD System was also included in a NSR Consent Decree; therefore, it should also be classified as a non-dispatchable scrubber.
Finally, the Controlled NOx Base Rate of 0.030 lbs/mm BTU that was achieved during the 2006 ozone season was an extraordinary performance. This NOx emission rate remains the lowest seasonal rate ever achieved by any SCR for which we have data. This emission rate is not sustainable over the long term and allowance allocation baselines need to be representative of the performance over the entire catalyst life cycle (3-5 years). The Controlled Annual NOx rate for this unit should be 0.05 lbs/mm BTU, similar to the assumed rate for new SCR equipment. [EPA-HQ-OAR-2009-0491-2710.1, p.6]
c. Greenville Station, Greenville. Ohio.
The Greenville Station units are peaking units. Nevertheless, EPA proposes to grant only 14 NOx emission allowances to them based upon historic emissions, which are inherently unreliable given the intermittent and variable operation of peaking units. However, even using historic emissions as a baseline, the Greenville Station units have been allocated less allowances than they have historically needed to operate and certainly below their permitted levels. This is arbitrary and unreasonable. These units are critical to grid reliability and must be allocated sufficient NOx emission allowances to operate when and as needed to meet peak load demands. In addition, natural gas-fired peakers are classified as a minor sources. Such units should receive allocations equal to the lesser of actual or permitted emission limits. [EPA-HQ-OAR-2009-0491-2710.1, p.7]
d. Robert P. Mone Plant, Convoy, Ohio.
EPA proposes to grant the Mone facility Zero NOx emission allowances despite the fact that it has been operating since 2002. This constitutes either a plain error, or a shocking example of the shortcomings of EPA's modeling-based allocation scheme. These units, by the very nature of being peakers, only operate when needed. These units are likewise critical to grid reliability. Moreover, these units are classified as a minor source, and therefore should receive allocations equal to the lesser of actual or permitted emission limits. [EPA-HQ-OAR-2009-0491-2710.1, p.7]
5. EPA's allocation scheme is unreasonable and arbitrary.
a. EPA's allocation methodology and modeling is not transparent and parties have not been given sufficient time to evaluate it.
EPA's methodology should be transparent and affected parties should be given adequate opportunity to understand EPA's methodology and data inputs. We understand that EPA released additional and updated CATR program-related methodology and supporting data on September 1 ('Notice of Data Availability Supporting Federal Implementation Plans to Reduce Interstate Transportation of Fine Particulate Matter and Ozone' ('NODA'). Parties have only until October 15 to comment on the NODA. This is clearly not enough time to evaluate such a complicated methodology. Furthermore, there was only one month between release of this data and when comments are due on CATR itself. [EPA-HQ-OAR-2009-0491-2710.1, pp.7-8]
The updated modeling assumptions are flawed; consequently, the CATR is likely to remain arbitrary and capricious, an abuse of discretion, and otherwise not in accordance with the law. [EPA-HQ-OAR-2009-0491-3724.1_NODA, p.1]
We believe that EPA should support and encourage maximum utilization of fully controlled units, such as Buckeye's, as compared to uncontrolled or lesser-controlled units. It appears that CATR, particularly after application of the updated model results, does not achieve this goal. Based upon Buckeye's review of the NODA data, operation of Buckeye's coal-fired units will be constrained even more so than under the NEEDS v. 3.02. This is bad public policy and contrary to law. Units employing BACT should not be constrained from normal operation to meet load responsibilities and to support grid reliability. [EPA-HQ-OAR-2009-0491-3724_NODA, p.2]
Heat Input and Operability Factors Utilized By EPA Are Arbitrary and Unreasonable
The assumed availability of Buckeye's coal units has been reduced in the updated model assumptions as compared to the NEEDS v. 3.02 model. This constitutes an abuse of EPA's discretion and renders the CATR arbitrary, capricious, and not in accordance with law since Buckeye's fully controlled units should be dispatched first, ahead of uncontrolled units, to meet load and support grid reliability. It appears that EPA may be limiting existing unit availability assumptions based upon certain historic capacity factors. However, depending on the circumstances, historic performance can be, and in this instance is, an inappropriate basis for setting emission limits. Fully controlled baseload units, are the most environmentally friendly and cost effective units to meet load requirements. It is contrary to the Clean Air Act permitting programs and objectives for EPA to arbitrarily constrain these units in lieu of uncontrolled units. [EPA-HQ-OAR-2009-0491-3724.1_NODA, pp.2-3]
EPA's revised model's use of historical capacity factors for Buckeye's Cardinal Units translates into an assumed 73% availability for Buckeye's Cardinal Units, which is less than the 85% assumed availability for new units. It is likewise arbitrary and capricious for EPA to conclude that Buckeye's units, which are fully controlled for S02 and NOx, should have an assumed availability less than a similarly equipped new unit. [EPA-HQ-OAR-2009-0491-3724.1_NODA, p.3]
Moreover, Buckeye's Cardinal units are part of the PJM Interconnection, LLC, which is a FERC approved regional transmission organization, or 'RTO.' As a member of the PJM RTO, Buckeye has daily 'must offer' requirements, and PJM, not Buckeye, decides which units must be dispatched to support regional grid reliability and to support economic dispatch of units within the RTO based upon the day ahead power 'bids.' EPA's proposed heat input and operability limits for Buckeye's BACT-controlled units conflicts with the grid reliability concerns of FERC and PJM, which assume a fully controlled unit is available for dispatch to support grid reliability and economic dispatch. There is no reason why Buckeye's fully-controlled units should not be so available. [EPA-HQ-OAR-2009-0491-3724.1_NODA, p.3]
Buckeye's NOx and S02 Rates Under CATR Would be Unreasonably and Arbitrarily Low
Buckeye's Cardinal's Unit 3 NOx rate is reduced under the updated model beyond the already impermissibly low rate ascribed under the NEEDS v. 3.02. EPA's calculated annual NOx emission rate of 0.023 lbs/mmBtu appears to be one of the lowest NOx rate assumptions in the United States for coal fired generation units. Buckeye reiterates the point made in its CATR comments that it is being punished for having already installed high performing SCR systems. Compounding the unfair impact, EPA is using one year (2007) as the base year for its NODA calculations. It is unrealistic, unfair, an abuse of EPA's discretion, and arbitrary for EPA to use one year's emissions data as the basis to constrain future emissions. It is particularly arbitrary and capricious as applied to Buckeye, as Buckeye's Cardinal 3 SCR equipment had its highest annual control efficiency ever in 2007. An 0.023 lbs/mmBtu NOx rate is inconsistent with historical and projected future Buckeye operations and not achievable during year round operation. This illustrates the inequity of using a single test year as the basis for allowance allocations. Buckeye should not be punished by having its allowance allocations substantially reduced because EPA uses a single test year and the highest performing year ever for Buckeye's SCR system. This is arbitrary and unreasonable, as Buckeye cannot be expected to sustain that level of control systems performance on a year-to-year basis. [EPA-HQ-OAR-2009-0491-3724.1_NODA, p.4]
It appears that Buckeye's S02 rate for its Cardinal Units also has been substantially reduced as compared to the S02 emissions rate under the NEEDS v. 3.02. The S02 emission rate in the NEEDS v. 3.02 was 0.218 as compared to 0.087 in the NODA. This constitutes a 60% reduction. Given the fact that Buckeye already employs BACT emissions controls, Buckeye can only conclude that this reduction reflects an erroneous EPA assumption about fuel switching. The lPM model appears to contemplate full switching to low sulfur coal in 2012; however, this cannot happen in the real world. First, Buckeye (like many companies) has long term high sulfur coal contracts which have minimum tonnage obligations, in place through December 31, 2017. Buckeye would have to breach those contracts or pay and take for tons not needed, if Buckeye is not allowed to burn high sulfur coal with its scrubbers. Second, many coal-fired boilers are limited to a minimum specification for sulfur content due to their boiler configuration, their ESP and/or their air permit limitations (e.g., use of low sulfur coals at certain units can cause opacity to exceed permit limits). Buckeye's scrubbers were designed to bum high sulfur coal. Design changes and additional expense may need to be incurred to allow its scrubbers to operate exclusively with low sulfur coal. Third, Buckeye is committed to having the option of using locally mined Ohio coal to operate its units. If low sulfur coal is required by these regulations, Buckeye would not be able to bum local Ohio coal; consequently, local jobs would be lost and the local economy would be damaged. For all of these reasons, at a minimum, Buckeye should be allowed to burn Ohio coal for the benefit of the local economy and Buckeye's member consumers. [EPA-HQ-OAR-2009-0491-3724.1_NODA, pp.4-5]
Buckeye suggests that at ~ minimum its NOx emission rate should be set at EPA's emission rate floor of 0.06 for NOx. Buckeye believes that the most reasonable and appropriate S02 emission rate floor would permit full operation of BACT -controlled units using locally mined high sulfur coal and the fact that the scrubbers have been designed for this local Ohio coal. There is no reason for Buckeye to be punished for having already installed high performing emission controls by having its NOx emission rate set at a rate lower than EPA's own emission rate floor. Setting emission rates based upon Buckeye's high performing equipment and highest performing year is entirely arbitrary and capricious as it sets a ceiling on emissions that cannot be met on a regular basis with normal operations, even with BACT already installed. This is arbitrary, capricious, and not in accordance with law and will result in unit curtailments or the purchase of high cost replacement power. [EPA-HQ-OAR-2009-0491-3724.1_NODA, pp.5-6]
As discussed in Buckeye's comments on the proposed CATR, Buckeye has acquired, at a cost of approximately $25 million, S02 allowances that may not be used (and thus will be rendered worthless) under CATR. This would constitute a 'taking' in violation of the Fifth Amendment of the U.S. Constitution. [EPA-HQ-OAR-2009-0491-3724.1_NODA, p.6]
Additional Factual Corrections
There remain a number of factual errors in EPA's NEEDS v. 4.10 database with respect to Buckeye which must be corrected. EPA indicates that the Cardinal Unit 3 scrubber will be operational in 2010. That is incorrect; the Cardinal Unit 3 scrubber is expected to start up by December 31,2012. Also, Buckeye's Cardinal Unit No.2 and 3 scrubbers are non-dispatchable because they are included in a NSR Consent Decree. Finally, contrary to the NODA data, Buckeye's Cardinal Unit 2 does currently have a wet scrubber installed and in operation. [EPA-HQ-OAR-2009-0491-3724.1_NODA, p.7]
EPA should withdraw and reconsider CATR, and re-visit and revise its NEEDS v. 4.10 assumptions and inputs. [EPA-HQ-OAR-2009-0491-3724.1_NODA, p.7]
Capital Power Corporation
For example, on September 1, 2010, EPA issued a Notice of Data Availability, in which it updated the data which defines availability of plants, with comments due October 15, 2010. In one case, data for one company indicated 79% availability for a facility with a contractually obligated 97% availability. Clearly, EPA's data will require close inspection and analysis by affected sources as all such data affects the implementation of the proposed rule. EPA needs to allow companies the opportunity to review the Rule and related models and data and comment on as a single exercise. [EPA-HQ-OAR-2009-0491-2753.1, p.3]
Clean Air Task Force
CATF makes the following specific comments on the NODA and the associated documentation for IPM v.4.10 (the "Documentation"): [EPA-HQ-OAR-2009-0491-3749.1_NODA, p.2]
The Documentation indicates that dry sorbent injection ("DSI") is not among the pollutant control technologies available for deployment in IPM.  See Documentation at Table 1-2 and Documentation at pages 5-1 and 5-2 Prior analysis by EPA indicates that in some cases, at least, DSI systems can have "significantly lower capital and annual costs than wet systems" for SO2 control, however, and "install easily and use less space" and are therefore "good candidates for retrofit applications."  This potential is reflected in recent compliance planning activity in the utility industry.  According to the Institute of Clean Air Companies, DSI may also offer reduced-cost "multi-pollutant control opportunities by combining acid gas, SO2, particulate control, and air toxics, including mercury." Bundling hazardous air pollutant control with lower cost sulfur control on existing coal units could significantly change the economics of Transport Rule and MACT compliance, and EPA should include DSI in IPM to reflect this possibility. [EPA-HQ-OAR-2009-0491-3749.1_NODA, p.2]
The Documentation indicates that carbon capture and sequestration ("CCS") is not among the carbon dioxide emissions reductions options available for existing and new combined cycle power plants burning natural gas ("NGCC") in IPM v.4.10.  See Documentation at Table 4-7 and related discussion and Documentation at Table 4-13 and related discussion.   Analysis by the Department of Energy suggests that the cost of electricity produced from NGCC with CCS may be less than the cost of electricity produced by coal power plants with CCS when natural gas prices are comparatively low, however, so omission of an "NGCC with CCS" reduction option in IPM could both overstate the costs of compliance with emission reduction mandates and significantly misrepresent the universe of potential compliance solutions available to policy-makers.  This is especially important as the Documentation indicates there are roughly 180 billion watts ("GW") of combined cycle capacity installed in the United States (compared to roughly 305 GW for coal power) and another 25 GW planned-committed through 2011. See Documentation at Tables 4-3 and 4-12. [EPA-HQ-OAR-2009-0491-3749.1_NODA, p.2]
The Documentation indicates that relatively tight constraints have been placed on deployment of CCS and nuclear power technologies in IPM.  Total deployment of CCS would be limited to just under 50 GW through model run year 2030, for example, in the event that no nuclear power is built during that time, and total deployment of nuclear power would be limited to just under 37 GW during the same time period if no CCS is built.  If some of both types of technologies are built, a combined constraint would apply in order to reflect bottlenecks in engineering and equipment supply chains.  See Documentation at page 3-21 and Appendix 3-7.    While EPA has provided some basis for the imposition of these constraints, they are at odds with historical precedents including the data provided in the Documentation itself, which indicates that during the `boom' years in nuclear power development in the US roughly 5 GW per year of new capacity were installed here.  See Documentation at Figure 3-2.   If such historical peak rates were applied to CCS and nuclear deployment in IPM, the constraints could well be looser.   Recognition of today's global context for engineering and manufacturing, as well as the potential for modular facility construction, could also result in significantly looser deployment constraints for these technologies. [EPA-HQ-OAR-2009-0491-3749.1_NODA, pp.2-3]
The Documentation indicates that IPM includes only a single vintage of performance and cost assumptions for CCS technology (for the period 2012 through 2054), and therefore does not reflect the likely possibility that costs and performance of CCS will improve over time as the technology is widely deployed.   See Documentation at Table 4-13 and related discussion.  This treatment is at odds with current literature on technology learning rates, which suggests that for CCS costs could decline significantly as capacity is installed. 6 [EPA-HQ-OAR-2009-0491-3749.1_NODA, p.3]
The Documentation suggests that for the Base Case analysis, at least, IPM is not able to deploy new electricity transmission between generators and load centers.  See Documentation at page 2-10.   If maintained in future runs, such a deficiency is likely to significantly limit the usefulness of IPM for analysis related to technologies with a high degree of spatial dependence, such as renewable power and CCS generally, and also to potential breakthrough technologies that might be analyzed in future years (such as those discussed in paragraph 6 below). [EPA-HQ-OAR-2009-0491-3749.1_NODA, p.3]
The Documentation does not reflect several emerging technologies that could significantly impact future CAA regulation compliance options, costs and impacts. These include underground coal gasification with carbon capture and sequestration (UCG/CCS) 7 and innovative, modular compressed air energy storage technology. While both of these technologies have geographic constraints for which complete data may not yet be available, these technologies could be included in a preliminary fashion to provide insight into how important they might be for reducing air pollutant emissions. [EPA-HQ-OAR-2009-0491-3749.1_NODA, p.3]
In conclusion, while CATF generally supports the appropriate use of IPM v.4.10 in the Transport Rule and future rulemakings involving the power sector, we urge EPA to improve this IPM version in accordance with the above comments. [EPA-HQ-OAR-2009-0491-3749.1_NODA, p.3]

 6 See, e.g., Rubin et al., "Use of experience curves to estimate the future cost of power plants with CO2 capture,"  International Journal of Greenhouse Gas Control, 2007, 188-197.
7 See CATF (2009), "Coal Without Carbon: An Investment Plan for Federal Action," available at: http://www.catf.us/resources/publications/files/Coal_Without_Carbon.pdf.
Cleco Corporation
EPA's Projections Are Inconsistent with FERC-Commissioned Projections [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.2]
EPA's projected heat inputs and resulting capacity factors for Evangeline are inconsistent with recent projections in connection with a study by the Federal Energy Regulatory Commission (FERC). FERC is currently analyzing the costs and benefits of Entergy and Cleco Power (Cleco's regulated electric utility business) joining the Southwest Power Pool (SPP) regional transmission organization (RTO). The FERC agreed to fund a Cost Benefit Analysis (CBA) to study the costs and benefits of Entergy and Cleco Power joining the SPP as full transmission-owning members with their transmission facilities under SPP operational control. The CBA was performed over a seven-month period, and included an open and collaborative discussion with stakeholders of the study framework, modeling approach, input assumptions, interim results, and qualitative issues throughout this period. Based on FERC's analysis, performed by Charles River Associates and Resero Consulting, if Entergy and Cleco Power do not join the SPP RTO (which is the "Status Quo Case" depicted in the attached Exhibit 1) Evangeline's capacity factor is projected to be approximately 25%, which is higher than both of EPA's IPM projections. These projections call into question EPA's methodology. [EPA-HQ-OAR-2009-0491-3727.1_NODA, pp.2-3]
In addition, this study evaluated the implications for Evangeline if Entergy and Cleco Power were to join the SPP RTO (which is the "Join SPP Case" depicted in the attached Exhibit 1). In that case, the FERC study shows Evangeline with capacity factors ranging between 50% and 60%. This analysis is a great example of how externalities  -  two regulated utilities joining an RTO  -  dramatically impact capacity factors and corresponding emissions. We believe it is imprudent to effectively limit the output of Evangeline in one regulatory arena, i.e., environmental, when it is significantly impacted by another arena, i.e., FERC. The FERC study suggests that IPM Version 4.10 is not necessarily the model of choice. [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.3]
EPA's IPM Projections Would Effectively Limit Evangeline's Operations [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.3]
Evangeline is already a low emitting facility equipped with state of the art pollution controls for NOx. The availability of allowances will likely be very limited, particularly in the first few years of the program. EPA itself stated that it expects very little if any trading as part of this rule. As a result, prudent operators cannot rely on the possibility that allowances might become available for purchase for purposes of compliance planning. Therefore, Cleco Midstream's only assured compliance alternative is to plan to reduce unit run time to stay within its allowance allocations if necessary to comply with this rule. A severe under-allocation of allowances would make it difficult for this low emitting unit with state-of-the art pollution controls to comply. Yet it appears that Evangeline is at risk of being under-allocated, based on our understanding of the data provided in this NODA. Limiting the emissions of Evangeline in this manner could require this facility to seek market allowances that may be difficult to obtain. [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.3]
Cleco Midstream is deeply concerned that, with EPA's addition of new data and a new version of IPM, a viable low emitting electric generating unit can go from 491 annual NOx tons to a mere 47 tons  -  a tenfold reduction. Because EPA has refused to issue a supplemental rule with updated allowance allocations, for compliance planning purposes, Cleco Midstream has to assume that the projected NOx tons in the IPM Parsed File for Base Case 2012 will correlate to the Agency's annual NOx allocation for this facility, which is simply unworkable. [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.3]
If EPA insists on retaining the FIP approach in this transport rulemaking, then Cleco Midstream urges EPA to evaluate these impacts and substantially revise its methodology for allocations and the allocations themselves. As applied to facilities like Evangeline, EPA's scheme causes great economic inequity with no discernable environmental justification. [EPA-HQ-OAR-2009-0491-3727.1_NODA, pp.3-4]
IPM is a linear programming model that generates optimal decisions under the assumption of perfect foresight and it determines the least-cost method of meeting energy and peak demand in a perfect dispatch world. Relying this heavily on the IPM 4.10 assumptions to formulate such rigorous federally enforceable environmental requirements is arbitrary and capricious on EPA's part and does a disservice to the customers of regulated utilities and wholesale generators. In Louisiana, there is anything but perfect foresight in the power sector and electric generating units are not dispatched purely on an economic basis. Transmission constraints, fuel limitations, voltage issues, reliability concerns, contractual obligations, and other issues all contribute to dispatch decisions of a particular generating unit. IPM 4.10 is ill-suited to be the basis of this rule because the IPM model is only as good and accurate as the inputs that go into it, and in this case the inputs will vary too substantially from the model assumptions to be solely relied upon. Most noted sources of natural gas pricing models such as the forecast in EIA's AEO have often changed their base case assumptions over time as the economy, population, supply, demand and other factors change. In fact, the EIA's AOE (which EPA uses as a reference natural gas price case) often adjusts its natural gas forecast price from year to year, and sometimes the change is drastic. There is an apparent disconnect with the proposed rule if it is setting the basis for a long term rule with a 2010 projection without adjustments or off-ramps in the later years, knowing full well that these forecasted inputs will change as time goes on. [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.4]
Corrections to Evangeline Power Station's Unit Performance Data [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.4]
In the NEEDS database associated with this NODA, EPA has indicated that the heat rate from Evangeline Power Station is 8,760 btu/kw. As mentioned previously, Evangeline is a state of the art combined cycle unit with a proven average heat rate of 7,450 btu/kw; a 15 percent heat rate improvement over the data in the NEEDS file. This performance is verified by unit performance test run by the facility in July of 2009 and attached in Exhibit 2. [EPA-HQ-OAR-2009-0491-3727.1_NODA, pp.4-5]
In the NEEDS database associated with this NODA, EPA has indicated that the Corrected NOx Base Emission Rate from Evangeline Power Station is 0.0213 lbs/mmBtu. However a review of CAMD data suggests that the reported emission rate is well above the projected emission rate in the NEEDS file. In fact, depending on the specific unit at Evangeline, in the period from 2005  -  2009, the NOx rate ranges from a minimum of 0.03 lbs/mmBtu to a maximum of 0.07 lbs/mmBtu. If in fact EPA uses this rate to form the basis of NOx allocations, this data should be corrected. [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.5]
Other Examples of Incorrect/Misapplied Data [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.5]
In this limited time, Cleco Midstream has attempted to review the proposed rule and all the technical provisions of IPM 4.10 contained therein, but it was not practical to review every data set and review, apply and understand all the IPM model applications. As such, Cleco Midstream fears that there are technical data errors that have been missed or overlooked in this limited timeframe for review. One example is that of emission allowances granted to units that cease to exist or are not currently operating. Washington Parish Energy Center (WPEC) (ORIS55486) located in southeast Louisiana is one such example. In IPM Version 3.02, WPEC was granted some 393 annual NOx allowances. These allowances were granted to a non-operating unit that isn't likely to operate in the future. In fact, a search of EPA's CAMD database turned up no operating data for this facility. Further, using IPM version 4.10, it appears that EPA intends to grant even more allowances to this same unit than it did in IPM Version 3.02. As best as we can ascertain, WPEC will be granted some 470 allowances. That's an additional 77 annual NOx allowances. Again, not knowing the black box calculations of the IPM Version 4.10, Cleco Midstream assumes that the apparent increase in annual NOx allowances to WPEC is attributable to the IPM 4.10 model dispatching the facility even more than in the previous 3.02 version. On what basis was this unit dispatched even more? With this type of apparent oversight and its significant impacts, we contend that the use of IPM Version 4.10 is not the proper method of basing this regulatory program. [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.5]
State Budget Issues [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.5]
From a review of the parsed files in IPM version 4.10, it appears that Louisiana's annual state NOx budget has been reduced from 43,946 allowances to 38,804 allowances. It is difficult to understand the methodology that EPA will employ to determine a state's budget. Presumably, EPA had determined using version 3.02 that limiting Louisiana's EGU's to 43,946 tons per year of NOx was sufficient to reduce its impact on maintenance or significant contribution to PM 2.5 nonattainment. By EPA's own modeling methodology, we would disagree that an additional 11,142 reduction is required. Cleco Midstream simply does not have enough time to determine what changed in the model to cause such a drastic further reduction. We note here that several comments filed on the October 1, 2010 for the proposed Transport Rule addressed and substantiated the insignificant contribution of nitrates to PM 2.5; yet another reason not to require an additional 11,142 ton state budget reduction. [EPA-HQ-OAR-2009-0491-3727.1_NODA, p.5]
The NODA provides enough information for us to know that our prior analysis is now irrelevant. With EPA's adoption of a new version of IPM and new data, the state budgets and unit allocations we reviewed are now obsolete. Unfortunately, that is about all we can determine from the NODA. EPA does not provide  -  and has indicated it will not provide  -  the numerous modeling runs and summary spreadsheets needed for us to determine what emissions will be allowed from EGUs in Louisiana and what portion of the permissible emissions are attributed/allocated to Cleco. Because the Agency does not intend to provide revised state budgets and unit allocations, commenting on compliance issues is nearly impossible. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.2]
Now, we no longer have before us enough information to evaluate: what is and is not a receptor, whether Louisiana is linked to any receptors, what emission reductions EPA assumes will be available at various cost per ton removal thresholds or the resulting air quality impacts, what breakpoints will define significant contribution and interference with maintenance, or whether Louisiana qualifies for the Group 2 off ramp. Put simply, the rule we commented on is rendered obsolete by the NODA. And now we struggle to comment with incomplete information on what the new rule will be. This undermines our ability to provide meaningful comments on compliance feasibility or the rule's impact on electric reliability. Instead, we are left commenting on broad principles (e.g., to auction or not to auction) and minute details (e.g., a single unit's reported heat input for a single quarter, math errors, or control assumptions for a single unit). [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.3]
This proposed rule is simply too important to promulgate without allowing for comprehensive, well informed public input and comment. We urge the Agency to publish a supplemental rule for comment. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.3]
EPA Must Provide Industry With Additional Information for Planning/Forecasting Purposes. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.3]
EPA's refusal to provide revised state budgets and unit allocations until the rule is finalized makes compliance planning impossible. EPA must advise states and industry of which programs they are in, what their state budgets will be and what their unit allocations will be well in advance of the compliance deadlines. Most, if not all, of the numerous compliance strategies EPA identifies (installing controls, switching fuels etc.) are not available with the short notice EPA intends to provide. State environmental agencies, the electric power industry, the coal and gas industries and the transportation industries require a longer lead time for planning. They are massive industries with enormous responsibilities and lengthy planning horizons. They cannot be expected to respond to such abrupt regulatory and policy shifts without sufficient notice of the critical information needed for planning purposes  -  in this case the state budgets and unit allocations. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.3]
IPM 4.10 Leads to Unrealistic Results. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.5]
The most telling sign that these projections are inadequate for establishing state budgets and unit allocations is the outputs themselves. EPA's projections for 2012 are wholly unrealistic. With respect to Cleco units alone, EPA's projections are significantly different from historical dispatch or from what common sense dictates future dispatch will be. For example, two of our coal fired power plants Rodemacher 2 (6190_B_2) and 3 (6190_B_3A and 6190_B_3B)) are projected by IPM to operate at about 49% (Rodemacher 2) and 27% (Rodemacher 3) capacity. One of these units, Rodemacher 3, was only recently brought online. Like all base load investments, Cleco, with Louisiana Public Service Commission approval, invested significant capital costs to bring the unit online. To recover those costs and for Louisiana rate payers to get the full economic benefit of their investment, these units must and will run at significantly higher capacity factors. [EPA-HQ-OAR-2009-0491-3726.1_NODA, pp.5-6]
These projected capacity factors are also way out of line with the historical capacity factors for our Louisiana coal fired generation. Since 1999 our Dolet Hills and Rodemacher 2 units have an average capacity factor of 74%. Rodemacher 2 alone has an average capacity factor of 69% since 1999, which is 140% of the capacity factor EPA projects it to have in 2012. In 1999, when natural gas prices were near record lows, these units averaged 68% capacity. Even in 2009, the worst economic recession since the great depression, these two units averaged 74.5% capacity. See Table 2 below. [EPA-HQ-OAR-2009-0491-3726.1_NODA, p.6; see p.6 of this comment summary for Table 2 entitled, Annual Capacity Factors for Cleco Power's Dolet Hills and Rodemacher 2 Facilities (1999 to 2009)]
Coal Utilization Research Council
The potential rate of introduction of CCS technology, both at greenfield and at retrofit sites, is an important issue. EPA's IPM analysis of HR2454, for example, placed a "joint constraint" on new nuclear and CCS-equipped capacity. 3 The only constraints imposed on CCS deployment in the current IPM documentation are "Capital Cost Adders" which would increase the cost of a technology if an assumed base level of capacity addition is exceeded in a given year. These adders appear to provide very little real constraint and EPA should develop and offer for comment a more rigorous approach to address limits to the rate of introduction of CCS technology.
The capital cost estimates of retrofit CCS (IPM documentation, Chapter 6) "are based on the cost reported for Case 1" of the DOE/NETL Conesville report. That report reached an incremental capital cost of $1319/kW, whereas the IPM estimate is $1972/kW. Although we support the use of higher estimate for early CCS deployment 4, the documentation should explain how the NETL figure was modified to arrive at the IPM number. The IPM O&M estimates for retrofit differ by a factor of as much as 6 with the DOE/NETL report cited as a basis for those numbers. The reasons for such a large difference should be explained in the documentation. 
Because CCS is an emerging technology, and because significant R&D is underway in the US and globally to reduce the cost of this technology, it can be assumed that the "Nth of a kind" unit will cost less than "1st of a kind" units, and that the technology will go through generic generations, with progressively better performance and lower cost. This is perhaps the most critical issue associated with projecting deployment costs for CCS. The IPM documentation provides no discussion of how the model's costs for CCS will evolve over time, or with increasing deployment, and implies that technology costs are fixed within the model. This is a particularly important issue for greenfield units, because the model's costs are based on "Nth of a kind" configurations, but the baseline projections show very little new coal capacity of any kind being built. 5 In other words, according to IPM, we may not reach "Nth of a kind" economics for greenfield units within the model's time horizon. The model documentation should address the factors influencing changing CCS economics over the model's time horizon, and incorporate estimates of the impact of those factors. 
The evaluation of CO2 transportation (pipeline) costs states that there are large economies of scale associated with transporting CO2. However, achieving those economies of scale means that multiple capture projects would need to collaborate on permitting and constructing a pipeline. This shared approach seems particularly unsuited to greenfield applications of CCS, given the relatively small number of new coal units projected by IPM prior to 2030. 
IPM provides cost and performance assumptions for both greenfield and retrofit coal-based power generation. The documentation has omitted analogous information for systems fueled by natural gas; is there a reason why EPA omitted this information? This type of information is readily available from the same sources cited by EPA in EPA's development of the coal-related parameters. 6 

3 Supplemental EPA Analysis of the American Clean Energy and Security Act of 2009, Appendix, USEPA, January 29, 2010.  
4 The IPM value is consistent with a recent DOE/NETL report which evaluated the cost to retrofit CCS on a subbituminous subcritical pulverized coal unit ($1999/kW). Assessment of Power Plants That Meet Proposed Greenhouse Gas Emission Performance Standards, DOE/NETL-401/110509, November 5, 2009.  
5 EPA's Base Case IPM runs for the Transport Rule show no new coal capacity commencing operation between 2012 and 2030, other than 2GW of coal w/CCS built with federal subsidies. See http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html.
6 For example, Cost and Performance Baseline for Fossil Energy Plants, Vol.1., DOE/NETL-2007/1281, May 2007, subsequently cited in these comments as the "Baseline Bituminous report"; or Assumptions to the Annual Energy Outlook 2010, (Table 8.2) USEIA, DOE/EIA-0554(2010), April 2010, subsequently cited in these comments as "EIA AEO-2010 assumptions document". 
Cogen Technologies Linden Venture, LP
D. Facilities Should Have the Opportunity to Correct Any Erroneous Data Relied Upon as the Basis for Establishing Unit Allocations
The foregoing errors illustrate how small anomalies in the data and assumptions can have drastic consequences in IPM's projections at the level of the individual unit. Before relying upon IPM projections demonstrably at odds with historic dispatch for individual units, EPA must at the very least provide facility owners with the opportunity to review and correct the inputs to IPM. [EPA-HQ-OAR-2009-0491-2712.1, p.12]
Linden Cogen considered how EPA could have come to assume a heat rate more typical of a simple-cycle combustion turbine for each of Linden Cogen's generating units. The supporting documentation for EPA Base Case v.4.10 suggests that heat rates used within IPM were derived from AEO 2008, as follows: [EPA-HQ-OAR-2009-0491-2712.1, p.12]
The heat rates in EPA Base Case v.4.10 are based on values from AEO 2008. These values were screened and adjusted using a procedure developed by EPA to ensure that the heat rates used in EPA Base Case v.4.10 are within the engineering capabilities of the generating unit types. Based on engineering analysis, the upper and lower heat rate limits shown in Table 3-10 were applied to coal steam, oil/gas steam, combined cycle, combustion turbine, and internal combustion engines. If the reported heat rate for such a unit was below the applicable lower limit or above the upper limit, the limit was substituted for the reported value. [EPA-HQ-OAR-2009-0491-2712.1, p.12]
Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model, EPA Clean Air Markets Division, August 2010, Table 4-1, Data Sources for NEEDS v.4.10 for EPA Base Case v.4.10, 3-17. [EPA-HQ-OAR-2009-0491-2712.1, p.12]
Linden Cogen examined the referenced publication - AEO 2008 - and can identify no instance wherein it provides facility-specific heat rate information that EPA could have relied upon to populate the NEEDS database. In light of this, Linden Cogen assumes that EPA did not rely upon AEO 2008 for the unit-specific heat rates appearing within NEEDS, but rather to establish the upper and lower limits of heat rates for various 'generating unit types'. Id. [EPA-HQ-OAR-2009-0491-2712.1, p.12]
Apart from the section quoted above expressly addressing the source of heat rate data, the supporting documentation for EPA Base Case v.4.10 suggests that the heat rates appearing within the NEEDS database were derived from information submitted by electric generators to the Energy Information Administration ('EIA') on Form 860. 8 Linden Cogen examined its historic submittals on EIA Form 860 and believes that the information reported there might have been the source of the erroneous heat rate assigned to its generating units. Linden Cogen has historically reported the gross heat rate for each combustion turbine and steam turbine separately, rather than a combined cycle heat rate. Thus, if a particular combustion turbine has demonstrated that it can generate a kilowatt of energy from a given number of British thermal units of natural gas in performance testing, Linden Cogen reported that number as the heat rate to EIA, irrespective of any useful thermal energy derived from use of combustion turbine exhaust to generate steam and additional power. Similarly, for its three steam turbines, Linden Cogen has historically reported the gross heat rate of each steam turbine as confirmed by performance testing that measures the amount of thermal energy provided to the steam turbine and the corresponding amount of electricity generated by that steam. [EPA-HQ-OAR-2009-0491-2712.1, pp.12-13]
Upon further investigation, Linden Cogen believes that its historic reporting practices do not conform with EIA's instructions that a reporting entity should not 'report a heat rate that includes the fuel used for the production of useful thermal output. 9 Linden Cogen is in the process of submitting corrected versions of Form 860 to the EIA. The average heat rate that Linden Cogen will report for its generating units will be approximately 7965 Btu/kWh 10. This is much lower than the heat rates Linden Cogen reported in 2009 on Form 860, which ranged from 9900 Btu/kWh to 10300 Btu/kWh. While the gross heat rates previously reported by Linden Cogen are even higher than assumed by EPA in IPM (9174 Btu/kWh), we are not aware of any other source of data that might have been relied upon by EPA in assigning a heat rate of 9174 Btu/kWh to each of Linden Cogen's generating units. Nor are we aware of the source of the different, but equally erroneous heat rates that appeared in earlier versions of the NEEDS database and IPM: In the 2000 and 2003 versions, Linden Cogen's heat rate was identified as 8305.737927 Btu/kWh 11; in 2004, it was 9441.28 Btu/kWh. 12 [EPA-HQ-OAR-2009-0491-2712.1, p.13]
EPA must provide sources the opportunity to correct any inaccurate data and assumptions used in its model, before relying upon the model results to impose an arbitrary and punitive allocation on a source owner. Assuming the erroneous heat rate was derived from Linden Cogen's historic reporting of 'gross' unit heat rates on EIA Form 860, we would note that this information was submitted to a wholly separate agency to inform its ongoing analysis and projections concerning the power market. It was never intended to provide critical inputs forming the basis of proposed emission allowance allocations under an air regulatory program with significant compliance obligations. Consistent with the principles of notice and comment rulemaking and fundamental fairness, EPA must therefore provide affected facilities the opportunity to review and correct any erroneous data relied upon by IPM, before basing unit allocations on model results wholly inconsistent with a particular facility's reality. [EPA-HQ-OAR-2009-0491-2712.1, pp.13-14]
SUPPLEMENTAL COMMENTS CONCERNING IPM V.4.10 [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.2]
The Problems Identified by Linden Cogen's October 1, 2010 Comments Concerning Reliance Upon IPM Results as the Basis for Allocating Allowances Pertain Equally to Both IPM Results Initially Released with the Proposed Transport Rule (v.3.02) and the IPM Results Released with the NODA (v.4.10) [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.2]
While we will not restate our October 1, 2010 Comments concerning IPM in detail, IPM has wrongly projected the dispatch of Linden Cogen at only a fraction of its historical operating levels because IPM arbitrarily ignores the impact of long-term contracts on dispatch. See October 1. 2010 Comments, 5-9. Further, EPA also made several errors concerning the underlying assumptions applied to Linden Cogen within IPM that also may have contributed to IPM's erroneous projections of future dispatch for Linden Cogen. See id., 10-11. Both versions of IPM suffer from these errors. Thus, even if EPA were to rely upon the results of IPM v.4.10 released with the NODA as the basis for allocating NOx allowances in New Jersey, the resulting allocation for Linden Cogen would still represent only a small fraction of its historic emissions. See id., 6, nt. 1. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.3]
As indicated by our October 1, 2010 Comments, EPA's proposed allocations of 41 tons annual NOx and 30 tons ozone season NOx would respectively represent approximately only 10% and 19% of historic emissions, as reported during the four most recent calendar quarters. See October 1, 2010 Comments, 6. Furthermore, in comparison to average historic emissions over the past seven calendar years, EPA's proposed allocations amount to approximately only 9% and 16% of historic annual and ozone season NOx emissions, respectively. Id. Moreover, although EPA has not published a revised version of the allocation table or otherwise announced its intention to base the final allocations on the results of IPM v.4.10, the resulting projections of emissions generated by IPM v.4.10 - 45.66 tons annual NOx and 31.9 tons of ozone season NOx - would still be dramatically insufficient, although slightly higher than the results generated by IPM v.3.02. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.3]
In light of the significant shortfall in allowances that Linden Cogen would experience under either the results of either IPM v.3.02 or IPM v.4.10, Linden Cogen anticipates that it could be required to purchase allowances at a cost that could exceed $1,000,000 per year, according to estimates provided by emissions brokers. As we observed in October 1, 2010 Comments, EPA has proposed to allocate 88% of New Jersey's budgeted emissions to six coal-fired generating plants. Id., 17. Some of these facilities would receive significantly greater allocations than they had received under the Clean Air Interstate Rule ('CAIR') or than their historic emissions. Id. Thus, as a likely consequence of EPA's allocation methodology, these coal-burning facilities in New Jersey would presumably become sellers of allowances and gain a substantial subsidy, at the expense of cleaner facilities such as Linden Cogen that would become buyers of allowances. Id., 18. [EPA-HQ-OAR-2009-0491-3743.1_NODA, p.3]

 8. The supporting documentation states that 'NEEDS v.4.10 uses EIA Form 860 (2006) data as one of the primary data inputs.' Id., 4-3. The supporting documentation for EPA Base Case v.4.10 also states that, while 'EIA Form 860 (2006) and Form 767 (2005) is the starting point and largest component of the existing unit population in NEEDS v.4.10 [,] the final population of existing units is supplemented based on information from other sources, including comments from utilities, submissions to EPA's Emission Tracking System, Annual Energy Outlook, and reported capacity in Global Energy's New Entrants Database.' Id.
9. EIA Form 860, instructions for line 15.
10. The average heat rate reported for the plant's generating units may not reflect the actual heat rate of individual units or the maximum heat rates appearing in the contractual terms governing the pricing of power or reimbursement for costs related to its generation.
11.  See NEEDS Database for IPM V.2.1 and NEEDS Database for IPM 2003, available at: http://www.epa.gov/airmarkets/progsregs/epa-ipm/past-modeling.html.
12. See NEEDS Database for IPM 2004, available at: http://www.epa.gov/airmarket progsregs/epa-ipm/past-modeling.html.
Consolidated Edison Company of New York, Inc, (CECONY)
Recommended Changes to the NEEDS v. 4.10 Database
There are four CECONY-owned EGUs listed in the NEEDS v. 4.10 database: [See EPA-HQ-OAR-2009-0491-2653.1, p.2 for table listing the four CECONY-owned EGUs listed in the NEEDS v. 4.10 database]
In the order shown above, CECONY refers to these units as East River 2/20, East River 1/10, East River 7/70 and East River 6/60; a short description of each unit's characteristics is provided below. [See EPA-HQ-OAR-2009-0491-2653.1, pp. 2-8 for comments pertaining to units: East River 1/10 and East River 2/20, East River 6/60, and East River 7/70; See EPA-HQ-OAR-2009-0491-2653.1, pp. 3-7 for tables: Data Issue No. A-1: MW Rating of Each Plant, Data Issue No. A-2 Heat Rate, Data Issue No. A-3: Cogeneration Status, Data Issue No. A-4: Modeled Fuel, Data Issue No. A-5: NOx Combustion Controls, Data Issue No. A-6: SO2 emission rate, Data Issue. A-7: Uncontrolled NOx Base Rate, Data Issue No. A-8: Controlled NOx Base Rate, Data Issue No. A-9: Uncontrolled NOx Policy Rate, and Data Issue No. A-10: Controlled NOx Policy Rate. 
Consumers Energy
We also request that the comment period for the NODA be extended from October 15, 2010 to November 30,2010, as well. [EPA-HQ-OAR-2009-0491-1890.1, p.1]
To further complicate the process, the September 1st NODA announced that EPA has placed into the docket of this rulemaking, numerous new documents and computer runs that bear directly on the proposed Transport Rule. The new information totals over 3,000 pages of documentation. The NODA provides a 45-day comment period, until October 15,2010, on the new information but states, without explanation, that the comment period on the proposed Transport Rule is not extended beyond the existing October 1, 2010 comment deadline. [EPA-HQ-OAR-2009-0491-1890.1, p.2]
The new information placed in the docket on September 1, 2010, is of central relevance to commenters' assessment of the proposed Transport Rule on such critically important matters as state emission budgets, unit allowance allocations, and state air quality 'linkages.' EPA acknowledges as much by stating in the NODA that the new information could affect the final rule by, among other things:
1. Changing emission projections that were used to determine which downwind areas have air quality concerns (i. e., non-attainment or maintenance) absent this rulemaking and to determine which States contribute to those problems.
2. Changing cost and emission projections used in the multi-factor test to determine the amount of emissions that represent significant contribution. Any such changes should be evaluated by EPA. Following that, the results of EPA's evaluation should be placed into the rulemaking docket, so that affected companies can fully understand the ramifications of the NODA information. [EPA-HQ-OAR-2009-0491-1890.1,pp.2-3]
That would enable us to discuss the ramifications with our respective state environmental regulatory agencies and public service commissions. Sources and states should not be expected to comment, in a bifurcated fashion, on these extraordinarily complex, interrelated matters, and certainly should not be expected to do so on such a highly compressed schedule as is represented by EPA's current October 1 and October 15 comment deadlines. [EPA-HQ-OAR-2009-0491-1890.1, p.3]
As several other entities have pointed out, EPA is subject to neither a statutory nor court-ordered timetable to complete this rulemaking. The extended comment deadlines would provide Consumers Energy, as well as any other affected and interested organizations, a reasonable opportunity to prepare detailed, meaningful comments that may be useful to the Agency in resolving in an appropriate way the many legal, policy, and technical issues raised by the Proposed Transport Rule and, now, by the NODA as well. [EPA-HQ-OAR-2009-0491-1890.1, p.3]
On September 14, 2010, Consumers Energy submitted a request seeking the extension of the public comment period for the Transport Rule by 60 days, to November 30, 2010. We also requested that the comment period for the NODA be extended to the same date. As of this date, we have not received a response from EPA regarding either of these extension requests. [EPA-HQ-OAR-2009-0491-2837.1, p.2]
To further complicate the process, the September lst NODA announced EPA's placement in the docket of this rulemaking numerous new documents and computer runs that bear directly on the proposed Transport Rule. The new information totals over 3,000 pages of documentation. The NODA provides a 45-day comment period, until October 15, 2010, on the new information but states, without explanation, that the comment period on the proposed Transport Rule is not extended beyond the existing October I, 2010 comment deadline. [EPA-HQ-OAR-2009-0491-2837.1, p.4]
The new information placed in the docket on September 1,2010, is of central relevance to commenters' assessments of the Proposed Transport Rule on such critically important matters as state emission budgets, unit allowance allocations, and state air quality 'linkages.' EPA acknowledges as much by stating in the NODA that the new information could affect the final rule by, among other things:
1. Changing emission projections that were used to determine which downwind areas have air quality concerns (i.e., nonattainment or maintenance) absent this rulemaking and to determine which States contribute to those problems.
2. Changing cost and emission projections used in the multi-factor test to determine the amount of emissions that represent significant contribution. [EPA-HQ-OAR-2009-0491-2837.1, p.4]
Any such changes should be evaluated by EPA, and the results of EPA's evaluation should be placed in the rulemaking docket, so that affected companies can fully understand the ramifications of the NODA information and be able to discuss the ramifications with our respective state environmental regulatory agencies and public service commissions. Sources and states should not be expected to comment in a bifurcated fashion on these extraordinarily complex, interrelated matters, and certainly should not be expected to do so, on such a highly compressed schedule as is represented by EPA's current October 1 and October 15 comment deadlines. To do so violates the very tenet of public comment by not allowing those affected by the proposed rule to provide meaningful comment for the EPA to consider in shaping a final rule. A sham comment period neither promotes the spirit, nor the letter, of the very Act that EPA claims to be enforcing by promulgating this proposed rule. [EPA-HQ-OAR-2009-0491-2837.1, p.4]
We also requested that the comment period for the NODA be extended to the same date. On October 12, 2010, we received a response from EPA denying both of these extension requests. EPA's letter was dated October 5, 2010 and postmarked October 6, 2010. [EPA-HQ-OAR-2009-0491-3795.1_NODA, p.2]
As was the case for the proposed Transport Rule, the comment period on the NODA is arbitrarily and unreasonably short. Consumers Energy joins many others in requesting that EPA reopen the comment period, allowing a reasonable comment period and providing supporting technical documents that were not made available to the public as part of the NODA. The combination of the short comment period allotted and the lack of supporting data have made it extremely difficult for us to conduct a full review of the NODA, in order to provide meaningful comments on the NODA and how it affects the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3795.1_NODA, p.4]
As both UARG and EEI point out, it is a near certainty that the new EGU information supplied by companies in their comments on the proposed Transport Rule, combined with changes to the NEEDS database and the IPM inputs identified in EPA's Transport Rule NODA, would affect, among other things, EPA's significant contribution analysis, the creation and evaluation of the cost curves, and the breakpoints selected based on the cost curves. It also is possible that the NODA, and comments received on the data contained in it, may result in changes in EPA's determinations of which states are regulated under the Transport Rule, the emission budgets to which those states will be subject, and unit-level allowance allocations supporting the final Transport Rule.  [EPA-HQ-OAR-2009-0491-3795.1_NODA, p.4]
The potential changes described above are significant. EPA did not provide a final set of information and assumptions on which the proposed Transport Rule was based at the time the proposal was issued. This error was compounded and further complicated by not providing an adequate amount of time for EEI member companies to complete an in-depth analysis of both the proposed Transport Rule and the impacts of changes caused by the NODA on individual company operations. The result of this series of errors is that EPA is placing companies, like Consumers Energy, in the position of revising plans for control projects that are currently being implemented, with associated costs in the billions of dollars. Such revisions would incur substantial cost penalties.  [EPA-HQ-OAR-2009-0491-3795.1_NODA, p.4]
UARG's comments describe, in detail, how data contained in the NODA affect key elements of EPA's proposed Transport Rule.  [EPA-HQ-OAR-2009-0491-3795.1_NODA, p.4]
Consumers Energy is also aware of comments being submitted by the Midwest Ozone Group (MOG). Those comments direct EPA's attention to errors in the data characterizing existing EGUs as well as erroneous assumptions, modeling disconnects, and database errors related to the Integrated Planning Model (IPM). Specifically, MOG points out that EPA has failed to provide any Technical Support Documents (TSD) on the NODA, which are critical in understanding the new modeling platform. This is a particular concern with respect to unit allowance allocations. Without this type of information, electric generators are unable to identify, with certainty, any errors or inaccuracies, but are left to guess what these values will be under the NODA. [EPA-HQ-OAR-2009-0491-3795.1_NODA, p.4]
 The prudent course for EPA is to retract and rethink this NODA and the proposed Transport Rule. The process requires more upfront transparency and a greater degree of involvement by the States and affected sources. EPA has neither a Court mandated nor a statutory required date for completion of this rule. Consequently, we recommend that EPA take this opportunity to make the necessary changes.  [EPA-HQ-OAR-2009-0491-3795.1_NODA, pp.4-5]
 EPA must work with the states and affected sources to correct the numerous errors and assumption, with respect to source emissions, control plans and decommissioning plans contained within the proposed rule.  [EPA-HQ-OAR-2009-0491-3795.1_NODA, p.5]
Council of Industrial Boiler Owners (CIBO)
EPA's use of the revised IPM as discussed in the NODA does not resolve the problems with the Transport Rule. As made clear in the background document for the NODA, 'Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model' (Base Case Documentation), IPM utilizes a series of 'decision variables' for 'model plants.' Model plants are 'aggregate representations of real life electric generating units.' Base Case Documentation at 2-3 and n.1. Based on IPM decision variables for model plants, EPA projects what it believes will be the heat input for each covered facility. Heat input effectively is determinative of allocations of allowances for compliance. However, IPM does not consider critical variables such as units' obligations to run based on contractual agreements (i.e., Power Purchase Agreements; whether or not a renewable energy source contracted to sell its Renewable Energy Credits; or other contractual obligations). This is a significant change from past practice of defining a boiler's heat input based on an evaluation of the past five years of data and utilization. EPA is in essences allowing IPM to determine how much a facility will run, by implementing what the model indicates is the proper allocation for any given facility. IPM, with short-sighted data, is selecting winners and losers. This problem is compounded by EPA's proposed intra-state trading only, and creates even greater difficulties for single-unit entities that cannot trade credits among units. [EPA-HQ-OAR-2009-0491-3754.1_NODA, pp.2-3]
EPA improperly has concluded the Transport Rule will be expanded in the near future, yet its data and analytic underpinnings are not even finalized according to the NODA. [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.3]
The proposal makes clear that sources gain no certainty from that rulemaking. EPA projects 2012 and 2014 projections are already outdated, as they do not account for emission reductions required under new pending or soon-to-be-issued regulations. EPA's analysis of costs for sources to comply with the Proposed Rule reflect an expectation that sources will install scrubbers, SCR or implement other similar emission control upgrades. EPA indicates that its analysis assumes only rules in place as of December 2008. Since December 2008, EPA has proposed, finalized or will propose and finalize these regulations that mandate some or all of the very same emission reduction strategies that will be required by this rule: SO2 NAAQS, NO2 NAAQS, Ozone NAAQS, Boiler MACT, CISWI, Utility MACT, PM NAAQS, CO NAAQS as well as a host of MACT and NSPS standards under the Risk and Technology Review provisions. Adding to this uncertainty for sources regarding future required controls are the requirements for greenhouse gas control, including the PSD Tailoring Rule, and upcoming NSPS for boilers. [EPA-HQ-OAR-2009-0491-3754.1_NODA, pp.3-4]
Even regarding only the Transport Rule, the NODA itself indicates that the information is a work in progress and that EPA plans to utilize the data in v4.10 to ultimately project total and ozone period heat input for determining the amount of allowances to be allocated to a facility. Unless EPA has finalized the data and assumptions, regulated entities have no means of accurately assessing the rule's impact on their operations nor of providing meaningful comment to EPA on those impacts. [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.4]
In the broadest sense, industry needs to know what controls will be required in total so that plans and costs can be optimized. It is very hard for business to plan and budget for control needs without clarification of what reductions will ultimately be required. Open-ended piece meal regulations are inconsistent with meeting environmental objectives and planning funding and resources to accomplish those objectives in a reasonable manner. This Proposed Rule carries no semblance of certainty or the orderly administration of regulation. [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.4]
These other intervening rules also affect EPA's assumptions, yet they are unaccounted for in the model and data of the NODA. For example, EPA's planned rulemakings on NOx and utility MACT will impose additional costs and impacts on EGUs. These rules could provide different circumstances for determining whether or not a plant continues to run. In some cases, the plants that were modeled to decrease output may be the plants that are in a better position to operate under these potential new rules, but will not be able to do so because of the allocations received under the Transport Rule. [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.4]
Model plant assumptions are inflexible and lead to incorrect heat input, emission reduction assumptions, dispatch and other critical data. [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.4]
Several critical issues regarding IPM v4.10 are not clear. For example, EPA reports that it is using ETS 2007 for determining the heat rate of a unit. This is apparent from the total heat input from the CAMD data divided by the Net Output of the Facility/Unit. However, based on a preliminary review of CFB waste coal plants, the heat rate has been underestimated. In addition, plant availability and capacity also appear to have been underestimated. [EPA-HQ-OAR-2009-0491-3754.1_NODA, p.4]
Dairyland Power Cooperative
Dairyland Power understands the NEEDS database is used by the EPA as an input to the Integrated Planning Model (IPM) v4.10, and that the EPA plans to use the modeling results from the IPM model runs in crafting a final Transport Rule regulation. If the EPA intends to go through with finalizing a regulation based on the NEEDS database and the IPM model, Dairyland Power believes it is essential that historical operating data for our units is accurately reflected in the NEEDS database. Additionally, if the EPA is going to perform modeling scenario(s) that include switching the coal type (e.g., bituminous to 100% PRB or bit.lsubbit. blend to 100% PRB) for fueling some of Dairyland Power's boilers, then it is equally essential that the NEEDS database include data that reflects the effects on unit performance associated with any coal-switch scenario the EPA is inclined to model. [EPA-HQ-OAR-2009-0491-3765.1_NODA, pp.1-2]
The EPA must not overlook the issues of boiler/fuel compatibility and fuel-related effects on boiler performance and efficiency especially if the EPA intends to create new regulatory limits on Dairyland Power units in a final Transport Rule. [EPA-HQ-OAR-2009-0491-3765.1_NODA, p.2]
I. Net Summer Dependable Capacity Does Not Correspond to Net Dependable Capacity as reported in the 2009 North American Electric Reliability Corporation Generating Available Data (GADS).
The NEEDS database column 'Capacity (MW)' is defined in the 'NEEDS v.4.10 User Guide' as 'The net summer dependable capacity (in megawatts) of the unit available for generation for sale to the grid. Net summer dependable capacity is the maximum capacity that the unit can sustain over the summer peak demand period reduced by the capacity required for station services or auxiliary equipment.' The 'Dependable Capacity (MW)' in the GADS database is reported monthly. The months of June, July and August can be averaged together to develop a net summer dependable capacity. Dairyland Power proposes the use of the 2009 GADS data for Dairyland Power's units in the NEEDS v4.l0 database for modeling the units as they are currently operated. For any scenario that switches bituminous or bituminous/subbituminous blend units to 100% PRB coal, please see the comments in section III below. The following table presents the NEEDS 'Net Summer Dependable Capacity' and the net summer dependable capacity as developed from the 2009 GADS data. [EPA-HQ-OAR-2009-0491-3765.1_NODA, p.2][[See Docket Number EPA-HQ-OAR-2009-0491-3765.1_NODA, pp.2-3 for the table.]]
II. Heat Rate Does Not Correspond to Heat Rate as Calculated from 2009 Department of Energy EIA-923 data.
The NEEDS database column 'Heat Rate (Btu)' is defined in the 'NEEDS v.4.10 User Guide' as 'The net heat input (in Btu) required to generate 1 kilowatt hour of electricity. It is a measure of a generating unit's efficiency.' Unit net generation and heat input are contained in the Department of Energy EIA-923 report. From these two parameters, heat rate as defined in the NEEDS v.4.10 User Guide can be calculated. It is assumed that the NEEDS heat rate is an annual average since a different averaging period is not specified in the user's guide. Using the Department of Energy EIA-923 data, Dairyland Power calculated annual average heat rates for each of Dairyland Power's steam generating units. Dairyland Power proposes the use of the 2009 GADS data for unit heat rate in the NEEDS v4.10 database for modeling the units as they are currently operated. For any scenario that switches bituminous or bituminous/subbituminous blend units to 100% PRB coal please see the comments in section III below. The following table presents the NEEDS 'Heat Rate' and the net heat rate as developed from the 2009 EIA-923 data. [EPA-HQ-OAR-2009-0491-3765.1_NODA, p.3] [[See Docket Number EPA-HQ-OAR-2009-0491-3765.1_NODA, p.3 for the table.]]
III. Alma Unit 4, Alma Unit 5 and Genoa (1): Loss of Capacity and Increase in Heat Rate When Burning 100% PRB Coal.
In previous comments to this docket, Dairyland Power addressed the extensive modifications that would have to be performed in order to handle and burn 100% PRB coal. In addition to combustible dust issues, it is Dairyland Power's estimate that fueling Alma Unit 4 and Alma Unit 5 with 100% PRB coal will result in an electric output capacity reduction of 37% for each unit resulting from the reduced heat input to the boiler due to the lower heating value of PRB coal. It is also estimated that unit heat rate will increase approximately 15%. [EPA-HQ-OAR-2009-0491-3765.1_NODA, p.3]
Dairyland Power's experience with fueling the Genoa (1) unit with 100% PRB coal results in an electric output capacity reduction of approximately 23% to 28% resulting from the reduced boiler heat input. The unit also experiences a heat rate penalty of approximately 13%. [EPA-HQ-OAR-2009-0491-3765.1_NODA, p.4]
The following table presents the Current NEEDS capacity and heat rates for the Dairyland Power units affected by a switch to 100% PRB Coal. Dairyland Power proposes these values be used in the NEEDS database and any subsequent IPM runs that assumes a 100% PRB fuel switch as a operating/compliance scenario. [EPA-HQ-OAR-2009-0491-3765.1_NODA, p.4] [[See Docket Number EPA-HQ-OAR-2009-0491-3765.1_NODA, p.4 for the table.]]
We believe that EPA needs to do a considerable amount of work to revise the NEEDS database as it is presented in the NODA to realistically model the dispatch and emissions of the utility system with the changes USEP A has proposed in the Transport Rule. [EPA-HQ-OAR-2009-0491-3765.1_NODA, p.4]
We also urge the EPA to revise the NEEDS database capacities and heat rates for Dairyland Power units consistent with the values provided in the above tables. [EPA-HQ-OAR-2009-0491-3765.1_NODA, p.4]
Dominion
EPA's New Notice of Data Availability
EPA recently issued a NODA which added a significant amount of new technical information into the docket that is of central relevance to critical elements of this rulemaking that will, perhaps significantly, alter state budgets and unit allocations in a final rule. In the NODA, EPA indicates that it will base final rule budgets/allocations on a new/updated version of the IPM model as well as a revised NEEDS database. EPA has provided a 45-day comment period for the NODA which ends only 2 weeks after the October 1, 2010 date to submit comment on the proposed rule. The issuance of this NODA in the middle of the 60-day comment period EPA established for the proposed Transport Rule rulemaking that contains such a voluminous amount of new/updated information that is different, yet highly interrelated to the technical information used in development of the proposed rule has rendered evaluation and comment on this rulemaking daunting and cumbersome. In light of this NODA and the numerous assumption errors/issues noted, EPA should address/fix all assumption errors, rerun all relevant technical assessments (including reanalysis of air quality/downwind impact assessments, etc.) using the updated model, and reissue the rule for public comment as a Supplemental Notice of Proposed Rulemaking (SNPR). Stakeholders should not be expected to comment in such a bifurcated manner on these very complex, interrelated matters on the very compressed schedule that was put forth under EPA's current October 1st and October 15th comment deadlines. [EPA-HQ-OAR-2009-0491-2715.1, p.11]
We are still reviewing the information contained in the NODA and will submit pertinent comments specific to the NODA by October 15th. However, based on our preliminary review of the NODA, we are submitting the following corrections to the NEEDS - Version4.1 0 database: [EPA-HQ-OAR-2009-0491-2715.1, p.11]
Brayton Point (ORIS Plant Code 1619): Unit 3 is incorrectly listed as having a wet scrubber installed by 2006. As noted in Section III.1 above, this unit is scheduled to have a dry scrubber installed by 2014. [EPA-HQ-OAR-2009-0491-2715.1, p.12]
Chesterfield Power Station (ORIS Plant Code 3797): Units 3,4 and 5 are listed as having wet scrubber installed by 2010. Unit 5 tie-in is scheduled by the end of 2011; The Unit 3 and 4 schedules have not been finalized. [EPA-HQ-OAR-2009-0491-2715.1, p.12]
Salem Harbor (ORIS Plant Code 1626): Units 1, 2 and 3 are incorrectly listed as having activated carbon injection (ACI) technology installed in 2002. These units do not have or operate ACI controls. [EPA-HQ-OAR-2009-0491-2715.1, p.12]
EPA's Addition of Significant New Information to the Docket That Is of Central Relevance to the Determination of State Budgets and Unit Allocations Warrants the Need for a Supplemental Proposal and Additional Time for Adequate Public Review and Comment
The NODA has added new information to the docket that is of central relevance to assessment of the Transport Rule on such critical matters such as state emission budgets, unit allowance allocations and state emission-to-downwind air quality linkages that will affect the final rule. In the NODA, EPA indicates that it will base final rule budgets/allocations on a new version of the Integrated Planning Model (IPM) as well as a revised National Electric Energy Data System (NEEDS) database, details of which it has placed into the docket. EPA has provided a 45-day comment period for the NODA which ends only 2 weeks after the October 1, 2010 deadline to submit comment on the proposed rule. The issuance of this NODA in the middle of the 60-day comment period EPA established for the proposed Transport Rule rulemaking that contains such a voluminous amount of new/updated information that is different, yet highly interrelated to the technical information used in development of the proposed rule has rendered evaluation and comment on this rulemaking daunting and cumbersome. In light of this NODA and the numerous modeling assumption errors/issues that were noted in comments previously filed on the proposed rule, EPA should address/fix all assumption errors, rerun all relevant technical assessments (including reanalysis of air quality/downwind impact assessments, etc.) using the updated model, and reissue the rule for public comment as a Supplemental Notice of Proposed Rulemaking (SNPR). Stakeholders should not be expected to comment in such a bifurcated manner on these very complex, interrelated matters on the very compressed schedule that was put forth under the Transport Rule proposal and this subsequent NODA. [EPA-HQ-OAR-2009-0491-3717.1_NODA, pp.1-2]
The NODA Does Not Contain All of the Pertinent Information Needed for Adequate Review and to Provide Meaningful and Comprehensive Comment
The NODA does not contain all of the pertinent data necessary to adequately assess and to comment meaningfully on the new information. Much of the information necessary to properly evaluate the nature and extent of changes that are likely to the proposed Transport Rule are not contained in the docket. While the results of 48 IPM runs (using IPM-Version 3.02) were provided in conjunction with the proposed rule, only 8 model runs (with revised Version 4.10) have been provided in the NODA. Of These, four runs related to an entirely new alternative set of model input assumptions based on the Energy Information Administration's (EIA) Annual Energy Outlook 2010 for natural gas resources, leaving only four runs associated directly to the set of 48 modeling runs used in support of the proposed Transport Ru1e. Missing in the NODA is such critical information as:
:: Cost effectiveness runs and other modeling runs including the 'TR S02 2000' IPM run and associated parsed data file that, in conjunction with the 'TR SB 2014 Limited Trading' run and parsed data file, was the basis of EPA's development of the 2014 S02 budgets and unit allocations
:: The 'TR SB 2012 Limited Trading' run and parsed file that would have reflected adjustments applied to EGU's with controls that EPA deemed 'dispatchable' that are critical to understanding of the 2012 state budgets and unit-specific allocations.
:: Comparable critical summary tables, such as 'Allocation Table - Technical Support Document for the Transport Rule - State Budgets, Unit Allocations, and Unit Emission Rate', which provided in some detail the basis of 2012 budgets and unit specific allocations including projected vs. reported data as well assumptions and adjustments made to account for operation of existing or planned/assumed pollution control equipment (controls EPA deemed 'dispatchable'). [EPA-HQ-OAR-2009-0491-3717.1_NODA, p.2]
This information was critical to companies to complete the detailed reviews that were conducted for evaluating and providing comment on the basis for the budgets/allocations in the proposed rule. Failure to provide the detailed information on all of the pertinent data and assumptions on which EPA plans to base the final rule renders any comprehensive comment very difficult. EPA should, at a minimum, place all of this critical information into the docket and provide additional time for public comment. [EPA-HQ-OAR-2009-0491-3717.1_NODA, pp.2-3]
The Revised IPM Modeling Platform and New Information in the NODA Warrants a Re-evaluation of Both State Budgets and Unit Allocations
In the NODA, EPA indicates that the IPM policy runs (Limited Trading runs) provided include the same state-level caps that EPA modeled in the proposed Transport Rule. The state emission caps 'have not been modified to account for any changes that the new modeling might suggest' but are provided merely for 'informational purposes to allow commenters to understand the impact that changes in the modeling platform have on projected impacts of the caps'. This statement is of concern in that it suggests the possibility that EPA may consider holding the state budgets constant (as established in the proposed rule) and using the revised IPM modeling assumptions (and any unit-specific corrections applied based on comments received during the previous comment period on the proposed rule) to merely 're-distribute' allocations among individual sources in each state. We believe the effect of the new modeling will definitively result in the need to establish revised state emission budget in addition to unit -specific allocations. Although, as noted above, EPA has not provided much of the pertinent information based on the revised (Version 4.10) IPM modeling platform that is needed to fully evaluate impacts on state budgets and allocations, cursory review of the revised IPM (Version 4.10) modeling run summary reports indicate changes in projections of power demand, the projected mix of new generation capacity and emission control retrofits that would yield revised emission projections that would warrant a re-evaluation of emissions-to-air quality linkages and revised state emission budgets to the extent such budgets established in the final rule are to be based on the revised IPM modeling platform and the revised NEEDS data base.[EPA-HQ-OAR-2009-0491-3717.1_NODA, p.3]
Updated NEEDS Database
We are submitting the following corrections for Dominion owned or co-owned facilities to the NEEDS - Version 4.10 database: [EPA-HQ-OAR-2009-0491-3717.1_NODA, p.3]
Heat Rate Corrections
:: Brayton Point Power Station (ORIS Plant Code 1619): Unit I heat rate listed as 9,110 Btu -should be 9,790 Btu; Unit 2 heat rate listed as 9,110 Btu - should be 9,870 Btu.
:: Salem Harbor Power Station (ORIS Plant Code 1626): Unit 2 heat rate listed as 10,519 Btu - should be II, I 00 Btu.
:: North Branch Power Station (ORIS Plant Code 7537): Unit IA and Unit IB heat rate listed as 11,204 Btu - should be 13,100 Btu. [EPA-HQ-OAR-2009-0491-3717.1_NODA, p.3]
:: Morgantown Energy Center (ORIS Plant Code 10743): Unit CFB I and Unit CFB2 heat rate listed as 10,331 Btu - should be 13,200 Btu. [EPA-HQ-OAR-2009-0491-3717.1_NODA, p.4]
Pollution Control Installation Corrections
:: Brayton Point Power Station (ORIS Plant Code 1619): Unit 3 is incorrectly listed as having a wet scrubber installed by 2006. This unit is scheduled to have a dry scrubber installed by the end of the 1st quarter in 2014.
:: Chesterfield Power Station (ORIS Plant Code 3797): Units 3, 4 and 5 are listed as having wet scrubber installed by 2010. Unit 5 tie-in is scheduled by the end of 2011; The Unit 3 and 4 schedules have not been finalized.
:: Salem Harbor Power Station (ORIS Plant Code 1626): Units 1, 2 and 3 are incorrectly listed as having activated carbon injection (ACI) technology installed in 2002. These units do not have or operate ACI controls. [EPA-HQ-OAR-2009-0491-3717_NODA, p.4]
Pollution Control Efficiency Corrections
:: Chesterfield Power Station (ORIS Plant Code 3797): Scrubber efficiency removal rates for Units 5 and 6 are listed at 98% - the sustained removal rates for these units are 95%.
:: Mt. Storm Power Station (ORIS Plant Code 3954): Scrubber efficiency removal rates for Units 1 and 2 are listed at 95.5% - the sustained removal rates for these units are 95%.
:: Altavista Power Station (ORIS Plant Code 10773): Scrubber efficiency removal rates listed as 95% - the sustained removal rates are 90% (dry scrubber).
:: Southampton Power Station (ORIS Plant Code 10774): Scrubber efficiency removal rates listed as 95% - the sustained removal rates are 90% (dry scrubber).
:: Brayton Point Power Station (ORIS Plant Code 1619): Units 1,2 and 3 are listed at 95% mercury removal- the sustained mercury removal rates are 85%. [EPA-HQ-OAR-2009-0491-3717.1_NODA, p.4]
Revised IPM Model-Input Assumptions
Scrubber Removal Efficiency: The revised IPM (Version.4.1 0) modeling platform assumes an increase in maximum SO2 emission removal efficiency for wet flue gas desulfurization systems (FGDs) from 95% to 98%. It is not clear whether the new 98% removal efficiency represents an assumption of continuous control efficiency. If so, this assumption is not realistic; this level of efficiency is not achievable on a continuous basis. Rather, wet scrubber removal efficiencies at these levels (98%) are generally based on vendor guarantees with spec fuels and optimal equipment condition encountered during acceptance testing. Accordingly, a 95% removal efficiency, which was used in the version of IPM on which EPA relied in developing the proposed Transport Rule, is still benchmark for sustained operation of a wet scrubber and should be retained in !PM Version 4.10. [EPA-HQ-OAR-2009-0491-3717.1_NODA, p.4]
Retrofit Assumptions for Units IPM Unit-Specific Modeling Assumptions/Inaccuracies
In comments submitted on October 1, 2010 on the proposed Transport Rule, we noted in detail numerous inaccuracies in the IPM model (Version 3.02) input assumptions specific to Dominion facilities and electric generating units that were relevant the state emission budgets and individual unit allocations in the proposed rule and provided documentation for correcting the noted discrepancies. Based on our review of the new information that is provided in the NODA, many of these inaccuracies persist and in some cases are more problematic. Although we realize it was not possible for EPA to have incorporated corrections provided in our initial set of comments prior to issuing the NODA, we are including a summary of these inaccuracies in these comments to reiterate the need for EPA to address these assumption errors, rerun all relevant technical assessments using the updated model, and reissue the rule for public comment as a Supplemental Notice of Proposed Rulemaking (SNPR). [EPA-HQ-OAR-2009-0491-3717.1_NODA, p.5]
Brayton Point Unit 3): The proposed CATR assumes the installation of a wet scrubber by 2012 on Brayton Point Unit 3. In accordance with Brayton Point's Mass DEP-approved 310 CMR 7.29 Emission Control Plan a dry scrubber will be installed on Brayton Point Unit 3 for SO2 control. This dry scrubber will be equipped with a Fabric Filter (FF) baghouse for control of particulate matter emissions and will commence commercial operation in the first quarter 2014, per the Department's approval of its 310 CMR 7.29 Emission Control Plan dated December 29,2008 and Mass DEP's Proposed Conditional Approval for Brayton Point Relative to The Major Comprehensive Plan Approval for 310 CMR 7.02 Plan Approval and Emissions. Therefore, for Brayton Point Unit 3, we request the EPA modify its assumptions to include a dry scrubber with a commercial operation date of first quarter 2014, consistent with Mass DEP's Emission Control Plan approval dated December 30, 2008, and modify the unit and state budgets accordingly. [EPA-HQ-OAR-2009-0491-3717.1_NODA, p.5]
Salem Harbor Units 1, 2 and 3: In the proposed rule, EPA did not allocate NOx allowances for Units 1 and 2 apparently due to an erroneous adjustment made to projected 2012 NOx emissions to account for annual operation of SNCR's. In addition, EPA assumed a scrubber would be installed on Unit 3 by 2012 resulting in a significant shortfall of S02 allocations. The new IPM Version 4.10 runs are more problematic in that the model predicts that all 3 coal units do not operate in the 2012 base case (no predicted fuel throughputs by the model). There is no explanation provided for these changes. Although EPA has not provided any of the detailed resultant unit-specific allocations (as it did for the initial IPM-Version 3.02 runs used in the proposal), one could assume that use of the Version 4.10 modeling assumption would result in no allocated allowances for both S02 and NOx for these units in 2012. Although the model does show the units running (with a scrubber on Unit 3) in the 2014 'Limited Trading' policy run, it is not clear what relevance this would have to allocations beginning in 2014 (and beyond) since NOx allowances for all states and S02 allowances for Group 2 states (Massachusetts) are based on the 2012 modeling projections and are applicable for 2012 and all years beyond. (Group 2 states are not subject to the additional S02 budget reductions and revised allocations imposed in the Group 1 states beginning in 2014). There is no explanation provided for the discrepancy between the 2012 base case run (assumes units do not operate) and the 2014 policy run (units assumed to operate). As noted in our previous comments, Salem Harbor Units 1 and 2 are committed operationally and commercially to provide capacity at least through May 31, 2012 in the region's Forward Capacity Market (FCM) managed by New England's Independent System Operator (ISO-NE). Although static-delist bids were accepted by ISO-NE for each of these units in Forward Capacity Auctions (FCAs) 3 and 4, the acceptance of these bids by ISO-NE does not preclude these supply resources from continuing to operate for regional energy and ancillary services support and thus require both NOx and S02 allowances under the CATR. Unit 3 is committed operationally and commercially to run at least through May 31, 2014 (and very possibly may be required longer) in accordance with ISO-NE's determination that the unit - together with Salem Harbor Unit 4 - is needed to support system reliability in the Boston Import Area. In addition, the model assumes a scrubber on Unit 3 by 2014. We have not planned to install a scrubber on this unit. However, Salem Harbor will continue to achieve S02 emission reductions to comply with 310 CMR 7.29 in accordance with the June 2003 Administrative Consent Order (ACO) Number ACO-NE-03-7001 and subsequent May 2005 amendment (AACO).[EPA-HQ-OAR-2009-0491-3717.1_NODA, p.6]
Brayton Point Unit 4 (Oil) and Salem Harbor Unit 4 (Oil): As in the previous version of IPM, the revised modeling runs assume that Brayton Point Unit 4 and Salem Harbor Unit 4 will not continue to run past December 31, 2011 (model predicts no heat input capacity for these units). While these units typically have low capacity factors, we fully expect to operate them in the future, as demonstrated by the capacity supply commitments from the FCM 2, 3 and 4 auction. Moreover, Salem Harbor Unit 4 is needed to support Boston Import Area reliability at least through May 31, 2014 in accordance with ISO-NE's determinations in the FCM 3 and 4 auctions. Therefore, for Brayton Point and Salem Harbor Units 4, we request that EPA modify 
Brayton Point Unit 4 (Oil) and Salem Harbor Unit 4 (Oil): As in the previous version of IPM, the revised modeling runs assume that Brayton Point Unit 4 and Salem Harbor Unit 4 will not continue to run past December 31, 2011 (model predicts no heat input capacity for these units). While these units typically have low capacity factors, we fully expect to operate them in the future, as demonstrated by the capacity supply commitments from the FCM 2, 3 and 4 auction. Moreover, Salem Harbor Unit 4 is needed to support Boston Import Area reliability at least through May 31, 2014 in accordance with ISO-NE's determinations in the FCM 3 and 4 auctions. Therefore, for Brayton Point and Salem Harbor Units 4, we request that EPA modify its assumptions to include continued operation of both units consistent with IS0-NE market rules and modify the unit and state budgets accordingly. [EPA-HQ-OAR-2009-0491-3717.1_NODA, pp.6-7]
Possum Point Unit 5 and Yorktown Unit 3 Oil-Fired Units: The revised IPM modeling projections show no fuel throughput in the 2012 base case run or the 2014 policy run. Although annual capacity factors have been low in recent years, these units are called upon to operate under certain conditions and are expected to continue to do so in the future. As noted in our previous comments, Dominion Virginia Power is a member of the PJM RTO and is subject to its reliability requirements and market rules. The RPM capacity market is a three-year forward market that acquires capacity to meet load plus reserve requirements. Possum Point 5 and Yorktown 3 are currently committed through May 2014 and it is our intent to continue committing these units into RPM as a means to meet our capacity requirement. Both units have run for economic and reliability reasons and there is no basis to conclude that pattern will change. Accordingly, EPA should allocate a reasonable number of allowances to these units based on historical data (at a minimum, averaged over several years).[EPA-HQ-OAR-2009-0491-3717.1_NODA, p.7]
Morgantown Energy Center: In our comments for the proposed rule, we indicated that EPA may have assumed that this facility is exempt from the CATR requirements under the proposed provisions of the rule that exempt certain cogeneration units and provided information (with supporting documentation) explaining why we believe the facility does not qualify for the exemption. We could find no information concerning this facility in the detailed parsed files provided for the revised IPM-Version 4.10 base case 2012 and 2014 Limited Trading policy runs. Accordingly, we reiterate our previous comments that this facility should be treated as a CA TR -affected facility and should be allocated appropriate S02 and NOx allowances. [EPA-HQ-OAR-2009-0491-3717.1_NODA, p.7]
Bremo Units 3 and 4: The IPM-Version 4.10 2014 policy run predicts scrubbers on these units by 2014. There are no specific requirements or current plans to install scrubbers on these units. [EPA-HQ-OAR-2009-0491-3717.1_NODA, p.7]
Additional EPA Updates Concerning Pollution Controls
EPA's document entitled 'Planned Updates to IPM v.4.10' lists a 'planned future revision' with respect to particulate matter (PM) controls for Dominion's State Line Unit 4 coal-fired boiler. Section III - Table 1 indicates that current assumptions for PM controls, which consist of a cold-side electrostatic precipitator (ESPC), will be revised to reflect the installation of hot-side ESP (ESPH) and a baghouse. The Company has no current plans to convert to an ESPH or to install a baghouse. [EPA-HQ-OAR-2009-0491-3717.1_NODA, p.7]
Coal Price Assumptions Used in IPM [EPA-HQ-OAR-2009-0491-3771.1_NODA, p.1]
The minemouth Appalachia coal prices identified in the IPM v4.10 Runs and Parsed Files appear to be between 20% and 30% low relative to the current market and between 5% and 10% low relative to the Appalachia coal prices identified in EIA 2010 Annual Energy Outlook. The use of such low coal price projections within the IPM framework will lessen the adverse financial impact on coal generating units resulting from the Transport Rule. Consequently, the IPM runs will result in a lower level of projected coal unit retirements which will in turn mask potential future reliability issues. To address this concern, Dominion recommends EPA perform an IPM sensitivity analysis that reflects increased coal prices. The results should be analyzed to assess the magnitude of coal unit retirements and also the level of new generation necessary to maintain adequate reserve margins under such a scenario. [EPA-HQ-OAR-2009-0491-3771.1_NODA, p.1]
DTE Energy
EPA has not provided adequate information for stakeholders to provide meaningful analysis and comments on the NODA and its impact on the Proposed CATR. DTE does not have access to relevant information to determine appropriate unit specific allocations, or even Michigan's budget, as a result of EPA's revised Base Case v4.10. EPA has requested electric generating companies to provide detailed comments correcting any inaccurate data or incorrect assumptions made with respect to specific units. The lack of information, completely identified in the comments of UARG, prevents DTE from the ability to evaluate the accuracy of EPA's assumptions with respect to its individual units and provide meaningful comments. [EPA-HQ-OAR-2009-0491-3714.1_NODA, p.2]
EPA's decision to re-run the Limited Trading unit-level parsed file for 2014 with the revised NEEDS database and updated IPM platform while leaving state budgets based on unrevised data and IPM platform used in the Proposed CATR is illogical and arbitrary. The very substantial changes in EPA's projections for demand for power, the projected mix of new generation capacity, and projected pollution control retrofits suggest that it would be reasonable to expect significant changes in 2014 SO2 budgets for group 1 states if those budgets are based on the revised versions of NEEDS and IPM. [EPA-HQ-OAR-2009-0491-3714.1_NODA, p.2-3]
DTE Energy Services (DTEES)
DTEES would also like to correct several errors in the National Electric Energy Data Systems (NEEDS) v.4.10 database for EJ Stoneman.
The online date is incorrect. The database states 2009 yet the facility has yet to reach full load operation in order to be considered 'online' and delivering electricity reliably under the power purchase agreement. The facility did not fire any woody biomass until July 28, 2010 and construction and commissioning is still ongoing as of October 1st, 2010. ;
The SO2 permit rate is 3.17 lbs/mmBtu. ;
Uncontrolled NOx base rate is 0.33 lbs/mmBtu (also not sure if this is applicable since the units are covered by a NOx control policy, for ex BACT) ;
Firing is not Wall, this was the configuration for coal firing. Woody biomass firing is with vibrating hydrograte Stoker. ;
NOx Post-CombControl should be SNCR, NOx Comb Control should be over-fired air;
Using a Mode 2 NOx emission rate is inappropriate since the unit does not have a mercury emission limit nor will it. Additionally, the Mode 2 NOx emission rate is inaccurate in that it should be 0.2 lbs/mmBtu. ;
Mode 3 NOx emission rate is inappropriate since the units are not covered by a seasonal NOx policy, the Mode 3 NOx emission rate is inaccurate in that it should be 0.2 lbs/mmBtu. ;
The Mode 4 NOx Rate should be 0.2 lbs/mmBtu. [EPA-HQ-OAR-2009-0491-2699.1, pp.4-5] [EPA-HQ-OAR-2009-0491-3721.1_NODA, p.4]
Duke Energy
It seems certain that the significant differences between the data on which EPA based the Proposed Transport Rule and the data EPA released pursuant to the NODA, along with additional data updates EPA has indicated it plans to make will have significant impacts on all aspects of the rule, including state budgets and unit level allowance allocations. Therefore, EPA should incorporate the NODA data or whatever other data EPA may now deem most appropriate while addressing the many comments it has received to date, rerun its analysis and issue a new proposal for public comment before issuing a final rule. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.2]
Changes to the NEEDS v4.10 Database. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.2]
Assumed Scrubber Efficiencies for Some Duke Energy Units in the NEEDS v4.10 Database are Inappropriate for Purposes of Modeling and Should Be Changed. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.2]
Cayuga (ORIS PL 1001) Unit 1. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.2]
The NEEDS v4.10 database indicates 98% SO2 removal efficiency for the existing FGD systems ('scrubbers') at Duke Energy's Cayuga (ORISPL 1001) Unit 1. This unit is designed for 97% removal and have performed at that level on a regular basis but at lower than design sulfur coal. Recent performance has continued at design level primarily due to reduced load demand which has masked the affects of normal wear on equipment such as the recirculation pumps. The limestone that is readily available to this unit is borderline in CaCO3 content which makes it difficult to achieve design performance and meet the required gypsum quality for aftermarket sales. One way to increase the SO2 removal is to increase the absorber pH. But one of the consequences of raising the pH is a reduction in gypsum quality. This FGD system and the wastewater treatment system are not designed for the addition of performance enhancing additives such as Dibasic Acid. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.2-3]
Duke Energy projects that this unit at best can achieve a 97% removal consistently over the full range of coal quality expected. To achieve 98% SO2 removal would require significant capital modification to the system that would exceed the $2,000 per ton cost breakpoint, and would produce uncertain results. For these reasons, EPA should assume a removal efficiency of 97% for this unit. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.3]
W H Zimmer (ORISPL 6019) Unit 1. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.3]
The NEEDS v4.10 database incorrectly shows 98% removal efficiency for the existing Zimmer Unit 1 FGD system ("scrubber"). This unit cannot average 98% removal and EPA should use a lower assumed removal percentage for setting the Ohio state SO2 budgets and allocating SO2 allowances. Duke Energy strongly recommends a removal efficiency of no greater than 95%. The Zimmer Station Unit 1 scrubber was designed in the late 1980's. As an NSPS unit, it was permitted and constructed at that time to meet a 91% removal requirement. Its scrubber tower size and configuration was designed to use a magnesium enhanced lime process which places significant restrictions on its performance. This unit has a much smaller tower height compared to limestone scrubbers and is limited to a much lower liquid to gas ratio. These physical limitations coupled with the process's chemical reaction kinetics make 98% removal efficiency unattainable. If Zimmer's scrubber were intended to achieve 98% removal, it would have been designed and constructed very differently. These changes cannot be retrofitted into the existing unit. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.3-4]
Duke Energy projects that this unit at best can achieve a 95% removal, but even this level of performance has not been demonstrated on a sustained basis. Achieving even this level exceeds the scrubber's original design envelope and operating outside the air permit's specification to operate with installed spare equipment. As another example, to prevent pluggage due to scaling, the mist eliminators in each module must undergo regular cleaning. This requires that one of the six modules is almost always out of service an any given time. This necessity was reflected in the original facility air permit. For these reasons, Duke Energy therefore recommends that EPA assume a removal efficiency of no more than 95% for Zimmer's scrubber. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.4]
Cayuga (ORISPL 1001) Unit 2, Gibson (ORISPL 6113) Units 1, 2, and 3, and Miami Fort (ORISPL 2832) Units 7 and 8. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.4]
The NEEDS v4.10 database indicates that Cayuga (ORISPL 1001) Unit 2, Gibson (ORISPL 6113) Units 1, 2, and 3, and Miami Fort (ORISPL 2832) Units 7 and 8 are dispatchable scrubbers. It is not clear why any of these scrubbers are shown as dispatchable. Given that they are shown as dispatchable, there is no scrubber efficiency shown for these units. The FGD systems for each of these units are designed for 97% removal and have performed at that level on a regular basis but at lower than design sulfur coal. Recent performance has continued at design levels primarily due to reduced load demand which has masked the affects of normal wear on equipment such as the recirculation pumps. The limestone that is readily available to these units is borderline in CaCO3 content which makes it difficult to achieve design performance and meet the required gypsum quality for aftermarket sales. One way to increase the SO2 removal is to increase the absorber pH. But one of the consequences of raising the pH is a reduction in gypsum quality. These FGD systems and the wastewater treatment systems are not designed for the addition of performance enhancing additives such as Dibasic Acid. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.4-5]
Duke Energy projects that these units at best can achieve a 97% removal consistently over the full range of coal quality expected. To achieve 98% SO2 removal would require significant capital modification to the system that would exceed the $2000 per ton cost breakpoint, and would produce uncertain results. For these reasons, Duke Energy therefore recommends that EPA assume a removal efficiency of 97% for each of the units. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.5]
Marshall (ORISPL 2727) Units 1, 2, 3, and 4, Belews Creek (ORISPL 8042) Units 1 and 2, and G G Allen (ORISPL 2718) Units 1, 2, 3, 4, and 5. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.5]
The NEEDS v4.10 database indicates 98% SO2 removal efficiency for the existing FGD systems ("scrubbers") at Duke Energy's Marshall (ORISPL 2727) Units 1, 2, 3 and 4, Belews Creek (ORISPL 8042) Units 1 and 2, G G Allen (ORISPL 2718) Units 1, 2, 3, 4 and 5 in North Carolina. None of these scrubbers are capable of averaging 98% SO2 removal. EPA should therefore use a lower average removal efficiency percentage for these units for setting the North Carolina state SO2 budgets and allocating SO2 allowances. Duke Energy strongly recommends a removal efficiency of 95%.  [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.5]
The Marshall, Belews Creek and Allen scrubbers were each designed to meet the North Carolina Clean Smokestack Act annual SO2 emission caps. Although there was no specific SO2 removal efficiency requirement specified in the state legislation, the FGD systems were designed to achieve 95% SO2 removal. Due to the structure of the state program as a system-level cap, the scrubber designs did not include the installation of spare Absorber Recycle Pumps. Demonstrated performance testing has verified that each scrubber is currently achieving 95% SO2 removal performance. However, recycle pump reliability has not met expectations and has placed the 95% SO2 removal at risk on a long-term performance basis. Certainly, the scrubbers are not capable of averaging 98% SO2 removal. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.5-6]
While certain performance enhancing organic acids, like Dibasic Acid ("DBA") have been tested and utilized in the utility industry to enhance FGD performance, the number of sources of DBA has diminished significantly and currently the remaining sources are oversubscribed (no availability). Looking at substitutes, the projections are that suitable substitutes will also be oversubscribed and will have limited availability. In addition, the currently installed DBA storage and handling system at each plant may be incompatible with substitutes and will likely require significant modification to installed equipment. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.6]
Duke Energy projects that each of these FGD systems at best can achieve a 95% continuous average removal efficiency but with significant uncertainty. Achieving even this performance level exceeds the scrubber's capability on a long term basis without installed spare equipment. To achieve higher SO2 removal would require significant capital investment with uncertain results and the same spare equipment limitations, and at a cost likely to exceed the $2000 per ton cost breakpoint. For these reasons, Duke Energy recommends that EPA assign and model the Marshall, Belews Creek and Allen scrubbers at 95% SO2 removal efficiency. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.6]
The NEEDS v4.10 Database Incorrectly Indicates That Some Units Are Currently Capable of Burning Subbituminous Coal [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.7]
The NEEDS v4.10 database incorrectly shows a number of Duke Energy units as being capable of burning subbituminous coal. They include R Gallagher (ORISPL 1008) units 1-4, Miami Fort (ORISPL 2832) unit 6, and Walter C Beckjord (ORISPL 2830) units 1-6. In its Transport Rule proposal, EPA states that its "...analysis does not allow a unit designed for bituminous coal to switch to (very low sulfur) subbituminous coal unless the unit has demonstrated that capability in the past. EPA assumes units with that capability have already made any investments needed to handle a switch to subbituminous coals. EPA therefore assumes that any modeled coal switching from bituminous to subbituminous has no cost or schedule impact." EPA has provided no information about what in its view constitutes a demonstration of the capability to burn subbituminous coal. In cases where IPM has modeled a 100% fuel switch to subbituminous coal, it seems reasonable that having demonstrated the capability would mean that the unit IPM has switched has actually operated on 100% subbituminous coal in the past. Certainly units that have never burned subbituminous coal in any quantity would not be considered to have demonstrated the capability to burn subbituminous coal. Yet the NEEDS v4.10 database shows the above identified units as capable of burning subbituminous coal, and the TR_SB_Limited Trading_2014 parsed file that was added to the docked as part of the NODA shows each of these units burning 100% subbituminous coal where none of the units have never burned any amount of subbituminous coal in the past, not even for a test burn. This is clearly an error that should be corrected. None of these units are capable of burning subbituminous coals. No capital investment has been made that would allow these units to safely handle and burn this fuel type, such as fuel handling upgrades, dust suppression, mill modifications and fire protection, boiler tube surface changes, sootblower additions, etc. In addition to the fact that none of these units have ever burned any subbituminous coal, Duke Energy has estimated the cost of fuel switching these units to be far in excess of EPA's $2,000 per ton cost breakpoint for SO2. It is therefore not appropriate for IPM to model any of these units as being capable of burning subbituminous coal. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.7-8]
The NEEDS v4.10 database also shows that Duke Energy's Miami Fort (ORISPL 2832) Units 7 and 8 are capable of burning subbituminous coal. These units are only capable of burning up to a 20% blend of subbituminous coal. Significant capital investment would be required to allow the units to safely handle and burn this fuel type in blends higher than 20%, such as fuel handling upgrades, dust suppression, mill modifications and fire protection, boiler tube surface changes, sootblower additions, etc. However, Miami Fort Station does not have a coal handling system that would allow for the controlled blending of bituminous and subbituminous coals, and these units cannot burn straight subbituminous coal (such as with alternating the fuel types). Therefore, EPA must include the cost of an on-site coal blending system (approximately $55 million for the two units), or increase the cost of the delivered fuel to account for off-site blending cost premiums (approximately $10 to $14 per ton of blended coal from terminals on the Ohio River) in any consideration of subbituminous coal at these units. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.7-8]
There Are Affected Units Missing From the NEEDS v4.10 Database. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.8]
The Edwardsport (ORISPL 1004) Units 7-1, 7-2, and 8-1 are each existing Proposed Transport Rule NOx Annual, Ozone Season, and SO2 Group 1 units based on the applicability criteria of §97.404, §97.504, and §97.604 of the Proposed Transport Rule. Each of these units reports emissions data to EPA under the Acid Rain Program and the CAIR SO2 and NOx programs. None of these units, however, appear in the NEEDS v4.10 data base and are therefore not included in the IPM modeling. EPA states in its Proposed Transport Rule State Budget, Unit Allocations, and Unit Emissions Rates Technical Support Document that "IPM is a representation of all units which are capable of supplying electricity to the US electric grid..." Each of these units meets this criterion for inclusion in IPM. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.8-9]
It appears that none of these units were included in the inventory of units used by EPA to establish the Indiana SO2 and NOx budgets, but per EPA's stated methodology for establishing state budgets, they should have been included. In addition, per EPA's stated methodology for allocating allowances to individual units, each of these units should have received both SO2 and NOx allowance allocations, but EPA has proposed neither SO2 nor NOx allocations for any of the units. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.9]
Duke Energy requests that EPA include each of these units in the determination of the Indiana SO2 and NOx budgets, and allocate allowances to each unit appropriately. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.9]
Incorrect Particulate Controls Identified in NEEDS v4.10. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.9]
The NEEDS v4.10 database shows the R Gallagher (ORISPL 1008) Units 1-4 with cold side electrostatic precipitators ("ESPC"). Each of these units is equipped with a baghouse. Each ESPC has been retired and removed. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.9]
NEEDS v4.10 Indicates Selective Noncatalytic Reduction ("SNCR") Technology Where the Technology No Longer Exists. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.9]
The NEEDS v4.10 database indicates that Duke Energy's Miami Fort (ORISPL 2832) Unit 6 has SNCR. The SNCR has been completely removed from this unit (the EPA website indicates that the SNCR was retired on September 30, 2008, but it was physically removed in the spring of 2006). As a result, when EPA updates the NOx emission rates to 2009 rates, it should not apply a 35% reduction factor to this unit's emission rates to account for SNCR operation, which means the Controlled NOx Base Rate and the Controlled NOx Policy Rates for this unit should be the same as the Uncontrolled NOx Base Rate and Uncontrolled NOx Policy Rate. In the NEEDS v4.10 data base the Controlled NOx Base Rate and the Controlled NOx Policy Rate for this unit are currently shown 35% lower than the Uncontrolled NOx Base Rate and Uncontrolled NOx Policy Rate. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.9-10]
There are Errors in the IPM Modeling That Need to Be Corrected. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.11]
IPM Is Modeling Some Duke Energy Combustion Turbines as Oil-Fired Units That Should Be Modeled As Natural Gas Units [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.11]
The NEEDS v4.10 database shows Duke Energy's Rockingham (ORISPL 55116) combustion turbines Units 1-5 as natural gas and distillate oil-fired units. While these units are capable of burning both fuels, their primary fuel is natural gas. Both the TR_Base_Case_2012 and TR_SB_Limited Trading_2014 parsed output files included as part of the NODA, however, indicate that IPM is selecting oil as the fuel type for these units and as a result, IPM does not operate any of the units. This is incorrect. These units should all be modeled as natural gas-fired units. IPM is selecting natural gas as the fuel type for Duke Energy's other North Carolina combustion turbines, and for all but a few other combustion turbines in the state so it makes no sense that IPM should select oil as the fuel type for any of the Rockingham units. These units would not be operated on oil while Duke Energy's other combustion turbines in North Carolina are operating on natural gas. Duke Energy requests that EPA correct this error and ensure that IPM models these 5 units as natural gas-fired units. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.10]
IPM Has Inappropriately Fuel Switched Duke Energy Units to a Lower Sulfur Bituminous Coal [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.11]
The ParsedFile TR_SB_Limited Trading_2014 that is part of the NODA shows that IPM has switched Duke Energy's Wabash River (ORISPL 1010) units 2, 3, 4, and 5 to about a 0.7 lb/mmBtu SO2 bituminous coal. However, EPA has not provided any additional detail about the quality and nature of this proposed fuel, including full proximate and/or ultimate analysis or the modeled source region. The constituents of coal can vary dramatically, even within the same seam and general sulfur grade. It is difficult for Duke Energy to assess the potential impact of this fuel on the units without knowing this additional detail. This would include ash content and moisture content, as well as fuel combustion characteristics such as grindability, slagging and fouling indices, and volatility. Knowing these details is critical to making an assessment of whether the unit can manage this fuel. Wabash River Units 2, 3, 4, and 5 have ball mills, which are especially susceptible to changes in coal properties. Higher ash, higher moisture, and/or lower grindability characteristics, which are typical in some combination for most lower sulfur coals (whether bituminous or subbituminous), can result in mill skidding and reduced mill fineness. This usually results in increased boiler slagging and fouling; pluggage; higher NOx and CO emissions; lower unit efficiency; higher opacity; and therefore reduced unit availability and capacity. It can also result in mill explosions, which are a significant safety hazard, and require expensive fire protection and suppression system upgrades (again, even for bituminous coals); and in conjunction with ash resistivity impacts, reductions in precipitator performance requiring precipitator conditioning systems and/or expensive precipitator upgrades or replacements, as the precipitators on these specific units are very small (only 130 SCA, with rigid discharge electrodes and 11 inch plate spacing), and were originally designed for 6 to 7 lb/mmBtu SO2 fuels. These units have not been able to burn coals with less than 2.8 lb/mmBtu SO2 without suffering constant opacity exceedances. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.11-12]
Further, IPM has specified the same coal grade for Wabash River Unit 6 (approximately 0.7 lb/mmBtu SO2). The current Wabash River unit 6 precipitator is an Environmental Elements design and was installed in 1993. It has a Specific Collection Area (SCA) of 281 and was designed to burn medium sulfur coal (2.5  -  3.5 lb/mmBtu SO2). It consists of two (2) casings arranged in a parallel configuration. Each precipitator casing has four (4) fields with fifty foot (50') tall collecting plates, and eight (8) chambers with one hundred fifty eight (158) gas passages spaced at sixteen inches (16"). The precipitator is powered by eight (8) 70kV, 750 mA, and eight (8) 70kV, 1000mA transformer-rectifier (T/R) sets. The precipitator is a rigid discharge electrode (RDE) design and treats 1,310,398 ACFM of flue gas at 291F. Design gas velocity is 4.31 feet per second. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.12-13]
This unit typically burns a 1.67 lb/mmBtu SO2 or higher coal on a daily basis with an average opacity of 10% or less. In the past a lower sulfur coal (1.2 lb/mmBtu SO2 range) was tried and the unit began to experience high opacity (20% - 30%). An even lower sulfur coal (0.8 lb/mmBtu SO2) was tried with no success. The unit experienced constant emissions excursions. In order to burn a 0.7 lb/mmBtu SO2 low sulfur coal, Wabash River Unit 6 would need to install a SO3 flue gas conditioning system. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.13]
Due to the limited information provided, and the limited time allotted for comments, Duke Energy cannot reasonably research, engineer, and develop a capital cost estimate for this grouping of projects that would be instructive for EPA to consider in its economic assessment. Duke Energy can therefore only recommend, due to the configuration of these specific units and the recognized impact that coals of this general characteristic can have, that these units are not capable of burning the fuel selected by IPM (or equivalently, that given the proper time for project development, cost estimation, and assessment of the impacts on unit availability and capacity, that this option has a high likelihood of exceeding the $2000/ton cost breakpoint for SO2). [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.13]
Duke Energy requests that EPA model no less than a 1.67 lb/mmBtu SO2 bituminous coal for Wabash River Units 2 through 6. Coal of this general sulfur grade represent a vastly larger market share than the ~0.7 lb/mmBtu SO2 coal, offer wider variability in constituents and combustion characteristics (thereby making finding a suitable fuel more likely), and may even represent a mix of higher and lower sulfur fuels again optimizing sourcing options. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.13-14]
In addition, Wabash River Station has a common coal handling system for all of the units that would require a capital investment to separate the system to allow Unit 6 to manage a vastly different fuel from Units 2 through 5 which would likely cost significantly more than $2000 per ton. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.14]
Lastly, the ability to specify a suitable fuel with a sulfur content in the 0.7 lb/mmBtu SO2 range in the market that has the requisite composition and characteristics to minimize the operational problems on these units may significantly limit the volume of fuel available, thereby resulting in higher coal costs than what IPM may be modeling (and thus affecting the economic assessment of this fuel choice relative to the $2000/ton cost breakpoint for SO2). Otherwise, a considerable capital investment would be required, including investments in the precipitators and mills, again affecting the economic assessment of this option. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.14]
Recommended Updates to NOx Emission Rates in NEEDS v4.10 Data Base. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.14]
EPA Should Apply an Annual and Ozone Season Floor NOx Emission Rate of 0.06 lb/mmBtu to both New and Existing SCRs. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.14]
The NOx emission rates in the NEEDS v 4.10 data base indicate that EPA has made downward adjustments to reported NOx emission rates for units with an existing SCR that are unwarranted, unreasonable, and inaccurately described in the Proposed Transport Rule State Budgets TSD. The State Budgets TSD indicates that "NOx controls were assumed not to control beyond a floor of 0.06 lb/mmBtu." The way EPA has applied this rate to units with existing SCRs, however, the 0.06 lb/mmBtu rate would be more accurately described as a ceiling rather than a floor because of the downward adjustments EPA has made to NOx emission rates. If a unit had reported historical data that supported a NOx emission rate EPA's application of a 0.06 lb/mmBtu NOx emission rate without regard for the actual capability of existing SCRs to achieve that emissions rate resulted in EPA overestimating the amount of NOx emissions reduction available at $500/ton. The consequence is to make the lower than 0.06 lb/mmBtu, EPA used that lower emission rate. Yet if a unit had reported historical data that demonstrated a NOx emission rate higher than 0.06 lb/mmBtu, EPA -- apparently arbitrarily -- made a downward adjustment of that rate to 0.06 lb/mmBtu. Such downward adjustments are unfair and unwarranted. Incentives exist in most cases to emit at the lowest reasonably achievable NOx emission rate whenever the SCR is in operation, and if a given unit reports NOx emissions at rates above 0.06 lbs/mmBtu, it is because that unit cannot physically and consistently operate at a lower rate. At a minimum, an across-the-board downward adjustment to 0.06 lb/mmBtu, without consideration of case-by-case factors, cannot be justified. Just because EPA thinks a unit should be able to emit at a 0.06 lb/mmBtu rate doesn't mean that it can actually achieve that rate. Under EPA's proposed approach, where an existing unit cannot in fact meet the 0.06 lb/mmBtu rate, that unit may well be forced to upgrade its pollution control device. Such an option was not anticipated in the Proposed Transport Rule and the cost associated with such an option does not appear to have been accounted for in the Proposed Transport Rule analysis. Certainly the $/ton removal cost for upgrades required to allow a unit to perform consistently at a 0.06 lb/mmBtu emission rate will exceed EPA's $500/ton cost breakpoint for NOx controls, and also could not be completed between the time EPA finalizes the Proposed Transport Rule and January 1, 2012. EPA should therefore use the 0.06 lb/mmBtu rate as a floor rate for units with either a new or existing SCR. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.14-15]
EPA's application of a 0.06 lb/mmBtu NOx emission rate without regard for the actual capability of existing SCRs to achieve that emissions rate resulted in EPA overestimating the amount of NOx emissions reduction available at $500/ton. The consequence is to make the annual and ozone season state budgets much more constraining than they should be based on actual SCR capabilities. Take for example a unit that is currently operating at an ozone season emission rate of 0.10 lb/mmBtu. When EPA models this unit's NOx emission rate at 0.06 or adjusts the unit's reported NOx emission rate to reflect a 0.06 lb/mmBtu emission rate for purposes of establishing a state's budget and allocating allowances, EPA has effectively reduced the emissions attributable to this unit by 40%. When this downward adjustment occurs at many units within a state and across the region, the result is a substantially reduced sector ozone season NOx cap beginning in 2012. [EPA-HQ-OAR-2009-0491-3752.1_NODA, pp.15-16]
EPA has stated correctly that additional controls cannot be brought on line by 2012 unless they are already under construction. So if EPA finalizes the Proposed Transport Rule with the unreasonable 2012 compliance timeframe that reflects a ceiling of 0.06 lb/mmBtu NOx emission rate for all units, and in 2012 when units for which EPA adjusted their NOx emission rates down to 0.06 lb/mmBtu are still operating at their reported 2009 emission rate because that's what the SCRs are capable of achieving, the potential for achieving the caps will be low. Add to this the fact that while EPA is proposing in the Proposed Transport Rule not to apply variability limits in 2012 and 2013 (a proposal which Duke Energy supports), the ability of the trading program under the Proposed Transport Rule to serve as a cost-effective and reliable compliance alternative is uncertain at best. What is certain is if state budgets are based on a ceiling NOx emission rate of 0.06 lb/mmBtu, allowance prices in 2012 will likely be very high, much higher than they would be if EPA applies the 0.06 lb/mmBtu emission rate as a floor instead of a ceiling and used a unit's actual reported emission rate when it is above 0.06 lb/mmBtu. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.16]
The $500/ton cost breakpoint EPA is using for NOx emissions is intended to ensure that all existing NOx controls are operated in 2012. This should mean that they operate at their current capability, not at some artificial level that EPA selects and that requires controls to be upgraded. As stated previously and reiterated here, the budgets that result from EPA modeling existing SCRs with a ceiling emission rate of 0.06 lb/mmBtu will certainly require emission reductions that cost more than $500/ton to achieve, and for which there is not enough time between when EPA plans to finalize the Proposed Transport Rule (mid-2011) and January 1, 2012 to implement. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.17]
In the NODA Federal Register notice (75 Fed. Reg. 53614) EPA indicates that it intends to update the NOx emission rates in the NEEDS v4.10 data base to 2009 data. When EPA does this, for units with an existing SCR where the SCR has operated all of 2009 to comply with the Clean Air Interstate Rule, consent decrees, state requirements, etc., Duke Energy recommends that EPA use two separate NOx emission rates, the ozone season rate and the non-ozone season rate, to describe a unit's annual NOx emissions. Further, each of these emission rates should be set at the greater of the 0.06 lb/mmBtu floor that Duke Energy recommends for units with an existing SCR, and a unit's actual 2009 ozone season and non-ozone season NOx emission rates. [EPA-HQ-OAR-2009-0491-3752.1_NODA, p.18]
Edison Electric Institute (EEI)
EPA has issued a related notice in the form of a Notice of Data Availability (NODA) on September 1, in which the Agency announced that it has placed a large amount of new information in the proposed Transport Rule docket, including an updated version of NEEDS (4.10), which provides unit-level characteristics of the electric generating units included in the IPM modeling; information on new IPM assumptions; and new IPM 4.10 base case and policy case modeling runs for the proposed Transport Rule. The notice indicates that the agency "proposes to use this version of the IPM model in the final Transport Rule, modified to address any comments that EPA receives as part of the transport rulemaking effort and other power sector analysis." EPA will accept comments until October 15 on both the specific data being placed in the docket as well as any potential impacts of that data on the proposed Transport Rule. EEI anticipates that it will submit comment in response to the NODA. [EPA-HQ-OAR-2009-0491-2697.1, pp. 10-11]
 EPA Must Allow for Adequate Time for Review of Data in the NODA and Its Effects on the Proposed Transport Rule   
As discussed in its comments on the Transport Rule, EEI is aware that inaccurate factual inputs existed in the original Integrated Planning Model (IPM); that EPA had made incorrect assumptions regarding individual electric generating units (EGUs), including in the NEEDS data base (e.g., incorrectly describing pollution control retrofits); and that IPM modeling run outputs in some cases are erroneous (e.g., incorrectly projecting the fuels to be used, retirements, etc.). EEI's October 1, 2010, Transport Rule comments provided several examples of errors our members had discovered, but no attempt was made by EEI to document every error our members had identified. [EPA-HQ-OAR-2009-0491-3716.1_NODA, p.2]
While EEI appreciates EPA's efforts to update IPM and specific EGU information in the NEEDS database to correct for those initial deficiencies, EEI is concerned that EPA issued the NODA midway through the comment period on the proposed Transport Rule, adding nearly 3,500 pages of new documentation to the docket while allowing only an additional 15 days past the original October 1, 2010, deadline for comments on the NODA. [EPA-HQ-OAR-2009-0491-3716.1_NODA, p.2]
As EEI discussed in its September 3, 2010, request for an extension of the proposed Transport Rule comment deadline, the potential impacts of the NODA data undergird the legal and technical basis for the proposed rule. The proposed Transport Rule is based on modeling of sulfur dioxide (SO2) and nitrogen oxides (NOx) emissions from the EGU sector and this modeling is necessary to respond to the D.C. Circuit Court decision regarding the Clean Air Interstate Rule. North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008). Therefore, since the potential impact of the new data runs and information EPA has placed into the docket clearly impact the legal and technical basis for the proposed rulemaking, EEI stated it believed that EPA's NODA statement either constituted, or should have constituted, an effective extension of the comment period date for the proposed Transport Rule to at least October 15, 2010. [EPA-HQ-OAR-2009-0491-3716.1_NODA, p.2]
Second, we observed that the public comment period must allow sufficient time for analysis and the development of comments on the Transport Rule, which includes a complex and lengthy preamble and proposed rule text. The NODA only added to the this underlying task and, since the NODA affects the modeling performed for the original proposal, the information EPA has placed into the docket is in fact inseparable from the proposal. EEI argued that this would justify, at minimum, extending the comment period until at least November 1, 2010, based on EPA's original timeframe of 60 days for submitting comments on the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3716.1_NODA, pp.2-3]
It is a near certainty that the new EGU information supplied by companies in their comments on the proposed Transport Rule, combined with changes to the NEEDS database and the IPM inputs identified in EPA's Transport Rule NODA, would affect, among other things, EPA's significant contribution analysis, the creation and evaluation of the cost curves, and the breakpoints selected based on the cost curves. It also is possible that the NODA, and comments received on the data contained in it, may result in changes in EPA's determinations of which states are regulated under the Transport Rule, the emission budgets to which those states will be subject, and unit-level allowance allocations supporting the final Transport Rule. [EPA-HQ-OAR-2009-0491-3716.1_NODA, p.3] 
The potential changes described above are significant. EPA did not provide a final set of information and assumptions on which the proposed Transport Rule was based at the time the proposal was issued. This error was compounded and further complicated by not providing an adequate amount of time for EEI member companies to complete an in-depth analysis of both the proposed Transport Rule and the impacts of changes caused by the NODA on individual company operations. The result of this series of errors is that EPA has disadvantaged companies. [EPA-HQ-OAR-2009-0491-3716.1_NODA, p.3]
Moreover, EEI member company comments in response to the proposed Transport Rule and the new data in the NODA likely will make it necessary for EPA to issue a Supplemental Notice of Proposed Rulemaking (SNPR) to allow owners of covered units to verify the data underlying emission allowance allocations in the final rule and provide any necessary comments to correct the data. This SNPR could occur while EPA is drafting other provisions of the final rule. [EPA-HQ-OAR-2009-0491-3716.1_NODA, p.3]
 Comments on Select IPM Inputs   
Through the NODA, EPA has made significant changes to some of the assumptions in IPM, resulting in new version 4.10. EEI appreciates EPA's efforts to update these assumptions and notes that many of the changes appear to be very responsive to past industry feedback. In this section we provide comment on several of the specific assumptions EPA has made in this update to IPM. [EPA-HQ-OAR-2009-0491-3716.1_NODA, p.4] 
As a preliminary matter we note that, on the issue of determining retrofit costs values, EPA has the difficult task of setting average national-level costs as input into IPM. Yet, as EPA and our members know, retrofit costs are very site specific and can vary widely based on unique site characteristics that are impossible to account for when attempting to set average national values. We expect that many of EEI's member companies will be providing input directly to EPA on these costs issues, which will help EPA arrive at better estimates of average values to use in national-level modeling.[EPA-HQ-OAR-2009-0491-3716.1_NODA, p.4]
 1. FGDs. EPA has significantly raised retrofit control costs in many categories in IPM, including those for wet and dry flue gas desulfurization (FGD) systems. We believe that EPA's new cost information is more reflective of the real-world experience of many of our companies, and the new retrofit costs for wet and dry FGD systems are generally supported by our members. [EPA-HQ-OAR-2009-0491-3716.1_NODA, p.4]
 2. SCRs. EPA has implemented modest increases to the cost of selective catalytic reduction (SCR) systems. Many companies believe that EPA's new costs in this category are still too low. They point out, for example, that the bulk of SCR installations that have already occurred were completed on the lowest cost, easiest to retrofit units. They believe that the units that remain to be retrofit represent the higher cost, more technically complex installations. As Sargent & Lundy (S&L) notes in the SCR Cost Development Methodology prepared for EPA and included in the docket, the "retrofit difficulties" expected at these sites "may result in capital cost increases of 30 to 50% over the base model." In-depth review of the S&L SCR cost information indicates that the costs may be low since they appear not to take into account factors  -  such as the need to modify the economizer outlet, precipitator inlet or air heater inlet  - which would increase the cost of SCR installations. There is also concern that the S&L costs do not reflect an SCR designed for operation over the full boiler output range. When SCRs are designed for operation over the full boiler range, modification of the economizer section of the boiler is also required, leading to higher capital costs than those shown by S&L. S&L also has based its allowance for funds used during construction (AFUDC) calculations on a two-year engineering and construction plan. Some companies believe a more realistic assumption for engineering and construction is 3 - 4 years, resulting in a higher AFUDC charge for SCR installations. [EPA-HQ-OAR-2009-0491-3716.1_NODA, pp.4-5]
 3. First Year In Service. EPA appears to be very aggressive in its updates to the first allowed in service year for several of the replacement generation sources. For example, as shown in the tables below, EPA has assumed that some technologies, such as a super-critical pulverized coal (SCPC) unit can be installed as early as 2013 under IPM 4.10, two years earlier than assumed under IPM 3.02. Given the operation of IPM, which assumes new generation comes online during the first day of a given year, that would mean that a new unit could be permitted, constructed and brought into operation within 26 months of the filing of these comments. It would not be possible to permit and construct a new facility in just over two years. EEI members have similar concerns with the shortened timeframes associated with other technologies as well. EEI also believes that EPA's aggressive estimates fail to take into consideration the significant litigation related delay that any type of new generation, even renewable technologies, faces in today's litigious climate.  [EPA-HQ-OAR-2009-0491-3716.1_NODA, p.5]
 While our members will have differing experiences with actual construction and permitting times based on specific site conditions; state air, water and solid waste permitting authorities; and the need to receive other regulatory approvals (such as a certificate of public convenience and need from a public service commission), there is broad agreement that the timelines EPA has adopted are unrealistically short. In general, EEI members would prefer EPA to consider adjusting its first year allowed assumptions to reflect those proposed by EEI as shown in the last column of Table 1 below. While these values represent general agreement among EEI members for first year allowed, some EEI members believe that it is possible under some circumstances to build some types of units (e.g., combustion turbines) one year in advance of the EEI dates. [EPA-HQ-OAR-2009-0491-3716.1_NODA, pp.5-6] [[See Docket Number EPA-HQ-OAR-2009-0491-3716.1_NODA, p.6 for Table 1.]]
 4. Mercury Control for Lignite. While EPA has provided updated control costs for bituminous coals in IPM 4.10, EEI notes that IPM 4.10 has not been updated to include new capital costs, fixed and variable O&M values, or percentage removal requirements for lignite fuels. We request that EPA update these values in a timely manner to allow for the most accurate modeling of lignite-fueled units within IPM.  [EPA-HQ-OAR-2009-0491-3716.1_NODA, p.6]
 Comments on Carbon Capture and Sequestration  
To the extent that the IPM Model also may serve as the basis for EPA's analysis of future legislative proposals, or expected regulation of carbon dioxide (CO2) emissions from power plants, EEI provides these comments on EPA's assumptions related to carbon capture and sequestration (CCS).  [EPA-HQ-OAR-2009-0491-3716.1_NODA, p.7]
1. The Transport Rule does not limit CO2 emissions, so the direct relevance of CO2 capture technology information to the Transport Rule would depend on the degree to which EPA's modeling incorporated state climate regulations. An initial review of the IPM documentation suggests that EPA did not include such State climate regulations in its analysis. It does appear that EPA "hardwires" into their base case analyses an assumption that 2 GW of coal-based generation will be equipped with CCS technology between 2012 and 2015, but this small amount of carbon capture would not materially impact regional or national model results. The basis for this assumption may be assumptions used by the Energy Information Administration (EIA)for its Annual Energy Outlook 2010, but this is not clear. Moreover, it is unrealistic as there are less than 20 MW of coal-based generation equipped with CCS at the end of 2010. [EPA-HQ-OAR-2009-0491-3716.1_NODA, p.7]  
2. There is no IPM documentation for CCS cost and performance data related to CCS systems for power plants fueled by natural gas. Presumably the model does not offer a CCS option for natural gas combined cycle (NGCC) plants. This omission cannot be due to the lack of availability of such information, or due to a lack of economic competitiveness for the natural gas option. The National Energy Technology Laboratory (NETL) report used by EPA as a primary reference for coal-based CCS costs also included cost and performance data for NGCC units equipped with CCS (NGCC/CCS). [EPA-HQ-OAR-2009-0491-3716.1_NODA, p.7]
 Additionally, the Annual Energy Outlook (AEO) 2010 Assumptions, also a primary technology cost and performance reference cited in the IPM documentation, provides estimates for the cost and performance of NGCC/CCS systems. The IPM documentation provided no explanation for why EPA excluded this technology alternative from its modeling effort. Given that NGCC systems (without CCS) provided approximately 80 percent of new capacity additions between 2000 and 2009, excluding combustion turbines (peakers); that the IPM base case projections for the Transport Rule include very little new coal capacity being introduced within the modeling forecast horizon (through 2030); and that NGCC capacity increases by 23 percent under EPA's preferred natural gas price assumptions, EPA should include NGCC/CCS cost and performance data in IPM 4.10.   [EPA-HQ-OAR-2009-0491-3716.1_NODA, p.8]
3. The cost and performance characteristics of CCS systems retrofit to existing PC power plants are presented in Chapter 6 of the IPM documentation. The capital costs are reportedly based on a 2006/2007 NETL assessment of hypothetical retrofits to American Electric Power Company's Conesville Unit #5 (Conesville Report). However, the O&M costs are based primarily on Baseline Bituminous Report. As with greenfield units, there is no documentation for retrofitting an existing NGCC power plant. CO2 storage costs are based on an EPA spreadsheet identified as "GeoCAT." IPM's CO2 storage costs cannot be effectively evaluated in the absence of much more information on the spreadsheet model. It appears that EPA has not made the GeoCAT model available for review.   [EPA-HQ-OAR-2009-0491-3716.1_NODA, p.8]
 4. With respect to capital costs for retrofit CCS systems, the incremental capital cost identified in the Conesville Report was $1,319/kW, somewhat less than the value in the IPM documentation ($1,972/kW for a comparably sized unit). Although the IPM value seems more realistic than the somewhat dated Conesville Report, the documentation does not explain what specific cost adjustments were made. In addition, a substantial economy of scale is used within IPM. For example, a 750 MW CCS retrofit is about 20 percent cheaper per kW than a 500 MW retrofit. Since the capture and compression systems are likely to be relatively modular, the basis for this degree of economy of scale should be more clearly explained. For comparison, IPM estimates that FGD systems and SCR systems have approximately 10 percent and 5 percent capital cost savings ($/kW), respectively, for comparable size increases. The IPM documentation states that Baseline Bituminous Report is the basis for incremental O&M costs for retrofit CCS systems in the IPM. IPM assumes incremental variable O&M (VO&M) to be $2.35/MWh, and incremental fixed O&M (FO&M) to be $3/kW-y ($2/kW-y for units over 750 MW). Table 2 (below) presents data from the Baseline Bituminous Report, as well as data on subbituminous coal CCS systems from a more recent DOE/NETL report. In general, these reports found that incremental FO&M would be about 4.5 times as large as the value in IPM's documentation, and VO&M would be about 75 percent larger. As with capital costs, IPM indicates that a scaling factor was used for FO&M. The difference between a 500 MW unit and a 750 MW unit was a 33 percent reduction in FO&M (in $/kW-y). This seems to a very large reduction, and no explanation is offered in support of the figure. [EPA-HQ-OAR-2009-0491-3716.1_NODA, pp.8-9]
 5. The capacity penalty and the heat rate penalties in the Conesville Report were 30 percent and 43 percent, respectively. The Baseline Bituminous Report and the Emissions Performance Standards Assessment estimated that SCPC units increased heat rates by 44 percent when adding CCS, and subcritical PC units (the designs addressed by the IPM retrofit analysis) to increase by 48 percent. See Table 2. However, IPM uses values of 25 percent (capacity penalty) and 33 percent (heat rate penalty) "based on reported research and field experience as of the summer of 2010." NODA at 6-2. The specific research and experience are not identified. Additionally, readers should note that EPA handles the power loss resulting from retrofit CCS projects within the general "supply" requirements of IPM, and makes no effort to establish costs for the CCS project associated with the cost of (new) replacement power. This is appropriate for analysis within the IPM framework, but analysts should use care not to apply this data in an alternative framework, such as a spreadsheet which does not account for replacement of the power used by the CCS system. [EPA-HQ-OAR-2009-0491-3716.1_NODA, pp.10-11] [[See Docket Number EPA-HQ-OAR-2009-0491-3716.1_NODA, p.10 for Table 2.]]
 6. The CO2 transport analysis suggests that EPA is anticipating challenges that high quality CO2 storage sites are not available in all regions of the United States. See NODA at 6.5. The documentation includes an example of CO2 transport of roughly 1,000 miles (at a cost of about $20/tonne CO2). To achieve this relatively low cost, IPM assumes that eight power plants would collaborate to share a large diameter pipeline with economies of scale. This is an ambitious assumption for units owned by different companies using an emerging technology and required to undergo public utility commission review while seeking to permit and construct a multi-state pipeline and a distant storage facility (which presumably would have shared liability obligations). This shared approach seems particularly unsuited to greenfield applications of CCS, given the relatively small number of new coal units likely in the foreseeable future (as noted, IPM predicts 2 GW of new coal units between 2012 and 2030 in its assessment of the Transport Rule). Additionally, the model assumes that the transport system could obtain needed power for 7 cents per kWh. This assumption merits further support given that the average retail price of electricity in the United States is currently 9.7 cents/kWh, and IPM's projected increase in wholesale electricity prices under the Transport Rule is 73 percent between 2012 and 2030. A Transportation Matrix (costs for moving CO2 from sources to storage areas) is provided in Appendix 6-2. Some of the entries are unrealistic, such as transporting California CO2 to New York, Florida, or the Atlantic for roughly $41-46 per tonne. [EPA-HQ-OAR-2009-0491-3716.1_NODA, p.11]
Electric Energy, Inc. 
III. The IPM V 4.10 Data for Joppa is not realistic.
The IPM run data provided in the September 1, 2010 Notice of Data Availability has projections that are not reasonable. Following are comments on the two files that project the emissions for 2014. [EPA-HQ-OAR-2009-0491-2628.1, p.2]
ParsedFile_TR SB Limited Trading_2014.xls
This file lists the Joppa units as 'Coal Early Retirement' with a very small amount of bituminous coal used. There are no plans to retire the Joppa Steam units in 2014. The Joppa units are a low cost provider of electricity and we expect to be cost competitive even after installation of additional pollution controls. [EPA-HQ-OAR-2009-0491-2628.1, pp.2-3]
ParsedFile_TR SB Limited Trading AEO gas_2014.xls
This file lists the Joppa Units as burning a blend of sub bituminous and bituminous coals. S02 emissions are 69% less than the base case but no scrubber is indicated in the Post Combustion Control or Dispatchable FGD Control columns. There are no plans to burn a blend of subbituminous and bituminous coals at Joppa. Also as noted above, there is insufficient time from the time this transport rule is finalized to engineer, procure, construct, and start up a scrubber on the Joppa units prior to 11/1/2014. [EPA-HQ-OAR-2009-0491-2628.1, p.3]
Exeter Energy Limited Partnership
Exeter Energy has reviewed the updated unit level input data (the National Electric Energy Data System (NEEDS v4.10)) referenced in the NODA and is commenting on the following aspects of such data with respect to Exeter Energy's units B1 and B2:  
1.The uncontrolled and controlled NOX base rates and uncontrolled and controlled NOX policy rates for each unit appear to be reasonably consistent with estimates based on actual 2009 monitored data from the facility for each unit. The SO2 permit rate is consistent with each unit's permit limit.  Therefore, Exeter Energy agrees with the SO2 and NOX unit level input data for units B1 and B2 included in the NEEDS. 
2.Exeter Energy questions why Mercury Emission Modification Factor (Hg EMF) inputs have been assigned to its units, which appear to apply only to coal-fired units.  Exeter Energy consists of two (2) tire-fired units.  No coal is combusted at the facility. [EPA-HQ-OAR-2009-0491-3722.1_NODA, p.2]
Exxon Mobil Corporation
2. EPA's projection of reasonable interference was based on the IPM v. 3.02 Base Case modeling for 2012. On September 1,2010, EPA published a Notice of Data Availability for the IPM v. 4.10 modeling, including a revised TR Base Case 2012 scenario. Under the revised modeling, projected emissions of SO2 are more than 20,000 tpy less than projected under the IPM v. 3.02 version. Based on this factor alone, it is believed that any revised air quality analysis based on the IPM v. 4.10 modeling will demonstrate no impact whatsoever on Harris Co. PM2.5 levels that could conceivably interfere with maintenance of attainment of the annual PM2.5 NAAQS. While EM has reservations about some of the other inputs to the IPM model, as discussed herein, EM believes that the v. 4.10 estimates rely upon a slightly more accurate forecasting of natural gas prices. For that reason, the v. 4.10 should be used to determine, at least as a screening mechanism, the potential for significant contribution or interference with maintenance of a NAAQS. [EPA-HQ-OAR-2009-0491-2841.1, p.3]
3. EPA's own modeling shows that the reductions in estimated Louisiana emissions from the Transport Rule Base Case v. 3.02 to the Base Case v. 4.10 are greater than what EPA stated was needed to remove 'interference with maintenance' in Harris County, Texas. EPA indicated that the difference between the TR Base Case 2012 v. 3.02 and TR Limited Trading Option case represents the amount necessary for a state to reduce emissions in order to remove significant interference and/or interference with maintenance. [EPA-HQ-OAR-2009-0491-2841.1,pp.3-4]
On September 1, 2010, EPA published the NODA indicating that EPA intends to use the IPM version 4.10 modeling, including a revised TR Base Case 2012 scenario, for revising the determinations of significant impact and interference with maintenance. Under the revised IPM TR v. 4.10 Base Case, projected emissions of SO2 from Louisiana EGUs are more than 20,000 tpy less than was projected under the IPM v. 3.02 version. (See Table below.) Based on this factor alone, because EPA's own data showed sulfate to be the culprit, it is believed that any revised air quality analysis based on the IPM v. 4.10 will demonstrate no impact whatsoever on Harris Co. PM2.5 levels. The same is true with respect to reductions of annual and ozone season NOx, EPA's revised IPM v. 4.10 Base Case 2012 model results show significant reductions in projected SO2 and NOx emissions that will occur even without implementation of the CATR/FIP (or CAIR). If these values are used in revised air quality modeling, it is virtually certain that the conclusion will be that Louisiana emissions do not impact the annual PM2.5 or 1997 8-hour ozone standards in Texas.9  [EPA-HQ-OAR-2009-0491-3736.1_NODA, p.3]
Even without a revised air quality analysis, however, EM believes that use of the TR Base Case v. 4.10 data supports the conclusion that Louisiana should not be included in the CATR/FIP. The original CATR/FIP determined that a certain level of emission reductions from EGUs would remove 'significant contribution' and 'interference with maintenance' The revised IPM v. 4.10 Base Case shows that emission reductions greater than that level will occur by 2012, even without CATR. The following table demonstrates this conclusion: [EPA-HQ-OAR-2009-0491-3736.1_NODA, p.3]
Even without air quality modeling, these results demonstrate on their face that because the quantity of SO2 and NOx: emissions that were required to be removed to prevent 'significant contribution' and 'interference with maintenance' are now projected to be removed by 2012 through factors other than the CATR/FIP, there is no legal basis for a CATR/FIP for annual SO2 or annual or ozone season NOx control for Louisiana EGUs. [EPA-HQ-OAR-2009-0491-3736.1_NODA, p.4]
If Louisiana is still included under the CATR/FIP after revised modeling and air quality analysis, EM requests that EPA not use the IPM v. 4.10 (or any other version of the IPM) to make unit level allocations under the CATR/FIP. EPA should make SO2 and NOx allocations proportionate to the ratio of each unit's existing SO2 and NOx allocations to the state CAIR budgets already approved by both EPA and LDEQ. Although the court in North Carolina v. EPA struck down CAIR and required a revised look at the actual state budget needed to eliminate significant contribution or interference with maintenance, the court did not find any problem with the Louisiana (or other state's) unit level allocations. Louisiana DEQ, together with the Louisiana Public Service Commission, worked very hard on a fair allocation scheme for NOx allowances. This scheme was enacted into rule by the State after public notice and Comment and was approved by EPA. [EPA-HQ-OAR-2009-0491-3736.1_NODA, pp.4-5]
On September 27, 2006, the Louisiana Department of Environmental Quality (LDEQ) submitted a SIP revision to EPA adopting the CAIR SO2 Trading Program to address its 'good neighbor' obligations under CAA Section 110(a)(2)(D) with respect to the potential impact of Louisiana emissions on downwind PM. 2.5 receptors in the State of Alabama. EPA approved this SIP revision on July 20, 2007 at 72 Fed. Reg. 39741. 12 On July 12, 2007, LDEQ submitted a SIP revision to EPA adopting a SIP for a CAIR NOx Trading Program to address both the 1997 8-hour ozone standard and the 1997 annual PM2.5 standard. EPA approved this SIP revision on September 28, 2007 at 72 Fed. Reg. 55064. LDEQ submitted amendments to its NOx CAIR SIP on July 1, 2009, which are pending before EPA for decision. EPA should base its allocation system as closely on these prior approved Louisiana CAIR provisions as is possible. [EPA-HQ-OAR-2009-0491-3736.1_NODA, p.5]
EPA lacks a credible rationale for premising its NOx and SO2 allocations on the IPM v. 4.10. Although the allocations are slightly more generous than were the allocations under version 3.02, they are woefully inadequate to allow the Louisiana 1 station to normally operate the Cogen units without incurring enormous costs. EM incorporates by reference its comments on the improper use of the IPM model for NOx allocations made in EM's original comments. [EPA-HQ-OAR-2009-0491-3736.1_NODA, p.5]
The IPM is an economic model that fails to account for realistic operations at many Louisiana facilities, in particular, cogeneration units serving industrial sources. The unit level allocation scheme based on the IPM (as distinguished from the. state budget) has nothing to do with preventing significant contribution or interference with maintenance. In fact, huge economic inequities are being created with no underlying environmental reason. The following table shows a comparison of the allocations that EM would receive under IPM v. 4.10 version as well as actual reported emissions to CAMD for 2005-2010. [EPA-HQ-OAR-2009-0491-3736.1_NODA, p.5]
As indicated in its original comments, the Louisiana 1 Cogen units are must run units for the Louisiana 1 station. The assumptions made in the IPM are obviously grossly in error with respect to the utilization of these units. It would be arbitrary and capricious for EPA to base its allocations on the IPM- either v. 3.02 or v. 4.10 given these facts. [EPA-HQ-OAR-2009-0491-3736.1_NODA, p.6]
EPA's approach for projected emissions inventories, as well as considerations of control technology under the IPM v. 4.10, eliminated the consideration of any reductions required by CAIR, due to the fact that the CAIR rule was overturned in North Carolina v. EPA, 531 F.3d 896, 901 (D.C. Cir. 2008). However, this results in overly conservative projections. The CAIR rule was remanded, but not vacated. Many regulated public utilities already invested in capital projects for reduction that were approved by their regulatory bodies and/or ratepayers. In most cases, legal obstacles would prevent the undoing of these projects. In addition, each physical project undertaken for purposes of CAIR reductions was of necessity permitted under an enforceable Title V permit Those projects and permit limits cannot be relaxed without the facilities triggering Prevention of Significant Deterioration (PSD) rules. Triggering PSD would involve imposition of Best Available Control Technology, which, in most cases, would mean that the facilities would have to keep the pollution control equipment they installed for CAIR, or would have to meet even more stringent requirements. EPA should have undertaken a much more rigorous analysis for projecting what steps EGUs would take-if CAIR were vacated completely, with no replacement EPA has tools to easily accomplish this, such as a Clean Air Act Section 114 request for information. In short, EPA overestimated Base Case emissions for both 2012 and 2014 by eliminating all CAIR control requirements. [EPA-HQ-OAR-2009-0491-3736.1_NODA, p.6]
The documentation for the IPM v. 4.10 does not clearly indicate whether EPA included only the grid-demand for electricity or also industrial facility demand. Section 3.2 of the Documentation for the EPA's IPM v. 4.10 Base Case tends to indicate that EPA considered only the grid-demand. This may have discounted the total electrical demand in Louisiana as many industries have cogeneration units. Some of these units provide power to the grid, as does EM. However, if EPA did not appropriately account for the fact that industries that partially self-generate need continuous and reliable electrical and steam output, then the IPM may make deficient economic choices in its selection of EOU behavior.  [EPA-HQ-OAR-2009-0491-3736.1_NODA, p.6]
The Documentation for the IPM v. 4.10 Base Case, Chapter 3.5.1 indicates that EPA made certain assumptions about EGU availability in its modeling. EPA stated 'Power plant availability is the percentage of time that a generating unit is available to produce electricity to the grid. Availability takes into account both scheduled maintenance and forced outages...' EPA indicated that Appendix 3-9 shows the availability assumptions for all EGUs in EPA Base Case 4.10. In Appendix 3.9, EPA indicated that the 'availability' for the RS Cogen traits was as follows: [EPA-HQ-OAR-2009-0491-3736.1_NODA, pp.6-7]
EM disputes these assumptions. The Louisiana 1 Cogen units must be operated year round to provide adequate electricity and steam to the Exxon Mobil manufacturing facility in Baton Rouge, Louisiana. Actual data submitted to EPA CAMD reflects Louisiana 1's actual utilization of these Cogen units. EM requests that EPA revise these values to show Availability of 96% for these units. [EPA-HQ-OAR-2009-0491-3736.1_NODA, p.7]
In Section 3.9.2 of the Documentation for the IPM v. 4.10 Base Case (pages 3-18 through 3-20), EPA indicates that it used four different NOx rates in NEEDS 4.10 'to allow all possible modeling scenarios involving NOx controls to be set up.' The 4 modes of operation were set forth in the NEEDs 4.10. EM believes that EPA erred in its assignment of NOx rates to the EM units under these 4 modes. EM requests that EPA use instead the actual data reported to the CAMD under the Acid Rain and CAIR programs for a more accurate depiction of its NOx emission rates. The rates used in NEEDS 4.10 are significantly less than have been achieved in actual practice by these mars. [EPA-HQ-OAR-2009-0491-3736.1_NODA, p.7]
The documentation for the IPM v. 4.10 indicates that EPA continued an error that was also made in the IPM v. 3.02 Base Case with respect to existing environmental regulations. In Section 3.9.4 of the Documentation of EPA's IPM v. 4.10 Base Case, EPA listed the state rules that it included in the model. As indicated in EM's original comments, EPA improperly considered the Louisiana NOx Reasonably Available Control Technology rule in LAC 33:III.Ch. 22 reductions of NOx in the modeling used to project future impact. In Appendix 3-2.2, EPA had the following entry for Louisiana: [EPA-HQ-OAR-2009-0491-3736.1_NODA, p.7]
The cited rule does apply to NOX, but the information in the 'Emission Specifications' column is totally erroneous. The NOx emission limits are much lower than this, but different limits apply to different types of units. Further there are different limits for different parishes. EM requests that EPA update the model by using the actual limits of the rule, as set. forth at LAC 33:III.Chapter 22, available at: http://www.deq.louisiana.gov/portal/tabid/96/Default.aspx [EPA-HQ-OAR-2009-0491-3736.1_NODA, p.7]

9 If EPA conducts revised air quality modeling, EM urges EPA to also make the revisions to the Louisiana emissions inventory discussed in EM's original comments.
12 Louisiana Department of Environmental Quality, Louisiana SIP Revisions, http://www.deq.louisiana.gov/portal/Default.aspx?tabid=2381.
First Energy
FE appreciates and supports the EPA's attempt to update the NEEDS database to correct for current economic conditions in the NEEDS v4.10 data, as presented September 1, 2010. [EPA-HQ-OAR-2009-0491-2657.1, p.4]
FE strongly suggests the EPA rerun all model data since the inputs to the model have changed between NEEDS v3.02 and NEEDS v4.10, to accurately reflect the current economic conditions and database updates and generate reliable and accurate model outputs. Not to do so would be internally inconsistent with EPA's admission that the original database was flawed enough to require correction with NEEDS v4.10, and would represent flawed regulatory development. Following remodeling and issuance of updated results, if would be appropriate to provide the public with an additional 60 days for the public to review and comment on the corrected IPM outputs. [EPA-HQ-OAR-2009-0491-2657.1.p.4] [[This comment can also be found in Section XVIII..C.1.]]
Turn Down Constraints
In NEEDS v4.10, the EPA applies turn down constraints for each unit provided by ICF International. It is not apparent that ICF addressed SCR operating restrictions in the assumed turndown constraint. SCR's must operate within a specific temperature window to maintain control efficiency; as boiler exhaust temperature drops with reduced load, the SCR must be taken out of service well above the boiler minimum load. Incorrectly modeling turn down would overstate the annual average control efficiency and NOx tons reduced. EPA should verify ICF used the correct turn down operating assumptions or the database must be corrected to correct the NOx removal performance assumptions. [EPA-HQ-OAR-2009-0491-2657.1,p.8; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.7 10/15/2010]
Bay Shore 4
The EPA NEEDS v3.02 & v4.10 assumes Bay Shore Unit 4 (BS4) will install a scrubber for the control case and allocation assumptions. This assumption is in error. FE has not installed a scrubber on BS4 and has no plans to do so. EPA may have assumed a scrubber installation following a preliminary announcement to install a Multi-pollutant control technology at Bay Shore. A subsequent announcement stated that the project would not go forward. [EPA-HQ-OAR-2009-0491-2657.1,p.9; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.9 10/15/2010]
RE Burger Plant (Boiler 7&8)
NEEDS v4.10 does not list a scrubber installation for Burger in 2010, but it assumes a NOx controlled rate of 0.1000 and an SO2 controlled rate of 0.1. The Consent Decree has a 30 day rolling average rate of either 0.1 or 0.15 SO2, and either 0.1or 0.20 NOx, not the fixed 0.1 SO2 and 0.1 NOx rates listed in the NEEDS controlled data. [EPA-HQ-OAR-2009-0491-2657.1, p.10]
Bruce Mansfield (BMP)
BMP 1-3 has an upgraded FGD efficiency of 95%. The Bruce Mansfield scrubbers were upgraded in 2006, 2007 & 2008, and any assumption that the scrubbers can be immediately tuned or improved further would be incorrect. [EPA-HQ-OAR-2009-0491-2657.1, p.10; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.9 10/15/2010]
The uncontrolled Mode 1 NOx rate for BMP is 30% lower than actual uncontrolled NOx rate. Current uncontrolled NOx rates run between 0.50 & 0.60 on all three units. The marginal cost per ton controlled would be in the hundreds of thousands of dollars if further upgrades were required. [EPA-HQ-OAR-2009-0491-2657.1, p.10; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.9 10/15/2010]
This adjustment is primarily due to the elevated boiler tube wastage when operating at the EPA's reported rate. NEEDS v4.10 applies a 0.06#/mmBtu NOx emission rate for the controlled scenario, consistent with the 90% NOx removal assumption for SCR's by the EPA. This does not reflect typical industry experience. The SCR's at BMP have not achieved this NOx rate since the original pristine condition performance test of the SCR before the SCR incurred ash fouling and activity degeneration typical of these installations. Its typical day to day emission rate is between 0.08 and 0.10#NOx/mmBtu, consistent with the typical performance of the rest of the industry as cited earlier. In order to improve the accuracy of the modeling runs, FE requests the EPA to correct the NEEDS database to reflect actual NOx control performance. [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.9]
NEEDS v4.10 incorrectly applies a 0.06#/mmBtu NOx emission rate for BMP 1-3 for the controlled scenario, consistent with the 90% NOx removal assumption for SCR's by the EPA. This does not reflect typical industry experience. The SCR's at BMP have not achieved this NOx rate since the original pristine condition performance test of the SCR before the SCR incurred ash fouling and catalyst degeneration typical of SCR installations. Its typical day-to-day emission rate is 0.08#NOx/mmBtu, consistent with the typical performance of the rest of the industry as cited earlier. In order to improve the accuracy of the modeling runs, FE requests that EPA correct the NEEDS database to reflect actual NOx control performance. [EPA-HQ-OAR-2009-0491-2657.1,p.10]
Eastlake Unit 5 (EL5)
The EL5 SNCR online year is incorrect in v3.02 & v4.10. The SNCR installation year should be 2007 not 2000. EL5 is required to operate and meet reduction targets per a Consent Decree. The SNCR driven NOx reductions reflected in the 2007-2009 emissions from EL5 represents the controlled NOx emission rate for NEEDS v4.10 reported as Mode 1, but this should be Mode 4 for a controlled rate. The NEEDS v3.02 EL5 Mode 1 rate is in line with typical uncontrolled NOx emissions from EL5. The EPA incorrectly assumes the EL5 uncontrolled NOx rate (Mode1) to be 0.29 in NEEDS v4.10. This is actually the controlled rate. EPA uses 0.29 as their uncontrolled Mode 1 then incorrectly applies a 35% SNCR NOx reduction to this controlled 0.29 rate. The application of the SNCR removal efficiency to the 0.29 SNCR controlled rate applies additional 35% removal efficiency on top of the actual removal efficiency from EL5's operating SNCR. This error not only double-counts the control efficiency, but also assumes the overstated rate of 35% reduction, as discussed earlier. This is clearly in error and must be corrected. [EPA-HQ-OAR-2009-0491-2657.1 ,p.11; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.10 10/15/2010] [[This comment is also in Section XVIII.C.1.]]
Eastlake 5 cannot and has never achieved a consistent 35% SNCR removal efficiency. FE expects the EPA to correct the assumptions for Eastlake 5. [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.10]
WH Sammis
Units 1-5 are listed as dry scrubbed, but a wet FGD was placed in service in 2010. The FGD for Sammis 6&7 was online in 2010, not 2011. [EPA-HQ-OAR-2009-0491-2657.1 ,p.11; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.10 10/15/2010] [[This comment is also in Section XVIII.C.1.]]
The reported NOx rates for Sammis Uncontrolled MODE 1 & 3 are representative of the typical controlled NOx rates. The Sammis SNCR's operate annually per the Consent Decree so the data used to project the uncontrolled rate is actually representative of the controlled rate. As in the case of Eastlake 5 above, the application of the SNCR removal efficiency to the SNCR controlled rate on the Sammis Units applies additional overstated 35% removal efficiency on top of the actual removal efficiency by all operating SNCR's. This is clearly in error and must be corrected. [EPA-HQ-OAR-2009-0491-2657.1 ,p.11; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.10 10/15/2010] [[This comment is also in Section XVIII.C.1.]]
NEEDS v3.02 is missing the Sammis 6&7 SCR installation in 2010. The SNCR installation dates for Sammis SNCR's should also be corrected. The correct dates are: SA1-2006, SA2-2000, SA3-2000 then upgraded in 2006: SA4-2006: SA5-2006: SA6- 2005: SA7-2003. The correction of installation dates for NEEDS v4.10 is the same as above except the SA6 SNCR installation date is missing for Sammis 6. [EPA-HQ-OAR-2009-0491-2657.1 ,p.11; these comments can also be found at EPA-HQ-OAR-2009-0491-3772.1_NODA, p.10 10/15/2010] [[This comment is also in Section XVIII.C.1.]]
Rulemaking Timing [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.2]
CATR is an extremely sophisticated rulemaking, over 250 pages in length, incorporating complex modeling and very detailed model inputs and technical support documents totaling several thousands of additional pages. The additional two weeks to review the NODA v4.10 data released by EPA on September 1, 2010 is appreciated, but insufficient. FirstEnergy proposes the EPA revise the 90 day comment window to begin on September 1, 2010. The revised due date for CATR and the NODA would be November 30, 2010. The revised comment period would allow the appropriate amount of time to evaluate the corrected assumptions used in the NODA data and the impact those assumptions have on the proposed CATR. An additional option that should be considered by the EPA is to allow a 60 day comment period after the EPA corrects all identified data errors and publishes the revised CATR rule based on the NODA and corrected assumptions used in the IPM model. [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.2]
EPA's own comments in the rulemaking at page 45227, Section E "Anticipated Rules Affecting the Power Sector," suggest that the Agency recognizes the need for this certainty and intends to coordinate the various rulemakings "with the goal of fostering investments in the most efficient and forward-looking expenditure of investor, shareholder and public funds...". It serves no one's interest to invest millions to comply with CATR and then strand that expenditure if the facility is retired due to the next EPA rulemaking. FE strongly suggests EPA follow through with coordination of the development and public comment and review of the NODA supporting the proposed CATR, CATR and EGU MACT, at a minimum. [EPA-HQ-OAR-2009-0491-3772.1_NODA, pp.2-3]
Air Quality Modeling Approach and Results [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.3]
FE appreciates the use of sound modeling principles, model construction, and pre and post processing, but strongly believes the EPA's use of a 2005 base year is entirely unrepresentative. Using 2005 as a Base Year indeed captures a 'Pre-CAIR' world, as EPA stated, but is not representative of recent emissions and meteorological conditions. FirstEnergy also appreciates the EPA's attempt to improve some model inputs based on information that is more representative of current unit operation and controls identified in the NODA. [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.3]
FE requests additional information regarding the 1% "Significant Contribution" designation for upwind states impacting ambient air monitoring sites as an acceptable method for assigning and controlling upwind impacts along with the modeled impacts of the NODA information from NEEDS v4.10. [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.3]
Needs Data Corrections [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.4]
FE supports the EPA's attempt to update the NEEDS database to correct for current economic conditions and facility control installations in the NEEDS v4.10 data, as presented September 1, 2010. [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.4]
In order to produce the most accurate model output possible, FE strongly suggests the EPA rerun all model data since the inputs to the model have changed between NEEDS v3.02 and NEEDS v4.10, to accurately reflect the current economic conditions and database updates and generate the best output possible. Not to do so would be internally inconsistent with EPA's admission that the original database was flawed enough to require correction with NEEDS v4.10, and would represent flawed and irresponsible regulatory development. Following remodeling and issuance of updated results, it would be appropriate to provide the public with an additional 60 days to review and comment on the corrected IPM outputs. [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.4]
COST ASSUMPTIONS [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.5]
Flue Gas Desulfurization (FGD) [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.5]
FE believes the EPA's capital cost assumptions ($/kW) for scrubber installations are more representative of recent installation costs. FE capital cost experience at WH Sammis for a 2005- 2010 Scrubber installation with a multi unit configuration (2-vessels, 840 GMW/vessel) was between $340 and $360/kW for Units 5, 6, &7. The remaining WH Sammis scrubber CAPEX for Sammis Units 1-4 (192 GMW each) was between $470 and $490/kW. Surprisingly, the original EPA data assumes a cost range of similar scrubber size in NEEDS v3.20 from $182 to $215/kW, which is grossly underestimated. This understated the capital cost by as much as 250%. The Chapter 5 the NODA v4.10 $/kW range was more in line with realistic cost estimates. The range for v4.10 was from $407 to $451. The EPA assumed O&M cost ($/kW) is approximately half of FE's actual O&M cost. Since the original model outputs are based on the incorrect EPA assumptions, FE recommends the EPA correct the IPM input data to reflect real world installation costs. The EPA should re-run the IPM model cost curves, re-determine each state's "Significant Contribution," revise state allocation totals for NOx and SO2, and correct the individual unit allowance database. Once these corrections are made, FirstEnergy recommends the EPA provide an additional 60 day comment window to review and comment on the corrected IPM data. [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.5]
Selective Catalytic Reduction (SCR) [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.6]
FE does not agree with EPA's capital cost assumptions ($/kW) for SCR installations. FE capital cost experience at WH Sammis for a 2005-2010 SCR installation for Units 6&7 was between $220 and $250/kW. The EPA data in Chapter 5 assumes a cost range on a similarly sized unit from $162/kW to $169/kW. FE recommends the EPA correct the cost assumptions to reflect a range of actual current SCR installation experience. [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.6]
CONTROL EQUIPMENT PERFORMANCE ASSUMPTIONS [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.6]
General NOx reduction assumptions relative to industry and FE units [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.6]
The 90% SCR NOx reduction applied to the NEEDS data by the EPA does not reflect typical industry experience. A 90% removal efficiency is exceedingly difficult and rare to achieve on a long term annual basis. Performance is primarily impacted by SCR fouling, catalyst deactivation and system reliability. Based on 2009 CAMD data from 224 units, SCR NOx removal efficiency for the industry averages just above 80%. Ironically, the respected work by Sargent and Lundy highlighted in Chapter 5 of the NODA data applies a 70% removal efficiency in their post combustion installation capital and O&M spreadsheets for SCRs. In order to consistently generate quality IPM model outputs, typical SCR NOx removal efficiencies should be used in IPM. [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.6]
Finally, Sargent and Lundy SNCR capital and O&M Cost Estimate spreadsheets for NEEDS v4.10 referenced a 25% NOx reduction for their cost model. The EPA uses an assumed 35% reduction in the utility NEEDS data which is not representative of real world performance over the boiler operating range. In order to improve the data accuracy, the SNCR removal efficiency assumptions should be corrected from 35% to 25%. [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.6]
Unit Availability Data [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.7]
The NEEDS database dramatically understates FE generating unit availability and should be corrected. (See Appendix D) [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.7; see p.27 of this comment summary for appendix D entitled, Comparison of FE NEEDS Availability Assumptions versus Actual: 2001 - 2005  and 2005-2009]
The average unit availability for the FE system in NEEDS for the period 2001-2005 is 72.5, versus the actual availability of 82% as reported to GADS (Referenced in the NODA Chapter 3). For the period 2005-2009, the average availability for the FE system rose to 84%. As FE understands the operation of the IPM model, this erroneous assumption on unit availability translates directly into an under-allocation of allowances to FE of at least 10%. This error must be corrected, and consistent with our earlier comments, we urge EPA to use the most recent, most accurate data available. Additionally, the assumed HI data in the NODA parsed file_TR SB Limited Trading_2014 was grossly under projected. The data in the parsed file is approximately 10% lower than 2006 & 2007 actual HI data for the entire FE fleet. More specifically, the Bruce Mansfield Plant HI data in the parsed file is between 10-20% below historical HI data. The EPA's assumption that specific generating units will operate significantly below historical operation is unacceptable to FE. The data does not appear to maximize generation from the units that have the lowest pollutant footprint per MW generated. FE recommends a logical approach for the EPA reevaluate the model outputs to maximize generation from units that already have optimal controls. [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.7]
Chapter 3 stated the use of NERC GADS data for unit availability. NERC GADS data is reported voluntarily and is not QA/QC'd, unlike the data reported into the Clean Air Market Division. [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.7]
The EPA further assumes any unit capable of burning a blend of PRB can burn 100% PRB without issue. This assumption is grossly inaccurate and is highlighted in the NODA parsed file_TR SB Limited Trading_2014. The EPA assumes Eastlake Unit 5 will convert to 100% Sub bituminous (PRB) yet does not apply a unit derate in the NEEDS v4.10 data. It is FE's experience that units switching to 100% PRB are invariably assigned a fuel derate. A unit may be able to blend PRB with bituminous fuel to achieve NDC, but each boiler would have a different blending and derate arrangement. Typically, the derate is related to the significant drop in Btu's in the PRB fuel vs. typical eastern fuel (approximately 30% less Btu's in PRB) and limitations with increasing the volume of fuel feed and air flow to make up for the lower heat content of the PRB substitute. FE recommends the EPA correct all generation IPM inputs where an assumed sub bituminous fuel blend will be applied for a specific unit. [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.8]
On the other hand, the IPM model should also account for improved NOx emissions on units switching to 100% PRB. Typical PRB fuel bound nitrogen is ~0.8% while bituminous fuel bound nitrogen is ~1.0 to 1.2%. IPM should also account for the improved NOx emissions when considering fuel switching as an option to control SO2 emissions. It is not apparent in the NODA NEEDS v4.10 that the NOx rates are impacted by combusting sub bituminous coal. [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.8]
The EPA's assumption that multiple units can switch to 100% PRB without significant capital cost at a facility does not account for the necessary, fuel transfer facilities, fire protection, dust suppression, mill adjustments and coal pile reconfiguration required to accommodate firing PRB fuel. Further, many plants do not have rail access to PRB delivery. Those facilities without good transportation access to PRB supplies will face additional delivery cost, which can make PRB an uneconomical option. For facilities assumed to convert to 100% PRB, FE recommends the EPA evaluate each facility's logistical issues and include the revised cost of capital to complete the fuel switch. [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.8]
In order to improve data accuracy, the data adjustments for the NEEDS model runs will have to be corrected to reflect actual emissions control installations. The EPA could verify control installations and their dates against the CAMD data since the CAMD data is populated with quality assured information. [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.9]
RE Burger Plant [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.9]
The RE Burger Plant (BU7&8) will convert to biomass by 12/31/20012 as an agreement in the Sammis Consent Decree. Per the Consent Decree, the boilers will be capable of burning up to 20% sub-bituminous coal with the biomass. NEEDS v4.10 it assumes a NOx controlled rate of 0.1000 and an SO2 controlled rate of 0.1. The Consent Decree has a 30 day rolling average rate of either 0.1 or 0.15 SO2, and either 0.1or 0.20 NOx, not the fixed 0.1 SO2 and 0.1 NOx rates listed in the NEEDS controlled data. It seems logical, that if the model inputs change, the IPM model runs should be re-run to reflect the new baseline model inputs. FE requests for the EPA to re-run all IPM scenarios based on the new v4.10 data and corrected model inputs. [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.9]
RE Burger Boiler 5&6 is targeted to have an "Early Coal Retirement." This assumption by the EPA is incorrect. The Burger Boiler 5&6 operated in 2010 and may be expected to operate in the future. The EPA's assumption that a unit that has operated in recent history will be retired by a utility is premature. [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.9]
In general, the EPA should correct all incorrect control equipment assumptions placed into the IPM model through the inaccurate NEEDS data. Correcting this information will improve the accuracy of the model outputs. [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.9]
FE recommends the EPA use the upgraded FGD removal efficiency of 95% for the IPM model assumptions. [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.9]
Additional NEEDS v4.10 Database Corrections [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.11]
The EPA appears to have distributed allowances to some facilities in the NEEDS v4.10 database that do not operate or have a binding commitment to retire a facility under a Consent Decree (CD). Specifically, Lake Road Unit 11 has not and does not appear to operate at all. The Lake Road facility has been allotted a significant amount of allowances based on the NEEDS v4.10 and is projected to operate based on the NODA parsed file_TR SB Limited Trading_2014. In order to distribute allowances to units that operate, specifically to units that operate with a reduced emissions footprint per Mw, FE recommends the EPA reallocate allowances from Units that are unlikely to operate in the future operating units in Ohio. Additionally, the Richard Gorsuch plant is subject to a CD with the EPA executed on May 18, 2010. The CD requires the Gorsuch Plant to retire on December 31, 2012. FE recommends the EPA correct the IPM model to reflect the CD settlements that were left out of the original CATR rulemaking and the subsequent NODA data. Correcting these specific IPM inputs will more accurately represent the model outputs the EPA uses to identify ambient air non-attainment. FE recommends the EPA correct additional assumptions based on New Unit installations where the projects have been cancelled. Specifically, Constellation Energy announced the cancellation of the Calvert Cliffs Nuclear plant project in Maryland. EPA should eliminate projected MW generation from the cancelled plants to correct the IPM model since the system load profile will change. [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.11]
Conclusion [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.11]
The NODA supporting the proposed Clean Air Transport Rule contains assumption errors, modeling and data inaccuracies that must be corrected and the associated modeling re-run to facilitate the development of sound public policy and be fair to all affected parties. Following corrections to the modeling assumptions, input data and re-modeling, if EPA still believes regulatory action is warranted, EPA must provide the regulated community with an additional 60 day period to digest and comment on the changes. The fact that the EPA provided limited technical support documents that should have accompanied the NODA information added additional confusion to the NODA. [EPA-HQ-OAR-2009-0491-3772.1_NODA, pp.11-12]
We note again that by simply recognizing the use of the most recent (2006-2009) monitoring data released by EPA, 80% of residual non-attainment areas identified by EPA in 2012 actually are already in attainment. [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.12]
Further, air quality modeling conducted by the Midwest Ozone Group which shows that - using a more representative base year and accounting for all existing enforceable federal, state, and local control - all Ozone monitors and all but two PM 2.5 monitors come into attainment by 2018 for the 1997 and 2006 standards respectively  -  without any additional controls. Because the Court did not assign a deadline for EPA to address a remedy to CAIR, and because revised standards for PM and Ozone are imminent (which will still bring the EPA-sought after health benefits referenced in CATR), the CATR rule is simply not needed at this time. [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.12]
Recognizing there is no deadline to address a CAIR remedy, FE strongly suggests EPA take time to consider the upcoming revisions of the Ozone and PM 2.5 NAAQS, and utilize more recent emissions data and power sector estimates to develop a revised rule. With this approach the stated health benefits are still achieved (through continued air quality improvements via established and revised standards) and a more cost effective and rational control strategy can be fashioned, in concert with other announced rulemaking including the EGU MACT Rule. [EPA-HQ-OAR-2009-0491-3772.1_NODA, p.12]
Florida Electric Power Coordinating Group, Inc. (FCG)
EPA Did Not Provide Sufficient Time to Develop Comments [EPA-HQ-OAR-2009-0491-3751.1_NODA, p.1]
On September 1, 2010, EPA published the NODA and placed new information relevant to EPA's proposed Transport Rule in the Transport Rule's docket. This new information modified assumptions integral to the proposed Transport Rule, yet EPA did not extend the already insufficient 60-day commenting period for the proposed rule; rather, EPA provided only an additional 14 days to review and comment on the extensive and complex, newly-provided information. EPA's new and modified information contains assumptions that result in significant changes in cost and generation from the proposed Transport Rule-assumptions and changes that must be analyzed by review of complex data files and spreadsheets. Initial reviews of this data have revealed that EPA has provided only a portion of the information needed to evaluate its implications. Accordingly, EPA has effectively precluded meaningful public involvement by providing insufficient time to review and develop meaningful comment on the proposed Transport Rule and NODA. [EPA-HQ-OAR-2009-0491-3751.1_NODA, pp.1-2]
EPA Must Publish another Proposed Rule [EPA-HQ-OAR-2009-0491-3751.1_NODA, p.2]
As explained in the FCG's comments on the proposed Transport Rule, EPA's proposal suffers from numerous errors in methodologies and numerous incorrect assumptions which impact every aspect of the proposed rule. In fact, the new information associated with the NODA revises assumptions underlying the rule's modeling platform, yet itself does not represent final refinement of EPA's assumptions. Specifically, EPA includes in the NODA a list of further planned revisions to modeling assumptions and inputs that it intends to undertake prior to final rulemaking. [EPA-HQ-OAR-2009-0491-3751.1_NODA, p.2]
EPA acknowledges that changes from using an updated model could impact the final rule in a number of ways, including, but not limited to (1) changing emission projections that were used to determine which downwind areas have air quality concerns absent rulemaking and to determine which states contribute to those problems, and (2) changing cost and emission projections used in the multi-factor test to determine the amount of emissions that represent significant contribution. 75 Fed. Reg. 53614. These changes affect the heart of the proposed rule; changes to the modeling platform will necessarily change the compliance obligations of every state, company and unit, and affected parties must be given an opportunity to review and comment as to whether EPA has corrected its mistakes, made new mistakes, and whether parties can meet their new compliance obligations. Further, EPA's NODA did not provide sufficient information to calculate the air quality impacts, state budgets, or unit allocations resulting from the NODA's revised information. Accordingly, EPA is obligated to publish a second proposal to provide the public an opportunity to review and comment on the accuracy and achievability of EPA's corrected approach before this rule is finalized. [EPA-HQ-OAR-2009-0491-3751.1_NODA, p.2]
EPA's Use of Its Integrated Planning Model is Fundamentally Flawed [EPA-HQ-OAR-2009-0491-3751.1_NODA, p.2]
EPA has made substantial changes between version 3.02 and version 4.10, yet its use is still fundamentally flawed because there are still material errors in the data and assumptions, and a predictive model is inappropriate and unnecessarily inaccurate for a two-year horizon. [EPA-HQ-OAR-2009-0491-3751.1_NODA, p.2]
The changes EPA made between versions 3.02 and 4.10 are substantial, and yield substantially different results. Some of the substantial changes for Florida are summarized in the tables below. [EPA-HQ-OAR-2009-0491-3751.1_NODA, p.2; see p.3 of this comment summary for the table displaying the change from v3.02 to v4.10, 2012 Base Case]
Accordingly, EPA must redo its air quality modeling to understand the air quality impact of the changes, as well as the different emission reductions that states must make to address interstate contributions, and ultimately, the different allocations for each specific electric generating unit. EPA's data still contains numerous material errors. For example, in Florida EPA's 2012 Base Case data indicates that Gulf Power's Crist Units 4, 5, 6, and 7, and Progress Energy's Crystal River Units 4 and 5, are unscrubbed. Yet, as explained in the FCG's comments on the proposed Transport Rule, all seven of these units have installed wet FGD systems and are required to operate them by permit. Further, EPA's 2014 Limited Trading data in version 3.02 indicate that Gulf Power's Crist Units 4 and 5 are unscrubbed, and version 4.10 indicate that Gulf Power's Crist Units 4, 5 and 7 are unscrubbed. EPA appears to have corrected the information regarding Crystal River Units 4 and 5 between versions 3.02 and 4.10, by reflecting the FGD systems, but the absence of the FGD systems for Crist Units 4, 5 and 7 is a material error. Correction of these material errors, which account for a substantial percentage of Florida's total SO2 emissions, in the Base Case and Limited Trading data could substantially change the obligations for Florida relating to its contribution to other states nonattainment and maintenance areas. [EPA-HQ-OAR-2009-0491-3751.1_NODA, pp.3-4]
Also, EPA's use of a complicated and flawed predictive model (i.e., IPM) for a projection only two years from the present, is inappropriate and unnecessarily inaccurate. Many sources recently installed controls in anticipation of CAIR, and have permits requiring their operation. And as EPA recognizes, the installation of additional controls before 2012 is not feasible. As such, states already know the level of expected (or at least allowable) 2012 emissions. EPA's use of a wildly complicated, and flawed, predictive model, therefore, is inappropriate and unnecessarily inaccurate. [EPA-HQ-OAR-2009-0491-3751.1_NODA, p.4]
[See p.5 of this comment summary for a table entitled, TRANSPORT RULE--COMMENTS TO BE MOVED]
Florida Municipal Power Agency (FMPA)
Sufficient Time has not been Provided to Develop Comments [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.2]
FMPA reiterates the argument asserted by others that sufficient time has not been provided to review and provide meaningful input on the Notice of Data Availability (NODA) for the Proposed Transport Rule.  The NODA was published in the Federal Register on September 1, 2010, and allows a 45 day comment period. In support of the NODA and the Proposed Transport Rule, EPA has provided a large amount of data and technical documents, upon which numerous assumptions have been made by EPA.  The NODA suggests broad changes to the modeling platform used by EPA to develop the Proposed Transport Rule, which will necessarily change the compliance obligations of every state, company and unit, and affected parties must be given an opportunity to review and comment as to whether EPA has corrected its mistakes, made new mistakes, and whether parties can meet their new compliance obligations.  Given the vast amount of data and technical documents, and the limited resources of public power entities such as FMPA, we believe that EPA's 45 day comment period is unreasonable and should be extended for an additional 60 days period, or, in the alternative, EPA should publish a second proposal to provide the public an opportunity to review and comment on the accuracy and achievability of EPA's corrected approach before this rule is finalized. [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.2]
The NEEDS Version 4.10 Database in the TSDs Contains Errors and Omissions [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.2]
FMPA has discovered errors and omissions with respect to certain FMPA generating units in the NEEDS Version 4.10 Database included in the Technical Support Documents for the NODA. [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.2]
FMPA understands that EPA has used the NEEDS Version 4.10 Database and IPM modeling to determine the impact of Florida's emissions on downwind states.  However, this cannot be done accurately if the inputs to the model are based on erroneous data.  The number of errors and omissions related to the FMPA units is a strong indication that the model inputs may also be inaccurate for other generating units as well.  If the inputs to the model are inaccurate, then it is not appropriate to use the model results to assess the impact of emissions on downwind states, nor to base the state emissions budgets and the compliance requirements for individual facilities on these results. [EPA-HQ-OAR-2009-0491-3745.1_NODA, pp.2-3]
FMPA agrees with the comments of others that, due to the importance of the decisions that will be made based on the IPM modeling results, EPA should either carefully review all assumptions, and correct all errors, or, alternatively, should utilize the states' knowledge of expected/allowed 2012 emissions instead of implementing the complicated and potentially flawed IPM modeling.  In either case, an additional comment period will be necessary for interested parties to independently assess the inputs, methodologies, and results. [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.3]
The following specific errors and omissions must be corrected prior to their incorporation into the modeling and the Final Rule: [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.3]
FMPA's Cane Island Unit 4 (ORIS Code 7238, Air Construction Permit No. PSD-FL-400) is improperly omitted from EPA's NEEDS Version 4.10 Database.  Construction of the unit is currently underway and the planned commercial operation date is in July 2011.  In the NEEDS Version 4.10 User Guide, EPA has indicated that units not currently operating, but firmly anticipated to be operational in the future should be included as "Committed" units.  Thus, Cane Island Unit 4 is a committed unit that should be included in the NEEDS Version 4.10 Database and accounted for as an existing unit in all aspects of the Proposed Transport Rule.  Cane Island Unit 4 is a 300 MW (nominal) combined cycle generating unit, located in Osceola County, Florida, which will fire Natural Gas exclusively.  NOx Combustion Control will be accomplished via Dry Low NOx Burners (DLNB).  NOx Post-Combustion Control will be accomplished via Selective Catalytic Reduction (SCR).  The pollution controls are required to operate in accordance with the Air Construction Permit for the facility. [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.3]
FMPA's Treasure Coast Energy Center Unit 1 (ORIS Code 56400) is improperly omitted from EPA's NEEDS Version 4.10 Database.  Treasure Coast Unit 1 should be included in the NEEDS Version 4.10 Database, with an On Line Year of 2008, and accounted for as an existing unit in all aspects of the Proposed Transport Rule.  Treasure Coast Unit 1 is a 365 MW combined cycle generating unit, located in St. Lucie County, Florida, which fires Natural Gas and Distillate Fuel Oil.  NOx Combustion Control is accomplished via Dry Low NOx Burners (DLNB) and Water Injection (H2O).  NOx Post-Combustion Control is accomplished via Selective Catalytic Reduction (SCR).  The pollution controls are required to operate in accordance with the conditions of the Title V Permit for the facility. [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.3]
FMPA's entire H.D. King (ORIS Code 658) facility was retired as of May 2008.  The NEEDS Version 4.10 Database should be updated to reflect a Retirement Year of 2008 for all units at this facility. [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.3]
The following FMPA units were improperly characterized in the NEEDS Version 4.10 Database: [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.4]
Cane Island (ORIS Code 7238)  -  Unit 1 [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.4]
Dry Low NOx Burners (DLNB) should be added to NOx Combustion Control Equipment [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.4]
Water Injection (H2O) should be added to NOx Combustion Control Equipment [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.4]
Cane Island (ORIS Code 7238)  -  Units 2 and 2A [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.4]
Dry Low NOx Burners (DLNB) should be added to NOx Combustion Control Equipment [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.4]
Water Injection (H2O) should be added to NOx Combustion Control Equipment [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.4]
Selective Catalytic Reduction (SCR) should be removed from NOx Post-Combustion Control Equipment [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.4]
Cane Island (ORIS Code 7238)  -  Units 3 and 3A [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.4]
Dry Low NOx Burners (DLNB) should be added to NOx Combustion Control Equipment [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.4]
Water Injection (H2O) should be added to NOx Combustion Control Equipment [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.4]
Hansel (ORIS Code 672)  -  Units 21, 22, and 23 [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.4]
Water Injection (H2O) should be added to NOx Combustion Control Equipment [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.4]
Distillate Fuel Oil should be removed from the Modeled Fuels.  Firing of distillate fuel oil at this facility was terminated as of March 2008, at which time there was no fuel oil remaining at the site.  The fuel oil tanks were subsequently removed and there will be no future fuel oil firing at the facility. [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.4]
Stock Island (ORIS Code 6584)  -  Unit IC1 [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.4]
The REtirement Year is 2010  [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.4]
Stock Island (ORIS Code 6584)  -  Unit IC3 [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.4]
The Retirement Year is 2010 [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.4]
Stock Island (ORIS Code 6584)  -  Unit GT1 [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.4]
Water Injection (H2O) should be added to NOx Combustion Control Equipment [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.4]
Stock Island (ORIS Code 6584)  -  Unit GT2 [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.4]
Water Injection (H2O) should be added to NOx Combustion Control Equipment [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.5]
Stock Island (ORIS Code 6584)  -  Unit GT3 [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.5]
Water Injection (H2O) should be added to NOx Combustion Control Equipment [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.5]
Stock Island (ORIS Code 6584)  -  Unit GT4 [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.5]
Dry Low NOx Burners (DLNB) should be added to NOx Combustion Control Equipment [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.5]
Water Injection (H2O) should be added to NOx Combustion Control Equipment [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.5]
The specific errors listed above very likely impact EPA's assumptions regarding heat rates and/or emissions rates for the FMPA generating units.  Due to time constraints, it was not possible for FMPA to determine precisely how EPA calculated these values, so we are also unable to determine what the errors are, if any, nor to suggest corrections, although in general we believe certain values do not appear to fall within the expected ranges for several of the FMPA units.  Therefore, FMPA believes that EPA must evaluate the impact of the above errors on the values of these parameters, correct the NEEDS Version 4.10 Database and IPM modeling accordingly, and provide an additional comment period after the corrections are published. [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.5]
For the reasons stated above, EPA should provide additional time for comment in this rulemaking, or, in the alternative, EPA should provide an additional comment period prior to adopting a Final Rule that takes account of FMPA's and others' comments. [EPA-HQ-OAR-2009-0491-3745.1_NODA, p.6]
Gulf Coast Lignite Coalition
EPA Should Issue a Supplemental Proposed Transport Rule with a New Regulatory Impact Analysis. [EPA-HQ-OAR-2009-0491-3744.1_NODA, p.1]
In the NODA, EPA stated that unlike the proposed Transport Rule, the final Transport Rule will rely on updated 2009 data (e.g., new units, control technology) and assumptions (e.g., planned retirements). The EPA also states that 'between [the publication of the NODA] and the time that EPA finalizes the Transport Rule, additional information used to support the final transport rulemaking may be placed in the docket.' It appears from this statement, that the EPA is opening the door to adding new information that will form the basis of the final Transport Rule, even well after the NODA comment deadline. [EPA-HQ-OAR-2009-0491-3744.1_NODA, pp.1-2]
The data assumptions EPA will be relying on to formulate the final Transport Rule will likely result in different emission budgets and allowance allocations compared to the proposed Transport Rule. It appears that the public is not given a meaningful opportunity to review, assess, and then comment on this updated information which could well be supplemented past any comment deadline. [EPA-HQ-OAR-2009-0491-3744.1_NODA, p.2]
Institute of Clean Air Companies (ICAC)
ICAC's overarching comment on this NODA is that the capital cost figures for emission control technologies and equipment that EPA proposes to use in the new IPM model (version 4.10) are exceedingly high, both in absolute terms and relative to the inputs used in past IPM modeling. ICAC understands EPA's effort to get true and accurate capital costs in the IPM model, especially with the increase in commodity prices. We also understand that the analysis performed by Sargent & Lundy in the documentation for IPM version 4.10 is a completely new exercise that is fundamentally different and bears no relationship to past IPM capital cost inputs. Herein lies our issue such that we do not believe that the timing is correct to use IPM version 4.10 for the final Transport Rule as version 3.02, with much lower capital costs, was used for the proposed Transport Rule, while version 4.10, with much higher capital costs, is proposed to be used for the final Transport Rule. This is the classic case of "comparing apples and oranges." [EPA-HQ-OAR-2009-0491-3791.1_NODA, pp.1-2]
We believe that the primary impact of using these exceedingly high capital cost inputs will result in the IPM model over-estimating retirements of coal-fired electricity generating units. We see this may be especially true for smaller units that could potentially remain viable due to a growing number of innovative emission control technologies. Utility decision makers need flexibility in planning their investment strategies in the next 5- year timeframe, and the final Transport Rule is one of many upcoming regulations that they have to consider. An IPM modeling run in support of a final Transport Rule that unrealistically predicts constraints in their choices sets up an unrealistic anticipation of a reality that does not serve the national interest of achieving a clean and reliable energy infrastructure. [EPA-HQ-OAR-2009-0491-3791.1_NODA, p.2]
A related comment is that the new IPM model version 4.10 does not have direct sorbent injection (DSI) or circulating dry scrubbing (CDS) as alternative control technology options. DSI or CDS are viable and often better technology choices for many smaller coal-fired boilers.1 This lack of DSI or CDS options in this version of IPM combined with our observation that capital cost figures are unrealistically high will cause IPM to propagate the unrealistic prediction of the retirement of too many coal-fired units. This, in turn, will affect the allocations in the final Transport Rule. ICAC believes it is in EPA's and the nation's best interests to increase the flexibility afforded to the utility sector to achieve the requirements of the final Transport Rule; a reality achieved when market forces seek low cost options. The proposed IPM modeling inputs do not promote that flexibility. Therefore, ICAC strongly recommends that EPA include DSI and CDS as options in IPM version 4.10. [EPA-HQ-OAR-2009-0491-3791.1_NODA, p.2]
ICAC notes that the cost assumptions resulting from "major update of emission control technology assumptions" in Chapter 5 of the EPA Base Case v.4.10 documentation entitled "Emission Control Technologies" are significantly higher than those used in past IPM versions. As an example, the wet FGD (LSFO) capital cost for a 500 MW unit with a 10,000 Btu/kWh heat rate in EPA Base Case 2006 v. 3.0 was $174/kW (2004$), and a similar unit in IPM v3.02 EISA Base Case had a capital cost of $263/kW (2006$). The capital cost in the NODA for EPA Base Case v. 4.10 for a similar unit is $517/kW (2007$). [EPA-HQ-OAR-2009-0491-3791.1_NODA, p.2]
We believe that the majority of the capital cost increase in EPA Base Case v. 4.10 is explained by the 30% increase in bare module costs "to account for additional engineering and construction fees." This 30% increase is comprised of three separate 10% add-ons: 1) Engineering and construction management costs, 2) Labor adjustment for 6 x 10 hour shift premium, per diem, etc., and 3) Contractor profit and fees. The resulting value is the capital, engineering, and construction cost (CECC) subtotal. This CECC subtotal is then increased by 5% to account for owner's home office costs, i.e., owner's engineering, management, and procurement costs. The resulting sum is then increased by another 10% for FGD to factor in an Allowance for Funds used During Construction (AFUDC) over the 3-year engineering and construction cycle assumed for FGD. The final value, expressed in $/kW, is the capital cost factor that is used in EPA Base Case v. 4.10. ICAC did not discover similar add-ons in the previous IPM versions 3.0 or 3.02. [EPA-HQ-OAR-2009-0491-3791.1_NODA, pp.2-3]
We note the following differences between the "Limited Trading" modeling results for the proposed Transport Rule using version 3.02, and the "Limited Trading" modeling results posted in the docket using version 4.10: [EPA-HQ-OAR-2009-0491-3791.1_NODA, p.3]
1) 3 GW of retired coal in 2015 in version 3.02 versus 8 GW in the 4.10 version, [EPA-HQ-OAR-2009-0491-3791.1_NODA, p.3]
2) 237 GW of cumulative FGD, including 80 GW of retrofits, in 2015 in version 3.02 versus 196 cumulative FGD, including 37 GW of dispatchable FGD retrofits and 12 GW of non-dispatchable FGD retrofits, in the 4.10 version, and [EPA-HQ-OAR-2009-0491-3791.1_NODA, p.3]
3) 185 GW of cumulative SCR, including 19 GW of retrofit SCR, in 2015 in version 3.02 versus 139 GW of cumulative SCR, including 2 GW of dispatchable SCR retrofits, and 15 GW of non-dispatchable SCR retrofits in the 4.10 version. [EPA-HQ-OAR-2009-0491-3791.1_NODA, p.3]
We also note the significant difference in the Henry Hub delivered price in 2015 of $6.12/MmBtu (2006$) in version 3.02 versus $5.02/MmBtu (2007$) in the 4.10 version. [EPA-HQ-OAR-2009-0491-3791.1_NODA, p.3]
ICAC understands that IPM is a dynamic and complex model, and we are not necessarily attributing all of these differences in modeled equipment installations to the significantly higher pollution control capital cost assumptions in version 4.10. It is likely that the 20% lower natural gas cost in version 4.10 could be a dominant factor in the lower levels of equipment installations in version 4.10. However, the significant discrepancies in equipment installations between versions 3.02 and 4.10 lead us to request that EPA do an identical version 4.10 modeling run with the version 3.02 capital cost assumptions. Stakeholders would then be able to see the impact of the lower natural gas prices used in version 4.10 on equipment installations, and, thus, ultimately, total costs. After seeing the results of the model run requested above, ICAC requests that EPA consider modifying the capital cost assumptions in version 4.10. [EPA-HQ-OAR-2009-0491-3791.1_NODA, p.3]
Finally, ICAC notes that corporate contracts for multiple units lead to lower capital costs than those that appear in version 4.10. IPM does not take such efficiencies into account. In contrast, it would be a rare and unusual circumstance for our industry to propose projects, and end-users to implement projects that do not include such efficiencies. Although we realize that level of variability and nuance would be difficult to model in IPM, we believe that EPA and stakeholders should be aware of this business reality, and the resulting cost efficiencies. [EPA-HQ-OAR-2009-0491-3791.1_NODA, p.3]
ICAC has specific comments as follows: [EPA-HQ-OAR-2009-0491-3791.1_NODA, p.4]
1) ICAC believes the new capital cost analysis missed an important and basic design issue in its consideration of capital costs that results in unrealistically high capital costs. For example, the analysis assumes that each boiler has one FGD with a complete limestone handling (storage, preparation, and injection) and a gypsum dewatering system per boiler. Most plants have multiple boilers on site and share the cost of limestone handling and gypsum dewatering over multiple units. [EPA-HQ-OAR-2009-0491-3791.1_NODA, p.4]
A fundamental weakness of how IPM handles reagent handling costs is that IPM assumes that technology is applied to the unit, not to the plant. This is a faulty assumption for all systems using reagents (FGD, SDA, CDS, DSI, SCR, SNCR), especially on plants with multiple, small units. Both capital costs and fixed operating costs are affected by this assumption. The impacts of this assumption are: [EPA-HQ-OAR-2009-0491-3791.1_NODA, p.4]
Capital and fixed operating costs are overestimated for plants with multiple small units. [EPA-HQ-OAR-2009-0491-3791.1_NODA, p.4]
For this reason IPM will overestimate SO2 and NOx control costs, and may even predict too many coal unit retirements. [EPA-HQ-OAR-2009-0491-3791.1_NODA, p.4]
This is exacerbated by the fact that IPM does not currently have DSI or CDS as options, which may be a better fit for some small coal-fired boilers. [EPA-HQ-OAR-2009-0491-3791.1_NODA, p.4]
Since many large units are controlled at this point, most of the remaining units are small, and there are often multiple small units on a site. This assumption of one reagent handling system per unit will significantly overestimate the cost of a scrubber as IPM does not capture the efficiencies from facility-wide reagent handling systems. Therefore, ICAC recommends that EPA examine if IPM can be modified to address the more realistic situation where a reagent handling system is applied to multiple units at the same site. [EPA-HQ-OAR-2009-0491-3791.1_NODA, p.4]
It is unclear if IPM's lack of including reagent handling efficiencies also extends to a lack of including control efficiencies whereby multiple units are serviced by a single control device. For example, it has become a common practice for multiple boilers to feed into a single FGD scrubber, dramatically reducing both the control and related equipment cost and installation timing. [EPA-HQ-OAR-2009-0491-3791.1_NODA, p.4]
2) ICAC notes that the scaling factors used for FGD, SCR, SNCR, and NOx combustion controls have changed. We believe that these new scaling factors were developed from a proprietary database not included in the docket. This has made it very difficult for us to analyze the data points and statistical procedures used in arriving at the new and much higher capital cost figures proposed for the new IPM version 4.10. Accordingly, we request that EPA make available the database used for these calculations. [EPA-HQ-OAR-2009-0491-3791.1_NODA, p.4]
However, what is most troublesome is that although these lower, more conservative scaling factors by themselves should lead to lower capital costs, the capital costs have risen dramatically between the two IPM versions, as explained above. We believe that this points to how the "add-ons" in version 4.10 overwhelm all other factors in explaining the increase in capital costs. [EPA-HQ-OAR-2009-0491-3791.1_NODA, p.5]
3) We note that in Table 5-8 on page 5-11 of Chapter 5 entitled "Emission Control Technologies," non-FBC SNCR was "not modeled" for capacities greater than 100 MW. We are troubled by this omission, and the implication that SNCR is not a valid technological solution for coal-fired units greater than 100 MW. We request EPA's clarification on this issue, and the related question of how SNCR is handled by the new IPM version 4.10. [EPA-HQ-OAR-2009-0491-3791.1_NODA, p.5]
4) We note a discrepancy in the $/kW scrubber costs for a 500 MW unit. In table 5-4, page 5-6 of Chapter 5, the capital cost is $517/kW (2007$), while on page 9 in Appendix 5-1A entitled "Wet FGD Cost Development Methodology," total project cost is $501/kW (2009$). [EPA-HQ-OAR-2009-0491-3791.1_NODA, p.5]
International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers and Helpers (AFL-CIO Boilermakers Union)
Lastly, the Boilermakers welcome the Notice of Data Availability (NODA) released September 1, 2010 and commends EPA in particular for revising the capital cost assumptions for FGD and SCR units in Base Case v. 4.10 for use with the Integrated Planning Model (IPM). EPA's previous capital cost assumptions were unrealistically low, leading to an overestimation of the quantity of emission reductions that can be achieved at any particular marginal abatement cost. For example, EPA had previously assumed that a wet scrubber at a 500 MW EGU would have a capital cost of less than $300 per kilowatt, about 40% less than the capital costs reported by the National Electric Reliability Council (NERC) and the Utility Air Regulatory Group (UARG). Likewise, EPA's previous assumed capital cost for a SCR unit at a 500 MW EGU was approximately 60% less than the NERC and UARG estimates on a per kilowatt basis. [EPA-HQ-OAR-2009-0491-2672.1, pp.7-8]
In Base Case v.4.10, EPA's new capital cost assumption for a wet scrubber installed on a 500 MW EGU ranges from $473 to $517, which is slightly higher than the NERC/UARG estimates and certainly far more realistic than the previous assumed amount. EPA's new capital cost assumption for a SCR unit on a 500 MW EGU ranges from $163 to $193 per kilowatt; this range is substantially less than the NERC/UARG estimate of approximately $240 per kilowatt, but still reflects a considerable improvement over the exceedingly low figure that EPA previously used. In general, we believe that the capital cost assumptions in Base Case v.4.10 generally correspond to the real-world experience of our members, and correct a major analytical flaw in the modeling for the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2672.1, p.8]
That said, the Boilermakers are concerned that the NODA and its associated documents did not, apparently, include any recalculation of state emission budgets or individual EGU allocations. If EPA's assumed capital costs for SCR and FGD units have increased since the release of the proposed Transport Rule, it is likely that state emission budgets will also need to be modified to reflect the lower quantity of emission reductions achievable at EPA's selected abatement cost limits. We urge EPA to conduct the necessary analysis to determine whether this is the case. Assuming adjustments to state emission budgets (and hence individual EGU allocations) will indeed be required, the Boilermakers also request that EPA make those adjustments available for public comment prior to the finalization of the Transport Rule. [EPA-HQ-OAR-2009-0491-2672.1, p.8]
Lafayette Utilities System
LUS believes that EPA made the following errors in the NEEDS v 4.10 Database:
i. For Hargis Hebert Unit 1 and Unit 2, the Modeled Fuels column in NEEDS v4.10 Database includes Distillate Fuel Oil. However, the Hargis Hebert units burn only Natural Gas. [EPA-HQ-OAR-2009-0491-2983.1,p.14]
ii. For Hargis Hebert Unit 1 and Unit 2, the NOx Comb Control column in NEEDS v4.10 Database shows no NOx controls. However, the Hargis Hebert units have water injection NOx controls.
iii. LUS believes that EPA used actual monitored NOx emission rate data reported to EPA under the Acid Rain program from 2007 for the uncontrolled NOx base rates and controlled NOx base rates. However, LUS is unclear how EPA obtained the uncontrolled NOx policy rates and controlled NOx policy rates. [EPA-HQ-OAR-2009-0491-2983.1,p.15]
Louisiana Chemical Association (LCA)
After wrestling with the assumptions and inputs for the IPM TR Base Case v. 3.02 model to understand what comments need to be made, on September 1, 2010, EPA announced in a Notice of Data Availability that the final rule will be based on the IPM Transport Rule version 4.1 not on version 3.02. Thus this will requires reevaluation of a significant amount of data that we have already spent much time reviewing. EPA allowed only 15 days of additional time for this review, even though much of the final FIP will be affected by this new data. Additional time is necessary to prepare comments on these issues and their impact on the reliable transmission of power to Louisiana consumers. [EPA-HQ-OAR-2009-0491-1925.1, pp. 3-4]
LCA supports use of the updated IPM for use in making screening decisions to assist in making findings of 'significant contribution' or 'interference with maintenance' under Clean Air Act Section 110(d). LCA urges EPA, however, to make certain updates to the assumptions and inputs for IPM v. 4.10 as discussed in these comments. Further, as indicated in LCA's original comments, the IPM Base Case, whether premised on v. 3.02, v. 4.10 or some future version, should only be a screening tool for indications of potential 'significant contribution' or 'interference with maintenance'. The IPM is simply not accurate enough and is dependent upon too many uncertain assumptions and imprecise inputs to make binding decisions of 'significant contribution' or 'interference with maintenance.' EPA should always place great weight on empirical data to modify projected model conclusions when making these determinations. [EPA-HQ-OAR-2009-0491-3790.1_NODA, p.2]
On September 1, 2010, EPA published the NODA indicating that EPA intends to use the IPM version 4.10 modeling, including a revised TR Base Case 2012 scenario, for revising the determinations of significant impact and interference with maintenance. Under the revised IPM TR v. 4.10 Base Case, projected emissions of SO2 from Louisiana EGUs are more than 20,000 tpy less than was projected under the IPM v. 3.02 version. (See Table below. [See p.4 of this comment summary for a table entitled, Comparison of TR Base Case v.3.02 to TR Base Case v.4.10 for Louisiana EGUs]) Based on this factor alone, because EPA's own data showed sulfate to be the culprit, it is believed that any revised air quality analysis based on the IPM v. 4.10 will demonstrate no impact whatsoever on Harris Co. PM2.5 levels. The same is true with respect to reductions of annual and ozone season NOx, EPA's revised IPM v. 4.10 Base Case 2012 model results show significant reductions in projected SO2 and NOx emissions that will occur even without implementation of the CATR/FIP (or CAIR). If these values are used in revised air quality modeling, it is virtually certain that the conclusion will be that Louisiana emissions do not impact the annual PM2.5 or 1997 8-hour ozone standards in Texas. 11 [EPA-HQ-OAR-2009-0491-3790.1_NODA, pp.3-4]
Even without a revised air quality analysis, however, LCA believes that use of the TR Base Case v. 4.10 data supports the conclusion that Louisiana should not be included in the CATR/FIP. The original CAT1L/FIP determined that a certain level of emission reductions from EGUs would remove 'significant contribution' and 'interference with maintenance.' The revised IPM v. 4.10 Base Case shows that emission reductions greater than that level will occur by 2012, even without CATR. The following table demonstrates this conclusion: [EPA-HQ-OAR-2009-0491-3790.1_NODA, p.2; See p.4 of this comment summary for a table entitled, Comparison of TR Base Case v.3.02 to TR Base Case v.4.10 for Louisiana EGUs]
Even without air quality modeling, these results demonstrate on their face that because the quantity of SO2 and NOx emissions that were required to be removed to prevent 'significant contribution' and/or 'interference with maintenance' are now projected to be removed by 2012 though factors other than the CATR/FIP, there is no legal basis for a CATR/FIP for annual SO2 or annual or ozone season NOx control for Louisiana EGUs. [EPA-HQ-OAR-2009-0491-3790.1_NODA, p.4]
The significant difference between the results of the v. 3.02 and v. 4.10 Base Case show the imprecision of the IPM model. Due to this imprecision and the uncertainties attendant to the many assumptions made for the IPM modeling, LCA believes that an IPM projected impact of less than 2 ppb from an upwind to a downwind state should never be used as a level indicating 'significant contribution' or 'interference with maintenance' under the 'good neighbor' provisions of the Clean Air Act, 42 U.S.C. 7410(a)(2)(D). At most, the IPM should be used as a screening tool for making rebuttable presumptions for 'significant contribution' or 'interference with maintenance' determinations if a value above 2 ppb contribution is modeled. However, such presumptions should be always subject to a reasonable opportunity for rebuttal by empirical evidence and a weight of evidence approach used to determine if there is actually such contribution or interference. LCA urges EPA to adopt this 2 ppb rule as a bright-line cut-off for screening. If the modeled contribution is 2 ppb or below, then no contribution or interference should be presumed. If the modeled contribution is above 2 ppb, then there could be a rebuttable presumption of contribution or interference. [EPA-HQ-OAR-2009-0491-3790.1_NODA, pp.4-5]
If Louisiana is still included under the CATR/FIP after revised modeling and air quality analysis, LCA requests that EPA not use the IPM v. 4.10 (or any other version of the IPM) to make unit level allocations under the CATR/FIP. EPA should make SO2 and NOx allocations proportionate to the ratio of each unit's existing SO2 and NOx allocations to the state CAIR budgets already approved by both EPA and LDEQ. Although the court in North Carolina v. EPA struck down CAIR and required a revised look at the actual state budget needed to eliminate significant contribution or interference with maintenance, the court did not find any problem with the Louisiana (or other state's) unit level allocations. Louisiana DEQ, together with the Louisiana Public Service Commission, worked very hard on a fair allocation scheme for NOx allowances. This scheme was enacted into rule by the State after public notice and comment and was approved by EPA. [EPA-HQ-OAR-2009-0491-3790.1_NODA, p.5]
On September 27, 2006, the Louisiana Department of Environmental Quality (LDEQ) submitted a SIP revision to EPA adopting the CAIR SO2 Trading Program to address its 'good neighbor' obligations trader CAA Section 110(a)(2)(D) with respect to the potential impact of Louisiana emissions on downwind PM2.5 receptors in the State of Alabama. EPA approved this SIP revision on July 20, 2007 at 72 Fed.Reg, 39741. 14 On July 12, 2007, LDEQ submitted a SIP revision to EPA adopting a SIP for a CAIR NOx Trading Program to address both the 1997 8-hour ozone standard and the 1997 annual PM2.5 standard. EPA approved this SIP revision on September 28, 2007 at 72 Fed. Reg. 55064. LDEQ submitted amendments to its NOx CAIR SIP on July 1, 2009, which are pending before EPA for decision. EPA should base its allocation system as closely on these prior approved Louisiana CAIR provisions as is possible. [EPA-HQ-OAR-2009-0491-3790.1_NODA, p.5]
EPA lacks a credible rationale for premising its NOx and SO2 allocations on the IPM v. 4.10. Although the allocations are slightly more generous than were the allocations under version 3.02, they. are woefully inadequate to allow LCA members with cogeneration units to normally operate their units without incurring enormous costs. Further, they are inadequate to allow many of the public EGUs to operate at normal levels without incurring enormous costs that will be passed on to LCA members as industrial users. LCA incorporating by reference its comments on the improper use of the IPM model for NOx allocations made in LCA's original comments. [EPA-HQ-OAR-2009-0491-3790.1_NODA, p.5]
The IPM is an economic model that fails to account for realistic operations at many Louisiana facilities, in particular, cogeneration units serving industrial sources. The unit level allocation scheme based on the IPM (as distinguished from the state budget) has nothing to do with preventing significant contribution or interference with maintenance. In fact, huge economic inequities are being created with no underlying environmental reason. The following table shows a comparison of the allocations that Louisiana Sources would likely receive under IPM v. 4.10 version as well as actual reported emissions to CAMD for 2005-2010 are shown on LCA Exhibit 1, attached. [EPA-HQ-OAR-2009-0491-3790.1_NODA, pp.5-6; see p.8 of this comment summary for Exhibit 1]
The assumptions made in the IPM v. 4.10 are obviously grossly in error with respect to the utilization of these units. It would be arbitrary and capricious for EPA to base its allocations on the IPM - either v. 3.02 or v. 4.10 given these facts. LCA urges EPA to carefully review the comments of the Louisiana Public Service Commission staff on October 1, 2010 in connection with allocation issues. [EPA-HQ-OAR-2009-0491-3790.1_NODA, p.6]
EPA's approach for projected emissions inventories, as well as considerations of control technology under the IPM v. 4.10, eliminated the consideration of any reductions required by CAIR, due to the fact that the CAIR rule was overturned in North Carolina v. EPA, 531 F.3d 896, 901 (D.C. Cir. 2008). However, this results in overly conservative projections. The CAIR rule was remanded, but not vacated. Many regulated public utilities already invested in capital projects for reduction that were approved by their regulatory bodies and/or ratepayers. In most cases, legal obstacles would prevent the undoing of these projects. In addition, each physical project undertaken for purposes of CAIR reductions was of necessity permitted under an enforceable Title V permit. Those projects and permit limits cannot be relaxed without the facilities triggering Prevention of Significant Deterioration (PSD) rules. Triggering PSD would involve imposition of Best Available Control Technology, which, in most cases, would mean that the facilities would have to keep the pollution control equipment they installed for CAIR, or would have to meet even more stringent requirements. EPA should have undertaken a much more rigorous analysis for projecting what steps EGUs would take if CAIR were vacated completely, with no replacement. EPA has tools to easily accomplish this, such as a Clean Air Act Section 114 request for information. In short, EPA overestimated Base Case emissions for both 2012 and 2014 by eliminating all CAIR control requirements. [EPA-HQ-OAR-2009-0491-3790.1_NODA, p.6]
The documentation for the IPM v. 4.10 does not clearly indicate whether EPA included only the grid-demand for electricity or also industrial facility demand. Section 3.2 of the Documentation for the EPA's IPM v. 4.10 Base Case tends to indicate that EPA considered only the grid-demand. This may have discounted the total electrical demand in Louisiana as many industries have cogeneration units. Some of these units provide power to the grid, as do some of the LCA members who own or operate cogeneration units. However, if EPA did not appropriately account for the fact that industries that partially, self-generate need continuous and reliable electrical and steam output, then the IPM may make deficient economic choices in its selection of EGU behavior. [EPA-HQ-OAR-2009-0491-3790.1_NODA, p.6]
LCA believes, for the reasons stated in the comments of the staff of the Louisiana Public Service Commission (LPSC) on the proposed CATR/FIP, that the IPM fails to adequately consider transmission constraints within Louisiana. LCA believes this is a deficiency in both the IPM v. 3.02 and v. 4.10. LCA Urges EPA to carefully consider the comments of the LPSC staff. [EPA-HQ-OAR-2009-0491-3790.1_NODA, p.6]
The Documentation for the IPM v. 4.10 Base Case, Chapter 3.5.1 indicates that EPA made certain assumptions about EGU availability in its modeling. EPA stated 'Power plant availability is the percentage of time that a generating unit is available to produce electricity to the grid. Availability takes into account both scheduled maintenance and forced outages...' EPA indicated that Appendix 3-9 shows the availability assumptions for all EGUs in EPA Base Case 4.10. EPA indicated that it was using an 85% availability assumption for all combined cycle units. LCA believes this is erroneous. The combined cycle cogeneration units serving chemical manufacturing facilities typically have an availability of over 95% per year. [EPA-HQ-OAR-2009-0491-3790.1_NODA, pp.6-7]
The documentation for the IPM v. 4.10 indicates that EPA continued an error that was also made in the IPM v. 3.02 Base Case with respect to existing environmental regulations. In Section 3.9.4 of the Documentation of EPA's IPM v. 4.10 Base Case, EPA listed the state rules that it included in the model. As indicated in LCA's original comments, EPA improperly considered the Louisiana NOx Reasonably Available Control Technology rule in LAC 33:III.Ch. 22 reductions of NOx in the modeling used to project future impact. In Appendix 3-2.2, EPA had the following entry for Louisiana: [EPA-HQ-OAR-2009-0491-3790.1_NODA, p.7; See p.7 of this comment summary for a table showing a section of a table published by EPA in Appendix 3-2.2]
The cited rule does apply to NOX, but the information in the 'Emission Specifications' column is totally erroneous. The NOx emission limits are much lower than this, but different limits apply to different types of units. Further there are different limits for different parishes. LCA requests that EPA update the model by using the actual limits of the rule, as set forth at LAC 33 :III.Chapter 22, available at: http://www.deq.Louisiana.gov/portal/tabid/96/Default.aspx [EPA-HQ-OAR-2009-0491-3790.1_NODA, p.7]

11 If EPA conducts revised air quality modeling, LCA urges EPA to also make the revisions to the Louisiana emissions inventory discussed in LCA's original comments.
14 Louisiana Department of Environmental Quality, Louisiana SIP Revisions, http://www.deq.Louisiana.gov/portal/Default.aspx?tabid=2381.
Louisiana Energy and Power Authority (LEPA)
LEPA continues to object to the process by which the EPA developed the proposed Transport Rule, including its separate publication and comment period for the NODA. The NODA contains 'new' and 'updated' detailed modeling data that the EPA apparently intends to use to support the proposed Transport Rule, including the allocation of zero emission allowances to LEPA's units. LEPA was prejudiced by the abbreviated time period permitted for review of and comment on this highly complex and technical modeling data, as well as the failure to include the NODA with the Proposed Rule. There was insufficient time for an adequate review of the NODA and it was impossible to disaggregate the information contained in the NODA from the information published with the proposed Transport Rule and separately comment on each set of information. The EPA should have used the best information available to develop the Transport Rule, should have published the Transport Rule together with all information used to develop it, and should have permitted sufficient time for review of and comment on the rule with one set of supporting data. [EPA-HQ-OAR-2009-0491-3738.1_NODA, pp.2-3]
The analysis LEPA was able to perform of the NODA in the limited time permitted and with the limited information made available confirms LEPA's conclusion in its earlier comments that the EPA's methodology for allocating emission allowances to Electric Generating Units ('EGUs') is seriously flawed. That methodology fails to allocate any allowances to critical EGUs that must run to serve load in communities across Louisiana. This error appears to result from a lack of model inputs or modeling logic that properly capture transmission constraints or otherwise reflect the fact that some EGUs, like LEPA's Morgan City and Houma units, must run to serve load. Thus, none of the information contained in the NODA in any way responds to or addresses the concerns raised in LEPA's comments on the proposed Transport Rule. All of LEPA's earlier comments apply to the NODA and LEPA hereby incorporates them by reference and adopts them in response to the NODA without repeating them. [EPA-HQ-OAR-2009-0491-3738.1_NODA, p.3]
THE PROCESS BY WHICH EPA DEVELOPED THE PROPOSED TRANSPORT RULE, INCLUDING THE PUBLICATION OF THE NODA ON A SEPARATE TRACK, WAS SERIOUSLY DEFICIENT AND PREVENTED INTERESTED AND AFFECTED PERSONS FROM SUBMITTING MEANINGFUL COMMENTS. [EPA-HQ-OAR-2009-0491-3738.1_NODA, p.4]
The EPA did not permit sufficient time nor provide sufficient information or resources to allow LEPA to meaningfully participate in this rulemaking process. The Transport Rule proposes sweeping changes to the environmental regulations applicable to EGUs based on highly technical data and analyses. The NODA contains highly complex modeling data that cannot possibly be properly analyzed and understood in the time permitted and with the information made available. LEPA is a small organization run for the benefit of its modest member communities, who face substantially increased costs and possible power shortages as a result of the Proposed Rule. Neither LEPA nor its member communities have the internal technical or legal staff to analyze the Transport Rule and the complex modeling data in the NODA. It has been extremely burdensome for LEPA to gather the necessary resources, particularly in the limited time allowed. [EPA-HQ-OAR-2009-0491-3738.1_NODA, pp.4-5]
The review and comment process also has been seriously compromised by the EPA's piecemeal approach to supplying supporting information. The EPA published its proposed Transport Rule along with a Technical Support Document entitled State Budgets, Unit Allocations, and Unit Emissions Rates, explaining how state budgets and unit allocations were determined. That document explained that unit allocations were set based on projections on how much each EGU would run as determined by the Integrated Planning Model ('IPM'). Some modeling information was provided in connection with the proposed Transport Rule. The NODA subsequently provided modified modeling runs; an updated NEEDS database, which provides unit level characteristics of the EGUs included in the IPM modeling; and more detailed information on the IPM and the NEEDS data base. The EPA explained that the information in the NODA could be used to support the final rule and may be modified. The EPA stated that 'additional information' may be placed into this docket before the final rule is published. [EPA-HQ-OAR-2009-0491-3738.1_NODA, p.5]
It is impossible for LEPA to get a handle on the shifting basis for the rule. The supporting technical data is already highly complex and voluminous, and it is made even more so by its modification in the NODA and future unknown modifications. Proper rulemaking procedure, particularly for a complex rule like the proposed Transport Rule, is for the agency to consider all available information to determine the proper basis for developing the rule and then to publish the rule along with all supporting data and analysis. [5 U.S.C. § 553]. The agency should not publish a proposed rule and then subsequently consider and develop other 'supporting' data. The rule, along with all information used to develop the rule, should be supplied at the same time in connection with the public notice giving sufficient time for review and analysis, so that interested and affected parties can understand the basis for the rule and participate meaningfully in the process. [EPA-HQ-OAR-2009-0491-3738.1_NODA, pp.5-6]
LEPA was hampered in its ability to review and comment on the proposed Transport Rule and the NODA also by a lack of available detailed information. For example, LEPA attempted to identify the specific input data assumptions used for the modeling of the LEPA units. The available documentation is a high-level overview of the model, however, and does not provide sufficient detail to determine this or to explain how the dispatch and commitment process works or what type of logic is used to model operating reserve constraints. The EPA should provide more detailed documentation, including a detailed step-by-step discussion of the commitment and dispatch process that clearly explains how units are started up, dispatched, and either backed down or ramped up when constraints occur. The EPA should also provide detailed information on what logic is used to model operating reserve constraints, if any such logic is incorporated into the model. If there is no such logic integrated in the model, this is a serious flaw in the model and the EPA should inform the parties. [EPA-HQ-OAR-2009-0491-3738.1_NODA, p.6]
THE DATA PROVIDED IN THE NODA CONFIRMS THAT EPA'S MODELING IS INADEQUATE AND FAILS TO ACCOUNT FOR TRANSMISSION CONSTRAINTS AND ASSOCIATED OPERATIONAL REQUIREMENTS. [EPA-HQ-OAR-2009-0491-3738.1_NODA, p.7]
As explained in LEPA's comments on the proposed Transport Rule, the EPA's IPM projected that LEPA's Houma Unit 16, Houma Unit 15 and Morgan City Unit 4 would not run in the future and therefore they receive no emission allowances under the proposed rule. This is a serious flaw in the modeling because those units must run to maintain reliability in LEPA's service territory. LEPA's service territory is located in a transmission-constrained area, and LEPA cannot import sufficient electricity into its service area at all hours of the year because of limited available transmission. LEPA, therefore, must run its Houma and Morgan City units located inside LEPA's control area to supply electricity to its members. If LEPA cannot run those units, it would not have electricity to supply its members needs and it would be forced to curtail power. [EPA-HQ-OAR-2009-0491-3738.1_NODA, p.7]
From its review of the information supplied with the Transport Rule, LEPA tentatively concluded, based on the limited available information and opportunity to review, that the IPM did not project its units to run because the model did not include proper inputs regarding transmission constraints and reliability must run requirements. LEPA further examined the modeling data provided in the NODA in an attempt to ascertain why its units do not operate in the modeling. Again it appears that the modeling does not incorporate sufficient inputs to reflect transmission constraints and must-run requirements. [EPA-HQ-OAR-2009-0491-3738.1_NODA, p.7]
With regard to transmission modeling, the EPA Base Case v.4.1 0 using the IPM incorporates 32 interconnected load regions. The transmission regions and limits modeled between the regions are laid out in Chapter 3 of the supplied documentation. It explains that flows between the 32 regions are monitored and dispatch is altered when the flows exceed the limits input into the EPA models. [EPA-HQ-OAR-2009-0491-3738.1_NODA, p.8]
This modeling approach is overly simplistic and does not capture transmission constraints in Louisiana, including the region where the LEPA service territory is located and likely does not capture transmission constraints that exist in other regions. LEPA's generating units are interconnected to the Cleco and Entergy transmission systems. The IPM incorrectly reflects these transmission systems as being located in one unconstrained region. Typically, when Entergy performs its own modeling studies, it subdivides its system into six or seven sub-regions and monitors the power flows between these sub-regions. Without the ability to model transmission constraints between these sub-regions, the IPM will not accurately reflect the effect of internal transmission constraints on the dispatch of LEPA's units. The fact that the IPM monitors transmission flows between two regions such as Entergy and Southern Company is not a substitute for more detailed transmission modeling within regions that have a greater influence on the dispatch of units like the Morgan City and Houma units. [EPA-HQ-OAR-2009-0491-3738.1_NODA, p.8]
The fact is that the IPM was not designed to capture the kind of detail that must be factored into the allocation of emission allowances. The IPM is an optimization model used to perform optimal resource planning studies for various purposes. For example, it is able to develop an optimal long-term resource portfolio, while at the same time developing appropriate generating unit control technologies for existing generating resources in order to conform to environmental standards. Optimization models such as this typically sacrifice modeling detail to reduce study run times. The model can perform long-term, high-level studies, but cannot perform the detailed analysis required to allocate fairly emission allowances on a unit-by-unit basis. It is an inappropriate tool to use for unit-by-unit allowance allocations and should not be used for this purpose. If, however, the EPA continues to rely on the IPM model for the Transport Rule, then additional modeling inputs should be incorporated to reflect sub-regional transmission limits, like those that exist in Louisiana, and better capture the commitment requirements of the LEPA generating units. [EPA-HQ-OAR-2009-0491-3738.1_NODA, pp.8-9]
The EPA IPM modeling approach is further flawed because in the absence of incorporating a more detailed transmission model, it also does not attempt to use other modeling logic that is commonly available in production cost models to force the commitment of LEPA's Morgan City and Houma units. LEPA could not discern what such logic was included in the IPM, if any, nor what inputs were included for the LEPA units in any such logic. It appears from the EPA IPM modeling documentation in Chapter 2 that Turn Down/Area Protection inputs may be able to be used for the LEPA units in order to 'take into account the cycling capabilities of the units, i.e., whether or not they can be shut down at night or on weekends, or whether they must operate at all times, or at least at some minimum capacity level. These constraints ensure that the model reflects the distinct operating characteristics of peaking, cycling, and base load units.' [Chapter 2, 'Turn Down/Area Protection Constraints']' However, there was not enough information provided in the NODA to permit LEPA to evaluate how the Turn Down! Area Protection inputs work or whether they were even input for the LEPA units. Turn Down! Area Protection inputs clearly should be included for the LEPA units in any further modeling to recognize the reliability must-run status of those units. [EPA-HQ-OAR-2009-0491-3738.1_NODA, pp.9-10]
There is no question that LEPA's units actually run and that they run due to a lack of transmission capability in LEPA's service territory, as well as to provide transmission support within the region. Attachment 4 to LEPA's comments submitted October 1,2010 shows that LEPA's three units ran for thousands of hours in 2007, 2008 and 2009, and shows that the units ran particularly during the summer high load period. An analysis of the hourly unit generation data for the three units shows that those units operate over 90% of the time at or near their minimum capacity levels and are therefore run to satisfy a reliability constraint: [EPA-HQ-OAR-2009-0491-3738.1_NODA, p.10; see p.10 of this comment summary for a table entitled, 2007 - 2009 Summary of Operating Results]
Thus, LEPA's units without doubt are must-run units and EPA's modeling approach and its resulting emission allocation scheme should recognize this. Either the IPM model and data must be modified to reflect more detailed transmission constraints, a new more sensitive modeling tool should be used, or the Proposed Rule should explicitly recognize the must-run status of these units and directly assign them emission allowances to ensure reliability. [EPA-HQ-OAR-2009-0491-3738.1_NODA, pp.10-11]
Louisville Gas and Electric Company (LG&E) and Kentucky Utilities Company (KU)
Station Specific NEEDS v4.10 Comments:
E. W. Brown  -  Mercer County, KY
The revised NEEDS v4.10 data incorrectly shows E. W. Brown Units 1 & 2 as equipped with FGD's, each online in 2009. The units were not equipped with FGD in 2009. Unit 1 & 2 are expected to become scrubbed in early 2011. [EPA-HQ-OAR-2009-0491-3755.1_NODA, p.2]
NEEDS v3.02 incorrectly showed that E. W. Brown Unit 3 was equipped with an SCR. The revised NEEDS v4.10 data now correctly shows that E. W. Brown Unit 3 is not equipped with an SCR. EPA did not release a revised Allocation Table with the NODA; therefore it is impossible to review whether the correction has been properly incorporated. [EPA-HQ-OAR-2009-0491-3755_NODA, p.3]
Ghent  -  Carroll County, KY
The revised NEEDS v4.10 incorrectly shows Ghent Unit 2 as equipped with SCR online in 2009 and a "Policy Case" NOx emission rate of 0.06 lb/mmBtu. Ghent Unit 2 is not equipped with an SCR and none is planned. The revised Base Case 2012 also incorrectly lists an SCR as control equipment. The revised Limited Trading Case 2014 shows emission rate of 0.06 lb/mmBtu, which is not achievable without installation of a SCR. [EPA-HQ-OAR-2009-0491-3755.1_NODA, p.3]
It is possible that these NOx control equipment errors are related to the complex stack configurations at Ghent. Currently, Units 2 and 3 shared a common stack, and emissions are monitored and reported together under an approved monitoring plan. Apportioning the emissions to individual units is not required under the monitoring plan and apportioned emissions are not reported. Ghent Unit 3 is equipped with a SCR. Therefore, the combined NOx emissions and NOx emission rates represent the combination of a unit with a SCR and one without a SCR. Apportioning the total emissions by heat input is a common approach and one apparently used by EPA since the Base Case shows Ghent Units 2 and 3 with emission rates of 0.19 lb/mmBtu and 0.23 lb/mmBtu, respectively. However this leads to erroneous interpretation of the each unit's level of NOx control. [EPA-HQ-OAR-2009-0491-3755.1_NODA, p.3]
Trimble Co. Unit 2  -  Trimble County, KY
In the NEEDS v3.02 database there was a unit in the allocation table designated "TVAK_KY_Coal Steam Unit 1." The "TVA" portion of the name appears to refer to the region, rather than the utility company. Other information indicates it is a 732 MW unit located in Trimble County. Since no other generating units are similar to the description, this suggests that the reference is to the 760 MW Trimble County plant Unit 2, which is scheduled to begin operation in late 2010. However, it has a different plant ORIS code than the Trimble County plant (ORIS 6071) and is called Unit 1. [EPA-HQ-OAR-2009-0491-3755.1_NODA, p.3]
The allowance allocation table shows an SO2 allocation for 2012 but zero allowances allocated for 2014 for this unit. [EPA-HQ-OAR-2009-0491-3755.1_NODA, p.4]
In the updated NEEDS database (v4.10), the unit information has been revised to list the unnamed unit with the county as "unknown" and with capacity of 750 MW. [EPA-HQ-OAR-2009-0491-3755.1_NODA, p.4]
Trimble County Unit 2 commenced commercial operation in 2010, as defined in the proposed rule, in 2010. Accordingly, it should receive an allocation for both 2012 and 2014 as an "existing unit" as defined in the proposed regulations. [EPA-HQ-OAR-2009-0491-3755.1_NODA, p.4]
General NEEDS v4.10 Comments:
NOx projected emissions are unrealistically low:
The NOx projected emission rates for the KU and LG&E units with SCR controls are based on unrealistically low NOx emission rates. EPA states that it assumes SCRs can achieve 90% removal, down to a floor of 0.06 lb/mmBtu. However, EPA's projections include units achieving much lower rates (as low as 0.03 lb/mmBtu). EPA has clarified that the floor of 0.06 lb/mmBtu is for only new SCRs, and that lower emission rates were used for existing SCRs that temporarily achieved lower rates. Analysis of the historic emission data shows that EPA is assuming these lower rates based on a very limited time frame. The TSD methodology uses emission rates based on historic ozone season emission rates. However, this is not representative of an achievable annual average emission rate. Units generally operate at high capacity levels during the summer ozone season, resulting in atypically low emission rates. During lower electricity demand periods, many units operate at much lower capacity levels and their SCRs may not be able to be operated continuously due to low boiler exit combustion gas temperatures in the SCR. [EPA-HQ-OAR-2009-0491-3755.1_NODA, p.4]
Also EPA must consider degradation of catalyst reactivity over time, variations in unit design, and other factors which make it impossible for a unit to repeat its best short-term performance on a year after year basis. Our experience with year round operation (2009) and at units with relatively new catalyst layers have not achieved lower than 0.055 lb/mmBtu. And even these low rates were only achieved at units equipped with economizer bypass which allowed SCR operation at an extended (lower) operating range. [EPA-HQ-OAR-2009-0491-3755.1_NODA, pp.4-5]
The projected NOx emission rates in NEEDS v4.10 are an average 14% lower than our current actual data, and are not likely to be achievable without additional installation of NOx control equipment1. This NOx reduction cannot be accomplished by 2012 which is the premise of EPA's proposed budgets. All KU and LG&E units are currently equipped with various levels of Low NOx Burner technologies. The table below compares recent data with the values in NEEDS v4.10. [EPA-HQ-OAR-2009-0491-3755.1_NODA, p.5][[See Docket Number EPA-HQ-OAR-2009-0491-3755.1_NODA, p.5 for the table.]]
SO2 projected emissions are unrealistically low
The NEEDS v4.10 database which will be used by EPA to finalize allocations should represent "actual" emissions. However, the listed emissions were typically the first 3 quarters of 2009 and the fourth quarter of 2008. This period was not only the heart of the recent economic downturn, but ambient temperatures were milder than normal in Kentucky. Summer temperatures in the Midwest during 2009 were over 25% below the 30-year average. Therefore, this period had significantly reduced electric generation and is unrepresentative of normal operations. Indeed, EPA's Base Case heat input projections for Kentucky are 17% higher than this time period. The low historic emissions combined with the higher projected heat input results in unrealistically low emission reduction targets. Utilities in Kentucky will have to reduce emission rates by approximately 17% to even meet the allocations for 2012. This is contrary to EPA's assertion that the 2012 CATR reductions can be achieved without significant new equipment. EPA's "Recent" emissions data should be updated with more recent (last quarter of 2009 and the first 3 quarters of 2010) actual emissions. If the most recent available data for LG&E and KU is used in the NEEDS v4.10 (Oct. 2009  -  Sep. 2010), then the current average annual SO2 emissions for LG&E and KU increase by 10%2. [EPA-HQ-OAR-2009-0491-3755.1_NODA, p.6]

1 Btu-weighted average of the NEEDSv4.10 Policy Case NOx emission rate versus recent actual data from Oct 2009 through September 2010. Ghent Units 2&3 were excluded from this average as obvious errors described previously; if included, the NEEDSv4.10 NOx emission rates are 24% below recent actual data. [EPA-HQ-OAR-2009-0491-3755.1_NODA, p.5]
2 Excluding Brown 3 and Ghent 2, where FGD's became operational between EPA's "recent" data and the most recent data. [EPA-HQ-OAR-2009-0491-3755.1_NODA, p.6]
Marquette Board of Light and Power
Inaccurate Uncontrolled NOx Base Rate
The National Electric Energy Data System database (NEEDSv4.10) uses an uncontrolled NOx Base Rate of 0.138 lbs/mmBtu for Shiras Unit 3. This number is incorrect and is not representative of the uncontrolled emission rate for this unit. Shiras Unit 3 is currently controlling NOx to the Clean Air Interstate Rule (CAIR) emission rate level of 0.15 lbs/mmBtu. The uncontrolled NOx emission rate for the Shiras Unit 3 is 0.30 lbs/mmBtu. We request that the Agency update this information in the NEEDSv4.10 database. Using inaccurate data will negatively affect the results of the Integrated Planning Model (IPM) and therefore negatively affects the underlying data used to write the rule. [EPA-HQ-OAR-2009-0491-2764.1, p.2]
Massachusetts Department of Environmental Protection
Corrections to NEEDS v.4.10 EPA-HQ-OAR-2009-0491-0310
Blackstone (ORISPL 1594)
MassDEP believes no units at this facility qualify as Transport Rule eligible units as explained below. Blackstone Units 11 and 12 located at the Harvard University steam generation plant in Cambridge, MA serve a common steam header along with two other boilers (Units 6 and 13 also not affected Transport Rule EGUs). Units 11 and 12 are allocated allowances in the proposed Appendix A, but according to the operator neither qualify as Transport Rule eligible EGUs, with a nameplate capacity equal to or greater than 25 MWe.
:: Unit 11 is a Combustion Engineering VU-60 dual fuel boiler, rated at 252 MmBtu/hr (commenced operation in 1963) firing No.6 Fuel Oil and natural gas;
:: Unit 12 is a Combustion Engineering VU-60 dual fuel boiler, rated at 286 MmBtu/hr (commenced operation in 1963) firing NO.6 Fuel Oil and natural gas.
In conjunction with Units 6 and 13, Units 11 and 12 feed at most 5 MW back pressure to a steam turbine that generates electricity. [EPA-HQ-OAR-2009-0491-3818.1_NODA, p.3] [EPA-HQ-OAR-2009-0491-2787.2]
Brayton Point (ORISPL 1619)
Unit 1 (1619_B_l) listed as a 243 MW coal steam bituminous-fired boiler. The reported nameplate capacity is 255 MWe, and heat rate is 2,250 MmBtu not 9,110 MmBtu. The modeled fuel listed for Unit 1 is bituminous coal. Unit 1 is also capable of firing No.6 Fuel Oil (residual oil), No.2 Fuel Oil and pipeline natural gas as well. Unit 1 is capable of firing at:
:: 100% maximum continuous rating (MCR) pulverized bituminous coal,
:: 100% MCR NO.6 Fuel Oil (back-up fuel),
:: 100% MCR No.2 Fuel Oil (alternate back-up fuel),
:: 25% MCR pipeline natural gas (secondary fuel) at 25% MCR. Brayton Point (ORISPL 1619)
Unit 2 (1619_B_2) listed as a 244 MW coal steam bituminous-fired boiler. The reported nameplate capacity is 255 MWe, and heat rate is 2,250 MmBtu not 9,110 MmBtu. The modeled fuel listed for Unit 2 is bituminous coal. Unit 2 is also capable of firing NO.6 Fuel Oil (residual oil), No.2 Fuel Oil and pipeline natural gas as well. Unit 2 is capable of firing at:
:: 100% maximum continuous rating (MCR) pulverized bituminous coal,
:: 100% MCR NO.6 Fuel Oil (back-up fuel),
:: 100% MCR No.2 Fuel Oil (alternate back-up fuel),
:: 25% MCR pipeline natural gas (secondary fuel).
Brayton Point (ORISPL 1619) Unit 3 (1619_B_3) listed as a 612 MWe coal steam bituminous-fired boiler, equipped with wet scrubber online in 2006. The reported nameplate capacity is 633 MWe. As of September 2010 no scrubber has been installed. Current PSD approval and modified plan approval allows operator to commence construction of dry scrubber by April 2011. Operator provided construction schedule indicates dry scrubber online by 1st Quarter 2014. The dry scrubber will be equipped with a fabric filter baghouse for particulate control. The modeled fuel listed for Unit 3 is bituminous coal. Unit 3 is also capable of firing NO.6 Fuel Oil (residual oil), No.2 Fuel Oil and pipeline natural gas as well. Unit 2 is capable of firing at:
 :: 100% maximum continuous rating (MCR) pulverized bituminous coal,
:: 100% MCR NO.6 Fuel Oil (back-up fuel),
:: 100% MCR No.2 Fuel Oil (alternate back-up fuel),
:: 10% MCR pipeline natural gas (secondary fuel). [EPA-HQ-OAR-2009-0491-3818.1_NODA, p.4] [EPA-HQ-OAR-2009-0491-2787.2]
Canal (ORISPL 1599)
Canal (ORISPL 1599) Units 1 (1559_B_1) and Unit 2 (1599_B_2) listed as 559 and 553 MWe oil/gas steam boilers respectively are missing flue gas recirculation (FR) as a NOx combustion controls in addition to low NOx burners with overfire air (LNBO). Unit 2 (1599_B_2) is also missing an installed NOx post combustion control device, a selective noncatalytic reduction (SNCR), added sometime between 2006-2008. The SNCR was optimized for a specific load range for which the operator reports Unit 2 now largely operates at. Natural gas firing is limited to 40% MCR for Unit 2 (1599_B_2). The planned update correction to NEEDS v.4.10 Table 2, Planned Revisions to Installed NOx Post Combustion Controls, should be revised, moving the SNCR from the Planned Future Revision column to the Current NOx Post-Combustion Control Assumption column. [EPA-HQ-OAR-2009-0491-3818.1_NODA, pp.4-5] [EPA-HQ-OAR-2009-0491-2787.2]
M Street Jet (ORISPL 10176)
MassDEP believes no EGUs at this facility qualify as Transport Rule eligible units as explained below. Two separate EGUs have apparently been merged into a larger single unit (10176_G_NO.6) to create a Transport Rule eligible EGU in NEEDS v.4.10 EPA-HQ-OAR-2009-0491-0310. It's identified in the proposed Appendix A allocation table as South Boston Combustion Turbines B (ORISPL 10176) and listed as a 50 MW combustion turbine firing distillate fuel oil. Facility actually consists of two Turbo Power & Marine FT4C-3F, simple cycle combustion turbine generator sets, each with heat rate of 396 MmBtu per hour, with a summer capacity of approximately 24 MW. Unit ID should be Units A and B, not No.6. [EPA-HQ-OAR-2009-0491-3818.1_NODA, p.5] [EPA-HQ-OAR-2009-0491-2787.2]
Montgomery L'Energia (ORSIPL 54586)
This facility appears to be omitted from NEEDS v.4.10 EPA-HQ-OAR-2009-0491-0310. Unit 2 is a combined cycle Rolls Royce Trent 60 with 545 MmBtu/hr maximum heat input, commenced operation in 2008, and equipped with NOx post combustion control device, selective catalytic reduction (SCR). [EPA-HQ-OAR-2009-0491-3818.1_NODA, p.5[EPA-HQ-OAR-2009-0491-2787.2]]
Mount Tom (ORISPL 1606)
Mount Tom (ORISPL 1606) Unit 1 (1606_B_1) listed as a 144 MWe coal steam bituminous-fired boiler, added a dry scrubber (dry lime FGD) that commenced commercial operation in the 4th Quarter 2009 and that is not listed in NEEDS v.4.10 EPA-HQ-OAR-2009-0491-031O. Operator installed a Babcock Power Environmental Turbosorp dry scrubber system utilizing hydrated lime.2 As part of a 2007 consent decree3 with MassDEP, Mount Tom must meet an actual 502 emission rate of 3 lbs/MWh calculated over any consecutive 12 month period, recalculated monthly beginning October 1,2010. The planned update correction to NEEDS v.4.10 Table 1, Planned Revisions to Installed S02 Controls, should be revised, moving the dry scrubber from the Planned Future Revision column to the Current S02 Control Assumption column. [EPA-HQ-OAR-2009-0491-3818.1_NODA, p.6] [EPA-HQ-OAR-2009-0491-2787.2]
As the chart below indicates, Mount Tom Unit 1 S02 emission trends are declining to 3 lbs/MWh and EPA should adjust NEEDS vA.l0 EPA-HQ-OAR-2009-0491-0310 and other input files to reflect the lower S02 emission rate. [[See chart on page 15/17]]  [EPA-HQ-OAR-2009-0491-2787.2]
Potter (ORISPL 1660) and Thomas G. Watson (82100)
Thomas G. Watson Units 1 {82100_G_l} and Unit 2 {82100_G_l} and Potter Units 4 and 5 are the same units. Each is a Rolls Royce Trent 60 DLN combustion turbines each with a summer capacity of 58 MW firing natural gas and distillate fuel oil, equipped with a NOx post combustion control device, a selective catalytic reduction {SCRL and they are enrolled in CAIROS, RGGI and ARP programs as Potter Units 4 and 5. This appears to be erroneous data carried over from an EIA Form 860, Thomas G. Watson Station is used by the operator, Braintree Electric Light Department to connote the new power projects, which are physically located at Potter (ORISPL 1660) Station. The Thomas G. Watson Units 1 (82100_G_1) and Unit 2 (82100_G_1) should be removed from NEEDS v.4.10 EPA-HQ-OAR-2009-0491-031O and replaced with Potter Units 4 and 5.  [EPA-HQ-OAR-2009-0491-2787.2] [EPA-HQ-OAR-2009-0491-3818.1_NODA, p.7]
Corrections to NEEDS v.4.10 EPA-HQ-OAR-2009-0491-0310
Note that the corrections discussed in this narrative are also provided in the attached spreadsheet - MA Corrected Needs v. 4.10 xlsx. [[See Docket Number EPA-HQ-OAR-2009-0491-3818.2_NODA for spreadsheet]]
Combined Cycle and Dual Fuel Units
MassDEP notes that several combined cycle units operating in Massachusetts are treated disparately in NEEDS v.4.10. We urge EPA to use a consistent methodology in listing generation units in the NEEDS v.4.10 input file and future versions. We believe errors in characterizing various units described below aggravate the bias against combined cycle units in EPA's proposed allowance allocation methodology. [EPA-HQ-OAR-2009-0491-3818.1_NODA, p.1] 
We understand that the IPM treatment of combined cycle units reflects an allocation methodology based upon historical heat input and multiplying that against the S02 pipeline natural gas emission factor of 0.0006 lb/mmBtu. Since the IPM module builds out the model combined cycle units across the four quarters, and annual S02 emissions are between 2-4 tons for the largest combined cycle units in Massachusetts, IPM appears to be calculating quarterly emissions at less than 0.5 tons and then rounding down to 0 tons. Hence the units identified below are allocated zero S02 allowances. EPA should modify the application of the rounding convention to extremely low emitting base-load and intermediate-load following combined cycle units to allow rounding up to a level that will reflect the historical emissions level on an adjusting three-year rolling average. [EPA-HQ-OAR-2009-0491-3818.1_NODA, p.1]
NEEDS v.4.10 Should Utilize Nameplate, Not Summer Dependable Capacity MassDEP has significant concerns with EPA's use of net summer dependable capacity rather than nameplate capacity as defined in the proposed Transport Rule without restriction by seasonal or other deratings. Reliance on summer dependable capacity in NEEDS v.4.10 introduces another source of bias against combustion turbines and combined cycle units as higher ambient temperatures result in derating of units during summer operation. [EPA-HQ-OAR-2009-0491-3818.1_NODA, p;p.1-2]
Turndown Assumptions
We note that the IPM technical documentation identifies turndown assumptions that prevent coal and oil/gas steam units from operating strictly as peaking units, which would be inconsistent with their operating capabilities.' While the original operational parameters for these oil/gas steam units did not contemplate their utilization as peaking units, operators have responded to changing market conditions and have been utilizing oil/gas steam units as peaking units. Examining peak demand episodes between 2005 and 2008 in New England, ISO-NE has observed an increased utilization of oil/gas steam units in the dispatch of the last 500 MW during high energy demand episodes. In Massachusetts and other New England States, oil/gas steam units are being utilized as peaking assets during high energy demand episodes; this contradicts the IPM turndown assumptions that prohibit modeling of these market conditions. [EPA-HQ-OAR-2009-0491-3818.1_NODA, p.2]
These oil/gas steam units listed above have experienced a marked change in capacity utilization trends. Operators report they are dispatched infrequently and primarily due to peak demand episodes or transmission constraints. We urge EPA to more closely review actual operational behavior of individual plant type units in regional power pools rather than relying so heavily on the IPM macro assumptions, which apparently have not incorporated evolving market conditions in projecting future operations. In the case of Massachusetts, we ask EPA to re-examine IPM assumptions, inventories, and output to ensure that the Massachusetts final budgets for S02 and NOx reflect the continued operation of and emissions from oil/gas steam and gas/oil combined cycle units. We believe the present IPM output results are inconsistent with existing and projected market trends that ISO-NE considers most likely in their regional system reliability planning. [EPA-HQ-OAR-2009-0491-3818.1_NODA, p.2]
Berkshire Power (ORISPL 55041)
Berkshire Power is a combined cycle unit consisting of an Alstom Power GT-24 combustion turbine, an unfired heat recovery steam generator, a condensing steam turbine generator. It is a single combined cycle unit. However, Berkshire Power combined cycle unit is divided into Units GEN 1 and GEN 2 and listed in NEEDS vA.10 as separate combined cycle units, Unit GEN 1 {55041_G_GEN1} 153 MWe and Unit GEN 2 {55041_G_GEN2} 79.1 MWe. [EPA-HQ-OAR-2009-0491-3818.1_NODA, p.3]
EPA should be consistent in its treatment of similar plant types in NEEDS vA.10 and future versions. NEEDS vA.10 lists four other similar combined cycle units in Massachusetts as single combined cycle units, without separately listing condensing steam turbine generators, despite their similarity to Berkshire Power. ANP Bellingham {ORISPL 55211} Unit 1 (55211_G_U1), Unit 2 {55211_G_U2}, and ANP Blackstone {ORISPL 55212} Unit 1 {55212_G_U1}, Unit 2 {55212_G_U2} are equipped with ABB GT-24 combustion turbines, unfired heat recovery steam generators, and condensing steam turbine generators, a largely identical configuration to Berkshire Power, but 55211_G_U1, 55211_G_U2, 55212_G_U1, and 55212_G_U2 are listed as single combined cycle units. [EPA-HQ-OAR-2009-0491-3818.1_NODA, p.3]
Cleary Flood (ORISPL 1682)
Both Units 9A and 9 are included in NEEDS vA.10 as separate combined cycle units, Unit 9A (1682_G_9A) and Unit CA9 (1682_G_CA9). However, they exist in an unusual combined cycle configuration, consisting of a combustion turbine Unit 9A, a General Electric Model No. MS-5001 - which exhausts otherwise lost waste heat exiting the combustion turbine into a conventional boiler - Unit 9, a Riley Stoker Model No. ISR-22. Units 9A and 9 share a common stack and should be considered a single combined cycle or other boiler, since all emissions are reported as Unit 9. Unit 9 is capable of producing 557,000 pounds per hour of 1,875 psig steam at approximately 1,000°F. This steam supply is directed into a steam turbine with a nameplate capacity of 90.0 MWe. [EPA-HQ-OAR-2009-0491-3818.1_NODA, p.5]
Unit 9A has a nameplate capacity of 24.0 MWe, with water injection the only installed pollution control device reported in the Operating Permit for this facility. The EPA CAMD database indicates Unit 9 commenced commercial operation on July 1,1975.
:: Unit 9A has a sulfur in fuel limit of 0.17 lb/MmBtu (heat input, HHV) applicable to No.2 Fuel Oil (310 CMR 7.04(9)), Units 9 and 9A are also subject to an S02 emission limit of 1.2 lb/MmBtu (heat input, HHV) which is a state only requirement (310 CMR 7.22(1)).
:: Unit 9A (firing Natural Gas or No.2 Fuel Oil) has a NOx emission limit of 512 tons per 12-month rolling average and fuel specific NOx emission limits of 65 ppmvd @ 15% O2 for Natural Gas and 100 ppmvd @ 15% O2 for No.2 Fuel Oil (310 CMR 7.19(7)(a)2.a, 2.b).
:: Unit 9 has a NOx emission limit of 1,268 tons per 12-month rolling average and 0.28 lb/MmBtu (heat input, HHV) applicable to Natural Gas or No.6 Fuel Oil firing (310 CMR 7.19(4)(a)3.b).
:: Units 9A and 9 in combined cycle operation have NOx emission limit of 0.28 lb/MmBtu and 1,636 tons per 12- month rolling average (310 CMR 7.19(4)(a)3.b). [EPA-HQ-OAR-2009-0491-3818.1_NODA, p.5]
Mystic Station (ORISPL 1558) and Fore River (ORISPL 55317)
There are discrepancies in the reported summer dependable capacities in NEEDS v.4.10 for similarly configured combined cycle units. NEEDS v.4.10 lists differing nominal output for Mystic 81-82 (1558_G_GT81, 1558_G_GT81) and 93-94 (1558_G_GT93, 1558_G_GT94) and Fore River Units 11-12 (55317 G_GT11, 55317 _G_GT12). However, they are identically configured combined cycle units. Each pair consists of: [EPA-HQ-OAR-2009-0491-3818.1_NODA, p.6]
:: two (2) Misubishi Heavy Industries 501G combustion turbines with heat recovery steam generators,
:: paired with a condensing steam turbine for a nominal output of 775 MWe.
However, in NEEDS v.4.l0 the summer dependable capacity differs between these power blocks:
:: Mystic 81-82 (1558_G_GT81, 1558_G_GT81) plus condensing steam turbine 85 (1588_G_ST85) are rated at 682 MWe, reducing the nominal output for this group by 93 MWe.
:: Mystic 93-94 (1558_G_GT93, 1558_G_GT94) plus condensing steam turbine 96 (1588_G_ST96), are rated at 678 MWe, reducing the nominal output for this group by 97 MWe.
:: Fore River 11-12 (55317 _G_GT11, 55317 _G_GT12) plus condensing steam turbine 15 (55317 _G_ST15) are rated at 776 MWe, which is approximately the reported nameplate capacity for this power block, 775 MWe. [EPA-HQ-OAR-2009-0491-3818.1_NODA, p.6]
The operator confirms that the Mystic 81-82 and Mystic 93-94 summer dependable capacity are near past reported summer claim capability audit test results submitted to ISO-NE. They, and we, cannot explain why Fore 11-12 has a reported summer dependable capacity of 775 MWe in NEEDS v4.10, when they have reported summer claim capability audit test results to ISO-NE of 690 MWe. It appears the Fore 11-12 could have been assigned the average of its recent winter (840 MWe) and summer (690 MWe) claimed capability audit results. Regardless, each of these power blocks, and all other included units, should have the reported capacities based on the same methodology. We have provided below what we believe to be the corrected nominal output capacity for each of the affected units for Column 0 (Capacity (MW)) of NEEDS vA.10. However, as noted earlier, MassDEP has significant concerns about EPA's use of net summer dependable capacity rather than nameplate capacity as defined in the proposed Transport Rule without restriction by seasonal or other deratings. [EPA-HQ-OAR-2009-0491-3818.1_NODA, pp.6-7]
Mirant Corporation
The ultimate effects on Mirant from the changes contemplated by the NODA are undecipherable (if not unknowable). It is unreasonable to seek comments on the NODA without presenting the precise effects that flow from the NODA (e.g., how many allowances would be allocated to each, unit). We are being asked to comment on a complex (yet incomplete) regulatory proposal that may have large financial implications on the electric industry and the consumers of electricity. [EPA-HQ-OAR-2009-0491-3826_NODA 1, pp.1-2]
As we stated in our previous comments, to avoid penalizing companies that have installed expensive control technology and to ensure that pollution control costs are shared equitably, allowances should be allocated based on heat input, as in past EPA programs. Alternatively, for EGUs located in Maryland, allowances could be based on the approach that the Maryland already adopted in the Healthy Air Act (HAA) and the accompanying regulations. EPA has approved the Healthy Air Act into the Maryland SIP, including the unit-specific tonnage limitations and the company system-wide compliance option. See 75 Fed. Reg. 51599 (Sep. 4, 2008). Thus, EPA has already approved the approach that Maryland has developed for allocating the burden of reducing EGU emissions in the State, and it would be arbitrary and capricious for the Transport Rule to be fundamentally inconsistent with the approach that EPA has already approved in the SIP. [EPA-HQ-OAR-2009-0491-3826_NODA 1, p.2]
National Grid
Correction to the NEEDS V4.10 Database
National Grid has reviewed both the 3.02 version as well as the 4.10 version of the NEEDS database. Since EPA will be using the 4.10 version going forward, we are providing specific comments on that version. Attached please find a revised copy of the NEEDS V4.10 database with corrections for the National Grid units. [[See Docket Number EPA-HQ-OAR-2009-0491-2583.2 for the attached file].  Additional columns have been added and those columns, as well as other corrections, have been highlighted in blue. We believe that this data represents the most accurate and current data that should be incorporated and used for all future modeling. [EPA-HQ-OAR-2009-0491-2583.1, p.1]
NOx Combustion Control (Column Z) - This column was revised to reflect the addition of Water Injection installed on Holtsville Units 6-10 in 2009. This control, which achieved an approximately 55% reduction in NOx emission rates, is designed to operate during the Ozone Season (May 1 through Sep 30).  [EPA-HQ-OAR-2009-0491-2583.1, p.1]
NOx Post Combustion Control (Column AA) - This column was revised to reflect Selective Catalytic Reduction (SCR) on Glenwood Landing (ORIS 7869) Units GT 4 and GT 5. These units were constructed in 2002 with SCRs as part of the original installation.  [EPA-HQ-OAR-2009-0491-2583.1, p.1]
SO2 Permit Emission Rate - Two columns have been added to the spreadsheet. The first column added provides SO2 emission rates (lbs/mmBtu) based on the most recent Percent Sulfur in Fuel Title V permit limitations. The second column added provides S02 emission rates based on the actual fuel being purchased and consumed at the facilities. For example, in 2005, in response to the NYS Acid Deposition Reduction Program, National Grid began purchasing residual fuel oil with a maximum sulfur content of 0.7% rather than the allowable 1.0% for our Northport (ORIS 2516) and Port Jefferson (ORIS 2517) facilities. Additionally, National Grid has been purchasing low sulfur kerosene for our Holtsville facility (ORIS 8007) and other small combustion turbine sites (as identified on the spreadsheet) to improve fuel combustion during startup. Since National Grid has been using these fuels for a number of years and is planning on continued use of these fuels in the future, we believe that it is appropriate for the EPA to use these SO2 emission rates in any modeling effort. At a minimum, EPA should be using the correct permitted emission rates. [EPA-HQ-OAR-2009-0491-2583.1, pp.1-2]
NOx Emission Rates - Over the past several years, National Grid has embarked on an aggressive NOx reduction program and has committed to install Separated Over Fire Air (SOFA) on all four steam electric boilers at our Northport facility (ORIS 2516) and on the two steam electric boilers at our Port Jefferson facility (ORIS 2517). Installation of SOFA was completed this past spring on Northport Unit 3 and Port Jefferson Unit 4. Results were very favorable, with NOx emission rate reductions of approximately 40% on gas and 20% on oil from our already low emission rates. National Grid believes that at a minimum, the vendor guaranteed emission rates should be used as the applicable emission rates in the EPA's modeling efforts. The in-service date schedule for SOFA installation on the other units is as follows: Northport Unit 4 (2011), Unit 1 (2012), Unit 2 (2013) and Port Jefferson Unit 4 (2011). Therefore, the emission rates reported for Northport Unit 3 should be used for the other three Northport units in the appropriate time frame, as well as using the Port Jefferson Unit 4 rates for Port Jefferson Unit 3 beginning in 2011. These rates have been identified in the revised NEEDS database attached as part of this submittal. Furthermore, in 2009, water injection was installed on the Holtsville (ORIS 8007) Units 6-10; a 55% reduction in NOx emission rates was realized and the reduced rates should be used for the May 1 -September 30 ozone period. [EPA-HQ-OAR-2009-0491-2583.1, p.2]
In addition to the installation of the control technology on these six boilers, National Grid has adopted an internal NOx minimization program for all its steam boilers. Each unit has a series of NOx target emission rates that are fuel and load specific. The operators are instructed to comply with these targets while operating the units. Their performance is evaluated quarterly and the NOx targets are evaluated and adjusted annually. This policy has resulted in a NOx reduction of 10-20% (varies by unit) since its implementation four years ago. The reductions achieved through this program are reflected in our corrections to the NEEDS database. [EPA-HQ-OAR-2009-0491-2583.1, p.2]
Three columns have been added to the attached spreadsheet. Since all of our steam electric boilers and the EF Barrett (ORIS 2511) combustion turbines are oil/gas capable, with significantly different fuel dependent emission rates, one column represents the corrected oil NOx emission rate and the other the corrected gas NOx emission rate. Changes to the other oil fired combustion turbine NOx emission rates were also added. [EPA-HQ-OAR-2009-0491-2583.1, p.2]
We have also indicated where we believe the existing data to be correct. The third added column contains comments explaining the changes. [EPA-HQ-OAR-2009-0491-2583.1, p.3]
However, a review of the Parsed File TR_SB_Limited Trading V4.10, raises additional concerns as to the model's ability to accurately reflect the operation of National Grid's units on Long Island. It appears that in this updated version, the EPA is modeling the Northport and Port Jefferson units on natural gas, but to reiterate the comment from above, the IPM model should develop a mechanism to more accurately represent gas/oil units.  [EPA-HQ-OAR-2009-0491-2583.1, p.3]
While it appears that the revised model uses the more appropriate fuel, an additional and more significant concern is how the IPM Version 4.10 is representing the utilization of the National Grid fleet as a supplier to meet the energy demand of Long Island. National Grid units are expected to provide 20-30% of the electrical demand on Long Island for 2014 and beyond. The results of the Parsed File TR SB-Limited Trading V4.l0 2014 results indicate the National Grid units will run only enough to generate 3-4% of the energy needs. National Grid believes that this inaccurate representation of our future operation may result from a lack of or inappropriate modeling of internal, detailed transmission constraints within Long Island. Furthermore, the local system operator may run on-island units uneconomically in order to ensure local reliability. National Grid recommends that the EPA either modify the model or correct the model results to more accurately portray actual and expected operation of these units. [EPA-HQ-OAR-2009-0491-2583.1, p.3]
National Mining Association (NMA)
NMA submits comments in three areas. First, the NODA states that EPA has prepared a new version 4.10 of the National Electric Energy Data System (NEEDS) and a new v.4.10 platform for the Integrated Planning Model (IPM) based on a number of changed assumptions, including as to natural gas availability and price. Although EPA states that these changed assumptions could result in changes to the state budgets in the proposed Transport Rule, EPA has not set forth how those budgets will change. As a result, at this point, the public is being asked to comment on a proposed rule that may be changed in unspecified but material ways from the previously proposed rule. Asking the public to comment on a proposed rule without setting forth important elements of that proposed rule contradicts the right of the public to fair notice and an opportunity to comment under Section 307(d) of the Clean Air Act (CAA) and other applicable rulemaking requirements. [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.1]
Second, EPA's natural gas assumptions are far too optimistic. For instance, although the Energy Information Administration (EIA) has a documented history of over-predicting natural gas supplies and under-predicting natural gas prices, EPA's shale gas assumptions are approximately three times higher than EIA's. EPA's overly ambitious shale gas assumptions have implications far beyond the Transport Rule, since the IPM model is used by EPA to formulate and inform an array of regulatory and policy choices. EPA's high shale gas assumptions may result in EPA policy decisions that will increase the country's dependence on natural gas for electric generation. If these assumptions prove to be wrong, which is likely to be the case, the country will be penalized with higher natural gas and electric prices and with increasing reliance on imports of liquefied natural gas (LNG) from countries that are hostile to the United States and at prices pegged to world oil prices. [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.2]
Third, information contained in the NODA document concludes that EPA's new natural gas assumptions will not result in the proposed Transport Rule causing fuel-switching from coal to natural gas. That conclusion, however, is wrong for the same reason that EPA was wrong in concluding that the proposed rule, using the original natural gas assumptions, would not result in fuel-switching. In both scenarios -- the original gas assumptions and the v.4.10 gas assumptions -- EPA's prediction that the rule won't cause fuel-switching is based on the assumed ability of utilities to comply with the rule through the installation of pollution control equipment and switching from high to low sulfur coal by the 2012 and 2014 compliance deadlines. But the targets and timetables in the rule are too stringent for utilities to meet solely by coal-switching and installing pollution controls. In fact, the rule will likely force utilities to close coal generation and substitute more costly gas generation, and the overall economic impact of this result will be masked by EPA's new and unjustified natural gas assumptions. [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.2]
EPA Does Not Provide Notice of and a Fair Opportunity to Comment on the Proposed Rule [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.2]
EPA recognizes that the new v.4.10 assumptions may affect the specific regulatory requirements that will be set forth in the final Transport Rule. But for reasons that EPA does not explain, EPA does not set forth how those regulatory requirements will change from the originally proposed version. [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.2]
If more gas is available at lower prices than projected in the proposed Transport Rule, as EPA now says will be the case, then presumably there will be more natural gas generation than previously projected and therefore the emissions from affected Electric Generating Units (EGUs) will change. Such changed emissions may change the attainment/nonattainment status of various downwind areas and the degree to which emissions from various upwind states may or may not significantly contribute to downwind nonattainment. As EPA states, [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.2]
[c]hanges from the projections relied on in the proposed rule, from using an updated model, could impact the final rulemaking in a number of ways including, but not limited to: [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.2]
1. Changing emission projections that were used to determine which downwind areas have air quality concerns (i.e., non-attainment or maintenance) absent this rulemaking and to determine which States contribute to those problems. [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.3]
2. Changing cost and emission projections used in the multi-factor test to determine the amount of emissions that represent significant contribution. [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.3]
As a result of these changes, the NOX and SO2 budgets set forth in the proposed Transport Rule, and the list of states that are in Group 1 versus Group 2, may be different from the proposed rule. Yet, despite the fact that the state budgets are the regulatory heart of the rule, setting forth the total amounts of SO2 and NOX that states and therefore sources can emit, EPA does not set forth what the new budgets are, assuming they are changed. As a result, the public was asked to comment by October 1 on a proposed rule that may now be obsolete, and it is now being asked to comment on a new methodology for determining what the new proposed rule will be without knowing what specific regulatory requirements these methodological changes will produce. [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.3]
Moreover, because EPA has not published the version of the rule that it is now proposing, EPA has not complied with any of the various statutory and Executive Order reviews to which the Agency is subject when it does rulemaking. All of such reviews set forth in the preamble to the proposed rule may now, like the rule, be obsolete. Critically, EPA's Regulatory Impact Analysis (RIA) may similarly be obsolete, and EPA has not published a new draft RIA to reflect any changes to the proposed rules. [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.3]
This state of affairs does not comport with elementary requirements for the agency to provide notice of and an opportunity to comment on its proposed rules under CAA § 307(d) and other applicable authority. EPA has no choice at this point but to repropose the rule so that the public may comment on it. [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.3]
Finally, on this point, NMA's comments on the rule as originally proposed argued that EPA must undertake a cumulative impact analysis of all the air quality and greenhouse gas rules that EPA intends to promulgate for the electric utility sector. Without such an assessment, the public is uninformed and cannot effectively comment on the overall, cumulative cost of EPA's regulatory agenda for the utility sector. [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.3]
The fact that EPA published the NODA without setting forth the new proposed Transport Rule that will result from the new v.4.10 database and modeling platform emphasizes even further EPA's failure to provide the public an adequate opportunity to comment on its utility sector agenda. When the Administration took office, one of the first actions the President took was to issue a memorandum on transparency and open government that stressed the desirability of full public participation in the rulemaking process. Failing to provide the public with a meaningful opportunity to comment on the proposed Transport Rule and its impacts does not comport with this policy. [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.3]
EPA's Shale Gas Assumptions Are Far Too Ambitious, Will Further Encourage Fuel-Switching from Coal to Gas, and Will Therefore Create Rising Energy Prices and Imperil the Country's Energy Security [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.4]
EPA's Optimistic Shale Gas Assumptions Represent a Risky Bet on an Unproven Resource [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.4]
EPA's shale gas assumptions are highly optimistic -- predicting approximately three times the shale gas availability as EIA, and EIA has historically over-predicted natural gas availability. It is widely understood that domestic natural gas production and Canadian imports will decline, and, before talk of a new shale gas 'paradigm,' it was widely assumed that the only way to offset these declines in the availability of conventional gas was through imported LNG. Now the natural gas industry claims that there has been a 'paradigm shift,' and that shale gas will be so low cost and abundant that it will more than compensate for declining conventional production. EPA through its new shale gas assumptions endorses these claims. [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.4]
But the new shale gas claims are just that -- claims. There is no long-term proven history of the type of large-scale shale gas development that the natural gas industry envisions. If these claims prove to be untrue, as so many claims as to natural gas availability have proven to be untrue in the past, then policies adopted in reliance on these claims will have caused further dependence of the utility sector on a diminishing resource, with negative consequences for the country. [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.4]
The fact that EPA proposes to incorporate these new optimistic assumptions as to shale gas into the v.4.10 IPM has ramifications far beyond just the Transport Rule. NMA has commented to EPA previously in this and other dockets that EPA has failed to adequately assess the degree to which its various air quality and greenhouse gas regulatory proposals are forcing a reduction in the use of coal for electric generation, with the result that the country will become increasingly reliant on natural gas. The v.4.10 IPM with EPA's new shale gas assumptions will now be used by EPA to formulate and analyze the effects of these various regulations on coal and gas usage and on the economy in general. The fact that these shale gas assumptions are three times more aggressive than EIA's will result in regulatory policies that will further discourage coal use and encourage the use of even more natural gas. [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.4]
About 90 percent of electricity in the United States is generated either by coal (49 percent), nuclear power (20 percent) or natural gas (21 percent). Coal and nuclear are the established baseload fuels with natural gas typically serving as an intermediate and peaking fuel. This combination has given the United States one of the most reliable and affordable electric power supply systems in the world, steadily increasing our quality of life and enabling manufacturers to be competitive at the global level. [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.4]
In large measure, this is because of coal's tremendous domestic abundance -- at 94 percent of U.S. proved fossil fuel reserves. [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.4]
[See p.5 of this comment summary for a table entitled, Fossil Fuel - U.S. Proved Reserves and U.S. proven fossil fuel reserves expressed as BOE]
Since 2000, however, more than 90 percent of constructed electricity generation capacity has been natural gas-based. At this pace, natural gas capacity will approach 500 GW by 2013, coal will near 350 GW and nuclear 108 GW. However, while natural gas will make up 50 percent of the name-plate capacity of the three fuels, it will only represent 24 percent of their actual generation because the capacity factor (the ratio of actual output and full-time operation at name-plate capacity) for natural gas power plants is about 35 percent, while coal is above 70 percent and nuclear 90 percent. For those reasons, natural gas is generally the last of the three fuels to be dispatched because it is consistently the most expensive and has the greatest price volatility. [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.5]
In the major report America's Energy Future, the National Academy of Sciences warned about the supply issues associated with further reliance on natural gas for power: 'it is not clear whether natural gas supplies at competitive prices would be adequate to support substantially increased levels of electricity generation.' The North American Electric Reliability Corporation also warned that '[c]ontinued high levels of dependence on natural gas for electricity generation in Florida, Texas, the Northeast, and Southern California have increased the bulk power system's exposure to interruptions in fuel supply and delivery.' [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.5]
Claims that shale gas represents a new paradigm shift that will enable the country to utilize ever increasing amounts of natural gas for electric generation at low prices fail to acknowledge that, according to EIA, shale gas increases will not offset other declines in other sources of natural gas supply as forecasted by EIA and as shown on the graph below. Indeed, even with shale gas development, overall natural gas supply is projected to decline by more than 4 percent by 2020. [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.6]
Since shale gas is the only substantial source of new domestic fossil fuel supply going forward, EPA actions in reliance on its new shale gas assumptions that lead utilities to fuel-switch to natural gas are a risky bet on shale gas production and price. This risk is all the more alarming because of the significant number of unknowns that surround shale gas production in regard to cost, sustainability, deliverability, reliability and environmental impact. [EPA-HQ-OAR-2009-0491-3732.1_NODA, p.6]
National Rural Electric Cooperative Association (NRECA)
NRECA indentified many problems with the CATR that have not been addressed in the NODA. Notably, the comment period for response to the CATR and now the NODA is not adequate to allow sufficient time to study and analyze the voluminous additional data contained in the NODA; and to construct meaningful comments. [EPA-HQ-OAR-2009-0491-3756.1_NODA, p.1]
And (4) aside from supplying additional information necessary to address the aforementioned, what additional information does EPA foresee adding to the rulemaking docket up to the time of CATR finalization? EPA states that additional information will be added. So why would such additions not be fundamental to the CATR as to necessitate a reopening of the comment period? [EPA-HQ-OAR-2009-0491-3756.1_NODA, p.3]
In conclusion, EPA is not free to propose anything it may deem desirable as a means of addressing interstate air pollution as it has done here. As NRECA has commented before in regard to the proposed CATR, EPA must give interested and affected parties adequate notice and opportunity to comment. EPA has not done that here. The NODA time limit for comment submittal is woefully inadequate, especially considering the volume and complexity of the additional information. The NODA itself adds more uncertainty to an already uncertain proposal by introducing this additional information without explaining its ultimate use in the promulgation of a final rule. EPA must initiate a supplemental proposal with its actual proposed state and unit emissions budgets for comment, something that it has not done yet. [EPA-HQ-OAR-2009-0491-3756.1_NODA ,p.3]
Nelson Industrial Steam Company (NISCO)
On September 1, 2010, EPA published the NODA indicating that EPA intends to use the IPM version 4.10 modeling, including a revised TR Base Case 2012 scenario, for revising the determinations of significant impact and interference with maintenance. Under the revised IPM TR v. 4.10 Base Case, projected emissions of SO2 from Louisiana EGUs are more than 20,000 tpy less than was projected under the IPM v. 3.02 version. (See Table below. [See p.3 of this comment summary for a table entitled, Comparison of TR Base Case v. 3.02 to TR Base Case v. 4.10 for Louisiana EGUs]) Based on this factor alone, because EPA's own data showed sulfate to be the culprit, it is believed that any revised air quality analysis based on the IPM v. 4.10 will demonstrate no impact whatsoever on Harris Co. PM2.5 levels. The same is true with respect to reductions of annual and ozone season NOx, EPA's revised IPM v. 4.10 Base Case 2012 model results show significant reductions in projected SO2 and NOx emissions that will occur even without implementation of the CATR/FIP (or CAIR). If these values are used in revised air quality modeling, it is virtually certain that the conclusion will be that Louisiana emissions do not impact the annual PM2.5 or 1997 8-hour ozone standards in Texas. 8 [EPA-HQ-OAR-2009-0491-3789.1_NODA, p.3]
Even without a revised air quality analysis, however, NISCO believes that use of the TR Base Case v. 4.10 data supports the conclusion that Louisiana should not be included in the CATR/FIP. The original CATR/FIP determined that a certain level of emission reductions from EGUs would remove 'significant contribution' and 'interference with maintenance.' The revised IPM v. 4.10 Base Case shows that emission reductions greater than that level will occur by 2012, even without CATR. The following table demonstrates this conclusion: [EPA-HQ-OAR-2009-0491-3789.1_NODA, p.3; See p.3 of this comment summary for a table entitled, Comparison of TR Base Case v. 3.02 to TR Base Case v. 4.10 for Louisiana EGUs]
Even without air quality modeling, these results demonstrate on their face that because the quantity of SO2 and NOx emissions that were required to be removed to prevent 'significant contribution' 'interference with maintenance' are now projected to be removed by 2012 through factors other than the CATR/FIP, there is no legal basis for a CATR/FIP for annual SO2 or annual or ozone season NOx control for Louisiana EGUs. [EPA-HQ-OAR-2009-0491-3789.1_NODA, p.4]
If Louisiana is still included under the CATR/FIP after revised modeling and air quality analysis, NISCO requests that EPA not use the IPM v. 4.10 (or any other version of the IPM) to make unit level allocations under the CATR/FIP. EPA should make SO2 and NOx allocations proportionate to the ratio of each unit's existing SO2 and NOx allocations to the state CAIR budgets already approved by both EPA and LDEQ. Although the court in North Carolina v. EPA struck down CAIR and required a revised look at the actual state budget needed to eliminate significant contribution or interference with maintenance, the court did not find any problem with the Louisiana (or other state's) unit level allocations. Louisiana DEQ, together with the Louisiana Public Service Commission, worked very hard on a fair allocation scheme for NOx allowances. This scheme was enacted into rule by the State after public notice and comment and was approved by EPA. [EPA-HQ-OAR-2009-0491-3789.1_NODA, p.4]
On September 27, 2006, the Louisiana Department of Environmental Quality (LDEQ) submitted a SIP revision to EPA adopting the CAIR SO2 Trading Program to address its 'good neighbor' obligations under CAA Section 110(a)(2)(D) with respect to the potential impact of Louisiana emissions on downwind PM2.5 receptors in the State of Alabama. EPA approved this SIP revision on July 20, 2007 at 72 Fed.Reg. 39741. 11 On July 12, 2007, LDEQ submitted a SIP revision to EPA adopting a SIP for a CAIR NOx Trading Program to address both the 1997 8-hour ozone standard and the 1997 annual PM2.5 standard. EPA approved this SIP revision on September 28, 2007 at 72 Fed. Reg. 55064. LDEQ submitted amendments to its NOx CAIR SIP on July 1, 2009, which are pending before EPA for decision. EPA, should base its allocation system as closely on these prior approved CAIR provisions as is possible. [EPA-HQ-OAR-2009-0491-3789.1_NODA, pp.4-5]
EPA lacks a credible rationale for premising its NOx and SO2 allocations on the IPM. This is an economic model that fails to account for real life conditions in Louisiana. The unit level allocation scheme (as distinguished from the state budget) has nothing to do with preventing significant contribution or interference with maintenance. In fact, huge economic inequities are being created with no underlying environmental reason. This is illustrated by the significant allowances that would be provided under IPM version 3.02 versus version 4.10. The following table shows a comparison of the allocations that NISCO would likely receive under each version as well as actual reported emissions to CAMD for 2009. [EPA-HQ-OAR-2009-0491-3789.1_NODA, p.5; See p.5 of this comment summary for a table showing the comparison of the allocations that NISCO would likely receive under each version as well as actual reported emissions to CAMD for 2009]
2009 was an unusual year as Boiler 1A had a turnaround during summer months. 2008 was a more representative year. In 2008, the total NOx emitted was 1580 tpy and ozone season NOx was 418 tpy for both Units 1A and 1B combined. [EPA-HQ-OAR-2009-0491-3789.1_NODA, p.5]
However, even assuming that 2009 emissions were representative, under the IPM v. 3.02, NISCO would have received allowances for SO2 that were short of 2009 actual emissions by 224 tpy; however, under IPM v. 4.10, the shortage would be 1795 tpy. (As 2009 was a relatively low emitting year, the shortage is actually greater.) The cost to NISCO would be significant to purchase allowances of SO2 or to retrofit. No retrofit to achieve the SO2 levels likely to be allocated under the v, 4.10 approach is technologically feasible, and certainly not within the time period proposed by EPA. NISCO's two boilers are pet-coke fired cogeneration units servicing industrial owners. As noted in its original comments, NISCO sells less than 1% of its electrical output to the grid, and in many years sells none. NISCO uses pet-coke from one or more of its owners as fuel, thus preventing waste of an otherwise valuable resource. There is no reason to presume that NISCO will be operating so much less under v. 4.10 than it was under v. 3.02. This 'economic' presumption, resulting from economic choices made by the model, does not align with how the NISCO facilities will actually operate. They will be operating the same as they always have in order to service their industrial joint venture owners. [EPA-HQ-OAR-2009-0491-3789.1_NODA, p.6]
Under the IPM v. 3.02, NISCO would have received annual NOx allocations in excess of its 2009 actual rate, but under version 4.10, the NOx shortage would be 237 TPY (again, assuming that 2009 represents a typical NISCO operating year). At an estimated $1200 per ton to purchase annual NOx allowances, this is over $284,000 in annual economic costs to NISCO. Compared to 2008 rates, the shortage would be 671 tons, so the annual costs are actually more like $671,000 per year if the v. 4.10 is used. [EPA-HQ-OAR-2009-0491-3789.1_NODA, p.6]
The NISCO units are already well controlled for NOx, with Unit 1A averaging an emission rate of 0.11 lb/MmBtu NOx and Unit 2A averaging 0.15 lb/MmBtu. There is no apparent reason, from an environmental viewpoint, that NISCO's allocations should differ so much from one version of the IPM to another. The primary difference must be due to the economic choices that the model selects...perhaps erroneously assuming that NISCO will not operate as much or that its owners would choose to purchase outside electricity rather than operate the units. However, due to the unique nature of this facility and its need to provide year round service to its three industrial owners, in the form of both steam and electricity, NISCO believes the IPM has made inaccurate assumptions about its operations. [EPA-HQ-OAR-2009-0491-3789.1_NODA, p.6]
It would be arbitrary and capricious for EPA to base its allocations on the IPM - either v. 3.02 or v. 4.10 given these facts. [EPA-HQ-OAR-2009-0491-3789.1_NODA, p.6]
EPA's approach for projected emissions inventories, as well as considerations of control technology under the IPM v. 4.10, eliminated the consideration of any reductions required by CAIR, due to the fact that the CAIR rule was overturned in North Carolina v. EPA, 531 F.3d 896, 901 (D.C. Cir. 2008). However, this results in overly conservative projections. The CAIR rule was remanded, but not vacated. Many regulated public utilities already invested in capital projects for reduction that were approved by their regulatory bodies and/or ratepayers. In most cases, legal obstacles would prevent the undoing of these projects. In addition, each physical project undertaken for purposes of CAIR reductions was of necessity permitted under an enforceable Title V permit. Those projects and permit limits cannot be relaxed without the facilities triggering Prevention of Significant Deterioration (PSD) rules. Triggering PSD would involve imposition of Best Available Control Technology, which, in most cases, would mean that the facilities would have to keep the pollution control equipment they installed for CAIR, or would have to meet even more stringent requirements. EPA should have undertaken a much more rigorous analysis for projecting what steps EGUs would take if CAIR were vacated completely, with no replacement. EPA has tools to easily accomplish this, such as a Clean Air Act Section 114 request for information. In short, EPA overestimated Base Case emissions for both 2012 and 2014 by eliminating all CAIR control requirements. [EPA-HQ-OAR-2009-0491-3789.1_NODA, pp.6-7]
The documentation for the IPM v. 4.10 does not clearly indicate whether EPA included only the grid-demand for electricity or also industrial facility demand. Section 3.2 of the Documentation for the EPA's IPM v. 4.10 Base Case tends to indicate that EPA considered only the grid-demand. This may have discounted the total electrical demand in Louisiana as many industries have cogeneration units. Some of these units provide power to the grid, as does NISCO. However, if EPA did not appropriately account for the fact that industries that partially self-generate need continuous and reliable electrical and steam output, then the IPM may make deficient economic choices in its selection of EGU behavior. [EPA-HQ-OAR-2009-0491-3789.1_NODA, p.7]
NISCO believes, for the reasons stated in the comments of the staff of the Louisiana Public Service .Commission (LPSC) on the proposed CATR/FIP, that the IPM fails to adequately consider transmission constraints within Louisiana. NISCO believes this is a deficiency in both the IPM v. 3.02 and v. 4.10. NISCO urges EPA to carefully consider the comments of the LPSC staff. [EPA-HQ-OAR-2009-0491-3789.1_NODA, p.7]
The Documentation for the IPM v. 4.10 Base Case, Chapter 3.5.1 indicates that EPA made certain assumptions about EGU availability in its modeling. EPA stated 'Power plant availability is the percentage of time that a generating unit is available to produce electricity to the grid. Availability takes into account both scheduled maintenance and forced outages...' EPA indicated that Appendix 3-9 shows the availability assumptions for all EGUs in EPA Base Case 4.10. In Appendix 3,9, EPA indicated that the 'availability' for the two NISCO units was as follows: [EPA-HQ-OAR-2009-0491-3789.1_NODA, p.7; see p.7 of this comment summary for a table showing the availability assumptions for the two NISCO units]
NISCO disputes these assumptions. NISCO must operate year round in order to service its industrial owners. Actual data submitted to EPA CAMD reflects NISCO's actual utilization of these units. NISCO requests that EPA revise these values to adequately reflect the quarterly data provided to EPA CAMD under the CAIR program. Further, NISCO requests that EPA correct the plant type from 'coal steam' to 'petroleum-coke'. [EPA-HQ-OAR-2009-0491-3789.1_NODA, p.7]
The documentation for the IPM v. 4.10 indicates that EPA continued an error that was also made in the IPM v. 3.02 Base Case with respect to existing environmental regulations. In Section 3.9.4 of the Documentation of EPA's IPM v. 4,10 Base Case, EPA listed the state rules that it included in the model. As indicated in NISCO's original comments, EPA improperly considered the Louisiana NOx Reasonably Available Control Technology rule in LAC 33:III.Ch. 22 reductions of NOx in the modeling used to project future impact. In Appendix 3-2.2, EPA had the following entry for Louisiana: [EPA-HQ-OAR-2009-0491-3789.1_NODA, p.7; see p.8 of this comment summary for an entry in Appendix 3-2.2 for Louisiana]
The cited rule does apply to NOX, but the information in the 'Emission Specifications' column is totally erroneous. The NOx emission limits are much lower than this, but different limits apply to different types of units. Further there are different limits for different parishes. NISCO requests that EPA update the model by using the actual limits of the rule, as set forth at LAC 33:III.Chapter 22, available at: http://www.deq.Louisiana.gov/portal/DIVISIONS/LegalAffairs/RulesandRegulations/Title33.aspx [EPA-HQ-OAR-2009-0491-3789.1_NODA, p.8]

11 Louisiana Department of Environmental Quality, Louisiana SIP Revisions, http://www.deq.louisiana.gov/portal/Default.aspx?tabid=2381.
Northern Star Generation LLC
In the event that EPA maintains its position that allowances be allocated according to EPA's projections of future unit dispatch, then errors in the NEEDS data bases and in the model assumptions must be corrected. One substantial error that Northern Star has noted is in EPA's assumed cost of waste coal as fuel. In reviewing fuel cost information for our waste coal facilities, we have concluded that EPA's estimate of fuel cost is at least double, and for one plant almost triple, the actual fuel costs we have incurred. Such a gross overestimate of fuel costs has no doubt contributed to EPA's projection that these plants will operate substantially less in the future then they have in the past. Northern Star will be providing comments on the notice of data availability (NODA) for NEEDS4.10 on or before the deadline of October 15, 2010. [EPA-HQ-OAR-2009-0491-2814.1, p.2]
The following table compares these historic heat rates during the past five years (2005 - 2009) to the heat rates projected by the Integrated Planning Model for future year 2014. [EPA-HQ-OAR-2009-0491-3728.1_NODA, p.2; See p.2 of this comment summary for a table comparing historic heat rates during the past five years to the heat rates projected by the IPM for future year 2014]
The IPM heat input projections used by EPA for the year 2014 represent substantial reductions from the average heat input over the past five years. The projected heat input for Unit 1 is approximately 15% lower than the historic average whereas the projected heat input for Unit 2 is more than 22% lower than the historic average. We believe that this is largely due to errors in the NEEDS 4.10 data base that were the basis for the IPM v4.10 model outputs. [EPA-HQ-OAR-2009-0491-3728.1_NODA, p.2]
Based on our understanding of how EPA is using IPM to predict future unit dispatch rates, the key input parameters are availability, unit heat rate, and fuel costs. Cambria has been assigned an annual availability factor of 95% in NEEDS 4.10. Over the past five years (2005-2009) as reported to EPA's Clean Air Markets Division (see Attachment 1 to this letter [See p.8 of this comment summary for Attachment 1 entitled, Operating Hours at Cambria Cogen (2005 to 2009) As Reported to CAMD), both Units 1 and 2 at Cambria have averaged operating more than 96.5% of all possible hours. As such, the NEEDS 4.10 assumption of 95% availability is slightly underestimating historic plant availability. [EPA-HQ-OAR-2009-0491-3728.1_NODA, p.2]
A major error in the NEEDS 4.10 data base is the assumption of heat rate for these two units. The assumed heat rates used by EPA for the two Cambria units (which are identical CFB boilers) are 11,076 Btu/kWh for Unit 1 and 10,331 Btu/kWh for Unit 2. It is not clear how these unit heat rates were derived, but it is interesting to note that there are several other Pennsylvania units in NEEDS 4.10 that have heat rates of exactly 10,331 Btu/kWh and at least one other unit that has a heat rates of exactly 11,076 Btu/kWh. This seems highly improbable. Of more importance, is the actual historic heat rate that has been achieved in practice at Cambria. Attachment 2 [see p.9 of this comment summary for  Attachment 2 entitled, Plant Wide Net Heat Rate Cambria Cogen 2006 to Present] to this letter shows the plant heat rate (i.e., combined heat rate for Unit 1 and Unit 2) by month since 2006. The monthly heat rates have been as low as 11,699 Btu/kWh and as high as 13,060 Btu/kWh and over this entire period have averaged 12,200 Btu/kWh. At no time has the plant heat rate ever approached even the higher of the EEDS 4.10 values let alone a heat rate as low as 10,331 Btu/kWh. Clearly, the assumption of a much lower heat rate than is being achieved in practice has led to a substantial underestimate in future heat input to the Cambria units. [EPA-HQ-OAR-2009-0491-3728.1_NODA, pp.2-3]
Fuel costs are used in the IPM model to estimate the cost of generating power. In the TR Base Case Summary Report, EPA has made an assumption that the cost of waste coal will be $2.27/MmBtu in 2012 and increase slightly in years after that. As mentioned earlier in this letter, Cambria Cogen owns the waste coal piles that are the exclusive source of fuel for the plant. The cost of fuel supplied from these piles is simply the cost of the mining operations and transportation of fuel to the power plant. These costs are considerably lower than the EPA assumption. In 2009 Cambria expended slightly more than $7.3 million to supply approximately 8.9 TBtu of fuel to the power plant, resulting in fuel costs of $0.82/MmBtu. Assuming an annual inflation rate of 3%, this would result in an expected cost of fuel of $0.90/MmBtu in 2012. This is less than half the projected fuel costs being used by EPA. It should be added that these costs also include the cost of transportation and placement of ash for reclamation purposes at the waste coal mining sites. [EPA-HQ-OAR-2009-0491-3728.1_NODA, p.3]
Conclusions/Recommendations for Cambria Cogen [EPA-HQ-OAR-2009-0491-3728.1_NODA, p.3]
EPA has dramatically underestimated future heat input and, as a result, future emissions from Cambria Cogen. This appears to be primarily due to a substantial underestimate in the heat rate of the two boiler units at Cambria. This has resulted in a large underestimate in the amount of projected future heat input and emissions from Cambria. It should also be noted that the cost of waste coal as the fuel for Cambria has been overestimated by more than a factor of two. This means that despite the higher heat rate, the cost of generating power at Cambria is much lower than estimated by EPA. [EPA-HQ-OAR-2009-0491-3728.1_NODA, p.3]
Northern Star recommends that EPA make the following corrections for Cambria Cogen to the NEEDS 4.10 database and the input assumptions to IPM: [EPA-HQ-OAR-2009-0491-3728.1_NODA, p.3]
Change the annual availability for both units from 95% to 96.5%, consistent with historical performance. [EPA-HQ-OAR-2009-0491-3728.1_NODA, p.3]
Change the unit heat rates in NEEDS 4.10 to 12,220 Btu/kWh for both Unit 1 and Unit 2. [EPA-HQ-OAR-2009-0491-3728.1_NODA, p.3]
Change the fuel cost from $2.27/MmBtu in 2012 to $0.90/MmBtu. [EPA-HQ-OAR-2009-0491-3728.1_NODA, p.3]
Colver [EPA-HQ-OAR-2009-0491-3728.1_NODA, p.4]
The Colver Power Project ('Colver') is a 110 MW (net) waste coal power plant located near Colver, Pennsylvania. Colver utilizes a single circulating fluidized bed (CFB) boiler unit. Colver produces electric power for sale under the terms of a power purchase agreement (PPA) with Pennsylvania Electric Company (Penelec) that runs until March 2020. Colver utilizes waste bituminous coal (gob) from a number of sources, most of which are mining sites owned and/or leased by the Colver partnership (Inter-Power AhlCon Partners). Colver has always operated as a base load facility and has had high historic availability and capacity factors. This is reflected in the plant annual heat input values as reported to EPA as part of the required Part 75 Continuous Emission Monitoring (CEMS) reports. The following table compares these historic heat rates during the past five years (2005 - 2009) to the heat rates projected by the Integrated Planning Model for future year 2014. [EPA-HQ-OAR-2009-0491-3728.1_NODA, p.4; see p.4 of this comment summary for a table comparing historic heat rates during the past five years to the heat rates projected by the IMP for future year 2014]
The IPM heat input projection used by EPA for the year 2014 represents substantial reductions from the average heat input over the past five years. The projected heat input for Colver is approximately 17.5% lower than the historic average. We believe that this is largely due to errors in the NEEDS 4.10 data base that were the basis for the IPM v4.10 model outputs. [EPA-HQ-OAR-2009-0491-3728.1_NODA, p.4]
Based on our understanding of how EPA is using IPM to predict future unit dispatch rates, the key input parameters are availability, unit heat rate, and fuel costs. Colver has been assigned an annual availability factor of 76.6% in NEEDS 4.10. We believe that this low availability factor was based on the NEEDs data for 2006. In 2006, Colver had an extended outage related to its steam turbine generator that required the plant to be down for six weeks. In typical years, the planned outage durations are two to three weeks. As a result, the plant availability in 2006 was uncharacteristically low. This is evident when one examines the heat input in the above table. Using operating hours as a surrogate for availability (see Attachment 3 [see p.10 of this comment summary for Attachment 3 entitled, Operating Hours at Clover Power Project (2005 to 2009) As Reported to CAMD]) it can be seen that in the years 2005, and 2007-2009, the availability averaged 95.4%.. As such, the NEEDS 4.10 assumption of 76.6% availability is significantly less than historic plant availability. [EPA-HQ-OAR-2009-0491-3728.1_NODA, p.4]
The plant heat rate used by EPA for Colver is 10,994 Btu/kWh, which is somewhat lower than the heat input that the plant has actually achieved in recent years. In combination with the underestimate of plant availability, this has led to a significant under prediction of future heat input for Colver. The average heat rate achieved by Colver over the period 2005 through 2009 was 11,083 Btu/kWh, as shown in attachment 4 [see p.11 of this comment summary for Attachment 4 entitled, Historic Net Heat Rate Colver Power 2005 to Present] to this letter. It should be noted that due to the efforts of the plant operating personnel, improvements to heat rate have been seen during this period. However, thus far in 20 I0 heat rate has increased somewhat and we feel that the five year average heat rate of 11,083 Btu/kWh is a fair representation of the plant heat rate now and going forward. [EPA-HQ-OAR-2009-0491-3728.1_NODA, p.5]
Fuel costs are used in the IPM model to estimate the cost of generating power. In the TR Base Case Summary Report, EPA has made an assumption that the cost of waste coal will be $2.27/MmBtu in 2012 and increase slightly in years after that. As mentioned earlier in this letter, Colver owns the waste coal piles that are the primary source of fuel for the plant. The cost of fuel supplied from these piles is simply the cost of the mining operations and transportation of fuel to the power plant. Colver does purchase some fuel from third parties, but only when this fuel can be obtained at less than the costs for mining at the sites owned or leased by the plant. These costs are considerably lower than the EPA assumption. In 2009 Colver expended slightly less than $12.4 million to supply approximately 9.7 TBtu of fuel to the power plant, resulting in fuel costs of $1.28/MmBtu. Assuming an annual inflation rate of3%, this would result in an expected cost of fuel of $1.39/MmBtu in 2012. This is 40% lower than the projected fuel costs being used by EPA. It should be added that these costs also include the cost of transportation and placement of ash for reclamation purposes at the waste coal mining sites. [EPA-HQ-OAR-2009-0491-3728.1_NODA, p.5]
Conclusions/Recommendations for Colver Power [EPA-HQ-OAR-2009-0491-3728.1_NODA, p.5]
EPA has dramatically underestimated future heat input and, as a result, future emissions from Colver Power. This appears to be primarily due to a substantial underestimate in the availability of the facility due to the selection of an unrepresentative operating year for this parameter. This has resulted in a large underestimate in the amount of projected future heat input and emissions from Colver. It should also be noted that the cost of waste coal as the fuel for Colver has been overestimated by 40%, which means that the cost of generating power at Colver is much lower than assumed by EPA. [EPA-HQ-OAR-2009-0491-3728.1_NODA, p.5]
Northern Star recommends that EPA make the following corrections for Colver Power Project to the NEEDS 4.10 database and the input assumptions to IPM: [EPA-HQ-OAR-2009-0491-3728.1_NODA, p.5]
Change the annual availability for the plant from 76% to 95.4%, consistent with historical performance. [EPA-HQ-OAR-2009-0491-3728.1_NODA, p.5]
Change the unit heat rates in NEEDS 4.10 to 11,083 Btu/kWh. [EPA-HQ-OAR-2009-0491-3728.1_NODA, p.5]
Change the fuel cost from $2.27/MmBtu in 2012 to $1.39/MmBtu. [EPA-HQ-OAR-2009-0491-3728.1_NODA, p.5]
Comments on Future Emission Rates [EPA-HQ-OAR-2009-0491-3728.1_NODA, p.5]
EPA has projected future emission rates of NOx and SO2 for both Cambria and Colver that are considerably lower than their historical emission rates. Apparently, EPA views these as emission rates that can be achieved using cost effective controls. Both Cambria and Colver are facilities that already achieve high levels of emission control, utilizing SNCR for NOx control, limestone injection for control of SO2 and acid gases, and a fabric filter baghouse for control of particulate matter. [EPA-HQ-OAR-2009-0491-3728.1_NODA, p.6]
EPA projects a future NOx emission rate of 0.089 to 0.092 lb/mmBtu for these two plants. Although both plants are technically capable of reaching this emission rate with a sufficient amount of additional ammonia injection, there are environmental issues that may prevent this level of emission control to be continuously maintained. Both Cambria and Colver have a permit limit for ammonia slip (5 ppmv) that could be exceeded if too much ammonia is injected, leading to increases in un-reacted ammonia in the flue gas. In addition, Cambria Cogen has observed that while operating at high levels of ammonia injection in cold weather a visible plume can be observed from the stack that may be in violation of the plant's opacity limit. Given these factors, both plants consider 0.11 lb/MmBtu to be the lowest emission rate that can be maintained on a continuing basis. It is not clear whether EPA expects the plants to achieve the lower emission rate with additional controls (such as SCR), but if so, it is highly unlikely that such a retrofit would meet EPA's cost effectiveness assumption of$500/ton. EPA-HQ-OAR-2009-0491-3728.1_NODA, p.6]
EPA has projected SO2 emission rates of 0.336 - 0.385 lb/mmBtu at Cambria and 0.355 lb/mmBtu at Colver in 2012, and lower SO2 emission rates for 2014 and thereafter (0.32-0.33 lb/mmBtu at Cambria; 0.305 lb/mmBtu at Colver). Again, it appears that EPA considers these to be emission rates that are achievable using cost effective controls. Both Cambria and Colver utilize limestone injection to control SO2 and are required in their Title V permits to achieve at least 92% emission control. Historically, Cambria has averaged SO2 emissions of about 0.6 lb/mmBtu while Colver has averaged around 0.5 lb/mmBtu. The differences between the SO2 emission rates at the two plants are primarily due to differences in sulfur content of the fuel being used. EPA-HQ-OAR-2009-0491-3728.1_NODA, p.6]
Additional control of SO2 (i.e., above 92%) is theoretically possible through increasing the rate of limestone injection to the boilers. However, there are diminishing returns associated with attempts to control using this approach. The additional limestone injected requires additional fuel to be fired in order to calcine the limestone. This increase in fuel fired increases emission of NOx and other pollutants. Also, there are physical limitations to the quantity of fuel, ash, and limestone that these boiler units are capable of accommodating. As such, we believe that the minimum emission rate that these plants are capable of attaining using their currently available fuel to be in the range of 0.40 to 0.45 lb/mmBtu. It is not clear what cost effective technologies EPA believes is applicable to these facilities that would produce SO2 emission rates as low as 0.30 lb/mmBtu. EPA-HQ-OAR-2009-0491-3728.1_NODA, pp.6-7]
Occidental Chemical Corporation (OCC)
We are continuing to review the revised modeling platform, which is quite complex, and we may submit comments on the revised modeling by the October 15, 2010 deadline. However, as will be evident from our comments set forth below, the results of the modeling platform provide a substantial portion of EPA's technical basis for the allocation of unit-level emissions allowances to implement the proposed rule and we are providing preliminary comments on the revised platform today. Despite the fact that revisions to the modeling platform were not made public until half-way into the 60-day comment period on the proposed rule, EPA denied our request for an extension of time to provide comments on the proposed rule published on August 2, 2010. [EPA-HQ-OAR-2009-0491-2754.1, p. 2]
Problems with Data Inputs to the Model We have reviewed the proposed rule and associated technical support documents, modeling outputs and data, and we have significant concerns relating to this information. With regard to the information contained in the Budgets and Allocations - Detailed Unit-Level Data, NEEDS V 4.10, and Parsed File TR Base Case data files, our concerns are set forth below: [EPA-HQ-OAR-2009-0491-2754.1, p. 19; see pp 19-20 for discussion of the following topics: The La Porte cogeneration facility is not listed in any of the documents or data analyses prepared by the Agency; and The NEEDS Version 4.10 data base and the Parsed File Transport Rule Base Case for 201235 contains erroneous information]
Oglethorpe Power
The released information is a substantially revised new data set that (as best Oglethorpe Power can tell) changes virtually every aspect of the Proposed Transport Rule. Refusing to extend the comment period for the proposed rule, despite numerous requests from commenters, EPA provided a 45-day deadline, running concurrently with the comment period for the formal proposal, ending a mere 15 days later, within which to respond on the record to the NODA. As a result, EPA has failed to provide adequate time for commenters to meaningfully respond to the NODA. [EPA-HQ-OAR-2009-0491-3753.1_NODA, p.3]
In addition, EPA has failed to provide the data necessary for the preparation of responsive, robust and comprehensive comments. Much of the information necessary to properly evaluate the nature and extent of changes that are likely to the Proposed Transport Rule, due to the new information in the NODA, is conspicuously absent from the docket. [EPA-HQ-OAR-2009-0491-3753.1_NODA, p.3]
EPA provided the results of 48 IPM runs to support the Proposed Transport Rule, but has provided only 8 to support the NODA. The results from many of those 48 runs were essential to understanding the rule (and to prepare responsive comments to it). For example, EPA failed to provide key summary tables in the NODA that were derived and listed in the proposal and/or the rulemaking docket. Comparable runs/results are needed to understand fully and comment meaningfully on the NODA - especially on the unit-level allocations. Thus, the Corporation is unable to meet EPA's request that allocations be reviewed in the detail needed to identify all substantial errors and inaccuracies - rather, Oglethorpe Power is left with guessing what those values will be under the NODA. This is not proper notice-and-comment rulemaking, and a supplemental notice of proposed rulemaking will be required to fulfill EPA's obligations for proper public review and comment under applicable law. [EPA-HQ-OAR-2009-0491-3753.1_NODA, pp.3-4]
Missing Data [EPA-HQ-OAR-2009-0491-3753.1_NODA, p.4]
Notwithstanding the difficulty in evaluating unit-level allocations, Oglethorpe Power has identified some specific problems with the data EPA might use pursuant to the NODA to calculate allowance allocations for its units in the final rule. The first category deals with missing 2008 heat input, and is similar to the problem first identified in the unit allocations in the Proposed Transport Rule. The table below [see pp.4-5 of this comment summary for a table summarizing the errors that can be caused by mission heat input data for 2008, for annual NOx emissions, broken out by the Corporation's units] summarizes the errors that can be caused by missing heat input data for 2008, for annual NOx emissions, broken out by the Corporation's units. [EPA-HQ-OAR-2009-0491-3753.1_NODA, p.4]
The 'X' entries in the above table indicate missing data for 2008 annual heat input. The missing heat input data prevents the assigning of NO, annual allowances to the units listed above. EPA should revisit its annual heat input data for these units and true up its determinations as needed. Based upon Oglethorpe Power's analysis, this error would result in Oglethorpe Power's units being allocated 87 less NOx annual allowances than should otherwise be the case, if the NODA data was corrected to reflect actual heat input for the units listed above. The missing allowances were computed using 2009 annual NOx emission rates from EPA's CEMS Data Base. EPA states that it intends to use 2009 NOx Rates in IPM v. 4.10. 75 Fed. Reg. at 53614. [EPA-HQ-OAR-2009-0491-3753.1_NODA, p.5]
IPM Projections [EPA-HQ-OAR-2009-0491-3753.1_NODA, p.5]
Another problem involves EPA's IPM runs, which project unit by unit heat input. For the majority of its generating units, EPA's projections are significantly lower than Oglethorpe Power's 2014 projections. In several instances, EPA's projections are more than an order of magnitude less than the Corporation's projections. These discrepancies highlight a point made in our comments on the Proposed Transport Rule. EPA's use of computer model projections of future individual unit utilization and emission reduction capability, as the basis for permanent unit allocations will unnecessarily result in gross inequities in the allocation of allowances. Any model, including IPM, will fail to consider all of the variables (many of which are today unknown) that will determine utilization and installation of control equipment in upcoming years. Regardless of the purported sophistication of EPA's IPM, it does not and cannot accurately forecast how each and every fossil fuel-fired unit in the Transport Rule's 32 state trading areas will be utilized, or what the future costs and results will be in meeting the emission reduction obligations dictated by the model. Therefore, EPA should use an approach like that taken in the final CAIR NO, allocation program, where allocations to all existing units were based on historical data for each unit over a period of years. An approach that periodically updates allowance allocations, based on how units have actually operated in the recent past is the only way to be fair to all EGUs that will be subject to the rule. [EPA-HQ-OAR-2009-0491-3753.1_NODA, p.5]
Ohio Utility Group (OUG)
The Utilities applaud EPA's effort to refine the proposed Transport Rule before final promulgation. In theory, the NODA is a constructive supplement to the Transport Rule. However, even after updating the data and modifying the modeling platform, inaccuracies linger and the proposed Transport Rule remains fundamentally flawed. Furthermore, EPA falls short of providing the information necessary to evaluate the impact of, and comment on, the mass of information provided pursuant to the NODA. [EPA-HQ-OAR-2009-0491-3761.1_NODA, p.2]
The magnitude of such a lost opportunity may be typified by peaking units throughout the industry. For example, EPA's planned IPM re-run will use somewhat higher coal prices, somewhat lower natural gas prices, and a reduced forecast of electric generation. Small peaking units, like Dayton Power and Light's ('DP&L') Hutchings facility, are first on the chopping block to receive less allocations. DP&L has an even greater - and legitimate - concern. the Hutchings Station, which received a small number of allocations under the proposed rule, may be dropped from the solution and receive zero allocations based on the updated modeling assumptions in the NODA. All the while DP&L was held in the dark without the opportunity to comment and, should the updated model drop Hutchings, DP&L would experience irreparable loss. The Utilities assert that the Transport Rule - including the supplemental information - is a deficient proposal and suggest that EPA take the steps necessary to generate this information, apply it to the proposed rule, provide the state budgets and unit allocations (which are almost certain to change), and then re-submit the rule for comment. [EPA-HQ-OAR-2009-0491-3761.1_NODA, p.2]
I. EPA's Investigative and Reevaluation Process is Incomplete, Thereby Denying the Utilities of Critical Information and, Ultimately, of a Meaningful Opportunity to Comment on the NODA. Therefore, EPA Must Finish the Process It Started and then Re-submit the Rule for Comment.
In their comments on the Transport Rule, the Utilities stressed the importance of utilizing the most accurate data, especially when attempting to regulate at the unit level. While EPA has taken a step in the right direction to acquire accurate data, the task is incomplete. The investigative and reevaluation process which EPA initiated through the NOD A cannot be considered a cure-all as a one-time procedure. Rather, it must be an ongoing process, performed until accuracy can be confirmed with reasonable certainty. The Utilities will demonstrate that EPA is far from confirming accuracy. [EPA-HQ-OAR-2009-0491-3761.1_NODA, p.2]
As an initial matter, the Utilities have been denied a meaningful opportunity to comment on the effects of the information submitted pursuant to the NODA. Ironically, what the NODA is purported to provide - information to support the final rule - the NODA lacks in quantity and quality. EPA acknowledged the substantial impact that the updated information will have on the final rule stating that the changes resulting from using the updated information could: [EPA-HQ-OAR-2009-0491-3761.1_NODA, p.2]
1. Change emission projections that were used to determine which downwind areas have air quality concerns ... absent this rulemaking and to determine which States contribute to those problems. [EPA-HQ-OAR-2009-0491-3761.1_NODA, p.2]
2. Change cost and emission projections used in the multi-factor test to determine the amount of emissions that represent significant contribution. [EPA-HQ-OAR-2009-0491-3761.1_NODA, p.3]
EPA has not provided this information. Most notably, EPA plainly stated that, under the new IPM runs, 'the [state] caps have not been modified to account for any changes that the new modeling might suggest; they are merely provided for informational purposes.' The Utilities have been unable to discern what informational purposes EPA is suggesting. [EPA-HQ-OAR-2009-0491-3761.1_NODA, p.3] 
The lack of any substantial gain from the information in the NODA stems from EPA's failure to carry out its processes in such a way that would produce useful results. Although there were several IPM runs that EPA did not complete in the NODA which were completed for the proposed rule, the failure to perform a 2012 Parsed File run based on the updated NEEDS database and IPM platform was most damning. As a result, the unit-specific information needed to calculate 2012 state budgets is missing. Without state budgets, or any additional guidance, it is impossible for the Utilities to calculate unit-level allocations. Buckeye Power Inc.'s Robert P. Mone facility is a prime example of the impetus to provide affected companies with complete information. The Mone facility is a peaking station, critical to grid reliability. Under the proposed Transport Rule, Mone was allocated zero NOx allowances - an unreasonable allocation with the potential to cut grid reliability in the area the facility services. Under the NODA, it appears that Mone would be granted some allowances, but the lack of information prevents Buckeye from determining the exact allocation and commenting on the appropriateness of such allocation. [EPA-HQ-OAR-2009-0491-3761.1_NODA, p.3]
Given the fact that one change of data input, which EPA admits could substantially affect the overall analytical construct of the rulemaking, it would be an exaggeration to state that any of EPA's last minute updates 'should have been anticipated ... as a logical outgrowth of EPA's earlier statements.,, With that, the Utilities contend that finalizing the Transport Rule without providing an additional opportunity to comment constitutes an arbitrary rulemaking. The Utilities urge EPA to complete a thorough investigation ensuring that the most accurate data is being used, conduct additional runs through an updated modeling platform, evaluate the entire rule based on those results, and then re-submit the proposed rule for comment. [EPA-HQ-OAR-2009-0491-3761.1_NODA, p.3]
II. Information in the NODA Failed to Correct Several Data Base Errors and Modeling Disconnects
In addition to the information produced pursuant to the NODA being incomplete, much of that information is still incorrect. The NODA, in itself, is an affirmation that the proposed transport rule is plagued with mistakes. As detailed below, and buttressed by the fact that EPA has committed to make additional 'updates,' many mistakes are yet to be addressed. It is apparent that the comments submitted on the Transport Rule were not considered when EPA updated the NEEDS database and IPM platform as many of those same mistakes appear in the updated version. Other data inaccuracies went from bad to worse. And some faulty assumptions present inexplicable modeling disconnects. [EPA-HQ-OAR-2009-0491-3761.1_NODA, pp.3-4]
The Ohio Valley Electric Corporation ('OVEC') is one member company that discovered faulty data that remained unchanged. The data used in the proposed rule indicated that OVEC's Kyger Creek facility has an FGD system in place as of 2010. OVEC identified the mistake in its Transport Rule comments, and explained that the system will not be completed until 2012. The updated version of the NEEDS database still shows Kyger Creek having an FGD system in place as of 2010. [EPA-HQ-OAR-2009-0491-3761.1_NODA, p.4]
Several other member companies have identified data inaccuracies which must be corrected before the Transport Rule is finalized. The American Electric Power system ('AEP') Conesville Unit 3 is missing entirely from the NEEDS database. Buckeye Power's Cardinal Unit 3 is also miscredited with the installation of a wet scrubber. Data corrections are also required for AEP's Cardinal Unit 1 and Buckeye's Cardinal Unit 2. The scrubbers at both units are non-dispatchable because they are included in a NSR decree, and the Cardinal Unit 2 does currently have a wet scrubber installed and in operation. [EPA-HQ-OAR-2009-0491-3761.1_NODA, p.4]
The modeling disconnects - where outputs are inconsistent with their inputs and with themselves - that appear in the NODA are most peculiar. For example, the scrubber that is incorrectly assumed at Kyger Creek in 2010 disappears in the modeling outputs for 2012.8 Buckeye also objects to the significant reduction in the S02 emission rates for its Cardinal units. The S02 emission rate in the NEEDS v.3.02 was 0.218 lbs/mmBtu as compared to 0.087 lbs/mmBtu in the NOD A. Finally, AEP determined that several of AEP's units were assigned emission rates that are feasible only upon the assumption that the units bum subbituminous coal. However, these units cannot bum the low sulfur coal without significant operational limitations or the addition of control equipment not assumed in the NODA. [EPA-HQ-OAR-2009-0491-3761.1_NODA, p.4]
State budgets, unit allocations and, ultimately, the control equipment companies will be required to install to comply with the Transport Rule are inextricably linked to the accuracy of data inputs and modeling outputs. Furthermore, the fact that some of the mistakes in the original proposal carried over to the 'updated' information in the NODA supports the Utilities' request that EPA re-submit the proposed Transport Rule for comment after EPA has made the necessary corrections. Emphasizing deadlines - final promulgation and compliance dates - over completeness and accuracy would be a(nother) grave miscalculation with a detrimental impact on the entire industry. [EPA-HQ-OAR-2009-0491-3761.1_NODA, p.4]
III. The Information in the NODA Did Nothing to Address the Fundamental Flaws of the Proposed Transport Rule
Even if EPA corrected every data inaccuracy and faulty assumption, the proposed Transport Rule would remain flawed. The importance of factual accuracy was demonstrated in the preceding sections - data input controls modeling output. However, a rule must be fundamentally sound before any data can be applied. The information in the NODA was purely factual and, thus, did nothing to the structure of the proposed rule itself. In this final section, the Utilities reiterate three fundamental flaws of the proposed Transport Rule that must be considered before finalizing the rule. [EPA-HQ-OAR-2009-0491-3761.1_NODA, pp.4-5]
A. The IPM model is inadequate for EPA's chosen bottom-up methodology
Many of the faulty assumptions seen throughout the proposed Transport Rule and the NODA are a direct result of EPA's use of the IPM model for determining unit-specific emissions controls. EPA's attempted 31-state RACT is a problem in itself and will be discussed in the following section, but the use of the IPM model to do so magnifies the problems associated with EPA's unlawful unit-level regulation. [EPA-HQ-OAR-2009-0491-3761.1_NODA, p.5]
The IPM model is designed for broad regional modeling. IPM's metrics and algorithms lack the precision to model every significant source in the Eastern United States. The model cannot, and does not, take into account all the unit-specific operating constraints needed to provide accurate output data. The negative impact of IPM's improper use for purposes of this rulemaking is two-fold. First, the industry cannot rely on the output data, thereby preventing adequate preparation for compliance. Second, unit allocations are improperly distributed. [EPA-HQ-OAR-2009-0491-3761.1_NODA, p.5]
The Utilities have been choked by the IPM's lack of precision. Compared to historical operating data (accurately reflecting unit-specific operational tendencies and limitations), the information in the NOD A shows units being unreasonably constrained. The NOx emissions rates will be almost impossible to achieve in many cases. For example, information in the NODA lists baseline NOx emission rates below that which Kyger Creek has been able to achieve based on historical data. All of OVEC's units are wet-bottom boilers and, thus, cannot meet the proposed NOx targets even with EPA's assumed NOx controls unless all eleven of OVEC' s units underwent complete structural re-construction. Similarly, The Dayton Power and Light Company's Stuart Station was listed as being able to achieve 0.06 lbs/mmBtu yet the historical data submitted by DP&L for recent years shows that the Stuart Station is only capable of achieving 0.12 lb/mmBtu. IPM's use of a single test year and failure to consider historical and projected operations has positioned the Utilities for failure. Buckeye's Cardinal Unit No.3 was assigned a miniscule NOx rate of 0.023 lbs/mmBtu primarily due to the unit achieving its highest annual control efficiency - ever - in 2007. Buckeye suggests that at a minimum, its NOx emissions rate should be no lower than 0.06 lbs/mmBtu. [EPA-HQ-OAR-2009-0491-3761.1_NODA, p.5]
EPA's use of the IPM model also creates an inaccurate portrayal of the viability of emissions reductions through coal switching. For example, the information in the NODA assigns AEP's Muskingum River units 1-4 S02 rates as low as 1.42 lbs/mmBtu based on the modeled emissions and heat input. Such a low emissions rate is largely indicative of burning low sulfur coal. However, low sulfur coal is not compatible with these wet-bottom units and the units are limited to coal with an S02 content of 4.0 lbs/mmBtu or above. [EPA-HQ-OAR-2009-0491-3761.1_NODA, p.5]
Yet another aspect of the proposed Transport Rule raises the issue of factual accuracy. The use of the IPM model is inappropriate for purposes of this rulemaking, and EPA must consider the ramifications of treating a particular unit as being capable of an emissions rate half of that of which it is actually capable. The Utilities suggest that EPA adjust the model to allow for a more thorough consideration of unit-specific operations and historical data. [EPA-HQ-OAR-2009-0491-3761.1_NODA, p.6]
Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
The NODA contains multiple factual errors that OVEC will address, but because EPA failed to update any of the emissions allocations, OVEC has no way to fully assess the impact of EPA's mistakes. OVEC will supplement its comments once EPA makes complete and adequate information about the Proposed Transport Rule available to the public. EPA's piecemeal approach and statements that this piecemeal approach will continue are counterproductive to meaningful notice and opportunity to comment on the ever-shifting basis and purpose underlying this rulemaking. EPA should suspend its rushed approach to the Proposed Transport Rule and fully consider all impacts and effects of a proposed rule rather than breaking the proposal into confusing, successive pieces. [EPA-HQ-OAR-2009-0491-3734.1_NODA, pp.1-2]
There are No Updates to Unit Allocations [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.4]
Further frustrating meaningful review of the NODA and Proposed Transport Rule is the fact that despite publishing updated inputs and different modeling outputs, OVEC cannot find anywhere in the NODA where the centrally relevant unit level allocations are re-assessed and described. EPA states that the 'policy runs include the same State-level caps that EPA modeled in the Proposed Transport Rule. The caps have not been modified to account for any changes that the new modeling might suggest.' 75 Fed. Reg. 53,614. OVEC cannot be expected to have an adequate opportunity to comment on EPA's Proposed Transport Rule when the most basic of information - the proposed emissions allocations allotted to its units - remains unknown. [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.4]
OVEC will supplement its comments when and if EPA updates and corrects information in both NEEDS and in the outputs it publishes. [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.4]
The NODA Demonstrates That EPA Could Correct Its Mistakes [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.4]
EPA issued the NODA less than a month after the Proposed Transport Rule. The fact that EPA changed inputs and assumptions in the model in so short a time frame shows that it is still possible to correct the problems with the inputs and modeling assumptions EPA is using. As discussed in OVEC's PTR Comments, OVEC cannot fully comment on or assess the Proposed Transport Rule until all updates have been received, data corrected, and emissions re-allocated in a manner that takes into account all of the variables EPA has yet to consider. [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.5]
EPA has already indicated that it will be issuing future changes and updates, and there is no reason for EPA to neglect the type of documented corrections OVEC has submitted. [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.5]
EPA Should not Engage in Piecemeal Opportunity for Comment [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.5]
Finally, even though EPA could and should update its facts to reflect actual unit characteristics, the fact that EPA issued additional updates and information before the' initial comment period ended on the Proposed Transport Rule further illustrates OVEC's point in its PTR Comments that EPA is arbitrarily and unreasonably rushing this Proposed Transport Rule. OVEC cannot be expected to fully assess and comment on EPA's proposals when the data and assumptions underlying EPA's proposals are opaque and constantly moving. First, less than fifteen months from the proposed initial compliance date, the affected entities do not even know what their allocations are proposed by EPA to be. EPA itself admits that it does not know what the effect of the NODA will be: 'changes in the projections relied upon in the proposed rule ... could impact' emissions projections and the test to determine whether there is significant downwind contribution. 75 Fed. Reg. 53,614 (emphasis added). [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.5]
Second, EPA is not yet finished issuing changes and updates to its Proposed Transport Rule. The NODA simply indicated that there will indeed be additional, significant changes. 'EPA also intends to update information related to new units, new installation of pollution controls, and planned retirements.' 75 Fed. Reg. 53,615. OVEC has no way of knowing what those changes will be, whether they will address the flaws pointed out by OVEC and other commenters, or when the public may get notice of them. Just as OVEC objects to the Proposed Transport Rule because it does not fully consider all of the impacts the proposed emissions reductions would have, OVEC similarly objects to EPA's piecemeal and limited opportunity to comment. The public did not have an opportunity to respond to the Proposed Transport Rule itself before its fundamental underpinnings were updated and changed. [EPA-HQ-OAR-2009-0491-3734.1_NODA, p.5]
OVEC strongly encourages EPA to correct all of the factual errors in its inputs and modeling approach, and to fully consider the direct and indirect costs of its Proposed Transport Rule. Once that process is complete, the public should have the opportunity to fully review and comment on an entire proposal before any changes are made to the existing regulatory approach. [EPA-HQ-OAR-2009-0491-3734.1_NODA, pp.5-6]
Old Dominion Electric Cooperative
ODEC is providing general comments in key areas, and additionally, is requesting an extension of the comment period to allow the power sector time to provide more meaningful comments. [EPA-HQ-OAR-2009-0491-3797.1_NODA, p.2]
Construction Costs and Commercially Available Technology
First, the in-service dates listed in the summary of the assumptions for new resources are very aggressive. The nuclear, coal gasification combined cycle, and coal with carbon capture and sequestration technologies do not currently exist in today's U.S. operating fleet of generating assets. For example, ODEC's best estimate at this time, based upon internal research and expertise provided by its engineering consultants indicates that a nuclear installation, consistent with the size assumptions included in the NODA, may be available in the early 2020's not by 2017. Additionally, ODEC's projected installed construction cost estimates in dollars per kilowatt ($/kW¡ are as much as three times higher than the summary information provided in the docket. [EPA-HQ-OAR-2009-0491-3797.1_NODA, p.2]
Additionally, ODEC's expectations for coal gasification combined cycle, at the assumed size included in the summary of supporting information, may be 'commercially' available by 2025. Again with this technology, the projected construction costs are significantly higher than what was listed in the docket information. Coal units which would employ carbon capture and product sequestration are still only in the developmental stage of engineering, ODEC's best estimate for commercial availability would be in the late 2020's and again, at significantly higher capital costs. [EPA-HQ-OAR-2009-0491-3797.1_NODA, pp.2-3]
Unit Retirement Evaluation
Second, ODEC is concerned that market reliability and costs are not adequately factored into the projection of unit retirements, existing unit retrofits, and new resources. There does not appear to be a proper avenue to account for these factors in the model assumptions. With the retirement of units in today's market, there needs to be significant input from the regional transmission operators (RTOs). Based upon ODEC's preliminary review, we are not convinced that this aspect of the supporting data is adequately addressed. [EPA-HQ-OAR-2009-0491-3797.1_NODA, p.3]
Variability of Future Market Conditions
Third, the inter-relationships between gas prices, coal prices, oil, reliability/congestion price impacts, energy market prices, capacity market prices, retrofit/retirement decisions, peak load and energy forecasts should all be modeled interactively. Exaggerated assumptions in any of these areas could have profound effects. Additionally, ODEC believes that an array of possible future market conditions needs to be assessed and provided as options for the final state emission allocations. [EPA-HQ-OAR-2009-0491-3797.1_NODA, p.3]
Request for Extension of Public Review and Comment Period
As stated in previous comments, (1) the unreasonable and unnecessary projected compliance deadlines in the proposed Transport Rule represent further complications for EPA and (2) the North Carolina court decision2 did not provide any requirement for expediting the rule, or subsequently, the compliance deadlines. These deadlines are therefore pushing a schedule of promulgation, inclusive of public participation, that is also unreasonable and not driven by court order. The volume of additional information that has been posted to the docket for review under the NODA is significant. The agency's expectation that all affected entities will be able to provide comments in an abbreviated period of time is completely unrealistic. [EPA-HQ-OAR-2009-0491-3797.1_NODA, p.3]
Based upon (1) the complexities of, not only the IPM model, but the analysis of fuel market factors, and (2) the statements by EPA that more information will be posted to the docket, ODEC requests that EPA extend the public review and comment period to allow more time for the power sector to provide meaningful comments. ODEC would suggest that EPA extend the comment period through the fall, closing after the first of the year. [EPA-HQ-OAR-2009-0491-3797.1_NODA, p.3]
Peabody Energy Company
EPA's new assumptions as to shale gas availability are much more aggressive than EPA's assumptions used in the proposed rule and in its AEO 2010 case. EPA notes that its AEO 2010 case assumes only 31 percent of the shale gas resource availability as NEEDS v.4.10. Similarly, EPA's v.4.10 case projects 2012, 2015 and 2020 natural gas prices at $4.27 ($2007$/MMBTU), $5.03 and $4.46, respectively, whereas its natural gas price assumptions for the original rule for the corresponding time periods were $6.76, $6.26 and $6.43. EPA's natural gas price assumptions for the AEO 2010 case for the same periods are $5.19, $5.71 and $7.88. [EPA-HQ-OAR-2009-0491-3762.1_NODA, p.1]
EPA states that the new v.4.10 IPM with the new natural gas assumptions will be used by EPA to formulate the Transport Rule. Thus, as EPA states, the rule as proposed in the August 2, 2010 edition of the Federal Register may change as a result of the new modeling. EPA, however, did not publish any such changes to the rule. Thus, EPA is asking the public to comment on new assumptions that will be used in the IPM and that may result in changes in the underlying proposed rule, but the public is not at this point told what the new rules will be and presumably will not be told until the rule is published in final form. [EPA-HQ-OAR-2009-0491-3762.1_NODA, pp.1-2]
I. EPA Does Not Provide Notice of and a Fair Opportunity to Comment on the Proposed Rule
EPA states that: [c]hanges from the projections relied on in the proposed rule, from using an updated model, could impact the final rulemaking in a number of ways including, but not limited to: 1. Changing emission projections that were used to determine which downwind areas have air quality concerns (i.e., nonattainment or maintenance) absent this rulemaking and to determine which States contribute to those problems. 2. Changing cost and emission projections used in the multi-factor test to determine the amount of emissions that represent significant contribution.[EPA-HQ-OAR-2009-0491-3762.1_NODA, p.2]
 It appears, therefore, that the changes EPA has made in the NEEDS data base, when used in the IPM model, may cause material changes in the rule. Yet EPA states that it has not set forth what those changes will be -- in other words, EPA has not yet published the version of the rule it proposes to promulgate. This state of affairs does not comport with elementary requirements for the agency to provide notice of and an opportunity to comment on its proposed rules. [EPA-HQ-OAR-2009-0491-3762.1_NODA, p.2]
It may be that EPA does not believe it has sufficient time to publish new proposed rules for comment given its proposal to commence regulation under the Transport Rule at the beginning of 2012. But EPA's desire to commence regulation in 2012 does not excuse EPA's failure to comply with notice and comment requirements. And, in any event, comments on the proposed rule from a large number of parties showed that EPA's 2012 deadline is not practically attainable regardless of whether the Agency, as it is required to do, publishes new regulatory proposals for comment. [EPA-HQ-OAR-2009-0491-3762.1_NODA, p.2]
II. EPA's Substantially Overstates the Amount of Shale Gas that Is Likely to Be Available
A. Shale Gas Development at the Scale EPA Projects Is Unproven, and Past Optimistic Estimates of Natural Gas Supplies Have Not Been Borne Out
EPA's shale gas assumptions are unreliable because they are based on a model with a monolithic and untested assumption regarding natural gas supply, i.e., shale gas production in the United States will increase far beyond even the most sanguine projections of the U.S. Department of Energy and the cost of that production will be low and stable. But in making these highly optimistic shale gas projections, EPA cannot answer five key questions: (1) how much of this gas can be delivered in a timely fashion, (2) how long can production be sustained, (3) why will the chronically persistent higher prices and price volatility of natural gas not apply to shale gas, (4) what will the environmental impact be, and (5) what are the consequences for American families, businesses and agricultural operations if shale gas production falls short of expectations? [EPA-HQ-OAR-2009-0491-3762.1_NODA, p.3]  
Despite the high rhetoric associated with shale gas, none of these questions has been even marginally resolved. Indeed, as the California Energy Commission has noted: "[t]he infancy of the development of natural gas from shale formations creates many uncertainties and thus leaves many questions unanswered." [EPA-HQ-OAR-2009-0491-3762.1_NODA,p.3]  
Importantly, the answers to these questions are meaningful beyond just the proposed Transport Rule because they will affect how EPA assesses the cost of various rules and regulatory policies using the IPM model. The higher shale gas assumptions will likely lead EPA into courses of action that favor substituting natural gas for coal on the ground that the economic impacts of doing so are favorable. But if EPA's shale gas assumptions turn out to be wrong, EPA will have led the United States into risking much of its energy future on one of the most price-volatile commodities in the world. The United States would then be forced to enter the international liquefied natural gas (LNG) market -- a market which will be dominated by questionable suppliers, since the OPEC nations and Russia own 75 percent of the world's natural gas -- and LNG is indexed to world oil prices. [EPA-HQ-OAR-2009-0491-3762.1_NODA, p.3] [See Docket Number EPA-HQ-OAR-2009-0491-3762.1_NODA, pp.3-10 for a detailed discussion on this issue.]
B. Environmental Concerns Are Likely to Limit Shale Gas Development
EPA's shale gas assumptions do not take proper account of increased concerns across the United States relating to the environmental impacts of shale gas, concerns that are likely to grow as shale gas development increases. As these impacts become more obvious to a growing number of people, regulations and restrictions on shale gas will constrain the heretofore unbridled rush to production. [EPA-HQ-OAR-2009-0491-3762.1_NODA, p.10] [[See Docket Number EPA-HQ-OAR-2009-0491-3762.1_NODA, pp.10-16 for a detailed discussion on this issue.]]
III. Using Correct Shale Gas Assumptions Will Dramatically Increase the Cost of the Rule
A. Overview of Results of EPA Modeling Runs
Given the fact that EPA has not published changes to the proposed Transport Rule that may result from the new v.4.10 assumptions, it is impossible to comment on how those changed assumptions will change the cost and regulatory impacts of the rule. Not having set forth how the proposed rules will change as a result of the changed assumptions, EPA also did not provide a new draft Regulatory Impact Assessment (RIA) showing the impacts of the changed rule. Without a new RIA, there is no current comprehensive information in the record with which to assess what the effects of the rule will be. [EPA-HQ-OAR-2009-0491-3762.1_NODA, p.16]
EPA, however, has provided modeling runs for a new base case using the new v.4.10 natural gas assumptions and a new regulatory case (TR SB Limited Trading) using the new v.4.10 natural gas assumptions. These can be compared with the modeling runs of the original base case and corresponding regulatory case. Importantly, the new regulatory case using the v.4.10 assumptions does not reflect changes to the proposed regulation that may result from the new assumptions. Instead, the modeling run of the regulatory case using the v.4.10 assumptions only shows the changes in fuel mix and other impacts that will result if the regulations as originally proposed were implemented in a scenario with higher gas availability and lower gas prices. The fact that higher gas availability and lower gas prices may change the rule itself is not taken into account. [EPA-HQ-OAR-2009-0491-3762.1_NODA, p.16]
As a result, comparing the modeling runs of the original base case and original regulatory case with the new base case and new regulatory case is of limited utility (because the "new" regulatory case may not, in fact, be the regulatory case that results from the new assumptions). Nevertheless, that is all the information that EPA has provided and, as a result, Peabody comments on that information. [EPA-HQ-OAR-2009-0491-3762.1_NODA, p.16]
As shown in the comments of the National Mining Association on the proposed rule, EPA's RIA did not project that the proposed rule with the original NEEDS data base assumptions would produce a significant economic impact or significantly change fuel use for electric generation. This is because the IPM model projected that (a) compliance with the 2012 budgets could be obtained primarily through switching from high sulfur to low sulfur coal and without building new NOX or SO2 pollution control equipment beyond those already planned and (b) compliance with the 2014 budgets could be obtained through cost-effective and feasible additions of new pollution control equipment. As a result, EPA concluded that the proposed rule would not result in shutting down a material amount of existing coal generation. [EPA-HQ-OAR-2009-0491-3762.1_NODA, p.16]
EPA's modeling runs projecting the impact of using the v.4.10 assumptions likewise show no material changes in the fuel mix for electric generation when one compares the new base case with the new regulatory case. Thus, if the assumptions underlying EPA's numbers are correct (and putting aside the fact that EPA did not model the rule as it may now be changed), the availability and price of gas do not matter to the effect the rule will have. In either case, according to EPA, industry will comply by coal switching and installation of pollution control equipment and will not significantly reduce coal usage. [EPA-HQ-OAR-2009-0491-3762.1_NODA, p.17]
On the other hand, when one compares the base case from the original rule with the new v.4.10 base case, and the original regulatory case with the new v.4.10 regulatory case, there are significant changes in the fuel mix. The amount of coal generation is significantly reduced, and the amount of gas, nuclear and renewable generation is increased. Thus, according to EPA's figures, increasing natural gas availability will lead to reductions in coal generation. But this effect is not the result of the proposed rule; it is only the effect of changed assumptions as to gas. According to EPA, the effect of the rule on fuel mix is neutral regardless of whether one assumes high gas availability or low gas availability. [EPA-HQ-OAR-2009-0491-3762.1_NODA, p.17]
The same relationships hold true for natural gas generation, renewable resource generation, coal plant retirements, new coal builds and other rule impacts. For all of these impacts, there are large changes from the original base case to the v.4.10 base case and from the original regulatory case to the v.4.10 regulatory case, but only small or no changes from the original base case to the original regulatory case and from the v.4.10 base case to the v.4.10 regulatory case. [EPA-HQ-OAR-2009-0491-3762.1_NODA, p.17]
B. EPA's Modeling Results Are Misleading. In Fact, the Rule as Proposed Will Result in a Loss of Coal Generation, and the Overall Economic Effect of This Result Will Be Masked by the New Gas Assumptions
There are three fundamental problems with the conclusion of the modeling runs that the proposed rule will not materially affect fuel mix under EPA's original or v.4.10 assumptions. [EPA-HQ-OAR-2009-0491-3762.1_NODA, p.17]
First, putting aside the natural gas issue, the information in the NEEDS data base has significant inaccuracies, as was pointed out extensively in comments. These problems do not need to be reiterated here, but the IPM model obviously cannot be relied on to predict how the electric system will operate in either a base or regulatory case if the input information is wrong. [EPA-HQ-OAR-2009-0491-3762.1_NODA, pp.17-18]
Second, because the IPM is proprietary, it is a "black box" to which the public does not have access and therefore cannot test or even completely understand. Without having access to the underlying model, the public is denied the opportunity to effectively comment on the modeling results. This is a particular problem where, as here, the model is used not just to project impacts the rule will have but to fundamentally shape the rule itself. For instance, a party cannot independently confirm or deny EPA's projection of a state's significant contribution to downwind nonattainment if the party does not have access to the workings of the model used to make that projection. [EPA-HQ-OAR-2009-0491-3762.1_NODA, p.18]
For example, the EPA has several base cases derived from successive versions of the IPM, yet there is no public documentation of the comparison of the forecasts between Version 1.0 and all of the successive versions through 4.10. This inter-version comparison must be extended to a comparison of actual observations over the same time horizons proposed in the models (a minimum of 20 years). The introduction of new model versions requires the same quality assurance as was required for the initial version adopted by EPA. EPA's website also claims that the consultant ICF has participated in "comparative modeling exercises sponsored by Stanford University's Energy Modeling Forum." Since the results of any Energy Modeling Forum inter-model comparisons are not made public, there is no available data to be used for judging the robustness of the model. [EPA-HQ-OAR-2009-0491-3762.1_NODA, p.18]
EPA has at its disposal non-proprietary, fully transparent models that can be used to perform the same Transport Rule analyses as the IPM performs. For example, the EIA National Energy Modeling System ("NEMS") can perform the same functions as IPM. EIA has before, at the request of Congress, used NEMS to analyze various strategies for reducing multiple pollutant emissions from power plants. In contrast to IPM, the EIA NEMS model is not proprietary, so its analytical processes are fully transparent. At least where EPA is using a model to shape basic requirements of a regulation, it should use a non-proprietary model such as NEMS rather than the proprietary IPM. [EPA-HQ-OAR-2009-0491-3762.1_NODA, p.18]
The Data Quality Act and EPA's modeling guidelines require no less. The Office of Management and Budget's Data Quality guidelines require that
if an agency is responsible for disseminating influential scientific, financial, or statistical information, agency guidelines shall include a high degree of transparency about data and methods to facilitate the reproducibility of such information by qualified third parties. [EPA-HQ-OAR-2009-0491-3762.1_NODA, p.18]
The guidelines lay out further requirements with regard to transparency:
With regard to analytic results related thereto, agency guidelines shall generally require sufficient transparency about data and methods that an independent reanalysis could be undertaken by a qualified member of the public. These transparency standards apply to agency analysis of data from a single study as well as to analyses that combine information from multiple studies. Making the data and methods publicly available will assist in determining whether analytic results are reproducible. [EPA-HQ-OAR-2009-0491-3762.1_NODA, p.19]
It is impossible to meet this standard for independent reanalysis and reproducibility if EPA uses the IPM model. [EPA-HQ-OAR-2009-0491-3762.1_NODA, p.19]
Third, and most fundamentally, as shown in numerous comments on the proposed rule, EPA overstates the ability of the utility industry to install the amount of scrubbers that EPA projects and the ability of the utility industry to switch from high to low sulfur coal on the timetable that EPA assumes. As a result, the rule will force utilities to close coal units and to invest in new natural gas generation. They will have no other compliance option, since the 2012 and 2014 state budgets are hard caps on emissions. [EPA-HQ-OAR-2009-0491-3762.1_NODA, p.19]
The cost of substituting natural gas generation for existing coal generation will depend on the price of natural gas. Presumably, under EPA's new natural gas assumptions, that cost would be lower than under EPA's previous natural gas assumptions. But since, as shown above, EPA's new gas assumptions are far too optimistic, those new assumptions are likely to mask the true cost of the fuel-switching that the rule will create. [EPA-HQ-OAR-2009-0491-3762.1_NODA, p.19]
In any event, it is plain that EPA's regulatory analysis is, at best, incomplete. EPA must publish the rules it is actually proposing and analyze the impacts such rules will have in a full RIA. EPA should also use more realistic assumptions -- as to natural gas prices and the amount of coal-switching and pollution control installations that are actually possible, and it should correct other errors that have been identified in the NEEDS data base. Until that information is provided, EPA will have failed to fulfill its statutory obligations to examine the impact of the proposed rule and to allow the public an adequate opportunity to comment. [EPA-HQ-OAR-2009-0491-3762.1_NODA, p.19]
PPG Industries, Inc.
PPG is diligently reviewing updates to the IPM announced in the September 1, 2010 Notice of Data Availability, but to date cannot understand why that IPM v.4.10 projects such limited operation of the RS Cogen units. PPG's manufacturing operations depend on the steam and electricity produced from the RS Cogen units. PPG needs more time to adequately prepare comments on this allocation scheme. [EPA-HQ-OAR-2009-0491-1926.1, p.2]
A comparison of actual data for fuel input and SO2 and NOx emissions for the RS Cogen units to the values for these projected by the EPA IPM model v. 3.02 follows: [EPA-HQ-OAR-2009-0491-2763.1, p. 11; see p. 12 for Comparison of actual data to TR projected data.]
PPG believes EPA's methodology for proposed SO2, NOx annual and NOx ozone season allocations is fundamentally flawed. Of particular concern is EPA's mixing of allocations for SO2 and NOx for the same units and the same calendar year using significantly different heat input rates. In Louisiana, EPA based 2012 allocations for SO2 based on ?adjusted reported? emissions and for NOx based on projected emissions based in the IPM modeling. This does not make any sense. How can EPA state in the same table that it projects high heat input for SO2 while at the same time project low heat input for NOx for the very same year? [EPA-HQ-OAR-2009-0491-2763.1, pp. 11-12]
PPG's RS Cogen for example, has SO2 allocations based on an assumed 2012 heat input for RS-6 of 13,329,878 mmBtu.21 This is a reasonable value based on past and projected future operations as can be seen from the certified data reported to EPA under the Acid Rain and CAIR programs. However, the same unit (RS-5) has an assumed heat input for NOx annual allocations of only 214,246 mmBtu and an ozone season assumption of only 21,425 mmBtu. Thus, the assumed heat input for NOx is only 1.6% of the actual adjusted reported value used for SO2. The same is true for the IPM projected heat input values for the RS5 unit. These values are not reasonable and since they were the product of the IPM model, PPG has grave questions about the accuracy of the model to predict heat input in future years. PPG does not understand the basis for the modeled prediction. It appears that the ozone season allocation heat input basis is exactly 10% of the annual NOx heat input basis (which as noted is already woefully short of an accurate prediction). This also does not make sense to PPG. PPG's units operate year around on the same basic operational schedule and therefore the ozone season heat input should be based on a realistic percentage based on May-September operation. EPA has the data in its quarterly CAMD reports to have seen that these units operate year round. Although the difference between reported and projected values improves very slightly under the IPM v.4.10, the same fundamental problem exists there as well. The annual and ozone season heat input and corresponding NOx emissions are only a tiny fraction of the RS Cogen's actual heat input and emission levels. [EPA-HQ-OAR-2009-0491-2763.1, p. 13]
In addition, PPG believes EPA made an error in providing allocations to the RS Cogen RS4 unit. RS Cogen unit RS-4 is a steam turbine. As such, it is an unfired unit and does not have its own emissions. The allocation table has an assumed heat input for 2012 SO2 for RS-4 of 6,445,585 mmBtu. PPG RS Cogen unit RS-5 is included as well and the allocation table also shows an assumed 2012 heat rate of 6,445,585 mmBtu. RS-5 is an identical unit to RS-6 and generally operated in tandem with RS-6 and therefore allocations should be based in similar heat inputs. It appears that EPA incorrectly included RS-4 (steam turbine) and arbitrarily gave it an assumed heat input of one-half the heat input of RS-5. The allocations should be for RS-5 and RS-6 as they are the fossil-fuel fired units with emissions. Although electricity is made from RS-4, it is not a fired unit. PPG recognizes that EPA has proposed to include the steam turbine in a combined cycle system within the definition of 'combustion turbine'. However, that does not alter the fact that the steam turbine is not a fired unit and does not generate emissions. [EPA-HQ-OAR-2009-0491-2763.1, p. 13]
PPG requests EPA abandon use of the IPM model for projecting electric utility operation in Louisiana for purposes of allocating unit-level allowances under CATR for cogeneration units as well as other EGUs. There are several fundamental issues with EPA's use of the IPM for this purpose. One of the foremost reasons is the lack of transparency concerning how the IPM accounts for economic and fuel cost factors in determining how much a unit will be utilized in future years. As clearly shown above, the output of the IPM does not come close to matching actual utilization for PPG's RS Cogen cogeneration facilities. The year 2012 is less than one and one-half years away and therefore is well within PPG's reasonable ability to project operations. The assumed heat inputs associated with NOx allocations for 2012 are not consistent with PPG projections. PPG utilizes a significant portion of the power generated by RS-5 and RS-6 for chemical manufacturing operations and is under long-term contract obligations to produce power for transfer to the power grid. [EPA-HQ-OAR-2009-0491-2763.1, pp. 13-14]
PPG recommends that EPA utilize the methodology for NOx allocations utilizing previously reported operations exactly like used for SO2. In the event EPA chooses to continue using projected emission for NOx allocations, PPG requests EPA modify the model to accurately project emissions from cogeneration facilities co-located with production facilities dependent upon cogeneration power. [EPA-HQ-OAR-2009-0491-2763.1, p. 14]
Currently RS-Cogen units RS-5 and RS-6 are subject to CAIR and would be the only units at the PPG Lake Charles site subject to CATR. The following table lists the 2012 NOx annual and ozone season allocations under CAIR via the EPA approved Louisiana SIP, the allocations proposed by EPA under CATR and the differences. [EPA-HQ-OAR-2009-0491-2763.1, p. 14; see p. 14 for the table.]
Note: PPG also notes that the heat rate information used by EPA for the RS5 and RS 6 units from the NEEDs data varies from the value reported by RS Cogen on its Annual Electric Generator Report Form EIA-860 to the US Department of Energy, Energy Information Administration. EPA stated that the NEEDs data was based on the EIA data, but for the RS Cogen units, this was not the case, or EPA made an error in transcription from the EIA-860 reports. PPG requests that EPA use the correct EIA data. [EPA-HQ-OAR-2009-0491-2763.1, p. 15]
On September 1, 2010, EPA published the NODA indicating that EPA intends to use the IPM version 4.10 modeling, including a revised TR Base Case 2012 scenario, for revising the determinations of significant impact and interference with maintenance. Under the revised IPM TR v. 4.10 Base Case, projected emissions of SO2 from Louisiana EGUs are more than 20,000 tpy less than was projected under the IPM v. 3.02 version. (See Table below.) Based on this factor alone, because EPA'S own data showed sulfate to be the culprit, it is believed that any revised air quality analysis based on the IPM v. 4.10 will demonstrate no impact whatsoever on Harris Co. PM2.5 levels. The same is true with respect to reductions of annual and ozone season NOx, EPA's revised IPM v. 4.10 Base Case 2012 model results show significant reductions in projected SO2 and NOx emissions that will occur even without implementation of the CATR/FIP (or CAIR). If these values are used in revised air quality modeling, it is virtually certain-that the conclusion will be that Louisiana emissions do not impact the annual PM2.5 or 1997 8-hour ozone standards in Texas.8 [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.3]
Even without a revised air quality analysis, however, PPG believes that use of the TR Base Case v. 4.10 data supports the conclusion that Louisiana should not be included in the CATR/FIP. The original CATR/FIP determined that a certain level of emission reductions from EGUs would remove 'significant contribution' and 'interference with maintenance.' The revised IPM v. 4.10 Base Case shows that emission reductions greater than that level will occur by 2012, even without CATR. The following table demonstrates this conclusion: [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.3; see p.4 of this comment summary for a table entitled, Comparison of TR Base Case v. 3.02 to TR Base Case v. 4.10 for Louisiana EGUs] 9
Even without air quality modeling, these results demonstrate on their face that because the quantity of SO2 and NOx emissions that were required to be removed to prevent 'significant contribution' 'interference with maintenance' are now projected to be removed by 2012 through factors other than the CATR/FIP, there is no legal basis for a CATR/FIP for annual SO2 or annual or ozone season NOx control for Louisiana EGUs. [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.4]
If Louisiana is still included under the CATR/FIP after revised modeling and air quality analysis, PPG requests that EPA not use the IPM v. 4.10 (or any other version of the IPM) to make unit level allocations under the CATR/FIP. EPA should make SO2 and NOx allocations proportionate to the of each unit's existing SO2 and NOx allocations to the state CAIR budgets already approved by both EPA and LDEQ. Although the court in North Carolina v. EPA struck down CAIR and required a revised look at the actual state budget needed to eliminate significant contribution or interference with maintenance, the court did not find any problem with the Louisiana (or other state's) unit level allocations. Louisiana DEQ, together with the Louisiana Public Service Commission, worked very hard on a fair allocation scheme for NOx allowances. This scheme was enacted into rule by the State after public notice and comment and was approved by EPA. [EPA-HQ-OAR-2009-0491-3735.1_NODA, pp.4-5]
On September 27, 2006, the Louisiana Department of Environmental Quality (LDEQ) submitted a SIP revision to EPA adopting the CAIR SO2 Trading Program to address its 'good neighbor' obligations under CAA Section 110(a)(2)(D) with respect to the potential impact of Louisiana emissions on downwind PM2.5 receptors in the State of Alabama. EPA approved this SIP revision on July 20, 2007 at 72 Fed.Reg. 39741.11 On July 12, 2007, LDEQ submitted a SIP revision to EPA adopting a SIP - for a CAIR NOx Trading Program to address both the 1997 8-hour ozone standard and the 1997 annual PM2.5 standard. EPA approved this SIP revision on September 28, 2007 at 72 Fed. Reg. 55064. LDEQ submitted amendments to its NOx CAIR SIP on July 1, 2009, which are pending before EPA for decision. EPA should base its allocation system as closely on these prior approved Louisiana CAIR provisions as is possible. [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.5]
EPA lacks a credible rationale for premising its NOx and SO2 allocations on the IPM v. 4.10. Although the allocations are slightly more generous than were the allocations under version 3.02, they are woefully inadequate to allow PPG to normally operate the RS Cogen units without incurring enormous costs. PPG incorporates by reference its comments on the improper use of the IPM model for NOx allocations made in PPG's original comments. [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.5]
The IPM is an economic model that fails to account for realistic operations at many Louisiana facilities, in particular, cogeneration units serving industrial sources. The unit level allocation scheme based on the IPM (as distinguished from the state budget) has nothing to do with preventing significant contribution or interference with maintenance. In fact, huge economic inequities are being created with no underlying environmental reason. The following table shows a comparison of the allocations that PPG would likely receive under IPM v. 4.10 version as well as actual reported emissions to CAMD for 2005-2010. [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.5; see p. 6 of this comment summary for a table showing a comparison of the allocations that PPG would likely receive under IPM v. 410 version as well as actual reported emissions to CAMD for 2005-2010]
As indicated in its original comments, the PPG RS Cogen units are must run units for the PPG manufacturing facility. The assumptions made in the IPM are obviously grossly in error with respect to the utilization of these units. It would be arbitrary and capricious for EPA to base its allocations on the IPM- either v. 3.02 or v. 4.10 given these facts. [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.6]
EPA's approach for projected emissions inventories, as well as considerations of control technology under the IPM v. 4.10, eliminated the consideration of any reductions required by CAIR, due - to the fact that the CAIR rule was overturned in North Carolina v. EPA, 531 F.3d 896, 901 (D.C. Cir. 2008). However, this results in overly conservative projections. The CAIR rule was remanded, but not vacated. Many regulated public utilities already invested in capital projects for reduction that were approved by their regulatory bodies and/or ratepayers. In most cases, legal obstacles would prevent the undoing of these projects. In addition, each physical project undertaken for purposes of CAIR reductions was of necessity permitted under an enforceable Title V permit. Those projects and permit limits cannot be relaxed without the facilities triggering Prevention of Significant Deterioration (PSD) rules. Triggering PSD would involve imposition of Best Available Control Technology, which, in most cases, would mean that the facilities would have to keep the pollution control equipment they installed for CAIR, or would have to meet even more stringent requirements. EPA should have undertaken a much more rigorous analysis for projecting what steps EGUs would take if CAIR were vacated completely, with no replacement. EPA has tools to easily accomplish this, such as a Clean Air Act Section 114 request for information. In short, EPA overestimated Base Case emissions for both 2012 and 2014 by eliminating all CAIR control requirements. [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.6]
The documentation for the IPM v. 4.10 does not clearly indicate whether EPA included only the grid-demand for electricity or also industrial facility demand. Section 3.2 of the Documentation for the EPA's IPM v. 4.10 Base Case tends to indicate that EPA considered only the grid-demand. This have discounted the total electrical demand in Louisiana as many industries have cogeneration units. Some of these units provide power to the grid, as does PPG. However, if EPA did not appropriately account for the fact that industries that partially self-generate need continuous and reliable electrical and steam output, then the IPM may make deficient economic choices in its selection of EGU behavior. [EPA-HQ-OAR-2009-0491-3735.1_NODA, pp.6-7]
The Documentation for the IPM v. 4.10 Base Case, Chapter 3.5.1 indicates that EPA made certain assumptions about EGU availability in its modeling. EPA stated 'Power plant availability is the percentage of time that a generating unit is available to produce electricity to the grid. Availability takes into account both scheduled maintenance and forced outages...' EPA indicated that Appendix 3-9 shows the availability assumptions for all EGUs in EPA Base Case 4.10. In Appendix 3.9, EPA indicated that the 'availability' for the RS Cogen units was as follows: [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.7; see p. 7 of this comment summary for a table containing EPA's indicated availability for the RS Cogen units]
PPG disputes these assumptions. PPG must operate the RS Cogen units year round in order to provide adequate electricity and steam to the PPG manufacturing complex. Actual data submitted to EPA CAMD reflects PPG's actual utilization of these RS Cogen units. Further, the annual on-stream time for each of these units in the past several years is as follows: [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.7]
2008:
R4 - 99.8 %
R5 - 95.4%
R6 - 89.0% [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.7]
2009:
R4 - 99.3%
R5- 94.6%
R6 - 88.0% [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.7]
2010 (thru Sept)
R4 - 77.0%
R5 - 94.4%
R6 - 96.5% [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.7]
PPG requests that EPA revise these values to adequately reflect actual availability and utilization of these units. [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.7]
In Section 3.9.2 of the Documentation for the IPM v. 4.10 Base Case (pages 3-18 through 3-20), EPA indicates that it used four different NOx rates in NEEDS 4,10 'to allow all possible modeling scenarios involving NOx controls to be set up.' The 4 modes of operation were set forth in the NEEDs 4.10. PPG believes that EPA erred in its assignment of NOx rates to the RS Cogen units under these 4 modes. [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.8; see p.9 of this comment summary for a table containing information about RS Cogen 5, 6 and 4]
PPG has consistently reported to CAMD that its RS Cogen units each meet a NOx emission rate of 0.5 to 0.6 lbs/mmBtu, throughout the year, for units 5 and 6. These units are equipped with low NOx burners and SCR. {Unit 4 does not emit, so it is not clear why EPA has included it in the NEEDS data base as having emissions.} There is no reason that the Mode 2 and Mode 4 rates should be 0.0122 lbs/MmBtu. The units are not capable of achieving those levels and have never been required to achieve those levels. No other Louisiana natural gas fired combined Cycle cogeneration units had such a disparity between Modes. The basis for this is unstated and appears to be in error. [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.8]
The documentation for the IPM v. 4.10 indicates that EPA continued an error that was also made in the IPM v. 3.02 Base Case with respect to existing environmental regulations. In Section 3.9.4 of the Documentation of EPA's IPM v. 4.10 Base Case, EPA listed the state rules that it included in the model. As indicated in PPG's original comments, EPA improperly considered the Louisiana NOx Reasonably Available Control Technology rule in LAC 33:III.Ch. 22 reductions of NOx in the modeling used to project future impact. In Appendix 3-2.2, EPA had the following entry for Louisiana: [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.8; see p. 9 of this comment summary for a table showing EPA's entry for Louisiana in Appendix 3-2.2]
The cited rule does apply to NOX, but the information in the 'Emission Specifications' column is totally erroneous. The NOx emission limits are much lower than this, but different limits apply to different types of units. Further there are different limits for different parishes. PPG requests that EPA update the model by using the actual limits of the rule, as set forth at LAC 33:III.Chapter 22, available at: http ://www.deq.louisiana.gov/portal/DIVISIONS/LegalAffairs/RulesandRegulations/Title33.aspx [EPA-HQ-OAR-2009-0491-3735.1_NODA, p.8]

8 If EPA conducts revised air quality modeling, PPG urges EPA to also make the revisions to the Louisiana emissions inventory discussed in PPG's original comments.
9 Data obtained from 75 Fed. Reg. at 45,210, 45,291, Tables.IV-E-1 and IV-E-2 (Aug. 2, 2010). This is the value PPG believes that EPA used in the modeling to determine significant contribution or interference with. maintenance. See Environmental Protection Agency, Technical Support Document for the Transport Rule, Air Quality Modeling (2010), http://www.epa.gov/airquality_/transport/pdfs/TR__AQModeling_TSD.pdf. It is possible that EPA used the Transport Rule Base Case v. 3.02 value for SO2 rather than the lower SO2 state budget, which was based on adjusted, reported data; however, PPG took the conservative approach of determining that EPA used the lower value. For NOx, EPA used the Transport Rule Base Case v. 3.02 projection as the budget.
Louisiana Department of Environmental Quality, Louisiana SIP Revisions, http://www.deq.louisiana.gov/portal/Default.aspx?tabid=2381.
PPL Corporation
Errors in Data Files used to Develop the Transport Rule Budgets.
PPL is providing corrections to data characterizing PPL's units that are in the NEEDS 4.10.xls data file located on EPA's established website for the rule (www.epa.gov/airtransport). These corrections are provided in a table at the end of these comments. [[EPA-HQ-OAR-2009-0491-2739.1, p.7] [See page 11 of this comment for the table.]]
As described in the attachment, PPL is particularly concerned about very low sulfur dioxide emission rates (0.06 lb/MmBtu) that appear to be assigned to our Pennsylvania coal-fired units in some of the NEEDS version 4.10 data bases that we have reviewed. The emission rates appear to be much lower than those for any other similar size coal-fired units that have or are projected to install flue gas desulfurization systems and are much lower than the emission rates to which these units presently operate.  [EPA-HQ-OAR-2009-0491-3766.1_NODA, p.1]
1. Montour Units 1 &2 NOx Emission Rates.
Montour Units 1&2 are coal-fired units equipped with selective catalytic reduction (SCR) to reduce NOx emissions. The 'Controlled NOx Base Rate' and 'Controlled NOx Policy Rate' emission rates shown in the NEEDSv410.xls data file available on the proposed Transport Rule website (www.epa.gov/airtransport) appear incorrect. The emission rates shown are just under 0.056 lb/MmBtu. [EPA-HQ-OAR-2009-0491-3766.1_NODA, p.2]
The following table shows annual and ozone season heat input and NOx emissions data from the BADetailedData.xls file available on the Transport Rule website. The data are for the most recent four quarters (4th quarter 2008 and 1st, 2nd, 3rd quarters 2009) and most recent ozone season (2009) presented in the ''''reported data' sheet of the file. The corresponding emission rates (lb/MmBtu) were calculated by PPL based on those data and are also shown in the following table. [EPA-HQ-OAR-2009-0491-3766.1_NODA, p.2][[See Docket Number EPA-HQ-OAR-2009-0491-3766.1_NODA, p.3 for the table.]]
As shown in the table, the ozone season emission rates are lower than the annual rates because the SCR systems operated during part of the four quarters (including the ozone season) but not during the entire four quarters during those specific four quarters. [EPA-HQ-OAR-2009-0491-3766.1_NODA, p.3]
The emission rates presented in the NEEDS version 4.10 data base (NEEDSv41O.xls) and calculated from data in the ''TR SB Limited Trading v4.10' and 'TR SB Limited Trading AEO Gas v4,10' parsed files (and maybe others) are considerably lower than the actual emission rates during either the annual or ozone base periods as shown in the above table. PPL is not sure of the basis of these low rates and is concerned that they are being used to represent emission rates under present operations in the NEEDS database. In fact, during that base period ozone season, monthly average NOx emission rates for only one of those units and for only one of the five ozone season months were operated at an emission rate at that low level (actually, 0.057 lb/MmBtu). [EPA-HQ-OAR-2009-0491-3766.1_NODA, p.3]
PPL understands that the floor for NOx emission rates under the Transport Rule allocation scheme as presented in technical support document 'State Budgets, Unit Allocations, and Unit Emission Rates,' is 0.06 lb/MmBtu. Additionally, data for these units do not indicate that they have been operating consistently at or below 0.06 lb/MmBtu. Therefore, NOx emission rates of 0.0561 lb/MmBtu are not appropriate. PPL requests that the base year ozone season emission rates presented in the above table (0.087 and 0.1121 lb/MmBtu for Units 1&2 respectively) be used as representing present operation in the NEEDS data base, not an emission rate of 0.056 lb/MmBtu. [EPA-HQ-OAR-2009-0491-3766.1_NODA, p.3]
2. Status of SO2 Flue Gas Desulfurization (FGD) Systems at the Montour and Brunner Island Plants.
PPL wants to clarify that Montour Units 1&2 and Brunner Island Units 1,2&3 presently operate with PGD systems to reduce SO2 emissions. As correctly presented in the NEEDSv410.xls data file, the Montour FGD systems began operating in 2008 and the Brunner Island systems in 2009. The permitted SO2 emission rates for these units is 0.85 lb/MmBtu. The NEEDSv41O.xls data file incorrectly lists the permitted rates as 3.7 lb/mmBtu for the Brunner Island Units and Montour Unit 1. [EPA-HQ-OAR-2009-0491-3766.1_NODA, pp.3-4]
The NEEDSv41O.xls file reports that the units have FGD systems under both the 'Wet/Dry Scrubbers' column and also under the 'Dispatchable Scrubbers' column. PPL is not sure if EPA intends both columns to be used. There is no column for the scrubber control efficiency in this NEEDSv410.xls file, but PPL notes that an unrealistic control efficiency of 97% is presented in an earlier NEEDS file (NEEDSv3[I].02_EISA.xls) in the 'Dispatchable Scrubber Efficiency' column. That percentage provides no cushion for any pumps to be out on maintenance or for any degradation in the equipment. This is not a condition that can be achieved on a continuous basis into the future even with the most aggressive maintenance. In fact, PPL is not even sure that its scrubbers can achieve a 95% control efficiency as even this level would require all pumps to be running and there is no room to add any spare pumps to operate if maintenance is being performed on a pump. Therefore, a control efficiency of less than 95% should be used. [EPA-HQ-OAR-2009-0491-3766.1_NODA, p.4]
3. Future S02 Control Levels Projected for Montour Units 1&2 and Brunner Island Units 1,2&3.
Run files 'TR Base Case v4.10,' 'TR SB Limited Trading v4.10,' 'TR Base Case AEO Gas v4.1O' and 'TR SB Limited Trading AEO Gas v4.1O' presented on the Transport Rule website present annual heat input and SO2 emissions data that correspond to annual SO2 emission rates that are confusing. These emission rates may also be presented in other version 4.10 runs. [EPA-HQ-OAR-2009-0491-3766.1_NODA, p.4]
The SO2 emission rate calculated from annual heat input and annual SO2 emissions presented in the 'TR Base Case v4.10' and 'TR Base Case AEO Gas v4.10' parsed files for Montour Unit 2 is 0.06 lb/MmBtu. In previous PPL comments to the proposed Transport Rule submitted on October 1,2010, PPL noted that this value also appeared in the 2012 Allocation Table (and, it also would be calculated from annual heat input and NOx emissions data in the 'BADetailedData.xls' file, 'Projected Data' screen). As we noted at the time, the value is excessively low and appears to be an error. [EPA-HQ-OAR-2009-0491-3766.1_NODA, p.4]
PPL also observes that the SO2 emission rates calculated from annual heat input and annual SO2 emissions data in the 'TR SB Limited Trading v4.1 0' and 'TR SB Limited Trading AEO Gas v4.10' parsed data files also come out to this apparently ultra-low SO2 emission rate error of 0.06 lb/MmBtu. But, in these files the problem exists for all of PPL's coal-fired units at the Montour and Brunner Island plants. PPL is very confused and very concerned that this is happening. An SO2 emission rate of 0.06 lb/MmBtu is much lower than the emission rates at which the units presently operate and is much lower than the emission rates for which allocations in the proposed Transport Rule are based for other similar size coal-fired power plants in Pennsylvania that have or that IPM assumes will install FGD systems. The allocation tables for the proposed rule show allocations for all other such units in Pennsylvania based on emission rates over 1 lb/MmBtu and in some cases over 2 lb/MmBtu. [EPA-HQ-OAR-2009-0491-3766.1_NODA, p.4]
PPL requests that this inconsistency and apparent error in the emission rates being assigned to Montour Units 1&2 and Brunner Island Units 1,2&3 be corrected. [EPA-HQ-OAR-2009-0491-3766.1_NODA, p.4]
PSEG Services Corporation
When reviewing EPA's modeling assumptions and results, PSEG has noted a number of incorrect assumptions and unrealistic results. The individual unit corrections are noted below in a table and in reference to the NEEDS database version 4.10. Additionally, one area of particular concern is the model's treatment of dual-fuel oil and gas units. During a July 7, 2010 EPA briefing hosted by the Edison Electric Institute ("EEI"), EPA staff acknowledged that the IPM has difficulty handling dual-fuel units because there are non-economic reasons that a company must run such units that are not considered by the model. PSEG strongly encourages EPA to correct this modeling limitation through adjustments to the model or through post-modeling adjustments to unit emissions. We also note that this issue is not limited to dual-fueled units. [EPA-HQ-OAR-2009-0491-2627.1, p.8]
There are a number of other issues that are not appropriately handled by the model. For Example, PSEG has units located in load pockets with high demand that are modeled as having a lower heat input than has historically been required to maintain reliability. This is a clear example of why EPA should move away from the model-based approach to allocating allowances and toward a historic basis as recommended. If EPA elects not to change the allocation approach, then EPA will need to make the appropriate adjustments to the model or its output. [EPA-HQ-OAR-2009-0491-2627.1, pp.8-9]
We also recommend that prior to finalizing the Transport Rule, EPA release a Supplemental Notice of Proposed Rulemaking and/or a Notice of Data Availability ("NODA") that allows owners of covered units to verify the data underlying the allocations in the final rule and provide any necessary comments correcting the data. For example, if EPA decides to retain the proposed allocation methodology, PSEG recommends that EPA release the updated assumptions and modeling results used as the basis for the allocations along with revised unit allocations. Such a process would provide stakeholders with an opportunity to submit additional corrections before EPA implements the rule and would ensure the final data underlying the rule is as accurate as possible. [EPA-HQ-OAR-2009-0491-2627.1, p.9]
Finally, for future rulemakings, including any companion rules to the Transport Rule, PSEG recommends that EPA publicly distribute any information and data that will be used in the rulemaking through an advanced notice of proposed rulemaking to ensure there is sufficient time to verify the information. This process would allow data verification to occur simultaneously to EPA's development of the proposed rule. Through this process, EPA and owners of covered sources can ensure that the rulemaking is based on the most up-to-date and accurate information, thereby resulting in a more effective and legally-defensible program. [EPA-HQ-OAR-2009-0491-2627.1, p.9]
[See EPA-HQ-OAR-2009-0491-2627.1, p.9 for Table entitled: PSEG corrections to NEEDS database version 4.10]
Documentation for EPA Base Case v.4.10 Using the IPM Document [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.1]
Comment 1: Appendix 3-2.4 only lists NOx RACT regulations from New Jersey that were implemented in 2007, there were significant changes to NOx RACT requirements in 2009, with some taking effect in 2010, 2012 and 2015. Please ensure that these are reflected in EPA's analyses. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.1]
Comment 2: Appendix 3-3.2 erroneously refers to PSEG Fossil's Mercer Generating Station Unit Nos. 1 and 2 NOx control requirements for its NSR Settlement. A NOx Control Rate of 0.13 pounds per million British thermal units (lb/mmBtu) is listed, which was the original commitment of the Consent Decree. However, PSEG Fossil entered into an Amended Consent Decree which lowered the NOx requirements for these units to 0.1 lb/mmBtu, among other changes. This limit took effect on January 1, 2007. Also, these units must meet a PM emission limit of 0.015 lb/mmBtu by December 31, 2010 through the amended Consent Decree. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.1]
Comment 3: Section 4.3 states that EPA Base Case v.4.10 includes all planed-committed units that are likely to come online because ground has been broken, financing obtained, or other demonstrable factors indicate a high probability that the unit will be built before 2012. PSEG Fossil is currently permitting a simple cycle project at its New Haven Harbor Generating Station in New Haven, Connecticut. The proposed project will consist of three GE LM6000PC combustion turbines. The turbines are used to meet peak power demands. The turbines will fire both natural gas and ultra-low sulfur distillate oil (ULSD), and they will utilize water injection and selective catalytic reduction (SCR) for NOx emissions control. The project will provide a summer electrical generating capacity of 129.6 megawatts (MW) and a winter capacity of 145.5 MW. These units are expected to commence commercial operation in June 2012. As such, PSEG Fossil requests that these units be included in EPA's analyses. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.2]
PSEG Fossil is also currently permitting a simple cycle project at its Kearny Generating Station in Kearny, New Jersey. The proposed project will consist of six GE LM6000PC combustion turbines. The turbines are used to meet peak power demands. The turbines will fire natural gas exclusively, and they will utilize water injection and SCR for NOx emissions control. The combined maximum electricity generated by the six turbines will be 294 MW. These units are expected to commence commercial operation in May 2012. As such, PSEG Fossil requests that these units be included in EPA's analyses. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.2]
NEEDS v.4.10 Spreadsheet [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.2]
Comment 4: Rows 4675 through 4679 list Unit No. 1 at the PSEG Bergen Generating Station. The unit's SO2 Permit Rate is listed as 0. This unit emits SO2 when combusting natural gas at approximately 0.00083 lb/mmBtu which is based on its permitted SO2 emission limit of 1.25 pounds per hour (lb/hr). [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.2]
Comment 5: Rows 4675 through 4679 list Unit No. 1 at the PSEG Bergen Generating Station. This unit employs dry low NOx burners (DLNB) and water injection (H2O) as NOx combustion controls. Please add DLNB and H2O to the NOx Comb Control column. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.2]
Comment 6: Rows 4680 through 4682 list Unit No. 2 at the PSEG Bergen Generating Station. The unit's SO2 Permit Rate is listed as 0. This unit emits SO2 when combusting natural gas at approximately 0.00084 lb/mmBtu which is based on its permitted SO2 emission limit of 2 lb/hr. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.2]
Comment 7: Rows 4685 through 4687 and Row 4696 list Unit No. 9 at the PSEG Burlington Generating Station. Rows 4692 through 4695 list Unit No. 11 at the Burlington Generating Station. Based on a review of the facility's EDRs submitted in 2007 in accordance with 40 CFR 75, PSEG Fossil believes the NOx emissions reflected in the spreadsheet should be switched since the facility reported approximately 0.692 lb/mmBtu NOx for Unit No. 9 and 1.2 lb/mmBtu for Unit No. 11. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.2]
Comment 8: Row 4684 and Rows 4689 through 4691 list Unit No. 12 at the PSEG Burlington Generating Station. This unit employs water injection (H2O) as NOx combustion controls. However, this unit does not employ SCR as NOx post-combustion control. Please remove SCR from the NOx Post-Comb Control column. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.2]
Comment 9: Row 4684 and Rows 4689 through 4691 list Unit No. 12 at the PSEG Burlington Generating Station. The controlled NOx rates are listed as approximately 0.02 lb/mmBtu while the uncontrolled NOx rates are listed as approximately 0.1 lb/mmBtu. As stated in Comment 8, this unit does not employ SCR for NOx emissions controls, thus the uncontrolled and controlled NOx emission rates should be identical. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.3]
Comment 10: Row 4710 lists one generator connected to two combustion turbines that are part of Unit No. 12 at the PSEG Essex Generating Station. This unit does not employ water injection (H2O) as NOx post-combustion control for any days except high electric demand days (HEDD) as determined by the New Jersey Department of Environmental Protection. There are approximately 5 to 15 HEDDs per year. The facility does not have discretion to use this control technology on any non-HEDDs. As such, it would make send to remove H2O from the NOx Post-Comb Control column as it would unnecessarily complicate EPA's analyses. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.3]
Comment 11: Row 4710 lists one generator connected to two combustion turbines that are part of Unit No. 12 at the PSEG Essex Generating Station. As stated in Comment 10, this unit does not employ water injection (H2O) for NOx emissions controls, thus the uncontrolled and controlled NOx emission rates should be identical and should be similar to the other units that comprise Unit No. 12 (Rows 4711 through 4713). [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.3]
Comment 12: Row 4722 lists Unit No. 1 at the PSEG Hudson Generating Station. This unit does not employ water injection (H2O) as NOx combustion controls. This unit also does not employ SCR as NOx post-combustion control. Please remove H2O from the NOx Post-Comb Control column and SCR from the NOx Post-Comb Control column. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.3]
Comment 13: Row 4722 lists Unit No. 1 at the PSEG Hudson Generating Station. This unit does not employ water injection (H2O) as NOx combustion controls. As stated in Comment 12, this unit does not employ water injection (H2O) for NOx emissions controls or SCR as NOx postcombustion control, thus the uncontrolled and controlled NOx emission rates should be identical. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.3]
Comment 14: Row 4723 lists Unit No. 2 at the PSEG Hudson Generating Station. This unit does not yet employ SCR as NOx post-combustion control. The SCR is required to be operational on December 31, 2010. Please change the SCR On-Line Year column from 2007 to 2010. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.3]
Comment 15: Row 4723 lists Unit No. 2 at the PSEG Hudson Generating Station. The controlled NOx rates are listed as 0.06 lb/mmBtu. As stated in Comment 14, this unit will employ SCR for NOx emissions controls on December 31, 2010 to achieve a NOx emission limit of 0.1 lb/mmBtu. Thus, the controlled NOx emission rates should be changed to 0.1 lb/mmBtu. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.3]
Comment 16: Rows 4725 and 4726 list Unit Nos. 10 and 11 at the PSEG Kearny Generating Station. These units are committed to being retired on May 1, 2012, commensurate with the startup of four out of six proposed simple cycle combustion turbines referenced in Comment 3 of this letter. Please add May 1, 2012 to the Retirement Date column for these units. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.3]
Comment 17: Row 4728 lists Unit No. 9 at the PSEG Kearny Generating Station. This unit is committed to being retired on May 1, 2013, commensurate with the startup of the remaining two out of six proposed simple cycle combustion turbines referenced in Comment 3 of this letter. Please add May 1, 2013 to the Retirement Date column for these units. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.4]
Comment 18: Rows 4724, 4727, 4729 and 4730 list Unit No. 12 at the PSEG Kearny Generating Station. This unit does not employ a post-combustion NOx emissions control device. As such, the uncontrolled and controlled NOx emission rates for all four columns should be identical. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.4]
Comment 19: Row 4735 lists Unit No. 3 at the PSEG Linden Generating Station. This unit was permanently retired several years ago. Please remove this unit from EPA's analyses. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.4]
Comment 20: Rows 4736 through 4741 list Unit Nos. 1 and 2 at the PSEG Linden Generating Station. These units employ SCR as NOx post-combustion controls. These units also employ dry low NOx burners (DLNB) and water injection (H2O) as NOx combustion controls. Please add DLNB and H2O to the NOx Comb Control column. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.4]
Comment 21: Rows 4736 through 4741 list Unit Nos. 1 and 2 at the PSEG Linden Generating Station. These unit's SO2 Permit Rates are listed as 9999. These units emit SO2 when combusting natural gas at approximately 0.00082 lb/mmBtu which is based on its permitted SO2 emission limit of 2 lb/hr. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.4]
Comment 22: Rows 4731 through 4734 list Unit Nos. 5, 6, 7 and 8 at the PSEG Linden Generating Station. These units do not employ a post-combustion NOx emissions control device. As such, the uncontrolled and controlled NOx emission rates for all four columns should be identical. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.4]
Comment 23: Rows 4743 and 4744 list Unit Nos. 1 and 2 at the PSEG Mercer Generating Station. These units employ SCR as NOx post-combustion control. The SCR became operational in 2004. Please change the SCR On-Line Year column from 1995 to 2004. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.4]
Comment 24: Rows 4743 and 4744 list Unit Nos. 1 and 2 at the PSEG Mercer Generating Station. These units employ Baghouses as PM controls. These units also employ cold side electrostatic precipitators with flue gas conditioning (ESPC) as PM controls. Please add ESPC to the PM Control column. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.4]
Comment 25: Rows 4743 and 4744 list Unit Nos. 1 and 2 at the PSEG Mercer Generating Station. The controlled NOx rates are listed as 0.06 lb/mmBtu. These units employ SCR for NOx emissions controls to achieve a NOx emission limit of 0.1 lb/mmBtu. Thus, the controlled NOx emission rates should be changed to 0.1 lb/mmBtu. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.4]
Comment 26: Rows 4750 through 4753 list Unit Nos. 1, 2, 3 and 4 at the PSEG Sewaren Generating Station. These units do not employ a post-combustion NOx emissions control device. As such, the uncontrolled and controlled NOx emission rates for all four columns should be identical. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.4]
Comment 27: Rows 4952 through 4955 list Unit Nos. 1, 2 and 3 at the PSEG Bethlehem Energy Center. These units employ SCR as NOx post-combustion control. These units also employ dry low NOx burners (DLNB) and water injection (H2O) as NOx combustion controls. Please add DLNB and H2O to the NOx Comb Control column. [EPA-HQ-OAR-2009-0491-3768.1_NODA, p.5]
San Miguel Electric Cooperative, Inc.
Corrections to the Unit Level IPM  [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.2]
San Miguel reviewed the NEEDS (v4.10) and believes the information is correct. San Miguel discovered errors in the IPM Base Case for 2012 parsed file and TR SB Limited Trading Case for 2014 parsed file. The discovered errors are for the San Miguel generating unit and require correction. The ID number for the San Miguel generating unit is 6183_B_SM-1. Similar errors were in the original IPM (v3.02) and were commented on by San Miguel on September 29, 2010. [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.2]
In reviewing the parsed file for the Base Case and the TR SB Limited Trading case discrepancies were discovered:  [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.2]
1. Base Case for 2012: column Q, Retrofit Control 1; and column S, Retrofit SO2/NOx Controls- states "SCR". This is incorrect! The San Miguel unit does not have an SCR, nor is one under construction and there is no plan to install an SCR.  [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.2]
2. Base Case 2012: columns U and V - Summer and Total Fuel Use; column AA and AB - Summer Lignite and Total Lignite Fuel Use; column AC and AD - Summer NOx and Total NOx Emission; column AE - Total SO2 Emission, column AF - Total CO2 Emission; and column AG - Total Hg Emission. All values indicate the unit will only be run during the summer season. This is not correct! The projected values are unrealistic for the following reasons: [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.2]
a. The San Miguel unit is a base load unit, as such the annual heat input varies between 32,000,000 and 35,000,000 mmBtu. [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.2]
b. The San Miguel unit is the least cost energy generator for our consumer -owners and no change in load is expected during the TR base case and limited trading case projections (2012  - 2014). [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.2]
c. Since the San Miguel unit is base loaded the heat input during the ozone season should be approximately 50% of the annual heat input. This is higher than the percentage of the calendar year due to the fact that planned outages are not scheduled during the peak generating season, which coincides with the ozone season. [EPA-HQ-OAR-2009-0491-3740.1_NODA, pp.2-3]
3. TR SB Limited Trading Case for 2014: column Q, Retrofit Control 1 and column S, Retrofit SO2/NOx Controls; states "Coal Early Retirement". This is not correct! The San Miguel unit is the least cost energy generator for our consumer-owners and no change in load is expected during the TR Base Case and TR SB Limited Trading Case projections (2012  - 2014). There are no plans to retire the San Miguel unit in 2014. The unit is and has been a base load unit running at an annual load factor above 80% for years. The San Miguel recently signed wholesale power contracts for the entire output of the unit until the year 2037. [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.3]
4. TR SB Limited Trading Case for 2014: columns U and V - Summer and Total Fuel Use; column AA and AB - Summer Lignite and Total Lignite Fuel Use; column AC and AD - Summer NOx and Total NOx Emission; column AE - Total SO2 Emission; column AF - Total CO2 Emission; and column AG - Total Hg Emission; need to be corrected to show a unit that is base loaded. See discussion above in bullet items 2 and 3 [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.3]
5. Column AE - Total SO2 Emission - in both the Base Case and The TR SB Limited Trading Case emission is unbelievably low for a high sulfur fuel and a scrubber that was designed in 1979. The low SO2 mass emissions indicate the fuel projection or scrubber efficiency in the model is incorrect for the San Miguel unit. San Miguel is a mine mouth plant. In 2009 the fuel averaged 5,280 Btu/lb, and sulfur in the fuel was 2.72%. The San Miguel unit was built with a wet scrubber and in 2009 the actual SO2 removal efficiency averaged 93.8%. Based on the fuel analysis from 2009 the Projected Base Case Annual SO2 Mass emission would specify 98.5% SO2 removal efficiency. This needs to be corrected to the existing scrubber efficiency rather than a new scrubber efficiency projection. [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.3]
6. Column AF  -  Total CO2 Emissions - in both the Base Case and The TR SB Limited Trading Case emission is very low and needs to be corrected for a base loaded unit. [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.3]
7.Column AG - Total Mercury Emissions - in both the Base Case and The TR SB Limited Trading Case emission is very low and needs to be corrected for a base loaded unit. In addition the mercury emissions does not accurately reflect the amount of mercury in our fuel, please see discussion in Fuel Assumptions in IPM for San Miguel Unit in the next section. Mercury emissions need to be corrected for the high levels of mercury in our coal and for a base loaded unit. [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.3]
San Miguel requests the discrepancies be corrected to reflect how the San Miguel unit is actually run. Corrections need to be made in all IPM model runs, not just the models runs outlined above. [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.4]
Fuel Assumptions in IPM for San Miguel Unit  In the documentation for the EPA base case v. 4.10 (Base Case) chapter 9 discusses coal assumptions. We are commenting on the assumptions used for Texas lignite. San Miguel uses a very poor quality of fuel as compared to the fuel characteristics in table 9-3, 9-4 and 9-5.  The table below compares IPM Texas lignite, TX LE, (table 9-5) to San Miguel lignite: [See p. 4 of this comment summary for the table comparing IPM Texas lignite, TX LE, (table 9-5) to San Miguel lignite; EPA-HQ-OAR-2009-0491-3740.1_NODA, p.4]
Per the documentation in Chapter 9, the assumptions in the Base Case on the heat, mercury SO2 and ash content of the coal were derived from the EPA's Information Collection Request of 1998-2000. As you can see from the table above San Miguel fuel does not match the Base Case fuel TX LE. [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.4]
Additionally one of the aspects of the 1998-2000 ICR was to collect accurate information on mercury content of the as-fired fuel. The mercury content information from San Miguel was incorrect. San Miguel commented on this in our comments to the Docket ID No. OAR-2002-0056, on June 22, 2004. The error in mercury content is significant - reported data, approximately 7 lbs/TBtu as compared to the corrected analysis of approximately 32 lbs/TBtu. San Miguel will supply copies to the EPA of the June 22, 2004 comments if requested. [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.4]
San Miguel believes the fuel characteristics needs to be corrected to accurately model the San Miguel Generating Station. [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.4]
Method of Allowance Allocation  EPA is proposing to use the updated version (4.10) of the IPM in the final transport rule. San Miguel believes the corrections state above need to be made to accurately predict emissions for the San Miguel Generating Station. As stated in our comments to the Transport Rule, the EPA should use historic data not model results to establish emissions allocations. Regardless of the sophistication of EPA's model, it does not and cannot accurately forecast how each and every fossil fuel unit among thousands will be utilized. Case in point is the numerous errors, outlined above, of the San Miguel generating unit. It is not likely that the San Miguel unit is the only unit where errors have occurred. [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.4-5]
The model also cannot account for future business decisions, the necessity of which is not yet presently known or anticipated but nonetheless may need to be made that would significantly affect an individual unit's utilization within the utility system. There are literally dozens of significant factors that affect future unit utilization of which the model does not and cannot take into account. [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.5]
San Miguel believes most of the problems inherent in the proposal's methodology could be resolved if state budgeted allowances were distributed to each unit within the state based pro-rata on the unit's portion of the state historic heat rate updated periodically to include new units. Such distribution should sub-categorize between coal, gas, and oil. The allocation methodology could be structured in a manner similar to that contained in Clean Air Interstate Rule (CAIR) for annual NOx allocations as a SIP for all the CATR trading programs. Specifically, the salient features of this methodology include allocating allowances to existing units based on historic heat input using the three highest heat inputs of the past five years to derive annual averages (seasonal for ozone), and allocating allowances to new units based on a set-aside and folding new units into existing unit category after five years of operation. As with the CAIR approach, this methodology could provide options for each state to consider whether new units should receive allowances from a set-aside during their initial year of operation and if retired units should continue to receive allowances, and if so how long or at a diminished allocation. [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.5]
San Miguel encourages the EPA to revise the methodology for unit allocations from the proposed method to a historically based system similar to the CAIR proposal. [EPA-HQ-OAR-2009-0491-3740.1_NODA, p.5]
Seminole Electric Cooperative Inc.
EPA Must Publish another Proposed Rule
As explained in Seminole's comments on the proposed Transport Rule, EPA's proposal suffers from numerous errors in methodologies and numerous incorrect assumptions which impact every aspect of the proposed rule. In fact, the new information associated with the NODA revises assumptions underlying the rule's modeling platform, yet itself does not represent final refinement of EPA's assumptions. Specifically, EPA includes in the NODA a list of further planned revisions to modeling assumptions and inputs that it intends to undertake prior to final rulemaking. [EPA-HQ-OAR-2009-0491-3723.1_NODA, p.1]
EPA acknowledges that changes from using an updated model could impact the final rule in a number of ways, including, but not limited to (1) changing emission projections that were used to determine which downwind areas have air quality concerns absent rulemaking and to determine which states contribute to those problems, and (2) changing cost and emission projections used in the multi-factor test to determine the amount of emissions that represent significant contribution. 75 Fed. Reg. 53614. These changes affect the heart of the proposed rule; changes to the modeling platform will necessarily change the compliance obligations of every state, company and unit, and affected parties must be given an opportunity to review and comment as to whether EPA has corrected its mistakes, made new mistakes, and whether parties can meet their new compliance obligations. Further, EPA's NODA did not provide sufficient information to calculate the air quality impacts, state budgets, or unit allocations resulting from the NODA's revised information. Accordingly, EPA is obligated to publish a second proposal to provide the public an opportunity to review and comment on the accuracy and achievability of EPA's corrected approach before this rule is finalized. [EPA-HQ-OAR-2009-0491-3723.1_NODA, p.2]
EPA Has Not Provided Sufficient Time to Develop Comments
On September 1,2010, EPA published the NODA and placed new information relevant to EPA's proposed Transport Rule in the Transport Rule's docket. This new information modified assumptions integral to the proposed Transport Rule, yet EPA did not extend the already insufficient 60-day commenting period for the proposed rule; rather, EPA provided only an additional 14 days to review and comment on the extensive and complex, newly-provided information. EPA's new and modified information contains assumptions that result in significant changes in cost and generation from the proposed Transport Rule-assumptions and changes that must be analyzed by review of complex data files and spreadsheets. Initial reviews of this data have revealed that EPA has provided only a portion of the information needed to evaluate its implications. Accordingly, EPA has effectively precluded meaningful public involvement by providing insufficient time to review and develop meaningful comment on the proposed Transport Rule and NODA. [EPA-HQ-OAR-2009-0491-3723.1_NODA, p.2]
EPA's IPM Results for Seminole are Materially Wrong
EPA's IPM Base Case v4.10 projects that Seminole's annual fuel use for Unit 1 and 2 will be 41.27 and 40.63 TBtu, respectively.1 This projection is not representative of existing and historic fuel use, which is approximately 50 TBtu per unit per year. As explained in Seminole's comments on the proposed Transport Rule, Units 1 and 2 are baseload units, operating historically between 80 and 85 capacity factor and supplying approximately 60 percent of Seminole's distribution cooperatives' needs. Accordingly, it is materially wrong for IPM to predict that Seminole's units will operate approximately 20 percent less than historic levels. [EPA-HQ-OAR-2009-0491-3723.1_NODA, pp.2-3]
Moreover, the decrease in projected fuel use from IPM Base Case v4.10 to v.3.02 is unexplained by available information. EPA's IPM Base Case v.3.02 projected Units 1 and 2's annual fuel use to be 48.31 and 47.56 TBtu, respectively. EPA has not indicated what changes in assumptions or input into the modeling platform effected this change; therefore, Seminole is unable to adequately comment on this issue, and must be given an opportunity to directly comment once EPA explains the basis for this result. [EPA-HQ-OAR-2009-0491-3723.1_NODA, p.3]
Seminole is also unable to adequately assess, and, therefore, specifically comment on, the fuel quality (I.e., sulfur content) that IPM projects it will use. Seminole provided extensive comments on this issue in its submittal regarding the proposed Transport Rule. While it appears that Seminole's predicted sulfur content has increased between IPM v.3.02 and IPM v4.10, it is still less than current, historic, and permitted values. EPA must explain why and how these values for Seminole changed between v.3.02 and v4.10, and more importantly, EPA must correct its inputs and assumptions such that the IPM results match reality. [EPA-HQ-OAR-2009-0491-3723.1_NODA, p.3]
Seminole was not given sufficient time to review and comment on all of the documents and issues that EPA published as part of its proposed rule on August 2, 2010, and as part of its NODA on September 1,2010. The data and assumptions EPA chose, and the predictions resulting from EPA's IPM modeling, do not resemble reality. Specific corrections must be made to EPA's data, approach, and allocations. In order for Seminole to meaningfully participate in this rulemaking, EPA must publish a corrected version of its proposed rule, and allow an adequate time for review and comment, before it becomes final. [EPA-HQ-OAR-2009-0491-3723.1_NODA, p.3]

1 The IPM unique ID for Unit 1 is '136_B_1'; the ID for Unit 2 is '136_B_2/1. [EPA-HQ-OAR-2009-0491-3723.1_NODA,p.2]
South Carolina Department of Health and Environmental Control 
DHEC notes that the EPA over-relies on IPM in the proposed Transport Rule. The uncertainty inherent in the model means that the EPA should reconsider its use in developing state budgets and unit-level allocations, and instead use empirical heat-input data as it did in the NOx SIP Call and the Clean Air Interstate Rule ('CAIR). The uncertainty in IPM led DHEC to request more appropriate thresholds for including states in the in the Transport Rule. With thresholds of 1 ug/m3 for the 1997 and 2006 Particulate Matter National Ambient Air Quality Standards ('NAAQS') and 1 ppb for the 1997 Ozone NAAQS, South Carolina would not be subject to the Transport Rule trading programs. If the EPA changes the modeling approach used in making threshold determinations based on new data on the NODA, DHEC requests that the EPA re-notice the proposal to provide adequate opportunity for review and meaningful comments to be developed. [EPA-HQ-OAR-2009-0491-3718.1_NODA, p.2]
DHEC notes that even if the NEEDS data is correct, then the Budgets and Allocations Spreadsheet still indicates that the EPA does not necessarily include all of the actual controls listed in NEEDS, in part because it determined that the controls were installed to comply with the CAR. The EPA should reconsider this decision not to include CAIR-based controls. South Carolina's utilities, and their rate payers, committed considerable resources to installing and operating controls on several coal-fired units to meet the requirements of the CAIR. [EPA-HQ-OAR-2009-0491-3718.1_NODA, p.2]
Southern IL Power Cooperative
The "NEEDSv410" spreadsheet shows uncontrolled NOX emission rates for SIPC's Unit 123 boiler as 0.0920 lb/MBtu and Unit 4 boiler as 0.999 lb/MBtu. These numbers are incorrect, and the proper uncontrolled emission rates should show Unit 123 boiler uncontrolled NOX emission rate as 0.16 lbs/MBtu and Unit 4 (cyclone) boiler as 1.2 lbs/MBtu. Similarly, the 2014 SO2 emission rate shown for Unit 123 is 0.318 lbs/MBtu and Unit 4 is 0.325 lb/MBtu. Our average emission rates for these boilers from 2006 through 2009 have been 0.499 lbs/MBtu for U123 and 0.484 lbs/MBtu for U4. These values equate to 90  -  92% reduction of SO2 because of SIPC's pollution control strategies and equipment. The various pollution control equipment that is employed by Southern Illinois Power Cooperative were state-of-the-art when they were constructed (wet FGD & ESP for Unit 4 in 1978 & SCR for U4 and CFB with SNCR in 2003), and it is not logical to "assume" that higher reduction efficiencies can be obtained from such equipment. The proposed allocation methodology departs radically from previous Clean Air Act allowance allocation without explanation. By requiring such additional reductions, EPA is punishing facilities that have chosen to reduce their emission footprint by installing such pollution control equipment early. In doing so, EPA is also punishing their customers who have paid for such emission reduction improvements through rate increases over the years. SIPC believes this is bad policy, and such actions will dissuade utilities from investing in the cleanest generation technology in the future. [EPA-HQ-OAR-2009-0491-2863.1 p.3]
State of Louisiana, Department of Environmental Quality
Comment: Based on the new data, Louisiana should be removed from the Transport Rule. [EPA-HQ-OAR-2009-0491-3725.1_NODA, p.1]
Louisiana is included in the proposed Transport Rule as a state that shows 'significant contribution' and 'interference with maintenance' with monitors located in Texas. Based on new information contained in the NODA, LDEQ's position is that Louisiana should be removed· from this rulemaking. [EPA-HQ-OAR-2009-0491-3725.1_NODA, p.1]
In the proposed rulemaking, EPA used as its base case the following inventories: [EPA-HQ-OAR-2009-0491-3725.1_NODA, p.2]
Sulfur dioxide (S02): 98,110 tpy [EPA-HQ-OAR-2009-0491-3725.1_NODA, p.2]
Annual nitrogen dioxide (NOx): 43,946 tpy [EPA-HQ-OAR-2009-0491-3725.1_NODA, p.2]
Ozone season: NOx 21,220 tpy [EPA-HQ-OAR-2009-0491-3725.1_NODA, p.2]
When using these emissions as the base case for the IPM v3.02, Louisiana was considered to either contribute to or interfere with the attainment/maintenance of monitors located in Texas. However in this NODA (IPM vA.l0), EPA used the following emissions inventories, which accurately reflect the actual emissions inventories, as inputs: [EPA-HQ-OAR-2009-0491-3725.1_NODA, p.2]
S02: 80,381 tpy [EPA-HQ-OAR-2009-0491-3725.1_NODA, p.2]
Annual NOx: 32,804 tpy [EPA-HQ-OAR-2009-0491-3725.1_NODA, p.2]
Ozone season NOx: 15,159 tpy [EPA-HQ-OAR-2009-0491-3725.1_NODA, p.2]
The differences in the base case inventories are now greater than the required emission reductions that are necessary to eliminate significant contribution or interference with maintenance as listed in the Transport Rule. The reductions in the base case for S02 are greater than two times the reductions that the proposal required. The NOx reductions are approximately one and one-half times greater than those required by the proposed rulemaking. This mathematical equation indicates that Louisiana is no longer a significant contributor and should therefore be removed from the proposed rule. [EPA-HQ-OAR-2009-0491-3725.1_NODA, p.2]
West Virginia Department of Environmental Protection
The WV DEP also requests an extension of the public comment period on EPA's Notice of Data Availability Supporting Federal Implementation Plans To Reduce Interstate Transport of Fine Particulate Matter and Ozone, as published at 75 FR 53613, 01 SEP 2010. EPA announced a 45-day public comment period on this Notice of Data Availability (NODA), requiring comments to be submitted by October 15, 2010. WV DEP is requesting an extension of the public comment period by 45 days, to November 30, 2010. [EPA-HQ-OAR-2009-0491-2057, p.1]
Subsequent to the proposed Transport Rule, EPA released the NODA, which contains a substantial amount of additional information directly related to the proposed Transport Rule. EPA has allowed only 45 days for review of the NODA, 30 days of which are concurrent with the review of the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-2057,p.1]
The issuance of the NODA, which contain new data and modeling results shows that EPA has acknowledged inaccurate or flawed data in the development of the proposed rule . EPA should reevaluate the results caused by these changes and the updated evaluation should be placed in the rule -making docket so that states, affected industry sources and the general public can understand the ramifications of the new NODA information . It is apparent that states' previously developed comments regarding data and modeling for the Transport Rule also may need to be reevaluated in light of the new data contained in the NODA, whether or not agencies have formally submitted them to the docket. An extension of the comment deadline will allow the WV DEP to prepare detailed constructive comments that may be useful to the EPA in finalizing this rule. [EPA-HQ-OAR-2009-0491-2057, p.2]
Given that the Clean Air Interstate Rule (CAIR) is still in place, we do not believe there will be any environmental harm caused by extending the comment period on the proposed Transport Rule and the NODA until November 30, 2010, to allow for a proper review of the technical information and the development of constructive comments for how the proposal can be improved . We urge EPA to grant this extension and provide adequate time for meaningful feedback. [EPA-HQ-OAR-2009-0491-2057, p.2]
The West Virginia Division of Air Quality (WVDAQ) previously commented on the proposed Transport Rule and offers the following comments regarding EPA's subsequent, related Notice of Data Availability (NODA) [75 FR 53613]. WVDAQ believes that EPA has once again provided a totally inadequate time for meaningful review and comment on the voluminous technical documentation. The agency's web-page lists four IPM runs comprising over 27 megabytes of information and 11 chapters describing Base Case v4.10 comprising over 24 Mb of information. Despite the brief review time, WVDAQ staff have identified the following significant inaccuracies in the inputs to the IPM model. It is likely that other corrections and improvements may have been detected had more review time been available. It also seems likely that the cumulative effect of mistakes, both known and unknown, could alter some of EPA's original conclusions. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.1]
Mt. Storm Unit JF1 (3954_G_JF1) is an emergency generator and should not be included in the NEEDS v4.10 database. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.1]
Morgantown Energy Associates (l0743B_CFB1 and CFB2) is identified in NEEDS v4.10, however, it was not allocated allowances under the Transport Rule, as proposed. The WVDAQ believes that EPA did not include MEA in the proposed allocations because it was erroneously assumed that the facility would meet the exemption requirements for cogeneration units. However, MEA does not meet the exemption requirements as proposed. Therefore, the facility should be treated as an existing unit under the Transport Rule and allocated allowances accordingly. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.1]
Alloy Steam Station (500 12_B_BLR4) does not provide power to the grid and should not be included in the NEEDS v4.10 database. The Alloy Steam Station should not receive allocations under the Transport Rule. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.2]
Philip Sporn Unit 51 is a 450 MW operational unit which was not included in the NEEDS v4.10 database, and should be included. EPA should refer to EIA for the unit characteristics and include this unit in an updated NEEDS database. Philip Sporn Unit 51 should receive allocations under the Transport Rule. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.2]
RFCP _WV_Coal_Steam (82914_C_1) in the NEEDS v4.10 database refers to the Longview Power Plant under construction in Monongalia County. The correct ORIS Code for this facility is 56671. The facility was allocated allowances in the proposed Transport Rule for 2012 and 2013, but not 2014 and beyond. The facility meets the proposed definition of an existing unit and, therefore, should receive allocations for 2014 and beyond, as well as for 2012 and 2013. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.2]
Ft. Martin Unit 1(3943_B_1) is identified in NEEDS v4.10 as having a scrubber which came online in 2006, the scrubber did not come online until October 31, 2009. It is also identified as having an SNCR which came online in 1997, however, the unit is equipped with SNCR-Trim, a single point injection system, which is not designed with a 35% removal efficiency, but rather a 10-15% removal efficiency. Furthermore, the SNCR-trim was installed in 2004, not 1997. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.2]
Ft. Martin Unit 2 (3943_B_2) is identified in NEEDS v4.10 as having a scrubber which came online in 2006, however, the scrubber did not come online until August 26, 2009. It is also identified as having an SNCR which came online in 1997, however, the unit is equipped with SNCR- Trim, a single point injection system, which is not designed with a 35% removal efficiency, but rather a 10-15% removal efficiency. Furthermore, the SNCR-trim was installed in 2004, not 1997. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.2]
Harrison Unit (3944_ B_) is identified in NEEDS v4.10 as having a PM scrubber, the unit is not equipped with a PM scrubber, instead it is equipped with a wet FGD for S02 control. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.2]
Harrison Unit 2 (3944_ B_2) is identified in NEEDS v4.10 as having had an SCR installed in 2000, however, the SCR came online April 1, 2003. NEEDS v4.10 also indicates that Unit 2 is equipped with a PM scrubber, instead it is equipped with a wet FGD for S02 control. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.2]
Harrison Unit 3 (3944_B_3) is identified in NEEDS v4.10 as having had an SCR installed in 2000, however, the SCR came online April 1, 2003. NEEDS v4.10 also indicates that Unit 3 is equipped with a PM scrubber, instead it is equipped with a wet FGD for S02 control. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.2]
John Amos Unit 1 (3539 _B_1) is identified in NEEDS v4.10 as having a wet scrubber with an online year of2008, however, the scrubber is not scheduled to come online until 2011. John Amos Unit 2 (3539_B_2) is identified in NEEDS v4.10 as having a wet scrubber with an online year of 2008, however, the scrubber did not come online until March of 2010. NEEDS also indicated that the SCR came online in 2005, when it actually came online May 16, 2004. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.3]
John Amos Unit 3 (3539_B_3) is identified in NEEDS v4.10 as having a wet scrubber with an online year of 2007, however, the scrubber did not come online until May of 2009. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.3]
Kammer Unit 1 (3947 _B_1) is identified in NEEDS v4.10 as having a scrubber with an online year of 2007. This unit has never been, and is not currently, equipped with a scrubber. Furthermore, the WVDAQ has no knowledge of any plans for a scrubber to be installed on this unit by 2014. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.3]
Karnmer Unit 2 (3947_B_2) is identified in NEEDS v4.10 as having a scrubber with an online year of 2007. This unit has never been, and is not currently, equipped with a scrubber. Furthermore, the WVDAQ has no knowledge of any plans for a scrubber to be installed on this unit by 2014. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.3]
Mitchell Unit 2 (3948 _B_2) is identified in NEEDS v4.10 as having a scrubber with an online year of2006, when the scrubber did not come online until January 15, 2007. [EPA-HQ-OAR-2009-0491-3731.1_NODA, p.3]
Response: 
In regards to comments received suggesting a longer comment period, supplemental proposal, re-proposal of the Transport Rule, EPA feels that it provided reasonable comment periods for the TR proposals and subsequent NODAs.  Furthermore, EPA made materials available to the public through its website before each comment period began.  This had the effect of adding additional time beyond the stated comment period for review, effectively extending the stated 30, 45, or 60 day comment period.  Furthermore, the Court did not specify a definitive date by which EPA should promulgate the Transport Rule, it did not give the Agency an infinite stay on CAIR and did, in fact, indicate that the Transport Rule was to be completed in a timely manner.  Section 307(d)(5) of the CAA requires the Administrator to give an opportunity for written or oral comments.  The Act does not specify the length of time, other than the record must be open 30 days after holding public hearings - with which EPA complied.  Given the time frame EPA provided to the public for submission of comments, and indicative of the fact that the Agency received several thousand substantive comments, commenters did, in fact, have sufficient time to submit their comments for consideration.  Section XVII of this RTC document addresses these comments more thoroughly.
EPA recognized that there was significant comment regarding IPM assumptions, the impact of those assumptions on unit level IPM projections, and the proposed allocation methodology which relied on IPM projections for unit level allocations.  EPA's response to these concerns was twofold.  First, EPA changed its allocation methodology to be based on historic heat input and emissions data that is generally reported by the sources' Designated Representative who testifies to its accuracy and completeness.  By switching to a historic data based methodology, the degree to which any discrepancy between a unit's actual future operation and its IPM projected future operation would impact the unit's allocation is greatly diminished.  EPA recognizes that IPM is a dynamic linear programming model that generates optimal decisions under the assumptions of perfect foresight and results in a least cost method of meeting demand.  However, invariably, there will be discrepancies between IPM unit level projections and a unit's actual future operations due to non-economic or other variables that IPM does not capture.  Stakeholders emphasized this point  through the comments  At the state and regional level, as pointed out by some commenters, these non-economic variables do not have a significant impact because the sample of units being examined is large and unit level disparities between projected and observed data generally balance out.  However, their impact at the unit level may be significant and this was one of the drivers behind switching to an allocation method based on historic data.
Second, EPA reviewed the comments and has made significant updates to its IPM v.3.02 modeling used at proposal and the initial IPMv.4.10 made available in the September 1, 2010 NODA .  These updates include changes to both the more general IPM assumptions (e.g., gas price assumptions) and specific unit level assumptions (e.g., that current retrofit status at a unit).  These updates were made to the IPM model, and the updated version (EPA IPM v.4.10) was used for all the final rule analysis.  In regards to unit specific adjustments, EPA did not manually adjust projected unit level modeling outputs, but it did make unit level updates to its NEEDS database used as a model input which impacts the modeling projections when rerun for final Transport Rule analysis.  Some of the more prevalent IPM comments regarding IPM were addressed through major modeling updates.  For instance, FGD removal efficiency was adjusted for new retrofits, and for existing retrofits it was indexed to historic performance at the unit.  Additionally, EPA modified its modeling to better reflect the cost and feasibility of switching and blending coals.  EPA also modified its capital cost for control technologies, added new control technologies (e.g., DSI), adjusted it approach to cogeneration modeling, incorporated additional state rules and consent decrees and made thousands of adjustments to unit level assumptions based on comments received from stakeholders.  For more detailed discussion of EPA IPM v.4.10 assumptions and assumption updates, see the EPA IPM v.4.10 documentation (specifically "Documentation Supplement for EPA Base Case v.4.10_FTransport - Updates for Final Transport Rule") and the "Transport Rule IPM Assumptions Response to Comments" in the Appendix.  This later document categorizes and indexes many of the unit level adjustments that were made in response to corrected data submitted by commenter.  For instance, if the commenter suggested that EPA's data did not accurately reflect the control status at a particular unit and suggested a change, EPA reviewed the comment and made such changes where the comment was significant and reasonable.  The Appendix contains a record of the several thousand unit level changes made in IPM of this nature.
Also, in regards to unit level compliance concerns, EPA notes that there are a variety of options available to sources and that the rule does not require any one particular compliance option for a particular source, but affords flexibility for the source to determine its least cost option.  See section VII.C of the preamble for further discussion regarding compliance with the 2012 and 2014 compliance timeframes.
Organization: Kansas Department of Health and Environment
Kansas City Power and Light Company (KCP&L)
Kansas City Board of Public Utilities (BPU)
Comment: 
Kansas City Board of Public Utilities (BPU)
EPA FAILED TO FULLY UTILIZE THE ADDITIONAL INFORMATION IN THE NODA LEADING TO INCORRECT STATE BUDGETS AND UNIT ALLOCATIONS [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.6]
The NODA Fails to Fully Evaluate the Effects of the Revised IPM Data on the Rule [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.6]
The NODA includes an updated version of the power sector modeling platform with different unit level input data and new IPM runs. EPA proposes to use the new IPM runs in the final Transport Rule; however, as more fully explained in the attached October 14, 2010 letter from Trinity Consultants [see p.11 of this comment summary for the Trinity Consultants' letter], EPA failed to publish revised projected 2012 emissions in the NODA. Id. at 53614/3. The NODA recognizes that '[c]hanges from the projections relied on in the proposed rule, from using an updated model, could impact the final rulemaking in a number of ways....' Id. Such impacts include '(1)[c]hanging emission projections that were used to determine which downwind areas have air quality concerns ... and to determine which States contribute to those problems[]'; and '(2) [c]hanging cost and emission projections used in the multi-factor test to determine the amount of emissions that represent significant contribution.' Id. [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.7]
The revised IPM data would affect the projected 2012 emissions. Projected 2012 emissions in turn affect evaluation and quantification of an upwind state's contribution and interference with maintenance. Consequently, a state's emission budget, which is tied to EPA's quantification of each individual state's significant contribution and interference with maintenance, will be affected by the revised IPM data. It follows that individual unit allocations will change by virtue of a change in the state emissions budget. Therefore, EPA's failure to publish revised projected 2012 emissions results in a failure to provide reasonable notice to EGUs about how state budgets and individual unit allocations will be made under the Rule. [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.7]
Reported emissions should be adjusted using a five-year look-back period [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.7]
EPA's Technical Support Document entitled 'State Budgets, Unit Allocations, and Unit Emissions Rates' ('TSD') describes the process used to determine a state's budget. State budgets were based on the lesser of the state's adjusted projected emissions versus the state's adjusted reported emissions for the fourth quarter of2008 and the first three quarters of 2009. Annual and ozone season NOx emissions were adjusted 'to account for unusually low utilization in 2009' which will 'typically result[] in larger annual NOx emissions.' Id. at 9. This adjustment was calculated by multiplying the emissions by the ratio of the 2008 heat input to the heat input determined for the fourth quarter of 2008 and the first three quarters of 2009. Id. The ozone season emissions were adjusted by multiplying the emissions by the ratio of the 2008 ozone season heat input to the 2009 ozone season heat input. Id. [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.7]
Although EPA through this adjustment exercise implicitly recognized the need to use representative data, the heat input data used fails to be representative and, therefore, fails to provide a supportable basis for the requirements that will be imposed under the Rule. EPA should implement a five-year look-back period to provide representative heat input data from which to calculate emissions. Five years provides an adequate period of evaluation to accommodate variation in utilization. In addition, a five-year look-back is consistent with other data evaluation regulations under the Clean Air Act such as the New Source Review regulations. [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.8]
EPA failed to make heat input adjustments in calculating SO2 emissions in contravention to the recognized need to make adjustments. Thus, the SO2 emissions used to calculate state budgets and then individual allocations are not representative under EPA's own view. This leads to inconsistent regulatory results and a flawed basis for SO2 state budgets and consequent individual unit allocations. [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.8]
Adjusted reported emissions should include emissions for units that lawfully operate yet are not required to report to the Clean Air Markets Database [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.8]
The state budgets are based on the lesser of the State's adjusted projected emissions and its adjusted reported emissions. Reported emissions were gathered from units that report to the Clean Air Markets database; however, the Rule applies to individual units that are not required to report to the Clean Air Markets database. Consequently, a state's adjusted reported emissions does not account for emissions from units not included in the Clean Air Markets database regardless if the units were in operation during the relevant time period. Units lawfully operating yet not required to report to the Clean Air Markets database received zero allocations in Appendix A to the TSD accompanying the Rule. [EPA-HQ-OAR-2009-0491-3750.1_NODA, pp.8-9]
BPU has three units at its Quindaro plant, GT1, GT2 and GT3 and one unit, CT4, at its Nearman plant that received zero allocations in Appendix A to the TSD. All of these units operated under authorization of Clean Air Act permits during the relevant time period for consideration in the Rule and NODA and will continue to operate. The units are not required to report emissions on the Clean Air Markets database and the state of Kansas was not included in the NOx SIP Call. Failure to provide allocations for these units cannot be supported under applicable law including the Clean Air Act and implementing regulations. [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.9]
NODA does not contemplate enforceable NOx reductions from additional emissions controls [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.9]
The IPM data included in the NODA fails to include NOx reductions from the addition of low NOx burners at BPU's Quindaro Unit 2 and Nearman Unit 1. Pursuant to Section 28-19-713 of the Kansas Administrative Regulations, BPU is required to achieve NOx reductions at Quindaro Unit 2 to 0.20 lb/mmBtu by January 1,2012 and reductions at Nearman Unit 1 to 0.26 lb/mmBtu by July 1,2012. BPU believes EPA should have accounted for such reductions in the NODA model runs. Such reductions would minimize the contribution of these units to attainment and maintenance in downwind states and therefore should have been included in the IPM projections. [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.9]
For the reasons stated herein, BPU requests that EPA recalculate state budgets and individual unit allocations using the revised IPM projections included in the NODA and incorporate the following modifications in the recalculation: [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.10]
1. Recalculate significant contribution and state budgets/individual unit allocations using the revised IPM modeling from the NODA; [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.10]
2. Recalculate SO2 emissions based on heat input adjustments; [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.10]
3. Use a five-year look-back period when adjusting heat input for reported NOx and SO2 emissions; and [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.10]
4. Provide Appendix A allocations for units not required by law to report to the Clean Air Markets database. [EPA-HQ-OAR-2009-0491-3750.1_NODA, p.10]
[See p.14 of this comment summary for Attachment 1 entitled, Annual SO2]
Kansas City Power and Light Company (KCP&L)
Comments on EPA Base Case v.4.10
1. In Base Case v.4.10, EPA has provided two IPM scenarios, one including the AEO Gas module and one without. EPA does not state which set of runs will be used, and there are significant differences between the results for individual units. EPA should state its intent so that comments may be focused on one scenario or the other. [EPA-HQ-OAR-2009-0491-2709.1, p.7] [EPA-HQ-OAR-2009-0491-3757.1_NODA, pp.3-4]
2. There are errors in the unit information contained in the NEEDS v.4.10 database.
a. The Iatan Unit 1 wet scrubber and baghouse not included (this is identified in EPA's Planned Updates to IPM v.4.10).
b. The SNCR for Sibley Units 1 and 2 is not included, nor is the SCR for Sibley Unit 3 (this is identified in EPA's Planned Updates to IPM v.4.10)
c. SO2 Emission Rates
i. The SO2 permit rate for Iatan Unit 1 should be 0.07 lb/MmBtu, per the current Title V operating permit, instead of 1.2 lb/MmBtu.
ii. The SO2 permit rate for Lake Road Unit 6 should be 1.43 lb/MmBtu, per the current Title V operating permit, instead of 8.6 lb/MmBtu. [EPA-HQ-OAR-2009-0491-2709.1, pp.7-8] [EPA-HQ-OAR-2009-0491-3757.1_NODA, p.4]
d. NOx Emission Rates
i. Mode 1 Uncontrolled NOx Base Rates
(1) Hawthorn Unit 5A has a rate of 0.0714 lb/MmBtu, which is clearly with the SCR online. This is incorrect, as Mode 1 should represent the uncontrolled emission rate. This unit has never reported uncontrolled emissions, and it operates the SCR year-round, so it is not clear how EPA would obtain an uncontrolled emission rate.
(2) The rate of 0.5103 lb/MmBtu for La Cygne Unit 1 (ID 1241_B_1) is incorrect. That unit began operating an SCR on June 1, 2007. The SCR operates year-round in order to meet the unit's construction permit limit of 0.15 lb/MmBtu. An appropriate uncontrolled rate for Unit 1, taken from 2006 (pre-SCR) ARP reported data, would be 0.94 lb/MmBtu. [EPA-HQ-OAR-2009-0491-2709.1, p.8] [EPA-HQ-OAR-2009-0491-3757.1_NODA,p.4]
ii. Mode 2 Controlled NOx Base Rate
(1) For Hawthorn Unit 5A, the rate of 0.06 lb/MmBtu may or may not be correct depending on the resolution of 2.d.i.(1) above. It should be the lesser of [0.1* the correct Uncontrolled NOx Base Rate] or 0.06 lb/MmBtu.
(2) For La Cygne Unit 1, the rate of 0.06 lb/MmBtu is incorrect. Using the Mode 1 rate and 90% removal efficiency yields 0.094 lb/MmBtu, which is greater than the floor rate of 0.06 lb/MmBtu. According to EPA's methodology, the Mode 2 rate equals the lesser of 0.094 and the ETS summer NOx rate, which for this unit is 0.30 lb/MmBtu. Therefore, the Mode 2 NOx rate for La Cygne Unit 1 should be 0.094 lb/MmBtu. [EPA-HQ-OAR-2009-0491-2709.1, p.8][EPA-HQ-OAR-2009-0491-3757.1_NODA,p.4]
iii. Mode 3 Uncontrolled NOx Policy Rate
(1) The rate of 0.5103 lb/MmBtu for La Cygne Unit 1 is incorrect. Because Mode 3 = Mode 1 for units with SCR post-combustion NOx control, this rate is also incorrect and should be 0.94 lb/MmBtu.
(2) The rate of 0.23 lb/MmBtu for La Cygne Unit 2 (ID 1241_B_2) appears to have been calculated using the equations in Table 3-1.3 of Appendix 3-1, but that is incorrect. La Cygne Unit 2 is a coal unit without post-combustion NOx controls. Regardless of whether or not it has combustion controls, the Mode 1 rate is less than the cutoff rate in Table 3-1.2. It therefore has SOA control and its Mode 3 rate is determined per Step 5 (see Appendix 3-1.2 and 3-1.3). The summer NOx rate is less than the provisional SOA NOx rate, so the Mode 3 rate should be equal to the summer NOx rate.  The 2007 ozone season rate was 0.30 lb/MmBtu. [EPA-HQ-OAR-2009-0491-2709.1,pp.8-9][EPA-HQ-OAR-2009-0491-3757.1_NODA, pp.4-5]
iv. Mode 4 Controlled NOx Policy Rate
(1) For La Cygne Unit 1, Mode 4 = Mode 2. The Mode 4 rate should be corrected to 0.094 lb/MmBtu per 2.d.ii.(2) above. [EPA-HQ-OAR-2009-0491-2709.1, p.9] [EPA-HQ-OAR-2009-0491-3757.1_NODA, p.5]
2 EPA has not provided the necessary data to allow meaningful comment on the data provided in the NODA and the docket omits much of the information necessary to evaluate the nature and extent of the likely changes to the Proposed Transport Rule ("PTR"). In support of the PTR, EPA provided the results of 48 IPM runs, which provided at least some basis for evaluating and commenting on the various steps in EPA's process of developing unit-specific allowance allocations. [EPA-HQ-OAR-2009-0491-3757.1_NODA, p.2]
Due to its decision to apply the revised inventory and model as the last step in its methodology in developing a final rule, EPA provided in the NODA only a fraction of the IPM runs necessary to allow electric utilities to understand and comment on the impact of the NODA on unit-specific allocations as well as to attempt to replicate EPA's methodology for determining such allocations. Utilities therefore have no way of predicting what their allocations will be or to verify that the allocations contained in the final rule are appropriate.  [EPA-HQ-OAR-2009-0491-3757.1_NODA, p.2]
In the PTR, the information contained in the "Allocation Table  -  Technical Support Document for the Transport Rule  -  State Budgets, Unit Allocations, and Unit Emission Rates" provided electric generating companies at least some ability to evaluate the accuracy of EPA's assumptions with respect to their individual units. Such tables were not provided to account for the changes contained in the NODA.[EPA-HQ-OAR-2009-0491-3757.1_NODA, p.2]
This lack of IPM data also makes it impossible for even the states themselves to determine the revised 2012 statewide annual emissions budgets for SO2 and NOx and the seasonal budgets for NOx based on EPA's updated NEEDS database and revised platform because, as stated in the "State Budgets, Unit Allocations, and Unit Emission Rates" ("State Budgets") TSD, the 2012 budgets are based on the lower of the recent actual emissions or the 2012 IPM-projected base case emissions at the state level. Without a revised 2012 IPM-projected basis, there is no means of comparison to the actual data to determine which scenario results in lower state-wide emissions. [EPA-HQ-OAR-2009-0491-3757.1_NODA, pp.2-3]
3. EPA's decision to base the 2014 SO2 allowance allocations for units in Group 1 states on the same statewide caps proposed in the PTR is arbitrary and unjustified, given that the purpose of the NODA was to correct and update unit level input data in NEEDS v.4.10. EPA has not provided justification for not providing an updated "TR SO2 2000" IPM run using the updated NEEDS database and IPM modeling platform. [EPA-HQ-OAR-2009-0491-3757.1_NODA, p.3]
EPA's decision to re-run the Limited Trading unit-level parsed file for 2014 with the revised NEEDS database and updated IPM platform while leaving state budgets based on the unrevised data used in the PTR results in an incorrect state budgets and therefore incorrect unit-level allocations. [EPA-HQ-OAR-2009-0491-3757.1_NODA, p.3]
4. EPA continues to ignore the effects of CAIR, even though it remains binding law until it is replaced by a valid rule. EGUs, even in states covered by CAIR but that may not be regulated under the Transport Rule, have already made emissions reductions pursuant to CAIR and it is not certain that they will increase their emissions to pre-CAIR levels, or it if will even be legal for them to do so, once CAIR expires. [EPA-HQ-OAR-2009-0491-3757.1_NODA, p.3]
5. Even EPA, by issuing the Planned Updates to IPM v.4.10 Technical Support Document (TSD), has identified the need for further refinement of the IPM input data. The regulated community should have an additional opportunity to review and comment on the changes once they have been made. [EPA-HQ-OAR-2009-0491-3757.1_NODA, p.3]
Kansas Department of Health and Environment
It is unclear how the new IPM runs will affect the cost curves as this was not discussed in the NODA issued on September 1, 2010. KDHE recommends future rulemakings include the latest data for all aspects of the rule so stakeholders can comment on one set of data that affect various parts of the rule and the underlying decisions therein. [EPA-HQ-OAR-2009-0491-2606.1, p.7]
One large concern that KDHE has on the rulemaking process, and our ability to effectively comment, concerns the late arrival of additional data coupled with a virtually overwhelming amount of technical data and documentation on this proposed rule. Providing the NODA at such a late date is useful for better understanding what final emissions might be, but at the same time it makes the CAMx modeling and allocations obsolete as there is now a large disconnect between the CAMx modeling and underlying emissions along with questions on what the final allocations may look like in light of this new data. KDHE recommends in future rulemaking that EP A provides the latest inventory data and modeling concurrently so all stakeholders can effectively comment and review the entire package without wasting precious resources reviewing data that is changed midcourse in the review process. [EPA-HQ-OAR-2009-0491-2606.1, p.8]
Response: 
EPA has responded to the above concerns through two primary changes in its final Transport Rule analysis.
First, EPA finalized an allocation methodology that is based on unit level historic, not projected, data.  This addresses the significant body of public comment expressing concern over the IPM unit level projections and their impact on unit level allocations.  See section VII.D of the preamble for more discussion on the final allocation approach under a FIP.
Second, EPA has made significant updates to its IPMv.4.10 model based on comments received in both the Transport Rule and NODA1 comment periods.  These changes include unit level changes (e.g., updating the SCR and SNCR status at Sibley units per commenters corrections) and more universal updates (e.g., including constraints to reflect Section 28-19-713 of the Kansas Administrative Regulations per commenters corrections).  These types of updates improved the models representation of EGUs.  EPA conducted all of its final rule air quality and multi-factor analysis using values provided  by this updated IPM.v4.10 model.  See EPA IPMv.4.10 documentation and the RTC Appendix for further discussion on IPM assumptions and updates made in response to comments.
EPA's decision to base the 2014 SO2 allowances in the NODA3 on the same caps as those that were proposed was not arbitrary as those budgets reflected EPA's best available data at the time.  At the point of issuing the NODA3, EPA had not determined the final Transport Rule geography nor had it redone budget analysis with the IPMv.4.10 model.  Furthermore, as EPA pointed out in the NODA3, the intention of the NODA was to provide the public with final allocations, but to demonstrate the new methodologies, the underlying data that would be part of those allocation approaches, and the percentage of state budgets that would be allocated to a source under that alternative approach.  The NODA3 provided commenters the opportunity to review and comment on each of these inputs to the final allocation methodology.  For the final allocation methodology, EPA was able to review the significant body of public comment received on the allocation alternatives and corrections to underlying data, and appropriately incorporate those comments.
In regards to comments received suggesting a longer comment period, supplemental proposal, re-proposal of the Transport Rule, EPA feels that it provided reasonable comment periods for the TR proposals and subsequent NODAs.  Furthermore, EPA made materials available to the public through its website before each comment period began.  This had the effect of adding additional time beyond the stated comment period for review, effectively extending the stated 30, 45, or 60 day comment period.  Furthermore, the Court did not specify a definitive date by which EPA should promulgate the Transport Rule, it did not give the Agency an infinite stay on CAIR and did, in fact, indicate that the Transport Rule was to be completed in a timely manner.  Section 307(d)(5) of the CAA requires the Administrator to give an opportunity for written or oral comments.  The Act does not specify the length of time, other than the record must be open 30 days after holding public hearings - with which EPA complied.  Given the time frame EPA provided to the public for submission of comments, and indicative of the fact that the Agency received several thousand substantive comments, commenters did, in fact, have sufficient time to submit their comments for consideration.  Section XVII of this RTC document addresses these comments more thoroughly.
Organization: Midwest Ozone Group
Utility Air Regulatory Group (UARG)
Wisconsin Power and Light Company
New York Power Authority
Rochester Public Utilities (RPU)
Minnesota Power 
Greenmont Energy Consulting LLC.
Connecticut Department of Environmental Protection
New York State Department of Environmental Conservation
Tennessee Valley Authority (TVA)
Southern Company
NRG Energy
State of Ohio Environmental Protection Agency (Ohio EPA)
Comment: 
Connecticut Department of Environmental Protection
CTDEP offers current, quality controlled data to replace out-of date or inaccurate information for certain Connecticut units. CTDEP also offers corrections to the statutory and regulatory information used in preparing the base case modeling. These inaccuracies in data and assumptions are compounded by the inherent limitations of the Integrated Planning Model (IPM) in projecting unit-level operations in small geographic areas such as the State of Connecticut. The issues of concern, more fully described below, must be corrected for the Transport Rule to function as intended and protect public health within Connecticut. [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.1]
I. DOCUMENTATION FOR EPA BASE CASE V. 4.10, CHAPTER 3, POWER SYSTEM OPERATION ASSUMPTIONS
Appendix 3-2 State Power Sector Regulations included in EPA Base Case v. 4.10 
NOx - The 'Emission Specifications' field states that a 0.15 lbs/MmBtu annual rate limit applies for all fossil electric generating units > 15 MW. However, the 0.15 lbs/MmBtu limit specified in Regulations of Connecticut State Agencies (RCSA) section 22a-174-22 (Control of NOx) is a non-ozone season limit (from October 1 through April 30, inclusive), not an annual limit. The non-ozone season NOx limit does not apply to fossil-fired units unless the units are subject to both RCSA section 22a-174-22 and the NOx Budget Program.! The Environmental Protection Agency (EPA) should revise the 'Emissions Specifications' field as follows: [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.1]
Emission Specifications: 0.15 lbs/MmBtu non-ozone season rate limit (October 1 through April 30, inclusive) for all sources subject to RCSA section 22a-174-22 that are also NOx Budget Program sources. [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.1]
SO2: The 'Bill' field states that the relevant legal references are Executive Order 19, RCSA 22a-198 and Connecticut General Statues (sic) (CGS) 22a-198. However, the correct regulatory references are RCSA section 22a-174-19a and Connecticut General Statutes section 22a-198. Executive Order 19 directed CTDEP to adopt regulations and laid out the framework for the requirements but did not apply directly to sources, so the reference to it should be deleted. In addition, the 0.33 lbs/MmBtu rate referenced in the 'Emission Specifications' field is a quarterly rate instead of an annual rate, and the 0.33 lbs/MmBtu rate only applies to Title IV sources that are also equal to or greater than 15 MW or equal to or greater than 250 MmBtu/hr. As alternatives, sources can combust fuel with a fuel sulfur limit of equal to or less than 0.3% sulfur or can average and meet a quarterly emission rate of 0.3 lb/MMBtu.2 For fossil fuel-fired sources equal to or greater than 15 MW or equal to or greater than 250 MmBtu/hr that are not Title IV sources, a 0.55 lb/MmBtu emission rate applies starting January 1, 2002 (as alternatives, sources can combust fuel with a fuel sulfur limit equal to or less than 0.5% sulfur or can average and meet a quarterly emission rate of 0.5 lb/MmBtu). [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.2]
EPA should revise the Bill, Emission Specifications and Implementation Status fields as follows: [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.2][[See Docket Number EPA-HQ-OAR-2009-0491-3715.1_NODA, pp.2-3 for the revisions.]]
Mercury (Hg) -The 'Bill' field references RCSA 22a-198, however the correct statutory reference is CGS section 22a-199. The reference to Public Act No. 03-72 should be removed since it was codified in CGS section 22a-199. In addition, the 'Emission Specifications' field includes incorrect emission limit information. EPA should revise the 'Bill' and 'Emissions Specifications' fields as follows: [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.3]
Bill: CGS section 22a-199
Emissions Specifications: (A) Meet an emissions rate of equal to or less than 0.6 pounds of mercury per TBtu, or (B) meet a mercury emissions rate equal to a ninety per cent reduction of mercury from the measured inlet conditions for the affected unit, whichever emissions rate is more readily achievable by such affected unit. [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.3]
II. TR 2012 BASE-CASE V 4.10 IPM RUN
As explained in CTDEP's comments on the Transport Rule submitted on September 30, 2010, the IPM Base Case model run for 2012 projects that the 9 oil/gas load following boilers (LFBs) in Connecticut will not operate in 2012. However, all 9 LFBs have already bid into the ISO-NE Forward Capacity Market through May 2013 and are contractually obligated to be available through that date, making it highly unlikely that they will cease operations by 2012. Furthermore, 8 of the 9 LFBs are contractually obligated to be available in the Forward Capacity Market through May 2014. Only Bridgeport 2 is not contractually obligated through May 2014. CTDEP recommends that EPA consider the Integrated Resource Plan model results (see Attachment C of CTDEP's September 30, 2010 Transport Rule comments) and contractual obligations of the LFBs and revise the IPM model results accordingly. [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.3] [[See Docket Number EPA-HQ-OAR-2009-0491-2780.1, pp.26-367 for Attachment C.]]
III. NEEDS V. 4.10
The items described below are also highlighted or changed in red in the spreadsheet in Attachment A: [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.3][[see Docket Number EPA-HQ-OAR-2009-0491-3715.2_NODA for Attachment A.]]
Peaking unit NOx rates
NEEDS v. 4.10 includes either a 0.1490 lb/MmBtu NOx rate (all four modes) or a 1.2 lb/MmBtu default rate (all four modes) for the following units: [EPA-HQ-OAR-2009-0491-3715.1_NODA,p.4] [[See Docket Number EPA-HQ-OAR-2009-0491-3715.1_NODA, p.4 for the table.]]
Presumably, the 0.1490 lb/MmBtu emission rate is from the non-ozone season restriction of 0.15 lbs/MmBtu in RCSA section 22a-174-22. However, with the exception of the Cos Cob units, these units are not controlled. All units have actual emission rates higher than 0.:1490 lb/MmBtu and with the exception of the Cos Cob units, higher than 75 ppmvd (24-hr limit}. These units do not have continuous emissions monitors, so the actual emission rates provided in Table 1 are from emissions test data. All of the units currently comply with permitted and/or regulatory limits by operating under Trading Agreements and Orders (see Attachment B} that allow the sources to purchase NOx discrete emission reduction credits and/or NOx allowances through May 31, 2014. The Trading Agreements and Orders set the framework by which the owners and operators of the peaking units will assess energy market conditions and current and planned environmental restrictions in order to determine operational status beyond May 31, 2014. CTDEP recommends that EPA revise NEEDS v. 4.10 to reflect the actual emission rates of the turbines in Table 1.[EPA-HQ-OAR-2009-0491-3715.1_NODA, p.5]
Kleen Energy
NEEDS v. 4.10 lists the on-line year of the two combined cycle turbines at Kleen Energy as 2008. However, Kleen Energy has not started operating yet, and will not likely begin operating until at least mid-2021. CTDEP recommends that EPA change the on-line year for gleen Energy in NEEDS v. 4.10 from 2008 to 2011 and the ORIS plant code from 56798 G to 56798 C. [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.5]
Unlisted existing/committed units
There are several existing and committed units that are not listed in NEEDS v. 4.20. CTDEP recommends that EPA include the units listed on Attachment A to NEEDS v. 4.10. [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.5]
SO2 Emission rates for Covanta Bristol Energy, Covanta Wallingford Energy and Wheelabrator Lisbon
The SO2 emission rates listed in NEEDS v. 4.10 for Covanta Bristol Energy (units 1 & 2), Covanta Wallingford Energy (units 101-103) and Wheelabrator Lisbon (BW1 & BW2) are 0.5S lb/MmBtu, 0.55 lb/MmBtu and 0.3 lb/MMgtu, respectively. However, the permitted SO2 emission rate for all of the units is 29 ppmvd, or 0.07 lb/MmBtu. CTDEP recommends that EPA revise the SO2 emission rates for all of the Covanta Bristol Energy, Covanta Wallingford Energy, and Wheelabrator Lisbon units to 0.07 lb/MmBtu.
NOx combustion control for Bridgeport Energy Project, Milford Power, Wallingford Energy, Kleen Energy, Waterside Power and Algonquin Windsor Locks
NEEDS v. 4.10 does not list NOx combustion control for the Bridgeport Energy turbines. The turbines have low NOx burners and water injection for NOx controls. NEEDS v. 4.10 lists dry low NOx Burners (with water injection for Wallingford Energy and Kleen Energy) for Milford Power, Wallingford Energy and Kleen Energy for NOx controls, but NOx controls consist of regular low NOx burners. All of Waterside Power's turbines have water injection, but unit 7 in NEEDS v. 4.10 does not have water injection listed as a NOx control. Algonquin Windsor Locks has ammonia injection for post-combustion NOx control, but it is not listed in NEEDS v. 4.10. CTDEP recommends that EPA revise NEEDS v. 4.10 with the correct NOx controls. [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.5] 
Committed units to be removed
EPA lists 2 committed units, a 24 MW combined cycle unit and a 100 MW combustion turbine that EPA should remove from NEEDS v. 4.10. The 200 MW combustion turbine may be Waterbury Generation that is separately listed as an additional unit and CTDEP does not have knowledge of a 24 MW combined cycle unit that has started construction or secured financing to ensure start-up prior to the end of 2011. [EPA-HQ-OAR-2009-0491-3715.1_NODA, pp.5-6]
Covanta Mid-CT Energy, units 11-13 mercury controls efficiencies
The mercury controls efficiency column entries for Covanta Mid-CT Energy, units 11-13 are blank but the units have permitted mercury controls efficiencies of 85%. CTDEP recommends that EPA add the appropriate mercury controls efficiencies for Covanta Mid-CT Energy, units 11-13.  [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.6]
Waterside Power, LLC, unit 7 modeled fuels
Distillate fuel oil is the only modeled fuel listed for Waterside Power, LLC's unit 7. However, the unit is also permitted to burn natural gas. CTDEP recommends that EPA add natural gas as a modeled fuel for Waterside Power, LLC, unit 7.  [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.6]
John Street 1 & 2 and Cytec 1 & 2 NOx limits and controls
The John Street 1 & 2 and Cytec 1 & 2 units were issued revised permits in 2008. The NOx limit in the old permits was 2.67 lb/MMgtu. The NOx limit in the new permits is 0.27 lb/MmBtu. All of the units installed SCR for NOx control. Although NEEDS v. 4.1 is based on 2007 data, comments were added to the spreadsheet regarding the revised permit limits and NOx controls so that EPA may make updates in future versions of NEEDS. [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.6]
Bushranger Ingelheim and CMEEC 8 on-line years
NEEDS v. 4.10 lists 2011 as the on-line year for Boehringer Ingelheim and CMEEC 8. However, both units started operating in 2008. [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.6]
CTDEP urges EPA to make the changes recommended in this letter. Previously, CTDEP has expressed significant concerns to the EPA about the IPM and its documented inability to accurately project unit level operations in smaller states such as Connecticut. It is CTDEP's expectation that EPA's incorporation of the recommended changes will improve the accuracy of the modeling used for the final Transport Rule. [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.6]

1. NOx Budget Program units are fossil fuel-fired stationary sources serving a generator with a nameplate capacity of 15 MW or greater or a fossil fuel-fired boiler or indirect heat exchanger with a maximum heat input capacity of 250 MmBtu/hr or more. [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.1]
2 RCSA section 22a-t74-19a(e), Sulfur dioxide emissions standards and fuel sulfur limits effective on and after January I, 2003. Notwithstanding the provisions of subsection (b) of this section, this subsection shall apply, on and after January 1, 2003, to the owner or operator of a Title iV source that is also an affected unit or units. On and after January 1, 2003, such owner or operator shall: (1) Combust liquid fuel, gaseous fuel or a combination of each provided that each fuel possess a fuel sulfur limit of equal to or less than 0.3 % sulfur, by weight (dry basis); (2) Meet an average emission rate of equal to or less than 0.33 pounds SO2 per MmBtu for each calendar quarter for an affected unit at a premises; or (3) Meet an average emission rate of equal to or less than 0.3 pounds SO2 per MmBtu calculated for each calendar quarter, if such owner or operator averages the emissions from two or more affected units at a premises. [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.2]
3. RCSA section 22a-174-19a(c), Sulfur dioxide emission standards and fuel sulfur limits effective on and after January 1, 2002. On and after January 1, 2002 and except as provided in subsection (f) of this section, the owner or operator of an affected unit or units shall: (1) Combust liquid fuel, gaseous fuel or a combination of each provided that each fuel possess a fuel sulfur limit of equal to or less than 0.5 % sulfur, by weight (dry basis); (2) Meet an average emission rate of equal to or less than 0.55 pounds SO2 per MmBtu for each calendar quarter for an affected unit at the premises; or (3) Meet an average emission rate of equal to or less than 0.5 pounds SO2 per MmBtu calculated for each calendar quarter, if such owner or operator averages the emissions from two or more affected units at the premises. [EPA-HQ-OAR-2009-0491-3715.1_NODA, p.2]
Greenmont Energy Consulting LLC.
My analysis shows that the Integrated Planning Model (IPM), which is used in the various modeling run cases made public by EPA, has numerous problems which make it unreliable as a predictor of future industry and market impacts and is therefore inconsistent with the 'Objectivity' guideline of the federal 'Data Quality Act' as promulgated by the Office of Management and Budget. Based on my many years of experience and study, it is my opinion that the disseminated data generated by IPM for this purpose is not presented in a manner that is accurate, clear, complete and unbiased; neither is it accurate, reliable and unbiased in a matter of substance. [EPA-HQ-OAR-2009-0491-3713.1_NODA, p.1]
The following are deficiencies in the Integrated Planning Model (IPM):
- IPM's use of 'prototype' plants on the demand side and 'prototype' mines on the coal supply side of the modeling does not provide sufficient specificity to determine reliable forecasts.
- IPM does not approach the exploitation of existing coal mines in the appropriate way because of the manner in which IPM handles the use of mining cost curves to provide coal supply. [EPA-HQ-OAR-2009-0491-3713.1_NODA, p.1]
- IPM uses overly simplified coal transportation cost estimates which are often not representative of the actual cost of movement of coal to specific coal-fired plants and therefore result in incorrect economic decision-making in the model.
-IPM does not solve in an integrated manner of simultaneously considering the variation of several key variables, but rather runs separate 'modules' in a looping fashion which often leads to a failure of the composite to 'converge' to the correct optimal solution.
- IPM does not adequately account for all of the driving forces behind increases and decreases in allowance prices under a cap and trade system.  [EPA-HQ-OAR-2009-0491-3713.1_NODA, p.2]
For these reasons, it is my opinion that the data upon which EPA relied in proposing its regulations is unreliable. [EPA-HQ-OAR-2009-0491-3713.1_NODA, p.2]
Midwest Ozone Group
In the September 1, 2010 NODA, EPA gives notice that it has placed additional information that EPA admits is 'relevant' to the proposed Transport Rule, including 'an updated version of the power sector modeling platform that EPA proposes to use to support the final rule.' 75 Fed. Reg. 53,613/1. The additional information is voluminous and consists of at least thirty-four files, some of which are large 'zipped' files, and totals over 3,000 pages. Most importantly, and as EPA acknowledges in the NODA the additional information '[c]hanges ... the projections relied on in the proposed [Transport Rule]'. Id. at 53,614/3. The projections form the foundation for EPA's determining the upwind states to be covered by the final rule and the amount of emissions reductions to be required by those states in the final rule. [EPA-HQ-OAR-2009-0491-1921.1, p.2]
The changes are not minor, technical corrections. In EPA's own words:
Changes from the projections relied on in the proposed rule, from using an updated model, could impact the final rulemaking in a number of ways including, but not limited to:
1. Changing emissions projections that were used to determine which downwind areas have air quality concerns (i.e., non-attainment or maintenance) absent this rulemaking and to determine which States contribute to those problems.
2. Changing cost and emission projections used in the multi-factor test to determine the amount of emissions that represent significant contribution. Id. at 56,314/3. [EPA-HQ-OAR-2009-0491-1921.1, p.2]
MOG recognizes that EPA has established a separate comment period for its "Notice of Data Availability Supporting Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone; Notice of Data Availability (NODA) for the Proposed Transport Rule," published September 1, 2010 (75 Fed. Reg. 53,613). MOG is reviewing the NODA at this time and will offer comments by the established deadline. [EPA-HQ-OAR-2009-0491-2809.1, p.2]
MOG also notes that the NODA deals mainly with the allocation process. MOG believes that allocations should be reserved to the affected states. At most, MOG believes that EPA might establish state specific emissions caps, but the allocations of those emissions within the cap should be done at the option of the individual states, not EPA. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.cover page 1]
The comment period on the NODA is arbitrarily and unreasonably short and MOG joins many others in requesting that EPA reopen the comment period, allowing a reasonable comment period and providing supporting technical documents that were not made available to the public as part of the NODA. It is impossible based on the short comment period allotted and the lack of supporting data for anyone to make meaningful comments on either the NODA or the CATR. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.cover page 1]
With respect to the IPM projections, Mr. Marchetti concludes that there are major significant modeling disconnects between the CATR and the NODA, including errors in specific unit emission rates, mistakes in projected unit retirements, disparities in installed SCR and FGD capacity between the CATR and NODA, suspect allowance pricing assumptions, erroneous and arbitrary assumptions regarding availability of new pulverized coal and wind capacity and erroneous NODA base case emissions. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.cover page 2]
General Comments on the NODA [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.2]
The NODA was released in the middle of the comment period on the Proposed Transport Rule (TR), at which time EPA announced a new modeling platform IPM version 4.10. The information in the NODA is both voluminous and substantially different (e.g., new generation forecast, revised control assumptions) from the information used in the TR. EPA has provided only a 45 day comment period on the NODA, which ran concurrently with the comment period on the TR, ending a mere 14 days after the comment period for the TR. As a result EPA has failed to provide adequate time for commenters to review this large body of new information and provide meaningful comments. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.2]
Unlike the TR, EPA failed to provide any Technical Support Documents (TSDs) on the NODA, which are critical in understanding the new modeling platform, specifically in regard to unit allowance allocations. Without this type of information, electric generators are unable to thoroughly identify and assess errors and inaccuracies and evaluate how those errors and inaccuracies should be corrected, and are left to guess what these values will be under the NODA [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.2]
EPA Should Provide Proposed Revised Unit Allocations [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.2]
In the NODA, EPA indicated the information and assumptions in the documents issued with the NODA will be the information and assumptions used in a new modeling platform (4.10) that will be used to develop the final rule. As pointed out by EPA, there are significant modeling changes to IPM in version 4.10, in comparison to the modeling information used in the TR. For example, EPA used a different electrical generation forecast in version 4.10 in comparison to the TR. As mentioned earlier, version 4.10 incorporated the electrical generation forecast from EIA's Annual Energy Outlook 2010 (AE020 I0); whereas, the TR modeling used AEO 2008. As shown in the figure below [see p.3 of this comment summary for Figure 1 entitled, Forecasted National Generation: AEO 2008, 2009 & 2010], there are significant differences between the two forecasts. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.2]
The primary underlying factor impacting these generation forecasts is the economic recession of 2009. AEO 2008 was completed (January 2008) prior to the economic events beginning in late 2008, while the modeling for AEO 2010 includes data from the recession and reflects the effects of economic downturn in its electrical generation forecast. Since the 2014 SO2 allocations are based upon forecasted heat input and emissions it is critical that EPA provide information on how the incorporation of this new generation forecast, along with changes in other assumptions, will impact 2014 SO2 unit allocations. This will allow electric generators to compare their allocations under the TR and NODA and be able to more thoroughly identify and assess errors and inconsistencies. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.3]
Potential Implications for 2014 Allocations in Using AEO 2010 and Modeling Outputs [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.3]
As indicated earlier, the forecasted electrical generation from AEO 2010 is significantly lower than AEO 2008. A major consequence of using a lower generation forecast is that on the whole, units will have lower heat input, which is a major component in the computing of 2014 unit SO2 allocations for Group 1 States. To assist in analyzing the NODA modeling we used two electric generating unit data sets and they are: (i) Ameren's electric generating units in Illinois; and, (ii) AEP's electric generating units in West Virginia. The primary purpose of using these two data sets is to identify and track potential errors and modeling inconsistencies with regard to the NODA, which might be prevalent throughout EPA's modeling. The two parsed files that were the focus of this initial evaluation are: (i) the Proposed Transport Rule (TR) 2014 TR_SB_Limited Trading file; and, (ii) the NODA's 2014 TR_SB_Limited Trading file. [EPA-HQ-OAR-2009-0491-3746.1_NODA, pp.3-4]
Using Ameren's Illinois and AEP's West Virginia units as examples and replicating EPA's 2014 SO2 allocation methodology using the NODA file 2014 TR_SB_LT and the same 2014 state budgets as the TR, it was found that both systems could experience a significant decrease in their 2014 SO2 allocations primarily due to changes in projected heat input, as well as some modeling outputs. The modeling concerns relate to some changes in technology deployment/retirements and SO2 emission rates between the Transport Rule's 2014 TR_SB_LT parsed file and the NODA 2014 TR_SB_LT parsed file. Many of these changes seem to be attributable to modeling disconnects and/or data base errors which are discussed later. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.4]
[See p.4 of this comment summary for Table 1 entitled, Comparison of 2014 Heat Input and SO2 Allocation - Transport Rule and NODA]
EPA use of modeled projections for individual unit utilization and emission reduction capability, as a basis for permanent unit allocations will result in gross inequities in the allocation of allowances. To avoid these types of allocation issues, it is recommended that EPA use a historical time series based upon heat input, similar to the CAIR NOx allocation methodology to allocate unit allowances. This historical time series can be adjusted every year based upon new operating information. The use of historical data better reflects how a unit has actually operated instead of some future projection, which is based upon assumptions related to future operation and technology deployment. Consequently, the use of historical information avoids many of these pitfalls. In addition it is also recommended that the states handle the unit allocations, as they do in CAIR NOx. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.4]
Modeling Disconnects between the Proposed Transport Rule and the NODA [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.5]
In an attempt to better understand the modeling information presented in the NODA, two parsed files were examined and compared and they were: (i) TR's 2014 TR_SB_LT (2014) parsed file for SO2 and NOx; and, (ii) the NODA's 2014 TR_SB_LT (2014) parsed file for SO2 and NOx. To undertake the SO2 analysis, the same two data sets - Ameren - IL and AEP - WV - were used to highlight these modeling disconnects and data base errors. As shown in Table 2 [See p.6 of this comment summary for Table 2 entitled, SO2 Modeling and Data Issues - Transport Rule and the NODA], several modeling issues have been identified. If analysis of small data sets like these has identified several problems, there is a major concern that these same types of issues exist throughout the entire modeling results of the NODA. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.5]
In the TR 2014 Joppa 1 - 6 is retrofitted with an FGD; however, in the NODA 2014 the unit is retired. In addition, the Joppa units in NODA 2014 have SO2 emission rates comparable to a retrofitted FGD; however, their heat input is 84 percent less than TR 2014 heat input due to a projected retirement in 2014. (The parsed file seems to indicate the Joppa units are projected to be retired sometime during 2014.) It should be noted Ameren does not have any plans to retire Joppa by 2014. Moreover, in any event, it does not seem logical that a unit, which is a candidate for an FGD in one simulation, is retired in another simulation. Understanding there are changes in control cost assumptions, which may make a retrofit uneconomical, it would seem more plausible that the Joppa units be treated like Meredosia 3 and be economical to operate in NODA 2014 without an FGD. NODA 2014 modeling does retire almost 3,000 MW of FGD capacity that was retrofitted under TR 2014. Some of this retired capacity is under agreements with either EPA or a state to retire, repower or retrofit by a specific date. If this is the case EPA needs to identify these units in the NEEDS Data Base 4.10 that they are candidates for retirement. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.5]
Another modeling/data base disconnect relates to the Kammer units. In TR 2014 the three units are retrofitted with FGD systems (even though AEP does not have plans to install FGD systems on any of these units); however, in NODA 2014, Kammer 1 and 2 have existing FGD systems, which is incorrect. There are no existing FGD systems on either Kammer 1 and 2. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.5]
There also seem to be some unusual emission rate differences between the two parsed files, specifically units with an FGD system. For example Duck Creek's SO2 emission rate moves from 0.133 in TR 2014 to 0.295 in NODA 2014, and the Philip Sporn units' emission rate more than doubles. These radical changes in SO2 emission rates seem to indicate some kind of modeling error. Also, it seems the 0.087 SO2 emission rate for an FGD is some kind of default value; EPA should explain whether and why that is the case. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.5]
In evaluating NOx, the NODA modeling seems to have applied some very aggressive NOx emission rates on some coal units. Using the Ameren - IL data set as an example, the table below illustrates some of these concerns. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.6; see p.7 of this comment summary for Table 3 entitled, NODA NOx Modeling Issues]
Coffeen I & 2 are cyclone boilers with an existing SCR and are burning a sub-bituminous coal and it is unlikely that either of these units could achieve a NOx rate of 0.06 lbs/mmBtu. The Joppa units in 2009 had NOx rates that ranged between 0.112 and 0.121 lbs/mmBtu, while burning a sub-bituminous coal and operating Low NOx Burners (LNB) and Separated Overfire Air (SOFA). The NODA modeling of these units has them being retired, which was discussed earlier, as well as achieving very aggressive NOx emission rates of 0.063 and below. The combination of retiring units and achieving SCR-like emission rates at the same time does not make sense. Moreover, it should be noted, such low NOx emission rates clearly cannot be achieved with the use of LNB/SOFA without the addition of post-combustion controls (which the NODA information does not project will be installed on these units). Both Newton 1 & 2 have LNB and OFA, along with Operational Modifications (OPMOD) and burn a subbituminous coal and achieved 2009 NOx emission rates of 0.092 and 0.100 lbs/mmBtu, respectively. NODA modeling has Newton 1 at a 0.060 lbs/mmBtu rate with a retrofitted SCR and Newton 2 at 0.082 lbs/mmBtu. It is unlikely an SCR would be retrofitted on Newton 1 to move from 0.092 to 0.060 lbs/mmBtu due to the high cost of an SCR, and the availability of cheaper alternatives (e.g., SNCR). Secondly, the Newton 2 NODA NOx rate is very aggressive and to achieve that type of rate would require some additional post-combustion technology. [EPA-HQ-OAR-2009-0491-3746.1_NODA, pp.7-8]
Changes in FGD and SCR Capacity [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.8]
With the changes in both generation forecast (AEO 2008 to AEO 2010) and other assumptions in the NODA modeling, there is a considerable decline in 2014 of retrofit FGD capacity and a smaller, but still significant, decline in retrofit SCR capacity, as compared with EPA's original projections in this rulemaking, as shown in Figures 2 & 3. [See p.8 of this comment summary for Figure 2 entitled, Comparison of 2014 Retrofit FGD Capacity Under the Transport Rule and NODA; see p.9 of this comment summary for Figure 3 entitled, Comparison of 2014 Retrofit SCR Capacity Under the Transport Rule and NODA] Specifically, the NODA modeling estimates almost 12 GW of FGD capacity and 7.4 GW of SCR capacity will have to be installed by 2014 to achieve the targets of the TR. On the other hand earlier TR modeling estimated almost 25 GW of FGD capacity and 8.3 GW of SCR capacity would be installed by 2014. This is a significant drop between the two simulations. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.8]
As shown in both figures there are sizeable amounts of modeled FGD and SCR capacity that are either retired or for some other reason do not receive a retrofit in the NODA modeling. Some of the retired capacity is on units that have been identified as potential retirements stemming from either consent decrees or state programs. However, there is still slightly over 10 GW of FGD capacity from the TR modeling that is projected not to receive FGD systems. Even after accounting for a projected reduction in future electrical generation in moving from ABO 2008 to ABO 2010, which will affect emissions, EPA still needs to better explain the underlying factors leading to this 10 GW reduction in projected FGD capacity. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.9]
Allowance Prices Seem Unrealistic [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.9]
In the NODA TR_SB_Limited Trading System Summary Report, EPA presents SO2 allowance prices under the TR for both Group 1and 2 states. For 2015 EPA estimates Group 1 SO2 allowance prices at $313 and Group 2 allowance prices at $184. These values seem very unrealistically low given the marginal cost of control for FGD systems based upon EPA's revised FGD control assumptions, and a focus on intra-state trading due to the limitations on regional trading. In an analysis of an SO2 allowance market for a Group 1 state under the TR and allowing for only intra-state trading, the projected SO2 allowance prices were around $1,900 in  2015. Consequently, it seems EPA has significantly underestimated the prices of SO2 allowances under TR. [EPA-HQ-OAR-2009-0491-3746.1_NODA, pp.9-10]
Also, there is a NOx allowance market under TR, both seasonal and annual; however, EPA provides no NOx allowance prices. Does this mean that under TR no entity will have to buy or sell allowances for compliance or did EPA just miss computing both seasonal and NOx allowance prices? EPA needs to explain why no NOx allowance values are present in the NODA TR_SB_Limited Trading System Summary Report. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.10]
NODA Coal Retirements and Data Base Issues [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.10]
In a quick review of the NODA Parsed File_TR SB Limited Trading, there seem to be some potential errors/issues with regard to coal units projected to be retired by EPA. The table below [see p.10 of this comment summary for Table 4 entitled, Example Concerns Related to EPA Unit Retirements] presents some examples of these modeling concerns. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.10]
Consequently, EPA not only needs to further explain how these additional retirements were determined, but thoroughly review the modeling results to insure they are plausible given the future plans of many coal-fired units. If a unit has been retired due to a consent decree and/or state agreement, this information should be contained either in the NEEDS 4.10 Data Base or the parsed file. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.11]
Given the very short time allowed by EPA to evaluate the entire NODA information package, it is difficult to thoroughly identify all the potential data base issues. However, here are examples of a few data base issues that could be quickly identified and they are: [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.11]
No existing FGDs on Kammer 1 & 2 (as noted above), Bay Shore 4 and Shawville 2, which are identified in the NEEDS Data Base 4.10 as having existing FGDs. Also in the new NEEDS Data Base, Potomac River I - 5 and Dunkirk 3 & 4 have been identified as having a DFGD system, when in reality they have a TRONA system. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.11]
Sunbury 1 - 4 in the NEEDS Data Base 4.10 are projected to have a WFGD installed in 20 I0, but these retrofits have been put on hold. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.11]
Cape Fear 5 in the NEEDS Data Base 4.10 is expected to have a WFGD installed by 2011, but the unit will be retired between 2013 and 2017. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.11]
John Sevier 1-2 in the NEEDS Data Base 4.10 is expected to have a WFGD installed by 2011, but these two units will be idled between 2014 and 2015. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.11]
Kyger Creek in the NEEDS Data Base 4.10 is expected to have a WFGD installed by 2012, but the FGD system is planned for 2013 at the earliest. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.11]
EPA Estimate of New Pulverized Coal Capacity and Wind Capacity Do Not Seem Plausible [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.11]
In the TR, EPA estimates by 2020 there would be 54.7 GW of new pulverized coal capacity; however, in the NODA there is 0 GW of new pulverized coal projected capacity for 2020. On the other hand EPA estimates 4.0 GW of wind capacity in 2020 under the TR, but in the NODA EPA estimates 22 GW of wind capacity in 2020. This is almost a complete inverse of the two energy sources and does not seem plausible. EPA needs to explain how one iteration of the model yields one result, while a second iteration yields a completely opposite result. Even AEO 2010 predicts a modest increase in new coal capacity by 2020 of 15.6 GW under a remanded Clean Air Interstate Rule (CAIR) regulatory regime. AEO 2010 uses the same 3 percentage-point capital charge adder for the lack of a CO2 policy, but their capital costs for a new pulverized coal unit are slightly below those assumed in IPM version 4.10. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.11]
NODA Base Case Emissions are Unrealistic [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.12]
As mentioned in our comments filed on October 1,2010 on the Proposed Transport Rule, EPA fails to consider the extensive amounts of controls installed after 2005, resulting in a large and erroneous overestimation of emissions, because EPA assumes that CAIR is not in effect. 2 This erroneous assumption continues in the NODA's Base Case SO2 and NOx emission projections, even though in 2009 electric generators in the CAIR region began complying with the rule's NOx requirements and this year (2010) began meeting the rule's SO2 requirements. Electric generators will continue to comply with CAIR until the first year of compliance with the replacement rule. The table below [See p.12 of this comment summary for Table 5 entitled, EPA and MOG National Emission Forecast Comparison - 2012 & 2015] illustrates the significant overestimation of emissions in EPA's NODA Base Case compared to MOG's Business As Usual (BAU) forecast, which includes compliance with CAIR. [EPA-HQ-OAR-2009-0491-3746.1_NODA, p.12]
Minnesota Power 
Review time.  The magnitude of Proposed Transport Rule and NODA data offered by EPA for review is vast and time for review has been scant.  Minnesota Power has observed deviations between the initial Transport Rule and NODA/NEEDS data ascribed to Minnesota sources.  EPA has indicated that it intends to make final determinations about State significant contributions and prospective Group 1 and Group 2 State SO2 and NOx budgets using some data that has not yet been generated or made available for review and comment. Conceivably, Minnesota affected utility units could be determined to be out of the Transport Rule, subject to Group 2 State requirements or prospectively subject to Transport Rule 2, State requirements.  Consequently, Minnesota Power requests that EPA provide another opportunity for data review and comment after EPA makes its proposed final determinations.  It is important that EPA provide the regulated community the opportunity to understand the basis for data discrepancies and seek corrections before the Transport Rule is finalized.   [EPA-HQ-OAR-2009-0491-3742.1_NODA, p.3]
Clear basis for determining Transport Rule compliance obligations.  There are still apparent discrepancies in Minnesota source emissions data and model input assumptions used by EPA in their modeling and the Minnesota actual emissions and projected emissions at modeled output levels and permitted emission rates. For example, the EPA projected budget for Minnesota presented in the Transport Rule tallies to a different amount than is referenced by EPA in the NODA unit level allocations.  EPA has indicated that further adjustments in proposed Minnesota emissions budgets may occur through the use of updated data and modeling analysis.  EPA should clearly identify the basis for unit level emissions applied when they estimated state significant contributions to nonattainment and state emission budgets calculated relative to a 2005 base year, emission control retrofit estimates and assumptions about future unit generation output.  [EPA-HQ-OAR-2009-0491-3742.1_NODA, p.3]
Credit for controls installed from 2000 to Transport Rule enactment.  The Clean Air Act, Acid Rain Program established requirements for emission reductions in 1995 and 2000 for the same group of emission sources EPA is proposing for regulation under the Transport Rule.  EPA is citing 2005 as a base line for determining the percent emission reductions to be achieved by Transport Rule, proposed 2012 or 2014 compliance dates.  Yet, EPA in the Transport Rule Technical Support Documents and related inputs cited in the NODA for IPM modeling indicates that utility units that have provided for emission control retrofits since 2005 will have their emissions budgets adjusted to reflect post control emission rates, without consideration of the Transport Rule percent emission reduction targets.  Since Group 2 States are targeted for an approximate 50% reduction in emissions, a generating unit that provided for 90% emission reductions after 2005 (e.g. installed selective catalytic reduction technology for NOx reductions) may receive no credit for outperforming targeted reductions when receiving its budget allocation.  Generating units that did not provide for emission reductions do not experience this write down of their budget allocation.  Consequently, it is not clear if EPA is giving reasonable consideration or credit for early controls installation in the Transport Rule. [EPA-HQ-OAR-2009-0491-3742.1_NODA, pp.3-4]
Wind backup duty.  As the production of wind based generation increases in a region subject to renewables performance standards, there is an increasing need for backup resources like natural gas and coal based generation to provide reliability to the electric system when the wind is not blowing.  That sort of service can require that coal and natural gas units targeted for control under the proposed Transport Rule can fall short of budget allocations needed to preserve electric system reliability.  EPA's NODA does not appear to include information about how EPA addresses the need for dispatch of fossil fueled generation sources to support system reliability under wide scale deployment of renewables. [EPA-HQ-OAR-2009-0491-3742.1_NODA, p.5]
Smaller generating unit retrofit costs.  EPA NODA information cites how EPA is extending IPM model control retrofits for smaller units, under 100 Megawatt (MW) Capacity by assuming costs per kilowatt assigned to the 100 MW capacity units.  EPA itself acknowledges that the size of the unit being retrofit with controls makes a difference in control costs, with larger units posted with a lower cost per kilowatt capacity for control retrofits than smaller units.  EPRI Technical Assessment Guide analysis affirms that units of size under 100 megawatts continue to incur higher costs for control retrofits per unit of capacity than for larger units.  EPA should provide substantiation that controls like selective catalytic reduction, scrubbers and fabric filters can be installed on units in the 25 to 100 MW size range at pricing for a 100 MW unit. [EPA-HQ-OAR-2009-0491-3742.1_NODA, p.5]
Well controlled units under 100 Megawatt Capacity.  Minnesota Power operates nine units in the size group of 25 to 100 MW and has demonstrated that emissions of SO2, NOx, mercury and particulates can be well controlled by using technologies other than EPA's IPM model presumed technologies.  For example, substantial emission reductions have been delivered by Minnesota Power units in the 25 to 100 MW size range that utilized technologies like Rotating Opposed Fire Air, Furnace Sorbent Injection, Selective Non Catalytic Reduction, Wet Particulate Scrubbers and Low NOx Burners with Over Fire Air.  EPA has not provided information in the NODA that justifies their presumed retrofits of SCR, scrubbers and fabric filters in lieu of these technologies that also deliver cost effective, well controlled operation.  For smaller units, EPA should also give consideration to performance coal (lower sulfur, low mercury) as a control option.  Similarly, the need for preservation of transmission system reliability can justify allowing "well controlled" units under 100 MWs to operate with restricted dispatch in lieu of requirements for BACT-like retrofit of controls that would make the unit uneconomic.  [EPA-HQ-OAR-2009-0491-3742.1_NODA, p.5]
Optimal performance emission rates vs. long term average emission rates.  EPA has selected fairly aggressive emission rate performance values for IPM model inputs that likely reflect optimal performance rather than practical, long term (e.g. 30 day rolling average, annual average) performance.  For example, 98% SO2 removal is cited for scrubber performance input to the IPM model, whereas 30 day rolling average values that address output variability, start up and shut downs might more realistically deliver 90% SO2 removal. EPA IPM 4.10 modeling assumptions for emissions performance should reflect sustainable operational performance. [EPA-HQ-OAR-2009-0491-3742.1_NODA, p.6]
Annual Energy Outlook reference year assumptions.  EPA has indicated that IPM 4.10 will apply EIA AEO 2010 assumptions for rule finalization assessments, whereas 2008 data was applied when EPA determined utility emission budgets cited in the proposed Transport Rule.  2008 through 2010 represents a period when many utilities have been significantly impacted by a recession, where customer demand for electricity has been depressed and utility electricity generation output has significantly shifted.  EPA should perform analysis that examines how economy related electricity production levels and related environmental emissions impact Transport Rule budgets and relative stringency for emissions performance on individual units.  Electricity generating units should not be compelled to install costly environmental controls to compensate for economy related swings in customer demand. [EPA-HQ-OAR-2009-0491-3742.1_NODA, p.6]
New York Power Authority
EPA's National Electric Energy Data System (NEEDS)DATA does not reflect permitted or actual historical emissions.
NYPA reviewed the EPA NEEDS data version 4.10. The NEEDS data file indicates that SO2 emission rate for Flynn as zero, where as the emission rate for SO2 while burning 0.2% sulfur oil is approximately 0.2 lb/mmBtu. [EPA-HQ-OAR-2009-0491-3820, p.3]
Similarly, the NOx emission rate for Flynn was identified as 0.0537 lbs/mmBtu, however, when the unit burns fuel oil the NOx emission rate is 0.1743 lbs/mmBtu.
In addition NEEDS data shows uncontrolled and controlled NOx policy rate as 0.0280 lbs/mmBtu. Both these NOx policy rates are lower than the permitted value burning natural gas. As stated earlier the permit limit is 9.0 ppm (0.04 lbs/mmBtu) while burning natural gas and 42.0 ppm (0.1743 lbs/mmBtu) while burning fuel oil. [EPA-HQ-OAR-2009-0491-3820, p.3]
Similarly, the NEEDS data identifies the SO2 emission rate for 500 MW Combined Cycle Unit as zero while the unit is permitted to burn 0.04%sulfur kerosene for 30 days a year. Also for this unit, a single uncontrolled NOx emission rate of 0.0083 lbs/mmBtu was identified. The NEEDS data identified a controlled NOx policy emission rate of 0.0064 lbs/mmBtu which is lower than the value of 0.0074 lbs/mmBtu permitted while burning natural gas. This unit is equipped with state of the art Selective Catalyst Reduction (SCR) and reduces the NOx emission to 2 ppm (0.0074 lbs/mmBtu). Achieving lower than permitted value is technically not feasible. [EPA-HQ-OAR-2009-0491-3820, p.3]
NYPA respectfully requests that EPA review the input data for the models. [EPA-HQ-OAR-2009-0491-3820, p.3]
New York State Department of Environmental Conservation
Since the comment period for this NODA comes on the heels of the comment period for the proposed Transport Rule, Department staff have had limited time to fully evaluate the implications of this new data. The comments that follow are therefore not a complete evaluation of the dataset and the Department is requesting that EPA provide more time to allow for a full review of this data as well as an evaluation of how the final rule would be adjusted based upon this data. [EPA-HQ-OAR-2009-0491-3763.1_NODA, p.1]
The Department expects that a new set of model run results with the updated modeling platform (Integrated Planning Model (IPM) v4.10) will significantly modify the allocations provided to the affected units within the Transport Rule. These modified allocations have not been made available and the Department urges EPA not to adjust the allocations without providing states and other interested parties the opportunity to review and comment on the changes prior to the release of the final version of the Transport Rule. [EPA-HQ-OAR-2009-0491-3763.1_NODA, p.2]
The Department remains very concerned that IPM does not do an adequate job of estimating or projecting emissions for many units in New York State. In our original comments dated October 1, 2010, the Department commented on the proposed allocation to New York facilities of about 11,000 tons for the ozone season. That allocation was based upon EPA's criteria of the lower value of 2009 actual emissions or IPM version 3.02 base case emissions. In the NODA, EPA is proposing to update the IPM analysis to version 4.10. Since EPA has not completed its work nor has determined how the modified IPM run will impact the final allocations, the Department can only compare the two IPM runs in an attempt to anticipate how this might impact New York. EPA's IPM model version 3.02 predicts 15,686 tons of NOx emissions for New York in the base case, but in the base case for version 4.10, the model predicts only 6,949 tons - a discrepancy of over 100%. As we explained in our comments dated October 1, 2010, the proposed allocation for New York does not accurately reflect the emissions baseline and it is very inequitable. An allocation based upon these updated and extremely low emissions would be even more inequitable to New York and some other states. [EPA-HQ-OAR-2009-0491-3763.1_NODA, p.2]
NRG Energy
The following is a discussion of plant by plant data corrections as they relate to EPA's Notice of Data Availability (NODA) that supports the proposed Clean Air Transport Rule (Transport Rule). The comments discuss:
1. GenConn Energy LLC's new generating units in Connecticut
2. NRG's Dunkirk and CJ Huntley Generating Stations in New York
3. NRG's Indian River Generating Station Units 3 and 4 in Delaware
4. The NRG Texas generation fleet
5. NRG's Big Cajun II facility in Louisiana [EPA-HQ-OAR-2009-0491-3792.1_NODA, p.2]
1.1 GenConn Energy LLC New Generating Units 
GenConn Energy LLC (GenConn) is a 50/50 partnership between The United Illuminating Company and NRG. GenConn Devon LLC is the owner of four new 50 MW simple cycle combustion turbines at NRG's Devon Station (Devon), ORIS Code 544. These units came on-line in 2010 and should be Existing Units under the Transport Rule because their commercial operation dates are prior to January 1, 2012. [EPA-HQ-OAR-2009-0491-3792.1_NODA, p.2]
The units are designated as Units 15, 16, 17, and 18 at Devon. Each unit is equipped with an inlet air chiller, a Selective Catalytic Reduction (SCR) system, and a carbon monoxide catalyst reduction system. The units combust either natural gas or ultralow sulfur (15 ppm) distillate oil (ULSD) and are limited to a combined 10.8 tons per year of NOx and 0.9 ton per year of SO2 under the NSR permits Nos.105-0098 through 105-0101, as issued by the Connecticut Department of Environmental Protection (CTDEP). [EPA-HQ-OAR-2009-0491-3792.1_NODA, p.2]
Similarly, GenConn Middletown LLC is the owner of four new 50 MW simple cycle combustion turbines at NRG's Middletown Station (Middletown), ORIS Code 562. These units are currently under construction with a scheduled in-service date of June 1, 2011. These units should be Existing Units under the Transport Rule because their commercial operation dates are prior to January 1, 2012. The units are designated as Units 12, 13, 14, and 15 at Middletown. Their design, operational, and permit limits are identical to the Devon units and contained in the NSR permits Nos.104-0144 through 104-0147, as issued by the CTDEP. [EPA-HQ-OAR-2009-0491-3792.1_NODA, p.2]
Technical design information and permitted emission rates are shown in the Attachment 2 spreadsheet. [EPA-HQ-OAR-2009-0491-3792.1_NODA, p.2] [[See Docket Number EPA-HQ-OAR-2009-0491-3792.1_NODA, pp.5-23 for Attachment 2.]]
1.2 Dunkirk Generating Station 
NRG's Dunkirk Generating Station (Dunkirk) located in New York consists of four coal fired steam generating boilers, Units 1, 2, 3, and 4. Units 1 and 2 each have a net capacity of 75 MW; Units 3 and 4 are each 190 MW units. All of the units are equipped with SNCR, trona injection and baghouses for the control of particulate matter, NOx and SO2. The equipment was installed per NY Consent Order No. 02-CV-00245 signed on January 11, 2005. The corrected rates in the Attachment 2 spreadsheet reflect emission limitations required by the Consent Order and which the control equipment is designed to meet. [EPA-HQ-OAR-2009-0491-3792.1_NODA, pp.2-3] [[See Docket Number EPA-HQ-OAR-2009-0491-3792.1_NODA, pp.5-23 for Attachment 2.]]
1.3 CJ Huntley Generating Station 
NRG's CJ Huntley Generating Station (Huntley) located in New York consists of two coal fired steam generating boilers, Units 67 and 68. The units each have a net capacity of 190 MW units, equipped with SNCR, trona injection and baghouses for the control of particulate matter, NOx and SO2. Like Dunkirk, the equipment was installed per NY Consent Order No. 02-CV-00245 signed on January 11, 2005. The corrected rates in the Attachment 2 spreadsheet reflect emission limitations required by the Consent Order and which the control equipment is designed to meet. [EPA-HQ-OAR-2009-0491-3792.1_NODA, p.3] [[See Docket Number EPA-HQ-OAR-2009-0491-3792.1_NODA, pp.5-23 for Attachment 2.]]
1.4 Indian River Generating Station Units 3 and 4 
The current EPA NEEDS database does not reflect a recent Consent Order which will determine the way this plant is operated in the future. Effective 5/1/2011 the Indian River Generating Station will operate only two baseload units subject to CATR, Units 3 and 4. Unit 3 is a load following coal fired unit with a net capacity of approximately 155 MW and a nominal heat input of 1,904 MmBtu/hr. In addition to pollution controls for mercury and particulate, the unit has Low NOx Burners (LNB), Overfire Air (OFA), and Selective Non-Catalytic Reduction (SNCR) for NOx. It utilizes low (1.2%) sulfur coal. Unit 4 is a load following coal fired unit with a net capacity of approximately 410 MW and a nominal heat input of 5,091 MmBtu/hr. By 2012, the unit will operate with an SCR for NOx control and a circulating dry scrubber (CDS) for SO2 removal as well as mercury and particulate controls. The Delaware DNREC and NRG signed a consent order for shut down of Units 1 and 2 and installation of controls on Unit 4 on July 16, 2010. Operating parameters and emission rates associated with this recently signed consent order are provided in the spreadsheet in Attachment 2. The current data for the units are not correct. It should be noted that this Consent Order requires the retirement of Units 1 and 2 in 2011 and 2010 respectively, retirement of Unit 3 before January 1, 2014 and installation of advanced controls on Indian River 4 by 12/31/2011. [EPA-HQ-OAR-2009-0491-3792.1_NODA, p.3] [[See Docket Number EPA-HQ-OAR-2009-0491-3792.1_NODA, pp.5-23 for Attachment 2.]]
It is also important to discuss PJM Variables and dispatch of this plant. In 2009 and 2010, coal-fired generation in PJM has been impacted by lower than usual natural gas pricing, the infusion of Marcellus Shale Gas supply, and the current economic recession. Even under these conditions, which will likely continue through 2014, annual capacity factors for Units 3 and 4 have remained in the range of 45% to 65%. For the first three operating quarters of 2010, Unit 3 and 4 realized capacity factors of 44% and 45%. It is a concern that EPA's model does not accurately reflect operation now or in the future because it disregards non-economic dispatch for VAR support and PJM grid stability. Indian River Unit 4 dispatch, for example, through September 2010 ran 9% for reactive support and this number is expected to increase to 13% by year end as we go through the temperate shoulder months. It also appears that EPA has included the proposed MAPP transmission line project and Blue Water Wind off shore wind farm in advance of their current installation dates of 2015 and 2016, respectively. Considering these facts, we believe that the model and allocations should reflect more realistic operations with annual capacity factors for Units 3 and 4 in the 55% to 65% range. [EPA-HQ-OAR-2009-0491-3792.1_NODA, pp.3-4]
Three back up documents can be found in Attachment 3, which support the discussion on Indian River dispatch.
1. A Letter from PJM to Pepco Holdings Inc dated August 16, 2010 which approves the June 1, 2015 in-service date for the MAPP transmission line.
2. Excerpts from Operating Agreement of PJM Interconnection LLC  -  Intra -PJM Tariffs that reference mandates to respond to PJM and Reactive Power Payments
3. Section 12.1 of the 2009- PJM RTEP that addresses the state of Delaware 4. NERC Voltage and Reactive Standards- PJM Training Guide [EPA-HQ-OAR-2009-0491-3792.1_NODA, p.4] [[See Docket Number EPA-HQ-OAR-2009-0491-3792.1_NODA, pp.24-28 for Attachment 3.]]
1.5 NRG Texas Fleet 
The attached spreadsheet includes revisions to EPA's NEEDS database regarding our Texas plants. Explanations for each change are included in the comments section. [EPA-HQ-OAR-2009-0491-3792.1_NODA, p.4] [[See Docket Number EPA-HQ-OAR-2009-0491-3792.2_NODA for attached spreadsheet.]]
1.6 Big Cajun II Units 1, 2, and 3 
The 2012 and 2014 projected SO2 rate based on the coal specifications for Big Cajun II is 0.65lb/mmBtu. The corrections in the attached spreadsheet reflect this change. [EPA-HQ-OAR-2009-0491-3792.1_NODA, p.4] [[See Docket Number EPA-HQ-OAR-2009-0491-3792.2_NODA for attached spreadsheet.]]
Rochester Public Utilities (RPU)
General Comments on EPA's proposed Transport Rule and the NODA  [EPA-HQ-OAR-2009-0491-3729.1_NODA, p.2]
Given the complexity and breadth of the proposed Transport Rule (accompanied by the vast amount of supporting technical data in the docket), the significant differences between the data on which EPA based the proposed rule and the data EPA released pursuant to the NODA, RPU believes that EPA should withdraw the Proposed Transport Rule, revise it using corrected, quality-assured data with appropriate input from the affected facilities, and republish it for public comment with an adequate comment period. [EPA-HQ-OAR-2009-0491-3729.1_NODA, p.2]
Comments on NEEDS Version 4.10 EISA Database [EPA-HQ-OAR-2009-0491-3729.1_NODA, p.2]
Our review of the NEEDS Version 4.10 Database generated the following comments: [EPA-HQ-OAR-2009-0491-3729.1_NODA, p.2]
The Scrubber_Online_Year listed for ORISPL 2008, Unit 4 (UniqueID 2008_B_4) is incorrect. The correct year is 2009, not 2010, as outlined in RPU's Background comments above. [EPA-HQ-OAR-2009-0491-3729.1_NODA, p.2]
The SNCR_Online_Year listed for ORISPL 2008, Unit 4 (UniqueID 2008_B_4) is incorrect. The correct year is 2009, not 2005, as outlined in RPU's Background comments above. [EPA-HQ-OAR-2009-0491-3729.1_NODA, p.2]
The SO2 Permit Rate (lbs/mmBtu) listed for ORISPL 2008, Unit 4 (UniqueID 2008_B_4) is incorrect. This is the maximum allowable by MN State rule but is not applicable to Unit 4. The permitted SO2 rate for Unit 4 prior to 1/26/10 was 2.1 lbs/mmBtu. On 1/26/10 the permitted level dropped to 0.6 lbs/mmBtu. [EPA-HQ-OAR-2009-0491-3729.1_NODA, p.2]
The uncontrolled NOX rate (Mode1) for ORISPL 2008, Unit 4 assumes the use of Low NOX Burners (LNB). However, during the AQCS retrofit the LNBs needed to be removed for placement of the ROFA system and SNCR. The successful operation of the new AQCS precludes the reinstallation of the LNB. [EPA-HQ-OAR-2009-0491-3729.1_NODA, p.2]
Comments on ParsedFile_TR Base Case_2012 [EPA-HQ-OAR-2009-0491-3729.1_NODA, p.2]
A review of the ParsedFile_TR_Base Case_2012 generated the following comments: [EPA-HQ-OAR-2009-0491-3729.1_NODA, p.2]
The Retrofit Control 1 column incorrectly lists SCR on ORISPL 2008, Unit 4. As described above, RPU has recently installed a $38 million state of the art control system on this unit that includes ROFA for combustion control and SNCR for post combustion control of NOX. An SCR is neither existing, under construction nor planned on this unit for 2012 or for any year after 2012. [EPA-HQ-OAR-2009-0491-3729.1_NODA, p.2]
The IPM projections in this parsed file incorrectly assume fuel switching for ORISPL 2008, Unit 4. The fuel use is identified as 100% sub-bituminous coal. While this unit is permitted to combust either bituminous or sub-bituminous coal, this unit has never successfully operated on sub-bituminous coal. At this point, RPU is not prepared to operate this unit on sub-bituminous coal. [EPA-HQ-OAR-2009-0491-3729.1_NODA, pp.2-3]
The IPM incorrectly projects fuel use for UniqueID 6058_G_1 and 6058_G_2 at 100% natural gas. The two combustion turbines at Cascade Creek are peaking units that are permitted to operate on either natural gas or distillate oil. These units are subject to gas curtailments and the current natural gas infrastructure coming into Rochester does not allow for both turbines to operate on natural gas simultaneously during the winter months. Thus the IPM projections need to reflect operation of these units on both natural gas and distillate oil. [EPA-HQ-OAR-2009-0491-3729.1_NODA, p.3]
Southern Company
As explained in the attached comments., Southern Company strongly urges EPA to correct the underlying data and modeling flaws included in the NODA. Furthermore, 'EPA. must determine which dataset will be used in the final Transport Rule; completely redo its air quality and significant contribution analysis; update. the state budgets and unit allocations; and issue a supplemental proposed role with an adequate time for public comment. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p. Cover page 1]
As explained in Southern Company's Transport Rule comments to EPA, the proposed Transport Rule suffers from numerous errors in methodologies and numerous incorrect data and assumptions which impact every aspect of the proposed Transport Rule. Commenting on the proposed Transport Rule was exceedingly difficult given 1) the unreasonably. short time allowed for public comment, 2) the lack of clarity provided for EPA's methodology, and 3) the numerous flaws identified in EPA's data and methodologies. Further complicating the process was the fact that EPA added 'updated' data and modeling files to the docket in the middle of the proposed rule comment period, issued a Notice of Data Availability (NODA), and declared that the new data will be used in the final Transport Rule. Because EPA did not extend 'the comment period for either the proposed Transport Rule or the NODA, stakeholders were forced to evaluate and comment on two sets of data--each of which have different implications to the final Transport Rule-at the same time. The new information adds hundreds of pages of documentation to the docket for this rulemaking and will ultimately cause many changes to the Transport Rule. However, with the NODA, EPA has provided only a small portion of the data, assumptions, and analyses needed to evaluate its implications and has expressly declined to illustrate how these changes will affect the final rule. Additionally, EPA has declared that 'between now and the time that EPA finalizes the Transport Rule, additional information used to support the final transport rulemaking maybe placed in the docket.' It is unreasonable to expect stakeholders to provide meaningful comments on a 'moving target.' Each time that EPA changes the underlying data set and planning model, the underpinnings of EPA's proposed rule will change from emissions and air quality impacts to the statewide budgets and allocations. And, while the new data introduced in the NODA corrects some of the errors identified in the data used for the proposed Transport Rule, it contains new errors that did not exist in EPA's original data set. Given the magnitude of errors and flawed methodologies that still remain and given the fact that CAIR is in place and achieving significant environmental benefits, EPA must take the necessary time to: [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.5]
correct the errors (in data and assumptions); [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.5]
re-run all the models (IPM, CAMx, OSAT, PSAT, AQAT); [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.5]
adjust its methodology; [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.5]
apply the revised methodology with the corrected data, assumptions, and model outputs; [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.5]
update the proposed budgets and allocations; and [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.5]
issue a supplemental proposed rule-with all supporting data, files, and models-allowing adequate time for public comment. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.5]
At minimum, EPA should provide all the necessary files and documentation for stakeholders to assess how the revised data will impact the final rule. Without this information on how the new data impacts the final rule, stakeholders cannot understand the implication nor make meaningful comments. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.5]
EPA Should Have Issued a Supplemental Proposed Rule with the New Data and New Modeling [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.6]
While EPA provided this new information to the docket, the Agency expressly declined to provide updated Transport Rule analyses and instead implied that it would unveil the revised emissions, air quality impacts and significant contribution analysis, and state budgets and unit allocations in the final rule (i.e., with no opportunity for public comment). The proposed Transport Rule depends heavily on the results of the IPM outcomes and the outcomes provide significantly different emission results (see section III below). In the NODA, EPA acknowledged the potential changes by stating: [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.6]
Changes from the projections relied on in the proposed rule, from using an updated model, could impact the final rulemaking in a number of ways including, but not limited to: [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.6]
1. Changing emission projections that were used to determine which downwind areas have air quality concerns (i.e., non-attainment or maintenance) absent this rulemaking and to determine which States contribute to those problems. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.6]
2. Changing cost and emission projections used in the multi-factor [i.e., cost curve] test to determine the amount of emissions that represent significant contribution. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.6]
Though quite complex, the proposed Transport Rule allowance allocation methodology can be broken down into approximately eight major steps: [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.6]
1. IPM projects EGU emissions. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.6]
2. The IPM projected EGU emissions are used in CAMx atmospheric modeling to project downwind nonattainment and maintenance monitors. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.6]
3. The source apportionment tools OSAT and PSAT are used within the IPM dependent CAMx modeling to assess interstate contributions to nonattainment and maintenance. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.7]
4. Cost curves are developed from IPM outputs to determine the amount of pollutant reduction available at varying cost, and to determine control cost thresholds or 'breakpoints.' [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.7]
5. The IPM-dependent cost curves developed in Step 4 above are used in AQAT to estimate the air quality benefits of upwind emission reductions.
6. The IPM-dependent AQAT is used to establish air quality 'breakpoints.' [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.7] [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.7]
7. IPM results are used to establish state budgets. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.7]
8. Various IPM parsed files (along with other factors) are used to calculate EGU unit-specific allowance allocations. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.7]
As the list above indicates, at every major step in EPA's methodology -- e.g., creating emission inventory cases as inputs to CAMx modeling, projecting future nonattainment and maintenance problem areas, establishing linkages of upwind states to downwind nonattainment and maintenance problem areas, defining significant contribution to nonattainment and interference with maintenance, and establishment of unit-specific allocations -- IPM plays an indisputably critical role in ultimately determining unit-specific allowance allocations. Despite EPA having the latest NEEDS emission inventory data and revised IPM platform to calculate (and then allow public review and comment on) updated unit-specific allocations and knowing that the resulting emissions would be significantly different, EPA chose not to update the results of the proposed rule. EPA must revisit the basis for its proposal if it intends to proceed with this rulemaking and to continue to use its proposed approach to implementing section 110(a)(2)(D)(i)(I) of the Act. In doing so, EPA should redo each step of its methodology as outlined above using the revised NEEDS inventory and revised IPM. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.7]
In summary, the NODA completely undermines stakeholders' opportunity to provide meaningful comments on this proposed rule - comments on the original proposal were based on data and a version of the planning model now abandoned by EPA and meaningful comments on the new data and modeling cannot be formulated because EPA has not illustrated how the new data and modeling impacts the Transport Rule. Because EPA has declined to illustrate how the new data and modeling may affect the final rule, Southern Company cannot possibly provide the type of comments this rulemaking deserves and is essentially denied the opportunity to comment that the regulatory process requires. Accordingly, EPA must issue a supplemental proposed rule, one that includes the agency's revised regulatory analyses based on the new data, new IPM model results, and a modified methodology; all with an adequate time for public review and comment. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.7]
EPA Did Not Provide Enough Information in the NODA for Stakeholders to Calculate Air Quality Impacts or State Budgets and Unit Allocations [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.8]
In the NODA, EPA requested comments on the new data, plus comments on the impact of the new data on the proposed Transport Rule. 'EPA will accept comments on both the specific data that EPA is placing in the docket as well as any potential impacts of that data on the proposed Transport Rule until October 15th, 2010.' While we commend EPA for publishing this information, we are disappointed that EPA has published only a small portion of the data necessary to evaluate the potential impacts on the proposed Transport Rule and then expects us to provide comments on its implications. Furthermore, EPA plans to make additional changes to the datasets to support the final rulemaking. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.8]
Since EPA did not publish or post all of the information necessary to evaluate the potential impacts of the NODA, stakeholders can only speculate on how these changes may impact the final rule. Additionally, since the data will change again, comments made on the regulatory impacts from the data will be irrelevant to the final rule. EPA has placed the burden of deciphering the impacts of the NODA on the stakeholders. EPA must provide a coherent and thorough assessment of the changes to the proposed rule and must seek comment on the implications of the changes. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.8]
EPA should, at a minimum, 1) make all pertinent IPM parsed files available, 2) provide updated CAMx air quality modeling results (using PSAT and OSAT for determining state contributions), 3) provide updated cost curves based on the updated IPM modeling, 4) provide an updated significant contribution analysis, and 5) publish updated state budgets and unit allocations for all affected states and units. We also suggest, as EPA updates the significant contribution analysis, that they reconsider their methodology for determining significant contribution, giving due consideration to the comments and suggestions that were submitted by Southern Company and UARG on the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.8]
The New Data Will Impact The Transport Rule Air Quality Analysis [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.8]
EPA published in the NODA updated IPM results (v4.10) for the 2012 Base case and the 2014 State Budget Limited Trading case, including parsed files containing model output for EGUs that are greater than 25 MW (i.e., those units being considered in the Transport Rule). From the parsed files projected statewide emissions for those two scenarios could be calculated. After applying the assumption that non-EGU emissions and emissions from EGUs that are less than 25 MW do not change from the v3.02 IPM Base Case, we calculated statewide anthropogenic emissions of SO2 and NOx. Using this information, we applied our replicated version of the AQAT to estimate new 'Base Case' air quality at each monitor and upwind contribution from each state. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.8]
Table 1 [See p.9 of this comment summary for Table 1. Comparison of the number of monitors with nonattainment and maintenance issues based on emissions derived from IPM 2012 Base Case v3.02 and v4.10.] shows our estimate, using the replicated version of the AQAT, of the number of monitors that are projected to be in nonattainment or maintenance for each of the three NAAQS considered in the Proposed Transport Rule (Annual PM2.s, 24-Hour PM2.5 and 8-Hour Ozone), using the 2012 Base Case emissions from IPM v3.02 and v4.10 (the number of maintenance monitors includes nonattainment monitors). The result is astonishing in that, even though significant flaws still exist in the modeling methodology that overestimate emissions, close to half of the PM2.5 monitors no longer have nonattainment or maintenance issues. [EPA-HQ-OAR-2009-0491-3767.1_NODA, pp.8-9]
Table 2 [See p.9 of this comment summary for Table 2. Comparison of the number of states linked to downwind nonattainment and maintenance monitors based on emissions derived from IPM 2012 Base Case v3.02 and 4.10.] shows our estimate of the number of states that are linked to downwind nonattainment and maintenance monitors, using the 2012 Base Case emissions from IPM v3.02 and v4.10 (the number of states linked to maintenance monitors includes states linked to nonattainment monitors). The table demonstrates that the updated emissions (which are overestimated in some cases) may result in fewer states being included in the Transport Rule program, especially for ozone. Florida is one of the states that no longer contribute significantly to downwind nonattainment or maintenance. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.9]
This change in estimated air quality is significant and should motivate EPA to re-run the CAMx air quality modeling using the updated IPM v4.1 0 emissions. Only because Southern Company invested significant time and resources in attempting to replicate the AQAT for our initial Transport Rule review were we able to make these estimates of the impact of the new data on the predictions of air quality. EPA should use the new data, or whichever data it intends to use in the final rule, update all of the analyses and calculations made in the proposed Transport Rule, and issue a supplemental proposed rule for comment. [EPA-HQ-OAR-2009-0491-3767.1_NODA, pp.9-10]
The New Data Will Impact State Budgets and Unit Allocations [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.10]
The updated assumptions in the IPMv4.10 model runs have impacted both the 2012 and 2014 projected emissions for the states that cover the Southern Company territory. For the 2012 Base Case, projected annual and seasonal NOx emissions go down in all states, most dramatically in Florida (43% annual, 45% seasonal). 2012 Base case SO2 emissions are unchanged for Florida, but are significantly changed for Alabama, Georgia and Mississippi--emissions increased by 47,932 tons (14%) in Alabama, decreased by 48,233 tons (9%) in Georgia and increased by 12,102 tons (29%) in Mississippi. (See Table 111-3 and Table-III-4.) [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.10]
These changes in the 2012 Base Case emissions are not trivial and will affect the significant contribution analysis. These emissions would also most certainly affect the 2012 NOx and SO2 budgets and allocations. However, EPA has not provided updated tables of budgets and allocations, nor have they provided all the files necessary to apply the state budget and unit allocations algorithm documented in the Budgets and Allocations TSD. (See Section III-C for a list of files that we think are necessary to make this calculation). [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.10]
[See p. 10 of this comment summary for Table 3. Change In 2012 Base Case Emissions Between IPM V3.02 And V4.10 and Table 4. Percent Change In 2012 Base Case Emissions Between IPM V3.02 And V4.10]
For the 2014 State Budget Limited Trading Case, EPA states that they limited the emissions budgets to the caps modeled in the Proposed Transport Rule: 'These policy runs include the same State-level caps that EPA modeled in the Proposed Transport Rule. The caps have not been modified to account for any changes that the new modeling might suggest; they are merely provided for informational purposes to allow commenters to understand the impact that changes in the model platform have on the projected impacts of the caps.  However, there are sizable differences in individual state emissions projections between v3.02 and v4.10. Most noteworthy is that Florida's SO2 emissions increased 34,074 tons (25%). Both Florida and Georgia had sizable decreases in emissions for both annual and seasonal NOx, greater than a 20% reduction. (See Tables 5 and 6.) [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.11; See p.11 of this comment summary for tables 5, Changes In 2014 Limited Trading Case Emissions Between IPM V3.02 and V4.10 and table 6, Percent Changes In 2014 Limited Trading Case Emissions Between IPM V3.02 And V4.10]
EPA also posted in the NODA alternative IPM model runs with altered gas price assumptions. In these four state, these assumptions led to an increase in NOx emissions of 2 - 5% over the default v4.10, and an increase in 802 emissions of 0 - 9% in the 2012 Base Case for these four states. (See Table 7.) [See p.12 of this comment summary for table 7, Percent Changes In 2012 Base Case Emissions Between IPM V4.10 and V4.10 With Updated Gas Assumptions] The increase in Florida SO2 emissions of 9% is an especially important indicator of the value of doing multiple runs with different assumptions about unknown future availability and price of natural gas. The fact that IPM results are this sensitive to unknown future fuel prices suggests that EPA needs to be much more respectful of uncertainties if it intends to base state budgets and EGD allocations on IPM results. We would prefer an approach based on multiple years of historical data rather than projections. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.11]
EPA Should At Minimum Provide the Following Files in Order For Stakeholders to Determine How the New Data May Impact the Transport Rule [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.12]
As noted in Section II of these comments, EPA added new information to the docket. However, it did not provide the same documentation and data files for the new IPM and NEEDS v4.1 0 that it provided under the proposed rule for the old IPM and NEEDS v3.02-including the summary state budget and unit allocation data. Further, the agency did not provide all the files necessary for stakeholders to calculate the impacts of the new data and modeling on the proposed Transport Rule. If EPA does not provide the updated state budgets and unit allocations for public comment, then it must at a minimum provide enough data for stakeholder to evaluate how EPA's reliance on the new versions will impact the rule and its critical components (e.g., state budgets and unit allocations). In the interest of transparency and to allow stakeholders to provide meaningful comments, EPA must allow public comment on the additional data and modeling files and their subsequent impacts to the final rule. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.12]
The following files are necessary to calculate state budgets and unit allocations for the 2012 Base Case, and EPA should make them available as expeditiously as practicable: [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.12]
:: IPM Parsed data for $5001ton NOx for annual and ozone season (TR_NOX_500 and TR_NOX_OS_500) [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.12]
:: IPM Parsed data for $1600lton SO2 (TR_SO2_1600) [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.12]
The following additional files were made available in the proposed Transport Rule with the original data. The corresponding 'updated' files are necessary to fully understand the impact of the new data to the proposed Transport Rule and to provide meaningful comments: [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.12]
:: Revised Budgets and Allocations - Detailed Unit-Level Data (Excel) (i.e., BADetailedData.xls) [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.12]
:: Updated cost curves, summary reports, and parsed files derived from the suite of IPM runs: [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
o 2012 and 2014 $0 to $5000 per ton for seasonal NOx [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
o 2012 and 2014 $0 to $2500 per ton for annual NOx [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
o 2012 and 2014 $0 to $2400 per ton for annual SO2 [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
:: New 2014 IPM Base Case parsed file (v4.10) [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
:: Allocation Table (Excel) [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
:: Air Quality Contributions Data File (Excel) [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
:: TR SB Limited Trading Files for 2012 (Input and Output Files, TR_SB_Limited_Trading System Summary Report.xls, ParsedFile_TR_SB_Limited_Trading.xls) [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13] 
:: TR SB Intrastate Trading Files for 2012 and 2014 (Input and Output Files, TR_SB_Intrastate_TradingSystemSummaryReport.xis, ParsedFile_TR_SB_Intrastate_Trading.xls) [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
:: TR Direct Control Files for 2012 and 2014 (Input and Output Files, TR_Direct_Control System Summary Report.xls, ParsedFile_TR_ Direct_Control.xls) [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
In addition, EPA should provide the following information and update the following technical support documents based on its new data and the new IPM and NEEDS versions: [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
:: Non-EGU Emissions Reductions Cost and Potential (PDF). EPA updates its pollution control retrofit cost and performance assumptions, U.S. Environmental Protection Agency, Clean Air Markets Division, Integrated Planning Model (IPM) Version 4.10 Summary of Model Updates (Sept. 22, 2010)., yet it does not provide information on how this might impact the cost effectiveness of including other emission source categories in the rule or whether it made similar adjustments to control cost and performance assumptions for other emission source categories. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
:: Emissions Inventories. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
:: State Budgets, unit Allocations, and Unit Emissions Rates (PDF). [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
The New IPM Assumptions Result in Significant Changes in Generation From the Proposed Transport Rule Southern Company compared the four new IPM (v4.10) summary results with the comparable results in the proposed Transport Rule (v3.02). This comparison included the following: [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
:: IPM v3.02 base case IPM results; [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
:: IPM v4.1 0 base case IPM results; [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
:: IPM v4.10 base case IPM results with the AEO 2010 gas resource assumptions;- [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
:: IPM v3.02 policy case IPM results; [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
:: IPM v4.10 policy case IPM results; [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
:: IPM v4.10 policy case IPM results with the AEO 2010 gas resource assumptions; [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
A key difference between IPM v3.02 and v4.10 is that projected coal generation has decreased significantly. For example, projected total national coal generation for 2015 is about 15% lower in the v4.IO (in the base case and both policy cases). This is not a small change. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.13]
Overall projected generation for 2015 is also substantially lower (about 5%) in IPM v4.10. These changes have brought EPA projections into closer agreement with EIA's projections in ABO 2010. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.14]
Although notable changes have occurred in IPM v4.10 over v3.02, the NODA and associated documentation provided by EPA do not adequately explain the relative decrease in projected energy demand. For example, the heat input for the state of Georgia projected by IPM v4.10 in the base case is approximately 20% lower compared to IPM v3.02. However, the impact on the capacity factors of individual units is often disproportionate. It appears that IPM v4.10, likely inaccurately, places the brunt of the decrease on certain units. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.14]
EPA proposes to use revised modeling assumptions in the final Transport Rule, including new projections on future natural gas prices. Both the IPM v4.1 0 and the IPM v4.1 0 with the AEO 2010 gas resource assumptions assume natural gas prices prior to 2016 to be much lower than assumed in IPM v3.02. EPA has stated a preference for its IPM v4.10 natural gas resource assumptions as compared to the previous projections and the new ABO 2010 gas resource assumptions. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.14]
Natural gas prices, however, are notoriously volatile; therefore, future natural gas prices are difficult to predict. Much of the future uncertainty surrounds the availability of shale gas production. In Appendix 10-1 of the documentation for EPA Base Case v.4.10, EPA acknowledges this, noting that the view of shale gas availability in the EPA base case v.4.1 0 is about three times as large as EIA's view in AEO 2010 (see also Figure 2 below). [See p.15 of this comment summary for Figure 2,IPM Natural Gas Price Assumptions] Figure 1 below [See p.14 of this comment summary for Figure 1, Monthly Georgia Natural Gas Price Sold to Electric Power Consumers] shows a large volatility of natural gas prices in Georgia over an eight year period, from January 2002 to June 2010. The minimum price was 2.97 dollars per thousand cubic feet in February 2002 and the maximum 15.82 in September 2005. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.14]
Fuel price is a primary driver of economic dispatch; therefore, EPA's assumptions about relative fuel prices can significantly change the results of its modeling - from emissions to cost and allocations. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.14]
While electric utilities routinely rely on relative fuel price predictions for purposes of dispatch planning, compliance planning, and integrated resource planning, these predictions and the related analyses are updated on an ongoing basis. In contrast, EPA intends to use today's projections and develop federally enforceable requirements based on these. This improper reliance can significantly impact the cost of the proposed rule. Figure 2 below illustrates that the IPM v4.1 0 AEO runs show that the future costs of the Transport Rule may be much greater than published in the proposal. While AEO predicts relatively low natural gas prices in the near term, it predicts that prices will almost double in less than 15 years. This comparison illustrates the potential risks in setting permanent allocations derived from modeling projections that only account for a short period of time (2012 and 2014). At minimum, EPA must recalculate the costs of the final Transport Rule given the revised fuel price assumptions (EPA's preferred and alternate assumptions) and provide· them for review and comment. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.15]
The NODA Includes Many Inaccurate Inputs and Assumptions for-and Unrealistic Outputs from-EPA's Integrated Planning Model (IPM) [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.15]
EPA Made Many Assumptions in NEEDS v4.10 Regarding Individual Units that Are Inaccurate [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.15]
In reviewing the NEEDS v4.10, Southern Company found several flaws that need to be corrected. These are listed below: [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.16]
NOx Emission Rates: EPA's methodology for determining NOx emission rates is not sufficiently clear. Further, EPA's proposed NOx emission rates do not match how we project our units to operate and do not match up with past actual NOx rates for any single year that we can determine. We are continuing to review the NOx emission rate methodology and may provide further comments as soon as possible. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.16]
SO2 Emission Rates: For SO2, EPA represents that it has relied on NEEDS for the SO2 emission rates used to develop the proposed rule. However, in some cases, it appears that the Agency has not used the most recent update to NEEDS and in other cases, it appears that NEEDS itself contains inaccurate information. If EPA insists on relying on NEEDS for purposes of this rulemaking, the Agency should correct the errors. However, Southern Company urges EPA to reconsider its reliance on NEEDS and instead use actual SO2 emission rates to better represent historical operation. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.16]
Emission Controls: [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.16]
:: EPA needs to correct the timing of planned controls. The control online years listed in NEEDS (including corrections listed below) appear to represent the actual calendar year the pollution control either came online or is required to come online. This does not necessarily represent a full year in which the control will be operational. IPM modeling should not account for controls until the year after NEEDS indicates they come online. FGD online dates for the following units were correct for NEEDS v3.02 but are incorrect in NEEDS v4.10. The correct years are: [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.16]
o Bowen 1- 2010 [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.16]
o Bowen 2 - 2009 [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.16]
o Bowen 3 - 2008 [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.16]
o Bowen 4 - 2008 [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.16]
o Hammond 4 - 2008 [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.16]
:: To accurately reflect Georgia State Rule 391-3-1-.02(2)(sss), the Multipollutant Rule, the Scherer 4 FGD online year should be listed as 2012 (required 12/31/2012). The first full year that the Scherer 4 FGD is required to be online is 2013. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.16]
:: In the NODA, EPA has changed its assumed scrubber removal efficiencies from 95 to 98%. EPA should not assume a continuous removal efficiency of 98% because this level is not sustainable on any medium or long-term basis taking into account startups, shutdowns, and other fuel or operational variability. While vendors may guarantee 98% removal, those guarantees are on a one-time, instantaneous basis. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.16]
:: States recognize that variability factors must be taken into account when setting expectations for long term operation of control equipment. As noted above, Georgia State Rule 391-3-1-.02(2)(uuu) regulates SO2 emissions from electric utility steam generating units and requires a 95% removal on a 30-day rolling average basis for affected units, not 98%. The scrubbers most recently installed Georgia Power units are designed to meet 98% removal on an instantaneous basis, but 95% on a 3D-day rolling average. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.17]
:: EPA should also recognize that not all scrubbers were designed to achieve 95% removal, much less 98%. For example, EPA assumes an SO2 removal for the Yates Unit 1 scrubber of 95% but the actual removal rate should be 90%. consistent with Georgia State Rule 391-3-1-.02(2)(uuu). The scrubber on this unit was a full scale demonstration project installed in the early 1990s without the type of vendor guarantees associated with more recent installations. The Georgia Power Title V application has always indicated an expected 90% removal by the Yates 1 scrubber. The recent Georgia Rule (uuu) also made a distinction between the Yates 1 scrubber and the more recently installed scrubbers with a removal requirement of 90% for Yates instead of 95% for more recent scrubbers. We believe this distinction is proper in recognizing that the Yates 1 scrubber is both already nearly 20 years old and the first full-scale version of its design. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.17]
:: The scrubber efficiencies (95%) appear to be missing for: [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.17]
o Barry 5 [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.17]
o Gaston 5 [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.17]
o Gorgas 8-10 [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.17]
:: The actual historical NOx Emission Rates for coal-fired units with SCRs are larger than the value in NEEDS. Specifically, the 0.06 lb/mmBtu rate assigned to coal-fired units with SCRs has not been historically demonstrated. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.17]
:: NEEDS v4.10 incorrectly identifies Crist unit 6 as having OFA for NOx control. Crist 6 does not have a functional OFA system. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.17]
:: NEEDS v4.10 incorrectly identifies Crist unit 7 as having an SCR in 2004. Crist unit 7 should be listed with an SCR in 2005 with full-time operation. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.17]
:: NEEDS v4.10 lists Crist units 6-7 as 'yes' to having dispatchable scrubbers. These units have scrubbers that are required to operate by Crist FGD Air Construction Permit 0330045-023-AC.9 Therefore, Crist units 6-7 should not be listed as 'yes' to having dispatchable scrubbers. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.17]
:: NEEDS v4.10 does not list Crist units 4-5 as having a wet scrubber. Crist units 45 have a wet scrubber and it is required to operate by Crist FGD Air Construction Permit 0330045-023-AC. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.17]
:: EPA's 2012 Base Case data indicates that Crist Units 4, 5, 6, and 7 are unscrubbed. As explained in Southern Company's comments on the proposed Transport Rule, all of these units have installed wet FGD systems and are required to operate them by permit. Further, EPA's 2014 Limited Trading data in v4.10 incorrectly indicates that Gulf Power's Crist Units 4, 5, and 7 are unscrubbed. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.18]
Other: [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.18]
:: The NEEDS v4.1 0 database appears to be using net capacity in Megawatts for the 'Capacity' input. Plant Joseph M. Farley operates 2 Nuclear Units in Houston County which are inaccurately listed as 851 and 860 MW each. The appropriate net capacity for these units is 883MW each. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.18]
:: Heat Rates in NEEDS v4.10 are the same Heat Rates in NEEDS 3.02, just rounded to the nearest whole number, which can cause significant impacts to modeled emissions when applied to many Megawatts-hours of electric generation. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.18]
:: NEEDS has divided combined cycle units (CCs) into the two combustion turbines (CT) and the steam turbine (ST), which is different from how these units report emissions to the Clean Air Markets Division of EPA. If EPA chooses to treat CCs in this manner, it must ensure that the total megawatts under this method add up to the total megawatts for the unit. For example, Lansing Smith CC unit 3 should be a total of 556 MW. EPA has listed Smith unit 3 as: 3A (158 MW); 3B (158 MW); and 3S (166 MW). This only adds up to 482 MW. If EPA continues to treat the ST as a separate entity, it must first correct the total to 556 MW and then it must correct the individual megawatts to: 3A (175 MW); 3B (175 MW); and 3S (206 MW). [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.18]
EPA Made Many Assumptions in IPM Regarding Individual Units that Are Inaccurate [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.18]
:: Plant Mitchell Unit 3 is a coal-fired unit. It is incorrectly listed in NEEDS 4.10 as a biomass unit, and it is not included in any of the IPM.4.10 runs. Georgia Power is considering a switch from coal to biomass for this unit but has not made a decision about this potential conversion due to regulatory uncertainty surrounding pending EPA regulations. Any conversion would happen well after EPA's proposed 2012 compliance date for the proposed rule. This unit should be listed as a coal-fired unit, as it was in NEEDS 3.02, and should be included in the IPM 4.10 runs. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.18]
:: The IPM v4.10 runs list Scherer 4 NOx controls as 'LNB + SOFA' while all other Scherer units are listed with only 'OFA.' The proper existing NOx control for all four units at Scherer is overfire air, or OFA. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.18]
:: For Scherer 4, the 2014 IPM run lists only SCR as a retrofit control and does not list FGD. Both the SCR and FGD are required by the Georgia Multipollutant Rule by 12/31/2012. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.19]
:: For Scherer 1, the 2014 IPM run lists SCR/FGD as a retrofit control. The Georgia Multipollutant Rule does not require the SCR and FGD until 12/31/2014. As stated above, EPA should not account for controls until the year after they come online which, in this case, is 2015. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.19]
:: Greene County 1 is a wall-fired boiler. It is incorrectly classified as a cell-fired boiler in IPM v4.10. IPM v4.1 0 also lists Greene County CTs 2-10 with no fuel consumption in 2012 and 2014, which likely means the model assumes that these units will not run. This is inaccurate and inconsistent with our expectations. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.19]
:: IPM v4.10 lists the fuel type for Greene County CTS 2-10 as burning No.2 fuel oil beginning 2012. These units currently bum natural gas. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.19]
Many of the Control Technology Cost Assumptions in IPM v4.10 Are Improved, Yet Some Require Additional Improvements [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.19]
EPA revised the cost inputs for the IPM model by sponsoring an architect/engineering company - Sargent & Lundy Engineers (S&L) - to derive control technology costs based on a database of component costs and installation charges. For a complete analysis of EPA's new assessment see 'Overview of Projected Costs for Control Technology -as Developed for EPA's Integrated Planning Model (IPM)', prepared by J. Edward Cichanowicz, October 15,2010, included with the October 15, 2010 comments of UARG. The following are additional points regarding control technology assumptions. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.19]
:: FGD Systems: EPA has significantly raised retrofit control costs in many categories in IPM, including those for wet Flue Gas Desulfurization (FGD) systems. While EPA has raised the wet FGD control costs to a more reasonable level, due to site constraints such as space these projections still fall $100-150/kw short across all unit sizes. Additionally, EPA has incorrectly assumed that FGD systems can continuously achieve a 98% SO2 removal rate. Southern Company's newest FGDs are designed for a 98% instantaneous SO2 removal in order to meet a 95% 30-day rolling average. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.19]
:: SCR Systems: EPA has implemented modest increases to the cost of Selective Catalytic Reduction systems (SCRs). EPA's SCR costs are still too low. The SCR control costs used in the IPM model do not reflect reality for Southern Company. With more than 10,000 MWs of the most economical SCRs already installed, retrofitting the remainder of the fleet would cost 2 - 3.5 times the EPA assumptions depending on the site. Additionally, EPA has incorrectly assumed that units with SCRs can consistently achieve a NOx rate lower than 0.07 lbs/mmBtu. Southern Company does not have demonstrated experience operating SCRs consistently below 0.07 lbs/mmBtu, especially when SCRs are operated year-round instead of seasonally. [EPA-HQ-OAR-2009-0491-3767.1_NODA, pp.19-20]
:: Fabric Filter: EPA should give a cost range for fabric filters with activated carbon injection with an upper bound $50-100/kw higher. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.20]
:: CCS: Southern Company supports EPA's consideration of CCS in its updated IPM modeling. However, the rate of introduction of this technology is of concern. In the IPM v4.1 0 data, thirteen thousand gig watt hours are included in the generation mix by 2012. This seems unreasonable due to the fact there are no commercial scale coal projects with CCS scheduled to be online by 2012. Southern Company understands that because CCS is a developing technology, projecting the rate at which it will be introduced is challenging and warrants EPA's attention. Southern Company supports the comments of the Coal Utilization Research Council (CURC), especially CURC's suggestion that EPA should develop and offer for comment a more rigorous approach to address limits to the rate of introduction of CCS technology. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.20]
IPM Results Are Being Inappropriately Used In The Proposed Transport Rule [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.20]
IPM simulates the operation and evolution of the US electricity system, including the investments made to reduce emissions while increasing energy output. In particular, EPA uses IPM to 'guess' about whether particular control technologies will be installed at individual EGUs and estimates future emissions of those EGUs based on these 'guesses.' Many of these 'guesses' (and thus emissions estimates for many EGUs) will likely turn out to be wrong. Nevertheless, EPA prescribes EGU allowance allocations based on the IPM model as if the 'guesses' are absolute. IPM does not take into account all of the relevant factors that utilities use to make investment decisions. These are incredibly complex decisions involving many site and situation-specific considerations that are not part of IPM (such as unit space and construction challenges, unit-specific boiler design issues, transmission issues, fuel sourcing issues, local or company-specific regulatory issues, etc.). Further, IPM makes these 'guesses' assuming that it accurately predicts future fuel prices (while ignoring any feedback from changes in electricity fuel use on fuel prices) and assuming that it accurately predicts the future costs and performance of technologies. Making predictions to this level of accuracy is unrealistic. Models such as IPM are iterative - not static - and should not be used to establish federally enforceable, fixed budgets and allocations. EPA's misuse and overreliance on IPM results in this rulemaking is particularly egregious because in this proposed rule EPA is not planning to allow the states an opportunity to develop their own allocations. EPA must recognize the limitations of IPM and should not rely on IPM results to prescribe future emissions budgets for states and allowance allocations at the unit level. [EPA-HQ-OAR-2009-0491-3767.1_NODA, p.20]
State of Ohio Environmental Protection Agency (Ohio EPA)
In this notice U.S. EPA acknowledges that the changes in assumptions in the latest modeling platform could impact the final rulemaking in a number of ways including changing emission projections that were used to determine which downwind areas have air quality concerns, which States contribute to those problems, and/or changing cost and emission projections used in the multi-factor test to determine the amount of emissions that represent significant contribution. In turn these changes will likely impact budget allocations. Ohio EPA is extremely concerned that given the ramifications of these data changes, additional concerns may arise, without the ability to comment, when the final rule is promulgated. Ohio EPA requests U.S. EPA provides additional opportunities for notice and comment on the final data changes, including state budgets and allocations to specific units, prior to finalizing the Transport Rule. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.1]
Ohio EPA staff reviewed the background documentation the best that they could; however, finding the actual technical reason for the unit specific allocations was not clear in all cases. The basis for unit specific allocations was NEEDS V3.02. This was updated to NEEDS V4.1 0 (herein referred to as 'NEEDS') as a part of this NODA. Ohio EPA has found it difficult, in the time afforded, to extensively investigate the accuracy of all of the information in NEEDS and the NODA and its potential affect on the proposal. However, Ohio EPA has found that it still contains errors that necessitate correction before a final Transport Rule can be completed. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.2]
Ohio EPA is concerned with the lack of transparency on exactly which assumptions, and therefore, numbers, are used in determining allocations. For example, the 'State Budgets, Unit Allocations, and Unit Emissions Rates' Technical Support Document (TSD) from July 2010 contains Table 1 'Adjustments to Report Emissions to Account for Controls' and Table 2 'Adjustments to Reported Emissions to Account for Controls.' These tables contain a matrix of decisions for the procedure for adjustments. For NOx, one such procedure includes choosing the greater of 0.06 lbs/mmBtu or the 'removal rate from IPM documentation' under Table 1. Similarly for Table 2, a procedure for choosing the greater of the 'removal rate from IPM documentation' or 'emissions rate in controlled model projection.' A footnote for both tables states the removal rate in the Integrated Planning Model (IPM) is 90% for Selective Catalytic Reduction (SCR). In the IPM documentation NEEDS, there are four NOx rates in lbs/mmBtu identified: Uncontrolled NOx Base Rate, Controlled NOx Base Rate, Controlled NOx Policy Rate, and Uncontrolled NOx Policy Rate. In Appendix 3-1.1 'NOx Rate Development in EPA Base Case vA.10' there is an additional decision making table describing how rates, and ultimately allocations, are decided. However, ultimately, within all of this documentation there is no indication as to which decision, rate, etc. is associated with each individual unit allocation. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.3]
Furthermore, within Appendix 3-1.1 it states: [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.3]
'Calculations can get complex, so we'll illustrate it here for coal units only and with the assumption that the data were absolutely complete and consistent with what engineering theory tells us its values should be. Otherwise, we apply additional screens. Explaining them is beyond the scope of this illustration. Basically, here's how the values would be derived:' [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.3]
It is very difficult to give meaningful comments regarding unit-by-unit level assumptions in NEEDS and the associated modeling results when it is not clear which of the multiple 'complex' levels of .calculations, adjustments (or screens) and assumptions are applied to a specific unit. While we understand the desire to produce a rule as soon as possible and the amount of work involved, U.S. EPA is not allowed to forgo the appropriate procedural mechanism because it is too complex or difficult. It is imperative that states and owners of these units are provided detailed unit-by-unit information as to the basis of allocations in order to ensure appropriate information is used for future allocations. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.3]
Ohio EPA is concerned with the Integrated Planning Model's (IPM) one size fits all assumptions and the affect of these assumptions on unit level allocations and costs. In Chapter 5 of the documentation (Emissions Control Technology), U.S. EPA describes the two types of Flue Gas Desulfurization (FGD) technologies applied to the modeling and states 'In EPA Base Casev4.10 when a unit retrofits with a Lime Spray Dryer (LSD)  SO2 scrubber, it loses the option of BG, BH, and LG coals due to their high sulfur content.' Ohio EPA is concerned with the model applying these types of one size fits all assumptions that do not take into account the specific circumstances of each plant. For example, for some 'mine - mouth' plants, the infrastructure (no barge or inadequate rail) may not be available to handle large quantities of low sulfur coal. If an LSD type scrubber is assumed for one of these plants, at a specific cost threshold, it may be incorrect or impractical. And ultimately, those assumptions will dictate the unit level allocations received forcing certain plants to install a wet FGD system, when an LSD system was assumed, which could ultimately affect the cost thresholds and allocations received. [EPA-HQ-OAR-2009-0491-3747.1_NODA, pp.3-4]
Ohio EPA has concerns regarding the level of emission reduction assumed for NOx controls. In Chapter 5 of the documentation (Emissions Control Technology) U.S. EPA states 'Potential (new) coal-fired, combined cycle, and IGCC units are modeled to be constructed with SCR systems and designed to have emission rates ranging between 0.01 and 0.06 lb NOx/mmBtu. In Appendix 5.2A, 'IPM Model - Revisions to Cost and Performance for APe Technologies, SCR Cost Development Methodology' by Sargent and Lundy it is recommended that the 'Lower level of NOx removal is recommended as 0.07 NOx lb/mmBtu' for bituminous coal. Yet, U.S.EPA appears to make the assumption that older coal-fired units retrofitted with SCRs can also achieve a 0.06 lb NOx/mmBtu rate.  Ohio EPA is not as confident that this one size fits all rate is achievable for retrofits.
Cardinal Units 1, 2 and 3 [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.4]
NEEDS identifies units 1 and 2 as having a wet scrubber installed in 2007. Our records indicate March 2008. NEEDS identifies a 98% removal efficiency for unit 1. The owner indicates unit 1 is achieving approximately 95.5%. No assumptions are identified for unit 2. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.4]
NEEDS identifies unit 3 as having a wet scrubber in 2010 with no indication of removal efficiency. This unit is currently not scrubbed; however, it is required to have scrubbing by 12/31/2011. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.4]
It appears there have been adjustments to annual NOx emissions under both the reported and projected methods for all three units. NEEDS identifies a SCR install date of 2003 which is consistent with our records. However, it is not clear if U.S. EPA accounted for this SCR beginning continuous operation starting in 2009 based upon a Consent Decree. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.4]
J M Stuart Units 1, 2, 3 and 4 [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.5]
NEEDS identifies the installation of a wet scrubber in 2008. Although these were installed in early 2008 full operation did not begin until July of 2009 which is apparent by the actual emissions identified for these units. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.5]
NEEDS identifies these units as achieving 96% (unit 1) to 98% (units 2, 3 and 4) scrubber efficiency; however, these units are more closely achieving 95% according to the owner. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.5]
All units at J M Stuart installed SCRs in 2004 and began continuous operation of the SCRs in May of 2009. With the understanding that 2009 was a year of low demand due to the economic state of the country, Ohio EPA looked at the 2007 to 2009 average ozone season NOx emissions for each of these units. Ohio EPA is concerned regarding the ozone season NOx allocations for these units and believes they may not be sufficient. Each unit, controlled by an SCR, is receiving allocations that are only 44 to 57 % of the average 2007 to 2009 ozone season emissions. It is not transparent as to what assumptions were made as part of the IPM process that would result in such a drastic reduction in allocations for highly controlled units and just how those allocations may be affected by the newest IPM runs. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.5]
Gavin Units 1 and 2 [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.5]
NEEDS identifies these units as being controlled by scrubbers achieving 96.6% (unit 1) and 98% (unit 2) efficiency while the owner indicates they are in the range of 94.5%. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.5]
Similar to the J M Stuart units, Gavin installed SCRs in 2001 and began continuous operation in 2009; yet allocations are 69-89% of the average 20072009 ozone season emissions. Looking at allocations (based upon the IPM modeling), annual NOx allocations do not appear to be sufficient. Gavin's units, controlled by an SCR for all of only the first three quarters of 2009, had NOx emissions of 2,469 to 2,516 tons while allocations for four quarters are 2,384 to 2,584. Based on these historical controlled operations, Gavin will be left with insufficient allocations for at least a quarter of the year. Again, it is not transparent as to what assumptions were made and how allocations may be affected by the newest IPM runs. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.5]
Avon Lake Units 10 and 12 [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.5]
Avon Lake unit 10 received no SO2 allocations for 2014 based upon IPM model runs. There is no indication of this unit ceasing operations and it is not transparent as to whether the revised IPM runs have corrected this. Ohio EPA does not believe it is appropriate to allow IPM to retire units when allocations are based upon these runs. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.6]
Unit 12, a 671 MW uncontrolled unit with 2007 to 2009 average annual  SO2 emissions of 29,382 tons, received 2014 allocations of 2,466 tons of  SO2 based upon the IPM runs. Yet a similar sized unit with recent scrubber technology installed in 2008, J M Stuart unit 4 (573 MW, and 2007 uncontrolled SO2 annual emissions of 27,610 tons), received allocations of 3,529 tons of SO2 for 2014. And IPM, based on NEEDS, assumed a 98% efficiency for the J M Stuart unit. Ohio EPA is concerned that the multitude of assumptions made by IPM, for which allocations are made, does not make practical sense and creates inconsistencies. It is not transparent as to what assumptions were made and how allocations may be affected by the newest IPM runs. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.6]
Conesville Units 3, 4, 5 and 6 [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.6]
Conesville unit 3 appears not to exist in the NEEDS file and, therefore has received no allocations. This unit is running and the owner has indicated no intent of retiring this unit. It should receive allocations. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.6]
Conesville unit 4 received 266 tons of SO2 allowances in 2012 and 5,539 tons in 2014. It is not transparent as to what data or assumptions resulted in this 2012 allocation and if it has been corrected. Ohio EPA assumes the 2012 allocation must be an error that has been or will be corrected in the IPM runs. This unit installed a 98% efficient scrubber in 2009; however, it is an 800 MW unit with historical uncontrolled emissions of 72-92,000+ annual SO2 emissions. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.6]
The Proposed Transport Rule states that 2012 NOx reductions will come from operating 'existing SCRs on a year-round basis and up to their design removal efficiencies and the installation of limited amounts of low NOX burners are possible by 2012.' Conesville units 5 and 6 do not have advance NOx control and their 2007 to 2009 average annual NOx emissions are 5,172 and 4,838 tons, respectively. Yet they received NOx allocations of 2,855 and 2,808. It is not transparent as to what assumptions were made but it appears in order to maintain emissions commiserate with the allocations these units may need to be underutilized or install advanced controls, which was not the intent of this proposal. This analysis is also applicable to the ozone NOx season allocation. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.6]
Zimmer Unit 1 [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.6]
This unit is controlled by a wet scrubber installed in 1990 operating year-round. NEEDS identifies this scrubber with a 98% control efficiency yet the owner approximates a 91-93% efficiency is achieved and that it may be possible to optimize to 95%; however, 98% would not be achievable from this unit. The 2007 to 2009 average annual controlled SO2 emissions are 15,661 tons, yet they only received allocations of 5,775 tons in 2014. This would not be achievable without replacement of the wet scrubber which would be very difficult by 2014. [EPA-HQ-OAR-2009-0491-3747.1_NODA, pp.6-7]
NEEDS accurately identifies an SCR installed in 2004. The owner has operated the SCR continuously since 2009. However, this unit was allocated 13,515 tons of annual NOx but only 882 tons of ozone season NOx. Ozone season NOx emissions for 2009, when the SCR was being operated continuously, were 1,457 tons. It is not transparent as to what assumptions were made, but it appears unrealistic that this newer SCR could be optimized to a point to make up for a 40% reduction in NOx ozone season allocations compared to 2009 emissions. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.7]
Hamilton Unit 1 This unit does not have advance NOx control and the 2007 to 2009 average annual NOx emissions are 245 tons. Yet they received NOx allocations of 141 tons. It is not transparent as to what assumptions were made but it appears in order to maintain emissions commiserate with the allocations this unit, which serves a municipality, must be underutilized or install advanced controls, which was not the intent of this proposal. This analysis is also applicable to the ozone NOx season allocation. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.7]
Killen Unit 2 NEEDS accurately identifies an SCR installed in 2004. This unit was allocated 494 tons of ozone season NOx and 1,127 tons of annual NOx. Ozone season NOx emissions for 2009 were 901 tons and the 2007 to 2009 average ozone seasons NOx emissions are 1,393 tons. It is not transparent as to what assumptions were made, but it appears unrealistic that this newer SCR could be optimized to a point to meet the NOx ozone season and annual allocations. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.7]
Lake Road Unit 11 This unit is identified in NEEDS as having a capacity of 85 MW, and therefore subject to this program. However, this unit has a name plate capacity of 20.2 MW as confirmed by the owner. It should not be a subject source. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.7]
Kyger Units 1, 2, 3, 4 and 5 [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.7]
Currently these units are not controlled by an FGD. The owner is in the process of installing FGDs but, due to technically difficulties they do not anticipate installation will be complete by the 2014 deadline. However, it was assumed these FGDs would be installed based on their allocations. We wish to reiterate, as identified in our October 1, 2010 comments, that it may be difficult for some units to achieve the schedule, which has no case-by-case flexibility built in. [EPA-HQ-OAR-2009-0491-3747.1_NODA, pp.7-8]
NEEDS accurately identifies an SCR installed in 2003 for these units. The owner has operated the SCRs continuously since 2009. It is not transparent as to what assumptions were made, but it may difficult for these newer SCRs to achieve the NOx ozone season and annual allocations compared to 2009 emissions, which were low due to the economic down turn. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.8]
Lima Energy Unit 1 This unit received allocations although it does not appear to meet the criteria for consideration as an existing unit. The owner did begin some construction in late 2005 which was suspended in the middle of 2006. Significant additional construction will be necessary before this unit could begin operating. We believe it is more appropriate to treat this source as a new source. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.8]
Miami Fort Units 5-1, 5-2, 6, 7, and 8 Units 5-1 and 5-2 are not identified in NEEDS V4.10 but were identified in NEEDS V3.02, which was the basis for the unit level allocation$. These units are permanently shutdown. Although not transparent in the information provided for the new IPM modeling, it is assumed allocations provided to these units will not be in the final Transport Rule.  [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.8]
NEEDS accurately identifies an SCR installed in 2003 on units 7 and 8. The owner has operated the SCRs continuously since 2009. However, unit 7 was allocated 355 tons of ozone season NOx and 879 tons of annual ozone NOx. Ozone season NOx emissions for 2009, when the SCR was being operated continuously, were 520 tons. Likewise, unit 8 was allocated 368 tons of ozone· season NOx and 2,505 tons of annual ozone NOx. Ozone season NOx emissions for 2009, when the SCR was being operated continuously, were 442 tons. It is not transparent as to what assumptions were made and why there is such a disparity between annual NOx for each of these units. It appears unrealistic that this newer SCR on unit 7 could be optimized to a point achieve the allocations compared to 2009 emissions. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.8]
Muskingum River Units 1, 2, 3, 4 and 5 [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.8]
Currently these units are not controlled by a scrubber. The owner is required by a Consent Decree to retire, retrofit, or repower by the end of 2015. Based upon allocations it appears IPM has 'assumed' units 1 and 2 will retire prior to 2014 as no allocations were provided. Ohio EPA does not believe it is appropriate for U.S. EPA to use IPM to predict retirement and therefore eliminate allocations. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.8]
It appears based on allocations and documentation that the IPM modeling has assumed unit 5 will install an FGD by 2011. The owner has indicated an FGD will not be on line in 2012, and that it may be difficult by 2014. It is not apparent if the updated modeling will affect allocations to account for the FGD not being installed in 2011. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.9]
Units 1 through 4 do not have advanced NOx control. The 2007 to 2009 average annual NOx emissions range from 2,890 to 3,399 tons. Yet the annual NOx allocations range from 1,842 to 2,047 tons. It is not transparent as to what assumptions were made but it may be difficult, if not impossible, to meet the annual allocation budget without installation of more advanced controls. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.9]
Niles Units 1 and 2 [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.9]
Units 1 and 2 are both 120 MW units. NEEDS correctly identifies a wet scrubber was installed in 1995 on unit 1. Unit 1 has 2007 to 2009 average annual controlled SO2 emissions of 6,486 tons while allocations are set at 4,925 tons in 2012 and 870 tons in 2014. Unit 2 does not have advanced SO2 control. Unit 2 has 2007 to 2009 average annual controlled SO2 emissions of 5,717 tons while allocations are set at 2,913 tons in 2012 and 1,852 tons in 2014. It appears from these allocations IPM is assuming an FGD will be installed on unit 2. It is not transparent as to what assumptions were made, and why the disparity between 2014 allocations for these units. It appears unrealistic that the scrubber on unit 1 could be optimized to a point to meet the 2014 allocations. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.9]
Orrville Unit 12 [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.9]
This unit is identified in NEEDS as having a capacity of 28.7 MW, and therefore subject to this program. However, this unit has a name plate capacity of 25.0 MW as confirmed by the owner. It should not be a subject source. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.9]
Picway Unit 5 (identified as unit 9 in NEEDS) [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.9]
Based upon allocations it appears IPM has 'assumed' this unit will retire prior to 2012 as no NOx allocations were provided or 2014  SO2 allocations (although 2012  SO2 allocations were provided). Ohio EPA does not believe it is appropriate for U.S. EPA to use IPM to predict retirement and therefore eliminate allocations. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.9]
R.E. Burger Units 5, 6, 7 and 8 [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.9]
Units 5 and 6 did not operate in 2009 due to the economic down turn. Therefore, it appears 2012 SO2 allocations were based upon IPM rather than historical emissions during periods of running. For example, 2007 SO2 emissions were 723 (unit 5) and 671 (unit 6) tons.  SO2 allocations for each of these units during 2012 are 7,793 tons. This analysis is also applicable to the annual and ozone NOx season allocations. [EPA-HQ-OAR-2009-0491-3747.1_NODA, pp.9-10]
Units 7 and 8 are accurately identified as converting to biomass. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.10]
Gorsuch Units 1, 2, 3 and 4 [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.10]
The owner, AMP Ohio, has signed a Consent Decree that requires shutdown of the facility by the end of 2012. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.10]
W.H. Sammis Units 1, 2, 3, 4, 5, 6 and 7 [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.10]
These units are currently operating under a Consent Decree agreed to by U.S. EPA. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.10]
Lastly, Ohio EPA would like to reiterate an October 1, 2010 comment made regarding the Proposed Transport Rule: [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.10]
Ohio EPA has concerns regarding the methodology to determine allocation budgets based on actual emissions. U.S. EPA must use appropriate years representative of normal operation when calculating allocations based upon actual emissions. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.10]
Ohio EPA is concerned with what appears to be an arbitrary decision; using quarter 4 of 2008 and quarters 1, 2 and 3 of 2009 to establish 2012 budgets1 - both of which were low demand years yet U.S. EPA believes this more accurately represent emissions from these sources. It appears U.S. EPA is not recognizing the nation, and particularly the Midwest, was in a severe economic downturn during in 2008 and 2009. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.10]
Ohio's budget, and unit specific allocations, are being established based on a specific period of time, a time of economic crisis, without any future adjustment to being considered to those base budgets for improvement in economics, and therefore, demand. The variability limits are not sufficient to make up for this situation of severely low demand years in the base budgets. In addition, some units were not operating for some or all of this period in order to install controls to address CAIR. While it appears from the technical support documents U.S. EPA intended to substitute other quarters in the calculations when emissions were zero; however, if emissions were obviously drastically under previous quarter emissions (e.g., a unit may have operated for only a small part of a quarter) there was no such adjustment. In many cases, units are allocated budgets for 2012 and 2013 that assumes demand is as low as it was in 2008 and 2009. Such units may be forced to be underutilized if demand does improve. [EPA-HQ-OAR-2009-0491-3747.1_NODA, pp.10-11]
Ohio EPA believes it is imperative U.S. EPA take the time to ensure the appropriate historical emissions and assumptions are used when establishing allocations of the budgets as these allocations are not adjusted in the future. Ohio EPA believes it would be appropriate to use a similar methodology used when establishing the variability limits; averaging a series of years. The variability limit is based on the average heat input over several years but starting budget allocations account for emissions in one arbitrary year only and in this case, a low demand year. A multi-year averaging approach should be used, continuing to account for controls put in place since such time, and making appropriate corrections and substitutions for periods of non (or very low)- operation. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.11]
This comment applies to the following units' emissions: [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.11]
Ashtabula unit 1: all quarters used to establish the 2012 SO2 allowances were well below historical emissions due to the economic down turn. Especially 02 and 03 of 2009. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.11]
Eastlake units 1 to 4: 01 and 02 SO2 emissions were significantly below historical emissions due to the economic down turn. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.11]
Hamilton unit 9: all quarters used to establish the 2012 SO2 allowances were well below historical emissions due to the economic down turn. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.11]
Lake Shore unit 18: all quarters used to establish the 2012 SO2 allowances were well below historical emissions due to the economic down turn. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.11]
Muskingum River units 1 to 4: all quarters used to establish the 2012 SO2 allowances were well below historical emissions due to the economic down turn. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.11]
Niles units 1 and 2: all quarters used to establish the 2012 SO2 allowances were well below historical emissions due to the economic down turn. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.11]
O.H. Hutchings units H-1 to H-6: all quarters used to establish the 2012 SO2 allowances were well below historical emissions due to the economic down turn. Also, some of the smaller units are peaking units and given the 2014 modeled allocations, the 2012 SO2 allocations do not appear to be sufficient if additional utilization is needed. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.11]
Picway unit 5: all quarters used to establish the 2012 SO2 allowances were well below historical emissions due to the economic down turn. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.11]
W.H. Sammis units 3 and 5: 02 emissions were very low due to the tie in of the scrubber. [EPA-HQ-OAR-2009-0491-3747.1_NODA, p.11]
Bayshore units 2 to 4: all 2009 quarters used to establish the 2012 SO2 allowances were well below historical emissions due to the economic down turn.[EPA-HQ-OAR-2009-0491-3747.1_NODA, p.11]
Tennessee Valley Authority (TVA)
While TVA submitted substantial comments on the Proposed Rule published in the Federal Register on August 2, 2010, it would only be fair for EPA to provide the public another opportunity to submit comments on the next version that will be substantially different from the proposed version. Furthermore, the NODA lists additional planned updates EPA is going to undertake in future to support the final rulemaking prior to issuance. This constantly- moving-target approach to rulemaking makes it almost impossible to formulate meaningful comments for lack of an opportunity to review the comprehensive proposal. Accordingly, TVA encourages EPA to carefully assimilate all data and revised modeling results, and then re-propose the rule with an aligned set of technical supporting documentation, providing additional opportunity for meaningful public comment. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.1]
Issue: EPA's NEEDs Version 4.10 has a errors concerning installed TVA controls. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.1]
While the database correctly lists an SNCR for Johnsonville Unit 1, revisions are needed to Johnsonville Units 2, 3 and 4. include operating SNCRs for John Sevier units 1, 2, 3 and 4 and [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.2]
Shawnee 1 does not have an SNCR. (That SNCR was only for purposes of d demonstration, and was subsequently removed from service.) [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.2]
The database incorrectly assumes that both Wet Scrubbers and SCRs will be installed on John Sevier Units 1-4 in 2011. TVA does not have any such controls under construction... [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.2]
Issue: In both the NEEDs Version 4.10 database and the 2014 trade case, the EPA has two future plants listed as being constructed within the TVA region in Kentucky. The units are listed with the plant names "TVAK_Ky_Coal steam" and "TVAK_Ky_Combustion TurbineTurbine". [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.2]
TVA Comment: TVA does not have any plans to construct coal steam plants or combustion turbine plants in Kentucky. These units should be removed from the database or ascribed to some other utility that may be actively planning to construct these units. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.2]
Issue: The EPA NEEDs Version 4.10 database list various TVA plants as being capable of burning both 100% bituminous and 100% sub-bituminous coal. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.2]
TVA Comment: Gallatin units 1-4 are the only TVA units capable of routinely burning 100% sub-bituminous (PRB) coal. The NEEDs Version 4.10 database incorrectly lists the following units as being capable of burning 100% sub-bituminous coal: Allen 1-3, Colbert 1-5, Johnsonville 1-10, Kingston 1-9, Paradise 1-3, Shawnee 1-10, and Widows Creek 1-8. Except for the Gallatin plant, TVA recommends the NEEDs Version 4.10 database be modified to remove sub-bituminous coal as a "Modeled Fuel" for TVA's plants. (See Comment G herein for additional information on sub-bituminous coal use at TVA plants.) [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.2]
Issue: EPA's 2014 Limited trading case erroneously assumes Widow Creek Units 1-6 will be retired in 2014. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.2]
TVA Comment: TVA has not announced plans to retire Widows Creek Units 1-6. TVA has announced plans only to "idle" these units, in a phased approach, between now and 2015. TVA defines "idling" as temporarily removing a unit from service until needed for economic dispatch. Such removal from service could be temporary, depending on other generating issues such as gas prices, nuclear plant performance, etc. Allocations should not be zeroed out to sources that EPA unilaterally, without any basis, decides should be retired. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.2]
Moreover, EPA's use of "retirements" as a "control technology" for reducing SO2 or NOx emission is not a credible alternative. It does not appear that the costs of retiring units have been properly integrated into the marginal cost curves, as the marginal cost for retiring a unit would be much higher than $2,000/ton for SO2 or $500/ton for NOx. The inclusion of such retirements in the EPA analysis seriously undermines the credibility of EPA's IPM-based marginal cost approach.  [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.3]
Accordingly, all retirement assumptions should be removed from the Proposed Rule's trading case assessments, unless EPA has been officially notified that a utility intends to permanently retire a specific EGU and a fixed prior retirement date has been assigned. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.3]
Issue: The net heat rates listed for TVA's coal plants in EPA's NEEDs Version 4.10 are approximately 2.3% lower, on the average, than recent historical TVA levels. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.3]
TVA Comment: The net heat rates listed in the NEEDs Version 4.10 database are low compared to average annual 2006-2008 heat rate derived from TVA's "Data Fuser" database. Larger errors were observed for TVA's Alabama units, where the EPA average net heat rate was 4.3% lower than TVA historical rates. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.3]
TVA recommends the EPA use of the TVA net heat rate data for 2006-08 as listed in Attachment A [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.3; See p.7 of this comment summary for Attachment A]
Issue: The EPA assumes NOx emission rates for both controlled and uncontrolled units that are not achievable in the long term. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.3]
TVA Comment: The EPA estimated NOx rates for controlled SCR units tend to be low and track the performance of ozone season SCR operations prior to the CAIR requirement for annual operation. The EPA rates tend to seriously overestimate TVA's SCR capabilities when the units are in year-around continuous operation. Example data for TVA's SCRs are provided in Attachment B. [;See p.8 of this comment summary for Attachment B] This data shows that the rates the EPA's used are an average of 0.006 lb/Mbtu lower than the rate TVA actually achieved in the 2006-2008 timeframe. Further, 2009 annual data shows TVA could not maintain the relatively low "ozone season" rates when compelled to operate round the year. As shown in Attachment 3 [;See p.9 of this comment summary for Attachment C] , the achievable annual rate for NOx was an average of 0.0149 lb/Mbtu higher than the estimated EPA rates. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.3]
It appears the EPA is using rates based on SCR guaranteed control efficiencies. These "guaranteed" rates are "idealized" in the sense that the rates reflect the performance of new units undergoing steady state short term acceptance testing and do not reflect sustainable rates. Sustainable SCR rates vary from the "guaranteed" standard due to practical considerations such as process variability during periods of startup, shutdown, and load change. In addition, the SCRs experience normal equipment deterioration and catalyst deactivation which further reduce performance until scheduled maintenance can be performed. [EPA-HQ-OAR-2009-0491-3769.1_NODA, pp.3-4]
For units with existing post combustion NOx controls, TVA recommends using the average of annual unit specific NOx rates for calendar year 2009, since annual NOx reductions were not achieved for most units until January 2009. (TVA did operate SCRs in 2008 from May thru December.)  [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.4]
For units where future post-combustion NOx controls are projected to be needed, TVA recommends nominal annual rates no lower than 0.08 lb/MM-Btu, considering site specific issues, SCR inlet gas an ammonia injection distribution issues with changing loads, and startup/shutdown issues where units are not operating with gas temperatures high enough for ammonia injection into SCRs. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.4]
For units with no post combustion NOx controls (no SCR, SNCR, ect.), TVA recommends EPA use unit specific three year average annual NOx rates from calendar year 2006-2008. Averaging emission rates over multiple years for units without SCR or SNCR minimizes the distorting effects of NOx fluctuations associated with operational boiler combustion or burner problems during specific time periods for individual plants. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.4]
Attachment C [See p.9 of this comment summary for Attachment C] provides what TVA believes are sustainable NOx rates for year round operation of TVA's units. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.4]
Issue: EPA's analysis projects emission rates incorrectly as it assumes all TVA units can readily switch to very low sulfur sub-bituminous coal by 2012. Data in the NEEDs Version 4.10 database indicates that TVA's units used sub-bituminous coals that have unrealistically low SO2 rates. These rates are as low as 0.58 lb/MM-Btu.
TVA Comment: Although the sub-bituminous SO2 rates used by NEEDs Version 4.10 database has increased compared to the NEEDs Version 3.02 database, these rates continue to be unrealistically low and often reflect the unrealistic assumption that TVA units can use 100% sub-bituminous coal. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.4]
As indicated in TVA's October 1, 2010, comments to the Transport Rule, EPA's assumed SO2 rates are not achievable long term for TVA's units (without FGD) when burning low sulfur coal. Coal sulfur content is not homogenous even in the same seam, and coal suppliers will not guarantee sulfur contents that support EPA's assumed rates on TVA's uncontrolled units. [EPA-HQ-OAR-2009-0491-3769.1_NODA, pp.4-5]
TVA has been switching to low sulfur coal on units without scrubbers since 1995 for compliance with the 1990 Clean Air Act Amendments. Over that time, TVA has incrementally exhausted all cost-effective means of achieving low sulfur coal fuel switches on its unscrubbed units. For most of TVA's unscrubbed units, Powder River Basin (PRB) sub-bituminous coal is both the lowest sulfur coal available and the lowest cost low sulfur coal available. Therefore, TVA has already maximized the use of PRB coal on all unscrubbed units wherever feasible. Most TVA units cannot accommodate 100% PRB coal; only Gallatin routinely burns 100% PRB coal. Allen routinely burns a blend of around 80% PRB coal, and units 1-6 at Johnsonville can burn 75% PRB coal. All other unscrubbed units generally burn 0-30% PRB coal with a few units on occasion increasing their PRB burn rate by 20% when the coal system can economically accept some capacity derates. Over these 15 years, TVA has increased the use of low sulfur coals wherever possible each year, and has not reverted back to burning medium or high sulfur coals (until units are scrubbed). [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.5]
Extensive equipment changes at significant cost would be required for TVA to significantly further reduce emission levels through increased use of lower sulfur coals. This is contrary to EPA's assumption that "switching form bituminous to sub-bituminous has no cost or schedule impact" [p. 45273]. These equipment changes include those that would have to be made to the coal handling and processing equipment (pulverizers, feeders, etc.), as well as the particulate control equipment. Making such expensive changes for just a few years before scrubber installations are potentially required for implementing hazardous air pollutant regulations, SIPs for achieving revised fine particulate ambient air quality standards, or other regulations promulgated under the CAA does not make economic or practical sense. The expected time for test burns, environmental review, permitting, design, procurement and construction of such fuel switch projects is approximately 48 months. Outages would need to be staggered to ensure reliability. With the final Transport Rule expected in mid-2011, the earliest most of these fuel switch changes could be implemented is mid-2015. Some changes would likely require additional time. Ironically, capital upgrades that enable the use of lower sulfur fuel would present an impediment to further clean air controls on our plants as multiple design changes complicate the permitting and design of major control equipments. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.5]
Utilities, including TVA, contract long term for a significant portion of their coal supplies. Upon final release of the Transport Rule near mid 2011, utilities would have to renegotiate some fuel contracts, cancel others, and enter into some new fuel contracts. Any sudden shift to lower sulfur coals has the potential to cause major contractual and coal supply disruptions that would affect both coal companies and utilities in 2012. Such shifts in coal supply without a two to three year notice are not reasonable under existing contracts. EPA should not expect significant coal switches o begin before mid 2013 where extensive equipment changes are not required. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.5]
For SO2 rates, TVA recommends that EPA use, at a minimum, unit-specific three year average annual SO2 rates from calendar years 2006-2008 with adjustments for controls added since 2006. Averaging emission rates over multiple years minimizes the distorting effects of SO2 fluctuations resulting from both the variations in coal deliveries over limited time periods and the variations due to operational problems at individual plants. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.6]
For units with new SO2 scrubbers built after 2006, TVA recommends EPA assumed rates for SO2 be modified to be no less than 0.15 lb/MM-Btu for units expected to burn high or medium sulfur coal and 0.08 lb/MM-Btu for units burning low sulfur coal (PRB). SO2 rates on controlled units can be found lower than these stated rates, but considering normal equipment deterioration and reliability between maintenance opportunities and lack of equipment sparing typical for scrubbers designed for cap and trade programs, these rates are the most realistic annual average sustainable rates TVA can recommend for new SO2 controls. These rates allow for the following realistic scenarios: [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.6]
Wet FGD for units burning high sulfur coal (approximately 5 lb SO2/MM-Btu) to be designed for 98% removal for short term performance tests, but to operate with a small degree of upsets with annual average SO2 removal down to 97% (achieving a 0.15 lb SO2/MM-Btu rate). [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.6]
Wet or dry FGD for units burning medium sulfur coal (approximately 2.5 lb SO2/MM-Btu) to be designed for 95% removal for short term performance tests, but to operate with a small degree of upsets with annual average SO2 removal down to 94% (achieving a 0.15 lSO2/MM-Btu rate). [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.6]
Dry FGD for units already burning 100% PRB (with an SO2 rate around 0.80 lb SO2/MM-Btu) to be designed for 95% removal for short term performance tests, but to operate with a small degree of upsets with annual average SO2 removal down to 90% (achieving a 0.08 lb SO2/MM-Btu rate). Annual average 90% removal is typical of dry scrubber spray dryer designs requiring brief periods of time with no SO2 removal, while a unit's atomizer is pulled for maintenance. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.6]
Attachment C [See p.9 of this comment summary for Attachment C] provides yearly SO2 emission rates that TVA believes are achievable by 2014 for all of  TVA's coal fired units. [EPA-HQ-OAR-2009-0491-3769.1_NODA, p.6]
Utility Air Regulatory Group (UARG)
The tight implementation schedule that EPA proposes is in effect made even tighter by the fact that EPA is already changing the terms of the proposed rule. As discussed above, on September 1, 2010, midway through the public comment period on the proposed rule, EPA published its NODA, announcing information that in effect will result in substantial changes to the proposed rule and noting that further changes are to come. Among other things, the NODA announced the release of (i) an updated version of the National Electric Energy Data System ("NEEDS"), which provides the unit-level EGU characteristics used as inputs for the Integrated Planning Model ("IPM"), (ii) results of new base case and policy case modeling runs using an updated version of IPM, and (iii) results of new base case and policy case modeling runs using an updated version of IPM and including data from the Energy Information Administration's Annual Energy Outlook 2010 natural gas resource assumptions. 75 Fed. Reg. at 53614/2-3. It also announces the release of "[a] summary of other planned input updates to be implemented in the final rulemaking." 75 Fed. Reg. at 53614/3. The data released in connection with the NODA will, when applied by EPA, change substantially the statewide budgets and allowance allocations for 2012 and the allowance allocations for 2014, and there will presumably be additional changes leading up to promulgation of a final rule based on the planned input updates that EPA says will be implemented later. [EPA-HQ-OAR-2009-0491-2756.1, pp.17-18]
The scope of the impact that the new data will have is clear at a glance. For example, the parsed file that EPA released in connection with the proposed rule, showing the initial IPM run, indicates that IPM projected about 23,723 MW of new coal generation from unidentified plants yet to be built in 10 different states. See IPM Run File "TR SB Limited Trading", available at http://www.epa.gov/airmarkets/progsregs/epa-ipm/transport.html. By contrast, the updated parsed file that EPA added to the docket in connection with the NODA appears to indicate that IPM projected only about 2,001 MW of new coal generation from unidentified plants yet to be built in four states. See Docket ID No. EPA-HQ-OAR-2009-0491-0312, IPM Run - TR SB Limited Trading v.4.10 - 2014 Parsed File (Sept. 1, 2010), available at http://www.regulations.gov/search/Regs/home.html#docketDetail?R=EPA-HQ-OAR-2009- 0491. This is likely to be merely one indicator of the substantial changes in EPA's proposal that will result from use of the NODA information, and the impact of the future changes that EPA anticipates remains to be seen. Clearly, there is no way for sources to begin planning for compliance based on the information that EPA has provided in the docket. [EPA-HQ-OAR-2009-0491-2756.1, pp.18-19]
On September 10, 2010, EPA denied UARG's August 19, 2010 request for an extension of the comment period on the PTR, and on October 5, 2010, the Agency denied UARG's September 10, 2010 request for a comment deadline extension for the NODA as well as for the PTR itself.1 In light of the significant differences between the data on which EPA based (or says it based) the PTR and the data EPA released later pursuant to the NODA, EPA should withdraw the PTR, revise the PTR using the NODA data or whatever other data EPA may now deem most appropriate -- while addressing as well the many other deficiencies discussed in UARG's comments on the PTR and the present comments -- and publish a complete, properly supported proposal for public comment with an adequate comment period. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.3]
The Comment Period on the NODA Is Inadequate To Allow for Adequate Public Review of the Extensive Material Associated with It. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.4]
Despite this large quantity of new information, the NODA provides only an additional 14 days for public comment beyond the comment deadline that UARG and other members of the public were required to meet for the PTR. This does not allow enough time for a comprehensive review of the new material provided, much less enough time to analyze the material, determine its implications for the underlying rule, and develop and submit complete comments. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.4]
The substantial impact of the NODA on the Proposed Transport Rule was apparent in recent comments by EPA representatives. During an EPA webinar held on September 22, 2010, in response to a question regarding which aspects of the PTR would be affected by the NODA, a representative of EPA's Clean Air Markets Division indicated that the information contained in the NODA would affect, among other things, EPA's "significant contribution" analysis, the creation and evaluation of the "cost curves" in EPA's multi-factor analysis for determining emission reduction obligations under the PTR, and the cost-effectiveness "breakpoints" for emission controls that EPA will select based on the cost curves and the multi-factor analysis. This EPA representative acknowledged that the NODA may result in changes in EPA's determinations of which states are regulated under the Transport Rule, which states will be classified as group 1 rather than as group 2 states with respect to additional SO2 emission control obligations in the second phase of the program, the emission budgets to which regulated states will be subject, and unit-level allowance allocations. These matters are far from tangential to EPA's development of the Transport Rule. To the contrary, they go to the very heart of the rulemaking. Yet, EPA provided only 14 days for public comment on the NODA beyond the comment period on the PTR. [EPA-HQ-OAR-2009-0491-3773.1_NODA, pp.4-5]
Equally important, as discussed below, EPA has unreasonably withheld information necessary to allow UARG, members of UARG, other members of the public, and states to develop and provide meaningful and comprehensive comments on the NODA and on the Proposed Transport Rule itself. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.5]
Despite the Quantity of New Information Added to the Docket Pursuant to the NODA, EPA Has Failed To Provide Data Necessary To Allow Meaningful Comment on That Information. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.5]
The problems associated with the unreasonably abbreviated period EPA has provided for comment on the voluminous and complex information issued pursuant to the NODA are exacerbated by EPA's failure to provide much of the information necessary to evaluate and meaningfully comment on the NODA. The docket omits much of the information that is necessary to properly evaluate the nature and extent of the changes that are likely to the PTR based on the addition to the docket of the data listed in the NODA. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.5]
In support of the PTR, EPA provided in the docket the results of 48 IPM runs. These runs provided the public at least some basis for evaluating and commenting on the various steps in EPA's process of developing unit-specific allowance allocations. In contrast, in support of the NODA, EPA provided the results of only eight IPM runs. Of these eight runs, four relate to an entirely new alternative proposal based on the Energy Information Administration's ("EIA") Annual Energy Outlook 2010 natural gas resource assumptions -- leaving only four IPM runs that constitute a repeat of runs used to support the PTR. The paucity of IPM runs that EPA has provided with the NODA, using the revised National Electric Energy Data System ("NEEDS") inventory and IPM v.4.10 frustrates the public's ability to comment knowledgeably on the effects on the PTR of the updated NEEDS database and IPM platform. See section VII infra. Despite EPA's limited use of the revised NEEDS inventory and IPM model in the allowance allocation step of its analysis,2 EPA still has not provided the IPM runs necessary for electric generating companies and others, including states, to understand and comment knowledgeably on the impact of the NODA on statewide emission budgets and unit-specific allocations. [EPA-HQ-OAR-2009-0491-3773.1_NODA, pp.5-6]
In addition to failing to provide many critical updated IPM runs using the NODA information, EPA has failed to provide key summary tables that it did provide in conjunction with the PTR. The key summary tables provided in support of the PTR include the "Allocation Table - Technical Support Document for the Transport Rule - State Budgets, Unit Allocations, and Unit Emission Rates" (EPA-HQ-OAR-2009-0491-0057.1) and the "Detailed Unit-Level Data for State-Budgets, Unit Allocations, and Unit Emission Rates" (EPA-HQ-OAR-2009-0491-0074.1). In the PTR, these tables provided important guidance regarding a unit's allowance allocations under the PTR and provided electric generating companies at least some ability to evaluate the accuracy of EPA's assumptions (or apparent assumptions) with respect to their individual units. For reasons that UARG explained in its comments on the PTR, EPA's calculation of allowance allocations in the PTR was hardly a model of clarity. But EPA's failure to provide with the NODA tables comparable to the above-described PTR tables leaves UARG members and other electric utilities and electric generating companies even further in the dark about what their unit allowance allocations will be, based on the outcome of EPA's 2012 allowance allocation determinations using the updated NEEDS database and the updated IPM platform. [EPA-HQ-OAR-2009-0491-3773.1_NODA, pp.6-7]
Perhaps the single most important file EPA did not provide with the NODA was a file comparable to the PTR "Detailed Unit-Level Data for State-Budgets, Unit Allocations, and Unit Emission Rates" (EPA-HQ-OAR-2009-0491-0074.1) (an Excel spreadsheet entitled "BADetailedData.xls"). Without this file, electric generating companies cannot determine the impact of the NODA on their allowance allocations. Although EPA did provide a new "IPM Run  -  TR Base Case v.4.10  -  2012 Parsed File" and a new "IPM Run-TR SB Limited Trading v.4.10  -  2014 Parsed File," without critically important additional information, electric generating companies cannot calculate the SO2 or NOx allowance allocations for their units for 2012 or (where applicable) 2014. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.7]
EPA made "adjustments" to the IPM-projected unit-specific emissions for 2012, and provided these adjustments in the BADetailedData.xls file for the PTR. See BADetailedData.xls at the "Adjustments" tab. In addition to providing these EPA adjustments to the IPM results, the BADetailedData.xls file provided the projected unit-specific operating parameters (e.g., heat rates, emission rates, and controls) in one location, allowing electric generating companies to check EPA's assumptions and better understand how EPA calculated each unit's allocations. The BADetailedData.xls file also clarified whether a state's annual 2012 NOx and SO2 unit allocations and seasonal NOx unit allocations were based on reported data or on the 2012 IPM projections. As described in EPA's Technical Support Document ("TSD") on "State Budgets, Unit Allocations, and Unit Emissions Rates" ("State Budgets TSD"),3 EPA based the 2012 budgets (annual SO2 and NOx and seasonal NOx) on the lower of the recent actual emissions (essentially the 2009 reported emissions for existing units, aggregated by state) or the 2012 IPM projected base case emissions at the state level. In the BADetailedData.xls file, EPA indicated which emission amount was lower for each state and, thus, whether the 2009 "reported" emission amount or the 2012 "projected" emission amount served as the basis for the allowance allocations in that state. Without the BADetailedData.xls file, it is not possible to determine from the NODA the statewide budgets and the unit allowance allocations for 2012.4 EPA should not proceed further with this rulemaking until it has provided this critical information for public review and comment. [EPA-HQ-OAR-2009-0491-3773.1_NODA, pp.7-8]
In addition to not providing information needed to evaluate the effects of the NODA on state budgets and unit allowance allocations, EPA states in the NODA that it intends to change the NOx emission rates used in its calculations again before it takes final action in this rulemaking: [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.8]
EPA intends to update the NOx rates for fossil-fuel fired units in the final rule to reflect the more recent 2009 data. IPM v.4.10 and the previous version of IPM used for the Proposed Transport Rule analysis relied on 2007 unit level NOx rates. The updated NOx rates will more accurately portray the unit level control installations that have occurred at power plants during the past several years. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.9]
These changes in the NOx rates will result in additional changes to the final unit-level allowance allocations. Electric generating companies will have no opportunity to review the new NOx rates assigned to their units and, thus, no opportunity to evaluate whether EPA made correct adjustments. Thus, EPA should also provide this information for public review and comment before proceeding to final action. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.9]
For the reasons discussed above and in UARG's PTR Comments, the proposed NOx and SO2 allocations are likely to change due to a number of factors, including the many errors and ill-founded assumptions contained in NEEDS and IPM and reflected in the NODA information. EPA will presumably make at least some of the corrections requested in comments on the PTR and NODA. Fluctuation of allowance allocations prevents electric generating companies from planning for the future, which further exacerbates the problems associated with the extremely compressed schedule under EPA's proposal for installation of controls -- a matter discussed in detail in UARG's PTR comments. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.9]
In a stakeholder meeting held shortly after EPA issued the PTR but before its publication in the Federal Register, EPA requested that electric generating companies provide detailed comments correcting any inaccurate data or ill-founded assumptions that EPA made with respect to specific units. Publication of the NODA, which changes much of the information and many of the assumptions on which the PTR was based, has required electric generating companies to start over and to attempt, at considerable cost and with great difficulty, to repeat the same process -- to the extent it is even possible to do so based on the limited and incomplete information provided by EPA. Yet EPA has, without explanation, failed to provide the information that would be necessary for companies to complete reviews similar to those that they undertook with respect to the PTR. Without the detailed information regarding key IPM runs and the assumptions associated with statewide budgets and unit-specific allocations discussed above, electric generating companies lack the information necessary to comment meaningfully on the impact of the NODA on the PTR. Thus, EPA has failed to provide an adequate opportunity for public review and comment on its proposal. [EPA-HQ-OAR-2009-0491-3773.1_NODA, pp.9-10]
EPA's Decision To Base 2014 SO2 Allowance Allocations for Units in Group 1 States on the Same State-Level Emission Caps Used in the PTR -- Even Though Revised Data and an Updated Modeling Tool Were Available -- Is Arbitrary and Unjustified. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.10]
The primary purpose of the NODA was ostensibly to announce "an updated version of the power sector modeling platform that EPA proposes to use to support the final rule . . . consist[ing] of updated unit level input data ( [NEEDS v4.10]) and a set of model run results with the updated modeling platform ([IPM] v4.10)." The "set" of model run results that EPA elected to provide pursuant to the NODA was, in fact, seriously deficient, for reasons discussed in these comments. With respect to UARG's comments in section VII below, which urge EPA to redo its entire analysis using the updated NEEDS database and revised IPM platform, EPA's decision not to provide an updated "TR SO2 2000" IPM run, using the revised database and modeling platform, to establish new proposed 2014 SO2 state budgets provides one of the clearest example of the flaws in EPA's process. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.10]
EPA stated in its State Budgets TSD that "[g]roup 1 state budgets are based on reductions projected to be cost-effective at $2000 per ton of SO2 . . . [based on] . . . the IPM run [i.e., TR SO2 2000]." EPA did not state directly in the NODA that this critically important run would be omitted from the new data "set," but it got that point across nonetheless: [EPA-HQ-OAR-2009-0491-3773.1_NODA, pp.10-11]
These policy runs [i.e., the limited set of runs that EPA provided] include the same State-level caps that EPA modeled in the Proposed Transport Rule. The caps have not been modified to account for any changes that the new modeling might suggest; they are merely provided for informational purposes to allow commenters to understand the impact that changes in the model platform have on the projected impacts of the caps. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.11]
The "State-level caps" to which EPA apparently refers, i.e., the 2014 SO2 budgets for group 1 states, are the results of the TR SO2 2000 IPM run. The results of that run are input to the IPM Run  -  TR SB Limited Trading  -  Summary Report run and the unit-level parsed file for 2014. The practical effect of holding the 2014 SO2 budgets for group 1 states constant and re-running the TR SB Limited Trading runs with the updated NEEDS database and IPM platform is that an individual unit's percentage of the state budget changes but the state budget does not -- i.e., a unit's share of the "pie" changes but the size of the pie (artificially) remains the same. It would be far more relevant and more useful for electric generating companies (and states) to have access not only to the information provided with the NODA but also to a model run that demonstrates the effects of the updated database and modeling platform on the size of the state budgets. EPA must have known that "new modeling" of state budgets based on the updated NEEDS and IPM platform would not merely "suggest" revised emission caps -- that new modeling in fact would plainly result in establishment of new caps at levels different from those proposed under the PTR. EPA provides no justification for its decision not to provide a TR SO2 2000 IPM run using the updated NEEDS database and IPM platform. In short, EPA's decision to re-run the Limited Trading unit-level parsed file for 2014 with the revised NEEDS database and updated IPM platform while leaving state budgets the same -- based on the unrevised data and IPM platform used in the PTR -- is illogical and arbitrary. [EPA-HQ-OAR-2009-0491-3773.1_NODA, pp.11-12]
Although EPA's failure to provide the updated 2014 SO2 budgets for group 1 states based on IPM v.4.10 undermines the public's ability to understand the impact of the updated NEEDS database and IPM platform on the state-level caps for 2014, even a cursory comparison of the limited set of new IPM runs provided with the NODA demonstrates that the impact of the updated NEEDS database and updated IPM platform must be significant. Among the few IPM runs based on the updated NEEDS database and updated IPM platform that EPA did provide in the NODA are the TR SB Limited Trading Summary reports for 2012, 2015, 2020, and 2030. The following comparisons of these reports with reports based on the corresponding IPM run using the earlier versions of NEEDS and IPM illustrate the dramatic impacts of using the new information: [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.12]
The total projected demand for power in 2015 is reduced by 230 GWh -- from 4,333 GWh in the PTR to 4,103 GWh in the NODA. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.12]
The PTR projected 23.7 GW of new generation capacity from coal and 2.3 GW of new generation capacity from wind by 2015. The NODA projects only 2 GW of new generation capacity from coal and 22 GW of new generation capacity from wind by 2015 -- almost the exact inverse of EPA's projection for these two energy sources in the PTR. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.12]
The PTR projected a total of 80.3 GW of flue gas desulfurization ("FGD") unit retrofits by 2015, while the NODA projects a total of only 49 GW of FGD retrofits by 2015. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.12]
These very substantial changes in EPA's projections of the demand for power, the projected mix of new generation capacity, and projected pollution control retrofits suggest that it would be reasonable to expect significant changes in the 2014 SO2 budgets for group 1 states (as well as the 2012 SO2 and NOx budgets) if those budgets are based on the revised versions of NEEDS and IPM. EPA thus should promptly provide the results of a re-run TR SO2 2000 using the new NEEDS and IPM versions. [EPA-HQ-OAR-2009-0491-3773.1_NODA, pp.12-13]
Several of the Revisions to NEEDS and IPM that Are Reflected in the NODA Are Inappropriate or Inadequately Explained. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.13]
EPA's Upward Adjustment of Its Assumption Regarding FGD Maximum Removal Efficiency Is Unjustified and Inaccurate. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.13]
EPA states in its IPM v.4.10 Documentation that it assumes a maximum SO2 emission removal efficiency for wet FGDs of 98%, representing an increase of three percentage points over the maximum percentage removal assumption used in the version of IPM on which EPA relied in developing the PTR. Compare IPM v.4.10 Documentation at 5-2 with EPA, "Updates to EPA Base Case v.3.02 EISA Using the Integrated Planning Model" ("Base Case v.3.02 TSD") at 8 n.3 (July 2010), Docket ID No. EPA-HQ-OAR-2009-0491-0052, available at http://www.epa.gov/airquality/transport/tech.html. EPA does not provide an explanation or any justification for this upward revision in assumed wet FGD removal efficiency, other than to say that, in transferring data from the EIA's Form 767 for use in IPM v.4.10, "changes were made." Base Case v.4.10 Documentation at 5-2. EPA states further that, in modeling the effects of installing wet FGDs, EPA assumed that the new scrubbers would operate at maximum efficiency. Id. ("existing units that are selected to be retrofitted by the model with [wet] scrubbers are given the maximum removal efficienc[y] of 98% . . . . Potential (new) coal-fired units built by the model are also assumed with a [wet] scrubber achieving a removal efficiency of 98% . . . ."). In the absence of a more explicit explanation by EPA, commenters can only presume that this is an assumption of continuous control efficiency of 98%. It is unreasonable for EPA to assume that new FGDs will always operate at maximum efficiency, regardless of the percentage of SO2 that is estimated to be removed at maximum efficiency. Equally important, the level at which EPA assumes wet FGDs will operate -- 98% -- is unrealistic. [EPA-HQ-OAR-2009-0491-3773.1_NODA, pp.13-14]
A recent study of the best-performing FGD equipment -- evaluating the removal performance of the ten lowest SO2 emitting units nationwide -- concluded that "none of these `top performing' wet FGD systems was able to achieve a removal efficiency of 98% or greater in every month of the year." See Cichanowicz, J.E., "Overview of Information on Projected Control Technology Costs and Performance as Developed for EPA's Integrated Planning Model (IPM)," at 4 (Oct. 15, 2010) (hereinafter "Cichanowicz Report") (quoting Weilert, C.V., et al., "Emissions Control Performance Achieved in Practice by Electric Utility FGD Systems in the United States," at , proceedings of the 2010 Power Plant Air Pollutant Control MEGA Symposium (Aug. 30-Sept. 2, 2010, Baltimore, Maryland)). In fact, the available data suggest that even top-performing wet FGD units are unable to achieve consistent, annual average reduction levels of more than perhaps 95% to 96% SO2 removal. Id. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.14]
EPA's assumption that the "new" scrubbers that IPM projects will be installed in the coming years will operate continuously and consistently at 98% efficiency -- a level perhaps 2 to 3 percentage points above the efficiency level that they may be likely to actually achieve on an annual average -- will result in an insufficient number of allowances being allocated to units projected to add new FGD. Thus, based on EPA's proposal, units projected to be retrofit with wet scrubbers will have insufficient allowances at the start of each control year and will be forced to purchase allowances to make up the difference. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.14]
This effect of EPA's unrealistic assumption regarding the removal efficiency of new wet FGDs is exacerbated by the fact that EPA proposes to reduce allowance allocations by 3% to create an allowance set-aside for new units before distributing allowances to existing units. See 75 Fed. Reg. at 45309/1. Given that EPA plans to set aside 3% of each state's allowance budget for new units and distribute the remaining 97% among existing units, the Agency should be all the more careful to avoid making unrealistically aggressive assumptions regarding removal efficiency. [EPA-HQ-OAR-2009-0491-3773.1_NODA, pp.14-15]
EPA should adjust its assumption regarding the control efficiency at which new scrubbers will operate to reflect a more realistic annual-average maximum-removal assumption of 95% to 96% and recalculate state budgets and unit-level allocations accordingly. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.15]
Units with Generating Capacity Less than 100 MW Cannot Properly Be Assumed To Be Candidates for Installation of FGD or SCR. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.15]
EPA explains in its Base Case v.4.10 Documentation that IPM v.4.10 assumes that units with generating capacities between 25 MW and 100 MW are candidates for installation of FGD and selective catalytic reduction ("SCR"). However, in the base case for the PTR, EPA assumed that "coal-fired EGUs under 100 MW capacity [did] not have the option of retrofitting FGD or SCR." Base Case v.3.02 TSD at 20 (emphasis added). EPA fails to provide any plausible explanation for changing this assumption. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.15]
In fact, EPA's new assumption that units with capacities between 25 MW and 100 MW can be retrofit with FGD and SCR is unrealistic. In many cases, it is impossible to retrofit units with capacity below 100 MW with FGD and SCR. And in cases where it is technically possible to do so, it would rarely, if ever, be cost-effective. EPA acknowledged in its Base Case v.3.02 TSD that "FGD and SCR retrofits to such small units are very costly in any case." Id. The emission reduction (and air quality improvement) benefits to be gained from such a large expense are quite limited due to the low emission amounts from "such small units." Thus, even in cases where below-100 MW units theoretically could be retrofit with FGD or SCR, it would not be an economic choice to do so, at least in the great majority of cases. [EPA-HQ-OAR-2009-0491-3773.1_NODA, pp.15-16]
EPA should recalculate its base case emission inventories to remove the assumption that small units, with capacities between 25 MW and 100 MW, can be retrofit with FGD and SCR. At a minimum, EPA should explain its reasoning for changing its assumption regarding small unit retrofits in the NODA. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.16]
EPA May Well Be Understating SCR Capital Costs. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.16]
UARG supports EPA's decision to retain Sargent & Lundy ("S&L") to estimate control technology costs for the Proposed Transport Rule based on S&L's database of component costs and installation charges. Using a firm that specializes in determining the average costs of installation, operation, and maintenance of electric power generation and emission control equipment is likely to produce data that is more accurate than if EPA had pursued certain other cost-estimation approaches. See Cichanowicz Report at 1. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.16]
Although UARG believes that many of S&L's cost estimates are reasonable and likely to be accurate, or close to accurate, see generally id., S&L's projected capital cost of adding SCR appears likely to be an underestimate. See id. at 7-9 (describing differences between S&L's estimates and those provided as a result of a recent UARG survey and discussing possible reasons for those differences). [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.16]
This apparent underestimate of SCR costs can affect the calculations and assumptions on which EPA relies in the Proposed Transport Rule, including the creation and evaluation of cost curves in EPA's multi-factor analysis for determining emission reduction obligations under the PTR and the selection of "breakpoints" for emission controls, based on the cost curves. Furthermore, the S&L estimates reflected in the NODA differ from the control cost estimates that EPA used for its analyses in the PTR. EPA's use of these different cost estimates will affect EPA's analyses, regardless of whether the new cost estimates are more or less accurate than the estimates used for the PTR. See also section VII infra. EPA should therefore revise its analyses using appropriate control cost estimates and allow for public comment on the results. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.17]
EPA's Revised NEEDS Database and IPM Platform Still Contain Numerous Errors and Have Introduced Additional Inaccurate Assumptions. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.17]
As discussed in section VIII of UARG's comments on the PTR, NEEDS v.3.02 and IPM v.3.02 contained many inaccurate inputs, in the form of errors in NEEDS, inaccurate IPM constraints, and inaccurate outputs. Despite the limited time provided for UARG members to check the accuracy of the "updated" NEEDS v.4.10 and IPM v.4.10, UARG and its members have discovered that it appears that EPA has introduced additional errors and inaccurate assumptions in the updated versions, while leaving many earlier problems uncorrected. As illustrated by the discussion in section V.A supra, certain systemic adjustments to EPA's assumptions regarding new FGD control efficiencies are inconsistent with real-world experience and would result in inadequate allowance allocations. Moreover, unit-specific examples of changed assumptions are provided below. In addition to the same categories of errors and assumptions catalogued in UARG's comments on the PTR, new assumptions in IPM v.4.10 regarding fuel prices and the cost of control technologies appear to have resulted in a new  category of errors -- errors related to, for example, the retirement of coal-fired units and the controls that existing units are projected to install. [EPA-HQ-OAR-2009-0491-3773.1_NODA, pp.17-18]
Examples of errors and incorrect assumptions in NEEDS v.4.10 include: [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.18]
NEEDS v.4.10 reports that Units 1-3 at the Baldwin Energy Complex in Illinois are currently equipped with wet FGD systems. That is incorrect. As a result of a consent decree, Unit 1 is required to install a dry FGD system by the end of 2011, Unit 2 is required to install a dry FGD system by the end of 2012, and Unit 3 is required to install a dry FGD system by the end of 2013. NEEDS also assumes a 98% removal efficiency for wet FGD, which, for reasons set forth above, could not be assumed to be achievable on an annual basis even if these units were to install wet rather than dry FGD. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.18]
NEEDS v.4.10 reports that Units 1-3 at the Baldwin Energy Complex in Illinois are currently equipped with cold-side electrostatic precipitators ("ESPs") and baghouses. This is incorrect. Although these units are currently equipped with ESPs, Unit 1, Unit 2, and Unit 3 are not required to construct baghouses until the end of 2011, 2012 and 2013, respectively. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.18]
NEEDS v.4.10 reports that Units 1 and 2 at the Baldwin Energy Complex in Illinois have an uncontrolled NOx rate of 0.0723 lb/mmBtu. Based on continuous emission monitoring system ("CEMS") data previously reported to EPA, the uncontrolled rate of these units is 0.61 lb/mmBtu. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.18]
NEEDS v.4.10 reports that Unit 9 at the Havana Station in Illinois has an uncontrolled NOx rate of 0.0723 lb/mmBtu. Based on CEMS data previously reported to EPA, the uncontrolled rate of this unit is 0.61 lb/mmBtu. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.18]
NEEDS v.4.10 reports that Unit 2 at the Ghent facility in Kentucky had an SCR installed as of 2009. That unit does not have an SCR, and installation of SCR is not planned at that unit. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.18]
NEEDS v.4.10 reports that two units at the Armstrong power station in Pennsylvania have installed selective noncatalytic reduction ("SNCR"). A Mobotech Rotamix system was installed in 2003 in an effort to reduce NOx, but the equipment was ineffective and was removed. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.18]
NEEDS v.4.10 reports FGD removal efficiency at the Mitchell power station in Pennsylvania as 99.9% and at the Pleasants power station in West Virginia as 97%. These removal efficiencies are incorrect. Actual removal efficiency at the Mitchell power station averages 97% and actual removal efficiency at the Pleasants power station averages 95%. [EPA-HQ-OAR-2009-0491-3773.1_NODA, pp.18-19]
Examples of errors in IPM outputs and erroneous IPM inputs include:  [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.19]
IPM v.4.10 reports in both the TR_SB_Limited_Trading parsed files that the primary fuel for Units 1 and 2 at the Danskammer power station in New York is natural gas. The primary fuel for both units is oil. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.19]
IPM v.4.10 reports in both the TR_SB_Limited_Trading parsed files that the primary fuel for Units 1 and 2 at the Roseton power station in New York is natural gas. The primary fuel for both units is oil. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.19]
IPM v.4.10 reports NOx controls for Unit 4 at the Scherer power station in Georgia consisting of low NOx burners and separated overfire air. This is inaccurate -- only overfire air is installed at that unit. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.19]
IPM v.4.10 reports in the 2014 TR_SB_Limited_Trading parsed file that the coal-fired Unit 3 at the Sibley power station in Missouri will retire early. SCR was installed in 2009, making it highly unlikely that the unit will retire in or by 2014. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.19]
:: IPM v.4.10 reports in the 2014 TR_SB_Limited_Trading parsed file that the coal-fired Mount Tom power station in Massachusetts will retire early. Dry FGD was installed in 2009, making it highly unlikely that that facility will retire in or by 2014. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.19]
IPM v.4.10 reports in the 2014 TR_SB_Limited_Trading parsed file that the coal-fired Unit 4 at the Indian River power station in Delaware will retire early. Installation of dry FGD is planned for 2012, making it unlikely that the unit will retire in or by 2014. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.19]
The specific errors cited above are provided as examples of the types of mistakes found in the updated NEEDS and IPM modeling -- they represent a mere sampling of the problems found by electric generating companies. In order to provide an adequate opportunity to comment on proposed unit-level allowance allocations, EPA should correct these errors and publish a revised allocation table for comment. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.19]
In addition to the flawed IPM outputs for specific units, other outputs provided on a regional scale in the IPM Run  -  TR SB Limited Trading v.4.10  -  Summary Report do not seem plausible and call into question the accuracy and validity of the modeling results. Two examples are (1) IPM's forecast for additional wind generation by 2015 and (2) IPM's projected SO2 allowance price. [EPA-HQ-OAR-2009-0491-3773.1_NODA, pp.19-20]
As mentioned above, the IPM Run  -  TR SB Limited Trading  -  Summary Report projected 23.7 GW of new generation capacity from coal and 2.3 GW of new generation capacity from wind in 2015. The IPM Run  -  TR SB Limited Trading v.4.10  -  Summary Report projects only 2 GW of new generation capacity from coal and 22 GW of new generation capacity from wind in 2015. The magnitude of the projected increase in predicted new wind generation between successive versions of the model calls into question the validity of the model results. In any event, even if there is some "logical" justification for IPM's projection of 22 GW of new wind generation, there are certain practicalities that make that projection doubtful. As of January 1, 2010, the total installed wind generation capacity in the United States stood at 35 GW. IPM predicts that 21 of the 22 GW of projected new wind generation will be online by 2012. Thus, the additional wind generation that EPA projects would constitute a 60% increase in the United States capacity in approximately three years. Considering that the average-sized wind farm in 2009 had generation capacity of 91 MW, that would mean that approximately 231 average sized wind farms would have to be permitted and built by 2012. According to the American Wind Energy Association, it takes approximately 18 months to two years to permit and build even relatively small (50 MW) wind farms. The dramatic change in generation mix between successive versions of IPM and practical considerations of actually permitting and building that many new wind farms in a very short period call for explanation and additional justification by EPA of this very substantial change in its projections. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.20-21]
Finally, the IPM Run  -  TR SB Limited Trading v.4.10  -  Summary Report provides estimates of SO2 allowance prices for group 1 and group 2 states at $313 and $184, respectively. Although it is not possible to compare these prices to projections from the IPM Run  -  TR SB Limited Trading  -  Summary Report because allowance price projections were not provided in that report, a report by James Marchetti for the Midwest Ozone Group ("MOG") and submitted with MOG's comments on the NODA notes that the cost in 2015 of SO2 allowances in a group 1 state under an intra-state-only trading regime was estimated at approximately $1,900 per allowance. At best, this analysis demonstrates that the IPM projection of 2015 SO2 allowance prices is considerably underestimated. At worst, this analysis suggest a flaw in IPM's methodology. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.21]
In Making the Changes Represented in the NODA, EPA Continues To Ignore the Effects of CAIR and Local Controls. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.21]
EPA indicates that IPM v.4.10 takes into account all existing federal and state air emission regulations (except for CAIR), as well as new source review ("NSR") and other settlements, that were in effect or were final as of August 2010. Base Case v.4.10 Documentation at 1-1.21 By contrast, the previous version of IPM, used to model the PTR, took into account these same factors effective as of February 3, 2009. 75 Fed. Reg. at 45243/2. Despite this updating by about 18 months with respect to EGU emission limitations, EPA in the NODA improperly continues to ignore the effects of CAIR and local emission controls, including controls affecting emissions from non-EGU point sources and nonpoint stationary sources. [EPA-HQ-OAR-2009-0491-3773.1_NODA, pp.21-22]
EPA Should Have Considered the Effects of CAIR. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.22]
As UARG explained in its comments on the PTR, EPA should have included CAIR in its base case modeling because it remains binding law until it is replaced by a valid rule. See UARG's PTR Comments at 50-53. According to the terms of the D.C. Circuit's December 2008 opinion on rehearing in North Carolina v. EPA, CAIR will remain binding law until a new rule is in place. Thus, it is appropriate for EPA to conclude in this rulemaking that there will be no time when neither CAIR nor a CAIR replacement rule will be in effect. See id. at 50-51. Additionally, EPA has not demonstrated that EGUs in the few states that were regulated under CAIR but may not be regulated under the Transport Rule, as proposed, are likely to increase their emissions when CAIR expires, or that such increases would be permitted under state law. In reality, these EGUs have already made reductions pursuant to CAIR and it is very unlikely that they will increase their emissions to pre-CAIR levels once CAIR expires. Based on these factors, as well as the downward trend that EPA has acknowledged in PM2.5 and ozone concentrations nationwide,22 it is far more realistic to assume that CAIR applies than it is to assume that it does not. See UARG's PTR Comments at 52-53. [EPA-HQ-OAR-2009-0491-3773.1_NODA, pp.22-23]
EPA Should Have Considered the Effects of Local Controls. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.23]
UARG also explained in its comments on the PTR that EPA's proposal improperly failed to account for local emission controls. Section 107(a) of the CAA states that "[e]ach State shall have the primary responsibility for assuring air quality within the entire geographic area comprising such State." 42 U.S.C. § 7407(a). See UARG's PTR Comments at 64-66. Thus, EPA's proposal to promulgate and implement a rule that regulates sources of transported pollutants without considering the effects of local controls, see 75 Fed. Reg. at 45226/3, is contrary to the Act. EPA attempted to explain its failure to account for local controls in the PTR by asserting that "nonattainment areas for the 1997 PM2.5 and ozone standards were not announced until 2004 and 2005 respectively, and the corresponding [SIPs] were not due until 2007 and 2008, thereby preventing the inclusion of these local measures in the 2005 emissions inventory." EPA, "Emissions Inventories" TSD ("Emissions TSD") at 11 (June 2010), Docket ID No. EPA-HQ-OAR-2009-0491-0050, available at http://www.epa.gov/airquality/transport/tech.html. As UARG noted in its comments on the PTR, however, the unavailability of this information in 2005 does not explain EPA's failure to account for it in its future base case projections. See UARG's PTR Comments at 65 n.39. Again, despite the many updates reflected in the NODA, EPA fails to account for local controls. EPA must consider the effects of local controls on its modeling and on air quality and attainment and interference with maintenance of the NAAQS.  [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.23]
Moreover, even if one were to accept that EPA had insufficient time to account for local controls in the entire proposed control region before issuing the PTR, EPA could and should have at least considered the effects of local controls on the areas surrounding the six monitors with perceived maintenance problems that led to EPA's proposed designation of the group 1 states that are subject to additional SO2 reduction requirements in 2014. See UARG's PTR Comments at 61-64 (discussing EPA's classification of group 1 states based on six monitors with perceived maintenance problems). EPA certainly has the resources to consider the effects of local controls in the areas surrounding these six monitors.23 Such consideration of local controls may have eliminated the need (as determined by EPA) for additional SO2 reduction requirements in 2014, or at least may have reduced the number of group 1 states. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.24]
The Availability of NEEDS v.4.10 and IPM v.4.10 and the Central Role These Items Play in the Structure of EPA's PTR Warrant a New or Supplemental Proposed Rule Based on the Results of the New Data and Modeling. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.24]
EPA's PTR depends in substantial measure on the validity, reliability, and accuracy of IPM. No other tool has as great an influence on key elements of the PTR. Indeed, the results of IPM runs have a direct or indirect effect on every major step in EPA's PTR methodology. In the NODA, EPA acknowledged as much by stating: [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.24]
Changes from the projections relied on in the proposed rule, from using an updated model, could impact the final rulemaking in a number of ways including, but not limited to: [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.24]
Changing emission projections that were used to determine which downwind areas have air quality concerns (i.e., non-attainment or maintenance) absent this rulemaking and to determine which States contribute to those problems. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.24]
Changing cost and emission projections used in the multi-factor [e.g., cost curve] test to determine the amount of emissions that represent significant contribution. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.24]
75 Fed. Reg. at 53614/3. If anything, EPA understates the potential impact of the updated database and platform. The NEEDS inventory and the output of IPM substantially influence the fundamental components of the PTR: the analyses of air quality; the linkages of upwind states to downwind problem areas; the definition of significant contribution to nonattainment and interference with maintenance; and the establishment of statewide budgets and unit-specific allocations. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.25]
Despite the central role of IPM in each of these components, EPA elected to provide a very limited number of runs using the updated NEEDS database and revised IPM platform and then further qualified the import of the runs by stating that "they are merely provided for informational purposes to allow commenters to understand the impact that changes in the model platform have on the projected impacts of the caps." It is unclear why EPA tries to downplay the potential impact of the updated NEEDS database and IPM platform when EPA clearly "proposes to use this version of the IPM model [IPM v.4.10] in the final Transport Rule." As discussed in section IV above, a cursory comparison of the NODA IPM runs with the PTR IPM runs demonstrates that changing the NEEDS emission inventory and using an updated IPM version result in significantly different outcomes. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.25]
UARG appreciates that entirely redoing EPA's analysis using the updated NEEDS database and IPM platform takes significant time and resources. EPA should, however, conduct its analysis using the most current model and information at its disposal, and then should make all the results available to the public and allow an adequate time for public review and comment before taking any final action in this rulemaking. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.25]
In all its complexity, EPA's PTR methodology can be broken down into approximately eight major steps. In each of these steps, IPM provides information critical to the accuracy and validity of EPA's analysis. The purpose of reviewing each of these steps is to demonstrate EPA's thoroughgoing reliance in this rulemaking on IPM and the importance of EPA undertaking a full analysis with the revised modeling tool and data, and allowing a full opportunity for public comment on the methodology and results of that analysis. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.26]
The following paragraphs describe the eight major steps in EPA's methodology, as reflected in the PTR, and discuss why these steps depend on IPM results: [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.26; See pp.26-29 of this comment summary for the eight step process in EPA's methodology]
If a state's 2012 budget was based on the IPM 2012 projection (because the state's 2012 projected emissions were lower than its actual reported emissions), then the individual allocations for units in that state were based on the projected emissions for units in the same IPM Run-Parsed File SB Limited Trading run that contained the 2012 unit-level emissions. Yet, without offering any particular explanation as to why it replicated certain portions of this step using the new IPM version even though it did not do so for earlier steps, EPA recalculated the 2014 unit-level SO2 emissions for units in group 1 states in a new "SB Limited Trading v.4.10  -  2014 Parsed File" -- but apparently limited by the original proposed state emission budgets derived from the PTR IPM-based TR_2000_SO2. Without explanation, EPA elected not to provide for public review and comment the parsed results for 2012 unit specific emissions based on the updated NEEDS database and IPM platform. [EPA-HQ-OAR-2009-0491-3773.1_NODA, pp.29-30]
As the discussion above indicates, at every major step in EPA's methodology -- e.g., creating emission inventory cases as inputs to CAMx modeling, projecting future nonattainment and maintenance problem areas, establishing linkages of upwind states to downwind nonattainment and maintenance problem areas, defining significant contribution to nonattainment and interference with maintenance, and establishing unit-specific allocations -- IPM played an indisputably critical role in ultimately determining unit-specific allowance allocations. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.30]
Although EPA states in the NODA that it proposes to use IPM v.4.10 (along with NEEDS v.4.10) "in the final Transport Rule," the NODA is unclear as to exactly where and how EPA intends to use it. EPA should clarify these issues for the public and should revisit the basis for its proposal if it intends to proceed with this rulemaking and to continue to use its proposed approach to implementing section 110(a)(2)(D)(i)(I) of the Act. In doing so, EPA should redo each step of its methodology as described above using the updated NEEDS inventory and IPM platform. EPA then should issue the results of its new analysis for public review and comment, providing an adequate comment period. [EPA-HQ-OAR-2009-0491-3773.1_NODA, p.30]
Wisconsin Power and Light Company
WPL notes that the EPA lists inclusion of the Wisconsin Mercury Rule (NR446) in the IPM 4.10 model (Chapter 3, Appendix 3-2.5). WPL does not believe that it is appropriate to include the NR446 Wisconsin Mercury Rule in the IPM modeling for CATR as it is intended to only address emissions reductions for S02 and NOx. The inclusion of this rule for CATR may result in unintended consequences in the EPA's IPM modeling, such as overestimated emissions reductions, reduced generation operation and even premature retirements that may not be reasonable assumptions. In addition, the Wisconsin Mercury Rule includes the following requirement for review upon issuance of the federal Utility MACT standard: [EPA-HQ-OAR-2009-0491-2844.1 p.5]
'NR 446.19 Evaluation reporls. (2) 1n addition to Ihe reporl required under sub. (1), the department shall report to the natural resources board within 6 months of the date of promulgation of a federal regulation under section 111 or 112 of the Act (42 USC 7411 or 7412) or the enactment of a federal law that has mercury reduction requirements for the mercury emission sources affected by this subchapter. The report shall include a comparison of the federal requirements and the requirements of this subchapter along with recommendations for revisions to this subchapter or other actions. ' [EPA-HQ-OAR-2009-0491-2844.1 p.6[EPA-HQ-OAR-2009-0491-2844.1]]
WPL reinforces that EPA must assure the accuracy of the input data for the final CATR. This includes validating generation data inputs used in EPA's integrated planning and air quality models. Utility companies nationwide have recently submitted much of the information required in EPA models as part of certified responses to the Utility Maximum Achievable Control Technology (MACT) Information Collection Request (ICR). This includes information on generation fleet operating characteristics and permitted emissions rates. WPL requests that input data and modeling used for the final CATR be appropriately updated to reflect the Utility MACT ICR database. In addition, WPL provides Table I below with corrections to the EPA's NEEDS 4.10 database. Corrected values are in the cells highlighted yellow and in red text. [EPA-HQ-OAR-2009-0491-2844.1 p.6[EPA-HQ-OAR-2009-0491-2844.1]]
Response: 
Many of the above comments are centered around concerns with EPA's modeling, and the subsequent use of that modeling to determine state budgets and unit level allocations.  EPA took significant action to respond to these concerns in its final Transport Rule.
First, EPA changed its allocation methodology to be based on historic heat input and emissions data that is generally reported by the sources' DR who testifies to its accuracy and completeness.  This was done in response to comments that expressed concern/disagreement about the IPM unit level projected emissions on which the proposed allocations were based.  By switching to a historic  data based methodology, the degree to which any discrepancy between a units actual future operation and its projected future operation would impact the unit's allocation is greatly diminished.  EPA recognizes that IPM is a dynamic linear programming model that generates optimal decisions under the assumptions of perfect foresight and results in a least cost method of meeting demand.  However, invariably, there will be discrepancies between IPM unit level projections and a unit's actual future operations due to non-economic or other variables that IPM does not capture.  At the state and regional level, the discrepancies are small and random and thus do not result in biases.  However, their impact at the unit level may be significant and this was one of the drivers behind switching to an allocation method based on historic data. For more information on the allocation method, see Preamble Section VII D.
Second, EPA reviewed the comments and has made significant updates to its IPM v.3.02 modeling used at proposal.  These updates include changes to both the more general IPM assumptions (e.g., gas price assumptions) and specific unit level assumptions (e.g., that current retrofit status at a unit).  These updates were made to the IPM model, and the updated versions (EPA IPM v.4.10) was used for all the final rule analysis.  In regards to unit specific adjustments, EPA did not manually adjust projected unit level modeling outputs, but it did make unit level updated to its NEEDS database used as a model input that impacted the unit level model outputs.   Some of the most frequent general IPM comments noted above that were addressed in the updates are: FGD removal efficiency was adjusted for new retrofits, and for existing retrofits it was indexed to historic performance at the unit.  Additionally, many of the above comments were focused on a sources ability to switch coals.  EPA modified its modeling to better reflect the cost and feasibility of switching and blending coals.  State Rule and consent decrees were updated according to comments.  Additionally, there were more than 1000 unit specific modeling changes made in response to corrections provided by the commenter.  For more detailed discussion of EPA IPM v.4.10 assumptions and assumption updates, see the EPA IPM v.4.10 documentation and the "Transport Rule IPM Assumptions Response to Comments" in the Appendix
These two adjustments, updates to the modeling and updates to the allocation methodology, work in concert to comprehensively address many of the concerns expressed by commenters on their unit level projections and allocations.
Finally, EPA notes that it conducted its air quality analysis and its multi-factor analysis to determine state budgets completely anew for the final Transport Rule using the updated modeling that reflected input and corrections received from commenters.
Organization: New Jersey Department of Environmental Protection (NJDEP)
Comment: 
After reviewing the data used by USEPA to support the Transport Rule, New Jersey's Department of Environmental Protection ("Department") found that the information for many New Jersey sources was not correct. More importantly, the data did not correctly reflect recent rule adoptions by the Department  -  Sulfur in Fuels (N.J.A.C. 7:27-9, August 24, 2010) and Ozone RACT (N.J.A.C. 7:27-16 & N.J.A.C. 7:27-19, March 20, 2009). Attached are two documents: NJ_EGU_Data.xls [EPA-HQ-OAR-2009-0491-3770.1_NODA] and NJ_EGU_rules.doc. [EPA-HQ-OAR-2009-0491-3770.2_NODA] NJ_EGU_Data.xls is the list of electric generating units in New Jersey that are affected by the Transport Rule. This spreadsheet contains current and future permit limits for NOx and SO2. This data should replace those that the USEPA used in the NODA. Additionally, NJ_EGU_rules.doc summarizes New Jersey's rules for EGUs, which should be included as constraints in the NODA. [EPA-HQ-OAR-2009-0491-3770_NODA, p.1]
The Department urges the USEPA to use the provided information to update the data used to support the Transport Rule, including updating the NOx and SO2 allowance allocations for the sources in New Jersey. It is very important that the analysis behind the Transport Rule be based on sound information. [EPA-HQ-OAR-2009-0491-3770_NODA, p.1]
Response: 

The updated IPM modeling used in EPA's final Transport Rule analysis includes updates to NOX rate limits and SO2 permit rates in New Jersey.  See the final Transport Rule base case and policy case for emission rates observed in the analysis and the IPM NEEDS file for the SO2 permit rates imposed at specific units.  See "Transport Rule IPM Assumptions Response to Comments" for an additional listing of unit level changes made in the IPM modeling between proposed rule and final rule.

Organization: State of Wisconsin, Department of Natural Resources
Comment: 
State of Wisconsin, Department of Natural Resources
EPA should not use the IPM model results to set statewide or unit specific operating levels and emissions (S02 and NOx) for the 2012 and 2013 compliance years for purposes of either emission budget or allowance allocation. The IPM model curtailed operation of a significant number of generation units based on faulty heat rate and dispatch assumptions. Rather, the 2012 and 2013 state and unit specific operating levels should be derived from historic information such as the 2009 heat input level coupled with a moderate grow1h factor or a derived average operate level. The 2009 operating year already represents a low capacity scenario for individual generating units and it is not reasonable to assume that individual unit operation can be further curtailed prior to 2014. A comparison of fuel consumptions for Wisconsin and adjacent states is provided in Attachment A. As stated under the broader comment, Wisconsin also looks to EPA to allow a different basis other than IPM outputs for allocating emission budgets for 2014 and after. [EPA-HQ-OAR-2009-0491-3803.1_NODA, p.1] [[See Docket Number EPA-HQ-OAR-2009-0491-3803.2_NODA, pp.1-2 for Attachment A.]]
Wisconsin is providing corrections to technical assumptions and data for individual generation units, as provided in Attachment B, for application to the NEEDs input data and IPM modeling effort. [EPA-HQ-OAR-2009-0491-3803.1_NODA, p.1] [[See Docket Number EPA-HQ-OAR-2009-0491-3803.2_NODA, pp.3-12 for Attachment B.]]
I.    Comments to General IPM assumptions   
-Generation Unit Heat Rates  -   The heat rate or the efficiency of converting fuel to electricity appears to be a key parameter in IPM determining the dispatch order for operating units.....especially coal fired generation.  As shown in Table 1 review of the heat rates in the NEEDs database indicates significant inconsistencies for specific generation units when compared to other data sources including previous versions of the NEEDs database and the 2009 Acid Rain database.  The presented Acid Rain heat rate is calculated from gross generation and heat input reported to the Clean Air Markets Division database.  [EPA-HQ-OAR-2009-0491-3803.2_NODA, p.4]  
Even if not a similar basis to NEEDs 4.10 heat rates ('net' versus 'gross'), the alternative heat rates illustrate the impact that relative heat rates can have on unit dispatch order.  In Table 2 the larger coal fired units are compared.  Sorting by most to least efficient heat rates yields a significantly different dispatch order.  One particular example, is for the Columbia 2 plant which under IPM 4.1 has operation curtailed because the assumed heat rate puts the unit far down the list.  In comparison, the Acid Rain based heat rates have the Columbia 2 unit much further up the list in comparable efficiency.  This latter dispatch order is more consistent with the relative operating levels seen between Wisconsin units in 2009.  At a minimum Wisconsin requests EPA to review and correct heat rates for coal and combined cycle generation units with a difference greater than 5% as shown in Table 1.  Some units even appear to have a default assumed heat rate which are not adequate.  The bottom line is that assigning the correct heat rate is essential for effective representation of unit operation by the IPM model.  [EPA-HQ-OAR-2009-0491-3803.2_NODA,p.4] [[See Docket Number EPA-HQ-OAR-2009-0491-3803.2_NODA, p.6 for Table 1 and p.8 for Table 2.]]
Detailed generating unit information addressing the following comments is provided under the section 'Specific Comments to Individual Wisconsin Generating Units'  [EPA-HQ-OAR-2009-0491-3803.2_NODA, p.4]
-Units missing from the emissions budget and allocation determination  -  Several generation units feed generators greater than 25 MW but are not included as Transport Rule generation units (Table 3).  [[See Docket Number EPA-HQ-OAR-2009-0491-3803.2_NODA, p.7 for Table 3.]]
-Existing and Committed Controls - EPA intends the IPM model to capture controls committed by 2012.  These controls are best reflected by first considering actual 2009 / 2010 emission rates.  For NOx the emission rates should be derived from operation during the ozone season whereas SO2 emission rates should be derived from annual data.  Where emission limitations are in place requiring post-combustion controls these limits should be in place of the actual emissions.  To this intent, emission rates and limits are provided in Table 4 for changes necessary to the NEEDs and IPM databases.  Also shown are applicable changes in later years reflecting controls available by 2012 and final NOx RACT requirements by the 2013 ozone season for EGUs in Wisconsin's ozone non-attainment counties. [EPA-HQ-OAR-2009-0491-3803.2_NODA, p.4][[See Docket Number EPA-HQ-OAR-2009-0491-3803.2_NODA, p.9 for Table 4.]]
-Control options assumed available under IPM for 2012 - EPA appears to include low NOx burner installations in additional cases by the 2012 timeframe.  The intervening timeframe appears too short, especially, when considering energy agency approvals and coordination of installation of multiple units over the available outages.   [EPA-HQ-OAR-2009-0491-3803.2_NODA, pp.4-5]
Another control option that appears overstated is the ability to switch from higher to lower sulfur fuels.  EPA should consider that, where practical, utilities have probably applied this option in response to CAIR 2010 to 2012 SO2 requirements.  The case of switching from bituminous to subbituminous coals typically requires equipment modification and additional safety measures that may take several years to achieve.  Even in the case where boilers are already burning a mixture of coals there is a threshold where additional equipment changes are probably needed.  EPA did not account for this technical issue.  In addition, boilers may not be designed for the lower Btu fuels and loose efficiency.  In fact some units in Wisconsin, such as Genoa, burn a specific mixture of bituminous and subbituminous coal in order to optimize the unit heat rate.  EPA also assumes that utilities burning subbituminous coals can obtain the cleanest of subbituminous coals.  This requires utilization of a limited number of mine sources and delivery options which is difficult to see happening by 2012 and 2013.   [EPA-HQ-OAR-2009-0491-3803.2_NODA, p.5]
On the whole EPA should not consider any level of fuel switching options to reduce SO2 emissions for the 2012 timeframe.  Wisconsin generation units with artificially low SO2 emission rates are identified in Table 5 along with their actual 2009 emission rate.  [EPA-HQ-OAR-2009-0491-3803.2_NODA, p.5] [[See Docket Number EPA-HQ-OAR-2009-0491-3803.2_NODA, p.10 for Table 5.]]
-Actual vs. Permitted SO2 emission rates  -  In predicting future emissions IPM increases SO2 emission rates for certain generation units when compared to current actual operations.  This appears to be based on IPM switching to lower cost fuel as allowed under the units permitted limit for SO2.  In this case a specific unit is provided a benefit at the cost of controls placed on other generation units.  For generation units shown in Table 6 the SO2 emission rates should be changed to reflect the 2009 emission rates.  [EPA-HQ-OAR-2009-0491-3803.2_NODA, p.5] [[See Docket Number EPA-HQ-OAR-2009-0491-3803.2_NODA, pp.10-11 for Table 6.]]
-Fixed Capacity Units  -  There are a number of generations units which have dedicated purposes not reflected in the IPM results including: grid support, district heating and cooling, and units with committed controls for long term operation.  EPA needs to consider these units, as listed in Table 7, with minimum proposed operating levels.   [EPA-HQ-OAR-2009-0491-3803.2_NODA, p.5] [[See Docket Number EPA-HQ-OAR-2009-0491-3803.2_NODA, pp.11-12 for Table 7.]]
-Installation Timeframes  -  The EPA assumes standard timeframes for the installation of different types of control equipment.  These timeframes also need to account for processes for approval to build the equipment from state agencies which have regulatory over-sight.  For example, a public utility in Wisconsin must have approval from the Wisconsin Public Service Commission in order to recover cost via the electric rate base.  This approval process in the past has taken up to a year when the requirement is clear-cut.  And in the case of capital intensive equipment such as FGDs and SCRs this process can extend even longer.  And in many cases such approval processes cannot be entered until EPA promulgates the final Transport Rule. [EPA-HQ-OAR-2009-0491-3803.2_NODA, p.5]
-Wisconsin Mercury Requirements  -  EPA incorporates a constraint into IPM for the Wisconsin state mercury rule which requires 90% reduction by 2015.  This rule also provides an alternative mercury reduction schedule if implementing significant NOx and SO2 controls.  It is not apparent from the documentation, but controls for NOx and SO2 should not be placed as an IPM constraint under the state rule  [EPA-HQ-OAR-2009-0491-3803.2_NODA, p.5]
Response: 
EPA has revised its allowance allocation methodology in response to concerns expressed by commenters.  The unit level allocations no longer rely on IPM modeling.  See section VII.D of the preamble for a description of the final Transport Rule allocation methodology.  EPA also made updates to its model where it received comments with well documented corrections that would have a significant impact on the model.  The final rule analysis was conducted with the models updated to reflect corrected data submitted in the comment period.  See EPA IPMv.4.10 documentation and the RTC Appendix for more details on IPM modeling adjustments in response to comments. 
EPA does rely on modeling projections at the state level for determining state budgets.  As many commenters noted, the model is much more accurate at this level and therefore appropriate to use for determining state and regional projections.  EPA's IPM model contains over 13 million variables, and while discrepancies between the variables as modeled and as reflected outside of the model could have significant impacts at the unit level, they are generally muted at the state and regional level due to the large sample of units being analyzed at that level.  Therefore, EPA feels it is appropriate to use the IPM model to determine state level budgets.  Furthermore, there are a lack of viable alternatives for determining state budgets; recent historic data would not work as it reflects operations under CAIR policy constraints and EPA is developing state budgets independent of CAIR budget or emission levels as the Court determined the rule to be illegal. 
In regards to the Wisconsin state mercury rule, EPA only models Hg constraints from this particular rule.  There are NOx constraints reflected in the rule stemming from the separate state rule requirements under NR 428 Adm Code.
Organization: we energies
Comment: 
we energies
Second, the NEEDS database contains factual errors regarding We Energies coal fleet. In particular, the database does not properly reflect the addition of flue gas desulfurization and selective catalytic reduction equipment on South Oak Creek units 5  -  8. This omission is significant and would likely have a dramatic effect on the modeling in our region. [EPA-HQ-OAR-2009-0491-2629.1, p.3]
Response: 
These controls at South Oak Creek are all reflected in EPA's updated base case modeling.  However, they are not incorporated into the NEEDS database as they are not expected to be installed (as noted by the commenter) prior to January 1, 2012.
Organization: Westar Energy, Inc.
Comment: 
Westar Energy, Inc.
On behalf of Westar Energy, Inc., this letter is to request an extension of time to provide comments on the 'Clean Air Transport Rule,' 75 Fed. Reg. 45210, and on the 'Notice of Data Availability,' 75 Fed. Reg. 53613. Currently, comments on the Rule are due October 1, and comments on the NODA are due October 15. We request an extension to allow the filing of a single set of comments on both aspects of the rulemaking, to and including November 30, 2010. [EPA-HQ-OAR-2009-0491-1924.1, p.1]
As noted in the docket, the proposal for rulemaking is based on complicated modeling as to the upwind sources that are contributing significantly or interfering with the maintenance of downwind sites. Because the proposed rules will have significant service, cost, logistical, construction, and operational impacts on Westar and affected electric generating units (EGUs), We star has undertaken to analyze the modeling used in the rulemaking. The publication of the NODA has severely impacted that analysis. Since EPA did not conduct modeling in support of the NODA, any attempt to understand how the NODA will impact the conclusions that EPA reached prior to the NODA requires the input of the NODA data set into the modeling. Due to the complexity of the modeling, inputting and analyzing that new data and its impact will take a matter of weeks to complete. In addition, other new data was received from EPA on September 14, correcting a corrupt model-ready emissions file. Currently, and despite Westar's best efforts, it appears that it will be extremely unlikely, if not impossible, to incorporate the new data into the modeling in a timely fashion that will allow Westar to file comprehensive and meaningful comments which should be considered by EPA. [EPA-HQ-OAR-2009-0491-1924.1, pp.1-2]
Westar and other EGUs in states identified for the first time by EPA as subject to the proposed Air Transport Rule, face an especially difficult burden to prepare and file comments as to the potential impacts that the Rule will have on them. In contrast to EGUs in states previously subject to clean air transport rules, Westar and other EGUs in 'first time states' have no historical basis on which to ground their analyses, nor were they invited to 'listening sessions' as to what direction EPA proposed to take in the rulemaking docket to which other stakeholders from states previously subject to clean air transport regulations were invited. [EPA-HQ-OAR-2009-0491-1924.1, p.2]
We star is currently working to understand the full significance of the proposed rule to Westar and other EGUs in the State. Through EPA's docket, Westar has obtained and is reviewing EPA's background documentation including modeling information. As a result of the new information in the NODA, these efforts have been hampered by creating a 'moving target' that impedes these efforts to evaluate the applicability and potential impacts of the proposed rules on Kansas and Westar. [EPA-HQ-OAR-2009-0491-1924.1, p.2]
These issues have created an almost impossible situation for We star to respond in a full and meaningful manner by the current October 1 and October 15 deadlines, particularly given We star's and Kansas' status as 'first time state' affected by the proposed rule. In addition, the rulemaking record would be better served by a single set of comments that address comprehensively the new and old data. To assure a full and meaningful comment period consistent with statutory and regulatory intent, additional time to comment is appropriate. Accordingly, Westar requests that EPA replace the current comment dates and grant an extension to and including November 30,2010 for a single set of comments to address all matters raised by the original Notice and the NODA. [EPA-HQ-OAR-2009-0491-1924.1, p.2]
EPA HAS NOT ALLOWED SUFFICIENT TIME FOR MEANINGFUL REVIEW AND COMMENT ON ITS PROPOSED RULE AND ADDITIONAL TIME IS NEEDED FOR ADEQUATE RESPONSE. [EPA-HQ-OAR-2009-0491-3737.1_NODA, p.5]
Through the NODA, EPA has added to an already overwhelming volume of information upon which any eventual decision will be made. Yet final determinations on important issues such as the inclusion of states including Kansas in the CATR rule, and any determination of state budgets or unit-specific allocations are lacking. Westar and other parties have requested an extension of time for response, to and including November 30, 2010, but that request had not been acted on by EPA when those comments were filed. The volume of new and changed information provided by EPA and the omissions and erroneous conclusions of EPA identified by Westar and other parties create the need for an additional comment period by EPA after providing more specific information upon which any final rule may be based. EPA's failure to provide results of the impact of the new information in the NODA as it affects Kansas, by completing modeling runs and providing results of modeled impacts and state budgets and source allocations is fatal to the ability of Westar and other parties to meaningfully review and comment on EPA's proposal. The examples provided by Westar and others of EPA's failure to recognize existing federally-enforceable control requirements on Kansas sources, including Westar's Jeffrey Energy Center and the La Cygne facility, are examples of the lack of fully developed evaluation which should be included in any final rulemaking. Coupled with the inadequacy of EPA's modeling tool, there is not a sufficient basis for a final rule. [EPA-HQ-OAR-2009-0491-3737.1_NODA, pp.5-6]
Response: 
EPA appreciates the comment and has updated its IPM modeling to include the federally enforceable requirements under the Westar Consent Decree and the requirements for the Ly Cynge facility.  See EPA IPMv4.10 Documentation as well as the RTC Appendix "Transport Rule IPM Assumptions Response to Comments" for a further description of such changes made in the final IPMv.4.10 used in the final Transport Rule analysis.
Organization: Xcel Energy Inc.
Comment: 
In version 4.1 of the NEEDS database, EPA has mischaracterized Bay Front Units 1 and 2 as biomass fuel units. In actuality Units 1 and 2 burn biomass as well as coal and natural gas. Xcel Energy requests that EPA identify Bay Front Units 1 and 2 as coal units and not as biomass units. This database also lists the particulate control devices for these units as baghouses, when in fact they both use electrified filter beds for particulate control. [EPA-HQ-OAR-2009-0491-2728.1, p.6]
Xcel Energy also noted that in NEEDS version 4.1 EPA has mischaracterized Bay Front Unit 5 as a biomass fuel unit. This unit is currently a coal-fired unit and is expected to remain so during at least the early years of the CATR program. Xcel Energy believes this mischaracterization is a result of EPA using data from a Northern States Power Wisconsin (NSPW) filing in 2009 with the Wisconsin Public Service Commission ("WPSC") where NSPW proposed converting Bay Front Unit 5 to a biomass gasifier unit. Xcel Energy has asked the WPSC for an additional six months to evaluate other alternatives as a response to increased costs since the project was proposed. As a result, EPA should show this unit as coal-fired instead of biomass-fired. [EPA-HQ-OAR-2009-0491-2728.1, p.6]
Response: 

See "Transport Rule IPM Assumptions Response to Comment" document for a list of unit level changes made in IPM between proposal and final based on input from commenters.  This particular facility already operates primarily on biomass fuel according to the most recent EIA form 923 data from 2010.  Both the comment and independent analysis conducted during periodic model updates suggest that the facility will likely continue this pattern, as conversion plans for the third unit have been announced that would allow 100 percent biomass use at the facility.  This would potentially be complete in the first year of Transport Rule compliance.  Accordingly, the IPM modeling used for the final Transport Rule unit identifies these units as biomass sources.

XIX. Transport Rule 2 and Other Future Transport Rulemakings

Organization: 8-Hour Ozone State Implementation Plan (SIP) Coalition
Comment: 
8-Hour Ozone State Implementation Plan (SIP) Coalition
Future Assessment of Transport Impacts From EGU and Non-EGU Sources  The Coalition is concerned about EPA's plans to apply this rule's technical analysis and framework to an analysis of the potential role of non-EGU sources on downwind areas in 2011, and a re-examination of the sufficiency of this rule for EGUs after new NAAQS are adopted.  A thorough examination of the utility of this approach to assessing transported emissions from industrial sources must be performed before any future determinations can be made with respect to transport for the following reasons. [EPA-HQ-OAR-2009-0491-2736.1, p. 4]
1) EPA uses the IPM to assess various control scenarios and as the basis for its cost and feasibility analyses underlying the TR.  No comparable tool exists for non-EGUs.   [EPA-HQ-OAR-2009-0491-2736.1, p. 4]
2) Emissions from the diverse equipment and units that make up petrochemical and refining facilities are mostly emitted at or near ground level.  Stack heights for those emissions that come from non-EGU stacks are shorter than those found in EGUs.  Therefore, the assumptions that underlie the long-range transport of emission plumes from EGUs cannot apply to petrochemical and refining facilities.  EPA will need to re-examine this aspect of the modeling analysis. [EPA-HQ-OAR-2009-0491-2736.1, pp. 4-5]
3) EPA should use the most current years of data for an analysis of affected nonattainment or maintenance areas.  For example, in the TR, the entire state of Louisiana is brought in to the TR because of a small modeled impact on PM2.5 annual levels at the Clinton Drive monitor in Houston.  However, for the past three years, emission levels at this site have been trending downward, and EPA has determined that the area will not be designated as nonattainment.  Other areas may face similar situations. [EPA-HQ-OAR-2009-0491-2736.1, p. 5]
4) Cost profiles are different for EGUs and non-EGUs.  In many states with mature nonattainment SIP programs, petrochemical and refining facilities (and in the Houston region, EGUs) have installed numerous control strategies to reduce emissions for local nonattainment problems.  In addition, many sources have installed controls in compliance with consent decrees and other programs.  Thus, there may not be any remaining "highly cost effective" controls available.  EPA's own analysis throughout the rule proposal concurs with this assessment. [EPA-HQ-OAR-2009-0491-2736.1, p. 5]
5) EPA's modeling approach includes all of the emissions in a state from all source categories to determine if one state's emissions significantly affect a downwind area.  But in many cases, point sources are not the major source of emissions.  The analysis presented by EPA does not present a demonstration that an individual sector's emissions specifically cause or contribute to nonattainment in a downwind area.  If this rule is broadened in the future to include more EGUs and non-EGUs EPA should instead develop a methodology that tests the significance of the particular source category on a downwind state. [EPA-HQ-OAR-2009-0491-2736.1, p. 5]
6) In other tests to determine if a source causes or contributes significantly to interference with maintenance (as in the Prevention of Significant Deterioration programs), EPA uses a Significant Impact Level of 4% of the NAAQS level.  The Coalition supports the use of this 4% Significant Impact Level for any rulemakings wherein EPA intends to evaluate the significant contribution of point sources. [EPA-HQ-OAR-2009-0491-2736.1, p. 5]
7) The Coalition also believes that the photochemical models as used in the rulemaking are not sufficiently precise to examine changes in precursor emissions that could affect as minute a level as 1% of the NAAQS for PM2.5 and ozone.  A 4% significance level would better fit the purpose and precision that the model can be expected to achieve. [EPA-HQ-OAR-2009-0491-2736.1, p. 5]
Response: 
As noted in the preamble, EPA believes that the broad framework for evaluating significant contribution and interference with maintenance outlined in this rule is applicable to future NAAQS as well.   However, EPA is not taking any final action at this time to apply this framework to any future NAAQS and additional technical analysis would be necessary to do so.  Given the collective nature of emissions contributions, EPA disagrees that it is necessary to demonstrate or test the significance of each particular source category. 
See preamble section V.D.1 for discussion of EPA's choice of the 1 percent threshold.
Organization: Adirondack Council
Comment: 
Adirondack Council
We urge EPA to use a stronger baseline for NOX emissions than the 1997 National Ambient Air Quality Standards (NAAQS). At a minimum, EPA should use the more stringent 2008 standard, and update the Transport Rule when a new standard is put in place, hopefully later this year, although that is now uncertain and litigation may also slow this process. [EPA-HQ-OAR-2009-0491-2848.1, p.2]
Response: 
See discussion in preamble section IV.C.1.  
Organization: Ameren Services Company
Comment: 
Ameren Services Company
EPA should abandon this rule making in light of the soon to be revised Ozone and PM25 standards
EPA in the preamble to this rule indicates that a follow on to this rule will be necessary when EPA revises the 8-hour ozone and PM25 standards currently under reconsideration. From the results described above EPA needs to abandon this rule making as the existing standards will be attained with on the books controls and the continuation of CAIR. When EPA revises theses standards at that time EPA should reanalyze the current ambient levels and emissions using the most up to date information available. Then only after going thru a thorough analysis, propose emission reductions that are beneficial to areas not meeting the standards. [EPA-HQ-OAR-2009-0491-2722.1, p.26]
Response: 
EPA has an obligation to address the concerns raised by the court over the CAIR in an expeditious manner.  In light of the court decision in North Carolina, the CAIR cannot remain in force indefinitely.  Moreover, this rule provides for substantial benefits to public health and the environment in the near term.
While there will be a need to address statutory requirements for any future NAAQS, EPA disagrees that this rule should be abandoned. 
Organization: American Lung Association
Comment: 
American Lung Association
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.15-16.]
Right now, under the proposed rule, you've identified 10 states that contribute a significant portion of the ozone and particulate matter in Georgia. But you'll find that only -- you find that only four states, Florida, Mississippi, Tennessee, my home state, and South Carolina, are sending significant amounts of ozone. And the only Georgia counties getting protected are in the Atlanta metro area.
However, under a 75 ppb model, we would expect that other counties in Georgia would need to get help from the Transport Rule to tackle the significant contribution of unhealthy air coming into their communities. Many other states may need to cut their emissions to keep from adding to the burden of ozone in Georgia and EPA will need to recalibrate the contribution of Georgia's power plants to other states' ozone burdens.
Response: 
EPA agrees that more stringent standards could increase the number of states contributing at a given location.   We intend to work with states to address interstate transport requirements for the reconsidered ozone NAAQS in a timely manner once we finalize the reconsideration of the ozone NAAQS.
Organization: American Petroleum Institute (API)
Comment: 
American Petroleum Institute (API)
Future Assessment of Transport Impacts From Non-EGU Sources API is concerned about EPA's plans to apply this rule's technical analysis and framework, to an analysis of the potential role of non-EGU sources to downwind areas in 2011. A thorough examination of the utility of this approach to assessing transported emissions from non-EGUs must be performed before any determinations can be made with respect to transport from non-EGUs for the following reasons. [EPA-HQ-OAR-2009-0491-2649.1, p. 4]
 1) EPA uses the IPM to assess various control scenarios and as the basis for its cost and feasibility analyses underlying the TR. No comparable tool exists for non-EGUs. [EPA-HQ-OAR-2009-0491-2649.1, p. 4]
2) Emissions from the diverse equipment and units that make up petrochemical and refining facilities are mostly emitted at or near ground level. Stack heights for those emissions that come from stacks are shorter than those found in EGUs. Therefore, the assumptions that underlie the long-range transport of emission plumes from EGUs cannot apply to petrochemical and refining facilities. EPA will need to re-examine this aspect of the modeling analysis. [EPA-HQ-OAR-2009-0491-2649.1, p. 4]
 3) EPA should use the most current years of data for an analysis of affected nonattainment or maintenance areas. For example, in the TR, the entire state of Louisiana is brought in to the TR because of a small modeled impact on PM2.5 annual levels at the Clinton Drive monitor in Houston. However, for the past three years, emission levels at this site have been trending downward, and EPA has determined that the area will not be designated as nonattainment. Other areas may face similar situations, particularly as new NAAQS are proposed and states are proceeding through a designation process. [EPA-HQ-OAR-2009-0491-2649.1, p. 5]
4) Cost profiles are different for EGUs and non-EGUs. In many states with mature nonattainment SIP programs, petrochemical and refining facilities have installed numerous control strategies to reduce emissions for local nonattainment problems. In addition, many sources have installed controls in compliance with consent decrees and other programs. Thus, there may not be any remaining ?highly cost effective? controls available. EPA's own analysis throughout the rule proposal concurs with this assessment. [EPA-HQ-OAR-2009-0491-2649.1, p. 5]
5) EPA's modeling approach includes all of the emissions in a state from all source categories to determine if one state's emissions significantly affect a downwind area. But in many cases, point sources are not the major source of emissions. The analysis presented by EPA does not present a demonstration that an individual sector's emissions specifically cause or contribute to nonattainment in a downwind area. If this rule is broadened in the future to include non-EGUs EPA should instead develop a methodology that tests the significance of the particular source category on a downwind state. [EPA-HQ-OAR-2009-0491-2649.1, p. 5]
6) In other tests to see if a source causes or contributes significantly to interference with maintenance (as in the Prevention of Significant Deterioration programs), EPA uses a Significant Impact Limit of 4% of the NAAQS level. API supports the use of this 4% Significant Impact Limit for any rulemakings wherein EPA intends to evaluate the significant contribution of non-EGU sources. [EPA-HQ-OAR-2009-0491-2649.1, p. 5]
7) API also believes that the photochemical models as used in the rulemaking are not significantly precise to examine changes in precursor emissions that could affect as minute a level as 1% of the NAAQS for PM2.5 and ozone. A 4% significance level would better fit the purpose and precision that the model can be expected to achieve. [EPA-HQ-OAR-2009-0491-2649.1, p. 5]
Response: 
As noted in the preamble, EPA believes that the broad framework for evaluating significant contribution and interference with maintenance outlined in this rule is applicable to future NAAQS as well.   However, EPA is not taking any final action at this time to apply this framework to any future NAAQS and additional technical analysis would be necessary to do so.  Given the collective nature of emissions contributions, EPA disagrees that it is necessary to demonstrate or test the significance of each particular source category. 
See preamble section V.D.1 for discussion of EPA's choice of the 1 percent threshold. 
Organization: Calpine Corporation
Comment: 
Calpine Corporation
Lastly, Calpine agrees with EPA that the proposed rulemaking and the corresponding Federal Implementation Plan (FIP) will need to be adjusted to comply with the revised ozone standard. It is expected that the ozone standard will be lowered and therefore require a corresponding reduction in the state ozone season NOx budgets. [EPA-HQ-OAR-2009-0491-3614,p.2]
Response: 
It will be necessary to address the CAA interstate transport requirements upon any revision to the ozone standard.
Organization: Clean Air Task Force
Clean Air Council
Comment: 
Clean Air Council
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.43-44.]
The Council strongly supports EPA's commitment to reviewing whether the Transport Rule needs to be tightened each time EPA revises an air quality standard. It will obviously need to do so, after the new ozone standard that is established. By making clear that this is the EPA policy, major NOX and SO2 producers are now on notice and can plan accordingly.
Clean Air Task Force
Footnote:14 Attainment of the ozone NAAQS will be more difficult. Furthermore, EPA is currently reconsidering the 2008 ozone NAAQS, has made a revised proposal earlier this year to strengthen the standard (75 Fed. Reg. 2938), and is expected to finalize it later this year.  [EPA-HQ-OAR-2009-0491-2738.1, p.1]
Finally, we welcome EPA's stated intention to promulgate a number of rules in the future to require emission reductions from this sector beyond those in the Transport Rule proposal, including -- additional transport rules as necessary to address upwind transport in connection with future revisions to the ozone or fine PM NAAQS (both primary and secondary), including a revised ozone NAAQS later this year and a further rulemaking addressing any associated needed reductions in transported NOx by 2012.[EPA-HQ-OAR-2009-0491-2738.1, p. 5]
Response: 
Comments noted.
Organization: Connecticut Department of Environmental Protection
Comment: 
Connecticut Department of Environmental Protection
EPA developed the proposed Transport Rule with the goal of addressing Section 110(a)(2)(D) transport attainment/maintenance requirements for the 1997 8-hour ozone and annual PM2.5 NAAQS and the 2006 24-hour PM2.5 NAAQS. The timing of the proposed remedy comes well after the CAA requirement that states modify their SIPs to address transport within three years after a new NAAQS is promulgated, yet still does not address all significant impacts. Therefore, it is imperative that EPA adopt a framework to address transport on a time frame compliant with CAA requirements. [EPA-HQ-OAR-2009-0491-2780.1 p.12]
EPA indicates in the proposed Transport Rule that the agency intends to propose additional rules to address transport as new or revised NAAQS are promulgated. It is important that these subsequent transport rules be proposed and finalized on a timetable tied to NAAQS promulgation to ensure that states implement timely SIP revisions to meet their transport obligations under Section 110(a)(2)(D). [EPA-HQ-OAR-2009-0491-2780.1 p.12]
CTDEP recommends that EPA concurrently evaluate significant transport when setting or revising a NAAQS and develop a Federal Implementation Plan (FIP) backstop when issuing a SIP call to ensure the requirements of CAA section 110(a)(2)(D)(i) are met in a timely manner. Based on the timing requirements of the CAA, CTDEP recommends that the process adhere to the following schedule:
Year 0 (of new or revised NAAQS) EPA promulgates a new or revised NAAQS EPA proposes a Transport SIP call for the new or revised NAAQS and a Transport FIP as a backstop to SIP Call. EPA releases all modeling and technical information with the proposed Transport SIP call to help inform the process and to assist states in developing their Transport SIPs.
Year 1 (of new or revised NAAQS) States recommend to EPA NAAQS designations (maximum one year after NAAQS) EPA finalizes Transport SIP call and FIP
Year 2 (of new or revised NAAQS) EPA finalizes NAAQS designations (maximum two years after NAAQS is promulgated)
Year 3 (of new or revised NAAQS) States submit to EPA final Transport SIPs (maximum three years after NAAQS is promulgated) EPA implements transport FIPs for states that do not submit Transport SIPs or submit inadequate SIPs. This is triggered in any state that fails to submit a complete Transport SIP on time, and helps ensure that transport is dealt with in a timely manner.
Year 5 (of new or revised NAAQS) States submit attainment SIPs (maximum three years after designations) Transport SIP/FIP controls are implemented (three years prior to attainment deadlines)
Year 7 (of new or revised NAAQS) Attainment deadline under Clean Air Act, Part D, subpart 1 for non-ozone NAAQS
Year 8, 11, 14, and onward (of new or revised NAAQS) Attainment deadline for moderate, serious, severe, and other ozone areas under Clean Air Act, Part D, subpart 2
[EPA-HQ-OAR-2009-0491-2780.1 p.13]
Furthermore, EPA is expected to finalize a revised 8-hour ozone NAAQS later this year in the range of 60 to 70 ppb and to propose a second Transport Rule in 2011 to establish a mechanism for states to comply with the CAA transport provisions for that revised NAAQS. Clearly, given the location of the Greenwich monitor and the minimal influence of Connecticut emissions on that monitor, Connecticut will be dependent on the second Transport Rule to provide substantial upwind emission reductions to provide the 10 to 20 ppb improvement needed to attain the revised NAAQS at that monitor. The level of necessary upwind reductions will even be greater, depending on the growth of upwind emissions resulting from economic recovery. [EPA-HQ-OAR-2009-0491-2780.1 p.13]
FIP vs. SIP. CTDEP understands EPA's proposal of a FIP instead of a SIP for rule implementation due to timing concerns. In subsequent transport rules, CTDEP recommends that EPA provide SIP guidance to states and allow states to choose a SIP or FIP path, as was done under CAIR. This would allow states to choose their own allocation methodologies to address differing energy resource portfolios, provided that such methodologies do not result in individual sources violating Section 110(a)(2)(D) of the CAA. [EPA-HQ-OAR-2009-0491-2780.1 p.20]
Response: 
EPA appreciates the comments on suggested approaches for systematically addressing transport as an integral part of the NAAQS publication and implementation process.   See preamble section X for discussion of SIP alternatives to the FIPs in the Transport Rule.
Organization: Constellation Energy
Comment: 
Constellation Energy
Constellation Energy also urges EPA to consider timing any revision of the Transport Rule to be concurrent with the regulatory changes necessary to implement the upcoming strengthening of the ozone national ambient air quality standard. [EPA-HQ-OAR-2009-0491-3613,p.2]
Response: 
EPA will consider this recommendation.   Given that certain technical analyses are dependent on the selected level of the NAAQS, it may be difficult to address transport issues concurrently.   EPA intends to work with states to address transport requirements in a timely manner to assist states in developing their transport SIPs by the statutory deadline.
Organization: Council of Industrial Boiler Owners (CIBO)
Comment: 
Council of Industrial Boiler Owners (CIBO)
While CIBO in principle prefers to have advance notice of planned future regulatory actions by EPA, EPA's approach here creates the worst of all worlds. EPA is tying an aggressive future timeline for issuing new Transport Rule standards on industrial sources to the issuance of the soon-to-be published revised ozone rule. Yet presumably States would first implement the revised ozone standard and would make determinations based on statewide data, which sources would be regulated, and by what relative measures. Yet here EPA informs of region wide NOx and SO2 reductions in advance of State SIP deadlines for the revised ozone standard not yet published. This gives businesses zero certainty for what to expect over the next several years, making business planning impossible.
Response: 
Specific SIP requirements for upcoming air quality standards are, by necessity, dependent on the level of the standard that is chosen.    It is not possible to predict, in advance of the necessary technical analyses, the degree of emissions reductions required by those standards.    EPA intends to work with states to address CAA transport requirements for any revised standards in a timely manner.  EPA is not taking any final action with respect to any transport requirements for any NAAQS other than the 1997 ozone the 1997 PM2.5 and the 2006 PM2.5 NAAQS. 
Organization: Dominion
Comment: 
Dominion
A reasonable timeline to comply with new regulations is especially important for planning purposes considering the number of additional EPA regulatory actions expected over the next several years. EPA has recently finalized new S02 and NOx NAAQS, has indicated it will issue a subsequent 'Transport Rule II' by late next year and on the heels of finalizing this rule to address the expected promulgation (October 2010) of a more stringent ozone standard, and it is almost certain that EPA will propose an additional major transport rule in 2012 to address a more stringent late-2011 NAAQS for particulate matter. [EPA-HQ-OAR-2009-0491-2715.1, p.16]
Response: 
See discussion in preamble section VII.C.1 regarding importance of coordinating this rule with attainment deadlines for the 1997 ozone and 1997 and 2006 PM2.5 standards.  
EPA will be evaluating the appropriate deadlines for any future air quality standards.
Organization: Edison Electric Institute (EEI)
Edison Mission Energy (EME)
EquiPower Resources Corp.
Comment: 
Edison Electric Institute (EEI)
Many states and environmental groups are calling for Transport Rule II to consider sources beyond EGUs because of their relative importance to attaining and maintaining NAAQS. EEI agrees that the Agency should consider sources other than utility units in any such future rulemakings, including the next revision of the particulate matter NAAQS.  [EPA-HQ-OAR-2009-0491-2697.1, p.15]
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, pp.53-54.  These comments were also submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-2009-0491-1938, pp.102-103.]
EEI has misgivings regarding the proposed Transport Rule providing little long-term certainty because its requirements will be superseded in the near future. EPA is planning to issue a separate proposal regarding NOx emissions related to the 1997 ozone standard. In the near future, EPA also has indicated it will issue a Transport Rule II related to the October 2010 ozone standard and it is almost certain that EPA will propose an additional major Transport Rule by 2012 to address the more stringent 2011 particulate matter standard.
Edison Mission Energy (EME)
Finally, with respect to EPA's statement, in the overview materials that it will be Assessment Group Region for Purposes of Reducing Regional Transport of Ozone, 63 Fed. Reg. 57356, 57467 (Oct. 27, 1998). 36 Phase I of the Transport Rule70, EME submits that the Agency should not propose a Transport Rule II, but rather should, as explained in Section VIII, look for the necessary reductions from other NOX sources as EGUs only constitute a small fraction of total NOX emissions in the U.S. Finally, with respect to EPA's statement, in the overview materials that it will be proposing a "Transport Rule II" in 2011 to obtain NOX reductions beyond those contemplated by Phase I of the Transport Rule, EME submits that the Agency should not propose a Transport Rule II, but rather should, as explained in Section VIII, look for the necessary reductions from other NOX sources as EGUs only constitute a small fraction of total NOX emissions in the U.S. [EPA-HQ-OAR-2009-0491-2707.1, pp.35-36]
THE EMISSION REDUCTIONS CONTEMPLATED BY THE TRANSPORT RULE WILL ACHIEVE SIGNIFICANT EMISSIONS REDUCTION SOLELY FROM THE POWER GENERATION SECTION; FUTURE SO2 AND NOX REDUCTIONS BEYOND PHASE II SHOULD COME FROM NON-EGUS [EPA-HQ-OAR-2009-0491-2707.1, p.42]
The NOx and SO2 emissions reductions proposed in the Transport Rule represent substantial emissions reductions. In fact, the Phase II caps represent EGU reductions in affected states equal to 71% for SO2 emissions and 52% for NOx emissions compared to 2005 levels. EPA predicts that the Phase II SO2 and NOx caps will bring 194 of the 207 counties with nonattainment areas into attainment with respect to either the PM2.5 or Ozone NAAQS  - approximately 94% of all nonattainment areas. In addition, the remaining nonattainment areas will be considerably closer to achieving attainment. Despite the substantial progress outlined in the Proposed Rule, EPA has nonetheless indicated that there will be a second phase of the Transport Rule targeted at further reductions of NOx emissions (and potentially SO2). [EPA-HQ-OAR-2009-0491-2707.1, p.42]
Based on the substantial progress toward NAAQS attainment that the proposed reductions will achieve, and particularly given that the power generation sector will shoulder the entire financial and regulatory burden to achieve them, EME submits that EPA (and ultimately state regulators) should not look to EGUs for additional reductions in a "Second Transport Rule." Rather, EPA should look to non-EGU sources for any additional reductions that are needed to bring downwind states into attainment with NAAQS beyond those proposed. Indeed, it would be inefficient, inequitable, and likely ineffective for regulators to seek additional reductions from EGUs for purposes of further ameliorating downwind nonattainment after the Transport Rule's reductions have occurred. [EPA-HQ-OAR-2009-0491-2707.1, pp.42-43]
[See EPA-HQ-OAR-2009-0491-2707.1, pp.43-44 for additional comments pertaining to The Emissions Reductions Contemplated by the Transport Rule will Achieve Significant Emissions Reductions Solely From the Power Generation Section; Suture SO2 and NOx Reductions Beyond Phase II Should Come From Non-EGUs] 
EquiPower Resources Corp.
The Agency should not seek additional NOX reductions from EGUs beyond those The Agency should not seek additional NOX reductions from EGUs beyond those already contemplated by the Transport Rule. NOX emissions from EGUs before the Transport Rule even takes effect have declined by over 70% since 1990 and currently account for only 12% of the national total. After the reductions required by Phase I and II of the Rule have occurred, these levels will be even lower. It is unreasonable for EPA to expect additional NOX reductions from EGUs, when they will account for such a small proportion of the total that remains. [EPA-HQ-OAR-2009-0491-2704.1, p.2]
THE AGENCY SHOULD NOT SEEK ADDITIONAL NOX AND SO2 REDUCTIONS FROM THE POWER GENERATION SECTOR BEYOND THOSE CONTEMPLATED BY THE TRANSPORT RULE [EPA-HQ-OAR-2009-0491-2704.1, p.30]
While the emission reductions proposed under the Transport Rule are predicted to make substantial progress toward NAAQS attainment, with the Phase II SO2 and NOx caps bringing 194 of the 207 counties with nonattainment areas into attainment for either the PM 2.5 or Ozone NAAQS, EPA has nonetheless indicated that it will be proposing a second rule in 2011 targeted at further reductions of NOx emissions (and potentially SO2).65 EquiPower submits that EPA (and ultimately state regulators) should not look to EGUs for additional reductions in a "Transport Rule II." Rather, additional reductions should be sought from other NOX emissions sources. The power generation sector will shoulder the entire financial and regulatory burden to achieve the reductions in the Transport Rule, yet EGUs only constitute a small fraction of total NOX emissions in the U.S. Thus, it would be inefficient, inequitable, and likely ineffective for regulators to seek additional reductions from EGUs after the Transport Rule's reductions have occurred. [EPA-HQ-OAR-2009-0491-2704.1, p.30; see pp.30-31 of this comment summary for additional comments pertaining to THE AGENCY SHOULD NOT SEEK ADDITIONAL NOX AND SO2 REDUCTIONS FROM THE POWER GENERATION SECTOR BEYOND THOSE CONTEMPLATED BY THE TRANSPORT RULE] 
In sum, targeting the power generation sector for further reductions before requiring other source sectors to contribute to environmental achievements would be inefficient, inequitable and ineffective. A myopic, EGU-centric approach to regulation would waste considerable resources, delay environmental benefits, and result in unjustified cost increases to consumers of electricity. Accordingly, for reductions beyond the Phase II caps, regulators should look to source sectors for which additional reductions would be efficient, effective and equitable. In sum, targeting the power generation sector for further reductions before requiring other source sectors to contribute to environmental achievements would be inefficient, inequitable and ineffective. A myopic, EGU-centric approach to regulation would waste considerable resources, delay environmental benefits, and result in unjustified cost increases to consumers of electricity. Accordingly, for reductions beyond the Phase II caps, regulators should look to source sectors for which additional reductions would be efficient, effective and equitable. [EPA-HQ-OAR-2009-0491-2704.1, p.31]
EquiPower is also concerned that: The Agency is considering additional NOX reductions from EGUs beyond those already contemplated by the Transport Rule. [EPA-HQ-OAR-2009-0491-2704.1, p.32] 
Response: 
EPA is not taking any final action with respect to the transport requirements for any NAAQS other than the 1997 ozone, 1997 PM2.5 and 2006 PM2.5 NAAQS.
Organization: Environmental Defense Fund (EDF)
Comment: 
Environmental Defense Fund (EDF)
EPA should carefully consider raising the cost threshold for NOx in light of CAMx modeling results suggesting that the proposed thresholds are insufficient to achieve full attainment with the 24-hour PM2.5 NAAQS, EPA's failure to take protection action for the March 2008 ozone NAAQS as well as the scientific evidence that nitrates contribute disproportionately to nonattainment in winter months. And EPA must thoroughly examine this issue in the forthcoming part II Transport Rule by providing for a higher, more protective cost threshold and examining the range of available emissions reductions from a wider variety of sources).  [EPA-HQ-OAR-2009-0491-2834.1 p.7]
c. Smart investment now can help EGUs prepare for future regulations [EPA-HQ-OAR-2009-0491-2834.1 p.14]
Sound federal regulatory policy works best when partnered with common-sense behavior by regulated entities. Federal regulations do not come as a surprise. There are legislated timetables for many EPA actions, including review and updates of the NAAQS. Other timelines are spelled out in Consent Decrees and other Court Orders. Regulated entities are well aware of the suite of regulatory action expected over a given time period. With such foreknowledge, competent regulated entities can plan their investment strategies, not in a reactive piecemeal fashion, but in a long-term proactive manner  --  aligning prudent investment plans with the nation's public health goals  --  rather than fighting them.
For instance, the manner in which one complies with the proposed Transport Rule through installation of emissions control technologies and other strategies, can affect how well-prepared companies are for future regulations of air toxics and pollutants. EPA has announced its intention to issue a new NAAQS for ozone and will be promulgating other rules that will impact EGUs over the next several years. The updated ozone NAAQS, for example, has been in process for some time and EPA announced it will tighten the standard in the fall of 2010 to between 60 and 70 ppb to be consistent with recommendations of the Clean Air Scientific Advisory Committee in 2006. Industry should look ahead to the suite of regulations that are in the pipeline to make strategic, long-term decisions about investments made to comply with the Transport Rule. However, for some aging coal plants it may be more economical to retire the plant instead of investing in modern control technology when prudently coordinating compliance with existing and reasonable foreseeable air quality actions by EPA over the next several years. Measures like energy efficiency can be implemented as a key part of a multi-pollutant reduction strategy to smooth this transition for many power companies. [EPA-HQ-OAR-2009-0491-2834.1 p.15]
Response: 
See discussion in section IV.C.1 of the preamble to the final rule.  
Organization: Exelon
Comment: 
Exelon
EPA is proposing to establish revised or new NAAQS for ozone and particulate matter that are more protective of health and the environment. The proposed Transport Rule provides a workable methodology for calculating and rapidly implementing any future reductions in state budgets that will be necessary to eliminate upwind states' significant contribution to nonattainment and interference with maintenance of any new or revised NAAQS. Reductions in the state budgets contained in the proposed Transport Rule will, in fact, be needed to eliminate significant contributions to nonattainment and interference with maintenance of these new lower NAAQS by upwind states. EPA should therefore propose any reduced state budgets at the time it adopts the new or revised NAAQS and include requirements for states to implement these reductions in their budgeted emissions in the SIP calls for these new or revised NAAQS. Even if EPA could not include these requirements in a FIP, it could include adjusted budgets and proposed compliance dates as a part of a SIP call. [EPA-HQ-OAR-2009-0491-2666.1, p.12]
Response: 
EPA intends to work with states to address transport requirements for any new or revised NAAQS in a timely manner once those NAAQS are published. 
Organization: Florida Department of Environmental Protection
Comment: 
Florida Department of Environmental Protection
In addition, states are anticipating the promulgation of the new ozone standard in approximately 30 days and understand the PM2.5 standard will be revisited in the near future as well. The Division is concerned that decisions required to implement this rule may not mesh well with EPA's second transport rule (Transport Rule 2). It would be more efficient to address these issues holistically once the new ozone and PM2.5 standards are promulgated. [EPA-HQ-OAR-2009-0491-2624.1, p.2]
Response: 
EPA currently intends to promulgate the new ozone standard later this year.  EPA appreciates the comment that we need to ensure that subsequent requirements under any subsequent transport rule would mesh well with the requirements of this rule.
Organization: Florida Electric Power Coordinating Group, Inc. (FCG)
Florida Municipal Electric Association (FMEA)
Comment: 
Florida Electric Power Coordinating Group, Inc. (FCG)
EPA also acknowledges that it intends to propose revisions to the Transport Rule, at the same time as it finalizes the rule, to address imminent changes to the ozone and PM2.5 ambient standards. This piecemeal approach to rulemaking is flawed on numerous grounds. From a legal standpoint, it is an abuse of discretion and arbitrary and capricious. From a bureaucratic standpoint, it is highly wasteful and inefficient. From a planning and economic standpoint, it is nonsensical. And from an environmental standpoint, it is needlessly redundant; CAIR is doing the job on an interim basis. In fact, EPA's September 28,2010 CAIR report cited above touts the benefits of CAIR, and shows that 2009 NOx emissions (annual and ozone season) were already below levels EPA projected for 2012 under the Transport Rule. EPA should wait and promulgate a single, defensible Transport Rule addressing all ambient standards. [EPA-HQ-OAR-2009-0491-2658.1, p.4]
Florida Municipal Electric Association (FMEA)
EPA also acknowledges that it intends to propose revisions to the Proposed Transport Rule, at the same time as it finalizes the rule, to address imminent changes to the ozone and PM2.5 ambient standards. This piecemeal approach to rulemaking is flawed on numerous grounds. From a legal standpoint, it is an abuse of discretion and arbitrary and capricious. From a bureaucratic standpoint, it is highly wasteful and inefficient. From a planning and economic standpoint, it is nonsensical. In fact, EPA's September 28, 2010, CAIR report cited above touts the benefits of CAIR, and shows that 2009 NOx emissions (annual and ozone season) were already below levels EPA projected for 2012 under the Transport Rule. And from an environmental standpoint, it is needlessly redundant; CAIR is doing the job on an interim basis. EPA should wait and promulgate a single, defensible Transport Rule addressing all ambient standards. [EPA-HQ-OAR-2009-0491-2731.1, p. 6]
The threat of moving Group 2 states to Group 1 creates unnecessary uncertainty: While Florida is currently in Group 2 with no additional reductions required in 2014, EPA makes it clear that it is going to reevaluate the Group placement of states in light of the revised NAAQS in 2011 and 2012 meaning some states may be moved to Group 1. However, EPA is considering only the 1997 Ozone NAAQS in the current Transport Rule proposal even though a revised Ozone NAAQS is in effect. FMEA believes that such a piecemeal approach to dealing with current and future NAAQS revisions creates confusion and makes compliance planning by state regulators and industries nearly impossible. EPA should fix only those CAIR issues remanded by the D.C. Court in this Transport Rule and subsequently initiate a new interstate rulemaking once all current NAAQS reviews are completed. This second interstate rulemaking should allow sufficient time to avoid the mandatory Federal Implementation Planning of states envisioned in the Proposed Transport rule. [EPA-HQ-OAR-2009-0491-2731.1, p. 10]
Response: 
EPA has an obligation to address the concerns raised by the Court in a timely manner.  EPA is not taking any final action with regard to transport requirements related to any NAAQS other than the 1997 ozone, 1997 PM2.5 and 2006 PM2.5 NAAQS.
Organization: Gainesville Regional Utilities (GRU)
Comment: 
Gainesville Regional Utilities (GRU)
The Threat of Moving Group 2 States to Group 1 Creates Unnecessary Uncertainty
While Florida is currently in Group 2 with no additional reductions required in 2014, EPA makes it clear that it is going to reevaluate the Group placement of states in light of the revised NAAQS in 2011 and 2012 meaning some states may be moved to Group 1. However, EPA is considering only the 1997 Ozone NAAQS in the current proposed CATR proposal even though a revised Ozone NAAQS is in effect. GRU believes that such a piecemeal approach to dealing with current and future NAAQS revisions creates confusion and makes compliance planning by state regulators and industries nearly impossible. EPA should fix only those CAIR issues remanded by the DC Court in this proposed CATR and subsequently initiate a new interstate rulemaking once all current NAAQS reviews are completed. This second interstate rulemaking should allow sufficient time to avoid the mandatory 'FIPing' of states envisioned in the proposed CATR. [EPA-HQ-OAR-2009-0491-2674.1, p.7]
Response: 
EPA has an obligation to address the concerns raised by the Court in a timely manner.  EPA does not believe we have the option to delay this rule until all current NAAQS review are completed.  Moreover, the rule provides for substantial public health benefits in the near term. 
Organization: Indiana Department of Environmental Management 
Comment: 
Indiana Department of Environmental Management 
Examples of issues that U.S. EPA must address in this second proposal include:
:: Updating the air quality data relied upon within the proposed rule. This includes updating the monitored design values (2007 was the most current year used, while quality assured data is readily available through 2009).
:: Updating the emissions data and emission control assumptions and providing a transparent explanation of how future year budgets and allocations were derived from baseline emissions.
:: Describing how it intends to track and enforce allocations, especially based on the agency's proposal to rely on FIPs with only State level emission caps as the primary enforcement tool. [EPA-HQ-OAR-2009-0491-2645.1]
Response: 
EPA made numerous updates to air quality and emissions data in response to comments on the Transport Rule proposal. 
See preamble section VII for discussion of tracking and enforcement of allocations.
Organization: Iowa Department of Natural Resources (IDNR)
Comment: 
Iowa Department of Natural Resources (IDNR)
On January 6, 2010, EPA proposed to lower the primary 8-hour ozone standard within the range of 60- 70 ppb and to add a new secondary standard. This action, when finalized, will likely significantly increase the number of areas struggling to attain or maintain the standards. We are encouraged by EPA's commitment to promulgate a second phase of the Transport Rule to assist states in meeting their clean air and interstate contribution obligations following the revision to the ozone NAAQS. An adequate and timely second phase to the Transport Rule is needed as the revised ozone standard is expected to increase the number of nonattainment or maintenance areas significantly impacted or overwhelmed by interstate pollutant transport. We urge EPA to quickly propose a suitable second phase of the Transport Rule shortly after the expected revision to the ozone standard. [EPA-HQ-OAR-2009-0491-2609.1, p.1]
 A second phase of the Transport Rule should coordinate timelines for emissions reductions with attainment dates. It is expected that ozone implementation regulations will be required to determine nonattainment classifications and resulting attainment deadlines. We request that EPA quickly propose and finalize an ozone implementation rule following promulgation of the revised standard. Timely implementation rules in concert with a second phase of the Transport Rule are necessary components to reduce or eliminate interstate pollutant contributions in those areas failing or struggling to attain the standards. An ozone implementation rule and a second phase to the Transport Rule developed with regulatory consistency and schedule harmonization would assist states in the efficient development of appropriate State Implementation Plans. [EPA-HQ-OAR-2009-0491-2609.1, pp.1-2]
Consistent with NACAA's comments provided at the Public Hearing held in Chicago on August 19, 2010, we also strongly support EPA's pledge to consider whether a new or revised transport rule is warranted when a NAAQS is revised or added. [EPA-HQ-OAR-2009-0491-2609.1, p.2
Response: 
EPA intends to address CAA interstate transport requirements in a timely manner for any future revised NAAQS.
Organization: Lansing Board of Water & Light
Gulf Coast Lignite Coalition
Golden Spread Electric Cooperative
E.ON U.S.
JEA
Comment: 
E.ON U.S.
EPA states that the requirements of the rule are expected to change, but fails to address the impacts of the expected more stringent requirements and the uncertainty this creates. EPA states that it expects to issue a separate proposal regarding NOx emissions related to the 1997 ozone standard and a "Transport Rule II" related to an again-revised ozone standard. EPA is clearly creating a moving target that makes planning nearly impossible and very inefficient. [EPA-HQ-OAR-2009-0491-2797.1, p.3]
Golden Spread Electric Cooperative
EPA's proposal includes plans to develop a second phase plan in response to the upcoming finalization of a new ozone standard; the first phase plan for the ozone NAAQS considers only the 1997 standard.  Given the short periods between the developments of these plans, and with additional control requirements forthcoming in updated New Source Performance Standards and new Maximum Achievable Control Technology NESHAPS (National Standards for Hazardous Air Pollutants), EPA should coordinate the regulation developments to avoid or clarify overlapping or conflicting requirements.  It is more cost efficient to take an integrated approach rather than to have separate programs that could require multiple steps for emission reduction technologies, especially when some deadlines have been arbitrarily set. [EPA-HQ-OAR-2009-0491-2808.1 p.5]
Gulf Coast Lignite Coalition
 The Transport Rule relies on 1997 annual PM2.5 standards, the 2006 daily PM2.5 standards, and the 1997 8-hour ozone standards, which are all currently under review by the EPA and will likely be revised within the next year or two.1 To base emission reduction requirements on standards which will change before the 2012 and 2014 compliance deadlines proposed in the Transport Rule, only adds to the difficulty in demonstrating compliance with the Transport Rule. As a solution, EPA offers that they will "issue as soon as possible a proposal to address the transport requirements with respect to the reconsidered standard."2 However, the solution only offers additional rule promulgations in the future, not addressing the immediate compliance deadlines.
1 The revised 8-hour ozone NAAQs should be published in October of 2010 according to the EPA. The 2006 PM2.5 standards are currently under EPA review and revised standards may be proposed as early as February 2011.
[EPA-HQ-OAR-2009-0491-2734.1 p.2]
JEA
The threat of moving Group 2 states to Group 1 creates uncertainty
While Florida is currently in Group 2 with no additional reductions required in 2014, EPA makes it clear that it is going to reevaluate the Group placement of states in light of the revised NAAQS in 2011 and 2012 meaning some states may be moved to Group 1. However, EPA is considering only the 1997 Ozone NAAQS in the current Transport Rule proposal even though a revised Ozone NAAQS is in effect. JEA believes that such a piecemeal approach to dealing with current and future NAAQS revisions creates confusion and makes compliance planning by state regulators and industries nearly impossible. EPA should only fix the CAIR remanded issues in this Transport Rule and initiate new interstate rulemaking once all current NAAQS reviews are completed. [EPA-HQ-OAR-2009-0491-2713.1, p.4]
Lansing Board of Water & Light
Proposed update to a proposed rule creates too much uncertainty, too much risk 
EPA has already announced their intent to revise the proposed rule in regards to emissions of NOx, based upon a forthcoming reconsideration of the ozone NAAQS. The level of uncertainty this creates throughout the electrical generation industry is beyond fathom! Pollution control equipment for this industry is not something that can be bought at a local supermarket, only to be discarded when a new one is needed. This equipment takes years to design and install requiring investments of several million dollars. With a proposal to modify a proposed rule, based on another decision that is not yet final, BWL will have to gamble with the resident's and business community's money. BWL will either gamble with a minimum investment to meet the first proposed rule or more expensive investment assuming the revision will require greater control. This is an unacceptable risk and a very poor money-management practice, especially for a municipal utility. [EPA-HQ-OAR-2009-0491-2752.1,pp.8-9]
Furthermore, this is but the beginning of a series of mismanaged regulatory proposals targeted upon the electrical generating industry. [EPA-HQ-OAR-2009-0491-2752.1, p.9]
Response: 
EPA hopes to reduce the uncertainty associated with the requirements of any future NAAQS as much as possible.   In the meantime, EPA is addressing its obligation to move expeditiously to address the concerns raised by the court in North Carolina case, and to address, for states in the eastern United States, the requirements of section 110(a)(2)(D)(i)(I) with respect to the 2006 PM2.5 standards.
Organization: Maryland Department of Environment (MDE)
Comment: 
Maryland Department of Environment (MDE)
When EPA addresses the proposed new 2010 NAAQS in its next update to the proposed Transport Rule, MDE advocates that EPA proceed as follows: (1) determine the emission reductions necessary to eliminate each state's significant contribution to nonattainment and interference with maintenance of another state's ability to meet the new NAAQS; (2) examine costs. Note that if a state eliminates its significant contribution to nonattainment or interference with maintenance, any additional reduction does not have as much impact on improving its neighbor's air quality as do local measures. [EPA-HQ-OAR-2009-0491-2639.2, p.5]
Future Transport Rules and Ongoing Policy Concerns, Transport Rule II
In order to complete the task under section 110(a)(2)(D)(i) to eliminate all significant contribution and interference with maintenance, EPA needs to include additional reductions in the final rule that fully address the transport component of nonattainment with the 1997 ozone and 2006 PM2.5 NAAQS. In the proposed Transport Rule, EPA acknowledges that the transport FIPs will not completely satisfy the emission reduction requirements of Clean Air Act section 110(a)(2)(D)(i)(I). Two areas -- Houston, Texas and Baton Rouge, Louisiana -- are expected to still be in violation of the 1997 ozone NAAQS in 2014, while the New York City area is expected to have continued maintenance issues with this standard. [EPA-HQ-OAR-2009-0491-2639.2, pp.17-18]
In addition, EPA will soon be releasing its reconsidered ozone NAAQS, which will require even greater efforts by upwind states to reduce transport impacts. To solve the additional transport impacts under the soon-to-be revised ozone NAAQS, EPA's next version of the Transport Rule, "Transport Rule II," will need to be released in a timely manner. It will also need to contain assurances that upwind impacts will be eliminated within a timeframe that allows downwind states to attain the NAAQS with three years of clean air quality data. It is critical that the precedents set by the currently proposed transport rule are solid and sustainable to application to future updates to the rule. [EPA-HQ-OAR-2009-0491-2639.2, p.18; For additional comments pertaining to Future Transport Rules and Ongoing Policy Concerns: Transport Rule II, see pages 17-19 of this comment]
The 2008 NAAQS and the Next NAAQS Issuance
EPA did not appropriately expand the scope of the analyses in the current proposed rule to include the new and current 2008 8-hour ozone NAAQS (75 ppb). In this proposed Transport Rule, EPA has understandably focused in fixing the "fatal flaws" of CAIR in order to comply with the court's remanding of CAIR. Even though EPA has reconsidered the 2008 standard, it is still effective until a new standard is promulgated; therefore, Maryland would like to point out that any effort by EPA to control precursors of ozone should address the new 0.075 ppm and not the old 0.08 ppm standard. [EPA-HQ-OAR-2009-0491-2639.2, pp.19-20]
The old ozone NAAQS was promulgated in 1997 and effective in 2004. The SIP for the 0.08 ppm NAAQS was due in 2007 and the attainment date was 2010 for moderate nonattainment areas, which covered the majority of the nonattainment areas. Since both of these dates and the due date of the Transport SIP for the 0.08 ppm standard have already passed, Maryland believes that this rule should focus more on what new standards the states will have to address moving forward, such as the 0.075 ppm level. If the EPA had focused on the 0.075 ppm standard, the technical analysis for the proposal would be based on possibly 2014 as the first moderate attainment year, which would then provide EGUs the time needed to install advanced NOx controls such as selective catalytic reduction (SCR) systems. This also falls in line with the second date in the Transport Rule for the SO2 control year. [EPA-HQ-OAR-2009-0491-2639.2, p.20]
All of these issues raise further questions that Maryland would like EPA to fully address, such as what levels will the new ozone NAAQS be set at later this year, and how will they be integrated with this current proposed Transport Rule, if at all? When will the new ozone NAAQS be enforceable on its own, or (as Maryland expects) will it only be enforced through the issuance of a second transport rule? If this is the case, and EPA expects to enforce the new ozone NAAQS through the issuance of a second transport rule, Maryland notes that EPA needs to issue a firm timetable for the issuance of the second transport rule to allow states, industry stakeholders and all affected parties time to develop proper strategies to successfully implement the next rule and have a realistic shot at achieving measurable emissions reductions benchmarks. [EPA-HQ-OAR-2009-0491-2639.2, p.20]
Response: 
EPA appreciates these comments.  EPA is not, however, taking any final action act this time with respect to the transport requirements of any NAAQS other than the 1997 PM2.5, 1997 ozone and 2006 PM2.5 NAAQS. 
Organization: Massachusetts Department of Environmental Protection
Comment: 
Massachusetts Department of Environmental Protection
The proposed Transport Rule requires NOx reductions by 2012 but does not require additional NOx reductions in 2014. For states to meet the expected 2017 attainment deadline for moderate areas under a 2010 ozone standard, additional NOx reductions from power plants and other source sectors in the 2014-2016 timeframe are needed. EPA should require a second phase of NOx reductions for 2014 in the final Transport Rule, as it has proposed for S02. [EPA-HQ-OAR-2009-0491-2787.2 p.2]
In light of the promulgation of the 2008 ozone NAAQS, and the anticipated October 2010 ozone NAAQS, we believe EPA should not have restricted the scope of the proposed Transport Rule to significant contribution to non-attainment or interference with maintenance under the 1997 ozone standard. We strongly urge EPA to promptly propose a second Transport Rule in 2011, as it has committed to do, and to finalize a rule in time for states to realize the benefits of reduced transport by their attainment years under the new anticipated ozone standard. It is essential that EPA address transport concurrently with the adoption of new air quality standards in a timeframe that will allow Massachusetts to meet its attainment requirements without imposing onerous and far less cost-effective state control measures.  [EPA-HQ-OAR-2009-0491-2787.2 p.3]
We commend EPA for proposing a methodology for assessing transported air pollution that allows for quicker and more consistent analysis of the impact of transport under future revised air quality standards. Massachusetts air quality does not meet the 2008 ozone standards and we anticipate a non-attainment designation under the ozone standard expected to be issued in October 2010. It is crucial that the health protections these new standards will provide be realized as quickly as possible. A timely assessment of the impact of transport on Massachusetts air quality is essential to meeting that goal. [EPA-HQ-OAR-2009-0491-2787.2 p.11-12]
Response: 
EPA intends to work with states to address CAA transport requirements for revised ozone standards in a timely manner once any ozone NAAQS revision is published.
Organization: Metropolitan Washington Air Quality Committee
Comment: 
Metropolitan Washington Air Quality Committee
However, we are aware that the proposed rule will not establish emission reduction requirements necessary for our region to achieve new more stringent NAAQS for ozone and fine particles expected in the very near future. It will be urgent for EPA to conduct necessary analysis needed to support a new rulemaking to amend the final Transport Rule so that controls on other sources and/or new lower state emission budgets for power plants are set at levels that will enable states to meet the new NAAQS. We also urge EPA to advance other new federal initiatives to address emissions during high electricity demand days and to reduce emissions from other sectors that contribute to emissions of air pollutants as well, either through amendments to the Transport Rule or through other regulatory initiatives. [EPA-HQ-OAR-2009-0491-2618.1, p.1]
Response: 
EPA appreciates the commenters suggestion for update technical analysis to address CAA interstate transport requirements for updated NAAQS.
Organization: Minnesota Pollution Control Agency (MPCA)
Comment: 
Minnesota Pollution Control Agency (MPCA)
The MPCA acknowledges the unique circumstances of this Transport Rule, which is necessary to ensure the continuance of reductions achieved under CAIR and to meet requirements for a Federal Implementation Plan (FIP) for 11 0(a)(2)(D). These circumstances lead to a very short timeframe for implementing the rule, which makes it difficult for states to consider undertaking a State Implementation Plan (SIP) to substitute for the FIP and may also make it difficult for some sources to install necessary controls. The MPCA recognizes that the necessary timeline for this first Transport Rule will make it difficult for EPA to address these concerns, but hope that Transport Rule Two will allow for longer implementation timelines and resolve some of these concerns. Therefore, the MPCA encourages EPA to move quickly to Transport Rule Two and ensure that future transport rulemakings allow a longer time period for implementation planning for both states and affected sources. [EPA-HQ-OAR-2009-0491-2521.1, p.1]
Response: 
EPA intends to work with states to address CAA interstate transport requirements under any revised ozone NAAQS in a timely manner once those standards are published.   We agree that moving in timely manner would be helpful for implementation and planning.
Organization: Mothers and Others for Clean Air
Comment: 
Mothers and Others for Clean Air
[These comments were submitted as testimony at the Atlanta, Georgia public hearing on September 1, 2010.  See Docket Number EPA-HQ-OAR-0491-1939, p.18.]
I'm here today to support EPA's preferred version of the proposed Transport Rule and also to urge EPA to integrate more quickly the new 2010 ozone standard into the final Transport Rule rather than waiting to finalize a response in 2012.
Response: 
Additional technical analyses will be needed to address the new ozone standards.  Some of those technical analyses are dependent on the level of the standard, and thus it is not possible to integrate those considerations into this Transport Rule without a significant delay.
Organization: National Association of Clean of Air Agencies (NACAA)
Comment: 
National Association of Clean of Air Agencies (NACAA)
EPA Needs to Finalize Transport Rule II Quickly and Work With Closely with NACAA and Its Members in Fashioning the Rule
Finally, and very critically, NACAA urges EPA to finalize Transport Rule II quickly. EPA must promulgate a second Transport Rule no later than 2012 if the agency is indeed serious about helping state and local air pollution control agencies to address interstate transport, meet their statutory obligations under the Clean Air Act (e.g., meet the attainment deadlines for moderate nonattainment areas) and to ultimately attain the health-based standards. We also urge the agency to work closely with NACAA and its members so that this next phase fits seamlessly into state and local air agency planning and reflects a deep collaboration with state and local air agencies. [EPA-HQ-OAR-2009-0491-2771.1, p.7]
[These comments were submitted as testimony at the Chicago, Illinois public hearing on August 19, 2010.  See Docket Number EPA-HQ-OAR-0491-1746, pp.107-110.  Comments also submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.80-83.]
We are also pleased that EPA's committed to quickly finalizing a second transport rule, Transport Rule II, in recognition that much tighter NOx caps will be needed to address the pending revision to the 8-hour ozone standard.
NACAA strongly supports EPA's pledge to review whether a new or revised Transport Rule is needed each time it revises an air quality standard.
Then, as EPA plans, the Agency should turn to the forthcoming ozone standard and promulgate a far more stringent NOx cap for Transport Rule II that achieves the maximum emission reductions that are technologically feasible and cost effective to ameliorate the entire transport problem associated with the revised ozone standard.
EPA must address these source categories as well when it proposes its Transport Rule II.
Finally, and very critically, NACAA urges EPA to finalize Transport Rule II quickly.
EPA must promulgate a second Transport Rule no later than 2012 if the Agency is indeed serious about helping state and local air pollution control agencies to address interstate transport, meet their statutory obligations under the Clean Air Act and to ultimately attain the health-based standards.
Response: 
EPA agrees with the need to address transport under any revised NAAQS, and agrees that any such analysis would need to consider additional source categories.  EPA is not, however, taking any final action at this time with respect to the transport requirements related to any NAAQS other than the 1997 ozone, 1997 PM2.5 and 2006 PM2.5 NAAQS.
Organization: New Jersey Department of Environmental Protection (NJDEP)
Comment: 
New Jersey Department of Environmental Protection (NJDEP)
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.157 & 161.]
committing to a second phase of the Transport Rule to achieve additional and necessary emissions reductions to address all NAAQS.
I urge the USEPA to move forward with Transport Rule 2 and better address regional transport and cost effective public health benefits in a timely manner. Without effective regulation, states will not be able to attain the ozone, sulfur dioxide, and fine particulate health standards. We will be submitting more detailed written technical comments into the docket.
Response: 
EPA agrees with the need for further efforts to address transport under revised NAAQS.
Organization: New York State Department of Environmental Conservation
Comment: 
New York State Department of Environmental Conservation
EPA should establish a procedural framework in this rule. Reductions from upwind states that contribute significantly to nonattainment or interfere with maintenance should come three years prior to the attainment date of a NAAQS. EPA would therefore need to update its transport rule for a revised NAAQS in a prompt manner. To accomplish this, a Transport SIP Call and FIP should be proposed at the same time any new NAAQS is finalized . This would result in the transport SIP being due three years after NAAQS promulgation, or the FIP would become final, allowing freedom to states in how the transport program is enforced, while ensuring that reductions will be made to meet their statutory obligations. [EPA-HQ-OAR-2009-0491-2730.1, p.4]
The following timeline should be implemented: Year 0: Finalize the new NAAQS, propose a transport SIP call, and propose a FIP Year I: Finalize transport SIP call rule and FIP Year 2: EPA designations final (2 yrs max after the new NAAQS is promulgated) Year 3: Transport SIP due with the necessary controls due 2 - 3 yrs later Final FIP if no SIP is submitted Year 5: Attainment SIP due (3 yrs after designations are final) Year 7+: Attainment deadlines [EPA-HQ-OAR-2009-0491-2730.1, p.5]
The process recommendation above provides adequate time to assess and implement measures in accordance with the CAA. We also recommend establishing the timeline outlined above for any and all subsequent NAAQS revisions. [EPA-HQ-OAR-2009-0491-2730.1, p.5]
Use of 1997 8-Hour Ozone NAAOS

The 1997 8-hour ozone was used in assessing significant contribution and interference with maintenance. Since a lower NAAQS was formally established in 2008, EPA should at least use the 2008 standard as the basis of the Transport Rule instead of the 1997 standard. Furthermore, given the imminent proposal (20 I 0) of an even more restrictive standard than the 2008 NAAQS, EPA should consider addressing the transport elements associated with the more restrictive 2010 NAAQS. [EPA-HQ-OAR-2009-0491-2730.1, p.5]
Similarly, section 110(a)(2)(D)(i)(I) addresses transport ' ... with respect to any such national primary or secondary ambient air quality standard ...' Because the 1997 ozone, 1997 PM 2.5 and 2006 PM2.5 NAAQS all had identical primary and secondary standards, this hasn't been a concern. Transport Rule II, however, will have to consider the W-126 secondary standard under the ozone reconsideration (assuming it is part and of the final rule). A transport analysis of the S02 NO2 secondary standards, scheduled to be finalized in early 2012, would also be appropriate. [EPA-HQ-OAR-2009-0491-2730.1, p.15]
The Future Transport Rule
EPA's next version of the Transport Rule (''Transport Rule II') must consider the recently adopted SO2 and NO2 NAAQS and the soon to be finalized reconsidered ozone NAAQS. Additionally, the rule should include all significantly contributing sectors. Section 110(a)(2)(D) does not confine EPA to the EGU sector. [EPA-HQ-OAR-2009-0491-2730.1, p.15]
While EPA has committed to updating its interstate transport determinations for future ozone and PM2.5 NAAQS, it is important to assess transport impacts of other pollutants as well, notably S02 and NO2. Section 110(a)(2)(D)(i) calls on states to prohibit the emission of any air pollutant which will contribute significantly to nonattainment or interfere with maintenance of a standard. The proposed Transport Rule notes that 'EPA does not expect peak S02 levels to be a long-range transport issue' (75 FR 45228) but does not allude to any study that yielded this finding. There is no mention of the recent N02 NAAQS. A technical review should be completed to determine if any reduction in the S02 or NOx budget would be required for the recently revised S02 and N02 NAAQS. A review of the transport effects of each criteria pollutant upon review of the NAAQS is necessary for the protection of public health in downwind areas. [EPA-HQ-OAR-2009-0491-2730.1, p.15]
Response: 
EPA appreciates the comments on suggest approaches for systematically addressing transport as an integral part of the NAAQS publication and implementation process.   We intend to work with states to address CAA interstate transport requirements in a timely manner once those NAAQS are published.  EPA, however, is not taking any final action at this time with respect to the transport requirements associated with any NAAQS other than the 1997 ozone, 1997 PM2.5 and 2006 PM2.5 NAAQS.
Organization: Northeast States for Coordinated Air Use Management (NESCAUM)
Comment: 
Northeast States for Coordinated Air Use Management (NESCAUM)
Meeting current and future NAAQS requires highly effective national and regional solutions, often coupled with strict local controls. Pollution transport is one key element of meeting NAAQS that must be characterized and addressed up front, before attainment plans are due. Having technical documentation of the amount of transport relief to be expected would allow downwind states to plan for and implement reasonable levels of local controls with the knowledge that significant transported pollution will be eliminated. We therefore urge EPA to promulgate future transport rules concurrent with finalizing new NAAQS. This would provide states with critical information needed to develop their SIPs at the beginning of the planning process. It would also greatly assist states in developing SIPs that are produced in a timely manner (i.e., within the required three years after EPA promulgates a NAAQS), approvable under Clean Air Act section 110(a)(2)(D), and effective in yielding the appropriate amount of emissions reductions.
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.10.]
First, EPA indicates that this rule may not fully satisfy the transport requirements of the Clean Air Act for a number of states, and a forthcoming second transport rule will complete the task. While we appreciate EPA's acknowledgement and future commitment, we are concerned that this sets a precedent of postponing to an uncertain date the completion of an essential element needed for downwind states to meet a national ambient air quality standard by the attainment deadline.
Response: 
EPA agrees with the need to provide for addressing transport requirements in a timely manner once NAAQS are revised.  It may not always be possible for the technical necessary to do this to be completed concurrently with publication of the NAAQS.  
EPA notes that the final rule completely addresses the requirements of section 110(a)(2)(D)(i)(I) with respect to the 1997 and 2006 PM2.5 NAAQS for the states covered by the rule for PM2.5.
Organization: Northern Indiana Public Service Company (NIPSCO)
Comment: 
Northern Indiana Public Service Company (NIPSCO)
EPA characterizes the allowances allocated under the Transport Rule as permanent allowances. Yet EPA asserts that the Transport Rule is intended to provide a template for addressing the requirements of Section 11 0(a)(2)(D) as NAAQS are tightened in the future. This suggests that the allowances may not, indeed, be permanent. Will the program revisions under Transport Rule II (ozone NAAQS revision reductions) and the Transport Rule III (PM NAAQS revisions) require removal of allowances or the imposition of a surrender ratio similar to the CAIR provisions for reducing the value of the Title IV allowances for use in the CAIR? The possibility of changing the allocations or surrender rates of the allowances as a consequence of the revisions to the NAAQS introduces uncertainty for future planning for EGUs. For future planning, EPA should provide additional information on how emission allowance allocations for future years will be impacted by development of Transport Rule II and potentially other future Transport Rule(s), including the value of any banked Transport Rule allowances as future versions of the rule are promulgated.
EPA indicates it proposes to record initial allowances for existing units in facility accounts by Sept. 1, 2011, for control periods in 2012, 2013, and 2014. EPA also proposes to record the quantity of allowances for existing units by July 1, 2012, and July 1 of each subsequent year thereafter, for the control periods in the third year after the year the allowances are recorded. Under this scenario, EPA would record existing unit allowances by July 1, 2012, for control periods in 2015. We question how the number of allowance allocations will be impacted by the planned revision to the Transport Rule that results from the anticipated revision to the ozone NAAQS and request EPA provide additional clarification.
By implementing the Transport Rule through FIPs, EPA has created an unnecessary complexity. Assuming for purposes of argument that EPA's findings that states' SIPs addressing transport are insufficient or nonexistent is correct, EPA has justified the use of a FIP for this first version of the Transport Rule. However, when EPA adjusts the applicable NAAQS in the future, under the CAA, states must submit SIPs to address the new standards, and it is only after states have failed to do so or EPA has found their proposed SIPs to be insufficient that EPA can impose a FIP. For example, if EPA adjusts the ozone standard to a point within the proposed range, it appears that the seasonal NOx budgets presently proposed for the Transport Rule may have to be adjusted downward, as EPA has acknowledged. The CAA provides that states have a period of time during which they must develop and submit SIPs to demonstrate compliance with the new standard, including addressing downwind impacts under Section 110(a)(2)(D). Assuming that states can satisfactorily address downwind impact, EPA must approve those SIPs. In an ozone SIP addressing Section 11 0(a)(2)(D) or SIP revision to include EPA Transport Rule II provisions, the state could establish an entirely new allocation methodology for seasonal NOx allowances that would comport with the new, lower seasonal NOx budget, including the variability limits, and yet be a totally different allocation methodology than what EPA has promulgated in the Transport Rule I. Sources in that state, then, would be subject to the federal allocation methodology, with its 'permanent' allowances, for annual NOx and S02 and to perhaps an updating methodology for seasonal NOx allowances. The permanence of allowance allocations that EPA promised in the Transport Rule, subject to the adjustments to accommodate revisions to the NAAQS, has been abrogated. This creates unacceptable uncertainties for generating companies and raises significant legal questions regarding EPA's approach. [EPA-HQ-OAR-2009-0491-2747.1 p.7]
Response: 
[CAMD needs to address allowance "permanence" issue]
See preamble discussion of rationale for FIPs, and how States can provide for SIP alternatives.
Organization: Ozone Transport Commission (OTC)
Comment: 
Ozone Transport Commission (OTC)
However, in the future OTC urges EPA to propose a Transport SIP Call and FIP concurrently with any future NAAQS proposals. This would result in the Transport SIP being due 3 years after NAAQS promulgation, or the FIP would become final.
OTC recommends the following changes to EPA's proposed timetable below, with changes and additions in bold/italics:
Year 0: Finalize NAAQS
Propose SIP Call
Propose FIP
Year 1: Finalize transport SIP call rule and FIP
Year 2: EPA designations (2 year maximum)
Year 3: Transport SIP due  -  controls due 2  -  3 years later
Final FIP imposed, if no SIP submitted
Year 5: Attainment SIP due (3 years after designation)
Year 7+: Attainment deadlines [EPA-HQ-OAR-2009-0491-2737.1, p. 6]
As EPA moves forward with developing Transport 2, OTC recommends that: (1) EPA ensure that Clean Air Act Section 110(a)(2)(D) requirements are fully addressed in it and any future transport rules; (2) the regulatory framework be revised as needed to fully address transport in the timeframes required to meet Clean Air Act compliance deadlines as outlined in our comments in Section I; (3) EPA set a higher cost threshold for ozone-season NOx controls as necessary to eliminate significant contribution and interference with maintenance; (4) it also account for the new W-126 secondary ozone standard; and (5) the rule must address transport impacts of SO2 and NO2, regard to their specific 1-hour NAAQS. [EPA-HQ-OAR-2009-0491-2737.1, p. 15]
In addition, EPA will soon be releasing its reconsidered ozone NAAQS, which will require even greater efforts by upwind states to reduce transport impacts. To solve the additional transport impacts under the soon-to-be revised ozone NAAQS, EPA's next iteration - Transport 2 - will need to be released in a timely manner and contain assurances that upwind impacts will be eliminated within a timeframe that allows downwind states to attain the NAAQS with three years of clean air quality data. It is critical that the precedents set by the currently proposed Transport Rule (with the modifications provided in these comments) are solid and sustainable to application to Transport 2 and to future updates to address transport. [EPA-HQ-OAR-2009-0491-2737.1, p. 15-16]
As discussed earlier in our comments, EPA's proposed Transport Rule presents a framework that we believe, with some modification, can be adapted for future NAAQS as they are revised. Ideally, reductions from upwind states would come three years prior to the attainment date of a NAAQS; EPA would therefore need to update its next iteration - Transport 2 - for the revised ozone NAAQS in a prompt manner. The OTC recommends that any future proposed revisions to the proposed Transport Rule be released in conjunction with the final revision of a NAAQS. This should prove to be a reasonable timeframe for EPA, and will aid in fulfilling states' obligation to submit a Transport SIP within three years of a new NAAQS being promulgated. We refer you to comments made in Section I of this document on the regulatory framework and ideal timetables for addressing the transport component to meet future NAAQS. Further, OTC believes that there are other issues that need to be resolved in Transport 2 regarding the rule's framework. While we have already focused on portions of the rule framework as they relate to transitioning from the proposed Transport Rule to Transport 2 and future rules, there are additional framework issues and questions that EPA must absolutely address moving forward. For example, will the next rule allow FIPs and SIPs to be simultaneously issued, and if so, what will EPA's strategy with this new policy be to help states achieve measurable emissions reductions? We recommend that prior to proposing Transport 2, EPA convene discussions with OTC and other state groups to get further perspectives on how to strengthen the framework to help states meet their Clean Air Act requirements. [EPA-HQ-OAR-2009-0491-2737.1, p. 16]
EPA also needs to pursue unlimited or state-specific cost thresholds in Transport 2 and future transport rules to fulfill its statement in the proposed rule that it "intends to proceed with additional rulemaking to address fully the residual significant contribution to nonattainment and interference with maintenance with the ozone standard as quickly as possible," and that it is "expeditiously conducting further analysis of NOX control costs, emissions reductions, air quality impacts, and the nature of the residual air quality issues" (75 FR 45213). The OTC strongly believes that a greater cost threshold must be set for ozone-season NOx controls. While the $500 per ton value in the proposed rule was established only to maintain the operation of already installed SCR units, the large NOx emission reductions which will be required will necessitate the actual installation of new control equipment. And section 110(a)(2)(D) does not confine EPA to regulation of the power sector alone; non-EGU stationary sources are some of the biggest emitters of NOx (and SO2) in the region. These units would greatly benefit from emissions controls and such reductions would aid in solving the residual effects from upwind states. Compared to the cost of other types of controls implemented by states in the OTR, combustion controls from non-EGUs are cost effective for reducing and/or eliminating transported air pollution (costs of non-EGU controls in the OTR are included in Appendix 1). [EPA-HQ-OAR-2009-0491-2737.1, p. 16]
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, pp.117-118.]
We understand that EPA proposes to address ICI boilers, as well as other NOX source categories, in a second transport rule that will follow.
Finally, and most importantly, it is imperative that EPA fulfill the promise it makes in this proposal to quickly adopt, no later than 2012, a second transport rule to address the more health-protective ozone standard anticipated this fall. Under this new standard, further reductions in transported pollution will be needed beginning as early as 2014 for states to meet their transport obligations and to realize the goal of clean air.
[These comments were submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.112.]
We also commend EPA for proposing a methodology for assessing transported air pollution that will provide a framework for more quickly analyzing the impact of transport under future revised air quality standards.
Response: 
EPA appreciates the comments on suggested approaches for systematically addressing transport as an integral part of the NAAQS publication and implementation process.   We intend to work with states to address CAA transport requirements in a timely manner after any new or revised NAAQS are published.  In addressing any future NAAQS, it will be likely be necessary to consider additional source categories.  
Organization: Pennsylvania Department of Environmental Protection
Comment: 
Pennsylvania Department of Environmental Protection
The DEP commends EPA for making the commitment in the proposed Transport Rule to an ongoing process of examining the need for further action to address transport for future NAAQS, starting with the adoption of the 2010 ozone NAAQS anticipated in October 2010. We further support EPA's approach for establishing a framework within which transported pollution affecting the attainment and maintenance of revised NAAQS would be analyzed. We recommend that EPA such an analysis for the recently promulgated short term nitrogen dioxide and SO2 NAAQS. Ideally, reductions in upwind states would come at least three years prior to the attainment date of a NAAQS (because attainment is assessed on three years of air monitoring data). [EPA-HQ-OAR-2009-0491-2660.1, p.9]
[This comment was also submitted as testimony at the Philadelphia, Pennsylvania public hearing on August 26, 2010.  See Docket Number EPA-HQ-OAR-0491-1938, p.54.]
The DEP understands that EPA is already working on the proposal for the second Transport Rule (Transport Rule II), which should be available during the summer of 2011. We urge EPA to expeditiously finalize Transport Rule: in order for state to meet regulatory deadlines and SIP obligations for the more protective ozone NAAQS anticipated in October 2010. [EPA-HQ-OAR-2009-0491-2660.1, p.9]
EPA should consider, as part of the Transport Rule II, the impacts and costs associated with the transport of NOx emissions from states outside: the Chesapeake Bay watershed that are significantly contributing to nitrate deposition in Pennsylvania and in other affected states.[EPA-HQ-OAR-2009-0491-2660.1, p.9]
Response: 

EPA agrees with the need to address interstate transport of ozone in a timely manner after publication of updates  to the ozone NAAQS.
Organization: Santee Cooper
Comment: 
Santee Cooper
An extension of the compliance deadline also would provide additional benefits of coordination among the rulemakings facing the power sector. States would have a chance to tailor their SIPs not only to the Transport Rule, but also to the utility MACT and the expected revisions to the ozone and fine particulate matter NAAQS. In addition, states could develop more efficient, tailored policies than the one-size-fits-all approach of the FIP. [EPA-HQ-OAR-2009-0491-2820.1, pp.16-17] [[These comments can also be found in Section VII.C.]]
Response: 
See discussion in preamble section VII.C on rationale for compliance deadlines in this Transport Rule.
Organization: Sierra Club
Comment: 
Sierra Club
In addition, it particularly critical that the EPA set explicit, mandatory time frames for updating the Transport Rule to address future ozone and PM2.5 NAAQS revisions. This is because the EPA has used the 1997 ozone and 2006 PM2.5 NAAQS to establish allowable emissions thresholds and determine which states significantly contribute to non-attainment or interfere with maintenance in downwind states. Yet the EPA strengthened the ozone NAAQS in 2008 and is expected to take final action in October on a proposal to further strengthen those standards. See EPA Status Report, State of Mississippi v. EPA, No. 08-1200, Doc. 1261654 (Aug. 20,2010).4 EPA has also indicated that it expects to complete a review of the PM2.5 NAAQS in 20 II, and the science strongly supports strengthening those standards as well. Though EPA acknowledges that these changes will occur and necessarily impact the proposed Transport Rule and its application, EPA does not provide sufficient, concrete assurances that any such revisions will be accounted for in timely, subsequent Transport Rule promulgation that incorporates those standards. [EPA-HQ-OAR-2009-0491-2872.1 p.3]
In order to assure that any transport rule promulgated by the EPA remains current and compliant with the mandates of section 11O(a)(2)(D), the Sierra Club urges EPA to commit to a determinate time frame within which it will issue updated transport requirements that will prevent significant contribution to non-attainment (or interference with maintenance) of any future ozone and PM2.5 NAAQS revisions. Since EPA has already stated that it can issue a final transport rule for the revised ozone NAAQS within two years of its promulgation, the Siena Club call on EPA to include in the rule an express commitment to that effect (i. e. that EPA will promulgate an updated Transport Rule addressing the revised ozone NAAQS not later than 2 years after promulgation of that NAAQS). Likewise, EPA must commit to adapting the Transport Rule to reflect any future PM2.5 NAAQS revisions within two years of their promulgation.6 [EPA-HQ-OAR-2009-0491-2872.1 p.3-4]
Response: 
EPA recognizes the need to address interstate transport requirements in a reasonable time period once NAAQS are finalized.   EPA believes the amount of time needed may vary, dependent on the nature of the transport problem and the necessary technical analysis.
Organization: South Carolina Department of Health and Environmental Control 
Comment: 
South Carolina Department of Health and Environmental Control 
The EPA plans to use the proposed Transport Rule's method of defining "significant contribution to nonattainment" and "interference with maintenance" when revised NAAQS will require a Transport Rule component. DHEC recommends that the EPA base these future Transport Rules on newer emissions inventories and updated modeling tools. We will first discuss emissions inventories, and then address modeling. [EPA-HQ-OAR-2009-0491-2677.1 p.10]
The proposed Transport Rule is based on the 2005 National Emissions Inventory ("NEI"). DHEC notes that during the development of the 2005 NEI, the EPA and states were focused on developing the 2008 NEI, a process the EPA called the "reinvention of the NEI." Moreover, many sectors in the 2005 NEI relied heavily on the 2002 NEI, meaning that some of the data in the Transport Rule modeling is almost a decade old. The 2008 NEI also included updated modeling platforms, such as the switch from MOBILE6 to MOVES. The vast improvements in the 2008 NEI over the 2005 NEI highlight the need to use the 2008 NEI, or a more current NEI, in revisions to the Transport Rule. [EPA-HQ-OAR-2009-0491-2677.1 p.10]
Related to this comment, the EPA has specifically requested comments on its non-EGU data spreadsheet,24 so that it has accurate data on non-EGUs for this rulemaking and future Transport Rule rulemaking. DHEC has attached this spreadsheet, with comments embedded, as Attachment A to this letter. As a general comment on this data, DHEC notes that when the EPA actually includes non-EGUs in a future Transport Rule, it should use at least the 2008 NEI, so that the EPA has the most accurate understanding of emissions. This analysis should also include the most updated modeling tools available. Most of the problems that DHEC found in this spreadsheet were a result of the data being 5 years old. Also, in our comments, we only address plant closures, new or closed units, and ownership-transfers. Because of the brief comment period, we do not address emissions data. This lack of comment on the emissions data should not be construed as an approval of the data's accuracy. [EPA-HQ-OAR-2009-0491-2677.1 p.10]
DHEC further notes that the EPA placed a revised version the spreadsheet in the docket on September 28, 2010, as Document # EPA-HQ-OAR-2009-0491-2525, with revised PM emissions data. We are submitting our comments in the original spreadsheet, Document # EPA-HQ-OAR-2009-0491-0128, which the EPA posted in the docket on August 5, 2010. DHEC notes that this is another example of how moving targets in the Transport Rule docket warrant an extended comment period. [EPA-HQ-OAR-2009-0491-2677.1 p.11]
Regarding modeling, DHEC would like to urge the EPA to carefully consider the modeling tools used to conduct modeling for future Transport Rules. Given modeling is the basis for the budgets outlined in the proposed Transport Rule, and will likely also form the basis for budgets in future Transport Rules, DHEC would like some assurance that the model and input data sets used to conduct this modeling are the most up-to-date and readily available. DHEC appreciates the rationale provided for decisions related to the air quality modeling platform, including the development of future-year emissions, air quality modeling, source apportionment, and post-processing provided in the proposed Transport Rule. DHEC also notes the precedent that this rule will have on future Transport Rule revisions as well as on transport provisions of section 110 SIP submittals. As such, DHEC requests that any future iterations of the Transport Rule include separate public comment periods with adequate time to provide states the opportunity to comment on any updates to the air quality modeling platform. Any modeling done with future Transport Rules should seek to address the most readily available and representative state-of-the-science tools to assess air quality. [EPA-HQ-OAR-2009-0491-2677.1 p.11]
In addition to this request, DHEC is also concerned about national consistency when applying and requiring air quality modeling in any of proposed EPA rules. Because the proposed Transport Rule addresses the Good Neighbor Provision required of all SIPs submitted to the EPA, it seems likely that the assumptions and results of this proposed rule will have lasting effects, in the same way that the CAIR affected many parts of SIP-submissions over the last five years. DHEC is concerned about the consistency with which the modeling platform proposed under federal rules like the Transport Rule is and will be available to, and required of, states for SIP submittals. More specifically, the EPA, in developing regulations uses CAMx, which is then codified in the Code of Federal Regulations. Then the EPA requires states and tribes to do their own modeling, using the CMAQ system. Without this assurance of consistency in modeling, states may find themselves comparing apples to oranges, applying modeling platforms that are inconsistent regionally and nationally. [EPA-HQ-OAR-2009-0491-2677.1 p.11]

The proposed Transport Rule addresses nonattainment and maintenance with the 1997 Ozone NAAQS, the 1997 annual PM2.5 NAAQS, and the 2006 24-hour PM2.5 NAAQS. While DHEC is pleased that the EPA is addressing thirteen-year-old standards, DHEC is concerned about transport issues associated with the 2010 Ozone NAAQS. The EPA plans to release a revised Ozone standard in 2010. DHEC recognizes its responsibility for attaining and maintaining this new standard, but many parts of South Carolina could be designated as nonattainment with this new standard. South Carolina and other states rely on EPA measures, like the proposed Transport Rule, to control interstate transport of ozone precursors. [EPA-HQ-OAR-2009-0491-2677.1 p.20]
In the proposed Transport Rule, the EPA states that it intends to issue a proposal to address the transport components of the 2010 Ozone NAAQS as soon as possible.52 Without such a timely revision to the Transport Rule, it is unlikely that South Carolina could attain the 2010 Ozone Standard. As we have noted in previous comment letters, it is critical for the EPA to recognize that setting a NAAQS itself does not protect public health. It is the implementation that achieves the desired public health benefits. DHEC has an obligation to the citizens of South Carolina to provide clean air, and, in the spirit of cooperative federalism, we hope our co-regulator, the EPA, upholds its obligations and quickly issues updates to the Transport Rule so that South Carolina citizens can experience the public health benefits that meeting the EPA's NAAQS would bring. [EPA-HQ-OAR-2009-0491-2677.1 p.20]
Response: 
EPA appreciates the comments and insights into issues related to future technical analyses.
Organization: State of Connecticut
Comment: 
State of Connecticut
EPA should commit to a rapid proposal of a new 'Phase II' transport rule that implements controls by 2014 so as to achieve the transport reductions necessary for Connecticut to timely achieve the new, more stringent ozone NAAQS that EPA is expected to finalize this Fall. The proposal's assertion that no further NOx controls are needed in 2014 is contrary to logic and must be revised. [EPA-HQ-OAR-2009-0491-2534.1, p.2]
Response: 
EPA will be addressing the appropriate time frame for additional NOx reductions in its assessment of transport under any revised ozone NAAQS.   We intend to work with states to address CAA interstate transport requirements for any  new ozone standard in a timely manner after the update to the ozone NAAQS is published.
Organization: State of Ohio Environmental Protection Agency (Ohio EPA)
Comment: 
State of Ohio Environmental Protection Agency (Ohio EPA)
a. Ohio EPA is concerned with the 'one size fits all' approach by which U.S. EPA is aligning compliance dates in the Proposed Transport Rule with NAAQS attainment dates. Given that there will likely be a new ozone standard in 2010, U.S. EPA should promulgate a Transport Rule that addresses the upcoming revised standard. [EPA-HQ-OAR-2009-0491-2793.2, p. 2]
10. 0hio EPA has concerns with the constantly moving regulatory target and the lack of coordination between programs within U.S. EPA. In establishing requirements and implementation schedules for the Transport Rule, U.S. EPA must take into consideration all impending regulatory requirements that states and the regulated entities are facing. [EPA-HQ-OAR-2009-0491-2793.2, p. 9]
a. U.S. EPA has stated that they likely will strengthen the NOx budgets based on a second Transport Rule to be promulgated to assist with attaining the soon to be revised 2008 ozone standard. Consistent with comment 1.a. above, U.S EPA should recognize that a new ozone standard will be issued shortly and promulgate a Transport Rule that addresses the revised standard, with an appropriate implementation schedule. [EPA-HQ-OAR-2009-0491-2793.2, pp. 9-10]
Ohio EPA has serious concerns about the constantly moving regulatory targets. In order to provide more certainty so that appropriate planning can occur, Ohio EPA believes U.S. EPA should take the time now, within the current Proposed Transport Rule, to address state NOx budgets needed for the revised ozone standard and .provide appropriate and reasonable implementation schedules. It would 'be our preference to see a more restrictive NOx budget, adequate time to 'reach that lower NOx level, and then have those NOx levels maintained for an extended time period. [EPA-HQ-OAR-2009-0491-2793.2, p. 10]
b. Given U.S. EPA's acknowledgement in the proposal that there will be a series of regulatory actions over the course of the next two years that will affect the power sector, better planning and coordination regarding the imposition of these programs is needed. [EPA-HQ-OAR-2009-0491-2793.2, p. 10]
Ohio EPA is also extremely concerned that each time U.S. EPA promulgates a new (more restrictive) air quality standard, U.S. EPA intends to assess the need to revise the Transport Rule and establish more restrictive budgets. First, we expect that at some, point, it will be difficult or impossible to develop and implement technology that can achieve the new, more restrictive budgets. Second, the regulated community must have some degree of certainty to timely plan investments in controls, fuels, and operations at generating facilities in order to achieve necessary emission levels by the relevant deadlines. We would recommend that any budget U.S. EPA promulgates for an emissions sector would not change for at least ten years and then only if U.S. EPA demonstrates that additional controls are technically achievable and cost effective. [EPA-HQ-OAR-2009-0491-2793.2, p. 10]
Response: 
EPA recognizes that there is uncertainty regarding the requirements of future NAAQS, and we hope to reduce this uncertainty as much as possible in the event of any revisions to the NAAQS.    In the meantime, EPA is addressing its obligation to move expeditiously to address the concerns raised by the court in North Carolina v. EPA, and to address, for states in the eastern United States, the requirements of section 110(a)(2)(D)(i)(I) for the 2006 PM2.5 standards.
Organization: State of Wisconsin, Department of Natural Resources
Comment: 
State of Wisconsin, Department of Natural Resources
Addressing future 2010/11 Air Quality Standards - EPA needs to consider deeper EGU emission reductions within this rule assessment and clearly identify non-EGU control programs that may be needed. Methods to accomplish this include a supplemental notice or a notice of intent to a future proposal once the new ozone standards are promulgated. [EPA-HQ-OAR-2009-0491-2829.2, p.3]
Potential regulatory geographic scope and individual state contribution assessments need to be revisited once a final ozone standard is promulgated (expected date late fall of2010), and again once any PM standard revision should occur under the current standard review (expected proposal spring of 2011 and final fall 2011). [EPA-HQ-OAR-2009-0491-2829.2, p.3]
While the preamble speaks to EPA's intent to promulgate a second, and perhaps third round FlP in the near future to address NOx and S02 transport related to new standards, that action is not hardwired within this proposal. Significant contribution from other sectors in upwind states is demonstrated and impacts Wisconsin's current and potential PM nonattainment areas. EPA notes that some states do not receive full remedy under this proposal (FR page 45221), yet does not identify or ensure a full remedy outcome. This lack of remedy precludes the capability to use a weight of evidence projection based on 'expected' reductions within regional attainment modeling much less formally demonstrate attainment/maintenance. The final rule needs to more directly ensure these categories get addressed in a timeframe required for Wisconsin's attainment planning as it is already apparent that timely attainment or maintenance will not be feasible without further emission reductions from the major emission sectors in upwind contributing states. [EPA-HQ-OAR-2009-0491-2829.2, p.3]
One potential mechanism to address this incremental additional transport remedy is to set firm additional emission reduction dates within the current program framework. These would provide for a range of more stringent EGU sector potential control levels based on downwind state air quality impact reduction and absolute emission reduction levels in addition to relative cost-effectiveness. Next budgets should at least meet the reduction commitments built into the final CAIR program budgets (i.e.- no backsliding). These 'next step' thresholds should also contain placeholders providing for minimum new reduction targets to be set for other source categories shown to impact air quality downwind but not included within this proposal. Those targets need to be additive to existing federal and state control programs, i.e. - assessment of contribution should include the projected improvements based on existing regulations and the relative contribution and reduction potential assessed relative to this future baseline. [EPA-HQ-OAR-2009-0491-2829.2, p.3]
While additional states significantly contribute to Wisconsin's ozone concentrations below the 0.08 ppb 8-hour ozone standard (84 ppb and below design values), EPA's air quality projections indicate the 1997 standard will be attained [but not necessarily maintained] by and after the anticipated 2012 FIP compliance dates. It would benefit regional planning for EOU controls installations under this FIP if EPA indicated which additional states would surpass the 1% contribution threshold again under a new ozone standard set within the range re-proposed by EPA to replace the promulgated 75 ppb ozone standard. At a minimum, EPA could issue an additional NODA under the current FIP proposal indicating which states would likely be identified for participation in a Section 110 remedy at the new standard level. A preferred approach would be a supplemental SNPR that fully addresses the new ozone standard within the current program structure - identifying an added summer NOx reduction phase for 2015, 2016, or 2017, depending on EPA's interpretation of a critical attainment year reduction program target. Such a supplement would also confirm final budgets for comment that include updated projections and unit level corrections provided via the current NODA on NEEDS 4 and the current IPM assessments. [EPA-HQ-OAR-2009-0491-2829.2, pp.5-6]
Response: 
EPA agrees with the need to move expeditiously to address interstate transport requirements upon publication of revisions to the ozone standard.  Because additional technical analyses are needed, it is not possible in this final rule to provide for the information and provisions related to future standards that the commenter requests.
Organization: Texas Commission on Environmental Quality
Comment: 
Texas Commission on Environmental Quality
If the EPA intends to consider regulating non-EGU sources under a future transport rule proposal, it must account for existing local controls prior to initiating any additional requirements for these sources. The EPA should work with states to gather accurate information on the local non-EGU controls outside of the Transport Rule comment period for use in developing the final rule. [EPA-HQ-OAR-2009-0491-2857.2, p.13]
Response: 
EPA would appreciate any information of this nature, particularly on nonEGU controls, that the commenter could provide.
Organization: Texas Mining and Reclamation Association
Comment: 
Texas Mining and Reclamation Association
The Transport Rule relies on 1997 annual PM2.5 standards, the 2006 daily PM2.5 standards, and the 1997 8-hour ozone standards, which are all currently under review by the EPA and will likely be revised within the next year or two.1 To base emission reduction requirements on standards which will change before the 2012 and 2014 compliance deadlines proposed in the Transport Rule, only adds to the difficulty in demonstrating compliance with the Transport Rule. As a solution, EPA offers that they will "issue as soon as possible a proposal to address the transport requirements with respect to the reconsidered standard." However, the solution only offers additional rule promulgations in the future, not addressing the immediate compliance deadlines. [EPA-HQ-OAR-2009-0491-2734.1 p.2]
The Transport Rule sets new emission budgets for each state and requires compliance with set emission reductions by 2012. With such a quick compliance deadline less than one year after the final rule is published, it is not clear how states will coordinate emission reduction mandates from the federal level with ongoing efforts at the state level.   [EPA-HQ-OAR-2009-0491-2734.1 p.2]
For example, Texas is in the middle of demonstrating attainment for several of their nonattainment regions for the 1997 8-hour ozone standard. Specifically, the Texas Commission on Environmental Quality (TCEQ) recently adopted the Houston Galveston Brazoria (HGB) Attainment Demonstration SIP Revision and the HGB Reasonable Further Progress SIP revision for the 1997 8-hour ozone standard. In this latest SIP revision, Texas will be demonstrating an 18% emission reductions, with 3% reductions between 2008, 2011, 2014, 2017, and 2018. Now, the EPA is proposing NOX emission reductions under the Transport Rule with a compliance date of 2012. Further complexity will be inserted by the planned adoption of a revised Ozone NAAQS, which will trigger a host of additional SIP Revision activities. Layering so many regulatory compliance timelines and developments on top of each other will cause confusion for state regulatory agencies, the regulated community, and the general public.  [EPA-HQ-OAR-2009-0491-2734.1 p.2]

Footnote 1: The revised 8-hour ozone NAAQs should be published in October of 2010 according to the EPA. The 2006 PM2.5 standards are currently under EPA review and revised standards may be proposed as early as February 2011.
Response: 
This Transport Rule will provide necessary reductions in ozone season NOx from upwind states that will help the Houston Galveston Brazoria (HGB) area to meet the ozone NAAQS.    EPA believes EGUs within the HGB areas, generally already subject to stringent requirements, will be able to readily comply with the Transport Rule.

XX. NODA on Allocations and Related Matters (January 7, 2011)

Organization: AES Corporation (AES)
Comment: 
AES Corporation (AES)
Comments on the flaws of the original allocation methodology and rule were submitted in October 2010. As stated in those comments, some contract facilities have obligations to operate with no provision to recoup any of the additional cost for compliance. Provisions should be made to keep these allocations neutral with the needs to operate as was intended in the Title IV and PURPA Act. [EPA-HQ-OAR-2009-0491-4016, p. 3]
Response: 
--------------------------------------------------------------------------------
See sections VII.B and D of the preamble.    The commenter failed to explain what it meant by stating that allocations should be "neutral with the needs to operate."   In the final rule, EPA adopts for existing units a uniform methodology for allocating allowances that calculates a unit's allocation based on historical heat input and using historical emissions as a ceiling in the calculation.  The commenter failed to provide any information showing why the allocation methodology for other units should not be applied to units described by the commenter as "contract facilities."   For example, the commenter does not compare the "contract units' " emissions to such units' allocations and does not assert, much less demonstrate, that it will suffer any financial hardship from application of the allocation methodology that is used for all other existing units.  
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Organization: Alcoa Power Generating Inc. - Warrick Power Plant
Comment: 
Alcoa Power Generating Inc. - Warrick Power Plant
APGI does have concerns with the overall GATR concept, in general. EPA seems not to have considered air quality improvements achieved by the vacated CAIR rule. The most recent air quality data indicate substantially fewer nonattainment and maintenance areas than EPA's data. [EPA-HQ-OAR-2009-0491-4024, pp.1-2]
3.) Modeling of existing CAIR requirements and other OTB controls indicate no need for the nature and extent of controls as proposed in the CATR. APGl thus conditions its recommendation for Option 1 on a re-evaluation by EPA of needed pollutant reductions based on improvements the vacated CAIR. rule provided. [EPA-HQ-OAR-2009-0491-4024, p.2]
4.) EPA has proposed a FIP rather than a SIP; followed by a FIP, as required by the CAA. Congress intended States to take the primary role in regulating stationary sources under Title I of the CAA. Title I unequivocally guarantees States the opportunity to establish a statewide program for achieving the NAAQS, and only where States fail to establish such programs does a FIP apply directly to the sources within the State. [EPA-HQ-OAR-2009-0491-4024, p.2]
EPA lacks statutory authority to reverse the order of the NAAQS process designed by Congress and immediately impose its program for a State's achievement of the NAAQS, unless and until a State has failed to develop and obtain approval obits own State program. [EPA-HQ-OAR-2009-0491-4024, p.2]
Not only does a FIP-first approach violate the CAA, it also deprives States and sources the opportunity - intended by the statutory scheme - to selectively target reductions from among the many emissions sources. It also does not allow states to consider hardware installations that have provided air quality improvements, and to find innovative, source-specific solutions to achieving emission reductions. [EPA-HQ-OAR-2009-0491-4024, p.2]
Especially in light of air quality improvements achieved pursuant to the vacated CAIR rule, the urgency in mandated severe emissions reductions proposed by the CATR rule FIP first approach is not warranted. APGI thus strongly encourages EPA to allow states to address the needed realistic emissions reductions through the normal SIP amendment process provided by the Clean Air Act. [EPA-HQ-OAR-2009-0491-4024, p.2]
Response: 
With regard to EPA's choice of analysis baseline, including the treatment of CAIR, please see Preamble Section V.B.
 Comments regarding EPA's authority to impose the FIPs in this rule are discussed in detail in Preamble Section IV.C.2 and in section III.A. of this RTC.
Organization: Alliance for Industrial Efficiency
Comment: 
Alliance for Industrial Efficiency
Conventional power generation is incredibly inefficient and has changed little since the days of Thomas Edison. As the following graphic illustrates, roughly two-thirds of energy inputs (68 percent) are simply emitted into the air under conventional approaches, with a mere 32 percent actually delivered to customers: [EPA-HQ-OAR-2009-0491-3941[1].1, p.2] [[See Docket Number EPA-HQ-OAR-2009-0491-3941[1].1, p.2 for graphic.]]
Perpetuating energy waste is a mistake. By capturing and reusing this waste heat, Waste Heat Recovery (WHR) and Combined Heat and Power (CHP) convert what would otherwise be wasted energy into additional electricity and thermal energy (heat). This dramatically increases fuel efficiency  -  allowing utilities and companies to effectively "get more with less." EPA recognizes these benefits and is elsewhere supportive of WHR and CHP. As EPA states on its CHP Partnership website, CHP provides an "efficient, clean, and reliable approach to generating power and thermal energy from a single fuel source." [EPA-HQ-OAR-2009-0491-3941[1].1, p.2]
EPA itself has long recognized that output-based standards encourage energy efficiency in general  -  and CHP in particular. As EPA notes on its website:  
Output-based emission limits are particularly important for promoting the energy and environmental benefits of CHP. CHP units produce both electrical and thermal output. Output-based limits can be designed to explicitly account for both types of output in the compliance computation. Traditional input-based limits, on the other hand, do not account for the pollution prevention benefits of CHP. [EPA-HQ-OAR-2009-0491-3941[1].1, p.2]
EPA has also requested comments on approaches for states to allocate allowances. As we explained in our original comment letter, EPA should encourage states to redistribute allowances to encourage efficiency. This can be done by establishing "set asides" to industrial facilities that invest in WHR and CHP. These companies, in turn, can sell the allowances to regulated utilities to generate additional revenue. This will encourage companies to invest in WHR and CHP. This approach would not increase emissions because the total number of distributed allowances would remain unchanged. In short, distribution of allowances within a state does not affect overall emissions in the state. EPA will need to provide guidance and model rules for states to help implement this reallocation. The final rule should clarify that EPA will look favorably upon State Implementation Plans that incorporate Federal Implementation Plan elements (e.g., with respect to total allowances) but adopt this approach. [EPA-HQ-OAR-2009-0491-3941[1].1, p.3]
Response: 
With regard to end-use energy efficiency, EPA response to key comments and rationale for believing that  EE set-asides are more likely to be more practically and effectively implemented at the state level can be found in Preamble Section VIII.D.2.
Organization: Alliance to Save Energy
Comment: 
Alliance to Save Energy
The Alliance reiterates its commendation of the EPA for recognizing the benefits of end-use energy efficiency as a means to reduce pollutant emissions from electrical generation not only in the CATR Notice of Proposed Rulemaking (NOPR) but also in the previous Clean Air Interstate Rule (CAIR) and associated guidance. As was stated in the NOPR, 'achievement of energy efficiency improvements in homes, buildings, and industry is an important component of achieving emissions reductions from the power sector while minimizing associated compliance costs. By reducing electricity demand, energy efficiency avoids emissions of all pollutants associated with electricity generation, including emissions of NOx and S02 targeted by this rule.' [EPA-HQ-OAR-2009-0491-3926[1].1, pp.1-2]
The Alliance understands that states that incorporated EERE set-asides under CAIR required significant technical assistance from EPA, the Department of Energy (DOE), and outside consultants. Each of those states individually struggled to determine EPA acceptable SIP parameters, including such things as, among others, additionality and enforceability concerns, measurement & verification (M& V) issues, and types of energy efficiency measures that could be eligible for set-asides. Guidance offered in the previously cited 2004 EPA document 'Guidance on State Implementation Plan (SIP) Credits for Emission Reductions from Electric-Sector Energy Efficiency and Renewable Energy Measures' is at a very high and broad level and was of limited utility for state and local air quality agencies seeking to incorporate EERE set-asides into their programs. [EPA-HQ-OAR-2009-0491-3926[1].1, pp.2-3]
Response: 
With regard to end-use energy efficiency, EPA response to key comments and rationale for believing that EE set-asides are more likely to be more practically and effectively implemented at the state level can be found in Preamble Section VIII.D.2.
Organization: Ameren Services Company
Comment: 
Ameren Services Company
1) EPA has now with this third Notice of Data Availability (NODA) requested comments in whole or in part 4 times on the proposed Transport Rule. First on August 2, 2010 (i.e. 75 Fed. Reg. 45210-45465); next 3 separate NODAs were issued for comment:
a) One on the EGU emissions inventories (i.e. 75 Fed. Reg. 53613- 53615) on September 1, 2011
b) One on the Non EGU sector emission inventories (i.e. 75 Fed. Reg. 66055-66057) on October 27, 2010
c) This NODA on allocation methodologies (i.e. Fed. Reg. 1109-1121) on January 7, 2011 . [EPA-HQ-OAR-2009-0491-3894[1].1, p.1]
These requests for comments and other information cover a broad portion of the Transport Rule as proposed and depending on the comments that EPA receives will alter the form and function of this rule. EPA should after consideration of the comments received from these requests for comment repropose the Transport Rule so industry and the public at large can comment on how all of these considerations have affected EPA's decisions to modify the original Transport Rule. [EPA-HQ-OAR-2009-0491-3894[1].1, p.1]
On page 1119 EPA requests comments on the provisions for states to submit their own SIPs to implement the Transport Rule. EPA correctly states 'by promulgating these Transport Rule FIPs, EPA would in no way affect the right of states to submit, for review and approval, a SIP that replaces the Federal requirements of the FIP with state requirements.' Ameren favors the approach taken in CAIR and the NOx SIP Call. In these rule makings EPA developed a model rule by which the states could pattern their SIP after (e. g. either adopting the EPA allocation scheme or developing their own). However as Ameren has noted in its original comments (August 2, 2010 Transport Rule proposal) EPA should not immediately issue a FIP as CAA § 101 (a)(3) states
' ... that the prevention and control of air pollution at its source is the primary responsibility of States and local governments'. [EPA-HQ-OAR-2009-0491-3894[1].1, p.2]
EPA should give the states at least 18 months (e.g. in other EPA regulations EPA gives up to 3 years - Part 51 Section 51.166(a)(6)(i>> to develop a SIP. And only after the state has not met this deadline should EPA issue a FIP. [EPA-HQ-OAR-2009-0491-3894[1].1, p.2]
EPA needs to give the states sufficient time to develop their SIPs and thus should delay implementation of the Transport Rule at least until 2014 or 2015. This would allow the states ample time to develop a SIP and go thru their mandated regulatory approval process. [EPA-HQ-OAR-2009-0491-3894[1].1, p.3]
However, care should be taken to assure that the allowances are allocated in a fair and equitable way. Under the August 2,2010 Transport Rule proposal Sections 97.402, 97.502, 97.602 and 97.702 (Definitions) EPA defines 'Owner's assurance level' and 'Owner's share'. These definitions define the amount each owner will receive from the variability limit based on the proportion of allowances allocated to the owner to the total allowances allocated to the state. According to the proposed rule these definitions come into play when a state's emissions exceed (either annual or 3 yearly) the allocations + variability limits. If an inequitable allocation of allowances is allowed owners that receive an arbitrarily low allocation based on past operations could also be penalized if their respective state exceeds its allocation plus variability limit. That is, if a source has an arbitrarily low allowance allocation; first there is a likelihood they may not be able to comply with the Transport Rule without purchasing additional allowances; second if the state does exceed its allocation + variability limits the owner will receive an arbitrarily low portion of the state's variability. This penalizes the owner twice. [EPA-HQ-OAR-2009-0491-3894[1].1, p.3]
Response: 
Thank you for your comment.
Organization: America's Natural Gas Alliance
Comment: 
America's Natural Gas Alliance
As the Agency has recognized in various settings, natural gas is 'considered a 'clean' fuel,' one that can be used to achieve the overall emission reduction and improved air quality goals of the Clean Air Act (CAA). When used to generate electricity, natural gas emits half the C02 emissions of coal, 80% less NOx, virtually no S02 or particulate matter, and no mercury. In addition, natural gas is currently under-utilized for power generation; such use could be increased quickly to provide cleaner energy and have an immediate pollution-reduction impact. Significant reductions in overall emissions of NOx and S02 can be realized from increased use of natural gas in the power generation sector, and ANGA encourages EPA to ensure that the CATR takes advantage of the natural gas as an abundant, domestic, cleaner burning fuel. [EPA-HQ-OAR-2009-0491-3939[1].1, p.1]
In that regard, ANGA submitted comments to EPA regarding the Agency's first Notice of Data Availability regarding the CATR (75 Fed. Reg. 53613 (Sept. 1, 2010). In those comments ANGA supported the Agency's decision to use the updated IPM power sector modeling platform (V-4-10), including integrating natural gas modeling directly into the IPM, for purposes of the CATR. ANGA also expressed concern with respect to the Agency's proposed approach to allocating emission allowances to individual units based on modeled or historic actual emissions, and encouraged EPA to consider revising the allowance allocation methodology proposed in the CATR, and identified two potential alternatives: an allocation methodology utilizing historic input (heat such as million British thermal units) or output (megawatt-hour). [EPA-HQ-OAR-2009-0491-3939[1].1, pp.1-2]
Both the originally proposed emission-based methodology and the Option II methodology could result in allocations that are reduced, in effect penalizing those companies that have taken or that are scheduled to implement projects to reduce emissions of the regulated pollutants, whether by fuel switching, installation of controls, or otherwise. ANGA submits that such 'penalties' run counter to the broader goals of the CAA, as well as the specific goals regarding transport of air pollutants to downwind areas. [EPA-HQ-OAR-2009-0491-3939[1].1, p.3] [[This comment can also be found in Section XX.A.1.b.]]
ANGA strongly supports the Agency's efforts to reduce NOx and S02 emissions from combustion sources to address interstate transport of those pollutants, and believes that the CATR can be a very effective tool employed by the Agency to do so. [EPA-HQ-OAR-2009-0491-3939[1].1, p.5]
Response: 
Thank you for your comment.
Organization: American Electric Power
Comment: 
American Electric Power
There Is No Demonstrated Need for Additional Reductions in 2012 and 2014
AEP reiterates that EPA has not demonstrated that the timelines and stringent budgets within this Proposed Transport Rule are necessary. The modeling data developed by the Midwest Ozone Group (MOG) and its Industrial Modeling Coalition, in conjunction with ambient air quality data collected by EPA, show that full compliance with the NAAQS targeted by this rulemaking is achieved for all but a few areas that have ambient concentrations dominated by local sources. As AEP stated in the comments on the Proposed Transport Rule, EPA should limit the current rulemaking to providing enhanced technical support for the current CAIR provisions as amended to include narrow corrections specifically required by the North Carolina decision, and otherwise continue to rely upon the current CAIR program budgets, deadlines, trading, and banking until 2015, at a minimum. EPA should address the post-2015 period in a revised proposal that takes into account the states' primacy for SIP development, the current planning being undertaken for the revised S02 and N02 NAAQS, EPA's planned revisions of the ozone and PM-2.5 NAAQS, and air quality improvements achieved through CAIR. EPA should then allow the public adequate time to review and comment on the new inputs and outputs. Only then can there be a fair assessment of the air quality improvements achieved by existing requirements, and any additional reductions needed to make further progress toward the public health goals underlying the NAAQS. EPA's plan to conduct repeated rounds of SIP calls and piecemeal modeling exercises eliminates the opportunity to plan the capital investments and execute the construction projects that are necessary to achieve emission reductions on the scale of the Proposed Transport Rule.   [EPA-HQ-OAR-2009-0491-3934[1].1, p.2]
The Proposed Schedule Fails to Provide Adequate Time to Install Controls
In AEP's comments responding to the original notice, we attempted to explain the time required to design, permit and install the controls necessary to meet the strict budgets in this proposal. We are currently reviewing our plans to install a scrubber on Big Sandy Unit 2 in Kentucky. At this time, controls cannot be approved, permitted, designed, constructed and commence operation on this unit until December 2015. Attached as Exhibit A is the actual timeline for the installation of S02 control equipment at several coal-fired generating units on the AEP system. The timeline is based on AEP's actual experience installing these controls on over 6,200 MW at five facilities over the last seven years. A four-year time frame is required given the design and engineering, permitting, and regulatory challenges associated with each one-of-a-kind retrofit project. The schedule in the Proposed Transport Rule does not take this reality into account. In addition, AEP's experience in permitting and constructing the landfills needed for the byproducts generated by new S02 controls is 54 months from beginning of conceptual design to obtaining permits and finally constructing the landfill and all access roadways needed for its operation. [EPA-HQ-OAR-2009-0491-3934[1].1, p.2] [[See Docket Number EPA-HQ-OAR-2009-0491-3934[1].1, p.10 for Exhibit A.]]
As we have stated in our comments on the Original proposal and the subsequent notices of data availability, we recommend that EPA take the comments from the public, correct the inaccuracies in the inputs to the models, re-run the models, and then use that information to develop and publish a supplemental notice. That supplemental notice can include options that can be evaluated and commented upon using verifiable support data. [EPA-HQ-OAR-2009-0491-3934[1].1, p.4]
Employing a methodology which specifies budgets and allocates allowances on the basis of speculative modeled reductions will lead to costs much higher than optimally needed. Additionally, the complexity of the model makes it impossible to review the accuracy of all inputs and outputs of the model with the level of scrutiny required given the enormous financial implications of this proposal. Because of the potential adverse impact on the modeled results caused by the inflated inventory, we recommend EPA allow itself the opportunity to correct the problems we have found, correct any additional issues that may arise through an in-depth quality assurance review of the inventories used, and then remodel the proposal. EPA should then allow the public adequate time to review and comment on the new inputs and outputs. [EPA-HQ-OAR-2009-0491-3934[1].1, p.4]
AEP has only limited concerns with original allocation methodology proposed for the beginning of the program (2012) and thus would_prefer the original methodology be retained for initial allocations as opposed to the NODA alternatives. The original methodology allocated 2012 allowances based on expected emissions. Recognizing that only the most limited emissions reductions can legitimately be expected in 2012, we feel this is a prudent approach as long as good data is used in developing the expected emission forecast. However, we are concerned that expected 2012 emissions were adjusted downward in the original methodology based on unrealistic performance assumptions and by using a period of historically low demand. The historical data used for 2012 S02 budget development in the original proposal was from the years 2008-2009. Late 2008 and early 2009 happen to coincide with the longest and deepest economic recession since World War II, and represent one of the lowest periods in recent history of utility power plant utilization. Additionally, emissions during this period were exceptionally low as high cost uncontrolled units did not run. Thus, using those portions of 2008 and 2009 as a basis for state and unit level budgets is highly punitive and arbitrary. Given the aforementioned issues, a more representative historical time perspective should be used to set 2012 S02 budgets. We would recommend a three year average from 2006-2008 to capture more typical plant operation. Furthermore, any corrections to unit emission rates for controls should: a) take into account more realistic performance expectations (see NEEDS FGD Removal Assumptions in original comments); b) adjust for higher sulfur coal use with FGD installations; and c) take into account only partial year operation of control equipment. Based on these reasonable adjustments, we favor an historic emissions-based allocation methodology for S02, Annual NOx and Seasonal NOx for the period beginning in 2012. [EPA-HQ-OAR-2009-0491-3934[1].1, p.5]
Response: 
EPA believes that the commenter's suggestion that EPA should have promulgated only "narrow corrections specifically required by the North Carolina decision, and otherwise continue to rely upon the current CAIR program budgets, deadlines, trading, and banking until 2015" is tantamount to proceeding as if the North Carolina opinion had never been issued at all.  The Court found CAIR to be "fatally flawed" and originally decided to vacate the rule in its entirety; on rehearing, EPA submitted that it would replace CAIR within 2 years and the Court agreed with petitioners to remand CAIR without vacatur "to preserve the environmental values covered by CAIR," notably not the CAIR programs in them of themselves.  The Court also explicitly found the CAIR budgets to be illegal, and that CAIR's 2015 compliance deadline failed to align with the relevant NAAQS attainment deadlines as required under section 110(a)(2)(D) of the Clean Air Act.  The commenter recommends that the Agency somehow promulgate a rulemaking which attempts to issue "narrow corrections" to what the Court found to be a "fatally flawed" rule, and in doing so, to extend specific aspects of that rule that the Court deemed to be illegal.  EPA does not understand how any of the commenter's rulemaking recommendations are compatible either with the Clean Air Act or with the Court's interpretation of the statute in the North Carolina opinion.   
Organization: ARIPPA
Comment: 
ARIPPA
ARIPPA provided extensive comments on EPA's Proposed Rule concerning the Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone (the 'Proposed Transport Rule'), as well as the Notice of Data Availability for Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone; Proposed Rule (the 'First NODA').  ARIPPA's comments concerning the Proposed Transport Rule addressed many points.  Of particular significance to the Second NODA, ARIPPA objected to the approach proposed by EPA for unit-specific allocations under the Proposed Transport Rule.  Among other objections, ARIPPA demonstrated that EPA's attempt to allocate allowances based upon projected emissions (and associated operating levels) reflected severe inaccuracies and errant assumptions relative to the operational and emission profiles for distinct electric generating units (EGUs), particularly with respect to smaller independent power production facilities.  ARIPPA also emphasized that EPA's proposed approach through the Proposed Transport Rule represented a substantial and unjustified departure from the approach historically utilized by EPA in devising interstate air quality regulatory schemes under the Clean Air Act.   [EPA-HQ-OAR-2009-0491-3903[1].1, p.1] 
In commenting upon the First NODA, ARIPPA recognized that EPA had refined its modeling projections, and thereby reduced the inaccuracies in its modeled emission projections; nonetheless, ARIPPA demonstrated that the First NODA remained wholly inadequate in its attempt to rectify the fundamental flaws in EPA's proposed allowance allocation methodology.  ARIPPA's comments also identified various inaccuracies in the data reported by EPA for the ARIPPA facilities.  [EPA-HQ-OAR-2009-0491-3903[1].1, pp.1-2]
EPA's proposed regulatory approach continues to evaluate cost effective emission controls based upon a singular analysis of available emission control technologies and resultant emission levels for all EGUs, without regard to significant and material distinctions that undercut EPA's technical and economic assumptions.  EPA has not justifiably concluded that these unique source types substantially contribute to downwind nonattainment.  [EPA-HQ-OAR-2009-0491-3903[1].1, p.3] 
By proposing to allocate unit-specific allowances based solely upon consideration of established heat input and projected emission rates resulting from the application of 'cost effective controls' derived by EPA for traditional coal-fired electric utility generating units, EPA proposes unit specific allocations for other source types, specifically including coal refuse-fired circulating fluidized bed ('CFB') units, that are clearly insufficient to account for emissions from sources following the application of technologically available controls.   [EPA-HQ-OAR-2009-0491-3903[1].1, p.3]
Based on these considerations, it would be most appropriate for EPA to remove these sources from the rulemaking effort.  Alternatively, EPA must refine its allowance allocation scheme to consider sulfur dioxide emission rates attainable from cost effective controls for each source type.  [EPA-HQ-OAR-2009-0491-3903[1].1, p.3]
EPA's proposed unit-specific allowance allocations under the Proposed FIP remain inappropriate and inequitable under the Second NODA, as applied to the ARIPPA plants.  
ARIPPA provided extensive comments on the Proposed Transport Rule in support of the position that EPA's stated basis for determining unit-specific allowance allocations under the proposed FIP is inappropriate and inequitable.  The First NODA reported upon EPA's more refined model for projecting information relevant to the proposed allocation of unit-specific allowances under the FIP.  However, as addressed by ARIPPA within its comments on the First NODA, EPA's modeled projections under the First NODA remained substantially inaccurate and inappropriate, at least with respect to the ARIPPA facilities. [EPA-HQ-OAR-2009-0491-3903[1].1, p.3]
ARIPPA's earlier comments on this rulemaking docket demonstrated that EPA's proposed allocation scheme through the Proposed Transport Rule and First NODA were fundamentally flawed because, in determining proposed allowance allocations for affected EGUs, EPA relied on considerations of projected emissions, among other factors.  EPA attempted to project emission rates based upon its own assessment, reflective of integration between different modeled projections, of anticipated generation rates in the future.  EPA's projections for future generation rates were closely linked to its assumptions concerning the future cost of electricity generation, focusing principally on fuel cost.  For the reasons identified in ARIPPA's comments on the First NODA, relative to the ARIPPA facilities, EPA incorrectly estimated the cost of coal refuse as a fuel, as reflected by current fuel costs incurred at the point of fuel production.  In addition, EPA's reliance on fuel cost as the primary basis for projecting future generating rates failed to adequately account for numerous other factors affecting generating rates.  [EPA-HQ-OAR-2009-0491-3903[1].1, pp.3-4]
Accordingly, as more fully detailed and substantiated in ARIPPA's comments on the Proposed Transport Rule and the First NODA, EPA's proposed approach toward unit-specific allocations under the Proposed Transport Rule is irreparably flawed.  EPA's modeling methodology, even following refinement through the First NODA, includes multiple inaccuracies.  More fundamentally, however, by basing its scheme on projected emission rates, EPA necessarily undertakes to project operating rates for relevant sources.  These efforts, in turn, are based upon assumptions which attempt to simplify operating characteristics across affected units, without regard to fundamental differences in operating patterns, contractual obligations, fuel costs and emission characteristics among the various EGU categories identified as subject to the Proposed Transport Rule.    [EPA-HQ-OAR-2009-0491-3903[1].1, p.4]
For these reasons, ARIPPA strongly recommended that EPA revert to its historic approach for allocating unit-specific allowances in the context of interstate transport regulation:  relying upon established heat input for affected sources.  By tying allowance allocations to reported heat input rates, EPA would substantially reduce inaccuracies inherent in projections which, in turn, rely upon assumptions regarding future operations.   [EPA-HQ-OAR-2009-0491-3903[1].1, p.4]
Significantly, however, the enhancements to the Proposed Transport Rule described in the Second NODA continue to reveal the fundamental flaw in EPA's base analysis within this rulemaking.  EPA has stated throughout the rulemaking docket that it has established proposed emission caps for the Proposed Transport Rule by considering available cost-effective controls for affected sources.  In essence, EPA undertook to establish unit-specific allocation protocols that would provide sufficient allowances to individual sources to enable such sources to comply with the final Transport Rule, if the sources limited emissions consistent with the application of available and cost effective controls for the source category.  [EPA-HQ-OAR-2009-0491-3903[1].1, p.5]
EPA has determined a state-specific sulfur dioxide emissions budget under the Proposed Transport Rule based in significant part on EPA's determination that electric generating units can achieve a certain SO2 emission rate by installation and operation of scrubbing technology as a 'cost effective' control.  In performing its analysis, however, EPA does not make a specific determination that such technology is 'available' for distinct EGU source categories; yet EPA's definition of affected EGUs extends beyond traditional large utility units.    [EPA-HQ-OAR-2009-0491-3903[1].1, p.5]
In fact, such scrubbing technology is not consistent with the SO2 emission control techniques used by coal refuse-fired CFB units.  CFB technology is inherently cleaner-burning and, therefore, more environmentally friendly, than traditional coal combustion technology.  Significantly, for CFB units, emission controls are primarily achieved in the combustion zone, not through back-end control equipment.  Specifically, the introduction of limestone into the circulating fluidized bed allows for the absorption of SO2 and significant reductions in SO2 emissions.  With respect to NOx, strict management of combustion zone characteristics limit the formation of NOx.  In both cases, the CFB technology emits substantially lower SO2 and NOx emissions - per ton of fuel, per MMBtu/hr of heat input and per MW/hr energy output - than conventional coal-fired EGUs.  EPA's background technical documents and preamble included within the regulatory docket, and relied upon in development of the Second NODA, identify dry scrubbing technology as 'cost effective' controls for EGUs.  For the reasons discussed above, coal refuse-fired CFB units do not utilize this technology.  Indeed, ARIPPA is not aware of any existing coal refuse-fired CFB unit that has been retrofitted to utilize dry scrubbing technology for sulfur dioxide control, nor is such technology otherwise 'commercially available' for this source type.   [EPA-HQ-OAR-2009-0491-3903[1].1, pp.5-6]
In particular, EPA's background documents reflect its technical analysis of the application of dry scrubbing technology to larger, conventional coal-fired utility units.  The analysis confirms that such technology is 'available' for this application, but the analysis does not extend to coal refuse-fired CFB units.[1]  Moreover, EPA determined the reasonable resultant sulfur dioxide emission rate based upon the application of scrubbing technology to these conventional PC units.  The docket for the proposed transport rule does not, however, reflect any similar determination or emission projections for the application of scrubbing technology to waste coal-fired CFB units.  [EPA-HQ-OAR-2009-0491-3903[1].1, p.6]
Even to the extent that these CFB sources can technically utilize scrubbing technology as a back-end control, such technology certainly does not correspond to EPA's analysis of cost effective controls for EGUs.  The economic analysis is dramatically altered when applied to smaller CFB units.  Specifically, the relative cost of control, per megawatt of energy generation, dramatically increases for smaller units, because the fixed costs of many aspects of the control technology are not substantially reduced for smaller units.  More importantly for these purposes, existing sulfur dioxide control methods, based upon limestone injection, already accomplish approximately 90% reduction of the sulfur contributing to sulfur dioxide emissions.  Therefore, the incremental cost of achieving modest additional sulfur dioxide reductions through the use of dry scrubbing technology is exhorbitant (in some cases an order of magnitude higher) when compared to the relative costs of control for traditional coal-fired units.  For these reasons, in evaluating the propriety of projecting sulfur dioxide emissions, and therefore calculating proposed allowances, for coal refuse-fired CFB units, the proposed application of dry scrubbing technology cannot in any way be described as 'cost effective,' as discussed and analyzed by EPA in the context of the Proposed Transport Rule, and as used by EPA in developing the allocation proposals under the Second NODA.  [EPA-HQ-OAR-2009-0491-3903[1].1, p.6]
Even without regard to any analysis by EPA through this rulemaking of the benefits or propriety of imposing additional sulfur dioxide controls on coal refuse-fired CFBs as part of the transport rule, and disregarding the severe economic impacts on these source types, many coal refuse-fired CFBs simply cannot reduce SO2 emissions to the levels associated with EPA's proposed allowance allocation (even using the refined heat input method) by application of dry scrubbing technology.  In other words, even if these sources installed the specific controls that EPA has identified as the basis for its proposed allowance allocations, the resultant SO2 emissions from many of these coal refuse-fired CFB sources would exceed the allowance allocations proposed by EPA for such sources under all methodologies identified in the Proposed Transport Rule, the First NODA and the Second NODA. [EPA-HQ-OAR-2009-0491-3903[1].1, pp.6-7]
The Proposed Transport Rule, even in consideration of the Second NODA, does not identify a justifiable regulatory approach for coal refuse-fired CFB units.
1. EPA's analysis of affected sources under the Proposed Rule does not reflect consideration of the unique characteristics of coal refuse-fired CFBs, and such sources should be excluded from the Transport Rule.  
EPA states within the Proposed Transport Rule that it evaluated alternative means of achieving emission reductions requisite to elimination of significant source contribution to interstate nonattainment.  EPA's analysis of emission source reportedly extended to 'EGUs, non-EGU point sources, stationary nonpoint sources, on-road mobile sources, and non-road mobile sources.'  See 75 Fed. Reg. 45238.  EPA's analysis reportedly confirmed that multiple source categories are responsible for significant generation of nitrous oxide ('NOx') and sulfur dioxide ('SO2') emissions, relative to the total emission inventories of the affected states.  However, EPA determined that it would be equitable, appropriate and consistent with statutory requirements to establish emission control requirements for those sources that significantly contribute to downwind nonattainment and can be cost effectively controlled.  EPA evaluated available emission controls for EGUs, and concluded that the objectives of the Proposed Transport Rule can most cost effectively be achieved by regulating only EGUs.  [EPA-HQ-OAR-2009-0491-3903[1].1, p.7]  
In fact, however, EPA's categorization of sources for purposes of the Proposed Transport Rule is inconsistent with the objectives stated by EPA for the Proposed Transport Rule, and results in allowance allocation proposals for certain EGUs that are not supported by EPA's analysis.  Specifically, the Proposed Transport Rule, including through the Second NODA, would apply allowance surrender requirements to any stationary fossil fuel-fired boiler or combustion turbine meeting the definition of EGU under the Proposed Transport Rule.  Importantly, EPA's analysis in support of the Proposed Transport Rule does not recognize distinctions among types of EGUs, on the basis of emissions characteristics, fuel source, operational design, emissions control options, or any other criteria.  In this way, the Proposed Transport Rule at once eliminates from regulation numerous significant NOx and SO2 emission sources based on categorical distinctions, while at the same time establishing a 'one-size-fits-all' approach to evaluating EGUs under the Proposed Transport Rule.  See 75 Fed. Reg. 45272 ('EPA determined for specific cost per ton thresholds, the emissions reductions that would be achieved in a state if all EGUs in that state used all emission controls and emission reduction measures available at that cost threshold' (emphasis added)).  EPA's proposed approach of regulating all EGUs under the Proposed Transport Rule, without giving any consideration to significant distinguishing characteristics among those EGUs, is inappropriate, and results in arbitrary applicability determinations.  Because the ARIPPA facilities are fundamentally different from traditional EGUs in ways that distinguish the ARIPPA plants from the traditional, large EGUs analyzed by EPA, EPA failed to demonstrate that sulfur dioxide controls that would be cost effective for larger PC plants would also be available and cost effective for the ARIPPA coal refuse-fired CFB units.   [EPA-HQ-OAR-2009-0491-3903[1].1, pp.7-8]
Unlike traditional EGUs, the ARIPPA facilities use CFB boiler technology to convert coal refuse and/or other alternative fuels, such as biomass, into electricity and steam.  Moreover, because emission controls are achieved through careful management of the combustion zone, CFB operators must maintain careful control over combustion zone characteristics in order to prevent a shift in concentration of other pollutants.  For example, to the extent a CFB operator increases limestone addition rates to attempt to achieve further SO2 emission reductions, such adjustments can affect characteristics in the combustion zone in a way that influences NOx formation, as well as particulate and carbon monoxide emission rates.  Further, these control techniques face asymptotic limitations in effectiveness.  At a critical point, the facility must add significantly greater quantities of limestone to achieve modest incremental reductions in SO2 emissions; for the reasons discussed above, such increases would also likely increase NOx and particulate emissions.  Moreover, for certain CFB plants, it is not even possible to add sufficient quantities of limestone to achieve the SO2 emission reduction requirements in the Proposed Transport Rule, due to design characteristics, heat transfer limits, and permit restrictions.    [EPA-HQ-OAR-2009-0491-3903[1].1, p.8]
EPA's failure to consider or analyze these distinct emission control characteristics in developing the Proposed Transport Rule, First NODA and Second NODA is evident in at least two respects.  First, the emission control technologies considered by EPA for application to EGUs under the Proposed Transport Rule do not readily extend to CFB technology, in the same manner and extent as applied to traditional coal-fired units.  EPA identified scrubbing technology as the basis for achieving necessary sulfur dioxide emissions control under the Proposed Transport Rule.  As more fully discussed above, while back-end emission control technology can be applied to CFB units under certain situations, unique boiler design and operational criteria create additional challenges to effective operation of these emission control systems.    While scrubber technology may reduce emissions from traditional coal-fired utility units to emission rates equivalent to EPA's proposed allocation levels under the Second NODA, the technology has not been commercially demonstrated as a retrofit application to reduce SO2 emissions from an existing coal refuse-fired CFB to emission levels corresponding to EPA's allowance allocation proposal.    [EPA-HQ-OAR-2009-0491-3903[1].1, p.8]
Second, EPA's analysis of the cost effectiveness of SO2 controls is also inapplicable to ARIPPA facilities.  Because the CFB technologies are inherently cleaner burning, the quantity of emissions available for back-end control is substantially less than conventional PC units.  In this way, the denominator of the cost effectiveness calculation is substantially reduced on a relative scale.  By contrast, the capital and operational costs associated with the back-end controls are not substantially reduced for these smaller facilities, because of the inherent fixed cost capital requirements of these systems, and some unique issues posed by the distinct CFB technology.   Further, unlike traditional utility units, many ARIPPA facilities are subject to long-term, fixed price contracts, which prevent these facilities from passing through the additional control costs to any consumer. [EPA-HQ-OAR-2009-0491-3903[1].1, pp.8-9]
EPA's cost effectiveness analysis under the Proposed Transport Rule fails to account for these significant distinctions in any material way.  In this regard, EPA's determination that EGUs -- as a single category of sources -- can be cost effectively controlled consistent with the objectives of the Proposed Transport Rule does not, in fact, apply to the CFB technology utilized by ARIPPA facilities, any more than it would apply to non-EGU stationary sources excluded by EPA from regulation under the Proposed Transport Rule.2 [EPA-HQ-OAR-2009-0491-3903[1].1, p.9]
For these reasons, the allocation scheme developed by EPA through the Second NODA fails to satisfy EPA's stated objective of providing sufficient allowances to accommodate emissions form affected sources employing 'cost-effective' controls.  Even to the extent that scrubber technology is technologically available and applicable for coal refuse-fired CFBs, the technology does not comport with EPA's analysis of cost effective controls, and would not, in any event, reduce SO2 emissions to the extent necessary to enable these sources to limit emissions consistent with the allowance allocation proposed by EPA through the Second NODA.  [EPA-HQ-OAR-2009-0491-3903[1].1, p.9]
Likewise, under the second part of EPA's 'significant contribution' analysis, EPA's determination that EGUs may be cost effectively controlled simply does not apply to the ARIPPA facilities.  Most significantly, the emission reduction techniques identified by EPA -- scrubbers and fuel switching to lower sulfur fuels -- are either inapplicable to the ARIPPA facilities or would necessitate a substantially different control analysis.  Indeed, ARIPPA is not aware of any CFB boiler firing coal refuse that has been retrofitted with a dry scrubber that would enable such unit to achieve the SO2 reductions required by the Proposed Transport Rule.  [EPA-HQ-OAR-2009-0491-3903[1].1, p.9]
Instead, the ARIPPA facilities are more closely related to non-EGUs, such as biomass units, which EPA clearly distinguishes from traditional EGUs in the Proposed Transport Rule.  EPA's basis for distinction under the Proposed Transport Rule is that non-EGUs cannot achieve comparable cost effective emissions reductions.  Specifically, relative to its evaluation of the relevant NAAQS for PM2.5, EPA states that its 'review of the costs of EGU and non-EGU controls resulted in a conclusion that substantial SO2 and NOx reductions from EGUs are available at a cost per ton that is lower than the cost per ton of non-EGU controls.'  75 Fed. Reg. 45300.  See also 75 Fed. Reg. 45272 ('EPA believes there are little or no non-EGU reductions available at the cost thresholds used in [the Proposed Transport Rule]').  Therefore, because EPA proposes to distinguish source categories on the basis that specific design and/or operating characteristics make it economically infeasible for such source categories to comply with the emission reduction requirements in the Proposed Transport Rule, ARIPPA's CFB units should not be included among the sources subject to regulation under EPA's Transport Rule. [EPA-HQ-OAR-2009-0491-3903[1].1, pp.9-10]
These deficiencies in EPA's analysis as applied to the ARIPPA facilities need not be fatal to the Proposed Transport Rule, however.  Upon recognizing the unique characteristics of the ARIPPA facilities, based primarily on use of CFB technology and combustion of coal refuse, it is clear that EPA's analysis of 'significant contribution' under the Proposed Transport Rule is inapplicable to the ARIPPA plants.  Specifically, EPA's evaluation depends, in material part, upon an evaluation of the emissions and the cost effectiveness of available controls for EGUs.  In the context of emission impacts, the emissions from the ARIPPA facilities are materially less than traditional coal-fired EGUs.  Therefore, to the extent that EPA evaluates the air quality impacts from EGUs as a single category, without distinction for the unique emission profiles of these facilities, EPA inappropriately and inaccurately concludes that the ARIPPA EGUs contribute to downwind nonattainment to the same extent as traditional EGUs.  Instead, the emission characteristics of the ARIPPA CFB units distinguish these sources from traditional coal-fired EGUs.  In fact, evaluation of emission characteristics more closely aligns the ARIPPA facilities with the many emission sources that EPA proposes to exclude from regulation under the Proposed Transport Rule.  [EPA-HQ-OAR-2009-0491-3903[1].1, p.10]
For these reasons, EPA's analysis as reflected in the Proposed Transport Rule does not support a finding that the ARIPPA facilities significantly contribute to nonattainment in downwind states, nor that emissions from ARIPPA facilities can be cost effectively controlled.  To conclude otherwise would be inconsistent with both the D.C. Circuit Court's decision vacating CAIR, and EPA's stated objectives for implementing the Proposed Transport Rule.  See 75 Fed. Reg. 45227.  Finally in this context, emissions from the ARIPPA plants comprise a very small portion of Pennsylvania's total emissions budget.  As such, a determination that the ARIPPA facilities are among a relatively small percentage of facilities significantly contributing to downwind nonattainment is not consistent with the emission inventory for Pennsylvania.  Similarly, exclusion of the ARIPPA facilities from the Proposed Transport Rule would not have a meaningful impact on EPA's analysis of projected downwind impacts.  [EPA-HQ-OAR-2009-0491-3903[1].1, p.10]
Therefore, EPA should exclude these sources from the Transport Rule.  EPA's approach for allowance allocation identified through the Second NODA would likely be sufficient and appropriate for traditional coal-fired EGUs.  [EPA-HQ-OAR-2009-0491-3903[1].1, p.10]
2. To the extent that EPA determines to subject all EGUs to regulation under the Transport Rule, the proposed allocation scheme must ensure that sources that control emissions consistent with EPA's analysis of cost effective controls receive an adequate allowance allocation.  
EPA carefully enumerated 'key guiding principles' within the Proposed Transport Rule in determining to propose regulation of specific sources.  75 Fed. Reg. 45226-227.  Among these guiding principles, EPA states that its proposed regulatory approach would provide for 'cost effectiveness,' as well as providing incentives and flexibility to the regulated community.  In addition, through the Second NODA, EPA expresses the need, raised by many commenters, to ensure that the regulation provides appropriate incentives for emission reductions, and equitably distributes the burden among appropriate emission sources.   For the reasons discussed above, these guiding principles are not satisfied with respect to the ARIPPA facilities, predominately because the proposed emission reductions cannot be achieved cost effectively, and the regulatory standards would establish requirements that these facilities cannot satisfy.  Similarly, because of the relatively low emissions profiles for these ARIPPA facilities, EPA's guiding principle of 'appropriately identify[ing] necessary upwind reductions,' id., would not be achieved by further regulating the relatively low emissions from the ARIPPA facilities.  [EPA-HQ-OAR-2009-0491-3903[1].1, pp.10-11] 
The significance of EPA's approach under the Proposed Transport Rule is substantially magnified because of EPA's proposed restrictions on allowance transfer.  By severely limiting opportunities for securing allowances necessary for compliance demonstrations, EPA would restrict the ability of sources to comply with allowance obligations by more cost effectively securing greater emission reductions at other sources.  These constraints are least severe for companies that operate multiple emission units, at least within the same state, since the freedom to transfer allowances among such units is greatest under EPA's various trading options.  By contrast, smaller facilities with single affected units are afforded no such option.  Where such sources also cannot cost effectively reduce emissions at the affected source because of the unique operating, design or fuel characteristics, as in the case of the coal refuse-fired CFB units, such facilities may not be afforded any compliance option under the Proposed Transfer Rule.   [EPA-HQ-OAR-2009-0491-3903[1].1, p.11]
If EPA nonetheless determines that these unique, smaller coal refuse-fired CFBs should be regulated under the Proposed Transport Rule, then EPA must expand its analysis of cost effective controls to establish an allocation scheme that ensures that these sources will be allocated sufficient allowances to accommodate emission rates associated with application of cost effective controls.   [EPA-HQ-OAR-2009-0491-3903[1].1, p.11]
As an alternative to adjusting the allocation scheme for different EGU source categories based upon source specific operating or emission characteristics, EPA could reasonably determine to leave such refined analyses to individual states.  Although the Second NODA provides an expedited opportunity for states to develop unique allocation methods, the baseline allocation proposal developed by EPA under the FIP may nonetheless apply in individual states for some period of time.  Further, having established a baseline allocation, it would be more challenging for individual states to revise such allocations based upon source category specific considerations.  In order to avoid these concerns while also delegating to states the specific determination of category specific requirements, EPA could provide an additional allowance set-aside within each state budget for redistribution for these purpose.  This set-aside would be in addition to the new unit set-aside already contemplated by the Proposed Transport Rule and proposed FIP.  ARIPPA proposes that such set-aside be set at a minimum of 3% of each total state budget, and established for the purpose of facilitating state-specific redistribution of allowance allocations based upon EGU source category-specific considerations that are not reflected in the baseline allocation developed by EPA.  In addition, any allowances set aside but not allocated to new sources should be made available for this redistribution allowance pool, as well.  [EPA-HQ-OAR-2009-0491-3903[1].1, p.12]
In the preamble to the Proposed Transport Rule, EPA explained that, 'by promulgating these Transport Rule FIPs, EPA would in no way affect the right of states to submit, for review and approval, a SIP that replaces the federal requirements of the FIP with state requirements. 75 Fed. Reg. 45342. EPA further recognized that
[i]n CAIR, EPA allowed the states to replace the CAIR FIP with SIPs and provided substantial flexibility.  Again, EPA wants to offer states substantial flexibility for addressing the Section 110(a)(2)(D)(i)(I) transport issues though a SIP should they choose to do so.  The EPA's intent is to provide states with substantial flexibility in implementing these requirements.  Id. [EPA-HQ-OAR-2009-0491-3903[1].1, p.13]
Within its comments on the Proposed Transport Rule, ARIPPA strongly endorsed EPA's stated intention to ensure states substantial flexibility in implementing the requirements of the Transport Rule.  Consistent with this approach, states should be permitted under the Transport Rule to allocate allowances to affected EGUs in any manner, and on any basis, they deem appropriate to satisfy their established emissions budgets.  States should not be constrained to allocate allowances among affected EGUs based on an individual source's relative contribution to the state's total emissions budget, in the manner used by EPA in allocating allowances under the proposed FIP.   [EPA-HQ-OAR-2009-0491-3903[1].1, p.14]
In addition, states must be afforded every available opportunity to expedite SIP development and authorization.  EPA stated within the Proposed Transport Rule that initial emissions reductions for NOx and SO2 would be required in 2012, followed by a second phase of reductions in 2014.  75 Fed. Reg. 45215-216.  The initial compliance deadline of January 1, 2012, does not provide states adequate time to develop and implement state-specific strategies for achieving their emissions budgets, as authorized under the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3903[1].1, ,p.14]
EPA clearly states in the Proposed Transport Rule that it 'wants to offer states substantial flexibility for addressing the Section 110(a)(2)(D)(i)(I) transport issues though a SIP should they choose to do so.'  75 Fed. Reg. 45342.  However, affected states would not have sufficient time to develop state-specific regulations and then satisfy all elements of the SIP-revision approval process, and secure EPA approval of the SIP, all before January 1, 2012.  See 75 Fed. Reg. 45342 ('The Transport Rule FIPs would be in place in each covered state until a state's SIP was submitted and approved by EPA to replace a FIP.'); 75 Fed. Reg. 45227 (recognizing that '[b]oth EPA and state resources are limited and EPA recognizes the importance of developing requirements that make efficient use of limited EPA and state resources').     [EPA-HQ-OAR-2009-0491-3903[1].1, p.14]
The imposition of this near-term compliance deadline would be particularly challenging for certain EGUs, like the ARIPPA plants, whose only options for reducing emissions would necessarily require drastic changes to technology and operations (to the extent that any such changes are even feasible).  ARIPPA facilities and other similar plants cannot simply make relatively minor technological or operational changes through the addition of traditional add-on controls or fuel switching.  Therefore, any compliance plan designed to meet the stringent emissions reductions required under the Proposed Rue would necessitate a substantial period of time to implement. [EPA-HQ-OAR-2009-0491-3903[1].1, p.14]         
The inability of states to finalize state-specific SIP-based programs for implementing the Transport Rule would not merely postpone transition from a FIP-based to a SIP-based program.  Instead, affected sources must pursue compliance options based upon the regulations that will be effective at the earliest time.  Affected facilities would not likely have the option of implementing a transitional approach during the first phase of regulation that could simply be undone and replaced with a longer term strategy once the state SIP is promulgated and approved.  For this reason, it is critical that states be afforded a reasonable opportunity to finalize and establish state-specific allocation approaches before affected sources would be subject to the promulgated standards.  [EPA-HQ-OAR-2009-0491-3903[1].1, p.14]
Even should EPA promulgate authorization for partial SIPs in accordance with the Second NODA, EPA should nonetheless extend the initial compliance deadline in the Proposed Transport Rule until January 1, 2015 (with the second phase of emissions reductions beginning in January 2017), as ARIPPA proposed through its initial comments on the Proposed Transport Rule.  Such reasonable time extension would allow affected states and EGUs within those states sufficient time to develop and implement approved SIPs and compliance plans, respectively.  Specifically, EPA should allow states until January 1, 2015, to develop SIPs and complete the SIP-approval process, and any FIP should not become effective unless the state has failed to implement an appropriate SIP by that date.  The states and EGUs affected by the Proposed Rule should not be penalized as a result of the delay in the regulatory development process associated with the Court's vacatur of CAIR.  Further, the continued emission reductions mandated by CAIR would mitigate any adverse impacts associated with the postponement of the implementation of the Transport Rule.  Indeed, the application of CAIR would result in greater NOx emission reductions than the Proposed Transport Rule.  [EPA-HQ-OAR-2009-0491-3903[1].1, p.15]
[1] In fact, ARIPPA is not aware of any supplier of dry scrubbing technology that will provide assurances or supported estimates that such technology, if retrofitted as a back-end control device for an existing coal refuse-fired CFB unit, will achieve the degree of sulfur dioxide emission reduction that are achieved by larger, traditional coal-fired PC units, or that would correspond to the emission rates utilized by EPA in setting allowance allocations under the Second NODA.
[2] In evaluating emission control options under the Proposed Transport Rule, EPA also considered opportunities for sources to engage in fuel switching as part of EPA's determination that EGUs may cost effectively reduce SO2 emissions.  See 75 Fed. Reg. 45273.  Initially, EPA's analysis of cost-effectiveness of fuel switching is limited to bituminous and sub-bituminous coal; this analysis does not consider non-traditional coal used as fuel, notably including coal refuse, which is distinguishable from other coal species in terms of sulfur content and other key characteristics.  In addition, for the technological, legal, economic and practical reasons discussed by ARIPPA within its comments on the Proposed Transport Rule, the ARIPPA facilities cannot simply switch from using coal refuse to a lower-sulfur fuel in order to satisfy the stringent emission reduction requirements in the Proposed Transport Rule.
Response: 
The commenter cites "stringent emission reduction requirements" but does not appear to recognize that these requirements are imposed at the state level, not at the unit level.  EPA maintains that its applicability criteria are reasonable and that multiple types of EGUs offer a variety of cost-effective reductions within each state that the air quality-assured trading programs can achieve in a least-cost manner.  The Transport Rule trading programs provide multiple unit-level compliance options, including installation of less costly pollution controls and the purchase of allowances where necessary to cover emissions.
Organization: Associated Industries of Massachusetts (AIM)
Comment: 
Associated Industries of Massachusetts (AIM)
As a result AIM is concerned about fuel diversity, reliability and the potential impacts to electric prices in Massachusetts as a result of CATR implementation as proposed. For example, although EPA has proposed alternative allowance allocation options in this NODA, the resultant allocations are still based on the state budgets established in the original CATR proposal and are simply a redistribution of the originally-proposed state budgets. As a result, electric generating units in Massachusetts are severely under-allocated. The original proposal contained numerous inaccuracies in assumptions specific to electric generating facilities in Massachusetts that were relevant in the determination of the state emission budgets, leading to a significant underestimation of the state SO2 and NOx emission budgets, and to unit allocations under those budgets that were grossly insufficient. With this NODA, these issues persist. EPA data indicates that the MA statewide EGU emissions for 2009 for SO2 and NOx were 35,143 tons and 7,870 tons, respectively. However, the proposed CATR MA state budget for SO2 and NOx is merely 7,902 and 5,960 tons. In 2012 and beyond, with a SO2 budget which is one quarter the size of actual emissions, it is difficult to imagine how the electric market will function properly in Massachusetts. [EPA-HQ-OAR-2009-0491-3906[1].1, p.2]
Furthermore, the CATR rules are not intended to require facilities to install controls beyond what is already planned in the first two years of the program. These rules should allow well controlled units to burn coals that the already installed controls were designed for and to allow economic dispatch of these units into the marketplace. [EPA-HQ-OAR-2009-0491-3906[1].1, p.2]
Regardless of which allocation method is applied, there continues to be a pressing need for EPA to correct the deficiencies with respect to the determination of state emission budgets under the proposed rule. Failure to do so will result in even fully controlled facilities that have spent or are planning to spend significant capital for environmental controls not being allocated sufficient allowances to fully operate. With Massachusetts sources located in the smaller of two separate SO2 trading zones and the inability to trade allowances across zones, it will be impossible for Massachusetts electric generating units with severe under allocations to procure enough allowance to operate. These units will not be able to bid into the market place because they do not have or cannot procure enough allowance to operate in compliance with CATR and will eventually be forced shut down. Fuel diversity and reliability would be compromised in Massachusetts. EPA should fix its inaccurate assumptions and reallocate additional allowances to the state of Massachusetts and its electric generating units. To do otherwise would have a grave impact on electric markets in Massachusetts, causing yet higher electric prices and in turn a grave impact on the Massachusetts industries and businesses that are already struggling to overcome one of the toughest economic recessions in decades. [EPA-HQ-OAR-2009-0491-3906[1].1, pp.2-3]
Response: 
EPA notes that Massachusetts was not found to have emissions that significantly contribute nonattainment or interfere with maintenance in another state in the analysis for the final Transport Rule, as described in Preamble Section V.D.2. Electric generating units in Massachusetts must continue to meet monitoring and reporting requirements only to the extent the units are subject to Part 75 under some other program (such as the Acid Rain Program or a state adopted program requiring such monitoring and reporting). This makes moot the other issues raised by AIM. 
Organization: Association of Electric Companies of Texas (AECT)
Comment: 
Association of Electric Companies of Texas (AECT)
EPA's Inclusion of Texas in the Clean Air Transport Rule (CATR) Ozone Season NOx Program is Not Justified by Appropriate Data
EPA's proposed inclusion of Texas in the CATR ozone season NOx program is based on the unjustified and erroneous conclusion that Texas NOx sources are impacting Baton Rouge's ability to demonstrate attainment with the 1997 ozone standard. The overestimation of NOx emissions by some 19,000 tons per year from the Houston-Galveston-Brazoria ozone nonattainment area is improperly being used to support that conclusion. Moreover, in the September 9, 2010, Federal Register, EPA issued its final decision that the Baton Rouge area has, in fact, demonstrated attainment with the 1997 ozone standard. Thus, there is no basis for the continued inclusion of Texas in the CATR ozone season NOx program. [EPA-HQ-OAR-2009-0491-3981[1].1, pp.1-2]
EPA Should Establish Reasonable Timelines for Controls for Compliance
The timing of the development and implementation of CATR is at EPA's discretion, in that EPA is under no court-ordered schedule. Moreover, CAIR remains in place while CATR is being developed. Thus, there seems little reason to compress the CATR rulemaking process and initiating CATR in 2012. [EPA-HQ-OAR-2009-0491-3981[1].1, p.2]
It is clear that a significant amount of work is needed to accurately compile and model emissions; accurately assess impacts; and document projections and methodologies. Additionally, aEPA needs to account for adequate lead time for companies to plan, procure equipment, and implement the CATR requirements, should EPA proceed with adoption of CATR. [EPA-HQ-OAR-2009-0491-3981[1].1, p.3]
Impact in Texas
Texas generates almost 80% more electricity than any other state, which is about the same amount of electricity as is generated in the United Kingdom. The state depends on coal-fired power plants to provide reliable and affordable baseload electricity to meet the ever-growing demand. Moreover, the Electric Reliability Council of Texas (ERCOT) manages the largest competitive electric market in the country and maintains a fuel diverse portfolio of power plants, with about 40 percent of electricity generated by coal. Fuel diversity is critical for maintaining reliable and affordable electricity in the state. [EPA-HQ-OAR-2009-0491-3981[1].1, p.3]
Moreover, 12 percent of electricity that is generated in Texas is generated using native Texas coal (lignite), which is an amount equal to the electricity generation of the entire state of Wisconsin. If CATR was to lead to the switch from native Texas coal to more imported coal and natural gas, it would not only negatively impact the electric reliability and affordability that is needed to meet Texas' large and ever increasing electricity demand, but would also produce severe, negative impacts, especially in parts of the state where the local economy is dependent on native Texas coal-fired electric generation and native Texas coal mining. [EPA-HQ-OAR-2009-0491-3981[1].1, p.3]
Response: 
As discussed in sections III, V, and VI of the preamble to the final Transport Rule, EPA has updated and improved the modeling inputs and platforms used to identify states with contributions to downwind nonattainment or maintenance receptors that meet or exceed the 1% air quality thresholds. These updates -- which include a number of updates to the modeling inputs for Texas -- were made based on public comments received on the proposed rule and the subsequent notices of data availability (NODAs) and other standard updates.
Regarding including Texas for Ozone Season NOx under the final Transport Rule, AECT comment of overestimating NOx emissions in the HGB area are discussed in the Emissions Inventory RTC document, specifically in a response to a comment from the Texas Council on Environmental Quality. Regarding the Baton Rouge receptor, please see EPA's response to Luminant's comment in RTC section IV.C.5. 

Regarding the AECT comment on electric reliability, see section V.D.2.g in this RTC document and the Resource Adequacy and Reliability in the IPM Projections for the Transport Rule TSD in the Transport Rule docket.
Regarding the AECT comment about benefits and economic impacts of the Transport Rule, see sections VIII and XII of the preamble and see the Regulatory Impact Analysis (RIA).
Organization: Birchwood Power Partners, L.P.
Comment: 
Birchwood Power Partners, L.P.
Birchwood Power submitted comments on the proposed rule and Federal Implementation Plan To Reduce Interstate Transport of Fine Particulate Matter and Ozone, Clean Air Transport Rule (hereinafter, 'Proposed Transport Rule'), 75 Fed. Reg. 45210 (Aug. 2, 2010).  See letter from Julie Caiafa to the Honorable Lisa P. Jackson, re: Proposed Rule; Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone, EPA-HQ-OAR-2009-0491 (Oct. 1, 2010, Document ID No. EPA-HQ-OAR-2009-0491-2706 (hereinafter, 'October 1, 2010 Comments).  In our October 1, 2010 Comments, Birchwood Power expressed our concern that EPA's proposed allocation of annual NOx allowances would be insufficient to meet Birchwood's needs when demand for electricity returned to levels experienced prior to the recession.  See October 1, 2010 Comments, 2-3.  As Birchwood Power explained, it is operated pursuant to the long-term contract that requires it to operate whenever called to dispatch by Dominion, but the contract does not allow for the recovery of the costs for emissions allowances. Id., at 3.  Birchwood Power suggested ways that EPA could provide relief to long-term contract generators that cannot pass along the costs of allowances to their power purchasers, as Congress has previously done under the Clean Air Act's ('CAA's') Acid Rain Program and in legislation considered during the 111 th Congress to address greenhouse gas emissions. Id., at 3-4. [EPA-HQ-OAR-2009-0491-3940[1].1, p.2]
Response: 

See section VII.D of the preamble.  The final rule adopts a methodology for allocating allowances to existing units based on the average heat input of the three highest years of heat input during 2006 to 2010.  Because this time period includes several years preceding the "recession" period (2009 through the first half of 2010) for which the commenter claimed its unit had low heat input, the allocations for the commenter's unit are based on the unit's heat input before, not during, such "recession" period.   Consequently, there is no basis for the commenter to claim that the unit's allocation will be insufficient because of the heat input in the 3-year period used to calculate the allocation is unrepresentative or to claim that the unit should receive the "relief" suggested by the commenter, i.e., additional allocations from the new unit set-aside.  
Organization: Buckeye Power, Inc.
Comment: 
Buckeye Power, Inc.
Buckeye objects to EPA's contemplated 2012 deadline for meeting the proposed CATR's initial emissions limits. This abbreviated deadline is deficient for several reasons: first, this deadline does not allow adequate time for facilities that will need to install control technology to meet emissions limits; second, this deadline does not give states adequate opportunity to submit State Implementation Plans ('SIPs') designed to maximize the market forces that have proven to be the most efficient method to reduce emissions; and third, this deadline is unlikely to be met in any event given inevitable litigation over the issuance of this rule and a probable stay associated with such litigation. On the other hand, a 2014 compliance deadline addresses each issue in that it gives facilities that must install control technology sufficient time to have such technology ordered and installed; gives states adequate opportunity to submit SIPs appropriate for their particular circumstances; and gives adequate time for the rule to take effect and for any litigation to be resolved, which ultimately speeds the reduction of emissions impacting downwind states. [EPA-HQ-OAR-2009-0491-3900[1].1, p.5]
Buckeye endorses EPA's proposal to treat units that become operational on or after January 1, 2009 as 'new units' for several reasons. First, state budgets were set based on units in existence prior to that date, and it would be inequitable to set a statewide budget and then divide that budget by new units. Second, new units, including those installed on or after January 1, 2009, can less expensively install control technology in the construction phase than existing units can retrofit such technology. Therefore, it makes sense to place those units installed on or after January 1, 2009 in a separate category. Finally, units installed on or after January 1, 2009 do not have sufficient historical data to establish baselines. Therefore, Buckeye supports EPA's approach to treat units installed on or after January 1, 2009 as 'new units.' [EPA-HQ-OAR-2009-0491-3900[1].1, p.6]
EPA's proposed FIP is contrary to the Clean Air Act because it does not give states the opportunity to submit SIPs conforming to the proposed CATRs overall state reduction mandates. The Clean Air Act grants states up to three years to submit SIPs to remedy interstate transport, in this case to meet proposed CATR reduction mandates. 42 U.S.C. § 74l0(a). In light of the invalidation of the Clean Air Interstate Rule, this period should begin to run when EPA issues a final CATR. The Clean Air Act does not authorize EPA to determine source or unit obligations, only to determine statewide reduction levels. [EPA-HQ-OAR-2009-0491-3900[1].1, p.6]
EPA would take away from the states, who are in the best position to determine the proper individual unit allowance allocations, the ability to determine how best to meet overall state reduction levels. In some cases, meeting individual unit allowance limits under EPA's preferred CATR approach would be difficult, if not impossible. States may be able to meet the required overall state reduction levels through properly tailored SIPs, which take into account differences between individual units performance in the applicable state. States, rather than EPA, are best able to take into account the characteristics of individual generating units within their jurisdictions. Buckeye submits that imposition of a FIP is unreasonable, arbitrary, and contrary to law. [EPA-HQ-OAR-2009-0491-3900[1].1,p .6]
EPA should delay implementation of the Clean Air Transport Rule until 2014, allowing states the necessary amount of time to submit approvable SIPs to EPA. [EPA-HQ-OAR-2009-0491-3900[1].1, p.6]
Response: 
Thank you for your comment.Organization: City of Dover, Delaware
Comment: 
City of Dover, Delaware
The City previously submitted comments in response to the Proposed Transport Rule, expressing concern over a number of issues, especially the proposed allowance allocation methodology. The City felt that the proposed methodology inaccurately projected future emissions by failing to account for the variable amounts units run and emit in a given year, particularly smaller peaking units. As the amount of time a peaking unit runs is determined by a number of factors, which can vary greatly from year to year, the City felt that a longer interval of time should be used to establish a historic baseline for projecting future emissions. [EPA-HQ-OAR-2009-0491-3881[1].1, p.1]
Response: 
EPA's analysis in the final rule did not find that emissions in Delaware significantly contribute to nonattainment or interfere with maintenance of the assessed NAAQS in another state.
EPA has concluded that the method and time period used to determine historic heat input rates, as described in Preamble Section VII.D, is reasonable and allows for a representative sample of past operating history to be considered for purposes of allowance allocation to existing units.
Organization: City of Hamilton
Comment: 
City of Hamilton
Hamilton continues to maintain, consistent with earlier comments submitted by Hamilton as well as comments submitted by Ohio EPA, that the proposed Transport Rule, and now the NODA, do not include sufficient allowance allocations. As such, Hamilton is unable to comment substantively on the methodologies contained in the NODA since both are predicated on inadequate allowance pools for Ohio. [EPA-HQ-OAR-2009-0491-3984[1].1, p.1]
Hamilton urges U.S. EPA to consider the impact of an insufficient allowance pool on municipal and small generators like Hamilton. [EPA-HQ-OAR-2009-0491-3984[1].1, p.1]
Response: 
With regard to how state budgets were determined, please see Preamble Section VI.
Organization: City of Springfield, Illinois, Office of Public Utilities
Comment: 
City of Springfield, Illinois, Office of Public Utilities
CWLP agrees with the USEPA's method of handling the addition of new generation and the eventual retirement of existing generation. The addition of the retiring unit's allowance allocation to the New Unit Set-Aside (NUSA), rather than the existing unit pool, would provide a method of NUSA growth. This would be vital, given that units deemed to be a part of the NUSA would remain in that classification indefinitely and would be in competition for allowances with any future generation units. [EPA-HQ-OAR-2009-0491-3885[1].1, p.2]
CWLP supports the efforts of the USEPA to craft reasoned and efficacious regulations based upon the Clean Air Act that preserve and improve interstate air quality. [EPA-HQ-OAR-2009-0491-3885[1].1, p.2]
Response: 
EPA thanks City of Springfield, Illinois, Office of Public Utilities for their comments
Organization: City of Tallahasse
Comment: 
City of Tallahasse
The City of Tallahassee has serious concerns with the aggressive implementation schedule and specific electric generation unit (EGU) reduction requirements proposed in the Clean Air Transport Rule (CATR) also known as the Transport Rule. The January NODA provides a 30- day time frame in order to provide comments on the two proposed alternative methodologies. Given the amount of extremely technical and complex documents that comprise the Technical Support Documents, numerous modeling files and spreadsheets, and the three distinct previously proposed regulatory alternatives, its nigh impossible for any utility to devote extensive resources on developing significant comments on the impact of the rule, nor identify significant errors within these documents, within the 30-day timeframe as it relates to the totality of the Transport Rule. In addition, due to the piecemeal delivery of the items above, affected parties, such as the City, are effectively denied the ability to participate in the rulemaking process. The City is hereby requesting the EPA to reconsider the aggressive implementation schedule and re-publish a second proposal that addresses all stakeholder comments and takes into account the correction of erroneous information that was used to base the originally proposed allocations in the Transport Rule. [EPA-HQ-OAR-2009-0491-3912[1].1, p.2]
The City would like to reiterate its previous comment that the Transport Rule need not be in place by 2012. To implement a 2012 compliance obligation by a rule that is as far-reaching as the Transport Rule is unrealistic and problematic. Generally, the EPA has insisted that emission levels required in 2012 would occur even in the absence of the Transport Rule, primarily relying on the emission reductions that have resulted from compliance with the Clean Air Interstate Rule (CAIR). In order to meet our emission obligations under the currently proposed amount of allocations in the Transport Rule, the City would be forced to perform either upgrades to existing control equipment, new selective catalytic reduction (SCR) installation on one of our larger units, increased ammonia use in existing SCR control equipment, and quite possibly suspend the retirement of a more inefficient unit (Purdom 7 ORIS 689 scheduled to be retired no later than December 31, 2013) while such work was done, notwithstanding the added expense to our customers. There are a number of concerns with this: permitting obligations that would have to be met; the process of obtaining bids and awarding contracts; and negotiating new ammonia slip limits in current permits, may also be an issue. [EPA-HQ-OAR-2009-0491-3912[1].1, p.2]
In the state of Florida, a fair number of emissions units that would be regulated under the Transport Rule hold permits that require compliance with ammonia slip limits, which were negotiated during the Best Available Control Technology process. The City is requesting information on what measures EPA considered for ammonia slip condition relief for these facilities and/or what pressure will EPA bring to bear against permitting agencies that have placed ammonia slip limits in permits. Resolving this matter would require additional time so that facilities would not be forced to operate in a manner which would require operating more inefficient units for fear of violating ammonia standards. [EPA-HQ-OAR-2009-0491-3912[1].1, p.2]
Response: 
The commenter is mistaken in the assumption that unit operations are governed by Transport Rule allowance allocations.  Under the Transport Rule's air quality-assured trading programs, sources may acquire the number of allowances necessary to cover emissions during the control period; no source's emissions are limited by the number of allowances initially allocated.  Therefore, the Transport Rule does not prevent the commenter's units from operating within the bounds of other applicable regulations.  In addition, the Transport Rule's state budgets for NOX are not predicated on any installation of new SCRs beyond those already scheduled for other reasons (and, as described in Chapter 7 of the RIA, EPA does not project any new SCRs being built in response to the Transport Rule).
Organization: Clean Energy Group
Comment: 
Clean Energy Group
As stated in our October 1, 2010 comments, the Clean Energy Group supports the proposed Transport Rule. The proposed rule will achieve important air quality, health, and economic benefits utilizing EPA's current authority. It is critical that EPA implement the rule as expeditiously as practicable to ensure realization of these benefits. We are committed to working with EPA to ensure the Agency can implement the Transport Rule by January 1, 2012, and to that end, we offer these comments on the January 7 NODA. [EPA-HQ-OAR-2009-0491-4002[1].1, p.1]
As we noted in our comments on the proposed rule, the language of the Clean Air Act provides EPA with broad authority to implement allocation methodologies, and there is no strong policy or legal reason that the methodology for determining state budgets and the methodology for distributing allowances to units need to be the same. By maintaining the proposed methodology for determining the state budgets,EPA is consistent with the D.C. Circuit's decision requiring that state budgets be based on each state's significant contribution. [EPA-HQ-OAR-2009-0491-4002[1].1, p.2]
As we explained in our comments on the proposed rule, the Integrated Planning Model (IPM) used to project emissions under the proposed allocation approach does not consider a range of non-economic factors that may influence a company's decision to operate particular types of units or for the respective Independent System Operator (ISO) to call upon specific units. As a result, the modeling can create unrealistic scenarios for some individual units, such as ignoring dispatch requirements of EGUs subject to power purchase agreements, running natural gas combined cycle units at higher utilization than can be accommodated by the local natural gas pipeline network, and not running oil-fired units that are required to operate to meet load requirements. While these distortions of the electricity market are masked when data are aggregated at the state level for setting state budgets, the modeling results in unrealistic or infeasible outcomes when used at the unit level to allocate allowances. By contrast, a historic heat input basis for allocating the state budgets avoids these problems and thus strengthens the legal basis for the rule. [EPA-HQ-OAR-2009-0491-4002[1].1, p.2]
Response: 
Thank you for your comment.Organization: Cleco Corporation
Comment: 
Cleco Corporation
I. EPA Must Abandon Its Timeframe and Issue a Comprehensive Supplemental Proposed Rule for Comment.
With each new NODA, EPA increases the uncertainty surrounding its proposed replacement for CAIR  -  the proposed Transport Rule. NODA-3 further increases that uncertainty. Prior to NODA-3, EPA had proposed: (i) three different remedies; (ii) two different IPM versions; (iii) three different fuel cost assumptions; and (iv) revised emission inventories. These variables compound the uncertainty about what we are being asked to comment on. Additionally, EPA has not provided the information needed to understand how the NODAs (e.g., the revised fuel cost assumptions in the first NODA or the revised emission inventories in the second NODA) will impact the underlying rule. [EPA-HQ-OAR-2009-0491-4007[1].1, p.2]
With NODA-3, EPA adds to this list of variables three potential unit-level allocation methods. Each method would lead to widely divergent allocations for our generating units and would dramatically impact our compliance strategy. At this point, we cannot plan for future compliance. There is no comprehensive proposed rule sufficient to afford the public a meaningful opportunity to comment or to guide our compliance planning. Yet EPA has not expressly abandoned its ambitious rulemaking timeline and compliance schedule (i.e., a final rule this summer and the compliance periods beginning less than a year from now). The uncertainty is too great and EPA's timeline is unnecessary and unattainable. Less than a year from the intended compliance period, we do not know, among other things, whether Louisiana will be subject to the rule, which allowance trading programs will apply to Louisiana if it is subject to the rule, whether trading will be allowed and, if so, what the limitations on trading will be. We do not know what the Louisiana state budget will be or what our individual unit allocations will be. There is no meaningful way to plan a compliance strategy given the short timeframe and the level of uncertainty. All the while, CAIR is in place and continues to ensure emission reductions. EPA must abandon its timeframe, leave CAIR in place, and provide a comprehensive supplemental proposal for comment. [EPA-HQ-OAR-2009-0491-4007[1].1, p.2]
II. EPA Must Allow the States an Opportunity to Develop SIPs.
As outlined in our and many other comments on the proposed Transport Rule, EPA's FIP is premature, illegal and ill-advised. The Clean Air Act requires that states be afforded the opportunity to determine in the first instance how best to eliminate any significant contribution or interference with maintenance. States are best suited to determine where reductions are available and most familiar with the local mix of emission sources and with local economic matters. [EPA-HQ-OAR-2009-0491-4007[1].1, p.2]
III. EPA's Haste to Issue a Final CAIR-Replacement Rule Is Arbitrary and Capricious.
There is no rational basis for EPA's accelerated timeline. EPA took two years following the CAIR vacatur to issue a proposed rule. It expects to take almost another full year to issue a final rule and then allow the regulated community only a half year to plan for compliance. On this timeline, EPA will have taken three years to issue a CAIR-replacement rule and will afford the regulated community less than six months to comply. And, today, less than eleven months from the proposed compliance deadline, we have almost no idea what the rule or its emission reduction targets will be. Because CAIR is in place, EPA does not need to push unrealistic timeframes. There is simply no air quality basis for EPA's rush. In light of these points and others, EPA's haste is arbitrary and capricious and not in accordance with law. As soon as possible, EPA must let states know whether they are in or out of each program and, to the extent trading will be a part of the final rule, publish the state budgets and unit allocations. [EPA-HQ-OAR-2009-0491-4007[1].1, p.3]
A. EPA should use the emissions-based allocation method articulated in the proposed Transport Rule.
EPA should use the emissions-based allocation method articulated in the proposed Transport Rule, amended to reflect public comments on that method. As explained in our comments on the proposed rule, EPA should not rely too heavily on its own projections for state budget allocations and EPA should look at a longer baseline period. By reference to our initial comments, we reiterate those points here. [EPA-HQ-OAR-2009-0491-4007[1].1, p.3]
Emission-based allocations provide the most equitable distribution of allowances and more evenly distribute the compliance burden across all covered units. Further, they do not lead to windfall benefits for different types of generation. Allowance trading programs are designed to force cost effective emission reductions at the margins. [EPA-HQ-OAR-2009-0491-4007[1].1, p.4]
E. If EPA uses one of the NODA-3 Options, it must adjust the new unit set aside to account for substantial new generation in Louisiana.
Under the NODA-3 Options, EPA proposes to change the critical date that impacts whether a unit is new versus existing (from January 1, 2012 to January 1, 2009). Between January 1, 2009 and January 1, 2012 at least 1,100 MW of new generation will have been brought online in Louisiana. Under the proposed Transport Rule method, these units' allocations would come from the 97% of the state budget reserved for existing units. Under the NODA-3 methods, these unit's allocations would come from the 3% of the state budget reserved for new units. That would lead to significant under-allocations for these units. EPA must adjust the size of the new-unit set aside for Louisiana. [EPA-HQ-OAR-2009-0491-4007[1].1, p.6]
F. EPA Must Clarify Its Proposal for Determining New Unit Allocations.
In the proposed Transport Rule, EPA explains that new unit allocations will be based on the unit's reported emissions for the prior year. New units would be required to request allocations for their first full year of operations. It appears from the preamble or the regulatory language that this method would seriously under-allocate to new units. First, most new units will not come online on January 1 of a given year, rather they will come online somewhere in the middle of the year. Accordingly, they will only report partial year emissions. If reported emissions for the prior year are the basis for the unit's allocations, it will be under-allocated allowances to the extent it only reported partial year emissions. Additionally, EPA's method does not appear to account for the fact that new units will undergo a shakedown period, where they are operated at well below intended capacity. To correct this apparent oversight, EPA should set new unit allocations based on vender design values. For example, new unit allocations could be based on the vendor's heat-input rate design values and reasonable emission rates and capacity factors for the given technology and fuel type. [EPA-HQ-OAR-2009-0491-4007[1].1, p.6]
VII. Conclusion.
EPA must issue a supplemental proposed rule and extend its rulemaking and compliance timelines. There is simply too much uncertainty to continue with an extraordinarily aggressive timeline. Further, there is no need for such haste, because CAIR is in place. EPA must stop and take its time to assure that the public is afforded full and fair notice and an opportunity to comment and the states are afforded the opportunity to develop SIPs. [EPA-HQ-OAR-2009-0491-4007[1].1, p.7]
Response: 
Thank you for your comment.Organization: Cogen Technologies Linden Venture, LP
Comment: 
Cogen Technologies Linden Venture, LP
In our prior comments, Linden Cogen objected to the allocations of allowances for nitrogen oxides ('NOx') that were proposed for New Jersey under the Proposed Transport Rule because they were based upon projections of utilization generated by EPA's Integrated Planning Model ('IPM'), which have little or no correlation to the historical operations of power plants in the state and fail to reflect Linden Cogen's long-term contractual obligations. Due to several other errors in the model inputs, IPM wrongly projected the dispatch of Linden Cogen at only a fraction of its historical operating levels because IPM arbitrarily ignores the impact of long-term contracts on dispatch. See October 1, 2010 Comments, 5-9. The IPM inputs also incorrectly assumed that Linden Cogen dispatched all of its power into the PJM market. In reality, Linden Cogen dispatches most of its power to the New York City market and also supplies approximately 130 MW of electricity to ConocoPhillips' Bayway Refinery. In light of these erroneous results, Linden Cogen argued that EPA could not rely upon IPM's projections of dispatch unless and until it could fix the model so it appropriately predicted dispatch of cogeneration units. See October 15, 2010 Comments at section II.B.4. [EPA-HQ-OAR-2009-0491-3938[1].1, p.2]
Because of these problems with IPM's projections of future dispatch, Linden Cogen also could not support the alternative allocation methodology EPA proposed with the Proposed Transport Rule, wherein unit allocations would be based on each unit's share of projected statewide heat input. 75 Fed. Reg. at 45311. See October 1, 2010 Comment at 21. While this alternative would generally favor cleaner units, it still would face the same problems of basing allocations on IPM's erroneous projections of future dispatch for units like Linden Cogen. However, Linden Cogen also said that, 'if EPA's proposal were instead to allocate allowances based on each source's share of historical statewide heat input, irrespective of IPM's projections for same, Linden Cogen agrees that this would be a fair and equitable approach.' Id. (emphasis in original). Linden Cogen also suggested that, if EPA could not make changes to IPM so that it would accurately predict dispatch of facilities such as Linden Cogen, EPA should instead base NOx allocations for New Jersey on the same reported emissions data that were used to establish the state budget, as augmented by assumptions about operation of emissions controls. Id., at 20. [EPA-HQ-OAR-2009-0491-3938[1].1, p.2]
SUMMARY OF PRIOR COMMENTS ON PROPOSED TRANSPORT RULE'S PROPOSED ALLOCATIONS
As conveyed by Linden Cogen's October 1, 2010 Comments on the Proposed Transport Rule and October 15, 2010 Comments on the September 1, 2010 NODA, Linden Cogen objected to the allocations of annual and ozone season NOx allowances proposed under the Proposed Transport Rule for New Jersey because they were based upon projections of utilization generated by IPM that have little or no correlation to the historical operations of power plants in the state and fail to reflect Linden Cogen's long-term contractual obligations. See October 1, 2010 Comments, 5-9. EPA also made several errors concerning the underlying assumptions applied to Linden Cogen within IPM that also may have contributed to IPM's erroneous projections of future dispatch for Linden Cogen. See id., 10-11; October 15, 2010 Comments, 4-6. For example, the IPM inputs incorrectly assumed that Linden Cogen dispatched all of its power into the PJM market. In reality, Linden Cogen dispatches most of its power to the New York City market and also supplies approximately 130 MW of electricity to ConocoPhillips' Bayway Refinery. [EPA-HQ-OAR-2009-0491-3938[1].1, p.3]
Both the initial version of IPM released in August (v.3.02) and the revised version released with the September 1, 2010 NODA (vA.1.0) suffered from these errors. As a consequence, reliance upon either version of IPM as the basis for allocating NOx allowances in New Jersey would result in an allocation for Linden Cogen that represented only a small fraction of its historic emissions. Such a result would bear no relationship to real-world observations about how the facility has historically been operated or is required to continue operating under its contracts for the sale of steam and power. See October 15, 2010 Comments, 3. EPA cannot simply ignore these discrepancies in setting the unit allocations. To do so would run afoul of the D.C. Circuit's mandate that EPA explain disparities between IPM's projected future utilization rates and ''real world' evidence to the contrary. See Appalachian Power Co. v. EPA, 249 F.3d 1032, 1054 (D.C. Cir. 2001) ('Appalachian Power I'). As we noted in our October 1, 2010 Comments, the D.C. Circuit has twice previously thrown-out EPA's reliance upon IPM's projected future utilization rates, where IPM 'generated seemingly implausible results' and no attempt was made to explain 'what appear to be stark disparities between its projections and real world observations.' See Appalachian Power I, 249 F.3d at 1035; Appalachian Power Co. v. EPA, 251 F.3d 1026, 1035 (D.C. Cir. 2001). EPA's reliance upon IPM's projections to establish the unit-level allocations would be particularly egregious, when EPA rejected those projections as less reliable than actual data in setting the state budgets. See October 1, 2010 Comments, 16-17. [EPA-HQ-OAR-2009-0491-3938[1].1, pp.3-4]
In our October 15, 2010 Comments, Linden Cogen discussed how EPA might resolve the problems within IPM so that it accurately predicts dispatch of cogenerators subject to long-term contractual obligations, such as Linden Cogen. See October 15, 2010 Comments, 4-7. If EPA could not incorporate the highly complex contractual provisions governing dispatch into IPM, Linden Cogen concluded that EPA would need to 'set the dispatch for cogens within IPM at historic heat input levels using readily available information from EPA databases, and then let IPM solve for the dispatch of other electric generating facilities.' Id., at 7. [EPA-HQ-OAR-2009-0491-3938[1].1, p.4]
As Linden Cogen previously described, long-term contract generators such as Linden Cogen can be severely impacted by the requirement to purchase emissions allowances because, unlike a utility that can seek to recover allowance costs from its ratepayers or a merchant generator that can recover such costs through the market price of electricity, long-term contract generators are subject to contractual obligations that do not allow for full recovery of allowance costs. See id., at 22. Further, long-term contract generators typically must operate whenever dispatched by their counter-party or the grid operator. As we previously suggested, 'Congress has previously recognized the economic realities faced by long-term contract generators who have no way of recovering the cost of emissions allowances, both upon enacting the Acid Rain Program under the 1990 Clean Air Act Amendments and more recently as part of the development of a federal cap and trade program for emissions of greenhouse gases.' Id. Linden Cogen believes that EPA should also take these economic realities into account in developing an allocation methodology that avoids saddling long-term contract generators with unrecoverable costs. [EPA-HQ-OAR-2009-0491-3938[1].1, p.4]
COMMENTS ON ALTERNATIVE ALLOCATIONS PROVIDED BY THE NODA
In Linden Cogen's October 1, 2010 comments on the Proposed Transport Rule, Linden Cogen said it did not support the proposed alternative allocation methodology described by EPA in the preamble to the Proposed Transport Rule, wherein each facility would be allocated allowances based on its 'share of projected heat input.' 75 Fed. Reg. at 45311. See October 1, 2010 Comments at 21. Linden Cogen said that, although this alternative methodology would generally favor clean units such as Linden Cogen, it would still base unit-level allocations on the IPM's inaccurate projections for dispatch and, as a consequence, did not avoid the arbitrary results of EPA's proposed allocations. However, Linden Cogen also said that, 'if EPA's proposal were instead to allocate allowances based on each source's share of historical statewide heat input, irrespective of IPM's projections for same, Linden Cogen agrees that this would be a fair and equitable approach.' Id. (emphasis in original). If EPA could not resolve the problems with IPM so that it would accurately predict dispatch of facilities subject to long-term contractual agreements, such as Linden Cogen, we suggested that EPA should instead base NOx allocations for New Jersey on the same reported historic emissions data that were used to establish the state budget. Id., at 20. [EPA-HQ-OAR-2009-0491-3938[1].1, pp.4-5]
Response: 
Thank you for your comment.
Organization: Cogentrix Energy, LLC
Comment: 
Cogentrix Energy, LLC
Cogentrix submitted detailed comments regarding allocations in a September 2010 comment letter on the proposed Transport Rule. In addition to the allocations comments, Cogentrix also provided detailed comments in support of any opportunity to trade credits to promote economic efficiency and to improve the implementation process by giving the state agencies a more active role. [EPA-HQ-OAR-2009-0491-3916[1].1, p.2]
Response: 
Congentrix's previously submitted comments are addressed elsewhere in the Response to Comment document.
Organization: Connecticut Department of Environmental Protection
Comment: 
Connecticut Department of Environmental Protection
Although EPA did not open the question of allocation methods more broadly, CTDEP feels obligated to suggest that an energy output-based allocation is preferable because it would reward more efficient units and support a more efficient electric generation system overall. [EPA-HQ-OAR-2009-0491-3884[1].1, p.1]
Response:

Thank you for your comment. 
Organization: Consolidated Edison Company of New York, Inc, (CECONY)
Comment: 
Consolidated Edison Company of New York, Inc, (CECONY)
Con Edison believes it makes no sense to assign a 2012 EGU compliance requirement to units that have long-ceased functioning as EGUs, and which were not operating as EGUs even during the EPA-established baseline period. Moreover, even if these units were to be withdrawn from the CA TR, they will still be subject to the Acid Rain provisions of the Clean Air Act, and will continue to report their emissions, and surrender relevant allowances, under that program. Furthermore, the units do not derive any income from the sales of electricity so that any costs associated with their compliance with the CA TR would be borne only by the small number of steam system customers, and not by CECONY's vastly larger (three million plus) electric customer base. This disconnect between costs and revenues is contrary to the fundamental premises of the emission allowance market scheme, and militates in favor of determining that these 74th Street Steam Station units must not be subject to the CATR. [EPA-HQ-OAR-2009-0491-3910[1].1, p.3]
Response: 
These units are currently being left in the list of potential existing Transport Rule units that receive final allowance allocations.  However, EPA notes that the inclusion of this unit in no way suggests that EPA has made a determination about the applicability of the proposed Transport Rule to any unit.  EPA is including the unit in the allocation tables finalized for the Transport Rule because based on its best available data and that submitted by the commenter, the sources' applicability status is unclear.  Therefore, EPA is including the unit so that it has allocations in the event that it a covered Transport Rule unit.  If the unit is subsequently determined not to be subject to the final Transport Rule, than EPA has established procedures for redistributing allowances that would otherwise have been allocated to that unit.  Therefore, their inclusion in the list of potentially covered Transport Rule units reflects a conservative approach by EPA to guard against the possibility of the units being subject to the Transport Rule without receiving any allowance allocation.
Organization: Constellation Energy
Comment: 
Constellation Energy
We previously submitted comments on the proposed Clean Air Transport Rule on October 11 2010; our primary comment was that EPA should move forward quickly with full Implementation of the rule. The rule will appropriately level the regulatory playing field and provide the sector with enough certainty to plan operations for the future. The proposed rule will achieve Important air quality, health, and economic benefits utilizing EPA's current authority. It is critical that EPA implement the rule as expeditiously as practicable to ensure realization of these benefits. Constellation Energy is committed to working with EPA to ensure the Agency can implement the Transport Rule by January 1, 2012, and to that end, we offer these comments on the January 7 NODA. [EPA-HQ-OAR-2009-0491-4031, pp.1-2]
After identifying states contributing to the nonattainment or Interference with maintenance of future NAAQS, EPA should promulgate revised budgets as soon as reasonable and certainly within a timeframe that would allow companies to take account of future requirements in capital planning and positioning in the allowance and electricity markets. [EPA-HQ-OAR-2009-0491-4031, p.2]
Constellation Energy favored the original allocation plan In our October 1, 2010, comments; one criticism of this approach is that it rewards companies that delayed installing controls and penalizes companies who controlled early, or invested in low-emitting generation In anticipation of tightening emission limits. In response to the allocation Options 1 and 2 presented in the NODA, Constellation Energy offers the following: [EPA-HQ-OAR-2009-0491-4031, p.2]
Response: 
Thank you for your comment.Organization: Consumers Energy
Comment: 
Consumers Energy
Whatever approaches are ultimately adopted for allocating allowances or potential alternative means of satisfying states' emission reduction obligations under the proposed rule, there remains a pressing need for EPA to address the deficiencies discussed in Consumers Energy's previous comments with respect to the Proposed Transport Rule, NODA 1 and NODA 2. [EPA-HQ-OAR-2009-0491-4008[1].1, p.4]
Consumers Energy shares the concerns of the Michigan Department of Natural Resources and Environment (MDNRE) regarding EPA's abbreviated timelines for State Implementation Plans (SIPs) and Federal Implementation Plans (FIPs) to implement the programs called for under the Proposed Transport Rule. Historically, EPA has promulgated and finalized rules with adequate time allowed for the states to submit SIPs to implement programs. The Proposed Transport Rule dramatically shortens the time for the States to act, while NODA 3 affords the opportunity for an abbreviated SIP. Like the MDNRE, Consumers Energy believes that the schedule for program implementation can be modified in order to allow the states to adequately address the requirements of the final rule and submit approvable SIPs. FIPs should not be initiated for a minimum of 18 months after a final Transport Rule is in place. [EPA-HQ-OAR-2009-0491-4008[1].1, p.4]
EPA's Proposed Transport Rule is one of the most extensive and complicated rules that EPA has ever proposed under the Clean Air Act. EPA is proposing to limit the interstate transport of emissions of nitrogen oxides (NOx) and sulfur dioxide (SO2). In this action, EPA is proposing to both identify and limit emissions within 31 states and the District of Columbia, in the eastern United States that affect the ability of downwind states to attain and maintain compliance with the 1997 and 2006 fine particulate matter (PM 25) NAAQS and the 1997 ozone NAAQS. [EPA-HQ-OAR-2009-0491-4008[1].1, p.4]
As proposed, the rule would significantly affect the planning, spending and operations of Consumers Energy, as well as those for all utilities within the Transport Rule region. Our company's planning includes capital expenses and scheduling built around the final and still enforceable CAIR to create and maintain a balanced energy portfolio. As proposed, EPA's Transport Rule would force acceleration of spending and construction schedules (if even possible) and, in all likelihood, increase costs for capital expenditures that Consumers Energy currently projects to total in excess of one billion dollars The likely cost increases, coupled with accelerated retirements of units throughout the proposed Transport Rule region, including Michigan, have also caught the attention of the Michigan Public Service Commission (MPSC) which serves to protect the ratepayers in Michigan. [EPA-HQ-OAR-2009-0491-4008[1].1, p.5]
On October 1,2010, Consumers Energy submitted comments on EPA's proposed Transport Rule In those comments, we noted that: [EPA-HQ-OAR-2009-0491-4008[1].1, p.5]
:: EPA was not under any court or statutory mandated schedule to propose and finalize the proposed Transport Rule.
:: The proposal was developed using emissions inventory data that has no relevance to the situation that exists today.
:: The proposed rule has been developed using ambient air quality monitoring data that are not representative of air quality as it currently exists.
:: EPA's choices of emissions inventory and ambient air quality monitoring data result in allowance totals that will be inadequate to support even a limited emissions trading program.
:: EPA uses its choices of emissions inventory and ambient air quality monitoring data to propose an implementation schedule that is considerably more ambitious than the schedule in the rule it is designed to replace, CAIR. For reasons described in our comments and those of the UARG, EPA's schedule is impossible for the industry to meet.
:: EPA made a deliberate choice to isolate itself from the affected states and sources as the Agency crafted this rule.
We reiterated those points as part of our comments on NODA I and NODA2. [EPA-HQ-OAR-2009-0491-4008[1].1, p.5]
The combination of the short comment periods allotted, the lack of supporting data for NODA I, and the extreme difficulty encountered in being able to access and process the 500 MB of data files for NODA 2, have made it extremely difficult for us to conduct a full review, in order to provide meaningful comments on NODA 2 and how it affects the proposed Transport Rule. Consequently, we support and incorporate, by reference, the comments provided by UARG. [EPA-HQ-OAR-2009-0491-4008[1].1, p.5]
EPA freely concedes that the new EGU information supplied by companies in their comments on the Proposed Transport Rule, combined with changes to the NEEDS database, changes to the emission inventory and the IPM inputs identified in EPA's NODA I, NODA 2 and NODA 3, will likely result in a final rule that differs, significantly, from the proposal. Among other things, we expect to see changes in EPA's significant contribution analysis, the creation and evaluation of the cost curves, and the breakpoints selected based on the cost curves. It also is possible that NODA I, NODA 2, NODA 3 and comments received on the data contained in them will result in changes in EPA's determinations of which states are regulated under the Proposed Transport Rule, the emission budgets to which those states will be subject, and unit-level allowance allocations supporting the final Transport Rule. [EPA-HQ-OAR-2009-0491-4008[1].1, p.6]
The potential changes described above are indeed significant. The result of these changes, combined with the series of errors identified in comments to the Proposed Transport Rule and NODA I, is that EPA is placing companies, like Consumers Energy, in the position of revising plans for control projects that are currently being implemented, with associated costs in the billions of dollars. These revisions are being based on a proposed rule and three NODAs, with the expectation that a final rule will be significantly different. Such revisions will incur substantial cost penalties. [EPA-HQ-OAR-2009-0491-4008[1].1, p.6]
EPA has neither a Court mandated nor a statutory required date for completion of this rule. Consumers Energy joins many others in requesting that EPA now retract, revise and repropose the Transport Rule, allowing a reasonable comment period. [EPA-HQ-OAR-2009-0491-4008[1].1, p.6]
Consumers Energy makes the following recommendations: [EPA-HQ-OAR-2009-0491-4008[1].1, p.6]
:: The prudent course for EPA is to retract and rethink the Proposed Transport Rule, NODA I, NODA 2 and NODA 3. The process requires more upfront transparency and a greater degree of involvement by the States and affected sources. EPA has neither a court mandated nor a statutory required date for completion of this rule. EPA has stated that a revision to the final Transport Rule will be proposed to accommodate the final reconsidered 2008 ozone NAAQS, which is now slated to be released by the summer of 2011. Consequently, we recommend that EPA take this opportunity to make the necessary changes and repropose the rule for comment. We respectfully point out that CAIR will continue to remain in effect until a final Transport Rule is in place. Likewise, our Company's plans for implementing controls will also remain in place. [EPA-HQ-OAR-2009-0491-4008[1].1, p.6]
:: EPA must work with the states and affected sources to correct the numerous errors and assumptions, with respect to source emissions, control plans and decommissioning plans contained within the proposed rule. [EPA-HQ-OAR-2009-0491-4008[1].1, p.6]
:: Once EPA settles on final budgets for the states, the allocation of allowances should be handled by the states. The states know their jurisdictions and their sources best. A total allowance budget should be assigned to each state. They can handle the distribution schemes. [EPA-HQ-OAR-2009-0491-4008[1].1, p.6]
:: EPA must recognize that the affected sources have been making substantial plans and progress towards the implementation of controls, in accordance with CAIR, which remains final and enforceable. Any changes to CAIR must take these plans into account. The changes to the schedule contained in the Proposed Transport Rule are not attainable. Any attempt to meet them will result in limited success, substantial noncompliance across the region, with substantial cost penalties. [EPA-HQ-OAR-2009-0491-4008[1].1, p.7]
:: EPA must change the implementation schedule for the final Transport Rule to allow the states adequate time to prepare SIPs. No FIPs should be initiated for a minimum of 18 months following publication of a final Transport Rule in the Federal Register. [EPA-HQ-OAR-2009-0491-4008[1].1, p.7]
Response: 
Thank you for your comment.Organization: CPS Energy
Comment: 
CPS Energy
The implementation of SCR takes well over 36 months, from the time of contract award to the time of operation. There would not be enough time to install additional reduction technology. [EPA-HQ-OAR-2009-0491-3947[1].1, p.1]
Response: 
Regarding installation of EGU controls and the timing of Transport Rule implementation (2012 and 2014), EPA received extensive comment and took these comments into consideration when designing the final Transport Rule.  For a detailed description of EPA's rationale for the final Transport Rule, please refer to section VII.C of the preamble for the final Transport Rule.
Organization: Dayton Power and Light Company (DP&L)
Comment: 
Dayton Power and Light Company (DP&L)
The original proposed rule of August 2,2010 proposed methodologies for distributing allowances based on projected emissions. Since then, EPA has issued three NODAs to supplement the original proposed rule. DP&L submitted comments on the original proposed rule and incorporates those comments by reference. [EPA-HQ-OAR-2009-0491-3973[1].1, p.2]
B. Adoption of Comments by the Environmental Committee of the Ohio Utility Group
DP&L has also participated in the development of and hereby adopts and supports comments that are being submitted by the Environmental Committee of the Ohio Utility Group ('EC-OUG'). The Ohio Utility Group is a group of six electric utilities operating in Ohio, who actively participate in various State and Federal initiatives involving environmental regulation of utilities. DP&L's comments herein are to supplement the comments of the EC-OUG. [EPA-HQ-OAR-2009-0491-3973[1].1, p.2]
Response: 
EPA thanks DP&L for their comments. Responses to previously submitted comments and comments from OUG can be found elsewhere in the Response to Comments document.
Organization: Dominion
Comment: 
Dominion
Comments on the NODA Alternative Allocation Options
Relationship to Original Proposed State Budgets
We commend EPA for presenting additional allocation methodologies for consideration. However, the resultant allocations are still based on the state budgets established in the original CATR proposal and merely represent a redistribution of the originally-proposed state budgets. In our previous comments, we noted in detail numerous inaccuracies in the Integrated Planning Model (IPM) input assumptions specific to Dominion facilities and electric generating units that were used to determine the state emission budgets and individual unit allocations in the proposed rule, and provided detailed documentation for correcting the noted discrepancies. These inaccuracies led to significant underestimation of state emission budgets and insufficient unit allocations under those budgets. Based on our review of this NODA, these issues persist and the use of these alternative options to allocate allowances to units in states with insufficient state budgets (as currently proposed) are even more problematic. [EPA-HQ-OAR-2009-0491-3987[1].1, p.2]
Regardless of which allocation method is applied, there continues to be a pressing need for EPA to correct the deficiencies in the determination of state emission budgets under the proposed rule. Failure to do so could result in even fully controlled facilities that have spent or plan to spend significant capital for environmental controls not being allocated enough allowances to operate fully. An internal evaluation of potential compliance scenarios for CATR that the Company has performed for our Massachusetts facilities illustrates this possibility. The results of these potential scenarios are provided in the attached table and discussed in the following paragraphs. [EPA-HQ-OAR-2009-0491-3987[1].1, p.2]
[Table can be found on page 8 of this comment.]
Dominion owns and operates the Brayton Point and the Salem Harbor coal- and oil-fired power plants in Massachusetts. Since the Company acquired Brayton Point in 2005, the Company has installed substantial pollution control equipment to reduce emissions. These include Selective Catalytic Reduction (SCRs) on Units 1 and 3 in 2006 to reduce NOx, Activated Carbon Injection (ACI) on Units 1-3 in 2007 to reduce mercury, and Flue Gas Desulfurization (FGD) on Units I & 2 in 2008 to reduce SO2. In addition, the Company is in the process of installing FGD on Unit 3 and has completed 60 percent of the cooling tower construction needed to convert the full station to closed-cycle cooling. Capital spending to achieve all these environmental improvements will exceed $1.3 billion (plus additional annual operating costs) when all equipment is installed. The Company will continue to achieve SO2 emission reductions to comply with existing requirements under Massachusetts 310 CMR 7.29. [EPA-HQ-OAR-2009-0491-3987[1].1, p.2]
The proposed CATR assumes that the Brayton Point Unit 3 scrubber noted above will be installed and operational by 2012. This is not possible, as construction of the scrubber has just begun. This scrubber is required by the Massachusetts Department of Environmental Protection to begin commercial operation by the first quarter of 2014. CATR also assumes the installation of a scrubber at Salem Harbor Unit 3 by 2012. The Company currently has no plans to install this equipment. These assumptions have resulted in a significant underestimation of emissions from these facilities in 2012 and a subsequent significant underestimation of the state budget for Massachusetts applicable for 2012 and 2014. As a result, the stations would face a significant shortfall of SO2 allowances in 2012-2013 and for 2014 and beyond under the original set of proposed allocations and an even greater shortfall under the alternative options proposed in this NODA (see Potential Scenario #1). [EPA-HQ-OAR-2009-0491-3987[1].1, pp.2-3]
We analyzed several potential scenarios to reduce SO2 emissions at Brayton Point using fuel switching. We evaluated the four currently commercial available coals: Central Appalachian (CAPP) coals, Columbian coal, Powder River Basin (PRB) coal and Indonesian Adaro coal. The S02 emission rates for these coals range from 1.40 Ibs/MMbtu SO2 content to 0.43 Ibs/MMbtu SO2 content. The lowest sulfur fuels are the PRB and Indonesian Adaro coal. However, these would not be available at Brayton Point until the 2014 timeframe because burning either of these coals would require significant upgrades to the coal handling equipment at Brayton and Salem Harbor in order to safely handle these more volatile fuels. The coal handling upgrades required would require environmental permitting, which combined with the upgrades would take a minimum of two years. The coal handling upgrades can take a significant amount of time to complete because the schedule for the upgrades must be balanced against the plant's ability to continue to operate. This requires the upgrade of the coal handling system now in use. Dominion performed coal handling upgrades at our Salem Harbor Station (Massachusetts); that project took approximately two years to complete. [EPA-HQ-OAR-2009-0491-3987[1].1, p.3]
Switching fuels for a boiler designed for CAPP coal to a western PRB coal or the Indonesian Adaro coal also presents several technical issues. A typical PRB coal has a SO2 rate of 0.8 Ib/MMBtu and a HHV of 8,800 Btu/lb. Converting a boiler designed for CAPP coal to PRB coal would result in de-rating the unit by approximately 20 percent or more depending on unit specific design.. Indonesian Adaro coal will also significantly de-rate the units.' [EPA-HQ-OAR-2009-0491-3987[1].1, p.3]
In addition, switching to Indonesian or PRB coal poses logistical and economic issues. For example, there are no East Coast terminals for PRB coal. Indonesian coal comes from a politically unstable part of the world. Indonesian Adaro coal is also very expensive. The station would rarely dispatch if it were to switch to this coal. The Company would not choose an option that is not economically viable. [EPA-HQ-OAR-2009-0491-3987[1].1, p.3-4]
A fuel switch to Columbian coal (the only alternative fuel available in 2012) is insufficient to ensure that Brayton Point can meet the CATR caps, as shown in Potential Scenario #2 in the attached table). The station is still short allowances under the original CATR allocations and is even shorter under the alternative allocations in the NODA. Moreover, Columbian coals are more expensive and use of such coals would affect Brayton Point's ability to dispatch economically. [EPA-HQ-OAR-2009-0491-3987[1].1, p.4]
The station would still be short of allowances even if the station were to switch to Columbian coal and even if other potential options were pursued such as the retirement of Salem Harbor units and the use of Salem Harbor allowances for compliance at Brayton Point (Potential Scenarios #3 and #4), and after the Unit 3 scrubber is installed (Potential Scenario #5). Note that the analysis of these options assumes that the SO2 allowances from Salem Harbor would be allowed for use at Brayton Point in accordance with the EPA draft CATR rule (which allows retired units to retain their allowances for 6 years after a unit is retired). [EPA-HQ-OAR-2009-0491-3987[1].1, p.4]
The CATR rules are not intended to require facilities to install controls beyond what is already planned in the first two years of the program. The rules should allow controlled units such as Brayton Point I, 2 and 3 to bum the coals for which the emission control systems were designed. This will allow economic dispatch into the market. As illustrated in this example, the allowances allocated to Brayton Point both in the original proposal and in this NODA are significantly insufficient (largely due to the erroneously low state budget proposed for Massachusetts) to allow the station to comply economically with the CATR requirements even once the station is fully controlled for SO2. This is true for both the 2012 and 2014 allocations. [EPA-HQ-OAR-2009-0491-3987[1].1, p.4]
The outcomes described above are not consistent with the rationales that have been provided in the preamble to the Transport Rule for the proposed state budgets and unit-specific allocations in the early years of the program. The preamble to the proposed Transport Rule emphasizes that 2012 budgets are based on 'existing and planned controls,' and are intended mainly to ensure the operation of those controls. Further, EPA acknowledges that 2012 reductions from scrubbers 'can only reasonably be achieved if that scrubber exists today, or if it is currently under construction.' It is not possible to reconcile these statements with the budget and allocation issues outlined above. [EPA-HQ-OAR-2009-0491-3987[1].1, p.5]
Furthermore, as explained above, fuel-switching is not an adequate stopgap to make up for the shortfalls in allowances caused by incorrect data and assumptions about scrubber installation. The preamble acknowledges that there is 'some uncertainty about how quickly units potentially capable of switching fuels would actually be able to implement such fuel switching.' However, as the above discussion makes clear, the term 'uncertainty' significantly understates the obstacles involved in substantial fuel switching for the Company's facilities. [EPA-HQ-OAR-2009-0491-3987[1].1, p.5]
In addition, it is not clear how allowances available in the CATR banking and trading program which the agency itself refers to as 'Limited' - can make up for shortfalls as substantial as those outlined above. If, for example, there are other companies situated similarly to Dominion, then it would appear likely that the CATR market will be deeply 'short'- particularly, if even well-controlled units would have to be allowance buyers. EPA has not provided an adequate rationale for such an approach. If the real intent of CATR is to achieve substantial controls and/or retirements of units, then EPA should provide a full analysis of the economic and energy market impacts of such an approach that appears to deviate significantly from the intent for a more orderly implementation of emission controls stated in the preamble to the CATR proposal. [EPA-HQ-OAR-2009-0491-3987[1].1, p.5]
Conclusion
Regardless of which allocation methodology EPA ultimately chooses, it is crucial to Dominion that the program provide a sufficient amount of allowances that will allow the Company to continue to operate our generating units, particularly those that have already installed controls or will do so over the next few years. We respectfully submit that EPA should correct the issues identified in the original proposal and subsequent NODAs, and recalculate the state budgets before proceeding with further action to finalize this rule. [EPA-HQ-OAR-2009-0491-3987[1].1, p.7]
Response: 
EPA notes that Massachusetts was not found to have emissions that significantly contribute nonattainment or interfere with maintenance in another state in the analysis for the final Transport Rule, as described in Preamble Section V.D.2.  This finding renders moot several of this commenter's concerns.
Organization: Dow Chemical Company
Comment: 
Dow Chemical Company
Dow submitted comments on CATR on October 1, 2010. Dow does not waive its prior comments based on providing comments here. Dow reiterates its belief that Louisiana should not be included in the proposed Transport Rule. Dow also believes that EPA's method for allocations under the Transport Rule! FlP is flawed when compared to the allocations under CAlR via the State of Louisiana SlP. [EPA-HQ-OAR-2009-0491-4018[1].1, p.1]
Response: 
EPA does not believe that it is appropriate to compare the Transport Rule FIP with a CAIR SIP, as CAIR was found to be unlawful and was remanded in the North Carolina court decision. 
Organization: DTE Energy
Comment: 
DTE Energy
EPA has proposed distribution of 97% of each state's budgeted allocation to existing sources, holding back 3% for new sources. DTE Energy supports this distribution, but there must be a mechanism to redistribute the unused portion of the 3% new source set aside to the existing (and new) sources at the end of each reporting period. If there are few, if any, new affected sources in a state, existing sources will still need to provide generation without having adequate NOx or S02 allocations to cover emissions from that generation. [EPA-HQ-OAR-2009-0491-3932[1].1, pp.2-3]
DTE Energy is also concerned that the deadlines for states to develop, process, and get SIPs finalized and submitted to EPA for approval is inadequate. An 18-month time frame is required for most states to get a SIP approved through the relevant legislative process. The Michigan Department of Natural Resources and Environment (DNRE) has submitted comments requesting implementation of the federal implementation plan (FIP) be delayed a minimum of 18 months to allow for state implementation. DTE Energy supports this recommendation. [EPA-HQ-OAR-2009-0491-3932[1].1, p.3]
Response: 
Preamble section VII.D includes a description of how unallocated allowances in the new unit set-asides will be redistributed to existing units.
Organization: DTE Energy Services (DTEES)
Comment: 
DTE Energy Services (DTEES)
If EPA does not increase the proposed allocations to DTE Stoneman to reflect reasonable maximum emissions it will likely cause significant economic hardship to the facility. There are no other units owned by DTEES within the state of Wisconsin with which DTE Stoneman could trade allowances. Additionally, if the allocations do not change DTE Stoneman will bear a disproportionate emissions reduction burden under both the Proposed Remedy (interstate trading) and First Alternative (intrastate trading) leading to potential economic hardship for the facility. While DTE Stoneman's power purchase agreement allows for limited cost sharing for a change in law it may not apply to this rulemaking or provide enough relief due to the large difference in allocations versus expected emissions. [EPA-HQ-OAR-2009-0491-3950[1].1, p.4]
Response: 
EPA notes that DTEES is not limited to trading allowances only between its own units but may obtain allowances from any party throughout the relevant Transport Rule program's region.
Organization: Duke Energy
Comment: 
Duke Energy
In addition, as Duke Energy noted in its comments on the PTR, EPA's IPM modeling for 2012 for that rule showed total SO2 emissions from the entire universe of oil and gas fired units (including steam units) across all PTR states to be less than 40 tons, with most of these emissions coming from just a few oil fired steam units. Clearly at such levels there is no reason to even regulate the SO2 emissions from combustion turbines and combined cycle units. [EPA-HQ-OAR-2009-0491-3965[1].1, p.4]
There does not appear to be any legitimate reason why EPA or the states should need to regulate SO2 emissions from these units under the Transport Rule, but if EPA is concerned about excluding such units from the program, it could develop realistic projections of future SO2 emissions that such units might collectively be expected to produce by state, and subtract those amounts of SO2 from final state SO2 budgets and allocate the remaining allowances. [EPA-HQ-OAR-2009-0491-3965[1].1, p.5]
While many gas- and oil-fired combustion turbines and combined cycle units are required to monitor, report, and provide SO2 allowances for emissions under the Title IV Acid Rain Program, that is not a compelling reason to continue including them in new programs like the Transport Rule, especially when there is no linkage between the Title IV Acid Rain SO2 Program and the Transport Rule SO2 program. The additional administrative requirements associated with permitting, allocation, monitoring, reporting, and market transactions for the Transport Rule are unwarranted for the very small amount of SO2 emissions these units produce. In addition, these units collectively received a small number of SO2 allowances under the Title IV Acid Rain Program so their inclusion in that program did not create the absurd SO2 allocations that would be created under Option 1 if they were to remain in the Transport Rule SO2 program. [EPA-HQ-OAR-2009-0491-3965[1].1, p.5]
This issue is fundamentally different from the court decision on fuel factor adjustments to NOx allocations in the Clean Air Interstate Rule litigation. All combustion sources create varying levels of NOx based on design and operation of the source and the use of add-on controls. SO2 levels from combustion turbines (simple cycle or combined cycle) do not depend on the design and operation of the sources. Rather the emissions are strictly a function of the sulfur in the fuel supplied to the facility. The resulting level of SO2 emissions from combustion turbines and combined cycle sources using these fuels is therefore very low and do not warrant any regulation or control. EPA and the states should have no interest in regulating these very low emissions of SO2, and regulation will serve no purpose. [EPA-HQ-OAR-2009-0491-3965[1].1, pp.5-6]
However, Duke Energy is not recommending, as it does for SO2, that NOx emissions from natural gas and fuel oil should eliminated from the Transport Rule. [EPA-HQ-OAR-2009-0491-3965[1].1, p.6]
Duke Energy agrees, and suggests that EPA exempt gas- and oil-fired combustion turbines and combined cycle units, as discussed above, rather than giving huge allocations away to these units when they have little need for the allowances. [EPA-HQ-OAR-2009-0491-3965[1].1, p.8]
Response: 
Thank you for your comment.
.
Organization: Dynegy, Inc.
Comment: 
Dynegy, Inc.
In our previously submitted comments (dated October I, 2010) on the proposed Transport Rule, Dynegy urged EPA to allocate allowances to all fossil fuel-fired EGUs based on each source's proportional share of historic total state heat input (or gross electrical output). As explained in those comments, EPA's originally proposed allocation methodology, which is based on a combination of adjusted historic and adjusted projected emission data, would inappropriately reward higher emitting EGUs by allocating them more allowances and punish well-controlled EGUs by allocating them fewer allowances. It also encouraged increased operation of higher emitting EGUs relative to well-controlled EGUs by allocating relatively more allowances to less operationally expensive units that either do not utilize emission control technology or utilize less emission control.   [EPA-HQ-OAR-2009-0491-3944[1].1, p.2]
Under the originally proposed allocation approach, well-controlled EGU systems would be more like ly to be subject to the assurance provision allowance surrender requirements than uncontrolled or under-controlled EGU systems. Because allocations to well-controlled units would be much lower than uncontrolled units, all things being equal, emissions from well-controlled EGUs would be more likely to exceed their allocations and, thus, subject the EGU system owner to the assurance provision penalties. In effect, the originally proposed approach would double penalize well-controlled EGU systems: first, by allocating fewer allowances to well-controlled units and, second, by imposing assurance provision penalties on systems with those well-controlled units when emissions from the system exceed its comparatively lower aggregate allowance allocation. [EPA-HQ-OAR-2009-0491-3944[1].1, p.3]
In the event EPA decides instead to adopt its originally proposed allocation methodology, the Agency must correct the erroneous technical data and assumptions regarding Dynegy's units as identified in our October 1, 2010 comments. [EPA-HQ-OAR-2009-0491-3944[1].1, p.4]
Finally, before issuing the final Transport Rule, we encourage EPA to publish a NODA providing an opportunity for public comment on the updated emissions inventories, budgets, and modeling. Given the importance of this rulemaking, we believe that an opportunity to comment on the updated data would help ensure that the rule is supported by the best possible information and ease implementation. [EPA-HQ-OAR-2009-0491-3944[1].1, p.4]
Response: 
Thank you for your comment.
Organization: Edison Mission Energy (EME)
Comment: 
Edison Mission Energy (EME)
On October 1, 2010, EME submitted comments on EPA's Proposed Rule to impose Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone. While supporting the overall emission reduction goals set forth in the Transport Rule as consistent with ongoing progress to achieve important air quality goals under the Clean Air Act, EME raised specific concerns with key components of the Proposed Rule including: (1) EPA's aggressive emission reduction timelines achieved through the implementation of Federal Implementation Plans ('FIPs') are contrary to law because Title I of the Clean Air Act ('CAA') gives states, not EPA, primary responsibility for attaining air standards within their borders; (2) EPA's emission reduction timelines are also technically infeasible; (3) EPA's state-level SO2 and NOX allowance allocations are flawed and penalize states that have already taken action to reduce emissions; (4) EPA's unit level SO2 and NOX allowance allocations are critically flawed as they make unrealistic assumptions about the control efficiency that can be obtained by existing emission controls; (5) EPA's proposed variability limits are too restrictive and do not account for the emissions variability seen under real world conditions; (6) EPA failed to indicate, as it had with respect to CAIR, that compliance with the Transport Rule would be sufficient to satisfy regional haze requirements; and (7) EPA should not seek additional NOX reductions from EGUs beyond those already contemplated by the Transport Rule. [EPA-HQ-OAR-2009-0491-3953[1].1, pp.1-2]
The Transport Rule NODA's heat input-based unit level allocations demonstrate the significant problems with Phase I implementation of the Transport Rule and show that the Phase I timeline for implementation should be abandoned. [EPA-HQ-OAR-2009-0491-3953[1].1, p.2]
EPA's Transport Rule NODA proposal is equally flawed for Phase II of the Transport Rule. [EPA-HQ-OAR-2009-0491-3953[1].1, p.3]
Moreover, EPA's proposed methodology for unit level allocations does nothing to correct errors in the baseline or significant flaws in the state budgets. The state budgets must be re-proposed before any approach to unit-allocations is adopted. [EPA-HQ-OAR-2009-0491-3953[1].1, p.3]
Since states will need time to develop SIPs, Phase II of the Transport Rule should be postponed and should not begin in 2014. EPA should also follow the suggestions EME made in its October 1, 2010 comments on the Transport Rule. [EPA-HQ-OAR-2009-0491-3953[1].1, p.3]
EPA has not made the statutorily-required findings to implement the Transport Rule directly through FIPs and its approach violates the cooperative federalism structure of Title I of the CAA. EPA should follow the procedural mandates of the CAA and allow states reasonable time to propose SIPs. [EPA-HQ-OAR-2009-0491-3953[1].1, p.3]
EPA's stated basis for the reductions it will require during-and the allocations it issued for-Phase I of the Transport Rule was that the emission limits represent NOx and SO2 reductions that can be obtained using existing controls already in place or that EPA believes will be installed and available by 2012. In support of this approach, EPA claimed that reductions can come from operating existing scrubbers and SCRs year-round that are currently operated less frequently and the potential use of coal with lower sulfur content or the installation of limited amounts of low NOx burners. EPA also assumes the installation of emission controls that are scheduled to go online by 2012. In other words, Phase I was designed to reflect the status quo of existing controls13 and its allocations to each unit were intended to be sufficient to cover that unit's actual emissions during Phase I.14 EPA based the Phase I reductions on the status quo of existing controls because EPA acknowledged 'that it is not possible to require the installation of post-combustion SO2 controls (scrubbers) or post-combustion NOx controls (SCRs) before 2014 (because it takes about 27 months to install a scrubber and 21 months to install an SCR) . . . .' By industry calculations, it would take even longer than EPA suggests for EGUs to install such controls. EME submits that it actually takes between 40 and 60 months to install an FGD system and make it fully operational and it would take 32 to 46 months to install an SCR.16 Thus, EPA concedes that it would be impossible for sources to install controls to meet emission reduction requirements in Phase I and EME submits that it is also very unlikely that it could be done in time for Phase II. [EPA-HQ-OAR-2009-0491-3953[1].1, pp.5-6]
In addition to the fact that it will be impossible for these units to install new controls to achieve the emissions reductions required by EPA's proposed approach by the time the Transport Rule takes effect, there is also no assurance that they will be able to purchase allowances on the market to cover any shortfall. Since EPA's Transport Rule proposes a hybrid cap-and-trade approach with limitations on the extent to which EGUs within a state can cover emissions through purchasing additional allocations (particularly from out of state), EGUs will likely have difficulty purchasing additional allowances. [EPA-HQ-OAR-2009-0491-3953[1].1, p.7-8]
EPA's Transport Rule proposal included assurance provisions providing that if a state's emission cap is exceeded, then all EGUs in the state would be penalized on a 2-to-1 basis for their proportional share of the emissions exceeding the cap. Although EPA proposed in the Transport Rule that the penalties in EPA's proposed assurance provisions would not apply until 2014, the only way EGUs will have additional allowances to cover any potential penalties in 2014 and later is to begin saving them when the Rule takes effect. EPA's Transport Rule does not allow a carryover of CAIR allowances. Furthermore, there is no way for an EGU to predict whether or not the state cap will be exceeded; EPA proposed in the Transport Rule that variability be assessed retrospectively-first on an annual basis and then using a three-year variability limit. This uncertainty can create a disincentive for EGUs to trade excess allowances and may encourage them to hold extra allowances in reserve. Thus, if a loweremitting EGU has a windfall based on EPA's heat input-based allocation methodology proposed in the Transport Rule NODA, the EGU may save excess EGUs to cover any potential shortfalls in Phase II of the Transport Rule rather than trade them on the market. As such, allowances may not be available for EGUs to purchase to cover shortfalls during Phase I of the Transport Rule. [EPA-HQ-OAR-2009-0491-3953[1].1, p.8]
Moreover, EPA's Proposal is punitive in nature. Under the proposed heat input approach to allocating unit level allowances, some EGUs will be unable to meet their emissions reductions because of timing and others will be given allowances that exceed their emissions. Thus, some EGUs will be penalized for historic decisions and others will get a windfall. EPA has acknowledged that EGUs will not be able to install new or additional controls until Phase II of the Transport Rule. Thus, EGUs that acted in good faith under existing regulations will be penalized because they cannot get controls in place in time for Phase I compliance. The most that these EGUs will be able to complete in the time they will have under EPA's proposal is to plan for whatever installation of controls is needed to reduce emissions in 2014, but it will be impossible for these EGUs to comply with required emission reductions in Phase I. EPA's Proposal unfairly punishes EGUs even if they have taken significant steps to reduce emissions in compliance with other regulatory requirements despite the fact that EGUs could not be expected to predict what EPA would require. As an example, on December 11, 2006, EME's subsidiary Midwest Generation EME, LLC entered into an agreement with the Illinois Environmental Protection Agency ('IL EPA') whereby it committed to aggressive fleet-wide reductions in emissions of mercury, NOX and SO2 from its Illinois-based coal-fired generation facilities. This commitment will help Illinois attain the PM2.5 and ozone NAAQS and advance the emission reduction goals of the Transport Rule and Clean Air Interstate Rule ('CAIR'). EME committed to a 4-fold reduction in its fleet-wide SO2 emissions rate, a two-fold reduction in its fleet-wide NOX emissions rate (these NOX reductions are on top of the 50% reduction made to comply with the NOX SIP Call) and a 90% reduction in its fleet-wide mercury emissions rate. As part of its commitment to achieve these reductions, EME agreed to install emissions controls on certain units to achieve the fleet-wide emissions rates. However, Midwest Generation phased installation of the controls based upon the state's priorities. The mercury controls were the first to be implemented, and were completed in 2009. While the NOX reductions will be fully implemented by 2012, the SO2 reduction measures will be phased in and completed by 2018 to allow staggered outages at plants and phased capital expenditures. Midwest Generation should not be penalized if the schedule of controls in the agreement does not line up with EPA's Proposal. Midwest Generation made an early commitment to significant emission reductions in exchange for regulatory certainty, but EPA's Proposal punishes Midwest Generation for this early commitment. Under EPA's Proposal, EGUs will be forced to pay-potentially significant sums of money-to competitors to purchase allowances (if allowance are even available) because EPA has not allowed for sufficient time to install controls. [EPA-HQ-OAR-2009-0491-3953[1].1, pp.8-9]
Since EPA's Transport Rule proposes significant limitations on the extent to which EGUs within a state can cover emissions through purchasing additional allocations (particularly from out of state), EGUs will likely be forced to purchase allowances from EGUs within their state. The EGUs whose allocations exceed their needed allowances will be selling the allowances in a market where there are very few sellers and buyers have no other options (short of curtailment of operations) to comply with the Transport Rule. Thus, EPA's Proposal will distort the market and allow sellers to charge unreasonable prices for allowances resulting in a transfer of wealth among EGUs and monopolistic markets. [EPA-HQ-OAR-2009-0491-3953[1].1, p.10]
Another consequence of EPA's alternative methodologies in the Transport Rule NODA is that EGUs who need additional allowances to meet their shortfall will be required to invest their funds in the purchase of these allowances rather than investing in the installation of additional control technology to reduce emissions. If EGUs are unable to obtain additional allowances on the market, they will likely be forced to curtail operations, which would further limit the funds available to invest in the installation of new control technology. [EPA-HQ-OAR-2009-0491-3953[1].1, p.10]
Thus, EPA should abandon the timeline for Phase I implementation of the Transport Rule, re-propose the state budgets as discussed in section C.2 below, postpone Phase II and follow the other recommendations outlined in section IV and in EME's prior comments on the Transport Rule, and allow states to implement the Transport Rule through SIPs as described in section V.C below. [EPA-HQ-OAR-2009-0491-3953[1].1, pp.10-11]
EPA's State Budgets are Based upon Incorrect Assumptions Regarding Control Rates
As noted above, the Transport Rule established Phase I emission reduction requirements based on what EPA deemed achievable if EGUs: (i) operate emissions controls year-round that are currently operated less frequently, such as NOx controls that have, until 2009, only been operated during the summer ozone season (May 1st - September 30th), and (ii) complete the installation of proposed controls that are scheduled to go online by 2012. In addition to assumptions about the emission controls which will be in place by 2012, EPA made assumptions about the level of NOx and SO2 removal provided by those controls. For example, EPA assumed that existing SCRs will achieve a NOx removal efficiency of 90%, resulting in an emissions rate of 0.058 lbs/MMBtu. EPA may presume this assumption is reasonable for newly installed NOx controls operating under ideal conditions (e.g., at peak load, with fresh catalyst, and not accounting for start-up and shut down periods; see below). However, EME does not believe EPA's assumption is accurate for existing SCR systems that may only achieve approximately a 0.1 lbs/MMBtu NOx emissions rate. [EPA-HQ-OAR-2009-0491-3953[1].1, pp.11-12]
The Transport Rule assumed that all existing controls will continuously achieve state-ofthe- art control rates, even though this is not likely for many EGUs that have been operating existing SO2 and NOX controls over a number of years. The emission reduction assumptions made by EPA do not account for the full range of operational conditions that emission control systems experience. The control rates assumed by EPA for an FGD or SCR may be technically obtainable on a new system when it is operating at full capacity in prime condition (e.g., with fresh catalyst at peak power), but these assumptions are not representative of real world operational conditions as EGUs do not operate at peak capacity at all times. For example, EPA is well aware that SCRs operate at lower removal efficiencies when a plant is not functioning at peak load, such as during overnight periods. There may be periods of start-up and shut down throughout the day where a plant and its emissions controls are not operating under optimal conditions, and therefore emissions rates are higher. Similarly, for an SCR to achieve EPA's 0.058 lbs/MMBtu control rate the catalyst will have to be changed more frequently. However, when the catalyst is exchanged more frequently, there will be more periods when the emission control is bypassed so that the new catalyst can be installed. Finally, EGUs tend not to operate at peak load during the shoulder seasons - fall and spring - which means that SCRs will operate less than optimally during those seasons. All of the foregoing result in situations where a plant's emissions rate is higher than its optimal performance. Therefore, to achieve an average rate of 0.058 lbs/MMBtu for NOX, for example, an SCR has to achieve a much lower control rate than 0.058 lbs/MMBtu when it is operating under optimal conditions. EME submits that EPA's assumed control rates should have, but did not, account for these operational factors that affect average emissions rates; doing so would result in higher emissions rate assumptions and therefore a higher baseline. [EPA-HQ-OAR-2009-0491-3953[1].1, pp.12-13]
Significant Errors in EPA's State Budgets Require Re-Proposal
The data and assumptions described above are central to EPA's determination of the state budgets for Phase I of the Transport Rule since EPA based the required emissions reductions in Phase I on what EPA deemed achievable without the installation of new controls. In addition, many states and companies have explained that EPA erred in its assumptions about which plants would have controls installed by 2012. All of the errors in EPA's data on existing controls and existing emissions and EPA's assumptions regarding the performance of controls directly impact the calculation of state budgets. [EPA-HQ-OAR-2009-0491-3953[1].1, p.13]
The comments submitted by the state environmental and air agencies highlight the magnitude of the flaws and the resulting errors in state budgets. For example, Illinois stated that 'the initial 2012 budgets are based on unrealistic expectations for optimization of controls for some emission units.' Florida commented that EPA's 'proposed allocations, especially for NOx, are very different than 2009 actual emissions, or what we anticipate emissions will be in 2012 and 2014,' and suggested that the 'NOx allocations seem to be random and will result in a great deal of intrastate trading to more closely align allocations with actual emissions in 2012.' Similarly in its request for an extension of time in which to respond to EPA's Transport Rule proposal, Georgia highlighted significant concerns identified on its 'very cursory review' of the proposal including 'the inclusion of non-EGUs' and 'incorrect emissions modeled for both 2012 and 2014.' Georgia emphasized that '[a]ll of these issues may lead to incorrect decisions regarding Georgia's contribution to the receptors EPA has linked us to, the amount of reductions that will actually need to be made, and what group we are placed in for SO2 reductions.' This is consistent with the findings of many other states including Indiana ('Indiana has several concerns regarding the accuracy of the data used for justifying the proposed rule [and] establishing state budgets. . . .'), Kansas ('we have identified several inconsistencies in the emissions modeling inputs that we believe could lead to a significant overestimation of contribution to nonattainment from Kansas sources.'), and Northeast States for Coordinated Air Use Management (NESCAUM) ('Over the years, we have repeatedly observed IPM predictions that do not reflect real world conditions because transmission constraints and reliability rules for our region are not always fully reflected in the model. . . . Due to such issues, IPM is therefore not our preferred model for use in establishing state budgets and allocations.'). [EPA-HQ-OAR-2009-0491-3953[1].1, pp.13-14]
Given that EPA stated both that it was updating the emissions inventories and modeling, and that was not proposing any changes to its approach to each state's emissions budget, it is not clear whether the state budgets will change or not. The proposed allocation methodology in the Transport Rule NODA does nothing to address the fundamental flaws in the state budgets. However, the state budgets are so flawed and so important to unit level allocations, and given that the proposed allocation methodology in the Transport Rule NODA uses the state budgets as a starting point, the NODA is inherently insufficient. EPA's attempt to gloss over the flaws by using heat input data does nothing to fix the defect. EME submits that EPA must reassess its assumptions regarding the status quo and achievable emissions in 2012 and re-propose the state budgets. [EPA-HQ-OAR-2009-0491-3953[1].1, p.14]
Since states will need time to develop SIPs, Phase II of the Transport Rule should not begin in 2014. Phase II should be postponed to allow states to craft methodologies for allocating allowances in the most effective manner and to allow states time to promulgate the SIPs-either through notice-and-comment rulemaking or the enactment of legislation as required. EPA should also follow the additional suggestions EME submitted in its October 1, 2010 comments on the Transport Rule. [EPA-HQ-OAR-2009-0491-3953[1].1, p.15]
The CAA commits to the states 'the primary responsibility for assuring air quality within [the state] . . . by submitting an implementation plan . . . which will specify the manner in which national primary and secondary ambient air quality standards will be achieved and maintained . . . .' However, EPA may determine that a state's SIP does not meet the requirements of the CAA, and the CAA sets forth procedures EPA must follow in order to make these findings: (1) EPA may make a finding that that a SIP is 'substantially inadequate to attain or maintain' the relevant NAAQS, to 'mitigate adequately' interstate pollutant transport or otherwise fails to comply with requirements of the CAA under §110(k)(5) and EPA 'shall require the State to revise the plan as necessary to correct such inadequacies;' (2) EPA must notify the state of the inadequacies in the SIP and EPA may set 'reasonable deadlines (not to exceed 18 months after the date of such notice)' to submit SIP revisions; (3) if and when a state submits a SIP revision, EPA must make a determination of completeness-whether the revised SIP meets the minimum criteria established by EPA pursuant to § 110(k)(1)(A)-and EPA must make this determination within 60 days of receipt of the SIP revision, but the decision must be made no later than six months after receipt; (4) if EPA makes no determination within six months after receipt, the SIP revision is deemed to meet the minimum requirements established under § 110(k)(1)(A) by operation of law; (5) following submission of a completed SIP revision, EPA must act within 12 months and either approve or disapprove the revision. [EPA-HQ-OAR-2009-0491-3953[1].1, pp.17-18]
Section 110(c)(1) requires EPA to promulgate a FIP any time within two years after EPA: '(A) finds that a State has failed to make a required submission or finds that the plan or plan revision submitted by the State does not satisfy the minimum criteria established under § 110(k)(1)(A), or (B) disapproves a State implementation plan submission in whole or in part' unless the state corrects the deficiency and EPA approves the SIP or SIP revision before it promulgates the FIP. Importantly, while the statute requires EPA to promulgate a FIP after making one of the required findings, the statute does not permit EPA to promulgate a FIP unless one of these three circumstances is met. In other words, EPA can only promulgate a FIP where: (1) the state failed to submit a SIP or SIP revision; (2) EPA finds the SIP submission to be incomplete; or (3) EPA disapproves the SIP in whole or in part, and the state fails to correct the deficiency. [EPA-HQ-OAR-2009-0491-3953[1].1, pp.18]
EME submits that EPA has not made the statutorily-required findings, and the approach in the Transport Rule NODA, which would not allow SIPs by law under the 2014 control year at the earliest, is flatly contrary to the CAA's requirements, as well as being inconsistent with the cooperative federalism dictates of Title I. This is yet another reason why EPA should abandon the timeline for Phase I implementation of the Transport Rule. [EPA-HQ-OAR-2009-0491-3953[1].1, p.18]
EPA noted in the Transport Rule's preamble that in 2005 it found certain states had failed to make submissions meeting the requirements of § 110(a)(2)(D)(i) regarding the interstate transport of pollution. EPA later promulgated CAIR and concluded that state SIP submissions satisfying CAIR would satisfy § 110(a)(2)(D)(i) requirements. Most states submitted SIP revisions complying with the CAIR requirements, and EPA approved most of those SIP revisions. Despite the fact that the CAA is clear that it is EPA's action in disapproving a SIP (or finding it incomplete) that triggers the FIP process, EPA inexplicably argued that the D.C. Circuit Court of Appeals' remand of CAIR in December 2008 somehow acted as a repeal of EPA's approvals of the CAIR-based SIP revisions and that the 2005 findings of failure to submit are now back into effect for the states in which EPA approved SIP revisions under CAIR. The preamble to the Transport Rule did not provide any legal basis for this conclusion nor did EPA argue that it made the required finding that a SIP is 'substantially inadequate to attain or maintain' the relevant NAAQS or to 'mitigate adequately' interstate pollutant transport under § 110(k)(5). [EPA-HQ-OAR-2009-0491-3953[1].1, p.18-19]
The CAA does not support EPA's conclusion that it may implement a FIP for these states. First, while EPA made a finding of failure to submit for these states in 2005, EPA's later action in approving each state's SIP as meeting the requirements of § 110(a)(2)(D)(i)(I) and expressly withdrawing the FIP in each state ended EPA's authority to dictate which control methods are necessary to meet the NAAQS. The D.C. Circuit's decision in North Carolina v. EPA did nothing to restore that authority to EPA. Second, while the D.C. Circuit remanded CAIR and the CAIR FIP, EPA's individual SIP approvals were not before the court in that case and, therefore, remain in place. Third, the fallacy in EPA's analysis is further demonstrated by the Agency's actions in continuing to approve SIP revisions under CAIR. EPA approved six SIPs to meet the requirements of CAIR after the D.C. Circuit's remand of the CAIR rule in December 2008. In these approvals occurring after the D.C. Circuit's remand, EPA acknowledged the remand of CAIR, but explained that it was moving forward in approving SIPs under CAIR requirements consistent with the D.C. Circuit's goal in remanding the rule to 'temporarily preserve environmental values covered by CAIR.' [EPA-HQ-OAR-2009-0491-3953[1].1, pp.19-20]
EPA's Rationale Regarding 2006 PM2.5 NAAQS is Flawed
In the preamble to the Transport Rule, EPA explained that it had separately issued a finding of failure to submit § 110(a)(2)(D)(i)(I) transport SIPs for the 2006 PM2.5 NAAQS. Twenty-nine states or territories were included in EPA's June 9, 2010 finding of failure to submit. [EPA-HQ-OAR-2009-0491-3953[1].1, p.20]
EPA's conclusion that the 2010 finding of failure to submit establishes EPA's authority to promulgate a FIP for those states is flawed because EPA did not give the states the opportunity to which they are entitled under law to comply with the 2006 PM2.5 NAAQS. EPA concluded that since it promulgated the final NAAQS September 21, 2006, states were required under § 110(a)(1) to make a SIP submission for the NAAQS by September 21, 2009. First, EME disagrees with EPA's interpretation that the deadline in § 110(a)(1) applies to the requirements of § 110(a)(2)(D)(i). Under § 110(a)(1) states must submit SIPs that provide 'for implementation, maintenance, and enforcement of such primary standard in each air quality control region (or portion thereof) within such State.' (emphasis added). Arguably, the requirement to prohibit emissions that contribute to nonattainment of the air quality standards in 'any other state' does not fall within this statutory deadline. Second, the finding did not take into account the fact that EPA was late in making its designations for the 2006 PM2.5 NAAQS. Under § 107(d)(1)(B)(i), EPA is directed to make its designations two years from the date of promulgation of new or revised NAAQS (with a clause that allows extension for up to one year if EPA does not have sufficient information to promulgate the designations). EPA published the final designations in the Federal Register on November 13, 2009,--more than three years after EPA promulgated the final 2006 PM2.5 NAAQS and nearly two months after EPA claimed states were required to submit their SIPs. It would have been impossible for states to hae submitted their SIPs when EPA argues they were due since they did not even know whether EPA would designate them as attainment or nonattainment. EPA should have given states reasonable time to comply after the final designations were made rather than rushing to make a finding of failure to submit seven months later. EPA's rush to find a failure to submit was an abuse of process and a transparent attempt to misappropriate the authority that Congress has vested in the states to determine how best to comply with the air quality standards. [EPA-HQ-OAR-2009-0491-3953[1].1, pp.20-21]
The CAA commits to the states 'the primary responsibility for assuring air quality within [the state] . . . by submitting an implementation plan . . . which will specify the manner in which national primary and secondary ambient air quality standards will be achieved and maintained . . . .' Courts have consistently held that the CAA grants to states the primary authority to determine what measures are necessary to ensure that the NAAQS are met. For example, in Train v. Natural Resources Defense Council, the Supreme Court considered 'whether Congress intended the States to retain any significant degree of control of the manner in which they attain and maintain national standards' and found that EPA 'is relegated by the Act to a secondary role in the process of determining and enforcing the specific, source-by-source emission limitations which are necessary if the national standards it has set are to be met.' As the Seventh Circuit Court of Appeals has stated, '[t]he Clean Air Act is an experiment in federalism, and the EPA may not run roughshod over the procedural prerogatives that the Act has reserved to the states . . .' In Virginia v. EPA, the D.C. Circuit Court of Appeals cited Train and noted with approval other circuit precedent similarly establishing this division between EPA and state control over the manner in which air quality standards are met within states. The D.C. Circuit found that the CAA did not give EPA the authority to condition approval of a SIP upon adoption of a specific control measure. [EPA-HQ-OAR-2009-0491-3953[1].1, pp.21-22]
EPA's Approach in the Transport Rule NODA Violates the Cooperative Federalism Structure of Title I of the CAA [EPA-HQ-OAR-2009-0491-3953[1].1, p.21]
These cases  -  all of which address the interplay between state and federal authority under Title I  -  have all found that Congress intended to give the states great discretion in developing SIPs, so long as those SIPs meet the minimum requirements set forth in the CAA. By implementing FIPs in Phase I (and potentially the 2014 control year and beyond), the Transport Rule NODA approach usurps the states' role, expressly provided for in the CAA and affirmed by the case law, as the entity Congress chose for deciding how air quality standards are to be met on a state-by-state basis. [EPA-HQ-OAR-2009-0491-3953[1].1, p.22]

13 While Phase I of the Transport Rule was designed to reflect existing controls, EPA made additional assumptions-such as controls that are currently in the planning phase being in place by 2012 or that EGUs could make required reductions by operating existing controls year round. Thus, even though EPA's Phase I approach is designed to reflect the status quo of existing controls, EME submits that EPA's state budgets (and resulting unit level allocations) do not do so.
14 In fact, however, EME-and many others in industry and the states-explained in their comments that the Phase I allocations did not accurately account for actual emissions.
Response: 
Regarding SCR NOx rates, please see preamble section VII.C.2 and the "Transport Rule Engineering Feasibility Response to Comments" document in the docket.
EPA disagrees with the commenter's argument that EPA should re-propose the state budgets.  EPA provided an ample opportunity to comment on the data and methodology used to calculate the budgets, and an ample opportunity to comment on alternative methodologies for allocating allowances.  EPA included illustrative budgets in the proposal and illustrative unit level allocations in the proposal and the allowance allocation NODA, but as it was also requesting comment on the data and methodologies used to calculate these budgets and allowance allocations, it also put the public on notice that the final budgets and final allowance allocations could differ from the illustrative budgets and allocations provided in the proposal and NODAs.  Further, in the NODA, EPA emphasized that the unit-level allocations presented were only intended to "provide an indication of the proportional share of a State's budget that would be allocated to individual existing units if the alternative methodologies would be used."  76 FR 1111.  EPA explicitly noted that the illustrative allocations were based on the proposed state budgets and that the "final state budgets may differ from the proposed budgets."  Id.
EPA satisfied the applicable notice and comment requirements by providing a full opportunity for comment on whether the states identified in the proposal should be included in the Transport Rule programs, and a full opportunity to comment on the methodologies and data to be used to quantify the emissions in each state that must be prohibited pursuant to section 110(a)(2)(D)(i)(I) with respect to the 1997 ozone NAAQS, the 1997 PM2.5 NAAQS, and the 2006 PM2.5 NAAQS.  EPA received numerous comments on the data and methodologies used to quantify each state's significant contribution and interference with maintenance and made updates and modifications to its data and methodologies in response.  The notice and comment process does not begin anew each time updates and modifications are made in response to comments received on a proposal.  A final rule need not be identical to the proposed rule, it need only be a "logical outgrowth" of the proposed regulations.  See Small Refiner Lead Phase-Down Task Force v. EPA, 705 F.2d 506, 546-47 (D.C. Cir. 1983).  As the court has long recognized, a contrary approach would lead to the absurd result that "the agency can learn from the comments on its proposal only at the peril of stating a new procedural round of commentary," International Harvester Co. v. Ruckelshaus, 478 F.2d 615 (D.C. Cir 1973). As explained above, EPA provide an ample opportunity to comment on the methodology and data inputs to be used to calculate states' significant contribution, and explicitly provided notice to the affected states and sources in the affected states that EPA was considering including them in the final rule Transport Rule due to the impact of emissions within the state on downwind nonattainment and maintenance problems with respect to the 1997 PM2.5 NAAQS, 1997 ozone NAAQS and/or 2006 PM2.5 NAAQS.
EPA also disagrees with the commenter's assertion regarding EPA's authority to promulgate FIPs with respect to the 2006 PM2.5 NAAQS.  As explained in section IV.C.2 of the preamble to the final rule and section III.A. of this RTC, EPA has an obligation to promulgate each of the FIPs in this rule.
There is no basis for the commenter's argument that the deadline in § 110(a)(1) does not apply to the requirements of § 110(a)(2)(D)(i).  Under § 110(a)(1) states must submit, within three years of promulgation or revision of a NAAQS, SIPs that provide "for implementation, maintenance, and enforcement of such primary standard in each air quality control region (or portion thereof) within such State."  Section 110(a)(2) then lays out in greater detail what a the SIPs required to be submitted pursuant to 110(a)(1) must contain.  The Act, on its face, describes what these SIPs must contain and there is thus no basis for the commenter's suggestion that the requirements of 110(a)(2)(D) are outside the scope of the submissions required pursuant to section 110(a)(1) and thus not subject to the three year deadline provided therein.  
Further, the commenter appears to confuse the 110(a)(1) SIPs known as infrastructure SIPs with the nonattainment SIPs that states with designated nonattainment areas are required to submit pursuant to other sections of the statute.   Pursuant to section 110(a)(1) the deadline for submitting 110(a)(1) infrastructure SIPs for a particular NAAQS runs from the date of promulgation or revision of that NAAQS.  The date on which EPA makes designations for the NAAQS thus has no impact on the 110(a)(1) SIP submittal deadline.  Further, the structure of the statutory scheme demonstrates that Congress did not intend to require EPA to finalize attainment designations before requiring the submission of 110(a)(2)(D)(i)(I) SIPs.   As noted above, these SIPs are due within three years of promulgation of the NAAQS, and section 107(d)(1)(B)(i) of the Act allows EPA to take that same length of time in some instances to make designations with respect to the NAAQS.  The structure of the statutory scheme suggests that Congress intended states to have, within a few years of the promulgation or revision of a NAAQS, information regarding the steps to be taken by upwind states to address transported emissions.  Having such information makes it easier for downwind states to develop the nonattainment SIPs required for each designated nonattainment area.  This structure makes sense given the difficulties faced by downwind states which have significant amounts of pollution coming from out-of-state sources.  Without information regarding steps taken in upwind states to address transported emissions, if is extremely difficult for downwind states to develop plans to bring nonattainment areas within the state into attainment.   Further, the fact that the time for submission of 110(a)(2)(D)(i)(I) SIPs runs, not from the date of designations but from the date of promulgation or revision of the NAAQS, and the fact that EPA in some instances is given the same length of time to complete designations, suggests that the designation status of an area should not be considered relevant to the 110(a)(2)(D)(i)(I) analysis.  EPA's approach is thus consistent with the plain language of the statute and the statutory structure.
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Finally, EPA's approval of CAIR SIPs and technical corrections to CAIR SIPs following the remand of the CAIR rule has no impact on EPA's authority to promulgate the FIPs in this rule.  The fact that court decided to keep the requirements of CAIR in place temporarily does not disturb the court's conclusion that CAIR and the CAIR SIPs/FIPs do not satisfy the requirements of 110(a)(2)(D)(i)(I).  Some CAIR related SIP submissions were approved after the remand for the limited purpose of implementing the D.C. Circuit's decision remanding the rule without vacatur to temporarily preserve environmental values covered by CAIR.  Given this mandate, EPA determined that it was appropriate to continue implementing the CAIR program, including promulgating SIP approvals, until the program could be replaced. 
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Edison Mission Electric, and several other commenters, expressed concern that allowance trading markets would not develop under the Transport Rule's air quality-assured trading programs. These commenters made the following arguments: 

1) Commenters argue that it will take time to get markets started and functioning
EPA notes that SO2 and NOX trading are well established practices under ARP, NBP, and CAIR, with an existing knowledge base of compliance options and allowance market operations. The experience and familiarity that units, states, and EPA have with emissions trading programs will help speed development of a trading market for the Transport Rule programs.  The power sector and emission trading community have known that EPA was preparing this approach under the Transport Rule since its proposal in July 2010, leaving ample time for companies to prepare in advance of this final rule promulgation. Finally, while the first control periods begin on January 1 and May 1, 2012, trading activity may occur throughout the entire control period until the allowance transfer deadlines following the conclusion of the control periods.  Covered units can therefore anticipate the flexibility to conduct allowance transactions to cover emissions as the control period progresses.  Also, EPA will record allocations for the first control period by no later than 90 days after publication of the final rule and therefore in advance of the beginning of the first control periods, further promoting the development of the Transport Rule allowance markets.  

2) Commenters argue that markets will not develop because units will bank excess allowances instead of trading 
EPA disagrees with EME's assertion that allowance banking by some units will prevent other units from acquiring allowances in a given control period. Using or banking an allowance has an opportunity cost (i.e. the price a unit could receive if it sold the allowance in the current control period).  The raison d'etre of emission trading programs is that different units have different marginal costs of controlling emissions.  The difference between units in this marginal cost of control will lead some units to achieve more cost-effective emission reductions (related to the stringency of the state budgets) than other units.  Units are incentivized to make cost-effective reductions because they are then able to sell surplus allowances to other units who realize cost savings through allowance purchases to cover, rather than directly reduce, a portion of their emissions.  Any unit's decision to bank, rather than sell, a particular allowance reflects that current demand for that allowance is relatively low.  Therefore, rather than being an inhibitor of market activity, allowance banking would be a sign that the current market is oversupplied and the allowance price is relatively low at that time.

3) Commenters argue that uncertainty about future state-wide emissions will cause units to hold on to excess allowances. 
EPA releases EGU emissions data quarterly, rapidly providing information to the market on state-wide emissions.  Consequently, EPA anticipates that sources will be able to factor the progression of a state's emissions throughout the year into their trading decisions, and that sources will not engage in "allowance hoarding" as they can collectively witness the ability of the state as the year progresses to respect its assurance level.

4) Commenters argue that the stringency of state budgets will prevent anybody from having excess allowances to trade
EPA disagrees with this argument and notes that it overlooks the foundation of emission trading programs.  It is not necessary to inflate emission budgets to enable an allowance market to develop.  At any stringency level (including those supporting the Transport Rule budgets), there is variation at the source level in the marginal cost of reducing emissions. Many sources will have emission reduction opportunities at costs below the market-wide allowance price. Those units can make those cost-effective emission reductions and sell excess allowances to units with higher marginal abatement costs. 

5) Commenters argue that EPA's allocations to existing units will lead to monopolistic behavior
For reasons explained in section VII.D. of the preamble to the final rule, EPA believes that the allocation method selected for use in the FIPs is both reasonable and appropriate for use in this rule.  Commenters did not provide any evidence for the assertion that unit-level allocations, under any methodology, would result in the exercise of market power.  The Transport Rule's air quality-assured trading program structure was specifically designed to accommodate interstate allowance markets in each of the program.  Because units will have access to allowances from other units throughout all of the states included in the same Transport Rule program, the allowance markets are far too diffuse, under any unit-level allocation methodology, to permit any one allocation recipient in these interstate markets to exercise market power.     
Organization: Empire District Electric Company (Empire District)
Comment: 
Empire District Electric Company (Empire District)
CATR is not designed to force MACT or to specify/force one control technology above another. This approach could be litigated and we suggest EPA avoid unnecessarily provoking such wasted resources. Such additional control will be governed by EGU MACT and CATR II, thus providing electric utilities additional time for adequate planning, engineering, regulatory approval, bidding and construction. [EPA-HQ-OAR-2009-0491-3883[1].1, p.2]
Empire District supports the new unit allocation methodology set-aside of 3% as outlined in the proposed CATR. The 3% set-aside is appropriate. [EPA-HQ-OAR-2009-0491-3883[1].1, p.2]
Possible Options for States Wishing to Submit SIPs Providing for State Allocation of Allowances  
The CATR has usurped the States ability to properly develop their SIPs according to the CAA and has shifted power to the EPA. Empire District encourages the EPA to delay the CATR, leave CAIR in place, and allow time for proper SIP development to address transport issues. In fact, for the state of Missouri to develop their SIP for the distribution of 2014 allowances, the Missouri rulemaking process and SIP must be completed by November of this year. Due to the extreme lack of time Missouri's distribution of even the 2014 allowances is impossible.  [EPA-HQ-OAR-2009-0491-3883[1].1, p.2]
The EPA is not under a consent decree or settlement agreement specifying the timing of CATR because of the wisdom of the court. Delaying the CATR would allow the EPA adequate time to refine its chemical modeling and provide corrected and adequate information which the States and industry need in order to comply. The current proposal requires utilities and States to utilize their crystal ball which is not a very scientific approach to planning. [EPA-HQ-OAR-2009-0491-3883[1].1, p.2]
The greatly accelerated pace of CATR leaves inadequate time for `higher-emission-rate units' to reduce emissions. [EPA-HQ-OAR-2009-0491-3883[1].1, p.2]
Instead of the piece-meal approach currently underway the EPA should complete its modeling and emissions inventories, re-propose the rule and then allow an adequate period for public comment.  [EPA-HQ-OAR-2009-0491-3883[1].1, p.3]
Further, Empire District believes that the EPA should allow adequate timing for utility compliance planning and should not use CATR to create winners or losers. In addition, the States should be provided with the time to properly develop their own allocation methodologies through the CAA SIP process. [EPA-HQ-OAR-2009-0491-3883[1].1, p.3]
Response: 
Thank you for your comment.Organization: EquiPower Resources Corp.
Comment: 
EquiPower Resources Corp.
EquiPower has been an active participant in this rulemaking. On October 1, 2010, EquiPower submitted comments on EPA's Proposed Rule to impose Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone. While applauding EPA's efforts to improve air quality, EquiPower identified a number of legal, technical and policy concerns with EPA's Transport Rule proposal including: (1) EPA's state budget caps and assurance provisions stand in the way of an effective emissions trading market; (2) The Transport Rule has co-opted state authority and adopted a regulatory approach that is flawed and contrary to law because under Title I of the Clean Air Act ('CAA'), states have the primary responsibility for attaining air quality standards through promulgation of State Implementation Plans ('SIPs'); (3) The Proposed Rule relies on flawed data and assumptions resulting in significant errors in unit-level allocations and state emission budgets, making compliance with the Phase I and Phase II emissions caps impracticable and causing the Transport Rule to penalize clean sources and those with existing emission controls; and (4) The Agency should not seek additional NOX reductions from electric generating units ('EGUs') beyond those already contemplated by the Transport Rule. [EPA-HQ-OAR-2009-0491-3928[1].1, pp.1-2]
At a minimum, EPA should re-propose the Transport Rule after correcting its errors in data and assumptions. [EPA-HQ-OAR-2009-0491-3928[1].1, p.3]
First, facilities will not be able to install additional or new controls in time for Phase I of the Transport Rule in 2012. This may not even be feasible in Phase II for economic reasons or because of time constraints. EPA acknowledged in the Transport Rule that 'it is not possible to require the installation of post-combustion SO2 controls (scrubbers) or post-combustion NOx controls (SCRs) before 2014,' noting that 'it takes about 27 months to install a scrubber and 21 months to install an SCR . . . .' EquiPower believes that EPA has underestimated the time it actually takes to install controls. For example, the Utility Air Regulatory Group ('UARG') has indicated that it actually takes between 40 and 60 months to install an FGD system and make it fully operational. While EPA may believe that the installation of controls is an option to meet the emission reductions required in Phase II of the Transport Rule, industry experience suggests otherwise. Thus, installing controls will not be an option for EGUs that exceed their allowance allocations in Phase I and may not be an option in Phase II. [EPA-HQ-OAR-2009-0491-3928[1].1, p.5]
Second, there is no guarantee that allowances will even be available on the market if an EGU needs to obtain additional allowances to make up for its shortfall. EPA conceded in the Transport Rule that even its preferred option ('State Budgets/Limited Trading' - the option with the greatest flexibility) would only provide 'some limited flexibility to covered sources' because the provisions as drafted only provide for 'limited interstate trading.' EPA's proposed statewide caps (even accounting for the variability limits) represent a dramatic disincentive to trading because, under the Transport Rule, if a state cap is exceeded, then all sources within the state are penalized on a 2-to-1 basis for their proportional share of the emissions exceedance. Sources cannot know contemporaneously whether or not the state cap will be exceeded, as variability is assessed retrospectively on an annual basis initially and then using a three-year rolling average. These penalty provisions mean that, in addition to holding allowances equal to annual NOX and SO2 emissions, a source needs to hold extra emission allowances in reserve to account for the contingency that a state's emission cap (plus variability limit) will be exceeded and that the source will be subject to a penalty. The potential for the state cap to be exceeded creates strong disincentives to trading and encourages EGUs to hoard allowances. Thus, since EGUs will not likely have the option to install additional controls and allowances may not be available on the market, many facilities will only have the option of curtailing operations. [EPA-HQ-OAR-2009-0491-3928[1].1, pp.5-6]
Many parties have predicted that the Transport Rule, combined with mercury regulations, could result in a significant percentage of the U.S. coal fleet being at risk for shut down. In addition to these regulations, EPA will also be promulgating new regulations governing cooling water intake structures at facilities such as power plants under Clean Water Act § 316(b) and potentially a new rule regulating coal combustion residuals under the Resource Conservation and Recovery Act. At the very least, these rules will cause many facilities to be forced to operate at reduced capacity. EPA should be mindful that if these shut downs or reductions in capacity should occur, combined cycle gas plants are the most likely source to make up for the lost baseload capacity provided by those coal-fired units. It is possible that gas plants would need to run at as high as 90% capacity factor in some areas to make up for shut downs in the coal fleet. However, many of these facilities have historically run at lower capacity, with capacity factors ranging from 30 to 70%. [EPA-HQ-OAR-2009-0491-3928[1].1, p.6]
In the immediate term, the supply shortages may lead to rolling blackouts. However, it also likely will lead to the hasty construction of new plants-which would be an inefficient solution. First, new plants may be inefficiently run due to time constraints in construction. Second, it is inefficient to build new, expensive plants when existing facilities are not permitted to run at full capacity. Third, because new plants will be limited to allowances available through the new plant set-aside proposed in the Transport Rule,18 new plants will also have constrained capacity. Thus, this may create a situation where you have an existing plant and a new plant both run at 40% capacity factor, even though it is far more efficient to have one plant running at 80% capacity factor. This would result in the same level of emissions, but would be a huge waste of capital in a time when the nation cannot afford it. [EPA-HQ-OAR-2009-0491-3928[1].1, p.7]
This absurd and inefficient result is also entirely inconsistent with President Obama's new executive order, 'Improving Regulation and Regulatory Review.' The executive order states the general principles of regulation, including that the regulatory system 'promote predictability and reduce uncertainty' and 'identify and use the best, most innovative, and least burdensome tools for achieving regulatory ends.' The order directs an agency to 'tailor its regulations to impose the least burden on society' and to 'select, in choosing among alternative regulatory approaches, those approaches that maximize net benefits (including potential economic, environmental, public health and safety, and other advantages; distributive impacts; and equity).' However, EPA's Proposal adopts an approach that would impose the most burden on society-likely forcing an investment in the construction of new plants when existing plants could increase capacity and meet demand. This approach certainly does not maximize net benefits. [EPA-HQ-OAR-2009-0491-3928[1].1, p.7]
In contrast, states typically do regular re-allocations to adjust for changes in the source mix, capacity, etc. Re-allocations will be necessary to reflect the current and future status of statewide generation. However, neither the Transport Rule nor the Transport Rule NODA allow for re-allocations. This omission, in combination with EPA's reliance on historic heat input data, acts as a disincentive for greater utilization of these cleaner, more efficient gas plants. [EPA-HQ-OAR-2009-0491-3928[1].1, p.8]
EquiPower highlighted a number of significant flaws in the data and methodology that EPA used in the Transport Rule. For example, EPA's methodology for Phase I of the Transport Rule is based upon its estimate of the NOx and SO2 reductions that EPA believes could be obtained using existing controls or controls that EPA believes will be installed by 2012. However, there were fundamental problems with the underlying data and assumptions that EPA used to determine what NOx and SO2 reductions could be achieved without installing additional controls. [EPA-HQ-OAR-2009-0491-3928[1].1, p.10]
Aside from this error, Massachusetts' state budget would still be significantly short. EGUs in Massachusetts have had to make drastic NOx and SO2 reductions to meet the requirements of the NOx SIP Call, CAIR and Massachusetts regulations requiring the oldest, highest-emitting ("Filthy Five") plants in the state to significantly reduce their emissions. Therefore, the majority of EGUs in Massachusetts have already installed new control technology, and, therefore, cannot rely upon controls to reduce their emissions. While a few units are anticipated to retire, the state will still likely be short allowances because other EGUs will increase operations to make up for the retired sources. [EPA-HQ-OAR-2009-0491-3928[1].1, p.11]
Additionally, state budgets are inaccurate because EPA made assumptions about the level of control provided by existing controls which assumed that older, but still effective controls, obtained emissions rates that were equal to rates obtained by newly installed controls even though the Agency had (and should have used) data showing the actual level of performance achieved by those existing controls. Moreover, EquiPower does not believe that EPA's assumed control rates for new controls are necessarily achievable on a sustained basis because they only reflect the level of control obtained when a unit is operating at peak capacity and do not reflect the level of control obtained during periods of start-up, shutdown, or non-peak operation that occur throughout the year at most sources. Again, these inaccuracies led to underallocated state budgets because EPA has not determined the reductions that are actually achievable without installing additional controls. These problems, coupled with the inadequate time to install controls and likely lack of available allowances on the market (described in III.A.1 above), illustrate why Phase I implementation of the Transport Rule is infeasible and should be abandoned. [EPA-HQ-OAR-2009-0491-3928[1].1, p.11]
The Transport Rule NODA's Approach to Unit-Level Allocations Seeks to Obscure These Flaws by Using Heat Input Data, But This Is An Inadequate Solution
The Transport Rule NODA's proposed allocation methodology merely glosses over the flawed data and incorrect assumptions EPA relied upon in the Transport Rule by using heat input data rather than historic and projected emissions data. Thus, EPA's Transport Rule NODA shifts the emissions shortfall in the state budgets (described above) to higher-emitting facilities -- in EPA's own words "putting relatively greater burden on the higher-emission-rate units to reduce emissions or purchase additional allowances in order for the units to be in compliance with the proposed Transport Rule trading programs."  [EPA-HQ-OAR-2009-0491-3928[1].1, p.12]
However, under the Transport Rule NODA approach, all EGUs will still be penalized by the inaccuracies in the state budgets because the fundamental flaws in the initial state budget allocations will result in a lack of allowances available on the market and the assurance provisions will likely be triggered. When a state cap is exceeded, then all sources within the state will be penalized on a 2-to-1 basis for their proportional share of the emissions exceedance. Thus, EPA's attempt to gloss over its errors by using heat input data is no solution to the problem. [EPA-HQ-OAR-2009-0491-3928[1].1, p.12]
In contrast to the approach taken in the Transport Rule, EPA had previously given states the flexibility to determine unit-level NOx allocations under CAIR. Before that, EPA gave states the flexibility to determine unit-level NOx allocations under the NOx SIP call. These prior rulemakings confirmed the wisdom of giving the states a lead role in making unit-level allocation decisions. [EPA-HQ-OAR-2009-0491-3928[1].1, p.13]
If EPA does not allow states to implement the Transport Rule through SIPs, EPA must correct the underlying errors in its baseline data and assumptions and it must update state budgets. 
The Transport Rule NODA suggested that EPA was updating emissions inventories and modeling, but did not provide any details, did not state that it was reconsidering any of the assumptions relied upon in determining state budgets, and did not propose any changes to its approach to establishing state emissions budgets. Thus, it is unclear whether EPA will address any of the significant flaws in its data and assumptions or whether EPA will re-propose state budgets. However, given the magnitude of EPA's errors in the data and assumptions, the significance of the data and assumptions to the development of state emissions budgets, and the significance of state emissions budgets to the unit-level allocations, EquiPower submits that EPA must both fix the errors and re-propose the state budgets. [EPA-HQ-OAR-2009-0491-3928[1].1, p.13]
Massachusetts highlighted the need to retain output-based allocations in its October 1, 2010 comments on the Transport Rule. The comments described Massachusetts' tailoring of its regulations to address "important state policy issues, including output-based allocations," and stated that it was "unfortunate" that the Transport Rule timeframe did not allow for implementation of a SIP to incorporate "these important state policy goals." Massachusetts urged EPA to include in the final FIP a provision allowing states the flexibility to retain output-based allocations. Massachusetts also explained the benefits of its output-based approach, including encouraging more efficient generation. [EPA-HQ-OAR-2009-0491-3928[1].1, p.14]
Additionally, a critical part of the unit-level allocation approach should be to provide for periodic re-allocation. As EGUs make adjustments to operations to meet the required reductions under the Transport Rule, there will likely be adjustments to the generation distribution in each state. Thus, regular re-allocations will be necessary to take into account the changing distribution of electricity supply in each state. [EPA-HQ-OAR-2009-0491-3928[1].1, p.14]
EPA's proposal does not allow states to implement the Transport Rule through SIPs at any point during Phase I of the Transport Rule. EPA's Proposal requires that the final allocations for existing units be issued two years before the control period in which the allowances would be distributed. EPA acknowledges in the Transport Rule NODA that it "assume[s] that the first year for which state allocations might be used, in lieu of EPA allocation, would be 2014." What EPA does not acknowledge is the fact that it is highly unlikely that states would be able to meet the deadline for submitting a SIP proposal for the 2014 control year because the deadline would be November 1, 2011. Since EPA has not even finalized the Transport Rule, this deadline is nearly impossible to meet -- particularly since all states must promulgate a rule through notice-and-comment rulemaking prior to submitting their SIP revisions and some states must even enact legislation to promulgate a SIP. Given the short time period between when EPA is likely to finalize the Transport Rule and November 1, 2011, neither of those actions would appear even to be feasible. Thus, under EPA's Proposal, states are precluded from implementing the Transport Rule through a SIP for the first two or three years of the Rule, making it a certainty that the Transport Rule will be implemented through FIPs. Not only does EPA not have the authority to do so (as described below), but EPA's act of imposing FIPs makes it even more unlikely that states, such as Connecticut, Massachusetts, and New Jersey, that currently use output-based allocation methods would switch back to their own methodology after being required to adjust to EPA's heat input-based methodology. (See section III.B supra). [EPA-HQ-OAR-2009-0491-3928[1].1, pp.15-16]
Even when states are able to submit SIPs under EPA's Proposal, they will have limited discretion to decide how best to achieve the emission standards for their state. A state submitting an abbreviated SIP under EPA's Proposal could substitute its own unit-level allocation provisions for EPA's unit-level allocations, but could not change other aspects of the Transport Rule trading program. A state submitting a "full SIP" under EPA's Proposal must adopt Transport Rule trading program regulations but may adopt its own unit-level allocation provisions like states submitting abbreviated SIPs. [EPA-HQ-OAR-2009-0491-3928[1].1, p.16]
EPA Did Not Make the Statutorily-Required Findings and Does Not Have Authority to Directly Implement FIPs
Congress recognized the wisdom of giving states the primary authority for the "on the ground" decisions about how air quality standards should be met. The CAA commits to the states "the primary responsibility for assuring air quality within [the state] . . . by submitting an implementation plan . . . which will specify the manner in which national primary and secondary ambient air quality standards will be achieved and maintained . . . in such state." The CAA limits EPA's authority to implement FIPs, requiring EPA first to make one of three findings: (1) that the state failed to submit a SIP or SIP revision; (2) that the SIP submission is incomplete; or (3) that EPA disapproves the SIP in whole or part and the state fails to correct the deficiency before EPA promulgates a FIP. Under Title I, EPA cannot implement a FIP until one of these statutorily-required findings is made. While EPA's Transport Rule NODA proposes the option for states to submit SIPs years after the Transport Rule actually goes into effect, this does not cure the fundamental defect in EPA's approach. Both the Transport Rule NODA and the Transport Rule ignore the procedural prerequisites in the statute by directly implementing FIPs without providing states the opportunity, to which they are entitled under law, to promulgate a SIP to meet the emission reductions required under the Transport Rule. As a result, EPA's implementation of FIPs in Connecticut, Massachusetts, and New York is contrary to law. [EPA-HQ-OAR-2009-0491-3928[1].1, pp.16-17]
EPA has no authority to implement FIPs in any of these states to address the 2006 PM2.5 NAAQS transport requirements because EPA has not made a statutorily-required finding under § 110(c)(1). EPA bases its authority to issue a FIP, in part, upon a finding of failure to submit 2006 PM2.5 NAAQS SIPs for a number of states. That finding, however, did not include Connecticut, Massachusetts and New York. Thus, since EPA has not made the statutorily required findings for any of the three states, it may not implement a FIP addressing the 2006 PM2.5 NAAQS. [EPA-HQ-OAR-2009-0491-3928[1].1, p.17]
Additionally, EPA's explanation for its authority to implement FIPs to address the 1997 Ozone and PM2.5 NAAQS transport requirements is unsupported in law -- and it is particularly flawed for Massachusetts and Connecticut. As background, EPA made a finding in 2005 that states had failed to submit SIPs meeting the transport requirements for 1997 Ozone and PM2.5 NAAQS, but EPA later promulgated CAIR and determined that if states promulgated SIPs meeting CAIR requirements, the transport requirements would also be satisfied. Most states (including Connecticut, Massachusetts and New York) submitted SIPs, which EPA approved, and EPA withdrew the CAIR FIPs for those states. Despite these approvals, EPA argued in the Transport Rule (without any support in the CAA or case law), that the D.C. Circuit Court of Appeals' remand of CAIR in December 2008 in some way repeals EPA's approvals -- thus returning into effect the 2005 findings of failure to submit for the states in which EPA approved SIP revisions under CAIR. This is simply untrue. [EPA-HQ-OAR-2009-0491-3928[1].1, pp.17-18]
EPA's approval of each SIP as meeting the transport requirements and withdrawal of the CAIR FIP ended EPA's authority to dictate how states meet the transport requirements of the CAA. As an example, in approving Connecticut's SIP (for ozone-season NOX) EPA stated, "[o]nce the SIP is fully approved, EPA no longer has authority for the FIP." The D.C. Circuit's decision in North Carolina v. EPA did nothing to restore that authority to EPA. The decision did not invalidate SIPs as they were not before the court, and even if they had been, the court remanded CAIR rather than vacating it. Thus, the D.C. Circuit's opinion does not satisfy any of the three statutory prerequisites to EPA being granted authority to implement a FIP as it does not constitute a state's failure to submit a SIP; it does not constitute an EPA determination that a SIP is incomplete; and it does not constitute an EPA disapproval of a SIP. [EPA-HQ-OAR-2009-0491-3928[1].1, p.18]
EPA's position is further undermined by its own inconsistent actions. EPA issued six additional SIP approvals after the D.C. Circuit's remand of the CAIR rule in December 2008. In these approvals, EPA explained that it was moving forward in approving SIPs under CAIR consistent with the D.C. Circuit's goal in remanding the rule to "temporarily preserve environmental values covered by CAIR." If EPA interpreted the D.C. Circuit's decision as repealing CAIR-approved SIPs, it would not have gone through the time and effort of approving the additional SIPs (as late as December 2009). [EPA-HQ-OAR-2009-0491-3928[1].1, pp.18-19]
Setting aside EPA's flawed argument regarding the effect of North Carolina v. EPA, EPA still would not have authority to directly implement FIPs in Connecticut and Massachusetts for the SO2 and annual NOX programs even under EPA's own interpretation of the law. Under CAIR, these states were only required to impose controls to address the interstate transport of ozone during the summer ozone-season (May to September). Connecticut and Massachusetts both complied with this requirement by promulgating SIPs that EPA approved as meeting CAIR's transport requirements. Since Connecticut and Massachusetts were not covered under the CAIR rule for 1997 PM2.5 transport, EPA may not directly implement a FIP for this NAAQS  -  i.e., for annual NOx and SO2 reductions.[EPA-HQ-OAR-2009-0491-3928[1].1, p.19]
Moreover, EPA's proposal to issue FIPs for Massachusetts and Connecticut is plainly inconsistent with what EPA did with respect to Kansas under the Transport Rule -- a state that was not covered under the original CAIR rule, either for ozone or PM2.5. There, EPA acknowledged that it never issued either an original SIP call (under CAIR) or a FIP for Kansas, and as such, EPA (implicitly) acknowledged that it does not have the authority to proceed directly to a FIP for Kansas, even under the (flawed) reasoning in the preamble to the Proposed Rule. As a result, EPA proposed to issue a SIP Call and establish a deadline for Kansas to submit a new transport SIP for the 1997 ozone NAAQS that complies with the Transport Rule's requirements. The reasoning employed by the Agency with respect to Kansas applies directly to Massachusetts and Connecticut at least with respect to the PM2.5 NAAQS, and thus, the annual NOx and SO2 components of the Transport Rule. As with Kansas, EPA's own reasoning in the Transport Rule provides it with no legal basis to issue a FIP for PM2.5 in Massachusetts and Connecticut, and thus, at minimum, those states should be subject to a SIP call deadline before being subjected to a Transport Rule FIP.[EPA-HQ-OAR-2009-0491-3928[1].1, pp.19-20]
EPA's approach is contrary to case law assessing EPA's authority under the CAA. The case law makes clear that when EPA usurps the authority Congress committed to the states, it contradicts the cooperative federalism dictates of the CAA. The regulatory framework is clear: EPA has the authority to set and enforce the air quality standards, but states have the primary role in determining how those air quality standards are met. Courts have consistently upheld this framework. For example, in Train v. Natural Resources Defense Council, the Supreme Court considered "whether Congress intended the States to retain any significant degree of control [over] the manner in which they attain and maintain national standards" and found that EPA "is relegated by the Act to a secondary role in the process of determining and enforcing the specific, source-by-source emission limitations which are necessary if the national standards it has set are to be met."  As the Seventh Circuit Court of Appeals has stated, the CAA "is an experiment in federalism, and the EPA may not run roughshod over the procedural prerogatives that the Act has reserved to the states . . ."  In Virginia v. EPA, the D.C. Circuit Court of Appeals cited Train and noted with approval other circuit precedent similarly establishing this division between EPA and state control over the manner in which air quality standards are met within states borders. For example, the D.C. Circuit has held that the CAA did not give EPA the authority to condition approval of a SIP upon adoption of a specific control measure.  The common theme in all these cases is that states have the discretionary authority to develop the SIPs, as long as those SIPs meet the standards established by EPA. [EPA-HQ-OAR-2009-0491-3928[1].1, pp.20-21]
In sum, if EPA has made a finding that these states' SIPs are "substantially inadequate to attain or maintain" the relevant NAAQS, to "mitigate adequately" interstate pollutant transport or otherwise fail to comply with requirements of the CAA, the CAA requires that EPA notify the states of the inadequacies in the SIPs and allows EPA to set "reasonable deadlines" for states to submit SIP revisions. It does not allow EPA to immediately propose FIPs for those states. Thus, EquiPower recommends that EPA comply with the procedural requirements of the CAA and: (1) issue a SIP call; (2) allow states reasonable time to propose SIPs; and (3) then determine whether the SIPs meet the requirements of the CAA. Only after it takes those actions would the Agency be in a position, if necessary, to implement FIPs in the 32 states covered by the Transport Rule. [EPA-HQ-OAR-2009-0491-3928[1].1, p.21]
The Transport Rule NODA, like the Transport Rule, directly implements the regulations through FIPs, but EPA does not have authority to do so as it has not made the statutorily-required findings and EPA's approach is contrary to the cooperative federalism dictates of Title I of the CAA. [EPA-HQ-OAR-2009-0491-3928[1].1, p.21]
Therefore, EquiPower submits that EPA should: (1) issue a SIP call and allow states reasonable time to propose SIPs; (2) re-propose the Transport Rule after correcting its errors in data and assumptions; and (3) If EPA does not decide to implement the Transport Rule through SIPs, it should codify states' existing approaches to unit-level allocations and allow for periodic re-allocations. [EPA-HQ-OAR-2009-0491-3928[1].1, pp.21-22]

18 Additionally, the Transport Rule does not provide for reallocation, so the new plant set-aside will be static in time.
Response: 
First, EPA notes that Massachusetts and Connecticut are not covered in the final Transport Rule, rendering moot several of the concerns raised by the commenter. For states subject to the Transport Rule and the analysis that lead to those determinations, please see Preamble Sections V and VI.
EPA releases EGU emissions data quarterly, rapidly providing information to the market on state-wide emissions.  Consequently, EPA anticipates that sources will be able to factor the progression of a state's emissions throughout the year into their trading decisions, and that sources will not engage in "allowance hoarding" as they can collectively witness the ability of the state as the year progresses to respect its assurance level. 
Furthermore, EPA notes that the commenter's hypothetical example of new and existing units running at inefficient low capacity levels does not apply to any recognizable requirements of the Transport Rule programs. First, the commenter appears to ignore the Transport Rule's allocation methodology to new units, which is largely based on the new unit's emissions in the prior control period.  As described in section VII.D, EPA has established the size of each state's new unit set aside based on projected emissions from planned units specifically located in that state in addition to the largest share of a state's Transport Rule budgets projected to be emitted by potential units in any covered state.  The commenter also ignores that allocations to existing units which cease operation are redistributed to the new unit set asides.  As a result, the commenter's allegation that the new unit set asides will be oversubscribed is baseless and unsubstantiated.  With that allegation removed, the hypothetical example of the Transport Rule somehow forcing an inefficient standoff between new unit and existing units cannot withstand rational scrutiny.
Organization: Exelon
Comment: 
Exelon
We continue to urge EPA to implement the rule largely as proposed and to do so as quickly as possible. Specifically, we encourage the EPA to issue its final Transport Rule during the first half of 2011 and to require full implementation of the final rule no later than January 1, 2012. [EPA-HQ-OAR-2009-0491-3919[1].1, p.1]
As set forth in its comments on the Transport Rule dated October 1, 2010 ("Original Comments"), Exelon strongly supports EPA's efforts to reduce the impacts of releases of SO2 and NOx from uncontrolled electric generating units on downwind populations, and continues to urge implementation of the final Transport Rule by January 1, 2012. The proposed Transport Rule will further promote the modernization of the electric generating industry and reduce the implicit "pollution charge" that stymies growth and economic development in Exelon's primary service areas. [EPA-HQ-OAR-2009-0491-3919[1].1, p.2]
To that end, Exelon believes that both proposed changes affecting EPA's allocation scheme militate in favor of EPA's adopting the improved method for calculating the share of emissions against which compliance is measured (i.e., the owner's share) suggested in Exelon's original comments. Original Comments at 24-26, 30-42. [EPA-HQ-OAR-2009-0491-3919[1].1, p.3]
As noted in the Original Comments, Exelon strongly supports the policy objectives underlying EPA's proposals, which represent a first step in efforts that will provide the clarity in environmental policy essential to the industry's plans to meet America's growing demand for power while reducing impacts on public health and the environment. [EPA-HQ-OAR-2009-0491-3919[1].1, p.3]
As noted in the Original Comments, it is important to maintain an allocation method based on an historic metric that is not "updated" (i.e. changed) in future years in order to avoid creating perverse operating incentives. Original Comments at 31. Use of historic heat input, as proposed by EPA in the NODA, is such an historic metric. [EPA-HQ-OAR-2009-0491-3919[1].1, p.5]
The assurance provision set forth in the Transport Rule, as originally proposed, created a "budget" for measuring compliance equal to the emissions allocated to the affected EGUs (which are summed to create the "owner's share"). Both the allowance allocation and the owner's share reflected EPA's judgment regarding which facilities should install and operate control equipment. Importantly, EPA's original allocation scheme and its "owner's share" calculation were designed to work in tandem. Changing one without the other will make compliance more problematic. [EPA-HQ-OAR-2009-0491-3919[1].1, p.11]
As discussed in the Original Comments, EPA should also allow owners of units smaller than 25 MW to opt into the Transport Rule cap and trade program. See, Original Comments at 42-43. This is important to compliance because many of these units are included in existing state programs and both compliance and enforcement will be simplified if the same universe of units is covered. EPA does not need to provide any opt-in unit with any allocation of allowances. [EPA-HQ-OAR-2009-0491-3919[1].1, p.16]
Response: 
For reasons described in Preamble Section VII.B, the final Transport Rule does not allow any non-covered units to opt into the trading programs as administered under the FIPs, although states may consider allowing small EGUs of 25 MW or less to opt-in under a Transport Rule SIP.
Organization: Exxon Mobil Corporation
Comment: 
Exxon Mobil Corporation
1. Current Air Quality for Ozone demonstrates few states should be subject to the CATR proposal - For example, it appears that at year end 2010 only 2 nonattainment areas (Tarrant County, TX Ozone design value of 0.084 ppm and Harford County, MD with an Ozone design value of 0.089 ppm) have an Ozone design value exceeding the 1997 8-Hour ozone NAAQS of 0.08 ppm. We suggest that many states which the EPA CATR proposal shows as contributing to downwind Ozone non-attainment by modeling should be removed from this program based on an evaluation current air quality data. We strongly recommend and support EPA providing guidance that will provide clarity about the use of current air quality data in the determination of whether a state has a downwind Ozone NAAQS impact. [EPA-HQ-OAR-2009-0491-3999[1].1, p.1]
Comment 1 : EM reiterates and incorporates herein by reference prior comments EM made on the proposed CATR/FIP that were filed on October 1, 2010 and on the September 1, 2010 NODA filed on October 15, 2010. In particular, EM reiterates its position that Louisiana sources should not be subject to the proposed CATR/FTP because Louisiana emissions of sulfur dioxide (SO2) and nitrogen oxides (NOx) are not interfering with the attainment or maintenance of the National Ambient Air Quality Standards ('NAAQS') for PM2.5 in Harris County, Texas. The modeling which indicated that Louisiana sources will interfere with maintenance of the PM2.5 NAAQS at one monitor, the Clinton Drive monitor, in Harris County, Texas is simply wrong. That modeling was based upon significant errors noted in EM's prior comments. It is our understanding that EPA is conducting modeling with revised input data based upon comment in this docket. As indicated in EM's prior comments, Harris Co., Texas has been in attainment with the PM2.5 NAAQS for some time and the design values at the Clinton Drive monitor have continued to show an improving trend. There is simply no basis for inclusion of Louisiana within CATR for the annual SO2 and annual NOx trading Programs. [EPA-HQ-OAR-2009-0491-4028, p.2]
Likewise, EM's prior comments demonstrated that Louisiana sources should not be included in CATR for the ozone season NOx trading program because Louisiana emissions do not significantly impact attainment of the 1997 8-hr ozone NAAQS in either the Houston or Dallas areas. As noted in EM's prior comments, the Houston area has been in attainment for two years and the Dallas area is very close to attainment. EM is confident that the revised, corrected modeling to be performed by EPA will demonstrate that Louisiana emissions do not have a significant impact on the ability of the Dallas area to attain or maintain attainment with the 1997 8-hr ozone standard. [EPA-HQ-OAR-2009-0491-4028, p.2]
EPA initially proposed allocations based on IPM v. 3.02, and then revised the allocations based upon the September 1, 2010 NODA which relied upon IPM  v. 4.10. Both IPM-based allocation sets significantly penalized EM's operations and those of other clean-burning, natural gas fired EGUs within Louisiana. The IPM based allocations used unrealistic economic projections that predicted an almost near cessation of usage of the EM Louisiana 1 units. [EPA-HQ-OAR-2009-0491-4028, p.3]
The proposed IPM v. 4.10 allocation for the five Louisiana 1 Generating Station units for annual NOx was only 27 tpy despite the fact that these units actually emitted 1646 tpy in 2005 and average over 1500 tpy. The ozone season NOx allocation was equally as flawed - with only 27 tpy allocated even though ozone season NOx averages over 500 tons per ozone season. As indicated in its prior comments, EM does not plan to cease operating its refining oz chemical manufacturing facilities or its Louisiana 1 Generating assets . The IPM v. 4.10 allocations were wholly inadequate to allow EM to continue its business operations even though these units have a well controlled NOx emission rate. [EPA-HQ-OAR-2009-0491-4028, p.3]
Response: 
Thank you for your comment.Organization: First Energy
Comment: 
First Energy
FirstEnergy believes this rulemaking is NOT needed in order to attain the current national ambient air quality standards for ozone and fine particulate and meet the intention of the Court. To illustrate this point, the Midwest Ozone Group (MOG) retained Alpine Geophysics to conduct air quality modeling using the latest version of CAM-x, utilizing a 2008 emissions and meteorology platform. The modeling effort that followed EPA protocol showed by using more recent (2008) meteorology and emissions data that virtually all 8h Ozone and PM non attainment areas come into attainment by 2014, with the three residual monitors remaining in nonattainment due to local, not transported, emission sources. This modeling, which was summarized by MOG and referenced in our original comments on the CATR rule submitted on October 1, 2010, demonstrated essentially universal attainment of the ambient standards. Given the Court did not establish a deadline for EPA to revise CAIR and that revised modeling will demonstrate widespread attainment the CATR rule is actually not needed unless revised standards for PM and Ozone result once again in widespread non-attainment issues. [EPA-HQ-OAR-2009-0491-3904[1].1, pp.1-2]
EPA's final rule should incorporate all data corrections identified in public comments regarding the original Proposed Transport Rule, NODA I, and NODA II (Docket ID No. EPA-HQ-OAR- 2009-0491-2756.1 (Oct. 1, 2010); Docket ID No. EPA-HQ-OAR-2009-0491-3773.1 (Oct. 15, 2010); and Docket ID No. EPA-HQ-OAR-2009-0491-3853.1 (Nov. 24, 2010)). Additionally, EPA should repropose the rule providing an additional 60 day public comment period. This will provide the necessary public transparency required for a rule of this significance and complexity. FirstEnergy and the public can support a final rule that fixes incorrect modeled ambient levels, source apportionment methodologies, construction schedule assumptions, cost curves, unit specific data, and future unit operations and pollution control installations. [EPA-HQ-OAR-2009-0491-3904[1].1, p.2]
FirstEnergy objects to the use of a proprietary model that has not been peer reviewed or publically scrutinized to define state by state allocations of allowances. [EPA-HQ-OAR-2009-0491-3904[1].1, p.2]
FirstEnergy supports the EPA's alternative approach to the assurance provisions on an Owner by Owner basis instead of the Designated Representative ("DR") by DR basis. The DR by DR assurance provision simplifies the responsibility of a utility to manage and track CATR allocations.    [EPA-HQ-OAR-2009-0491-3904[1].1, p.3]
State SIPs
FirstEnergy does not support the Federal Implementation Plan (FIP) first approach of the USEPA, but FirstEnergy does support the right of each State to develop a their own SIP prior to finalizing the proposed rule. Typically, the States have a far better understanding of the actual root cause behind local ambient monitor non-attainment and should be given the opportunity to address the root cause at the local level. The FIP first approach attempts to address nonattainment with a broad brush, with a primary focus on power plant emissions and no assurance that this is universally the most cost-effective path to achieving attainment. [EPA-HQ-OAR-2009-0491-3904[1].1, p.3]
The USEPA should hold off finalizing the CATR until 2014, as supported by the recent MOG study. The study finds, all but two (2) monitoring sites fall into attainment under the original CAIR and remain in attainment through 2018. The short SIP completion timeframe and restrictive boundaries proposed in NODA III restricts the flexibility of each State to develop a meaningful and economically viable SIP. Finalizing CATR in 2014 also provides each State the opportunity to develop and propose a SIP that meets the guidelines of the CATR as framed by the court. This should be done before prematurely imposing a FIP. [EPA-HQ-OAR-2009-0491-3904[1].1, p.3]
Modeling to project State budget allocations could also be improved given the additional time for States to develop their own SIP. EPA could use the provided SIPs as an additional model input. This would eliminate the economic bias IPM places on States, since IPM allocates each State's allocation budget through these inputs. Delaying the rule until 2014 and allowing SIPs to be developed by each affected State, would necessitate an additional 60 day comment period to the final CATR. [EPA-HQ-OAR-2009-0491-3904[1].1, p.3]
But whatever allocation approach is selected by the EPA, the EPA must provide the regulated community an additional 60 day period to digest and comment on the revised rulemaking incorporating the most accurate modeling assumptions and database corrections from the submitted comments from all three NODA's and the original CATR. FirstEnergy believes that an additional comment period should be established to allow public comment on all previously identified data corrections. [EPA-HQ-OAR-2009-0491-3904[1].1, p.4]
Recognizing there is no deadline to address a CAIR remedy, FE strongly suggests EPA take the time to get it right by factoring in the upcoming revisions of the Ozone and PM 2.5 NAAQS, and by utilizing the most recent and most accurate emissions data and power sector estimates available to develop a revised rule. We believe this will demonstrate that the stated health benefits can be achieved with a far less onerous CATR rule that is less disruptive to business and the economy. Further, the EPA should utilize a coordinated approach and modeling effort to include assessment of the impact of all of the regulatory initiatives facing the electric utility industry, and in particular the EGU MACT Rule. A coordinated approach would reduce regulatory uncertainty and minimize the inefficiency associated with compliance with sequential and in many ways contradictory regulatory programs, and would likely demonstrate that the CATR rule is on balance totally unnecessary to demonstrate ambient attainment. [EPA-HQ-OAR-2009-0491-3904[1].1, p.4]
Response: 
The commenter objected to the use of IPM to define state by state allocations of allowances in the proposed rulemaking.  IPM was not used for this purpose in the final rulemaking.
EPA disagrees with the commenter's characterization of the IPM model and EPA's use of IPM modeling in the development of the Transport Rule.  EPA has made all modeling assumptions, inputs, and results publicly available both at proposal and in a subsequent detailed NODA, and the Agency has received, reviewed, and implemented changes for the final rule based on numerous public comments on these data.  Contrary to the observation made in the comment, IPM is subject to regular peer review.
Regarding the Transport Rule's interaction with other regulations, please see Preamble Section IX. EPA appreciates that many EGUs will have compliance obligations under both the Transport Rule and the Mercury and Air Toxics Standards (MATS),but notes that MATS has not been finalized yet and therefore was not included in the Transport Rule analysis. For more information on how EPA developed a baseline for Transport Rule analysis, please see Preamble Section V.B. EPA finds no reason to doubt that EGU owners and operators will be able to make sound investment and operational decisions on the basis of compliance with this final Transport Rule and the finalization of MATS later this year.  In fact, EPA believes that finalization of the Transport Rule today greatly increases regulatory certainty in the power sector and provides an additional "known" which will allow for better compliance planning in regard to other pending regulations the Agency has proposed.

Organization: Florida Department of Environmental Protection
Comment: 
Florida Department of Environmental Protection
  We are also aware that EPA is completing a re-analysis of states' contribution to nonattainment areas in other states using corrected data provided during the previous comment period. Our understanding is that the results of this re-analysis, and any resulting changes (potentially major changes) to states' applicability, would not be made available until the Transport Rule goes final. Consequently, we strongly urge you to re-propose the rule to allow states and other affected entities the opportunity to comment on the re-analysis prior to any final agency action. [EPA-HQ-OAR-2009-0491-3879[1].1,p.1]
Response: 
Thank you for your comment.Organization: Florida Electric Power Coordinating Group, Inc. (FCG)
Comment: 
Florida Electric Power Coordinating Group, Inc. (FCG)
EPA Must Publish another Proposed Rule
The FCG cannot overemphasize that EPA's piecemeal approach in its development of the Transport Rule deprives affected parties adequate opportunity to effectively participate in the rulemaking process and, therefore, is legally deficient. EPA must allow for stakeholder involvement as it develops and publishes a second proposal addressing all of the comments. The second Proposed Rule, along with all information used to develop the proposal, should be provided at the same time so that affected parties can understand the impacts of the Proposed Rule and participate meaningfully in the rulemaking process. [EPA-HQ-OAR-2009-0491-3990[1].1, pp.1-2]
While the January NODA presents alternative allocation methodologies that do not rely on model-predicted emissions, it does not address EPA's use of the flawed IPM model that establishes each state's significant contribution and interference with maintenance and each state's emissions budget. EPA has provided no evidence that it has corrected the numerous fundamental errors in the IPM model. The January NODA states that EPA is still in the process of updating its emission inventories and modeling and that state contributions and unit allocations could change, 76 Fed. Reg. 1111, 1114; therefore, publication of another Proposed Rule is critical for regulated sources to understand the precise extent to which they are affected by the Rule (for example, whether it will have to buy allowances, assuming they are available, and how many). [EPA-HQ-OAR-2009-0491-3990[1].1, p.2]
Additionally, the FCG reiterates previous comments that the Transport Rule need not be in place by 2012. As many commentators have noted, the Proposed Rule provides many electric generating units insufficient time to install controls or implement operational changes necessary to reduce emissions from historical levels to proposed allowances. Moreover, the Clean Air Act does not grant EPA authority to promulgate a FIP without first providing states adequate time and opportunity to develop and submit SIPs. States are better suited to develop fair and consistent approaches and/or allocations that take into consideration unique aspects of electric generating units in the state. Nonetheless, EPA recognizes in the January NODA that there will be insufficient time for states to develop SIPs, with or without allowance allocation provisions, and for EPA to review and approve such SIPs, before EPA will record allocations to existing units for 2012 and 2013. Thus, the first year for which state allocations could be used is 2014. The Transport Rule, therefore, should not begin before 2014. [EPA-HQ-OAR-2009-0491-3990[1].1, p.2]
As explained in prior comments, EPA's original proposal to use 2008 and 2009 as baseline years for NOx and S02 emissions, respectively, would not represent normal operating conditions for many of the units regulated under the Transport Rule. Additionally, EPA has never adequately explained its proposed use of different baseline years for the two pollutants. [EPA-HQ-OAR-2009-0491-3990[1].1, p.3]
Response: 
In the final Transport Rule, EPA has based state emission budgets on projected data, not on historic data.  EPA's budget-setting methodology in the final rule is the same for all pollutants regulated under the Transport Rule programs.
Organization: Florida Municipal Power Agency, Gainesville Regional Utilities, JEA, Orlando Utilities Commission, and City of Tallahassee
Comment: 
Florida Municipal Power Agency, Gainesville Regional Utilities, JEA, Orlando Utilities Commission, and City of Tallahassee
  The above mentioned community-owned electric utilities provide electric service to over 2.5 million Floridians. The electric generation resources for the City of Tallahassee, Gainesville Regional Utilities, Orlando Utilities Commission, JEA of Jacksonville, and the Florida Municipal Power Agency are almost entirely fossil fuel-based. Our utilities actively participated in the Clean Air Interstate Rule (CAIR) development and have installed or are in the process of installing additional air pollution controls to meet CAIR emission reductions requirements. All our utilities will be significantly impact by EPA's new and more stringent requirements of the proposed CATR. [EPA-HQ-OAR-2009-0491-3907[1].1, p.1]
Abbreviated or Full SIPs Revisions to Allow for State Allowance Allocations: We have commented previously through our state trade association, the Florida Municipal Electric Association, comments on the problems with "FIPing" states with regard to implementing CATR. There appears to be no mandate by the United States District of Columbia Court of Appeals that would require the proposed CATR compliance schedule, which forces EPA to impose Federal Implementation Plans (FIPs) on affected states, including Florida, rather than permitting states to develop State Implementation Plans (SIPs) to comply with CATR. We believe that EPA should return to the process established by the Clean Air Act in which EPA identifies emission reductions necessary to achieve NAAQS compliance (often with a suggested model rule) and with states responsible for developing the implementation plan best suited for their state. We believe that EPA should only use a FIP in cases where states fail to develop a SIP due to direct state inaction and not an unreasonable and arbitrary time requirement. [EPA-HQ-OAR-2009-0491-3907[1].1, p.2] 
In addition, we urge EPA to publish another proposed CATR for full public comment, after making the corrections to the data used to determine each state's contribution to downwind states, and prior to issuing a final CATR. [EPA-HQ-OAR-2009-0491-3907[1].1, p.2]
Response: 
Thank you for your comment.Organization: Fond du Lac Reservation
Comment: 
Fond du Lac Reservation
In a letter to the EPA dated September 29, 2010, Ms. Wiecks expressed concern with the lack of modeling specifically to how our citizens are affected by the pollution from our neighboring upwind states. This shortfall by the Agency is compounded due to the Federal government's trust responsibility. This mandate should provide assurance that the Agency is looking out for the health and welfare of the Band; however, this isn't the case if the agency just mixes tribal data with data from the surrounding state. By doing this, the Federal government fails to provide the assurance that the desired effect, of reducing NOx and S02 will be gained by the implementation of this rule. As a result, the Band, again, requests and recommends that the EPA redo its technical analysis to include Indian tribes and to gain a better understanding of the impacts and obligations truly associated with upwind states; technical analyses for any forthcoming Agency rule should consider Indian tribes as well. In support of this effort, particularly when an EPA rule is intended to affect the emissions of specific sources, the Agency should provide for an overlay of tribal lands so tribes can have a better understanding as to how they are being affected by such sources and how the proposed rule might improve their situation. [EPA-HQ-OAR-2009-0491-4021, pp.1-2]
Tribal allocations have several shortfalls that will be addressed here. First, when proposing a method for determining allocations for existing sources, the Federal government failed to provide reasonable allocations for Indian nations. This is a problem for several reasons, first and foremost, as a whole tribes are more cognizant and caring for the environment that surrounds them. This is so because of the spiritual and cultural significance in which our environmental surroundings hold, this is to say nothing about how tribes often rely on hunting, fishing and gathering rights to feed and care for its people. Second, by excluding tribes the Federal government is continuing the economic suppression of a population that it has historically oppressed. These allocations are likely to be the next form of currency, to be traded openly between entities to meet environmental or more than likely economic goals. As a result, this action knowingly excludes a sovereign population that has no other control over how its lands and resources are polluted. By being granted an existing allocation of credits a tribe will likely reduce the levels of emissions by that much more. This is due to the before mentioned spiritual and cultural beliefs of the tribes. Most tribes are likely to hold onto their allocations and keep them 'out of circulation.' A highly beneficial result of this is that there is ultimately less emission allowed into the environment. If tribes chose to put their allocations 'in circulation,' the tribe can barter with existing sources (utilities) to better provide for the health and welfare of its people. [EPA-HQ-OAR-2009-0491-4021, p.2]
In conclusion, we strongly recommend the consideration and implementation of modeling that will more accurately demonstrate the effects on Indian country and the individuals that live, work, hunt, fish and gather on reservations and ceded territories. We also strongly believe that a percentage of existing allocations is necessary for bringing some economic security as well as beginning to level the playing field. Without a portion of the existing allocations, Tribes will be unable to compete with large utilities. [EPA-HQ-OAR-2009-0491-4021, p.3]
Response: 
Since this letter was received, EPA has offered and participated in consultation with interested tribes regarding the Transport Rule and its potential impacts on tribes.  EPA also addressed tribal concerns and provided opportunity to comment in the January 7, 2011 Notice of Data Availability for Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone: Request for Comment on Alternative Allocations, Calculation of Assurance Provision Allowance Surrender Requirements, New-Unit Allocations in Indian Country, and Allocations by States.  EPA has taken appropriate action to fulfill its responsibilities to tribes.
EPA is designating a new unit set-aside for each state with federally recognized tribal land for any future EGUs constructed in Indian country in the Transport Rule region as part of the final rule.  EPA will maintain control of the Indian country new unit set-asides, even in the event that a state submits a Transport Rule SIP.  Allowances are allocated from the Indian country new unit set-aside if and when a covered EGU is constructed in Indian country and otherwise are returned to the state budget for allocation to existing or new units (or other uses in accordance with a state's SIP).  As allowances are ultimately required for compliance by emitting EGUs, unallocated allowances from the Indian country new unit set-asides are not provided to the tribes. See the preamble section VII.D for more details.
EPA's impacts and benefits analysis show that the emissions reductions required by the Transport Rule result in substantial decreases in transported PM2.5 and ozone concentrations throughout the eastern half of the United States.  EPA notes that the types and levels of reductions seen in states within this region will also be achieved by tribal locations that are encompassed within those states.  
With respect to the issue of "hot spots," EPA's air quality analysis for the Transport Rule did not show any resulting increases in ozone or PM2.5 anywhere in the Eastern United States as a result of this rule. 
Air quality in tribal areas and health effects for tribal people were considered in the benefits analysis, although they are not presented separately from the main analysis.  In addition, the distributional analysis, which examined the distribution of reductions in mortality risk due to reductions in PM2.5 exposure, does include specific analysis of changes in risk for Native American populations.
Organization: Forest County Potawatomi Community
Comment: 
Forest County Potawatomi Community
FCPC has a strong interest in the implementation and effects of the proposed rule, due to both the Tribe's general environmental ethic and the concrete impact the rule is likely to have on particular Tribal resources. Overall, FCPC strongly supports the timely implementation of the Transport Rule, which will significantly improve air quality throughout the eastern United States. [EPA-HQ-OAR-2009-0491-3882[1].1, p.1]
Response: 
Thank you for your comment.
Organization: Gainesville Regional Utilities (GRU)
Comment: 
Gainesville Regional Utilities (GRU)
GRU has commented earlier on the problems with 'FIPing' states with regard to implementing CATR. There appears to be no mandate by the United States District of Columbia Court of Appeals that would require the proposed CATR compliance schedule, which forces EPA to impose Federal Implementation Plans (FIPs) on affected states, including Florida, rather than permitting states to develop State Implementation Plans (SIPs) to comply with CATR. GRU believes that EPA should return to the process established by the Clean Air Act in which EPA identifies emission reductions necessary to achieve NAAQS compliance (often with a suggested model rule) and with states responsible for developing the implementation plan best suited for their state. [EPA-HQ-OAR-2009-0491-3922[1].1, p.2]
Response: 
Thank you for your comment.Organization: GenOn Energy, Inc.
Comment: 
GenOn Energy, Inc.
1. EPA appears to be rushing to adopt a final Transport Rule without giving the public, including the companies affected by it, nearly enough time to understand, analyze, and comment on the Rule -- especially in light of the serial re-proposals contained in the three different NODAs. Because the Clean Air Implementation Rule (CAIR) remains in place during this rulemaking, there is no environmental justification for this piecemeal approach and truncated schedule. In order to develop a sound program for replacing CAIR (and the NOx SIP Call, as well as the Acid Rain Program for much of the country), EPA should prepare a comprehensive supplemental proposal that incorporates revised and updated data, including the data provided in the three NODAs, in a way that allows an adequate period for public review and comment on a fully coherent proposal. This is of particular concern for NODA 3 because the allowance allocations affect other key provisions of the proposed rule, including the compliance assurance provisions. [EPA-HQ-OAR-2009-0491-3996[1].1, pp. 1-2]
2. EPA has now proposed three very different schemes for distributing allowances, but has done almost nothing to explain the possible justifications for choosing one over the other. The financial impacts of these different schemes vary dramatically, and yet the Agency has only given us 30 days to digest and comment on them. For GenOn, the differences between the various options are substantial and potentially vary by many millions of dollars. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 2]
6. EPA cannot adopt either of the NODA 3 allocation options without reconsidering the proposed compliance assurance scheme or pushing back the compliance schedule. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 2]
a. Under the original proposal, GenOn would receive many more allowances than what is now contemplated under NODA 3. If either of the NODA 3 options were to be adopted in the final rule, GenOn would face a much greater risk of running afoul of the proposed compliance assurance provisions. Yet given the proposed compliance schedule, there would not be sufficient time for any company to install additional control devices beyond those already under construction or planned. EPA must either push back the compliance schedule or proceed with the original scheme for distributing allowances based on projected future emissions (or both). [EPA-HQ-OAR-2009-0491-3996[1].1, p. 3]
b. The new allocation schemes proposed in NODA 3, along with the proposed compliance assurance provisions, also create serious problems for companies that must bid their units into the day ahead energy markets and participate in future year capacity auctions. Units must be bid into the day ahead market based on the cost of generation, but the unit owner will not know for sure whether the state will exceed its budget plus variability and thus whether the unit will incur additional costs to meet the enhanced allowance surrender requirements. Of course, this was a potential problem even under the original proposed allocation, but much less of a concern because the allocation was much closer to projected emissions, which made it easier for a plant to control its own destiny. Moreover, GenOn is now preparing for capacity auctions that require estimates of available capacity for 2015. The uncertainty created by the Proposed Transport Rule and exacerbated by NODA 3 has made it difficult to estimate future capacity and to understand how to participate in the ongoing capacity auctions. This situation highlights the need for EPA and energy regulators to make a greater effort to align the timing and impacts of their respective regulatory requirements. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 3]
7. Regardless of the allocation approach adopted by EPA, the Agency must ensure that the final rule does not provide an incentive for old units to run simply to avoid losing the allowances allocations for those units. In the original proposal, EPA proposed to continue allocating allowances to non-operating units during the 3 consecutive years of non-operation plus an additional 3-year period. 75 Fed. Reg. 45210, 45310-45311. We believe the best way to ensure that old and inefficient plants do not run solely for the purpose of maintaining allowances is to adopt the approach chosen by Congress in the Acid Rain program and maintain perpetual allocations for incumbent units. If EPA proceeds with either of the NODA 3 allocation options, it should either adopt the Acid Rain approach or the approach proposed in the original Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 3]
8. If EPA proceeds to issue a final Transport Rule without preparing a comprehensive supplemental proposal and allowing adequate time for public comment, then it should either: a. Adopt the allocation method proposed in the Transport Rule in August 2010; [EPA-HQ-OAR-2009-0491-3996[1].1, p. 3]
I. Given the complexity and importance of the Proposed Rule and the updated data and analysis provided in three subsequent NODAs, EPA should prepare a comprehensive supplemental proposal and allow adequate time for the public to understand, analyze, and comment on it. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 4]
As noted above, EPA published the Proposed Transport Rule on August 2, 2010. 75 Fed. Reg. 45210. Then, on September 1, 2010, EPA published a Notice of Data Availability with respect to the Proposed Transport Rule (NODA 1). 75 Fed. Reg. 53613. NODA 1 supplemented the Proposed Transport Rule with extensive new information that, in substantial part, concerns electric generating units (EGUs) and EPA's assessment of whether and to what extent SO2 and NOx emissions in certain states contribute to nonattainment or interfere with maintenance of national ambient air quality standards (NAAQS) for ozone and fine particulate matter in other states. Then, on October 27, 2010, EPA published a second NODA for the Proposed Transport Rule, primarily addressing emission inventory issues with respect to non-EGU source sectors. 75 Fed. Reg. 66055 (NODA 2). Most recently, on January 7, 2011, EPA published a third NODA for the Proposed Transport Rule, primarily addressing two possible alternative methodologies for allocation of SO2 and NOx emission allowances as well as certain related issues. 76 Fed. Reg. 1109 (NODA 3). [EPA-HQ-OAR-2009-0491-3996[1].1, p. 4]
However, even with four different proposals (the original Proposed Transport Rule and three subsequent NODAs), the proposed state budgets are based on a wide range of emission inventory and other data (and decisions based on those data) that, for reasons discussed in previous comments, have not been adequately explained and documented. These deficiencies, in turn, undermine the basis for EPA's proposed determinations of interstate contribution to nonattainment and interference with maintenance of NAAQS under section 110(a)(2)(D)(i) of the Clean Air Act. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 4]
Even without the complexities introduced by the recent string of NODAs, the Proposed Transport Rule raised a number of complex issues. These issues are not only complex, but of great importance to the power sector. As a practical matter, the Transport Rule will not only replace CAIR, but also the NOx SIP Call and, for much of the country, the whole Acid Rain Program. As is clear from the recent NODAs, the Proposed Transport Rule was not fully developed back in August when it was originally proposed and, in fact, is still not fully developed. The Agency must put together a fully coherent proposal, incorporating revised and updated data as appropriate, and then provide a meaningful opportunity for the public to review and comment on it. [EPA-HQ-OAR-2009-0491-3996[1].1, pp. 4-5]
We understand that this approach will delay EPA's rulemaking schedule, but such a delay will not have an adverse impact on air quality because EPA's Clean Air Interstate Rule (CAIR) will remain in effect during the pendency of the current rulemaking. CAIR was designed to accomplish the same objectives as the Proposed Transport Rule and will ensure that EGUs throughout the eastern U.S. continue to reduce their emissions of NOx and SO2. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 5]
Although the D.C. Circuit Court of Appeals found legal flaws in CAIR, the Court specifically allowed it to remain in effect until EPA is able to finalize the Transport Rule. Under these circumstances, there is no reason for EPA to rush to finalize the Transport Rule. EPA should take the time to ensure that the Transport Rule is carefully designed and legally defensible. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 5]
In the Proposed Transport Rule, EPA describes how it is proposing to determine whether emissions from one state "significantly contribute" to nonattainment problems in other states. 75 Fed. Reg. 45210, 45229-45299. The Agency then proposes to set state budgets for states that are found to be significantly contributing to downwind nonattainment. 75 Fed. Reg. 45218, 45290-45292. The purpose for setting state budgets is to ensure that each state will eliminate all emissions that are significantly contributing to nonattainment or maintenance problems in other states. To accomplish this objective, the Transport Rule requires each state to eliminate all EGU emissions that can be reduced cost effectively. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 5]
The purpose of distributing allowances is to allocate, among individual plants, the cost of meeting the state budget. This is not a trivial matter. EPA estimates that the annual compliance costs for the proposed Transport Rule range from $2.8 billion to $4.3 billion. 75 Fed. Reg. 45210, 45352. In the Proposed Transport Rule, the Agency indicated that it planned to distribute allowances to individual units using the same approach that it used for setting state budgets  -  using the lower of historic emissions or projected future emissions. Although some commenters were critical of this approach, many of them simply pointed to problems in the modeling assumptions for specific units that could be easily corrected. [EPA-HQ-OAR-2009-0491-3996[1].1, pp. 5-6]
Under the original proposal, GenOn would receive many more allowances than what is now contemplated under NODA 3. If either of the NODA 3 options were to be adopted in the final rule, GenOn would face a much greater risk of running afoul of the proposed compliance assurance provisions. Yet given the proposed compliance schedule, there would not be sufficient time for any company to install additional control devices beyond those already under construction or planned. EPA must either push back the compliance schedule or proceed with the original scheme for distributing allowances based on projected future emissions (or both). [EPA-HQ-OAR-2009-0491-3996[1].1, p. 9]
The new allocation schemes proposed in NODA 3, along with the proposed compliance assurance provisions, also create serious problems for companies that must bid their units into the day ahead energy markets and participate in future year capacity auctions. Units must be bid into the day ahead market based on the cost of generation, but the unit owner will not know for sure whether the state will exceed its budget plus variability and thus whether the unit will incur additional costs to meet the enhanced allowance surrender requirements. Of course, this was a potential problem even under the original proposed allocation, but much less of a concern because the allocation was much closer to projected emissions, which made it easier for a plant to control its own destiny. Moreover, GenOn is now preparing for capacity auctions that require estimates of available capacity for 2015. The uncertainty created by the Proposed Transport Rule and exacerbated by NODA 3 has made it difficult to estimate future capacity. This problem, of course, is made much worse by the other regulatory requirements that EPA intends to promulgate but has not yet finalized (such as the coal ash rule) or even proposed (such as Utility MACT and the 316(b) rule under the Clean Water Act.) This situation highlights the need for EPA and energy regulators to make a greater effort to align the timing and impacts of their respective regulatory requirements. [EPA-HQ-OAR-2009-0491-3996[1].1, p-. 9-10]
V. EPA must prepare a comprehensive supplemental proposal to allow for public review and comment on a fully developed proposed rule and seek comment on three options for distributing allowances. A. Adopting the allocation method originally proposed in the Transport Rule. B. Eliminate gas-fired plants from the SO2 program and distributing SO2 allocations based on heat input for coal- and oil-fired plants. C. Adopting a modified version of Option 2 from NODA3 that recognizes that (1) there is a vast difference between SO2 emission rates from well-controlled coal, gas, and oil-fired units and (2) there must be a more rational approach for considering the wide range of capacity factors. In particular, the use of the 95th percentile dramatically overstates actual operations of many peaking units. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 10]
Response: 
EPA has not included an upper-bound capacity factor in the final Transport Rule's allocation methodology to existing units. 
Organization: Georgia-Pacific LLC (GP)
Comment: 
Georgia-Pacific LLC (GP)
It should be noted that under the proposed Transport Rule (see Federal Register Volume 75, No. 147, August 2,2010, pps. 45210-45465) a cogeneration unit qualifies for an exemption from the proposed rule if it supplied in any calendar year-starting the later of November 15, 1990 or the start-up of the unit's combustion chamber-no more than one-third of its potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system (also referred to as the 'Grid') for sale. As it concems the criteria for cogeneration in the proposed Transport Rule, EPA requested comments on whether or not it may be problematic to obtain sufficiently detailed information about unit efficiency and operation back to November 15, 1990 and whether the operating standards should be limited to even more recent years by requiring that the standards be met every year starting the later of a date (e.g., January 1) of a more recent year (e.g., 2000,2005, or 2009) or the date on which the unit first produces electricity. GP supported the comments on this topic submitted by the American Forest & Paper Association (AF&PA) on October 1, 2010, which stated that facilities would be 'hard pressed' to get data that is more than 5 years old much less data back to 1990.   [EPA-HQ-OAR-2009-0491-3967[1].1, p.1]
On June 1, 2007, GP submitted a letter to EPA, under Docket No. OAR-2004-0076, as part of its comments on the NODA for EGU NO, annual and NOx ozone season allocations issued by EPA under the Clean Air Interstate Rule (CAIR). In that letter (copy attached), GP asked for a formal response from EPA as to the CAIR applicability for Boiler B25 at Green Bay's Broadway Operations. Boiler B25 is the only boiler out of the five units serving the three turbine generators with capacities greater than 25 MWh that does not individually have a thermal efficiency greater than 42.5%, notwithstanding the fact that the boilers/turbine generators as a 'system' at the Green Bay Broadway Operations have a common steam header and the 'system' thermal efficiency is greater than 42.5%. The 42.5% thermal efficiency is one of EPA's criteria for qualifying a boiler as a cogeneration unit under the CAIR Rule. [EPA-HQ-OAR-2009-0491-3967[1].1, p.4]
Under the proposed Transport Rule (see page 45307), EPA has proposed to clarify the definition of a cogeneration unit such that if the cogeneration system of which a topping cycle unit (where power is produced first and then useful thermal energy is produced using the resulting waste energy) is a part meets the efficiency standard on a system-wide basis, then the unit is also deemed to meet that efficiency standard. EPA believes this definition is preferable because it addresses cases where one unit in a cogeneration system is operated at a lower efficiency (e.g., as a 'swing' unit whose use varies with demand) to allow the rest of the units in the cogeneration system to operate with higher efficiency. [EPA-HQ-OAR-2009-0491-3967[1].1, p.4]
Although GP has continued to provide additional data to EPA (Louis Nichols) when so requested concerning the CAIR applicability determination, GP has not received a formal response from EPA with its decision on whether or not Boiler B25 is subject to the CAIR, which EPA is proposing to replace with the Transport Rule. [EPA-HQ-OAR-2009-0491-3967[1].1, p.4]
Response: 
EPA thanks GP for its comment and providing information. EPA has provided a response to GP's original comment regarding B25 in this Response to Comment Document (section XX.A.3.)
Organization: Giarmarco, Mullins & Horton, P.C.
Comment: 
Giarmarco, Mullins & Horton, P.C.
As indicated in previous comments, the allocations proposed in the TR are based upon projections of utilization generated by the Integrated Planning Model that fail to reflect MCV's historic operations, as well as its long-term contractual obligations. MCV believes that the cause of this occurrence is EPA's treatment of MCV as a peaker facility which is incorrect. MCV is aware that other similarly situated natural gas-fired cogeneration facilities have also received inappropriate treatment under the IPM. As a result, MCV believes that should EPA choose to utilize the IPM results as opposed to the two alternatives discussed in the January 7, 2011 NODA, dispatch for cogeneration facilities should be set at a level consistent with the baseload operation of the facilities as reflected in the historic heat input. [EPA-HQ-OAR-2009-0491-4015[1].1, p. 2]
Response: 
EPA is not using IPM unit-level projections as a basis for existing unit allowance allocations under the final Transport Rule FIPs.
Organization: Great River Energy
Comment: 
Great River Energy
As discussed in our comments to the proposed rule, which were dated October 1, 2010, there were several inaccuracies with EPA's data set. Specifically, some of our emission units [Maple Lake (2042), Rock Lake (6741) and Cambridge Unit 1 (2038)] were listed  twice and had incomplete information, despite the fact that they had reported emissions under the Clean Air Interstate Rule (CAIR). Our October 1, 2010 comments provided the correct information on these emission units so that EPA could include them as part of the allocation process. [EPA-HQ-OAR-2009-0491-3898[1].1, p.2]
In our October 1, 2010, comments, Great River Energy questioned EPA's allocation methodology. In the original proposal, EPA allocated allowances based on an extremely short time period. Further, EPA's "Preferred Option" relied upon emissions from this short baseline period. At a minimum, Great River Energy commented that larger baseline should be used, since the proposed baseline represented a period of economic recession. We commented that we had significant concerns and that there was realistic potential for a state allowance monopoly. [EPA-HQ-OAR-2009-0491-3898[1].1,p .4]
Great River Energy can only support EPA's State Budgets/Limited Trading Proposed Remedy (the "Preferred Option") subject to comments provided herein. The Preferred Option has numerous limitations and contains critical errors, as discussed. Our support is contingent upon a viable and active interstate trading program and we have strong reservations about the existence of such activity. With respect to EPA's State Budgets/Intrastate Trading Remedy Option ("Option 2"), Great River Energy questions the "flexible and cost effective" nature of this program for Minnesota, given the effective monopoly that two utilities will have on the state's allowances.... [EPA-HQ-OAR-2009-0491-3898[1].1, p.4]
Under the Transport Rule, Great River Energy is faced with purchasing allowances as a sole compliance strategy. Great River Energy combustion turbines were not correctly allocated for the reasons presented herein. Controls are not cost effective for our combustion turbines, as deemed by EPA's own analysis. Great River Energy is worried that there will not be a viable intrastate trading program. Great River Energy is hopeful that interstate trading will bridge the compliance gap. This extremely awkward compliance strategy could easily result in years of allowance deficits and potential non-compliance, further penalizing Great River Energy's inherently clean simple cycle combustion sources.... Failing our preferred "allowance purchasing" option, GRE must consider installation of pollution controls, namely selective catalytic reduction ('SCR"), on our already controlled and, in certain instances, annually limited to synthetic minor thresholds per plant Title V permits. Our combustion turbines have been using Ultra Low Sulfur Diesel (ULSD <15ppm) since 2006. Therefore, we cannot expect to reduce SO2 emissions any further. With respect to NOx emissions, all of our units have dry low NOx (DLN) burners and water injection for oil combustion. These peaking plants are already controlled for Transport Rule pollutants, yet will not be able to meet EPA's proposed NOx allowance allocations. While simple cycle SCR installations may have been completed in California and other non-attainment areas, these controls fall well outside of EPA's cost thresholds for the Transport Rule. (GRE comments, October 1, 2010). [EPA-HQ-OAR-2009-0491-3898[1].1, p.4]
Response: 
EPA believes that its use of historic data as the basis for existing unit allowance allocations under the final Transport Rule FIPs will effectively capture the real-world operation of the types of units this commenter operates.
With regard to the "flexible and cost effective" nature of the trading programs, EPA notes that there are opportunities for interstate trading in the trading programs under the final Transport Rule, and believes there will be active interstate trading markets. As shown in the Assurance Penalty Level Analysis Final Rule TSD, many states do not emit up to their assurance levels, indicating that interstate trading is a viable compliance option. Additionally, EPA has seen active interstate trading markets develop in previous programs, such as CAIR, where interstate trading is allowed.
Organization: Gulf Coast Lignite Coalition
Comment: 
Gulf Coast Lignite Coalition
On October 1, 2010, GCLC timely submitted a comment on the proposed Transport Rule addressing a need to extend compliance dates under the Rule and for Texas to remain excluded from the 'Group 2' states. [EPA-HQ-OAR-2009-0491-3963[1].1, p.1]
EPA is also proposing to hold responsible any unit (or group of units) responsible for exceedances in the state budget, through application of the assurance provision allowance surrender requirement. Under this proposal, not only are coal-fired units given a lower allowance, unable to accumulate allowances, but should there be any exceedances, they may even be required to surrender allowances. [EPA-HQ-OAR-2009-0491-3963[1].1, p.3]
Response: 
EPA disagrees with the commenter's unsubstantiated assertion that "coal-fired units [are] unable to accumulate allowances."  Any unit may accumulate allowances under the Transport Rule's air quality-assured trading programs in the same manner units have accumulated allowances in prior emission trading programs; by receiving them as initial allocations, purchasing them in the marketplace, and/or banking them for future-year compliance use.  

Organization: Hoosier Rural Electric Cooperative
Comment: 
Hoosier Rural Electric Cooperative
Lastly, the timing of the implementation does not reflect the reality of units and sources having the ability to make substantive changes in order for the emission reductions to match allowance allocations.  2012 is an impossibility for plants (units) to integrate the planning, engineering, construction,  installation and testing of equipment necessary to meet the 20102 allowance allocations.  Since  many plants are affected by this timeline, there could be a possibility of contractor/equipment manufacturers/vendors shortfall. [EPA-HQ-OAR-2009-0491-3927[1].1, p.2]
Response: 
The commenter mischaracterizes the role of allowance allocations.  Initial allowance allocations are not requirements to be met; they are an administrative procedure for distributing allowances at the outset of a trading program, after which units may acquire additional allowances if necessary to cover emissions during the control period.
Organization: Horsehead Corporation
Comment: 
Horsehead Corporation
In the Proposed Transport Rule, EPA identified certain 'key guiding principles' for the design and implementation of the Transport Rule. See 75 Fed. Reg. 45226-7. In particular, 'EPA recognizes that requirements for EGUs must be mindful of the variability in the operation of the power grid, and that any requirements for broad reductions should be structured in a way that ensures a reliable power supply' (emphasis added). Id. at 45227. Consistent with this goal, in calculating the proposed emission allowance allocations under the Proposed Transport Rule, EPA considered projections for future generating rates, based on the anticipated future cost of electricity generation and market demand. [EPA-HQ-OAR-2009-0491-4003[1].1, p.1]
Horsehead's boilers are part of a captive power production operation dedicated to providing electricity for the Facility's zinc processing operations. Unlike traditional electricity generation plants, the amount of electricity required to be produced by the boilers to operate the zinc processing facility is not influenced by factors affecting the cost of electricity generation, including fuel cost, market demand, and other variables. Indeed, only a fraction of the electricity produced at the Facility is sold to the grid, and this process is ancillary to the boilers' primary purpose of providing power for the Facility's smelting equipment. For these reasons, it is anticipated that the Facility's boilers will continue to operate at current levels in the future. By contrast, traditional electricity generation units may operate at reduced rates in the future depending on fluctuations in power generation costs and market demand. Horsehead believes it is necessary to consider such projections for future generating rates, including the fact that Horsehead's generating rates are expected to remain consistent, for purposes of determining allowance allocations under the Transport Rule in order to ensure a reliable power supply. Further, such consideration is consistent with EPA's stated goals for implementing the Transport Rule. [EPA-HQ-OAR-2009-0491-4003[1].1, pp.1-2]
EPA has identified certain 'key guiding principles' for implementing the Transport Rule, including ensuring a reliable power supply. Consistent with this stated objective, EPA determined the proposed emission allowance allocations under the Proposed Transport Rule based on projections for future anticipated generating rates for affected units. [EPA-HQ-OAR-2009-0491-4003[1].1, p.3]
The boilers at the Horsehead Facility are part of a captive power production operation dedicated to providing electricity for the Facility's zinc processing operations. Accordingly, it is anticipated that these units will continue to maintain current operating levels in the future. Traditional electricity generation units, by contrast, may operate at reduced rates in the future depending on fluctuations in power generation costs and market demand. Horsehead believes it is critical to consider such projections for future generating rates for purposes of determining allowance allocations under the Transport Rule in order to ensure a reliable power supply. Further, such consideration is consistent with EPA's stated goals for implementing the Transport Rule. Therefore, EPA should determine the allowance allocations in the final Transport Rule using the allocation method originally set forth in the Proposed Transport Rule, rather than the alternative allowance allocation approaches proposed through the Second NODA. [EPA-HQ-OAR-2009-0491-4003[1].1, p.3]
Response: 

EPA notes that Horsehead Corporation has not provided any evidence that using a historic-heat input method, rather projected future generating rates, would cause any power reliability issues. Please see the Resource Adequacy and Reliability in the IPM Projections for the Transport Rule TSD for EPA's analysis of power reliability.
Organization: Illinois Environmental Protection Agency
Comment: 
Illinois Environmental Protection Agency
U.S. EPA's proposed allocation of sulfur dioxide allowances includes electric generating units that bum natural gas exclusively. The Illinois EPA does not agree with this approach and recommends that only coal-fired units he included for allocation of S02 allowances. The Illinois EPA recognizes that a revision of the definition of 'budget unit' may be needed to accomplish this, but allocating S02 allowances to Natural Gas plants. [EPA-HQ-OAR-2009-0491-3899[1].1, p.1]
Response:
Thank you for your comment. 
Organization: Independence Power & Light (IPL)
Comment: 
Independence Power & Light (IPL)
The IPL's combustion turbine at the Blue Valley Power Station, designated as 'RCT' in EPA's allocation tables, would not receive any allocations under the Original Methodology thus eliminating half the potential power production of the Blue Valley Station. This is in addition to the severe reduced use that the allocation imposes on Blue Valley 3; together, they severely restrict, if not totally curtail operation of these units, thereby eliminating 33% of IPL's generation capacity. [EPA-HQ-OAR-2009-0491-3949[1].1, p.3]
The NODA asks whether Option 1 and Option 2 'raise any implementation concerns, such as concerns about feasibility of implementing the methodology' and the interrelated question of whether they 'yield a reasonable distribution of allowances?' 76 FR at 1116/1-2. As noted above, the Option 1 or Option 2 would give IPL even fewer allowances than the Original Methodology, even though IPL could not run Blue Valley 3 under those initial allowances. This level of further reduced allowances makes feasibility concerns even more pressing because to produce sorely needed power under any of the allocation methodologies would require additional controls that cannot be realistically put in place before the 2012 deadline or the purchase of a greater amount of emissions allowances (which cannot necessarily be done without risk of penalties under the proposed Rule), increased power purchases from other utilities, or construction of a new unit, which clearly cannot be done by 2012, to make up anticipated generation shortfalls resulting from the low allowances. IPL's municipal customers will ultimately suffer under any of these scenarios by having to pay much higher costs for electricity, if electricity is even available. The reality is that it will be very difficult, if not impossible to replace such lost generation. If it could be replaced, brown-outs and black-outs would be expected as a consequence of having to rely on units off IPL's system. Moreover, the reliability of IPL's system will be significantly compromised. [EPA-HQ-OAR-2009-0491-3949[1].1, pp.6-7]
As a practical matter, because the gap between allocations IPL would receive under any of the schemes and the amount of allocations that are needed to continue operations to serve customers is so great, IPL cannot operate Blue Valley 3 or the RCT in any way that will offer meaningful amounts of generation to its customers. Thus, IPL would need to either find purchase power or construct a unit to replace Blue Valley 3 and the RCT. There is precious little purchase power available in IPL's load constrained area. That means IPL would likely have to add a transmission plant to bring in new purchased power, a move that requires IPL to follow the planning procedures of its regional transmission organization, SPP. [EPA-HQ-OAR-2009-0491-3949[1].1, pp.7-8]
EPA may not be aware that the Federal Energy Regulatory Commission has a process that must be followed by SPP when a transmission request is received to accommodate movement of new purchase power or power from a new unit. If IPL were to find purchase power or were able to bond the money, obtain permits, etc. for new construction, IPL would submit a proposal that is placed in a SPP queue with other such requests for yearly feasibility studies by SPP to determine whether and how all transmission requests made that year can be accommodated at the lowest cost using existing and new transmission capabilities. Only after that review is completed and all requestors have agreed to the resulting costs will SPP give its approval. SPP's review process will generally take more than a year to complete. In the case of approval for transmission of additional power, the construction of additional transmission service may be needed to accommodate movement of additional power, absorbing more time. In the case of construction of a unit to replace the lost generation an additional two to three years after SPP approval is needed to account for the time to issue bonds, engineer and design the new unit, obtain permits, and accomplish all the work needed to bring a new unit on line. So the reality is that IPL has no feasible way by 2012 (or even 2014) to replace the power that the allocation methodologies under the Rule or the NODA will take away from IPL. [EPA-HQ-OAR-2009-0491-3949[1].1, p.8]
IPL requests that any allocation methodology include realistic implementation schedules and allow a period of penalty-free continued operation for units that will be replaced because they are rendered obsolete under the Rule. [EPA-HQ-OAR-2009-0491-3949[1].1, p.12]
Response: 
EPA disagrees with the commenter's premise that Transport Rule allowance allocations will determine its units' operations.  As explained in the Allowance Allocation Final Rule TSD, the economic determination of dispatch is based on the operating cost of all relevant units, including the cost of emissions from those units' generation, whether or not the allowances required to cover those emissions were initially allocated to those units.  Therefore, it is not possible for allowance allocation methodologies to "take away" power generation from any source.  The market-based flexibility of the Transport Rule air quality-assured trading programs will allow utilities to continue to dispatch least-cost generation to meet electricity demand and maintain grid reliability, with the only difference being that "least-cost generation" will now factor in the cost of emitting SO2 and NOX subject to the state budgets under the Transport Rule (i.e., the price of surrendering allowances to cover emissions of those regulated pollutants). 
EPA is well aware of FERC regulations and authorities relevant to the Agency's power sector air quality regulations, in part because expert staff formerly at FERC and now at EPA were involved in the development of this rulemaking.  EPA finds no basis that the commenter's cited routine regional transmission planning processes would hamper Transport Rule implementation, or that the Transport Rule would otherwise cause reliability concerns.  See section V.D.2.g in this RTC document and the Resource Adequacy and Reliability in the IPM Projections for the Transport Rule TSD in the Transport Rule docket for more information. 
Organization: Kansas City Board of Public Utilities (BPU)
Comment: 
Kansas City Board of Public Utilities (BPU)
1. That EPA revisit the allocation methodologies put forth to date and develop an allocation methodology that is reasonable and consistent with CAA goals. [EPA-HQ-OAR-2009-0491-3978[1].1, p.11]
2. That, while far from perfect, if one of the allocation methodologies put forth to date is to be adopted into a final Rule, the Original Methodology for allocations be adopted because it is less problematic than Option 1 or Option 2. [EPA-HQ-OAR-2009-0491-3978[1].1, p.11]
4. That the final Rule include the full array of SIP options from which states can select the option most appropriate to accomplish the CAA goals in that state. [EPA-HQ-OAR-2009-0491-3978[1].1, p.11]
Response: 
Thank you for your comment.Organization: Kansas City Power and Light Company (KCP&L)
Comment: 
Kansas City Power and Light Company (KCP&L)
Prior to addressing NODA 3 specifically, KCP&L would like to reiterate its position taken in comments on the Proposed Transport Rule and NODA 1 that there continues to be a need for EPA to address the deficiencies already identified in the Proposed Transport Rule with respect to determination of states' emission reduction obligations under the proposed rule. EPA should withdraw the Proposed Transport Rule, revise it using whatever corrected data EPA deems most appropriate, and republish it for public comment with an adequate comment period. A new comment period is necessary to allow appropriate review of the new input data, model results, and resulting emission allowance allocations. The regulated community should have an additional opportunity to review and comment on the changes once they have been made. [EPA-HQ-OAR-2009-0491-3893[1].1, p.1]
Implementation of the Proposed Transport Rule pursuant to the schedule that EPA proposes would make it virtually impossible for states to implement SIPs prior to the first phase of the program. Issuing the Proposed Transport Rule as a FIP would effectively bypass the states' rights to develop their own plans. [EPA-HQ-OAR-2009-0491-3893[1].1, pp.1-2]
Under the Proposed Transport Rule, statewide budgets were set at levels necessary to eliminate downwind interference with other states' attainment of the NAAQS. The method used to allocate unit-level allowances within each state is irrelevant. [EPA-HQ-OAR-2009-0491-3893[1].1, p.2]
Prohibiting SO2 allowance trading between Group 1 and Group 2 states unfairly penalizes utilities with sources located in the same air shed, but on opposite sides of state boundaries. EPA should consider allowing trading between Group 1 and Group 2 states, or at a minimum, allow intra-utility trading between units in Group 1 and Group 2 states. While KCP&L generally supports interstate trading versus intrastate-only trading or specific limits, to provide some flexibility and allow cost-effective compliance options, the relatively small size of the variability pools will not provide enough flexibility. [EPA-HQ-OAR-2009-0491-3893[1].1, p.4]
Response: 
Thank you for your comment.Organization: Kentucky Division for Air Quality
Comment: 
Kentucky Division for Air Quality
Deadlines for achieving mandated emission reductions should be designed to support the attainment deadlines prescribed for the standards. At the same time, the regulated community must be granted the required time to design and implement control equipment and operational changes necessary to meet new emissions limits. [EPA-HQ-OAR-2009-0491-3970[1].1, p.2]
It appears that the date criteria for defining an existing unit in the NODA has changed to reflect those units that commenced commercial operation prior to January 1, 2009, as opposed to the proposed Transport Rule (75 FR 45210) that indicated existing units as units that commenced commercial operation or are planned to commence commercial operation prior to January 1, 2012. Given these existing unit criteria differences and in the interest of accuracy, the Division requests that before the Transport Rule existing unit allocations are finalized and recorded that EPA consult with the Division and other state air agencies to make sure that all existing units subject to the final Transport Rule have been properly identified in the final rule's existing unit allowance allocations. The Division reserves the right to inform EPA of any unit omission or incorrect inclusion for EPA's Transport Rule even after the comment period deadline has passed. [EPA-HQ-OAR-2009-0491-3970[1].1, p.2]
As with proposed Transport Rule, the January 7, 2011 NODA also omits NOx SIP Call Non-EGU units from existing unit ozone season NOx allowance allocations as provided in the NODA's alternative allocation tables and underlying data spreadsheet (altallocationtablesdata.xls). The Division again requests EPA to reconsider its decision not to allow the inclusion of NOx SIP Call Non-EGUs now in CAIR into the proposed Transport Rule NOx ozone season trading program. Due to the very small emissions budget for the Division's six NOx SIP Call Non-EGUs (64 ozone season (OS) NOx tons) that was added to the CAIR NOx OS budget, Kentucky disagrees with EPA's contention that including these units in the proposed Transport Rule would jeopardize a state's ability to eliminate its part of significant contribution and interference with maintenance that EPA has identified. As EPA has indicated in the Transport Rule preamble, states need a way to continue to meet their NOx SIP Call obligation for Non-EGUs and the Division recommends that the transport rule be that new way. Therefore, given the limited number of subject Non-EGUs and the small amount of their NOx ozone season budget emissions, the Division requests that EPA include the NOx SIP Call Non-EGUs into the proposed Transport Rule. If EPA changes its position to include the NOx SIP Call Non-EGU units, then the Division requests that EPA consult with the Division to ensure that all applicable Kentucky Non-EGUs are properly accounted for in the fmal Transport Rule. [EPA-HQ-OAR-2009-0491-3970[1].1, pp.2-3]
The proposed alternatives serve to highlight the unacceptable uncertainty facing utility companies and regulatory agencies under the rulemaking process and the need to extend the compliance deadlines. Comparing the original allocation proposal with the alternatives illustrates the magnitude of uncertainty regarding the number of allowances that units and companies might receive. The number of allowances that companies would receive at their Kentucky plants varies by tens of thousands, equating to variations of over 50% for several companies. Attachment A provides additional details. In some cases, companies will be in compliance, will curtail or retire unit operations or will need to install additional controls, depending on the allocation method selected. EPA has stated that It expects to finalize the rule and the accompanying allocations In mid-2011. This schedule is totally unacceptable since it allows only six months for companies to develop compliance plans, apply for and receive approvals from environmental agencies and public utility commissions, obtain financing, and construct required equipment. This is clearly unreasonable for affected companies and for regulatory agencies. It has been suggested that companies plan for the worst case and install equipment to comply. The rationale is that if a company receives more allowances than planned for, it will have surplus allowances that can be sold. To the extent that many companies go this route, the surplus of allowances would depress prices and result in inefficiencies that could be avoided by more reasonable compliance schedules. It is simply unreasonable to put utilities and the public utility commissions that approve their compliance investments in the position of being forced to undertake action without knowing the final targets. We request U.S. EPA delay issue of a final rule until they consider all comments on the four proposal notices thus far, correct all databases, remodel as necessary and issue a supplemental proposal for public comment. [EPA-HQ-OAR-2009-0491-3970[1].1, p.4] [[See Docket Number EPA-HQ-OAR-2009-0491-3970[1].1, p.6 for Attachment A.]]
Response: 
The commenter mischaracterizes the role of allowance allocations under the air quality-assured trading programs in the Transport Rule.  It is the stringency of the state budget, not the degree of a unit's initial allocation, that is the primary driver of cost-effective compliance decisions across the state's covered sources.  For example, SO2 budgets in Group 1 states are based on a cost threshold of $2,300 per ton in the final rule; the proposal applied a very similar cost threshold of $2,000 per ton for SO2 budgets in those states.  Sources in those states would thus find it reasonable to conduct advanced planning for compliance strategies to achieve any emission reductions that would be cost-effective up to at least $2,000 per ton, regardless of the eventual determination of initial allowance allocations to an individual source.  Assume a hypothetical example of a source who originally plans a cost-effective pollution control retrofit installation for 2014 but later learns that the state has submitted a SIP and issued a 2014 initial allowance allocation to the source that is in excess of its emissions once controlled by that retrofit.  Despite now receiving a larger allocation than it can use with the retrofit, the source would still find it economic to complete the retrofit installation and sell the allowances because it had already judged that the retrofit's emission reductions could be achieved for less cost than the likely market value of the associated allowances.  The market value of the allowances is determined by the cost threshold basis of the programs' emission budgets, to which the unit-level allocation of allowances is irrelevant.
Regarding interactions with the NOx SIP Call, please see Preamble Section IX.B.
Organization: Lafayette Utilities System
Comment: 
Lafayette Utilities System
LUS reiterates and incorporates herein by reference prior comments LUS made on the proposed CATR/FIP that were filed on October 1, 2010 and on the September 1, 2010 NODA filed on October 15, 2010. LUS specifically reiterates that Louisiana should not be subject to the proposed CATR/FIP for annual reductions of either sulfur dioxides (S02) or nitrogen oxides (NOx) because Louisiana emissions sources are not interfering with the attainment or maintenance of the PM2.5 National Ambient Air Quality Standards ('NAAQS') in Houston, Texas as projected by the initial Integrated Planning Model ('IPM') based modeling for CATR/FIP. LUS anticipates that if the corrections are made to the model inputs as requested in the LUS initial comments, the remodeling currently being performed by EPA will confirm this conclusion. LUS also reiterates that Louisiana should not be subject to the proposed CATR/FIP for ozone season NOx reductions because Louisiana emissions of NOx during the ozone season do not interfere with the attainment or maintenance of the 1997 8-hour ozone NAAQS in either the Houston or Dallas areas of Texas as projected by the initial erroneous IPM modeling. The reasons why Louisiana should be excluded from the CATR/FIP are found the previously filed comments of LUS and of the Louisiana Chemical Association in this docket. [EPA-HQ-OAR-2009-0491-3914[1].1, pp.2-3]
Response: 
EPA's response to the comments previously submitted by LUS can be found in the Response to Comment document.
1) The final rule modeling included many emissions inventory updates in both Louisiana and Texas.  Details on these updates can be found in preamble section V.C.1
2) Based on revisions EPA made to the emission inventories and air quality modeling following a review of public comments, the analysis for the final rule does not identify Harris county TX as a PM2.5 nonattainment or maintenance receptor in 2012, or identify Louisiana as a state with emissions that significantly contribute to nonattainment or interfere with maintenance of either PM2.5 NAAQS.  
3) In the final rule modeling Louisiana is still found to contribute significantly to nonattainment and interfere with maintenance for 8-hr ozone in Houston TX.  Preamble section V.C.2 explains why recent monitoring data should not and cannot be used to determine the nonattainment and maintenance receptor status for consideration under the Transport Rule.  
Organization: Lakeland Electric
Comment: 
Lakeland Electric
Lakeland asks EPA to comment on the feasibility of the coal units which must be modified in order to meet the Transport Rule limits to perform those modifications by 2012. Lakeland believes that EPA is not aware of the procedural steps many utilities, especially municipalities, must take before awarding a large contract, such as one that would be needed to convert a 365 MW unit from coal to natural gas. In addition, even minor modifications may require such facilities to obtain air construction permits from their respective state, and possibly EPA if greenhouse gas emissions are involved, before commencing work on the required modifications. Lakeland requests that EPA comment on the amount of time such possible modifications needed to meet the Transport Rule limits would take to permit at both the state and federal levels and how that may affect generating capacity over the next few years. [EPA-HQ-OAR-2009-0491-3892[1].1, p.3]
Lakeland also asks that EPA comment on any internal studies which have been performed that demonstrate that this regulation does not detrimentally affect reliability to the stability and security of the electric grid in Florida and that EPA make such reports available to the docket for public access. [EPA-HQ-OAR-2009-0491-3892[1].1, p.3]
EPA Must Publish another Proposed Rule
Lakeland cannot overemphasize that EPA's piecemeal approach in its development of the Transport Rule deprives affected parties adequate opportunity to effectively participate in the rulemaking process and, therefore, is legally deficient. EPA must allow for stakeholder involvement as it develops and publishes a second proposal addressing all of the comments. The second Proposed Rule, along with all information used to develop the proposal, should be provided at the same time so that affected parties can understand the impacts of the Proposed Rule and participate meaningfully in the rulemaking process. [EPA-HQ-OAR-2009-0491-3892[1].1, p.4]
While the January NODA presents alternative allocation methodologies that do not rely on model-predicted emissions, it does not address EPA's use of the flawed IPM model that establishes each state's significant contribution and interference with maintenance and each state's emissions budget. EPA has provided no evidence that it has corrected the numerous fundamental errors in the IPM model. The January NODA states that EPA is still in the process of updating its emission inventories and modeling and that state contributions and unit allocations could change, 76 Fed. Reg. 1111, 1114; therefore, publication of another Proposed Rule is critical for regulated sources to understand the precise extent to which they are affected by the Rule (for example, whether it will have to buy allowances, assuming they are available, and how many). [EPA-HQ-OAR-2009-0491-3892[1].1, p.4]
Additionally, Lakeland reiterates previous comments that the Transport Rule need not be in place by 2012. As many commentators have noted, the Proposed Rule provides many electric generating units insufficient time to install controls or implement operational changes necessary to reduce emissions from historical levels to proposed allowances. Moreover, the Clean Air Act does not grant EPA authority to promulgate a FIP without first providing states adequate time and opportunity to develop and submit SIPs. States are better suited to develop fair and consistent approaches and/or allocations that take into consideration unique aspects of electric generating units in the state. Nonetheless, EPA recognizes in the January NODA that there will be insufficient time for states to develop SIPs, with or without allowance allocation provisions, and for EPA to review and approve such SIPs, before EPA will record allocations to existing units for 2012 and 2013. Thus, the first year for which state allocations could be used is 2014. The Transport Rule, therefore, should not begin before 2014. [EPA-HQ-OAR-2009-0491-3892[1].1, pp.4-5]
1) Does EPA expect facilities to need to modify their units to stay in compliance with the Transport Rule reductions, and if so, how long does EPA believe it will take to perform those modifications?
2) If modifications are required to meet the Transport Rule's limits, how long does EPA believe it will take to obtain the necessary air construction permits from EPA and the respective state agencies in order to perform those modifications? [EPA-HQ-OAR-2009-0491-3892[1].1, p.5]
4) How much generation capacity does EPA expect will have to be retired or reduced, e.g., units operating at lower loads or part of the year in order to meet limits, due to the implementation of this proposed regulation?
5) Has EPA performed any modeling on what effect this proposed regulation will have on grid reliability, and if so, will EPA publish that modeling data? [EPA-HQ-OAR-2009-0491-3892[1].1, p.6]
Response: 
Regarding the number of facilities that EPA projects will modify their units or retire in response to the Transport Rule, please see RIA Chapter 7. EPA notes that while the FIPs will allocate allowances to individual units, they does not establish any unit-specific requirements to install pollution controls or retire, given the flexibility of the Transport Rule and the numerous compliance options available.
Organization: Louisiana Chemical Association (LCA)
Comment: 
Louisiana Chemical Association (LCA)
A. LCA Does Not Waive Its Prior Comments
LCA submitted comments on CATR on October 1, 2010; on the September 1, 2010 NODA on October 15, 2010; and provided supplemental comments to the EPA docket clerk and Rich Mason of EPA on December 3, 2010 in response to questions on the Louisiana emissions inventory sent by EPA to LCA counsel as a follow-up to LCA comments. By commenting on this 2011 NODA, LCA does not in any way waive any of its prior comments. [EPA-HQ-OAR-2009-0491-4027, p. 2]
In particular, LCA continues to strongly believe that Louisiana should not be included under the Clean Air Transport Rule because empirical evidence shows that Louisiana sources do not 'contribute significantly to nonattainment in, or interfere with maintenance by, any other State with respect to' the PM2.5 NAAQS or the 1997 8-hour ozone primary NAAQS within the meaning of Section 110(d) of the Clean Air Act ('CAA'). Without a finding that Louisiana actually does contribute to nonattainment or interfere with maintenance, EPA is powerless to impose a FIP. [EPA-HQ-OAR-2009-0491-4027, p. 2]
EPA proposed to include Louisiana under the CATR/FIP for the annual sulfur dioxide (S02) and annual nitrogen dioxide (NOx) trading programs based solely on a projection by use of the Integrated Planning Model that Louisiana emissions would interfere with maintenance of the PM2.5 annual primary NAAQS at one monitor in Harris County, Texas (the Clinton Drive monitor along the Houston Ship Channel) by contributing 0.34 ug/m3 in 2012. Actual data show that the Clinton Drive monitor has a design value greater than 0.34 ug/m3 now, and even EPA's data show that S02, NOx, and PM2.5 will be reduced from Louisiana sources before 2012 even without CATR. LCA's comments discussed why a modeled contribution of less than 1 ppb should never be sufficient to trigger the requirements of CAA Section 110(d). LCA comments also pointed out a number of deficiencies in the IPM modeling assumptions. Further, as noted by LCA, the IPM modeling was based on significant errors in the Louisiana emission inventory which grossly overstated PM2.5 and its precursor emissions . Simply put, there is no sound reason to believe that Louisiana sources contravene the good neighbor provisions of CAA Section 110(d) or to impose CATR on Louisiana for purposes of PM2.5 control. [EPA-HQ-OAR-2009-0491-4027, pp. 2-3]
EPA proposed to include Louisiana under the CATR/FIP for the ozone season NOx trading programs based on projections by use of the Integrated Planning Model that Louisiana emissions would significantly contribute to nonattainment with the 1997 8-hour ozone standard at several monitors in the Houston and Dallas areas and would interfere with maintenance of that standard at other monitors in the Houston and Dallas areas by 2012. The empirical data show that all of the monitors in the Houston area have been in attainment since 2009 and continued in attainment in 2010. All of the monitors in the Dallas area projected to be affected by Louisiana emissions, save one (the Alta Vista/Keller monitor in Tarrant Co.), have achieved attainment. The one monitor that has not achieved attainment has a design value of 86 ppb, just 2 ppb over the standard. [EPA-HQ-OAR-2009-0491-4027, p. 3]
As noted above, EPA itself projects actual emission reductions even without CATR. Thus, with corrected emission inventory data and improved modeling, LCA believes it will be demonstrated that Louisiana sources will not contribute to nonattainment or interfere with maintenance in Tarrant Co ., Texas. This belief is corroborated by a study by Al Armendariz, while a professor at Southern Methodist University, prior to becoming the . Regional Administrator of EPA Region 6, which indicated that in the 10 years 1997-2007, pollution levels have remained the same or risen slightly in Tarrant and Denton counties as they decreased elsewhere within the Dallas-Ft. Worth area. He attributed this to the cement plants in Ellis County, southeast of Fort Worth, and to the increased industrial activity in the Barnett Shale area. It is improbable that if Louisiana emissions were a significant contributor that ozone levels would fall in areas of DFW other than the location of the Keller monitor. Instead, it is much more probable that any issue with that monitor is due to local forces. [EPA-HQ-OAR-2009-0491-4027, p. 3]
The IPM is an economic simulation model designed to analyze power markets by forecasting market prices based on an analysis of traditional supply and demand factors. While it is useful for certain purposes, it possesses several flaws that contributed to its misprediction of premature retirement or significant reduction of generation from the vast majority of oil and natural gas fired EGUs in Louisiana for purposes of CATR. LCA pointed out these numerous problems in its initial October 2, 2010 comments on CATR, in particular at pages 40-43 and Exhibit 10. A review of this data reveals IPM modeling projected either early retirement or grossly scaled back utilization of LCA members' cogeneration units as well as a significant percentage of the state's oil/gas steam units owned or operated by public utilities. See also comments of Entergy Corp. in this docket. As indicated in LCA and Entergy comments, these units have continued to have very high utilization rates up through the end of 2010 and do not have plans to cease operations or significantly lower their utilization rates in the foreseeable future, as predicted by IPM. [EPA-HQ-OAR-2009-0491-4027, pp. 3-4]
As a regional model, EPA's version of IPM represents the electric transmission system on an interregional basis, with regional boundaries determined by known transmission bottlenecks. Unlike the private sector version of IPM developed by ICF that contains 104 U.S. regions, EPA's version contains only 32. The EPA version results in over-simplification of factors that become critical at the individual source level. As noted in the CATR comments supplied by Entergy in this docket: 'Transmission-related issues inherent to IPM's regional models include missing intraregional load pockets, voltage support, ancillary services, local requirements, etc. These limitations are further exacerbated by the limited number of regions in EPA's IPM, resulting in the premature reduced generation from oil/gas steam units . . .' [EPA-HQ-OAR-2009-0491-4027, p. 4]
The IPM fails to account appropriately for the operation of cogeneration units by industrial sources to serve as sources of both steam and electricity. The model thus erroneously predicted that the EGUs of four of LCA's members (Dow Chemical, the owner/operator of the Plaquemine Cogeneration facility; ExxonMobil Chemicals, the lessee of the Louisiana 1 Facility; Occidental Chemicals, the owner/operator of the Taft Cogeneration facility; and PPG Industries, a 50% joint venture owner and the operator of the RS Cogen facility) would operate only during the ozone season, not during the entire year, and even during ozone season at greatly reduced rates. Each of these EGUs are well-controlled natural gas fired cogeneration sources providing critical steam and electricity to the Dow, Exxon Mobil, Occidental and PPG chemical manufacturing facilities. Excess electricity is sold to the grid. Each of these EGUs runs year round, not simply during ozone season. All of these units represent substantial investments in the hundreds of millions of dollars to Dow, ExxonMobil, Occidental and PPG. All have been operating at a high percentage of their capacity and have no plans whatsoever to curtail operations. Under the IPM based methodology of allocations three of these four facilities have would received annual NOx allocations less than 5% of their actual 2009 operating rates would other-wise indicate. The fourth will receive allocations less than 10% of its 2009 actual NOx emissions. The IPM is plainly an inadequate basis for CATR allocations when its predictions deviate so substantially from reality. [EPA-HQ-OAR-2009-0491-4027, p. 4]
Moreover, as pointed out by both Entergy and the Louisiana Public Service Commission, EPA's use of the IPM does not account for the fact that oil and gas fired steam units are typically responsive to short term pricing benefits between daily gas and daily oil prices, particularly in peak periods. The IPM, which is not an hourly model and dispatches to broader time segments, has no way of capturing the daily dispatch decisions that might drive generation for these units. EPA's IPM utilizes seasonal gas prices (winter and summer, only) and a single, annual oil price. [EPA-HQ-OAR-2009-0491-4027, pp. 4-5]
In short, LCA believes that it is inappropriate for EPA to base unit-level allocations on IPM modeling, which has been demonstrated to result in significantly inaccurate predictions.  [EPA-HQ-OAR-2009-0491-4027, p. 5]
LCA does not share EPA's position that the IPM-based methodologies meet these CAA goals, at least with respect to the allocations proposed by EPA in the original CATR/FIP or the September 1, 2010 NODA. Those IPM-based allocations punished the cleaner, more efficient natural gas burning sources in Louisiana while favoring EGUs with greater emissions and less efficiency. [EPA-HQ-OAR-2009-0491-4027, p. 5]
EPA should not make the reductions required by CATR/FIP effective until calendar year 2013 rather than 2012 to provide states and regulated industries with sufficient time to implement CATR requirements. This has the added advantage of not placing untenable financial burdens on the economy which is struggling to recover. [EPA-HQ-OAR-2009-0491-4027, p. 7]
EPA indicated that because the final Transport Rule will not be adopted until around mid-2011, there would not be sufficient time for states to develop and submit abbreviated or full SIPS with allowance allocation provisions, and for EPA to review and approve such SIP submissions, before September 2011 when EPA would record allocations to existing units for 2012 and 2013. Thus, EPA proposes that the first year for which state allocations might be used under an abbreviated SIP, in lieu of EPA allocations, would. be 2014. EPA can avoid this result by not making allocations until September 2012. That would allow states time to submit and obtain approval of abbreviated SIPs, provided the states and EPA act expeditiously. [EPA-HQ-OAR-2009-0491-4027, p. 7]
Louisiana DEQ, together with the Louisiana Public Service Commission, worked very hard on a fair allocation scheme for NOx allowances under the prior CATR. This scheme was enacted into rule by the State after public notice and comment and was approved by EPA. Although the court in North Carolina v. EPA struck down CAIR and required a revised look at the actual state budget needed to eliminate significant contribution or interference with maintenance, the court did not find any problem with the Louisiana (or other state's) unit level allocations, The state is in the best position to make appropriate allocations and should be afforded a realistic opportunity to do so. [EPA-HQ-OAR-2009-0491-4027, p. 7]
Response: 
Thank you for your comment.Organization: Louisville Gas and Electric Company (LG&E) and Kentucky Utilities Company (KU)
Comment: 
Louisville Gas and Electric Company (LG&E) and Kentucky Utilities Company (KU)
These units have installed control equipment in part based on the financial assumption that they could sell excess allowances; the originally proposed allocations eliminate this. Under the original proposal, these units would have been better off if they did not install control equipment, received a higher allocation under the Transport Rule, and then installed the equipment. The original proposal rewards less-controlled units that continued to have higher emissions at the expense of well-controlled units. In addition, although the original proposal is based on projected emissions, units would receive fewer allowances than their projected emissions. This is due to ratcheting down allocations to meet statewide budgets and due to the 3% withhold for new source set-aside. The result is that units equipped with controls that are achieving near the lowest emissions technically feasible are being required to reduce emissions further. [EPA-HQ-OAR-2009-0491-3909[1].1, p.2]
The proposed alternatives serve to highlight the unacceptable uncertainty facing utility companies and regulatory agencies under the rulemaking process and the need to extend the compliance deadlines. [EPA-HQ-OAR-2009-0491-3909[1].1, p.2]
Comparing the original allocation proposal with the alternatives illustrates the magnitude of uncertainty regarding the number of allowances that units and companies might receive. The number of allowances that companies would receive at their Kentucky plants varies by tens of thousands, equating to variations of over 50% for several companies. Attachment A provides additional details. In some cases, companies will be in compliance, will curtail or retire unit operations, or will need to install additional controls, depending on the allocation method selected. [EPA-HQ-OAR-2009-0491-3909[1].1, p.2] [[This comment can also be found in Section XX.A.2.]] [[See Docket Number EPA-HQ-OAR-2009-0491-3909[1].1, p.3 for Attachment A.]]
EPA has stated that it expects to finalize the rule and the accompanying allocations in mid-2011. This schedule is totally unacceptable since it allows only six months for companies to develop compliance plans, apply for and receive approvals from environmental agencies and public utility commissions, obtain financing, and construct required equipment. This is clearly unreasonable for affected companies and for regulatory agencies. It has been suggested that companies plan for the worst case and install equipment to comply. The rationale is that if a company receives more allowances than planned for, it will have surplus allowances that can be sold. However, structuring a program to maximize the risk of 'over-compliance' is fundamentally inconsistent with utilization of a cap and trade mechanism which is aimed at optimizing the allocation of societal resources to achieve a targeted environmental outcome. The problem is easily solved by adopting more reasonable compliance schedules. It is simply unreasonable to put utilities and the public utility commissions that approve their compliance investments in the position of being forced to undertake action without knowing the final targets. We request U.S. EPA delay issuance of a final rule until they consider all comments on the original proposed rule and notices of data availability, correct all databases, remodel as necessary and issue a supplemental proposal for public comment. [EPA-HQ-OAR-2009-0491-3909[1].1, p.2]
Response: 
Thank you for your comment.Organization: Luminant
Comment: 
Luminant
 Luminant believes that it is important to also comment on issues of continuing concern. A summary of Luminant's comments on EPA's NODA is provided below.  [EPA-HQ-OAR-2009-0491-3980[1].1, p.2] 
CATR rules should establish targets based on demonstrated benefits to downwind areas. [EPA-HQ-OAR-2009-0491-3980[1].1, p.2]
The method of compliance required within the determined targets should not establish "winners and losers" among sources but rather, use proven market based systems for sources to comply effectively.   [EPA-HQ-OAR-2009-0491-3980[1].1, p.2]
EPA should establish reasonable timelines, accounting for adequate time for the planning, procurement, permitting, installation and implementation of controls for compliance.  [EPA-HQ-OAR-2009-0491-3980[1].1, p.2] 
Luminant Believes that Texas Should Not Be Included in the Ozone Season NOx Program  
The continued inclusion of Texas in the CATR program including the overestimation of NOx emissions by some 19,000 tons per year from the Houston Galveston Brazoria ozone nonattainment area, resulting in the conclusion that Texas sources are impacting Baton Rouge, to the point of interfering with the ability of Baton Rouge to demonstrate attainment with the 1997 ozone standard is without justification. EPA, in the September 9, 2010 Federal Register, issued its final decision that the Baton Rouge area has in fact met the 1997 ozone standard. There is no basis therefore, for the continued inclusion of Texas in the CATR ozone season NOx program. [EPA-HQ-OAR-2009-0491-3980[1].1, p.4]
The electric grid manager in Texas, the Electric Reliability Council of Texas (ERCOT), manages the largest competitive electric market in the country and maintains a diverse portfolio of power plants utilizing a mixture of fuel, with about 40% of electricity generated by coal and the remainder by natural gas, nuclear, and wind. Fuel diversity is critical for maintaining reliable and affordable electricity in Texas. [EPA-HQ-OAR-2009-0491-3980[1].1, p.5]
The mining of lignite in Texas and the use of coal to generate electricity in Texas accounts for over 33,000 direct jobs and nearly $10.5 billion annually in total expenditures. The coal industry in this state also provides over $300 million in annual state and local revenues, with over half of that money going to county services and school district operations. State and local taxing authorities would need to generate these lost revenues from other sources. [EPA-HQ-OAR-2009-0491-3980[1].1, pp.5-6]
The CATR Implementation Timeline is Unnecessarily Short  
The development and implementation of CAIR and the subsequent reformulated rule, CATR is discretionary rulemaking by EPA. EPA is under no court-ordered schedule for implementing CATR or CAIR. CAIR also remains in place. There seems therefore, little reason for compressing the rulemaking process and initiating the program in 2012. It is clear that a significant amount of work is needed to accurately compile and model emissions; accurately assess impacts and document projections and methodologies. Additionally, EPA also needs to account for adequate lead time needed for the planning, procurement or implementation of control equipment, should EPA proceed with a rule of this kind. [EPA-HQ-OAR-2009-0491-3980[1].1, p.6]
Luminant appreciates the opportunity to comment on this important rulemaking. Luminant continues to believe that Texas has been included in the ozone season NOx program in error and recommends that EPA removes Texas from the program. [EPA-HQ-OAR-2009-0491-3980[1].1, p.6]
Response: 
Thank you for your comment. Please see the response to the comment from Association of Electric Companies of Texas in this RTC section. Organization: Manitowoc Public Utilities (MPU)
Comment: 
Manitowoc Public Utilities (MPU)
MPU meets the definition and qualifies under the Small Business Regulatory Enforcement and Fairness Act of 1996 (SBREFA). The Small Business Act definition of a small electric utility is one that sells less than 4 million MWh annually at retail. The MPU Power Production Utility will be affected by EPA's Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3918[1].1, p.2]
The original proposal was not fair to a small municipal public utility that generates electricity. MPU agrees that historic heat input data is fuel neutral, emission control neutral, and should very accurately portray operations and is therefore a superior allocation method. [EPA-HQ-OAR-2009-0491-3918[1].1, p.2]
Response: 
Thank you for your comment.
Organization: Maryland Department of Environment (MDE)
Comment: 
Maryland Department of Environment (MDE)
ARMA does not support allocating additional allowances to dirty units under any methodology. [EPA-HQ-OAR-2009-0491-3972[1].1, p.2]
In Maryland's comments on the proposed Transport Rule, we expressed significant concerns with EPA's proposed variability structure. We particularly spoke about our concern that variability is added on top of the budget that was supposed to represent the maximum acceptable emissions, and that the variability concept as proposed would not provide the necessary assurances that the NOx budgets would be met. Mary land appreciates EPA's reevaluation of this issue. [EPA-HQ-OAR-2009-0491-3972[1].1, p.3]
Response: 
Thank you for your comment.
Organization: Massachusetts Department of Environmental Protection
Comment: 
Massachusetts Department of Environmental Protection
In MassDEP's comments on the proposed Transport Rule, we acknowledged that EPA's proposed use of a Federal Implementation Plan (FIP) provided assurance of achieving emission reductions quickly, but we expressed concern about the loss of a state's ability to tailor the trading program to meet its policy goals under a SIP. We urged EPA to give states the flexibility to adopt their own allocation methods and the flexibility to include in the state Transport Rule program smaller (15-25 megawatt (MW>> electric generating units (EGUs) and non-EGDs that it may have included in its Clean Air Interstate Rule (CAIR) ozone season program, but which are not covered units in the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-4017[1].1, p.1]
Response: 
--------------------------------------------------------------------------------
For reasons described in Preamble Section VII.B, the final Transport Rule does not allow any non-covered units to opt into the trading programs as administered under the FIPs, although states may consider allowing small EGUs of 25 MW or less to opt-in under a Transport Rule SIP.
Organization: Michigan Department of Natural Resources and Environment
Comment: 
Michigan Department of Natural Resources and Environment
One of the DNRE's most critical concerns, as stated in our original comments dated September 30, 2010, is the implementation timing for the proposed Interstate Transport Rule (TR), where Phase One begins in 2012 and Phase Two in 2014. The DNRE continues to believe the shortened timeline for implementation of the TR has adverse impacts on the states and sources affected. [EPA-HQ-OAR-2009-0491-3890[1].1, p.1]
It should be noted that the EPA is not obligated to have implementation time frames as early as proposed. Historically, the EPA has promulgated and finalized rules with time allowed for states to submit State Implementation Plans (SIPs) to implement the programs. The EPA finalized the NOx SIP call in 1998 with implementation dates for the Northeast states of 2003 and the Midwest states of 2004. Another major EPA rule package, the Clean Air Interstate Rule (CAIR), was finalized in 2005 and allowed state implementation using SIPs in 2009. [EPA-HQ-OAR-2009-0491-3890[1].1, p.1]
The current TR is expected to be finalized in 2011 with immediate EPA implementation of 2012. This latest NODA allows for states to submit full or abbreviated SIPs and implement them at the earliest in 2014, meanwhile keeping the EPA implementation in effect. The DNRE agrees with the EPA's proposal to allow for state submittals of full or abbreviated SIPs to implement the program. [EPA-HQ-OAR-2009-0491-3890[1].1, p.1] [[This comment can also be found in Section XX.E.]]
However, the DNRE believes the timing of program implementation can be delayed until states can adequately address the requirements and submit approvable SIPs. The December 2008 court remand of CAIR does not contain any requirements to implement the TR prior to allowing states the ability to submit approvable SIPS. The DNRE requests the implementation of the federal implementation plan (FIP) be delayed a minimum of 18 months to allow for state implementation. [EPA-HQ-OAR-2009-0491-3890[1].1, p.1]
Response: 
Thank you for your comment.Organization: Michigan Municipal Electric Association (MMEA)
Comment: 
Michigan Municipal Electric Association (MMEA)
These comments build upon the comments that MMEA and its members provided regarding the Transport Rule on October 1, 2010. Those comments provide more detailed descriptions of the 17 electric utility units affected by the proposed Transport Rule, which include Grand Haven's J.B. Sims Unit 3, Holland's 48th Street Station Units 7, 8 and 9 and James DeYoung Unit 5, Lansing's Eckert Unites 1-6 and Erickson Unit 1, Marquette's Shiras Unit 3, MSCPA's Endicott Generating Station, and Wyandotte's Unites 5, 7 and 8. [EPA-HQ-OAR-2009-0491-4020[1].1, p.1]
However, the proposed Transport Rule will continue to impose heavy and, in some cases, unreasonable burdens on small, public power electric utility units that are essential to the communities they serve. The proposed Transport Rule will require drastic, disproportionate NOx and/or SO2 emissions reductions from units that (1) cannot be cost-effectively controlled because of their small size, and that (2) have complied with and relied in good faith on NOx allowance allocations provided by the State of Michigan under an EPA-approved system that provides "hardship allowances" to small, municipal utility units to recognize their disadvantaged position under Clean Air Act requirements. [EPA-HQ-OAR-2009-0491-4020[1].1, p.1]
Under the proposed Transport Rule, EPA will allocate allowances under a Federal Implementation Plan (FIP) in a way that will preclude the State of Michigan from allocating allowances under a SIP until 2015 at the earliest, remove the hardship allowance provisions on which these Michigan units have relied without providing any other flexibility or support for small local government entities, and expose these public power utilities to the potential for undue market power and ill-designed EPA assurance provisions that could hurt these municipal utilities even more. [EPA-HQ-OAR-2009-0491-4020[1].1, p.2]
To remedy these deficiencies in the Transport Rule as proposed, MMEA and its members request that: [EPA-HQ-OAR-2009-0491-4020[1].1, p.2]
1. EPA should delay the implementation of the Transport Rule until 2015 (when CAIR Phase 2 is set to commence) to allow states like Michigan to develop, submit and receive EPA approval for abbreviated or full SIPs that allow States to control allocations of allowances within their own borders; [EPA-HQ-OAR-2009-0491-4020[1].1, p.2]
2. To the extent that EPA does not delay the Transport Rule implementation until 2015, EPA should form a "Small Entity Compliance Supplement Pool" of NOx ozone season and annual NOx allowances, for the period 2012-2014, that can be used to provide compliance support to small entities that have detrimentally relied on State-based hardship allowance allocations or that can demonstrate that they could be harmed by undue market power; and [EPA-HQ-OAR-2009-0491-4020[1].1, p.2]
3. EPA should craft the Transport assurance provisions in a way that does not cause undue harm to small public power units that rely upon allowances to comply with NOx and SO2 restrictions, and that will not be the units that cause any exceedance of Transport assurances levels by a State. The Small Entity Compliance Supplement Pool mentioned in #2 above can be a tool to ensure that assurance provisions do not impose unfair burdens on small entities. [EPA-HQ-OAR-2009-0491-4020[1].1, p.2]
MICHIGAN MUNICIPAL UTILITIES & COMPLIANCE WITH CAA REGULATIONS
MMEA repeats a portion of the comments provided to EPA on October 1, 2010 with respect to the Transport proposal, in order to emphasize why the 3rd NODA and EPA's proposed FIP allowance allocation methods will hurt Michigan public power: [EPA-HQ-OAR-2009-0491-4020[1].1, p.2]
Michigan public power communities have been subject to NOx emission limitations for more than a decade, under the NOx SIP Call, the Section 126 NOx rule, the Clean Air Implementation Rule and, of course, the State of Michigan's implementation of these NOx requirements. What EPA might not (but should) know is that Michigan public power systems have complied with NOx regulations through a State of Michigan approach that distributes "hardship allowances" to small EGUs that will suffer drastic, disproportionate impacts from Clean Air Act rules. The proposed EPA Transport rule ignores the Michigan hardship allowance approach in a way that could cause sudden and drastic impacts on covered Michigan communities. Thus, EPA (and the IPM) must take the Michigan hardship allowance program into account when assessing the six Michigan municipal utilities and their units affected here. [EPA-HQ-OAR-2009-0491-4020[1].1, p.2]
Since EPA began revising NOx regulations after the promulgation of the 1997 ozone NAAQS standard, MMEA and its members have sought to make the case, to EPA and the State of Michigan, that the relatively small units operated by Michigan public power communities would suffer drastic, disproportionate impacts from Clean Air Act controls because of the diseconomies of scale and other challenges associated with pollution control retrofits at these plants. For instance, in March 2004 comments to U.S. EPA on the then proposed "Interstate Transport Rule" to control ozone and fine PM (69 Fed. Reg. 4566, January 30, 2004), MMEA called on EPA to take into account that small municipal utility units have diseconomies of scale in pollution control, smaller rate bases, more limited access to capital, limited ability to average emissions across multiple units, and less "bang for the buck" in controlling relatively insignificant amounts of air emissions. MMEA commended EPA's recognition of these factors in its "Guidance on Mitigation of Impact to Small Business While Implementing Air Quality Standards and Regulations," EPA Policy Guidance at www.epa.gov/ttn/oar/oarpg (April 18, 1998), and in its Regulatory Impact Analysis for the 8-hour ozone standard, where EPA recognized that: [EPA-HQ-OAR-2009-0491-4020[1].1, pp.2-3]
Small entities, all other factors being equal, generally have less capital available for purchase of add-on pollution control technology than large entities. In addition, the control cost per unit of production for small entities will likely be higher than for large entities due to economies of scale. Thus, control measures requiring the use of add-on control technology may cause small entities affected by State rules to experience disproportionate economic impacts compared to large entities if no strategies to mitigate potential small entity impacts are available for implementation by States. . . . Consequently, EPA is encouraging States to exercise regulatory flexibility for small entities when developing strategies to meet the standards adopted today. While some States may need to turn to small businesses for emission reductions, small businesses will likely be among the last sources the States will choose to control. States may consider controls on small businesses only if such businesses are a significant part of an area's nonattainment problem and attainment cannot be reached through application of all available cost-effective measures to major sources. To the extent States consider controlling small businesses, EPA believes there are many ways States can mitigate the potential adverse impacts those businesses might experience. For example, States could choose to exempt or apply less stringent requirements to small businesses. ... States could also extend the effective date for control requirements for small businesses . . . States could also choose to apply control requirements to other businesses first, before requiring them for small businesses. [EPA-HQ-OAR-2009-0491-4020[1].1, p.3]
The State of Michigan and its Department of Environmental Quality . . . took these ideas to heart, and developed State Implementation Plans for the NOx SIP Call and CAIR that provided flexibility and support to small public power units that could demonstrate a disproportionate cost of NOx pollution control at their units. Michigan established a program to allocate "hardship allowances" to small entities (which includes all of the municipal systems commenting here, whom also qualify as "small entities" under the federal Small Business Regulatory Enforcement Fairness Act (SBREFA)). [EPA-HQ-OAR-2009-0491-4020[1].1, p.3]
Under Michigan's "hardship allowance" program in its EPA-approved SIP and state rules implementing the NOx SIP Call and then later CAIR, the State has set aside 1,200 annual allowances and 650 ozone season allowances that can be distributed to eligible municipal utility units that demonstrate "excessive or prohibitive cost" associated with NOx pollution controls. See Michigan Air Pollution Control Rules, Part 8 Emissions Limitations and Prohibitions  -  Oxides of Nitrogen (May 28, 2009, Rules 336.1810, 1824, 1832 at www.michigan.gov/documents/deq/deq-aqd-air-rules-apc-part8_314769_7.pdf. [EPA-HQ-OAR-2009-0491-4020[1].1, p.4]
These hardship allowances have been critical to Michigan public power communities. While many municipal utilities, including the ones here, have installed NOx pollution controls that were cost-effectively available, each of the systems commenting in this document have demonstrated excessive and prohibitive costs associated with NOx controls and received hardship allocations, and thus more drastic and expensive pollution controls have been able to be avoided. Simply, the hardship allowance program has been the cornerstone of compliance for Michigan public power  -  without violating Michigan's NOx budgets from EPA or otherwise increasing NOx pollution there or ozone pollution downwind. [EPA-HQ-OAR-2009-0491-4020[1].1, p.4]
Further, because the six Michigan public power utilities commenting here have properly relied upon the Michigan hardship allowance program when making short- and long-term operational, capital, economic, and pollution control plans, the sudden imposition of FIP-mandated individual unit allocations to these plants based on an IPM that has ignored the State's hardship allowance program will leave these systems in the lurch in 2012, 2014 and beyond. [EPA-HQ-OAR-2009-0491-4020[1].1, p.4]
We also note that the Michigan Department of Natural Resources and Environment, in its comments on the Transport Rule filed with EPA on September 30, 2010, states (at page 6) that "DNRE disagrees with the EPA's assumptions" regarding municipal utilities and states that these wrong assumptions have "created an area of economic hardship for small business sources within Michigan." These MMEA comments are also applicable to the 3rd NODA comments provided here. [EPA-HQ-OAR-2009-0491-4020[1].1, p.4]
EPA SHOULD DELAY THE IMPLEMENTATION OF THE TRANSPORT RULE TO ALLOW STATES TO DEVELOP SIPS AND ALLOWANCE ALLOCATIONS
As MMEA commented on October 1, 2010 and as explained above, Michigan public power units have relied and complied in good faith upon the ozone season and annual NOx allowance allocation programs established by the Michigan Department of Environmental Quality (MDEQ) and approved by EPA. Significantly, MDEQ has worked with Michigan public power over a decade to develop a "hardship allowance" program that addresses the unique issues with small, municipal utility units. [EPA-HQ-OAR-2009-0491-4020[1].1, p.4]
Now, EPA proposes the finalization and implementation of a Transport Rule that will not allow any state to conduct allowance allocations until 2014. Further, in the case of Michigan, the State is unable, under requirements established in law for the development of regulations, to set up an abbreviated or full SIP with state-based allowance allocations until 2015 at the earliest. Moreover, the EPA's proposed FIP allowance allocation proposal is in complete flux, preventing utility units from planning for the quickly-impending future. For MMEA public power units, this means that EPA's proposal for rapid implementation of this FIP will mean that hardship allowances will be yanked from these units a year from now. [EPA-HQ-OAR-2009-0491-4020[1].1, pp.4-5]
EPA repeats in the 3rd NODA the Transport Rule statement that "by promulgating these Transport Rule FIPs, EPA would in no way affect the right of states to submit, for review and approval, a SIP that replaces the federal requirements of the FIP with state requirements." 75 Fed. Reg. 45342. But EPA is putting the Clean Air Act on its head, essentially saying that a State can submit a SIP to fix an unacceptable FIP, rather than EPA being able to use a FIP to fix a missing or unacceptable SIP  -  which is the proper legal approach. Under the Clean Air Act, EPA may only impose a FIP "after the Administrator . . . finds that a State has failed to make a required submission or finds that the plan . . . submitted by the State does not satisfy the minimum criteria . . . or . . . disapproves a State implementation plan submission in whole or in part." 42 U.S.C. Section 7410(c)(1). See also the definition of "Federal Implementation Plan" under 42 U.S.C. Section 7602(y), which states that a FIP is meant to "fill all or a portion of a gap or otherwise correct all or a portion of an inadequacy in a State implementation plan . . ." [EPA-HQ-OAR-2009-0491-4020[1].1, p.5]
EPA's disregard of the Clean Air Act's requirements regarding FIPs in the case of the Transport Rule will cause significant hardship to Michigan public power units that have relied upon the long-standing NOx allowance allocation methodology used by the State of Michigan and long-approved by EPA. As stated in the comments submitted by the State of Michigan in its comments filed on February 4, 2011, EPA should delay Transport Rule implementation until 2015 to allow States like Michigan to develop a SIP. [EPA-HQ-OAR-2009-0491-4020[1].1, p.5]
EPA SHOULD ESTABLISH A "SMALL ENTITY COMPLIANCE SUPPLEMENT POOL" FOR 2012-2014
If EPA does not delay the Transport Rule implementation until 2015, it should at least consider the establishment of a NOx "Compliance Supplement Pool" for small entities, to protect these entities from disproportionate impacts or market power abuses. For the 17 units owned and operated by the six Michigan municipal utilities commenting here, the delta between their current NOx annual and ozone season allowance allocations under the currently-operating CAIR systems and the Transport Rule FIP allocations proposed by EPA for these units here, is approximately equivalent to the level of Michigan-based NOx annual and ozone season "hardship allowances" provided to these Michigan small municipal entities. [EPA-HQ-OAR-2009-0491-4020[1].1, p.5]
EPA can remedy this quickly impending problem for small local government entities through a "Small Business Compliance Supplement Pool" of annual and ozone season allowances. For the 2012-214 period, this compliance supplement pool could replace and serve the purpose of the Michigan "hardship allowances" that EPA approved under MDEQ's NOx reduction programs under the NOx SIP Call, CAIR and CATR. This pool could be available to entities that truly need the compliance flexibility, and could be limited based on reasonable factors such as: [EPA-HQ-OAR-2009-0491-4020[1].1, p.5]
- Affected entities that qualify as a "small entity" under the Small Business Regulatory Enforcement Fairness Act" (SBREFA), which defines a small electric utility entity as one that sells less than 4 million megawatt hours a year of electricity; [EPA-HQ-OAR-2009-0491-4020[1].1, p.5]
- Entities that have an obligation to serve electricity as a load-serving entity, rather than for-profit merchant power plants with no obligation to serve that are not subject to cost6 based rates or other electric utility regulations that apply to public power systems and other entities; and [EPA-HQ-OAR-2009-0491-4020[1].1, pp.5-6]
- Entities that have relied upon hardship allowances or other compliance flexibility that States have provided these entities under the CAIR/CATR NOx regulations. Such a requirement would prevent a windfall of extra allowances to entities that have applied controls or that seek to backslide from current emissions reduction efforts. [EPA-HQ-OAR-2009-0491-4020[1].1, p.6]
Such a compliance supplement pool would protect small, municipal utilities from having to consider drastic, cost-prohibitive pollution controls (which cannot be planned and installed in the coming 24 months anyway) or from having to make major allowance purchases during the 2012- 2014 compliance periods. [EPA-HQ-OAR-2009-0491-4020[1].1, p.6]
Such a Compliance Supplement Pool is also needed because many larger utility entities will be relying on the use of their own NOx allowances or allowances purchased from the market to meet compliance goals during the 2012-2104 period, when many units will be installing controls and will be unable to quickly install them. This could reduce the amount of allowances available on the limited interstate trading market and further expose Michigan municipal utilities to vulnerability. Moreover, during this 2012-2014 period, large entities with large fleets of utility units will be able to average system-wide emissions, further increasing their market power, which could be used to exacerbate the vulnerable positions of small municipal entities. [EPA-HQ-OAR-2009-0491-4020[1].1, p.6]
MMEA understands that very few states in the Transport region have provided "hardship allowances" or similar consideration to small, SBREFA-eligible utility units to comply with NOx regulations. Thus, the size of the Small Business Compliance Supplement Pool will likely not be required to be substantial, and could be achieved by a reservation of a very small percentage of the existing unit allowances allocated by the EPA under the FIP. In the case of Michigan entities, the total hardship allowance pool is 1,200 tons for annual NOx allocations and 650 tons for ozone season NOx allocations  -  a small but critical pool of compliance support that represents only approximately 2 percent of the Michigan budget and a negligible amount of the overall Transport Rule budget. [EPA-HQ-OAR-2009-0491-4020[1].1, p.6]
EPA should create a reasonable Small Entity Compliance Supplement Pool, set parameters on its use, and keep that tool available to deal with anomalies and inequities in the initial implementation of the Transport Rule. [EPA-HQ-OAR-2009-0491-4020[1].1, p.6]
THE TRANSPORT "ASSURANCE" PROVISIONS COULD HURT MICHIGAN PUBLIC POWER [EPA-HQ-OAR-2009-0491-4020[1].1, p.6]
EPA has asked whether its proposed alternative methods of allowance allocations should have any impact on EPA's use of the Transport assurance provision. See 76 Fed. Reg. at 1118. As MMEA stated in its October 2010 Transport Rule comments, EPA's assurance compliance provisions will impose a significant pro-rata penalty on any unit that did not reduce emissions sufficiently in any state that exceeds its emissions budget plus variability margin. However, given that Michigan public power units do not have the ability to cost effectively apply major pollution controls, and instead are maintaining compliance through Michigan hardship allowances, the application of assurance provisions on Michigan would impose major, disproportionate impacts on public power communities. Such disproportionate impacts on small units that rely on allowances for compliance will not change under the 3rd NODA proposal, which still does not allow States to provide initial allowance allocations, and which still takes away the hardship allowance feature established in Michigan. [EPA-HQ-OAR-2009-0491-4020[1].1, pp.6-7]
If the State of Michigan busts its assurance budget, it will not be because of these small utility units, whose emissions represent a small fraction of the State's emissions budget. For instance, the combined total annual NOx tons represented by all of the units owned and operated by the Michigan municipal commenters here represent less than 7 percent of the 62,984 ton annual NOx budget that will be provided to the State of Michigan under the proposed Transport Rule. If the larger entities with far larger and far more units bust the Michigan budget, they will likely have more options for compliance and fleet-wide averaging, yet the brunt of the assurance penalties will fall disproportionately on the small municipal units that depend on obtaining allowances to comply. [EPA-HQ-OAR-2009-0491-4020[1].1, p.7]
Any inequities imposed on small units like MMEA's members under the assurance provisions or through market power abuses could also be addressed through the use of a "Small Entity Compliance Supplement Pool" as suggested above, which could be used to address inequities in the application of assurance penalties. [EPA-HQ-OAR-2009-0491-4020[1].1, p.7]
MMEA urges EPA to delay the Transport Rule to allow states like Michigan to exercise their Clean Air Act right to submit a SIP to control allocations within their borders, and to consider the use of a compliance supplement pool to avoid disproportionate impacts on small municipal units that have complied in good faith with NOx and SO2 laws and regulations thus far. [EPA-HQ-OAR-2009-0491-4020[1].1, p.7]
Response: 
With regard to the deadlines for compliance, see section VII.C of the preamble.  
With regard to the suggested compliance supplement pool for small entities, the commenter failed to show that such a pool is necessary.   Based on its analysis of the impact of the final rule on small entities, EPA concluded that the Transport Rule will not have a significant impact on a substantial number of small entities.  See section XII.D of the preamble.   Further, the final rule establishes procedures under which state may submit SIP revisions that will replace, for control periods as early as those in 2013, EPA-determined existing-unit allowance allocations by state-determined existing-unit allocations.  See section X of the preamble.
With regard to the assurance provisions, the final rule implements the assurance provisions on a common designated representative basis.  This provides owners and operators of a unit, including a small municipal unit, the flexibility to group the unit with other units and sources in order to eliminate or reduce potential liability for any assurance provision penalty that would be imposed if the state exceeds the state assurance level for a given year.  See section VII.E of the preamble to the final Transport Rule.  
Organization: Midwest Ozone Group
Comment: 
Midwest Ozone Group
MOG believes that seeking comments on allowance allocations is a classic example of the tail wagging the proverbial dog. [EPA-HQ-OAR-2009-0491-3895[1].1, p.1]
MOG notes that the proposed CATR contains information related to a 2005 base year. EPA published a significant amount of data in the first NODA that MOG suggests does not support the CATR as proposed. NODA II contained additional modifications to data used by EPA in assessing the CATR. In NODA III, EPA is seeking comments on options for allocation of allowances. [EPA-HQ-OAR-2009-0491-3895[1].1, p.1]
Data submitted by MOG in comments responding to the proposed CATR clearly show that, with the exception of two Pittsburgh area monitors that are locally influenced, all of the stated air quality objectives of the CATR will not only be met by 2014, they will be met in 2018 through controls that are already on the books. MOG continues to believe that there is no need for a CATR and especially no need for a CATR focusing on the EGU sector, which constitutes less than ten percent of the precursor current inventory in the states affected by the proposed CATR. [EPA-HQ-OAR-2009-0491-3895[1].1, p.1]
EPA should remodel the CATR, taking into consideration both recent dramatic improvements in air quality since 2005 and updated inventories for all sectors, as well as comments submitted on the CATR and NODAs citing noted flaws in EPA's modeling platform and projection assumptions. [EPA-HQ-OAR-2009-0491-3895[1].1, pp.1-2]
Response: 
Thank you for your comment. Please see the response to MOG's previously submitted comment on this topic. 
Organization: Mille Lacs Band of Ojibwe
Comment: 
Mille Lacs Band of Ojibwe
Repeatedly, the USEPA have stated the primary purpose of the Air Transport Rule is to protect the health of the public and the health of the natural resources we share; it would be only prudent for the USEPA to implement remedy immediately and introduce modifications to the proposed Federal Implementation Plans (FIPs), so that the limits would apply starting in 2012 instead of 2014. [EPA-HQ-OAR-2009-0491-4019[1].1, p.2]
USEPA proposes to set air transport of pollution threshold at 1% of the National Ambient Air Quality Standards (NAAQS) for each of the key air pollutants-SO2 and NOx for PM2.5 and NOx for O3. The Band agrees with this 1% of NAAQS threshold as an initial step, but recommends USEPA to lower the threshold by 0.1% per decade such that in a century, no domestic air pollution would contribute to degradation of air quality through transport. In addition, to ensure protection of air quality to all citizens, the Band recommends USEPA to review the rate of progress every 5 years in the regions affected by the Air Transport Rule, and every 10 years to incorporate additional areas until all US States, Tribes, Protectorates and Territories are covered by the Air Transport Rule. During the same period, we encourage USEPA to coordinate with the US State Department to negotiate with our foreign neighbors and to encourage them to take parallel action to our Air Transport Rules such that neither we contribute to the degradation of their air quality nor they contribute to the degradation of our air quality. [EPA-HQ-OAR-2009-0491-4019[1].1, p.2]
The Band agrees with the USEPA that decoupling the precision of the air quality thresholds with the monitoring reporting requirements, and by using 2-digit values representing 1% of the NAAQS, which for under current PM2.5 NAAQS is 0.15 ug/m3 for the annual standard, and 0.35 ug/m3 for the 24-hour standard. This provides for a consistent approach for the annual and 24-hour standards, while readily making this approach applicable to any current and future NAAQS. [EPA-HQ-OAR-2009-0491-4019[1].1, p.2]
As air pollutant comes from all emission sectors, the Band recommends permitted non-EGU emissions reductions should be required if at the time of Prevention of Significant Deterioration (PSD) permit issuance or reissuance, modeling is conducted to holistically look at its cumulative effects of air pollution, and if the facility meets the Air Transport Rule's NAAQS-based threshold. If the non-EGU does not meet the NAAQS-based threshold, the facility would not be subject to the Air Transport Rule. This provision is of interest to the Band as within 80 miles of the Band are numerous non-EGU sources associated with the mining sector. Though some mining entities are already working towards reduction in NOx, vast majority of the mining sectors are not taking this proactive steps in reducing their NOx contribution; extending the Air Transport Rule to these non-EGU sources will help in improving our air quality. Similarly as another example, within 80 miles of the Band are three petroleum refineries. All three have taken steps to significantly lower their SO2 emissions, with a slight increase in their NOx emissions; repeatedly these three refineries are given as examples of being in the small group of cleaner refineries, but by extending the Air Transport Rule to non-EGUs, if they meet the NAAQS-based threshold, other peoples in the US who may be affected by the majority of not as clean petroleum refineries can receive similar benefits of cleaner air. [EPA-HQ-OAR-2009-0491-4019[1].1, p.2]
A concern for the Band is the availability of and access to affordable energy. Too often swings in market demands for energy have made the energy either physically inaccessible or unaffordable, which places great hardships on economically impoverished population groups, such as many of our Band members who live either on the Mille Lacs Indian Reservation or in Minneapolis' Phillips Communities, a group of four inner-city low-income neighborhoods. Too often energy providers implement temporary rate hikes which its effects disproportionately places our low-income Band members into peril, by loss of ability to feed themselves and their family, inability to go to and from their place of employment, or with sudden loss of a home. When implementing, the Band urges USEPA to ensure such implementation would not encourage EGUs to readily pass the cost of implementation to their customers. [EPA-HQ-OAR-2009-0491-4019[1].1, pp.3-4]
Though we understand USEPA would like comment on electric reliability issues, the Band realizes vast majority of electrical reliability issues stem not from EGUs, but rather from poor or antiquated electrical distribution system across the United States. We instead encourage USEPA to work closely with the US Department of Energy (USDOE) and the US Department of the Interior (USDOI) to develop a plan for the whole nation to better upgrade, maintain and secure our electrical distribution system. [EPA-HQ-OAR-2009-0491-4019[1].1, p.4]
While the Band agrees with USEPA that the proposed rule will generally make energy efficiency investments more competitive, if care is not taken by the USEPA on the treatment of minor sources, the new rule may instead foster a blossoming of many small EGUs across the country where their aggregated total emissions output may outpace the any improvements brought on through efficiency, thus nullifying the intent of the Air Transport Rule. For this reason, we strongly urge USEPA to consider not just the output from major source EGUs, but also take in consideration minor source EGUs by factoring in these minor sources' emissions in relation to density of their presence, and their relation to the major sources, such that we are not merely shifting a major source point source into an area source comprised of many minor source point sources. [EPA-HQ-OAR-2009-0491-4019[1].1, p.4]
The Band recognizes USDOE is the appropriate Federal entity to promote and regulate future energy policies and strategies. However, the Band also recognizes USEPA is the appropriate Federal entity to manage, regulate and reduce or eliminate environmental pollutants. Because of this, the Band strongly urges USDOE and USEPA to cooperatively work together to consider energy efficiency considerations in developing the allowance allocation methodology such that all citizens of the United States may enjoy access to affordable clean energy through a well-developed allowance allocation methodology. We caution, though, too often existing energy development took place on the backs of Tribes with little to no benefits given back to them. For example, the damming of river waters in name of flood control, but also used in managing the volume of waters flowing to hydroelectric generating facilities downstream, such as one located at the outlet of Big Sandy Lake for the Sandy Lake River-a major tributary of the Mississippi River-and several locations on the Mississippi, including dams located at Brainerd, Little Falls, Royalton and Sartell, have all significantly affected the Wild Rice beds, which their access and harvest by the Band are protected by treaties. Though we recognize hydroelectricity is very clean, allocations benefitting them for their production clean energy while our access to these treaty resources are threatened, or in many cases lost through policy taken by others, is a severe breech of Federal Trust responsibilities to the Tribes. No allowance allocation, even if the Band is financially compensated for the loss of this natural resource, is worth the loss of this precious gift from the Gichi-manidoo to all life; our past leaders have negotiated with the representative of the United States to ensure the protection of these resources and guarantee access to it for all future generations. [EPA-HQ-OAR-2009-0491-4019[1].1, p.4]
Response: 
EPA thanks Mille Lacs Band of Ojibwe for their comments. However, comments on setting the air transport pollution threshold, permitting non-EGUs, and future work with USDOE fall outside of the scope of NODA3.
With regard to the comment on access to affordable energy, EPA's analysis of the economic impacts of the final Transport Rule can be found in Preamble Section VIII.D.
Organization: Minnesota Power 
Comment: 
Minnesota Power 
Considering MPs high percentage of industrial customers who are high energy users and struggling to compete in a competitive global market economy, we are concerned that any further restrictions applicable to our facilities be implemented with reasonable timeframes and cost to minimize adverse impacts on our customers. [EPA-HQ-OAR-2009-0491-4009[1].1, p.2]
The magnitude of Proposed Transport Rule and NODA data offered by EPA for review is vast and time for review has been limited to 30 days. Consequently, Minnesota Power review has focused on a basic assessment of EPA's proposed budget allocations and matters related to Minnesota sources. As noted in previous comments by Minnesota Power (MP) to this Docket, MP has observed deviations between the initial Transport Rule and NODA/NEEDS data ascribed to Minnesota sources. [EPA-HQ-OAR-2009-0491-4009[1].1, p.3]
Response: 
Thank you for your comment.Organization: National Association of Clean of Air Agencies (NACAA)
Comment: 
National Association of Clean of Air Agencies (NACAA)
Since NACAA submitted its comments on the Transport Rule proposal, EPA has twice delayed its release of the revised ozone NAAQS. EPA is now scheduled to release the final revised ozone NAAQS by July 31, 2011, a year later than originally announced. Thus, it is unlikely the agency will be able to propose Transport Rule II in the summer 2011 and finalize it by summer 2012, as the agency had planned to do. [EPA-HQ-OAR-2009-0491-3964[1].1, p.2]
This postponement means a delay in critical reductions in air pollutant emissions from power plants. The Transport Rule reductions are designed to eliminate interstate transport of nitrogen oxide (NOx) emissions that interfere with attainment of the 1997 ozone standard of 0.084 parts per million (ppm), which is unprotective of public health. The Bush administration revised this standard to 0.075 ppm in 2008. However, EPA said it was unable to consider the more stringent 2008 standard in crafting the Transport Rule because EPA was reconsidering the standard. Thus the proposed Transport Rule is inadequate to the task of protecting public health. And, because EPA has postponed revising the 2008 standard, a new more protective Transport Rule II is also likely to be deferred until a later date. NACAA urges EPA to proceed as expeditiously as practicable with a Transport Rule II that takes into account a more protective ozone standard and thus includes more stringent NOx reductions. [EPA-HQ-OAR-2009-0491-3964[1].1, pp.2-3]
Response: 
EPA thanks NACAA for their comment, but it falls outside of the scope of NODA3. However, a similar comment previously submitted by NACAA has been responded to in RTC Section IV.E.1.
Organization: National Grid
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Oglethorpe Power
South Carolina Department of Health and Environmental Control 
State of Louisiana, Department of Environmental Quality
Comment: 
National Grid
We appreciate EPA's effort to develop regulations that will provide needed air quality improvements in a manner that addresses the Court's concerns and that can be implemented in a timely manner to ensure that air quality objectives can be realized. As a member of other industry groups, National Grid will be supporting other comments being submitted. [EPA-HQ-OAR-2009-0491-3921[1].1, p.1]
Oglethorpe Power
Federal Implementation Plan, EPA proposes to assume the responsibility of distributing allowances to affected EGUs in the CATR regions. As proposed, allocated allowances are to be based on the annual sulfur dioxide ('SO2'), annual nitrogen oxides ('NOx') and ozone season NOx emission budgets established for that state. Four discrete types of emissions allowances are to be allocated, for four totally separate cap-and-trade programs - SO2 Group 1 allowances, SO2 Group 2 allowances, NOx annual allowances and NOx seasonal allowances - to covered sources.  [EPA-HQ-OAR-2009-0491-3896[1].1, p.2]
Subsequently, on September 1, 2010, EPA published a Notice of Data Availability ('NODA 1') for the proposed CATR, supplementing the proposed rule with new information about EGUs. On October 27, 2010, EPA published a second NODA for the proposed CATR 'NODA 2'), which primarily addressed emission inventory issues for non-EGU source sectors. Recently, on January 7, 2011, EPA supplemented thg proposed CATR docket, with additional relevant information in a new NODA ('NODA 3').' [EPA-HQ-OAR-2009-0491-3896[1].1, p.2]
Oglethorpe Power Corporation ('Oglethorpe Power' or the 'Corporation') submitted comments on the proposed CATR (letter dated October 1, 2010) and on NODA 1 (letter dated October 15, 2010). As an owner, co-owner and/or operator of numerous EGUs in the State of Georgia, Oglethorpe Power has a substantial interest in ensuring that the Agency makes informed and reasonable decisions during this CATR rulemaking, as EPA moves forward to create regional NOx and SO2 emissions control/trading programs for EGUs that will replace those in the CAIR. Thus, Oglethorpe Power has a substantial interest in EPA's NODA 3. [EPA-HQ-OAR-2009-0491-3896[1].1, p.2]
Although Oglethorpe Power does not agree that assurance provisions are appropriate (or that the allowance surrender requirements or other penalty provisions in the proposed CATR are reasonable. [EPA-HQ-OAR-2009-0491-3896[1].1, p.5]
South Carolina Department of Health and Environmental Control 
On October 1,2010, DHEC submitted comments on the August 2,2010, Proposal. In this comment letter, DHEC noted, among other things, that the method used to determine allocations in the NOx SIP Call and Clean Air Interstate Rule ('CAIR), heat input, was more transparent and reliable than the method used in the August 2,2010, Proposal, basing projections on the Integrated Planning Model ('IPM). DHEC also noted that the EPA should elaborate on the State Implementation Plan ('SIP') options, and allow states a greater role in implementing the Transport Rule with the EPA. [EPA-HQ-OAR-2009-0491-3961[1].1, p.1]
State of Louisiana, Department of Environmental Quality
LDEQ understands that the unit-level allocations in this NODA are based on state emissions budgets in the proposed Transport Rule. LDEQ understands that final state budgets may differ from the proposed budgets because EPA is still in the process of updating its emissions inventories and modeling in response to public comments, including comments on the Integrated Planning Model (IPM). Furthermore, LDEQ applauds EPA's work toward final budgets based on the updated inventories and modeling. LDEQ works very hard to make certain that the state's emissions inventory is robust and appreciates EPA's effort toward the same goal. [EPA-HQ-OAR-2009-0491-3977[1].1, pp.1-2]
Louisiana, through approved SIPs, managed the allocations for the state's facilities through the. Clean Air Interstate Rule (CAIR). This program was developed by the LDEQ with stakeholder input. Such stakeholders were the Louisiana Public Service Commission and the different electric generating units (EGUs) statewide. This program was very effective and Louisiana has realized a decrease in the emissions of S02 and NOx. [EPA-HQ-OAR-2009-0491-3977[1].1, p.2]
we energies
  EPA has requested comment on alternative unit-level emission allocation methodologies. However, in its January 7 notice, EPA recognizes that its proposed budgets are still a work in progress due to the fact that the agency is continuing the process of updating its emission inventories and modeling due to public comment received on the original July 2010 proposal. [EPA-HQ-OAR-2009-0491-3976[1].1, p.1]
We have made significant investments in reducing NOx and SO2 emissions, and wish to receive equitable allowance allocations. We hope to avoid allocation penalties that could result from not receiving enough allowances to cover our full system of fossil units. Our compliance plan revolves around first making investments at our larger baseload units where controls are most cost effective, and essentially over-controlling at these units to cover higher emission rates at our smaller units, that are more costly to retrofit. [EPA-HQ-OAR-2009-0491-3976[1].1, p.2]
Response: 
[No response needed.]
Organization: National Mining Association (NMA)
Comment: 
National Mining Association (NMA)
NMA also reiterates the position it has taken in prior comments in this and other rulemakings that EPA must assess the cumulative impact of all of its regulations that affect the use of coal for electric generation and as a commercial and industrial fuel. Cumulative impact analysis is called for in the President's recent Executive Order 13563 and is particularly important here because NODA-3 and the Transport Rule represent one of a series of EPA regulations that may profoundly affect the most dominant fuel this country uses for electric generation. We therefore urge EPA to take a pause in the Transport Rule process until it performs a cumulative impact assessment. [EPA-HQ-OAR-2009-0491-4013[1].1, p.2]
A pause is also warranted because, with each of EPA's three successive NODAs, the nature of the rule that EPA is actually proposing has become increasingly uncertain. As NMA has commented previously, the fact that the public does not at this point know fundamental aspects of EPA's proposal impairs the public's right to notice and comment in the rulemaking process. Moreover, with the January 1, 2012 compliance date rapidly approaching, the utility industry does not have sufficient time to prepare to comply with whatever requirements ultimately are adopted. [EPA-HQ-OAR-2009-0491-4013[1].1, p.2]
A pause at this point for EPA to package up all of the changes it wishes to make to the proposed rule as a result of the three NODA processes and to issue a new proposed rule for public comment would not impair air quality. The Clean Air Interstate Rule remains in place. EPA can, and at this point must, delay the start of the CATR program in order to do the rulemaking process correctly and in accordance with law. [EPA-HQ-OAR-2009-0491-4013[1].1, p.2]
:: All of this increase comes at the expense of coal units. EPA set state budgets based on reported or projected emissions and used those values to determine unit level allocations. Thus, the PTR Method allocations to coal-fired electric generating units (EGUs) represent EPA's approximation of emissions from coal-fired EGUs after elimination of significant contribution and interference with maintenance. [EPA-HQ-OAR-2009-0491-4013[1].1, p.4]
To be sure, the interest in accuracy in the first factor above could be a legitimate reason for selecting a particular allocation methodology. EPA, however, was satisfied enough with using historical and projected unit emissions in determining state budgets; indeed, the state budgets were determined by first determining and then adding up historical and projected emissions from units within the state. Thus, if historical and projected unit emissions data were sufficiently reliable for use in determining state budgets, they must be reliable enough for determining unit allowance allocations. This conclusion has even more force in that, as EPA would have to concede, the Agency has less discretion and therefore more need for accuracy in determining state budgets than it does in determining allowance allocations to individual units. [EPA-HQ-OAR-2009-0491-4013[1].1, p.8]
Furthermore, contrary to the implication that the emission-based methodology should be rejected because it is not "neutral" as to fuel and emissions controls, such methodology, in fact, is indifferent as to both factors. Under the emissions-based methodology, units are allocated allowances based on their reducing emissions down to the level necessary to eliminate their individual contribution to the state's overall significant contribution (their "contribution to significant contribution"). In other words (simplifying), if a unit emits 1000 tons, and EPA determines through its Integrated Planning Model ("IPM") that such unit can cost-effectively reduce emissions to 100 tons, then the unit gets 100 allowances, and that result is obtained regardless of the fuel the unit burns or the controls the unit has. [EPA-HQ-OAR-2009-0491-4013[1].1, p.9]
The rule, as proposed, ensures that higher-emission-rate units will reduce their emissions to the extent they can do so cost-effectively. The whole premise of the rule, and EPA's basic interpretation of CAA section 110(a)(2)(D)(i)(I) going back to the NOX SIP Call, is that a state's significant contribution is defined by the amount of emission reductions that a state can be make cost-effectively. The emissions-based methodology is designed to carry out this premise at both the state budget level and at the unit level. Thus, under the emissions methodology, units that can cost-effectively reduce will be required, in EPA's phrase, "to reduce emissions or purchase additional allowances" because their allowance allocations will match the amount of their emissions after they make cost-effective emission reductions. As EPA's projections show, precisely because it is more cost-effective in general to reduce emissions at higher-emission-rate units than lower-emission-rate units, the burden of reducing emissions will be borne to the greatest extent by the higher-emission rate units. [EPA-HQ-OAR-2009-0491-4013[1].1, p.10]
NMA has previously commented to EPA that NODA-1 and NODA-2 fundamentally impaired the public's right to comment on the proposed rule because the public no longer knows specifically what rule EPA is proposing. [EPA-HQ-OAR-2009-0491-4013[1].1, p.11]
Each of the three NODAs provides new information, revises critical underlying data, explains new modeling assumptions, or presents new methods. In many cases these changes are likely to impact literally every aspect of a final regulatory program. Yet with each NODA, EPA fails to provide the data needed to determine how the various NODA changes would impact the final rule. [EPA-HQ-OAR-2009-0491-4013[1].1, p.11]
At this point, the public does not know: (i) how significant contribution and interference with maintenance will be defined (including what cost-per-ton breakpoints EPA will select based on its multifactor analysis); (ii) which areas will qualify as downwind receptors triggering evaluation of upwind emission impacts; (iii) which states will be included in which programs; (iv) whether the rule will include interstate trading  -  and if so to what extent; (v) whether the rule will include trading at all; (vi) what the state budgets are, if trading programs are adopted; and (vii) what individual unit allocations will be. Without this information, the public cannot determine how it is affected by the proposed rule and therefore what its objections may be. [EPA-HQ-OAR-2009-0491-4013[1].1, p.11]
In the first place, even the proposed Transport Rule allocations are obsolete at this point. EPA has acknowledged that the state budgets  -  and thus the unit allocations  -  are subject to change. More significantly, before the close of the comment period on the proposed rule, EPA's first NODA proposed revisions to the critical NEEDS database and the IPM that were the basis for a significant number of state budgets and unit allocations. Many state budgets and unit allocations are based almost exclusively on unit level projections from the now outdated IPM. Yet with the first NODA, EPA did not provide the information needed to know how various unit allocations or state budgets would change. [EPA-HQ-OAR-2009-0491-4013[1].1, pp.11-12]
Additionally, EPA provided revised fuel price assumptions that would likely have a profound impact on how units are modeled to run  -  and thus, on what their projected emissions would be. Because of these changes, not to mention the initial data errors contained in the technical support documents for the proposed rule, the proposed Transport Rule allocations are obsolete and do not form a basis for comparing how units would be affected by the two new methods proposed. [EPA-HQ-OAR-2009-0491-4013[1].1, p.12]
In sum, the public does not know what EPA's regulation is and therefore does not have proper notice and opportunity to comment. [EPA-HQ-OAR-2009-0491-4013[1].1, p.12]
III. EPA Must Afford the Regulated Community an Opportunity to Develop Compliance Plans.
The problem created for the regulated community by EPA's failure to set forth the rule it is actually proposing goes beyond notice-and-comment requirements. The regulated entities do not have enough information or time to develop meaningful compliance strategies. NODA-3 compounds that problem. Now, in addition to not knowing what programs will apply to a given state or what the state budgets will be, regulated entities are left guessing at the widely divergent potential allowance positions that result from the three proposed allocation methods. [EPA-HQ-OAR-2009-0491-4013[1].1, p.12]
The compliance period for the rule is proposed to commence in January 2012, less than eleven months from today. EPA has stated that it intends to issue the final rule this "summer," which seems optimistic given the fundamental questions that EPA must address in response to public comments on the three NODAs. But even if EPA meets the summer deadline, regulated entities will have only as much as six months (and maybe only three depending when in the summer the rule is issued) to adjust to their final allowance positions [EPA-HQ-OAR-2009-0491-4013[1].1, pp.12-13]
This compressed timeframe exacerbates the problems owners and operators will face if the final rule under-allocates allowances to their units (which as demonstrated above is a real possibility under the NODA-3 allocation methods). Under-allocated owners or operators will not have time to develop compliance strategies other than to buy allowances or curtail operations  -  with only six months notice. Six months is not enough time to adequately assure that replacement generation (holding sufficient allowances) will be available. And six months is not enough time for stable allowance markets to develop. And these problems will be further compounded if EPA proposes additional limits on trading  -  e.g., intrastate trading only or a reduction in the size of Group 1 or Group 2. [EPA-HQ-OAR-2009-0491-4013[1].1, p.13]
Such a compressed compliance timeline is unprecedented, inappropriate and unnecessary. In CAIR, EPA issued the final rule three and a half years before the initial compliance period for NOx and four and a half years before the initial compliance period for SO2. Yet EPA intends here to allow at most six months notice from final rule to compliance period for all programs. There is simply too much uncertainty at this point for EPA to hold fast to its initial proposed ambitious timeline. To allow for the possibility of ordered, planned and efficient compliance, EPA must put aside its haste and allow, at a minimum, sufficient time for regulated entities to develop attainable compliance strategies. [EPA-HQ-OAR-2009-0491-4013[1].1, p.13]
As noted in our and numerous other comments on the proposed Transport Rule, the opportunity for states to develop a SIP precedes a FIP; not the other way around. EPA cannot impose a FIP without allowing the states an opportunity to develop a SIP. [EPA-HQ-OAR-2009-0491-4013[1].1, p.13]
V. This Rulemaking and EPA's Continued Issuance of Adjustments to the Proposed Rule Do Not Meet the Spirit or Letter of the New Executive Order 13563.
On January 18, 2011, the President signed Executive Order 13563, Improving Regulation and Regulatory Review. Executive Order 13563 supplements and reaffirms Executive Order 12866. Executive Order 13563 requires that regulations be based on the "open exchange of information," and that EPA afford "a meaningful opportunity to comment, with a comment period that should generally be at least 60 days." [EPA-HQ-OAR-2009-0491-4013[1].1, p.14]
The continuing release of NODAs that propose fundamental reworkings of the proposed rule with 30-day comment periods does not meet these requirements. The material provided in the NODAs is highly complex and cannot be adequately examined in only 30 days. [EPA-HQ-OAR-2009-0491-4013[1].1, p.14]
And most fundamentally, until EPA sets forth specifically what its regulatory proposal is, the public, in the words of the Executive Order, has not been afforded "a meaningful opportunity to comment." There is, to again quote the Executive Order, no "open exchange of information" between EPA and the public when the public is not informed as to how the various methodological changes it has under consideration affect its basic regulatory proposal. [EPA-HQ-OAR-2009-0491-4013[1].1, p.14]
NMA has commented to EPA several times that EPA needs to assess the impacts of the Transport Rule cumulatively with the many other rules that EPA has promulgated and is considering that affect the use of coal for electric generation and in industrial and commercial boilers. Without reiterating those comments here, NMA notes that Executive Order 13563 is further support for NMA's comment.
Executive Order 13563 states that it "is supplement [EPA-HQ-OAR-2009-0491-4013[1].1, p.15]al to and reaffirms the principles, structures, and definitions governing contemporary regulatory review that were established in Executive Order 12866 of September 30, 1993," which is one of the authorities on which NMA relied for its argument that EPA must do cumulative impact analysis. Executive Order 13563 explicitly quotes the cumulative impact requirement from Executive Order 12866: "As stated in that Executive Order and to the extent permitted by law, each agency must, among other things...tailor its regulations to impose the least burden on society, consistent with obtaining regulatory objectives, taking into account, among other things, and to the extent practicable, the costs of cumulative regulations...." NMA therefore reiterates that the Transport Rule is flawed unless EPA undertakes the necessary cumulative impact analysis. [EPA-HQ-OAR-2009-0491-4013[1].1, p.15]
NMA continues to urge EPA to re-propose the rule for further comment, to perform a cumulative impact assessment, and to delay the date for implementation of the rule. [EPA-HQ-OAR-2009-0491-4013[1].1, p.15]
Our analysis in Part II below (comparing allocations under the three allocation methods based on technology class/plant type) relies chiefly on the following three databases provided by EPA in this rule making:
-  The National Electric Energy Data System (or "NEEDS") database Version 4.10 provided with the first NODA (September 1, 2010) ("NEEDS Database");
- The Budgets and Allocations  -  Detailed Unit-Level Data (Excel) data file provided with the proposed Transport Rule ("PTR Database"); and
- The Alternative Allocation Tables and Underlying Data (Excel File) data file provided with NODA-3 ("NODA-3 Database"). [EPA-HQ-OAR-2009-0491-4013[1].2, p.2]
Unfortunately, EPA did not provide fuel type or technology class information in the PTR Database. To determine that information, we used the unique unit identifiers in the NEEDS Database and PTR Database (i.e., "UniqueID_Final" and "NEEDS ID," respectively) to pull "plant type" and "modeled fuels" data values for each unit from NEEDS Database into the PTR Database. This then allowed us to group the PTR Database data according to "plant type." Once that was completed, we were able to group the units based on "plant type." The plant type and technology class designations correlate, and we were therefore able to perform analysis/comparisons of data (e.g., allocations) under the PTR Method and the two NODA-3 Methods  -  Option 1 Method and Option 2 Method. [EPA-HQ-OAR-2009-0491-4013[1].2, pp.2-3]
Response: 
With regard to deadlines for compliance and EPA's authority to promulgate the Transport Rule FIPs, see sections IV.C and VII.C of the preamble to the final Transport Rule.  
With regard to the methodology for existing-unit allowance allocations, see section VII.D of the preamble.  EPA provided -- through the proposed rule and the NODAs -- notice and opportunity for comment on the allocation methodology and the resulting unit-by-unit allocations.  The allocation methodology and unit-by-unit allocations are a logical outgrowth of the proposed rule and NODAs.  See section VII.D of the preamble.
EPA complied with Executive Order 13563 in developing the final Transport Rule as discussed in section XII.A of the preamble.
Organization: National Rural Electric Cooperative Association (NRECA)
Comment: 
National Rural Electric Cooperative Association (NRECA)
The compressed timeline of 2012 for the CATR first compliance period, however, presents insufficient time to allow states the opportunity to distribute allowances under a SIP to reflect individual state needs and concerns.  [EPA-HQ-OAR-2009-0491-3943[1].2, p.1]
A significant portion of cooperative fossil-fuel electric generation is located within the 32 state regions addressed in the proposed CATR and would be affected by its mandates.  The proposal is complex, utilizes several atmospheric and economic models and extensive, although many times erroneous, electric utility unit operational and emissions control information to produce four separate electric utility cap-and-limited trading programs.   Utilizing this extensive modeling, the final rule dictates essentially permanent unit compliance obligations through limiting unit emissions allowances, while providing only extremely limited opportunities for any allowance reconciliations and no criteria for doing so.   [EPA-HQ-OAR-2009-0491-3943[1].2, p.3]
NRECA is disappointed, however, that the timelines EPA has proposed for CATR implementation, beginning in 2012, do not allow adequate time for states to submit and obtain SIP approvals incorporating allowance allocation methodologies better suited to meeting state or local concerns as compared to the chosen methodology in the generic FIP.   EPA's hurry-up compliance timeline of 2012 presents yet another problem with the CATR, that of the ability of a state to craft its own allowance policies to best suit its needs during the first two years of CATR implementation.  As we have commented previously, Section 110 of the Clean Air Act is constructed to provide states the opportunity to develop their own plans to meet state air act obligations, including addressing interstate transport of air pollution.  EPA's CATR proposal thus far has failed to provide states the opportunity to do this at least for two years after CATR's compliance provisions are to take effect. [EPA-HQ-OAR-2009-0491-3943[1].2, p.3]
NRECA is disappointed, however, that the agency has not addressed the problematic timing of the CATR 2012 and 2014 compliance periods, as NRECA and others have identified in earlier comments to the August 2, 2010, CATR.  EPA's failure to extend the CAIR beyond 2011 and its proposed imposition of the 2012 and the 2014 timelines continues to plague this rulemaking.   [EPA-HQ-OAR-2009-0491-3943[1].2, p.4]
As NRECA has noted in our earlier comments, there is no legal prohibition in the North Carolina decision against keeping CAIR in effect beyond 2011, and EPA's failure to do so would create yet another problem in so far as effectively prohibiting states from implementing SIPs addressing Clean Air Act Section 110(a)(2)(D)(i) deficiencies during the early stages of CATR implementation.  [EPA-HQ-OAR-2009-0491-3943[1].2, p.5]
Moreover, as NRECA has commented previously, the proposed compressed compliance timelines afford, at best, limited, and in most cases, no opportunity for units to alter their emission characteristics by 2012, even for those units that could cost-effectively reduce their emissions further.   [EPA-HQ-OAR-2009-0491-3943[1].2, p.5]
Response: 
Thank you for your comment.Organization: National Tribal Air Association (NTAA)
Comment: 
National Tribal Air Association (NTAA)
Opt-In of Non-Covered Sources
Apart from issue regarding the construction of new sources on Tribal lands, the NTAA also feels that the EPA has wholeheartedly failed to address a matter very relevant to the NODA, one which our organization put forth in its October 1, 2010 comment letter to the Agency. The issue specifically concerns the opt-in of non-covered sources on Tribal lands, something for which we now take this opportunity to copy our previous comments below: [EPA-HQ-OAR-2009-0491-3993[1].1, p. 3]
The Transport Rule also provides for non-covered sources (e.g., operating boiler,  combustion turbine, or other stationary combustion device) to voluntarily enter trade  programs with allowance allocations given to them based on their historical emissions3  While the expectation of EPA is that these sources might be better able to make lower  cost emissions reductions than EGUs within a state, thereby reducing the program's  overall costs, this approach offers a more important benefit in advancing the Rule's  larger purpose of limiting the "interstate transport of emissions of nitrogen oxides (NOx) and sulfur dioxide (SO2)."4 As such, the Agency should be utilizing every  opportunity to further this purpose which should include non-covered sources on  Tribal lands that lie contiguous or near to those states covered by the Rule. These  sources, like those located on the lands of states, are not otherwise obligated to  reduce their NOx and/or SO2 emissions unless covered by the Rule. With coverage,  however, the EPA could seize a valuable opportunity to further the Rule's purpose,  and ultimately help improve the health and welfare of all people and lands in the  Eastern U.S. [EPA-HQ-OAR-2009-0491-3993[1].1, pp. 3-4]
The NTAA therefore recommends that the EPA allow non-covered sources on  Tribal lands beyond EGUs to be covered under the Transport Rule but only on a  voluntary basis as is true for similar sources on state lands. [EPA-HQ-OAR-2009-0491-3993[1].1, p. 4]
Response: 
Please see the response to the previously submitted comment.
Organization: Nebraska Public Power District
Comment: 
Nebraska Public Power District
NPPD submitted comments on the proposed TR on October 1, 2010 stating that the EPA overestimated the contribution from Nebraska sources and that the EPA should remodel using more realistic emissions data. NPPD believes that this would show that Nebraska does not qualify to be included in the TR. NPPD has attached our original comments for your reconsideration and to restate our belief that Nebraska should not be included in the TR. [EPA-HQ-OAR-2009-0491-3886[1].1, p.1] [[See Docket Number EPA-HQ-OAR-2009-0491-3886[1].2 for NPPD's original comments.]]
Response: 
Regarding the inclusion of Nebraska under the Transport Rule, please see Preamble Section V.
Organization: Nelson Industrial Steam Company (NISCO)
Comment: 
Nelson Industrial Steam Company (NISCO)
It should also be noted that the EPA incorrectly identified these two units in the September 1, 2010 NODA and in the other Technical Support Documents underlying CATR as belonging to the Entergy owned RS Nelson facility in Calcasieu Parish. The correct facility name for the two NISCO units is 'Nelson Industrial Steam' and the correct ORlSPL identification number for this facility is 50030. [EPA-HQ-OAR-2009-0491-4026, p.1]
EPA should not include Louisiana sources under CATR for purposes of annual sulfur dioxide (S02) and annual nitrogen oxide (NOx) reductions because Louisiana's sources do not adversely impact PM2.5 levels in Texas. As indicated in NISCO's original comments, the IPM Base Case, whether premised on v. 3.02, v. 4.10 or some future version, should only be a screening tool for indications of potential 'significant contribution' or 'interference with maintenance'. The !PM is simply not accurate enough and is dependent upon too many uncertain assumptions and imprecise inputs to make binding decisions of 'significant contribution' or 'interference with maintenance.' EPA should always place great weight on empirical data to modify projected model conclusions when making these determinations. [EPA-HQ-OAR-2009-0491-4026, p.2]
EPA's original modeling, using the IPM version 3.02 for the Base Case, projected that Louisiana emissions may interfere with maintenance of the annual PM2.5 NAAQS in 2012, by contributing only 0.34 ug/m3 to the annual PM2.5 values at the Clinton Drive monitor in Houston, Hartis Co., TX. Of that total, EPA projected that nearly all of it, 0.33 ug/m3 is from sulfate emissions and only 0.004 ug/m3 from nitrate emissions. The projected design value for the Clinton Drive monitor in 2012 was 14.74 ug/m3 average and 15.14 ug/m3 maximum compared to the 15.0 NAAQS ug/m3. [EPA-HQ-OAR-2009-0491-4026, p.2]
In reality, the annual average PM2.5 in 2009 was only 12.8 ug/m3, and from January 1 through August 29, 2010, the average was 12.72 ug/m3. The design value dropped to 14.4 ug/m3 for the 2007-2009 period and is expected to drop to a value of only approximately 13.2 ug/m3 due to 2007 dropping out of the 3-year average. So, it is clear that current Louisiana emissions are not interfering with maintenance of the NAAQS in any way. These Louisiana emissions are projected by EPA to drop even further without the CATR/FIP. [EPA-HQ-OAR-2009-0491-4026, p.3]
NISCO anticipates that EPA's current remodeling with corrected data and inputs will show that there is no projection for interference with maintenance of the PM2.5 standard at the Clinton Dr. monitor in Houston, Texas. NISCO urges EPA to complete its assessment and conclude in the final rulemaking that Louisiana sources should not be included under CATR because such sources do not interfere with maintenance of the PM2.5 NAAQS. [EPA-HQ-OAR-2009-0491-4026, p.3]
EPA should not include Louisiana sources under CATR for purposes of ozone season NOx reductions because Louisiana's sources do not adversely impact the ability of the Houston or Dallas areas of Texas to comply with the 1997 8-hr. ozone NAAQS. EPA also projected, under the IPM version 3.02 Base Case, that Louisiana emissions will significantly contribute to nonattainment with the 1997 8-hour ozone NAAQS at certain monitoring sites in the Houston-Galveston-Brazoria ('HGB') and the Dallas-Ft. Worth ('DFW') Areas of Texas in 2012. EPA has projected that Louisiana emissions will interfere with maintenance of that NAAQS at other monitoring sites in the HGB and the DFW Areas of Texas in 2012. But, again, real data cast doubt on these projections. All monitors in the HGB Area are currently in attainment with the 1997 8-hour ozone NAAQS and have been for two years. AU of the DFW monitors that EPA projected were adversely impacted by Louisiana emissions, save one, are also currently in attainment with that NAAQS. The design value at that one monitor at issue in DFW is 86 ppb, just 2 ppb above the standard and available information indicate that local sources are the contributing factors to its attainment status. [EPA-HQ-OAR-2009-0491-4026, p.3]
On September 1, 2010, EPA published the NODA indicating that EPA intends to use the IPM version 4.10 modeling, including a revised TR Base Case 2012 scenario, for revising the determinations of significant impact and interference with maintenance. Under the revised IPM TR v. 4.10 2012 model results show significant reductions in projected S02 and NOx emissions that will occur even without implementation of the CATR/FlP (or CAIR). If these values are used in revised air quality modeling, it is virtually certain that the conclusion will be that Louisiana emissions do not impact the 1997 8-hour ozone standards in Texas. [EPA-HQ-OAR-2009-0491-4026, p.3]
As discussed in NISCO's comments on CATR and the September 2010 NODA, even without a revised air quality analysis, NISCO believes that use of the TR Base Case v. 4.10 data supports the conclusion that Louisiana should not be included in the CATR/FIP. The original CATR/FIP determined that a certain level of emission reductions from EGUs would remove 'significant contribution' and 'interference with maintenance.' The revised IPM v. 4.10 Base Case shows that emission reductions greater than that level will occur by 2012, even without CATR. These results demonstrate on their face that because the quantity of S02 and NOx emissions that were required to be removed to prevent 'significant contribution' 'interference with maintenance' are now projected to be removed by 2012 through factors other than the CATR/FIP, there is no legal basis for a CATR/FIP for annual S02 or annual or ozone season NOx control for Louisiana EGUs. [EPA-HQ-OAR-2009-0491-4026, pp.3-4]
Response: 
Thank you for your comment.Organization: New Jersey Department of Environmental Protection (NJDEP)
Comment: 
New Jersey Department of Environmental Protection (NJDEP)
In closing, the Department urges the USEP A to craft a rule that adequately reduces the transport of air pollution sufficiently to enable states to attain the 1997 and 2006 fine particulate health standards and the 1997 ozone health standard. More importantly, the USEP A needs to adopt similar rules which address the 2008 and future ozone health standards, the 2010 S02 health standard, and other new health standards to come. Staff at the Department are available to discuss the details of how the New Jersey NOx Budget Program and the CAIR NOx Trading Programs work. [EPA-HQ-OAR-2009-0491-3891[1].1, p.3]
Response: 
EPA thanks NJDEP for their comment , but finds it is outside of the scope of the NODA3. EPA is not taking any action in this rule to address the 2008 ozone standard under reconsideration or any future standards.

Organization: New York State Department of Environmental Conservation
Comment: 
New York State Department of Environmental Conservation
The NODA proposes a modified allocation scheme based upon the budgets contained in the original proposed transport rule of August 2, 2010.  While EPA is considering alternate ways to allocate at the unit level, it continues to rely on the flawed state budgets that were established in the proposal.  Even though EPA has said that it is not interested in comments on the overall state budgets in response to this NODA, the Department believes that this NODA, as well as the recently posted 2010 emission data on EPA's CAMD site, further illustrate the discrepancies contained in the state budgets.  The 2010 data is more representative of "normal" operations because of more representative meteorology and a start to the economic recovery in 2010.  When the 2010 statewide NOx emission data is sorted on a pound per million Btu basis and then compared to the reductions (Base Case minus proposed budgets) that would be required under the proposal, four of the six largest reductions on the state level are required from the four states with the lowest emission rates (at least a 25% reduction for each of those states).  Comparing this with the eleven (11) states with 2010 emission rates over 0.15 lb/MM Btu (the nominal rate promulgated in the 1998 NOx SIP Call), only four are required to lower their emissions by more than ten percent.   [EPA-HQ-OAR-2009-0491-3937[1].1, p.1]  
The Department renews its objection to EPA's continued reliance on the IPM model in establishing the budgets for this trading program.  IPM has proven unreliable in its prediction of unit operations, shutdowns and projection of new units.  [EPA-HQ-OAR-2009-0491-3937[1].1, p.1]
The Department fully supports EPA in its mission to develop programs to remedy the transport of emissions and would like to work closely with you as this rule is finalized and the next rule is developed. [EPA-HQ-OAR-2009-0491-3937[1].1, p.2] 
Response: 
Regarding how state budgets were determined, please see Preamble Section VI.
Regarding unit allocations, please see Preamble Section VII.D.
Organization: NextEra Energy, Inc.
Comment: 
NextEra Energy, Inc.
As stated in our October 1, 2010 comments, NextEra Energy generally supports the proposed Transport Rule. The proposed rule will achieve important air quality, health, and economic benefits utilizing EPA's current authority. It is critical that EPA implement the rule as expeditiously as practicable to ensure realization of these benefits. We are committed to working with EPA to ensure the Agency can implement the Transport Rule by January 1, 2012, and to that end, we offer these comments on the January 7th NODA. [EPA-HQ-OAR-2009-0491-3962[1].1, p.1]
As we noted in our comments on the proposed Transport Rule, the language of the Clean Air Act provides EPA with broad authority to implement allowance allocation methodologies, and there is no strong policy or legal reason that the methodology for determining state budgets and the methodology for distributing allowances to units need to be the same. By maintaining the proposed methodology for determining the state budgets, EPA is consistent with the D.C. Circuit's decision requiring that state budgets be based on each state's significant contribution. [EPA-HQ-OAR-2009-0491-3962[1].1, p.2]
As we explained in our comments on the proposed rule, the Integrated Planning Model (IPM) used to project emissions under the originally proposed allocation approach does not consider a range of non-economic factors that may influence a company's decision to operate particular types of units or for the respective Independent System Operator (ISO) to call upon specific units. As a result, the modeling can create unrealistic scenarios for some individual units, such as ignoring dispatch requirements of EGUs subject to power purchase agreements, running natural gas combined-cycle units at higher utilization than can be accommodated by the local natural gas pipeline network and not running oil-fired units that are required to operate to meet load requirements. While these distortions of the electricity market are masked when data are aggregated at the state level for setting state budgets, the modeling results in unrealistic or infeasible outcomes when used at the unit level to allocate allowances. By contrast, a historic basis for allocating the state budgets avoids these problems and strengthens the legal basis for the rule. [EPA-HQ-OAR-2009-0491-3962[1].1, p.2-3]
Under the compliance assurance provisions contained in the August 2, 2010 proposed Transport Rule, if the emissions from affected units in a covered state in any year exceed the state's 'assurance level' (i.e., the state budget plus the state's variability level), certain owners of affected units would be required to surrender allowances. The surrender requirement would be imposed on the owners and operators of units whose share of the state's total covered-unit emissions was greater than their share of the state's assurance level - i.e., the units that can be considered partially responsible for the exceedance. The allowances the owners would be required to surrender would also be proportionate to their responsibility for the state's exceedance. [EPA-HQ-OAR-2009-0491-3962[1].1, p.3]
Response: 
Thank you for your comment.Organization: Northern Indiana Public Service Company (NIPSCO)
Comment: 
Northern Indiana Public Service Company (NIPSCO)
As NIPSCO stated in its comments on the proposed Transport Rule dated October 1, 2010, NIPSCO believes that developing the appropriate allocation methodology is a task best suited to states. However EPA seems determined to proceed directly with federal implementation plans(FIPS). [EPA-HQ-OAR-2009-0491-3995[1].1, p. 2]
NIPSCO continues to believe that there are better allocation methodologies that could be developed and would likely be developed by the State of Indiana. [EPA-HQ-OAR-2009-0491-3995[1].1, p. 2]
NIPSCO notes that just as the use of projected emissions for Indiana EGUs as the basis for allocating allowances is, in NIPSCO's view, an inappropriate allocation methodology for individual EGUs, it is also an inappropriate basis for the statewide bUdgets. The statewide budgets, like the originally proposed allocations, reward states where emission controls have not occurred to the degree that they have in other states. The method for establishing the statewide budgets places the states on an uneven playing field at the outset. While Option II is definitely an improvement over the allocation methodology originally proposed, the problem of how the statewide budget was determined in the first place remains. Just as EPA proposes an alternative allocation methodology based on historic heat input, a more equitable means for determining the statewide budgets would be historic heat input, as well, with the budgets reduced by the amount necessary to address each state's downwind contributions to nonattainment or interference with maintenance of the air quality standards. Although EPA says that the statewide budgets are not subject to comment under the January 2011 NODA, the correction to the allocation methodology that EPA proposes in the January 2011 NODA should naturally be extended to the statewide budgets. [EPA-HQ-OAR-2009-0491-3995[1].1, p. 2]
USE OF FIPs TO IMPLEMENT THE PROPOSED TRANSPORT RULE
In the January 2011 NODA, EPA stated that states can submit full or abbreviated state implementation plans ('SIPs'), following promulgation of the Transport Rule. 76 Fed.Reg. 1109, 1119-1120. NIPSCO believes that EPA has ignored or misunderstood the thrust of comments regarding the submission of Transport Rule SIPs. The Clean Air Act places initial responsibility for compliance with federal requirements on the states. Proposing in a rule to allow states to submit SIPs to address the transport requirements of Section 110(a)(2)(D) of the Clean Air Act does not satisfy that basic delegation of responsibility to the states. [EPA-HQ-OAR-2009-0491-3995[1].1, pp. 2-3]
NIPSCO appreciates that EPA is making an effort to recognize that states may submit SIPs to address the Transport Rule. However, what EPA offers in the January 2011 NODA is not substantially different from what it discussed in the original proposal and still ignores the directive in the Clean Air Act that states have first responsibility to develop regulatory programs. EPA's drastic departure from the state-federal partnerships of the NOx SIP Call and the CAIR are unnecessary and contrary to the Clean Air Act. [EPA-HQ-OAR-2009-0491-3995[1].1, p. 23
NIPSCO recommends that EPA recognize that states have the responsibility to determine how they will comply with the statewide budgets imposed by the Transport Rule and that states must have a reasonable period of time, up to three years, following promulgation to develop and submit their Transport Rule SIPs. The CAIR will remain in place and applicable during the time that states are developing their Transport Rule SIPs. Current air quality demonstrates that the CAIR has been effective; therefore, the environment would not be negatively impacted by EPA's compliance with the Clean Air Act. [EPA-HQ-OAR-2009-0491-3995[1].1, p. 3]
Response: 
Thank you for your comment.Organization: Northshore Mining Company
Comment: 
Northshore Mining Company
As an initial matter, we understand that EPA has received significant comments on the proposed CATR and the subsequent NODAs and the agency is considering significant changes to the proposed rule.  Corrected data will necessitate a re-analysis of states' contributions to downwind areas. As you are aware, there has been some uncertainty regarding the nature and extent of the contribution of Minnesota sources to downwind areas.  The State of Minnesota and its affected sources deserve a full and fair opportunity to review the results of EPA's re-analysis and comment on any proposed changes.  EPA should re-propose the CATR to offer affected entities a complete opportunity to consider and comment on the corrected state applicability determinations and on EPA's preferred allowance allocation option. EPA seeks comment in NODA III on the implications of the allocation methodology options that EPA is still considering.  One of the most significant implications is the compressed schedule between EPA's final decision and the 2012 initial compliance year. The final rule in mid-2011 should not be the first time that affected sources understand what will be required of them in the 2012 CATR.  [EPA-HQ-OAR-2009-0491-3957[1].1, p.1]
Northshore's cogeneration system is unique in many respects. It is the only cogeneration system in the taconite industry subject to the CATR.  In fact, Northshore understands that it is the only non-utility, industrial boiler system in Minnesota that would be subject to the CATR.  As discussed in greater detail below, extending the cogeneration exemption to industrial cogeneration units in Minnesota (Northshore) would have no discernable effect on the goals of the CATR to alleviate downwind impacts.  Failing to provide relief, however, could be catastrophic for Northshore and the Northeastern Minnesota economy. [EPA-HQ-OAR-2009-0491-3957[1].1], p.4  
Based on the allowance allocation systems proposed in the NODA III, even with the corrections described in a separate section of these comments, the Northshore Units would face annual compliance costs estimated as high as $30 million depending on the price of allowances. These costs cannot be passed on in the price of taconite pellets for the iron and steel industry because Northshore's competitors will not have CATR compliance costs.  The utility sector, by comparison, will absorb the full cost of CATR in the marginal increase of the price of electricity shared by all of the electricity customers in the region.  This marginal increase in the price of electricity will provide a small benefit for Northshore as it will be able to sell its cogenerated electricity at a slightly higher price to the grid.  However, that benefit is a drop in the bucket compared to the significant annual cost of the CATR program for Northshore.  The bulk of the cost burden will be a direct hit on the company's profitability.  Northshore cannot absorb these costs and remain a viable taconite mining business.   [EPA-HQ-OAR-2009-0491-3957[1].1, p.4] 
As indicated in the Northshore comments from October 1, 2010, Northshore's demise will be a significant blow to the economy of Northeastern Minnesota.  Northshore's mining operations provide 640 direct jobs and 1150 additional indirect jobs in support of these operations.  Northshore contributes approximately $110 million each year to the local economy through its purchase of services and supplies and it pays approximately $11 million in state and local taxes.  These economic consequences are significant in this area of Minnesota and they are entirely avoidable with a minor clarification to the cogeneration exemption.  There is no indication that EPA considered these costs and the potential impacts on this facility when it proposed the CATR.  EPA was focused instead on the consequences for the utility sector, which are more measured and more evenly distributed.  EPA needs to take the time to properly consider the potentially severe economic consequences of its proposed approach to closing a loophole in the cogeneration exemption.  Excusing historic cogeneration units from the CATR would make that economic analysis unnecessary and mitigate an unintended and disproportionate economic consequence on Northshore that will eliminate jobs unnecessarily.  [EPA-HQ-OAR-2009-0491-3957[1].1, p.4]
Removing the Northshore Units from CATR is consistent with the environmental objectives of the rule.        
EPA has designed the CATR to limit the interstate transport of NOX and SO2 that affect downwind states' ability to attain and maintain compliance with the PM2.5 and ozone National Ambient Air Quality Standard (NAAQS).  Minnesota is excluded from the ozone season portion of the CATR because EPA has determined that sources within the state do not significantly contribute to downwind problems attaining or maintaining the eight-hour ozone NAAQS.  For the PM2.5 NAAQS, EPA has determined that the EGUs in Minnesota have some downwind effect on certain areas of Illinois, Iowa and Wisconsin.  Northshore is in the upper Northeast portion of Minnesota, much farther from these downwind areas than most of the Minnesota utilities that would remain subject to CATR if the historic industrial cogeneration units were excluded from the trading program. [EPA-HQ-OAR-2009-0491-3957[1].1, p.5]   
Also, the air quality is improving more quickly than EPA projected when the CATR was being developed.   The most recent air quality data indicate substantially fewer nonattainment and maintenance areas than EPA's modeling results originally projected. According to an ENVIRON study using 2006-2008 and 2007-2009 DVs, over 80% of EPA predicted ozone and PM2.5 nonattainment sites in 2012 are already in attainment as of 2009, over 80% of PM2.5 2012 maintenance sites and 1/3 of the ozone 2012 maintenance sites are no longer maintenance as of 2009. The air quality further improved in 2010 and is trending downward.  These improvements suggest that EPA's model may be over-predicting the effect of upwind sources on downwind monitors.  Until EPA properly calibrates its air models to predict the actual monitored ambient air quality values, EPA should move cautiously and incrementally with its rules to protect against imposing more economic harm than is justified by the targeted environmental objective.  By imposing CATR only on the utility sector, EPA would help ensure that legitimate industrial cogeneration units do not face severe economic consequences that are unnecessary to meet the downwind environmental objectives of the CATR.    [EPA-HQ-OAR-2009-0491-3957[1].1,p .5]
Alternatively, EPA should delay implementation of CATR for industrial cogeneration units.  
If EPA insists on using the PURPA efficiency criteria for pre-1980 cogeneration units, EPA should place the affected industrial cogeneration units on a different time schedule for CATR compliance.  Based on the air quality trends, applying the CATR only to the utility sector in Minnesota should be more than sufficient to meet the downwind objectives for the PM2.5 NAAQS.  If, however, EPA later determines after the CATR is implemented for the utility sector that additional reductions are necessary to mitigate actual downwind impacts from Minnesota, EPA could then bring the industrial cogeneration units like Northshore into the rule.  This phased approach to implementation is well within EPA's discretion and would ensure that the initial costs of the CATR are imposed only on the utility units that can easily spread those costs among electricity customers. This will also alleviate the severe time pressure on Northshore to prepare to meet the CATR and absorb its initial economic impact in 2012.  [EPA-HQ-OAR-2009-0491-3957[1].1, pp.5-6]
If EPA adopts either of the allocation methodologies outlined in the January 7, 2011 NODA, the Northshore Units will face substantial allocation deficit starting in 2012.  Northshore needs more than eight months to evaluate and implement emission control options to mitigate this deficit.  Without relief, Northshore will need to purchase significant numbers of allowances which will create material financial impact on the economic viability of the Northshore facility.  Adequate advance notice is necessary to accommodate the planning necessary to implement emission reductions, including engineering, environmental permitting, procurement, installation and shakedown.  It is unreasonable to expect a facility to implement a CATR compliance program with less than eight months lead time after the allocation methodology is finalized.    [EPA-HQ-OAR-2009-0491-3957[1].1, p.6]
EPA should wait until the emission reductions already in the pipeline have been implemented before extending the CATR to industrial cogeneration units.   For instance, Northshore is already subject to rules that will require NOX and SO2 emission reductions, though on a far more reasonable timeline than the CATR.  The Northshore Units are subject to the Best Available Retrofit Technology (BART) requirements under the Regional Haze rule, which target fine particle, NOX and SO2 emission reductions to help Class 1 areas meet visibility standards.  These are the same pollutants that contribute to PM2.5 formation.  The Regional Haze program timeline allows for a more deliberate process to evaluate cost effective technology for emission reductions.  BART will also be applied consistently across the entire taconite industry, ensuring that the regulatory requirements do not have a disproportionate impact on a single company.  By contrast, the CATR would apply to one taconite company, Northshore, and impose costs on this company years ahead of the emission control obligations for the rest of the industry sector.  Treating one taconite facility differently is an arbitrary exercise of EPA discretion.  Doing so because they had the foresight to install a cogeneration system in the 1950s and 1960s is unreasonable.   [EPA-HQ-OAR-2009-0491-3957[1].1, p.6]
With a phased approach, EPA has the ability to evaluate each incremental step to determine if the next step is cost effective and consistent with current job retention and job growth priorities.  EPA should take this time to consider carefully whether it is necessary or prudent to penalize historic cogeneration units to close a cogeneration loophole in CATR applicability.  Ironically, if Northshore had not built a cogeneration system, its industrial boilers would not be subject to CATR, as EPA has excluded the Non-EGU industrial boilers formerly included in the NOX Budget Trading Program from this utility-focused trading rule.  EPA should not treat these cogeneration units more stringently than their less-efficient industrial boiler counterparts.   [EPA-HQ-OAR-2009-0491-3957[1].1, p.6]
A trading program works best when the allocation methodology is transparent and predictable.  This starts with a clear list of the affected sources subject to CATR, which should exclude historic cogeneration units.  Then, the allocation methodology should be set and the allowance allocations established with enough advance notice to allow affected entities to implement a strategy for achieving the highly cost effective emission reductions available for their units.  The CATR affected sources do not have enough time to evaluate and implement emission reductions before the 2012 compliance year. This undercuts the value of a trading system as a means of achieving cost-effective emission reductions and merely shifts wealth from the buyers to the sellers in the allowance market.    Northshore encourages EPA to re-propose the CATR and allow industrial sources more time to implement emission reductions before their first compliance year.   [EPA-HQ-OAR-2009-0491-3957[1].1, p.7]
Response: 
A description of how the Transport Rule is applicable to certain cogeneration units can be found in Preamble Section VII.B.
Organization: NRG Energy
Comment: 
NRG Energy
 We support only a carefully designed trading program that takes into account the primary objective of the CAA and CATR objectives (air quality improvement and transport reduction) as well as the needs of each state and each state's individual fuel mix.    [EPA-HQ-OAR-2009-0491-3933[1].1, p.2]
 We support only a carefully designed trading program that takes into account the primary objective of the CAA and CATR objectives (air quality improvement) as well as the needs of each state and each state's individual fuel mix. [EPA-HQ-OAR-2009-0491-3933[1].1, pp.4-5]    
Response: 
Regarding the development of state budgets, please see Preamble Section VI.D. 
Organization: Occidental Chemical Corporation (OCC)
Comment: 
Occidental Chemical Corporation (OCC)
OCC reiterates and incorporates by reference our comments submitted to EPA on the proposed CATR on October 1, 2010, and October 15, 2010. Fundamentally, we object to including Louisiana and Texas in a final CATR. Furthermore, we object to including any cogeneration facilities in the CATR trading scheme, given that the primary purpose of the Public Utility Regulatory Policies Act is to encourage the development of cogeneration facilities. In addition, we endorse and adopt by reference the comments submitted by the Louisiana Chemical Association ('LCA') on the proposed rule on October 1, 2010, and October 15, 2010, and LCA's comments submitted today regarding the NODA. [EPA-HQ-OAR-2009-0491-3951[1].1, p.2]
In our previous comments, we expressed our disapproval of EPA's use of the Integrated Planning Model ('IPM') for developing emissions allowance allocations. We continue to believe that the IPM is an economic model that cannot account for the complex and realistic operations of power generating facilities and transmission grids. For example, the IPM apparently does not take into account electric load or steam demand by a co-located power/steam host. Thus, the operation of a facility like our Taft cogeneration plant, which provides both a significant amount of steam and electricity to the co-located OCC-owned manufacturing facility, is not modeled correctly. EPA's failure to recognize, model and allocate allowances to cover non-discretionary emissions generated in connection with the permitted operation of a manufacturing facility constitutes a fundamental flaw in EPA's allocation of emissions allowances and the CATR. Furthermore, the model does not take into account legally-binding power contracts or other supply mechanisms that exist now and into the future, or state and federal regulations governing electricity pricing and cost recovery. [EPA-HQ-OAR-2009-0491-3951[1].1, p.2]
Response: 
OCC's previously submitted comments are responded to elsewhere in the RTC document.
Organization: Ohio Utility Group (OUG)
Comment: 
Ohio Utility Group (OUG)
The Utilities have stressed the importance of accuracy throughout this rulemaking process and, in particular, have tried to illustrate the near-impossibility of issuing an appropriate number of SO2 and NOx allowances - at the unit-level- without accurate information and without utilizing the most appropriate implementation method. Allocating SO2 and NOx based on historical heat input data is a step toward remedying each of these deficiencies, highlighted by the Utilities in previous comments, that currently plague the proposed Transport Rule. Therefore, the Utilities urge EPA to, at the very least, implement either of the two Options proposed in NODA 3 rather than engaging in an allocation guessing game based on projected source emissions. [EPA-HQ-OAR-2009-0491-4005[1].1, p.2]
One of the most significant flaws of the proposed Transport Rule is that unit-level allocation - regardless of the 'method' - is a state responsibility under Section 110 of the Clean Air Act. The Utilities have commented extensively on EPA's unlawful Federal Implementation Plan ('FIP') proposal under the Transport Rule. Most notably, the states have more unit-specific regulatory experience and are more knowledgeable of the facilities within their own jurisdictions. As such, the states are in the best position to meet the required state reduction levels and, by working as individuals in a concerted effort, are more likely to achieve the reduction of interstate transport. Therefore, the imposition of a FIP, even with provisions for an 'abbreviated SIP' granting the states limited allocation authority, not only exceeds EPA's authority under the Clean Air Act, but will also result in a rule that is less effective and makes compliance more difficult. [EPA-HQ-OAR-2009-0491-4005[1].1, p.3]
Finally, EPA's piecemeal rulemaking is a flaw in itself which has effectively denied the Utilities the opportunity to submit complete and meaningful comments. Supplementing the docket on three separate occasions with little time to review substantial amounts of information is only part of the challenge. Furthermore, EPA has repeatedly made statements to the tune of: 'could impact the final rule in a number of ways' and ' ... could be used to implement the final rule' and 'final state budgets may differ from the proposed rule.' These statements continue to mask the true 'identity' of the final Transport Rule such that the Utilities cannot completely, or accurately, evaluate the issues presented in NODAs 1-3. Therefore, the Utilities respectfully request the Transport Rule in its entirety - reflecting all 'final' decisions resulting in any modification of the proposal - be resubmitted for public comment. [EPA-HQ-OAR-2009-0491-4005[1].1, pp.3-4]
Response: 
Thank you for your comment.Organization: Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
Comment: 
Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
No allocation methodology can change the fact that there is not enough pollution control equipment built or able to be built by 2012 and 2014 in Ohio and Indiana to achieve the drastic and overly stringent reductions called for in the PTR. [EPA-HQ-OAR-2009-0491-4010[1].1, p.2]
As OVEC explained in its original comments, it has spent almost $2 billion dollars to retrofit its units with state-of-the-art SO2 and NOx emission control equipment, and to allow its units to burn a blend of lower sulfur coals. While OVEC would receive more allowances under both NODA allocation methodologies than it would under the original PTR, its ability to comply with the overly stringent emission reductions is still seriously in question. OVEC has spent over a billion dollars installing scrubbers on its two plants, but the Clifty Creek Plant's scrubber is not scheduled to come online until mid-2013 - a date that would allow OVEC to achieve compliance with CAIR, but a date that will cause it to be out of compliance with the PTR from the outset. And once again, EPA has not considered the fact that the OVEC boilers are wet-bottom boilers which have an inherently higher baseline NOx emission rate than other types of boilers. [EPA-HQ-OAR-2009-0491-4010[1].1, p.2]
EPA has failed to demonstrate that such stringent emissions limitations on such an aggressive schedule will produce any greater demonstrable benefit to the downwind states than CAIR reductions - or CAIR's more reasonable schedule - would achieve. Nor has EPA provided a legal justification for the undue local economic and employment disruptions that the PTR will cause. Further, the proposed overly broad ban on interstate allowance trading after 2013 aggravates the mismatch of costs and benefits of the PTR compared to CAIR. [EPA-HQ-OAR-2009-0491-4010[1].1, p.2]
Where the facts are that controls cannot be timely installed and operated to achieve emission levels below PTR unit allocations, and there are not assurances (or even a likelihood) of sufficient allowances available for purchase and use for a unit's shortfall of PTR allocated allowances, the PTR effectively mandates confiscatory production curtailment. EPA rules that force production curtailments in one state for unverifiable air quality benefits in another state require the clearest and most convincing justification and demonstrated lack of more reasonable alternatives. The PTR lacks such justifications and more reasonable alternatives are available. [EPA-HQ-OAR-2009-0491-4010[1].1, p.3]
EPA's modeling and allocations are based on the premise that pollutants are transported from one geographic area to another geographic area. However, the allowances and reductions required of utility operators in upwind geographic areas are allocated based on the political boundaries of the states at issue. This is not a trivial difference given the strict limitations EPA is proposing on allowance trading. [EPA-HQ-OAR-2009-0491-4010[1].1, p.3]
Before 2014, EPA's proposal allows unlimited interstate trading, similar to the CAIR program currently administered by the agency. However, in 2014 and thereafter, EPA's proposal would limit the ability to trade allowances to the political boundaries of the state in which a source resides (with a very limited additional margin), without any regard to the geographic relationship between the two sources wishing to trade the allowances. The result is that operators such as OVEC - with just two plants located in two adjacent states - are unable to take advantage of the inherent flexibility in an emissions-trading program, while trying to comply with the extremely stringent emission limitations that take effect in 2014, even though OVEC's two plants are in closer geographic proximity than plants within the same state that are permitted to trade allowances. [EPA-HQ-OAR-2009-0491-4010[1].1, p.3]
By way of example: If the NOx control equipment at the Kyger Creek Plant (Ohio) achieves maximum removal efficiency throughout 2014 and is able to generate enough annual NOx allowances to cover a shortfall at the Clifty Creek Plant (Indiana), OVEC would not be able to achieve compliance if emissions at the Clifty Creek Plant exceed the assurance provisions, regardless of how large a margin of compliance is achieved at the Kyger Creek Plant. Instead, OVEC would have to locate and purchase allowances from another source in Indiana (if such allowances exist) and attempt to sell the excess allowances from Kyger Creek to a source located in Ohio (assuming that an Ohio source needs those allowances). Even then, if other multi-state operators in Indiana also purchase allowances (because they too installed more cost-effective controls in other states), OVEC will be penalized for actions over which it had no control, even though it has reduced emissions on its units collectively below the levels required by the PTR. The same result occurs when considering SO2 allowances While it may be able to use allowances generated by its operation of the Kyger Creek scrubber to cover an SO2 shortfall in part in 2012 and 2013, if there is any unforeseen delay in Clifty Creek's scrubber schedule, its available options for allowance trading are arbitrarily cut off at the borders of each state - assuming it can find any allowances available for trade in 2014 after the tightening of the SO2 budgets in Indiana. [EPA-HQ-OAR-2009-0491-4010[1].1, pp.3-4]
Similar situations exist for numerous operators along many major river systems covered by the PTR. In many cases, a person can actually stand at a plant in Ohio and see another plant owned by the same utility across the Ohio River in Kentucky or West Virginia. Under the PTR - whether using the original or newly proposed allocation methods .... the plant in Ohio could trade credits with a source hundreds of miles away (within the same state), but not with one within its own system just a few kilometers away. [EPA-HQ-OAR-2009-0491-4010[1].1, p.4]
The geographic modeling that EPA uses to estimate the impacts of transported air pollutants and justify its rulemaking in the PTR uses a grid system that has no relationship to state political boundaries. Indiana and Ohio are within the section of that grid that uses twelve kilometer squares. Emissions within each square of the grid are not distinguished from one another by state of origin. Given the granularity of the grid, emissions from sources in northern Ohio follow a different path and have a different effect than emissions from southern Ohio over 300 miles away. However, the allocation and trading provisions in the PTR NODA treat those emissions as completely interchangeable. The same provisions treat two sources within the same square of the grid as fundamentally different and not interchangeable under any circumstances. In short, the trading provisions treat such emissions in the opposite way from the modeling that allegedly supports them. This is irrational, arbitrary, and harmful to OVEC. [EPA-HQ-OAR-2009-0491-4010[1].1, p.4]
OVEC understands that the court in North Carolina v. EPA, 531 F.3d 896, 907 (D.C.Cir, 2008) vacated CAIR in part based on its unrestricted interstate trading provisions in the context of a pinpointed, specific source-receptor relationship. Id. at 907 ('Theoretically, sources in Alabama could purchase enough NOx and SO2 allowances to cover all their current emissions, resulting in no change in Alabama's contribution to Davidson County, North Carolina's non-attainment.'). OVEC also understands that the state boundaries are significant for many aspects of any attempted rulemaking - not the least of which is the development of State Implementation Plans, discussed below. OVEC is not proposing that EPA return to the completely open trading provisions of CAIR, or that the proposal completely disregard state borders. Rather, EPA's assurance provisions would achieve both the air quality and cost-effectiveness goals of the PTR if there were more rational requirements that balanced the virtues of the emissions trading scheme with assurance provisions that reflect the geographic and operational realities of the utility industry. [EPA-HQ-OAR-2009-0491-4010[1].1, p.5]
OVEC suggests that EPA allow trading between sources in adjacent states that have the same designated representative, subject to the same limitations as the current state assurance provisions. These assurance provisions would alleviate the D.C. Circuit's concern about entire states failing to make reductions because there is no one representative who acts for all of the EGUs in multiple states, and each state's budget reflects the required reductions on a regional basis. Requiring that the sources be in adjacent states creates a logical and rational geographic relationship between traded credits. The assurance provisions would help both large and small systems achieve compliance with any final rules consistent with traditional utility planning principles, as illustrated by the fact that OVEC - a two-plant system - would get actual, meaningful relief from such an exception. [EPA-HQ-OAR-2009-0491-4010[1].1, p.5]
While such limited trading may help companies craft rational compliance plans, it cannot be stressed enough that under current state budgets, trading as a compliance option may be illusory at best. Under EPA's current proposed state budgets for 2012, even units controlled with state-of-the-art pollution controls may not be able to achieve compliance with their allotted allowances. Kyger Creek has five units and every single unit is equipped with selective catalytic reduction (SCR) and overfire air (OFA). Even with the best possible pollution control equipment in place, under the original allocation method EPA proposed Kyger Creek could not comply with its proposed NOx emission limitations. Under the current allocation methodology, Kyger Creek may be able to comply, but much of its compliance ability turns on the absence of equipment problems and continuously optimizing performance of its pollution control equipment. [EPA-HQ-OAR-2009-0491-4010[1].1, p.5]
Thus, even fully controlled units are unlikely to generate significant SO2 or NOx credits for trading. After 2014, the SO2 budgets are even more stringent, which means even fewer allowances will be available for sale, regardless of the trading restriction placed upon them. Through its proposed state budgets and trading provisions, EPA is essentially forcing the curtailment or retirement of otherwise viable economic assets. The almost-immediate proposed compliance deadlines mean that coal-fired units that do not already have every available state-of-the-art pollution control cannot install such controls before 2014. The proposed state budgets in Indiana and Ohio are so stringent that it is unlikely there will be any meaningful allowance market, and trading restrictions make those allowances even less obtainable after 2014. Such units, then, will be forced to shut down or curtail production. In a state such as Ohio, where approximately 80% of electric generation comes from coal-fired units, EPA's proposed PTR would cause economic mayhem - the effects of which EPA does not analyze or justify in any of its rulemaking. There is simply no air quality or other justification for allowing unfettered trading up until 2014, and then needlessly restricting it based on political boundaries when there are more rational and reasonable options that EPA has not considered. [EPA-HQ-OAR-2009-0491-4010[1].1, pp.5-6]
While OVEC again reiterates these concerns about the overly stringent emission limitations and time frames proposed in the PTR, a more rational approach to the assurance provisions would alleviate some of the burden of complying with such reductions in the time frame proposed, and on a going forward basis. [EPA-HQ-OAR-2009-0491-4010[1].1, p.6]
EPA has demonstrated through its third NODA and its two prior NODAs, that it has the ability to take such basic unit characteristics into account, but continues to fail to do so. EPA is still underestimating the number of allowances that should be allocated to the OVEC units due to the OVEC boilers' inherent characteristics. [EPA-HQ-OAR-2009-0491-4010[1].1, p.6]
II. The SIP Procedures in the NODA Do Not Cure EPA's Attempt to Improperly Impose a Federal Implementation Plan (FIP)
OVEC now turns to the abbreviated and full SIP provisions in the NODA. EPA continues to ignore the fundamental legal flaw in the PTR of improperly using a FIP. OVEC's previous comments show that EPA has not complied with the Clean Air Act requiring that the Administrator make a finding that a SIP is substantially inadequate, and give a state an opportunity to correct the deficiency before imposing a FIP. §110(k)(5). Indeed, a FIP may not be imposed prior to two years after the Administrator finds that a state plan is deficient or disapproves a state plan that is submitted for approval. §110(c). [EPA-HQ-OAR-2009-0491-4010[1].1, pp.6-7]
Both Ohio (as to the Kyger Creek plant) and Indiana (as to the Clifty Creek plant) currently have approved interstate transport implementation plans for which there have been no subsequent notices of deficiency by the Administrator. 73 Fed. Reg. 6,034 (Feb. 1,2008) (Ohio partial approval), 74 Fed. Reg. 48,857 (Sept. 25, 2009) (Ohio full approval), 72 Fed. Reg. 59,480 (Oct. 27, 2007) (Indiana). Accordingly, all remain in place and effective in these states, and still apply to the Kyger Creek and Clifty Creek plants. As to the 2006 NAAQS establishing a 24-hour standard for fine particulates, both Ohio and Indiana submitted transport plans that are under review, and thus have not been found to be deficient by the Administrator. [EPA-HQ-OAR-2009-0491-4010[1].1, p.7]
The usurpation of State prerogatives as a result of the PTR will have shocking impacts to electric systems beginning in 2012. If EPA followed the rational option of retaining the CAIR benefits in place in 2012 and 2013, there would be ample time to follow the procedures required by the Clean Air Act and allow the states to revise their SIPs with appropriate SO2 and NOx emission reductions beyond the CAIR caps. Compliance with the Clean Air Act procedures also achieves efficiency in that the states are already engaged in SIP planning in response to the new ozone and PM2.5 NAAQS. The PTR is based on the 1997 and 2006 versions of the NAAQS. According to the PTR, EPA plans to revise both the ozone NAAQS (following reconsideration of 2008 revision) and the PM2.5 NAAQS in 2011. Delaying any compliance deadlines until 2014 allows EPA to consider the effect of the new NAAQS and allows the states to incorporate PTR reductions at the same time they are addressing the new NAAQS. Leaving CAIR in place until 2014 avoids burdening the states with multiple SIP planning exercises, and burdening electric generating unit owners with moving targets and inefficient resource allocations. [EPA-HQ-OAR-2009-0491-4010[1].1, p.7]
III. EPA's Artificially Expedited and Fragmented Rulemaking is Precluding Required Procedural Safeguards [EPA-HQ-OAR-2009-0491-4010[1].1, p.7]
Finally, EPA's continued issuances of NODAs and equivocation on when and whether state emissions budgets will change continue to prejudice the rulemaking process, and demonstrates that the original proposal was premature. The continued uncertainty as to the PTR's provisions, proposed state budgets, and allocation methodologies is robbing those most likely to be affected by the PTR of the opportunity to participate in the regulatory process. By not providing critical information until the last possible moment, EPA is destroying the open exchange of information and opportunity for the industry and public as a whole to meaningfully comment. [EPA-HQ-OAR-2009-0491-4010[1].1, pp.7-8]
We are now less than 11 months from the initial compliance deadline, and there are no final emission budgets, modeling, or revised unit characteristic assumptions. OVEC has nothing concrete on which to rely for compliance planning purposes, and is prejudiced by having to submit their comments on the PTR in pieces and parts as EPA issues continued NODAs. OVEC objects to EPA's piecemeal and limited opportunity to comment. [EPA-HQ-OAR-2009-0491-4010[1].1, p.8]
IV. Conclusion
In conclusion, CAIR is working, and a reasonable Transport Rule would similarly work to further minimize interstate transport of S02 and NOx emissions. But the proposed PTR start date of January 1, 2012 leaves insufficient time to install additional FGD or SCR controls, and for the states to revise their transport SIPs in accordance with the process required by the Clean Air Act. And absent a narrowly-crafted exception to the restriction on allowance trading between plants in adjacent states having the same designated representative and common control, the PTR will in effect dictate production curtailments and related economic disruptions, with no discernable additional benefits to downwind state air quality. [EPA-HQ-OAR-2009-0491-4010[1].1, p.8]
EPA's objectives in proposing the PTR are the same as when it instituted CAIR. CAIR is achieving those environmentally beneficial performance objectives while promoting economic growth, innovation, and preventing the job loss and other economic disruption that the PTR would create. EPA has made no real or reasonable calculation of the enormous cost and burden that the PTR will create, and even more significantly has not articulated or shown even the smallest additional benefit to be gained over the existing - and legally implemented - regulatory structure. [EPA-HQ-OAR-2009-0491-4010[1].1, p.8]
OVEC strongly encourages EPA to stop its piecemeal efforts to fully consider the direct and indirect costs and effects of its Proposed Transport Rule. Once that process is complete, the public should have a meaningful opportunity to comment on the entire proposed regulation before any changes are made to the existing regulatory approach. [EPA-HQ-OAR-2009-0491-4010[1].1, p.8]
Response: 
With regard to comparing the Transport Rule to CAIR, EPA notes that CAIR was remanded by the courts to be replaced by EPA with a rule that satisfies the statutory mandate of section 110(a)(2)(D).  As CAIR was found unlawful, EPA does not find a comparison of CAIR and the Transport Rule to be useful or relevant to the significant contribution analysis done for this rule.
The commenter suggests that EPA should administer the assurance provisions based on the geographic boundaries of a company's assets instead of on the geographic boundaries of the states.  However, the commenter offers no legal basis that EPA could use to disregard state boundaries in administering the assurance provisions, particularly with regard to the statutory language in CAA section 110(a)(2)(D) requiring the elimination of significant contribution to nonattainment and interference with maintenance in each upwind state.  The commenter's advocacy for "regional" regulatory treatment is also inconsistent with the commenter's demands that EPA defer the Transport Rule FIPs in favor of individual state SIPs, which would by definition apply separately to the commenter's units in each state.  Indeed, units on either side of state borders are already subject to distinct oversight and regulations from different states' utility commissions.  It is therefore not unreasonable or unprecedented in regulatory treatment of EGUs for EPA to administer the Transport Rule assurance provisions at the state level, notwithstanding the geographic proximity of facilities under common ownership in adjoining states.
Organization: Old Dominion Electric Cooperative
Comment: 
Old Dominion Electric Cooperative
As a not-for-profit utility, ODEC will be forced to pass along all costs of meeting any new requirements that may result from the Transport Rule to its Member Systems, and through them, to the member-consumers they serve. [EPA-HQ-OAR-2009-0491-4004[1].1, p.2]
EPA's hastened compliance timeline of 2012 again presents another problem with the CATR, that of the ability of a state to craft its own allowance policies to best suit its needs during the first two years of CATR implementation. [EPA-HQ-OAR-2009-0491-4004[1].1, p.2]
ODEC is disappointed, however, that the agency has not addressed the problematic timing of the CATR 2012 and 2014 compliance periods as ODEC and others have indentified in earlier comments to the August 2, 2010 CATR. EPA's failure to extend the CAIR beyond 2011 and its proposed imposition of the 2012 and the 2014 timelines continue to plague this rulemaking. Regarding the proposed SIP options, as EPA notes in the NODA III proposal, considering the time to submit and approved a SIP and record allowances, a SIP could not be applicable before the 2014 compliance period. As ODEC has noted in our earlier comments, there is no legal prohibition in the North Carolina decision against keeping CAIR in effect beyond 2011, and EPA's failure to do so would create yet another problem in so far as effectively prohibiting states from implementing SIPs addressing Clean Air Act Section 110(a)(2)(0)(i) deficiencies during the early stages of CATR implementation. [EPA-HQ-OAR-2009-0491-4004[1].1, pp.2-3]
Moreover, as OOEC has commented previously, the proposed compressed compliance timelines afford, at best, limited and, in most cases, no opportunity for units to alter their emission characteristics by 2012 even for those units that could cost-effectively reduce their emissions further. Additionally, a compressed timeline is in practice more detrimental to smaller utilities such as cooperatives due to the fact that a smaller generation fleet does not afford many cooperatives with the purchasing power that can compete with investor owned utilities to leverage swift acquisition and installation of control equipment. [EPA-HQ-OAR-2009-0491-4004[1].1, p.3]
Response: 
Thank you for your comment.Organization: Omaha Public Power District
Comment: 
Omaha Public Power District
In the way of background information, according to EPA's TR proposal, Nebraska is not a significant contributor to downwind ozone or to annual average fine particulate matter (PM2,s) concentrations, but only to 24-hour average PM2.5 concentrations [Federal Register, Aug. 2, 2010, page 45215]. OPPD previously provided comments to EPA on EPA's Proposed Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone ('Transport Rule'), 75 Fed. Reg. 45,210 (Aug. 2,2010), Docket ID No. EPA-HQ-OAR-2009-0491. In this previous comment submittal, OPPD questioned a number of the assumptions and data that went into the modeling used to determine whether Nebraska would be included in the Transport Rule and we believe that if some of these comments are accounted for, there is a good chance that Nebraska will not be included in the final Transport Rule. With this understanding, OPPD has the following comments on the information provided in the January 7, 2011 NODA. [EPA-HQ-OAR-2009-0491-3905[1].1, p.1]
In setting the S02 emissions budget, the actual emissions from the last quarter of 2008 and the first three quarters of 2009 were used as a basis. Four continuous quarters of operation is simply a snapshot of the actual operation of a utility boiler. This snapshot does not account for the variability in individual utility unit operation and utility operation throughout the state. This was recognized by EPA in their development of the Clean Air Interstate Rule (CAIR), where four years of operating data were used as a basis to establish state budgets and allowance allocations. The fact that a single four quarter period is inadequate to establish state budgets or unit allowance allocations was also recognized to some extent in the methodology used to establish the Transport Rule proposed NOx state budgets. On page 9 of the Technical Support Document for the Transport Rule titled 'State Budgets, Unit Allocations, and Emission Rates' it is indicated that in setting the NOx budgets and unit allowance allocations, reported annual and ozone season NOx emissions were adjusted to account for unusually low utilization in 2009. Therefore, EPA based NOx budgets and unit allowance allocations on 2008 heat input data, presumably because it was considered more representative of typical operations. However, the same data set that EPA deemed inappropriate for use in setting the NOx budgets and unit allowance allocations was used to set the S02 budgets and unit allowance allocations, with no apparent reason given for using this data that represents 'unusually low utilization'. [EPA-HQ-OAR-2009-0491-3905[1].1, p.2]
EPA needs to correct this deficiency in their rule development prior to finalizing the rule. It is not appropriate to indicate in the proposed rule documentation that Nebraska's state budget is based on no additional controls, while at the same time establishing state S02 and NOx budgets that are well below typical actual emissions. We suggest that EPA reevaluate state budgets to reflect actual emissions as intended by the proposed rule. A good approach would be to use the actual emissions in the five year data set provided in the January 7, 2011 NODA. [EPA-HQ-OAR-2009-0491-3905[1].1, p.2]
Further, when complying with the Transport Rule, it seems in general that it will be more difficult for units with already low emission levels to make cuts in emissions to meet the requirements of the Transport Rule as compared to more significant emission reductions available to units that have historically operated at higher emission levels. [EPA-HQ-OAR-2009-0491-3905[1].1, p.3]
Response: 
Regarding the inclusion of Nebraska under the final Transport Rule,  please see Preamble Section V.
Regarding the calculation of unit-level allocations, please see Preamble Section VII.D.
Organization: PowerSouth Energy Cooperative
Comment: 
PowerSouth Energy Cooperative
PowerSouth commented in October 2010 on the proposed "Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone," published in the Federal Register on August 2, 2010, at 75 Fed. Reg. 45210 ("Proposal").  In those comments PowerSouth stated that the Proposal, as written, fails to provide equitable treatment and the regulatory and economic certainty and flexibility that PowerSouth must have to meet our goal of providing reliable, affordable, low cost energy to our member owners.  Many of our comments addressed issues with the proposed allowance allocation methodology.   [EPA-HQ-OAR-2009-0491-3956[1].1, p.1]
PowerSouth re-states its recommendation that EPA abandon the allowance allocation methodology as detailed in the Proposal.  [EPA-HQ-OAR-2009-0491-3956[1].1, p.2]
1. The Proposal's allowance allocation methodology is unfair and punitive to PowerSouth and other utilities that made significant capital improvements to comply with CAIR and should be abandoned.  PowerSouth responded to CAIR by undertaking a multi-pollutant assessment, which included a myriad of control options, including the purchase of allowances.  PowerSouth's decision to retrofit the Lowman Plant in 2007 with an additional SO2 scrubber to allow 100% scrubbing of all three units and selective catalytic reduction (SCR) equipment for NOx emission reductions on two units in 2007 and 2008 at a cost of $300 million was based solely on compliance with CAIR and the economics of creating excess allowances to offset capital expenditures.  Allowance allocations to the Lowman Plant assigned in the Proposal  invalidate the rationale that led to the retrofits by only allocating enough allowances to meet compliance obligations at the manufacturer's guarantee level with no margin.  In fact, it will be very difficult to operate the control equipment continuously at the SO2 and NOx removal rates contemplated by the Proposal.  The cost of the capital project is not recoverable, PowerSouth has lost the opportunity to evaluate strategy based on true compliance options, and our flagship power plant is burdened with additional operational and cost constraints.   EPA should not now punish PowerSouth for investing capital to comply with CAIR.  [EPA-HQ-OAR-2009-0491-3956[1].1, p.2]
2. The Proposal as written penalizes early movers and encourages utilities to resist and delay investing capital in environmental improvements.  The drastic changes in the compliance "playing field" from CAIR to the Proposal teaches regulated entities to be recalcitrant and rewards utilities for not making capital investment to comply with EPA's rules.  The Proposal's allowance allocations and regulatory schemes incentivize regulated parties to resist capital improvements that benefit the environment and delay decisions as long as possible to see if regulatory conditions change.  Allowance allocations adopted in the final FIP should recognize and reward regulated entities that have retrofitted units in a good faith effort to comply with CAIR, or, at the very least, not punish them.  [EPA-HQ-OAR-2009-0491-3956[1].1, p.2]
3. Similarly situated facilities are disparately treated under the emissions-based allocation methodology in the Proposal.  A look at various coal-fired units and their relative compliance position for SO2 in the Proposal illustrates how taking no action is the best compliance option to environmental regulations.   Those units, who chose to "do nothing" under CAIR are in many cases in a much better position than utilities like PowerSouth who invested capital dollars in expensive control equipment.  For instance, coal-fired units in Mississippi within one hundred miles of our Alabama plant chose not to make any capital improvements in response to CAIR and now are entirely omitted from SO2 compliance requirements under the current Proposal.   Arbitrary state lines should not be the determining factor in setting compliance requirements.  [EPA-HQ-OAR-2009-0491-3956[1].1, p.2]
4. The Proposal's allowance methodology is unconscionable in that EPA rewards plants for being "dirty."   Units with no SO2 controls would be assigned allowances equivalent to their un-scrubbed emission rates in the Proposal.  In fact, some units in Alabama were assigned equivalent SO2 emission rates over 2.50 lb/MMBTU in the Proposal (for example, Alabama Power Company's Gorgas and Gaston units).  PowerSouth's Lowman Unit 1 flue gas can be directed through an uncontrolled by-pass yielding an emission rate of over 3 lb/MMBTU per hour.  In 2008-2009, the period EPA chose to use as the basis for allocations under the Proposal without our knowledge or input, PowerSouth was voluntarily directing flue gas from Unit 1 through a new scrubber for a portion of the period and therefore was assigned an equivalent SO2 emission rate of 0.478 lb/MMBTU.  Based on EPA's methodology, PowerSouth should not have built and operated the scrubbers or should have bypassed the scrubber on Unit 1.  PowerSouth emitting more would have resulted in a much more favorable compliance picture under the current Proposal.  PowerSouth is being penalized for voluntarily controlling its emissions.  It is unfathomable that utilities that responded proactively to EPA rules and installed and operated control equipment are disadvantaged and mistreated this way.  The Proposal's allocation methodology is not equitable, preferable, nor defensible.    [EPA-HQ-OAR-2009-0491-3956[1].1, p.3]
5. Using the equipment manufacturer's emissions removal rates without regard to ambient conditions, fuel parameters, and the plant's operating mode (startup, shutdown, load change, upset, etc.) is unrealistic.  Controlled emission rates assumed in IPM modeling and the resulting state budgets and unit-level allocations need to include realistic estimates for control device performance.  EPA's emission rate assumptions for units with existing FGD or SCR control are based on removal rates that are equivalent to continuous operation at manufacturer's guaranteed removal rates.  This tact is unfair and punitive as noted previously.  Further, it is unrealistic.  No pollution control device can be operated continuously to such low levels.  Such guarantees are typically established for specific operating conditions (such as steady state load conditions) or are specified for certain ambient conditions or specific fuel parameters.  In actual operating practice, units typically experience a range of load points, ambient conditions change dramatically from season to season, and coal sources change over time.  PowerSouth has been operating FGDs at Lowman since 1979 and knows from experience that this equipment will malfunction during the course of normal operation despite a utility's best efforts.  PowerSouth's recent experience with forced outages due to air heater plugging problems after installation of SCRs further illustrates that guarantee levels should not be used to model expected emissions or set allocations.  EPA should recognize that operating conditions on air quality control equipment will necessitate certain understandings about reasonable ranges of operation and adjust the Proposal accordingly.   [EPA-HQ-OAR-2009-0491-3956[1].1, p.3]
6. The data period used to develop the Proposal is too short to fairly represent each plant's range of operations and penalizes units for planned and unplanned outages that occurred during the extremely brief data period.  The Proposal uses only four strategically selected quarters of data to determine heat inputs and emission rates.  While this tact may have made it easier for EPA to design its regulatory remedy, it is inappropriate for such an important part of the Proposal.  EPA must use more data.  An alternative EPA has successfully used in the past is the highest three of five year methodology for heat inputs in the NOx SIP Call.   A larger data period more representative of plant operations is absolutely vital if the Proposal is enacted. [EPA-HQ-OAR-2009-0491-3956[1].1, pp.3-4]
7. The Proposal arbitrarily "cherry picks" data to allocate emissions.   There is no rational basis for assigning emission rates based solely on four quarters of data.  Further, the methodology used in the Proposal to determine which four quarters to use is not adequately explained and documented.  Adding or deleting a single quarter to the data set can change the resulting emission rate dramatically.  PowerSouth's review of the SO2 allocations to the Lowman Plant illustrates that the methodology used is arbitrary, unfair, and results in highly variable emission rates.  The Proposal as written indicates that for all three Lowman units, 3Q2009, 2Q2009, 1Q2009, and 4Q2008 should have been used.  Instead, EPA used what appears to be a "cherry picking" method, resulting in lower assigned SO2 allowance allocations.  For example, compare PowerSouth's equivalent SO2 emission rates from the EPA database.  In the Proposal, Unit 1 calculations are based on data from 1Q2009, 4Q2008, 3Q2008, and 2Q2008, passing over two more recent valid operating quarters.  Similarly, Lowman Unit 2 was assigned an equivalent SO2 emission rate in the Proposal based on data from 1Q2009, 4Q2008, 3Q2008, and 2Q2008, again passing over two quarters of more recent data.  The resulting equivalent emission rates are dramatically different as shown in the table below.  The method appears to have been applied, as written in the Proposal, to Unit 3.  Interestingly, if the same four quarters of data had been applied to Unit 3 as were applied to the other two Lowman units, the equivalent SO2 emission rate for Unit 3 would have been 0.321 lb/MMBTU! [EPA-HQ-OAR-2009-0491-3956[1].1, p.4] [[See Docket number EPA-HQ-OAR-2009-0491-3956[1].1, p.5 for table.]]
State regulatory participation is necessary for successful implementation of any CAIR replacement rule.  EPA has unfairly and unnecessarily usurped the State of Alabama's role in assigning unit allocations.  Alabama and other states have successfully administered state emissions budgets for the NOx State Implementation Plan (SIP) Call and the Clean Air Interstate Rule (CAIR) program and should be allowed to set and administer unit allocations based on the state budget.  EPA should relinquish control of program implementation back to the states.  PowerSouth supports including regulatory mechanisms and options to allow Alabama to take over the allowance allocation methodology in 2014. [EPA-HQ-OAR-2009-0491-3956[1].1, p.7]
Response: 
Thank you for your comment.Organization: PPG Industries, Inc.
Comment: 
PPG Industries, Inc.
PPG reiterates and incorporates herein by reference prior comments PPG made on the proposed CATR/FIP that were filed on October 1, 2010 and on the September 1, 2010 NODA on October 15, 2010. PPG specifically reiterates that Louisiana emission sources should not be subject to the proposed CATR/FIP because Louisiana emissions of S02 and NOx are not interfering with the attainment or maintenance of the annual or 24-hour PM2.S National Ambient Air Quality Standards ('NAAQS') in Texas and Louisiana emissions of NOx during the ozone season are not interfering with the attainment or maintenance of the 1997 8-hour ozone NAAQS in Texas. The justification for Louisiana's exclusion from the CATR/FIP is found in the prior comments of PPG and of the Louisiana Chemical Association in this docket. [EPA-HQ-OAR-2009-0491-3911[1].1, p.4]
Response: 
PPG's previously submitted comments have been responded to elsewhere in the RTC document.
Organization: PPL Corporation
Comment: 
PPL Corporation
Our initial major concern of was EPA's proposed, preferred approach for allocating allowances to individual generating units within each state. That approach assigns unit-specific allocations that are closely tied to unit-specific emission rates that EPA's Integrated Planning Model (IPM) forecasts are attainable in 2012 (nitrogen oxides and sulfur dioxide) and 2014 (sulfur dioxide in Group 1 states) at threshold control costs. This is an unfair approach because it allocates more allowances to units that have not invested in controls or that IPM projects will not attain emission rates as low as those of cleaner units. This is not only inequitable but also is inconsistent with a market-based approach that is intended to encourage dispatch of cleaner units by requiring dirtier units to purchase allowances to offset their higher emissions levels. [EPA-HQ-OAR-2009-0491-3935[1].1, p.3]
Additionally, allocating allowances based on future unit-specific emission rates modeled by IPM penalizes units whose future operation and emission rates are inaccurately characterized by a model that may form a basis for forecasting statewide conditions, but realistically cannot be expected to accurately characterize each unit individually. [EPA-HQ-OAR-2009-0491-3935[1].1, p.3]
PPL PA Generation requests U.S. EPA delay issuance of a final rule until they consider all comments on the original proposed rule and notices of data availability, correct all databases, remodel as necessary and issue a supplemental proposal for public comment and incorporate a timeline in the final rule that reflects the time needed to install any needed controls. [EPA-HQ-OAR-2009-0491-3935[1].1, p.5]
Response: 
Thank you for your comment.Organization: Prairie State Generating Company, LLC
Comment: 
Prairie State Generating Company, LLC
PSGC has one existing unit as defined in the proposed Transport Rule and one 'planned unit' as described in footnote 85 of the proposed Transport Rule at 75 Fed. Reg. 45309 (August 2, 2010), which are well under construction. Unit 1 is scheduled to commence commercial operation, as defined in the proposed Transport Rule in mid-July 2011 with Unit 2 following shortly thereafter in early 2012. Therefore, PSGC has a vital interest in the form of the final Transport Rule, as well as the details offered in subsequent Notices of Data Availability including this latest NODA issued on January 7, 2011. [EPA-HQ-OAR-2009-0491-3897[1].1, p.2]
PSGC appreciates the EPA considering, proposing, and allowing comment on alternative allocation methodologies and the additional topics related to allocation issues but is disappointed the underlying technical flaws in the air quality and modeling analysis are not acknowledged, let alone addressed. Since the analysis provides the basis for the statewide budgets, in failing to address the technical flaws, the proposed Transport Rule will continue to result in large and erroneous overestimation of emissions reductions necessary to eliminate significant contribution to downwind non-attainment of many states. PSGC and many others noted these serious concerns in earlier comments to EPA. PSGC offers the following comments on specific aspects of this NODA to aid EPA in its final decisions in this rulemaking. [EPA-HQ-OAR-2009-0491-3897[1].1, p.2]
Changing the allocation methodology on an individual unit basis does nothing to address the very legitimate concern that emissions reductions for existing units as a whole are proposed to be implemented too quickly to allow air pollution control equipment on existing units to be designed, permitted, procured, constructed and brought into full operation in accordance with model output, thereby precluding the development of a robust emissions trading market in which to purchase allowances. In a September 2, 2009 letter discussing the recommendations for the EPA to consider for the Clean Air Interstate Transport Rule ('CAIR') replacement rule, seventeen states in the eastern half of the U.S. recommended mechanisms to optimize existing NOx and S02 controls in 2014, low capital cost NOx controls in 2015, and emission caps which begin no later than 2017, a schedule which is much more conducive to allowing air pollution control equipment to be installed on existing units while addressing ambient air quality concerns. Slicing the same pie budget differently does not address the shortage of allowances in Illinois' new unit set aside ('NUSA') budget and it also does not remedy the problem with a state budget allotment which over estimates emissions reductions necessary to eliminate significant contribution to downwind nonattainment states.[EPA-HQ-OAR-2009-0491-3897[1].1, p.3]
EPA states they ' ... would hold back, for the new unit set aside for a state, 3 percent of the state budget. Three percent was established based on the total amount of new unit emissions projected for all the covered states. In this way, new units could be allocated some allowances for their emissions, which are part of the state's contribution to downwind nonattainment or interference with maintenance ... ' (75 Fed. Reg. 45310, 2nd column) (emphasis added). Allocating allowances to new units in this fashion creates an environmental regulation which forever discriminates against new units and assures the continued operation of older, less efficient plants. This proposed policy is antithetical to the objectives of the Clean Air Act by actually increasing the amount of emissions from power plants on a per kwh metric. New units have been constructed under strict New Source Review Program requirements which utilize best available technology (at a minimum) to protect downwind air quality and will be unfairly forever penalized by being forced to compete for allowances with other new units although the new units likely have lower emission profiles and are more efficient than existing units. New units should be allocated more than just 'some allowances'. They should be given the same proportional number of allowances as existing units, if not more, by virtue of the fact they are cleaner operating than existing ones. [EPA-HQ-OAR-2009-0491-3897[1].1, p.4]
The proposed Transport Rule continues to encourage discrimination against new units when allowances are not allowed to accumulate in the NUSA budget but instead are distributed back at the end of each control period to existing units which have been granted permanent allocations. Allowing NUSA pool allowances to accumulate at least offers some offset to this disservice to new units. [EPA-HQ-OAR-2009-0491-3897[1].1, p.4]
An even larger onerous concern for new units is that because the proposed Transport Rule has drastically underestimated the amount of time for air pollution control equipment to be designed, permitted, constructed and brought on-line for existing units to meet the model output, a robust emissions allowance trading market will not develop until several years after the rule goes into effect, thus precluding new units the opportunity to purchase the allowances needed to operate. If allowances cannot be purchased, then PSEC will be able to operate at only the capacity factor allowed by the number of allowances distributed from the NUSA, that is 33% - 38% under this NODA, a significantly lower operational level than the original 93% capacity factor which provided the basis for the business model for the facility. [EPA-HQ-OAR-2009-0491-3897[1].1, p.5]
States should be allowed to establish the allocation methodology most appropriate for their constituency, including determining the appropriate size of the NUSA budget to encourage new generation and to ensure new generation is accommodated sufficiently. Moreover, because ensuring that new, more efficient generation is allocated sufficient allowances is so important, states should be allowed to develop allocation methodologies and their state implementation plans ('SIPs') should be approved before the Transport Rule is applicable in those states. Recent air quality results demonstrate that the CAIR is addressing transported non-attainment concerns, and continuing that program until Transport Rule SIPs are approved will not negatively impact the environment. States are in the best position to know the new projects for which permits have been applied and which new projects are most likely to succeed. [EPA-HQ-OAR-2009-0491-3897[1].1, p.5]
Having said that, PSGC does not believe the variability limits established for Illinois have been set appropriately. The variability limits in Illinois do not accommodate known new generation units currently under construction or future potential new generation, and they do not appear to reflect the fact that Illinois has a significant amount of nuclear generation that provides base-loaded capacity for millions of users. When these base-loaded nuclear units are in outages for various reasons, that generation must be made up and, because Illinois is a net exporter of electricity, would likely be done so through increased fossil fueled generation. [EPA-HQ-OAR-2009-0491-3897[1].1, p.6]
Implementing the Transport Rule beginning in 2014, as recommended by the seventeen states in the eastern U.S.' September 2, 2009 letter, would allow the states sufficient time to develop SIPs and EP A to approve them. Furthermore, it would allow existing emission sources sufficient time to plan and optimize control measures. The Illinois EPA's September 30, 2010 comments on the proposed Transport Rule reiterates this recommended approach. Allowing states the time needed to develop their own SIP is consistent with the Clean Air Act requirements and the required SIP planning process while the current proposal usurps the role of the states to be afforded the first opportunity to develop a SIP which provides for attainment, maintenance and enforcement of the National Ambient Air Quality Standards. Allowing adequate time to develop, submit, and receive EPA approval of a SIP is not prohibited by and in no way undermines the court's decision in North Carolina v. EPA. [EPA-HQ-OAR-2009-0491-3897[1].1, pp.6-7]
PSGC supports the goals of the Clean Air Act but cannot support the proposed Transport Rule and its subsequent NODAs which create a long-term discriminatory environmental regulation against a new state of the art power plant which is highly-controlled and highly efficient by utilizing allowance allocation methodologies and assurance levels which do not put new units on a footing at least equal with, preferably more favorable than, existing plants. PSGC urges EP A to make changes to the proposed Transport Rule which affords new plants at least parity with existing ones, thereby encouraging the operation of new, more efficient generation.[EPA-HQ-OAR-2009-0491-3897[1].1, p.7]
Response: 
Thank you for your comment.Organization: Progress Energy Service Company
Comment: 
Progress Energy Service Company
As stated in our October 1, 2010 comments, many of Progress Energy's concerns regarding the Proposed Transport Rule could be resolved to a significant degree by eliminating the 2012 start year for Transport Rule compliance. Progress Energy believes that it is unreasonable and unrealistic to expect reductions - particularly the additional SO2 reductions in Group I states - Progress Energy required in the proposal by January 2012, a mere six months after the date on which EPA proposes to issue a final Transport Rule. EPA has not explained adequately why it proposes to require compliance beginning in 2012, particularly because the CAJR is currently in effect and will remain so until the Transport Rule or similar program replaces it at an appropriate time. [EPA-HQ-OAR-2009-0491-4011[1].1, pp.1-2]
According to EPA, the emission levels required in the 2012 phase generally reflect only the emission reductions that would occur even in the absence of the Transport Rule. However, in a number of cases EPA made incorrect assumptions regarding emission reductions that will occur at units by 2012. [EPA-HQ-OAR-2009-0491-4011[1].1, p.2]
Moreover, the Company believes that emissions reductions beyond those required by CAIR are not necessary. particularly in the early years of the Proposed Transport Rule program. EPA's data show that existing controls are working to reduce emissions -- emissions of S02 and Ox have declined steadily in recent years. The D.C. Circuit's opinion in North Carolina \I. EPA did not require that the overall levels of reductions required under the replacement rule for CAIR be greater than the levels under the CAIR, nor did the court include in its opinion a mandate that the replacement rule for CAIR must include a compliance date in 2012 or within any period of time as short as six months after final rule promulgation. [EPA-HQ-OAR-2009-0491-4011[1].1, p.2]
Progress Energy urges EPA to eliminate the 2012 compliance deadline in the Proposed Transport Rule and instead establish an initial compliance date no earlier than January 1, 2014. In the event that EPA promulgates a Transport Rule that includes requirement's more stringent than those in the CAJR, the initial compliance deadline should be later. Phase I of CAIR could remain in place and would continue to maintain emission reductions pending the initial compliance deadline for the Transport Rule. A later initial compliance date also would allow sufficient time for states to develop State Implementation Plans (SIPs) for implementation of the Transport Rule and therefore avoid the need for EPA to promulgate the rule as a Federal Implementation Program (FIP). The opportunity to replace federal requirements with a state plan at some point in the future does not satisfy the requirement that EPA allow the opportunity for states to craft their own plans, at the outset of the program, to comply with the Transport Rule. EPA's proposal would effectively bypass the states, at least with respect to the first phase of the program. Finally, a later start to the Transport Rule's more stringent emissions requirements would align this new program with the utility hazardous air pollutants (HAPs) maximum achievable control technology (MACT) program. Aligning these two major regulatory programs would also align compliance planning, emissions control system installation, and their associated costs. [EPA-HQ-OAR-2009-0491-4011[1].1, p.2]
Progress Energy reiterates the following specific concerns regarding the 2012 and 2014 compliance deadlines, as originally stated in our October I, 2010 comments. [EPA-HQ-OAR-2009-0491-4011[1].1, p.2]
2012 Deadline
EPA correctly recognizes that new FGD and SCR installations could not be added by January 2012 unless they are already under construction. However, EPA incorrectly claims that between final rule promulgation and January 1, 2012, utilities could install low-NOx burners and switch to burning lower sulfur coal. [EPA-HQ-OAR-2009-0491-4011[1].1, p.3]
2014 Deadline
EPA claims that additional FGD and SCR systems can be permitted, designed and installed between June 2011 (the date EPA plans to issue the final Transport Rule) and the end of2013 because, EPA claims, it takes about 27 months to design, permit, and build FGDs and about 21 months to design, permit. and build SCRs. Progress Energy believes that EPA has not adequately justified these assumptions. Progress Energy's experience in installing nine FGD system retrofits as well as nine SCR system retrofits is that the actual time to construct the equipment is in the range of time that EPA has assumed for the entire design, permitting, and construction process. However, the design and permitting parts of the process add approximately 18 months to the total time for installation, making EPA's estimates of 27 months for FGD installation and 21 months for SCR installation much too short. Progress Energy urges the EPA to make these assumed timeframes more realistic at approximately 44 months for FGD installation and 38 months for SCR installation. In addition, EPA should take into account the additional workload on state permitting authorities in order to process additional pollution control projects. This likely will extend the permitting portion of the project timelines and add to the total amount of time needed for project completion. [EPA-HQ-OAR-2009-0491-4011[1].1, p.3]
Again. this issue is in large part related to the unnecessarily fast implementation of the proposed Transport Rule. As noted earlier. if EPA allows the CAIR to continue through 2014. then the starting year of the more stringent Transport Rule would coincide with the implementation of the HAPs MACT, aligning these regulatory programs, the need for additional controls. and the expenditures for those controls. Progress Energy believes that this would be a much more common-sense approach to the implementation of the Transport Rule. Forcing significant additional reductions in emissions with only six months notice is unreasonable and unnecessary. [EPA-HQ-OAR-2009-0491-4011[1].1, p.4]
Response: 
EPA strongly disagrees with commenters' suggestions that the Transport Rule deadlines should be delayed.  Please see section VII.C.1 of the preamble for discussion of why EPA selected 2012 and 2014 as important compliance deadlines for the Transport Rule programs.  EPA's analysis in this final rule shows substantial benefits from implementing this rule by the 2012 and 2014 deadlines, which represent the costs to public health and welfare that Americans would incur without successful implementation of this rule; the cost of delay is therefore of considerable consequence to the public.  EPA cannot rely on keeping CAIR in place in the interim, since the Court specifically found these programs to be illegal and only allowed them to remain in place on the basis that EPA would act as quickly as possible to replace them with programs consistent with its statutory authority under the Clean Air Act.  
Organization: Public Power Generation Agency
Comment: 
Public Power Generation Agency
PPGA submitted extensive comments on the PTR on October 1, 2010. Docket ID No. EPA-HQ-OAR-2009-0491-2796 (Oct. 1, 2010) ("PTR Comments"). Pursuant to the original allowance allocation methodology in the PTR, WEC Unit 2 qualified as an "existing unit" because it "commenced commercial operation, or are planned to commence commercial operation, prior to January 1, 2012." Because under the PTR, WEC Unit 2 constitutes an existing unit, it should be allocated allowances as an existing unit under that proposal. The purposes of PPGA's October 1, 2010 PTR Comments were to demonstrate that WEC Unit 2 qualifies as an existing unit and thus is entitled to and should receive allowance allocations as an existing unit; to alert EPA to the fact that EPA's allowance allocation tables issued with the PTR erroneously omitted any allowance allocations for WEC Unit 2; and to propose a methodology for determining appropriate allowance allocations for WEC Unit 2. PPGA offered to meet with EPA to discuss appropriate allocations for WEC Unit 2 and to address any questions EPA may have regarding WEC Unit 2. Although EPA has not contacted PPGA, PPGA remains interested in such discussions with EPA on this matter. [EPA-HQ-OAR-2009-0491-3960[1].1, pp.1-2]
Under the PTR as originally proposed, as discussed above, WEC Unit 2 qualifies as an existing unit but was not given any proposed allowance allocation. To date, EPA has not admitted publicly that it made that error and thus far has failed to propose allocations of allowances to WEC Unit 2 prior to publication of the final rule  -  effectively depriving PPGA of any meaningful opportunity to comment on the PTR as it applies to WEC Unit 2. [EPA-HQ-OAR-2009-0491-3960[1].1, p.3]
On the one hand, under the allowance allocation methodology in the PTR, WEC Unit 2 should have received allowances based on the emissions the IPM model should have projected for the facility in 2012. EPA overlooked WEC Unit 2, however, and failed to account for or to predict the unit's share of Nebraska's projected 2012 emissions, which would serve as a basis for an allowance allocation for the unit. Because EPA has failed to contact PPGA regarding allowances or to update the proposed allowance allocation tables to correct for the numerous allocation errors brought to EPA's attention during the comment period, including the omission of proposed allocations for WEC Unit 2, PPGA simply has no way of knowing that EPA's IPM projection of emissions from WEC Unit 2 will be accurate or, at a minimum, fairly predict those emissions and that WEC Unit 2 will be allocated a reasonable number of allowances in the final rule. [EPA-HQ-OAR-2009-0491-3960[1].1, p.4]
Response: 
Thank you for your comment.Organization: Rochester Public Utilities (RPU)
Comment: 
Rochester Public Utilities (RPU)
We would also like to express our strong support for EPA to re-propose the rule giving affected entities the opportunity to comment on a re-analysis ofthe allocations prior to any final agency action. [EPA-HQ-OAR-2009-0491-3998[1].1, p.3]
Response: 
See section XX.F in this Response to Comments (RTC) document.
Organization: San Miguel Electric Cooperative, Inc.
Comment: 
San Miguel Electric Cooperative, Inc.
Being not-for-profit, San Miguel will be forced to pass along, to its consumer-owners, all costs of meeting any new requirements that may result from the implementation of CATR. [EPA-HQ-OAR-2009-0491-3997[1].1, p.1]
As a member-owned electricity supplier, San Miguel understands that reliable, affordable electricity has been one of the key drivers of economic growth and prosperity in this country. This fact must not be forgotten as the EPA makes decisions on whether and how to regulate electric generating unit emissions under this and future potential rulemakings. [EPA-HQ-OAR-2009-0491-3997[1].1, p.1]
San Miguel believes the agency should be attempting to solve the transport issue and not harm the economy. [EPA-HQ-OAR-2009-0491-3997[1].1, p.2]
The EPA originally proposed using historical emissions or future emissions based on the Integrated Planning Model (IPM) to allocate allowances. On September 1, 2010 EPA issued a NODA on the revised IPM version (4.10) to be used in the final transport rule. San Miguel commented on both the original Transport Rule and the September 1st NODA: [EPA-HQ-OAR-2009-0491-3997[1].1, p.2]
"the EPA should use historic data not model results to establish emissions allocations. Regardless of the sophistication of EPA's model, it does not and cannot accurately forecast how each and every fossil fuel unit among thousands will be utilized. Case in point is the numerous errors, outlined above, of the San Miguel generating unit." [EPA-HQ-OAR-2009-0491-3997[1].1, p.2]
San Miguel also commented:
"San Miguel believes most of the problems inherent in the proposal's methodology could be resolved if state budgeted allowances were distributed to each unit within the state based pro-rata on the unit's portion of the state historic heat rate updated periodically to include new units. Such distribution should sub-categorize between coal, gas, and oil." [EPA-HQ-OAR-2009-0491-3997[1].1, p.2]
Finally in the event that the EPA chooses one of the NODA allocation options, be aware that it would be impossible for coal fired units to make the necessary modifications to comply with the 2012 implementation date. [EPA-HQ-OAR-2009-0491-3997[1].1, p.4]
Slipping the implementation time of the Transport Rule could accomplish this. [EPA-HQ-OAR-2009-0491-3997[1].1, p.4]
Response: 
Thank you for your comment.Organization: Santee Cooper
PSEG Services Corporation
North Carolina Electric Membership Corporation
Midamerican Energy Holdings Company
Comment: 
Midamerican Energy Holdings Company
Compliance costs will be significant under the proposed Transport Rule and it is vitally important that the EPA's final rule provide for a fair and equitable distribution of allowances. Please note that these comments are only specific to issues raised in this NODA and do not abrogate any of the issues or positions raised in the previous comments on the Transport Rule submitted by MidAmerican to the regulatory docket on October 1, 2010. MidAmerican also requests that the EPA not perceive the absence of comments by MidAmerican as a conclusive indication of MidAmerican's implied consent or indifference with respect thereto.[EPA-HQ-OAR-2009-0491-3975[1].1, p. 2]
North Carolina Electric Membership Corporation
NCEMC feels that the methodology in the proposed Transport Rule inaccurately projected future emissions by failing to account for the variability of heat input and emissions, particularly with smaller peaking units which can vary greatly from year to year. Additionally, the allocations made in the proposed methodology were not reproducible by NCEMC, raising concern about the accuracy of these allocations to the Anson and Hamlet units. [EPA-HQ-OAR-2009-0491-4001[1].2, p.1]
PSEG Services Corporation
As stated in our October 1,2010 comments, PSEG Fossil supports the proposed Transport Rule. The proposed rule will achieve important air quality, health, and economic benefits utilizing EPA's current authority. It is critical that EPA implement the rule as expeditiously as practicable to ensure realization of these benefits. We are committed to working with EPA to ensure the Agency can implement the Transport Rule by January 1, 2012, and to that end, we offer these comments on the January 7th NODA. [EPA-HQ-OAR-2009-0491-3936[1].1, pp.1-2]
As we noted in our comments on the proposed rule, the language of the Clean Air Act provides EPA with broad authority to implement allocation methodologies, and there is no strong policy or legal reason that the methodology for determining state budgets and the methodology for distributing allowances to units need to be the same. By maintaining the proposed methodology for determining the state budgets, EPA is consistent with the D.C. Circuit's decision requiring that state budgets be based on each state's significant contribution. [EPA-HQ-OAR-2009-0491-3936[1].1, p.2]
As we explained in our comments on the proposed rule, the Integrated Planning Model (IPM) used to project emissions under the proposed allocation approach does not consider a range of non-economic factors that may influence a company's decision to operate particular types of units or for the respective Independent System Operator (ISO) to call upon specific units. As a result, the modeling can create unrealistic scenarios for some individual units, such as ignoring dispatch requirements of EGUs subject to power purchase agreements, running natural gas combined cycle units at higher utilization than can be accommodated by the local natural gas pipeline network and not running oil-fired units that are required to operate to meet load requirements. While these distortions of the electricity market are masked when data are aggregated at the state level for setting state budgets, the modeling results in unrealistic or infeasible outcomes when used at the unit level to allocate allowances. [EPA-HQ-OAR-2009-0491-3936[1].1, p.2]
Santee Cooper
In general, we are pleased to see that EPA has acknowledged concerns raised by Santee Cooper and other commenters in connection with the allocation provisions of the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3913[1].1, p.2]
In the NODA, EPA correctly recognizes that - as argued by Santee Cooper and others in comments on the proposed Transport Rule - the agency enjoys considerable discretion in crafting an allowance allocation methodology under all four Transport Rule trading programs. EPA also correctly points out that its choice of allocation methodology does not affect the overall environmental integrity of the Transport Rule, or the ability of any particular state to eliminate its contributions to nonattainment problems as called for in section 110(a)(2)(D)(i)(I) of the Clean Air Act. Santee Cooper appreciates EPA's acknowledgment of flexibility in this area, and the agency's willingness to consider alternatives to the proposed Transport Rule approach. [EPA-HQ-OAR-2009-0491-3913[1].1, p.2]
As documented in extensive detail in Santee Cooper's comments on the proposed Transport Rule, that approach-which is based on a combination of historic emissions data and unreliable projections of future emissions-would perversely withhold allowances from those utilities who have made the greatest strides toward reducing S02 and NOx emissions in the years preceding the Transport Rule. Because the proposed Transport Rule would allocate allowances to EGU s in part on the basis of historic emissions in 2009, less emissions-intensive utilities such as Santee Cooper-which made significant investments to reduce its emissions of S02 by 80% during 2005 and 2009- would receive lower allocations and face higher compliance costs than more emissions-intensive utilities under the proposed Transport Rule. As a result of this formula, other South Carolina utilities would receive as much as 8.6 times more S02 allowances per unit of generating capacity, and 2.8 times more NOx allowances, than Santee Cooper in 2012. EPA's proposal to use 2012 projected base case emissions as the basis for allowance allocations (where those projected emissions are lower than 2009 emissions) would also have similar effects, in that utilities that are projected to invest the least in pollution control over the next two years would gain the most benefit through allowance allocations. [EPA-HQ-OAR-2009-0491-3913[1].1, pp.2-3]
Response: 
As discussed in preamble section VII.D of the final Transport Rule, EPA decided not to finalize the emissions-based allocation method that was presented in the original Transport Rule proposal.  EPA decided to finalize a historic heat-input based method instead, as detailed in preamble section VII.D.
Organization: Seminole Electric Cooperative Inc.
Comment: 
Seminole Electric Cooperative Inc.
Seminole is very concerned about the impact of EPA's proposed Rule on its ability to continue to reliably and efficiently meet its statutory obligation to provide an essential public service. Accordingly, Seminole has provided to EPA comments regarding the proposed Rule on October 1, 2010, October 15, 2010 (October NODA), and November 24, 2010 (November NODA). [EPA-HQ-OAR-2009-0491-3992[1].1, p.1]
The original allowance allocation proposal would rely on the IPM modeling platform, which, as many commentators have noted, contains undecipherable and apparently erroneous assumptions, in addition to material factual errors. Seminole identified many such errors in its comments submitted on October 1 and 15, 2010. [EPA-HQ-OAR-2009-0491-3992[1].1, p.2]
EPA's original proposal to use 2008 and 2009 as baseline years for NOx and S02 emissions, respectively, would not represent normal operating conditions for many of the units regulated under the Transport Rule. Additionally, EPA has never adequately explained its proposed use of different baseline years for the two pollutants. [EPA-HQ-OAR-2009-0491-3992[1].1, p.2]
Unfortunately, however, as it appears EPA is intent on maintaining the 2012 start date, none of EPA's proposed allocation plans provide a step-wise transition to ultimate allowances. As many commentators have noted, the Proposed Rule provides many electric generating units insufficient time to install controls or implement operational changes necessary to reduce emissions from historical levels to proposed allowances. [EPA-HQ-OAR-2009-0491-3992[1].1, p.2]
Seminole is obliged to reiterate previous comments that the Rule need not be in place by 2012, and that the Clean Air Act does not grant EPA authority to promulgate a FIP without first providing states adequate time and opportunity to develop and submit SIPs. States are better suited to develop fair and consistent allocations that take into consideration unique aspects of electric generating units in the state. Nonetheless, EPA recognizes in the January NODA that there will be insufficient time for states to develop SIPs with allowance allocation provisions, and for EPA to review and approve such SIPs, before EPA will record allocations to existing units for 2012 and 2013. Thus, the first year for which state allocations could be used is 2014. [EPA-HQ-OAR-2009-0491-3992[1].1, pp.2-3]
While the January NODA presents alternative allocation methodologies that are more appropriate than EPA's originally proposed allocations based on model-predicted emissions, it does not address EPA's use of the same flawed IPM model that establishes each state's significant contribution and interference with maintenance and each state's emissions budget. EPA has provided no evidence that it has corrected the numerous fundamental errors in the IPM model. The January NODA states that EPA is still in the process of updating its emission inventories and modeling and that state contributions and unit allocations could change; therefore, publication of another proposed Rule is warranted. [EPA-HQ-OAR-2009-0491-3992[1].1, p.3]
EPA's piecemeal approach in its development of the Transport Rule deprives affected parties adequate opportunity to effectively participate in the rulemaking process and, therefore, is legally deficient. EPA must allow for stakeholder involvement as it develops and publishes a second proposal addressing all of the comments. The second proposed Rule, along with all information used to develop the proposal, should be provided at the same time so that affected parties can understand the impacts of the proposed Rule and participate meaningfully in the rulemaking process. [EPA-HQ-OAR-2009-0491-3992[1].1, p.3]
Response: 
Thank you for your comment.Organization: Southern Company
Comment: 
Southern Company
In the NODA3, EPA requests comment on two new allocation methodologies, an abbreviated State Implementation (SIP) process, as well as issues regarding the assurance provisions in the proposed Transport Rule. However, with the NODA3, EPA has for the third time declined to illustrate how the new information will impact the final Transport Rule. As Southern Company expressed in our comments on the proposed Transport Rule, the first Notice of Data Availability (NODA 1), and the second Notice of Data Availability (NODA2) it is extremely difficult to provide meaningful comments on new information without understanding how it will impact the final Transport Rule. EPA continues to ask stakeholders to comment on various changes to the proposed Transport Rule in isolation. It is imperative that EPA not piecemeal the public comment process and that the public be afforded the opportunity to comment on a single comprehensive, comprehendible regulatory proposal. Therefore, EPA must issue a supplemental proposed rule, one that incorporates all the 'corrected' updated data and reapplies a 'corrected' methodology, with an adequate time for public comment. A more thorough explanation and additional concerns with the NODA3 are identified in the attached document. [EPA-HQ-OAR-2009-0491-3946[1].1, pp.1-2]
As explained in Southern Company's comments on the proposed Transport Rule, the first Notice of Data Availability (NODA1), and the second Notice of Data Availability (NODA2), it is extremely difficult to comment on a "moving" target. The NODA3 represents the third time since EPA proposed the Transport Rule in August 2010, that EPA has issued new data or ideas without illustrating how it will impact the final rule. By the date of EPA's third Notice of Data Availability, EPA has proposed: (i) three different remedies; (ii) two different IPM versions; (iii) three different fuel cost assumptions; (iv) revised emissions inventories; and now (v) three different unit level allocation methods. EPA has essentially asked for comment on numerous isolated ideas and sets of data -- not a comprehensive and comprehendible remedy under Section 110(a)(2)(D). Not only does EPA's patch-work approach make it difficult to comment, but it also makes it impossible to plan for compliance. EPA proposes the Transport Rule compliance period will begin in January 2012, a mere six months after the anticipated issuance of the final rule. With only ten months to go before the proposed rule compliance date, utilities do not know which state is "in" for each program, the state budgets, or the individual unit-level allocations. This type of regulatory development process along with the compressed compliance timeline is simply unworkable for affected sources. [EPA-HQ-OAR-2009-0491-3946[1].1, p.6]
Given the magnitude of errors and flawed methodologies identified in Southern Company's previous comments and the magnitude of regulatory uncertainty that still remains, EPA must take the necessary time to:
:: correct the errors (in data and assumptions);
:: re-run all the models (IPM, CAMx, OSAT, PSAT, AQAT);
:: adjust its methodology applied in the significant contribution analysis (as suggested in previous Southern Company comments);
:: apply the revised methodology with the corrected data, assumptions, and model outputs;
:: update the proposed budgets and allocations; and
:: issue a supplemental proposed rule -- with all supporting data, files, and models --  allowing adequate time for public review and comment.[EPA-HQ-OAR-2009-0491-3946[1].1, p.6]
First, as addressed in detail in Southern Company's comments on EPA's proposed Transport Rule, the original proposed Transport Rule allocation methodology is very complicated and difficult to replicate.2 The proposed Transport Rule allocations were based on either adjusted historical emissions or on adjusted projected emissions. EPA should not rely on projected emissions as a basis for unit allocations. Regional energy planning models (such as the IPM) are ill-suited for accurately projecting individual unit emissions, and using such a model to dole out valuable emission allowances is arbitrary. Allocations should be based on actual emissions. Consistent with past practice (e.g, in the Acid Rain Program, NOx Budget Program, and CAIR), EPA should use a representative range of historical data rather than a single year to determine a unit's proportionate share of emissions. [EPA-HQ-OAR-2009-0491-3946[1].1, p.8]
Finally, EPA's unreasonable compliance deadlines leave inadequate time for sources to implement compliance plans, much less install new emission controls to meet the requirements. As noted in Southern Company's comments on the proposed Transport Rule, installing flue gas desulfurization (FGD) and selective catalytic reduction (SCR) cannot be accomplished by 2014, much less 2012.3 Therefore, installing new emission controls to limit emissions is not a compliance option at the outset of this program. The compliance difficulties are exacerbated considering EPA is proposing to render existing CAIR allowance banks unusable for compliance with the Transport Rule. Presuming that trading will ultimately be allowed in the Transport Rule, early markets will be very limited, shallow, volatile, unreliable, and cannot presently be economically analyzed as a compliance alternative. With compliance options so limited, it is imperative that initial Transport Rule allowance allocations go to units based on need. Further, one EPA FIP allocation methodology cannot possibly address the myriad of unit needs as efficiently and fairly as states can individually for their affected sources. [EPA-HQ-OAR-2009-0491-3946[1].1, p.9]

 2 Southern Company spent countless hours trying to replicate EPA's methodology and was unsuccessful for many units.
3 Southern Company's experience has shown that it takes an average of 54 months to install a single FGD and an average of 36 months to install a single SCR.
Response: 
Thank you for your comment. 
Organization: Southern IL Power Cooperative
Comment: 
Southern IL Power Cooperative
Eighty percent of the electric power generating plants owned by cooperatives, approximately 24,000 MWs, is coal-fired generation.  Southern IL Power Cooperative believes that fossil-fuel fired electric generating facilities would be significantly and negatively affected by the decisions EPA proposed in this (CATR) rule. Being not-for-profit, cooperatives will be forced to pass along all costs of meeting these new requirements to their consumer-owners.  Increased costs of electric energy, particularly in rural areas served by cooperatives, has negative impacts on economic development and jobs.  Because cooperatives have a disproportionate amount of coal-based generation when compared to the electric utility industry as a whole, these negative impacts could be disproportionately higher for cooperatives and their consumer-owners.  As a consumer-owned electricity supplier, Southern IL Power Cooperative understands that reliable, affordable electricity has been one of the key drivers of economic growth and prosperity in this country. In cases where small businesses like SIPC are affected, EPA is obliged to pursue the least costly approach in order to mitigate impacts on facilities that can least afford them.  That fact must not be forgotten as the agency makes decisions on future emission reductions to be required of small businesses like Southern Illinois Power Cooperative.  [EPA-HQ-OAR-2009-0491-3901[1].1, p.1]
Southern Illinois Power Cooperative feels the deadlines and percentage of emission reductions are too stringent, and are unnecessary to meet National Ambient Air Quality Standards.  Requiring coal-fired power plants to construct additional pollution control equipment and have it operational by 2012 to 2014 is not feasible.  Just manufacturing lead times for much of this equipment would be eight to twelve months within a normal business time, but for such a volume of equipment that would be required to meet the demands of the proposed rule, lead times would certainly be extended.  Similarly, sufficient quantities of skilled labor to install such equipment would be difficult to obtain and still meet the 2012 to 2014 deadlines.  CAIR need not be replaced by 2012.  There are no legal mandates to replace CAIR by a date certain, thus making the proposed 2012 CATR deadline unnecessary.  [EPA-HQ-OAR-2009-0491-3901[1].1, p.2]
However, SIPC is disappointed that timelines EPA has proposed for CATR implementation, beginning in 2012, do not allow adequate time for states to submit and obtain SIP approvals that incorporate allowance allocation methodologies better suited to meet state or local concerns as compared to the chosen methodology in the generic FIP.   EPA's "hurry up" compliance timeline of 2012, as described in the previous paragraph, presents another problem with the CATR; the ability of a state to craft its own allowance policies to best suit its needs during the first two years of CATR implementation.  There is no legal prohibition in the North Carolina decision against keeping CAIR in effect beyond 2011, and EPA's failure to do so would create yet another problem in so far as effectively prohibiting states from developing and implementing SIPs addressing Clean Air Act Section 110(a)(2)(D)(i) deficiencies during the early stages of CATR implementation.  [EPA-HQ-OAR-2009-0491-3901[1].1,p.2] 
In the initially proposed CATR EPA stated that is has broad discretion in distributing allowances, mindful that a distribution methodology cannot determine states' budgets in an effort to meet Clean Air Act Section 110 objectives to address interstate air pollution. To this end EPA indicated that allowances could be distributed based on identified groups of units having similar emissions characteristics.  For example, EPA went on to suggest the possibility of grouping units by size, fuel type and age.  SIPC agrees with EPA that it has the discretion to develop a sensible allocation methodology to reflect unit fuel and combustion design.  [EPA-HQ-OAR-2009-0491-3901[1].1, p.5]
As it appears that EPA ASSUMES that all coal-fired plants will switch to low sulfur coal AND be able to scrub at a 95% scrubbing efficiency.  Both ASSUMPTIONS are impractical.  Essentially, this rule would favor PRB (Powder River Basin) coal, which is not, and would not, be available in sufficient quantities (or transportation) for all the plants affected.  In addition, such a switch to PRB coal should include the additional transportation emissions required to deliver such coal to the states affected by this rule, PLUS the added mercury emission loading that would result from the increased utilization of such fuel. Further, FGD designs currently in use may not have the capability to scrub such fuel at the 95% control level.  Finally, again, there is no way such fuel switching & FGD construction could occur by 2012 or even 2014!! It is SIPC's opinion that the proposed "Clean Air Transport Rule" has underlying technical flaws in the air quality and modeling analysis, which provides the basis for the statewide budgets. Thus, the proposed APTR results in large and erroneous overestimation of emissions reductions necessary to eliminate significant contribution to downwind, non-attainment states. [EPA-HQ-OAR-2009-0491-3901[1].1, pp.5-6]
Southern Illinois Power Cooperative is of the opinion that the proposed rule is deeply flawed, and that, at its core, this rule is rooted in a political agenda that opposes the use of fossil fuels (especially coal) to generate power.  [EPA-HQ-OAR-2009-0491-3901[1].1, p.6] 
Much of what is presented in this NODA simply discusses different methodologies for allocating allowances to existing units (i.e. slicing and dicing the same pie differently). It doesn't address unnecessary emission reductions or the problems with allowance shortages, particularly with regards to the NUSA pool allowance shortage in Illinois. [EPA-HQ-OAR-2009-0491-3901[1].1, p.6]
Response: 
See section VII.D of the preamble for a description of EPA's final approach for determining new unit set-asides.  EPA has revised its approach from proposal to address concerns such as those outlined above that stemmed from the reclassification of some units from "existing unit" status to "new unit" status when moving from proposal to final rule.  The final rule entails state-specific set-asides that are tailored to accommodate the projected emissions of planned and potential new units (online after January 1, 2010) in each state.  The result is a greater percentage of the state budget set-aside for new units than would have otherwise occurred under the proposed method for calculating new source-set aside budgets.  For example, for annual NOx Illinois now has 8%, as opposed to the proposed 3%, of its budget set aside for new units. 
Organization: State of Ohio Environmental Protection Agency (Ohio EPA)
Comment: 
State of Ohio Environmental Protection Agency (Ohio EPA)
As expressed in Ohio's October 1, 2010 comments, Ohio feels it will be quite challenging if not impossible for a number of Ohio sources to install advanced control technologies by 2014, let alone 2012. Ohio doubts these sources could even meet these restrictive allocations by burning a low-sulfur coal. Because it is virtually impossible to install advanced S02 controls by 2012, these owners only available means of making up for the shortfall will be to purchase excess allocations from controlled units with excess allocations. . This allocation method is forcing an S02 allowance trading market in 2012 as the only method of compliance for many sources as installation of controls will not be an option. [EPA-HQ-OAR-2009-0491-3915[1].1, p.4]
Concerns with respect to this forced trading compliance method are further exacerbated due to the even tighter budgets on S02 emissions in 2014. As expressed in our October 1,2010 comments, Ohio EPA is very concerned that the insufficient allocations of S02, the restrictive variability limits, and limited trading scheme for Group 1 S02 States, in conjunction with the issues and questions raised in our previous comments regarding the new unit set aside, will inhibit trading. Due to the nature of the proposed program design, U.S.EPA cannot assume that wide-spread trading will occur to 'make up' for the shortfall in allocations for certain units. With such insufficient allocations, if any allocations are left at the end of the year sources will likely bank for future years rather than trade due to the significant repercussions that occur when assurance provisions are triggered. [EPA-HQ-OAR-2009-0491-3915[1].1, p.4]
Ohio EPA wishes to reiterate its October 1, 2010 comments again. Ohio EPA is very concerned that there are insufficient allocations of S02, especially given the selection of 2012 and 2014 compliance deadlines. Ohio continues to believe it will be challenging if not impossible to install controls by 2014. Installing controls by 2012 is not plausible. Many sources, as a result of consent decrees between U.S. EPA and the utilities, are required to reduce emissions in the future. Yet U.S. EPA has not made any attempt to align compliance dates that necessitate installation of controls with the consent decrees that they designed. For example, the Muskingum River units are required by their consent decree to retire, repower or retrofit before the 2016 control period while Gorsuch units are required by their consent decree to retire, repower or retrofit before the 2013 control period. Why would U.S. EPA not better align consent decree compliance dates with the compliance dates of the Transport Rule. Furthermore, U.S. EPA did not set unobtainable installation dates for control requirements as a part of the consent decrees, but this is exactly what has been done with the Transport Rule. And as noted before, Ohio has serious concerns that these tight State budgets will inhibit trading of allocations under this program. Given the serious consequences that will face sources not meeting their allocated budgets, it is imperative that U.S.EPA provide a workable approach within the Transport Rule and provide sufficient time for compliance. [EPA-HQ-OAR-2009-0491-3915[1].1 ,p.5]
Response: 
Thank you for your comment.Organization: State of Wisconsin, Department of Natural Resources
Comment: 
State of Wisconsin, Department of Natural Resources
I am pleased that EPA is evaluating additional mechanisms for allocating emission allowances and is proposing options for the submittal of a State Implementation Plan. However, the Department believes the rule as proposed will cause significant, potentially burdensome, emission reductions for some Wisconsin utilities as soon as 2012. [EPA-HQ-OAR-2009-0491-3968[1].1, p.1]
As a result, the Department believes EPA needs to further evaluate the compliance timeframes, especially when considering limited trading, and begin phasing in emission reductions no sooner than 2014. Additional compliance flexibility should also be incorporated in the final rule.[EPA-HQ-OAR-2009-0491-3968[1].1, p.1]
State Implementation Plan  --  Despite EPA's best efforts, states impacted by the Clean Air Transport Rule will still be subject to a default Federal Implementation Plan for a period of years. States must be afforded a clear opportunity to implement a state plan which may be the best means for avoiding undue cost and burden to both the regulatory agencies and affected sources. [EPA-HQ-OAR-2009-0491-3968[1].1, p.1]
The Department believes a finalized Transport Rule is necessary for enabling states to be able to make viable maintenance and attainment demonstrations for the 1997 ozone (0 3) and 2006 fine particulate (PM 2.5) air quality standards by 2014. However, it is also critical for the Transport Rule to support sustainability of the affected electric utilities and avoid undue cost to their customers. Therefore, we strongly support EPA's continued effort in addressing the issues under this NODA. We believe our comments will aid EPA in finalizing a Transport Rule that provides reasonable flexibilities for the affected sources while achieving necessary emission reductions. To that end we ask EPA to consider the following summarized points and to consider the attached comparison of Wisconsin utility emissions and allocations resulting from EPA's proposed allocation approaches. [EPA-HQ-OAR-2009-0491-3969[1].1, p.1]
The Department supports delaying Transport Rule emission compliance requirements until 2014 with the Clean Air Interstate Rule (CAIR) requirements remaining in place through 2013. Under this schedule, we recommend allowing affected sources access to an auxiliary 'compliance pool' for at least the revised initial 2014 and 2015 Transport Rule compliance years. The intent of the Transport Rule and its legal basis is to address the transport of pollutants and significant contribution affecting attainment and maintenance by 2014. This is supported by the court mandate to replace CAIR in an expeditious manner while leaving the initial phase of CAW in place. In previous dialogues with EPA, we have supported and relayed that 2014 is an expeditious date for the installation of controls beyond CAIR. In addition, an initial 2014 compliance date is consistent with EPA's goal under the rule to only capture existing emission controls for 2012 (CAIR) while implementing the necessary reductions related to significant contribution in 2014. [EPA-HQ-OAR-2009-0491-3969[1].1, p.1]
We understand that one of EPA's original needs for starting the Transport Rule by 2012 is to allow some utilities time to accumulate banked allowances for use in 2014 and after. This issue can simply be addressed by structuring a compliance pool for 2014 and 2015 and allowing access by sources demonstrating need. This approach both satisfies real compliance issues while minimizing any excess emissions - due to the use of banked allowances instead of real reductions - which could prolong nonattainment impacts. EPA took a similar approach for the initial CAIR NO„ compliance requirement. [EPA-HQ-OAR-2009-0491-3969[1].1, p.1]
Keeping CAIR in place through 2013 will also allow utilities to continue using existing CAIR allowances while controls are being installed for the 2014 Transport Rule compliance requirement. The CAIR level of control will be maintained as intended for the 2012 Transport Rule budgets. The Department sees an initial compliance date for the Transport Rule in 2014 as the smoothest available means for transitioning from CAIR to the Transport Rule. [EPA-HQ-OAR-2009-0491-3969[1].1, pp.1-2]
The Department also suggests new sources be treated in the following manner. [EPA-HQ-OAR-2009-0491-3969[1].1, p.3]
1. New sources should be considered as those units with less than three years of operating data. Therefore, for the first allocation block (if updating) new sources are those beginning operation in 2008. This also assumes EPA update the historic baseline to 2010 data.
2. New sources should be allowed to access allowances equal to their emission limitations applied to full capacity utilization. In this way, the new emission units are not penalized for having the best controls. If operating below its emission limitations the emission unit can have the opportunity to generate a small amount of excess allowances. In addition, these very efficient clean units can be expected to have full dispatch and therefore should not be restricted in capacity. Conversely, if these units are provided allowances based on heat input, they will receive allowances substantially higher than actual emissions and likely higher than even the unit's maximum potential emissions. On this basis large new well-controlled generation units can shift a significant number of allowances with no actual benefit to the environment.
3. The new sources should be periodically rolled into an updated historic operating baseline as discussed below. [EPA-HQ-OAR-2009-0491-3969[1].1, p.3]
The Department believes the Federal Implementation Plan (FIP) should provide several default allocation methods which the states can rapidly incorporate into their implementation plan. Our understanding is that the FIP will contain each generation unit's allocation of SO2 and NOx allowances determined according to a finalized allocation method. We believe that EPA can also provide actual methods and calculations within the Transport Rule which can be adopted as part of a State Implementation Plan (SIP) for rapid approval by EPA. This approach addresses a number of important issues. First, each state can quality assure named facilities and determine best data to use in calculating the actual allowance for each unit. The states are able to re-calculate and update allocations over time that address new source distributions, existing source shutdowns, and periodic five year updates. Second, this approach allows EPA to provide several allocation methods or options in addition to the default allocation approach. With multiple available options the states can work with affected sources and stakeholders to determine the most equitable allocation method meeting air quality needs. These alternative approaches can allow additional options to periodic updates or even approaches for incorporating generation efficiency, such as heat rate based calculations. Third and perhaps most importantly, providing default alternative methods and calculations will allow the states to adopt rules and gain EPA approval on an accelerated schedule. [EPA-HQ-OAR-2009-0491-3969[1].1, p.3]
For all allocation approaches, whether IPM projected or historic based, a default mechanism should be incorporated into the method that periodically updates the allocation of allowances for all sources, preferably on a five year basis (fixed or rolling blocks). None of the allocation methods currently proposed by EPA appear to substantially change the initial distribution of existing source allocations into the future. Because EPA intends to propose a Transport Rule update in response to new air quality standards there will be a related update to allocations in the relatively near term. However, in absence of new standards and in order for the Transport Rule to act as a complete template, an updating mechanism needs to be part of any allocation method. This approach aligns the distribution of allowances into the future with the generation sources that are actually meeting electricity demand. In working with our state utilities, the Department has found a five year period to be consistent with electric generation planning and the installation of pollution control equipment. We recommend that the allocations be updated on a five year basis with the initial allocation set at least three years into future. The updating mechanism could allow or provide either fixed or rolling average five year periods. The rolling approach can serve to smooth differences between allocation blocks. [EPA-HQ-OAR-2009-0491-3969[1].1, p.3]
The Department strongly believes that where feasible, EPA should avoid implementing a federal requirement such as the Transport Rule on a schedule which precludes implementation of a state plan for the initial compliance requirements of the rule. In the NODA, EPA estimates that a SIP addressing the Transport Rule allocation of allowances could not be in place before 2014. With an initial 2012 compliance year, there is at least a two year window under which sources will be subject to FIP allocations. In this case there is no opportunity for the state to address inequities in allocations that could yield compliance issues and undue cost. Further, EPA's methods do not account for other state processes affecting the utilities. For example, the Wisconsin Public Service Commission (PSC) currently is evaluating whether certain generation sources operated by Wisconsin utilities should be curtailed or permanently shut-down. In another case, a utility has requested authority to install sulfur scrubbing equipment on it's largest coal fired units. But that work is being challenged by interested parties and has been awaiting PSC approval for over two years. To address both potential allocation issues and state specific factors the most effective means for implementing the Transport Rule is through the SIP. To support a SIP approach we believe EPA should utilize both their ability to delay initial compliance requirements until 2014 and also provide default FIP allocation methods that can be rapidly approved and incorporated into the State Implementation Plans. [EPA-HQ-OAR-2009-0491-3969[1].1, p.4]
Response: 
Thank you for your comment.Organization: Sunbury Generation LP
Comment: 
Sunbury Generation LP
Sunbury previously submitted comments on the Proposed Transport Rule. Sunbury's comments on the Proposed Transport Rule addressed several points. Notably. Sunbury objected to EPA's consideration of emission reductions achievable through the installation of a proposed wet flue gas desulfurization scrubber (the 'Proposed Scrubber') at the Facility for purposes of determining the proposed S02 allowance allocation for the Facility's EGUs. Specifically, Sunbury objected to EPA's downward adjustment of the Facility's proposed S02 allocation on the basis that Sunbury had previously taken certain steps to secure authorization to install the Proposed Scrubber, notwithstanding that Sunbury has not yet moved forward to any significant extent with the construction of the Proposed Scrubber, and there is currently no legal basis requiring installation of the control unit. Sunbury also commented that EPA's proposed methodology for determining unit-specific allowance allocations under the Proposed Transport Rule is inappropriate and inequitable as applied to Sunbury, because such method is based on EPA's predictions of future anticipated generating rates. Relative to Sunbury, EPA apparently predicted a decline in operating rates in future years as compared to current levels and, on this basis, proposed under the Proposed Transport Rule to allocate unit-specific allowances to Sunbury at a substantially reduced rate. [EPA-HQ-OAR-2009-0491-3920[1].1, p.1]
Sunbury recognizes that EPA has identified. through the Second NODA, an alternative allocation methodology for potential use in the Transport Rule. Sunbury will address issues associated with the proposed allocations identified in the Second NODA below. To the extent, however, that EPA determines to propose final allocations under the Transport Rule in a manner consistent with the approach originally identified in the Proposed Transport Rule, then Sunbury reasserts its prior comments on the Proposed Transport Rule and requests that EPA consider these comments in developing the final Transport Rule. [EPA-HQ-OAR-2009-0491-3920[1].1, p.1]
Unit-specific Transport Rule allowance allocations should be based on accurate data reflecting current operating conditions at the Facility.
EPA states in the Second NODA that, '[i]n order to ensure the accuracy of the allocation calculations, the EPA is providing this opportunity for source owners and operators... to ... comment on the ... data used or that should be used to calculate the allocations and the resulting allocations, and ... submit corrections of the data or supplementary data.' 76 Fed Reg. 111 6. Sunbury appreciates the opportunity to comment on the accuracy of the data used to calculate the Transport Rule allowance allocations. [EPA-HQ-OAR-2009-0491-3920[1].1, p.3]
Relative to certain data relied upon by EPA in calculating Sunbury's S02 allowance allocations, as set forth in the Proposed Transport Rule, EPA apparently relied upon inaccurate information in determining the proposed S02 all owance allocations for affected EOUs at the Facility. That is, EPA considered emission reductions achievable through the installation of the Proposed Scrubber by January 2012, and adjusted the Facility's S02 allowance allocation downward on this basis. [EPA-HQ-OAR-2009-0491-3920[1].1, p.3]
As discussed in detail in Sunbury's comments on the Proposed Transport Rule, Sunbury had submitted to the Pennsylvania Department of Environmental Protection ('PADEP'), in December 2007, an application (the 'Permit Application') for Plan Approval (i.e., construction permit) for the voluntary installation of the Proposed Scrubber. At the time Sunbury submitted the Permit Application, the Facility's boilers were subject to the federal Clean Air Mercury Rule ('CAMR') and the Pennsylvania Air Mercury Rule (the 'PA Mercury Rule'), the Clean Air Interstate Rule ('CAIR'), the NO' Budget Program, and the Acid Rain Program. Sunbury believed installation of the Proposed Scrubber would be effective both in enabling the Facility to satisfy the applicable emission standards under the relevant regulatory programs, and providing the Facility with an economic benefit to sell excess emission allowances on the market. However, none of these regulatory programs specifically required installation of the Proposed Scrubber at the Facility. [EPA-HQ-OAR-2009-0491-3920[1].1, p.3]
Not long after Sunbury submitted the Permit Application, however, uncertainty surrounding these regulatory programs emerged, in the wake of numerous legal challenges at both the federal- and state-court levels, and the elimination of the NOx Budget Program in Pennsylvania in response to CAIR The manner in which EPA and Pennsylvania would seek to regulate mercury and NOx and S02 emissions from EGUs in the future also became uncertain. In the face of these uncertainties, Sunbury used alternative means to comply with the relevant emission control programs, including CAIR. [EPA-HQ-OAR-2009-0491-3920[1].1, p.4]
After receiving a Plan Approval for the Proposed Scrubber in June 2008, Sunbury initiated certain limited construction activities related to the installation of the Proposed Scrubber. However, the regulatory uncertainty related to CAMR, CAIR, the PA Mercury Rule, and the NOx Budget Program, as well as unforeseen developments in the power market, subsequently disrupted scheduling and design for the Proposed Scrubber. Based on these factors, among other on-site operational and economic considerations, Sunbury has not yet moved forward to a significant extent with the construction of the Proposed Scrubber. There are also no assurances that Sunbury will complete construction of the Proposed Scrubber, as there is currently no legal basis requiring installation of the unit, nor is the Facility aware of any potential legal or regulatory basis that will arise in the future which will require installation of the Proposed Scrubber. [EPA-HQ-OAR-2009-0491-3920[1].1, p.4]
Notwithstanding that Sunbury is not legally required to install, and has not yet moved forward to any significant extent with the construction of, the Proposed Scrubber, in determining the proposed S02 allowance allocations for the Facility under the Proposed Transport Rule, EPA considered emission reductions achievable through the installation of the Proposed Scrubber by January 2012, and adjusted the Facility's S02 allowance allocation downward on this basis. [EPA-HQ-OAR-2009-0491-3920[1].1, p.4]
For these reasons, EPA's calculation of S02 allocations under the Proposed Transport Rule allocation approach is based on inaccurate information. To the extent that EPA elects to finalize the allowance allocations as set forth in the Proposed Transport Rule, Sunbury asserts that such allocations should be calculated based on accurate information reflecting current operating conditions. In particular, any S02 allocation for Sunbury should not assume installation and operation of the Proposed Scrubber, or any other emission control device not already in operation and for which there is no legal basis requiring installation. Such approach would be consistent with EPA's acknowledgement in the Second NODA of the point made by commenters on the Proposed Transport Rule, that allocating allowances based on heat input is advantageous because '[h]istoric heat input data are emissions-control-neutral and thus do not yield reduced allocations for units that installed or are projected to install pollution control technology.' Id. at 11l3. [EPA-HQ-OAR-2009-0491-3920[1].1, p.4]
EPA clearly states within the Proposed Transport Rule that it 'wants to offer states substantial flexibility for addressing the Section 110(a)(2)(D)(i)(I) transport issues through a SIP should they choose to do so.' 75 Fed. Reg. 45342. However, affected states would not have sufficient time to develop state-specific regulations and then satisfy all elements of the SIP revision approval process, and secure EPA approval of the SIP, all before January 1, 2012. See id. ('The Transport Rule FIPs would be in place in each covered state until a state's SIP was submitted and approved by EPA to replace a FIP.') The inability of states to finalize state-specific SIP-based programs for implementing the Transport Rule would not merely postpone transition from a FIP-based to a SIP-based program. Instead, affected sources would be forced to pursue compliance options based upon the regulations that will be effective at the earliest time. Affected facilities would not likely have the option of implementing a transitional approach during the first phase of regulation that could simply be undone and replaced with a longer term strategy once the state SIP is promulgated and approved. For this reason, it is critical that states be afforded a reasonable opportunity to finalize and establish state-specific allocation approaches before affected sources would be subject to the promulgated standards. [EPA-HQ-OAR-2009-0491-3920[1].1, p.5]
The Proposed Transport Rule would purportedly require initial compliance with the final Transport Rule requirements by January 1, 2012. Yet as of now, just 11months before this deadline, EPA has not even promulgated a final regulation. Instead, with EPA's publication of the Second NODA in January 2011, it has become even more difficult for source owners to anticipate the emission reduction requirements of the final Transport Rule, and, more importantly, what, if any, operational changes facilities will need to implement to ensure compliance. Adding further to this problem is the marked uncertainty related to the proposed allowance trading programs under the Proposed Transport Rule. In particular, it remains unclear whether, and to what extent, affected facilities will have an opportunity to demonstrate compliance with the Transport Rule by obtaining additional allowances on the market. [EPA-HQ-OAR-2009-0491-3920[1].1, p.5-6]
Considering the proposed allowance allocations under the Proposed Transport Rule and the Second NODA as applied to Sunbury, the Facility could face the impossible obligation to reduce S02 emissions from approximately 40% to 80% from current operating levels within only 11 months, depending on which allocation approach EPA elects to implement through the final Transport Rule. When coupled with the notable uncertainty regarding the opportunities for allowance trading under the Proposed Transport Rule, this sweeping variability in potential emission reduction requirements among the proposed allowance allocation approaches makes it virtually impossible for the Facility to develop a compliance plan at this time in order to ensure compliance with the final Transport Rule. Further, even if EPA was able to promulgate a final Transport Rule in the relative short term, it would be impossible for an affected facility to secure any necessary permit approvals, let alone implement a compliance plan within an 11-month period, considering the significant amount of time required to complete construction activities after the necessary permits have been obtained. Similarly, the same constraints that make it virtually impossible for the Facility to develop and implement a compliance plan to ensure compliance with the Transport Rule by the start of2012 apply equally to the effective date for the second phase of emissions reductions under the Proposed Transport Rule, which commences in January 2014. [EPA-HQ-OAR-2009-0491-3920[1].1, p.6]
For these reasons, Sunbury believes that, while the option in the Second NODA to develop an abbreviated SIP offers some valuable flexibility to the states, this alternative does not afford affected source owners an adequate opportunity to develop and implement an appropriate compliance plan to ensure compliance with the Transport Rule by January 2012 (or even January 2014), based on the substantia1 uncertainty currently surrounding certain key aspects of the Transport Rule provisions. [EPA-HQ-OAR-2009-0491-3920[1].1, p.6]
Sunbury also asserts that the unit-specific Transport Rule allocations should be based on accurate data reflecting current operating conditions at the Facility. In response to EPA's specific request in the Second NODA for source owners and operators to comment on the data used to calculate unit-specific allocations, Sunbury explains in these comments (as well as Sunbury's comments on the Proposed Transport Rule) that EPA apparently relied upon inaccurate information in determining the proposed S02 allowance allocations for affected EGUs at the Facility. That is, EPA considered emission reductions achievable through the installation of the Proposed Scrubber by January 2012, and adjusted the Facility's S02 allowance allocation downward on this basis. [EPA-HQ-OAR-2009-0491-3920[1].1, p.7]
EPA apparently assumed installation and operation of the Proposed Scrubber by January 2012 based on Sunbury's previous submission of the Permit Application for the Proposed Scrubber in December 2007. At that time, Sunbury believed installation of the Proposed Scrubber would be effective both in enabling the Facility to satisfy the applicable emission standards under certain emerging regulatory programs intended to control mercury, S02, and NOx from EGUs, and providing the Facility with an economic benefit to sell emission allowances on the market. However, in the months following Sunbury's submittal of the Permit Application, there have been numerous changes on the regulatory front leading to significant uncertainty relative to the regulation of the relevant pollutants. On this basis, Sunbury has not moved forward to a material extent toward completing construction of the Proposed Scrubber. Moreover, there are no assurances that Sunbury will complete construction of the Proposed Scrubber, as there is currently no legal basis requiring installation of the unit, nor is the Facility aware of any potential legal or regulatory basis that will arise in the future which will require installation of the Proposed Scrubber. For these reasons, EPA's calculation of S02 allocations under the Proposed Transport Rule allocation approach is based on inaccurate information. To the extent that EPA elects to finalize the allowance allocations as set forth in the Proposed Transport Rule, Sunbury asserts that such allocations should be calculated based on accurate information reflecting current operating conditions. [EPA-HQ-OAR-2009-0491-3920[1].1, p.7]
Finally, although Sunbury supports EPA's proposal in the Second NODA to allow individual states to pursue partial SIPs in order to accelerate state-specific allocation approaches, Sunbury contends that this approach is in sufficient to remedy the unduly stringent ti,meline for demonstrating compliance with the Transport Rule. EPA clearly states within the Proposed Transport Rule that it wants to provide states flexibility for addressing the Transport Rule requirements through a SIP should they choose to do so. However, considering the Transport Rule's proposed January 1, 2012 initial compliance deadline, affected states would not have sufficient time to develop state-specific regulations and then satisfy all elements of the SIP revision approval process, and secure EPA approval of the SIP. Consequently, the states' transition from a FIP-based to a SIP-based program would be postponed, and affected sources would necessarily have to pursue compliance options based upon the regulations that will be effective at the earliest time. Therefore, it is cri ti cal that states be afforded a reasonable opportunity to finalize and establish state-specific allocation approaches before affected sources would be subject to the promulgated standards. [EPA-HQ-OAR-2009-0491-3920[1].1, pp.7-8]
At present, EPA has not yet promulgated a final Transport Rule, and yet the Proposed Transport Rule would purportedly require initial compliance within only 11 months. Further, EPA's publication of the Second NODA has made it even more difficult for source owners to anticipate the emission reduction requirements of the final Transport Rule, and what, if any, operational changes facilities will need to implement to ensure compliance. Relative to Sunbury, considering the proposed allowance al1ocations under the Proposed Transport Rule and the Second NODA, the Facility could face the impossible obligation to reduce S02 emissions from approximately 40% to 80% from current operating levels within the next 11 months, depending on which allocation approach EPA elects to implement through the final Transport Rule. This striking variability in potential emission reduction requirements among the proposed allowance allocation approaches makes it virtually impossible for the Facility to develop a compliance plan at this time to ensure compliance with the final Transport Rule. [EPA-HQ-OAR-2009-0491-3920[1].1, p.8]
Response: 
Thank you for your comment.Organization: Sunflower Electric Power Corporation
Comment: 
Sunflower Electric Power Corporation
For the reasons discussed in more detail below, Sunflower urges EPA to reconsider its proposed allocation methodologies and the compressed timeline of 2012 for the initial CATR compliance deadline. [EPA-HQ-OAR-2009-0491-3958[1].1, p.2]
Furthermore, Sunflower takes issue with the timelines EPA  proposed for CATR implementation. The proposed 2012  commencement date, , does not allow adequate time for states to submit and obtain SIP approvals incorporating allowance allocation methodologies tailored to meet state and local conditions and concerns and as a practical matter forces states into application of  methodology in the generic FIP.   All of these issues are the product of EPA's "rush to judgment" and will ultimately lead to additional problems and litigation much of which can be avoided by a more considered and reasoned approach. [EPA-HQ-OAR-2009-0491-3958[1].1, p.5]
Response: 
Comments on the allocation methodologies in the January 7, 2011 NODA (NODA 3) are addressed in preamble section VII.D and RTC sections XX.A through XX.A.3.  Comments on the Transport Rule compliance deadlines are outside the scope of NODA 3.  Section VII.C of the preamble, sections V.C and V.C.1 of this RTC, and the Transport Rule Engineering Feasibility Response to Comments document (available in the docket) address compliance timing.
Organization: Tampa Electric Company
Comment: 
Tampa Electric Company
Tampa Electric appreciates the opportunity to comment on this important proposed rule that, if finalized, has the potential to significantly impact on our customers. Tampa Electric also supports comments made by the Florida Electric Power Coordinating Group. Tampa Electric shares a commitment with the EPA to further reduce emissions from power generating facilities and supports the general policy objectives underlying EPA's proposed Transport Rule. Tampa Electric has been actively engaged with the rulemaking process, attending and presenting comments at hearings in Chicago and Philadelphia as well as participating in numerous stakeholder meetings. [EPA-HQ-OAR-2009-0491-3959[1].1, p.1]
Tampa Electric Requests EPA Must another Proposed Rule
Tampa Electric would like to assert that throughout this process there has not been adequate time for the public and affected parties to review the Transport Rule and all the subsequent revisions. Even though EPA's alternative allocation does not rely on the IPM model it is still important to note that the inconsistent IPM model is used to determine each individual emission budget. As noted in Tampa Electric's original comment letter to the EPA submitted on October 1, 2010, there were numerous flaws with the model assumptions at that time and there has been little clarification as to the corrections made. [EPA-HQ-OAR-2009-0491-3959[1].1, p.2]
Response: 
Thank you for your comment.Organization: Tenaska, Inc.
Comment: 
Tenaska, Inc.
Tenaska submitted comments under a cover letter dated September 30, 2010 on the Transport Rule. In those comments, Tenaska explained the uncertainty, in the energy markets and the attendant fluctuation of energy prices, as well as the high capital costs and long lead times needed in terms of developing energy infrastructure. Tenaska has suggested that more accurate allocations and greater flexibility in the Transport Rule is necessary to address that uncertainty. In its comments, Tenaska suggested using historical heat input, rather than past emission rates, as a means of allocation. Further, Tenaska suggested that the allocations be updated on a regular basis to provide the flexibility necessary to address variability and volatility in the energy markets over time. Tenaska requested an opportunity to review and verify data as heat input that might be used in developing a final rule. [EPA-R03-OAR-2010-1027-DRAFT-0005.1[1], p.1]
Response: 
Thank you for your comment.Organization: Tennessee Valley Authority (TVA)
Comment: 
Tennessee Valley Authority (TVA)
   TVA acknowledges EPA's instruction to provide comments relative to the discrete areas presented by this NODA and to refrain from raising other issues and comments related to the originally proposed rules. However, the original proposal and the three subsequent NODAs cannot individually be viewed in isolation as they are all intertwined. Therefore, TVA must reiterate that meeting an allowance limitation beginning in 2012, soon after the release of the final Transport Rule later this year, places an extreme and unrealistic hardship on owners who have already developed or are in the process of developing detailed company-wide business and financial plans for 2012. Also as we have stated in our previous comments the 2014 deadline does not allow sufficient time to install the requisite controls to meet the proposed emission targets. The stringency of the proposed 2012/2014 state budgets coupled with the high level of uncertainty surrounding the availability of allowances beginning in January 2012, has the potential to significantly disrupt business planning and operations.    [EPA-HQ-OAR-2009-0491-3983[1].1, p.1]
Response: 
Thank you for your comment.Organization: Texas Commission on Environmental Quality
Comment: 
Texas Commission on Environmental Quality
The EPA's continued piecemeal release of data and various program alternatives that could result in significant changes to the originally proposed rulemaking with limited comment periods and without opening the entire rule up for comment· results in inadequate public notice. The EPA should reopen the comment for the complete rulemaking package to allow for adequate opportunity for the public to evaluate the full potential impact of the rule and provide meaningful public comment. [EPA-HQ-OAR-2009-0491-4030, p.3]
If the EPA does continue to update information, including emission inventory data that is used to support the final rulemaking, the Texas Commission on Environmental Quality (TCEQ) requests that any such information be made available for public comment. Furthermore the TCEQ requests that the complete rulemaking package be reopened for comment and the EPA provide adequate time for all the technical information and any potential changes to the rule to be evaluated. Absent such an opportunity to comment on the complete proposed rule and any substantive changes that the EPA may make using new information the public is unable to reasonably provide meaningful comments or to evaluate the potential impact of the rule. [EPA-HQ-OAR-2009-0491-4030, p.3]
With the continued release of new data by the EPA in support of the Transport Rule and the repeatedly limited comment periods, the TCEQ strongly requests that the EPA provide all data and underlying assumptions in a timely, transparent, and user-friendly manner. [EPA-HQ-OAR-2009-0491-4030, p.4]
In identifying the parameters under which states might submit SIP revisions addressing Transport Rule requirements, the EPA notes that 'each state would still have the ability to submit other types of SlPs using emissions reduction approaches other  than the proposed Transport Rule trading programs to correct the deficiency under [Federal Clean Air Act section 110(a)(2)(D)(i)(1) in the state's SIP that was the basis for the proposed Transport Rule FIPs. ' The TCEQ is unaware of any deficiency in Texas' 'SIP regarding transport obligations for the 1997 eight-hour ozone standard. [EPA-HQ-OAR-2009-0491-4030, p.5]
The TCEQ submitted a Federal Clean Air Act Section 110(a)(2)(D)(i) SIP revision for the 1997 eight-hour ozone standard in April 2008, with receipt acknowledged by the EPA as of May 5, 2008. Because Texas was not originally included in the Clean Air Interstate Rule (CAIR) program for the 1997 eight-hour ozone standard, the state did not rely solely on CAIR modeling in meeting this 'infrastructure' SIP obligation and identified state-level controls adopted for major point sources, along with their associated emission reductions. and other Texas SIP revisions that would address Texas' Section 110(a)(2)(D)(i)(1) obligations. The submittal also documented the greater stringency of state electric generating utility NOx control strategies versus those required by CAIR. The EPA failed to consider many of these controls in its proposed Transport Rule modeling. Additionally, in its Transport Rule proposal, the EPA explicitly identified its plan for states not covered by the original CAIR who had, since 2005. submitted SIP revisions to satisfy the requirements of Section 110(a)(2)(D)(i)(I) for the 1997 eight-hour ozone (and PM2.5 NAAQS (75 FR 45342). 'For the states that have now been identified to be contributing significantly to nonattainment or interfering with maintenance under this proposed rule and whose [Section] 110(a)(2)(D)(i)(I) with respect to 1997 ozone and PM2.5 NAAQS are pending approval, EPA will finalize the FIP included in this proposed rule only if EPA either determines that the SIP submission is incomplete or disapproves the SIP submission.' Because approximately 33 months have passed since the EPA-acknowledged submittal date of the Texas' Section 110(a)(2)(D)(i)(I) SIP revision for the 1997 eight-hour ozone standard. the revision has been deemed by operation of law as of November 5, 2008, to meet minimum completeness requirements. in accordance with Section 110(k)(l) of the FCAA. The .EPA was therefore required to take action regarding fun, partial, or conditional approval or disapproval for this revision within 12 months of the completeness determination deemed by operation of law (November 5, 2009), but minimally,  must do so prior to any Transport Rule FIP finalization for Texas regarding the 1997 eight-hour ozone NAAQS. In any case, a FIP relying on the 2005 notice of failure to submit would be inappropriate under the FCAA when the EPA has failed to take action on a pending submittal directly responding to that notice. Because Texas has submitted~ in good faith, a SIP revision with additional substantive emission reductions beyond CAIR to address Section 110(a)(2)(D)(i) obligations for the 1997 eight-hour ozone standard because the EPA must take action on such submittals prior to finalization of Transport Rule FIPs and to date, has taken no action, and because Texas' proposed inclusion in the Transport Rule is based on flawed modeling data that fails to account for certain controls explicitly identified in its 2008 submittal, the inclusion of Texas in the Transport Rule FIP trading program is inappropriate. [EPA-HQ-OAR-2009-0491-4030, pp.5-6]
Response: 
EPA provided a full opportunity for comment on whether Texas should be included in the annual NOX and annual SO2 programs in the Transport Rule based on its significant contribution to nonattainment or interference with maintenance of the 1997 annual PM2.5 NAAQS in other states.  Indeed, any argument that the parties could not have anticipated EPA's ultimate decision to include Texas in the rule based on its significant contribution with respect to the 1997 PM2.5 standards is refuted by the fact that EPA explicitly requested comment on this issue. See 75 FR 45284.

It is well established that a final rule need not be identical to the proposed rule.  It need only be a "logical outgrowth" of the proposed regulations.  See Small Refiner Lead Phase-Down Task Force v. EPA, 705 F.2d 506, 546-47 (D.C. Cir. 1983).  As the court has long recognized, a contrary approach would lead to the absurd result that "the agency can learn from the comments on its proposal only at the peril of starting a new procedural round of commentary," International Harvester Co. v. Ruckelshaus, 478 F.2d 615 (D.C. Cir 1973).  The notice and comment process does not begin anew each time a proposed rule is changed in response to public comments on a proposal.  Notice is the primary consideration used by the courts to determine whether a proposed rule requires a supplemental proposal. To determine if a final rule is a logical outgrowth of a proposal, courts look to whether "interested parties `should have anticipated' that the change was possible and thus reasonably should have filed their comments on the subject during the notice-and-comment period." CSX Transp. Inc. v. Surface Transportation Board, 584 F.3d 1076 (D.C. Cir 2009) (internal citations omitted).  "'[A] final rule represents a logical outgrowth where the NPRM expressly asked for comments on a particular issue or otherwise made clear that the agency was contemplating a particular change.'" International Union v. Mine Safety and Health Administration, 626 F.3d 84 (D.C. Cir 2010) (internal citations omitted).  

In this instance, EPA explicitly asked for comments on the issue in question.  EPA explicitly notified the public in the proposal that it was considering including Texas in the Transport Rule annual programs as a group 2 state, and requested comment on that issue.  Then, in the final rule, EPA decided to do what it had told the public, in the proposal, that it was considering.  Specifically, in the proposal, EPA noted that its analysis for the proposal indicated that projected increases in Texas SO2 emissions associated with implementation of the Transport Rule (e.g, as a result of fuel switching associated with changes in the price of low verses higher sulfur coal) would cause Texas's contribution to exceed the threshold for annual PM2.5.  It then explicitly requested comment on "whether Texas should be included in the program as a group 2 state."  75 FR 45284.  The analysis for the final rule, then demonstrated that emissions in Texas significantly contribute to nonattainment and interfere with maintenance in another state even in the base case.  In other words, even without any increases in Texas emissions associated with implementation of the Transport Rule in other states, emissions in Texas are significantly contributing to nonattainment and maintenance problems downwind.  For this reason, EPA decided to do what it requested comment on.  That is, it decided to include Texas in the annual programs as a group 2 state.  For these reasons, EPA's inclusion of Texas in the final rule based on its significant contribution and interference with maintenance with respect to the annual PM2.5 NAAQS is a logical outgrowth of the proposal.

The fact that the proposal did not include illustrative annual NOX and annual SO2 budgets for Texas does not change this conclusion.  In the proposal, EPA clearly identified and took comment on a methodology for identifying and quantifying emissions within a state that significantly contribute to nonattainment or interfere with maintenance downwind.  EPA also clearly identified the states for which it would be doing such analysis, and it identified and took comment on the data inputs to be used in the calculation.  EPA received numerous comments on the methodology, including comments from TCEQ and sources in Texas.  EPA also received numerous comments on and corrections to Texas-specific data.  EPA refined its methodology and data inputs in response to public comments.  The illustrative budgets provided in the proposal merely demonstrated the outcome of applying the proposed methodology to the data inputs used for the proposal.  Adjustments were made to all states budgets and the allowance allocations for all states between proposal and final.  EPA provided an ample opportunity to comment on the methodology and data inputs to be used to calculate states' significant contribution, and explicitly provided notice that it was considering including Texas in the final rule due to its impact on downwind nonattainment and maintenance problems with respect to the 1997 PM2.5 NAAQS.  For these reasons, EPA's determination that Texas must be included in the annual programs because of these impacts is a logical outgrowth of the proposal.

Comments on EPA's authority to issue the Transport Rule FIPs are outside the scope of NODA. As described in section III.A. of this RTC and section IV.C.2 of the preamble, EPA has a legal obligation to promulgate each of the FIPs in this action. Section 110(c)(1) explicitly provides that once EPA has made a finding of failure to submit, it has a legal obligation to promulgate a FIP "unless the State corrects the deficiency, and the Administrator approves the plan."  Further, the statement in the preamble referenced by TCEQ applies only to those states who were not subject to the CAIR rule.  On its face, it does not distinguish between states that were subject to CAIR for one or both NAAQS.  Further, this statement is a statement of EPA intent and does not affect the scope of its authority or obligations under 110(c)(1).  See also the "Status of CAA 110(a)(2)(D)(i)(I) SIPs Final Rule TSD" in the docket.
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Comments on the NOx emissions inventories used in the analysis for the Transport Rule are outside the scope of NODA 3.  EPA received and considered extensive comments on its emissions inventories and modeling that were received on the proposed rule and NODAs 1 and 2 and updated its assumptions as appropriate, including numerous updates to the assumptions for Texas emissions.  Such comments are addressed in the preamble to the final rule, elsewhere in this RTC, and in the supplemental Response To Comments documents. Furthermore, EPA notes that the Texas SIP did not require any new emission reductions, nor did it identify any new controls for EPA to consider while updating EPA's data. 

Organization: Tri-State Generation and Transmission Association, Inc.
Comment: 
Tri-State Generation and Transmission Association, Inc.
Tri-State believes that states should be provided the opportunity to participate in the allowance allocation provisions of the proposed transport rule, and any other aspect of the rule in which states may choose to participate. Tri-State also believes that states are provided a right in the Clean Air Act pursuant to §IIO(a)(l) to meaningfully participate in the implementation of regulatory programs that provide for the implementation, maintenance, and enforcement of any national primary ambient air quality standard in each air quality control region within a state. States are provided up to 3 years '(or such shorter time period as the administrator may prescribe)' to submit State Implementation Plan (SIP) elements to accomplish this participation. While the Administrator may provide a shorter timeframe for states to develop and submit plans, the timeframe provided by the Administrator eliminates states ability to accomplish SIP development review/approval and participation in any (emphasis added) meaningful fashion prior to the promulgation of the proposed federal implementation plan (FIP). Simply allowing states to participate after a FIP is promulgated and implemented cannot be construed to be meaningful participation by the States. [EPA-HQ-OAR-2009-0491-3902[1].1, p.2]
Tri-State believes that EPA must abandon its current effort to promulgate a FIP and provide states with a meaningful opportunity to participate in the mitigation of the interstate transport of air pollutant emissions within their states. Tri-State believes that EPA should repropose a transport rule giving states a meaningful opportunity to participate in this program. [EPA-HQ-OAR-2009-0491-3902[1].1, p.2]
Tri-State believes that EPA could adopt a model trading program with accompanying regulations, allowing states to make (limited) revisions that can be determined to comply with the decision in North Carolina v. EPA. EPA should allow states to adopt the program and accompanying regulations into a state implementation plan element with an appropriate amount of time for program consideration/adoption providing reasonable notice and adequate public hearing. Tri-State believes that EPA is required by the Clean Air Act to provide states with this opportunity, and that EPA is required to provide states with a realistic timeframe in which states can be expected to accomplish this activity. [EPA-HQ-OAR-2009-0491-3902[1].1, p.2]
Tri-State recognizes models and modeling efforts as an important and valuable tool for developing environmental regulations, but cautions that they have limitations and they have a tendency to over-predict the benefits of emissions controls and when used alone, have a tendency to over regulate. Tri-State does not believe that the EPA modeling effort used to develop the state wide emission budgets or project the allocations in the initial proposal has adequately considered, and may not be capable of considering, the breadth and scope of the literally hundreds of factors that can and do affect the future cost of emission controls, unit utilization, and operation. EPA's initially proposed allowance allocation scheme, as well as the two proposed alternatives, is based upon a critically flawed modeling effort that will seriously disadvantage any allocation scheme that EPA chooses to promulgate. Any meaningful allocation program will require EPA to readdress this modeling effort. [EPA-HQ-OAR-2009-0491-3902[1].1, p.3]
EPA's initially proposed allowance allocation scheme penalizes cleaner, more well controlled, coal fired, emission units and the electricity consumers who have borne the higher costs to pay for the existing, expensive emission control systems. The model metrics do not adequately consider existing unit generation costs, and as such, some of the most costly, well controlled fossil fuel generation affected by the proposal would be required to incur substantially greater compliance costs associated with further emission reductions than some of the more highly polluting and less efficient affected units. It is poor public policy for EPA to penalize lower emitting units over higher emitting units in the process of allocating emission allowances. EPA can better address this issue by choosing a heat rate input based allocation calculation methodology that subcategorizes the allocations based upon fuel type and unit design as EPA had posited in the original proposal. [EPA-HQ-OAR-2009-0491-3902[1].1, pp.3-4]
In the original proposed rule on page 45311, EPA discusses a heat input based allocation methodology that considers grouping similar units by fuel type and design. Specifically EPA stated in the preamble:
There are other approaches to allocation. For example, EPA could identify groups of units in each state that are capable of having similar emissions characteristics (e.g., grouped by size, fuel type, or age). EPA would distribute a state's emissions budget without variability to each group of units in the state (in effect, distributing the responsibility for eliminating all or part of significant contribution) perhaps based on each group's proportional share of the state budget as projected in the initial year of the program. After apportioning a state's budget to the groups of units, under such an approach EPA could distribute allocations to individual sources within each group based on each source's proportional share of projected heat input. Like the first alternative allocation method described previously, this approach distributes each state 's Significant contribution and interference with maintenance to individual sources in the state. By determining groups and then distributing allocations within the groups based on proportional shares, this approach would treat units within the categories equally (i. e., it would not treat a source that had acted early to control differently from one that had yet to take control action). [EPA-HQ-OAR-2009-0491-3902[1].1,p.4]
Tri-State believes that such an approach would be a more appropriate heat input based approach to allocating allowances to electric generating units. Following this type of approach, previously suggested by EPA, EPA could base allocations on unit heat input combined with a well controlled emissions rate that would be reasonably achievable within each grouping. Grouping of units based on fuel type and design could use coal rank to separate coal fired units and could use unit design; combined cycle or simple cycle, to subcategorize oil fired and gas fired units.[EPA-HQ-OAR-2009-0491-3902[1].1, p.4]
Response: 
Thank you for your comment.Organization: United States Clean Heat & Power Association (USCHPA)
Comment: 
United States Clean Heat & Power Association (USCHPA)
  We are gratified by EPA's growing recognition of the important role of energy efficiency in its suite of Clean Air Act regulations. Indeed, energy efficiency reduces compliance costs for all of the Agency's rules - by reducing fuel demand and associated emissions. This perspective was reflected in EPA's recent Guidance for PSD and Title V Permits for Greenhouse Gasses ('BACT Guidance'), which expressly recognized the key role energy efficiency can play - not only in the reduction of greenhouse gasses, but in reducing emissions of all criteria pollutants. As EPA recognized in the Guidance, '[s]electing technologies, measures and options that are energy efficient translate[s] not only in the reduction of emissions of the particular regulated NSR air pollutant undergoing BACT review, but it also may achieve collateral reductions of emissions of other pollutants, as well as GHGs.' This appreciation for energy efficiency was also reflected in the Proposed Clean Air Transport Rule, wherein EPA acknowledged that  '[p]olicies that will promote efficient use of electric power can be an integral, highly cost-effective component of power companies' compliance strategies.' [EPA-HQ-OAR-2009-0491-3955[1].1, p.1]
Energy efficiency is a particularly important consideration under the Transport Rule because traditional power generation is woefully inefficient. As illustrated in the following graphic, two-thirds of the fuel we use to produce electrical power is wasted under conventional power production. Thus, as depicted below, roughly one-third (15,623 TWh) of primary energy input (49,555 TWh) - a mere 32 percent - is actually delivered to customers using conventional means. [EPA-HQ-OAR-2009-0491-3955[1].1, p.2]
Waste Heat Recovery and Combined Heat and Power, in contrast, can more than double this efficiency - capturing heat and putting it to good use. Assuming thermal losses alone are reduced by half (a conservative improvement), under the above scenario, an additional 15,624 TWh would be delivered to customers.  [EPA-HQ-OAR-2009-0491-3955[1].1, p.3]
Such losses have concomitant environmental effects. In fact, as depicted below, inefficiencies in conventional power generation lead to nearly three times the NOx emissions of Combined Heat and Power (45 tons/ year vs. 17 tons/ year in the graphic on the next page). Under the Combined Heat and Power scenario much less fuel is consumed and fewer emissions released to provide a given amount of useful energy as compared to separate heat and power. The lower emissions associated with Combined Heat and Power are clearly preferable and should be encouraged. [EPA-HQ-OAR-2009-0491-3955[1].1, p.3]
The Clean Air Transport Rule sets an important precedent. EPA plans to promulgate a second Transport Rule for industrial sources in the foreseeable future. By incorporating an output-based emissions standard in this rule, EPA can lay the groundwork to adopt a similar allocation methodology in Round Two. This is particularly important given the potential for emissions reductions through energy efficiency at industrial sources. Indeed, potential savings in industrial energy use are vast, as the industrial sector is responsible for about one-third of total US energy demand. [EPA-HQ-OAR-2009-0491-3955[1].1, p.5]
Appendix  Comments Advocating Output-Based Standards in Response to "Federal Implementation Plans To Reduce Interstate Transport of Fine Particulate Matter and Ozone" (EPA-HQ-OAR-2009-0491)
Comments of the Alliance for Industrial Efficiency, September 30, 2010, at pages 2-3  
(http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2009-0491-2773.1)  'First and most important, EPA should adopt output-based emissions standards in the Federal Plan. Rather than base pollution limits on the amount of fuel consumed, standards based on each unit of electricity (and thermal energy) produced would encourage efficiency. As a result, pollution would be prevented and emissions reduced.'
Comments of the Clean Energy Group, October 4, 2010, at page 6
(http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2009-0491-2702.1)  'Many of the Clean Energy Group companies have long supported output-based allocation approaches. An output-based allocation relies on energy production (megawatt-hour [MWh]) as the basis for determining the number of allowances that a unit will receive prior to the compliance year....The benefits of an output-based allocation include promoting more efficient and cleaner production of electricity. In addition, the methodology does not further penalize companies and their customers for investments made in cleaner generation prior to a regulatory mandate.'  
Comments of the American Clean Skies Foundation, October 1, 2010, at page 5
(http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2009-0491-2850.1)  'EPA should consider an output-based methodology...A number of states have adopted output based allocation methods, which allocate emissions allowances based on megawatts produced by power plants. This could reward states with large amounts of generation to retain significant generation, while rewarding the most efficient units.  
Comments of Equipower Resources Corporation, October 1, 2010, at page 16
(http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2009-0491-2704.1)  'The FIP that the Transport Rule would impose upon the states uses input-based calculations in determining allocations...In mandating an input-based regulation, EPA will usurp state authority to use a system that EPA itself has advocated for more than a decade...The use of an input-based calculation will lead to different allocations than an output-based calculation, which provides a greater number of allowances to more efficient plants.'  
Comments of the New Jersey Department of Environmental Protection -- Division of Air Quality, September 30, 2010, at page 16
(http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2009-0491-2684.1)  'The proposed allocation of allowances results in rewarding dirty units, while penalizing clean units. New Jersey urges the USEPA to revise their allocation method to be based on recent energy output with rolling updates...Under the USEPA's proposal, clean units that currently meet the Phase 1 CAIR emission rate of 0.15 lbs/MMBtu account for 59 percent of the affected units, but only get 16 percent of the total Transport Rule ozone season NOx allowance. In turn, units that are dirtier than 0.15 lbs/MMBtu account for 41 percent of the affected units, but get 84 percent of the allowances. This provides disincentive for dirty utilities to control their emissions, while under allocates to clean units that have less ability to reduce emissions.'  
Comments of the Northeast States for Coordinated Air Use Management (NESCAUM), October 1, 2010, at page 8
(http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2010-0162-1757.2)  'EPA can and should, at a minimum, establish allocations based on output.'  
Comments of Recycled Energy Development, September 24, 2010 at page 2
(http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2009-0491-2601.1)  'First and most important, EPA should adopt output-based emissions standards in the Federal Plan. Rather than base pollution limits on the amount of fuel consumed, standards based on each unit of electricity (and thermal energy) produced would encourage efficiency. As a result, pollution would be prevented and emissions reduced.'  
Comments of the US Clean Heat and Power Association, September 30, 2010, at page 2
(http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2009-0491-2823.1).  'First and most important, EPA should adopt output-based emissions standards in the Federal Plan. Rather than base pollution limits on the amount of fuel consumed, standards based on each unit of electricity (and thermal energy) produced would encourage efficiency. As a result, pollution would be prevented and emissions reduced.' [EPA-HQ-OAR-2009-0491-3955[1].1, pp.6-7]
Response: 
Comments cited by USCHPA have been responded to throughout the Response to Comment document.
Organization: Utility Air Regulatory Group (UARG)
Comment: 
Utility Air Regulatory Group (UARG)
UARG notes, however, that whatever approaches are ultimately adopted for allocating allowances (or potential alternative means of satisfying states' emission reduction obligations under the proposed rule, see id. at 1120), there continues to be a pressing need for EPA to address in this rulemaking the deficiencies discussed in UARG's previous comments with respect to determination of states' emission reduction obligations under the proposed rule. [EPA-HQ-OAR-2009-0491-3979[1].1, p.2]
As EPA emphasizes in NODA 3, "[t]he unit-level allocations in this NODA are based on State emissions budgets in the proposed Transport Rule," and the "final State budgets may differ from the proposed budgets because EPA is still in the process of updating its emissions inventories and modeling in response to public comments." Id. at 1111. As they stand, the proposed budgets are based on a wide range of emission inventory and other data -- and decisions based on those data -- that, for reasons discussed in UARG's previous comments, have not been adequately explained and documented. These deficiencies, in turn, undermine the basis for EPA's proposed determinations of interstate contribution to nonattainment and interference with maintenance of NAAQS under section 110(a)(2)(D)(i) of the Clean Air Act. If EPA is to undertake any further action in this rulemaking, it must correct these deficiencies and make the revisions and adjustments necessary to resolve the many flaws in its proposal that are identified in UARG's Proposed Transport Rule comments, NODA 1 comments, and NODA 2 comments, which are incorporated herein by reference. This level of revision will require EPA to withdraw the proposal and begin again. After making the necessary revisions and adjustments, EPA should complete each step of its methodology anew using appropriate updated modeling tools and data. With the results of this reanalysis, EPA should revisit the basis for the Proposed Transport Rule to determine whether or not the results support the use of the approach set forth in the proposed rule and to develop a revised approach as necessary. EPA should then publish a comprehensive revised proposal for public comment, providing the results of its reanalysis and all of the data used to conduct and complete it, and should allow an adequate period for public review of and comment on the revised proposal and its underlying data.[EPA-HQ-OAR-2009-0491-3979[1].1, pp.2-3]
Response: 
Thank you for your comment.Organization: Vectren Corporation 
Comment: 
Vectren Corporation 
The primary concern identified in our original comments is that an allocation methodology based upon an historic emissions methodology unfairly disadvantaged those facilities, like Vectren's, that have already made significant investments in pollution controls by awarding more emission credits to those utilities that have not installed the same controls. Coal-fired units that are not controlled have higher emission rates, and thus higher historic emissions. Under the original Transport Rule proposal, these uncontrolled units received more allowances than a similarly situated clean unit. [EPA-HQ-OAR-2009-0491-3923[1].1, p.2]
Vectren supports the 3% holdout for new unit-set asides
The 3% holdout from the state allowance budgets for new units is comparable to the holdouts for existing allowance programs which have proved adequate for the current source population and should be sufficient to bring new units into the allowance trading system given the anticipated retirements of a significant portion of uncontrolled units within the next ten year planning horizon. [EPA-HQ-OAR-2009-0491-3923[1].1, p.5]
Response: 
Thank you for your comments. 
Organization: Westar Energy, Inc.
Comment: 
Westar Energy, Inc.
The proposed Transport Rule included a unit-level allocation methodology ("Rule Methodology") that uses "a combination of adjusted historic and adjusted projected emissions data," Id. at 1113/2. EPA finds all three methodologies to be "reasonable and consistent with the goals of CAA section 110(a)(2)(D)(i)(1)," id. at 1113/3, but asks whether Option 1 and Option 2 are clear, "yield a reasonable distribution of allowances," are consistent with the statutory goals, and can be feasibly implemented. Id. at 1116/2-3. [EPA-HQ-OAR-2009-0491-3952[1].1, p.1]
The Rule Methodology is somewhat more comparable under some conditions in that it allocates much less than the 6000 t/y to two of the JEC units, and more than that for the third one. For NOx Annual, under some conditions the consent decree places a 12,400 t/y limit for all three JEC units combined by 2014, and 9,600 t/y by 2016. Options 1 and 2 allocate over 6,000 t/y to each unit, for a combined total that is about 50% more than the consent decree maximum. The Rule Methodology for NOx Annual allocates about 4,000 t/y to each of two JEC units, which would be in line with the consent decree limits, but allocates about 9,900 t/y to the third unit, again making the combined allowance greater than the consent decree limit. [EPA-HQ-OAR-2009-0491-3952[1].1, pp.2-3]
It appears that the Rule Methodology and Options 1 and 2 rely heavily on past historical data, and therefore fail to give any consideration to the increased controls (and resulting lower emissions levels) for the JEC units that are mandated to go into effect by 2012 under the consent decree. Thus, none of the approaches gives adequate consideration to what the consent decree changes will mean in 2012 and thereafter, or the applicability of the Transport Rule to Kansas.   [EPA-HQ-OAR-2009-0491-3952[1].1, p.2]
Westar also had a fair number of units that received a zero allowance for both SO2 and NOx under the Rule Methodology. [EPA-HQ-OAR-2009-0491-3952[1].1, p.2]
As the above discussion suggests, a rigid, formulaic approach to setting future emissions allowances to all units may not be the best approach. Rather, more in-depth analysis of each unit (or perhaps type of unit) based on known and reasonably expected conditions appears to offer a more realistic view of what can be achieved. The above discussion shows that each methodology has its advantages and its drawbacks. Comparing the JEC units proposed allowances under the different methodologies in light of the consent decree appears to favor the Rule Methodology as the better approach to what future emissions levels will realistically be at JEC. But adopting that approach uniformly to all units would mean a number of Westar's other (and other owners') units would receive a zero allowance, which cannot be justified. With Options 1 and 2, the reverse seems true, with the zero allowance units receiving a positive allocation, but a result for JEC that cannot be squared with the reality of the consent decree. The end result of the allowance allocation process should reflect the extent to which realistic emissions reductions can be achieved, or are required to be achieved, in the future to meet the Transport Rule limitations.   [EPA-HQ-OAR-2009-0491-3952[1].1, p.2]
The NODA asks "whether the allocation methodology chosen for each of the four trading programs must be the same or whether it would be reasonable to allocate using different methodologies for the different programs." 76 FR at 1114/1-2. That does not appear to be the right question to ask. The better question would be whether the same methodology should be applied to all units or different methodologies should be applied to different types of units or different types of situations, such as where a known consent decree is in place. While this might be more complicated than a "one-size-fits-all" approach applied across the entire spectrum of units, the final results would likely be more tailored to fit realistically within a framework of feasible reductions at individual units designed to meet the Transport Rule's limitations. [EPA-HQ-OAR-2009-0491-3952[1].1, pp.2-3]
Based on these considerations, Westar again requests EPA to withdraw its notice of proposed rulemaking and reevaluate the basis for any action, prior to any final decision on whether Kansas should be included in the Clean Air Transport Rule States. If any final rule is issued, the comments herein should be addressed. [EPA-HQ-OAR-2009-0491-3952[1].1, p.7]
Response: 
Thank you for your comments.
Organization: Western Farmers Electric Cooperative (WFEC)
Comment: 
Western Farmers Electric Cooperative (WFEC)
As to the latest NODA, WFEC is disappointed that the agency has not addressed the problematic timing of the CATR 2012 and 2014 compliance periods as others have identified in earlier comments to the August 2, 2010 CATR.  EPA's failure to extend the CAIR beyond 2011 and its proposed imposition of the 2012 and the 2014 timelines continue to plague this rulemaking. [EPA-HQ-OAR-2009-0491-3945[1].1], p.2  
General Comment for all WFEC units  -  the State of Oklahoma was not included in the original CAIR program but has been included with CATR during Ozone season. Why did it change?  It is our understanding that the state of Oklahoma was only included because of one modeling day in which the Dallas - Fort Worth (DFW) area was affected by Oklahoma emissions.  Since southerly winds are predominately and Oklahoma is north of DFW, it seems unwarranted to place such a heavy financial burden on the electrical consumers in Oklahoma.  [EPA-HQ-OAR-2009-0491-3945[1].1, p.4]
In addition WFEC has an energy portfolio with the highest percent of renewable energy in the state so again it seems that EPA has failed to recognize energy consumers who have invested in renewable energy.   [EPA-HQ-OAR-2009-0491-3945[1].1, p.4]
WFEC is disappointed, however, that the agency has not addressed the problematic timing of the CATR 2012 and 2014 compliance periods as NRECA and others have identified in earlier comments to the August 2, 2010 CATR.  EPA failed to extend the CAIR beyond 2011 and its proposed imposition of the 2012 and the 2014 timelines continue to plague this rulemaking.  There is no legal prohibition in the North Carolina decision against keeping CAIR in effect beyond 2011, and EPA's failure to do so would create yet another problem in so far as effectively prohibiting states from implementing SIPs addressing Clean Air Act Section 110(a)(2)(D)(i) deficiencies during the early stages of CATR implementation. [EPA-HQ-OAR-2009-0491-3945[1].1, p.4]
Response: 
EPA commends the commenter for its renewable energy portfolio but also observes that emissions from fossil fuel-fired EGUs in the state of Oklahoma are still capable of significantly contributing to nonattainment or interfering with maintenance of the NAAQS in a downwind state.
Organization: Wolverine Power Supply Cooperative
Comment: 
Wolverine Power Supply Cooperative
On October 1, 2010, Wolverine filed detailed comments regarding the proposed Transport Rule, focusing on our opinion that the proposed rule would not afford Wolverine assurance that it would be able to acquire necessary NOx annual and ozone season allowances to continue to operate this stranded generating asset. The proposal, in effect, discriminated against very low-emitting generators as well as stranded units and small generating fleets, as was described in our October 1, 2010, comments. [EPA-HQ-OAR-2009-0491-4014[1].1, p. 3]
Wolverine continues to believe that the other defects of the proposed rule that were identified in our October 1, 2010, comments remain unresolved. [EPA-HQ-OAR-2009-0491-4014[1].1, p. 3]
Wolverine still maintains, as expressed in our October 1, 2010, comments, that the USEPA's implementation strategy that preempts the SIP process by immediate imposition of a Federal FIP circumvents Section 110(a) of the Clean Air Act, and is neither legal nor advisable. Short-circuiting the SIP development process pre-empts state development of a workable allocation mechanism between subject sources within a state and other necessary control strategies to most cost-effectively support attainment of the National Ambient Air Quality Standards. [EPA-HQ-OAR-2009-0491-4014[1].1, p. 5]
The assurance provisions remain unreasonable in that they create a high level of risk to stranded and small systems, such as Wolverine's Sumpter plant, that they will incur unanticipated future allowance surrender obligations that are in many ways out of the source's direct control. [EPA-HQ-OAR-2009-0491-4014[1].1, p. 5]
Response: 
Thank you for your comment.Organization: Xcel Energy Inc.
Comment: 
Xcel Energy Inc.
Additional time should be allowed for proper implementation of the final CATR. [EPA-HQ-OAR-2009-0491-3948[1].1, p.2]
Finally, on the important issue of implementation schedule, it is clear that a delay in the CATR's effective compliance dates is necessary in order for the states and EPA to proceed responsibly considering both the law and due process. The extensive analysis of the CATR provided by EPA and others makes it plain that billions of dollars are at stake. However, the schedules included in the NODA do not allow adequate time for proper deliberation, comment and approval. Hasty implementation only risks further delay and does not in the end foster environmental progress. Xcel Energy encourages EPA to defer implementation of the CATR until 2014. This short delay will allow companies to work with state agencies, especially in situations where a state may propose an implementation plan with an alternative allocation. [EPA-HQ-OAR-2009-0491-3948[1].1, p.4]
Response: 
Thank you for your comment.
XX.A. Alternative Allocations Approaches

Organization: America's Natural Gas Alliance
Comment: 
America's Natural Gas Alliance
ANGA concurs that EPA has broad authority to design allocation methodologies under CAA Section 110(a)(2)(D)(i)(I) and the relevant definition of Federal Implementation Plan. The relevant provisions of the CAA focus on the requirement that states eliminate emissions that significantly contribute to non attainment or interfere with maintenance. They do not specify the manner in which states must achieve that goal, leaving the states with significant discretion to develop the appropriate SIP mechanism. Where, as here, EPA is developing a Federal Implementation Plan (FIP) designed to achieve the same statutory purpose, ANGA submits that the Agency similarly has significant discretion in crafting the control program. [EPA-HQ-OAR-2009-0491-3939[1].1, p.2]
As the Agency notes in the NODA, 'the definition of FIP in section 302(y) of the Act clarifies that a FIP may include 'enforceable emission limitations or other control measures, means or techniques (including economic incentives, such as marketable permits or auctions of emissions allowances)' but does not require EPA to use any particular methodology to allocate allowances under a FIP trading program.' It is apparent from this statutory language that the latitude granted to states in crafting their SIP programs to meet Section 110(a)(2)(D)(i)(I) requirements extends to the Agency where it is promulgating a FIP designed to meet the same statutory requirements. [EPA-HQ-OAR-2009-0491-3939[1].1, p.2]
ANGA also supports the manner in which the Agency would establish allocations for existing units subject to the CATR, and believes that the methodology that EPA ultimately selects should be used for all four of the CATR trading programs. [EPA-HQ-OAR-2009-0491-3939[1].1, p.2]
Where, as here, the FIP includes an allocation methodology as a critical component of that program, the Agency has discretion in the design of that methodology, provided that the methodology is 'reasonable and consistent with the goals of CAA section 1l0(a)(2)(D)(i)(I) of the Act, including improving long-term air quality and encouraging cost-effective emissions reductions.' ANGA agrees that an allocation methodology is 'consistent' with the goals of the transport provisions of the CAA where that methodology does not adversely impact the emission reduction target that the Agency has determined is necessary to abate the significant contribution/interference with maintenance. The methodologies under consideration in the CATR, including the input-based options outlined in the NODA, clearly do not: 'The methodology used to allocate allowances to individual units in a particular state has no impact on that state's budget or on the requirement that the state's emissions not exceed that budget plus variability.' [EPA-HQ-OAR-2009-0491-3939[1].1, pp.2-3]
ANGA believes that EPA should adopt a single allocation methodology for the CATR that should be applied across all four of the CATR trading programs. We do not see any legitimate rationale for utilizing different allocation schemes for any of the four different CATR trading programs. Furthermore, use of a single system is more transparent, easier to understand, and more simple to administer. [EPA-HQ-OAR-2009-0491-3939[1].1, p.4]
Response: 
EPA believes the allocation approach used in the final Transport Rule is reasonable and could be applied to all pollutants. The benefits of this approach, as described in Preamble Section VII.D., are relevant to all four trading programs. Additionally, EPA agrees with commenters that using a single allocation approach is simpler, easier to understand, and imposes a smaller administrative burden on covered sources.  Further detail on the implementation of this approach, rationale, and response to comments on the allocation method is provided in Preamble Section VII.D. as well as in the Allowance Allocation Final Rule TSD in the docket for this rulemaking.
Organization: ARIPPA
Comment: 
ARIPPA
ARIPPA recognizes and endorses EPA's efforts through the Second NODA to abandon the inaccurate and inequitable approach toward allocating unit-specific allowances based on EPA's projections of emission rates.  ARIPPA endorses the concept reflected in EPA's proposal through the Second NODA to allocate allowances based upon reported levels of historic heat input.  [EPA-HQ-OAR-2009-0491-3903[1].1, p.2]
ARIPPA also supports EPA's proposal to refine such allocations in order to avoid the provision of excess allowances to sources with actual emissions substantially below allowance allocation calculations based solely upon recorded heat input.  [EPA-HQ-OAR-2009-0491-3903[1].1, p.2]
ARIPPA endorses EPA's statements in support of an allocation methodology based upon established heat input for affected sources, and that constrains individual allocations to prevent any source from receiving a "windfall"  of allowances.  However, in reviewing the Second NODA, it does not appear that EPA has fully implemented this conceptual methodology in its specific proposed allocation schemes.  Most significantly, the information provided by EPA within the Second NODA and related documents does not clearly demonstrate the manner in which EPA implemented the concept of a heat input-based allocation in the calculation of unit-specific allocations under the Second NODA, particularly with respect to the second phase of allocations commencing in 2014.  In addition, in reviewing EPA's discussion of the implementation of the allocation methodology, as applied to specific allocation calculations, as well as the numeric results of EPA's calculations, it does not appear that EPA adequately constrained all unit-specific allocations to the extent necessary to avoid a windfall of allowances in certain cases.  In any event, because of the limited detail and clarity included within the Second NODA concerning EPA's proposed implementation of the allocation methods, it is not possible for ARIPPA to effectively comment on EPA's specific implementation of the proposed approach.  Therefore, ARIPPA supports the conceptual approach toward allocation methodology identified in the Second NODA, based upon established heat input allocation and a proposed cap on maximum allowance allocations, but cannot effectively comment on nor specifically endorse EPA's proposed implementation of that conceptual method.    [EPA-HQ-OAR-2009-0491-3903[1].1, p.5]
EPA's proposal through the Second NODA to base these allocations on established heat input represents an important positive step in this context, but is not itself sufficient for all sources.  EPA's guiding principles would require that the allocation also consider the emission rate reasonably achievable by each EGU source category through application of cost effective controls. [EPA-HQ-OAR-2009-0491-3903[1].1, p.11]       
For the ARIPPA facilities, SO2 emissions from coal refuse-fired CFBs are cost effectively controlled through the introduction into the combustion bed of an appropriate amount of limestone.  The resultant SO2 emission rates are higher than can be achieved by the cost effective application of scrubbing technology to traditional coal-fired PC units.  Therefore, EPA's allocation methodology should calculate allowance levels for coal refuse-fired CFBs that are consistent with the emission rate achieved through the application of the cost effective sulfur dioxide emission control technique for this source type. [EPA-HQ-OAR-2009-0491-3903[1].1, p.11]
In summary, although EPA should base its allocation of allowances under the Proposed Transport Rule based on established heat input rates as proposed through the Second NODA, the allocation calculus under the Proposed Rule must also recognize material distinctions in relevant characteristics of EGU source categories, to the extent that such characteristics dictate different emission rates resulting from the application of cost effective controls for that source category. [EPA-HQ-OAR-2009-0491-3903[1].1, pp.11-12]
As fully detailed above, ARIPPA supports several of the key concepts reflected in the Second NODA.  Notably, ARIPPA concurs with EPA that allowance allocations should be based upon established heat input for affected sources, rather than projections of future emissions which rely on inaccurate modeling using numerous assumptions.   [EPA-HQ-OAR-2009-0491-3903[1].1, p.15]
Response: 
Thank you for your comment.

Organization: City of Tallahasse
Comment: 
City of Tallahasse
The City strongly supports the use of historic heat input based data as the basis for allowance allocations as opposed to EPA's original allowance allocation that was initially proposed. The City believes that this approach is much more representative of actual operation of its assets, with some exceptions. The use of historic heat input eliminates what could be construed as arbitrary and capricious allocations under EPA's original allocation proposal. [EPA-HQ-OAR-2009-0491-3912[1].1, p.2]
The original allocation proposal provided a huge disincentive for companies to enact positive environmental benefits before regulatory mandates. [EPA-HQ-OAR-2009-0491-3912[1].1, p.3]
To correct this inequity, the City proposes three possible addendums to the alternative methodologies above:
1. In the case where a utility retires and then repowers a unit, allow the use of heat input data from the retired unit's operation that occurs during the multi-year look back before the replacement unit begins operation. (For the City of Tallahassee, Hopkins unit 2 operated during the look back with the following annual heat inputs:
2006 7,013,118.0 mmBtu
2007 5,575,851.0 mmBtu
2008 (1St Q only) 799,762.0 mmBtu; or
2. If a unit does not have three years of operation during the 2005-2009 timeframe, use the year with the highest annual heat input as the average. (In the case presented above, that would mean the year 2009, in which Unit 2A operated for the entire year.); or
3. Weight the annual heat input appropriately to account for partial operation in anyone year during the look back, in the calculation of the average annual heat input. This would more accurately reflect the actual operation of that unit. [EPA-HQ-OAR-2009-0491-3912[1].1, p.4]
Response: 
Under the final Transport Rule, units that are repowered (e.g. switched from coal fired to natural gas fired) and still reporting as the same unit would continue to receive the same allocation as prior to repowering.
For the rationale and more information on how allocations are determined based on historic heat-input, please see Preamble Section VII.D.1.c and the Allowance Allocation Final Rule TSD
Organization: Cleco Corporation
Comment: 
Cleco Corporation
IV. Comments on Allocation Methods and Related Issues.
If EPA insists on bypassing states and imposing a FIP (or otherwise suggests allocation methods for states to use), we believe allocations must be well-grounded in historical emissions data. [EPA-HQ-OAR-2009-0491-4007[1].1, p.3]
An emission-based allocation method similar to the method EPA articulated in the proposed Transport Rule is the most equitable approach. EPA should use that method but adjust it to look back at each unit's proportionate share of historical emissions over a three-year period (not including years where the economic downturn significantly impacted energy demand) and abandon all reliance on projected data. [EPA-HQ-OAR-2009-0491-4007[1].1, p.4]
B. To the extent EPA uses heat-input as the basis for allocations, it should use an improved emission constraint.
If EPA uses a heat-input based allocation method it must include an emission constraint that eliminates the windfall profits to certain generators. [EPA-HQ-OAR-2009-0491-4007[1].1, p.4]
C. EPA should not use heat-input to allocate SO2 allowances.
In NODA3, EPA seeks comment on whether it may be appropriate to use different allocation methods for the different trading programs. We believe that the improved proposed Transport Rule method, which does not rely on projected data and involves a longer baseline period (discussed in Section IV.A above), is most equitable and appropriate for all programs. Both NODA3 heat input methods lead to windfall allocations under all programs and the improved proposed Transport Rule method discussed above avoids that windfall. That said, if EPA chooses to use a heat-input method, e.g., the NODA3 methods, they should limit that allocation method to NOx allocations. Again, the windfall is troublesome for both the NOx and SO2 programs. But the windfall is more significant for the SO2 programs and less equitable, because natural gas units emit almost no SO2 and can do nothing to control for SO2. This final point is particularly significant given that a primary purpose of cap-and-trade programs is to incentivize the desired behavior  -  in this case emission reductions. If natural gas units can do nothing to reduce SO2 emissions then there is no conduct to incentivize. Accordingly, if EPA refuses to use the improved proposed Transport Rule method discussed above, it would, in the face of that refusal, be appropriate to use different allocation methods for the different programs. [EPA-HQ-OAR-2009-0491-4007[1].1, p.5]
D. EPA should allocate to new units in a manner that is consistent with its allocation to existing units. [EPA-HQ-OAR-2009-0491-4007[1].1, p.5]
In NODA-3 Options 1 and 2, EPA proposes to allocate allowances to existing units (online by January 1, 2009) based on heat-input. It would then allocate to new units (online after January 1, 2009) based on emissions (as explained in the proposed Transport Rule). This leads to unjustified discrepancies in how similar units would be treated. If EPA uses heat-input based allocations for existing units then it must use a consistent heat-input basis for new unit allocations. [EPA-HQ-OAR-2009-0491-4007[1].1, pp.5-6]
If EPA presses on without taking the time to assure it meets the legal requirements of fair notice and Clean Air Act federalism, we encourage EPA to offer states various options for unit level allocations. Those options should be grounded in reality, which is to say they should be based on reported historical emissions over a meaningful baseline period. [EPA-HQ-OAR-2009-0491-4007[1].1, p.7]
Response: 
Thank you for your comment.

Organization: Connecticut Department of Environmental Protection
Comment: 
Connecticut Department of Environmental Protection
Allocation methodologies and goals of Clean Air Act (CAA) section 110(a)(2)(D)(i)(I)
At 76 FR 1114 EPA claims:
'Regardless of the allocation methodology used, all emissions in each covered state that significantly contribute to nonattainment or interfere with maintenance in another state will be prohibited. In sum, the allocation methodology has no impact on the rule's ability to satisfy the statutory mandate of CAA section i10(a)(2)(D)(i)(I) to eliminate significant contribution and interference with maintenance in downwind states.' [EPA-HQ-OAR-2009-0491-3884[1].1, p.2]
EPA's claim is not entirely supported in all circumstances. For example, a geographically large state, such as New York, is upwind of Connecticut, a much smaller state that is most impacted by emissions from the greater New York City metropolitan area on high ozone days due :to wind direction and other factors. Two different allocation methodologies could result in large differences in emissions from the sources in the upwind corner of the larger state, with corresponding differences in impacts on the smaller state - potentially 'not eliminating significant contribution'. This is especially the case for sources located near state borders. EPA should ensure that any allocation methods chosen by states don't result in unintended consequences with respect to CAA section 110(a)(2)(D)(i)(I). [EPA-HQ-OAR-2009-0491-3884[1].1, p.2]
Response: 
--------------------------------------------------------------------------------
EPA disagrees that different allocation methodologies would result in a large difference in the location of emissions because each unit faces the same costs to emit a ton of pollution regardless of allocation (using an allowance to cover a ton of emission has an opportunity cost equal to the payment the unit would receive if it sold the allowance), as discussed in the Allowance Allocation Final Rule TSD.

Organization: Consolidated Edison Company of New York, Inc, (CECONY)
Comment: 
Consolidated Edison Company of New York, Inc, (CECONY)
If, however, EPA determines that the 74th Street Steam Station units are subject to the CATR, the Company requests that EPA ensure a sufficient allocation of allowances for these units based on historic heat input as currently provided under Options I and 2 of the NODA, described at 76 Fed. Register 1114-15. [EPA-HQ-OAR-2009-0491-3910[1].1, p.3]
Response: 
Thank you for your comment.
Organization: DTE Energy
Comment: 
DTE Energy
DTE Energy does object to the EPA distribution of S02 allocations to non-emitting sources. The various EPA proposed methods all allocate S02 proportionally across all affected units in each state. EPA has previously attempted to determine contribution from each state as a result of S02 emissions from each state. After using this determination to set an S02 budget for each state, it is only appropriate to allocate only to the sources that emit S02, EPA states that '[f]or the majority of units, the historic heat input-based allocation will not be sufficient to cover historic emission levels'. For this reason, it is even more critical for EPA to provide those allocations only to sources with S02 emissions. To provide to gas-fired sources with S02 allocations is clear preferential treatment by EPA for a specific fuel, something EPA has said it did not intend. Gas-fired sources should not receive S02 allocations. [EPA-HQ-OAR-2009-0491-3932[1].1, p.2]
Response: 
Thank you for your comment.
Organization: Duke Energy
Comment: 
Duke Energy
EPA requests comment on whether the allocation methodology chosen for each of the four trading programs must be the same or whether it would be reasonable to allocate using different methodologies for the different programs. Duke Energy does not see a reason why the allocation methodologies used for NOx and SO2 must be the same. In fact, because of the significantly differing SO2 emission characteristics among the affected units that result from the widely differing sulfur contents of coal and oil and natural gas, Duke Energy believes there is ample justification for using different allocation methodologies for SO2 and NOx to appropriately account for these differences. [EPA-HQ-OAR-2009-0491-3965[1].1, pp.10-11]
Response: 
Further detail on the implementation of this approach, rationale, and response to comments on the allocation method is provided in Preamble Section VII.D. as well as in the Allowance Allocation Final Rule TSD in the docket for this rulemaking.
Organization: Dynegy, Inc.
Comment: 
Dynegy, Inc.
Dynegy supports a consistent allocation approach for the four Transport Rule trading programs. A consistent allocation approach for all of the programs maximizes fairness, simplicity, case in understanding of the regulation by affected sources, and legality of the trading programs. In contrast, different allocation approaches for one or more of the Transport Rule trading programs would likely favor certain sources without any rational policy justification in terms of the requirements and goals of Clean Air Act Section 110(a)(2)(D)(i)(I). [EPA-HQ-OAR-2009-0491-3944[1].1, p.3]
Response: 
Thank you for your comment.

Organization: EquiPower Resources Corp.
Comment: 
EquiPower Resources Corp.
EPA should codify states' existing approaches to unit-level allocations and allow for periodic re-allocations. [EPA-HQ-OAR-2009-0491-3928[1].1, p.3]
EquiPower submits that if EPA declines to provide states the opportunity to implement the Transport Rule directly through SIPs, EPA should codify states' existing approaches to unit-level allocations (methods states have used to allocate allowances under CAIR and the NOx SIP Call). This would be the preferable approach to unit-level allocations as it would maintain the integrity of what states have already done and it would avoid the disruption of radical changes to allocation methodology. This is particularly true for Connecticut, Massachusetts and New Jersey since they adopted output-based allocations and EGUs in those states have invested in control technology based upon that methodology. [EPA-HQ-OAR-2009-0491-3928[1].1, pp.13-14]
Similarly, the allocation methodologies utilized in other states likely take into account state policy goals and state-specific considerations. Thus, EPA should codify these state approaches. [EPA-HQ-OAR-2009-0491-3928[1].1, p.14]
Response: 
EPA notes that the CAIR SIPs were developed under a rule that was remanded by the Court. They remained in force for the limited purpose allowed by the Court, that is to achieve interim reductions until EPA promulgated a rule to replace CAIR.  Furthermore, states may not want to adopt the same allocation methodology they had under CAIR, given differences in the new Transport Rule. Please see Preamble Section IV.C.2 and section III.A. of this RTC for a discussion of EPA's authority to promulgate the FIPs in this final rule.
Organization: Exelon
Comment: 
Exelon
Exelon commends EPA for considering one of the improvements to the proposed Transport Rule that Exelon and other Clean Energy Group companies suggested, namely an allocation based on historic heat input, and is pleased that EPA has appropriately allocated allowances to Exelon's fossil fuel fired facilities using that method. [EPA-HQ-OAR-2009-0491-3919[1].1, pp.2-3]
Exelon is pleased that EPA is considering a method for the initial allocation of pollution allowances using historic heat input, as suggested in Exelon's Original Comments. Original Comments at 24-26, 30-42. Use of historic heat input will result in an allocation of allowances that will be less vulnerable to challenge, since such allocations are based on recent historic operating data and not upon the results of a forward looking model (IPM) that does not always properly calculate future year unit-level operations (particularly for generating units that provide system reliability and balancing services beyond basic energy). [EPA-HQ-OAR-2009-0491-3919[1].1, p.4]
Use of historic heat input is more consistent with the method used for calculating allocations in connection with prior trading programs, most notably the Ozone Transport Commission's ("OTC") original NOx trading program and the NOx Budget Trading Program under the NOx SIP Call. Use of historic heat input also results in a fairer allocation of allowances that will reward those who have previously taken action to reduce emissions, whether by closing and replacing older plants or by installing control equipment. Allowances have monetary value. Under the original proposed methodology, an owner who invested capital in pollution control equipment would receive fewer allowances and less value than an owner who had not installed control equipment on a similar EGU. [EPA-HQ-OAR-2009-0491-3919[1].1, pp.4-5]
If allowance allocations were to be updated in future years, even if based on heat input, there would be a perverse incentive to keep older plants with higher pollution outputs operating to generate allowances. [EPA-HQ-OAR-2009-0491-3919[1].1, p.5]
Response: 
EPA believes that the unit-level allocation method proposed is reasonable and that periodic updating of unit-level allocations is not necessary for the final Transport Rule.
Organization: Exxon Mobil Corporation
Comment: 
Exxon Mobil Corporation
9. State allocation of allowance options- We support both the State allocation of allowance options EPA describes at FR 1119, where EPA notes that comments on the proposed CATR suggested that EPA provide state options similar to the two alternatives provided to states by EPA in the CAIR trading programs. We support EPA providing States the flexibility to choose how to participate. Our experience indicates that state agencies can work well with covered units to determine allocations that may result in improved allocation methods. A state can also better address special economic, historic operations, and electric reliability, electrical distribution, and cost distribution circumstances among Utilities and local areas via a state allocation program. We request that EPA develop timing that allows a state that wishes to choose this option to do so the first year of the CATR program operation. [EPA-HQ-OAR-2009-0491-3999[1].1, p.3]
Response: 
Preamble Section VII.C and section III.A. of this RTC explain EPA's obligation to promulgate the FIPs in this rule. 
Organization: GenOn Energy, Inc.
Comment: 
GenOn Energy, Inc.
EPA should not ignore the actual emissions from natural gas-fired plants in developing the allocation scheme. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 8]
As EPA develops the allocation schemes for the final Transport Rule, it should also consider the differences in the well-controlled NOx emission rates for different types of EGUs. Selective catalytic reduction (SCR) has been recognized as the best available control technology for reducing NOx emissions from virtually all types of fossil fuel generating plants, but this technology achieves different emission rates for coal-fired, gas-fired, and oil-fired units. If EPA uses some version of option 2, it should take this fact into account in developing the final allocation scheme for annual and ozone season NOx allowances. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 8]
EPA believes it has 'significant discretion' to implement alternative allocation methods under the Clean Air Act. 76 Fed. Reg. 1109, 1113. It is true that, under the Clean Air Act, states have broad discretion in determining how to allocate the burden of reducing emissions. In interpreting the CAA, the Supreme Court has specifically stated: Congress plainly left with the States, so long as the national standards were met, the power to determine which sources would be burdened by regulation and to what extent. Union Electric Company v. EPA, 427 U.S. 246, 269 (1976) [EPA-HQ-OAR-2009-0491-3996[1].1, p. 8]
However, EPA does not simply step into the shoes of the state and cannot allocate the burden in any fashion of its choosing. Although the Agency may have some discretion in distributing allowances, it cannot exercise this discretion arbitrarily and must provide a defensible rationale for choosing an allocation method.  [EPA-HQ-OAR-2009-0491-3996[1].1, p. 8]
Response: 
Thank you for your comment.Organization: Gulf Coast Lignite Coalition
Comment: 
Gulf Coast Lignite Coalition
GCLC requests that the EPA factor in necessary characteristics of combustion type and fuel type, including subcategories of coal.
EPA's proposed NODA and allocation methodologies should factor in combustion technology and fuel type, particularly subcategories of fuel such as coal. Coal must be given equal treatment with other fuel sources, and lignite must be properly subcategorized within any proposed performance standards or emission guidelines. [EPA-HQ-OAR-2009-0491-3963[1].1, p.4]
Response: 
Thank you for your comment.Organization: Hoosier Rural Electric Cooperative
Comment: 
Hoosier Rural Electric Cooperative
It is also very difficult to comment on the merits of the allocations without knowing the available venues for trading.  One would look at all options differently based on whether intrastate or nearby interstate trading is permissible.  [EPA-HQ-OAR-2009-0491-3927[1].1, p.2]
In conclusion, Hoosier Energy REC, Inc. cannot support any of the allocation options proposed in the original CATR rulemaking as well as those allowance allocation options proposed in this NODA III.  Hoosier Energy believes that a more fair and equitable system, taking into account, fuel type and plant type, could be used to propose allowance allocations that are more representative of the current EUG landscape. [EPA-HQ-OAR-2009-0491-3927[1].1, p.2]
Response: 
Thank you for your comment.Organization: Lakeland Electric
Comment: 
Lakeland Electric
Therefore, if this regulation is finalized as proposed with either Option 1 or Option 2, Unit 3 will be restricted on how many hours it can run in any given year. Such a restriction will certainly affect Florida's electric power supply reliability. Unit 3 began operation in 1982, therefore, its age is approximately 30 years old. As it appears that Unit 3 may have to be shut down or operate only part of the year to comply with the Transport Rule under either Option 1 or 2, one can infer that many older coal units will have to do the same, at least temporarily if not permanently, to stay in compliance for the 2012 deadline. According to the below table published in this January's Power Engineering Magazine which cites the Edison Electric Institute as its source, coal units older than 30 years of age account for 66% of the total coal generation in the Unites States. Because this will surely affect units that are 21-30 years of age also, of which Unit 3 falls into this category, if we factor those units into the total coal generation equation, we see that coal units which are older than 21 years of age account for 95% of the total coal power generation in the United States. Now, the Transport Rule directly affects only 31 states plus the District of Columbia, so these percentages are not completely precise, however, a large percentage of the older coal units are east of the Mississippi, and will therefore be regulated under this Rule. [EPA-HQ-OAR-2009-0491-3892[1].1, p.2]
3) How many and which units does EPA believe will have to execute major modifications or shut down or operate at reduced load, even temporarily, to meet the emission limits under either option proposed? [EPA-HQ-OAR-2009-0491-3892[1].1, p.6]
We would like to finish our comment by stating that Unit 3 is our highest capacity generating unit in our system, and the shutting down or derating of this Unit will mean severe economic harm to our Utility and Lakeland customers. Unit 3 was built with and has been running a scrubber since its inception in 1982 along with an electrostatic precipitator and now operates a selective catalytic reduction system, ultra low NOx burners, and an overfire air system to reduce pollutants. Because it is obvious that Unit 3 does not have enough allowances to operate in its current state, we can't help but feel that we are being punished for adding pollution control devices and running a clean unit before this regulation was proposed. [EPA-HQ-OAR-2009-0491-3892[1].1, p.6]
Response: 
Chapter 7 of the Regulatory Impact Analysis for the Federal Transport Rule details the impact on the electricity sector, including the number of controls projected to be installed by 2014. EPA also notes that in performing its modeling of the final Transport Rule, it assumed that most SO2 emission reductions in 2012 would come from running existing controls, including dispatchable controls that would not be run in the Transport Rule base case, and by units burning lower sulfur coal. Finally, EPA notes that units have a variety of compliance options, including running dispatchable controls, installing new emission controls, fuel switching, and buying and banking allowances.
Organization: Louisiana Chemical Association (LCA)
Comment: 
Louisiana Chemical Association (LCA)
5. LCA does not support use of different methodologies to make CATR. allocations for different pollutants. The methodology should be consistent across trading programs. [EPA-HQ-OAR-2009-0491-4027, p. 6]
Response: 
Thank you for your comment.
Organization: Manitowoc Public Utilities (MPU)
Santee Cooper
Buckeye Power, Inc.
Forest County Potawatomi Community
Alliance to Save Energy
Alliance for Industrial Efficiency
United States Clean Heat & Power Association (USCHPA)
Cogen Technologies Linden Venture, LP
Independence Power & Light (IPL)
Tenaska, Inc.
Comment: 
Alliance for Industrial Efficiency
Instead, we urge EPA to adopt an output-based alternative allocation formula, which would help benefit WHR and CHP. Reducing energy demand through these investments would not only reduce NOx emissions from power plants, but also reduce compliance costs of the rule. What's more, output-based standards do not favor any particular emissions controls  -  one of EPA's stated goals in the NODA. [EPA-HQ-OAR-2009-0491-3941[1].1, p.3]
Alliance to Save Energy
The Alliance questions why EPA has not pursued emissions allocations on an output basis instead of on a heat-input basis. As the EPA itself recognizes, output-based emissions regulation provides greater incentives for pollution prevention, energy efficiency, and emissions reduction than do traditional input-based emissions regulations. (See, for instance, EPA Combined Heat and Power Output-Based Regulations web page at http://www.epa.gov/chp/state-policy/output.html and the linked 'Output-Based Environmental Regulations Factsheet' and 'Output-Based Regulations: A Handbook for Air Regulators' documents.) [EPA-HQ-OAR-2009-0491-3926[1].1, p.3]
The EPA and some states have adopted output-based emissions regulations in a number of cases. For example, the New Source Performance Standard (NSPS) for Electric Utility Steam Generating Units (40 CFR 60.40Da et seq.) includes an output-based emissions standard for mercury (Sec. 60.45Da Standard for mercury), and output-based standards are an option for several criteria pollutants (particulate matter, sulfur dioxide, and nitrogen oxides). The aforementioned 'Output-Based Environmental Regulations Factsheet' notes twelve states that have output-based emissions regulations, including four that recognize non-electricity thermal output, such as from combined heat and power systems. [EPA-HQ-OAR-2009-0491-3926[1].1, pp.3-4]
Buckeye Power, Inc.
While the CATR remains flawed for all the reasons set forth in these and Buckeye's prior comments, Buckeye supports the use of historic heat input as the basis for any emissions allocation scheme. [EPA-HQ-OAR-2009-0491-3900[1].1, p.2]
Using historic actual emissions as the basis for allowances punishes early adopters of emission controls. Obviously, baseline emissions will be lower for units equipped with pollution controls. EPA's original proposed CATR approach would penalize that facility by allocating to it fewer allowances. Moreover, EPA's original approach, which essentially required additional control from units that had already installed state-of-the-art Best Available Control Technology, raised issues of technical infeasibility, which in tum would require the purchase of offsets, if available, for the cleanest units in the country. This approach would force proactive companies to essentially subsidize the installation of control technology on facilities that were not proactive, rewarding such late-comers not only with the delayed costs of emission reductions, but also with subsidies in the form of allocations that could be sold by facilities that chose to procrastinate. This approach is antithetical to the goals, purpose, and spirit of the Clean Air Act. Conversely, a heat input approach, unlike an emissions-based approach, would eliminate perpetual allocations to the highest emitting units, and does not punish consumers who have paid for investments in emission control equipment, thereby effectuating a rational policy. Historic heat input data are emissions control-neutral and thus do not punish, through reduced allocations, units that have installed pollution control technology. [EPA-HQ-OAR-2009-0491-3900[1].1, p.2]
Furthermore, as indicated in the voluminous commerits submitted to date, historic heat input data are more likely to be accurate at a unit-level than projected unit-level emission and generally are based on quality-assured data reported by sources from continuous monitoring systems. [EPA-HQ-OAR-2009-0491-3900[1].1, p.2]
As EPA notes, the Clean Air Act provides the Agency with discretion to select an appropriate allocation methodology that meets the objective of curtailing emissions that significantly contribute to exceedences of a national ambient air quality standard or interfere with maintenance thereof. Neither the Act nor the court's opinion in North Carolina v. EPA specifies a particular methodology that EPA must use to allocate emissions. Buckeye concurs with EPA's determination that an allocation methodology based on historic heat input data meets the Clean Air Act's requirements. [EPA-HQ-OAR-2009-0491-3900[1].1, p.3]
EPA's now-contemplated historic heat input-based allocation methodology furthers sound public policy: The initial allocation of allowances under each state budget to existing units will yield a distribution of allowances putting relatively greater burden on the higher-emission-rate units to reduce emissions or purchase additional allowances. This pattern would result because heat input-based allocations would provide the same share of allowances to units with the same heat input even though the higher-emissions-rate units would require more allowances in order to cover their emissions than would lower-emission-rate units. Fairness would dictate that because higher-emission-rate units generally are responsible for a disproportionate share of state's total emissions, such units should bear a higher burden than well-controlled units. [EPA-HQ-OAR-2009-0491-3900[1].1, p.3]
Cogen Technologies Linden Venture, LP
Linden Cogen continues to believe, as suggested by our October 1, 2010 Comments, that an allocation methodology based on historical reported emissions data, as augmented by assumptions about operation of existing and planned controls, would also represent a sound approach. Id. [EPA-HQ-OAR-2009-0491-3938[1].1, p.3]
As discussed in our October 1, 2010 comments, Linden Cogen would also support the use of historic emissions data as the basis of the Transport Rule allowance allocation methodology. [EPA-HQ-OAR-2009-0491-3938[1].1, p.5]
Forest County Potawatomi Community
EPA has requested comment on proposed alternative allocation methodologies based on historic heat input to EGUs. 76 Fed. Reg. 1116. FCPC strongly supports EPA's potential use of the heat input allocation methodologies, as opposed to the originally proposed methodology based on projected source emissions. As EPA notes, use of the alternative allocation methodology is substantially preferable to the original methodology because (1) historic heat input data are fuel neutral and (2) historic heat input data are emissions-control-neutral. Moreover, determining allowances based on heat input - rather than projected emissions - will encourage more efficient power generation and the use of cleaner fuels, and does not punish units that installed or plan to install pollution control technology by reducing their allocation. [EPA-HQ-OAR-2009-0491-3882[1].1, p.3]
In addition, a heat-input-based methodology helps to avoid over-allocations to sources based on overly generous emissions projections, which might allow dirty sources to stay dirty or provide them with a windfall for relatively cheap pollution reductions. As EPA noted during the tribal consultation, there is a significant risk of over allocation under the original method, since the allocations are based upon EPA's best guesses of source emissions. For example, the Blount Street facility in Madison, Wisconsin was allocated over 9,000 tons of 802 for 2012 under the original method, even though its Wisconsin Department of Natural Resources emissions inventory report shows approximately 400 tons of S02 emissions in 2009. Since owners of EGUs do not have an incentive to correct EPA when it overestimates the EGUs emissions, and since EPA likely does not have the resources to confirm every EGUs emissions, it is critical that EPA avoid over-allocation problems by utilizing a heat-input based methodology rather than its originally proposed methodology. [EPA-HQ-OAR-2009-0491-3882[1].1, p.3]
Overall, the alternative allocation methodology should provide stronger incentives for the heaviest-polluting sources to reduce harmful emissions, benefiting not only downwind areas but also the local communities near those sources. Therefore, an allocation methodology based on heat input will better promote the mandate of Clean Air Act section 110(a)(2)(D)(i)(I), which prohibits sources from contributing significantly to nonattainment of air quality standards in other states. [EPA-HQ-OAR-2009-0491-3882[1].1, p.3]
Though FCPC strongly supports the use of a heat-input-based allocation, as opposed to the original allocation method, an allocation based on historic energy output would be more efficient yet. EPA should consider an allocation methodology based on historic energy output, which would go even farther in rewarding units which have clean fuels, efficient energy production, and effective pollution control technology. [EPA-HQ-OAR-2009-0491-3882[1].1, p.4]
Independence Power & Light (IPL)
Putting aside the problem that none of the allocations methodologies proposed are reasonable for IPL and attempting to place the allocation methodologies on a more general 'reasonableness scale' shows that the use of adjusted historic and adjusted projected emissions data for development of the Original Allocation methodology appears to be a more realistic approach for an industry-wide allocation. [EPA-HQ-OAR-2009-0491-3949[1].1, p.4]
There is scant effort in the NODA to justify a shift to use of historic heat input as a basis for allocation methodologies. [EPA-HQ-OAR-2009-0491-3949[1].1, p.4]
Manitowoc Public Utilities (MPU)
MPU believes that the alternative allocation methodologies proposed for existing units are a significant improvement over the original proposed allocation scheme. [EPA-HQ-OAR-2009-0491-3918[1].1, p.2]
Santee Cooper
Santee Cooper believes that both of the heat input-based allocation formulas presented in the NODA are far superior to the proposed Transport Rule approach. [EPA-HQ-OAR-2009-0491-3913[1].1, p.2]
Tenaska, Inc.
For the reasons provided in its previous comments, Tenaska believes that heat input is a far preferable means of allocation than historical emission data. [EPA-R03-OAR-2010-1027-DRAFT-0005.1[1], p.1]
United States Clean Heat & Power Association (USCHPA)
We are very disappointed by EPA's failure to include an output-based emissions formula in the NODA. EPA acknowledges that it 'received numerous public comments' on alternative allocation approaches. While it asserts that the alternative methodologies included in the NODA 'emerge from comments that EPA received during the comment period on the proposed Transport Rule', it does not account for a wide range of comments in the docket advocating for adoption of an output-based allocation formula. (see Appendix for comment excerpts) The result is a rule that will place EPA guidance in direct conflict with energy efficiency. [EPA-HQ-OAR-2009-0491-3955[1].1, p.2]
We recommend that EPA adopt an output-based formula that considers both thermal and electric output by regulated units. By setting pollution limits based on each unit of energy produced, rather than the amount of fuel consumed, output-based standards provide greater incentives for pollution prevention, energy efficiency, and emissions reduction. This approach would reward those facilities that produce larger amounts of electricity with less NOx or SOx emissions. [EPA-HQ-OAR-2009-0491-3955[1].1, [p.2]
By allocating allowances based on electricity and thermal energy produced, the Transport Rule would create greater incentives for facilities to incorporate such efficiencies into their design, perhaps encouraging utilities to collocate near industrial sources or buildings that would be able to benefit from their thermal output. The Oak Ridge National Laboratory projects that Combined Heat and Power can provide 20 percent of US electric capacity by 2030. Deployment of CHP at this scale could lower demand for conventional power and significantly reduce compliance costs under the Transport Rule. The NODA should incorporate provisions that encourage such investments. [EPA-HQ-OAR-2009-0491-3955[1].1, p.3]
Notably, an output-based approach is also consistent with other EPA rulemakings. For instance, in the recently issued BACT Guidance, EPA expressly 'encourage[d] permitting authorities to consider establishing an output-based BACT emissions limit, or a combination of output- and input-based limits, wherever feasible and appropriate.' By likewise embracing an output-based formula for allowance allocation of permits under the Transport Rule, EPA can provide greater consistency across its rulemakings. [EPA-HQ-OAR-2009-0491-3955[1].1, p.5]
Waste Heat Recovery and Combined Heat and Power hold tremendous promise to reduce electricity demand and lower Clean Air Act compliance costs. We urge EPA to incorporate an output-based approach as an alternative allocation mechanism to help stimulate greater investment by regulated entities in energy efficiency, including WHR and CHP. [EPA-HQ-OAR-2009-0491-3955[1].1, p.5]
Response:

Thank you for your comment. 
Organization: Maryland Department of Environment (MDE)
Comment: 
Maryland Department of Environment (MDE)
b. Whether the allocation methodology must be the same for each of the four NOx/SO2 trading programs
ARMA encourages EPA to use the same methodology for all four programs, for simplicity of calculations and data tracking for sources and states. [EPA-HQ-OAR-2009-0491-3972[1].1, p.2]
Response: 
Thank you for your comment.
Organization: Massachusetts Department of Environmental Protection
Comment: 
Massachusetts Department of Environmental Protection
Furthermore, in MassDEP's comments on the proposed Transport Rule, we encouraged EPA to calculate allocations using an output-based methodology to encourage energy efficiency. We reiterate that recommendation while noting that a historic heat-input based allocation method comes closer to approximating the output-based approach that MassDEP used in CAIR. [EPA-HQ-OAR-2009-0491-4017[1].1, p.3]
Response: 
Thank you for your comment.
Organization: National Mining Association (NMA)
Comment: 
National Mining Association (NMA)
Each of these methods results in vastly different allocations for most individual units. These different allocations have substantial consequences for compliance planning and the cost of compliance for regulated entities. [EPA-HQ-OAR-2009-0491-4013[1].1, p.3]
It is difficult to accurately gauge the exact effect of these different methodologies because the Transport Rule has been a moving target, with state budgets likely to change significantly as a result of the previous two NODAs in ways that are at this point unknown. [EPA-HQ-OAR-2009-0491-4013[1].1, p.3]
The following exhibit provides summary data and analysis on the allowance allocations under EPA's three proposed unit-level allocation methods  -  the PTR Method (emissions based), Option 1 Method (heat-input based) and Option 2 Method (heat-input based with an emissions constraint). The purpose of our analysis was to compare the impact each allocation method had on electric generating units categorized based on fuel type. EPA did not provide sufficient data to efficiently and comprehensively perform that analysis. However, as an appropriate surrogate, we were able to compare the allocations base on technology class/plant type (e.g., coal-fired boilers, combined cycle units). [EPA-HQ-OAR-2009-0491-4013[1].2, p.1]
Response: 
Thank you for your comment.Organization: National Rural Electric Cooperative Association (NRECA)
Comment: 
National Rural Electric Cooperative Association (NRECA)
Based on our comments below, NRECA strongly recommends EPA develop an alternative allocation methodology that is equitable and recognizes the different emission characteristics between fossil fuels and combustion designs.   It is within EPA's regulatory discretion to develop a sensible allowance allocation methodology.  [EPA-HQ-OAR-2009-0491-3943[1].2, p.4]
In view of the obvious inequities inherent with all the allowance allocation methodologies proposed thus far, it is evident that a clear rationale has not been proposed.  NRECA believes that a better rational allocation methodology would recognize different inherent emission reduction capabilities between units considering fuel type and combustion design.  The allocation methodology should be based on emission levels that units can reasonably be expected to achieve.   [EPA-HQ-OAR-2009-0491-3943[1].2, p.9]
In the alternative, NRECA suggests that reasonably achievable emissions rates be based on fuel (coal rank, gas, oil, gas/oil duel fuel) and unit design (coal boiler, combined cycle, turbine).   [EPA-HQ-OAR-2009-0491-3943[1].2, p.9]
NRECA cannot support any of the allowance allocation options thus far presented in the CATR rulemaking process. All of the proposed options present numerous impossibilities for unit compliance, inequities and design flaws that could be largely corrected if the allocation methodology appropriately and accurately allocated allowances recognizing different emissions characteristics and reduction capabilities between categories of fuel, including coal, coal rank, gas, oil, gas/oil duel fuel and categories of unit design including coal boiler, combined cycle and combustion turbine.   Additionally, the proposed options fail to accurately reflect that many unit emission reductions required to match unit allowance allocations are not achievable by 2012.   [EPA-HQ-OAR-2009-0491-3943[1].2, p.1]
In the initially proposed CATR, EPA stated that is has broad discretion in distributing allowances, mindful that a distribution methodology cannot in effect determine states' budgets in an effort to meet Clean Air Act Section 110 objectives to address interstate air pollution. To this end, EPA indicated that allowances could be distributed based on identified groups of units having similar emissions characteristics.  For example, in the proposed CATR preamble, EPA suggested the possibility of grouping units by size, fuel type and age. NRECA agrees with EPA that it has the discretion to develop a sensible allocation methodology to reflect unit fuel and combustion design. [EPA-HQ-OAR-2009-0491-3943[1].2, pp.8-9]
These rates should be applied to provide a reasonable distribution of allowances as EPA attempted but failed to achieve under NODA option 2.  [EPA-HQ-OAR-2009-0491-3943[1].2, p.9]
Response: 
Thank you for your comment.Organization: New Jersey Department of Environmental Protection (NJDEP)
Comment: 
New Jersey Department of Environmental Protection (NJDEP)
However, the USEPA should utilize a more dynamic method similar to the one New Jersey used for the NOx Budget Program and the CAIR trading programs, which annually updates the allocation for future years based on the emissions data available from the three most recent years. All of the methods proposed by the USEPA are static in that the allocations are the same every year for the same units. This is not realistic because emissions from the affected sources change every year due to many reasons, including shutdowns,. Utilizing a dynamic method such as New Jersey's rolling three-year average provides a better match to the unit's change in dispatch. If the USEPA is concerned that a rolling average method would not provide owners and operators the certainty needed, then a schedule as in CAIR can be provided as follows: [EPA-HQ-OAR-2009-0491-3891[1].1, p.1]
-Allocations are the same for the first three years, from the initial allocation. In New Jersey for CAIR, allocations for 2009,2010, and 2011 were the same and were submitted to the USEPA by April 2007. The allocations were based on 2003,2004, and 2005 data, which were available at the time of the submittal.
-Starting with the fourth control year, allocations were submitted annually using the rolling three year method. In New Jersey for CAIR, the allocations for 2012 were submitted in 2008 based on data from 2005 through 2007. 2013 allocations were submitted in 2009 based on data from 2006 through 2008. A schedule like this where companies are allocated four years in advance will provide plenty of certainty. Also, because the calculation method was publicly available, companies can produce their own estimation of the number of allowances they may receive. [EPA-HQ-OAR-2009-0491-3891[1].1, p.2]
The specifics on the calculations used for the rolling three year method is in the New Jersey CAIR NOx Trading Program Rule (NJ.A.C. 7:27-30), which was approved by the USEPA as New Jersey's abbreviated SIP for CAIR on July 3, 2007. [EPA-HQ-OAR-2009-0491-3891[1].1, p.2]
A key advantage to utilizing a dynamic allocation method is that it will allow new units to become part of the base allocation after three years worth of emissions data has been generated to be used in the allocation calculation. As new units become part of the regular pool of units and draw from the base state budget, this frees up the new unit allowances from the set-aside for future new units. Facilitating the introduction of new units is desirable to lower emissions of all air contaminants.  [EPA-HQ-OAR-2009-0491-3891[1].1, p.2]
Response: 
Thank you for your comment.Organization: NRG Energy
Comment: 
NRG Energy
 Recommended Improvements / Alternate Allocation Methodologies  -  NRG supports EPA's approach to have an independent allocation method for each pollutant and recommends that no facility receive allocations greater than its respective operating permit or state regulatory limitations.    [EPA-HQ-OAR-2009-0491-3933[1].1, p.2]
By contrast, with allocations that reflect emissions, every plant's compliance costs are buffered in a fair and comparable manner and program implementation impacts are "economically neutral." This allocation protects both investors and consumers, conserves capital needed for massive investments in emission control equipment and clean energy projects, and provides a stronger incentive to make those investments. An emission-based allocation approach achieves these objectives without sacrificing any environmental and public health benefits - in fact, it is likely to support greater benefits, because coal-fired fleet owners are disproportionately making the largest investments in clean energy technologies. [EPA-HQ-OAR-2009-0491-3933[1].1, pp.2-3]
Thus EPA can choose between two ways of achieving the same environmental benefits:  
-a fair approach that buffers the cost impact on consumers and conserves scarce private sector capital needed for clean technology investment, or  
-an unfair approach that dramatically increases costs for coal plant owners while creating pure windfalls for gas plant owners.   [EPA-HQ-OAR-2009-0491-3933[1].1, p.3]
The latter approach makes it far harder for the owners of coal plants to afford the clean technology investments our country needs. Further, as realized in Delaware, these investments support local economic recovery by providing many short term construction and engineering jobs and assuring long term jobs at each facility.  [EPA-HQ-OAR-2009-0491-3933[1].1, p.3]
While complex, we believe EPA "got it right" in its initial July 2010 program design based on using current and projected emission as a basis for allowance distribution and state budgets. The predicted allocation is technology neutral and based on known factors for current emitters including: their current emission profiles, projected profiles, and their direct contributions to downwind attainment and maintenance in current and emerging energy markets. It is aligned with current generation planning, the increasing deployment of renewables, changing markets, the depressed price of gas, and current generation planning. [EPA-HQ-OAR-2009-0491-3933[1].1, p.4]
Recommended Improvements / Alternate Allocation Methodologies  -  EPA requested comments on the application of different allocations for different groups and or programs. NRG supports EPA's approach to have an independent allocation method for each pollutant and recommends no facility receive allocations greater than their operating permit or state regulatory limitations. [EPA-HQ-OAR-2009-0491-3933[1].1, p.7]
 Improvement 1  -  EPA should consider different allocation methods for different pollutants. SO2 emissions are the result of sulfur concentrations in the fuel and NOx is formed in the combustion process predominantly from nitrogen and oxygen in the air. Because these are exclusive pollutants created differently, allocations based on applicable factors lend to approaching them independently. Allocations of SO2 allowances should, therefore, give consideration to the type of fuel, generation technology, and available compliance options. Allocations to gas units could be limited to 1 or 2 allowances (equal to their potential to emit) and the remainder divided among coal and oil generation. Another alternative is discussed in the next bullet, Improvement 2.   [EPA-HQ-OAR-2009-0491-3933[1].1, p.7]
Improvement 2  -  To better align allocations with emissions, a unit should not receive an allocation greater than its permit or regulatory limitations. This application should be based on current requirements and this information should be readily available from Title V Permits and/or NEEDS inventory. This improvement is a key component in assuring lower emitting units do not receive allocations greater than their allowable or potential emissions.   [EPA-HQ-OAR-2009-0491-3933[1].1, p.7]
EPA Question  -  Are the alternative methodologies clear and easy to understand?   In any option, no matter how simple or complex, it is important to have accurate data. It is recommended that EPA provide the revised databases and allocation tables for public review before the final rule is published.   [EPA-HQ-OAR-2009-0491-3933[1].1, p.8]
 EPA Question  -  Are these methods consistent with the goals of the CAA?  EPA's mission within the CAA is to protect human health and the environment which includes the attainment of ambient air quality standards designed to protect public health and the environment and the assurance that no state will contribute to the inability of another state to achieve or maintain attainment. We can agree with EPA's position that because higher emission rate units generally are responsible for a greater share of the states total emissions, the focus should be on these emitters and their ability to reduce emissions. Associated with this position, allocation programs should be designed around and for these facilities. However, the CAA does not include goals that penalize one sector over another, suggest economic penalties or hardship for emitters, or indicate economic windfall rewards for certain classes of emitters. Realistically, these judgments are left to energy and emissions markets. [EPA-HQ-OAR-2009-0491-3933[1].1, p.8]
 EPA Question  -  Do these alternatives yield a reasonable distribution of allowances?  By contrast, the July projected emissions method and Option 2 (with recommended improvements) better reflect emissions, and a plant's compliance costs are buffered in a fair and comparable manner. This protects both investors and consumers, conserves capital needed for massive investments in emission control equipment and clean energy projects, and provides a stronger incentive to make those investments. This maintains the proper balance in protecting health and the environment while promoting economic growth.   [EPA-HQ-OAR-2009-0491-3933[1].1, p.9] [[This comment can also be found in Section XX.A.1.b.]]
 EPA Question  -  Are these methods consistent with the goals of the CAA?  Therefore, the application of any allocation method that economically favors one source over another and acts as a transfer of wealth conduit is not in the spirit of the CAA or the CATR. Of all the options provided by EPA, only the projected emissions method greatly reduces this unintended consequence, where, in contrast, Option 1 yields the greatest economic disparity among the options.  [EPA-HQ-OAR-2009-0491-3933[1].1, pp.8-9]
 EPA Question  -  Should the same methodology be used for each of the proposed CATR programs or should a different methodology be used for one or more such trading programs?  As noted in Comment 4, different methodologies should be applied since the compliance obligations are independent and exclusive and the plant emission characteristics vary by fuel and combustion technology. Most significant is the impact on SO2 allowances distribution.   [EPA-HQ-OAR-2009-0491-3933[1].1, p.9]
Response: 
Thank you for your comment.
Organization: Old Dominion Electric Cooperative
Comment: 
Old Dominion Electric Cooperative
Based on our comments below, ODEC strongly recommends EPA develop an alternative allocation methodology that is equitable, recognizes the different emission characteristics between fossil fuels and combustion designs, and provides for reasonable and achievable emissions reductions. All of which could be accomplished within EPA regulatory discretion. [EPA-HQ-OAR-2009-0491-4004[1].1, p.2]
In view of the obvious inequities inherent with all the allowance allocation methodologies proposed thus far, it is clear that a rational one has not thus far been proposed. ODEC believes that a better, more equitable allocation methodology would recognize different inherent emission reduction capabilities between units considering fuel type and combustion design. In other words the allocation methodology should be based on well controlled emission levels based on what units can reasonably be expected to achieve. As referenced earlier in these comments, information from EPA's own database as part of the CATR rulemaking docket demonstrates the one size fits all approach does not produce sensible allowance allocations. [EPA-HQ-OAR-2009-0491-4004[1].1, p.4]
ODEC suggests reasonably achievable emissions rates be based on fuel (coal rank, gas, oil, gas/oil duel fuel) and unit design (coal boiler, combined cycle, turbine). These rates Should be applied to provide a reasonable distribution of allowances as EPA attempted but failed to achieve under the NODA option 2. [EPA-HQ-OAR-2009-0491-4004[1].1, p.5]
ODEC cannot support any of the allowance allocation options thus far presented fn the CATR rulemaking process. All of the proposed options present inequities and design flaws that could be largely corrected if the allocation methodology appropriately and accurately allocated allowances recognizing different emissions characteristics and reduction capabilities between categories of fuel (including coal, coal rank, gas, oil, gas/oil duel fuel) and unit design (including coal boiler, combined cycle and combustion turbine) such that well controlled emission levels are based on what units can reasonably be expected to achieve. Additionally, the proposed options fail to accurately reflect that many unit emission reductions required to match unit allowance allocations are not achievable by 2012. [EPA-HQ-OAR-2009-0491-4004[1].1, p.5]
Second, ODEC cannot support any of the proposed options for allowance allocations thus far proposed. [EPA-HQ-OAR-2009-0491-4004[1].1, p.2]
In the initially proposed CATR, EPA stated that it has broad discretion in distributing allowances, mindful that a distribution methodology cannot in effect determine states' budgets in effort to meet Clean Air Act Section 110 objectives to address interstate air pollution. To this end, EPA indicated that allowances could be distributed based on identified groups of units having similar emissions characteristics. For example EPA went on to suggest the possibility of grouping units by size, fuel type and age. ODEC agrees with EPA that it has the discretion to develop a sensible allocation methodology to reflect unit fuel and combustion design. [EPA-HQ-OAR-2009-0491-4004[1].1, p.4]
Response: 
Thank you for your comment.Organization: PPG Industries, Inc.
Comment: 
PPG Industries, Inc.
PPG supports the use of the two alternative heat input-based allowance allocation methodologies presented in the 2011 NODA over the allocation methodologies based on the Integrated Planning Model ('IPM') that were proposed in the initial CATR/FIP (IPM v. 3.02) or introduced in a previous September 1, 2010 NODA (IPM v. 4.10). PPG believes that the alternative allocation methodologies proposed in the 2011 NODA are superior to the IPM-based methodology originally offered by EPA. First, unlike the IPM methodology which is based upon assumptions about economic factors, projected fuel use, electrical demand and a host of other factors, and modeled emissions based upon those assumptions, the 2011 NODA alternative allocation methodologies are based upon a unit's own historic heat input data. This heat input data is quality assured data that has been reported from continuous monitoring systems or is otherwise subject to significant penalty for false reporting. As EPA indicated in the January 7, 2011 NODA, historic heat input data is 'more likely to be accurate' at a unit wide level than is modeled unit emissions. Second, historic heat input data is fuel-neutral and does not raise concerns regarding the use of fuel adjustment factors that were of concern during the CAIR rulemaking. Third, the heat input data is emissions control neutral and, therefore, does not result in reduced allocations for units that have installed, or plan to install, pollution control technology. This neutral approach is important as it does not penalize companies that have made, or plan to make, the capital investments needed to control emissions. [EPA-HQ-OAR-2009-0491-3911[1].1, p.2]
PPG notes that use of either of the heat input-based allocation options more equitably distributes the burden of compliance by placing a lesser burden on the cleaner, lower emitting units such as the two RS Cogen gas-fired combined cycle cogeneration units. A greater burden will be placed on the higher emitting, less efficient EGUS. PPG agrees that if it is demonstrated that reductions are required, these 2011 NODA heat-input based options are significantly more in line with the goals of Section 110(a)(2)(D)(i)(I) of the Clean Air Act, including improving long-term air quality and encouraging costeffective emissions reductions. PPG does not share EPA's position that the IPM-based methodologies meet these CAA goals, at least with respect to the allocations proposed by EPA in the original CATR/FIP or the September 1,2010 NODA. Those IPM-based allocations punished the cleaner, more efficient natural gas burning sources in Louisiana while favoring EGU s with greater emissions and less efficiency. [EPA-HQ-OAR-2009-0491-3911[1].1, p.2]
EPA requested comment on whether the allocation methodology chosen for each of the four trading programs (S022012, S02 2014, annual NOx, ozone season NOx) should be the same. PPG believes that the allocation methodology should be consistent across the trading programs. This promotes consistency and ease of administration. There is no logical reason to employ one methodology for one trading program, such as S02, pollutant and a different methodology for NOx. The goal of the annual S02 and annual NOx trading programs is the same - to prevent emissions form the EGUs regulated under the program from interfering with the ability of a downwind state to meet the PM2.5 NAAQS. A program that allocated S02 allowances differently than NOx allowances may interfere with this goal. Further, it would make little sense to allocate annual NOx or a basis completely different than ozone season NOx for the same set of EGUs. Such would make both allocations and planning more difficult. [EPA-HQ-OAR-2009-0491-3911[1].1, p.3]
Response: 
Thank you for your comment.

Organization: Prairie State Generating Company, LLC
Comment: 
Prairie State Generating Company, LLC
Using the alternative allocation methodology proposed in this NODA, three new coal-fired units currently constructed or being constructed in Illinois would be required to obtain their allowances from the NUSA pool. Having used 100% of the NUSA pool allowances, these units would be required to obtain additional allowances from the emissions trading market. These three units, at expected operating capacity factors and permitted emission rates, alone would consume 38% to 64% of Illinois' one year variability limit and 66% to 112% of Illinois' three year variability limit if they must obtain all of their purchased allowances from interstate trading. [EPA-HQ-OAR-2009-0491-3897[1].1, p.6]
Response: 
EPA appreciates Prairie State Generating Company's comment and has addressed the issue with the method for determining the size of the new unit set aside for the final Transport Rule. Please see Preamble Section VII.D.2. for more information on how the size of the new unit set aside is determined. 
Organization: Progress Energy Service Company
Comment: 
Progress Energy Service Company
If EPA determines that a heat input-based approach will be used for allowance allocations and that the start of the program will be prior to 2014. then Progress Energy strongly urges the Agency to provide for additional allocations - that are based on projected emissions - to units that are not yet controlled and that cannot be controlled in the time remaining prior to the start year. [EPA-HQ-OAR-2009-0491-4011[1].1, p.4]
Response: 
Thank you for your comment.
Organization: San Miguel Electric Cooperative, Inc.
Comment: 
San Miguel Electric Cooperative, Inc.
San Miguel encourages the EPA to revise the methodology for unit allocations from the proposed methods to a historically based system that will adjust for fuel type (including subcategories of coal) and type of plant design. [EPA-HQ-OAR-2009-0491-3997[1].1, p.4]
EPA's final allocation method should adjust for fuel type, including coal subcategories, and type of plant design. Coal and lignite must be given equitable treatment with the other fuel types. The allocation method used should also provide for stable low cost electricity, which will help the economy grow. [EPA-HQ-OAR-2009-0491-3997[1].1, p.4]
Response: 
Thank you for your comment.Organization: Southern Company
Comment: 
Southern Company
In the NODA3, EPA requests comment on two alternative allocation methodologies, both of which are based on the outdated proposed Transport Rule state budgets. EPA already issued new versions of NEEDS and IPM in previous NODAs that would change the overall state budgets, yet has declined to issue any updated state budgets. Without the updated state budgets and subsequent allocations, utilities cannot plan for compliance. Further, the NODA3 asks stakeholders to compare the proposed Transport Rule allocations to two new allocation methodologies. This does not lead to a meaningful comparison since the underlying data and modeling files used to establish the proposed Transport Rule allocations contain numerous errors.1 Without both the updated state budgets and updated unit-level identifications and allocations from the proposed Transport Rule, we cannot provide a meaningful comparison of the impacts of each option on our generation planning and operations. [EPA-HQ-OAR-2009-0491-3946[1].1, p.6]

1 As noted in Southern Company's comments on the NODA1, EPA failed to illustrate how the new data in NODA1 would change the state budgets and unit-level allocations. Further, EPA failed to provide enough information for stakeholders to calculate these themselves.
Response: 
As explained in the NODA, EPA was illustrating the proportion of a state's budget that units would receive, not the actual number of allowances units would receive under the final rule.
Organization: Southern IL Power Cooperative
Comment: 
Southern IL Power Cooperative
SIPC strongly recommends EPA develop an alternative allocation methodology that is equitable and recognizes the different emission characteristics between fossil fuels and combustion designs.   This could be accomplished within EPA regulatory discretion. [EPA-HQ-OAR-2009-0491-3901[1].1, p.2]
In view of the obvious inequities inherent with all the allowance allocation methodologies proposed thus far, it is clear that a proper one has not been proposed.  SIPC believes that a better, rational allocation methodology would recognize different inherent emission reduction capabilities between units considering fuel type and combustion design.  In other words, the allocation methodology should be based on well-controlled emission levels based on what units can reasonably be expected to achieve.  As shown earlier in these comments, information from EPA's own database as part of the CATR rulemaking docket demonstrates the "one size fits all" approach does not produce sensible allowance allocations. [EPA-HQ-OAR-2009-0491-3901[1].1, ,p.5]
SIPC suggests reasonably achievable emissions rates be based on fuel (coal rank, gas, oil, gas/oil duel fuel) and unit design (coal boiler, combined cycle, turbine).  These rates should be applied to provide a reasonable distribution of allowances as EPA attempted (but failed) to achieve under NODA option 2.  [EPA-HQ-OAR-2009-0491-3901[1].1, p.5]
Response: 
Thank you for your comment.Organization: State of Ohio Environmental Protection Agency (Ohio EPA)
Comment: 
State of Ohio Environmental Protection Agency (Ohio EPA)
As intended, the new allocation proposals, based upon heat input rather than actual emissions, are fuel-neutral and control-neutral in an attempt to address commenters concerns. However, they obviously create an even greater disparity between allocations for units that are controlled compared to those that are not. [EPA-HQ-OAR-2009-0491-3915[1].1, p.3]
For example:1
:: Unit 12 at Avon Lake is uncontrolled unit and owners have indicated no planned S02 control. Under the original proposal this unit would have been allocated 33,578 tons of S02 emissions in 2012. Under Option 1 of this proposal this unit will be allocated 9,582 tons and under Option 2, 10,670 tons. The highest year of s02 emissions is 38,697 (2006).
:: Unit 1 at Cardinal is controlled by an FGD (2008). Under the original proposal this unit would have been allocated 2,975 tons of 802 emissions in 2012. Under Option 1 of this proposal this unit will be allocated 10,074 tons and under Option 2, 11,218 tons. The highest year of 8\S02 emissions is 52,481 (2003 before control) while post-control S02 emissions fell to 2,688 tons in 2009 (which was the highest year of heat input between 2005 and 2009).
:: Unit 5 at Eastlake is uncontrolled and owners have indicated no planned S02 control. Under the original proposal this unit would have been allocated 31,669 tons of S02 emissions in 2012. Under Option 1 of this proposal this unit will be allocated 12,658 tons and under Option 2, 14,096 tons. The highest year of S02 emissions is 49,293 (2005).
:: Unit 1 at Gavin is controlled by an FGD. Under the original proposal this unit would have been allocated 12,877 tons of S02 emissions in 2012. Under Option 1 of this proposal this unit will be allocated 30,273 tons and under Option 2, 16,439 tons. The highest year of S02 emissions is 16,439 (2004).
:: Unit 6 at Miami Fort is uncontrolled and owners have indicated no planned S02 control. Under the original proposal this unit would have been allocated 18,718 tons of S02 emissions in 2012. Under Option 1 of this proposal this unit will be allocated 3,473 tons and under Option 2, 3,868 tons. The highest year of S02 emissions is 22,918 (2003).  [EPA-HQ-OAR-2009-0491-3915[1].1, p.3]
For many uncontrolled units, like the examples above for Avon Lake, Eastlake and Miami Fort, there is a significant shortfall in the amount of S02 allocations that will be needed. [EPA-HQ-OAR-2009-0491-3915[1].1, p.4]
As demonstrated through U.S.EPA's latest allocation approaches, Ohio remains concerned that a fair and workable method can be found when it is apparent the issue lies within the State's S02 budget itself, especially given the very short time frame for implementation. The SO2 budgets for 2012 and 2014 are just not sufficient. [EPA-HQ-OAR-2009-0491-3915[1].1, p.5]

1 While Ohio EPA focus' its examples on S02 allocations and predominantly the 2012 control period our comments apply to both S02 and NOx allocations for all control periods as similar concerns are evident in all allocations.
Response: 
For more information on how state emissions budgets were developed, please see Preamble Section VI.D and the Significant Contribution and State Emissions Budgets Final Rule TSD.
Organization: State of Wisconsin, Department of Natural Resources
Comment: 
State of Wisconsin, Department of Natural Resources
We suggest that the following modifications should be incorporated into the historic based allocation method for at least the initial set of allowances allocated to existing generation units. [EPA-HQ-OAR-2009-0491-3969[1].1, p.2]
1. The historic operating baseline should reflect the most recent years for which data is available, from 2006 through 2010. Then according to EPA's proposed method calculate the heat input baseline as the average of the three highest years.
2. Allocations should reflect the emission limitations and consent decrees that are applicable to individual generation units in 2010. In this case however, if an emission limit is in a rule or consent decree but does not come into effect until after 2010 then these limits should not apply until becoming part of the historic baseline period in updating allocations.
3. Where pollution control equipment is in place with no emission limitation, the allowance should reflect a recent maximum emission rate for that equipment from 2009 and 2010 or a floor emission rate reflecting the same standard equipment and variability in operation. This approach can also be applied to determining an appropriate emission rate for fuels that will limit potential 502 emissions such as natural gas.
4. The emission limit or rate determined in step 2 or 3 is multiplied by the maximum heat input from the baseline years to determine a maximum allowance allocation. In this case the maximum heat input should likely be the historic maximum seen in the last five years. Other options include looking at a heat input capacity consistent with EPA's capacity factor capturing 95% of sources in that source type or using the unit's actual theoretical maximum heat throughput.
5. Any allocation of allowances in excess to step 4 should be rolled back into the allocation pool and distributed to other units based on the unit's proportion of heat input from EPA's TR AM method. At this point if the allocation of allowances, based on heat input, is in excess to the maximum potential emissions for all TR Alt 1 units, then EPA might consider placing such allowances into a state compliance pool. [EPA-HQ-OAR-2009-0491-3969[1].1, p.2]
Response: 
EPA notes that it has used the best available data for its modeling and has made extensive updates to this data based on comments. For information about these updates, please see the EPA IPM v.4.10 documentation and the "Transport Rule IPM Assumptions Response to Comments" in the Appendix
EPA believes the allocation method in the final Transport Rule is reasonable. EPA notes that using heat input as a basis for allocations is fuel and control neutral.  The allocation methodology used in the final rule is based on heat input, which is not affected by consent decrees that limit emissions. For more information about the unit allocation method, please see Preamble Section VII.D. as well as in the Allowance Allocation Final Rule TSD in the docket for this rulemaking.
Organization: Texas Commission on Environmental Quality
Comment: 
Texas Commission on Environmental Quality
Because the EPA has not proposed a state annual nitrogen oxide (NOx) or sulfur dioxide budget for Texas or unit-level allocations for units in Texas that may be subject to the Transport Rule's fine particulate matter (PM2.5) trading program, the TCEQ is unable to provide meaningful comment regarding whether either alterative methodology is adequate or fair or whether allocation methodologies could or should be different for different programs (ozone season versus annual trading or interstate versus intrastate trading). [EPA-HQ-OAR-2009-0491-4030, p.4]
Should Texas be included in the Transport Rule annual trading program for PM2.5, it would have been denied reasonable notice of and the opportunity to comment on the allocation methodology selected, unit-level allocations, and state budgets. [EPA-HQ-OAR-2009-0491-4030, p.4]
Response: 
In the proposal EPA requested comment on whether Texas should be included in the Transport Rule for annual PM2.5.  EPA's analysis for the proposal showed that emissions in Texas would significantly contribute to nonattainment or interfere with maintenance of the annual PM2.5 NAAQS if Texas were not included in the rule for PM2.5.  The proposal did not include an illustrative budget for Texas or illustrative allowance allocations.  However, the budgets and allowance allocations provided in the proposal were included solely to illustrate the result of applying EPA's proposed methodology for quantifying significant contribution to the data EPA proposed to use.  EPA provided an ample opportunity for comment on this methodology and on the data, including data regarding emissions from Texas sources, used in the significant contribution analysis.  EPA received numerous comments on and corrections to Texas specific data.  The modeling conducted for the final rule demonstrates that Texas significantly contributes to nonattainment or interferes with maintenance of the annual NAAQS in another state.  EPA provided a full opportunity for comment on whether Texas should be included in the rule for annual PM2.5, as well as on the methodology and data used for the significant contribution analysis for the final rule.  EPA therefore believes its determination that Texas must be included in the rule for annual PM2.5 is a logical outgrowth of its proposal.
Regarding determination of states covered by the final Transport Rule, please see Preamble Section V. Regarding the determination of state budgets, please see Preamble Section VI. Regarding unit level allocations, please see Preamble Section VII.D.
Organization: Tri-State Generation and Transmission Association, Inc.
Comment: 
Tri-State Generation and Transmission Association, Inc.
In addition, Tri-State is concerned that any allocation methodology finalized in this rulemaking process will set a precedent for future allocation mechanisms that would be implemented in the western United States in subsequent transport rules. [EPA-HQ-OAR-2009-0491-3902[1].1, pp.1-2]
Tri-State appreciates EPAs willingness to reconsider the allocation methodology laid out in the initial proposed rule by offering two additional heat rate input based allocation methodologies for consideration. Tri-State supports the use of a heat rate input approach to calculating allowance allocations as a substantially more reasonable and technically sound approach than that set forth in the initial proposed rule, but believes that additional work is necessary to develop a still more realistic methodology that does not penalize already well controlled coal fired electric generating units. [EPA-HQ-OAR-2009-0491-3902[1].1, p.3]
Tri-State believes that new sources should receive allocations from a new source set aside as proposed in the NODA However, Tri-State believes that the new source set aside should be set at 5% and this allocation should be available to existing sources if not used after a given amount of time in any allocation period. Tri-State believes that new sources should be in the 'new source' category for a period of 3 years and then should be transferred to the existing source category once they have established a sufficient baseline of emissions. Tri-State also believes that allowances set aside for new sources should be available to existing sources if new sources do not claim them within a six to nine month period. [EPA-HQ-OAR-2009-0491-3902[1].1, p.5]
Response: 
EPA also notes it has broad authority under the Clean Air Act to choose an appropriate allocation method for the specific situation consistent with the goals of section 110(a)(2)(D)(i)(I), and chose the allocation approach for the final Transport Rule for the reasons described in Preamble Section VII.D.
Organization: we energies
Comment: 
we energies
If EPA does not recognize in its allocation method the emission reductions that have already occurred at our units, then we may end up with a shortage of allocations on a system wide basis. We oppose an emission allocation method that would provide windfall emission allocations to large baseload units that have delayed adding emission controls.  [EPA-HQ-OAR-2009-0491-3976[1].1, p.2]
We are therefore not endorsing or offering specific comments on the alternative allocation methodologies since we are unable to determine how they would ultimately impact our prior investment decisions and early emission reductions. [EPA-HQ-OAR-2009-0491-3976[1].1, p.2]
Response: 
Thank you for your comment.
Organization: West Virginia Department of Environmental Protection
Comment: 
West Virginia Department of Environmental Protection
WVDAQ believes it is reasonable to use the same allocation methodology for each of the proposed Trading Rule programs. The use of the same allocation methodology results in an reasonable distribution of allowances in all programs, and results in trading programs that are clear, straightforward and transparent. It also would be simpler and easier to administer than other alternatives. [EPA-HQ-OAR-2009-0491-4000[1].1, p.2]
Response: 
Thank you for your comment.
Organization: Xcel Energy Inc.
Comment: 
Xcel Energy Inc.
Xcel Energy believes that both of the proposed allocation methodologies in the NODA are therefore inferior to the original CATR proposal. However, we strongly encourage EPA to consider an alternative approach that would combine the positive aspects of an historic (rather than forecast) basis with a more equitable balance in allocation outcome, as discussed further below. [EPA-HQ-OAR-2009-0491-3948[1].1, p.3]
EPA should replace the previously proposed CATR allocation methodologies with an historic, emissions-based allocation methodology.
Xcel Energy proposes that the CATR emission trading programs be implemented using an emission allowance allocation based on historic emissions data. An historic emissions-based allocation mechanism simply applies EPA's original proposal to the four new programs being promulgated via the CATR, but without the model forecast element. This solution would be simpler, more certain, and more workable. Consistent with our previous comments on the CATR, we also encourage EPA to allocate based on average emissions over a three-year period selected by each entity from the years 2005-2009. Allocations should also be made to units that have been retired or repowered during this timeframe in order to reward early emissions reduction projects. The comments Xcel Energy previously submitted illustrate in greater detail the importance of this procedure in recognizing and crediting significant early reductions already achieved by the company and funded by our customers. [EPA-HQ-OAR-2009-0491-3948[1].1, p.3]
Compliance with the CATR will require extensive and costly emission reduction measures regardless of the allocation mechanism EPA pursues. Historic emissionsbased allocations enable the most efficient and cost-effective compliance strategies while achieving the environmental goals set forth in the CATR. [EPA-HQ-OAR-2009-0491-3948[1].1, p.3]
Response: 
Thank you for your comment.

XX.A.1. General Comments on the Two Alternative Allocation Methodologies

Organization: AES Corporation (AES)
Comment: 
AES Corporation (AES)
AES appreciates the ability to view the underlying data utilized to develop this rule. In this particular situation, there are numerous errors identified in the data set used. The errors are evident but we are unsure as to the mechanism to verify and repair them. If the data is to be taken from EIA, that database may need to be updated. Additionally some data is missing altogether. Some data such as heat rate is inaccurate but the source is not identified. This will change the resulting allocations. [EPA-HQ-OAR-2009-0491-4016, pp. 3-4]
Finally some of the analysis were left incomplete and thus full evaluation was not possible. Examples of the data issues above are given below. [EPA-HQ-OAR-2009-0491-4016, p. 4]
AES Recommends that a process is pursued to correct all of the underlying data assumptions, disclosure of all of the sources used to acquire the data and this final data set be allowed to comment on in whole. [EPA-HQ-OAR-2009-0491-4016, p. 4]
The "reasonably foreseeable maximum emissions" calculation should be updated with accurate information such as actual plant heat rate, historical capacity factor and best reasonably achievable emission rates. The assumed emission rates (0.06 lb/mmbtu) used for this method is sometimes not achievable due to space constraints, physical barriers, process impediments, inability to pass on costs as well as other reasons. Alternate assumed emission rates need to be allowed on a case by case basis. [EPA-HQ-OAR-2009-0491-4016, p. 4]
Response: 
Thank you for your comment.
.
Organization: America's Natural Gas Alliance
Comment: 
America's Natural Gas Alliance
ANGA is pleased to see that the Agency is considering utilizing an input-based allocation methodology, which we believe would provide incentives for utilizing cleaner, more efficient sources, such as natural gas-fired units. Historic energy heat input methods also promote the early adoption of control technologies, which would be discouraged under an emissions-based allocation. [EPA-HQ-OAR-2009-0491-3939[1].1, p.2]
As discussed further below, ANGA also believes that the input-based methodologies set forth in the NODA are consistent with broader policy goals under the CAA. [EPA-HQ-OAR-2009-0491-3939[1].1, p.3]
ANGA also agrees with EPA that historic heat input based methodology is consistent with the goals of Section 110(a)(2)(D)(i)(I). Once the Agency has identified the 'budgets' that must be met by the states to eliminate significant contribution and interference with maintenance, the methodology by which states allocate allowances to meet that budget should be reasonable and equitable. [EPA-HQ-OAR-2009-0491-3939[1].1, p.3]
If the Agency chooses to allocate allowances using an historic input-based methodology, ANGA also suggests that the Agency reverse its decision to allocate allowances to existing units once. As we suggested in our October 15th comments on the first CATR NODA, ANGA believes that it would be appropriate to periodically update allowance allocations on a going forward basis. As the benefits of power generation with natural gas lead to greater use of natural gas in the power generating sector, it is good environmental policy to periodically update the allocation of allowances, as doing so would both avoid imposing a de facto penalty on companies that s',itch to cleaner burning fuels. [EPA-HQ-OAR-2009-0491-3939[1].1, pp.3-4]
ANGA recognizes that there needs to be some degree of predictability in allowance allocation for purposes of ensuring a robust and stable allowance trading market; however, we suggest that the Agency consider updating the allocation system every three years to allow the allowance market to take into consideration modernization of the power generating sector. [EPA-HQ-OAR-2009-0491-3939[1].1, p.4]
In terms of how the Agency will use the data for each of the units subject to the CATR to establish the allocations, ANGA believes that a five-year baseline period (2005-2009) is appropriate, and agrees with the Agency that use of such a baseline period will result in 'improved representation of a unit's normal operating conditions over time.' ANGA also supports the use of an in-service cutoff date of January 1, 2009 to ensure that the Agency will have at least one full year of data for all units subject to the program when it determines the unit-by-unit allocations. Finally, taking the average of the three highest 'nonzero years' within the baseline period also serves to ensure that the allocation will be based on a unit's normal operation, and will reduce the likelihood that the allocation to an individual unit could be skewed because of abnormal operational data from any single year (such as an extended shutdown or other circumstances). [EPA-HQ-OAR-2009-0491-3939[1].1, p.4]
Response: 
Thank you for your comment.
Organization: American Electric Power
Comment: 
American Electric Power
Allowance allocation mechanisms do not affect ultimate compliance obligations under the proposed Transport Rule, but are a key factor in determining the ultimate cost of the rule to electric generators and their customers. Therefore, allocation issues are better addressed at the end of the rulemaking process, once final data is available to support state and regional budgets and there is an accurate baseline for meaningful comparison. Knowing that the emission budgets are subject to change before final rule promulgation, it is hard to fairly assess the impacts of the new allowance allocation proposals in NODA-3 on AEP and its customers. Nonetheless, we offer the following comments on the general concepts embodied in NODA-3, as well as within the initial Transport Rule proposal, but request that these allocation issues be revisited for comment after revised state and/or regional budgets are published for comment, but before rule finalization. [EPA-HQ-OAR-2009-0491-3934[1].1, p.4]
We appreciate the fact that EPA has revisited the issue of allowance allocation, as we have serious concems with the initially proposed allocation system. While allocations based on historical data have significant merit, we feel that neither option 1 nor 2 in NODA-3 are ideal choices, and would prefer other approaches. [EPA-HQ-OAR-2009-0491-3934[1].1, p.4]
The primary reason that the alternative allocation methodologies presented in NODA-3 are not preferred options for allocation is because they are based on heat input without adjusting for differences in emissions based on fuel types. Natural gas generating units do not emit S02 and therefore do not have any need for S02 allowances. Any S02 allocation to natural gas units creates a 'windfall profit' for units that will already benefit from the additional dispatch cost on coal-fired units as a result of the allowance cap. In addition, natural gas units tend to have on average lower NOx emission rates than coal-fired units. Thus, an allocation predicated strictly on heat-input without adjusting for fuel type will further burden coal-fired generation and provide a subsidy for gas-fired generation. AEP cannot support allocations based strictly on heat input without differentiation by fuel type. However, a simple remedy for this issue would be to use historic emissions instead of heat input. [EPA-HQ-OAR-2009-0491-3934[1].1, pp.4-5]
In terms of the S02 allocation options for Phase II of the Transport Rule beginning in 2014, AEP feels the NODA allocation alternatives are a somewhat positive improvement to the inequities created by the original proposed allocation methodology, but do not go quite far enough. The original methodology contained a significant downward adjustment for units which the IPM modeling results predicted would install FGD, fuel switch, re-dispatch to a lower sulfur coal, or retire. Essentially, a computer model was picking winners and losers and taking the modeling process one step too far, given the considerable uncertainty surrounding the economics of future generation planning decisions. In this case, the losers were the owners and customers of the units that incurred the costs associated with any emissions reductions (by incurring costs to install controls, requiring recovery of remaining book balances for prematurely retired plants, and/or incurring costs associated with a fuel switch or change in dispatch), and also received a significantly reduced allocation. Thus, the two alternative allocation methods in NODA-3 are somewhat better approaches to 2014 allocations, as they do not penalize units based on a modeled outcome. However, they still allocate S02 allowances to natural gas units with no compliance obligations. [EPA-HQ-OAR-2009-0491-3934[1].1, pp.5-6]
AEP recommends an alternative, simplified allocation methodology. The easiest way to equitably spread costs associated with Phase II S02 compliance is to reduce individual unit allocations from 2012 to 2014 by the same percentage decrease as the overall decrease in state budgets from 2012 to 2014. This decrease should be moderated by including an exemption for 'controlled-units' (i.e. FGD) since there is no reasonable expectation that their emissions will decline from 2012 to 2014. In this way, the cost of additional S02 reductions within the state would be shared equally among all uncontrolled units, since each uncontrolled unit within the state would receive a reduced allocation. [EPA-HQ-OAR-2009-0491-3934[1].1, p.6]
Absent the adoption of AEP's preferred approach, AEP supports NODA option 2 or NODA option lover the original allocation methodology for Phase II of the Proposed Transport Rule, particularly if the heat input-based methodologies in the NODA are adjusted for fuel types. [EPA-HQ-OAR-2009-0491-3934[1].1, p.6]
Response: 
Thank you for your comment.

Organization: Associated Electric Cooperative, Inc. (AECI)
Comment: 
Associated Electric Cooperative, Inc. (AECI)
II. In the comments submitted by AECI on October 1, 2010, we stated that the proposed Federal Implementation Plan (FIP) was premature and preemptive of the process afforded the states in section 110 of the Clean Air Act.  As such, AECI cannot support either of the allocation plans of this NODA as we believe each state should be afforded due time to distribute allowances and amend their respective state implementation plans accordingly. However, allocation tables of this NODA based on historical heat input result in more equitable distributions compared to previous versions of this proposed rule. [EPA-HQ-OAR-2009-0491-3989[1].1, p.2]
Second, AECI cannot support any of the proposed options for allowance allocations thus far proposed. In the comments submitted by AECI on October 1, 2010, we stated that the proposed Federal Implementation Plan (FIP) was premature and preemptive of the process afforded the states in section 110 of the Clean Air Act.  As such, we cannot support either of the allocation plans of this NODA as we believe each state should be afforded due time to distribute allowances and amend their respective state implementation plans accordingly. However, allocation tables of this NODA based on historical heat input result in more equitable distributions compared to previous versions of this proposed rule.  To improve further, AECI strongly recommends EPA develop an alternative allocation methodology that is equitable and recognizes the different emission characteristics between fossil fuels and combustion designs.  This could be accomplished within EPA regulatory discretion. [EPA-HQ-OAR-2009-0491-3989[1].1, p.3]
II. The CATR NODA III proposed allowance allocation methodologies:
AECI agrees with EPA is its assertion that it has "significant discretion to select an allocation methodology that is reasonable and consistent with the goals of the CAA".  CATR NODA options 1 and 2, are both gas biased. [EPA-HQ-OAR-2009-0491-3989[1].1, p.4]
Response: 
Thank you for your comment.
Organization: Association of Electric Companies of Texas (AECT)
Comment: 
Association of Electric Companies of Texas (AECT)
The Method of Required Compliance Should Not Establish 'Winners and Losers'
EPA is taking comment on the options as described in the January 7, 2011, NODA to change the state allocation as proposed on August 2,2010. State budgets should be allocated fairly among sources so as to not disadvantage any category of sources against others in achieving compliance with the CATR requirements. [EPA-HQ-OAR-2009-0491-3981[1].1, p.2]
Rather than considering proven, market-based systems to allow sources to comply effectively with the CATR (if it is adopted), the proposed allocations in this NODA would significantly alter the allocations originally proposed, and would give unfair advantage to power plants that use certain fuels and penalize those that use coal, while providing no commensurate environmental benefit for doing so. [EPA-HQ-OAR-2009-0491-3981[1].1, p.2]
Response: 
Thank you for your comment.
.
Organization: Buckeye Power, Inc.
Comment: 
Buckeye Power, Inc.
The January 7 NODA seeks comment on two alternative allocation methodologies; two variations of historic heat input-based allocations. 'Option 1' would allocate a state's existing unit emissions budget based on each unit's proportionate share of the state's total historic heat input. 'Option 2' starts with the allocation derived under Option 1, but imposes a limit on allocations premised on the calculation of a unit's 'reasonably foreseeable maximum emissions.' [EPA-HQ-OAR-2009-0491-3900[1].1, p.3]
Both Option 1 and 2 employ the three highest, non-zero annual heat input values within the five-year 2005-2009 baseline period to create a unit's 'three-year average heat input' value. Buckeye supports this approach as it minimizes the chances that a unit's ultimate allocation is skewed by operational aberrations in any single year. [EPA-HQ-OAR-2009-0491-3900[1].1, p.3]
In order to remedy the over-allocation of allowances to natural gas-fired units, and under allocation of allowances to coal-fired units, under both Option 1 and Option 2, Buckeye suggests that, under both Option 1 and Option 2, EPA need not allocate S02 emission allowances to gas fIred units. As such units typically have no need for S02 allowances, it would be reasonable and appropriate to make all of the budgeted S02 allowances available to coal and oil-fired units. Buckeye also suggests that appropriate adjustments be made to both Option 1 and Option 2 to prevent the over-allocation of NO x allowances to natural gas-fired units. [EPA-HQ-OAR-2009-0491-3900[1].1, p.5]
Response: 
Thank you for your comment.

Organization: Business Council for Sustainable Energy (BCSE)
Alliance for Industrial Efficiency
United States Clean Heat & Power Association (USCHPA)
Michigan Department of Natural Resources and Environment
Comment: 
Alliance for Industrial Efficiency
We were surprised, however, to see that the proposed Alternative Allocation formula in the NODA discriminates against energy efficiency. Instead, by relying on an outmoded fuel-input formula, EPA simply locks in historic emissions and disadvantages sources that invest in efficiency.  [EPA-HQ-OAR-2009-0491-3941[1].1, p.1]
Yet, the proposed allocation formula does not provide any additional allowances to either utilities that incorporate WHR or CHP into their processes (e.g., by collocating near a source that can use its thermal output) or to industrial sources that use WHR or CHP. [EPA-HQ-OAR-2009-0491-3941[1].1, p.2]
Thus, by focusing exclusively on fuel inputs, the proposed allocation formula disregards the thermal benefits of WHR and CHP. In short, as EPA notes: "Allocation based on heat input gives more allowances to less efficient units." An output-based allocation strategy would credit these thermal benefits  -  putting more allowances in the hands of those who use WHR and CHP. The input-based measure EPA proposes does not account for this efficiency. It ignores the thermal output and looks only at the heat input of the fuel. [EPA-HQ-OAR-2009-0491-3941[1].1, p.3]
Business Council for Sustainable Energy (BCSE)
The Council has long supported the development and use of output-based emissions regulations as effective ways to promote long-term air quality and to encourage cost-effective emissions reductions. As EPA itself has noted, output-based regulations better reward and drive energy efficiency improvements than do input-based approaches. ii The heat input-based allocation methodologies presented in the NODA would not sufficiently recognize investments made in energy efficiency. This is particularly the case for facilities employing combined heat and power (CHP) and waste heat recovery (WHR). The alternative heat input-based allocation methodologies would have the added negative effect of locking-in emissions levels for inefficient facilities. The benefits of an input-based allocation methodology presented by the NODA, in our view, do not outweigh the lost potential efficiency gains encouraged by an output-based approach to allowance allocation. [EPA-HQ-OAR-2009-0491-3985[1].1, p.1]
Michigan Department of Natural Resources and Environment
In the NODA, the EPA offers two alternative options to determine the amount of allowances for an existing source. Option 1 utilizes the historical heat inputs and establishes a baseline heat input value for each subject unit. Option 2 uses the historical heat inputs but limits the maximum emissions levels so that the units will not be allocated excess allowances. [EPA-HQ-OAR-2009-0491-3890[1].1, p.2]
The DNRE would like to offer a third option; electricity output-based allowances. The DNRE determined under CAIR that an electricity output-based allocation would reward units that are energy efficient and still reduce emissions. The DNRE utilized an output-based method in our new source set-asides for CAIR NOx allowances. Since both currently proposed options in the NODA 'create' a value to be used to determine allowances, the DNRE believes the output method would work for the TR allowances as well. The DNRE utilized an emission factor of 1.0 pounds NOx per megawatt hour of electricity generation, which is recognized by several national organizations that are proponents of energy efficiency and renewable energy, as appropriate to reward sources for operating 'cleaner' units to generate electricity. [EPA-HQ-OAR-2009-0491-3890[1].1, p.2]
United States Clean Heat & Power Association (USCHPA)
Unfortunately, the alternative allocation mechanisms elaborated in the Notice of Data Availability do little to advance energy efficiency. Notably, there is no mention of efficiency goals in the NODA. Moreover, by embracing an input-based emissions formula, the proposal discriminates against efficiency. [EPA-HQ-OAR-2009-0491-3955[1].1, p.1]
In contrast, the alternative allocation strategy included in the NODA simply locks in historic emissions levels. By allocating allowances based on heat input, the NODA focuses on the amount of fuel consumed, rather than the amount of useful electricity (and thermal energy) produced by regulated facilities. This approach eliminates incentives for greater efficiency. [EPA-HQ-OAR-2009-0491-3955[1].1, p.2]
Response: 
Thank you for your comment.

Organization: City of Ames, Iowa
Comment: 
City of Ames, Iowa
Based on the allowances granted us under options 1 & 2 our immediate ability serve our customers would be greatly restricted without triggering assurance provisions.
As a municipal utility we do not have multiple and varied resources to shift generation to minimize the impact of the allocation.
Please consider the negative impact of the revised calculation methodologies on us and possibly others small municipal entities. We believe the original allocations best represent our historic emissions and least impact us and our customers. [EPA-HQ-OAR-2009-0491-3942-cp, p.1]
Response: 
Thank you for your comment.

Organization: City of Hamilton
Comment: 
City of Hamilton
That said, Hamilton did note that methodology option one and option two (for ozone season NOx) only used heat input data from 2005-2009. However, heat input data in option two (for annual NOX and S02) uses a longer baseline, from 2003-2009. Hamilton suggests that U.S. EPA utilize a consistent data set for purposes of heat input in both options. [EPA-HQ-OAR-2009-0491-3984[1].1, p.1]
Response: 
As described in Preamble Section VII.D., EPA is using heat input data from 2006-2010 to allocate allowances under the FIPs. EPA believes that this time period provides a reasonable representative sample.
 
Organization: City of Springfield, Illinois, Office of Public Utilities
Comment: 
City of Springfield, Illinois, Office of Public Utilities
In general, CWLP supports the underlying assumption that annual Heat Inputs over a five year look-back period, as described in both Option 1 and Option 2 of the NODA, provide the best means of producing an equitable model of allowance distribution. CWLP has great misgivings on the appropriateness of the original CATR proposal, whereby the decision-making and subsequent actions of private industry is modeled and predicted by a regulatory agency for the purpose of distributing essential and valuable allowances.  [EPA-HQ-OAR-2009-0491-3885[1].1, p.2]
Likewise, as described in both Options of the NODA, CWLP supports the use of the three largest annual Heat Input numbers from the look-back period. This would adequately capture and exclude years where planned or unplanned outages would have artificially reduced the average annual heat input, and thereby reduced the pro-rated allowance allocation of the individual state's budgeted total. [EPA-HQ-OAR-2009-0491-3885[1].1,p.2]
However, USEPA should clarify that, under the Options of the NODA, the new unit allocation methodology would mirror that of the existing unit methodology. Currently, the NODA states that allowance allocation would be based upon the provisions of the original proposed CATR. [EPA-HQ-OAR-2009-0491-3885[1].1, p.2]
Response: 

The City of Springfield is correct that a different method is used to allocate allowance to new units, compared to the method used for existing units. It is reasonable to distribute allowances from the new unit set-aside to new units based on emissions because other existing regulations include emission standards for new units will require new units to be well controlled. Additionally, allocating based on emissions ensures that new units will not be allocated more allowances than they need, which ensures the most efficient distribution of new unit set-aside allowances.
Organization: City of Tallahasse
Comment: 
City of Tallahasse
Over the last ten years, the City has made significant efforts to voluntarily initiate programs to reduce their emissions of NOx, S02, PM, and Ozone. Many of these efforts were done to reduce emissions prior to the implementation of different regulatory programs that at the time had not been adopted: mandatory greenhouse gas reduction programs, regional haze, and CAIR, just to name a few. Utilities like the City, that include environmental protection in all their decision making processes often initiate voluntary reductions prior to and often without regard to future potential enactment of environmental regulations. Specifically, the City has implemented a number of major electric generating improvements that have significantly improved the efficiency and environmental profile of its two power generating facilities. These include the construction of Combined Cycle Combustion Turbine Unit No.8 at the Sam O. Purdom Electric Generating Station (ORIS Code 689), two Sprint Combustion Turbines at the Arvah B. Hopkins (ORIS Code 688) Electric Generating Station (Hopkins), and the repowering of Unit No.2 at the Hopkins Plant from a conventional steam boiler to a combined cycle unit (renamed as Unit 2A). The City has installed SCR on the two combustion turbines and the combined cycle unit at Hopkins. Had the City chosen not to do so, it would have been 'rewarded' with additional allowances that the City could bank or sell. [EPA-HQ-OAR-2009-0491-3912[1].1, p.3]
Response:

Thank you for your comment. 

Organization: Clean Energy Group
Comment: 
Clean Energy Group
While many ofour companies have long supported allocation methodologies based on energy output (megawatt-hours), the Clean Energy Group supports allocating allowances for sulfur dioxide and nitrogen oxides to units based on historic heat input as contemplated under Options 1 and 2 in the January 7 NODA. [EPA-HQ-OAR-2009-0491-4002[1].1, p.1]
As we commented on the proposed rule, historic heat input-based allocation has a number of advantages over EPA's preferred approach. Most significantly, it is not based on modeled future emissions, which, while appropriate for developing the state budgets, have known inaccuracies at the unit level. For example, units that may dispatch for non-economic purposes would not be reflected in a modeled future emissions approach, but a historic heat input-based approach will reflect such realities and be based on verified data EPA has already collected. Additionally, the Clean Energy Group agrees with the advantages of a heat input basis cited by EPA and other commenters:
:: Historic heat input data are more likely to be accurate at a unit level than projected unitlevel emissions and are generally based on quality-assured data reported by sources from continuous monitoring systems.
:: Historic heat input data are fuel-neutral.
:: Historic heat input data are emissions-control-neutral and thus do not yield reduced allocations for units that installed or are projected to install pollution control technology. [EPA-HQ-OAR-2009-0491-4002[1].1, p.2]
Using a historic heat input basis for allocation corrects the proposed methodology's disadvantage for early actors that EPA acknowledged in the proposed rule and creates the right incentives to drive additional reductions. Thus, we agree with EPA that a heat input allocation meets the goals of section 110 of the Clean Air Act - to encourage the most cost-effective emissions reductions and to drive investment in the technologies necessary to address transport and non-attainment on a long-term basis.   [EPA-HQ-OAR-2009-0491-4002[1].1, p.2]
Response: 
Thank you for your comment.

Organization: Cleco Corporation
Comment: 
Cleco Corporation
By using historical emissions as the basis for determining a unit's proportionate share of the state budget, EPA properly sets up the trading program so that all regulated units are equally incented to achieve reductions. The alternative heat-input based allocations  -  particularly Option 2, which is completely unhinged from real world emissions  -  lead to significant over- and under-allocations. These over-/under-allocations are so severe they open the door to potentially monopolistic competitive practices. Particularly if EPA chooses the intrastate trading option, natural gas sources with significant over-allocations could refuse to sell allowances and expose competitors to Clean Air Act penalties, forced curtailment or forced retirement. Additionally, given the short timeframe EPA intends to allow for an allowance market to develop, significant under-/over-allocations are likely to lead to very volatile allowance markets. Finally, there is no basis for providing windfall profits to particular owners or operators based on the type of fuel they use. [EPA-HQ-OAR-2009-0491-4007[1].1, p.4]
Response: 

For reasons explained in section VII.D. of the preamble to the final rule, EPA believes that the allocation method selected for use in the FIPs is both reasonable and appropriate for use in this rule.  The commenter's assertion that it would lead to over/under-allocation of allowances is based on their own unstated assumptions regarding the appropriate method for allocating allowances.  For reasons explained in the preamble, EPA does not agree that allowances should be allocated based on projected future allowances.  Further, Cleco Corporation does not provide any evidence for their assertion that any over/under-allocations would be so severe they would result in "monopolistic competitive practices."
Organization: CPS Energy
Comment: 
CPS Energy
CPS Energy prefers the allocation methodology in the original publication of the Transport Rule over the two methods proposed on January 7, 2011. However, CPS Energy would like to comment on the alternative allocation options (options 1 & 2). Both option 1 & 2 calculate out to lower Nitrogen Oxide (NOx) rates in units of lb/mmbtu than can be achieved by some of our units without significant modifications. The NOx rates in both options are as low as 0.08 lb/mmbtu. Although, CPS Energy has made improvements to lower NOx emissions from our units such as installing low NOx burners, neural networks, Separated Over Fire Air (SOFA) systems, and Induced Flue Gas Recirculation (IFGR) our units cannot reach the low rates of 0.08 lb/mmbtu or 0.10 lb/mmbtu without additional NOx reduction technology. The only technology available to get to those lower rates would be Selective Catalytic Reduction (SCRs). [EPA-HQ-OAR-2009-0491-3947[1].1, p.1]
Response: 
Thank you for your comment.

Organization: Dominion
Comment: 
Dominion
Improvements to Initial Proposal EPA has addressed in this NODA a number of inaccuracies we identified in our previous comments concerning heat rate information for several of our electric generating units (Brayton Point, Salem Harbor and North Branch). We believe it is important that information used in the development of regulations be as accurate as possible and appreciate EPA's inclusion of these data corrections. [EPA-HQ-OAR-2009-0491-3987[1].1, p.1]
Another issue identified in our previous comments that is addressed through this NODA is allowance allocations to oil-fired units. The alternative allocation options contained in the NODA provide allocations to oil-fired units, which did not receive allocations in the original proposal [EPA-HQ-OAR-2009-0491-3987[1].1, p.2]
Response: 
Thank you for your comment. 
Organization: DTE Energy
Comment: 
DTE Energy
EPA requests comments regarding two possible alternative methodologies for allocation of S02 and NOx emission allowances. DTE Energy would support using historical operation as the basis for allocation distribution, rather than a combination of adjusted historic and projected emissions data. Historic heat input data will more likely reflect actual unit-level operation, and therefore emissions, than projections based on general industry-wide algorithms. [EPA-HQ-OAR-2009-0491-3932[1].1, p.2]
Response: 
Thank you for your comment. 
Organization: DTE Energy Services (DTEES)
Comment: 
DTE Energy Services (DTEES)
Using historical heat input as proposed in this NODA is not appropriate for the units at DTE Stoneman because the resulting allocations do not reflect expected operation on woody biomass. This is true for Options 1 and 2. In effect, using historical heat input penalizes the facility for the timing of converting from coal-fired electricity generation to renewable energy generation combusting woody biomass. Using historical input does not allocate the number of allowances that will be needed for full utilization of the units in the future. Through the use of woody biomass, DTE Stoneman will do its share of emission reductions required to reduce interstate transport of pollutants but under the proposed allocation methodology using historic heat input the units will bear a disproportionate burden. [EPA-HQ-OAR-2009-0491-3950[1].1, p.3]
Response: 

The final rule covers fossil-fuel-fired units serving generators with a nameplate capacity greater than 25 MWe producing electricity for sale and defines "fossil-fuel-fired" as combusting any amount of fossil fuel in 2005 or later.  The commenter claimed that biomass units that switch from burning some fossil fuel to burning no fossil fuel should be exempt just as new units that never burn fossil fuel are not covered by the Transport Rule trading programs.  EPA rejects the commenter's claim.  The approach in the final rule is consistent with the approach used in prior EPA trading programs covering the electric generation industry, e.g., the Acid Rain Program, the NOx Budget Trading Program, and the CAIR trading programs.  The commenter did not provide any basis for using a different approach in the Transport Rule trading programs covering the same industry.  Moreover, the commenter essentially suggested that the determination of whether a given biomass unit is subject to the Transport Rule trading programs should not be based on any historical information on whether the unit burned any fossil fuel, but rather only on what the unit is currently burning.  This approach would mean that, for all biomass units, owners and operators, and EPA, would not know at the start of the Transport Rule trading programs, whether the units were subject to the trading programs and that the units' regulatory status could change, and the units become subject to the trading programs, at any time that any fossil fuel was combusted.  Because all biomass units would not be reporting their fuel use to EPA until they became subject to the trading programs, the determination of whether specific units were subject to the trading programs, and assurance of compliance, would be problematic.  EPA believes that its approach is reasonable: biomass units that have recently (i.e., after 2004) operated burning some fossil fuel are treated differently than new biomass units that are initially designed to operate without combusting any fossil fuel and actually operate without any fossil fuel combustion.  The units burning fossil fuel after 2004 are more likely to continue to do so.  EPA maintains that it is reasonable to make these biomass units, like any other units burning at least some fossil fuel after 2004, subject to the Transport Rule trading programs.  Similarly, EPA believes it is reasonable to treat a biomass unit that has not burned and does not burn any fossil fuel (like any other units that have not burned and do not burn) any fossil fuel as not subject to the Transport Rule trading programs, unless and until they begin burning fossil fuel.
Organization: Edison Mission Energy (EME)
Comment: 
Edison Mission Energy (EME)
While EME agrees that a re-evaluation of the methodology used to determine unit level allocations is needed and believes that states should implement the emission limitation goals of the Transport Rule through State Implementation Plans ("SIPs"), EME does not believe that the allocation methodology or the SIP provisions proposed in the Transport Rule NODA adequately address the flaws it has identified with EPA's approach to the Transport Rule. [EPA-HQ-OAR-2009-0491-3953[1].1, p.2] [[This comment can also be found in Section XX.E.]]
The heat-input approach to unit level allocations bears no rational connection to EPA's stated basis for the reductions required in Phase I -- that the emission limits represent NOx and SO2 reductions that can be obtained using existing controls already in place or that EPA believes will be installed and available by 2012. [EPA-HQ-OAR-2009-0491-3953[1].1, p.2]
Far from reflecting the status quo that is the basis for Phase I, the proposed approach would put a greater burden on units with higher-emission rates to reduce emissions despite the fact that EPA concedes that these EGUs would not be able to install new controls by 2012. There also is no assurance that they would be able to purchase allowances on the market to cover any shortfall. Thus, EPA's alternative methodologies for unit-level allocations are punitive in nature, they would improperly result in a transfer of wealth that would give some EGUs inordinate market power over EGUs who need to purchase additional allowances; and they would require EGUs with insufficient allocations to spend their limited funds on purchasing additional allowances rather than investing in the installation of control technology needed to meet required emission reductions under the Transport Rule. [EPA-HQ-OAR-2009-0491-3953-cp, pp.2-3]
EPA's proposed alternative allocation methodologies in the Transport Rule NODA, which are based on historic heat input data, bear no rational connection to EPA's stated basis for the emission reductions required by 2012 for Phase I of the Transport Rule -- the presence of existing controls. In fact, far from reflecting the status quo that is the basis for Phase I, the proposal explains that it would put a greater burden on units with higher emission rates to reduce emissions. EPA stated that "the initial allocation of allowances . . . [based upon] historic heat input would yield a distribution of allowances putting relatively greater burden on the higher-emission- rate units to reduce emissions or purchase additional allowances in order for the units to be in compliance with the proposed Transport Rule trading programs." EPA justified this consequence of the allocation methodologies in EPA's Proposal stating that "because higher-emission- rate units generally are responsible for a greater share of a state's total emissions and thus bear greater responsibility for a states' significant contribution and interference with maintenance, this distribution of burden is consistent with the goals of CAA section 110(a)(2)(D)(i)(I)." [EPA-HQ-OAR-2009-0491-3953[1].1, p.6]
EPA cannot base the overall Phase I reductions on what is achievable in 2012 given existing controls and then allocate to units through a methodology that has no rational connection to existing controls or existing emissions. EPA's proposed approach would contradict its findings and would, by EPA's own admission, make it infeasible for many units to comply in Phase I absent the purchase of allowances (which, as discussed below, may not even be available). That is, EPA's proposed approach would require many units to install additional controls in order to continue at current operation levels and remain within their allocations. Yet, by EPA's own calculations, this is impossible to do before 2014. [EPA-HQ-OAR-2009-0491-3953[1].1, pp.6-7]
While agencies are generally allowed deference in carrying out their statutory mandates, "the agency must examine the relevant data and articulate a satisfactory explanation for its action including a `rational connection between the facts found and the choice made.'" Motor Vehicle Mfrs. Ass'n v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983) (quoting Burlington Truck Lines, Inc. v. United States, 371 U.S. 156, 168 (1962)). EPA's proposed alternative allocation methodologies in the Transport Rule NODA do not meet this standard. The "facts found" by EPA are that it is impossible for EGUs to install new control technology in time for Phase I of the Transport Rule and that Phase I emission reductions should be based on existing controls. There is no "rational connection" between these facts and the "choice made" in the Transport Rule NODA to allocate allowances in a way that has no correlation to existing controls. In fact, the Transport Rule NODA is irrational in light of EPA's findings regarding reductions in Phase I, and this is unsupportable in law. See, e.g., Williston Basin Interstate Pipeline Co. v. FERC, 519 F.3d 497, 503 (D.C. Cir. 2008) ("however one characterizes prior policy, we do not think the Commission has yet articulated a `rational connection between the facts found and the choice made,' as required by State Farm . . . ."). A court will deem an agency's regulation "arbitrary and capricious if the agency has . . . offered an explanation for its decision that runs counter to the evidence before the agency . . . ." Motor Vehicle Mfrs. Ass'n, 463 U.S. at 43. Here, the evidence before EPA is that Phase I reductions must be based upon emission levels achievable with existing controls, but EPA's proposed allocation methodology runs counter to this evidence as many EGUs will not be able to operate within allocations with existing controls even if they operate them year round as EPA suggests. [EPA-HQ-OAR-2009-0491-3953[1].1, p.7]
EPA concedes in the Transport Rule NODA that its proposed approach to unit level allocations will place a greater burden on some units to reduce emissions or purchase additional allowances. [EPA-HQ-OAR-2009-0491-3953[1].1, p.7]
Furthermore, the alternative methodologies for unit level allocations in the Transport Rule NODA would result in a transfer of wealth that would give some EGUs disproportionate market power over the EGUs that will need additional allowances to cover their shortfall. [EPA-HQ-OAR-2009-0491-3953[1].1, pp.9-10]
EPA's proposed methodologies for unit level allocations in the Transport Rule NODA are entirely inconsistent with President Obama's recent executive order, "Improving Regulation and Regulatory Review." Among other things, the Executive Order directs an agency to "tailor its regulations to impose the least burden on society. . . ." EPA's Proposal, which punishes EGUs for historic decisions made in good faith, including early commitments to aggressive emission reductions, imposes the most burden because EPA concedes that many EGUs will be unable to install controls necessary to make the required emission reductions and EPA's hybrid cap-and-trade approach makes it uncertain that EGUs will be able to purchase additional allowances on the market to cover the shortfall and will give some EGUs disproportionate market power over others. [EPA-HQ-OAR-2009-0491-3953[1].1, p.10]
The Transport Rule NODA's proposed unit level allocations for Phase I are significantly flawed because EPA has made no attempt to correct substantial errors in its baseline allocation methodology for 2012. [EPA-HQ-OAR-2009-0491-3953[1].1, p.11]
Thus, the proposed allocation methodology in the Transport Rule NODA does not address EPA's incorrect assumptions about the level of emissions controls actually achieved by existing controls. [EPA-HQ-OAR-2009-0491-3953[1].1, p.11]
Response: 

EPA disagrees that the achieving the 2012 state emissions budgets will require installing new controls. As EME notes, these budgets were designed specifically assuming that no new controls could be installed until 2014. Instead, unit's will be able to comply with the states' budgets though actions including: running existing controls, fuel switching and using lower sulfur coal, and buying and selling allowances.
EPA agrees that the allocation method does not match the method for determining state budgets. The state budgets were set to ensure the elimination of significant a contribution to non-attainment or interference with maintenance in other states.
Organization: Empire District Electric Company (Empire District)
Comment: 
Empire District Electric Company (Empire District)
  Empire District supports the proposed CATR allocation methodology, as published in 75 Federal Register 45210, August 2, 2010, and does not support the alternative allowance allocation methodologies, option 1 or option 2, described in this NODA. The following are reasons that Empire District does not support these alternatives and does not believe they yield a reasonable distribution of allowances. [EPA-HQ-OAR-2009-0491-3883, p.1]
a) Allocation options 1 and 2 appear to be developed by utilities with a high percentage  of gas-fired units. EPA's selection of either option 1 or 2 creates winners in the gas industry. The key to CATR is each States' budget system, not a fuel preference promoted by EPA.  
b) Selection of allocation option 1 or 2 will place coal-fired units at a severe disadvantage   due to the added liability should a State exceed its assurance level. Most coal-fired units will be forced to transfer allowances from their gas-fired units. The trigger point is unit allocation should the assurance level be exceeded. [EPA-HQ-OAR-2009-0491-3883[1].1, p.1]
f). Empire District believes that the allocation methodologies should be constant within all four trading programs (SO2 Group 1, SO2 Group 2, NOx Annual, and NOx Ozone Season). Empire District also supports using the same methodology for SO2 and for NOx allowance allocations. [EPA-HQ-OAR-2009-0491-3883[1].1, p.2]
The SO2 and NOx allowance markets will be winners since a vast number of gas-fired  turbines will be given SO2 allowances they do not need. [EPA-HQ-OAR-2009-0491-3883[1].1, p.2]
Response: 

EPA notes that the penalty assurance penalties are not imposed at the unit level, but rather the designated representative level, as described in Preamble Section VII.E. Several units may choose to be represented by a single designated representative, which can help reduce units' risk of incurring a penalty if the covered sources in a state exceed that state's emissions budget.
Organization: Entergy Services, Inc.
Comment: 
Entergy Services, Inc.
Allocations by States
In the unfortunate event the EPA elects not to finalize either Option 1 or Option 2 proposed in the NODA, Entergy strongly supports adding provisions to the Transport Rule that would allow states to replace the EPA's allowance allocation provisions by state-developed allocation provisions similar to what was established in the CAIR. [EPA-HQ-OAR-2009-0491-3986[1].1, p.2]
Response: 
Thank you for your comment.

Organization: EquiPower Resources Corp.
Comment: 
EquiPower Resources Corp.
EPA's alternative methodologies to unit-level allocation are inefficient and will increase the likelihood of supply disruptions and inefficient use of capital.
o The Transport Rule NODA approach will likely require curtailment of operations at higher-emitting EGUs, but will not allow lower-emitting EGUs to make up for the shortfall, leading to potential supply shortages or inefficient use of capital.
o The Transport Rule NODA approach will also cause further disruption in states that currently use output-based allocation methodologies. [EPA-HQ-OAR-2009-0491-3928[1].1, p.2]
The Transport Rule NODA's Unwise Distribution of Unit-Level Allocations Based Upon Historic Heat Input Data Will Likely Cause Supply Disruptions
The Transport Rule NODA unwisely distributes unit-level allocations based upon historic heat input data from 2005 to 2009 (and historic emissions data from 2003 to 2009) without taking into account the likely impacts of its regulations on the future supply distribution. This miscalculation could lead to significant supply disruptions. [EPA-HQ-OAR-2009-0491-3928[1].1, p.4]
The Practical Problem With EPA's Proposal
The Transport Rule will require many facilities to install additional controls to continue operating at current levels.11 The approach proposed in the Transport Rule NODA exacerbates the need for additional controls because EPA concedes that the historic heat input-based allocation methodology it proposes "would yield a distribution of allowances putting relatively greater burden on the higher-emission-rate units to reduce emissions or purchase additional allowances in order for the units to be in compliance with the proposed Transport Rule trading programs." [EPA-HQ-OAR-2009-0491-3928[1].1, p.4-5]
Unit-level allocations based upon historic heat input data will not allow these loweremitting gas facilities to ramp up capacity because allocations will correlate to the historic supply distribution. Additionally, EPA's Transport Rule NODA approach does not apply a growth factor in its methodology. Thus, under EPA's Proposal, these plants will be penalized for historically constrained operations. These plants will not likely have the allowances needed to substitute for the lost baseload capacity and, given the limitations on trading described above, are not likely to be able to acquire them. [EPA-HQ-OAR-2009-0491-3928[1].1, p.6]
Thus, EPA's proposed approach in the Transport Rule NODA: (1) will likely require curtailment of operations for certain higher-emitting EGUs; (2) will not allow lower-emitting EGUs to make up for the shortfall because EPA will not have allocated allowances in a manner that allows for adjustments in the supply distribution; and (3) will lead to supply shortages in many Transport Rule states. [EPA-HQ-OAR-2009-0491-3928[1].1, p.7]
EPA's policy is and should be to encourage greater utilization of cleaner, more efficient gas plants. However, the proposed allocation methodology in the Transport Rule NODA runs counter to that purpose -- it discourages greater utilization of cleaner, more efficient gas plants. [EPA-HQ-OAR-2009-0491-3928[1].1, p.8]
As described above, EPA's reliance on historic heat input data constrains gas plants' ability to make up for generating shortfalls that will result from likely supply disruptions in higher-emitting facilities that cannot comply with Transport Rule emissions reductions. This is particularly problematic given that the Transport Rule presents a one-time allocation that lasts throughout the duration of the Rule. [EPA-HQ-OAR-2009-0491-3928[1].1, p.8]
The Transport Rule NODA's Approach Will Cause Further Disruptions in States That Currently Allocate Allowances Based Upon Electricity Output
The Transport Rule NODA's proposal to make unit-level allocations based upon historic heat input data ignores the fact that some states, such as Connecticut, Massachusetts, and New Jersey, have already been using output-based allocations in emission trading programs for a number of years. Ironically, this system of output-based allocations is one that EPA itself has advocated for more than a decade. However, if EPA adopts the Transport Rule NODA approach -- mandating a switch to heat input-based unit-level allocations -- this would cause further disruptions that would likely lead to supply shortages and inefficient use of capital. [EPA-HQ-OAR-2009-0491-3928[1].1, p.8]
Output-based environmental regulations are calculated on the energy output of the process, which may be electricity, thermal, or mechanical output, and take into account the emissions benefits of efficiency. The use of a heat input-based calculation will lead to potentially substantially different allocations than an output-based calculation. [EPA-HQ-OAR-2009-0491-3928[1].1, p.9]
These differences in the allocations may have a significant impact on EGUs in output-based states because EGUs have made significant investments based on an output-based system of allocations. They will not have the time or options to adjust to the new methodology. As described above, installing new or different controls could take over 2 years in EPA's estimation and as many as 5 years in industry's estimation. Without the opportunity to install controls, EGUs in output-based states may likely have emissions that exceed their allowances. Additionally, as described above, there is a strong likelihood that EGUs would not have the option of purchasing allowances on the market. Therefore, their only option may be to curtail operations, leading to supply shortages and inefficient use of capital. [EPA-HQ-OAR-2009-0491-3928[1].1, p.9]
Furthermore, the heat input-based approach in the Transport Rule NODA also creates a considerable disincentive for an output-based state to promulgate a SIP to replace the Transport Rule FIP. If output-based states are forced to adopt EPA's heat input-based methodology, they would be unlikely to impose upon their sources the disruption that would result from changing the allocation method back to an output-basis. Thus, while EPA suggested in the Transport Rule that states may promulgate SIPs,26 and EPA claims to provide options for states to submit SIPs in the Transport Rule NODA, (see section VI.A), EPA cannot assume that states will be able to do so. In utilizing a heat input-based method of allocations, the Transport Rule NODA effectively throws Connecticut, Massachusetts, and New Jersey's investment and advances in emissions reductions out the window and will result in significant disruptions. [EPA-HQ-OAR-2009-0491-3928[1].1, p.9]
EPA's alternative methodologies to unit-level allocation are inefficient and will increase the likelihood of supply disruptions and inefficient use of capital --  particularly in states that currently use output-based allocation methodologies. [EPA-HQ-OAR-2009-0491-3928[1].1, p.21]

11 While EPA alleged that its methodology for Phase I of the Transport Rule was based upon reductions that EPA believed could be obtained using existing controls or controls that EPA believed would be installed by 2012, see 75 Fed. Reg. at 45,281, EquiPower believes that fundamental flaws in EPA's underlying data and assumptions led to significantly under-allocated state budgets (and resulting unit-level allowance allocations). See infra section IV.A. Therefore, many EGUs will exceed their Phase I allocations in 2012 and 2013 while operating with existing controls.
Response: 

By allowing for some trading of allowances, along with the existence of a variety of compliance actions units can take, EPA believes that there will not be a shortage of electricity. This is demonstrated in the TR_Limited_Trading_Final Integrated Planning Model (IPM) run. Specifically, EPA notes that gas-fired units could generate more electricity than they had historically by buying allowances from other units which could add controls, change fuels, or curtail operations.
Organization: First Energy
Comment: 
First Energy
FirstEnergy commends the EPA's use of historical QA'd CAMD data to establish unit allocations instead of the combined historical and future model prediction methods used in the original CATR and NODA I. [EPA-HQ-OAR-2009-0491-3904[1].1, p.1]
In the event all data and modeling errors are identified and corrected in EPA's efforts to finalize the CATR rulemaking, FirstEnergy would support Option 2 alternative allocation method over Option 1 and is completely opposed to the previously proposed IPM generated allocation methods. The EPA should adjust the allocation formulas that would address non-typical annual heat input (HI) and utilize actual three-year average data to establish an actual unit capacity factor. [EPA-HQ-OAR-2009-0491-3904[1].1, p.2]
Specific to both options, the EPA should use a seven year data range (2003  -  2009) to establish the three-year heat input average. EPA's proposed five year data range (2005  -  2009) would understate the three-year heat input average for Units that have three year outage cycles or may have been impacted by a critical component failure. For example, scheduled outages in 2005 and 2008 would bias the three year average lower since the remaining annual averages would be 2006, 2007 and 2009. 2009 is not representative of a typical year because of reduced demand driven by a weak economy. A unit starting a three year outage cycle in 2004 and 2007 may not have a significant bias since the remaining annual averages would be 2005, 2006, and 2008. By increasing the potential data range to 2003 - 2009 instead of 2005  -  2009, the EPA will eliminate any potential negative bias that would occur merely due to the outage cycle of particular units in the power generation sector. Furthermore, in Option 2 the EPA uses a seven year data range (2003  -  2009) to establish the maximum annual emissions, thus the use of a seven year range would be internally consistent with EPA's approach in Option 2. Finally, by extending the date range for annual heat input (HI) from 2003 to 2009, the EPA will minimize the negative impacts of a significant forced outage or unscheduled load reduction caused by a critical component failure. [EPA-HQ-OAR-2009-0491-3904[1].1, p.2]
Another alternative the EPA should consider is the periodic review of the Heat Input (HI) maximum average for Option 1 and Option 2. FirstEnergy recommends potential rolling 5-year review of HI and periodic reallocation of allowances. This should provide the EPA a means to reassess future allocation distributions in the power generation sector. [EPA-HQ-OAR-2009-0491-3904[1].1, p3]
The EPA should be commended for abandoning the use of a proprietary forward-looking model that picks winners and losers in the allocation of allowances and instead reaching a solution to sensibly allocate each State's budgeted allowances based on verifiable historical operating rates. FirstEnergy is cautiously supportive of the alternative allocation methods in this NODA over the EPA's initial interstate, intrastate, and command and control methods. [EPA-HQ-OAR-2009-0491-3904[1].1, p.4]
Response: 

 , Where commenters identified specific units that had partial-year or low heat-input years due to maintenance or outages, EPA did not include the heat-input for those years in the allowance allocation methodology.
Organization: GenOn Energy, Inc.
Comment: 
GenOn Energy, Inc.
3. Either of the allocation options proposed in NODA 3 would require owners of coal fired plants to transfer hundreds of millions of dollars to owners of gas-fired plants. Yet EPA does not even mention this fact in the NODA, much less provide any justification for it. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 2]
4. It may be that EPA simply wants to make coal-fired generation relatively more costly than gas-fired generation by forcing coal plants to buy SO2 allowances from gas plants, but EPA does not have the authority to accomplish this result through rule making. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 2]
5. Congress and EPA have long recognized that the primary reason for distributing allowances is to help defray some of the costs that companies will incur in order to reduce their emissions. Yet no gas plant in the country will need to incur any cost to control SO2 emissions. No gas-fired plant will need to install SO2 emission controls, pay the ongoing costs to operate and maintain a scrubber, or switch to a higher cost, lower-sulfur fuel. Under these circumstances, there is no rationale for providing hundreds of millions of dollars worth of SO2 allowances to gas-fired plants, and EPA does not even attempt to provide one. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 2]
8. If EPA proceeds to issue a final Transport Rule without preparing a comprehensive supplemental proposal and allowing adequate time for public comment, then it should either: b. Eliminate gas-fired plants from the SO2 program and distribute SO2 allocations only to coal- and oil-fired plants [EPA-HQ-OAR-2009-0491-3996[1].1, p. 4]
II. EPA has failed to provide any legal or policy justification for the two new approaches it proposes in NODA 3 for distributing hundreds of millions of dollars worth of emission allowances.  [EPA-HQ-OAR-2009-0491-3996[1].1, p. 5]
Rather than correcting the unit-specific problems with its model, however, EPA has now come forward, in NODA 3, with two other options for distributing allowances. These options are vastly different from the approach that EPA originally proposed, but the Agency has not provided a rational justification for either of them. Instead, the Agency simply takes the position that it has broad discretion in deciding how to distribute allowances. The discretion EPA relies upon, however, is not without limits. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 6]
Under either NODA option, the Agency would distribute a large number of SO2 allowances to natural gas-fired power plants that cannot be justified. Both options would will lead to a windfall for owners of natural gas plants by allocating a vast number of allowances that could never be used by the plants and could disrupt competition in the electricity marketplace. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 6]
We provide three examples comparing (1) the proposed allocation of SO2 allowances under Option 1 and 2 of the NODA to (2) the actual emissions from natural gas plants as reported in EPA's Clean Air Market Division emissions database. This is simply a random sampling of the available data, but the same basic findings are reflected throughout the data set and clearly demonstrate that EPA's NODA 3 allocation schemes would result in a massive windfall to owners of natural gas-fired power plants. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 6]
1. The Dearborn Industrial Facility in Michigan (Facility ID 55088) reported the following actual SO2 emissions in the most recent 5 years: 2005 0.6 tons, 2006 0.2 tons, 2007 0.3 tons, 2008 0.1 tons, 2009 0.1 tons. EPA is now proposing, in NODA 3, to give this facility the following number of SO2 allowances: Under option 1, the proposed 2014 SO2 allocation to this facility in the NODA is 2852 allowances. Under option 2, the proposed 2014 SO2 allocation to this facility in the NODA is 1434 allowances. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 6]
2. The Hines Energy Complex in Florida (Facility ID 7302) reported the following SO2 emissions for the last 5 years: 2005 0.6 tons, 2006 0.2 tons, 2007 0.3 tons, 2008 0.1 tons, 2009 0.1 tons. Under option 1 the proposed 2014 SO2 allocation is 6149 allowances. Under option 2, the proposed 2014 SO2 allocation is 3098 allowances. [EPA-HQ-OAR-2009-0491-3996[1].1, pp. 6-7]
3. The Elwood Energy Facility in Illinois (Facility ID 55199) reported the following SO2 emissions for the last 5 years: 2005 1.2 tons, 2006 0.6 tons, 2007 0.8 tons, 2008 0.4 tons, 2009 0.4 tons. Under option 1 the proposed 2014 SO2 allocation is 504 allowances. Under option 2, the proposed 2014 SO2 allocation is 498 allowances. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 7]
Under the NODA 3 proposals, the large windfalls for gas-fired plants would occur for two main reasons: (1) such plants may have large heat input, but always have very low SO2 emission rates; and (2) many such plants are operated as peaking units, but EPA's use of the 95th percentile to estimate capacity factors ensures that the actual capacity factor is too high for 95 percent of the units and many times too high for a significant number of them. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 7]
On its own website, EPA states 'emissions of sulfur dioxide and mercury compounds from burning natural gas are negligible' and that, compared to emissions from coal-fired generation 'one percent as much sulfur oxides' is emitted from a natural gas power plant. http://www.epa.gov/cleanenergy/energy-and-you/affect/air-emissions.html. Without considering the historic and/or projected emissions from sources in an allocation scheme, [EPA-HQ-OAR-2009-0491-3996[1].1, p. 7]
As discussed below, it has not and cannot provide a legally defensible rationale for either of the options proposed in NODA 3. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 8]
III. Neither of the NODA 3 allowance distribution options is acceptable because either would both force massive wealth transfers from owners of coal-fired power plants to owners of gas-fired power plants without any legal or policy justification. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 8]
Congress, EPA, and academic researchers have all made it clear that, under any cap-and-trade program, the policy rationale for distributing allowances freely is to help defray some of the costs that companies will incur in order to reduce their emissions. Yet no gas plant in the country will incur any cost to control SO2 emissions. No gas-fired plant will need to install SO2 emission controls, incur the significant cost of operating scrubbers, or switch to a different fuel source. Under these circumstances, there is no rationale for providing SO2 allowances to gas-fired plants, and EPA does not even attempt to provide one. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 8]
When Congress enacted the Acid Rain Program in 1990, it did give a small number of SO2 allowances to gas plants  -  but only a sufficient number to cover their very low emissions of SO2. Gas plants were excluded from Phase I of the Acid Rain Program, and Phase II allocations were equal to each unit's baseline heat input times the lesser of its actual 1985 emissions rate or 1.2 pounds of SO2 per million Btu. See Ellerman et al., Markets for Clean Air: The U.S. Acid Rain Program, Cambridge University Press (2000), p 44. Because no gas-fired unit was anywhere close to emitting 1.2 lbs per mmBtu, the program was basically designed to give them only enough allowances to cover their actual emissions. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 9]
Under both the Acid Rain Program and CAIR, cap-and-trade was designed to ensure that the cost of reducing SO2 from a group of coal-fired units would be distributed fairly among all the units in the group, even though only some of them were expected to install controls. This was accomplished largely by requiring uncontrolled coal-fired units to purchase allowances from units that incurred the cost of installing and operating expensive emission controls, and thus to help pay for those controls. EPA should maintain the basic equity of this approach, rather than using either of the NODA 3 options, which would require a substantial transfer of wealth from the owners of coal fired plants to the owners of gas-fired plants. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 9]
Response: 
Thank you for your comment.

Organization: Gulf Coast Lignite Coalition
Comment: 
Gulf Coast Lignite Coalition
Because the EPA may rely on the alternative allocation methodologies for the final Transport Rule, GCLC feels it is imperative to provide comment on the NODA and to highlight the disparity of treatment of fuel type in the proposed allocation methodologies. [EPA-HQ-OAR-2009-0491-3963[1].1, pp.1-2]
Since a Federal Implementation Plan (FIP) will be in place until the EPA Administrator receives and approves State Implementation Plans (SIPs), it is critical that the FIP in place accurately portrays and protects existing fuel sources; the currently proposed allocation methodologies that would become part of the FIP fails to accomplish this. [EPA-HQ-OAR-2009-0491-3963[1].1, p.2]
EP A proposes two alternative allocation methodologies, both of which implicate a strong bias against coal-fired units. The allowances afforded under Option 1 and 2 ultimately result in a reduced utilization of coal as a fuel source. [EPA-HQ-OAR-2009-0491-3963[1].1, p.2]
The original allocations were based on historical emissions and allocations in Texas were based on historical reported data. Yet, here, EPA proposes alternative allocation methodologies for the Transport Rule FIP that propose allocations based on historical heat input and set an emissions rate, without making adjustments for fuel type. Such a 'one-size-fits-all' approach for a wide variety of existing sources with different combustion techniques and fuel type, invariably results in disparate treatment and creates a disadvantaged category of sources. Here, EPA has pushed all coal-fired units into a category of sources that would be greatly disadvantaged by the Transport Rule. [EPA-HQ-OAR-2009-0491-3963[1].1, p.2]
The current methodology appears to clearly discriminate against coal, particularly coal with higher sulfur content. Subcategories of coal are integral to the nation's energy supply and to allow what EPA is proposing with the alternative allocation methodologies would directly favor a fuel choice and dictate a redesign of existing facilities, which goes directly against the Clean Air Act and EPA policy. [EPA-HQ-OAR-2009-0491-3963[1].1, p.3]
As currently proposed, the alternative allocation methodologies greatly disadvantage coal as a fuel source, which is not an economically viable approach. [EPA-HQ-OAR-2009-0491-3963[1].1, p.4]
Response: 
Thank you for your comment.

Organization: Homer City Owner Lessors 1-5, 7, and 8
Comment: 
Homer City Owner Lessors 1-5, 7, and 8
The Owner Lessors do not support either of the NODA's proposed heat-input allocation methodologies in their current form. Both are inconsistent with EPA's stated rationale and public policy objectives of the proposed Transport Rule and would impose severe economic hardship on Homer City, and other similarly situated power plants. In so doing, these options would also unnecessarily divert needed capital away from the installation of controls necessary to meet the Transport Rule's expected 2014 limits, without environmental benefit in the interim. [EPA-HQ-OAR-2009-0491-3988[1].1, pp.1-2]
Adoption of Options 1 or 2 of the NODA would reduce the SO2 allowances that Homer City would receive under the originally proposed Transport Rule in 2012 and 2013 by as much as 66%. Such an outcome likely would force Homer City to pay upwards of $84 million annually in 2012 and 2013 based on the allowance price estimated by EPA to maintain its current level of operations. Alternatively, if these allowances are unavailable for purchase or too costly to acquire, Homer City would be forced to curtail its operations, affecting both the grid and the facility's revenue. Either result could greatly complicate or jeopardize the financing of needed emission control technology and the orderly transition to the stringent emission reductions required by Phase II of the Transport Rule. Furthermore, both of the proposed heat-input methodologies are at odds with EPA's strategy to fulfill its obligations under Clean Air Act ('CAA') section 110(a)(2)(D)(i)(I) to address the significant contribution of upwind sources by establishing state emission budgets based on reductions deemed 'cost effective' and by providing sources with necessary allowances and sufficient time to install control technology. Options 1 and 2 would divorce the allocation of allowances from what a source can cost effectively achieve in the near term. [EPA-HQ-OAR-2009-0491-3988[1].1, p.2]
Given these deficiencies, the Owner Lessors recommend that EPA adopt the allowance allocations for Homer City contained in the proposed Transport Rule or, alternatively, propose a new option based more closely on historic actual emissions. [EPA-HQ-OAR-2009-0491-3988[1].1, p.2]
II. Options 1 and 2 Are Inconsistent With The Underlying Structure of The Proposed Transport Rule And Should Not Be Adopted.
The proposed Transport Rule provides for the reduction in emissions from EGUs in two phases. For Phase I, EPA proposes state emission budgets and allowance allocations that are based on its assessment of emission reductions achievable through the operation of controls installed as of 2012. EPA's proposed Phase II limits in contrast are based on the amount of cost-effective reductions necessary to address each state's downwind contribution. The Phase II limits assume that affected units will have installed necessary pollution control equipment by 2014. The allowance allocation methodology in the proposed Transport Rule is based on the same analysis and considerations, and hence is emissions based. [EPA-HQ-OAR-2009-0491-3988[1].1, p.3]
In proposing the state emission budgets and allowance allocations contained in the originally proposed Transport Rule, EPA was interpreting its CAA statutory authority and the effect of two decisions from the United States Court of Appeals for the District of Columbia Circuit: Michigan v. EPA and North Carolina v. EPA. EPA explicitly considered the emission reductions that would be necessary to address the requirements of CAA section 110(a)(2)(D)(i)(I) and the cost of achieving improvements in air quality from stationary sources. Citing North Carolina v. EPA, EPA explained that, in the proposed Transport Rule, the Agency "gave greater weight to air quality considerations and making it possible to tailor the significant contribution measurement more closely to different conditions in different groups of states." [EPA-HQ-OAR-2009-0491-3988[1].1, p.3]
As outlined in the NODA, Options 1 and 2 are not based on this statutory analysis or the technical analysis that supports EPA's proposed Transport Rule. Instead, Options 1 and 2 provide a completely different basis for the allocation of allowances, one based on an EGU's relative percentage of the heat input of all EGUs in a state, or a similar heat input based approach with an added constraint premised on reasonably foreseeable maximum emissions. As discussed below, the Owner Lessors oppose the adoption of both options in their current form. [EPA-HQ-OAR-2009-0491-3988[1].1, p.3]
A. Options 1 and 2 Will Impede the Transition From Phase I to Phase II.
The proposed Transport Rule is carefully designed to first require that EGUs in affected states rely on existing control technology in 2012 and 2013, while later imposing more stringent control levels in 2014 and thereafter in Phase II. The proposed rule deliberately 'phased-in' emission control requirements. Based on EPA projections, EGUs were allocated a sufficient quantity of allowances to continue their normal operations for at least two years. In other words, Phase I was designed to reflect the status quo of existing controls and its allocations to each unit were intended to be sufficient to cover that unit's actual emissions during Phase 1. Thereafter, EGUs would either need to have new emission control technology installed or purchase available emission allowances. [EPA-HQ-OAR-2009-0491-3988[1].1, p.4]
The heat-input based allowance allocations outlined in Options 1 and 2 for the years 2012 and 2013 make it impossible for existing units to operate with existing controls. They will be required either to install additional emissions controls, which EPA acknowledges is impossible to achieve by 2012, or purchase additional allowances. Under both options, EGUs with historically higher emissions would receive far less allowances in 2012 and 2013 than under the emissions-based allocation methodology in the proposed rule. If adequate emission allowances are not available, or not affordable, such EGUs would need to curtail their generation of electricity and/or, in the extreme, fail financially. Contrary to EPA's expectations, these units would not be able to smoothly transition from projected 'achievable' emissions in Phase I to the stringent emission reductions required in Phase II. Given that there will be less than one year between the finalization of the Transport Rule and the imposition of Phase I requirements, this change in operating scenarios will be unavoidable. [EPA-HQ-OAR-2009-0491-3988[1].1, p.4]
B. Options 1 and 2 Would Result in Adverse Economic Consequences.
As proposed, EGUs can comply with the Transport Rule either by operating within their allocated emission allowances or by purchasing allowances from other sources. The extensive reduction of Phase I allowances for Homer City under the heat-input options outlined in the NODA, however, would leave the facility with only one choice: to purchase allowances from other EGUs. Such a result would significantly raise the operating costs of Homer City and complicate efforts to install necessary emission control technology to comply with Phase II. [EPA-HQ-OAR-2009-0491-3988[1].1, p.4]
The allowance allocations under Option 1 and Option 2 for the Homer City facility on a unit-by- unit basis are displayed below, along with the corresponding allowance allocations provided for in Phase I and Phase II of the proposed Transport Rule. While the Transport Rule as originally proposed would ensure that Homer City has adequate allowances in the near term to continue normal operations until controls can be installed, such is not the case under Options 1 or 2. [EPA-HQ-OAR-2009-0491-3988[1].1, p.4]
[Table can be found on page 5 of this comment.]
Under Options 1 and 2, Homer City would receive approximately 62% and 66% less allowances, respectively, than under the allowance allocation methodology contained in the proposed Transport Rule. Thus, Options 1 and 2 would effectively act as a financial penalty to Homer City that cannot be avoided and diverts financial resources that could otherwise be allocated to planning and installation of emission control equipment needed for Phase II compliance. [EPA-HQ-OAR-2009-0491-3988[1].1, p.5]
Conversely, Options 1 and 2 would allow some EGUs to receive more allowances than are needed for their own operation or which may be necessary to finance additional emission reductions. While Option 2 can result in imposition of a 'well controlled rate maximum' limit of 0.06 lbs/mmBTU for SO2 and 0.06 lbs/mmBTU for NOx, such limits do not ensure that allowances will not be distributed to lower-emitting EGUs in excess of those reasonably needed to comply with the Transport Rule. The net result is that lower-emitting EGUs would receive a greater share of allowances than higher-emitting EGUs in the same state. EGUs with few SO2 emissions, and little or no allocation for such emissions under CAIR, would also receive allowances that they do not need for compliance. [EPA-HQ-OAR-2009-0491-3988[1].1, p.5]
Adoption of Option 1 or 2 would simply transfer wealth from higher emitting EGUs to lower emitting EGUs. This revenue flow is contrary to the need of higher emitting EGUs to invest in lower emitting technology to meet Phase II state emission budgets. The direction of this revenue flow could jeopardize or increase the cost of control equipment. The only option for an EGU that cannot afford the costs of controls would be to shut down or greatly reduce operations. This in turn would complicate matters further since it would lead to even less revenues. In cases where such operation is infeasible, the shutdown of units will directly result in the loss of jobs in the area where the EGU operates. [EPA-HQ-OAR-2009-0491-3988[1].1, p.5]
EPA's adoption of Options 1 or 2 as outlined also would be inconsistent with President Obama's recent executive order, 'Improving Regulation and Regulatory Review.' That order directs EPA, in promulgating regulations, to 'protect public health, welfare, safety, and our environment while promoting economic growth, innovation, competitiveness, and job creation,' and to 'identify and use the best, most innovative, and least burdensome tools for achieving regulatory ends.' These options are not necessary to protect public, will not promote growth and job creation (in fact the contrary will occur), and are far more burdensome than other allowance allocation options for 2012 and 2013. For these and other reasons, we urge EPA to reject these options as proposed in the NODA. [EPA-HQ-OAR-2009-0491-3988[1].1, p.6]
C. Options 1 and 2 Will Promote the Economic Interests of One Class of EGUs Over Another Without Commensurate Public Benefit.
The effect of basing allowance allocations on the methodology provided in Options I or 2 is exacerbated by the diminished opportunity to purchase emission allowances under the Transport Rule. Under the limited trading options in the proposed Transport Rule, EGUs that need to purchase allowances in Phase I could have little, if any, option other than to purchase allowances from other EGUs located in the same state. While the State Budgets/Limited Trading proposal 'assurance provisions' are not applied until 2014, there will be a strong incentive for sources to bank allowances for future years ( since any banked CAIR allowances cannot be used for compliance). This constrained market for allowances will have the effect of transferring income from EGUs that are short allowances to those with a surplus of allowances. As noted above, this transfer of wealth would take place without commensurate public benefit in the short term, and potentially at a cost since EGUs that need to invest in pollution control are forced to buy allowances from other EGUs instead. [EPA-HQ-OAR-2009-0491-3988[1].1, p.6]
In contrast to the multistate allowance market created under the NOx SIP Call and CAIR, over the long term, trading under the Transport Rule likely will be confined largely to competing EGUs within a state. Since allowances represent the ability to emit, Options 1 and 2 would accentuate the ability of those with excess allowances to control the emissions and generation of electricity by other EGUs. Thus, Options 1 and 2 could result in incentives to constrain the transfer of emission allowances and substantially raise the price of allowances. Those holding excess allowances would be in a position to realize financial windfalls through complete market knowledge that those needing allowances have access to relatively few sellers. Classic conditions of market scarcity would exist to the financial detriment of those needing additional allowances to support their 'normal' operations. [EPA-HQ-OAR-2009-0491-3988[1].1, p.6]
D. The Allowance Allocation Under Options 1 and 2 Are Punitive
The allowance allocation under Options 1 and 2 are punitive. The EPA has acknowledged that it is impossible for EGUs such as Homer City to install emission controls in time for Phase I compliance. Nonetheless, the proposed heat input approach, if enacted, would punish Homer City for its inability to install emission controls by 2012. See 76 Fed. Reg. at 1114 (EPA acknowledges the punitive effect that the NODA would have: 'heat input would yield a distribution of allowances putting relatively greater burden on the higher-emission-rate units to reduce emissions or purchase additional allowances in order for the units to be in compliance with the proposed Transport Rule .... EPA believes that ... higher-emission-rate units generally are responsible for a greater share of a state's total emissions and thus bear greater responsibility for a state's significant contribution ....'). Under EPA's proposal, Homer City will be forced to pay upwards of $84MM annually during 2012-2013 for SO2, assuming such allowances are available, to keep operating at current levels, or alternatively to cut its operations dramatically. Thus, even though Homer City has acted in good faith under the Acid Rain Program and CAIR, it will be penalized because it cannot achieve that which EPA has acknowledged is impossible to achieve. [EPA-HQ-OAR-2009-0491-3988[1].1, pp.6-7]
III. Allowance Allocations Under Options 1 and 2 Are Arbitrary and Capricious.
A. Allowance Allocations Are Not Rationally Related to State Emission Budgets for 2012.
An allowance allocation scheme based only on the heat input into a power plant (as provided in Option 1) or through a calculation of historic heat input as constrained by a 'well-controlled- rate maximum'(as provided in Option 2) bears little, if any, relationship to EPA's underlying analysis that established the Phase I state emission budgets. As discussed above, the proposed Transport Rule Phase I budget are based on what reductions individual EGUs can reasonable achieve using control technology available in 2012. Yet, allocation of allowances under Options 1 and 2 is based on heat input and other considerations that have nothing to do with what individual EGUs can reasonably achieve by 2012. All these options would do, as EPA expressly acknowledges, is place a greater burden on higher-emission-rate units (i.e., coal-fired units) and shift wealth from certain segments of the industry to others. If EPA is going to alter the rationale for allocating allowances, then it must also alter the rationale for the entire Transport Rule. [EPA-HQ-OAR-2009-0491-3988[1].1, p.7]
EPA's justification for taking comment on Options 1 and 2 relies solely on concerns expressed in comments the Agency received on the proposed Transport Rule. These comments are unrelated to EPA's allowance allocation analysis in the proposed rule. Moreover, under the options outlined in the NODA, higher emitting EGUs will need to purchase allowances from other EGUs if sellers are available. Thus, actual emissions and costs experienced by EGUs in a state could substantially vary from EPA projections in the Transport Rule. Yet, EPA offers no analysis on the cost impact of Options 1 and 2 and how they might impact the Regulatory Impact Analysis for the Transport Rule as a whole. At a minimum, EPA must conduct such an analysis before adopting either option. [EPA-HQ-OAR-2009-0491-3988[1].1, p.7]
B. Allowance Allocations Are Not Rationally Related to Phase II State Emission Budgets for SO2 and State Emission Budgets for NOx [EPA-HQ-OAR-2009-0491-3988[1].1, p.7]
In developing the Phase II SO2 state emissions budgets, EPA similarly relied on a fundamentally different methodology than the allocation alternatives outlined in the NODA. The Phase II SO2 state emissions budgets are based on the reduction of emissions that are projected to be achieved at a cost of $2,000 per ton. Conversely, the heat input into a unit, which forms the basis of allowance allocations in Option 1 of the NODA, need not be related to the actual cost of controlling SO2 emissions from the unit or purchasing allowances. Option 2 of the NODA, by relying on calculations apart from emissions and costs, is similarly unrelated to EPA's analysis and rationale for establishing Phase II budgets. [EPA-HQ-OAR-2009-0491-3988[1].1, pp.7-8]
For NOx, the basis of allocations for 2012 and years thereafter is 'the unit-level emissions assumption (tons) used in determining the state budget.' In other words, NOx allowance allocations are similarly derived in the proposed Transport Rule from EPA's determination of state emissions budgets. Thus, Option 1 or 2 as applied to NOx allowances are also disconnected from EPA stated rationale and cost assessment for the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3988[1].1, p.8]
C. Inclusion of Option 1 or 2 in FIPs Applicable in 2012 Would Violate Clean Air Act Cooperative Federalism.
In analyzing the effect of allowance allocations under Options 1 and 2, it is significant that FIPs providing for allowance allocations will be binding on all states in 2012. It is unlikely that states will be able to develop, submit, and obtain EPA approval of SIPs containing different allocation systems than that provided in the FIP before allowance allocations are required in 2012. Thus, if EPA finalizes Option 1 or Option 2 in the final Transport Rule, it will effectively mandate the implementation of the allowance allocation scheme in those options in all affected states. Such an action would violate the cooperative federalism mandate of the CAA. [EPA-HQ-OAR-2009-0491-3988[1].1, p.8]
IV. The Stated Rationales for Options 1 and 2 are Flawed.
EPA offers three rationales for allocating allowances pursuant to Options 1 and 2. First, EPA claims that historic heat input data are more likely to be accurate at a unit level than projected emissions. Second, EPA claims that Options 1 and 2 are 'fuel neutral.' Finally, EPA states that historic heat input data are 'emissions-control-neutral.' Each of these rationales is flawed. [EPA-HQ-OAR-2009-0491-3988[1].1, p.8]
A. Historic Heat Input Data Are Not Inherently More Accurate Than Projected Emissions.
EPA has echoed comments it received with regard to the proposed Transport Rule that historic heat input data are 'more likely to be accurate at a unit level than projected unit-level emissions." While Owner Lessors would agree that historical data are more likely to be accurate than projected emissions, this is not an indication that heat input data per se are superior to emissions data. Rather, this is simply a matter of the recordation and verification of such data versus data derived from projections made using the Integrated Planning Model. [EPA-HQ-OAR-2009-0491-3988[1].1, pp.8-9]
Instead of finalizing Options 1 or 2, EPA should solicit comment on a methodology that would utilize the historic emissions data of EGUs within a state.  By relying on historic emissions data, EPA state emissions budgets would more closely track the Agency's determination of significant contribution under CAA section 110(a)(2)(D)(i)(I). This option would also help to address concerns expressed above with regard to the transition from Phase I to Phase II of the Transport Rule and the availability of allowances in constrained state-based emission allowance markets. [EPA-HQ-OAR-2009-0491-3988[1].1, p.9]
B. Heat Input Data Are Not 'Fuel Neutral"
The effect of allocating allowances based on heat input data does not create a 'level playing field' between all different fuel types. Instead, use of heat input data as proposed in Options 1 and 2 and as implemented in the context of the proposed Transport Rule decidedly favors the use of fuels that have no SO2 content, a lesser degree of SO2 content, or which are able to be utilized in EGUs having greater efficiency. Use of heat input data as provided in Options 1 and 2, therefore, would favor natural gas and lower sulfur coals over higher sulfur coals used for electric power generation. Because the focus of the Transport Rule is on reducing upwind emissions based on both air quality and costs, favoring one fuel type over another with regard to allowance allocations is unrelated to the statutory purpose of addressing 'significant contribution.' [EPA-HQ-OAR-2009-0491-3988[1].1, p.9]
C. Heat Input Data Are Not Emissions-Control Neutral.
In addition to favoring certain fuel types over others, utilizing heat input data will favor EGUs that have already controlled emissions over those that have not, even though such units may have been operating under regulations established in the Acid Rain Program, NOx SIP Call, and CAIR. Such a result is contrary to the EPA's previous regulatory approach to controlling regional air pollution and state-to-state transport of emissions as well as the stated rationale and factual underpinnings of the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3988[1].1, p.9]
V. Conclusion
For the reasons discussed above, EPA should not adopt Option 1 or 2 of the NODA. Instead, EPA should finalize the allowance allocations for Homer City contained in the proposed Transport Rule or, alternatively, propose a new option based more closely on historic actual emissions. [EPA-HQ-OAR-2009-0491-3988[1].1, p.9]
Response: 
As discussed in Preamble section VII.D, "fuel-neutral" and "control-neutral" allocations mean that allocations were done based on metric that did not reflect fuel choice or use of controls. Using either historic or projects emissions would reflect both fuel type and use of controls. 
Further detail on the implementation of this approach, rationale, and response to comments on the allocation method is provided in Preamble Section VII.D, as well as in the Allowance Allocation Final Rule TSD in the docket for this rulemaking. In addition to providing this rationale, EPA also notes that allowance allocation method should not have an impact on operation decisions because using an allowance has an opportunity cost (i.e. selling that allowance rather than using it). Therefore, while there is a difference in cash outlay in the beginning, the final operating decisions should be the same. Since the Homer City Owner Lessors claims of job loss and hindrance of growth are unsupported and speculative, EPA rejects those claims (for more EPA's analysis of the economic impact of the final Transport Rule, please see Preamble Section VIII.D.
Organization: Horsehead Corporation
Comment: 
Horsehead Corporation
By contrast, the alternative emission allowance allocation methodologies proposed through the Second NODA are based on historic heat input. See 76 Fed. Reg. 1114-6. Option 1 under the Second NODA would establish a baseline historic heat input value for each existing affected unit, and allowances would be allocated to each unit based on the unit's percentage share of the total baseline historic heat input for all existing affected units in the state. Id. at 1114-5. Option 2 is also based on historic heat input, but proposes to modify the allocations so that no source's allocation exceeds the higher of either historic actual emissions or emissions calculated using a 'clean emission factor', and the reasonably expected maximum future heat input. Id. Importantly, neither of these allowance allocation methods takes into account anticipated future generating rates for affected sources. [EPA-HQ-OAR-2009-0491-4003[1].1, p.1]
For these reasons, Horsehead asserts that the alternative allocation approaches proposed through the Second NODA are inconsistent with EPA's stated guiding principle for the Transport Rule of ensuring a reliable power supply. Instead, EPA should determine the allowance allocations in the final Transport Rule using the allocation method originally set forth in the Proposed Transport Rule, which reflects EPA's projections for future generating rates. [EPA-HQ-OAR-2009-0491-4003[1].1, p.2]
However, the alternative allowance allocation methods proposed through the Second NODA do not take into account future anticipated generating rates, Instead, these allocation methods are based principally on historic heat input. [EPA-HQ-OAR-2009-0491-4003[1].1, p.3]
Response: 

EPA disagrees that this allocation method would result in power reliability issues, particularly power reliability issues that would be avoided if allocations were made based on projected emissions. First, the variability limits allow units flexibility to meet annual fluctuations in electricity demand. Second, units will trade allowances and generate power based on the opportunity cost (benefit of generating electricity and associated emissions versus the price that could be obtained by reducing generation and selling excess allowances), meaning the same generation decisions will be made regardless of the allowance allocations.
Organization: Independence Power & Light (IPL)
Comment: 
Independence Power & Light (IPL)
The NODA presents two alternative allocation methodologies that 'rely largely on historic heat input data to determine unit-level allocations,' 76 FR at 1110/3, for possible use in implementing the proposed trading remedies. Id. at 1111/3. These alternatives contrast with the proposed Rule methodology (hereinafter 'Original Methodology') that is 'based on a combination of adjusted historic and adjusted projected emissions data,' Id. at 1113/2. Despite stating that all three alternatives are 'reasonable and consistent with the goals of CAA section 110(a)(2)(D)(i)(1),' Id. at 1113/3, EPA seeks comment on whether the two NODA alternatives ('Option 1' and 'Option 2') 'yield a reasonable distribution of allowances,' are consistent with the statutory goals, can be feasibly implemented, and are clear. Id. at 1116/2-3.  [EPA-HQ-OAR-2009-0491-3949[1].1, p.2]
Even if one assumes that any of the allocation methodologies proposed by EPA are reasonable and consistent with CAA goals, the methodologies place IPL in the proverbial 'Catch-22' because the Rule and NODA proposals appear to make it impossible for IPL to continue to operate its generating units should the Rule become final in any of the proposed forms. [EPA-HQ-OAR-2009-0491-3949[1].1, pp.2-3]
Allocation Options 1 and 2 Serve Only to Shift the Burden of Reductions Which are Nonetheless Unreasonable and Cannot Be Shown As Consistent with Statutory Goals
Shifting between the allocation methodologies involves a zero-sum game because the Missouri state budget under the Rule remains constant however allocations among Transport Units in the State are calculated (76 FR at 1114/1). Therefore, the only effect of using one methodology or the other is to shift allocations among Transport Units in the state. For IPL, the Original Methodology would not allow IPL to operate its unit, Blue Valley 3, more than three months per year and changing from the Original Methodology to either Option 1 or Option 2 would have the practical effect of limiting operation of Blue Valley 3 to only about 30 days per year. Thus any of the proposed allocation methodologies completely compromises IPL's ability to meet its statutorily-imposed obligation to serve native load without taking drastic steps that have a very high price tag. In short, the NODA Option 1 and Option 2 allocation methodologies as well as the Original Methodology are not reasonable as applied to IPL because their impact is the shutdown or curtailment of a unit that must be operated to satisfy statutory obligations to provide load to municipal customers. This would have the effect of taking electricity away from residents and businesses in the City of Independence because IPL is their sole power source. [EPA-HQ-OAR-2009-0491-3949[1].1, p.3]
The second and third so-called advantages of reliance heat input data relate to their being fuel-neutral and emissions-control-neutral, Id. at 1113/2, but no support is given as to why neutrality is the preferred means for furthering the statutory objectives. Again, simply looking at the NODA suggests otherwise; [EPA-HQ-OAR-2009-0491-3949[1].1, p.5]
Use of Historic Heat Input as an Allocation Basis Yields Unreasonable Results
The NODA assumes that use of historic heat input, aggressive emission factors, and historic capacity factors for various types of fuels and units yields a reasonable result, but that is not evident. If a source attempts to dispatch units to 'fit' the allocated allowances by dispatching gas units more (putting aside the risk of proposed Rule potential penalties and allowance surrenders associated with exceeding the allocations for a unit), then EPA's capacity factor for gas units, i.e., combustion turbines, 76 FR at 1115, Table 1, simply is inadequate to accommodate the emissions from such dispatching. The 14% capacity factor is a historic run rate for gas-fired combustion turbines used as peaking units to support primarily coal units being used to serve base load at a full historic capacity factor. If a coal unit has so few allocations that it cannot serve as the primary base load generation and the owner attempts to shift capacity to a lower emitting gas turbine at the same power station, the combined allowances for both units are simply inadequate to allow that power station to deliver the production necessary to meet statutory obligations related to base load customer demand. [EPA-HQ-OAR-2009-0491-3949[1].1, p.6]
When considering the factors raised by commenters to support Option 1, EPA should recognize that merely labeling characteristics of heat input data, like historical accuracy, as 'advantages' does not make them so; rather, it must be shown these characteristics actually further the statutory objective before they can be viewed as advantageous. E.g., North Carolina v. EPA, 531 F.3d 896, 908 (D.C. Cir. 2008) ('But the flow of logic only goes so far. It stops where EPA is no longer effectuating its statutory mandate'). That showing has not been made. [EPA-HQ-OAR-2009-0491-3949[1].1, p.6]
NODA Options 1 or 2 would also place added strain on SPP's planning and operations which depends on IPL's current generation capacity being available to maintain system-wide reliability. If IPL is required to reduce generation proportionately with the reduced emission allowances under Option 1 or Option 2 starting in 2012, that would have effects throughout SPP. Finally, IPL has a statutory obligation to supply power at levels requested by its customers that is not reduced by lower emissions allowances. [EPA-HQ-OAR-2009-0491-3949[1].1, pp.8-9]
The Options 1 or 2 allowances have not been shown to be reasonable, have not been shown to provide a better representation of the future, and will cause serious implementation problems. [EPA-HQ-OAR-2009-0491-3949[1].1, p.9]
For the reasons stated herein, IPL requests that EPA revisit the unit allocation methodologies to tailor the methodologies to be consistent not only with the CAA, but also the pervasive impact that the Transport Rule, if placed into effect, will have on the ability of electric generating unit owners to provide power to satisfy statutory mandates and customer needs. [EPA-HQ-OAR-2009-0491-3949[1].1, p.12]
Response: 

EPA notes that the use of historic heat-input data is not that it is historical, but that it is quality assured and, as noted by many commenters, more reflective of real world operation than projected heat-input or emissions.
Regarding the interaction of allocation method and dispatch of electricity generation, please see the "Effects of Allowance Allocations on the Competition between Power Plants " addendum to the RTC.  
IPL has only asserted, but not demonstrated that allocation method would affect grid reliability. EPA believes that operation decisions will be similar regardless of allocation method, because using an allowance to emit a ton of pollutant has an opportunity cost (equal to the price it could be sold for). As discussed in Section VII.C of the Preamble, EPA believes the 2012 and 2014 deadlines are feasible, will not result in significant coal retirements, and will not result in any reliability issues. More information on reliability can also be found in the Resource Adequacy and Reliability TSD. Finally, EPA notes that utilities can meet statutory requirements to supply power without having to generate it by buying power from other generators.
Organization: Kansas City Board of Public Utilities (BPU)
Comment: 
Kansas City Board of Public Utilities (BPU)
The NODA presents two alternative methodologies that 'rely largely on historic heat input data to determine unit-level allocations,' 76 FR at 1110/3, for possible use in implementing the proposed trading remedies. Id. at 1111/3. These alternatives contrast with the proposed Rule methodology (hereinafter 'Original Methodology') that is 'based on a combination of adjusted historic and adjusted projected emissions data,' Id. at 1113/2. Despite stating that all three alternatives are 'reasonable and consistent with the goals of CAA section 110(a)(2)(D)(i)(1),' Id. at 1113/3, EPA seeks comment on whether the two NODA alternatives ('Option 1' and 'Option 2') 'yield a reasonable distribution of allowances,' are consistent with the statutory goals, can be feasibly implemented, and are clear. Id. at 1116/2-3. In Kansas, serious questions arise under each issue as to a possible implementation of Option 1 or Option 2. As a basic premise, BPU submits that neither Option 1 nor Option 2 fall within the zone of reasonableness required to support EPA's proposal. [EPA-HQ-OAR-2009-0491-3978[1].1, p.2]
A. Allocation Options 1 and 2 Serve Only to Shift the Burden of Reductions [EPA-HQ-OAR-2009-0491-3978[1].1, p.2]
The questions raised in the NODA require comparison of the unit allocation results under each of the three methodologies because a zero-sum game is involved. As the Kansas state budget remains constant in calculating unit allocations (76 FR at 1114/1), the only effect of using one methodology or the other will be to shift allocations among units. See Attachment 1 hereto (spreadsheets showing changes in Kansas unit allocation allowances under the three methodologies). For BPU, switching from the Original Methodology to either Option 1 or Option 2 would compromise its ability to meet its statutorily-imposed obligation to serve native load without taking drastic steps that have a very high price tag. The proposed emissions allocations under Options 1 or 2 for NOx, both annual and ozone season, for BPU's units (Nearman Creek and Quindaro) would be in the range of 50% lower and for SO2 would be 45% lower than the allocations for those units under the Original Methodology. For Kansas, the resulting SO2 reductions from switching to Option 1 or 2 are borne by 10 out of 75 in-state units, while for NOx, about 15 units bear all the reduction. On the other side, the 10 biggest gainers under Options 1 or 2 for SO2 in Kansas receive over 90% of the gains. Similar results are found for NOx gainers. See generally Attachment. In short, the real effect of choosing Option 1 or Option 2 over the Original Methodology in Kansas would be to shift emission allocations from one small group of relatively large emitters to another small group of relatively large emitters. [EPA-HQ-OAR-2009-0491-3978[1].1, p.3]
There is scant effort in the NODA to justify such a shift. Although the NODA states that Option 1, by using units' 'historic heat input[,] would yield a distribution of allowances putting relatively greater burden on the higher-emission-rate units to reduce emissions or purchase additional allowances in order for the units to be in compliance,' 76 FR at 1114/1, no support is offered to demonstrate this result appropriately balances the affected public interests. Indeed, Option 2 appears to undercut such a notion by reducing the burden on higher-emission-rate units through a reapportionment of the lower-emission-rate units' allowances. See 76 FR at 1116, Table II (giving example). Likewise, the Original Methodology with entirely different allocations from those under Option 1 still meets the statutory test (Id. at 1113/3), further eroding the notion that placing a greater burden on higher-emission-rate units is the preferred, much less the only, means to satisfy CAA § 110(a)(2)(D)(i)(I). This notion has an additional hurdle to overcome in Kansas, which is currently in compliance with the currently-effective air transport rules thus negating a claim that any units needed to reduce emissions to be in compliance. [EPA-HQ-OAR-2009-0491-3978[1].1, pp.3-4]
The second and third so-called advantages of reliance heat input data relate to their being fuel-neutral and emissions-control-neutral, Id. at 1113/2, but no support is given as to why neutrality is the preferred means for furthering the statutory objectives. Again, simply looking at the NODA suggests otherwise; for example, Option 2 takes into account different capacity factors that are largely fuel-oriented, 76 FR at 1115, Table 1 & n. 4, and makes other adjustments that are not emissions-control-neutral. Id., steps 5 and 6. Making adjustments to offset 'neutrality' leaves an open question of whether a better approach would consider fuel differences and emission-control differences as integral parts of the estimation process, as is done in the Original Methodology. [EPA-HQ-OAR-2009-0491-3978[1].1, p.5]
The NODA asks whether Option 1 and Option 2 'raise any implementation concerns, such as concerns about feasibility of implementing the methodology' and the interrelated question of whether they 'yield a reasonable distribution of allowances?' 76 FR at 1116/1-2. As noted above, the Option 1 or Option 2 results cut BPU's allowance roughly in half as compared to those under the Original Methodology. This level of reduction in allowances does raise feasibility concerns because it confronts BPU with a Hobson's choice of attempting to put on controls sufficient to meet the greatly reduced emissions allowances before the 2012 deadline or purchasing emissions allowances (or, alternatively, purchasing power from other utilities) to make up any generation shortfalls resulting from its lowered allowances. [EPA-HQ-OAR-2009-0491-3978[1].1, pp.5-6]
Either choice presents severe problems for BPU's customers, who ultimately will foot the bill for the added costs. Either choice would also place added strain on the Southwest Power Pool ('SPP'), of which BPU is a member, and whose planning and operations depend on BPU's current generation capacity being available to maintain system-wide reliability. If BPU is required to reduce generation proportionately with the reduced emission allowances under Option 1 or Option 2 starting in 2012, that would have serious ripple effects throughout SPP. Aside from these operational issues, BPU has a statutory obligation to supply power at levels requested by its customers. How it meets that obligation while simultaneously meeting the reduced emissions allowances of Option 1 or Option 2 will be a matter of grave concern. While BPU's allowances under the Original Methodology are less than ideal, they are roughly double the alternative allocations, and therefore offer a much more feasible means for BPU to implement the emissions limits while satisfying its power supply obligations.  [EPA-HQ-OAR-2009-0491-3978[1].1, p.6]
D. Allocation Options 1 and 2 Would Fail for Fairness and Reasonableness [EPA-HQ-OAR-2009-0491-3978[1].1, p.6]
Neither Option 1 nor Option 2 'yield a reasonable distribution of allowances,' 76 FR at 1116/2, in Kansas. Two factors demonstrate both allowances are unreasonable. First, the disparity between results under the Original Methodology and Options 1 or 2 for large emitters is too wide to fall within the same zone of reasonableness. See Attachment (showing changes for all Kansas units). BPU's Original Methodology allocations (as well as other units who 'lost') declined under Options 1 or 2 by roughly 50% for all three trading programs (SO2, NOx Annual, and NOx Ozone Season), while 'gainer' units' allowance increased not by percentages, but by multiples. Id. [EPA-HQ-OAR-2009-0491-3978[1].1, p.6-7]
The assumption that Option 1 'losers' are the only higher-emissions-rate units in Kansas, and thus should bear, at least in Kansas' case, the entire burden of the shift from the Original Methodology to Options 1 or 2 allowances, lacks support. [EPA-HQ-OAR-2009-0491-3978[1].1, p.7]
Second, the logic of Option 2 suggests that only higher-emissions-rate units would receive re-allocated shares of the state-wide positive difference between a lower-emissions-rate units' 'historic-heat-input-based allocation and its' reasonable foreseeable maximum emissions level.'' 76 FR at 1115/3. Yet, in Kansas, the 'gainers' for the most part along with the 'losers' receive Option 2 reallocations at the same proportionate level. Under the logic of Option 2, this means 'gainer' units also have higher emissions rates than suggested by their heat inputs, and thus are the type of unit that should bear a greater share of the reduced emissions burden. Yet, under Options 1 or 2 as compared to the Original Methodology, these units obtain significantly more allowances which translates to a correspondingly lower burden. This inconsistent treatment between similarly situated units signals unreasonableness. [EPA-HQ-OAR-2009-0491-3978[1].1, p.7]
A similar situation involves the allowance allocations for gas turbine ('GT') units in Kansas. All the GT units in Kansas received a zero allowance under the Original Methodology, including two BPU units. Even though BPU's GT units ran during part of the 2003-09 period used to calculate the Options 1 and 2 allowances, the BPU units were not allocated any allowances. In contrast, other GT units in the state did receive Options 1 and 2 allowances. The NODA offers no explanation for this difference, which, again, appears to be a case of similarly situated units being treated dissimilarly. [EPA-HQ-OAR-2009-0491-3978[1].1, pp.7-8]
BPU submits that the Options 1 or 2 allowances have not been shown to be reasonable, have not been shown to provide a better representation of the future, and will cause serious implementation problems. While far from perfect, the Original Methodology is not quite as problematic; accordingly, of the three, the Original Methodology allowances should be used. [EPA-HQ-OAR-2009-0491-3978[1].1, p.8]
Response: 
A fuel- and control-neutral allocation methodology is desirable for several reasons described in Preamble Section VII.D, particularly as it is reasonably aimed at avoiding penalizing units that have already installed emissions controls. 
Besides the rationale given for a heat-input methodology, EPA notes that BPU does not explain why a "zone of reasonableness" is required for allocation differences among the methods EPA proposed.
Organization: Kansas City Power and Light Company (KCP&L)
Comment: 
Kansas City Power and Light Company (KCP&L)
KCP&L supports either of the alternative methodologies proposed in NODA 3 over the methodology set forth in the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3893[1].1, p.2]
Do these alternative methodologies yield a reasonable distribution of allowances?
Yes. The proposed alternatives are preferred over the Proposed Transport Rule in that units that have already installed controls or are planning to install controls are not penalized. In addition, heat input-based allowance allocations are also fuel neutral and do not reduce allowances for multi-fuel units that may have been burning a "cleaner" fuel over the previous few years. Basing allowance allocations solely on historical heat input also avoids the incorrect conclusions reached in the Proposed Transport Rule regarding early unit retirements and fuel switching. [EPA-HQ-OAR-2009-0491-3893[1].1, p.3]
Should the same methodology be used for each of the proposed Transport Rule trading programs, or should a different methodology be used for one or more such trading programs?
KCP&L does not see any reason to use different methodologies for each trading program. Consistency across all four trading programs would be preferred.  [EPA-HQ-OAR-2009-0491-3893[1].1, p.3]
Response: 
Thank you for your comment.

Organization: Lafayette Utilities System
Comment: 
Lafayette Utilities System
LUS supports the use of either of the two alternative heat-input based allowance allocation methodologies presented in the 2011 NODA over the allocations based on the Integrated Planning Model ('IPM') that was introduced in previous NODAs. EPA initially proposed allocating allowances based upon IPM v. 3.02. Later, in the September 1,2010 NODA, EPA revised the allocations, relying on IPM v. 4.10. The heat-input based allocation methodologies are superior to the IPM methodology originally offered by EPA for the following reasons. First, unlike the IPM methodology which is based upon modeled emissions and questionable economic predictions, the alternative allocation methodologies are based upon a unit's own historic heat input data. This heat input data is quality assured data that has been reported from continuous monitoring systems. As EPA indicated in the 2011 NODA, historic heat input data is 'more likely to be accurate' at a unit wide level than is modeled unit emissions. Second, historic heat input data is fuel-neutral, which means that allocations are not based on uncertain fuel adjustment factors. Third and finally, the heat input data is emissions control neutral and, therefore, does not result in reduced allocations for units that have installed, or plan to install, pollution control technology. This neutral approach is important as it does not penalize companies that have made, or plan to make, the capital investments needed to control emissions. In the end, allocations based on the heat-input methodologies would be more in line with actual operations at generation facilities than would the IPM v. 4.10 allocations. The use of the heat-input based methodologies would do a better job in achieving the goals of Section 110(a)(2(D)(i)(I) of the Clean Air Act, which are to improve long-term air quality and to encourage cost-effective emissions reductions. [EPA-HQ-OAR-2009-0491-3914[1].1, p.3]
In determining Option 1 allowances and in calculating the initial steps for the Option 2 allowances, EPA takes into account those units that had zero heat input data for one or more of the baseline years. For these particular units, EPA selects and averages the three highest, non-zero annual heat input values within the 2005-2009 baseline to reduce the likelihood that any single year's operations would determine that unit's allocations. While this method is a fair way to deal with those units that did not operate for one or more of the baseline years, it still does not address the issue of those units that had no megawatts hours during a particular baseline year due to being out of service. Even when a unit is out of service, it may still have heat input at very low levels for such activities as testing or maintenance. Under both Options discussed in this 2011 NODA, EPA still includes the annual heat input data from those years where heat input is uncharacteristically low and not at all in line with normal operating values, which means that the unit would, in fact, be unfairly penalized by having a single year's non-existent operations determine that unit's allocations. [EPA-HQ-OAR-2009-0491-3914[1].1, p.4]
Response: 

Where commenters specifically identified issues like partial years or uncharacteristically low levels of operation, EPA updated IPM data and adjusted allocation calculations to ensure that these years did not inappropriately affect allocation amounts. For more detailed discussion of EPA IPM v.4.10 assumptions and assumption updates, see the EPA IPM v.4.10 documentation and the "Transport Rule IPM Assumptions Response to Comments" in the Appendix, and  the unit level allocations can be found in the separate file titled "Unit Level Allocations under the FIP" published as an Excel file and available in the docket and on EPA's website. 
Organization: Lakeland Electric
Comment: 
Lakeland Electric
Lakeland Supports an Historic Heat Input-Based Allocation
Lakeland generally supports the use of an historic heat input-based allowance allocation method as compared to EPA's original allowance allocation proposal, which assigns allocations based on an individual unit's proportional share of state emissions assumed in developing the state emissions budget. The original allowance allocation proposal would rely on the IPM modeling platform, which, as many commentators have noted, contains undecipherable and apparently erroneous assumptions, in addition to material factual errors. Assuming EPA could correct the IPM model, historic heat input data are still more likely to be accurate at a unit-specific level than model-projected unit-level emissions. Moreover, historic heat input data are fuel-neutral and, unlike EPA's original proposal, will not penalize emission units that have already installed expensive emission controls. [EPA-HQ-OAR-2009-0491-3892[1].1, p.5]
The use of the three highest heat inputs of the past five years to derive annual averages (seasonal for ozone) appears to be a reasonably accurate approach to representing the past performance for most units. As explained in prior comments, EPA's original proposal to use 2008 and 2009 as baseline years for NOx and SO2 emissions, respectively, would not represent normal operating conditions for many of the units regulated under the Transport Rule. Additionally, EPA has never adequately explained its proposed use of different baseline years for the two pollutants. [EPA-HQ-OAR-2009-0491-3892[1].1, p.5]
Response: 
Thank you for your comment.

Organization: Luminant
Comment: 
Luminant
The proposed allocations in this NODA significantly alter the allocations originally proposed, unfairly advantages the use of some types of fuel, disadvantaging coal with no commensurate environmental benefit. EPA has a long history of rulemakings that recognize the inherent differences in fuels with regard to regulatory compliance. EPA therefore should go back to the initial CATR allocation incorporated into the initial proposed rule of August 2, 2010. [EPA-HQ-OAR-2009-0491-3980[1].1, p.5]
Furthermore, Luminant recommends that EPA disregard the allocation methodology options as laid out in the 3rd NODA. Should EPA continue to pursue the development of CATR, [EPA-HQ-OAR-2009-0491-3980[1].1, p.6]
Response: 
Thank you for your comment.

Organization: Maryland Department of Environment (MDE)
Comment: 
Maryland Department of Environment (MDE)
Overall, ARMA commends EPA for their approach to allocations and state implementation plans as reflected in the Transport Rule NODA. We strongly support EPA's use of historic heat input for the two alternative allocation methodologies and EPA's proposal for an abbreviated SIP and full SIP allowing states to take control of allocation to our sources. [This comment can also be found in section XX.E.] [EPA-HQ-OAR-2009-0491-3972[1].1, p.1]
The Air and Radiation Management Administration commends EPA for their positive response to Maryland's comments on the Transport Rule proposal (75 Federal Register 45210), such as our comments expressing disagreement with the proposal's methodology for allocating annual and ozone season NOx and SO2 allowances based on historic emissions rates. We commend EPA for using a heat input based emissions limit for the two methodologies offered in the NODA. In our comments on the proposed Transport Rule, Maryland recommended that EPA recalculate allocations using heat input or output based emissions limits. We are pleased that EPA has taken this into consideration. Overall, ARMA supports the Transport Rule NODA's two alternative allocation methodologies, which are both based on historic heat input, and award more allowances to units that acted early to control their emissions, i.e. cleaner units. [EPA-HQ-OAR-2009-0491-3972[1].1]
While we support both alternative allocation methodologies in place of the allocation methodology in the proposed Transport Rule, we would prefer Option 1. As proposed, Option 1 does more to reward the units that acted early to control their emissions. These units are already contributing to cleaner air and reduced health risks to the population. Units that acted early to reduce their emissions, such as sources under the Maryland Healthy Air Act (HAA), should be rewarded accordingly with more allowances, while units with greater uncontrolled emissions should be forced to purchase allowances. [EPA-HQ-OAR-2009-0491-3972[1].1, pp.1-2]
c. Clarity and feasibility of the methodologies and their implementation
ARMA found the alternative allocation methodologies easy to understand. Also, implementation of these methodologies should be straightforward for Maryland. [EPA-HQ-OAR-2009-0491-3972[1].1, p.2]
Response: 
Thank you for your comment.

Organization: Minnesota Power 
Comment: 
Minnesota Power 
Allowance Allocations under the Proposed Limited Interstate Trading Remedy.
MP notes that the two alternative allocation methodologies involve redirecting allocations to a heat input basis rather than a historic emissions basis. These changes have the effect of redirecting NOx budget allocations from coal-fired generation units to natural gas fired generation units. This redirection of allocations has the effect of increasing the compliance cost for coal-fired generating units through replacement of lost allowance allocations via market purchases or providing for greater percentage emission reductions than would be otherwise required under the Transport Rule. Yet, EPA does not provide analysis that justifies the need for this redirection of allocations. In its earlier Technical Support Documentation, EPA had provided estimates of budgets that were prepared before emissions data was updated and with this NODA, EPA has estimated budgets after emissions data updates for the two allocation alternatives. MP requests that EPA clarify its basis for redirecting these allocations and provide an estimate of how NOx budget compliance costs requirements on existing coal generating units are being specifically impacted by this alternative methodology for budget allocations. [EPA-HQ-OAR-2009-0491-4009[1].1, p.4]
Response: 

EPA's modeling of the Transport Rule with the Integrated Planning Model (IPM) contained no specific description of allocations. Since entities will make generation decision based on opportunity cost (which includes the value of selling an allowance rather than using it), the same compliance decisions, and therefore system-wide compliance costs, should be made regardless of allowance allocations, given a functional trading market.
Organization: National Mining Association (NMA)
Comment: 
National Mining Association (NMA)
NMA strongly opposes EPA's use of a heat-input method to allocate allowances. Such a method provides an extremely large windfall to natural gas-fired units at the expense of coal-fired units that is not justified by Clean Air Act section 110(a)(2)(D)(i)(I) or any legitimate public policy purpose that derives from that statutory provision. [EPA-HQ-OAR-2009-0491-4013[1].1, p.1]
NMA believes that the two heat-input options are legally problematic. As EPA recognizes in NODA-3, EPA's discretion to allocate allowances to the unit level must be guided by the language and policy of section 110(a)(2)(D)(i)(I) to reduce emissions in a cost effective manner. NMA does not believe that EPA has justified the windfall to natural gas on that basis. [EPA-HQ-OAR-2009-0491-4013[1].1, p.2]
I. EPA's Heat-Input Based Allocation Methods Provide an Unfair, Unjustified and Legally Suspect Windfall Profit to Natural Gas. [EPA-HQ-OAR-2009-0491-4013[1].1, p.2]
There is more than sufficient information at this point, however, to conclude that the two heat-input allocation methodologies provide an unjustified and legally suspect windfall profit for natural gas generation and impose a significant  -  perhaps insurmountable  -  burden on coal-fired generation. [EPA-HQ-OAR-2009-0491-4013[1].1, p.3]
A. Heat Input Based Allocations Provide a Substantial Windfall to Natural Gas at the Expense of Coal.
As shown in more detail in the attached Allocation Method Comparison Exhibit, both heat-input based allocation methods result in large windfall profits to certain generating units  -  in particular natural gas. The following is a summary of some of the points our analysis showed. [EPA-HQ-OAR-2009-0491-4013[1].1, p.3]
E. EPA's Heat-Input Methodologies Are Likely Legally Invalid.
Although EPA in NODA-3 states that it has significant discretion in allocating allowances at the unit level, the Agency recognizes that such discretion is not boundless. The Agency "recognizes that it must select an allocation methodology that is reasonable and consistent with the goals of CAA section 110(a)(2)(D)(i)(I) of the Act, including improving long-term air quality and encouraging cost-effective emissions reductions." EPA's rationale for using heat-input methodology, however, seems to contradict this limitation on its discretion. [EPA-HQ-OAR-2009-0491-4013[1].1, pp.7-8]
1. The three rationales that caused EPA to consider heat-input methodologies.
EPA states that NODA-3 responds to comments that recommended consideration of a heat-input methodology based on three concerns: [EPA-HQ-OAR-2009-0491-4013[1].1, p.8]
(i) Historical heat input data are more likely to be accurate at a unit level than projected unit-level emissions and are generally based on quality-assured data reported by sources from continuous monitoring systems.
(ii) Historical heat input data are fuel neutral.
(iii) Historical heat input data are emissions-control-neutral and thus do not yield reduced allocations for units that installed or are projected to install pollution control technology. [EPA-HQ-OAR-2009-0491-4013[1].1, p.8]
None of these rationales pertain to the purposes of CAA section 110(a)(2)(D)(i)(I) as articulated by EPA. Instead, the rationales seem more related to the notions of fairness and equity that underlay the fuel factors in the Clean Air Interstate Rule that the court struck down in North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008). [EPA-HQ-OAR-2009-0491-4013[1].1, p.8]
The second and third concerns above  -  fuel and emissions-control neutrality  -  are equitable considerations that do not pertain to eliminating the significant contribution of sources "within a state" to downwind nonattainment (or interference with maintenance) on a cost-effective basis. These concerns appear to be based solely on the view that it is not fair that sources that utilize natural gas or that have already installed controls do not get as many allowances under the emissions methodology as they would under a heat-input methodology. But if, as EPA states, a guiding principle for allocating allowances at the unit level is "encouraging cost-effective emissions reductions" by sources "within a state," then fairness is not a relevant factor. [EPA-HQ-OAR-2009-0491-4013[1].1, pp.8-9]
Moreover, it is decidedly no less fair to utilize historical and projected emissions as a basis for allocating allowances at the unit level than it is to utilize historical and projected emissions to determine state budgets. Indeed, EPA appears to be acting arbitrarily in (a) determining a state's budget by essentially summing up the amount of cost-effective emissions reductions each covered unit in a state can make but then (b) allocating allowances to the individual units from that state budget using some different methodology. Severing the link between emissions and allowances suggests that EPA is allocating allowances on a basis that is not related to eliminating "significant contribution" through cost-effective emissions reductions. [EPA-HQ-OAR-2009-0491-4013[1].1, p.9]
In fact, it is the heat-input methodology that gives some units an advantage over others based on fuel and controls. As stated, the reason EPA is considering such methodology is because of the perception that natural gas units and units that have controls somehow deserve a greater number of allowances. The result of switching methodologies, however, is not an improvement in air quality through cost-effective emission reductions but a large transfer of wealth from coal units to natural gas units. [EPA-HQ-OAR-2009-0491-4013[1].1, p.9]
2. EPA's air quality rationale.
EPA offers one rationale in a single paragraph for the heat-input methodology that does address air quality. EPA states that the reduced allowance allocations to higher-emission-rate units would put "relatively greater burden" on them "to reduce emissions or purchase additional allowances." 7 EPA states that it "believes that, because higher-emission-rate units generally are responsible for a greater share of a state's total emissions and thus bear greater responsibility for a states' significant contribution and interference with maintenance, this distribution of burden is consistent with the goals of CAA section 110(a)(2)(D)(i)(I)." [EPA-HQ-OAR-2009-0491-4013[1].1, pp.9-10]
EPA's reasoning in this regard is not entirely clear, and NMA encourages EPA to explain its rationale more clearly. Based on NMA's understanding, however, EPA's rationale does not hold up. [EPA-HQ-OAR-2009-0491-4013[1].1, p.10]
First, although higher-emission-rate units unquestionably are responsible for a greater share of a state's significant contribution, it does not follow that a change in methodology is needed to make sure these units eliminate their "contribution to significant contribution."  [EPA-HQ-OAR-2009-0491-4013[1].1, p.10]
Second, if EPA's point is that higher-emission-rate units should be required or incented to make additional emission reductions beyond the cost-effective level, then EPA's rationale contradicts the basis of the rule, which is to require cost-effective emission reductions. It appears from EPA's reasoning that EPA thinks higher-emission-rate units should over-control (make emission reductions greater than those that cost-effectiveness requires) or even to shut down, so that lower-emission rate units will control less or not at all. But the premise of the rule is to require only those controls that are cost-effective; indeed, as noted, that is how the state budgets were determined. It thus does not follow that higher-emission-rate units should bear an emission reduction burden that is greater than is justified under EPA's cost-effectiveness test, or that lower-emission rate units should bear a lower emission reduction burden. [EPA-HQ-OAR-2009-0491-4013[1].1, p.10]
Third, EPA's air quality rationale proceeds from a faulty assumption. EPA states that "[t]he methodology used to allocate allowances to individual units in a particular state has no impact on that state's budget...." But since EPA determined state budgets in the first place by summing up the amount of emission reductions that in-state units could cost-effectively make, the method of allocating allowances does make a difference. As EPA notes, the statute requires the state to eliminate the significant contribution of sources "within the state." Having used historical and projected emissions of units "within the state" to determine state budgets, EPA necessarily has determined the specific "contribution to significant contribution" of each source "within the state." Thus, as stated, for EPA to then determine that the allowance allocations should not match the needed emission reductions would seem to indicate that EPA is motivated by factors that do not pertain to the basic goal of eliminating a state's significant contribution. [EPA-HQ-OAR-2009-0491-4013[1].1, pp.10-11]
Now, in NODA-3, EPA seeks comment on three different allocation methods, but there remains insufficient information to assess the proposals. [EPA-HQ-OAR-2009-0491-4013[1].1, p.11]
NMA urges EPA not to adopt either heat-input methodology option, although Option 2 is preferable to Option 1. [EPA-HQ-OAR-2009-0491-4013[1].1, p.15]
As demonstrated below, our analysis shows that the two NODA-3 heat-input based allocation methods provide a substantial windfall profit to natural gas generation  -  at coal-fired generation's expense  -  and lead to absurd over-allocations to certain technology classes/plant types, chiefly combined cycle natural gas. [EPA-HQ-OAR-2009-0491-4013[1].2, p.1]
We totaled these record values for all combined cycle units and then compared this record reported historical emissions value (for all combined cycle units) to the Option 1 and Option 2 allocations (for all combined cycle units). It is important to note that our record high total for the combined cycle technology class has never been achieved in a single year. In order for our record high total to be achieved, every single combined cycle unit subject to the rule would have to have record emissions in the same year. [EPA-HQ-OAR-2009-0491-4013[1].2, p.10]
We then repeated this process for the combustion turbine technology class.
This analysis demonstrates that under the NODA-3 heat-input based allocation methods, combined cycle units, and to a lesser extent combustion turbines, receive an extraordinary over-allocation. Even using this implausibly-high, record emissions value as a comparison, these technology classes are allocated allowances orders of magnitude greater than emissions. This is true under both Option 1 and Option 2 allocation methods. [EPA-HQ-OAR-2009-0491-4013[1].2, p.10]

7 Id. at 1114/1. Of course, putting a greater burden on high-emission-rate units to purchase more allowances is not an air quality consideration. [EPA-HQ-OAR-2009-0491-4013[1].1, p.9]
Response: 
EPA notes that CAA sections 110(a)(2)(D)(i)(II) and 302(y) give it broad authority for choosing an allocation method. This is further discussed in the Preamble Section VII.D. EPA notes that CAA section 110(a)(2)(D)(i)(I) pertains to prohibiting emissions "within a state" that significantly contribute to nonattainment or interfere with maintenance in another state, and that the state emission budgets, not the unit-level allocations, under the Transport Rule accomplish this.
As for the interaction of unit-level allocations and the state budgets, EPA notes that its modeling of the Transport Rule with the Integrated Planning Model (IPM) contained no specific description of allocations. Since entities will make generation decision based on opportunity cost (which includes the value of selling an allowance rather than using it), the same compliance decisions should be made regardless of allowance allocations, given a functional trading market.
Organization: Nelson Industrial Steam Company (NISCO)
Comment: 
Nelson Industrial Steam Company (NISCO)
If EPA does not allow the states to make the allocations, then as between IPM based allocation methods and heat-input based allocation methods, NISCO supports use of the heat input based options provided that EPA corrects the heat input data for NISCO as discussed below. As acknowledged by EPA in the January 7, 2011 NODA, historic heat input data is 'more likely to be accurate' at a unit wide level than are modeled unit emissions. Also, as indicated by numerous commenters, historic heat input data is fuel-neutral and does not raise concerns regarding the use of fuel adjustment factors that can cause inequities in allocation schemes. Finally, the heat input data is emissions control neutral and, therefore, does not result in reduced allocations for units that have installed, or plan to install, pollution control technology. This neutral approach is important as it does not penalize companiies that have made, or plan to make, the capital investments needed to control emissions. [EPA-HQ-OAR-2009-0491-4026, p.4]
Response: 

Thank you for your comment.

Organization: New York State Department of Environmental Conservation
Duke Energy
Wolverine Power Supply Cooperative
Old Dominion Electric Cooperative
Dayton Power and Light Company (DP&L)
Comment: 
Dayton Power and Light Company (DP&L)
This third NODA proposes alternative methodologies based upon heat input, and DP&L is generally supportive of this methodology as described below. [EPA-HQ-OAR-2009-0491-3973[1].1, p.2]
:: Allocations should be based upon historical heat input. [EPA-HQ-OAR-2009-0491-3973[1].1, p.4]
:: Allocations should not provide an inordinate number of SO2 allowances to units that combust fuels containing no sulfur. [EPA-HQ-OAR-2009-0491-3973[1].1, p.4]
DP&L appreciates the opportunity to comment on the proposed rule. The alternatives offered herein are generally an improvement over the original proposal. [EPA-HQ-OAR-2009-0491-3973[1].1, p.4]
Duke Energy
  Option 1 and Option 2 Allocation Methodologies  
In NODA 3 EPA requests comment on two alternative allocation methodologies that use historic heat input as the basis for allocating state SO2 and NOx budgets to individual affected units. As Duke Energy indicated in its comments on the PTR, Duke Energy supports the use of historic heat input as the basis for allocating SO2 and NOx state budgets under any final Transport Rule. Duke Energy believes the use of historic heat input, properly configured, is a better way of distributing allowances than the method EPA used in developing its PTR. Duke Energy agrees with EPA that the allocation methodology has no impact on the rule's ability to satisfy the statutory mandate of Clean Air Act section 110(a)(2)(D)(i)(I) to eliminate significant contribution and interference with maintenance in downwind states, meaning that the use of historic heat input as the basis for allocating allowances to individual units is a legally acceptable option. Any allocation methodology used, however, must reasonably allocate allowances to the affected sources and not over-allocate allowances to certain sources at the expense of others. While the Option 1 and Option 2 allocation methodologies presented in NODA 3 would not adversely impact the rule's ability to satisfy the statutory mandate of Clean Air Act section 110(a)(2)(D)(i)(I) to eliminate significant contribution and interference with maintenance in downwind states, both options as presented are flawed because each would allocate a windfall of SO2 allowances to low emitting units at the expense of coal-fired units. [EPA-HQ-OAR-2009-0491-3965[1].1, pp.1-2]
While Duke Energy does not support the SO2 allocations to low emitting units under Options 1 or 2, Duke Energy does support the historic heat input based methodology EPA uses in Option 1 and Option 2 for determining a unit's Initial SO2 Allocation. The use of the average of the 3 highest non-zero annual heat inputs from 2005 to 2009 is reasonable. Duke Energy also supports EPA's decision to use annual emissions over the period 2003 through 2009 to determine each unit's Annual Historical Cap. [EPA-HQ-OAR-2009-0491-3965[1].1, p.10]
New York State Department of Environmental Conservation
In response to EPA's request for comment on the allocation methodology, the Department supports the improvements contained in EPA's NODA to update the unit level allocations based upon a rolling average of heat inputs for the facility.  The Department, however, recommends an additional important step in the unit level allocation process.  This additional step would be to limit the allocation to any unit to any maximum emission level contained in a permit or other enforceable instrument.  This prevents a facility from receiving an allowance windfall in the allocation process.[EPA-HQ-OAR-2009-0491-3937[1].1, p.2]
Old Dominion Electric Cooperative
While we appreciate EPA proposing additional allowance allocation options in the NODA III, they fall significantly short of meeting rational decision making. The NODA III proposed allocation options are heavily gas bias. [EPA-HQ-OAR-2009-0491-4004[1].1, p.2]
OOEC agrees with EPA's assertion that it has 'significant discretion to select an allocation methodology that is reasonable and consistent with the goals of the CAA'...  However, CATR NOOA III options 1 and 2 do not function to distribute allowances in a reasonable, sensible or equitable manner. They are both unreasonably gas bias. [EPA-HQ-OAR-2009-0491-4004[1].1, p.3]
As a group combined cycle (CC) and turbine units receive far more allowances than these units can reasonably use. [EPA-HQ-OAR-2009-0491-4004[1].1, p.4]
Wolverine Power Supply Cooperative
The January 7, 2011, NODA requests comment on two alternate allocation mechanisms that are designed to alleviate the clean-unit discrimination that we identified, but do not address further the uncertainty resulting from the compliance mechanism of market concentration and allowance hording by large generators potentially resulting in a lack of a robust trading program. Aside from the potential relief on the allocation mechanism(s). [EPA-HQ-OAR-2009-0491-4014[1].1, p. 3]
The use of more traditional historical heat input as the allocation basis in both Options 1 and 2, as we recommended in our October 1, 2010, comments, would go a very long way in remedying the clean energy penalty in the proposed Transport Rule. This heat-input approach would eliminate perpetual allocations to the most polluting units, reward consumers who purchase power from newer clean sources, and overall demonstrate a rational policy to move the nation to a clean energy future. The heat-input based allocation mechanism would also put a relatively greater burden on the higher emitting units and provide more of an incentive to further control those units. [EPA-HQ-OAR-2009-0491-4014[1].1, p. 4]
We also note that heat-input based allocation methods would be lawful under North Carolina. [EPA-HQ-OAR-2009-0491-4014[1].1, p. 4]
Wolverine is supportive of the three-highest-out-of-five year heat-input baseline calculation; however, we believe that 2010 data now available should be included in the baseline. The relatively hot summer of 2010 would make the baseline more representative of normal conditions and operating duties. [EPA-HQ-OAR-2009-0491-4014[1].1, p. 4]
Wolverine believes that clean generating units should be allocated adequate allowances to operate without the need to turn to the allowance market; however, we also believe that a simple subsidy of excess allowances to clean and cleaner units is not in the best interest good of energy policy. The allocation scheme should not be used to favor one fuel over another, nor one technology over another, in the interest of maintaining a diverse electric energy mix for the nation. [EPA-HQ-OAR-2009-0491-4014[1].1, p. 4]
Response: 
Thank you for your comment.

Organization: NRG Energy
Comment: 
NRG Energy
 Allocation Methodology  -  NRG supports the initial allocation methodology provided in the July 6, 2010 version of the proposed Transport Rule that was based on historic adjusted 2009 emissions and/or adjusted 2012 projected emission data. We do not endorse either Option 1 or Option 2 as they do not enhance the Clean Air Act ("CAA") or Clean Air Transport Rule ("CATR") program objectives, are not the correct basis for allowance allocation, and place disproportional compliance burden on coal facilities, especially in states with significant gas generation.   [EPA-HQ-OAR-2009-0491-3933[1].1, p.2]
 Transfer of Wealth and Interstate Commerce Conflict  -  NRG believes a "Heat Input" approach provides an over allocation of allowances to sources that do not use them resulting in a transfer of wealth which is not the intent of the CAA or the CATR.   [EPA-HQ-OAR-2009-0491-3933[1].1, p.2]
In the January 7, 2011 NODA options proposed by EPA, allocations are based on historical heat input. We are concerned that with allocations based on 'heat input,' a gas unit that emits no SO2 and incurs no costs would get free allowances, while a coal unit that needs to invest hundreds of millions to protect public health and the environment gets far fewer allowances than it needs to cover its compliance costs. The result is a pure windfall for gas generators and punitive costs for investors and customers of coal plants. [EPA-HQ-OAR-2009-0491-3933[1].1, p.2]
 NRG supports the initial allocation methodology provided in the July 6 version of the proposed Transport Rule that was based on historic adjusted 2009 emissions and/or adjusted 2012 projected emission data. We do not endorse either Option 1 or Option 2 as they do not enhance the CAA or CATR program objectives, are not the correct basis for emissions allocation, and act to transfer additional compliance burden from natural gas facilities to coal facilities.   [EPA-HQ-OAR-2009-0491-3933[1].1, p.3]
NRG previously filed comments in support of EPA's proposed allocation methodology based on projected emissions. After review of EPA's proposed Option 1 and Option 2, we retain this position. [EPA-HQ-OAR-2009-0491-3933[1].1, p.3]
In addition, this method does not match the state allocation calculation. If a state variability is exceeded, the severely short units will have a tougher time meeting their own variability requirements. For any variability exceedances, there would be yet another allowance due. It could create situations where severely short coal would have to buy a large amount of allowances from a very limited number of in-state allowance holders. [EPA-HQ-OAR-2009-0491-3933[1].1, p.4]
In the NODA, EPA explained that the proposed options were based on interveners' comments and their reasoning for a heat input based approach. We do not agree with this reasoning for the following reasons:  
Simplicity and Certified Data Advantage  -  A good, thoughtful approach should not be sacrificed for simplicity. Further, using historical heat input data, even certified data, is outdated and irrelevant to current or pending conditions and opportunities for emissions reduction.   [EPA-HQ-OAR-2009-0491-3933[1].1, p.4]
 Controlled Unit Penalty  -  EPA's concern that the allocation process can penalize controlled coal units or those planning to control is not valid. The state allocations and July plant allocations are based on economic neutrality, with the exception of Group 1 units that are targeted for further SO2 reductions in Phase 2. Option 1, penalizes coal, controlled or uncontrolled, in favor of gas in states where there is significant gas generation. Option 2 increases SO2 allocations to coal and both controlled and uncontrolled units are treated the same.  [EPA-HQ-OAR-2009-0491-3933[1].1, p.4]  
In contrast, historic heat input only looks at the past and is based on the assumption that all plant data except heat input can be ignored. [EPA-HQ-OAR-2009-0491-3933[1].1, p.4]
 NRG believes a heat input approach provides an over-allocation of allowances to sources resulting in unjustified rewards and a transfer of wealth which is not the intent of the CAA or the CATR.   [EPA-HQ-OAR-2009-0491-3933[1].1, p.4]
An allocation based on projected emissions is the preferred method for allocation. However, in the event EPA opts for alternative allocation methods, NRG recommends Option 2 over Option 1 as Option 2 attempts to remedy (as stated in the rule) the over-compensation to lower emitting units at the expense of higher emitting units. It appears that by virtue of EPA considering Option 2, EPA must recognize as we do that Option 1 is fundamentally flawed. [EPA-HQ-OAR-2009-0491-3933[1].1, p.7]
Response: 
As for NRG's further comment that units with lower allocations may have a tougher time meeting their own variability limits, EPA notes that units may band together under a common designated representative to reduce the risk of exceeding variability limits, as described in Preamble Section VII.E.
Organization: Oglethorpe Power
Comment: 
Oglethorpe Power
Consistent with earlier comments, on the proposed CATR and NODA 1, Oglethorpe Power believes that EPA should use historical heat input, from a sufficient sampling period (5 year minimum), as the basis for determining allowance allocations for existing units from state budgets. Since both of the options proposed in NODA 3 use historical heat input from at least a 5 year baseline as their basis for determining allowance allocations, Oglethorpe Power strongly supports either option in lieu of the approach proposed last year in the CATR, where EPA would base its unit allocations on computer model projections of both future individual unit utilization and emission reduction capability. Use of historical data better reflects unit operations, rather than the combination proposed last year in the CATR, which was merely a one year baseline massaged by speculative assumptions on anticipated emissions controls and future operations. [EPA-HQ-OAR-2009-0491-3896[1].1, p.4]
This approach, however, still fails to include provisions for updating allocations for all units (new and existing), as more recent operational history becomes available. As currently proposed, new units, i.e., those units that while covered under the CATR's applicability provisions do not commence commercial operations before January 1, 2009, will remain new units and thus, for allocations to individual units, must always look to the 3 % new source set-aside available to them on a yearly basis. CAIR, on the other hand, uses a rolling 5-year look back of operations, constantly updating allowance allocations for all units, allowing new units to become existing units over time. That kind of approach was always an integral part of the CAIR allocation system, and we remain mystified why it has apparently been abandoned by the Agency in the CATR. Thus, Oglethorpe Power continues to support an allocation approach, such as that in the CAIR, which would continually update operational baselines, reclassifying new units over time as existing units and then allocating allowances to all existing units using a uniform methodology. [EPA-HQ-OAR-2009-0491-3896[1].1, p.4]
Response: 

The methodology for allocating allowances two new units and the size of the new unit set-aside in the final rule are reasonable and provide for a reasonable allocation of allowances to new unit.  The final rule entails state-specific set-asides that are tailored to the amount of planned new units (online after January 1, 2010) in each covered state.  The result is a greater percentage of the state budget set-aside for new units than would have otherwise occurred under the proposed method for calculating new source-set aside budgets.  As units are retired, the allocation for those units is diverted to the new unit set-aside, as described in Preamble Section VII.D.2. Over time, the new unit set aside will grow, making additional allowances are available for new units.Organization: Ohio Utility Group (OUG)
Comment: 
Ohio Utility Group (OUG)
While allocation Option 1 and Option 2 are substantively distinct and create practical implications of varying degree among the member companies, the Utilities support the underlying theory of both Options as they are driven by heat input data and, ultimately, result in a more reasonable, and accurate, allocation of SO2 and NOx allowances. [EPA-HQ-OAR-2009-0491-4005[1].1, p.2]
In the comments below, the Utilities will demonstrate why an allocation of SO2 and NOx allowances based on heat input is not only the more appropriate method, but also necessary. In addition, the Utilities will highlight aspects of the alternate allocation methods that can be further improved and identify inaccuracies in the data used to support these methods. [EPA-HQ-OAR-2009-0491-4005[1].1, p.2]
II. AN ALLOCATION METHOD BASED ON HEAT INPUT RECOGNIZES OPERATIONAL INTRICACIES CRITICAL TO DETERMINING ADEQUATE UNIT-LEVEL ALLOCATIONS WITHOUT UNDERMINING THE TRANSPORT RULE AND THE GOALS WHICH IT WAS DESIGNED TO ACHIEVE [EPA-HQ-OAR-2009-0491-4005[1].1, p.2]
The Utilities support an allocation method based on heat input for several reasons. First, allocating SO2 and NOx allowances based on heat input recognizes unit-specific capabilities and operational tendencies, thereby resulting in unit allocations that are more reasonable, accurate, and justifiable than the allocation guessing game based on projected emissions. The methods proposed in NODA 3 also alleviate - to some degree - compliance issues related to the 2012 deadline by reducing the risk of over allocation and, at the same time, reducing under allocation. [EPA-HQ-OAR-2009-0491-4005[1].1, p.2]
Furthermore, an allocation method based on heat input facilitates the strongest balance between acknowledging what is reasonable/feasible based on concrete data and maintaining the integrity of the Transport Rule. Historic heat input data are fuel neutral and emissions-control neutral. Unlike the method in the proposed rule which raised issues of technical infeasibility, the allocation methods in NODA 3 do not punish those facilities that have already invested in state-of- the-art emissions control technology. Instead, allocation by heat input still provides incentive for the largest emitters - which, in turn, are likely to be those that have made the largest investment in control technology - to reduce emissions, but will also trickle down and require reductions from smaller emitters. When SO2 and NOx are allocated based on heat input, the overall amount of emissions reductions is distributed proportionally, thereby reducing interstate transport while being mindful of what is actually feasible. [EPA-HQ-OAR-2009-0491-4005[1].1, pp.2-3]
The heat input Options in NODA 3 also preserve grid reliability by providing critical peaking units with a sufficient number of allocations to operate when necessary. Under the proposed Transport Rule, allocations to peaking units were severely reduced or eliminated entirely. By considering historical heat input, peaking units receive their representative fair-share of SO2 and NOx allowances. [EPA-HQ-OAR-2009-0491-4005[1].1, p.3]
While the alternative allocation methods based on heat input are preferred over the method employed in the proposed rule, the effectiveness of those methods is limited by their own flaws as well as more fundamental flaws of the proposed Transport Rule. With respect to the use of historic heat input, both allocation methods proposed in NODA 3 are flawed. Specifically, both methods over allocate SO2 to gas-fired units. Gas-fired units are historically low SO2 emitters and do not require the amount of allocations they would receive under the proposed methods. The Utilities suggest excluding these units from the Transport Rule's SO2 program entirely. [EPA-HQ-OAR-2009-0491-4005[1].1, p.3]
Response: 
Thank you for your comment.

Organization: Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
Comment: 
Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation
If EPA proceeds with a final PTR with rational state budgets for Indiana and Ohio, OVEC is supportive of the alternative allocation methods proposed in the NODA based on historic heat input. However, OVEC is concerned that while the proposed allocation methods represent a move in the right direction on how state budgets would be proportionally allocated [EPA-HQ-OAR-2009-0491-4010[1].1, p.2]
In short, while allocation methods based on heat input assumptions are preferable to the allocation methods originally proposed in the PTR, they do not produce a rational and reasonable result when the state budgets in Indiana and Ohio are too stringent to be met on the widespread and accelerated basis EPA is proposing. [EPA-HQ-OAR-2009-0491-4010[1].1, p.2]
Even assuming that EPA corrected its overly stringent emission limitations and time for compliance, there are still aspects of the allocation methodologies in the NODA that can and should be corrected. [EPA-HQ-OAR-2009-0491-4010[1].1, p.2]
B. The Allocation Methods do Not Account for the Inherent Characteristics of Wet-Bottom Boilers
OVEC respectfully submits that the proposed allocation procedures do not go far enough to address the concern raised in OVEC's original comments about the inherent NOx characteristics of OVEC's boilers. All of the OVEC Units are equipped with wet-bottom boilers. EPA has previously acknowledged that units with wet-bottom boilers are inherently higher NOx emitters than dry-bottom boilers, and has traditionally set NOx emission rates for wet bottom boilers at almost twice that of other types of boilers. See 61 Fed. Reg. 67,113-114 (Dec. 19, 1996). However, EPA continues to ignore those same characteristics in the current rulemaking. As noted above, because of the inherent nature of wet-bottom boilers, OVEC's NOx controls at the Kyger Creek Plant would have to work absolutely perfectly at all times for the Kyger Creek units to comply with the proposed NOx limitations. EPA's failure to continue to consider the same boiler characteristics as it has in the past, combined with the lack of meaningful trading provisions, means that any NOx control equipment problems after 2013 may force Kyger Creek to curtail production as the only possible way to comply with its proposed NOx limitations. [EPA-HQ-OAR-2009-0491-4010[1].1, p.6]
Response: 

EPA notes that units have many compliance options beyond curtailing production, including buying allowances, banking unused allowances, installing emission control equipment, and when applicable, changing fuels.
Organization: Omaha Public Power District
Comment: 
Omaha Public Power District
OPPD agrees with EPA that the original proposed allowance allocation methodology included in the August 2,2010 Federal Register was lacking in several respects and appreciates that EPA developed alternate methodologies for review. We feel that some of these same deficiencies also apply to the method used to set the state budgets. [EPA-HQ-OAR-2009-0491-3905[1].1, p.2]
Based on the January 7,2011 NODA, it appears that EPA recognized the inappropriateness of using a single four quarter period to set unit specific allowance allocations. The fact that the proposed additional options use 5 years of operating data as a basis for setting allowance allocations bears this out. However, in developing these additional options for allocating unit specific allowances, EPA continued to use the state budgets established with the use of only four quarters worth of data. [EPA-HQ-OAR-2009-0491-3905[1].1, p.2]
Regarding the proposed allowance allocation methods, both Options 1 and 2 of the January 7,2011 NODA provide an improvement over the originally proposed allowance allocation methodology in that five years of operating data is used as a basis to determine the number of allowances given to each entity rather than simply basing the allowance allocation on the four most recent operating quarters. Using five years of data allows for year to year variations in generating unit operation to be accounted for. Electrical generating units operations may change due to economic activity, atypical weather, or other unit or utility specific variations. [EPA-HQ-OAR-2009-0491-3905[1].1, p.3]
We believe that it is important that the allowance allocation methodology remain equitable and does not punish entities that have improved their emissions profile in recent years. While Nebraska is not a CAIR state, it seems unfair that entities who added controls or took other steps to reduce emissions as part of a CAIR compliance strategy will now be put in a position where that effort negatively impacts how the entity is treated under the Transport Rule, which will replace CAIR. Similarly, in non-CAIR states, the original methodology proposed for use in allocating allowances and Option 2 in the January 7,2011 NODA tend to penalize entities that have recently taken steps to lower emissions or have historically maintained lower emissions. [EPA-HQ-OAR-2009-0491-3905[1].1, p.3]
Response: 
Thank you for your comment.

Organization: Otter Tail Power Company
Comment: 
Otter Tail Power Company
Comment 1: As presented, Otter Tail opposes both alternative allocation methodologies described in the NODA. Both alternative methodologies will give natural gas-fired generating units a windfall of SO2 allowances that far exceeds their actual historical maximum emissions. [EPA-HQ-OAR-2009-0491-3888[1].1, p.1]
In the NODA, EPA presents two variations of historic heat input-based allocation methodologies. Option 1 allocates allowances to units based on the unit's percentage share of the total baseline historic heat input for all existing Transport Rule units in the state. Option 2 is similar to Option 1, except that Option 2 would limit allocations to a "maximum emissions level" so that units would supposedly not be allocated allowances in excess of their reasonably foreseeable maximum emissions. According to the NODA, "EPA believes that this approach would result in a reasonable initial distribution of allowances" (76 Fed. Reg. at 1115). [EPA-HQ-OAR-2009-0491-3888[1].1, p.1]
Otter Tail strongly disagrees that these methodologies will result in a reasonable distribution of allowances. [EPA-HQ-OAR-2009-0491-3888[1].1, p.1]
Comment 3: For group 2 states (such as Minnesota), the alternative allocation methodologies are inconsistent with how the 2012 state emission budgets were determined. Moreover, it is unreasonable, and in direct conflict with EPA's position in the proposed Transport Rule, to require units to install scrubbers by 2012 in order to operate within their allocated allowance budget. [EPA-HQ-OAR-2009-0491-3888[1].1, p.4]
EPA applied the following logic in the proposed Transport Rule when determining emission budgets for group 2 states:
"These states are only required to make SO2 reductions that could be made through (1) the operation of existing scrubbers, (2) scrubbers that are expected to be built by 2012 and (3) the use of low sulfur coal." 75 Fed Reg. 45290 [EPA-HQ-OAR-2009-0491-3888[1].1, p.4]
Specifically for Minnesota, after applying this logic, EPA summed each unit's projected SO2 emissions to determine the state budget. However, under Option 1 or 2 in the NODA, EPA would now be using a heat input-based method to distribute the budget. This results in an inconsistency between how the budget was determined and how the budget would be distributed. This can best be explained by looking at the specific case of Otter Tail Power Company's Hoot Lake Plant. For Hoot Lake Plant, projected emissions of 3,834 tons were used towards determining the Minnesota budget. However, by applying the alternative Option 2 heat input methodology, Hoot Lake would receive only 1,327 of these allowances. This obviously creates an inequitable distribution of allowances, whereby EPA would clearly be taking allowances from Hoot Lake Plant that went into determining the Minnesota SO2 budget and distributing them to natural gas-fired units. [EPA-HQ-OAR-2009-0491-3888[1].1, p.4]
Importantly, by creating this inconsistency between determining and distributing the state budgets, EPA would essentially require some units, such as Hoot Lake Plant, to install a scrubber by 2012 in order to operate within their allocated allowance budget. This is not only unreasonable, it is also in direct conflict with several statements that EPA made in the proposed Transport Rule:
' ... emissions reductions from scrubbers by 2012 or 2013 can only reasonably be achieved if that scrubber either exists today, or ifit is currently under construction.' 75 Fed. Reg. 45273 ' .. EPA believes that it is not possible to require the installation of postcombustion S02 controls (scrubbers) ... before 2014 (because it takes about 27 months to install a scrubber...)' 75 Fed. Reg. 45281 'However, given the time needed to design and construct scrubbers at a large number of facilities, EPA believes the 2014 compliance date is as expeditious as practicable for the full quantity of S02 reductions ... ' 75 Fed. Reg. 45301 [EPA-HQ-OAR-2009-0491-3888[1].1, p.5]
In conclusion, Otter Tail urges EPA to not adopt the heat input-based allocation methodologies. If EPA nonetheless decides to finalize a heat input approach, it must correct the disproportionate number of allowances that would be allocated in favor of natural gas-fired units. As currently presented in the NODA, the Option 1 and 2 heat input methodologies are clearly not 'fuel-neutral', as EPA indicates was suggested by other commenters (76 Fed. Reg. 1113). Instead, the methodologies would create a windfall of S02 allowances for natural gas-fired units, take away S02 allowances from certain units that served as the basis for determining the state emission budget, and require some coal-fired units to install scrubbers by 2012 in order to operate within their allocated allowance budget. [EPA-HQ-OAR-2009-0491-3888[1].1, p.5]
Response: 

EPA also notes that the 2012 state level budgets were set assuming that no new controls would be installed. Instead, other compliance options, including trading allowances, fuel switching, and operating existing controls on units were assumed to be available where appropriate.
Organization: PowerSouth Energy Cooperative
Comment: 
PowerSouth Energy Cooperative
The NODA addresses some of the shortfalls in Proposal. Alternative allowance allocation methodologies proposed in the NODA are based on historic heat inputs rather than historical or projected emission rates.  This is a step in the right direction.  However, PowerSouth suggests that EPA needs to further develop allocation methodologies for the Federal Implementation Plans (FIP) to address difference in fuels and combustion technologies. PowerSouth offers comments on the three allowance allocation methodologies proposed (in the original Proposal, NODA Option 1, and NODA Option 2). [EPA-HQ-OAR-2009-0491-3956[1].1, p.1]
PowerSouth applauds EPA's response to comments made by PowerSouth and other utilities to consider alternative allocation methodologies. [EPA-HQ-OAR-2009-0491-3956[1].1, p.2]
PowerSouth supports the development of a final allocation methodology based on historic heat input, and agrees with the points listed in the NODA in favor of such an approach.  Historic heat input data are more likely to be accurate at the unit level than projected unit-level emissions and are based on quality assured CEMS data. Historic heat input is fuel neutral.  Historic heat input data are emissions control neutral and thus do not yield reduced allocations for units that installed pollution control technology. This attribute of historic heat input allocation methodologies is particularly important to PowerSouth, since we have chosen to install state-of-the-art emissions control technologies on the Lowman Plant. [EPA-HQ-OAR-2009-0491-3956[1].1, p.6]
Response: 
Thank you for your comment.
Organization: Prairie State Generating Company, LLC
Comment: 
Prairie State Generating Company, LLC
Allowance allocation methodologies which do not address serious deficiencies in allowances needed for newly constructed units in Illinois and thereby threaten operations [EPA-HQ-OAR-2009-0491-3897[1].1, p.1]
The alternative allocation methodologies described in this NODA describe two variations of historic heat input based allocations. Although PSGC prefers the use of gross electrical output as the basis of allowance allocation to reward and encourage utilization of the most efficient generating units such as PSEC, supported by the Illinois EPA in its September 30, 2010 comments to the proposed Transport Rule, PSGC supports, in general, the utilization of heat-input based allowance allocation as a methodology which provides a more equitable approach for emission reductions over EP A's previously proposed emission based allotment. [EPA-HQ-OAR-2009-0491-3897[1].1, pp.2-3]
PSGC is concerned with the fact that the alternative allocation methodologies presented in this NODA simply distribute the same pool of state budgeted allowances differently for existing units. [EPA-HQ-OAR-2009-0491-3897[1].1, p.3]
That the Option 2 alternative methodology adjusts allowances for existing units based on historic emissions demonstrates the basis for developing the underlying statewide budgets is flawed. The alternative allocation methodologies highlight this fact and do not correct the problem. And, as discussed here, the alternative allocation methodologies intensify the disparities of the Transport Rule toward new, more efficient units, the very units that will be necessary to ultimately accomplish EPA's goals. [EPA-HQ-OAR-2009-0491-3897[1].1, p.3]
The Transport Rule as initially proposed does not sufficiently accommodate new, more efficient generation, and the NODA clearly exacerbates the situation. [EPA-HQ-OAR-2009-0491-3897[1].1, p.5]
Response: 

See section VII.D of the preamble for a description of EPA's final approach for determining new unit set-asides.  EPA has revised its approach from proposal to address concerns such as those outlined above that stemmed from the reclassification of some units from "existing unit" status to "new unit" status when moving from proposal to final rule.  The final rule entails state-specific set-asides that are tailored to accommodate the projected emissions of planned and potential new units (online after January 1, 2010) in each state.  The result is a greater percentage of the state budget set-aside for new units than would have otherwise occurred under the proposed method for calculating new source-set aside budgets.  For example, for annual NOx Illinois now has 8%, as opposed to the proposed 3%, of its budget set aside for new units. 

EPA notes that the final method for determining statewide budgets was changed for the final rule in response to comments, and is more extensively described in Preamble Section VI.
Organization: Progress Energy Service Company
Comment: 
Progress Energy Service Company
As described in the next section, the two alternative allowance allocation options contained in the NODA result in a significant under-allocation of SO2 allowances for certain units. Given the EPA's proposed 2012 start year for compliance with the Transport Rule, there is insufficient time to prepare for compliance in 2012. In Progress Energy's case, although some of the company's units would receive an increased allocation of SO2 under the two alternative options, overall the total allocation for Progress Energy's fleet would be significantly less than under the original proposal. The only alternative in order to assure compliance, particularly in the early years of the program, would be to rely on obtaining allowances from a very uncertain trading market. [EPA-HQ-OAR-2009-0491-4011[1].1, p.1]
In addition, as stated earlier in this section and as discussed in more detail below, the allocations under Options 1 and 2 for certain units are far less than projected emissions, requiring those units to obtain a significant number of allowances from other sources or from the allowance market, quite possibly at considerable additional cost while producing no additional environmental benefit. [EPA-HQ-OAR-2009-0491-4011[1].1, p.2]
The originally-proposed allowance allocations were based primarily on projected emissions levels from each of the affected units under the Transport Rule. Under Options 1 and 2, allocations are based on each unit's average annual total heat input as a percentage of the total heat input for the state in which it is located. These alternative allocations were established without taking into account fuel type or air emissions controls. As a result, units that use natural gas or that have advanced emissions control systems generally would receive significantly more allowances than are needed to cover emissions. To help address this issue, Option 2 includes reduced allocations for these types of units that are based on each unit's 'reasonably foreseeable maximum emissions level' The remaining allowances would then be redistributed to the other affected units. [EPA-HQ-OAR-2009-0491-4011[1].1, p.3]
Progress Energy has reviewed the draft allowance allocations under Options 1 and 2 and compared them to those in the original proposal. There are significant differences  among the three allocation schemes, particularly for S02. Options 1 and 2 both result in significantly lower overall allocations for Progress Energy's units than does the original proposal. The original S02 allocations would be a challenge to meet, particularly in the early years of the proposed program, so the allocations presented in the two options would be especially difficult to comply with - again particularly in the early years, because purchasing allowances in a very uncertain market would be the only viable alternative for compliance. [EPA-HQ-OAR-2009-0491-4011[1].1, pp.3-4]
Response: 
Thank you for your comment.

Organization: San Miguel Electric Cooperative, Inc.
Comment: 
San Miguel Electric Cooperative, Inc.
San Miguel applauds EPA in responding to the comments for a historical allocation based on heat input, unfortunately for this allocation to be fair it needs to recognize the difference between fuels and design types of generating units. San Miguel cannot support either of the allocation methodologies outlined in the January 7, 2011 NODA, as both options fall woefully short of being fair. [EPA-HQ-OAR-2009-0491-3997[1].1, p.2]
San Miguel believes using either of these options will significantly increase the cost of electricity, which most likely will cause a slowdown or a reversal in the economic recovery. [EPA-HQ-OAR-2009-0491-3997[1].1, p.2]
In this NODA the agency has provided two allocation methodologies that do use historical heat input to allocate allowances. However, Option One has no adjustment for fuel or plant design and Option Two provides a "one-size fits all" mechanism to adjust for historical NOx and SO2 emissions, which does not fairly allocate for type of fuel (including coal, coal rank, gas, or oil) or type of plant design (boiler, combustion turbine or combined cycle). San Miguel believes any historical allocation based on heat input must include adjustments for fuel and type of plant design! [EPA-HQ-OAR-2009-0491-3997[1].1, pp.2-3]
San Miguel has compared the original allocation to the alternative options for the state of Texas, which is in the ozone season only NOx allocation program. The comparative analysis is contained in the attached spreadsheet. What we discovered was most coal plants receive approximately 50- 65% of the original allocations for Option One and most gas combustion turbines and combine cycle plants received five to ten times the original allocation (original allocations were based on recorded historical emissions not the IPM). Option Two increased the allowances that coal units would receive but still showed a windfall gain to combined cycle and combustion turbines. Thus most coal plants would get half to three quarters of what they need while most gas plants would get five to ten times the amount they require. Both of the optional allocation methods are significantly flawed: Option One is totally unacceptable and Option Two would require significant changes to adjust for fuel and type of plant design. [EPA-HQ-OAR-2009-0491-3997[1].1, p.3]
The NRECA has provided additional analysis for the different emissions programs (NOx ozone season only, ozone annual and SO2 annual). Their analysis indicates the same result for all emission programs - the alternative allowance options are not a fair and justifiable way to allocate allowances. Below are some of their highlighted results that show how combined cycle and combustion turbines received windfall allowances under the NODA Allocation Options: [EPA-HQ-OAR-2009-0491-3997[1].1, p.3]
- Under the ozone NOx trading program: While emitting about 5.52% of total CATR tons, CC and combustion turbine units receive about 16% of the allowances, over 300% of their current emissions. [EPA-HQ-OAR-2009-0491-3997[1].1, p.3]
- Under the fine particulate trading program for annual NOx: While emitting about 2.98% of the total CATR tons, CC and combustion turbine units receive about 10% of the allowances, over 300% of their current emissions. [EPA-HQ-OAR-2009-0491-3997[1].1, p.3]
- Under the fine particulate trading for annual SO2: While emitting about 0.5% of the total CATR tons, CC and combustion turbine units receive about 5% of the allowances in 2012 and about 7% of the allowances in 2014, over 1400 % of their current emissions. [EPA-HQ-OAR-2009-0491-3997[1].1, p.3]
As shown in our analysis and in the NRECA analysis the NODA proposed methodologies are an unreasonable distribution of allowances. [EPA-HQ-OAR-2009-0491-3997[1].1, p.4]
As proposed in the NODA, the allocation methodologies are unfair and unjustifiably disadvantage coal fired steam generators. [EPA-HQ-OAR-2009-0491-3997[1].1, p.4]
Response: 
Thank you for your comment.
Organization: Santee Cooper
Tri-State Generation and Transmission Association, Inc.
Virginia Independent Power Producers
Gainesville Regional Utilities (GRU)
National Grid
Consolidated Edison Company of New York, Inc, (CECONY)
Louisville Gas and Electric Company (LG&E) and Kentucky Utilities Company (KU)
Minnesota Pollution Control Agency (MPCA)
New Jersey Department of Environmental Protection (NJDEP)
Florida Municipal Power Agency, Gainesville Regional Utilities, JEA, Orlando Utilities Commission, and City of Tallahassee
South Carolina Department of Health and Environmental Control 
NextEra Energy, Inc.
Florida Electric Power Coordinating Group, Inc. (FCG)
Tampa Electric Company
City of Dover, Delaware
PPL Corporation
PSEG Services Corporation
Birchwood Power Partners, L.P.
Massachusetts Department of Environmental Protection
Texas Commission on Environmental Quality
Giarmarco, Mullins & Horton, P.C.
Louisiana Chemical Association (LCA)
Constellation Energy
Dynegy, Inc.
Occidental Chemical Corporation (OCC)
Westar Energy, Inc.
West Virginia Department of Environmental Protection
North Carolina Electric Membership Corporation
Rochester Public Utilities (RPU)
Cogen Technologies Linden Venture, LP
Dow Chemical Company
Michigan Municipal Electric Association (MMEA)
Exxon Mobil Corporation
Midamerican Energy Holdings Company
Seminole Electric Cooperative Inc.
Tenaska, Inc.
ARIPPA
Comment: 
ARIPPA
As more substantially addressed below, ARIPPA supports many of the proposed refinements to the Proposed Transport Rule identified in the Second NODA.  However, a thorough analysis of EPA's projected approach confirms that EPA's failure to recognize the fundamental distinctions among EGU-source types prevents the regulatory scheme from achieving necessary outcomes for all sources, consistent with both EPA's statutory mandate and stated regulatory objectives.    [EPA-HQ-OAR-2009-0491-3903[1].1, p.2]
Therefore, to the extent that the Second NODA proposes that unit-specific allowance allocations would be based on historic heat input for affected sources, rather than projections and assumptions regarding future emission rates, ARIPPA endorses the revisions to the Proposed Transport Rule reflected in the Second NODA. [EPA-HQ-OAR-2009-0491-3903[1].1, p.4]
Birchwood Power Partners, L.P.
Birchwood Power supports the alternative allocations proposed by EPA with its January 7, 2011 NODA. Either of the two alternative allocation methods would generally provide Birchwood Power with sufficient NOx and S02 allowances to cover its emissions when its dispatch returns to pre-recession levels.1 Birchwood Power agrees with EPA that a heat input-based allocation is consistent with the goals of CAA Section 110(a)(2)(D)(i)(I) and would result in a fair and equitable allocation of allowances. Birchwood Power believes that either option would represent a fair allocation, [EPA-HQ-OAR-2009-0491-3940[1].1, p.2]
Birchwood supports the alternative allocation methodologies proposed by EPA with the NODA, believing that either Option 1 or Option 2 would represent a fair and equitable allocation of allowances. [EPA-HQ-OAR-2009-0491-3940[1].1, p.3]
City of Dover, Delaware
The City supports EPA's alternative allocation methodologies - that use a 5 year period to determine a baseline for historic heat input - as it more realistically and fairly accounts for units needs. [EPA-HQ-OAR-2009-0491-3881[1].1, p.1]
As the owner of four peaking units, the City is acutely aware of the importance that peaking units play to the overall reliability and security of the electricity system. Restraining these units with insufficient allocations will threaten to damage system reliability and will adversely impact customers. Ensuring that allocations adequately reflect a unit's historical heat input and emissions, by taking a wide enough range of historical data, EPA can help prevent disruptions to reliability on the electricity system. The City feels that while both proposed alternative allocation methodologies are far preferable to the original methodology in the proposed Transport Rule, Option 2 would result in the most appropriate distribution of allowances. [EPA-HQ-OAR-2009-0491-3881[1].1, p.1]
Cogen Technologies Linden Venture, LP
Consistent with our earlier suggestion to use historic data (i.e., either historic emissions or historic heat input) as the basis of the Transport Rule allowance allocation methodology, Linden Cogen supports the alternative allocation methodologies proposed by EPA with the January 7, 2011 NODA, wherein EPA would base unit allocations on each unit's share of historic statewide heat input, as calculated over a more representative period of time than a single year. [EPA-HQ-OAR-2009-0491-3938[1].1, pp.2-3]
Linden Cogen agrees that either of the two alternative allocation methodologies would represent a workable approach for allocating allowances to individual units. These alternative methodologies would avoid the problems associated with relying upon IPM's erroneous projections of dispatch as the basis for unit-level allocations.[EPA-HQ-OAR-2009-0491-3938[1].1, p.3]
Linden Cogen believes that either option would result in a fair and equitable allocation of allowances that promotes the Administrator's goal of fostering investment in a 'clean, efficient, and completely modern power sector' (75 Fed. Reg. at 45227). [EPA-HQ-OAR-2009-0491-3938[1].1, p.3]
The alternative allocation methodologies proposed by EPA in its January 7, 2011 NODA, 76 Fed. Reg. 1109 (Jan. 7, 2011), are consistent with Linden Cogen's suggestion: EPA would base allocations on each unit's share of historic statewide heat input, as calculated over a more representative period of time than a single year. In light of this, Linden Cogen agrees that either of the two alternative allocation methodologies would represent a workable approach for allocating allowances to individual units and would be preferable to the allocation methodologies and resulting allocations proposed by EPA with the Proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3938[1].1, p.5]
By basing the allocations on historic heat input, EPA's proposed alternative allocation methodologies avoid the problems associated with relying upon IPM's inaccurate projections for future dispatch of facilities. As suggested by the NODA, historic heat input data are much more likely to be accurate at the unit level than projected unit-level emissions data generated by IPM. See 76 Fed. Reg. at 1113 (describing comments favoring a heat input-based calculation because '[h]istoric heat input data are more likely to be accurate at a unit level than projected unit-level emissions'). Linden Cogen believes this fact alone strongly supports use of historic heat input data, than projected emissions data. Use of historic emissions data would also likely be a much more accurate method of predicting future NOx emissions at Linden Cogen and other plants operating under long term contracts than using IPM based projections. [EPA-HQ-OAR-2009-0491-3938[1].1, p.5]
Linden Cogen supports the proposal to use the average of the three highest, non-zero annual heat input values within the 5-year baseline (2005-2009) as the basis for computing each unit's share of the state's total historic heat input. As expressed in Linden Cogen's earlier comments, basing allocations on a more representative period of time than a single year would mitigate the risk that anomalies in the data set attributable to the recession might result in harshly punitive results for a particular facility. See October 1, 2010 Comments, 20-21. [EPA-HQ-OAR-2009-0491-3938[1].1, p.5]
The Alternative Allocation Methodologies Support Both the Clean Air Act's Goals and the Administrator's Policy Goals
Linden Cogen agrees that a historic heat-input-based allocation methodology represents a fair and equitable allocation method for facilities like Linden Cogen and is consistent with the goals of Clean Air Act ('CAA') Section 110(a)(2)(D)(i)(I). According to the NODA, 'EPA believes that, because higher-emission-rate units generally are responsible for a greater share of a state's total emissions and thus bear greater responsibility for a states' significant contribution and interference with maintenance, this distribution of burden is consistent with the goals of CAA Section 110(a)(2)(D)(i)(I).' 76 Fed. Reg. at 1114. Thus, the resulting allocation is favorable for highly efficient and low-emitting units like Linden Cogen. Linden Cogen believes that the resulting allocation is also consistent with the Administrator's stated goal in the preamble to the Proposed Transport Rule of fostering investment in a 'clean, efficient, and completely modem power sector.' 75 Fed. Reg. at 45227. [EPA-HQ-OAR-2009-0491-3938[1].1, p.6]
Linden Cogen supports the alternative allocation methodologies proposed by EPA with the NODA, believing that either Option 1 or Option 2 would represent a fair and equitable allocation of allowances for highly efficient and low emitting facilities like Linden Cogen. The historic heat input-based method reflected by these methodologies would avoid the problems associated with relying upon IPM's erroneous projections of future dispatch as the basis of unit allocations. Linden Cogen continues to believe, as suggested by our October 1, 2010 Comments, that an allocation methodology based on historical reported emissions data, as augmented by assumptions about operation of existing and planned controls, would also represent a sound approach. [EPA-HQ-OAR-2009-0491-3938[1].1, pp.6-7]
Consolidated Edison Company of New York, Inc, (CECONY)
The Company also endorses EPA's adoption of the historic heat input approach to intrastate unit allowance allocations, and commends the agency for circulating this NODA for comment in an effort to further develop the assumptions under which generating units will be subject to the final CATR program. [EPA-HQ-OAR-2009-0491-3910[1].1 ,p.2]
Constellation Energy
Constellation Energy supports allocating allowances for sulfur dioxide and nItrogen oxides to units based on historic heat input as contemplated under in the January 7 NODA. [EPA-HQ-OAR-2009-0491-4031, p.2]
An historic heat input-based approach would be based on verified data EPA has already collected, and will better reflect the reality that units may sometimes dispatch for non-economic purposes. Additionally, the Constellation Energy agrees with the advantages of a heat input basis cited by EPA and other commenters:
- Historic heat Input data are more likely to be accurate at a unit level than projected unit-level emissions and are generally based on quality-assured data reported by sources from continuous monitoring systems.
- Historic heat Input data are fuel-neutral.
- Historic heat input data are emissions-control-neutral and thus do not yield reduced allocations for units that installed or are projected to install pollution control technology. [EPA-HQ-OAR-2009-0491-4031, p.2]
Dow Chemical Company
Dow supports the use of the two alternative heat-input based allowance allocation methodologies used in the 2011 NODA over allocations based on the Integrated Planning Model (lPM). [EPA-HQ-OAR-2009-0491-4018[1].1, p.1]
Dynegy, Inc.
The NODA describes two alternative allowance allocation methodologies that rely on historic heat input data to determine unit-level allocations for existing units. As explained below, Dynegy supports both Option 1 (Historic Heat Input Approach) and Option 2 (Historic Emissions-Rate-In formed Historic Heat Input Approach) over the allocation methodology originally set out in the proposed Transport Rule. Either of the historic heat input approaches will result in a reasonable distribution of allowances consistent with Clean Air Act Section 110(a)(2)(D)(i)(I) and, unlike the allocation methodology originally set out in the proposed Transport Rule, will not inappropriately reward higher emitting electric generating units (EGUs) and punish well-controlled EGUs. [EPA-HQ-OAR-2009-0491-3944[1].1, p.1]
Either of the alternative allocation methodologies -- Option 1 Historic Heat Input Approach or Option 2 Emissions-Rate- Informed Historic Heat Input Approach -- would help ensure that allowance allocations do not disadvantage well-controlled EGUs relative to higher emitting EGUs. Either alternative allocation approach would create an opportunity for well-controlled units to recover a portion of their operating costs and at the same time create a strong incentive for higher emitt ing units to reduce their emissions. This would effectively impose the cost of buying additional allowances on less controlled units, making their operational cost nearer to that of well-controlled units. Moreover, either alternative allocation methodology would create a level playing field for all EGUs by not rewarding high emitting units with extra allowances and not penalizing well-controlled units with lower allocations. Thus, by forcing higher emitting units -- i.e., units that are, in general, more proportionately responsible for significant contribution to downwind nonattainment or interference with maintenance in downwind states -- to reduce emissions or obtain additional allowances in order to comply, the alternative allocation methodologies are not only reasonable and consistent with the intent of Clean Air Act Section 110(a)(2)(D)(i)(1), but also help achieve the intent of Section II 0(a)(2)(D)(i)(1) 10 a greater degree than the originally proposed allocation methodology. [EPA-HQ-OAR-2009-0491-3944[1].1, p.2]
Importantly, the historic heat input based alternative allocation methodologies would not penalize EGUs that voluntarily over-controlled emissions. For example, the originally proposed allocation methodology would effectively penalize Dynegy for having voluntarily achieved additional NOx reductions at its SCR units below enforceable NOx emission limits from 2005 through 2009 by allocating approximately 60 percent fewer annual and ozone season NOx allowances to these units than would otherwise have been allocated had Dynegy only met its enforceable NOx emission limits. Thus, either of the alternative historic heat input allocation methodologies achieves greater fairness than the originally proposed allocation approach.    [EPA-HQ-OAR-2009-0491-3944[1].1, p.2]
In addition, by basing allowance allocat ions on the average of the three highest annual historic heat input values during the baseline period 2005-2009, the alternative historic heat input allocation methodologies eliminate the unfairness in basing allocations on unrepresentative oneyear periods as in the original proposal. For example, use of the average of the three highest annual heat inputs during the 2005-2009 baseline period does not penalize units that experienced extended outages during a one-year baseline period to install advanced pollution controls or whose operating time was adversely affected by unusual conditions, such as abnormal weather. 1   [EPA-HQ-OAR-2009-0491-3944[1].1, pp.2-3]
The alternative allocation methodologies are also clearer and easier to understand than the methodology originally proposed. Simply put, because the allocations are primarily based on source-certified historic heat input data submitted under 40 CFR Part 75, the need for corrections and adjustments (and, ultimately, disputes over appropriate emissions projections) is minimized. More specifically, The originally proposed allocation methodology relied in part on EPA's IPM model which attempted to consider numerous economic impacts when predicting unit heat inputs in the future. Relying on source-certified historic heat input avoids the need for EPA to make those numerous and broad assumptions in IPM that may well be inconsistent with and significantly different than operating and economic projections made by commercial business models utilized by generating companies. [EPA-HQ-OAR-2009-0491-3944[1].1, p.3]
In short, EPA should adopt one of the alternative allocation methodologies -- Option 1 Historic Heat Input Approach or Option 2 Emissions-Rale-Informed Historic Heat Input Approach -- rather than the originally proposed allocation methodology because either alternat ive is reasonable, furthers the purpose of Clean Air Act Section 110(a)(2)(D)(i) (I) more than the originally proposed allocation methodology, and is clearer, easier to understand and fairer in implementation than the originally proposed allocation methodology.  [EPA-HQ-OAR-2009-0491-3944[1].1, p.3]
Dynegy urges EPA to adopt one of the alternative allowance allocat ion methodologies based on historic heat input in place of the originally proposed allocation methodology. Either of the alternative allocat ion approaches -- Option 1 Historic Heat Input or Option 2 Historic Emissions-Rate-In formed Historic Heat Input -- will result in a reasonable distribution of allowances that, unlike the originally proposed allocation methodology, will not force well-controlled EGUs to bear the brunt of compliance costs while rewarding higher emitting EGUs for not previously (or insufficiently) controlling NOX and SO2 emissions. [EPA-HQ-OAR-2009-0491-3944[1].1, p.4]

1 For example. as explained in Dynegy's October 1, 2010 comments on the proposed Transport Rule, the annual and ozone season baselines identified for Havana Unit 9 and Hennepin Units 1 and 2 were not representative of normal source operation due to extended outages associated with installation of bag houses 10 control particulate emissions and sorbent injection systems to control mercury emissions.
Exxon Mobil Corporation
Comment 2: With regard to the 2011 NODA, EM supports the use .of either of the two alternative heat-input based allowance allocation methodologies presented in the 2011 NODA. over the allocation methodology based on the Integrated Planning Model ('IPM') that was initially proposed by EPA in CATR/FIP. The alternative heat input-based allocation methodologies proposed by the 2011 NODA are far superior to the IPM methodology originally offered by EPA. [EPA-HQ-OAR-2009-0491-4028, p.3]
Unlike the IPM methodology which is based upon modeled emissions using dubious economic predictions rather than realistic data, the alternative allocation methodologies in the 2011 NODA are based upon a unit's verified actual historic heat input data. This heat input data is quality assured data that has been reported from continuous monitoring systems and is a much better platform for prediction of near term future operations than is the IPM. (The extreme variation between the IMP v. 3.02 and IPM v. 4.10 results demonstrates the sensitivity of the model to changes such as natural gas prices that were inaccurately forecast.) As acknowledged by EPA in the January 7, 2011 NODA, historic heat input data is 'more likely to be accurate' at a unit wide level than are modeled unit emissions.  Also, as indicated by numerous commenters, historic heat input data is fuel-neutral and does not raise concerns regarding the use of fuel adjustment factors that can cause inequities in allocation schemes. Finally, the heat input data is emissions control neutral and, therefore, does not result in reduced allocations for units that have installed, or plan to install, pollution control technology. This neutral approach is important as it does not penalize companies that have made, or plan to make, the capital investments needed to control emissions. [EPA-HQ-OAR-2009-0491-4028, p.3]
The use of either of the two heat-input based options proposed in the NODA results in a distribution of allocations that rewards cleaner, more efficient units, compared to the IPM-based allocations. Thus, use of the heat input based options is closer to the goals of Section 110 (a)(2)(D)(i)(1) the Clean Air Act, which are, as stated by EPA in the NODA 'improving long-term air quality and encouraging cost-effective emissions reductions.' [EPA-HQ-OAR-2009-0491-4028, p.3]
The historic heat input methodologies proposed in the 2011 NODA each would provide allocations to EM sufficient to operate and are based on realistic predictions of future operation. [EPA-HQ-OAR-2009-0491-4028, p.3]
Florida Electric Power Coordinating Group, Inc. (FCG)
The FCG Generally Supports an Historic Heat Input-Based Allocation
The FCG generally supports the use of an historic heat input-based allowance allocation method as compared to EPA's original allowance allocation proposal, which assigns allocations based on an individual unit's proportional share of state emissions assumed in developing the state emissions budget. The original allowance allocation proposal would rely on the IPM modeling platform, which, as many commentators have noted, contains undecipherable and apparently erroneous assumptions, in addition to material factual errors. Assuming EPA could correct the IPM model, historic heat input data are still more likely to be accurate at a unit-specific level than model-projected unit-level emissions. The FCG is not supporting, however, any particular option described by EPA. The use of the three highest heat inputs of the past five years to derive annual averages (seasonal for ozone) appears to be a reasonably accurate approach to representing the past performance for most units. [EPA-HQ-OAR-2009-0491-3990[1].1, pp.2-3]
Florida Municipal Power Agency, Gainesville Regional Utilities, JEA, Orlando Utilities Commission, and City of Tallahassee
  Heat Input Allowance Allocation Options: Our utilities strongly support the use of historic heat input data as the basis for allowance allocations under CATR. We believe this approach is fairer and more transparent than the allocation method initially proposed by EPA.  [EPA-HQ-OAR-2009-0491-3907[1].1, p.1]
 
Gainesville Regional Utilities (GRU)
GRU strongly supports the use of historic heat input data as the basis for allowance allocations under CATR. We believe this approach is much fairer and transparent than the allocation scheme initially proposed by EPA. Use of historic heat input will eliminate the uncertainty and potential arbitrary allocations under EPA's original allocation proposal. [EPA-HQ-OAR-2009-0491-3922[1].1, p.1]
 
Giarmarco, Mullins & Horton, P.C.
MCV has reviewed the alternative allocation tables and underlying data as part of EPA's Notice of Data Availability dated January 7,2011 ('January 7,2011 NODA'). MCV supports the implementation of heat-input based allowance allocation since it provides a more equitable approach for emissions reductions than that proposed previously by EPA. [EPA-HQ-OAR-2009-0491-4015[1].1, p. 2]
Louisiana Chemical Association (LCA)
1. The two alternative allocation methodologies
LCA supports the use of the two alternative heat input-based allowance allocation methodologies presented in the 2011 NODA over any allocation methodologies based on the Integrated Planning Model ('IPM'). The initial CATR/FIP proposed rule indicated that allocations were to be based, upon projections made by IPM version 3.02. In a September 1, 2010 NODA EPA indicated that it revised its IPM projections (and the corresponding allocations) by using an updated version - IPM v. 4.10. LCA. believes that the alternative allocation methodologies proposed in the 2011 NODA are superior to the IPM-based methodology originally offered by EPA. [EPA-HQ-OAR-2009-0491-4027, p. 3]
Either of the heat-input based options proposed in the 2011 NODA represent a significant improvement in allocation methodology. Unlike the IPM methodology which is based upon assumptions about economic factors, projected fuel use, electrical demand and a host of other factors, the 2011 NODA alternative allocation methodologies are based upon actual duality assured data that has been reported from continuous monitoring systems. As EPA indicated in the January 7, 2011 NODA, historic heat input data is 'more likely to be accurate' at a unit wide level than is modeled unit emissions. In addition, use of historic heat input data is fuel-neutral and does not raise concerns regarding the use of fuel adjustment factors that were of concern during the CA1R rulemaking. Finally, as noted by other commenters, the heat input data is emissions control neutral and, therefore, does not result in reduced allocations for units that have installed, or plan to install, pollution control technology. This neutral approach is important as it does not penalize companies that have made, or plan to make, the capital, investments needed to control emissions. [EPA-HQ-OAR-2009-0491-4027, p. 5]
LCA also notes that use of either of the heat input-based allocation options more equitably distributes the burden of compliance by placing a lesser burden on the cleaner, lower emitting units such as the gas-fired combined cycle cogeneratzon units operated by certain LCA members. A greater burden will be placed on the higher emitting, less efficient EGUs. If Louisiana becomes subject to CATR at all, LCA agrees that these 2011 NODA heat-input based options are significantly more in line with the goals of Section 110(a)(2)(D)(i)(1) of the Clean Air Act than are allocation options based on the IPM. [EPA-HQ-OAR-2009-0491-4027, p. 5]
2. LCA supports the use of a 3 year average which utilizes the highest three years out of the 2005-2009 period for determining a unit's historic heat input. This will avoid inclusion of non-representative years in the allocation determination. [EPA-HQ-OAR-2009-0491-4027, p. 5]
Louisville Gas and Electric Company (LG&E) and Kentucky Utilities Company (KU)
LG&E/KU believes that the alternative allowance allocation options based on heat-input are more sound and equitable than EPA's original proposal which was based on forecasted emissions. The alternatives are sounder because they utilize actual historical information which can be verified. By comparison, the original proposal was based on EPA's projected emissions which relied on many assumptions. While IPM projections may be reasonable on a regional level, they become less defendable at further disaggregated levels. Relying on the projections at a unit-by-unit level is extremely questionable. The alternatives are more equitable because allocations based on projected emissions provide unfairly low allocations to already well-controlled units. [EPA-HQ-OAR-2009-0491-3909[1].1, pp.1-2]
Massachusetts Department of Environmental Protection
Of the two approaches that EPA has proposed - historic and projected emissions versus historic heat input - MassDEP strongly supports the third NODA historic heat input approach. The proposed allocations under this approach address a number of our comments and concerns about the proposed Transport Rule method, which had resulted in a number of existing Massachusetts units receiving no SO2 and NOx allowances. Under the proposed NODA method, allowances are more equitably distributed to Massachusetts units. We also agree with EPA's acknowledgement in the third NODA that a heat input based approach puts a greater burden on higher emission rate units to reduce emissions or purchase additional allowances. Massachusetts has a number of facilities that have very low emission rates and therefore bear less responsibility for Massachusetts' significant contribution to transport. We believe that it is appropriate to allocate to these facilities at a level that reflects their investment in advanced controls and use of fuels that result in lower NOx and S02 emissions. [EPA-HQ-OAR-2009-0491-4017[1].1, pp.2-3]
Michigan Municipal Electric Association (MMEA)
In summary, MMEA and its members support the shift away from an allowance allocation methodology based on EPA projections using the IPM model, to one based on historic heat input utilization. [EPA-HQ-OAR-2009-0491-4020[1].1, p.1]
In conclusion, MMEA supports the heat input utilization method that EPA is proposing for allowance allocations, [EPA-HQ-OAR-2009-0491-4020[1].1, p.7]
Midamerican Energy Holdings Company
In general, MidAmerican supports the EPA's use of the heat input allocation methodologies (either Options 1 and 2) rather than the originally proposed allocations based on projected source emissions. The use of a heat input allocation methodology is preferable to the original proposal because historic heat input data is both fuel neutral and emissions control neutral. Specifically, determining allowances based on heat input rather than projected emissions will not penalize units that have already made recent substantial investments in capital intensive pollution control projects. A heat input based methodology effectively prevents over-allocations of allowances to uncontrolled sources. Any "windfall" or over-allocation of allowances could have perverse and unintended environmental consequences. [EPA-HQ-OAR-2009-0491-3975[1].1, p. 2]
One concern with an over-allocation of allowances based on emissions is that previously controlled sources which receive fewer allowances may not be dispatched if less well controlled facilities receive more allowances, resulting in a corresponding economic advantage. Such a scenario could result in adverse environmental impacts, effectively defeating the intended purpose of the Transport rule. MidAmerican further submits that a heat input based allocation should incentivize uncontrolled sources to reduce emissions, benefiting downwind areas and meeting the mandate under Clean Air Act section 110(a)(2)(D)(i)(I) which prohibits sources from contributing "significantly" to non-attainment of air quality standards in other sources  -  the main objective of the Transport Rule. [EPA-HQ-OAR-2009-0491-3975[1].1, p. 2]
MidAmerican supports the assumption that annual heat inputs over a five year look back period, as proposed in both Option 1 and 2 of the NODA, provide the best means of producing an equitable model of allowance distribution. MidAmerican also supports the use of the three largest annual heat input numbers for this "look back period." Such an approach would serve to exclude years where planned or unplanned outages and or underutilization for peaking plants may have artificially reduced the average annual heat input and reduced the pro-rated allowance allocation of the individual state's budgeted total. CalEnergy's Cordova Energy Center serves as a good example of this situation. Cordova has historically been underutilized and under the original emissions based allocation was allocated only two NOx allowances. An increase in the utilization of the facility, which employs selective catalytic reduction for NOx control, would require the facility to purchase virtually all of its allowances, despite the fact that it has not contributed to the non-attainment sought to be remedied. At the same time, significantly higher emitting facilities, having historically contributed to non-attainment, would have a sufficient number of allowances under the state budget cap and would not have to purchase any allowances. Increasing the utilization of the Cordova facility to accommodate potential reductions in the use of higher emitting generating facilities results in negative economic consequences to the Cordova facility. The proposed alternative heat input allocations address this inequitable and problematic distribution of allowances. [EPA-HQ-OAR-2009-0491-3975[1].1, pp. 2-3]
Minnesota Pollution Control Agency (MPCA)
Also, as stated in our initial comments, the MPCA had concerns that the historical baseline emissions used in developing the initial unit budgets looked only at 2008 and 2009 emission data. We encouraged EPA to look at emissions over a slightly longer period in order to determine baseline data. Given that both alternative allocation methods described in the NODA do use that longer baseline period, we believe that either Option 1 or Option 2 proposed in this NODA would be preferable to the original allocations proposed. [EPA-HQ-OAR-2009-0491-3889-cp, p.1]
National Grid
As we stated in our comments submitted last year, National Grid supports the use of historic heat input as an appropriate methodology for allocating allowances. The EPA has verified the accuracy of the majority of the data that would be used and recent actual operating data would be more representative of a unit's expected utilization than forecast data. Furthermore, the use of historic heat input rather than emissions does not penalize those units that have already installed or are planning to install control technology to achieve significant reductions.
New Jersey Department of Environmental Protection (NJDEP)
The Department reviewed the two alternative allocation methodologies proposed in this NODA and determined that they are improvements to the originally proposed method because they do not over-allocate allowances to uncontrolled units. [EPA-HQ-OAR-2009-0491-3891[1].1, p.1]
NextEra Energy, Inc.
While NextEra Energy has long supported allowance allocation methodologies based on energy output (megawatt hours), the Company supports allocating allowances under the Transport Rule for S02 and NOx to units based on historic heat input, as contemplated under Options 1 and 2 in the January 7th NODA. While both options address most of NextEra Energy's concerns with EPA's preferred approach, as reflected in the August 2, 2010 proposed rule, [EPA-HQ-OAR-2009-0491-3962[1].1, p.2]
A historic heat input-based allocation has a number of advantages over EPA's preferred approach. Most significantly, it is not based on modeled future emissions with its known inaccuracies for units that may dispatch for non-economic purposes and would be based on verified data EPA already holds. Additionally, NextEra Energy agrees with the advantages of allocating allowances on a heat input basis cited by EPA and other commenters:
:: Historic heat input data are more likely to be accurate at a unit level than projected unit-level emissions and are generally based on quality-assured data reported by sources from continuous monitoring systems.
:: Historic heat input data are fuel-neutral.
:: Historic heat input data are emissions-control-neutral and thus do not yield reduced allocations for units that installed or are projected to install pollution control technology.  [EPA-HQ-OAR-2009-0491-3962[1].1, p.2]
Using a historic heat input basis for allowance allocation corrects the originally proposed methodology's disadvantage for early actors that EPA acknowledged in the proposed rule and creates the right incentives to drive additional reductions. Thus, NextEra Energy agrees with EPA that an historic heat input-based allocation meets the goals of the section 110 of the Clean Air Act - to encourage the most cost-effective emissions reductions and drive investment in the technologies necessary to address transport and non-attainment on a long-term basis. [EPA-HQ-OAR-2009-0491-3962[1].1, p.3]
Conversely, an initial allocation of allowances based on units' historic heat input would put a relatively greater burden on units with higher emissions rates to reduce their emissions or purchase allowances. This is because a unit with a higher emissions rate would receive the same number of allowances as a lower emitting unit with the same heat input, yet be required to cover more emissions with those allowances. NextEra Energy shares EPA's belief that because higher-emissions-rate units are generally responsible for a larger share of a state's emissions - and thus that state's significant contribution and interference with maintenance - this distribution of burden is consistent with the goals of CM section 11 0(a)(2)(D)(i)(I).  [EPA-HQ-OAR-2009-0491-3962[1].1, p.3]
North Carolina Electric Membership Corporation
NCEMC supports the clear and straightforward alternative allocation methodologies presented by EPA, and EPA's decision to use a longer period of five years to determine a baseline for historic heat input. NCEMC feels that this more realistically accounts for the variability and needs of peaking units. NCEMC agrees with the EPA that a historical heat input methodology produces allocations that are more fuel neutral, which provides units greater flexibility in the future for meeting electricity demands. [EPA-HQ-OAR-2009-0491-4001[1].2, p.1]
While NCEMC believes that both alternative allocation methodologies result in more equitable distribution of state budgets than the proposed methodology, [EPA-HQ-OAR-2009-0491-4001[1].2, p.1]
Occidental Chemical Corporation (OCC)
Review of the NODA indicated that EPA had developed two alternative allocation methodologies (referred to as 'Option 1' and 'Option 2' in the NODA) - both of which rely on historic heat input and state-wide emission allocations. We applaud EPA for this alternative approach. These methodologies, unlike the various scenarios developed through the use of the IPM, provide for a simple and straight-forward way of developing emission allocations that more reliably accounts for the complex realities of the domestic power generation regime. [EPA-HQ-OAR-2009-0491-3951[1].1, p.2]
PPL Corporation
PPL PA Generation appreciates the opportunity to comment on the data that EPA has made available for public inspection and the fact that EPA has proposed two alternative methods for allowance allocations. Either of these methods is more equitable to the original proposed allowance allocation method. These comments below address EPA's alternative approaches. [EPA-HQ-OAR-2009-0491-3935[1].1, p.3]
PPL PA Generation believes that a sounder and more equitable approach is either of the two alternative approaches for which the EPA is seeking comment. It would allocate portions of the state budget to each unit within the state based on each unit's proportional share of the state's total heat input from all affected electrical generation units. [EPA-HQ-OAR-2009-0491-3935[1].1, p.3-4]
PPL PA Generation believes that the alternative allowance allocation options based on heat-input are more sound and equitable than EPA's original proposal which was based on forecasted emissions. The alternatives are sounder because they utilize actual historical information which can be verified. By comparison, the original proposal was based on EPA's projected emissions which relied on many assumptions. While IPM projections may be reasonable on a regional level, they become less defendable at further disaggregated levels. Relying on the projections at a unit-by-unit level is extremely questionable. The alternatives are more equitable because allocations based on projected emissions provide unfairly low allocations to already well-controlled units. These units have installed control equipment in part based on the financial assumption that they could sell excess allowances; the originally proposed allocations eliminate this. Under the original proposal, these units would have been better off if they did not install control equipment, received a higher allocation under the Transport Rule, and then installed the equipment. The original proposal rewards less-controlled units that continued to have higher emissions at the expense of well-controlled units. In addition, although the original proposal is based on projected emissions, units would receive fewer allowances than their projected emissions. This is due to ratcheting down allocations to meet statewide budgets and due to the 3% withhold for new source set-aside. The result is that units equipped with controls that are achieving near the lowest emissions technically feasible are being required to reduce emissions further. [EPA-HQ-OAR-2009-0491-3935[1].1, p.4]
The alternatives proposed by EPA address the equity issue for units with controls versus those without controls. Specifically, in Pennsylvania under the EPA original proposal:
-For 2012, the SO2 emission rate for Pennsylvania units over 150 MW varies between 0.108 lb/MMBtu and 0.465 lb/MMBtu
-For 2014, when apparently all units over 150 MW in Pennsylvania are assumed to have FGD systems, the SO2 emission rate varies between 0.105 lb/MMBtu and 0.263 lb/MMBtu. [EPA-HQ-OAR-2009-0491-3935[1].1, p.4]
These significant inequities are corrected under the proposed alternative allowance allocation methods. [EPA-HQ-OAR-2009-0491-3935[1].1, p.4]
PSEG Services Corporation
While the Company has long supported allocation methodologies based on energy output (megawatt hours), the PSEG Fossil supports allocating allowances for sulfur dioxide and nitrogen oxides to units based on historic heat input as contemplated under Options 1 and 2 in the January 7th NODA. [EPA-HQ-OAR-2009-0491-3936[1].1, p.2]
A historic heat input-based allocation has a number of advantages over EPA's preferred approach. Most significantly, it is not based on modeled future emissions with its known inaccuracies for units that may dispatch for non-economic purposes and would be based on verified data EPA already holds. Additionally, PSEG Fossil agrees with the advantages of a heat input basis cited by EPA and other commenters: 
:: Historic heat input data are more likely to be accurate at a unit level than projected unit-level emissions and are generally based on quality-assured data reported by sources from continuous monitoring systems.
:: Historic heat input data are fuel-neutral.
:: Historic heat input data are emissions-control-neutral and thus do not yield reduced allocations for units that installed or are projected to install pollution control technology. [EPA-HQ-OAR-2009-0491-3936[1].1, p.2]
Using a historic heat input basis for allocation corrects the proposed methodology's disadvantage for early actors that EPA acknowledged in the proposed rule and creates the right incentives to drive additional reductions. Thus, we agree with EPA that a heat input allocation meets the goals of the section 110 of the Clean Air Act - to encourage the most cost-effective emissions reductions and drive investment in the technologies necessary to address transport and nonattainment on a long-term basis. [EPA-HQ-OAR-2009-0491-3936[1].1, p.2]
By contrast, a historic basis for allocating the state budgets avoids these problems and strengthens the legal basis for the rule. [EPA-HQ-OAR-2009-0491-3936[1].1, p.2]
Rochester Public Utilities (RPU)
RPU believes that either methodology is a vast improvement over the methodology originally used in the proposed Transport Rule in determining the SO2 and NOx allowances. The methodologies used for the alternative allocations appear to be clear and easy to understand and do not appear to raise any implementation concerns. Either alternative allocation methodology would be acceptable to RPU. [EPA-HQ-OAR-2009-0491-3998[1].1, p.2]
We appreciate that EPA has addressed issues related to the methodology for calculating SO2 and NOX allocations. [EPA-HQ-OAR-2009-0491-3998[1].1, p.3]
Santee Cooper
By contrast, the heat input-based approach used in Options 1 and 2 in the NODA would create a level playing field among utilities with respect to pollution control investments. Allocations based on heat input would ensure that utilities are not penalized for past and projected investments in pollution control technologies, nor rewarded for having failed to make these investments in the past. Moreover, allocating allowances on the basis of heat input does not tend to favor particular classes of fuels. Lastly, heat input data is reliable and straightforward to obtain, ensuring the accuracy of allocations made on this basis. The heat input method has also been successfully demonstrated in other EPA cap-and-trade programs; in the 1998 NOx SIP Call, EPA selected a heat input approach to allocating allowances in the 'Model Rule' that states were encouraged to adopt. [EPA-HQ-OAR-2009-0491-3913[1].1, p.3]
Seminole Electric Cooperative Inc.
Seminole generally supports the use of a historic heat input-based allowance allocation method and requests that EPA abandon its original allowance allocation proposal, which assigns allocations based on an individual unit's proportional share of state emissions assumed in developing the state emissions budget. [EPA-HQ-OAR-2009-0491-3992[1].1, p.2]
Assuming EPA could correct the IPM model, historic heat input data are still more likely to be accurate at a unit-specific level than model-projected unit-level emissions. Moreover, historic heat input data are fuel-neutral and, unlike EPA's original proposal, will not penalize emission units that have already installed expensive emission controls. [EPA-HQ-OAR-2009-0491-3992[1].1, p.2]
The use of the three highest heat inputs of the past five years to derive annual averages (seasonal for ozone) should accurately represent the past performance for most units. [EPA-HQ-OAR-2009-0491-3992[1].1, p.2]
South Carolina Department of Health and Environmental Control 
In the NODA, the EPA proposed a method to allocate emissions allowances to sources based on empirical heat input rather than the modeled predictions from IPM in the August 2, 2010 Proposal. The NODA included two options that follow this method. Option one is based on heat input from 2005 through 2009. Option two builds on option one with additional steps to avoid allocating more allowances to a given source than that source emitted in 2003 through 2009, and to allow growth of smaller, lower-emitting units. DHEC supports both of these heat-input-based options. Upon review of the data that EPA provided with the NODA, DHEC finds that the allocations based on heat input are more reasonable and predictable than the allocations in the August 2, 2010 Proposal. The NODA allocations, in both option one and option two, involve fewer unexplainable changes in allocations from CAIR and the Acid Rain Program than the August 2, 2010 Proposal. Further, both heat-input-based methods are clearer and more transparent than the allocations based on IPM. Stakeholders can readily follow the method in allocation spreadsheets provided by the EPA. Because the NODA allocations are easily replicable whereas the August 2,2010, Proposal allocations are not, and because of their predictability, DHEC prefers the heat-input-based allocations.[EPA-HQ-OAR-2009-0491-3961[1].1, p.2]
Again, DHEC generally supports the EPA's options on allocations and SIPS as proposed in the NODA. [EPA-HQ-OAR-2009-0491-3961[1].1, p.2] [[This comment can also be found in Section XX.E.]]
Tampa Electric Company
Heat Input-Based Allocation
Tampa Electric Company supports the use of an historic heat input-based allowance allocation method and commends EPA for giving consideration to companies that committed to early emission reductions. As an early actor and an electric utility with a strong commitment to the environment Tampa Electric supports this method of allocation is order to provide the greatest benefit to our customers. The distribution of allowances based on heat input avoids arbitrarily rewarding those who did not install emission controls and avoids penalizing those who did install them. Using the alternative method of a heat input based allocation act an incentive for utilities to negotiate NSR agreements with EPA in the future. [EPA-HQ-OAR-2009-0491-3959[1].1, p.2]
Tenaska, Inc.
In the NODA, EPA offers two options for implementing a heat input-based allocation. The first would allocate the state's existing unit budget based on each unit's proportionate share of the state's total historic heat input. The second would yield the same initial allocation as the first option; however, if a unit's heat-based allocation exceeds its historical emission rate, the second option would cap the unit's allocation based on a reasonable estimate of future maximum emissions based on projections of future utilization of the unit and a well-controlled emission rate. [EPA-R03-OAR-2010-1027-DRAFT-0005.1[1], pp.1-2]
On balance, Tenaska is in support of either option one or option two over the originally proposed allocation based on historical emissions. As between these options, Tenaska is ambivalent, but we are providing our thoughts on the relative merits of the options. [EPA-R03-OAR-2010-1027-DRAFT-0005.1[1], p.2]
Texas Commission on Environmental Quality
The EPA's consideration of heat-input-based allocation methodologies is appropriate. However, the TCEQ has concerns regarding both provided alternative allocation methodologies. [EPA-HQ-OAR-2009-0491-4030, p.4]
Tri-State Generation and Transmission Association, Inc.
Tri-State believes that many of the unreasonable aspects of the proposed transport rule allocation methodology can be addressed by using a heat input based approach, but not as simply as the two options set forth in the NODA. [EPA-HQ-OAR-2009-0491-3902[1].1, p.4]
Virginia Independent Power Producers
VIPP endorses EPA's statements in support of an allocation methodology based upon established heat input for affected sources. [EPA-HQ-OAR-2009-0491-3925[1].1, p.2]
For these reasons, VIPP Agrees with EPA that a heat input-based allocation is consistent with the goals of the Clean Air Act, that it would resuit in fair and equitable allocations, and recommends its adoption as described in EPA proposed Option 1. [EPA-HQ-OAR-2009-0491-3925[1].1, p.2]
West Virginia Department of Environmental Protection
Alternative Allocation Methodologies
The WVDAQ supports the use of the alternative allocation methodologies using historic heat input, because it is a better option than using Integrated Planning Model (IPM) projections for allowance allocations as originally proposed. As we commented in our September 30, 2010 letter, we were not able to fully duplicate the 2012 or 2014 allocations for West Virginia using the methodology outlined in the proposed Transport Rule preamble. WVDAQ believes that both alternative methodologies, identified as Option 1 and Option 2 in the NODA, are clear, easy to understand and easily replicable, making implementation of either methodology straightforward and transparent. We agree with EPA that:
"...a historic-heat-input-based allocation methodology is consistent with the goals of CAA section 110(a)(2)(D)(i)(I)" [EPA-HQ-OAR-2009-0491-4000[1].1, p.1]
We have analyzed the allocations within our state under both methodologies and, despite the differences that result between the two, believe that either would yield defensible as well as equitable distributions in West Virginia. [EPA-HQ-OAR-2009-0491-4000[1].1, p.1]
Westar Energy, Inc.
The NODA introduces two methodologies ("Option 1" and "Option 2") that "rely largely on historic heat input data to determine unit-level allocations," 76 FR at 1110/3, to implement the proposed trading remedies. Id. at 1111/3. [EPA-HQ-OAR-2009-0491-3952[1].1, p.1]
The methodologies in Options 1 and 2 are clear; nonetheless, and considering that Westar's allowances increase under the Options, Westar has concerns as to whether a methodology based largely on historical data offers the better means to project future emissions levels as compared to the combined historical and projected analysis used in the Rule Methodology. [EPA-HQ-OAR-2009-0491-3952[1].1, pp.1-2]
For the most part, these units received a positive allowance under Options 1 and 2 for the trading programs. In Westar's view, a positive allowance for those units more closely reflects an appropriate allocation, as those units will continue to provide needed generation in 2012 and beyond.   [EPA-HQ-OAR-2009-0491-3952[1].1, p.3]
Response: 
Thank you for your comment.

Organization: Southern Company
Comment: 
Southern Company
In the NODA3, EPA notes that "A number of commenters requested that EPA publish allocations and underlying data for any potential alternative allocation methods before issuing a final Transport Rule." (76 Fed. Reg. at 1,110). To the extent EPA is suggesting that the information provided with NODA3 is sufficient information to support a final rule or satisfy Southern Company's request, EPA is mistaken. [EPA-HQ-OAR-2009-0491-3946[1].1, p.7]
In the NODA3, EPA proposed two additional unit allocation methodologies for comment and notes that it "will consider these alternative allocation methodologies, as well as the allocation methodologies presented in the proposed Transport Rule." (76 Fed. Reg. at 1,110). In the proposed Transport Rule, EPA allocated to units based on each unit's proportionate share of statewide emissions (either projected or reported). Both of the new NODA3 allocation methods are based on heat-input. Option 1 is a pure heat-input allocation method and would allocate based on each unit's proportionate share of the state's total historic heat input. Option 2 would yield the same initial allocation pattern as Option 1 (based on historical heat input) but would then add a constraint (i.e., a limit on allocations) based on a unit's reasonably foreseeable maximum emissions under the proposed Transport Rule trading programs. Each of these methods contain significant flaws that must be addressed. [EPA-HQ-OAR-2009-0491-3946[1].1, pp.7-8]
In sum, allocations should reflect actual emissions. EPA's heat-input methods do not accomplish that objective as drafted. If EPA chooses to stick with the heat-input method, it must refine its emission constraint and issue a supplemental proposed rule for comment. [EPA-HQ-OAR-2009-0491-3946[1].1, p.9]
Response: 

EPA notes that all data available was released for NODA3 and all sources reported. Furthermore, the NODA specifically states that EPA is calculating individual unit allocations, but rather the proportions of a state's budget that units would receive. As described in Preamble Section VII.D, EPA has refined its allocation method based on comments. 
Organization: Southern IL Power Cooperative
Hoosier Rural Electric Cooperative
Xcel Energy Inc.
National Rural Electric Cooperative Association (NRECA)
State of Louisiana, Department of Environmental Quality
Comment: 
Hoosier Rural Electric Cooperative
Hoosier Energy REC, Inc. appreciates EPA's proposed additional allocation methods described in the the NODA III.  However, it appears the same basis was used for the derivation of the  proposed Option I and Option II of the NODA.  It seems that allocations were defined regardless of fuel type.  Gas units, based on heat input, were given allocations based on heat input and not by historical emissions, therefore, allocating a large surplus to gas-fired units.  This is not an equitable way of allocation.  [EPA-HQ-OAR-2009-0491-3927[1].1, p.2]
National Rural Electric Cooperative Association (NRECA)
Second, NRECA cannot support any of the options for allowance allocations thus far proposed.  While we appreciate EPA proposing additional allowance allocation options in this NODA III, they fall woefully short of meeting rational decision making.  The NODA III proposed allocation options are shamefully and heavily gas bias.   [EPA-HQ-OAR-2009-0491-3943[1].2, p.4]
CATR NODA III options 1 and 2, however, do not function to distribute allowances in a reasonable, sensible or equitable manner.  They are both unreasonably gas bias. [EPA-HQ-OAR-2009-0491-3943[1].2, p.5]
NRECA agrees with EPA is its assertion that it has "significant discretion to select an allocation methodology that is reasonable and consistent with the goals of the CAA"...[EPA-HQ-OAR-2009-0491-3943[1].2, p.5]
Southern IL Power Cooperative
Southern Illinois Power Cooperative cannot support any of the proposed options for allowance allocations proposed thus far.  While we appreciate EPA proposing additional allowance allocation options in this NODA III, they fall woefully short of meeting the definition of rational decision making.  The NODA III proposed allocation options are shamefully biased toward natural gas.  [EPA-HQ-OAR-2009-0491-3901[1].1, p.2] 
SIPC agrees with EPA is its assertion that it has "significant discretion to select an allocation methodology that is reasonable and consistent with the goals of the CAA.   CATR NODA options 1 and 2, however, do not function to distribute allowances is a reasonable, sensible or equitable manner.  They are both unreasonably biased toward gas. [EPA-HQ-OAR-2009-0491-3901[1].1, p.3]
State of Louisiana, Department of Environmental Quality
Louisiana believes that using heat inputs alone is not an adequate method for distributing allocations. Many units in Louisiana have already installed controls so that using heat input to distribute allocations will lead to errors. The allocations for Louisiana in Option 1 and Option 2 have inflated allocations for some units while leaving other units with inadequate allocations to continue operating when compared to allocations distributed through CAIR. Units that are not given enough allocations to properly operate will be at a disadvantage and the cost of buying allocations will be passed on to the general public in the form of rate increases. [EPA-HQ-OAR-2009-0491-3977[1].1, p.2]
Xcel Energy Inc.
The allocation methodology in the NODA tends to shift allowances away from coal units most heavily impacted by the CATR to gas units that will need to do little or nothing to comply, Xcel Energy believes that an allocation approach that imposes additional costs on units already most impacted is not good policy, and reiterates its earlier position that EPA should instead employ an historic, emissions-based allocation. [EPA-HQ-OAR-2009-0491-3948[1].1, p.1]
The new allocation methodology in the NODA shifts allowances away from EGUs that will be most impacted to units that will need to do little or nothing for compliance.
The NODA presents two alternative allowance allocation methods. In contrast to the original CATR proposal, which based allocations on forecasted emissions, both of the NODA methods change the allocation basis to historic unit heat input. Internal analysis of the Xcel Energy system indicates this change will result in a large shift of allowances away from coal units that will likely have to install emissions controls to gas units that will likely have to do little or nothing to comply with the CATR. More specifically, our analysis indicates that, whereas under the original CATR allocation the bulk of allowances would be allocated to units otherwise needing control equipment retrofits, in the alternate NODA methodology, less than fifty percent (50%) of the allowances will be allocated to such units. In other words, under the NODA allocation approach, a substantial portion of the total allowance value that was initially slated to mitigate control costs on the most impacted coal units would be given to other units instead. [EPA-HQ-OAR-2009-0491-3948[1].1, p.2]
Any allowance allocation methodology that would impose additional costs on those units already most impacted is inequitable and does not represent good policy.
In the NODA, EPA sets forth its rationale for switching from an emissions basis to a heat input basis for allowance allocations as follows: 'EPA believes that, because higher-emission-rate units generally are responsible for a greater share of a state's total emissions and thus bear a greater responsibility for a states' significant contribution and interference with maintenance, this distribution of burden is consistent with the goals of CAA section 11 0(a)(2)(D)(i)(1 ).' [EPA-HQ-OAR-2009-0491-3948[1].1, p.2]
While a reasonable general argument can be made for linking cost burden to relative share of responsibility, Xcel Energy believes application of the methodologies proposed in the NODA shifts the balance too far in favor of those EGUs least affected by the CATR. To begin with, higher-emission-rate units also bear the higher direct cost of emission controls under the rule before any allocation system is applied. Most lower-emission-rate units, on the other hand, not only bear no direct cost, but stand to realize actual financial gain through higher prices for their output as a result of the CATR. Instead of using allocations to mitigate costs where they will be highest, both of the NODA proposals would provide a surplus of allowances to these lower-emission-rate units, further benefiting their economic position and increasing the burden on EGUs already facing highest costs. In the end, utility customers will ultimately bear the burden of any excessive cost involved in achieving the environmental goals of the CATR. [EPA-HQ-OAR-2009-0491-3948[1].1, p.3]
Response: 
Thank you for your comment.

Organization: State of Ohio Environmental Protection Agency (Ohio EPA)
Comment: 
State of Ohio Environmental Protection Agency (Ohio EPA)
Second, we remain concerned that the two new options still do not provide for a distribution mechanism of allowances that will meet the needs of the majority of Ohio's units. [EPA-HQ-OAR-2009-0491-3915[1].1, p.2]
When comparing the original proposal's allocations to the new allocation methods, Ohio EPA found the following for Ohio's coal units (includes only those units provided allocations in the first proposal):
:: 2012 Distribution of S02 (from over 450,000 tons total to distribute)
For units with advanced S02 controls either in place currently or planned to be in place by the 2012 control period, Option 1 allocates over 140,000 more tons and Option 2 allocates over 131,000 more tons. While for units without advanced S02 controls, Option 1 allocates nearly 140,000 less tons and Option 2 allocates over 124,000 less tons.
:: 2014 Distribution of S02 (from over 173,000 tons total to distribute)
For units with advanced S02 controls either in place currently or planned to be in place by the 2012 control period, both Options 1 and 2 allocate over 25,000 more tons. While for units without advanced S02 controls, both Options 1 and 2 allocate over 26,000 less tons.
:: 2012 Distribution of annual NOx (from over 94,000 tons total to distribute)
For units with advanced NOx controls either in place currently or planned to be in place by the 2012 control period, both Options 1 and 2 allocate over 22,000 more tons. While for units without advanced NOx controls, both Options 1 and 2 allocate over 21 ,000 less tons. [EPA-HQ-OAR-2009-0491-3915[1].1, p.2]
:: 2012 Distribution of ozone season NOx (from over 39,000 tons total to distribute)
For units with advanced NOx controls either in place currently or planned to be in place by the 2012 control period, both Options 1 and 2 allocate over 9,000 more tons. While for units without advanced NOx controls, both Options 1 and 2 allocate over 9,000 less tons. [EPA-HQ-OAR-2009-0491-3915[1].1, p.3]
While the two new allocation methods were an attempt to address concerns raised by Ohio and other commenters, the methods seem to result in an opposite extreme of new issues and concerns as identified in these comments. [EPA-HQ-OAR-2009-0491-3915[1].1 ,p.5]
Response: 

EPA notes that units' operation decisions are independent of allocation method, since there is an opportunity cost associated with using an allowance (that is, the price obtained by selling it).
Organization: State of Wisconsin, Department of Natural Resources
Comment: 
State of Wisconsin, Department of Natural Resources
Allocating Allowances  --  The Department strongly supports using historic operations as the basis for allocating allowances to individual sources. EPA's most recent allocation methods, as proposed, need to be carefully modified to avoid allocating excess allowances to some utilities, avoid burdensome emission reductions or avoid penalizing already well-controlled utilities. Emission allocations should be updated on a schedule consistent with electric utility practices and the installation of control equipment. [EPA-HQ-OAR-2009-0491-3968[1].1, p.1]
The Department strongly supports using a historic based allocation method over the IPM based allocation method originally proposed in the Transport Rule. However, several modifications are needed to the methods as proposed under this NODA. These changes are critical to enabling all Wisconsin utilities to be able to comply with the Transport Rule and are also consistent with EPA's intended goal of the alternative 2 option. We compared current utility emission levels with the allocations which result from the proposed historic based methods (TR-Alt1 and TR-Alt2). Of particular note is that EPA proposed TR-Alt2 to specifically address the potential over allocation of allowances to any particular source when compared to actual or potential emissions. In short, neither proposed method accomplished this intent for Wisconsin sources. As shown in the attachment, a substantial number of utilities receive allowances significantly beyond 2010 emission levels even under the TR-Alt2 approach. With the overall SO2 emission budget being reduced below current emission levels any over allocation of allowances can cause severe compliance issues for specific utilities. For example, looking at the 2012 allocations We Energies potentially receives 15,000 to 20,000 allowances in excess to current emission levels whereas Alliant Energy must reduce emissions by approximately 25,000 to 30,000 tons. Simply put, Alliant Energy cannot comply with this requirement through the installation of pollution control equipment by 2012. This same result is seen under the 2014 allocation of allowances for TR-AM and Alt2. We acknowledge that We Energies is a well-controlled utility and as such should not be penalized. However, under the short compliance timeframes of the Transport Rule, such large differences between actual emissions and allowances will likely cause substantial compliance issues or cost increases by simply requiring one utility to purchase allowances from another. Another example is where EPA's allocation method provides excess allowances to sources fired with natural gas. [EPA-HQ-OAR-2009-0491-3969[1].1, p.2] [[See Docket Number EPA-HQ-OAR-2009-0491-3969[1].1, pp.5-6 for the Attachment.]]
Response: 

EPA also notes that there are several options for compliance in 2012, including running existing emission controls, switching to lower emission fuels, and buying allowances. The 2012 state budgets were developed to reflect units' inability to build new controls prior to 2014. Therefore, EPA believes state emission limits are attainable without necessarily building new emission controls.
Organization: Sunbury Generation LP
Comment: 
Sunbury Generation LP
To the extent that EPA finalizes an allocation approach based on historic and projected emissions, such emissions data should not be adjusted downward based on the assumed installation of pollution control technologies, where such controls have not yet been constructed and there is no legal basis requiring their operation. [EPA-HQ-OAR-2009-0491-3920[1].1, p.4]
Response: 
Thank you for your comment.

Organization: Sunflower Electric Power Corporation
Comment: 
Sunflower Electric Power Corporation
The NODA allocations impose expected "well-controlled source" emission rates that are much lower than the recently promulgated SO2 and NOX NSPS emission standards for coal-based EGUs (2006). Allocations based upon the severe emission rates utilized as a basis for the allocation are woefully inadequate for unrestricted operation of state-of-the-art coal-based EGU resources. [EPA-HQ-OAR-2009-0491-3958[1].1, pp.2-3]
- All of the proposed allocation options present numerous impossibilities for unit compliance, inequities and design flaws in the methodology used that could be largely corrected if the allocation methodology appropriately and accurately allocated allowances recognizing different emission characteristics and reduction capabilities between categories of fuel, including coal, coal rank, gas, oil, gas/oil duel fuel and categories of unit design including coal boiler, combined cycle and combustion turbines. [EPA-HQ-OAR-2009-0491-3958[1].1, p.2]
- The allocations are not based upon emission reductions necessary to achieve statutorily mandated ozone and particulate matter improvements that are the basis for the regulation. [EPA-HQ-OAR-2009-0491-3958[1].1, p.3]
- Additionally the proposed options fail to accurately reflect that many unit emission reductions required to match unit allowance allocations are not achievable by 2012. [EPA-HQ-OAR-2009-0491-3958[1].1, p.3]
Sunflower joins with other commenters, including those of its national trade association (the National Rural Electric Cooperative Association). Those comments, which are incorporated by reference herein, reveal that the allocation methodologies used are overly simplistic and are based on factors and assumptions which are not based in reality. The proposed rule's  "one size fits all" approach cannot be justified on either a scientific or legal basis, Sunflower recommends EPA reconsider and develop an alternative allocation methodology that is equitable and recognizes the different emission characteristics between fossil fuels and combustion designs.   A rational pause in the regulatory process to assess and address the shortcomings within the current approach is fully  within EPA regulatory discretion.  More importantly, reconsideration is clearly justified given the legitimate criticisms raised as to the designs used by EPA for the allocations and the erroneous and simplistic emission levels used.It is far more important that the agency get it right than it is for the agency to simply get it done. [EPA-HQ-OAR-2009-0491-3958[1].1, p.5]
Response: 

EPA notes that it is the state budgets, not the unit allocations, that reflect the required emissions reductions in each state.

Organization: Vectren Corporation 
Comment: 
Vectren Corporation 
By contrast, the heat input based methodology proposed in the current NODA provides that those units that are already controlled receive allowances based upon a 'neutral' factor (i.e. heat input). Thus, units are not penalized for having already made significant emission reductions and are not inadvertently placed at a competitive disadvantage for having constructed actual controls (as opposed to merely purchasing allowances) to comply with previous EPA emission reduction programs. Most importantly, this more equitable allocation methodology does not undermine the overall intent of the Transport Rule because the individual state caps remain the same. The allocation methodology outlined in the NOOA merely more equitably and fairly allocates emission allowances within those state caps and replicates the more transparent allocation methodologies used in the successful Acid Rain Program, NOx SIP Call and CAIR programs. [EPA-HQ-OAR-2009-0491-3923[1].1, pp.2-3]
Vectren reiterates its full support for the NOOA's heat input methodology, finding both options far more equitable and balanced than the previous methodology based upon historic emissions. [EPA-HQ-OAR-2009-0491-3923[1].1, p.3]
These discrepancies in the NEEDS database make Option 2 less transparent, less reproducible and predictable for planning purposes, and are the reason Vectren favors NODA Option lover Option 2. Although, Vectren would again stress that despite its stated preference for Option lover Option 2, Vectren still supports both heat input methodology options over the original historic emissions methodology contained in the Transport Rule proposal. [EPA-HQ-OAR-2009-0491-3923[1].1, p.4]
Vectren supports the use of a 5 year look-back period.
In the NODA at issue EPA used a 5 year look-back period to assess historic heat input levels, specifically years 2005 - 2009. This addresses Vectren's previous concern detailed in its prior comments that by using an unrepresentative and depressed recessionary year for an emissions baseline, EPA had in effect imposed a 'double whammy' on clean units such as Vectren's. The double whammy being that controlled units were already placed at a competitive disadvantage under the proposed Transport Rule's use of an emission allowance allocation methodology based solely upon historic emissions (which were already low for these units) instead of a neutral heat input factor. Compounding that clean penalty was the fact that the emission period that EPA based its emission reduction requirement on was historic for its recessionary and steep decrease in generation (and thus emissions), and was simply not representative of future electric demand and necessary generation to meet that demand. By contrast, the 5 year lookback period of 2005- 2009 as proposed in the current NODA is a far more accurate representation of the operating histories of the units, and more predictive of post-recessionary operating levels, and will result in the use of more accurate heat inputs for purposes of the heat input allocation methodology. [EPA-HQ-OAR-2009-0491-3923[1].1, pp.4-5]
Vectren is highly supportive of the proposed heat input allocation methodology outlined in the NODA, as the proposed methodology successfully addresses Vectren's concerns with respect to the original historic emissions methodology published in the original Transport Rule proposal. Vectren believes that EPA should adopt the heat input methodology in the final rule. Adoption of this fair and more 'neutral' heat input methodology will lead directly to much needed planning certainty, and most importantly, to finther significant reductions in S02 and NOx without inadvertently putting clean units such as Vectren's at an economic and competitive disadvantage. [EPA-HQ-OAR-2009-0491-3923[1].1, p.5]
Response: 
Thank you for your comment.

Organization: we energies
Comment: 
we energies
Due to EPA's failure to complete and publish corrections to its database and modeling assumptions, we are unable to sort out whether the alternative allocation methodologies adequately recognize emission reductions that some utilities have already accomplished. Equity in allowance allocation is a key priority for We Energies since advanced post-combustion controls are installed or under construction and will be fully operational by 2013 at approximately 85% of our system's fossil generation capacity. [EPA-HQ-OAR-2009-0491-3976[1].1, p.2]
Response: 
Thank you for your comment.

Organization: Wisconsin Public Service Corporation (WPSC)
Comment: 
Wisconsin Public Service Corporation (WPSC)
1. Unit Allocations for New Units Based on Partial Operating Years Are Not Representative
Under either of the proposed options in the NODA, for units that began commercial operation near January 1, 2009 it is likely that the calculated heat input will not be representative of the actual heat input for the unit. Allocations are based on a unit's percentage of the State's annual heat input during the period from 2005 to 2009. The 3 highest heat input years in the 5 year look back period are averaged to establish a unit's heat input level and consequently its percentage of the State's annul allowance allocation. [EPA-HQ-OAR-2009-0491-3994[1].1, p. 1]
While EPA does give consideration to units without 3 years of data, in that it excludes years with zero annual heat input in the calculation, it presumes that heat input during years with any operation are representative of a full year of operation. This is unlikely for new units, especially coal units that may take months of testing and low load operation before the unit begins to approach normal operation. [EPA-HQ-OAR-2009-0491-3994[1].1, p. 1]
Response: 
EPA has received several comments on the method for calculating a unit's average heat input. When commenters identified years of data that represented partial operation for a specific unit, EPA adjusted the heat-input calculations to exclude those years of data.

XX.A.1.a. Option 1

Organization: Associated Electric Cooperative, Inc. (AECI)
Comment: 
Associated Electric Cooperative, Inc. (AECI)
Option 1 fails to account for the differences between fuels and combustion techniques, instead distributing unit allowances based only on percentage of unit heat in-put as a total of the state's aggregate for all affected fossil fuel units within the state.  Because natural gas has inherently lower sulfur and nitrogen content, these units in the aggregate receive many times the allowances than needed to cover their current emissions.  Moreover, as AECI has commented previously, the proposed compressed compliance timelines afford at best limited and in most cases no opportunity for units to alter their emission characteristics by 2012, even for those units that could cost-effectively reduce their emissions further. [EPA-HQ-OAR-2009-0491-3989[1].1, p.4]
Response: 
EPA is finalizing a method of emissions allowance allocation to individual units under the FIP base on based on that unit's share of the state's historic heat-input, but ensuring that no unit's allocations exceed that unit's historic emissions.  EPA decided to use the allocation methodology originally presented as heat input "option 2" in the January 7, 2011 NODA, modified in response to public comments.  EPA decided to use heat input option 2 but without the application of the "reasonable upper-bound capacity utilization factor and a well-controlled emission rate" factors. See final rule preamble section VII.D for further of discussion EPA's rationale for this approach and response to comments in favor of and in opposition to this approach.
Additionally, section VI of the preamble discuss potential compliance strategies that EPA considers achievable by 2012, and those that it does not.  For example, EPA believes there is substantial opportunity for sources to alter/lower there emissions from base case levels by simply operating already installed controls in 2012.  Other emission reduction opportunities (e.g., installation of FGD) are not available by the 2012 time frame, and thus were not considered as available options in EPA 2012 modeling or 2012 budget formation.
Organization: Cogen Technologies Linden Venture, LP
Comment: 
Cogen Technologies Linden Venture, LP
Between Options 1 and 2, Linden Cogen prefers the former in the interest of simplicity. [EPA-HQ-OAR-2009-0491-3938[1].1, p.3]
However, for the sake of simplicity, Linden Cogen would prefer Option 1 because it is rooted firmly in reported data and does not depend upon Option 2's assumptions about 'reasonable upper-bound capacity factor[s]' (established at the 95th percentile) for particular technology types. Id. [EPA-HQ-OAR-2009-0491-3938[1].1, p.6] 
Response: 
EPA is finalizing a method of emissions allowance allocation to individual units under the FIP base on based on that unit's share of the state's historic heat-input, but ensuring that no unit's allocations exceed that unit's historic emissions.  EPA decided to use the allocation methodology originally presented as heat input "option 2" in the January 7, 2011 NODA, modified in response to public comments.  EPA decided to use heat input option 2 but without the application of the "reasonable upper-bound capacity utilization factor and a well-controlled emission rate" factors. See final rule preamble section VII.D for further of discussion EPA's rationale for this approach and response to comments in favor of and in opposition to this approach.
Organization: Duke Energy
Dominion
NRG Energy
National Rural Electric Cooperative Association (NRECA)
Independence Power & Light (IPL)
Kansas City Board of Public Utilities (BPU)
Comment: 
Dominion
Alternative Option 1
Although we appreciate EPA's use of reported unit heat input data averaged over a multi-year period in Alternative Option 1, we prefer that EPA allocate allowances based on the emissions-based approach used in the initial proposed rule, but corrected to address the discrepancies we have noted above and in previously submitted comments on the CATR proposal (for example, correct the Massachusetts state budget). In this way, the unit-specific allocations and state budgets will be more representative of what generators will need to operate going forward. The original allocation methodology, if corrected, provides the best alternative for the continued operation of our fleet and does not disproportionately assign allowances to facilities that will not need them, p.6.
Duke Energy
Problem With and Remedy for Option 1  
Option 1 would allocate SO2 allowances to all affected units at the same pounds per million Btu ("lbs/mmBtu") rate regardless of a unit's fuel type. This makes no sense because on a lbs/mmBtu basis, natural gas and oil-fired combustion turbines and combined cycle units emit a fraction of the SO2 emitted by coal units due to the small amounts of sulfur in natural gas and oil combusted in turbines. Because of this, and the fact that natural gas is the dominant fuel used in these units, low SO2 emitting units under Option 1 would receive an SO2 allocation windfall at the expense of coal-fired units. While such an allocation would not have an impact on the rule's ability to satisfy the statutory mandate of Clean Air Act section 110(a)(2)(D)(i)(I) to eliminate significant contribution and interference with maintenance in downwind states, there are elements of fairness and common sense that should be factored into any potential allocation methodology that are clearly absent from Option 1 as it relates to SO2 allocations. [EPA-HQ-OAR-2009-0491-3965[1].1, p.2]
The following table illustrates the problem with the Option 1 SO2 allocations [EPA-HQ-OAR-2009-0491-3965[1].1, p.3] [[See Docket Number EPA-HQ-OAR-2009-0491-3965[1].1, p.3 for table.]]
There is no rationale that Duke Energy can think of for allocating such a large number of SO2 allowances to combustion turbine and combined cycle units that they do not need. The purpose of allowance allocations under a cap-and-trade program is to place a boundary on the level of emissions consistent with the level of reduction needed to achieve the environmental outcome, while providing some flexibility through the trading mechanism. Under the proposed SO2 allocations to gas and oil fired combustion turbines and combined cycle units, there would be no boundary at all. The allocations would far exceed any possible level of emissions from these units, and this takes scarce allocations away from coal-fired units that will be subject to additional controls. [EPA-HQ-OAR-2009-0491-3965[1].1, pp.3-4]
Even if combustion turbines and combined cycle units emitted SO2 in the future at historic levels (the sum of the average of 2003  -  2009 SO2 emissions for the universe of sources identified as combustion turbines and combined cycle units is 1,772 tons), which is highly unlikely due to the expanded use of very low sulfur oil and the ever increasing use of natural gas as the preferred fuel source for these units, this level of emissions would equate to less than 0.05 percent of the 2012 PTR SO2 budgets and about 0.07 percent of the 2014 PTR SO2 budgets. [EPA-HQ-OAR-2009-0491-3965[1].1, p.4]
nor is there any justification for allocating these units the thousands of allowances they would receive under Option 1. [EPA-HQ-OAR-2009-0491-3965[1].1, p.4]
The way EPA can address this SO2 allocation inequity under allocation Option 1 is to remove all existing and new combustion turbine and combined cycle units from the SO2 portion of any final Transport Rule. Removing these units from the program will eliminate an administrative burden on industry and EPA, and because these units collectively emit almost no SO2, doing so will not adversely impact the environmental performance of the program, but it will avoid unfair and unreasonable SO2 allocations. With these units excluded from Option 1, Duke Energy thinks that the fundamental approach to allocating SO2 allowances under Option 1 based on historic heat input is sound. [EPA-HQ-OAR-2009-0491-3965[1].1, pp.4-5]
With regard to annual and ozone season NOx allocations, Option 1 would also over-allocate NOx allowances to combustion turbines and combined cycle units although to a lesser degree than with SO2. Because we cannot identify a workable solution under Option 1 to fix the NOx allocation problem (in light of the court ruling that vacated the use of fuel-specific emission factors), Duke Energy recommends that EPA not adopt the Option 1 allocation methodology for NOx and instead recommends that EPA consider our comments on how to address this issue under Option 2, as discussed below. [EPA-HQ-OAR-2009-0491-3965[1].1, p.6]
Independence Power & Light (IPL)
Although the NODA states that Option 1, by using 'historic heat input[,] would yield a distribution of allowances putting relatively greater burden on the higher emission- rate units to reduce emissions or purchase additional allowances in order for the units to be in compliance,' 76 FR at 1114/1, no support is offered to demonstrate this result appropriately balances the affected public interests. [EPA-HQ-OAR-2009-0491-3949[1].1, p.4]
EPA states it is considering the validity of points made by commenters as grounds for using the Option 1 heat input allocations. 76 FR at 1113/2-3. But the so-called 'advantages' raised by commenters are merely matters of convenience that do not justify adopting a heat-input regime. The first point raised is that '[h]istoric heat input data are more likely to be accurate at a unit level than projected unit-level emissions and are generally based on quality-assured data.' Id. Even if true, this is hardly compelling given that EPA's role is to project what will best serve the statutory goals in the future, and it is unclear how reliance on historical data satisfies that role. This claimed advantage also runs afoul of the analogous and basic financial maxim that historical results do not predict future returns. Historical annual heat input data reflect a panoply of past decisional factors about how much to run individual units; among that multitude of factors are such things as weather, cost of competing fuels to power units, contractual obligations, maintenance, reliability concerns and so on. In addition, under a historic approach, future changes such as new units, unit retirements, expiration of purchase power agreements, and new purchase power contracts are not accounted for. Even accepting Option 1's broad brush attempt to make these past decisions representative of the future (see 76 FR at 1114/3, step 2, using highest three years), today's fluid energy markets make it increasingly unlikely that the past operations of units will necessarily be representative of their future operations. Thus, the Original Methodology, which incorporates forward-looking projections, is much more likely to present a more realistic future view than placing sole reliance on historical data as is done with Option 1. [EPA-HQ-OAR-2009-0491-3949[1].1, pp.4-5]
Kansas City Board of Public Utilities (BPU)
B. Historic Heat Input Does Not Provide a Reasonable Basis for Future Regulation [EPA-HQ-OAR-2009-0491-3978[1].1, p.4]
EPA states it is considering the validity of points made by commenters as grounds for using the Option 1 heat input allocations. 76 FR at 1113/2-3. But the so-called 'advantages' raised by commenters are merely matters of convenience that do not justify adopting a heat-input regime. The first point raised is that '[h]istoric heat input data are more likely to be accurate at a unit level than projected unit-level emissions and are generally based on quality-assured data.' Id. Even if true, this is hardly compelling given that EPA's role is to project what will best serve the statutory goals in the future, and it is unclear how reliance on historical data satisfies that role. This claimed advantage also runs afoul of the analogous and basic financial maxim that historical results do not predict future returns. Historical annual heat input data reflect a panoply of past decisional factors about how much to run individual units; among that multitude of factors are such things as weather, cost of competing fuels to power units, contractual obligations, maintenance, reliability concerns and so on. Even accepting Option 1's broad brush attempt to make these past decisions representative of the future (see 76 FR at 1114/3, step 2, using highest three years), today's fluid energy markets make it increasingly unlikely that the past operations of units will necessarily be representative of their future operations. In BPU's view, the Original Methodology, which incorporates forward-looking projections, is much more likely to present a more realistic future view than placing sole reliance on historical data as is done with Option 1. [EPA-HQ-OAR-2009-0491-3978[1].1, pp.4-5]
When considering the factors raised by commenters to support Option 1, EPA should recognize that merely labeling characteristics of heat input data, like historical accuracy, as 'advantages' does not make them so; rather, it must be shown these characteristics actually further the statutory objective before they can be viewed as advantageous. E.g., North Carolina v. EPA, 531 F.3d 896, 908 (D.C. Cir. 2008). ('But the flow of logic only goes so far. It stops where EPA is no longer effectuating its statutory mandate'). That showing has not been made. [EPA-HQ-OAR-2009-0491-3978[1].1, p.5]
National Rural Electric Cooperative Association (NRECA)
Option 1 fails to account for the differences between fuels and combustion designs, instead distributing unit allowances based only on percentage of unit heat in-put as a total of the state's aggregate for all affected fossil-fuel units within the state.  Because natural gas has inherently lower sulfur and nitrogen content, units utilizing gas in the aggregate receive many times the allowances needed to cover their current emissions.  This lop-sided allocation methodology in proposed option 1 leaves many coal-fired generating units, even those with well controlled emissions levels, with significant allowance shortfalls.  [EPA-HQ-OAR-2009-0491-3943[1].2, p.5]
NRG Energy
Option 1 does not enhance the CATR program objectives because there are other factors that affect emission rates or emissions reduction potential. The correct relationship should account for a source's emissions, historic or projected, emission rates and its ability to achieve reductions.[EPA-HQ-OAR-2009-0491-3933[1].1, p.3]
Option 1 creates an imbalance in the compliance burden: over-rewarding natural gas facilities while under allocating to higher emitting units such as coal, including scrubbed units. Reliable, affordable and efficient electricity markets are dependent on fuel and technology diversity. Both generation resources are needed as the US transitions to cleaner energy and CATR should remain non-discriminatory in approach. Plants that can further reduce emissions, like coal, should receive enough allocations to keep the impact financially on par and encourage further reductions through the sale of resulting excess allowances.  [EPA-HQ-OAR-2009-0491-3933[1].1, p.3]
This imbalance is apparent when comparing the allocation distribution of Option 1 to EPA's proposed projected method, or even to the more accommodating Option 2. [EPA-HQ-OAR-2009-0491-3933[1].1, p.3] [[This comment can also be found in Section XX.A.1.b.]]
Further, because the state budgets (and thus markets) are fixed, the actual "coal to gas" competitive gap is doubled because every one allowance not allocated to a coal unit is directly transferred to a gas facility, thus creating a resulting 2 ton competition gap. [EPA-HQ-OAR-2009-0491-3933[1].1, p.3]
 Option 1, heat input only, is anything but fuel neutral. It ignores the fact that there are inherent differences in fuels, generation technology and the ability to control emissions. It is absurd that gas units that do not emit SO2 should receive a large portion of the allocation. (see NY discussion below). [EPA-HQ-OAR-2009-0491-3933[1].1, p.4]
As discussed in the previous section, Option 1 assigns allowances to units with lower NOx obligation and virtually no SO2 obligation. This transfer yields a significant competitive windfall to gas units while placing an unfair economic burden and competitive disadvantage on coal facilities.  [EPA-HQ-OAR-2009-0491-3933[1].1, p.5]
The allocation imbalance varies from state to state and is most significant in states with a higher percentage of gas generation. It is notable in three states in which NRG operates: New York, Louisiana and Delaware. [EPA-HQ-OAR-2009-0491-3933[1].1, p.5]
 EPA Question  -  Are the alternative methodologies clear and easy to understand?  Option 1 sacrifices fairness and accuracy for simplicity; therefore it is "too simple." [EPA-HQ-OAR-2009-0491-3933[1].1, p.8]
 EPA Question  -  Do these alternatives yield a reasonable distribution of allowances?  Option 1 does not yield a reasonable distribution of allowances. It assigns windfall allocations of SO2 and tips the NOx allocation balance to plants that do not have a commensurate compliance obligation. A gas unit that emits virtually no SO2 and incurs no costs would get free allowances, while a coal unit that needs to invest hundreds of millions to reduce emissions gets far fewer allowances than it needs to cover its compliance costs. The result is a windfall for gas generators and punitive costs for investors and customers of coal plants. [EPA-HQ-OAR-2009-0491-3933[1].1, p.9]
Response: 
EPA is finalizing a method of emissions allowance allocation to individual units under the FIP base on based on that unit's share of the state's historic heat-input, but ensuring that no unit's allocations exceed that unit's historic emissions.  EPA decided to use the allocation methodology originally presented as heat input "option 2" in the January 7, 2011 NODA, modified in response to public comments.  EPA decided to use heat input option 2 but without the application of the "reasonable upper-bound capacity utilization factor and a well-controlled emission rate" factors. See final rule preamble section VII.D for further of discussion EPA's rationale for this approach and response to comments in favor of and in opposition to this approach.
Organization: Oglethorpe Power
Comment: 
Oglethorpe Power
A. Option I - Historic Heat Input
EPA's first option uses a baseline of historic heat input to determine unit allowance allocations. For each existing unit, the three highest five baseline years (2005 - 2009) of nonzero heat input data from EPA Continuous Emissions Monitoring System ('CEMS') files or National Electric Energy Data System ('NEEDS') information are averaged and used to determine the unit's pro-rata share of the state budget. For any unit with only two years of reported heat input values, its pro-rata share is determined by dividing the baseline heat input by two. For a unit with only one year of heat input data, that value becomes the unit's pro-rata share of the state budget. These three year aveÍage heat input values of all potential existing units in a state are summed to obtain the state's total 'three year average heat input.' Each unit's three year average heat input would be divided by the state's total three year average heat input to determine the unit's share of the state's total three average year input. Finally, each unit's share is multiplied by the state's existing unit portion of the state budget (i.e., 97%) to determine that unit's allowance allocation.
Response: 
EPA is finalizing a method of emissions allowance allocation to individual units under the FIP base on based on that unit's share of the state's historic heat-input, but ensuring that no unit's allocations exceed that unit's historic emissions.  EPA decided to use the allocation methodology originally presented as heat input "option 2" in the January 7, 2011 NODA, modified in response to public comments.  EPA decided to use heat input option 2 but without the application of the "reasonable upper-bound capacity utilization factor and a well-controlled emission rate" factors. See final rule preamble section VII.D for further of discussion EPA's rationale for this approach and response to comments in favor of and in opposition to this approach.
Organization: Southern Company
Clean Energy Group
State of Ohio Environmental Protection Agency (Ohio EPA)
Manitowoc Public Utilities (MPU)
PPG Industries, Inc.
City of Tallahasse
Lafayette Utilities System
Santee Cooper
Nebraska Public Power District
Connecticut Department of Environmental Protection
Southern IL Power Cooperative
Buckeye Power, Inc.
Forest County Potawatomi Community
Exelon
Omaha Public Power District
Virginia Independent Power Producers
Gainesville Regional Utilities (GRU)
Tennessee Valley Authority (TVA)
Florida Municipal Power Agency, Gainesville Regional Utilities, JEA, Orlando Utilities Commission, and City of Tallahassee
Vectren Corporation 
Sunbury Generation LP
Kansas City Power and Light Company (KCP&L)
Great River Energy
Gulf Coast Lignite Coalition
NextEra Energy, Inc.
Entergy Services, Inc.
PSEG Services Corporation
Birchwood Power Partners, L.P.
Cleco Corporation
AES Corporation (AES)
Massachusetts Department of Environmental Protection
Texas Commission on Environmental Quality
Constellation Energy
San Miguel Electric Cooperative, Inc.
Occidental Chemical Corporation (OCC)
America's Natural Gas Alliance
Exxon Mobil Corporation
PowerSouth Energy Cooperative
Old Dominion Electric Cooperative
Dayton Power and Light Company (DP&L)
Wisconsin Public Service Corporation (WPSC)
American Petroleum Institute (API)
GenOn Energy, Inc.
Alcoa Power Generating Inc. - Warrick Power Plant
National Grid
Tenaska, Inc.
Comment: 
AES Corporation (AES)
AES believes the alternative method Option 1 proposed in the NODA is superior and a more equitable methodology than the original allocation methodology proposed on July 6, 2010. [EPA-HQ-OAR-2009-0491-4016, p. 3]
Alternative allocation methods based upon historical heat input as identified by Option 1 have a track record of proven success as evident by the Acid Rain, NOx SIP and state emission reduction programs. Adjusting the allocations based on historical heat input increases allocations to facilities with a proven operational track record, and minimizes allocations to facilities historically shown to operate less frequently. Such an approach avoids potential over allocation for facilities with low capacity factors. Further, the Option 1 can be vastly improved if the Heat Input (HI) averages use the highest three 12 month periods rather than highest three calendar years. The analysis is easy to complete and will result in a more equitable distribution of allowances. [EPA-HQ-OAR-2009-0491-4016, p. 3]
AES also suggests EPA to consider a modified constraint on the Option 1 allocation to reduce the potential for an over-allocation to some units. The historical heat input allocation should limit allowance allocations based upon a unit's permit limitation and potential to Emit. This restriction has been employed by state administration in the NOx SIP call and state emission reduction programs. [EPA-HQ-OAR-2009-0491-4016, p. 3]
Option 1 Issues: Heat Input data for certain facilities that were analyzed, are in question. A mechanism is needed to repair these issues. [EPA-HQ-OAR-2009-0491-4016, p. 4]
Alcoa Power Generating Inc. - Warrick Power Plant
APGI recommends that NODA Option 1 be used for allocating state budgets to subject units. Option 1 proportions baseline heat input for each subject unit to total statewide baseline heat input to determine the share of state budget to be allocated. [EPA-HQ-OAR-2009-0491-4024, p.1]
America's Natural Gas Alliance
ANGA believes that the Agency has broad authority to design allocation methodologies under the CAA, and, as discussed further below, we support the use Option 1 identified in the NODA - historic heat-input based methodology with no constraints. [EPA-HQ-OAR-2009-0491-3939[1].1 ,p.2]
EPA has identified two input-based options in the NODA. ANGA supports Option 1 -- the use of historic heat input without artificial constraints -- as the most appropriate allocation methodology, for several reasons. First, ANGA believes that a methodology that is based on straight historic input without any adjustment or constraints is appropriate because it uses the most accurate data available. Most of the data that the Agency would use to establish allocations under Option 1 has been subjected to rigorous quality assurance/quality control review. Use of that data alone also does not involve the application of 'estimation' or 'projection' factors, unlike the originally proposed methodology (which uses 'adjusted projected emissions') and Option 2 (which would apply such factors as a calculated 'well-controlled emission rate' and a 'reasonable upper bound capacity factor'). [EPA-HQ-OAR-2009-0491-3939[1].1, p.3]
Second, use of a straight input-based methodology is decidedly fuel neutral. It also does not penalize 'early movers' that may have proactively switched fuels or installed emission control systems. [EPA-HQ-OAR-2009-0491-3939[1].1, p.3]
ANGA believes that Option 1 appropriately puts a greater burden on units that have higher emission rate to reduce emissions or purchase allowances from lower emission rate units, and we agree with EPA that 'because higher-emission-rate units generally are responsible for a greater share of a state's total emissions and thus bear greater responsibility for a states' significant contribution and interference with maintenance, this distribution of burden is consistent with the goals of CAA section 110(a)(2)(D)(i)(I).' These unit level allocation methodologies will ensure that the CATR sends the right economic signals to achieve the purpose of the rule - cleaner air. [EPA-HQ-OAR-2009-0491-3939[1].1, p.3]
Adoption of a straight heat input methodology also reduces the risk oflegal challenges and their attendant delay. It provides a clear, simple way to allocate emissions, while modeled future projected emissions are complex and likely to generate a number of errors that could be considered arbitrary and capricious. [EPA-HQ-OAR-2009-0491-3939[1].1, p.3]
In summary, the Option 1 methodology is the cleanest and easiest to understand, does not raise implementation concerns, comports with the goals of the CAA and of Section 110(a)(2)(D)(i)(I), and uses the best data, and ANGA urges the Agency to adopt this methodology. [EPA-HQ-OAR-2009-0491-3939[1].1, p.3]
ANGA strongly supports the use of the methodology identified by EPA as Option 1 in the NODA - the straight heat input-based methodology without constraints. This methodology is consistent with both the broad goals of the CAA and the goals in the specific transport provisions in Section 110(a)(2)(D)(i)(I) of the Act. It is also the most straightforward of the various options that EPA is considering, would be the easiest to implement, and uses the best data without further adjustment, and ANGA urges the Agency to adopt this methodology. [EPA-HQ-OAR-2009-0491-3939[1].1, p.6]
American Petroleum Institute (API)
A. API supports Option 1; it remedies a major problem with the CATR proposal allocation method that we attributed to the use of modeling projections and assumptions about future operations and emissions. [EPA-HQ-OAR-2009-0491-3982[1].1, p.2]
EPA requests comments for two alternative allocation methods for existing units subject to the Clean Air Transport Rule proposal in this NODA. API supports Option 1 of the January 7, 2011 NODA as it is based on a heat input method. [EPA-HQ-OAR-2009-0491-3982[1].1, p.2]
A. API supports Option 1.
This approach remedies a major problem with the CATR proposal allocation method from the August 2, 2010 proposed rule. We found that proposal wanting as it used modeling projections and assumptions about future operations and emissions. In many cases such as natural gas fired cogen units the use of the CATR proposal allocations method resulted in an allocation 95% or greater reduced from the historic emissions baseline due to errant assumptions about future operation. [EPA-HQ-OAR-2009-0491-3982[1].1, pp.2-3]
Option 1 has the following advantages:
1. Historic heat input data are a more accurate basis at a unit level than projected unit-level emissions.
2. Historic heat input data are generally based on quality-assured data reported by sources from actual measurements.
3. Historic heat input data reflect actual fuel choices and don't attempt to project fuel choices or changes in fuels into the future.
4. Historic heat input data are emissions-control-neutral and thus do not yield reduced allocations for units that installed or are projected to install pollution control technology.
5. The use of a high 3 out of 5 years does a reasonably good job of allowing near maximum capacity operations to meet product demand in 2005-2009 though in some cases, a particular unit's operation may have been well below capacity operation (due to, for instance, hurricane induced operation discontinuations in the Gulf Coast states). [EPA-HQ-OAR-2009-0491-3982[1].1, p.3]
In summary, API supports Option 1; it remedies a major problem with the CATR proposal allocation method that we attributed to the use of modeling projections and assumptions about future operations and emissions. [EPA-HQ-OAR-2009-0491-3982[1].1, p.5]
Birchwood Power Partners, L.P.
although it would suggest that EPA adopt Option 1 for the sake of simplicity, and to address concerns over the fact that independent power producers do not control how often and for how long they are dispatched under their long term offtake contracts. [EPA-HQ-OAR-2009-0491-3940[1].1, p.2]
However, for the sake of simplicity and to address concerns over the inability of independent power producers to control their dispatch under long term contracts, Birchwood Power would recommend EPA adopt Option 1 because it is rooted firmly in reported data and does not depend upon Option 2's assumptions about 'reasonable upper-bound capacity factor[s]' (established at the 95th percentile) for particular technology types. [EPA-HQ-OAR-2009-0491-3940[1].1, p.3]
Buckeye Power, Inc.
While neither Option is ideal, Option 1 constitutes the more sound and fair approach. Thus, as between the two Options, Buckeye urges EPA to adopt Option 1, with appropriate adjustments to prevent the over-allocation of allowances to natural gas-fired units. [EPA-HQ-OAR-2009-0491-3900[1].1, p.3]
Under Option 1, a unit's three-year average heat input would be divided by the relevant state's total three-year average heat input to determine that unit's share of the state's total three-year average heat input. Each unit's resulting share is then multiplied by the state's existing unit portion of the state's emissions budget to determine a unit's allocation. [EPA-HQ-OAR-2009-0491-3900[1].1, p.3]
Option 1 is clear and straightforward. Further, it would eliminate perpetual allocations to the highest emitting units, and would not punish well-controlled units and its owners' customers who paid for investments in emission control equipment. Based on our review of the data, it appears that Option 1 produces a more reasonable distribution of allowances than the historic emissions-based allocation methodology. [EPA-HQ-OAR-2009-0491-3900[1].1, p.3]
City of Tallahasse
Option #1 provides a more transparent methodology than the original proposal, yet it fails to recognize actions taken by many utilities in the years prior to the implementation of CAIR. [EPA-HQ-OAR-2009-0491-3912[1].1, p.2]
Option #1 provides additional allocations (or in fact over-allocations) for entities that refused to 'get clean' early. [EPA-HQ-OAR-2009-0491-3912[1].1, p.3[EPA-HQ-OAR-2009-0491-3912[1].1]]
Clean Energy Group
While both options address many of the Clean Energy Group's concerns with EPA's preferred approach proposed on July 6,2010, Option 1 is the more straightforward of the two options and our preference. [EPA-HQ-OAR-2009-0491-4002[1].1, p.1]
Cleco Corporation
EPA's Option 1 is a straight heat-input based allocation method. It results in absurd allocations and remarkable windfall profits to certain generating units. The allocation tables and unit-level data EPA provides along with NODA3 have numerous examples of large natural gas units that are allocated SO2 allowances more than 500 times their highest single year SO2 emissions between 2003 and 2009. Over-allocations like these  -  in the SO2 and NOx programs  -  equate to nothing more than EPA printing money under the Clean Air Act good neighbor provision and handing it out disproportionately to certain units  -  without consideration of air emissions. This is untenable. [EPA-HQ-OAR-2009-0491-4007[1].1, p.4]
Connecticut Department of Environmental Protection
At 76 FR 1116, EPA asks if the alternative allocation methodologies are clear and easy to understand. CTDEP agrees that Option 1 of the alternative heat input allocation methodologies is clear and easy to understand. [EPA-HQ-OAR-2009-0491-3884[1].1, p.1]
Among the three options EPA provides- the proposed Transport Rule allocation methodology and Options 1 and 2 in the 3rd NODA - CTDEP recommends that EPA choose Option 1 in the 3rd NODA for its ease of understanding and decreased emphasis on high allocations to high emission rate units. [EPA-HQ-OAR-2009-0491-3884[1].1, p.1]
Constellation Energy
Option 1 is the simplest, is therefore less liable to litigation, offers fuel and pollution control neutrality, and would likely provide for the greatest market liquidity; [EPA-HQ-OAR-2009-0491-4031, p.2]
Dayton Power and Light Company (DP&L)
C. Alternative Allocation Methodologies - Option 1 - Historic Heat Input Approach
DP&L strongly supports the allocation of emission allowances based upon historical heat input. We agree with others that have commented to EPA that using historic heat input as the basis for allocations has the following advantages: [EPA-HQ-OAR-2009-0491-3973[1].1, p.2]
:: Historic heat input data are more likely to be accurate at a unit level than projected unit-level emissions and are generally based on quality-assured data reported by sources from continuous monitoring systems. [EPA-HQ-OAR-2009-0491-3973[1].1, p.2]
:: Historic heat input data are emissions-control-neutral and thus do not yield reduced allocations for units that installed or are projected to install pollution control technology. [EPA-HQ-OAR-2009-0491-3973[1].1, p.2]
Further, we find this methodology to be clear and easy to understand, easily feasible for implementation, and yields a reasonable distribution of allowances. [EPA-HQ-OAR-2009-0491-3973[1].1, p.3]
DP&L submits, however, that this method could be improved by adjustments to the SO2 allowance methodology that would have the effect of distributing more allowances to units that combust fuels that contain sulfur and fewer allowances to units that combust fuels containing no sulfur (natural gas units.) [EPA-HQ-OAR-2009-0491-3973[1].1, p.3]
Entergy Services, Inc.
Entergy Supports The Proposed Option 1 Methodology For Allocating Allowances
While Entergy has long supported allocation methodologies based on energy output (megawatt hours), Entergy also supports the use of historical heat input as a means of distributing unit allowances as proposed in the EPA's Option 1.  In our October 1, 2010 comments on the proposed CATR Entergy encouraged the EPA to reconsider the use of the Integrated Planning Model  as a fair means of allocating allowances and supported the use of a proven, reliable methodology of allocating allowances, such as historical MW output or historical heat input, similar to what has been proposed in Option 1.  As the EPA has pointed out in the NODA, the use of historic heat input data is more likely to be accurate at a unit level than projected unit-level emissions, is fuel-neutral, and is emission-control neutral  (does not penalize units that have installed or are planning to install pollution control technology), making it the most equitable methodology to distribute allowances.  [EPA-HQ-OAR-2009-0491-3986[1].1, pp.1-2]
Exelon
For this reason, among others, Exelon prefers EPA's Option 1. [EPA-HQ-OAR-2009-0491-3919[1].1, p.4]
An allocation based on historic heat input will redress that inequity. For this reason, Exelon also supports Option 1 over Option 2. [EPA-HQ-OAR-2009-0491-3919[1].1, p.5]
Exxon Mobil Corporation
Option 1 allocates a state's existing unit budget based on each unit's proportionate share of the state's total historic heat input from regulated EGUs. [EPA-HQ-OAR-2009-0491-4028, p.]
3. Allocation Method Option 1 - We support use of this option rather than the Clean Air Transport Rule proposal option using future modeled projected operation to develop allocations. Option 1 uses historical heat fired supported by owners or operators, and we prefer it to Option 2. It remedies a major problem with the CATR proposal allocation method that we attributed to the use of modeling projections and assumptions about future operations and emissions. In many cases such as natural gas fired Cogeneration units that supply steam and power to an industrial user, the use of the CATR proposal allocations method resulted in an allocation 95%+ reduced from the historic emissions baseline due to errant assumptions about future operation. [EPA-HQ-OAR-2009-0491-3999[1].1, p.2]
4. Allocation Method Option 1 improvement suggestion - In addition, we recommend EPA consider allowing operators to provide information to adjust heat rate in any years where natural events caused a reduction in one of the 'high 3' years used in this option. [EPA-HQ-OAR-2009-0491-3999[1].1, p.2]
Comment
We support this option. It remedies a major problem with the CATR proposal allocation method that we attributed to the use of modeling projections and assumptions about future operations and emissions. In many cases such as natural gas fired cogeneration units the use of the CATR proposal allocations method resulted in an allocation 95% or greater reduced from the historic emissions baseline due to errant assumptions about future operation. We recommend EPA consider allowing operators to provide information to adjust heat rate in any such years where natural events caused a reduction in one of the 'high 3' years in step 1 above. [EPA-HQ-OAR-2009-0491-3999[1].1, p.5]
Option 1 has the following advantages:
1. Historic heat input data are a more accurate basis at a unit level than projected unit-level emissions.
2. Historic heat input data are based data reported by sources from actual measurements.
3. Historic heat input data reflect actual fuel choices and don't attempt to project fuel choices or changes in fuels into the future.
4. Historic heat input data are emissions-control-neutral and thus do not yield reduced allocations for units that installed or are projected to install pollution control technology.
5. The use of a high 3 out of 5 does a reasonably good job of allowing near maximum capacity operations to meet product demand in 2005-2009 though in some cases a particular unit's operation may have been well below capacity operation (due to , for instance, hurricane induced operation discontinuations in the Gulf Coast states). [EPA-HQ-OAR-2009-0491-3999[1].1, p.5]
Of the two alternative allocation methodologies proposed in the 2011 NODA, EM supports the use of the Historic Heat Rate Approach, referred to as Option 1, over the Emissions-Rate-Informed Historic Heat Rate Approach, referred to as Option 2, because EM believes that such option is more closely tailored to the goals of Section 110 of the Clean Air Act by more strongly favoring cleaner burning sources and due to the ease of administration of Option 1. [EPA-HQ-OAR-2009-0491-4028, p.4]
Florida Municipal Power Agency, Gainesville Regional Utilities, JEA, Orlando Utilities Commission, and City of Tallahassee
  Although Option #1 provides certainty by using a heat input methodology, it fails to sufficiently recognize actions taken by many utilities including our utilities to comply with CAIR. In addition, it does not address over allocation issues. [EPA-HQ-OAR-2009-0491-3907[1].1, p.1]
Forest County Potawatomi Community
Of the two options presented by EPA for implementing a heat-input-based allocation, FCPC supports Option 1, which is based on a three-year average of historic heat input for each covered EGU. Option 1 is superior to Option 2, which would limit some units' allocations if they exceeded a particular unit's historic emissions. Option 1 would better promote energy efficiency and the use of pollution control technology, since, unlike Option 2, Option 1 would not reduce the emission allocations of units that have implemented efficiency or pollution reduction measures. [EPA-HQ-OAR-2009-0491-3882[1].1, p.3]
Regardless, at a minimum, EPA should select Option 1 based on historic heat input. [EPA-HQ-OAR-2009-0491-3882[1].1, p.4]
Gainesville Regional Utilities (GRU)
Even though Option #1 provides certainty by using a heat input methodology, it fails to sufficiently recognize actions taken by many utilities including GRU to comply with CAIR. In addition, it does not address over allocation issues. [EPA-HQ-OAR-2009-0491-3922[1].1, p.1]
GenOn Energy, Inc.
Option 1 would give a substantial number of SO2 allowances to natural gas-fired plants that they do not need for compliance purposes, that does not in any way reflect their share of the compliance burden, and could have a significant impact on power and emission markets. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 7]
Great River Energy
Great River Energy supports EPA's Option 1  -  historic heat input approach alternative allocation methodology, as a superior alternative to EPA's Preferred Option in the original proposal. [EPA-HQ-OAR-2009-0491-3898[1].1, p.4]
In short, Great River Energy argued that the proposed emission based methodology inherently punished our clean burning, gas fired peaking turbines. Consequently, Great River Energy appreciates EPA's recent proposal and supports Option 1 that uses a larger baseline and, more importantly, uses a heat input based allocation methodology. [EPA-HQ-OAR-2009-0491-3898[1].1, p.4]
Again, we greatly prefer Option 1 and believe it more readily achieves the goals of the Clean Air Transport Rule. [EPA-HQ-OAR-2009-0491-3898[1].1, p.5]
Gulf Coast Lignite Coalition
Option 1 proposes allocations based on historical heat input, without an adjustment for fuel type. This is problematic because coal carries a higher sulfur and nitrogen content, automatically disadvantaging any unit utilizing coal because they would receive far less allowances than other sources, such as natural gas. [EPA-HQ-OAR-2009-0491-3963[1].1, p.2]
Kansas City Power and Light Company (KCP&L)
KCP&L favors Alternative 1, which is completely fuel-neutral, the most straightforward, and the easiest to understand and verify. [EPA-HQ-OAR-2009-0491-3893[1].1, p.2]
While it is understood that statewide budgets will most likely differ from what was contained in the Proposed Transport Rule, based on more refined modeling by EPA, KCP&L believes that Alternative 1 presented in NODA 3 is the most straightforward way to allocate allowances between units and is absolutely consistent with the goals of § 110(a)(2)(D)(i)(I) of the Clean Air Act. [EPA-HQ-OAR-2009-0491-3893[1].1, p.2]
Lafayette Utilities System
Option 1 allocates a state's existing unit budget based on each unit's proportionate share of the state's total historic heat input. [EPA-HQ-OAR-2009-0491-3914[1].1, p.3]
Manitowoc Public Utilities (MPU)
MPU prefers the adoption of Option 1 over Option 2. [EPA-HQ-OAR-2009-0491-3918[1].1, p.2]
Massachusetts Department of Environmental Protection
We support Option 1, which provides a simple allocation method based on the average of a unit's three highest annual heat input values over a 2005 - 2009 baseline period. [EPA-HQ-OAR-2009-0491-4017[1].1, p.3]
National Grid
Though either Option 1 or Option 2 addresses National Grid's preference for allowance allocations, we support Option 1 as being the more straightforward and less controversial choice. [EPA-HQ-OAR-2009-0491-3921[1].1, p.1]
Nebraska Public Power District
Option 1 allocates too many allowances to natural gas and well controlled units since it is based solely on heat input. [EPA-HQ-OAR-2009-0491-3886[1].1,p.1]
NextEra Energy, Inc.
Option 1 is the more straightforward of the two options and our preference. [EPA-HQ-OAR-2009-0491-3962[1].1, .2]
Occidental Chemical Corporation (OCC)
Specifically, assuming EPA continues to include cogeneration units located in Louisiana and Texas in the CATR, we support Option 1 for use as the final method whereby emission allocations would be provided to affected sources. Allocation in accordance with Option 1 will adequately address our concerns with the application of IPM allocation method to our Taft, Louisiana cogeneration facility. [EPA-HQ-OAR-2009-0491-3951[1].1, p.2]
Old Dominion Electric Cooperative
Option 1 fails to account for the differences between fuels and combustion techniques, instead distributing unit allowances based only on percentage of unit heat in-put as a total of the state's aggregate for all affected fossil fuel units within the state. Because natural gas has inherently lower sulfur and nitrogen content, these units in the aggregate receive more allowances than needed to cover their current emissions. This disproportionate allocation methodology in proposed option 1 leaves many coal-fired generating units, even those with well controlled emissions levels, with significant allowance shortfalls. [EPA-HQ-OAR-2009-0491-4004[1].1, p.3]
Omaha Public Power District
For the above reasons, OPPD believes that units should not be penalized with fewer allowance allocations because they are better controlled. Therefore, we suggest that Option 1 as included in the January 7, 2011 NODA, or a hybrid of option 1 that includes use of fuel adjustment factors as was done with the CAIR program, would be the most equitable approach to allowance allocation for the Transport Rule. [EPA-HQ-OAR-2009-0491-3905[1].1, p.3]
PowerSouth Energy Cooperative
This alternative is responsive to PowerSouth's comments on the original proposal, and it is preferred over the emissions based methodology of the Proposal.  However, this alternative is NOT the final methodology that should be incorporated into the final rule.  This alternative inappropriately allocates too many SO2 and NOx allowances to gas fired units.  PowerSouth prefers a methodology based on historic heat input AND fuel type.  [EPA-HQ-OAR-2009-0491-3956[1].1, p.6]
PPG Industries, Inc.
Of the two alternative allocation methodologies, PPG supports the use of the first methodology, referred to as the Historic Heat Input Approach or Option 1, over the second methodology, referred to as the Emissions-Rate-Informed Historic Heat Input Approach or Option 2. PPG favors Option 1 as it is a simpler method that is much easier for EPA and the states to administer. Option 1 allocates a state's existing unit budget based on each unit's proportionate share of the state's total historic heat input. Further, Option 1 results in a distribution of allowances that places greater reward on cleaner burning units. [EPA-HQ-OAR-2009-0491-3911[1].1, p.2]
Once a unit's initial Option 1 allowance has been determined, then EPA has to determine the maximum sulfur dioxide (S02) and nitrogen oxide (NOx) annual emission from the 2003-2009 period and the maximum annual ozone season emissions for NOx from the ozone season of that same time period. If a unit's allocation under Option 1 exceeds the maximum annual S02 or NOx rate, or the maximum ozone season rate, then an adjustment would be made downwards to the higher of the maximum annual emissions rate in this period or to an adjusted rate. [EPA-HQ-OAR-2009-0491-3911[1].1, p.2]
This adjustment rate would assume an emission rate of 0.06 lbs/mmBtu for S02 and for NOx. Further, the adjustment would include a 'reasonable upper bound capacity factor.' Each regulated EGU would be evaluated through this process, with each round of adjustment requiring reallocation among the sources. Simply stated, this allocation methodology is overly complicated and administratively burdensome. Further, PPG has concerns over the use of adjustment factors as discussed below. [EPA-HQ-OAR-2009-0491-3911[1].1, p.3]
Option 1 is the method most consistent with the goals of the CAA and provides the greatest ease of administration. Its selection is more likely to cause the shift in power generation to newer, cleaner burning units. [EPA-HQ-OAR-2009-0491-3911[1].1, p.3]
PSEG Services Corporation
While both options address many of the Company's concerns with EPA's preferred approach, Option 1 is the more straightforward of the two options and our preference. [EPA-HQ-OAR-2009-0491-3936[1].1, p.2]
San Miguel Electric Cooperative, Inc.
Option One distributes allowances based on historical heat input with no method to adjust for fuel or type of generating plant. Option One is extremely unfair to coal fired steam generators and provides a windfall of allowances to gas fired combustion turbines and combined cycle plants  -  many times more than they could possibly use. [EPA-HQ-OAR-2009-0491-3997[1].1, p.2]
Santee Cooper
However, we strongly prefer the 'Option 1' approach presented in the NODA because it is more straightforward and consistent with allocation approaches employed in past EPA trading programs. [EPA-HQ-OAR-2009-0491-3913[1].1 ,p.2]
Although either Option 1 or Option 2 would be vastly preferable to the emissions-based allocation method in the proposed Transport Rule, Santee Cooper urges EPA to adopt Option 1. [EPA-HQ-OAR-2009-0491-3913[1].1, p.3]
The fact that purely heat input-based allocations were used successfully in the Nx, SIP Call, weigh in favor of Option 1 rather than Option 2. [EPA-HQ-OAR-2009-0491-3913[1].1, p.4]
Southern Company
Second, EPA's pure heat-input based allocation method (i.e., NODA3 Option 1) is arbitrary and leads to absurd results. For example, in this approach, many large natural gas fired units would receive allocations more than 500 times their highest single year of emissions during the seven-year baseline period that EPA evaluates in NODA3. This option provides an overwhelming windfall to natural gas-fired units, and results in significant under - allocation to coal-based generation, with no consideration of allowance needs. Table 1 below illustrates this imbalance for SO2. EPA should not develop a pure heat-input based allocation scheme that does not give any consideration to historical emissions or need. [EPA-HQ-OAR-2009-0491-3946[1].1, p.8] [[See Docket Number EPA-HQ-OAR-2009-0491-3946[1].1, p.8 for Table 1.]]
Southern IL Power Cooperative
Option 1 fails to account for the differences between fuels and combustion techniques, instead distributing unit allowances based only on percentage of unit heat in-put as a total of the state's aggregate for all affected fossil fuel units within the state.  Because natural gas has inherently lower sulfur and nitrogen content, these units in the aggregate receive many times the allowances they need to cover their current operation.  Meanwhile, the lopsided allocation methodology proposed in option 1 leaves many coal-fired generating units, even those with well-controlled emissions levels, with significant allowance shortfalls.  Moreover, as stated before, the proposed compressed compliance timelines afford almost no opportunity for units to alter their emission characteristics by 2012, even for those units that could cost-effectively reduce their emissions further.  [EPA-HQ-OAR-2009-0491-3901[1].1, p.3]
State of Ohio Environmental Protection Agency (Ohio EPA)
Option 1 distributes allocations based on each unit's proportionate share of the state's total historic heat input evaluated during the 2005 to 2009 baseline period. [EPA-HQ-OAR-2009-0491-3915[1].1, p.1]
Sunbury Generation LP
According to the Second NODA, Option 1 would establish a baseline historic heat input value for each potential existing affected Transport Rule unit. Id at 1114. Allowances would then be allocated to each unit based on the unit's percentage share of the total baseline historic heat input for all potential existing affected units in the state. ld at 11 15. [EPA-HQ-OAR-2009-0491-3920[1].1, p.2]
Tenaska, Inc.
Tenaska believes that the first option offers benefits of simplicity since it is solely based on historical information. We also think using the three highest non-zero heat input values within the five-year base line is appropriate, especially if the year 2009 is included in that five-year period. As explained in the prior comments, 2009 is a non-representative year given the weather and economic conditions that existed. [EPA-R03-OAR-2010-1027-DRAFT-0005.1[1], p.2]
Tennessee Valley Authority (TVA)
Option 1 is less desirable because allocations based solely on an average of the three highest heat inputs in the 2005-2009 timeframe would unfairly allocate too many allowances to low-emitting units, well in excess of those needed to sustain commercial operation for those units. Moreover, Option 1 could result in an excessive need for intra-state trading and thereby result in the hoarding of allowances among one or more owners within a state to the detriment of other owners and operators within that state. [EPA-HQ-OAR-2009-0491-3983[1].1, p.1]
Texas Commission on Environmental Quality
Option One
The EPA acknowledges that the historic heat input data are emissions-control neutral. However, the allocation methodology itself goes no further than this historic heat input data and fails to consider the technological feasibility of controls for different unit types, contrary to extensive EPA guidance on control strategies for SIP submissions. While Option Two appears to consider this technological feasibility in a manner that penalizes sources that have already controlled emissions, technological feasibility is completely ignored under Option One. This proposed approach arbitrarily penalizes or rewards companies based solely on the choice of technology of the unit type, which may have been made decades prior to the EPA's Transport Rule proposal. [EPA-HQ-OAR-2009-0491-4030, p.4]
Vectren Corporation 
However, Vectren prefers the simplicity of the Option 1 approach as it is easily reproducible and allows for a far higher level of planning certainty. Vectren supports using this methodology for all of the trading programs (S02, NOx annual and NOx seasonal) addressed in the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3923[1].1, p.3]
Virginia Independent Power Producers
Of the two options proposed by EPA in the January 7, 2011 Notice of Data Availability (NODA), VIPP prefers Option 1 as being the more straightforward approach.  Additionally, Option 1 addresses the concerns of Independent Power Producers (IPPs) that do not control their own dispatch due to the terms of their long-term offtake contracts. The foundation of Option 1 is based on reported data and does not depend upon Option 2's assumptions about ''reasonable upper-bound capacity factor[s]' (established at the 95th percentile) for particular technology types, [EPA-HQ-OAR-2009-0491-3925[1].1, p.2]
Wisconsin Public Service Corporation (WPSC)
1. Given Option 1 or Option 2, Option 1 is Better
The Historic Heat Input Approach, option 1 methodology, allocates allowances consistently to all existing units. This option uses the unit's average historic heat input as a basis to allocate allowances to the existing units. In option 2, the "Emission-Rate- Informed Historic Heat Input Approach," complicates the methodology by reducing allocations to units at which historical average emissions are greater than the allowance allocation determined under the option 1 methodology. [EPA-HQ-OAR-2009-0491-3994[1].1, p. 2]
WPSC prefers option 1 for the following reasons:
-It is a simple straight forward methodology;
-The value of electricity production from lower emitting units is not discounted by reducing allowance allocation value to those units. An allocation methodology that is neutral in this respect is preferred;
-Lower emitting units receive larger allocations under option 1, thus units with historically lower emission rates are rewarded. This promotes lower emitting units and provides some incentive for owners to precede emission reduction rulemaking rather than following emission reduction rulemaking thereby resulting in earlier emission reductions. [EPA-HQ-OAR-2009-0491-3994[1].1, pp. 2-3]
Response: 
EPA is finalizing a method of emissions allowance allocation to individual units under the FIP base on based on that unit's share of the state's historic heat-input, but ensuring that no unit's allocations exceed that unit's historic emissions.  EPA decided to use the allocation methodology originally presented as heat input "option 2" in the January 7, 2011 NODA, modified in response to public comments.  EPA decided to use heat input option 2 but without the application of the "reasonable upper-bound capacity utilization factor and a well-controlled emission rate" factors. See final rule preamble section VII.D for further of discussion EPA's rationale for this approach and response to comments in favor of and in opposition to this approach.

XX.A.1.b. Option 2

Organization: ARIPPA
Ameren Services Company
Duke Energy
Dominion
Cleco Corporation
AES Corporation (AES)
Constellation Energy
Exxon Mobil Corporation
National Rural Electric Cooperative Association (NRECA)
National Mining Association (NMA)
Nelson Industrial Steam Company (NISCO)
Comment: 
AES Corporation (AES)
EPA should not select Option 2 as the final allocation methodology. Even though Option 2 would yield the same initial allocation pattern as Option 1 (based on historic heat input), the additional constraint (i.e., a limit on allocations) is based on a unit's "reasonably foreseeable maximum emissions" and under the proposed Transport Rule trading programs, will produce an inequitable allocation. The "reasonably foreseeable maximum emissions" are calculated with inaccurate heat input, heat rate, capacity factor and emission rates that are not achievable by some well controlled units. Allocation methods based in part or in full by modeling or projections will also result in unintended consequences. [EPA-HQ-OAR-2009-0491-4016, p. 3]
Data Issues: The EIA data often has large errors contained within the database. Facilities should have ample opportunity to correct these errors before the rule is finalized. Other data used in option 2 are not identified as to the source but also contains errors. The Heat Rate used in Option 2 is one such example. [EPA-HQ-OAR-2009-0491-4016, p. 4]
Option 2 Issues: The Step 4, Annual SO2 Rate Cap (tons), Annual NOx Rate Cap (tons), Ozone Season NOx Rate Cap (tons) and Ozone Season NOx Maximum Cap (tons) were left incomplete for many facilities. Without this data, proper evaluation cannot be completed. [EPA-HQ-OAR-2009-0491-4016, p. 4]
Additional comments
The Capacity Factors used in Option 2 are inaccurate in many cases. Shady Point, like many facilities do not take outages in the summer months and often reach Capacity Factors close to 100%. In fact there are steep penalties if the Capacity Factors falls below 95%. Other facilities like Beaver Valley and Warrior Run have similar contract situations. Errors like this should have ample opportunity to remedy. The Capacity Factors and heat rate should be based on a highest three years out of five if this option 2 (or similar option) is chosen. [EPA-HQ-OAR-2009-0491-4016, p. 4]
Ameren Services Company
On page 1115 of the Federal Register Notice Step 4a uses the reported heat input where available from the Part 75 reporting. EPA should realize that in many instances this 'maximum heat input' is based on a unit's design rating and not CEM data collected as part of Part 75. From Ameren's experience the heat input determined from the Part 75 monitoring is 5% :: 20% higher than that determined from fuel input based on amount of coal burned and analyses of the coal. The CEM heat input is based on either an EPA specified F-factor (based on fuel type) and flow or an F-factor based on coal analysis and flow. While every unit has the option to use the coal based F-factor determination it is Ameren's experience that many units use the EPA default F-factor. In Step 5 EPA is comparing the CEM emissions (generally based on CEM heat input) with most likely a manufacturer's design rating based emissions estimation. EPA should give consideration to calculating these emissions based on the same basis. Ameren suggests that EPA should use the CEM based emissions for both calculations (i.e. use the maximum CEM measured heat input). [EPA-HQ-OAR-2009-0491-3894[1].1, pp.1-2]
ARIPPA
The second allocation option presented by EPA through the Second NODA is based on historic heat input, but proposes to modify the allocations so that they do not exceed the higher of either historic actual emissions or emissions calculated using a "clean emission factor" and the reasonably expected maximum future heat input.  ARIPPA favors the objective behind this second option as a more equitable allocation approach.  However, as proposed by EPA, this second allocation option contains serious inequities.  Specifically, use of the "clean" SO2 emission factor of 0.06 lb/MMBtu is clearly inappropriate for certain sources, such as the ARIPPA facilities, that cannot achieve such emission rate through application of emission controls that are cost effective for such sources.  In the Second NODA, EPA describes the SO2 emission factor of 0.06 lb/MMBtu as "a well-controlled emission rate that all units (regardless of the type of fuel they combust) can meet for the pollutant."  This statement is unsupported in the NODA for retrofitted coal refuse-fired CFBs.  In fact, most, if not all, ARIPPA facilities cannot meet this emission rate in any "cost effective" manner.  [EPA-HQ-OAR-2009-0491-3903[1].1, p.4]
ARIPPA supports the Second NODA to the extent that it would constrain the allowance allocation methodology to prevent allocations to individual sources beyond potential emission rates based on past operating history.  
In developing its second alternative allocation methodology within the Second NODA, EPA proposes a redistribution of allowances by taking into account historic emission rates for lower emitting sources.  In particular, this second alternative would allow for additional allowances to be distributed to those sources that require higher initial allocations in order to satisfy EPA's emission cap objectives.  The allowances would be secured through redistribution of allowances from sources that would otherwise receive allowance allocations that materially exceed historic emission rates. [EPA-HQ-OAR-2009-0491-3903[1].1, p.12]
ARIPPA endorses this approach for multiple reasons.  First, unlike the Proposed Transport Rule, this second alternative identified by EPA through the Second NODA would base allowance allocations on established emission rates for lower emitting sources, and not projected emission rates based upon EPA models of future operating and electricity generating rates.  Such projections are based upon assumptions that are inherently vulnerable to inaccuracies in forecasting. [EPA-HQ-OAR-2009-0491-3903[1].1, p.12]
Second, this alternative allocation method would prevent any "windfall" of allowances from being provided to sources merely because of EPA's selection of the allocation methodology.  As stated by EPA within the Proposed Transport Rule and Second NODA, EPA's approach toward this regulation should not create incentives for sources to increase emissions.  Further, by redistributing the allowances to sources that currently exceed unit-specific emission allocations, EPA would be acting consistent with its stated objective of pursuing cost effective emission control options.  [EPA-HQ-OAR-2009-0491-3903[1].1, pp.12-13] 
EPA proposes through the Second NODA to constrain the allowance allocation levels for lower emitting sources to ensure that such sources do not receive substantially more allowances than historical actual emissions would support.  However, the proposed allocations identified through the second allocation method described in the Second NODA would clearly not fully implement EPA's conceptual proposal.  In addition, the Second NODA would not address another significant circumstance that would result in the allocation of allowances substantially in excess of the quantity required for sources' compliance with the Transport Rule  -  continued allocations to shutdown sources.  Consistent with EPA's statements in the Second NODA that the allocation methodology under the Proposed Transport Rule should not provide an allowance windfall to affected sources, the rule should not provide allowances to any source that has ceased operations.  Instead, the allocations for such sources should be redirected to increase the new source set-aside for the relevant state. [EPA-HQ-OAR-2009-0491-3903[1].1, p.13]
Further, EPA's proposed "clean" SO2 emission factor of 0.06 lb/MMBtu is two orders of magnitude higher than typical emission rates for the combustion of pipeline quality natural gas.  As a result, under the second allocation option in the NODA, EGUs that combust natural gas will receive windfall SO2 allowance allocations that may be two orders of magnitude more than they can physically emit (or are allowed to emit under their permits).  These allowances are therefore unavailable for allocation to those emission sources that have allowance shortfalls and no cost effective means of emission control.  [EPA-HQ-OAR-2009-0491-3903[1].1, p.13]    
In summary, consistent with EPA's proposed approach, the allowance allocation methodology should not result in a "windfall" to any facility; this can be ensured by limiting the maximum allocation to any affected facility to emission levels established by that source, and by ensuring that shutdown sources will not continue to receive an allocation.  Such approach would also be consistent with the objectives of the Clean Air Act and the D.C. Circuit Court's decision in North Carolina, by ensuring that the proposed program does not result in an emissions increase for any source.  [EPA-HQ-OAR-2009-0491-3903[1].1, p.13]
Further, ARIPPA also supports EPA's position articulated through the Second NODA's second alternative allocation methodology that allocations to affected sources should be limited based on established actual emission rates, in order to avoid any substantial "windfall" of excess allowances to certain sources.  This approach is consistent with EPA's stated objective under the Proposed Transport Rule to pursue cost effective emission reductions in support of the emission goals of the regulatory program.  [EPA-HQ-OAR-2009-0491-3903[1].1, p.15]
Cleco Corporation
In recognition of this unjustified windfall, EPA has proposed to add an emission constraint in its Option 2 method. Again, if EPA uses heat input as its basis for allocations, we encourage it to use an emission constraint. However, the NODA3 Option 2 emission constraint is significantly flawed. It fails to adequately mitigate the windfall and leads in many cases to only slightly less absurd results. By way of example, even under Option 2, many natural gas units would receive allocations that exceed their record emission levels (from 2003 to 2009) by over 15,000%. [EPA-HQ-OAR-2009-0491-4007[1].1, p.4]
EPA can and should correct Option 2's deficiencies by throwing out its use of the "well-controlled- rate maximum." EPA's method for calculating this value has no basis in reality. Even for gas units this method would determine a unit's "reasonable foreseeable maximum emissions level," i.e., its allocation cap, based on a 0.06 lbs/mmBtu for both SO2 and NOx. Admittedly this is an emission rate unique to well-controlled coal. EPA's use of capacity factors does not correct this error. EPA must take a hard look at this methodology and develop a more appropriate emission constraint. EPA should avoid the "well-controlled-rate maximum" concept and use each unit's "maximum historical baseline emissions" as its allocation cap, i.e., its "reasonable foreseeable maximum emissions level."  [EPA-HQ-OAR-2009-0491-4007[1].1, p.5]
If EPA insists on retaining the "well-controlled-rate maximum" concept, it should improve that method to provide sensible, realistic results. To do so, EPA could, for example, take into consideration reasonable emission factors based on fuel and generator type, rather than use the clearly erroneous, coal-specific emission rates of 0.06 lbs/mmBtu for SO2 and NOx. [EPA-HQ-OAR-2009-0491-4007[1].1, p.5]
Constellation Energy
Option 2 in contrast, Involves assumptions about plant operations that are complicated and likely more liable to litigation challenges, as well as probably providing less liquidity in the allowance market. [EPA-HQ-OAR-2009-0491-4031, p.2]
Dominion
Under the alternative options in the NODA, facilities in Massachusetts are allocated SO2 allowances based on a 0.043 Ib/mmBtu SO2 emission rate, which is much lower than the effective emission rate in most other states, below best available control technology (BACT) limits and below the 0.06 Ib/mmBtu emission rate that has been assumed for a 'well-controlled' unit that is applied as a constraint under the NODA Alternative Option #2. The NODA states that these 'well-controlled' emission rates represent the' lowest emission rates assumed achievable when state-of-the-art pollution control technologies are installed at coal units in the IPM modeling' and 'are intended to reflect the lower bound of emission rates that suppliers are willing to guarantee when installing state-of-the-art pollution control equipment."  Allowance allocations should not be based on emission rates that are below levels that can be achieved by state-of-the-art control technology. [EPA-HQ-OAR-2009-0491-3987[1].1, pp.4-5]
Any facility like Brayton Point that has spent significant capital for environmental improvements and will be well-controlled should receive sufficient allowances to enable it to continue to operate fully both during the period of time when control equipment is being installed and after the station is fully controlled. In addition, stations that are not controlled should receive sufficient allowances to allow for a coordinated transition with all other key stakeholders, including regional transmission organizations (RTOs), station employees and affected communities. [EPA-HQ-OAR-2009-0491-3987[1].1, p.5]
Alternative Option 2
Alternative Option 2 applies the same multi-year heat-input based approach used under Alternative Option I, but then applies a modification method that reduces allocations for units that are expected to be controlled if the projected emissions based on an assumed emission rate for a 'well controlled plant' are less than either the unit's historical emissions or the allocations determined under Alternative Option 1. This method would disadvantage units that plan to invest in controls by providing them fewer allowances than under Alternative Option 1. This could result in these well-controlled units being dispatched less than uncontrolled plants. EPA should abandon this approach. [EPA-HQ-OAR-2009-0491-3987[1].1, p.6]
Duke Energy
Problems With and Remedies for Option 2  
The Option 2 SO2 allocation methodology, for combustion turbines and combined cycle units, with the exception of two combustion turbine units, results in unit level SO2 allocations equal to either a unit's Initial SO2 Allocation plus reapportionment or its Annual SO2 Rate Cap . While the inclusion of the Annual SO2 Rate Cap in the Option 2 methodology reduces the total number of SO2 allowances collectively allocated to combustion turbine and combined cycle units relative to Option 1, as shown in the following table, the total allocation of SO2 allowances to combustion turbines and combined cycle units under Option 2 are still far in excess of the historic or potential SO2 emissions from these groups of units and are not appropriate. [EPA-HQ-OAR-2009-0491-3965[1].1, p.6]
As discussed above with respect to Option 1, one way to fix this problem is to exclude these low emitting units from the Transport Rule for SO2. A second option, if EPA does not choose to do this, is to modify the Option 2 SO2 allocation methodology so low emitting units do not receive as large an allocation windfall at the expense of coal units.  [EPA-HQ-OAR-2009-0491-3965[1].1, p.7]
As noted above, the Option 2 methodology includes what EPA terms an Annual SO2 Rate Cap, and this has the effect of slightly reducing the size of the SO2 allocation to combustion turbine and combined cycle units. EPA refers to the Annual SO2 Rate Cap as a "reasonably foreseeable maximum emissions level." EPA states in NODA 3 that it believes the Option 2 approach, which incorporates the Annual SO2 Rate Cap, results in a reasonable initial allocation of allowances that is consistent with the goals of CAA section 110(a)(2)(D)(i)(I). While just about any allocation methodology could be described as being consistent with the goals of the CAA, not any allocation methodology can be described as reasonable. For SO2, the Option 2 allocation methodology is not reasonable. [EPA-HQ-OAR-2009-0491-3965[1].1, pp.7-8]
The Annual SO2 Rate Cap calculation that is included in Option 2 uses an assumed SO2 emission rate of 0.06 lbs/mmBtu. This SO2 emission rate is several orders of magnitude greater than the SO2 emission rate for units burning natural gas and more than an order of magnitude greater that the SO2 emission rate for units burning fuel oil. Therefore, it is puzzling why EPA would use such a high emission rate for these units and also state that its use produces reasonable allocations. The use of this extremely high emission rate produces SO2 allocations that are far in excess of the SO2 emissions combustion turbines and combined cycle units could possibly produce. If EPA is taking the approach of using a single emission rate for all sources in response to the D.C. Circuit's decision in the Clean Air Interstate Rule NOx fuel adjustment factor litigation, EPA is misapplying that decision. The decision requires EPA to use a consistent allocation methodology but it does not require EPA to use a methodology that produces the absurd allocations Option 2 produces for SO2. By choosing such a high emission rate for gas- and oil-fired units, EPA is essentially saying that these units do not need to make emission reductions under the TR. [EPA-HQ-OAR-2009-0491-3965[1].1, p.8]
While Duke Energy favors the remedy that removes combustion turbine and combined cycle units from the Transport Rule, an alternative remedy to fix the Option 2 SO2 allocation problem is to eliminate the Annual SO2 Rate Cap test and allocate SO2 allowances to all units based on the lower of a unit's Initial 2012 and 2014 historic heat input based SO2 Allocation plus reapportionment and its Annual SO2 Historical Cap (Column AA in the Option 2 underlying data tab of EPA's altallocationtablesdata.xls file. Applying this consistent methodology across all units will not run afoul of the D.C. Circuit's NOx fuel adjustment factor decision and will result in more rational SO2 allocations that will still more than cover the projected emissions from these units. [EPA-HQ-OAR-2009-0491-3965[1].1, p.9]
With regard to annual and ozone season NOx allocations, Option 2 would over allocate NOx allowances to combustion turbine and combined cycle units, although to a lesser degree than it would over allocate SO2 allowances to these units. The remedy for Option 2 for annual and ozone season NOx is the same as for SO2; eliminate the Annual NOx Rate Cap test and allocate NOx allowances to all units based on the lower of a unit's historic heat input based 2012 Initial NOx Allocation plus reapportionment, and Annual NOx Historical Cap.[EPA-HQ-OAR-2009-0491-3965[1].1, p.9]
Duke Energy recommends EPA adopt the Option 2 allocation approach for SO2 and NOx with the following adjustments. For the reasons stated above, EPA should exclude combustion turbine and combined cycle units from the SO2 portion of the Transport Rule before applying the Option 2 methodology to the remaining units. With combustion turbine and combined cycle units removed from the Transport Rule SO2 program, Duke Energy feels that Option 2 produces a more appropriate SO2 allocation to the remaining units than Option 1 with or without the combustion turbine and combined cycle units included in the program. If EPA chooses not to exclude combustion turbine and combined cycle units from the Transport Rule SO2 program, Duke Energy recommends that EPA adopt the Option 2 approach for SO2, but as discussed above, eliminate the Annual SO2 Rate Cap test and allocate SO2 allowances to all units based on the lower of a unit's heat input based 2012 and 2014 Initial SO2 Allocation plus reapportionment and its Annual SO2 Historical Cap. [EPA-HQ-OAR-2009-0491-3965[1].1, pp.9-10]
For NOx, Duke Energy recommends that EPA modify the Option 2 methodology by eliminating the Annual NOx Rate Cap test and allocate NOx allowances to all units based on the lower of a unit's historic heat input based 2012 Initial NOx Allocation plus reapportionment and its Annual NOx Historical Cap. [EPA-HQ-OAR-2009-0491-3965[1].1, p.10]
If EPA decides not to adopt these recommendations, Duke Energy recommends EPA adopt Option 2 because it results in slightly more reasonable SO2 and NOx allocations for low emitting units than Option 1. Despite its flaws, however, Option 2, because it relies on historic heat input, is a better approach that the allocation approach EPA used to develop the PTR. [EPA-HQ-OAR-2009-0491-3965[1].1, p.10]
Exxon Mobil Corporation
5. Allocation Method Option 2 - Option 2 starts with Option 1 allocations, and then modifies the allowances by applying a Capacity Factor and historical emissions to change the Option 1 allocations. We support Option 2 compared to the CATR proposal method for similar reasons to those outlined above for Option 1 but note that it disadvantages facilities that we analyzed that have lower emissions per unit of heat input. It is not our preferred option of the two in this proposal. Though Option 2 also remedies a major problem with the CATR proposal allocation method that we attributed to the use of modeling projections and assumptions about future operations and emissions, the introduction of the use of historic emissions for example units we analyzed suggest Option 2 disadvantages lower emitting units compared to Option 1. [EPA-HQ-OAR-2009-0491-3999[1].1, p.2] 
6. Option 2 improvement suggestion-We suggest that as EPA continues to improve allocation methods for this rule or Clean Air Transport Rule-2 for the new Ozone NAAQS. We request EPA develop a separate capacity factor class for Cogeneration facilities supplying steam and power to industrial clients. We believe that a specific Cogeneration facility technology type in the capacity factor analysis will result in a higher capacity factor for these units more aligned with their actual operation. [EPA-HQ-OAR-2009-0491-3999[1].1, p.2]
Comment on Option 2
We note a preference for Option 1. We support Option 2 compared to the CATR proposal method for similar reasons to those outlined above for Option 1 but note that it disadvantages facilities that we analyzed that have lower emissions per unit of heat input. Though Option 2 also remedies a major problem with the CATR proposal allocation method that we attributed to the use of modeling projections and assumptions about future operations and emissions, the introduction of the use of historic emissions we believe disadvantages lower emitting units compared to Option 1. [EPA-HQ-OAR-2009-0491-3999[1].1, p.6]
Differentiating Cogen from Combined Cycle units
We recommend EPA clearly differentiate between combined cycle and cogeneration plants with respect to capacity factor. Combined cycle units are used by utility and merchant generators to produce electricity only; all steam is condensed to make more electricity with the significant remaining heat absorbed (wasted) by cooling towers. Cogeneration units produce large volumes of electricity and steam continuously because the host plant needs both 24 hours every day. The only downtime is for maintenance, so a reasonable capacity factor would be 95% both annually and for the ozone season. Cogen units occasionally have a year when a generator is undergoing a major overhaul, so in that year the capacity factor will be less than 95%. [EPA-HQ-OAR-2009-0491-3999[1].1, p.7]
Comment
We suggest EPA provide an option for Cogen units to provide historic use data in a request to have a higher than default (0.70) capacity factor to address this issue. [EPA-HQ-OAR-2009-0491-3999[1].1, p.7]
Option 2 is an emissions adjusted methodology that uses the same initial allocation pattern as Option 1 but then adds a constraint based upon a unit's 'reasonably foreseeable' maximum emissions under proposed CATR trading programs. Once a unit's initial Option 1 allowance has been determined, then EPA has to determine the maximum sulfur dioxide (SO2) and nitrogen oxide (NOx) annual emission from the 2003-2009 period and the maximum annual ozone season emissions for NOx from the ozone season of that same time period. If a unit's allocation under Option 1 exceeds the maximum annual SO2 or NOx rate, or the maximum ozone season rate, then an adjustment would be made downwards to the higher of the maximum annual emissions rate in this period or to an adjusted rate. This adjustment rate would assume an emission rate of 0.06 lbs/mmBtu for SO2 and for NOx . Further, the adjustment would include a '.reasonable upper bound capacity factor.' Simply stated, this Option 2 allocation methodology is overly burdensome and is based on inadequate capacity factors. [EPA-HQ-OAR-2009-0491-4028, p.4]
Comment 4: If EPA does decide to implement Option 2, it should revise the capacity factor (utilization factor) for combined cycle units that is used as an adjustment factor under the calculations for this option. For combined cycle cogeneration units Option 2 proposes to use only a 70% capacity factor for annual and 73% for ozone season calculations . Although EPA stated that this value was based upon data reported to EPA by source owners, EM questions such assertion. [EPA-HQ-OAR-2009-0491-4028, p.4]
It is difficult to determine whether EPA is equating the terms utilization factor and capacity factor. For a reasonable upper-bound estimate, EPA should be looking at a reasonable utilization factor - in other words, on-stream time. It appears that this is what EPA is trying to determine as the Preamble discussion in the 2011 NODA states: 'These upper-bounds would be calculated as the utilization values at the 95th percentile in each technology class.' (Emphasis added.) [EPA-HQ-OAR-2009-0491-4028, p.4]
The cogeneration units owned and/or operated by or on behalf of ExxonMobil, produce large volumes of electricity and steam continuously because the host plant (EM's refinery and chemical manufacturing -units) needs both 24 hours every day. These units occasionally have a year when a generator is undergoing a major overhaul; however, this generally does not happen on an annual basis. [EPA-HQ-OAR-2009-0491-4028, p.4]
Two of the Louisiana Station 1 generating units are combined cycle units. The utilization rates for both of these for the past 6 years are shown below: [EPA-HQ-OAR-2009-0491-4028, p.4]
[Table can be found on page 5 of comment letter 4028.]
EM requests that EPA revise the upper bound capacity factors for combined cycle units to be 98.5% annual and for the ozone season. [EPA-HQ-OAR-2009-0491-4028, p.5]
These combined cycle cogeneration units are fuel efficient - and therefore produce less emissions - than most other RGUs . The gas turbine generator makes electricity directly, then supplemental fuel is added to its very hot exhaust to make even more high pressure steam. The attached Heat Recovery Steam Generator / boiler may have a second, lower pressure steam generating section, and certainly will have a boiler feed water preheat section, both of which capture even more of the heat versus letting it go out the stack. In addition, the high pressure steam is used to run big turbines in place of motors or to spin a steam turbine generator to make more electricity and lower pressure steam. The lower pressure steam then goes to the host plant where it is used for multiple purposes, and often exhausts as low pressure steam / heat that is used elsewhere. In short, little if any energy is wasted. These units are distinguishable from utility combined cycle units which use steam only to produce electricity and waste much of the steam. [EPA-HQ-OAR-2009-0491-4028, p.5]
National Mining Association (NMA)
NMA appreciates that Option 2 is designed to limit the windfall. But as discussed below, even under Option 2, natural gas units nevertheless receive an extremely large windfall from coal-fired units for reasons that are not based on the underlying statute. [EPA-HQ-OAR-2009-0491-4013[1].1, p.1]
Nevertheless, while reserving the right to challenge whatever rule EPA adopts, if EPA is determined to adopt a heat-input methodology, NMA urges EPA to adopt Option 2. [EPA-HQ-OAR-2009-0491-4013[1].1, p.2]
C. Under Option 2, Coal-Fired Generation Bears the Full Brunt of Any Reductions in the State Budgets.
Because the public at this point does not know what the state budgets will be, it is at least possible  -  and seems likely  -  that some or many of the state budgets will be lower than those that were published with the proposed rule. If EPA uses the Option 2 method, all or substantially all of the state budget reduction will come from coal units. Natural gas unit allocations are essentially capped at the "reasonable foreseeable maximum emissions level." 3 Thus, they would be immune from reductions in the state budget to a certain point. Coal units on the other hand  -  particularly uncontrolled coal units  -  would bear the full brunt of the reduction because those allowances representing the reduction between the proposed state budget and the actual final state budget would not be available in the reapportioning step of the Option 2 method. Thus, coal alone bears the full brunt of any reductions in state budgets from proposed rule to final rule. [EPA-HQ-OAR-2009-0491-4013[1].1, p.7]
As shown above, even under Option 2  -  EPA's attempt to mitigate the windfall  -  many units are severely over-allocated allowances. [EPA-HQ-OAR-2009-0491-4013[1].1, p.7]
There are numerous other similar examples. An allocation method that results in over-allocations of this magnitude is frankly absurd. [EPA-HQ-OAR-2009-0491-4013[1].1, p.7]
In determining a given unit's "reasonable foreseeable maximum emissions level" EPA calculates, among other things, a "maximum historical baseline emissions" value for each covered unit under the rule. The maximum historical baseline emissions value is simply the single highest annual (or ozone season, depending on the program) reported emissions for a seven-year period from 2003 to 2009 for each unit. Put simply, the maximum historical baseline emissions value represents each unit's seven-year record high emissions. EPA recorded these record-high emissions values for each unit in its NODA-3 Database. [EPA-HQ-OAR-2009-0491-4013[1].2, p.10]

3 There are significant flaws in EPA's method for determining a unit's "reasonable foreseeable maximum emission level." To note just one flaw, EPA uses an emission rate specific to coal to calculate reasonable foreseeable maximum emissions for all units  -  including gas units, which in reality have emission rates for SO2 that are orders of magnitude lower than emission rates for coal units. [EPA-HQ-OAR-2009-0491-4013[1].1, p.7]
 
National Rural Electric Cooperative Association (NRECA)
NODA III option 2 attempts to somewhat correct the fallacies in option 1, but the end result is likewise unreasonably gas bias.  Option 2 attempts to avoid an unconscionable over allocation of allowances to gas units by incorporating a "reasonably foreseeable maximum emissions level reflecting a reasonable upper-bound capacity utilization factor and well controlled emission rate that all units (regardless of the type of fuel they combust) can meet for the pollutant." The fundamental problem with option 2 is the incorporation of a one-size-fits-all approach for the "well controlled emission rate" factor used to determine the "reasonably foreseeable maximum emissions level."  Since gas has inherently lower sulfur and nitrogen content than coal, as previously mentioned, this one-size approach, as applied in the option 2 allocation methodology, functions poorly in so far as more reasonably allocating allowances.   NRECA is under the impression that option 2 was constructed to be fair and equitable, while meeting the North Carolina requirements. NRECA believes EPA must recognize the obvious flaws in option 2.  [EPA-HQ-OAR-2009-0491-3943[1].2, pp.5-6]
The proposed NODA III option 2 "well controlled emission rate" of .06 lbs/mmbtu for both NOx and SO2 is a significant component in determining EPA's proposed "reasonably foreseeable maximum emissions level.  Use of this emissions standard as EPA admits is a one-size-fits-all emissions rate metric.  An analysis of the data, as follows, show that this "well controlled emission" standard functions poorly to effectively limit allowances to combined cycle and turbine units to a "reasonable initial distribution" as EPA maintains option 2 achieves in the NODA III. [EPA-HQ-OAR-2009-0491-3943[1].2, p.7]
Lastly, EPA maintains that "well controlled emissions rate" is one that "all units (regardless of the type fuel they combust) can meet."  Again, an analysis of the EPA's database in the docket of this rulemaking as follows show that "well controlled emissions rates" have little applicability to coal-fueled units within the CATR region: [EPA-HQ-OAR-2009-0491-3943[1].2, pp.7-8]
Thus, the EPA proposed one-size NOx and SO2 "well controlled emissions" standard as applied to coal-fueled units is a standard that less that .8% of the coal-fueled units in the CATR region can meet.   EPA has presented no information or analysis in connection with this rulemaking that show that any of the remaining 1050 units could meet the  proposed "well controlled emission rate" standard and if so, when.  Additionally as the attached summary of EPA data contained the CATR rulemaking docket shows, no coal unit currently meeting the "well controlled standard for SO2" is burning other than low sulfur coal.  [EPA-HQ-OAR-2009-0491-3943[1].2, p.8]   
In summary, EPA's choice of a one-size-fits-all "well controlled emissions rate" standard does not function to meet EPA's stated objective in proposing NODA III option 2, which is to institute an approach to result in "reasonable initial distribution" of allowances consistent with CAA Section 110. [EPA-HQ-OAR-2009-0491-3943[1].2, p.8]
EPA's proposed "well controlled emission rates" for coal units under option 2, in some cases, is better than what a BACT analysis would conclude. On the other hand, the proposed "well controlled emission rate" is one that every combined cycle unit in the CATR can achieve. In summary, as shown in these comments, information from EPA's own database as part of the CATR rulemaking docket demonstrates the one-size-fits-all approach does not produce sensible allowance allocations.  [EPA-HQ-OAR-2009-0491-3943[1].2, p.9]
Nelson Industrial Steam Company (NISCO)
Of the two alternative allocation methodologies proposed in the 2011 NODA, NISCO supports the use of the second methodology, referred to as the Emissions-Rate-Informed Historic Heat Input Approach or Option 2, over the first methodology, referred to as the Historic Heat Input Approach or Option 1. NISCO believes that Option 2 is a more equitable method that is based on more realistic factors that will prevent some sources from receiving unwarranted windfall allocations. [EPA-HQ-OAR-2009-0491-4026, p.4]
If EPA decides to implement Option 2 proposed in this NODA, NISCO believes that the capacity factor component of the methodology utilized by EPA for the NISCO units is too low. EPA used a capacity factor of 87% annual, 89% ozone season. for the two NISCO units. The NISCO units have higher capacity factors because they exist solely to support three industrial facilities that are dependent upon NISCO for their steam and electrical needs. Actual data reflects that the highest annual capacity factor for NISCO in the 2003-2009 period was 92%. The highest ozone season capacity factor for NISCO during that time period was 93%. NISCO requests that EPA revise its capacity factor values to more accurately reflect the actual operations of these units. [EPA-HQ-OAR-2009-0491-4026, p.6]
Response: 
EPA is finalizing a method of emissions allowance allocation to individual units under the FIP base on based on that unit's share of the state's historic heat-input, but ensuring that no unit's allocations exceed that unit's historic emissions.  EPA decided to use the allocation methodology originally presented as heat input "option 2" in the January 7, 2011 NODA, modified in response to public comments.  EPA decided to use heat input option 2 but without the application of the "reasonable upper-bound capacity utilization factor and a well-controlled emission rate" factors. See final rule preamble section VII.D for further of discussion EPA's rationale for this approach and response to comments in favor of and in opposition to this approach.
Organization: Southern Company
Clean Energy Group
State of Ohio Environmental Protection Agency (Ohio EPA)
Mississippi Department of Environmental Quality
PPG Industries, Inc.
City of Tallahasse
Lafayette Utilities System
Santee Cooper
Nebraska Public Power District
Connecticut Department of Environmental Protection
Southern IL Power Cooperative
Buckeye Power, Inc.
Exelon
First Energy
Virginia Independent Power Producers
Gainesville Regional Utilities (GRU)
Tennessee Valley Authority (TVA)
Florida Municipal Power Agency, Gainesville Regional Utilities, JEA, Orlando Utilities Commission, and City of Tallahassee
Sunbury Generation LP
Otter Tail Power Company
Oglethorpe Power
Great River Energy
Gulf Coast Lignite Coalition
NextEra Energy, Inc.
Associated Electric Cooperative, Inc. (AECI)
Entergy Services, Inc.
Tampa Electric Company
City of Dover, Delaware
Empire District Electric Company (Empire District)
City of Springfield, Illinois, Office of Public Utilities
DTE Energy
PSEG Services Corporation
Birchwood Power Partners, L.P.
Massachusetts Department of Environmental Protection
Texas Commission on Environmental Quality
Wolverine Power Supply Cooperative
Louisiana Chemical Association (LCA)
San Miguel Electric Cooperative, Inc.
America's Natural Gas Alliance
North Carolina Electric Membership Corporation
Horsehead Corporation
PowerSouth Energy Cooperative
Northshore Mining Company
Cogen Technologies Linden Venture, LP
Old Dominion Electric Cooperative
NRG Energy
Independence Power & Light (IPL)
Dayton Power and Light Company (DP&L)
American Petroleum Institute (API)
Northern Indiana Public Service Company (NIPSCO)
Seminole Electric Cooperative Inc.
GenOn Energy, Inc.
Consumers Energy
National Grid
PPL Corporation
Tenaska, Inc.
Comment: 
America's Natural Gas Alliance
Both the originally proposed emission-based methodology and the Option II methodology could result in allocations that are reduced, in effect penalizing those companies that have taken or that are scheduled to implement projects to reduce emissions of the regulated pollutants, whether by fuel switching, installation of controls, or otherwise. ANGA submits that such 'penalties' run counter to the broader goals of the CAA, as well as the specific goals regarding transport of air pollutants to downwind areas. [EPA-HQ-OAR-2009-0491-3939[1].1, p.3] [[This comment can also be found in Section XX.]]
American Petroleum Institute (API)
B. API does not support this option, although, notes Option 2 is still better than the base CATR proposal of August 20, 2010. [EPA-HQ-OAR-2009-0491-3982[1].1, p.2]
Option 2 "Emissions Informed" or "Emissions Adjusted" Heat Input Methodology - starts with Option 1 allocations and adds a limit on allocations based on a unit's reasonably foreseeable maximum emissions under the proposed Transport Rule trading programs. API does not support this option, although notes Option 2 is still better than the base CATR as outlined in the August 2, 2010 proposal. [EPA-HQ-OAR-2009-0491-3982[1].1, p.3]
For those units with heat input-based allocations that would exceed historic emissions, this option would limit allocations so that the units would not be given allowances in excess of their reasonably foreseeable maximum emissions. [EPA-HQ-OAR-2009-0491-3982[1].1, p.3]
EPA's attempt to use 'reasonable foreseeable maximum emissions' is admirable but deficient in the proposed Option 2. Allocation to low-emitting units by using a general calculation based on historical emissions would have to be improved by working with owner/operators to better estimate 'reasonably foreseeable maximum emissions' which are dependent on many factors beyond historical emissions. Historical emissions for many units in the time period of interest are NOT reflective of 'reasonably foreseeable maximum emissions'. Note that this is a reason to support allowing States to develop allocation methods which can better address this principle. [EPA-HQ-OAR-2009-0491-3982[1].1, pp.3-4]
Though Option 2 remedies a major problem with the CATR proposal allocation method that we attributed to the use of modeling projections and assumptions about future operations and emissions, the introduction of the use of historic emissions we believe disadvantages lower emitting units. [EPA-HQ-OAR-2009-0491-3982[1].1, p.4]
API does not support Option 2, although we note Option 2 is still better than the base CATR proposal of August 20, 2010. [EPA-HQ-OAR-2009-0491-3982[1].1, p.5]
Associated Electric Cooperative, Inc. (AECI)
NODA III option 2 attempts to somewhat correct the shortcomings of option 1, but the end result is likewise biased too much toward gas.  Option 2 attempts to avoid the over allocation of allowances to gas units by incorporating a "reasonably foreseeable maximum emissions level reflecting a reasonable upper-bound capacity utilization factor and well controlled emission rate that all units (regardless of the type of fuel they combust) can meet for the pollutant."  The fundamental problem with option 2 is the incorporation of a one size fits all for the "well controlled emission rate" factor used to determine the "reasonably foreseeable maximum emissions level."  Since gas has inherently lower sulfur and nitrogen content than coal, this one size approach as applied in the option 2 allocation methodology functions poorly in so far as more reasonably allocating allowances. [EPA-HQ-OAR-2009-0491-3989[1].1, p.4]
Further, EPA's choice of a one size fits all "well controlled emissions rate" standard does not function to meet EPA's stated objective in proposing NODA III option 2, which is to institute an approach to result in "reasonable initial distribution" of allowances consistent with CAA Section 110. [EPA-HQ-OAR-2009-0491-3989[1].1, p.4]
Birchwood Power Partners, L.P.
Birchwood Power can support the goal of Option 2 - of 'limit[ing] historic-heat-input-based allocations' to the 'reasonably foreseeable maximum emissions', which is calculated by taking the higher of 'maximum historic baseline emissions' or a 'well-controlled-rate maximum'. 76 Fed. Reg. at 1115. A heat input-based approach would generally favor cleaner units, which Birchwood Power agrees is consistent with goals of CAA Section 110(a)(2)(D)(i)(1). See 76 Fed. Reg. at 1114.  By limiting cleaner units' allocation to their reasonably foreseeable maximum emissions, EPA would make more allowances available to those units that may face greater burdens under a heat input-based approach. Birchwood Power believes this is fair and would alleviate the challenges that higher emitting units will face under such an approach. [EPA-HQ-OAR-2009-0491-3940[1].1, p.3]
Moreover, the Option 2 assumptions may fail to account for the specific contractual obligations of long-term contract generators, like Birchwood Power, who must operate whenever dispatched by the power purchaser without the ability to pass along the costs of the NOx and S02 allowances to the off taker under a long term contract. [EPA-HQ-OAR-2009-0491-3940[1].1, p.3]
Buckeye Power, Inc.
While Option 2 is preferable to EPA's initially proposed historic emissions-based allocation, it is flawed in several important respects. [EPA-HQ-OAR-2009-0491-3900[1].1, p.4]
First, the calculation of the 'constraint,' or limit, on a unit's allocation based on its 'reasonably foreseeable maximum emissions' is far less clear and easy to follow than Option 1, and it employs certain factors and uniform inputs that are unreasonable and inappropriate for many units, such as the Buckeye's. For instance, one component of the allocation's constraint is the calculation of a unit's 'well controlled rate maximum.' EPA uses a 'well controlled emissions rate' of 0.06 lbs/mmbtu for S02 and NOx, representing, according to EPA, the 'lowest annual emission rates assumed achievable when state-of-the-art pollution control technologies are installed at coal units in the IPM modeling.' However, application of EPA's 'well controlled emission rate' over-allocates allowances to natural gas-fired units and under-allocates allowances to coal-fired units. For example, Buckeye, which indeed employs state-of-the-art emissions controls, would be required to operate its coal-fired units at 99% control efficiency in order to meet its unit limits under Option 2. That is unfair, unreasonable, and, bottom line, infeasible. This is not a challenge unique to Buckeye. Of the more than 1,050 coal units identified in EPA's CEMS database for the CATR states that will be required to control S02 and NOx emissions, it appears that only 8 meet the 'well controlled emissions rate' for both S02 and NOx. Just 45 coal units meet the NOx 'well controlled emissions rate,' and only 27 coal units meet the S02 ''well controlled emissions rate' (and all of those units utilize low sulfur coal). Among other shortcomings, EPA's 'one rate fits all' approach clearly penalizes Midwest users of locally produced, higher sulfur coal. [EPA-HQ-OAR-2009-0491-3900[1].1, p.4]
It is also clear that EPA's ''well controlled emissions rate' over-allocates allowances to natural gas-fired units. Not one combined cycle gas unit has emissions in excess of S02 ''well controlled emissions rate' and less than 8% of combustion turbines have S02 emissions in excess of such rate. Even though the vast majority of combined cycle units are not equipped with selective catalytic reduction technology, only 20% of combined gas units have emissions in excess of the NOx 'well controlled emissions rate.' Despite constraints based on 'reasonably foreseeable maximum emissions' under Option 2, combined cycle and combustion turbine units receive significantly more allowances than their combined emissions. For example, although combined cycle and combustion turbine units emit only approximately 5.52% of the total CATR tons of Seasonal NOx, 2.98% of the total CATR tons of Particulate NOx and 0.5% of total CATR tons of Particulate S02, such units receive approximately 16% of the Seasonal NOx allowances, 10% of Particulate NOx allowances, and 5% of the Particulate S02 allowances in 2012 and 7% of such allowances in 2014. [EPA-HQ-OAR-2009-0491-3900[1].1, p.4]
Option 2 also makes and applies assumptions regarding units' utilization values - 95th percentile for each technology class, based on a series of capacity factors. Buckeye respectfully suggests that Option 2 is unnecessarily complex and, with each assumption that is utilized, its allocation drifts dangerously from the reality of electric generation economics. [EPA-HQ-OAR-2009-0491-3900[1].1, p.4]
City of Dover, Delaware
Further, the City believes that the second option of the Alternative Proposed Allocation Methodologies will result in the most equitable distribution of allowances. The City agrees with the logic of Option 2, that would act to limit instances where units receive substantially more allowances than they have ever needed in the past. By restraining allocations using the Reasonably Foreseeable Maximum Emission Methodology, and taking into account a 7 year emission profile, EPA will increase the likelihood that allowances are allocated to the appropriate units. [EPA-HQ-OAR-2009-0491-3881[1].1, p.1]
City of Springfield, Illinois, Office of Public Utilities
Given CWLP's support for the Heat Input allowance allocation methodology described in the NODA, it is clear that Option 2 is an inferior method to that described in Option 1. CWLP believes that the Emissions-Rate-Informed cap on allowance distribution would unfairly penalize utilities that consciously chose to reduce emissions before and during the previous decade with the installation of capital-intensive pollution control projects. In our case, CWLP chose to invest in control technologies for the removal of both SO2 and NOx at two aging, coal-fired, cyclone units that were not inherently low-emitting in either boiler design or fuel-type. CWLP believes that our proactive efforts would be penalized in the use of Option 2 over Option 1. [EPA-HQ-OAR-2009-0491-3885[1].1, p.2]
City of Tallahasse
While both options presented in the January NODA are preferable to EPA's original allocation proposal, the City believes that Option #2 represents a more equitable proposal, yet both options could be further refined. [EPA-HQ-OAR-2009-0491-3912[1].1, p.3]
Clean Energy Group
We are concerned that Option 2 introduces too many potential adjustment factors to be cleanly implemented without legal challenge in the short time EPA has to finalize the rule. [EPA-HQ-OAR-2009-0491-4002[1].1, p.1]
Cogen Technologies Linden Venture, LP
Linden Cogen can support the goal of Option 2, in which allocations would be limited to units' reasonably foreseeable maximum emissions level, since this would make more allowances available for higher emitting units that will face greater burdens covering their emissions under a heat input-based approach. [EPA-HQ-OAR-2009-0491-3938[1].1, p.3]
As between Option 1 and Option 2, Linden Cogen supports the goal of Option 2 - of 'limit[ing] historic-heat-input-based allocations' to the 'reasonably foreseeable maximum emissions', which is calculated by taking the higher of 'maximum historic baseline emissions' or a 'well-controlled- rate maximum'. 76 Fed. Reg. at 1115. A heat input-based approach would generally favor cleaner units, which Linden Cogen agrees is consistent with goals of CAA Section 1I0(a)(2)(D)(i)(l). See 76 Fed. Reg. at 1114. By limiting cleaner units' allocation to their reasonably foreseeable maximum emissions, EPA would make more allowances available to those units which will bear a greater burden under a heat input-based approach. Linden Cogen believes this is fair and would help alleviate the challenges that higher emitting units will face under such an approach.[EPA-HQ-OAR-2009-0491-3938[1].1, p.6]
While Linden Cogen believes the capacity factors established for combined cycle facilities - 0.70 and 0.73 for annual and ozone-season heat inputs, respectively under Option 2 - are reasonably representative of its operations, use of such capacity factors could fail to account for specific contractual requirements, particularly for cogeneration facilities, which must supply steam on a continuous basis for ongoing industrial operations. [EPA-HQ-OAR-2009-0491-3938[1].1, p.6]
Connecticut Department of Environmental Protection
CTDEP does not agree that Option 2 of the alternative heat input allocation methodologies is clear and easy to understand. Option 2 is cumbersome and does not necessarily result in significant differences in allocations compared with Option 1, at least in Connecticut. [EPA-HQ-OAR-2009-0491-3884[1]., p.1]
Consumers Energy
When comparing the allocations contained in the Proposed Transport Rule to the Option 1 and Option 2 allocations outlined in NODA 3, the preference of Consumers Energy would be Option 2. As always, that preference is subject to the details for the allocation scheme contained in the final Transport Rule. A key concern lies with how frequently EPA will change the size of the total allowance pool, with the ensuing reallocation of available allowances. [EPA-HQ-OAR-2009-0491-4008[1].1, p.4]
Dayton Power and Light Company (DP&L)
D. Alternative Allocation Methodologies - Option 2 - Emissions-Rate-Informed Historic Heat Input Approach
This methodology, like the first, places historic heat input at the center of the allocation methodology. DP&L supports that aspect of this method. DP&L further notes that this method contains within it a mechanism to make the kind of adjustments DP&L recommended above to distribute more SO2 allowances to units that combust fuels that contain sulfur and fewer allowances to units that combust fuels containing no sulfur. [EPA-HQ-OAR-2009-0491-3973[1].1, p.3]
However, DP&L is concerned that there is a degree of arbitrariness, future uncertainty, and complexity inherent in establishing allocations based on a so-called 'rate-informed' standard. On a long-term basis, this approach could be used to ratchet down the allowances provided to the best-performing units. In other words, 'rate-informed' may someday mean 'your SCR and FGD have performed well, and now you will receive fewer allowances.' [EPA-HQ-OAR-2009-0491-3973[1].1, p.3]
The potentially arbitrary nature of the term 'rate informed' is demonstrated by the definition in the proposed regulation that ''well-controlled'' means 0.06 lbs/mmBtu of NOx and 0.06 lbs/mmBtu for SO2. As a utility that has installed state-of-the-art FGDs on its major units within the last five years, DP&L submits that these values do not appropriately define ''well-controlled' for coal units. A value of 0.10 lbs/mmBtu may be a better representation of well-controlled. Subjective definitions of this nature may suggest that this approach is not easily feasible for implementation. [EPA-HQ-OAR-2009-0491-3973[1].1, p.3]
:: A new definition of well-controlled' SO2 and NOx emitters may not be appropriate. [EPA-HQ-OAR-2009-0491-3973[1].1, p.4]
DTE Energy
Of the two historical heat-input based options proposed by EPA, Option 2, with the consideration of historic emissions to allocations, would provide a more accurate distribution of required allocations. [EPA-HQ-OAR-2009-0491-3932[1].1, p.2]
Empire District Electric Company (Empire District)
d) The formulas used in option 2 appear to exceed BACT and emulate MACT. [EPA-HQ-OAR-2009-0491-3883[1].1, p.2]
Entergy Services, Inc.
We are concerned that Option 2 introduces too many potential adjustment factors to be cleanly implemented without legal challenge in the short time EPA has to finalize the rule. [EPA-HQ-OAR-2009-0491-3986[1].1, p.2]
Exelon
For this reason, among others, Exelon prefers EPA's Option 1, because Option 2 reintroduces the possibility of error by basing the allocation, in part, on modeling (e.g., assumed capacity factors by technology class) rather than a purely historic metric. [EPA-HQ-OAR-2009-0491-3919[1].1, p.4]
First Energy
Specific to Option 2, FirstEnergy favors the allocation method based on the established "Reasonable Foreseeable Maximum." Though a unit should not be awarded allocated allowances above their annual 7-year maximum and thereby be rewarded with allowances that would arguably allow it to exceed historical emission levels. Allocating allowances above historical levels may lead to increased localized emissions that could impact the local ambient maintenance limits. Minimizing localized impacts of all sectors, not just utilities, should remain a priority throughout this rulemaking. [EPA-HQ-OAR-2009-0491-3904[1].1, p.2]
Florida Municipal Power Agency, Gainesville Regional Utilities, JEA, Orlando Utilities Commission, and City of Tallahassee
While both Options #1 and #2 are superior to EPA's original allocation proposal, we believe that Option #2 represents better public policy and can be more easily defended by EPA. [EPA-HQ-OAR-2009-0491-3907[1].1, p.1]
Option #2 attempts to address both of these issues. First by using a multi-year look back for the "maximum actual" emission test; Option #2 does not disadvantage utilities that have spent significant resources to meet CAIR requirements since emissions levels prior to adding controls are considered in the allocation process. In addition, the "well controlled unit" test mitigates in large part the over allocation issue with gas-fired units, while still allowing sufficient allocations to dual fuel capable gas-fired units which must occasionally fire oil. Nearly all Florida gas-fired combined cycle units and many gas-fired steam units are dual fuel capable. [EPA-HQ-OAR-2009-0491-3907[1].1, pp.1-2]
Overall, Option 2 is the most favorable and defensible option because it strikes a reasonable balance between providing sufficient allowances to "well controlled units" (including those units that undertook early reductions to comply with CAIR) and providing a mechanism to prevent over allocation to these units. [EPA-HQ-OAR-2009-0491-3907[1].1, p.2]
Different Allocations Options for Different Trading Programs: The short time period allowed for comment on this NODA did not let us look at this issue fully. However, we believe that Option#2, with its heat input based allocation methodology and its provisions for dealing with over allocation issues, is the best of the three current allocation options for all four trading programs. [EPA-HQ-OAR-2009-0491-3907[1].1, p.2]
Gainesville Regional Utilities (GRU)
While both Options #1 and #2 are superior to EPA's original allocation proposal, we believe that Option #2 represents better public policy and can be more easily defended by EPA. [EPA-HQ-OAR-2009-0491-3922[1].1, p.1]
Option #2 attempts to address both of these issues. By using a multi-year look back for the 'maximum actual' emission test, Option #2 does not disadvantage utilities that have spent significant resources to meet CAIR requirements since emissions levels prior to adding controls are considered in the allocation process. In the case of GRU, this was over $140 million. In addition, the 'well controlled unit' test mitigates in large part the over allocation issue with gas-fired units. White this does not fully eliminate over allocations for these units, it is mitigated in many cases in that gas-fired units are often dual fuel capable. This is the case with nearly all Florida gas-fired combined cycle units and many gas-fired steam units. [EPA-HQ-OAR-2009-0491-3922[1].1, pp.1-2]
The short time period allowed for comment on this NODA did not let us look at this issue fully. However, assuming that EPA finds that the 'well controlled unit' test in Option #2 is sufficient to deal with over allocation issues for the whole CATR region , GRU finds that Option #2 is the best of the three current allocation options for all four trading programs. [EPA-HQ-OAR-2009-0491-3922[1].1, p.2]
GenOn Energy, Inc.
The 2nd Option discussed in NODA 3 would reduce this wealth transfer somewhat, but still give gas-fired plants orders of magnitude more SO2 allowances than they would ever need. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 2]
If EPA proceed to issue a final Transport Rule without preparing a comprehensive supplemental proposal and allowing adequate time for public comment, then it should either: c. Adopt a modified version of Option 2 from NODA3 that recognizes that (1) there is a vast difference between SO2 emission rates from well-controlled coal, gas, and oil-fired units and (2) there must be a more rational approach for considering the wide range of capacity factors. In particular, the use of the 95th percentile overstates actual operations for 95 percent of all units, and drastically overstates the operations of many peaking units. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 4]
Option 2 results in the same inequities as option 1, although it does reduce, to some extent, the windfall to gas-fired plants. Option 2 in NODA 3 is based on historic heat input, just as option 1, but restricts the allocation based on a 'well-controlled emission rate of 0.06 lbs/mmBtu for SO2.' 76 Fed. Reg. 1109, 1115. While 0.06 lbs/mmBTU may be a well-controlled emission rate for a coal-fired power plant, there is no way a natural gas fired power plant would ever have such a high emission rate. EPA's own compilation of AP-42 factors states that large uncontrolled gas turbines should use a 0.0006 lb/mmBtu to estimate emissions when the sulfur content is not available. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 7]
Great River Energy
To a lesser extent, Great River Energy views the NODA Option 2 as better than EPA's original 'Preferred Option." However, like the Preferred Option, Option 2 also allocates allowances based on emissions, which  inherently rewards dirtier plants at the expense of the cleaner plants. [EPA-HQ-OAR-2009-0491-3898[1].1, pp.4-5]
Gulf Coast Lignite Coalition
Option 2 proposes allocations in a similar fashion as Option 1, but includes an upper-bound capacity utilization factor and 'well-controlled' emission rate for all units, irrespective of fuel type. Again, due to coal carrying a higher sulfur and nitrogen content, coal-fired units will have a more difficult time meeting the 'well-controlled' emission rate than other fuel types. Meanwhile sources firing lower sulfur fuels will not only meet the emission rate, but also accumulate allocations more readily. The unique characteristics of fuel types and regional needs must be given adequate consideration, particularly with regard to coal and subcategories of coal, such as lignite. [EPA-HQ-OAR-2009-0491-3963[1].1, p.2]
To further highlight this issue, Option 2 proposes a 'well-controlled' emission rate of 0.06 lb/mmBtu for all units, irrespective of fuel type. According to the EPA's Continuous Emissions Monitor (CEMs) database, less than 1% of 1050 coal units could meet the 'well-controlled' emissions rate for nitrogen oxide (NOx) and sulfur dioxide (S02). Note that the 1 % of these coal units that meet the emissions rate, include those that bum low-sulfur fuels, which is not representative of the coal type utilized in all Transport Rule states. Natural gas units fared better with the 'well-controlled' emission rate, and ultimately are put in a position to earn allowances. [EPA-HQ-OAR-2009-0491-3963[1].1, p.3]
Horsehead Corporation
To the extent that EPA chooses to allocate allowances under the final Transport Rule based on one of the two allocation approaches described in the Second NODA, rather than the allocation method set forth in the Proposed Transport Rule, then EPA should rely on Option 2 under the Second NODA. As between the two options, Option 2 takes into account historic actual emissions, as well as reasonably foreseeable maximum emissions based on a well-controlled- rate emission factor for the relevant pollutant. Although neither allocation method described in the Second NODA is fully consistent with EPA's stated objectives for the Transport Rule, Horsehead believes reliance on Option 2 would be more consistent with the objective of developing a final Transport Rule that ensures a reliability power supply, as compared to Option 1, under which allowance allocations are based solely on historic heat input. [EPA-HQ-OAR-2009-0491-4003[1].1, p.2]
Independence Power & Light (IPL)
Indeed, Option 2 appears to undercut such a notion by reducing the burden on higher-emission-rate units through a reapportionment of the lower-emission-rate units' allowances. See 76 FR at 1116, Table II (giving example). [EPA-HQ-OAR-2009-0491-3949[1].1, p.4]
For example, Option 2 takes into account different capacity factors that are largely fuel-oriented, 76 FR at 1115, Table 1 & n. 4, and makes other adjustments that are not emissions-control-neutral. Id., steps 5 and 6. Making adjustments to offset 'neutrality' leaves an open question of whether a better approach would consider fuel differences and emission-control differences as integral parts the estimation process, as is done in the Original Methodology. [EPA-HQ-OAR-2009-0491-3949[1].1, p.5]
Lafayette Utilities System
Of the two alternative allocation methodologies proposed in the 2011 NODA, LUS supports the use of the second methodology, referred to as the Emissions-Rate-Informed Historic Heat Input Approach or Option 2, over the first methodology, referred to as the Historic Heat Input Approach or Option 1, due to the fact that Option 2 is a more equitable method that is based on more realistic factors, such as being based on a unit's actual emissions. [EPA-HQ-OAR-2009-0491-3914[1].1, p.3]
Option 2 is an emissions adjusted methodology, however, that uses the same initial allocation pattern as Option 1 but, if a unit's maximum annual emissions for a pollutant over the prior seven years are less than the Option 1 allocation, then adds a constraint based upon a unit's 'reasonably foreseeable' maximum emissions under proposed CATR trading programs. Option 2 is superior to Option 1 in that the allowances issued to each unit are constrained by the actual emissions from that unit. . Simply stated, no unit will be allocated more allowances than they would actually use. [EPA-HQ-OAR-2009-0491-3914[1].1,p.3]
The occurrence of over-allocations-and the substantial windfalls to those particular units that have more allowances than they can realistically use-is much less likely under Option 2 than under Option 1. The allowances granted under Option 2 are more realistic as to the actual operations of the units subject to CATR. [EPA-HQ-OAR-2009-0491-3914[1].1, p.4]
Louisiana Chemical Association (LCA)
3 . If EPA selects Option 2 - the Emissions-Rate-Informed Historic Heat Input method, LCA agrees that the look back period should be at least seven years (2003-2009); however, LCA believes a ten year period would provide more flexibility and would be more representative of actual capabilities of the units. This is particularly the case with respect to facilities that have more than one EGU where utilization of one unit may have been artificially low due to utilization of other available units. [EPA-HQ-OAR-2009-0491-4027, p. 5]
4. If EPA selects Option 2, LCA requests that EPA either revise the 'reasonable upper bound capacity factor' for combined cycle waits or create a separate category for combined cycle units that serve dedicated industrial manufacturing and refining facilities. EPA has indicated that these upperbound capacity factors for combined cycle units are 70% annually and 73% for ozone season. However, actual data for all of the LCA members with combined cycle units reveal capacity factors that are much higher, in the 95 to 98% range. It is difficult to determine whether EPA is equating the terms utilization factor and capacity factor. For a reasonable-upperbound estimate, EPA should be looking at a reasonable utilization factor - in other words, on-stream time. It appears that this is what EPA is trying to determine as the Preamble discussion in the 2011 NODA states : 'These upper-bounds would be calculated as the utilization values at the 95th percentile in each technology class.'  [EPA-HQ-OAR-2009-0491-4027, pp. 5-6]
The cogeneration units owned and/or operated by ox on behalf of Dow, ExxonMobil, Occidental, PPG produce large volumes of electricity and steam continuously because the host plant needs both 24 hours every day. The only downtime is for maintenance, so a reasonable utilization/capacity factor would be 95% both annually and for the ozone season . These units occasionally have a year when a generator is undergoing a major overhaul, so that year will be less than 95% capacity factor, however, this generally does not happen on an annual basis. [EPA-HQ-OAR-2009-0491-4027, p. 6]
In addition, cogeneration units are fuel efficient - and therefore produce less emissions - than most other EGUs. The gas turbine generator makes electricity directly, then supplemental fuel is added to its very hot exhaust to make even more high pressure steam. The attached Heat Recovery Steam Generator / boiler may have a second, lower pressure steam generating section, and certainly will have a boiler feed water preheat section, both of which capture even more of the heat versus letting it go out the stack. In addition, the high pressure steam is used to run big turbines in place of motors or to spin a steam turbine generator to make more electricity and lower pressure steam. The lower pressure steam then goes to the host plant where it is used for multiple purposes, and often  exhausts as low pressure steam / heat that is used elsewhere. In short, these units are designed to 'get the squeal out of the pig.' [EPA-HQ-OAR-2009-0491-4027, p. 6]
LCA believes a reasonable upper-bound utilization/capacity factor for these units is 98% to 99% both annually and during ozone season as several of the LCA members have had units with on-stream utilization time in this range within the past several years. If EPA is trying instead to determine the electrical and steam percent-of maximum-capacity factor, LCA believes that EPA does not have adequate data to do so. This is significantly more difficult and labor intensive as the ambient temperature and total steam and power demand is constantly moving. This data is not reported to EPA under CAMD and is not reflected in NEEDS 4.10. Further for combined cycle units with supplementally fired HRSGs- electrical utilization and steam utilization can be independent. [EPA-HQ-OAR-2009-0491-4027, p. 6]
Massachusetts Department of Environmental Protection
Option 2 is also based on historic heat input, but adds a formula to limit the number of allowances allocated to low-emission rate units by re-apportioning the allocation based on a 7-year baseline and a number of other complicated parameters (e.g., 'well-controlled-rate maximum' and 'reasonable foreseeable maximum emissions level'). MassDEP believes that EPA's attempt to limit the award of allowances in certain instances may be well-founded. However, because of the complexity of the proposed formula, we do not fully understand the implications of what is proposed in Option 2 and are not able to advocate for or against its adoption. [EPA-HQ-OAR-2009-0491-4017[1].1, p.3]
Mississippi Department of Environmental Quality
In allocating allowances to a unit level, Mississippi supports using a method like that described in option 2 which uses the historic heat input based approach, but limits the allowances given to a unit based on a unit's reasonably foreseeable maximum emissions. However we would recommend using the unit's maximum allowable permitted emissions to limit the allowances to a unit as well. While EPA may not be directly privy to this information it can be relatively quickly and easily obtained from the state or local permitting authorities by request. [EPA-HQ-OAR-2009-0491-3917[1].1, p.1]
National Grid
Option 2 introduces too many adjustment factors that may cause objections that would result in a delay of the implementation of the rule. [EPA-HQ-OAR-2009-0491-3921[1].1, p.1]
Nebraska Public Power District
However, if Nebraska remains in the TR, NPPD supports Option 2 as the preferred method for allowance allocations. Option 2 is preferred since it takes into account a unit's reasonably foreseeable maximum emissions. This reduces the allowances allocated to lower emitting units and redistributes those allowances to higher emitting units. [EPA-HQ-OAR-2009-0491-3886[1].1, p.1]
NextEra Energy, Inc.
We are concerned that Option 2 introduces too many potential adjustment factors to be cleanly implemented without legal challenge in the short time EPA has to finalize the rule. [EPA-HQ-OAR-2009-0491-3962[1].1, p.2]
North Carolina Electric Membership Corporation
The second option results in the fairest allocations to individual units. NCEMC supports the logic of the second alternative, which would use the Reasonably Foreseeable Maximum Emissions to limit instances where units would receive substantially more allocations than ever needed historically. [EPA-HQ-OAR-2009-0491-4001[1].2, p.1]
Northern Indiana Public Service Company (NIPSCO)
Without retreating from its view that the allocation methodology should be left to states, NIPSCO prefers Option II over all of the other proposed allocation methodologies. [EPA-HQ-OAR-2009-0491-3995[1].1, p. 2]
NIPSCO has not been able to replicate EPA's methodology employed in Option II; nevertheless, the allocation identified for NIPSCO's EGUs under Option II most closely reflect NIPSCO's calculations as to the number of allowances appropriate for NIPSCO under the proposed statewide budget. [EPA-HQ-OAR-2009-0491-3995[1].1, p. 2]
Northshore Mining Company
EPA has requested comment on two competing allocation methodologies presented in NODA III.  Northshore generally prefers the Option 2 Allocation Methodology, which caps allowances to avoid over-allocation windfalls for certain units. [EPA-HQ-OAR-2009-0491-3957[1].1, p.7]
NRG Energy
Option 2 attempts to correct this imbalance, but does not go far enough. See suggested improvement 2 below. [EPA-HQ-OAR-2009-0491-3933[1].1, p.3]
This imbalance is apparent when comparing the allocation distribution of Option 1 to EPA's proposed projected method, or even to the more accommodating Option 2. [EPA-HQ-OAR-2009-0491-3933[1].1, p.3] [[This comment can also be found in Section XX.A.1.a.]]
 In contrast, using historical emissions or adjustments as recommended for Option 2 (see comment 4, improvements below) are ways to return fairness and impartiality to the allocation and in turn, continue to support Americans' access to affordable and reliable power while transitioning to cleaner technologies and fuels. [EPA-HQ-OAR-2009-0491-3933[1].1, p.4]  
 Improvement 3  -  In proposed Option 2, the calculation uses the top 95th percentile for calculating capacity factors to determine potential emissions. Based on our review of generation data, these factors appear high. We recommend EPA consider using ISO regional or CATR average capacity factors for this calculation.   [EPA-HQ-OAR-2009-0491-3933[1].1, p.7]
 EPA Question  -  Are the alternative methodologies clear and easy to understand?  Option 2 and the original methodologies proposed in July 2010, while necessarily complex, are understandable. [EPA-HQ-OAR-2009-0491-3933[1].1, p.8] 
 EPA Question  -  Do these alternatives yield a reasonable distribution of allowances?  By contrast, the July projected emissions method and Option 2 (with recommended improvements) better reflect emissions, and a plant's compliance costs are buffered in a fair and comparable manner. This protects both investors and consumers, conserves capital needed for massive investments in emission control equipment and clean energy projects, and provides a stronger incentive to make those investments. This maintains the proper balance in protecting health and the environment while promoting economic growth.   [EPA-HQ-OAR-2009-0491-3933[1].1, p.9] [[This comment can also be found in Section XX.A.]]
Oglethorpe Power
This option retains the Option 1 approach, but adds a constraint for those units whose initial Option 1 allocations would exceed the highest annual emissions in a 7-year historic emissions baseline - 2003 through 2009. For such units, this option would establish, based again on historic data, a 'reasonaably foreseeable maximum emissions' level, using an upper-bound capacity utilization factor and a well-controlled emission rate that EPA believes all units (regardless of the type of fuel they combust) can meet for the pollutant. EPA's stated goal is that for those units whose heat-input-based allocations would exceed historic emissions, this option would limit the historic-heat-input-based allocations to a maximum emissions level, preventing units from being allocated allowances in excess of their reasonably foreseeable maximum emissions. [EPA-HQ-OAR-2009-0491-3896[1].1, p.4]
Old Dominion Electric Cooperative
NOOA III option 2 attempts to somewhat correct the inadequacies in option 1 but the end result is likewise unreasonably gas bias. Option 2 attempts to avoid an unconscionable over allocation of allowances to gas units by incorporating a 'reasonably foreseeable maximum emissions level reflecting a reasonable upper-bound capacity utilization factor and well controlled emission rate that all units (regardless of the type of fuel they combust) can meet for the pollutant." The fundamental problem with option 2 is the incorporation of a 'one size fits all' approach for the 'well controlled emission rate' factor used to determine the 'reasonably foreseeable maximum emissions level.' Since gas has inherently lower sulfur and nitrogen content than coal, as previously mentioned, this approach as applied in the option 2 allocation methodology continues to function poorly for reasonably allocating allowances. OOEC is under the impression that option 2 was constructed to be fair and equitable, while meeting the North Carolina requirements. [EPA-HQ-OAR-2009-0491-4004[1].1, p.3]
In addition, use of 'well controlled emission rate' of 0.06 Ibs/MMBtu for both NOx and SO2 as EPA admits is a 'one size fits all' emissions rate metric. NRECA's analysis of the data demonstrates that this 'well controlled emission' standard functions poorly to effectively limit allowances to combined cycle and turbine units to a 'reasonable initial distribution as EPA maintains in the NODA III and has little applicability to coal-fired units within the CATR region. [EPA-HQ-OAR-2009-0491-4004[1].1, p.4]
NRECA's summary also outlines that less that 0.8% of the coal fueled units in the CATR region can meet the 'well controlled emission standard' in option 2. Also, EPA has presented no information or analysis in connection with this rulemaking that shows that any of the remaining 1050 units could meet the well controlled standard and if so when. Additionally, no coal unit currently meeting the 'well controlled standard for S02' is burning other than low sulfur coal. [EPA-HQ-OAR-2009-0491-4004[1].1, p.4]
In summary, EPA's choice of a one size fits all 'well controlled emissions rate' standard does not function to meet EPA's stated objective in proposing the NODA III option 2, which is to institute an approach to result in 'reasonable initial distribution' of allowances consistent with CAA Section 110. [EPA-HQ-OAR-2009-0491-4004[1].1, p.4]
Otter Tail Power Company
Even focusing on Option 2, which in theory limits allowance allocations to a maximum emissions level, Table 1 below shows that existing natural gas-fired units in Minnesota would receive a windfall of SO2 allowances that far exceeds their actual historical maximum emissions. [EPA-HQ-OAR-2009-0491-3888[1].1, pp.1-2] [[See Docket Number EPA-HQ-OAR-2009-0491-3888[1].1, pp.2-3 for Table 1.]]
As shown in Table 1, under the Option 2 allocation methodology, in every case but one Minnesota combustion turbine and combined cycle units would receive significantly more SO2 allowances than their historical actual maximum emissions, and in some cases individual units would receive hundreds more allowances than needed. [EPA-HQ-OAR-2009-0491-3888[1].1, p.3]
Comment 2: If EPA finalizes a heat input-based methodology, the Option 2 methodology must be altered prior to issuing a final Transport Rule. [EPA-HQ-OAR-2009-0491-3888[1].1, p.3]
If EPA decides to finalize a heat input-based allocation methodology, Option 2 must be revised to correct the disproportionate number of SO2 allowances that natural gas-fired generating units would receive. Otter Tail suggests that this could be accomplished by simply using the maximum historical SO2 emissions as the capped allocation level. This is reasonable because EPA used a seven-year lookback period to determine the maximum historical emissions, which is an adequate period to reasonably indicate future maximum emissions. [EPA-HQ-OAR-2009-0491-3888[1].1, p.3]
EPA could also improve the Option 2 methodology by applying a different "well-controlled" SO2 emission rate to natural gas-fired generation when determining reasonably foreseeable maximum emissions. As proposed, Option 2 would use a well-controlled SO2 rate of 0.06 lbs/mmBtu for all units. For facilities that use pipeline natural gas, this factor is one hundred times too high. This is recognized by EPA in 40 CFR Part 75 Appendix D Section 2.3.1.1, which allows units that combust pipeline natural gas to use a default SO2 emission rate of 0.0006 lbs/mmBtu. [EPA-HQ-OAR-2009-0491-3888[1].1, p.4]
PowerSouth Energy Cooperative
This proposed methodology is an improvement on NODA Option 1, and the best of the three allocation methodologies described. Option 2 is a significant improvement over Option 1 since a methodology for accounting for differences in emissions sources is an essential part of any fair and equitable allocation scheme.  However, this alternative is NOT the final methodology that should be incorporated into the final rule.  The major flaw with Option 2 is that proposed "well controlled emission rates" are still too high for most gas fired units, and still result in significant over allocations of both SO2 and NOx allowances.  Option 2 can be modified and built upon to establish the final allocation methodology.  Fuel type and combustion technology must be incorporated to fairly distribute allowances to emissions sources.  [EPA-HQ-OAR-2009-0491-3956[1].1, p.7]
PPG Industries, Inc.
Option 2 is an emissions adjusted methodology that uses the same initial allocation pattern as Option 1 but then adds a constraint based upon a unit's 'reasonably foreseeable' maximum emissions under proposed CATR trading programs. [EPA-HQ-OAR-2009-0491-3911[1].1, p.2]
While PPG believes that Option 2 is superior to the IPM-based methodology due to its utilization of actual historic heat input data [EPA-HQ-OAR-2009-0491-3911[1].1, p.3]
Without waiving its position that Option 1 is superior to Option 2, if EPA decides to implement Option 2, PPG believes that the capacity factor component of the methodology utilized by EPA for combined cycle cogeneration units is artificially low. The capacity factor proposed by EPA as a reasonable upper bound capacity factor for such units is 0.70 annual and 0.73 ozone season, and EPA stated that this value was based upon data reported to EPA by source owners. PPG disputes the accuracy of this capacity factor for cogeneration units. Actual data submitted to EPA reflects that PPG's capacity factor for its cogeneration units is approximately 0.98 annually and [to be added] _ during ozone season. PPG believes that other combined-cycle cogeneration facilities within the State of Louisiana that serve industrial steam production use have similar capacity factors. PPG requests that EPA revise its capacity factor values to more accurately reflect the actual operations of these types of combined-cycle cogeneration units. [EPA-HQ-OAR-2009-0491-3911[1].1, p.3]
PPL Corporation
PPL PA Generation requests that EPA adopt Option 2 of the proposed alternatives. However either of the proposed options is preferable over the initial method proposed by EPA. [EPA-HQ-OAR-2009-0491-3935[1].1, p.3-4]
PSEG Services Corporation
We are concerned that Option 2 introduces too many potential adjustment factors to be cleanly implemented without legal challenge in the short time EPA has to finalize the rule. [EPA-HQ-OAR-2009-0491-3936[1].1, p.2]
San Miguel Electric Cooperative, Inc.
Option Two makes a feeble attempt to adjust for historical emissions but fails to allocate allowances fairly. [EPA-HQ-OAR-2009-0491-3997[1].1, p.2]
The NRECA analysis also indicated using the one-size-fits-all approach to the "well controlled emission rates" " (.06 lb/mmbtu for SO2 and NOx) is not representative of coal or gas units"
- No combined cycle (CC) gas unit emissions exceed the well-controlled SO2 rate.
- Only 20% of the CC gas units have emissions that exceed the well-controlled emissions rate for NOx and the vast majority of these units are not equipped with SCRs.
- Less than 8% of the combustion turbines have emissions that exceed the well-controlled rate for SO2 emissions. The vast majority of these units appear to use gas/diesel as a duel fuel. [EPA-HQ-OAR-2009-0491-3997[1].1, p.3]
- Of the more than 1050 coal units contained in EPA's CEMS database for the CATR states that will be required to control for both SO2 and NOx, just 8 units meet or are below the "well controlled emission rate" for both SO2 and NOX.
- 45 coal units in the CATR meet or are below the well-controlled rate for NOx.
- 27 coal units meet or are below the well-controlled rate for SO2, and all of these units utilize low sulfur coal. [EPA-HQ-OAR-2009-0491-3997[1].1, p.4]
Santee Cooper
The proposed Option 2 relies upon a complex formula to 'cap' allocations for individual EGUs at 'reasonably foreseeable maximum emissions,' yet EPA's proposed methodology for determining the cap on allocations relies upon assumed 'well-controlled emission rates' and capacity factors that may not accurately predict maximum emissions for individual EGUs subject to the Transport Rule. Moreover, the NODA provides no information as to how this methodology was crafted and whether it provides a representative estimate of maximum foreseeable emissions for most EGUs. Option 2 is also likely to be particularly inappropriate for predicting maximum foreseeable emissions for utilities that are experiencing rapid load growth, such as Santee Cooper. Santee Cooper believes the complex and untested nature of the maximum emissions formula in Option 2. [EPA-HQ-OAR-2009-0491-3913[1].1, pp.3-4]
Seminole Electric Cooperative Inc.
Allocations should be based on a unit's reasonably foreseeable maximum emissions. A so-called 'emissions-rate-informed' historic heat input approach would ensure no individual unit is allocated excess allowances. Such an approach would properly reflect the shared burden among electric generating units to reduce emissions in order to eliminate the state's significant contribution and interference with maintenance. [EPA-HQ-OAR-2009-0491-3992[1].1, p.2]
Southern Company
Third, if EPA uses a heat-input based allocation method, it must use an emission constraint that grounds a unit's allocations in reality  -  using real and credible emissions data. In NODA3 Option 2, EPA attempts to correct the inconceivable over-allocations that result from a straight heat-input based method (i.e., Option 1). To do so, EPA essentially caps a unit's allocation at the greater of its "maximum historical baseline emissions" (i.e., highest emissions for each compliance period from 2003 to 2009) and its "well-controlled-rate-maximum" (a calculated value). Option 2 contains hundreds and hundreds of examples of gross under- and over-allocations after applying Option 2's emission constraint. Put simply, EPA's emission constraint failed. The bulk of that failure is due to the flawed "well-controlled-rate-maximum" value. [EPA-HQ-OAR-2009-0491-3946[1].1, pp.8-9]
For a unit that reports hourly heat input, the "well-controlled-rate maximum" equals:
:: that unit's maximum hourly heat input,
:: multiplied by 0.06 lbs/mmBtu (for both SO2 and NOx allocations),
:: multiplied by 8,760 hours (or 3,672 for ozone season),
:: multiplied by set-technology-specific capacity factors. [EPA-HQ-OAR-2009-0491-3946[1].1, p.9]
This approach is fundamentally flawed. Option 2 can still lead to allocations that are 200 times greater than a unit's "maximum historical baseline emissions" (see Table 1 above and EPA's NODA3 Allocation Tables in the Docket). Also, there is no basis to use an emission rate (0.06 lbs/mmBtu for both SO2 and NOx) that is admittedly based on a well-controlled coal unit for all units. Individual units have significantly different emission rates depending on the fuel used; there is no reason for EPA to ignore such a fact when calculating an emissions value. Further, EPA's use of technology-specific capacity factors does not remedy the flaw. EPA's capacity factors are based on its effort to determine a realistic average capacity for certain technology types. Doing so might lead to a defensible prediction of maximum emissions if a proper fuel- or technology-specific emission rate were used, but given EPA's use of a coal-specific emission rate, the capacity adjustment is wholly ineffective at correcting the error. If EPA proceeds with this allocation methodology, it should throw out the flawed "well-controlled-rate-maximum" concept and allocate based on the "maximum historical baseline emissions." [EPA-HQ-OAR-2009-0491-3946[1].1, p.9]
Southern IL Power Cooperative
NODA III option 2 attempts to somewhat correct the fallacies in option 1, but the end result is still unreasonably gas biased.  Option 2 attempts to avoid an over allocation of allowances to gas units by incorporating a "reasonably foreseeable maximum emissions level reflecting a reasonable upper-bound capacity utilization factor and well-controlled emission rate that all units (regardless of the type of fuel they combust) can meet for the pollutant."    The fundamental problem with option 2 is the incorporation of a one size fits all for the "well-controlled emission rate" factor used to determine the "reasonably foreseeable maximum emissions level."  Since gas has inherently lower sulfur and nitrogen content than coal, as previously mentioned, this one size approach as applied in the option 2 allocation methodology functions poorly in reasonably allocating allowances.  [EPA-HQ-OAR-2009-0491-3901[1].1, p.3]
As a group combined cycle (CC) and turbine units receive the following windfalls of allowances in all the CATR trading programs:
-Under the ozone NOx trading program:   While emitting about 5.52 % of total CATR tons, CC and turbine units receive about 16% of the allowances, over 300% more than their current emissions.   [EPA-HQ-OAR-2009-0491-3901[1].1, p.3]
-Under the fine particulate trading program for annual NOx:  While emitting about 2.98% of the total CATR tons, CC and turbine units receive about 10% of the allowances, over 300% more that their current emissions.  
-Under the fine particulate trading for annual SO2:  While emitting about .5% of the total CATR tons, CC and turbine units receive about 5% of the allowances in 2012 and about 7% of the allowances in 2014, over 6200% of their current emissions.  [EPA-HQ-OAR-2009-0491-3901[1].1, p.4]
Thus in the aggregate combined cycle and turbines units receive far more allowances than these units can ever use.  [EPA-HQ-OAR-2009-0491-3901[1].1, p.4]
The proposed option 2 "well -controlled emission rate" of .06 lbs/mmbtu for both NOx and SO2 is a significant component in determining EPA's proposed "reasonably foreseeable" maximum emissions level.  Use of this emissions standard as EPA admits is a one size fits all emissions rate metric.  An analysis of the data, as follows, show that this "well-controlled emission" standard functions poorly to effectively limit allowances to combined cycle and turbine units to a "reasonable initial distribution as EPA maintains in the NODAIII.   [EPA-HQ-OAR-2009-0491-3901[1].1, p.4]
-No combined cycle (CC) gas unit emissions exceed the "well-controlled emissions rate" for SO2       
-Only 20% of the CC gas units have emissions that exceed the "well-controlled emissions rate" for NOx and the vast majority of these units are not equipped with SCRs.  
-Less than 8% of the combustion turbines have emissions that exceed the "well-controlled emissions rate" for SO2 emissions.  The vast majority of these units appear to use gas/oil as a duel fuel.  [EPA-HQ-OAR-2009-0491-3901[1].1, p.4]
Lastly, EPA maintains that "well-controlled emissions rate" is one that "all units (regardless of the type fuel they combust) can meet."  Again an analysis of the EPA's database in the docket of this rulemaking shows the "well-controlled emissions rates" have little applicability to coal-fueled units within the CATR region as follows:   
-Of the more than 1050 coal units contained in EPA's CEMS data base for the CATR states that will be required to control for both SO2 and NOx just 8 units meet or are below the "well-controlled emission rate" for both SO2 and NOX. 
-45 coal units in the CATR meet or are below the "well-controlled emissions rate" for NOx  [EPA-HQ-OAR-2009-0491-3901[1].1, p.4]
-27 coal units meet or are below the "well-controlled emissions rate" for SO2, and all of these units utilize low sulfur coal.  [EPA-HQ-OAR-2009-0491-3901[1].1, p.5]
Thus the EPA has proposed one size NOx and SO2 "well-controlled emissions" standard as applied to coal-fueled units is a standard that less that .8% of the coal-fueled units in the CATR region can meet.   EPA has presented no information or analysis in connection with this rulemaking that shows that any of the remaining 1050 units could meet the well controlled standard and if so when.  Additionally, as the attached summary of EPA data contained the CATR rulemaking docket shows, no coal unit currently meeting the "well-controlled standard for SO2" is burning other than low sulfur coal.     [EPA-HQ-OAR-2009-0491-3901[1].1, p.5]
Therefore, EPA's choice of a one size fits all "well-controlled emissions rate" standard does not function to meet EPA's stated objective in proposing NODA III option 2, which is to institute an approach to result in "reasonable initial distribution" of allowances consistent with CAA Section 110.   [EPA-HQ-OAR-2009-0491-3901[1].1, p.5]
State of Ohio Environmental Protection Agency (Ohio EPA)
Option 2 distributes allocations in the same manner as Option 1 but then constrains the allocation based on a unit's reasonable foreseeable maximum emissions, limiting a unit's ability to exceed historic emissions (from 2003 to 2009). Under Option 2, when a unit's heat input based allocation would exceed the maximum historic emissions baseline, a well-controlled-rate maximum would be calculated based on 0.06 lbs/MMBtu for S02 and NOx. [EPA-HQ-OAR-2009-0491-3915[1].1, p.1]
First, Ohio EPA does not agree that a well controlled rate of 0.06 lbs/mmBTU for S02 or NOx is appropriate. As noted in the NODA, this rate represents the 'lowest' annual emission rates assumed achievable when state-of-the art-technology is installed on coal units. A well controlled rate should be just that, not a lowest achievable rate. Ohio EPA reiterates the comment in our October 15, 2010 comments:
In Chapter 5 of the documentation (Emissions Control Technology) U.S.EPA states 'Potential (new) coal-fired, combined cycle, and IGCC units are modeled to be constructed with SCR systems and designed to have emission rates ranging between 0.01 and 0.06 lb NOx/MMBtu. In Appendix 5.2A, 'IPM Model - Revisions to Cost and Performance for APC Technologies, SCR Cost Development Methodology' by Sargent and Lundy it is recommended that the 'lower level of NOx removal is recommended as 0.07 NOx lb/mmBtu' for bituminous coal. Yet, U.S.EPA appears to make the assumption that older coal-fired units retrofitted with SCRs can also achieve a 0.06 lb NOx/mmBTU rate. Ohio EPA is not as confident that this one size fits all rate is achievable for retrofits. [EPA-HQ-OAR-2009-0491-3915[1].1, p.2]
For many controlled units, like the examples above for Gavin and Cardinal, there are excess allocations, except units with older control devices when Option 2 is applied. While Option 2 has attempted to limit the amount of excess allocations, the method used does have issues. The NODA acknowledges that 'for the majority of units, the historic heat input-based allocation will not be sufficient to cover historic emission levels' and that 'heat input-based allocations only exceed historic emissions for units at the lower end of the range of historic emission rates for the pollutant involved' and therefore, for these units, Option 2 would 'establish, based on historic data, a reasonably foreseeable maximum emissions level' based on a 'well-controlled emission rate that all units can meet.' However, in comparing emission rates for Gavin and Cardinal, Cardinal's much newer FGD is capable of achieving lower emission rates. [EPA-HQ-OAR-2009-0491-3915[1].1, p.4]
When comparing the Gavin unit and the Cardinal unit above, Gavin has an older FGD pre-dating the years of data used in this analysis and allocation method while Cardinal has a newer FGD. This seems to have worked as an advantage for Cardinal. Option 1 and the first steps of Option 2 results in allocations for Cardinal well above actual controlled emissions, but because the control device was installed within the years used for this analysis and the year of highest actual emissions (uncontrolled) is well above the heat-rate based calculation, there is no restriction under the second part of calculations under Option 22. However, for Gavin, because the control device was installed prior to the years of analysis, the year of highest actual emissions is a controlled year triggering the limitation on allocations under the second part of calculations under Option 2. While Option 2 attempts to constrain allocations based on a unit's reasonable foreseeable maximum emissions it does it in a manner that places a disadvantage to units with control devices installed prior to 2003. Also note that Gavin's average of the three highest annual heat inputs (96,340,367) is over three times larger than Cardinal's (32,060,238). This is obviously reflected in the allocations under Option 1, but Option 2 does not effectively discount both units in an equal manner. [EPA-HQ-OAR-2009-0491-3915[1].1, pp.4-5]

2 Note that Cardinal's allocations under Option 2 are actually higher than Option 1. This is due to re-distributing allocations among all units in the State after units restricted under Option 2 have their emissions reduced similar to Gavin's.
Sunbury Generation LP
EPA's proposed unit-specific allowance allocations under Option 2 of the Second NODA do not fully implement EPA's stated objective of avoiding a windfall of allowances for certain sources. [EPA-HQ-OAR-2009-0491-3920[1].1, p.1]
Like Option 1, Option 2 is based on historic heat input, but proposes to modify the allocations so that they do not exceed the higher of either historic actual emissions or emissions calculated using a 'clean emission factor' (referred to by EPA in the Second NODA as the 'well-controlled-rate maximum'), and the reasonably expected maximum future heat input. Id That is, allowance allocations for sources whose heat-input-based allocation would exceed historic emissions would be capped based on the sources' reasonably foreseeable maximum emissions. Id [EPA-HQ-OAR-2009-0491-3920[1].1, p.2]
Sunbury supports the conceptual methodology underlying the Option 2 approach of modifying allocations so that sources whose heat-input-based allocations would exceed historic emissions do not receive a windfall of allowances. However, EPA has not fully implemented this conceptual methodology in its specific proposed allocation approach, as described in the Second NODA. Specifically, under Option 2, a source's allowance allocation would be determined based on the higher of either the unit's historic actual emissions or the well-controlled- rate-maximum for the relevant pollutant (i.e., 0.06 lbs/mmBtu for S02). As a result, many low-emitting sources would receive an allocation dictated by a well-controlled-rate emission factor which substantially exceeds their actual emissions, thereby providing these sources with a windfall. This result is directly inconsistent with EPA's stated objectives in support of Option 2. EPA explains that the proposed approach is intended to 'reflect[] the shared burden on units to reduce emissions in order to eliminate the state's significant contribution and interference with maintenance.' Id at 1115. [EPA-HQ-OAR-2009-0491-3920[1].1, p.2]
The inequity resulting from this allocation approach is further compounded when considered in conjunction with the potential implications of the emission allowance trading options described under the Proposed Transport Rule. As addressed more fully in Sunbury's comments on the Proposed Transport Rule, EPA has proposed to limit the scope of the proposed trading programs; if finalized, this approach could substantially restrict the ability of affected facilities to trade allowances on the market. Relative to Option 2 under the Second NODA, if EPA elects to allocate allowances under the final Transport Rule using this approach, then any sources whose actual emissions are lower than the well-controlled-rate emission factor would receive more allowances than they need to operate in compliance with the Transport Rule. However, depending on the specific trading program provisions in the final Transport Rule, these excess allowances may not be fully avail able for transfer on the market. Likewise, other affected sources whose initial allowance allocations would be insufficient to cover their emissions would be unable to secure through trading the additional all owances they need to continue operating. Simply put, any 'extra' allowances distributed to low-emitting sources under Option 2 would be effectively 'tied up' and unable to be used by other affected sources. [EPA-HQ-OAR-2009-0491-3920[1].1, p.2]
In the Proposed Transport Rule, EPA identifies several 'key guiding principles' for implementing the Transport Rule, including but not limited to, consideration of cost-effectiveness, providing flexibility to the regulated community, and ensuring a reliable power supply. See 75 Fed Reg. 45226-7. However, for the reasons discussed above, the use of Option 2 for purposes of allocating unit-specific allocations in the manner described in the Second NODA would be directly inconsistent with these stated objectives. [EPA-HQ-OAR-2009-0491-3920[1].1 p.3]
For the foregoing reasons, if EPA elects to finalize a Transport Rule that relies upon the allocation methods described in the Second NODA, Sunbury urges EPA to fully implement the conceptual methodology underlying Option 2 by ensuring that allowance allocations are limited to a unit's actual historic emission rates during the relevant time period considered under the Second NODA. Failure to do so would run counter to EPA's enumerated guiding principles in the Proposed Transport Rule and the Second NODA, including cost effectiveness, providing flexibility to the regulated community, ensuring a reliable power supply, and avoiding a windfall for certain source categories. Id [EPA-HQ-OAR-2009-0491-3920[1].1, p.3]
Sunbury generally supports the conceptual methodology underlying the Option 2 allocation approach of modifying allocations so that sources whose heat-input-based allocations would exceed historic emissions do not receive; a windfall. However, Sunbury asserts that EPA has not fully implemented this conceptual methodology in its specific proposed allocation approach, as set forth in the Second NODA, because, under this approach, many low-emitting sources would receive an allocation dictated by a well-controlled-rate emission factor which substantially exceeds their actual emissions. In this way, these sources would receive more allowances than they need to operate in compliance with the Transport Rule and, as such, experience a windfall. Adding further to this inequitable result are the potential implications of the emission allowance trading options described under the Proposed Transport Rule. Depending on the specific trading program provisions in the final Transport Rule, any 'extra' allowances allocated to low-emitting sources under Option 2 may not be fully available for transfer on the market. Similarly, other affected sources whose initial allowance allocations would be insufficient to cover their emissions would be unable to secure through trading the additional allowances they need to continue operating. For these reasons, Sunbury contends that EPA's specific proposed allocation approach under Option 2 is directly inconsistent with EPA's stated key guiding principles for implementing the Transport Rule, including cost-effectiveness, providing flexibility to the regulated community, ensuring a reliable power supply, and avoiding a windfall for certain source categories. [EPA-HQ-OAR-2009-0491-3920[1].1, pp.6-7]
Tampa Electric Company
Tampa Electric supports Option 2 of the most recent Notice of Data Availability. [EPA-HQ-OAR-2009-0491-3959[1].1, p.2]
Tenaska, Inc.
The second option offers an attempt to adjust the allocation to reflect reasonably foreseeable emissions; however, it adds additional complexity because it would require an estimate of the reasonable upper-bound capacity utilization factor for each unit and determination of a well-controlled emission rate. This essentially equates to the difficult task of determining the potential to emit of a unit. While emission limitations are imposed typically in Title V permits for large units, minor sources do not have Title V permits. Moreover, the Title V permits do not always contain heat input limitations. Thus, states will need to exercise judgment and this may lead to disputes. [EPA-R03-OAR-2010-1027-DRAFT-0005.1[1],p.2]
Tennessee Valley Authority (TVA)
  By contrast, a modified Option 2 provides a rational and equitable allocation of allowances by reducing allocations of the low-emitting units to realistic and achievable levels, freeing up allowances for distribution to all other units. [EPA-HQ-OAR-2009-0491-3983[1].1, p.1]
  3) With regard to your request for comments on the other allocation alternatives, we recommend the elimination in Option 2 of the "Well-controlled-rate maximum" for lower-emission rate units. The use of the "maximum historic baseline emissions" within a seven-year baseline (2003 through 2009) would be sufficient to establish allowances at the appropriate level for lower-emission rate units. The use of an assumed, fixed emission rate 0.06 lb/MMBTU for both SO2 & NOx, and of assumed, fixed generation capacity factors appear arbitrary, and will likely result in the calculation of allowance levels for low-emitting units that are much higher than those allowance levels established by the "maximum historic baseline emissions" method alone. We do not see the necessity of providing low-emitting units additional allowances, which they have historically demonstrated they do not need. [EPA-HQ-OAR-2009-0491-3983[1].1, pp.1-2]
Texas Commission on Environmental Quality
Option Two appears to remove allowances from units that installed controls earlier and/or are better controlled and redistribute them to units that were less controlled during the baseline years of 2003 through 2009. Further, there appears to be some redistribution of allocations bused on source type. There appears to be no discernable pattern or purpose to this allocation redistribution in Option Two. Without understanding fully the EPA's premises for Option Two or the assumptions on which the data relies, it is difficult to determine if this complicated allocation methodology meets its intended purpose, and therefore the TCEQ is unable to provide meaningful comment on Option Two at this time. The EPA's alternative allocation tables (Excel files) released with this NODA do not appear to include complete formulas,  which must be found in the Federal Register publication, making the data more difficult to work with, and TCEQ staff has been unable to replicate or understand the EPA's procedures. [EPA-HQ-OAR-2009-0491-4030, p.4]
Virginia Independent Power Producers
Option 2's assumptions may fail to account for the specific contractual obligations of long-term contract generators such as VIPP's members who must operate whenever dispatched by the power purchaser and who lack the ability to pass along the costs of the NOx and SO2 allowances to the offtaker under a long term contract. Additionally, VIPP is concerned that Option 2, as proposed, would introduce a number of potential adjustment factors that likely would result in numerous legal challenges. Such legal challenges could be difficult to resolve in the short time available for EPA to finalize the rule. [EPA-HQ-OAR-2009-0491-3925[1].1, p.2]
Wolverine Power Supply Cooperative
We also strongly support the use of projected future heat inputs in Option 2, because the baseline period represents bad economic times coupled with cool summers in the Midwest, that collectively resulted in depressed electric demand that we do not believe is representative of the future. [EPA-HQ-OAR-2009-0491-4014[1].1, p. 4]
Wolverine is inclined to favor allocation mechanism of Option 2 over that of Option 1, because Option 2 is designed to prevent windfall allocations that exceed historical emissions as well as future projected needs for well-controlled units. [EPA-HQ-OAR-2009-0491-4014[1].1, p. 4]
Response: 
EPA is finalizing a method of emissions allowance allocation to individual units under the FIP base on based on that unit's share of the state's historic heat-input, but ensuring that no unit's allocations exceed that unit's historic emissions.  EPA decided to use the allocation methodology originally presented as heat input "option 2" in the January 7, 2011 NODA, modified in response to public comments.  EPA decided to use heat input option 2 but without the application of the "reasonable upper-bound capacity utilization factor and a well-controlled emission rate" factors. See final rule preamble section VII.D for further of discussion EPA's rationale for this approach and response to comments in favor of and in opposition to this approach.
Organization: Tri-State Generation and Transmission Association, Inc.
Comment: 
Tri-State Generation and Transmission Association, Inc.
The well controlled emission rate concept discussed in the NODA Option 2 is a useful concept but it must be an emission rate that is reasonably achievable by the units in a given grouping, and must consider the ability of the unit to install and operate the emission controls. Tri-State strongly disagrees that setting a well controlled emission rate for NOx or S02 at a coal fired unit at 0.06 lbs/MMBtu could be reasonably achieved. There are only a few new and retrofitted units in the United States that meet this assumed limit and to date, manufacturer/vendors will not give guarantees that units can meet these emissions rates. To ensure 100% compliance 100% of the time, EOUs will need to target achieving emission rates of 0.03 - 0.04 lbs/MMBtu on a regular basis so they can be assured of meeting this value. For many EOUs, this would be an insurmountable challenge. Tri-State also believes that a well controlled emission rate that is reasonably achievable should be linked to a reasonably achievable time frame. [EPA-HQ-OAR-2009-0491-3902[1].1, pp.4-5]
The time frames set forth in the NODA are unrealistic and unachievable. [EPA-HQ-OAR-2009-0491-3902[1].1, p.5]
Response: 
EPA is finalizing a method of emissions allowance allocation to individual units under the FIP base on based on that unit's share of the state's historic heat-input, but ensuring that no unit's allocations exceed that unit's historic emissions.  EPA decided to use the allocation methodology originally presented as heat input "option 2" in the January 7, 2011 NODA, modified in response to public comments.  EPA decided to use heat input option 2 but without the application of the "reasonable upper-bound capacity utilization factor and a well-controlled emission rate" factors. See final rule preamble section VII.D for further of discussion EPA's rationale for this approach and response to comments in favor of and in opposition to this approach.
 

XX.A.2. Unit-level Comments on Data

Organization: AES Corporation (AES)
Comment: 
AES Corporation (AES)
The Shady Point facility (ORIS 10671) is missing Heat Input for 2009 and inaccurate (low) for the other four years. A mechanism is needed to repair these issues. [EPA-HQ-OAR-2009-0491-4016, p. 4]
The Beaver Valley facility (ORIS 10676) data for annual Heat Input for 2005, 2006, and 2007 are actually the ozone season Heat Input. This results in a much lower allocation. A mechanism is needed to repair these issues. [EPA-HQ-OAR-2009-0491-4016, p. 4]
Red Oak (ORIS 55239) and Ironwood (ORIS 55337) are CCGTs that have seen a three and four fold increase in demand in the past two years. This will require many more allowances than in the baseline period in the option 1 and 2 proposals. This very recent market change has been dramatic and should be rectified in this rulemaking. The EPA should allow for extraneous circumstances and approve alternate baseline periods that more closely reflect the current operation of the facilities. The use of 2010 data and averaging two years instead of three are examples of potential alternate baselines. [EPA-HQ-OAR-2009-0491-4016, p. 4]
Response: 
EPA has updated its final allocation tables to be consistent with the final allocation methodology in the Transport Rule that is described in section VII.D of the preamble.  The Shady Point facility has 2009 heat input.  Furthermore, the heat input baseline includes 2010 which addresses some of the commenter concerns regarding the capture of increased facility operation in the baseline period.  In regards to Beaver Valley, the allocation methodology uses the three highest years among the five year baseline.  This would apparently include 2008, 2009, and 2010 for Beaver Valley if the source feels that the pre-2008 values are understated.  EPA made corrections to data in instances where corrected data was provided by commenter with explanation on why it was superior to that previously reported to EPA.
Organization: American Electric Power
we energies
Luminant
Comment: 
American Electric Power
NODA-3 requests comment on two alternative allocation options. However, the input errors identified in the original proposal and subsequent NODAs have not been corrected, and the resulting IPM model runs based on this incorrect data do not provide a valid basis for comparison. EPA has simply used the invalid and inaccurate state budgets from the original proposal. Until new model runs are completed, based on the information received during comment periods to correct the inaccuracies in the database and the control addition or retirement assumptions made by EPA, the public has no basis to evaluate the ultimate requirements and submit informed comments. While the allocation formulas described in NODA-3 are more easily verified because they use data currently reported to the Agency, the incorrect original IPM model output does not provide a basis for evaluation of what the actual allocations will be. [EPA-HQ-OAR-2009-0491-3934[1].1, pp.3-4]
Luminant
 Luminant believes that the assumptions and projections made in the modeling for this rulemaking are inconsistent with available information and data. EPA should update and correct the assumptions and modeling prior to proceeding with the rulemaking.   [EPA-HQ-OAR-2009-0491-3980[1].1, p.2]
The Integrated Planning Model Results Create Erroneous Predictions  
The Integrated Planning Model results that EPA has made available imply a number of surface mines will no longer operate after 2011. However, Luminant has just permitted a new mining area (Turlington Mine) to supply Big Brown plant. Also, we have permitted a new lignite surface mine (Leesburg Mine) to supply Monticello plant. Not all Texas coal-fired units can fire 100% subbituminous coal by 2012.[EPA-HQ-OAR-2009-0491-3980[1].1, p.4]
we energies
As identified by We Energies in September 2010, the data used by the agency contained numerous errors, missing values and other data issues with respect to the electric generating units ("EGUs") we operate, and the agency's modeling was based on outdated assumptions. Corrected data was provided as an attachment to our original comments. [EPA-HQ-OAR-2009-0491-3976[1].1, p.1]
Alternatively, We Energies requests that EPA, 1) correct all inaccuracies in its data set, 2) update all modeling assumptions and 3) re-run the models to establish updated state budgets and proposed unit allocations. [EPA-HQ-OAR-2009-0491-3976[1].1, p.2]
Because of the significant impact this rule and its allocations will have on We Energies and other EGUs, we recommend that EPA should re-propose the rule with all the data deficiencies corrected. Given corrections of the data issues identified, along with proper recognition of emission control equipment installations made to date or in progress, an updated rule proposal would probably identify a modified future attainment scenario and implementation schedule. This possibility was identified in our September 2010 comments wherein we identified modeling and analyses performed by Alpine Geophysics and Environ Corp. that had been presented to the Lake Michigan Air Directors Consortium. There is no recognition in the current NODA that this information was considered. [EPA-HQ-OAR-2009-0491-3976[1].1, p.2]
Response: 
In the final Transport Rule, EPA has updated its IPM modeling and used the updated modeling to determine state emission budgets.  These modeling updates reflect comments received during the comment period that corrected data inaccuracies and that would have a significant impact on the modeling.  The final allocations are based off budgets that were determined using the updated IPM model.  However, as EPA explained in the January 7, 2011 NODA, EPA wanted to give sources a chance to review and comment on data that would potentially be used in the final Transport Rule allocations under a FIP.  The purpose of the NODA was not to convey final, updated budgets, but to provide sources with a chance to provide additional comment on allocation methodology and underlying data.  See section VII.D of the preamble for a description of the final allocation methodology and the TSD for Allowance Allocation for a list of potential existing Transport Rule units and their allocations under a FIP.
Regarding Luminant's comment, EPA understands that for any mine-mouth lignite unit there could be a need for additional coal handling systems and improvements to any existing rail spur serving the site in order to receive large trainloads of subbituminous coal in lieu of the lignite currently delivered from nearby mining operations. However, EPA also understands that, except for the coal handling systems, any unit designed to burn a low rank coal like lignite can burn higher rank subbituminous coal with only a few relatively minor changes to the boiler and its related systems. This is because a lignite unit is in almost all respects "over designed" for the requirements of a higher rank coal. For a switch from lignite to subbituminous, the primary boiler improvement needed might only be the simple addition of modern "intelligent sootblowing" systems to manage the effects of "ash reflectivity" in the boiler furnace and convection pass with subbituminous. EPA believes that with such relatively minor boiler improvements a switch from lignite to subbituminous should result in no derating of electrical output, improved boiler efficiency, and reduced stack emissions.
Organization: Associated Industries of Massachusetts (AIM)
Comment: 
Associated Industries of Massachusetts (AIM)
Additionally, Massachusetts seems to be unfairly targeted by EPA. Under the alternative options in the NODA, facilities in Massachusetts are allocated SO2 allowances based on a 0.043 lb/mm Btu SO2 emission rate, which is much lower than the effective emission rate in most other states. EPA's allowance allocations should not be based on emission rates that are below levels that can be achieved by state-of-the-art control technology. [EPA-HQ-OAR-2009-0491-3906[1].1, p.2]
Response: 
In the final Transport Rule, Massachusetts was not identified as a contributing upwind state.  Therefore, it is not subject to the final Transport Rule and has not Transport Rule state emission budgets.
Organization: City of Ames, Iowa
Comment: 
City of Ames, Iowa
The original allowance allocations (Sept 1, 2010) granted us 1,154 tons of NOx allowances.

Under options 1 & 2, our emissions allowances are greatly reduced due to the calculation methods and our relative small size compared to the other EGUs in our state. The percentage decrease in NOx allowances from the original proposal to options 1 & 2 is on average 35% (706 or 765 tons of NOx respectively)

Our historic emissions for NOx are:

Year  NOx
2005 1,380
2006 1,296
2007 1,212
2008 1,129
2009 944
[EPA-HQ-OAR-2009-0491-3942-cp, p.1]
Response: 
See section VII.D of the preamble for a description of the final Transport Rule allocation methodology.  The TSD for Allowance Allocation also describes the list of potentially covered Transport Rule units and their allocation under a FIP.  EPA has reviewed the NOX emissions data noted above and confirmed that it matches the values being used in its allocation tables for the historic emissions baseline.  Furthermore, EPA notes that while the historic emission are correctly recorded, that for many units the allocation will be lower than historic emission levels.  Having allocations lower than historic emission levels is a necessary component of a program seeking emission reductions.
Organization: City of Tallahasse
Lafayette Utilities System
Madison Gas and Electric Company (MGE)
Illinois Environmental Protection Agency
Great River Energy
Edgecombe Genco, LLC
Indiantown Cogeneration, L.P.
Northshore Mining Company
Edison Mission Energy (EME)
Spruance Genco, LLC
Kansas City Board of Public Utilities (BPU)
Comment: 
City of Tallahasse
Option #2 attempts to correct this disadvantage to utilities that have spent significant resources to install control equipment to meet emissions reduction targets (such as CAIR). However, what Option #2 does not address is the retiring of more inefficient units which have been replaced promptly by more efficient and cleaner units. In the case of the City's Hopkins Generating Station, allowances were allocated to Unit 2A on the basis of emissions from the 2008 and 2009 timeframe. However, in the year 2008, Unit 2A did not initiate operation until May 2008 and therefore operated only part of the year (approximately June to December 2008). Thus the heat input data from this time does not accurately represent actual annual operation. Yet this data was averaged with a full year of operation (2009) and was used as the basis for allocations for the unit. This unfairly limits the amount of allocations that the unit would have received, as the average is not weighted to account for partial years of operation. [EPA-HQ-OAR-2009-0491-3912[1].1, p.3]
Edgecombe Genco, LLC
Specifically, Edgecombe is providing corrections to the underlying heat input and emissions data used to calculate the allocations. [EPA-HQ-OAR-2009-0491-3971[1].1, p.1]
The allocation tables calculate the baseline heat input as the average of the three highest years between 200S and 2009. However, the data presented in the Annual Heat Input columns from 200S to 2007 is actually the ozone season heat input, which was reported to CAMD under the NOx Budget Program. Edgecombe was not able to obtain all of the archived data prior to the comment date; however, we will provide this data prior to finalization of the allocations if one of the heat input-based allocation schemes is chosen. [EPA-HQ-OAR-2009-0491-3971[1].1, p.1]
Edison Mission Energy (EME)
EME hereby submits the data needed for EPA to perform the calculations under the two methodologies proposed in the Transport Rule NODA. [EPA-HQ-OAR-2009-0491-3953[1].1, p.3]
Great River Energy
Further, EPA has updated the state emission sources and has again used incorrect information for our emission units. Specifically, the data from the model included only one entry for our combustion turbine facility St. Bonifacius. This facility consists of two combustion turbines serving one electric generator. The combined output of the facility is nominally 50 MW. The data from the model only included the data from one of the combustion turbines. Details of both units are included in Table 1. [EPA-HQ-OAR-2009-0491-3898[1].1, p.2] [[See Docket Number EPA-HQ-OAR-2009-0491-3898[1].1, p.3 for Table 1.]]
In summary, Great River Energy requests that EPA fix the data inaccuracies associated with our emission units as explained herein. [EPA-HQ-OAR-2009-0491-3898[1].1, p.5]
Illinois Environmental Protection Agency
Accordingly, the heat input for Dallman Unit 4 should be 13,000,000 mmBTU/year and 6,000,000 mmBTU/ozone season. Also, the total heat input for all units in Illinois should be increased by these corresponding amounts before allocations to individual units are calculated. [EPA-HQ-OAR-2009-0491-3899[1].1, p.1]
Indiantown Cogeneration, L.P.
Specifically, Indiantown is providing corrections to the underlying heat input and emissions data used to calculate the allocations. [EPA-HQ-OAR-2009-0491-3954[1].1,p.1]
The allocation tables calculate the baseline heat input as the average of the three highest years between 2005 and 2009. However, Indiantown was not subject to any allowance trading programs and, therefore, did not submit data to CAMD prior to 2008. The tables use the 2008 and 2009 data only to generate the baseline heat input. This results in lower baseline heat input than it should be since those were historically low generation years for the facility. The NODA indicates that for facilities that were not subject to the EPA allowance trading programs, EPA used historic heat input data as submitted to the Energy Information Administration (EIA). Indiantown has provided this missing data in the attached tables and requests that these data be used to calculate the baseline heat input. [EPA-HQ-OAR-2009-0491-3954[1].1, p.1] [[See Docket number EPA-HQ-OAR-2009-0491-3954[1].1, pp. 2-7 for the tables.]]
In the same way, the tables are missing Annual and Ozone Season NOx and Annual SO2 and NOx Emissions data from 2003 through 2007. This data has been provided from the facility's annual emissions inventory data and we request that this information be used to calculate the facility's allowances under the selected allocation scheme. [EPA-HQ-OAR-2009-0491-3954[1].1, p.1]
Kansas City Board of Public Utilities (BPU)
[Attachment 1 (7 pages) can be found at the end of this comment.]
Lafayette Utilities System
For instance, EPA used the 2005,2006, and 2009 annual heat input data from LUS's Bonin Unit 3 to calculate the unit's average heat input, even though the year 2006 data was based on a year when the Bonin Unit 3 did not produce any electricity. A table of Bonin Unit 3' s annual heat input during the entire baseline period is provided below:
Bonin Unit 3 had exceptionally low heat input during the years 2006, 2007, and 2008 because during these particular years, Bonin Unit 3 was not used to produce electricity (i.e., it had no megawatt hours). In these years, the boiler was out of service. As such, nitrogen caps were being used and the heat input was based solely from the process of capping the boiler. In comparison to the years when Bonin Unit 3 is in normal operating mode, the heat input from 2006, 2007, and 2008 are essentially negligible. However, EPA used the data from 2006, one of the years that Bonin Unit 3 was out of service, to help determine its 'average' heat input and, thus, its allowance allocation under CATR. This method does not accurately reflect Boriin Unit 3's average emissions. LUS requests that EPA instead use only the data from 2005 and 2009 to determine the 'average heat input' from the Bonin Unit 3. [EPA-HQ-OAR-2009-0491-3914[1].1, pp.4-5] [[See Docket Number EPA-HQ-OAR-2009-0491-3914[1].1, p.4 for the table.]]
Madison Gas and Electric Company (MGE)
Fitchburg Generating Station Units 1 and 2 with ORIS 3991 were given allocations based only on the years 2008 and 2009 because MGE began reporting to Environmental Protection Agency (EPA) for the Clean Air Interstate Rule (CAIR) in 2008.  Since the alternative allocation methodologies in this NODA use heat input data starting with 2005 and emissions data starting with 2003, we have provided this information in the attached table.  If these alternative methods are used to calculate allocations, the EPA will have a complete set of data for these units, MGE reported the information in the attached table to the Wisconsin Department on Natural Resources in the Annual Emissions Inventory Reports for each of the years provided. [EPA-HQ-OAR-2009-0491-3924[1].1, p.1] [[See Docket Number EPA-HQ-OAR-2009-0491-3924[1].2 for the attached table.]]
Northshore Mining Company
The data in the January 7, 2011 NODA specific to the Northshore Units is inaccurate and incomplete and must be updated.
EPA also seeks comment on the data used in the NODA III preliminary allocation spreadsheets.  Since Northshore was not required to conduct Part 75 monitoring prior to CAIR, the data used by EPA to calculate allowance allocations is incomplete.  In the table below, Northshore provides the additional heat input data from 2005-2007 necessary to complete the record.  This increases the unit level average used to calculate allowances.  Please use this data to update your records. [EPA-HQ-OAR-2009-0491-3957[1].1, pp.6-7] [[See Docket number EPA-HQ-OAR-2009-0491-3957[1].1, p.7 for the table.]]
Additional information for the EPA database is included in Attachment A.    [EPA-HQ-OAR-2009-0491-3957[1].1, p.7] [[See Docket Number EPA-HQ-OAR-2009-0491-3957[1].1, pp.9-12 for Attachment A.]]
Spruance Genco, LLC
Specifically, Spruance is providing corrections to the underlying heat input and emissions data used to calculate the allocations. [EPA-HQ-OAR-2009-0491-3974[1].1, p. 1]
The allocation tables calculate the baseline heat input as the average of the three highest years between 2005 and 2009. However, the data presented in the Annual Heat Input columns from 2005 to 2007 is actually the ozone season heat input, which was reported to CAMD under the NOx Budget Program. Spruance was not able to obtain all of the historical data prior to the comment date; however, we are providing an attachment that contains the correct annual heat input data for these units and time periods. We will provide the remainder of the data prior to finalization of the allocations if one of the heat input-based allocation schemes is chosen. [EPA-HQ-OAR-2009-0491-3974[1].1, p. 1; see 3974[1].1, pp. 2-3 for attachment]
Response: 
See section VII.D of the preamble for a description of the allowance allocation methodology finalized under Transport Rule.  The TSD for Allowance Allocation provides more details as well as a list of potential existing Transport Rule units, their allocations, and underlying data used to calculate the allocation.  In response to comments on the January 7, 2011 NODA, EPA updated its underlying data tables for allocations where appropriate.  Specifically, it made updates to its unit level heat input and emission values where submitted by commenter with a reasonable explanation on why the previous values were incorrect.  As stated in the NODA, EPA did not anticipate many changes to historic data used for allocation purposes as it was generally reported by the sources designated representative who testified to its accuracy and completeness.  However, some sources did provide data where none had been reported previously (e.g., during years in which data was not required to be reported for a particular source).  Also, some sources noted that the data being used for annual heat input prior to 2008 actually just reflected the ozone season heat input for that year.  The reason being that the source was not required to report a full years worth of data at that time for a given pollutant.   Another case of data correction are instances where sources suggested the data for a particular year at their source was not representative because the source  began operation that year and therefore the annual data just reflect a partial year's worth of operation.  In these instances, EPA made adjustments to its historic emissions and heat input values used to determine allowance allocations.  There is a column in the allocation tables that flags where data values were adjusted based on comment.  If the commenter noted that a value was incorrect, but did not explain why and/or did not provide replacement values, EPA was unable to make adjustments in these cases.
Organization: DTE Energy Services (DTEES)
Comment: 
DTE Energy Services (DTEES)
DTE Pontiac North. This facility is located in Pontiac, Michigan (ORIS Code: 10111) and consists of three natural gas-fired boilers with rated capacities of 201.9MMBtu/hr each and one circulating fluidized bed coal-fired boiler with a rated capacity of 443MMBtu/hr. [EPA-HQ-OAR-2009-0491-3950[1].1, p.2]
The coal-fired boiler was installed August 1, 1984 and operates in cogeneration mode. It is connected to a single steam turbine generator set with a nameplate capacity of 28 MW. High pressure steam from the boiler is fed to the steam turbine to produce electricity and Low pressure steam is extracted from the turbine for process use at the plant. This unit was subject to the NOx budget program, CAIR NOx Annual, CAIR NOx Ozone Season and CAIR S02 programs. The facility has not operated the coal-fired boiler since May 2009.
DTEES believes the heat inputs used for NOx and S02 allowances is low. The records maintained by DTEES reflect the historic heat inputs below:
2007 Ozone Season 332,129MMBtu
2007 Annual 667,780MMBtu
2008 Ozone Season 568,277MMBtu
2008 Annual 2,039,304MMBtu
2009 Ozone Season 238,082MMBtu
2009 Annual 925,305MMBtu
The historic heat input of this unit reflects 6 months of operation in 2007 and 2009 and a full year of operation in 2008 using coal as the primary fuel. The intent of DTEES is to re-fire this boiler using woody biomass as the primary fuel with a projected annual heat input of 2,927,850 MMBtu/yr. The allocations currently assigned to DTE Pontiac North under Option 1 or 2 are insufficient for operations using woody biomass as the primary fuel. DTEES believes the allocations should be recalculated using the heat inputs above. [EPA-HQ-OAR-2009-0491-3950[1].1, p.2]
Since DTEES purchased the units and converted them to combust woody biomass, the utilization of the units is expected to be much higher (expected 87% capacity factor, compared to 3% to 17% during the baseline period combusting coal). [EPA-HQ-OAR-2009-0491-3950[1].1, p.3]
DTEES believes that EPA has underestimated the projected heat input to the DTE Stoneman units. Based on the changes to the facility outlined above, the heat input will be much greater than EPA has recorded as baseline heat input in the 3rd NODA allocation tables. The projected heat input to each unit should be 2,978,400 MMbtu. EPA should use these projected heat input values to determine the NOx and S02 annual allowances for the units. Using projected heat input values results in each unit receiving 298 NOx annual and 4,721 S02 annual allowances when using the projected heat inputs and the permitted emission rates of the modified units (0.2 lbs/MMbtu for NOx and 3.17 lbs/MMbtu for S02). These values are much higher than Option 1 in this NODA, which results in Unit 1 receiving 25 NOx annual allowances and 53 502 annual allowances in 2012 and 72 annual allowances in 2014. Unit 2 receives 34 NOx annual allowances and 72 S02 annual allowances in 2012 and 50 annual allowances in 2014. Option 2 provides for a small increase with Unit 1 receiving 26 NOx annual allowances and 58 S02 annual allowances in 2012 and 39 annual allowances in 2014. Unit 2 receives 34 NOx annual allowances and 78 S02 annual allowances in 2012 and 52 annual allowances in 2014. The two options provide only a small fraction of the allowances that will be required for compliance with the Transport Rule. [EPA-HQ-OAR-2009-0491-3950[1].1, p.3]
If EPA were to adjust the heat input to the expected value of 2,978,400 MMbtu per unit and then recalculate the reasonably foreseeable maximum emissions then these methods may yield the appropriate portion of S02 and NOx allowances to the units. [EPA-HQ-OAR-2009-0491-3950[1].1, pp.3-4]
Response: 
EPA updated its historic heat input baseline to 2006-2010.  See section VII.D of the preamble for a description of the final allocation methodology and The Allowance Allocation Final Rule TSD for a detailed list of potential covered units, their allocations, and underlying data used to determine allocations.  EPA made some corrections to its underlying historic data in instances where the commenter had provided corrected data as well as an explanation as to why the data previously reported by the designated representative was incorrect.  However, EPA saw no such explanation in the above comment, and has not made adjustments to the reported heat input values consequently.
Organization: EquiPower Resources Corp.
Comment: 
EquiPower Resources Corp.
The Transport Rule NODA does not address critical flaws in state budgets and underlying data and assumptions.
o The Transport Rule NODA relies upon the same mistaken data and assumptions as the Transport Rule, and EPA's attempt to obscure these flaws by using heat input data is an inadequate solution. [EPA-HQ-OAR-2009-0491-3928[1].1, p.2]
As an example, Massachusetts is still under-allocated in 2012 due to these mistaken assumptions on the status of controls in the state, and the Transport Rule NODA's approach to unit-level allocations does not fix this problem. EPA has adjusted the 2012 SO2 budget for Unit 3 at Dominion's Brayton Point Power Plant by assuming that the unit's FGD will be online in 2012. However, Massachusetts Department of Environmental Protection has reported that construction of that FGD is not scheduled to begin until April 2011, and therefore that the FGD will not be in full operation until the first quarter of 2014. Unit 3 is the largest unit at Brayton Point, which in turn is the largest coal-fired power plant in New England. As a result, the Agency has seriously understated the level of emissions that will be produced by Brayton Point in 2012, and as a result has under-allocated its (and by extension, the entire state's) allowances. As a result, EPA's state budget for Massachusetts is inaccurate. [EPA-HQ-OAR-2009-0491-3928[1].1, p.10]
Response: 
EPA has updated its IPM modeling so that no FGD is reflected at Brayton Point unit 3 in 2012.  Furthermore, EPA conducted is contribution analysis anew with the updated modeling, EGU and non-EGU inventories.  The final rule analysis did not suggest that Massachusetts was a contributing upwind state, and the state is not covered under any of the programs in the final Transport Rule geography.
Organization: Exelon
Wolverine Power Supply Cooperative
CPS Energy
Cogen Technologies Linden Venture, LP
Comment: 
Cogen Technologies Linden Venture, LP
Linden Cogen has also examined the underlying unit-level data used to generate the illustrative allocations and agrees that these data are correct for Linden Cogen's generating units. [EPA-HQ-OAR-2009-0491-3938[1].1, p.5]
CPS Energy
The data used in the allocation tables provided in the technical documents on the EPA's website is correct for CPS Energy units. [EPA-HQ-OAR-2009-0491-3947[1].1, p.1]
Exelon
Exelon's review of the proposed allocations set forth in the data tables accompanying the NODA reveals that the allocations to its fossil-fuel fired units have been properly calculated under this method and are more appropriate than the allocations appeared to be under the methodology presented in the original Transport Rule proposal. [EPA-HQ-OAR-2009-0491-3919[1].1, p.4]
To this end, Exelon's retiring units have properly been awarded allowances in the data tables accompanying the NODA. [EPA-HQ-OAR-2009-0491-3919[1].1, p.5]
Wolverine Power Supply Cooperative
Regarding the USEPA's request for comment on underlying unit-level data and allowance calculations, we have reviewed these data for Wolverine's Sumpter Plant, and find them to be accurate and complete. [EPA-HQ-OAR-2009-0491-4014[1].1, p. 4]
Response: 
See section VII.D for a description of the allocation methodology used in the final Transport Rule.  Additionally, the allocations and underlying data are described in the Technical Support Document for Allowance Allocations.
Organization: Exxon Mobil Corporation
Comment: 
Exxon Mobil Corporation
7. We would like to request an error correction. Our ExxonMobil Beaumont Cogeneration unit has been assigned a Capacity Factor of 0.22 (like a unit that delivers electricity only intermittently during high electricity demand days - 'Combustion Turbine'). This is instead a Cogeneration unit supplying steam and power to an industrial source to meet steam and power needs constantly for our local ExxonMobil Refining and Chemical complex and supplying supplemental electricity to the grid. Following the EPA logic in the proposal, it should have a 0.70 capacity factor or greater. [EPA-HQ-OAR-2009-0491-3999[1].1, p.3]
Error Correction Request
Our ExxonMobil Beaumont Cogen unit has in error been assigned a Capacity Factor of 0.22 (like a unit that delivers electricity only intermittently during high electricity demand days - 'Combustion Turbine')). We would like to request an error correction. This is a Cogeneration unit supplying steam and power to an industrial source to meet steam and power needs and supplying supplemental electricity to the grid and following the EPA logic should have a 0.70 capacity factor or greater. [EPA-HQ-OAR-2009-0491-3999[1].1, p.7]
[Table can be found on page 2 of comment letter 4028.]
EM requests that EPA correct any data used in development of the CATR to reflect the unit data provided above. [EPA-HQ-OAR-2009-0491-4028, p.2]
Response: 
The allocation methodology used in the final Transport Rule does not use a capacity factor assignment in its determination of allowance allocations.  The final allocation methodology eliminates the concern addressed by commenter regarding potential under allocation because of capacity factor assignment.  This concern only applies to option 2 of the January 7, 2011 NODA.  EPA did not finalize this option.  See section VII.D of the preamble for a complete description of the final allocation methodology.
Organization: Florida Department of Environmental Protection
Comment: 
Florida Department of Environmental Protection
In reviewing the allocation tables for both option 1 and 2, we note that when allocations are distributed as whole values, the total number of allowances actually distributed in a given state will usually not equal the amount allocated to the state. This is because of the rounding that takes place when allocating the fractional values. The actual distribution could be higher or lower than the amount allocated to the state. We did not see where the rule indicates how these orphan allocations would be dealt with. One option is that these extra or deficit allowances be added or subtracted from the new unit set-aside allocations. In any case, when any left-over new unit set-aside allocations are redistributed to the existing pool, there is also a need for a procedure to allocate orphan allowances. Florida has developed an "adjusted rounding" procedure for CAIR allowances that could be used. See attached spreadsheet.   [EPA-HQ-OAR-2009-0491-3879[1].1, p.2] [[See Docket Number EPA-HQ-OAR-2009-0491-3879[2].2 for the spreadsheet.]]
Response: 
Allocations to existing units under the Transport Rule FIPs are rounded to the nearest ton using conventional rounding.  This rounding may result in small differences between the sum of allocations to existing units in a specific state under a FIP, and the size of the existing unit pool of allowances from the state's trading budget.  Any such differences resulting from the existing unit allocations are reflected by adding or subtracting allowances, as appropriate, in calculating the number of allowances in the new unit set-aside for that state, and the resulting set-aside amounts are set forth in Tables XXX in section XX of the preamble. Similarly, small differences between the sum of allocations from the new unit set-aside to units in a state and the size of the new unit set-aside may also occur because of rounding in calculating unit-by-unit allocations, and EPA has established a procedure for handling such scenarios in the new unit-set-aside provisions (as well as in the Indian country new unit-set-aside provisions) in the Transport Rule text.  EPA notes that under  no circumstances will rounding result in total state allocations for a given control period in a FIP exceeding or falling short of the state budget for that control period in the FIP.  Total state allocations for a vintage year will equal the state budget.
Organization: Horsehead Corporation
Comment: 
Horsehead Corporation
C. Horsehead is addressing certain corrected heat input data in response to EPA's request in the Second NODA to comment on the accuracy of the data used to calculate the proposed allowance allocations.
EPA states in the Second NODA that, 'in order to ensure the accuracy of the allocation calculations, the EPA is providing this opportunity for source owners and operators ... to comment on the ... data used or that should be used to calculate the allocations and the resulting allocations ....' 76 Fed. Reg. 1116. [EPA-HQ-OAR-2009-0491-4003[1].1, p.2]
Horsehead previously reported to EPA certain incorrect heat input data for the Facility's boilers for the period from 2005 to 2010.  Upon discovering this reporting error in August 2010, Horsehead promptly began working with EPA to correct the relevant information. Horsehead was instructed by EPA that the Facility could submit corrected heat input data for calendar years 2009 and beyond, using EPA's electronic Emissions Collection and Monitoring Plan System (the 'ECMPS'). Accordingly, in October 2010, Horsehead submitted corrected heat input for 2009 and the first two quarters of 2010. However, EPA informed Horsehead that the ECMPS does not allow users to submit corrected data for years prior to 2009; therefore, Horsehead's reported heat input data for calendars years 2005 through 2008 has not been corrected within the ECMPS.  Horsehead has corrected the heat input data for calendar years 2005 through 2008 and is maintaining this information at the Facility. Horsehead is in the process of determining with EPA the best method for submitting this updated information to the Agency. [EPA-HQ-OAR-2009-0491-4003[1].1, pp.2-3]
Additionally, in response to EPA's specific request in the Second NODA that source owners and operators comment on the accuracy of the data relied upon by EPA in calculating the proposed allowance allocations, Horsehead is addressing within this letter certain corrected historic heat input data for the relevant time period considered under the Second NODA. [EPA-HQ-OAR-2009-0491-4003[1].1, p.3]
Response: 
EPA updated its heat input baseline to include 2010.  This should provide the Horsehead source with one additional year of complete and accurate data.  In regards to the pre-2009 data, EPA's final allocation tables continue to use the CAMD data available for these sources.  The comment did not specify the unit or the corrected heat input values for pre-2009 years, so EPA made no changes to those data points for purposes of these allocation tables.
Organization: Morgantown Energy Associates
Massachusetts Department of Environmental Protection
Comment: 
Massachusetts Department of Environmental Protection
b. Underlying data and assumptions
With respect to corrections to underlying data and assumptions that we previously submitted, to our knowledge, EPA has not made publicly available any changes made to its NEEDS data base in response to comments submitted on the proposed Transport Rule and first NODA. Therefore, we are unable to determine if EPA has made corrections to the underlying data and assumptions for Massachusetts facilities that we recommended. We understand that EPA is still making adjustments to the data and assumptions on which the final Transport Rule will be based. We encourage EPA to make the needed corrections for Massachusetts units so that final Transport Rule budgets and allocations for Massachusetts will be based on accurate descriptions of the Massachusetts units' characteristics and operations. [EPA-HQ-OAR-2009-0491-4017[1].1, p.4]
Brayton Point
We wish to again bring attention to a significant error in the underlying assumptions in the proposed Transport Rule for Brayton Point. As noted in our previous comments on the proposed Transport Rule, EPA's data reflects operation of a scrubber at Brayton Point (ORIS ID 1619) Unit 3 in 2012 while the current Prevention of Significant Deterioration (PSD) approval and MassDEP modified plan approval allows the operator to begin construction of a dry scrubber by April 2011; it will not be ready to operate in 2012. Dominion Energy New England, Inc., the operator of the Brayton Point facility, has provided a schedule to MassDEP showing construction of the scrubber commencing in 2012, with full operation by the 1st Quarter of 2014. EPA's incorrect assumption concerning the timeframe for installation of the scrubber must be corrected and the Massachusetts SO2 budget should be adjusted upward to account for SO2 emissions from Brayton Point Unit 3 in 2012 and 2013 - prior to installation and operation of the scrubber. Because the third NODA does not reflect changes in emissions controls on covered units, we cannot determine if EPA has made the correction to its underlying assumptions for this unit. [EPA-HQ-OAR-2009-0491-4017[1].1, pp.4-5]
As we previously commented, for 2014 and beyond, we believe the SO2 allocation for Brayton Point and the Massachusetts annual SO2 budget should reflect the reduced emissions that will result from the installation of the scrubber, which has been in the planning stage since 2002. Therefore, we encourage EPA in the final Transport Rule to provide Unit 3 with a higher level of allowances for 2012 and 2013 only, and provide a lower level of allowances for 2014 and beyond. [EPA-HQ-OAR-2009-0491-4017[1].1, p.5]
Salem Harbor
As we noted in our comments on the proposed Transport Rule, EPA assumed that a scrubber will be installed on Unit 3 at the Salem Harbor facility (ORIS ID 1626) in 2012. There are no plans to install a scrubber on this unit according to comments we have received from Dominion New England, Inc. [EPA-HQ-OAR-2009-0491-4017[1].1, p.5]
Morgantown Energy Associates
Specifically, MEA is providing corrections to the underlying heat input and emissions data used to calculate the allocations. [EPA-HQ-OAR-2009-0491-3966[1].1, p.1]
The allocation tables calculate the baseline heat input as the average of the three highest years between 2005 and 2009. However, the data presented in the Annual Heat Input columns from 2005 to 2007 is actually the ozone season heat input, which was reported to CAMD under the NOx Budget Program. MEA is providing an attachment that contains the correct annual heat input data for these units and time periods. [EPA-HQ-OAR-2009-0491-3966[1].1, p.1]
In addition, the data presented as Annual NOx Emissions from 2003 through 2007 is also incorrectly reported from ozone season emissions and the SO2 data is missing prior to 2009. The correct annual NOx and SO2 emissions data is also provided in the attached tables. [EPA-HQ-OAR-2009-0491-3966[1].1, p.1] [[See Docket Number EPA-HQ-OAR-2009-0491-3966[1].1, pp.2-6 for attached tables.]]
Response: 
EPA has updated its modeling, and the final EPA IPM base case used in the Transport Rule analysis does not include a scrubber at Brayton Point Unit 3.  Additionally, Massachusetts was not determined to be a contributing state in the final Transport Rule, which obviates the Mass DEP concerns regarding allocations to specific units.
Organization: Nelson Industrial Steam Company (NISCO)
Comment: 
Nelson Industrial Steam Company (NISCO)
NISCO appreciates the fact that EPA correctly identified its two units in the 2011 NODA; [EPA-HQ-OAR-2009-0491-4026, p.1]
However, as discussed below, EPA did not use the prior reported heat input data for the units in calculating NISCO's heat input under the two options for allocations proposed in the 2011 NODA. [EPA-HQ-OAR-2009-0491-4026, p.2]
In the underlying data supporting the allocations proposed in both Options 1 and Option 2 for NISCO in this 2011 NODA, EPA used an average of only two years of heat input data for the NISCO units. This was based on averaging only two years of data, that of 2008 and 2009. That is likely due to EPA's prior misidentification of the units. NISCO became subject to the CAIR program and in 2008 began reporting data directly to EPA's Clean Air Markets database. The heat input data that EPA shows for NISCO's two units in 2008 and 2009 does reflect actual heat input data for those years. However, 2009 was not representative of normal NISCO operation as Unit 1 was down from May 4, 2009 until early September 2009 due to significant damage to the turbine that required an extended outage to repair. [EPA-HQ-OAR-2009-0491-4026, p.5]
NISCO's units heat input data was reported to the Energy Information Administration ('EIA') for prior years by Entergy, the operator of the NISCO units. Ibis heat input data for 2005-2007 is available for these two units in the EIA database under ''Facility ID 1393, Facility Name RS Nelson Units - lA & 2A. NISCO requests that EPA recalculate the 3 year average heat input for its units by using the EIA data. The 2007 to 2010 data for fuel input to each boiler is available in the annual downloads at: http://www.eia.gov/cneaf/electricity/page/eia906 920.html, which is data collected on the Form EIA-923. Prior to 2006, the boiler fuel data was collected on the EIA-767. The F767 was discontinued in 2005 and no boiler data was collected fat 2006. F923 took up the collection in 2007. The F767 data is published at http://www.eia.gov/cneaf/electricity/page/forms.html [EPA-HQ-OAR-2009-0491-4026, p.5]
For your convenience, we have downloaded the 2005, and 2007 through October 2010 fuel input data for the two units from the EIA databases in one spreadsheet. The boiler data for 2007 to 2010 is on one tab, and the 2005 data is on another due to the F767's different format. The first tab is the total fuel and generation data for the plant by prime mover type. We are .attaching this spreadsheet as Exhibit 1. [EPA-HQ-OAR-2009-0491-4026, p.5]
[Exhibit 1 (24 pages) can be found on pages 7-30 of this comment.]
In summary, the heat input data for each unit is as follows: [EPA-HQ-OAR-2009-0491-4026, p.5]
[Table can be found on page 5 of this comment.]
In the underlying data supporting Options 1 and Option 2 in this 2011 NODA, EPA lists the capacity of the two units as 107 MW for Unit lA and 106 MW for Unit 2A. In actuality the maximum gross generating capacity is 130 MW for Unit 1A and 130 MW for Unit 2A. NISCO requests that this information be corrected. [EPA-HQ-OAR-2009-0491-4026, pp.5-6]
Response: 
EPA has updated its 2006 and 2007 ozone season heat input data with those values provided by commenter.  Additionally, EPA has finalized an allocation methodology that relies on a 2006-2010 emissions baseline.  EPA final allocation methodology does not use or report maximum gross generating capacity in its underlying data to determine its allocation methodology.  See section VII.D of the preamble for further detail on the Transport Rule allocation methodology under a FIP.
Organization: New Jersey Department of Environmental Protection (NJDEP)
Comment: 
New Jersey Department of Environmental Protection (NJDEP)
The Department has identified two errors in the New Jersey unit-level allocation calculated using the alternative methodologies. Firstly, the American Ref-Fuel of Essex unit (ORISID = 10643, UNITID = 3) in the allocation table should not be identified as a Transport Rule unit. Based on data the facility submits annually to the New Jersey Emission Statement Program, none of units at this facility has consumed enough fossil fuel to be anywhere close to 20% of the total heat input criteria under the Transport Rule. [EPA-HQ-OAR-2009-0491-3891[1].1, p.2]
Secondly, the allocation file appears to have omitted one of the units at the Cumberland Energy Center (ORISID = 5083, UNITID = 5001). There are two units at this facility, 4001 and 5001. Unit 5001 is a newer combustion turbine unit rated at 103 MWe that began operation in 2008. This unit should be included as a Transport Rule unit, and therefore, be allocated allowances.[EPA-HQ-OAR-2009-0491-3891[1].1, p.2]
Response: 
The final allocation tables have been updated based on the above comments.  Commenter may see section VII.D of the preamble for an explanation of how EPA determined its list of potentially covered Transport Rule units.  As suggested by the commenter, the Cumberland Energy Center unit 5001 has been added to the final allocation tables.
Organization: New York State Department of Environmental Conservation
Louisville Gas and Electric Company (LG&E) and Kentucky Utilities Company (KU)
Association of Electric Companies of Texas (AECT)
Vectren Corporation 
Lakeland Electric
Minnesota Power 
Progress Energy Service Company
NRG Energy
National Rural Electric Cooperative Association (NRECA)
Wisconsin Public Service Corporation (WPSC)
National Mining Association (NMA)
Comment: 
Association of Electric Companies of Texas (AECT)
EPA's Modeling Assumptions and Projections are Inconsistent with Available Information
EPA has a long history of rulemakings that recognize the inherent differences in fuels with regard to regulatory compliance. EPA, therefore, should return to the initial CATR allocation incorporated into the initial proposed CATR of August 2,2010. This would provide correction to EPA's subsequent assumptions and modeling prior to proceeding with the rulemaking. [EPA-HQ-OAR-2009-0491-3981[1].1, p.2]
Lakeland Electric
In 2008, Lakeland Electric's Unit 3 coal fired boiler at the C.D. McIntosh, Jr. Power Plant emitted 7,626.8 tons of SO2 (see EPA CAMD 2008). In 2008, Unit 3 operated its wet scrubber above 73% SO2 reduction efficiency on average for the entire year. In addition to the scrubber's high efficiency, Unit 3's coal annual average sulfur content was 1.14% for 2008. Notwithstanding these facts, EPA has only allocated Unit 3 the following allowances: 2,411 tons SO2 under Option 1 and 3,506 tons SO2 under Option 2. These allowances amount to a 68% and 54% reduction respectively by the year 2012 from 2008 SO2 emission values. [EPA-HQ-OAR-2009-0491-3892[1].1, p.2]
In order to reach an additional 68% or 54% SO2 reduction, Unit 3 would be required to undergo a major retrofit to its system before 2012 in order to meet these reductions. Unit 3 is not designed and is unable to run at full load on natural gas and retrofitting Unit 3's SO2 control equipment may still not result in the needed reductions. In addition, the ability to attempt and finish any major modifications by 2012 is not possible. It should also be noted that there is no additional room in the surrounding area around Unit 3 to even install an additional or larger scrubber, not to mention that it may be unattainable, or at least economically unattainable, to scrub an additional 54%-68% of sulfur dioxide from a flue gas made from 1.14% sulfur coal. [EPA-HQ-OAR-2009-0491-3892[1].1, p.2]
Additionally, EPA has not posted new modeling information with each option modeled, so Lakeland Electric cannot support either option at this time. Unit 3's SO2 allowances under the Clean Air Interstate Rule (CAIR) cover approximately 4,974 tons of SO2 emissions annually, not counting banked allowances, for the period 2010-2014. However, Option 1 allocates only 2,411 SO2 allowances for Unit 3 annually; this is a 52% reduction. Lakeland Electric would like EPA to explain why such a dramatic reduction is required from the earlier issued CAIR allowance scheme. Lakeland Electric would also like EPA to discuss how they are confident that the new disbursement of allowances under Options 1 or 2, as opposed to the original proposed Transport Rule allowance scheme, will still bring downwind states into attainment as allowance banks have now varied from facility to facility. [EPA-HQ-OAR-2009-0491-3892[1].1,p.4]
6) Has modeling been performed for Options 1 and 2 that demonstrates that downwind states will not be affected adversely, i.e., upwind states will still contribute a significant portion of the nonattainment pollutant, as opposed to the allowance schemes initially proposed, and if so, will EPA publish that data on the docket? [EPA-HQ-OAR-2009-0491-3892[1].1, p.6]
Louisville Gas and Electric Company (LG&E) and Kentucky Utilities Company (KU)
Comparing the original allocation proposal with the alternatives illustrates the magnitude of uncertainty regarding the number of allowances that units and companies might receive. The number of allowances that companies would receive at their Kentucky plants varies by tens of thousands, equating to variations of over 50% for several companies. Attachment A provides additional details. In some cases, companies will be in compliance, will curtail or retire unit operations, or will need to install additional controls, depending on the allocation method selected. [EPA-HQ-OAR-2009-0491-3909[1].1, p.2] [[This comment can also be found in Section XX.]]  [[See Docket Number EPA-HQ-OAR-2009-0491-3909[1].1, p.3 for Attachment A.]]
Minnesota Power 
The MP staff review of data provided by EPA in this rule making affirms that EPA's characterization of emissions and calculations for budget allocations has improved since the August 2 2010 NODA, with MP being able to confirm EPA calculations for most MP unit budget allocations. However, MP notes that while some units appear to be properly characterized by EPA in the NEEDS data base, MP cannot replicate the calculated result EPA has developed for budget allocations for all MP units. It is unclear to MP why EPA budget allocation calculation methodology appears to be different for similar units posted in the NEEDS data base. It is apparent to MP that emissions performance from control equipment retrofit on MP units that reduce SO2 and NOx emissions since 2005 have received some consideration in EPA calculations for budgets but calculation particulars are not clearly defined and MP staff cannot replicate some of the results. Regardless, MP notes that EPA has determined budget allocations for Minnesota sources that are significantly lower than emissions pre-2005, of a magnitude that tracks with EPA's targeted Group 2 State percent reductions in emissions of SO2 and NOx. MP notes that it is important that EPA provide the regulated community the opportunity to understand the basis for data discrepancies and seek corrections before the Transport Rule is finalized. [EPA-HQ-OAR-2009-0491-4009[1].1, pp.3-4]
National Mining Association (NMA)
:: Combined cycle 2012 SO2 allocations under Option 1 represent a 46,443% increase over the same allocation under the PTR Method. Under Option 2 the increase is just under half that  -  a 21,153% increase over the PTR Method allocation. For 2014 SO2 allocations are 51,049% (Option 1) and 29,183% (Option 2) greater than the PTR Method allocations. [EPA-HQ-OAR-2009-0491-4013[1].1, p.3]
:: The sum of all combined cycle units' annual historical cap value (which for each unit is its seven-year record high annual emissions) is 2,946. To emit this much SO2 in a single year, every single combined cycle unit covered by the rule would have to have record emissions in the same year all at the same time. Yet under Option 1 these units are allocated 311,631 allowances (an excess of 308,685) and under Option 2 they are allocated 141,934 allowances (an excess of 138,988). These gross over-allocations are annual over-allocations. That is, every year these units receive this windfall. These over-allocations  -  as compared with seven-year record high emissions  -  drop slightly in 2014 (when the SO2 allocations shrink for Group 1 states) to 233,805 (Option 1) and 133,662 (Option 2). Nonetheless, by just the forth year of the program Option 1 will have allocated well over a million excess SO2 allowances  -  that these units could never actually need to cover emissions. [EPA-HQ-OAR-2009-0491-4013[1].1, p.3]
:: Combined cycle annual NOx allocations under Option 1 represent a 485% increase over PTR allocations. Under Option 2 this increase is still 394%. Combined Cycle ozone season NOx allocations are 394% (Option 1) and 305% (Option 2) higher than PTR allocations. [EPA-HQ-OAR-2009-0491-4013[1].1, pp.3-4]
:: Under Option 1, combined cycle units are allocated 58,812 and 68,095 allowances more than historical record emissions for annual NOx and ozone season NOx respectively. That is, each year combined cycle units will receive over 125,000 NOx allowances to sell or bank. [EPA-HQ-OAR-2009-0491-4013[1].1, p.4]
Under Option 1, coal-fired EGUs would received 349,249 (2012 SO2), 282,357 (2014 SO2), 126,498 (annual NOx), and 96,131 (ozone season NOx) fewer allowances than they would under the PTR Method. That is, hundreds of thousands of allowances fewer than are needed to cover coal-fired EGUs lawful emissions. [EPA-HQ-OAR-2009-0491-4013[1].1, p.4]
Under Option 2, EPA's proposed under-allocation to coal-fired EGUs is 155,791 (2012 SO2), 167,756 (2014 SO2), 101,399 (annual NOx) and 74,681 (ozone season NOx) fewer than under the PTR Method. [EPA-HQ-OAR-2009-0491-4013[1].1, p.4]
[Tables can be found on pages 4-6 of this comment.]
This unit's lifetime-of-the-plant SO2 emissions are significantly less than its annual SO2 allocation for a single year. If the life-of-the-facility were fifty years, it would emit at most 70 tons of SO2. Under Option 1, it would be allocated 8,846 SO2 allowances each year. Thus, its first year allocation is 126 times its potential SO2 emissions over the life of the plant (assuming a fifty years). That is frankly absurd. [EPA-HQ-OAR-2009-0491-4013[1].1, p.6]
By way of example, the Whiting Clean Energy facility in Indiana is allocated over 200 times what it was allocated under the emissions-based PTR Method and over 200 times its record annual actual emissions. [EPA-HQ-OAR-2009-0491-4013[1].1, p.7]
EPA provides tables showing how the initial state budgets from the proposed rule would be allocated to the unit level under the two new allocation methods. In doing so, EPA notes that "[a] number of commenters requested that EPA publish allocations and underlying data for any potential alternative allocation methodologies before issuing a final Transport Rule." To be absolutely clear, that is not what EPA has provided. Instead, EPA has provided obsolete data based on obsolete state budgets. [EPA-HQ-OAR-2009-0491-4013[1].1, p.11]
Further, the new allocations that EPA provides in the Option 1 and Option 2 tables are based on the state budgets in the proposed Transport Rule, which are again obsolete. An individual unit, or the owners or operators of groups of units, cannot rely on the data for compliance planning. All that these tables allow is for owners and operators to evaluate how their proportionate share of the budget will change if EPA switches from Option 1 to Option 2. As noted above, because of changes identified in the first NODA, units cannot rely on their allocations under the proposed Transport Rule to determine their proportionate share of the state budget assuming EPA uses the allocation method in the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-4013[1].1, p.12]
A. Problems with Data EPA Has Provided.
EPA has not provided sufficient information that would allow the public to efficiently and comprehensively compare and analyze the unit-level allocations that result from these three vastly different allocation methods. EPA made numerous changes between the proposed Transport Rule and NODA-3 to the available unit-level databases that prevent us from completing a complete line-by-line, unit-by-unit comparison for all units. For example, the universe of units changed between the proposed rule and NODA-3 because EPA proposes different cut-off dates for determining when a unit will be treated as a new unit. Additionally, EPA treats and lists steam turbines at combined cycle facilities differently under NODA-3 than it did under the proposed rule. Further, EPA did not provide any single field (i.e., column) that is unique to each unit in all databases. Finally, there are numerous other changes and anomalies in the data that we were not able to resolve in the short time permitted for public review. [EPA-HQ-OAR-2009-0491-4013[1].2, p.1]
In the NODA-3 Database, EPA does not provide information about the fuel used by each unit. To perform our analysis we used EPA's unique "technology class capacity factors" as identified in the NODA-3 Database. Those factors were for the following five Technology Classes: Coal-Fired Boiler (0.87); Combined Cycle (0.70); Combustion Turbine (0.14); Oil or Gas Fired Boiler (0.46); and Other (0.71). This allowed us to group the units based on technology class. [EPA-HQ-OAR-2009-0491-4013[1].2, p.2]
Our analysis in Part III (comparing NODA-3 allocations to maximum emissions) and Part IV (providing sample unit data) relied solely on the information contained in the NODA-3 Database. [EPA-HQ-OAR-2009-0491-4013[1].2, p.3]
A. Comparisons of PTR Allocations to NODA-3 Option 1 Allocations.
The following charts show the change in total allocation to all units grouped by technology class/plant type that results from switching from the PTR Method to the Option 1 Method. [EPA-HQ-OAR-2009-0491-4013[1].2, p.3]
[Charts can be found on pages 4-6 of this comment.]
In the first year allocation alone (2012), combined cycle units and combustion turbines will receive a total of almost 600,000 more allowances under the Option 1 Method (as compared to the PTR Method). Coal-fired boilers would receive 571,877 fewer allowances under the Option 1 Method. These extra allocations to combined cycle units and combustion turbines would be realized each year of the program. That is, these combined cycle units and combustion turbines would collectively received an additional roughly 600,000 extra allowances in the second year (2013), and so on. Thus, by the beginning of the third year (2014), the Option 1 Method will allocate an extra 1.2 million allowances to combine cycle and combustion turbines collectively. Over this same period of time, coal-fired boilers collectively will receive over 1.1 million fewer allowances under the Option 1 Method. [EPA-HQ-OAR-2009-0491-4013[1].2, p.3]
The Option 2 Method still results in a significant shift of allowances from coal-fired boilers to other technology classes. In the first year allocation alone (2012), combined cycle units and combustion turbines will receive a total of 340,041 more allowances under the Option 2 Method (as compared to the PTR Method). Coal-fired boilers would receive 331,871 fewer allowances under the Option 2 Method. These extra allocations to combined cycle units and combustion turbines would be realized each year of the program. That is, these combined cycle and combustion turbines would collectively received an additional 340,041 extra allowances in the second year (2013), and so on. Thus, by the beginning of the third year (2014), the Option 2 Method will allocate an extra 680,082 allowances to combine cycle and combustion turbines collectively. Over this same period of time, coal-fired boilers collectively will receive over 660,000 fewer allowances under the Option 2 Method. [EPA-HQ-OAR-2009-0491-4013[1].2, p.7]
[Charts can be found on pages 7-9 of this comment.]
Under Option 1, in the first year alone, combined cycle units will receive over 300,000 allowances that they could never need. Even under Option 2, combined cycle units will receive nearly 140,000 allowances that they do not need  -  even in a year where every combined cycle unit has emissions equal to their seven-year record high. These over-allocations are realized every year of the program. [EPA-HQ-OAR-2009-0491-4013[1].2, p.10]
[Charts can be found on pages 11-13 of this comment.]
These tables demonstrate the severe over-allocation to many natural gas combined cycle units and the severe under-allocation to many coal-fired units. [EPA-HQ-OAR-2009-0491-4013[1].2, p.14]
[Tables can be found on pages 15-16 of this comment.]
National Rural Electric Cooperative Association (NRECA)
NRECA has closely examined the underlying CATR unit data and unit allowance allocations provided in the CATR rulemaking docket.  The NRECA spreadsheet submitted separately to the CATR docket is comprised from data contained in this rulemaking docket and serves as a reference for the following observations regarding allowance distributions under NODA III option 2.  [EPA-HQ-OAR-2009-0491-3943[1].2, p.6]
As a group, combined cycle (CC) and turbine units receive the following windfalls of allowances in all the CATR trading programs: 
-Under the ozone NOx trading program:   While emitting about 5.52% of total CATR tons, CC and turbine units receive about 16% of the allowances, over 300% more than their current emissions.   
-Under the fine particulate trading program for annual NOx:  While emitting about 2.98% of the total CATR tons, CC and turbine units receive about 10% of the allowances, over 300% more than their current emissions.   [EPA-HQ-OAR-2009-0491-3943[1].2, p.6]
- Under the fine particulate trading for annual SO2:  While emitting about .5% of the total CATR tons, CC and turbine units receive about 5% of the allowances in 2012 and about 7% of the allowances in 2014, over 6200% of their current emissions.   [EPA-HQ-OAR-2009-0491-3943[1].2, p.7]
Thus in the aggregate, combined cycle and turbine units receive far more allowances than these units can ever use.     [EPA-HQ-OAR-2009-0491-3943[1].2, p.7]
-Of the 420 CC gas units within the CATR region, not one has emissions that exceed the "well controlled emissions rate" for SO2.      
-Only 20% of the CC gas units have emissions that exceed the "well controlled emissions rate" for NOx, and the vast majority of these units are not equipped with SCRs. 
-Less than 8% of the turbines have emissions that exceed the "well controlled emissions rate" for SO2 emissions.  The vast majority of these units appear to use gas/oil as a duel fuel. [EPA-HQ-OAR-2009-0491-3943[1].2, p.7]
-Of the more than 1050 coal units contained in EPA's CEMS data base for the CATR states, just 8 units' emissions meet or are below the "well controlled emission rate" for both SO2 and NOx. 
-45 coal units' emissions in the CATR meet or are below the "well controlled emissions rate" for NOx. 
-27 coal units meet or are below the well "controlled emissions rate" for SO2, and all of these units utilize low-sulfur coal.   [EPA-HQ-OAR-2009-0491-3943[1].2, p.8]
New York State Department of Environmental Conservation
The Iatan facility in Missouri is a good example of EPA's proposed NODA over-allocating (and therefore requiring other facilities within the state to buy allowances from a facility that could not possibly use its entire allocation).  Iatan Unit 1 installed both SO2 and NOx controls which came on-line beginning in 2009.  SO2 emissions from this unit went from over 15,000 tons in 2008 to 152 tons in 2009.  Using the limits contained in the permit (8100 MMBtu/hr and 0.1 lb/MMBtu) provides a maximum emission of about 3,550 tons per year.  Both allocation methods in the NODA provide more than 12,000 tons in 2012 and 9,000 in 2014 for this unit.    [EPA-HQ-OAR-2009-0491-3937[1].1, p.2]
NRG Energy
Louisiana  
In Louisiana, 81% of capacity is natural gas generation; however, coal generation provides 99% of all SO2 emissions. Still the heat input method allocates 62% of the allowances to the non coal units compared to the July NODA which afforded 1% to these same units. Using EPA's projected allowance value of $500/ton and our calculated allowance transfer which exceeds 49,000 allowances, this would result in a transfer of wealth of $24.5 million dollars annually. [EPA-HQ-OAR-2009-0491-3933[1].1, p.5]
New York  
New York provides another example of this disparity. For example, compare a typical coal unit (Huntley Station) and a natural gas combined cycle unit (Poletti Station in New York City). The following graph shows a comparison of actual emissions to the allocations that would occur in each of EPA's preferred methods; the original July NODA (projected emissions), Option 1 (Heat Input) and Option 2 (Modified Heat Input). [EPA-HQ-OAR-2009-0491-3933[1].1, p.5] 
The Huntley facility is a coal fired station which has made significant emission reductions of both NOx and SO2 over the baseline period (2003  -  2009). During this baseline period the facility switched from bituminous coal to low sulfur Powder River Basin coal, installed selective non catalytic reduction technology to control NOx, and dry sorbent injection and fabric filter baghouses to reduce SO2, particulate, and HAP emissions. Even though annual emissions of SO2 have been reduced by 73%, annual NOx by 52% and ozone season NOx by 51%, the heat input based allocations of NOx and SO2 under options 1 and 2 fall far short of 2009 actual emissions. [EPA-HQ-OAR-2009-0491-3933[1].1, p.5]  
The graph reveals the combined cycle natural gas facility, with similar annual heat input, will receive SO2 allocations under Option 1 in excess of 250 times its actual emissions and in the case of annual NOx, more than 4 times its permit cap. As noted in the Louisiana example, the coal unit would have to buy allowances from the oversubscribed natural gas unit. In contrast, the July approach provides a reasonable allocation for both facilities: the gas unit receives all allocations needed to operate and the coal unit is still short and can make decisions on how to comply. [EPA-HQ-OAR-2009-0491-3933[1].1, p.5] [[See Docket Number EPA-HQ-OAR-2009-0491-3933[1].1, p.6 for the graph.]]
Delaware  
This concern is equally compelling when looking at the Indian River Generating Station, Unit 4 located in Millsboro Delaware. The four unit facility has retired one unit with two additional unit retirements planned for 2011 and 2013 leaving only Unit 4 in operation. The facility has invested over $360M in capital for the addition of an SCR to control NOx, a circulating dry scrubber and a fabric filter (baghouse) to reduce SO2, particulate, and HAP emissions. For Indian River, the allocation differential between the July approach and Option 1 is 1,238 tons representing and estimated $2.5 million dollars annually.  [EPA-HQ-OAR-2009-0491-3933[1].1, p.6]
Beyond New York, Delaware, and Louisiana, looking at the aggregation of all CATR states, this transfer of wealth is profound. Comparing the July projected method to Option 1, coal units would lose an estimated 199,679 allowances at a value of $99,839,500 annually. The latter represents an annual transfer of wealth or windfall to gas generation owners.  [EPA-HQ-OAR-2009-0491-3933[1].1, p.6]
An unfair allocation that provides windfall profits for one sector and at the same time excessive compliance burden to others is in conflict with the Clean Air Act, CATR, and recent mandates for fair policy and regulation that do not impede economic recovery.[EPA-HQ-OAR-2009-0491-3933[1].1, .6]
Progress Energy Service Company
Although the allocations for certain units increase under Options 1 and 2. those increases are overwhelmed by significant decreases at other units. A case in point involves Progress Energy's Crystal River Units 1 and 2 (ORIS Code 628). The SO2 allocations for these units decreased by 85 percent for Option 1 and by 78 percent for Option 2 when compared with the original draft allocations. These coal-fired units are currently unscrubbed, and it is impossible to install controls on them during the early years of the program. The loss of from 22,000 to 24,000 SO2 allowances, depending on the option, would have to be made up mainly through allowance purchases. [EPA-HQ-OAR-2009-0491-4011[1].1, p.4]
Vectren Corporation 
Vectren was able to completely reproduce the allocations to its units under Option 1. By contrast, the assumptions used to calculate the reasonably foreseeable maximum emissions constraint in Option 2, particularly the support for the maximum hourly heat input attributed to each unit, are not clear from the technical support material provided in the NOOA and Vectren was unable to reproduce these numbers by any means or by using the unit data included in the NEEDS IPM v4.1 O. The maximum hourly heat inputs assumed in the technical support documents exceed the Vectren units' operating capacities. Additionally, the 'clean S02 and NOx input rates' are lower than historic operating capabilities. The rates are BACT level, and can not necessarily be attained at existing units, even well-controlled units, without significant modifications. For example, EPA's assumptions around the efficiencies of an FOO scrubber system fail to take into account that the scrubbers on AB Brown Units 1 and 2 are the original scrubbers constructed with the units (1979 and 1986, respectively). The two AB Brown scrubbers are two of the few remaining dual alkali scrubbers currently in operation, and they are not capable of achieving the efficiency assumptions ascribed to scrubbed units in the model. In reality, the dual alkali scrubbers at AB Brown Units 1 and 2 are capable of achieving an average S02 removal efficiency of80-85%, instead of the assumed efficiencies of 87.7% (AB Brown Unit I) and 95.3% (AB Brown Unit 2) in the NEEDS database. [EPA-HQ-OAR-2009-0491-3923[1].1, pp.3-4]
Wisconsin Public Service Corporation (WPSC)
In particular, WPSC is concerned that the proposed unit average heat input calculation method is not representative for Weston Unit 4 (ORIS ID: 4078) by not characterizing operation in 2008 for which only 6 months of emission data were reported. During this startup year, the annual capacity factor was only 22.5%, in large part because it operated in only 6 months in 2008. In 2009,the unit had its first full year of operation. Emission data was reported for 12 months and the annual capacity factor was 64.7%. In 2010, Weston Units 4's second full year of operation, the annual capacity factor was 72.7%. Please see the operating summary below in Table 1.  [EPA-HQ-OAR-2009-0491-3994[1].1, pp. 1-2; see 3994.1, p. 2 for Table 1. Weston Unit 4 Operating Data 2005-2010]
In the NODA allowance allocation method, Weston Unit 4's unit level average of the 3 year highest annual heat input is determined by averaging the heat input values from 2 years of heat input data: 2008 and 2009. The heat input in 2008 and 2009 is not representative of normal unit operation due to unit startup and testing. The data from 2010 is more representative of the way this unit will operate but still less than the longterm projected capacity factor of 75 percent. [EPA-HQ-OAR-2009-0491-3994[1].1, p. 2]
We request that the methodology for the calculation of Weston Unit's 4 average heat input be altered so that partial reporting years are not included in the baseline data. For new units, such as Weston 4, the most recent available data from years with fulltime operation should be used - in this case, 2009 and 2010. If 2010 data cannot be used, then the unit heat input should be based on the one year with 12 months of reported data (2009). [EPA-HQ-OAR-2009-0491-3994[1].1, p. 2]
Response: 
EPA has finalized a heat input based allocation methodology that limits unit level allocation to levels that do not exceed emissions during a historic emission baseline period.  See discussion in section VII.D for why EPA chose this approach and how it addresses concerns expressed by commenters.  In this final allocation methodology, EPA uses a 2006-2010 heat input baseline.  Because final approach the highest three years, those units who expressed concern about pre-2008 annual data not being complete because the particular unit only reported for ozone season would still have three full years worth of data (2008, 2009, 2010) with this new baseline.  Additionally, EPA updated its heat input and emissions data used in the allocation tables based on data presented in comments.  The final approach does not rely on technology specific capacity factors to which some commenters had expressed concerns.
Organization: North Carolina Electric Membership Corporation
Comment: 
North Carolina Electric Membership Corporation
The twelve electric generating units located at Anson (Oris Code 56249) and the ten units located at Hamlet (Oris Code 56292) would be regulated by the EPA's proposed Clean Air Transport Rule ("Transport Rule") for SO2 and NOX emissions. These units have incorrect/missing MW capacity and Btu/kWh heat rate information in the Option #2 underlying data. Each unit should have a listed 28.3 MW capacity and 4980 Btu/kWh heat rate under columns BP and BQ, respectively. Although these values are not used in the calculations, we would like these values added/corrected for the record. [EPA-HQ-OAR-2009-0491-4001[1].2, p.1]
[An Excel spreadsheet can be found in the comment attachment, 4001.1.]
Response: 
EPA did not finalize option 2 from the January 7, 2011 NODA in the Transport Rule.  It uses a methodology that is described in section VII.D of the preamble. That methodology does not rely on capacity and heat rate information, and thus the corrects listed above would no longer directly enter the formula used to determine a units allowance allocation.  Section VII.D of the preamble describes the final allocation methodology under the Transport Rule FIP.
Organization: Prairie State Generating Company, LLC
Comment: 
Prairie State Generating Company, LLC
The size of the NUSA budget is of critical importance to PSGC since these units were designed, permitted, funded and began construction under regulations which provided adequate allowances for them to operate. PSGC expects to operate these extremely efficient units at a 90%+ annual capacity factor and at nearly 100% capacity during the ozone season once in normal routine operations. Although the NUSA was already underfunded for known new units in Illinois as originally proposed in the Transport Rule, this most recent NODA will exacerbate the underfunding problem in Illinois' NUSA, leaving PSGC with only 33%- 38% of the allowances needed to operate once both units are fully operational under either of the currently proposed alternatives. [EPA-HQ-OAR-2009-0491-3897[1].1, p.4]
Moreover, EPA even acknowledges that the allocations identified in this NODA are not final and are only approximations. 76 F ed.Reg. 1109, 1111. Therefore, the 'data' that are 'available' are not final and do not really provide a basis for more than approximate comments on that data, since the data themselves are only approximations. [EPA-HQ-OAR-2009-0491-3897[1].1, p.7]
Response: 
Organization: Rochester Public Utilities (RPU)
Comment: 
Rochester Public Utilities (RPU)
b. The underlying unit-level data:
o RPU reviewed the underlying data used in the allocation calculation for RPU units Silver Lake Plant Unit 4, Cascade Creek CT2 and Cascade Creek CT3. This data appears to be accurately represented with the exception of the generation capacity of CT2 and CT3. In the Option 2 underlying data tab of the "Updated Alternative allocation tables and underlying data - Jan. 7, 2011" document ID EPA-HQ-OAR-2009-0491-3875, the generation capacity for CT2 and CT3 are incorrectly listed as 28 and 48 MW, respectively. CT2 and CT3 are combustion turbine engines used for operating a single generator, CAMR Generator ID 2. This generator has a generation capacity of 49.9 MW. [EPA-HQ-OAR-2009-0491-3998[1].1, p.2]
Response: 
Generating capacity is not used in the allocation methodology finalized for Transport Rule.  See section VII.D of the preamble for more description of the final allocation approach.
Organization: San Miguel Electric Cooperative, Inc.
Comment: 
San Miguel Electric Cooperative, Inc.
[See Attachment - Coal Units - at the end of this comment letter (30 pages).]
Response: 
EPA has finalized an allowance allocation methodology based on historic heat input, but limited to maximum historic emission levels.  See section VII.D for a more detailed explanation of the allocation methodology.
Organization: Southern Company
Comment: 
Although the unit ID errors identified in the proposed Transport Rule appear to be correct in the NODA3, data flaws still exist. Below are specific examples of flaws that we identified. However, due to having only 30 days to review the data, other errors may still be present in NODA3.
:: The 2004 ozone season historical NOx emissions are incorrect. This is perhaps due to EPA pulling information from the CAMD database by program, i.e., the NOx SIP Call. In 2004, seasonal NOx compliance started on May 31, rather than May 1. EPA should use data from the entire ozone season, not just the data when the seasonal NOx program began.
:: There are some unit-level heat input errors for units sharing a common stack. For example, in 2009 Branch Unit 1 heat input is over by 26,484 while Branch unit 2 is under by 26,482. Overall, Plant Branch as an entire facility is approximately correct. There are similar errors in seasonal heat input for 2007-2009 for Plants McDonough and Yates.[EPA-HQ-OAR-2009-0491-3946[1].1, p.10]
Response: 

EPA used its best available data when it issued the January 7, 2011 NODA containing allocations under alternative methodologies and underlying heat input.  Commenters had the chance to review and submit corrected data which EPA considered and made updates to the underlying data where appropriate.  Additionally, EPA modified its approach for determining ozone-season emissions in the final allocation tables by using data from the five ozone-season months instead of data reported under the ozone-season for that year.  Therefore, the 2004 ozone season emissions in the final allocation tables include the emissions from the month of May (even though it was not considered part of the ozone-season at that time) and the first concern expressed above is no longer an issue in the final allocation tables.  Furthermore, EPA notes that this adjustment in the final allocation tables has little or no impact on most units.  The 2004 ozone-season emissions value is only factored into the final allocation if: 1) it was the highest year for ozone season emissions at a particular unit over the eight year baseline period, and 2) if the unit's initial heat input allocation was exceeding its historic maximum level.

In regards to the second bullet in the comment above, EPA has made this correction in the final allocation tables.  However, it notes that the change has no impact on total allocations to the facility.
Organization: Southern IL Power Cooperative
Comment: 
Southern Illinois Power Cooperative believes the NODA proposal unfairly treats plants that had added BACT prior to EPA's current proposal.  Plants that initiated the capital expense to reduce emissions earlier experienced higher generation costs, and, in today's power marketing scheme, would have been called upon for power later, as opposed to plants that didn't have the added expense of pollutions control equipment and have the capital expenses  calculated into the price of their power.  Thus, generated megawatt sales and the associated heat inputs for the early BACT plants will be lower than those who did not add pollution control equipment.  In addition, financial gains were seen by those who did NOT add pollution control equipment.  Under this rule, such facilities that did NOT add pollution control equipment are rewarded with more NOX & SOX allowances from higher heat input AND enjoy the additional financial improvement from selling more power over the years to now help finance (BACT) pollution control equipment.  The Heat Inputs for "controlled plants" should be raised, while the Heat Inputs for "uncontrolled" plants should be lowered to adjust for the inequity described above. [EPA-HQ-OAR-2009-0491-3901[1].1, pp.2-3]
Response: 
See section VII.D of the Transport Rule preamble for a description of the final allocation methodology under the Transport Rule FIP.  EPA disagrees with the commenter's characterization of the impacts of the final Transport Rule's allocation methodology.  FIP allowance allocations to existing units are largely based on historic heat input, which is neutral to a unit's historic choice of fuel or pollution control technology.  The commenter is effectively requesting that EPA adjust the Transport Rule's allocation methodology to compensate specific unit owners' prior investments in pollution control equipment; however, such investment was in many instances required by other state or federal environmental regulations.  EPA does not believe this kind of data adjustment would be appropriate considering the other potential legal and regulatory requirements leading to pollution control retrofit decisions at specific units.  Furthermore, EPA disagrees with the validity of the commenter's requested data adjustments even if EPA were to accept the premise of the adjustments.  EPA notes that under market-based programs already in place during this historic baseline period, all covered units would face the marginal price of emitting (as reflected by the market value of an allowance), and thus units which installed pollution controls would have a lower emission cost impact to factor in to their dispatch bids than uncontrolled units.  The commenter's assertion that pollution controls negatively affect unit dispatch ignores this positive side of the dispatch equation under existing market-based emission trading programs.   As a result, EPA finds the requested adjustments to be incorrect and inappropriate for the purpose of allowance allocations to existing units under the final Transport Rule.
Organization: West Virginia Department of Environmental Protection
Tenaska, Inc.
Comment: 
Tenaska, Inc.
Tenaska has reviewed the unit level heat input data and resulting projected allocations provided on the EPA website and finds no significant discrepancy from its own data and calculations. [EPA-R03-OAR-2010-1027-DRAFT-0005.1[1], p.2]
West Virginia Department of Environmental Protection
Underlying unit-level data and resulting allocations for the alternative methodologies
The WVDAQ supports the use of the most current continuous emissions monitoring system (CEMS) data available from EPA's Clean Air Markets Division ( CAMD) as the basis for the allocations. [EPA-HQ-OAR-2009-0491-4000[1].1, p.2]
Response: 
EPA is finalizing a historic heat input methodology for allocation of emissions allowances under the FIP.  This approach is analogous to "option 1" in the January 7, 2011 NODA.  See final rule preamble section VII.D for further of discussion EPA's rationale for this approach and response to comments in favor of and in opposition to this approach.
Organization: Westar Energy, Inc.
Comment: 
Westar Energy, Inc.
Westar's concerns about Options 1 and 2 reliance on historical data arise in light of the recent consent decree between Westar and EPA in United States v. Westar Energy, Inc., Civil Action No. 09-CV-2059 JAR/DJW ('consent decree'). That decree set maximum emissions levels for Westar's three Jeffrey Energy Center ("JEC") units combined for both NOx and SO2. As an example, under some conditions the consent decree sets maximum SO2 emissions level of 6600 t/y for all three JEC units combined, yet Options 1 and 2 propose an allowance greater than that for each unit separately, which translates on a combined basis to more than triple the consent decree maximum. [EPA-HQ-OAR-2009-0491-3952[1].1, p.2]
For NOx Annual, under some conditions the consent decree places a 12,400 t/y limit for all three JEC units combined by 2014, and 9,600 t/y by 2016. Options 1 and 2 allocate over 6,000 t/y to each unit, for a combined total that is about 50% more than the consent decree maximum. [EPA-HQ-OAR-2009-0491-3952[1].1, p.2]
Response: 
EPA has finalized an alternative allocation methodology slightly different than those described in the January 7, 2011 NODA.  See section VII.D for a description of this final allocation methodology.  EPA notes, that while it did updates its modeling to reflect consent decrees, unit specific allocations are determined purely on historic data and are not limited by permit and or consent decree requirements.  However, those emission limits will still apply regardless of the unit's allocation under Transport Rule, extra allowances would be sold or retired
Organization: Western Farmers Electric Cooperative (WFEC)
Comment: 
Western Farmers Electric Cooperative (WFEC)
It appears that data from three of WFEC's units (Anadarko unit 4, 5, and 6) was not included in EPA's Acid Rain database because these units were exempt from Acid Rain in the past and was further complicated because Oklahoma was one of the few states that were not included in CAIR but are now included in CATR.  Not having had this data in the original data bases has obviously resulted in no allocations for these three units.  Your help in resolving this unique problem will be greatly appreciated!  [EPA-HQ-OAR-2009-0491-3945[1].1, p.1]
Anadarko units #4, 5 and 6  -  These units have been completely overlooked and are not included in the allocation database.  During recent telephone conversations, I understand how this oversight might have occurred.  All three of these units have been exempt from acid rain reporting and are not included in the CAMD database used in this proposal; however, this results in the CATR Allocation Database being incorrect.  This should be corrected by using data from other sources such as the Oklahoma Emission Inventory if these units are to be included in CATR.  [EPA-HQ-OAR-2009-0491-3945[1].1, p.3]
Anadarko #9  -  11- There is limited data available for these three units as they began operation in mid - summer of 2009.  WFEC would like to suggest that the annual emissions be prorated for a full year  to determine the allocations for these three units. [EPA-HQ-OAR-2009-0491-3945[1].1, p.3]   
Anadarko units #1 and #2  -  These units have not been given allowances in the CATR Allocation Database.  Units #1 and #2 are very small units (15 MW) are therefore exempt from acid rain; therefore, allowances have not been provide.  WFEC would request allowances be provided for these units in the future if CATR is applicable to these small units. [EPA-HQ-OAR-2009-0491-3945[1].1, pp.3-4]    
Hugo unit #1  -  This unit is the only coal unit in the state of Oklahoma that already has installed low NOx burners and can achieve emission rates below 0.26 lb/mmBTU.  The other utilities have coal units that are allowed to meet emission rates much higher (0.286 lb/mmBTU) than WFEC's Hugo plant limit of .179 lb/mmBTU.  EPA's proposal fails to recognize units and the electric consumer who have borne the higher electricity costs because they must pay for existing, expensive emission controls. [EPA-HQ-OAR-2009-0491-3945[1].1, p.4]
Response: 
EPA has updated its allocation tables for the final Transport Rule, and they now include Anadarko units 4,5, and 6.  Additionally, it has updated its baseline to 2006-2010 for historic heat input, which addresses some of the commenters concern about Anadarko units 9-11 having only partial data for 2009.

XX.A.3. Unit-level Comments on Applicability (e.g., Remove or Add Unit to Inventory of Potential Existing Units)

Organization: Alcoa Power Generating Inc. - Warrick Power Plant
Comment: 
Alcoa Power Generating Inc. - Warrick Power Plant
1.) This NODA specifically invites comment regarding existing units listed in the initial Clean Air Transport Rule (CATR) that should not have been included. The CATR, as proposed, specified that the proposed rule would be applicable for electricity generating units producing electricity for sale. APGI consists of units 1-4. Units 1-3 are industrial boilers that produce electricity, steam, and hot process water for the· Alcoa Inc. - Warrick Operations primary aluminum smelter and aluminum fabrication plant. Electricity produced by these units is used for the exclusive use of Alcoa Inc., and is not sold on the grid. Unit 4 is jointly owned by APGI and Vectren. 50% of the electricity produced by this unit is sold to the grid, so it will be subject to the CATR. APGI requests that Units 1-3 be removed from the list of existing potential units, since they do not sell to the grid. [EPA-HQ-OAR-2009-0491-4024, p.1]
Response: 
As suggested by commenter, Warrick Units 1-3 are not included in the final list of existing potential Transport Rule units.  Sources should see section VII.D of the preamble for a description of how this list was developed.
Organization: Ameren Services Company
Comment: 
Ameren Services Company
EPA on page 1112 of the Federal Register Notice states 'In particular, if the unit was retired or in cold storage in 2010 or is a steam turbine at a combined cycle (CC) plant, then it was not included as a unit in the list of potential existing Transport Rule Units.' EPA may have inadvertently omitted some heat input by generalizing that all CC plants have only a turbine on the steam side of the generation. In many cases these CC plants also include Duct Burners that supplement the heat generated by the gas turbine. Has EPA arbitrarily omitted the heat input from these Duct Burners by eliminating the steam turbine part of the plant? [EPA-HQ-OAR-2009-0491-3894[1].1, p.1]
Response: 
The heat input values were used in their entirety, as reported, for allocations under the final Transport Rule.  No heat input has been omitted, the omissions references above reference an accounting of units corrections where an entity was reporting as one unit, but disaggregated into two units for modeling purposes.  However, the heat input would not change. 
Organization: Cogentrix Energy, LLC
Comment: 
Cogentrix Energy, LLC
Cogentrix has found conflicts in definitions of applicability between the proposed Transport Rule and the Acid Rain and CAIR Rules that have resulted in the exclusion of our two Virginia facilities from receiving allocations in the draft Rule. Cogentrix has reviewed proposed allocations listed in EPA's Technical Information for the Transport Rule, revised January 7, 2011. Cogentrix-owned sites in Hopewell, VA (ORIS Code 10377) and Portsmouth, VA (ORIS Code 10071) were not included in 'Altemative allocation tables.pdf.' Both sites operate with two 'three-on-one' boiler to generator designs, where three boilers provide steam to one 55-MWe electric generator. The Transport Rule provides applicability requirements listed under Title 40 Code of Federal Regulations 97.404(a)(J) as follows:
The following units in a State shall be TR NOy Annual units, and an source that includes one or more such units shall be a TR NOx Annual source, subject to the requirements of this subpart: Any stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine serving at any time, since the later of November 15, 1990 or the start-up of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe producing electricity for sale. [EPA-HQ-OAR-2009-0491-3916[1].1, pp.1-2]
Since the 'generator. .. nameplate capacity' for each generator (emphasis added) at each site is greater than 25 MWe, Cogentrix sites are included within the scope of the Transport Rule and therefore allocations for each site should be assigned. Cogentrix also reviewed EPA's Technical Information file entitled 'BADetailData.xls.' The analysis shown in this file appears to use the definition of applicability taken from the Acid Rain rules, where 'units' (interpreted to be boilers) with a capacity of less than 25 MWe are not included within the scope of the Acid Rain rule. Both Cogentrix facilities opted into the Acid Rain Program in 2008, and should have been included in EPA's allocation analysis on that basis alone. Both Cogentrix facilities have also participated in the CAIR program since its inception and likewise, should have been included in EPA's allocation analysis on that basis alone. [EPA-HQ-OAR-2009-0491-3916[1].1, p.2]
Because both units meet the applicability definition in the proposed Transport Rule, Cogentrix has conducted an analysis of allocations and required reductions from 2005 baseline emissions data using the methodology discussed in the preamble of the proposed rule. The calculation methodology is presented in Attachment 1 and the results are presented in Table 1. [EPA-HQ-OAR-2009-0491-3916[1].1, p.2] [[See Docket Number EPA-HQ-OAR-2009-0491-3916[1].1, p.2 for Table 1.]]
Cogentrix reiterates its request that EPA include the Cogentrix-owned sites in Hopewell, VA (ORIS Code 10377) and Portsmouth, VA (ORIS Code 10071) in the Transport Rule's Allocation Analysis. [EPA-HQ-OAR-2009-0491-3916[1].1, p.3]
Response: 
As suggested by commenter, Hopewell and Cogentrix Units are included in the final allocations tables as potentially covered Transport Rule units and have allocations based on the methodology laid out in section VII.D of the preamble. 
Organization: Connecticut Department of Environmental Protection
Comment: 
Connecticut Department of Environmental Protection
In Attachment B of CTDEP's September 30, 2010 comments on the proposed Transport Rule (see Appendix 1 to this letter), CTDEP requested the following: [[See Docket Number EPA-HQ-OAR-2009-0491-3884[1].1, pp. 4-8 for Appendix 1.]]
-That Norwich be removed from the Transport Rule Allocation Table as the unit has a nameplate capacity less than 25 MWe and therefore does not meet EPA's proposed Transport Rule applicability criteria. [EPA-HQ-OAR-2009-0491-3884[1].1, p.2]
-That the qualification requirement date for solid waste incineration units be changed to a more recent year, such as 2002. If EPA changes the qualification requirement date and if Exeter Energy (Exeter) is determined to combust 'solid waste,' it is CTDEP's understanding that Exeter would be considered a solid waste incineration unit and would not be subject to the Transport Rule.
-That the Pratt & Whitney cogeneration unit be removed from the Transport Rule Allocation Table as the annual data since 2003 show that Pratt & Whitney has consistently sold energy in amounts less than the 219,000 MWh cogeneration exemption threshold. [EPA-HQ-OAR-2009-0491-3884[1].1, p.3]
CTDEP again requests EPA to take action to remove Norwich and Pratt & Whitney from the existing unit list and to remove Exeter from the existing unit list if EPA changes the qualification requirement date for solid waste incineration units and if Exeter is determined to combust 'solid waste'. [EPA-HQ-OAR-2009-0491-3884[1].1,p.3]
Response: 
Connecticut was not determined to be a contributing state in the final Transport Rule.  Therefore, the state and units located in the state are not subject to the final Transport Rule.
Organization: Consolidated Edison Company of New York, Inc, (CECONY)
Capital Power Corporation
Kentucky Division for Air Quality
DTE Energy Services (DTEES)
Nelson Industrial Steam Company (NISCO)
Comment: 
Capital Power Corporation
1. The Portside Energy facility (ORIS No. 55096) is listed in and allocated emissions to in the NODA. The facility is a cogeneration unit and sells all the electricity (and steam) to the host facility. It does not sell any power to the grid. It appears to us that it should be exempted. EPA needs to clarify whether it is exempt from CATR. [EPA-HQ-OAR-2009-0491-3930 ,p.1]
2. We have several questions regarding the Morris Cogeneration facility (ORIS No. 55216).
a. In the original proposal, it was correctly identified as the "Morris Generation Facility". In the January 7, 2011 NODA database, it was listed as the "Aera (sic) South Belridge Cogen Facility." That is incorrect and we have no idea why it was so termed. This needs to be corrected in the database.
b. The Morris Cogeneration is and has always been a cogeneration facility. It appears to us that it should be exempted EPA needs to clarify that it is exempt from CATR. [EPA-HQ-OAR-2009-0491-3930, p.1]
3. We have several questions regarding Capital Power's CPI USA North Carolina, LLC  -  Roxboro facility (ORIS No. 10379), which is listed by a former name, EPCOR USA NC Roxboro, in the database.
a. The facility is a Qualifying Facility (QF) small power producer that burns greater than or equal to 75 percent non-fossil fuels. It was also a former QF cogeneration facility that lost its steam host but retains the capability to cogenerate. EPA needs to clarify whether it is exempt from CATR.
b. If the biomass portion of the fuel is removed from the equation, the resultant total generation capacity would be less than 25 Megawatts (MW). EPA needs to clarify whether it is exempt from CATR.
c. .The facility has 3 combustion units that exhaust to one stack and serve a single steam turbine generator. Even including biomass, each unit cannot generate 25 MWs. EPA needs to clarify whether it is exempt from CATR. [EPA-HQ-OAR-2009-0491-3930, p.1]
4. Capital Power's CPI USA North Carolina, LLC  -  Southport facility (ORIS No. 10378), which is listed by a former name, EPCOR USA NC Southport, in the database is a cogeneration facility.
a. The facility is a Qualifying Facility (QF) cogeneration facility that burns a significant portion of non-fossil fuel. EPA needs to clarify whether it is exempt from CATR.
b. The facility has 6 combustion units that exhaust to two stacks and serve two steam turbine generators. Even including the non-fossil fuels, each unit cannot generate 25 MWs. EPA needs to clarify whether it is exempt from CATR. [EPA-HQ-OAR-2009-0491-3930, p.1]
5. The EF Kenilworth facility in Kenilworth, NJ (ORIS No. 10806) is not listed in the database and was not subject to the Clean Air Interstate Rule (CAIR). Its generation capacity is less than 25 MW. We do not believe CATR would apply to this facility.. EPA needs to clarify that it is exempt from CATR. [EPA-HQ-OAR-2009-0491-3930, .1]
Consolidated Edison Company of New York, Inc, (CECONY)
The Allocation Table associated with the subject NODA lists three Con Edison-owned units at its 74th Street Steam Station that do not operate as electric generating units ('EGUs'). Specifically, the units shown in the table below (data taken from the Allocation Table) do not generate electricity but only provide steam to the Company's district steam system. [EPA-HQ-OAR-2009-0491-3910[1].1, p.2] [[See Docket Number EPA-HQ-OAR-2009-0491-3910[1].1, p.2 for the above referenced table.]]
Notwithstanding their non-electric generating operation, these units would be considered 'Transport Rule units', as defined in Section IV.A of the NODA, which states the following:
Under the proposed Transport Rule, a covered Transport Rule unit is generally any stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine located in a proposed Transport Rule state and serving at any time, since the later of November 15, 1990 or the start-up of the unit's combustion device, a generator with a nameplate capacity greater than 25 MWe producing electricity for sale. [EPA-HQ-OAR-2009-0491-3910[1].1, p.2]
These three units at the Company's 74th Street Steam Station did generate electricity between April 26, 1962, and December 31, 1999, and, based on EPA's definition in the NODA, would be subject to the CATR. However, because these units have not generated electricity in more than 11 years, including the baseline period chosen by EPA - 2005 through 2009 - for establishing allowance allocations, Con Edison believes these units should be exempt from participation in the CA TR, which would obviate the need for their receipt of allowance allocations. [EPA-HQ-OAR-2009-0491-3910[1].1, p.2]
DTE Energy Services (DTEES)
DTEES supports the revised definition of existing unit to include any facility that began commercial operation before January 1, 2009, thereby making any facility that began on or after that date a new unit.  New units would receive allowances from the State's new-unit set-aside pool. By setting January 1, 2009 as the delineation between new/existing units EPA should give repowered facilities the opportunity to receive allowances at a level that reflect current, not historical, operation. [EPA-HQ-OAR-2009-0491-3950[1].1, p.1]
DTEES also believes EPA should expand the definition of new units to include those that have recently been redeveloped or repowered with a renewable fuel that is different than what was used when their original commercial operation commenced. Excluding such repowering projects from the new unit definition and in turn its ability to obtain allowances will likely cause significant economic hardship to these projects and in turn present a disincentive for continuing with such investments. [EPA-HQ-OAR-2009-0491-3950[1].1, p.2]
DTE Stoneman, Cassville, WI, ORIS code 4146. The facility consists of two 340 mmbtu/hr rated boilers serving through cross connected steam headers, 33 MW and 18 MW generators. Emissions are through a combined stack. [EPA-HQ-OAR-2009-0491-3950[1].1, p.2]
This facility is subject to the Acid Rain program and CAIR. The two units were originally built in 1949 and 1951 and designed to burn coal. DTEES purchased the facility in May 2008. Prior to the purchase, the previous owner operated the plant intermittently, selling the electricity through the Midwest Independent System Operator (MISO) at market rates. After the facility was purchased by DTEES, the units were operated intermittently to burn down the remaining coal pile in preparation for the conversion from coal to wood biomass firing. The remaining coal pile was depleted in March 2009. The facility was shut down during the March 2009 to August 2010 period while it was modified to be repowered burning 100% woody biomass. The facility will sell all of the renewable electrical output while firing woody biomass to one customer under a power purchase agreement. The facility declared the commissioning period that began July 28, 2010 completed on October 8, 2010. The customer was also notified of the electric delivery start date (commercial operation date) under the power purchase agreement. We believe the historical coal-fired operations are not indicative of future operations burning woody biomass. [EPA-HQ-OAR-2009-0491-3950[1].1, pp.2-3]
EPA should expand the definition of new units to include those that have recently been redeveloped or repowered with a renewable fuel that is different than what was used when the original commercial operation commenced. For example, the units at DTE Stoneman began commercial operation in 1949 and 1951 combusting pulverized coal. Prior to DTEES purchasing the units, they were underutilized as coal units and not economically viable to operate. This resulted in low historic heat input compared to the potential heat input that is expected while burning woody biomass. [EPA-HQ-OAR-2009-0491-3950[1].1, p.3]
Kentucky Division for Air Quality
As for the proposed Transport Rule (75 FR 45210), the below comment remains relevant to the January 7, 2011 NODA since the Calvert City Cogeneration unit (26 MWe turbine - ORIS - 55308-Genl) should be examined to determine its applicability for the Transport Rule and the existing unit allowance allocations. Therefore, the Division requests that EPA contact and work with the Division to properly determine the Calvert City Cogeneration turbine's status pursuant to the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3970[1].1, p.2]
As for the proposed Transport Rule (75 FR 45210), the below comment remains relevant to the January 7, 2011 NODA since the Calvert City Cogeneration unit (26 MWe turbine - ORIS - 55308-Genl) should be examined to determine its applicability for the Transport Rule and the existing unit allowance allocations. Therefore, the Division requests that EPA contact and work with the Division to properly determine the Calvert City Cogeneration turbine's status pursuant to the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3970[1].1, p.3]
Pursuant to the proposed Transport Rule Preamble Section V.D.4.b.(I), the Calvert City Cogeneration EGU (turbine - ORIS - 55308-Genl) as shown in EPA's Technical Support detailed allocation file (BADetailedData.xls, Units Characteristics Worksheet) should indicate a capacity of 26 MWe instead of 23 MWe as is listed. This cogeneration EGU was part of the NOx SIP Call NOx ozone season trading program and was brought into the CAIR NOx ozone season program. However, the unit was exempted from the CAIR NOx annual program since it met the CAIR NOx annual program cogeneration exemption. Even with the CAIR ozone season cogeneration exemption, the unit was subject to the CAIR NOx ozone season trading program since it was previously subject to the NOx SIP Call NOx ozone season program, which did not provide a cogeneration exemption. For the Calvert City Cogeneration EGU, the Division requests that EPA work with the Division to: (1) verify that the unit is exempt from the proposed Transport Rule NOx annual trading program pursuant to the cogeneration exemption; and (2) determine whether the unit is subject to the proposed Transport Rule NOx ozone season trading program given that the unit was first subject to the NOx SIP Call ozone season trading program. [EPA-HQ-OAR-2009-0491-3970[1].1, p.3]
Nelson Industrial Steam Company (NISCO)
These units meet the definition of cogeneration unit and are exempt under the Acid Rain program. However, they do not meet the proposed efficiency standard to meet the definition of cogeneration unit under the proposed CATR. NISCO reiterates its prior comments requesting that EPA exempt the NISCO units from CAIR as they have not sold electricity to the grid for a number of years, and have never sold more than 1% of their potential electrical output to the grid. [EPA-HQ-OAR-2009-0491-4026, p.4]
Response: 
These units are currently being left in the list of potential existing Transport Rule units that receive final allowance allocations.  However, EPA notes that the inclusion of such units in no way suggests that EPA has made a determination about the applicability of the proposed Transport Rule to any unit.  EPA is including the units in the allocation tables finalized for the Transport Rule because based on its best available data and that submitted by the commenter, the sources' applicability status is unclear.  Therefore, EPA is including the unit so that it has allocations in the event that it a covered Transport Rule unit.  If the unit is subsequently determined not to be subject to the final Transport Rule, than EPA has established procedures for taking back any allocated allowances.  Therefore, their inclusion in the list of potentially covered Transport Rule units reflects a conservative approach by EPA to guard against the possibility of the units being subject to the Transport Rule without having any allowance allocation. 
Organization: Edison Mission Energy (EME)
Comment: 
Edison Mission Energy (EME)
EME's Waukegan 6 (Boiler 17) unit should have been included in EPA's list of potential existing Transport Rule units provided in the Transport Rule NODA.
Since the Transport Rule proposes unit level allocations for non-operating units in the six years post retirement and Waukegan 6 (Blr. 17) was not retired until late 2007, it should receive allocations in 2012 and 2013. [EPA-HQ-OAR-2009-0491-3953[1].1, p.3]
EME submits that EPA improperly excluded Waukegan 6 (Blr. 17) from its list of existing units in the Transport Rule NODA. Waukegan 6 (Blr. 17) should have been included pursuant to the Transport Rule applicability provisions because Waukegan 6 (Blr. 17) was not retired until late 2007. Since the Transport Rule proposes unit level allocations for nonoperating units in the six years post retirement, Waukegan 6 (Blr. 17) would receive allocations under the Transport Rule applicability provisions in years 2012 and 2013. Waukegan 6 (Blr. 17) was included as an existing Transport Rule unit in the Transport Rule proposal. The agreement between Midwest Generation and IL EPA (described in III.B above), required Waukegan 6 (Blr. 17) to be shutdown. Since, Waukegan 6 (Blr. 17) is entitled allocations in 2012 and 2013 under the Transport Rule applicability provisions, EME submits the following data needed to perform the calculations under the two methodologies proposed in the Transport Rule NODA. [EPA-HQ-OAR-2009-0491-3953[1].1, pp.23-24] [[See Docket Number EPA-HQ-OAR-2009-0491-3953[1].1, p.24 for the data tables.]]
EME's Waukegan 6 (Blr. 17) unit should have been included in EPA's list of potential existing Transport Rule units provided in the Transport Rule NODA. [EPA-HQ-OAR-2009-0491-3953[1].1, p.25]
Response: 
See section VII.D of the preamble for a description of how EPA determined its list of potentially covered existing Transport Rule units to which it allocates allowances.  This final list is also given in the Technical Support Document for Allowance Allocations.  As described in each of these documents, EPA looked at units reporting as "operating" in 2010 as an initial filter for developing this list.  Units that were listed as retired or in long term cold storage were not considered as potential existing Transport Rule units, and do not get, nor is its EPA intention, to allocate to these units.  The provisions cited by the commenter only apply to units that are considered existing Transport Rule units and that subsequently retire.  The provisions do not apply to units that retired, for example, in 2007.  The temporary continued allocation to Transport Rule units upon their retirement.
Continuing temporary allocations to Transport Rule units that retire has the benefit of reducing the incentive to keep units in operation that should otherwise be, for instance, permanently retired due to age and inefficiency.  There is clearly no such benefit from extending this provision to sources who retired years prior to the Transport Rule.
Organization: Exelon
Birchwood Power Partners, L.P.
Wolverine Power Supply Cooperative
America's Natural Gas Alliance
West Virginia Department of Environmental Protection
Comment: 
America's Natural Gas Alliance
ANGA supports the manner in which EPA would identify 'existing Transport Rule units' and establish allocations for existing units subject to the CATR. Use of data from the myriad ongoing EPA trading programs plus data from Integrated Planning Model IPM V.4.10 (National Electric Energy Data System - NEEDS) to identify potential existing Transport Rule units ensures that the Agency will capture the appropriate universe of units using the most up-to-date data. ANGA also supports retention of some flexibility to add or subtract individual units based on information supplied to EPA as part of the comment process. [EPA-HQ-OAR-2009-0491-3939[1].1, p.4]
Birchwood Power Partners, L.P.
As one of the cleanest coal-fired power plants in Virginia, Birchwood Power would generally receive adequate allowances under the proposed alternatives to cover its emissions when dispatch returns to pre-recession levels. [EPA-HQ-OAR-2009-0491-3940[1].1, p.2]
Exelon
Exelon thanks EPA for responding to its Original Comments by making corrections to EPA's alternative allocation data sets. See, Original Comments at 43-45. These corrections include the addition of Fairless Hills Units 4 and 5 to EPA's alternative allocation data sets. EPA should add these units to its database of units receiving allocations. Exelon also thanks EPA for including Mountain Creek Units 6 and 7 to its alternative allocation data sets. These units were inappropriately retired by the IPM model in EPA's original Transport Rule allocation tables, as discussed in Exelon's Original Comments. [EPA-HQ-OAR-2009-0491-3919[1].1, pp.15-16]
West Virginia Department of Environmental Protection
List of units used in applying the alternative methodologies, including the classification of "existing unit"
Under either of the proposed alternative allocation methodologies in the current NODA, allocations would be based on historical data not IPM projections, and no historical basis would exist for allocations to units that were not operating in the baseline period of 2005 through 2009. Under the originally proposed applicability provisions, allocations would be made to those units "that commenced commercial operation or are planned to commence commercial operation prior to January 1, 2012". Allocations made in accordance with those provisions would be problematic with the use of either of the newly proposed alternative allocation methodologies. Therefore, the WVDAQ supports the new classification of "existing unit" as those that commenced commercial operation prior to January 1, 2009. Units that began operation after that date could obtain allocations from the new unit set aside pool. [EPA-HQ-OAR-2009-0491-4000[1].1, p.2]
Wolverine Power Supply Cooperative
Regarding the USEPA's request for comment on appropriateness of the list of affected units, Wolverine finds the list to be correct as to units within which Wolverine has an ownership interest. [EPA-HQ-OAR-2009-0491-4014[1].1, p. 4]
Response: 
Thank you for your comment.  The final allocation methodology and description for determining potentially covered existing Transport Rule units and new source set-asides can be found in preamble section VII.D.  The Technical Support Document for Allowance Allocation has the final list of potentially covered existing Transport Rule units to which allowances are allocated in its appendix.
Organization: First Energy
Madison Gas and Electric Company (MGE)
Georgia-Pacific LLC (GP)
International Paper
City of Hamilton
Comment: 
City of Hamilton
Additionally, U.S. EPA's allowance allocation tables incorrectly include references to Hamilton's B008 unit at its municipal power plant. Hamilton's B008 unit is not a large electric generating unit ('EGU') and, therefore, is not subject to the proposed Transport Rule. 75 Fed. Reg. 45,210, 45,299, no. 77. Hamilton brought this mistake to the attention of Brian Fisher, U.S. EPA, Clean Air Markets Division, during a January 24, 2011 telephone conversation. As such, the letter serves as confirmation of the discussion and as Hamilton's written request that U.S. EPA remove B008 from the Transport Rule, the NODA and the accompanying allowance allocation tables. [EPA-HQ-OAR-2009-0491-3984[1].1, pp.1-2]
First Energy
FirstEnergy identified the Edgewater plant boiler A&B listed in both alternative allocation options. The Edgewater units (Oris # 2857) were removed from service indefinitely and should be removed from both NODA III alternative allocation databases, Option 1 & Option 2.    [EPA-HQ-OAR-2009-0491-3904[1].1, p.3]
Georgia-Pacific LLC (GP)
As explained below, the Georgia-Pacific LLC boilers that are listed in the Alternative Allocation Tables are not subject to the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3967[1].1, p.1]
Alabama River Cellulose LLC-(listed as Alabama Pine Pulp ORIS No. 54429 Power Boiler No.2)
The legal name for this mill is Alabama River Cellulose LLC. The facility operates several boilers that supply steam to two turbine generator sets at the facility. The turbine generators produce electricity, most of which is used to operate process equipment onsite. A small percentage of the total electrical power generated onsite is sold to the 'Grid'. One of the turbine generators produces approximately 40 MWh of electrical energy and the other turbine generator produces approximately 70 MWh of electrical energy. The estimated electrical generating capacity of Power Boiler No.2 is approximately 35 MWh. The total quantity of electricity sold by both turbine generators, based on available records from 2000 through 2010, has never exceeded 219,000 MWh in any calendar year. A list of the total quantity of electricity generated onsite by both hlrbine generators and sold to the 'Grid' from 2000 through 2010 is shown below: [EPA-HQ-OAR-2009-0491-3967[1].1, pp.1-2]
Calendar Year 2000     2001     2002     2003     2004     2005    2006    2007    2008    2009      2010
MWhsold       51,247 102,567 103,908 97,835 136,472 112,804 66,971 79,833 84,974 148,814 124,180 
As shown by the data listed above, Alabama River Cellulose LLC has not triggered the criteria under which either of its turbine generators would be subject to the Transport Rule since the combined quantity of electricity sold is far less than the threshold for a single generator with a capacity greater than 25 MWh. Based on these facts, Power Boiler No. 2 qualifies for the cogeneration exemption under the proposed Transport Rule. We therefore request that EPA remove Power Boiler No.2 from its Alternative Allocation Tables as the facility does not meet the criteria for operating an EGU under the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3967[1].1, p.2]
Leaf River Cellulose LLC-(ORIS No. 10233 Power Boiler)
Leaf River Cellulose LLC operates several boilers that supply steam to two turbine generator sets at the facility. The turbine generators produce electricity, most of which is used to operate process equipment onsite. A small percentage of the total electrical power generated onsite is sold to the 'Grid'. Each of the turbine generators at the facility has an estimated electrical generating capacity of approximately 31.5 MWh. The total quantity of electricity sold by both turbine generators, based on available records from 2000 through 2010, has never exceeded 219,000 MWh in any calendar year. A list of the total quantity of electricity generated onsite by both turbine generators and sold to the 'Grid' from 2000 through 2010 is shown below: [EPA-HQ-OAR-2009-0491-3967[1].1, p.2]
Calendar Year 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
MWhsold          9       7     11     10    17    22     13     21    10     13    14
As shown by the data listed above, Leaf River Cellulose LLC has not triggered the criteria under which either of its turbine generators would be subject to the Transport Rule since the combined quantity of electricity sold is far less than the threshold for a single generator with a capacity greater than 25 MWh. Based on these facts, the Power Boiler qualifies for the cogeneration exemption under the proposed Transport Rule. We therefore request that EPA remove the Power Boiler from its Alternative Allocation Tables, as the facility does not meet the criteria for operating an EGU under the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3967[1].1, p.3]
Green Bay, Wisconsin (listed as the Broadway Mill ORIS No. 10360 Boiler B25)
The legal owner/operator of this mill is Georgia-Pacific Consumer Products LP. In addition to the legal name, GP suggests that EPA also designate this mill as 'Green Bay Broadway Operations' in any listings. The Broadway Mill operates five boilers (B25, B26, B27, B28, B29) that serve three turbine generators with electrical generating capacities greater than 25 MWh, designated as Nos. 7, 9 and 10, whose ratings are identified in the CAIR Certificate of Representation as 28.9, 43.2, and 28.2 MWe, respectively, after the application of their power factors. The turbine generators produce extraction steam and electricity, most of which is used to operate process equipment onsite. A small percentage of the total electrical power generated on site is sold to the 'Grid'. The total quantity of electricity sold by the facility, based on available records from 1999 through 2010 has never exceeded 219,000 MWh in any calendar year. Prior to 1999, the capability of the utility tie-in was only 10 MW pel' hour (87,600 MWh per year maximum), thereby precluding sales of electricity above the 219,000 MWh annual threshold value. The tie line is physically limited in its capability by relays that are designed to protect the equipment from over-current situations. A list of the total quantity of electricity generated on-site by all turbine generators (there are two other turbine generators on-site with capacities less than 25 MWh) and sold to the 'Grid' from 1999 through 2010 is shown below: [EPA-HQ-OAR-2009-0491-3967[1].1, p.3]
Calendar Year 1999 2000 2001 2002 2003    2004    2005    2006    2007    2008     2009    2010
MWh sold      1,184   250   534    42     8,780 12,174 19,568 30,329 22,891 35,408 46,945 29,830
The thermal efficiency of the five boilers functioning on a system-wide basis exceeds the 42.5% criteria, with an average value for the time period of 2005 through 2009 of approximately 48%. Based on the proposed revised definition of a cogeneration unit, and the fact that the Green Bay Broadway Operations' system-wide thermal efficiency exceeds the 42.5% thermal efficiency criteria, Boiler B25 should be designated by EPA as a cogeneration unit. Furthermore, since the Green Bay Broadway Operations' turbine generator system has not sold more than 219,000 MWh of electricity to the 'Grid' in any calendar year, the system should be exempted from the CArR Rule and the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3967[1].1, p.4]
International Paper
The NODA directs us to the associated tables where the potentially applicable units are listed. International Paper's Augusta Mill units are on that list. Based on the applicability of the proposed rule, the International Paper sources RB2A and RB3A should not be on the list. [EPA-HQ-OAR-2009-0491-4006[1].1, p.1]
The units show up on the table for both alternative allocation methodologies. Regardless on which methodology is used, the International Paper units should be removed from the list prior to final publication of the rule. Please see attached previous comments provided on the Transport Rule that discusses the status of those units compared to the rule applicability. [EPA-HQ-OAR-2009-0491-4006[1].1, p.1]
I spoke with Mr. Brian Fisher of EPA's Clean Air Markets Division. He indicated that the list of sources on the database was intended to be a comprehensive listing of all potential units compiled from various lists available to EPA from various other programs, and just because a unit is on the list does not necessarily make the unit applicable to the Transport Rule. With our submission of these comments, we ask EPA to make sure that the nonapplicable Augusta Mill units are removed from the database of units. [EPA-HQ-OAR-2009-0491-4006[1].1, p.1]
International Paper was alerted to the fact that its units were listed on Transport Rule Allocation tables associated with the proposed Transport rule. International Paper operates its Augusta Mill under Part 70 PermiI2631-245-()()()6..V-02-0; Facility AIRS Number 04-13·245-00006. [EPA-HQ-OAR-2009-0491-4006[1].1, p.2]
Specifically, International Paper-Augusta Mill's Kraft pulping liquor recovery furnaces, RB2A NO.2 Recovery Boiler and RB3A NO.3 Recovery Boiler, were listed as affected units (ORIS 54358) in Georgia. These units, prior to EPA revising the cogeneration definition on October 19, 2007 72FR59,190, where affected facilities under the CAIR rule. However, based on EPA's current definition RB2A and RB3A are cogeneration units and not subject to CAIR or the Transport rule. [EPA-HQ-OAR-2009-0491-4006[1].1, p.2]
Augusta Mill's Recovery Boilers meet the definition of cogeneration units with useful power efficiencies consistently in the 100% to 10,000 % range for the RB2 and RB3. The high power efficiencies are a result of the boilers primarily being biomass burners. [EPA-HQ-OAR-2009-0491-4006[1].1, p.2]
Recovery Boilers at Augusta are not subject to the various sections of the Transport Rule as outlined in the proposed applicability sections (§§ 97.404 and 97.405,97.504 and 97.505, 97.604 and 97.605, and 97.704 and 97.705-Applicability). Specifically, these units are not applicable unit because they qualify as exempt cogeneration units as outlined in, for example, 97.404(b)(1 )(i). [EPA-HQ-OAR-2009-0491-4006[1].1, p.2]
Madison Gas and Electric Company (MGE)
West Campus Cogeneration Facility (WCCF) units listed as U1 and U2 with ORIS  7991 are included in the Allocation Table and should be removed because WCCF meets the exemption for cogeneration facilities.  WCCF is not currently subject to the CAIR and will continue to meet the criteria for exemption from the Transport Rule. [EPA-HQ-OAR-2009-0491-3924[1].1, p.1]
Response: 
These units have been removed from the final Transport Rule list of potentially covered existing units and do not receive allocations.  Several of these units have (West Campus Cogen and Broadway Mil)l had applicability determinations under CAIR that suggest they are not subject to the Transport Rule.  EPA has removed several others based on information received from the commenter that suggests, given the best data currently available to EPA, that they would not be subject to the final Transport Rule.  However, EPA notes that the units presented in this list of potential existing Transport Rule units reflects only a preliminary assessment of the applicability of the proposed Transport Rule and in no way suggests that EPA has made a determination about the applicability of the proposed Transport Rule to any specific unit. 
Organization: Great River Energy
Rochester Public Utilities (RPU)
Comment: 
Great River Energy
  Great River Energy notes that SEVERAL OF OUR UNITS WERE NOT INCLUDED in the NODA tables and should appropriately be added as applicable units. [EPA-HQ-OAR-2009-0491-3898[1].1, p.1]
Surprisingly, the January 7, 2011 NODA did not even include these emissions units. As a result, no emissions were attributed to these units, thus providing no basis for allowance allocation. Table 1 provides another update of our emission units, specifying those units incorrectly omitted from the NODA tables. Table 1 includes the omitted units and provides associated heat input and emissions information. Again, these are considered to be existing facilities and qualify for allowance allocation under the current proposed rule applicability requirements. [EPA-HQ-OAR-2009-0491-3898[1].1, p.2] [[See Docket Number EPA-HQ-OAR-2009-0491-3898[1].1, p.3 for Table 1.]]
Rochester Public Utilities (RPU)
One unit previously listed on the allocation tables for the Transport Rule is missing from the current tables, Cascade Creek CT1, ORIS code 6058, CAMD Unit ID 90209. This unit should qualify as an existing Transport Rule unit. This unit was subject to and reported under CAIR in 2008 and 2009 until the courts stayed the effectiveness of CAIR in Minnesota. This unit operates a single generator, Cascade Creek CAMR Generator ID 1, has a nameplate capacity of 38 MW and operated during each of the years from 2005-2009. Unless EPA has reason to believe otherwise, this unit should be added to the list of Transport Rule units and allocated allowances. The applicable information on the unit is as follows: [EPA-HQ-OAR-2009-0491-3998[1].1, p.2]
[Table can be found on page 2 of this comment.]
Response: 
EPA is including these facilities, per commenters suggestion, in the final list of potential existing Transport Rule units that receive allowance allocations.
Organization: Illinois Environmental Protection Agency
Comment: 
Illinois Environmental Protection Agency
The Illinois EPA recommends that the existing-unit cut-off date should be January 1, 2010 rather than January 1, 2009, as proposed. The effect of this change would be to include City Water, Light, and Power's Dallman Unit 4 (ORIS plant code 963, CAMD Unit ID 4, and in NEEDS v4.10 referred to in error as Unit ID 34) as an existing unit. Dallman Unit 4 commenced commercial operation on May 11, 2009, and is the cleanest and most efficient unit operating at City Water, Light, and Power. [EPA-HQ-OAR-2009-0491-3899[1].1, p.1]
Response: 
EPA agrees that the existing unit cut-off date should be changed to January 1, 2010.  The Rule has been finalized to reflect this change and the allocation tables have been updated accordingly.  EPA was able to make this change due between the January 7, 2011 NODA and the Rule's finalization because the 2010 data was reported and verified during that time period.  Having the complete 2010 data, allowed EPA to use January 1, 2010 as a cut-off date for existing units because the 2010 data afforded at least one full year of historic data on which to base a unit's allocation.  See Section VII.D of the Preamble for further discussion.
Organization: Mississippi Department of Environmental Quality
Florida Department of Environmental Protection
Covanta Energy Corporation
Dominion
Comment: 
Covanta Energy Corporation
Our comment concerns the mistaken inclusion of two of Covanta's MWC facilities in the unit inventories.  The allocation tables and underlying data include 3 units at the "SEMASS Resource Recovery Facility" in Massachusetts and one unit at the "American Ref-Fuel of Essex" in New Jersey.  The SEMASS facility is an energy-from-waste facility comprised of three MWCs.  It generates about 80 MW of electricity from the combustion of about 3,000 tons per day of MSW.  The Essex facility is also an energy-from-waste facility comprised of three MWCs and generates approximately 70 MW of electricity from the combustion of about 2,800 tons per day of MSW.  [EPA-HQ-OAR-2009-0491-3908[1].1, p.1]
The proposed transport rule includes a "solid waste incineration exemption" for such units as defined in Section 129(g)(1) of the Clean Air Act.  The SEMASS and Essex units referenced in the Allocation Tables meet this definition.  Sections 97.404(b)(2)(i) and (ii), 97.504(b)(2)(i) and (ii), 97.603(b)(2)(i) and (ii), and 97.704(b)(2)(i) and (ii) of the proposed rule provide the exemption for these units that have an average annual fuel consumption of fossil fuel of less 20 percent.  The MWCs at SEMASS and Essex are designed for the combustion of MSW and as such utilize fossil fuel only for start up and occasional stabilization. The percentage of fossil fuel used on a heat input basis is typically only 1 or 2 percent.  [EPA-HQ-OAR-2009-0491-3908[1].1, p.1]
The categorization of SEMASS and Essex as a Transport Rule unit appears to have been an inadvertent error. No other MWCs in the states of Massachusetts or New Jersey with a generating capacity greater than 25 MW are included.   [EPA-HQ-OAR-2009-0491-3908[1].1, p.2]
Dominion
Additional Issues
Inclusion of Biomass Units
Our review of the list of potential existing Transport Rule sources in the NODA indicates that units burning exclusively biomass, such as Dominion's Pittsylvania facility in Virginia, have now been included as affected sources. We believe this may not have been intentional and is an artifact of the use of a number of different and additional data sets that have been used in this NODA to identify potential units that would be subject to CATR. [EPA-HQ-OAR-2009-0491-3987[1].1, p.6]
The Pittsylvania facility bums wood and the units do not meet the definition of a fossil-fuel-fired unit in the proposed rule. Units that bum biomass were not subject to the NOx SIP Call or to the Clean Air Interstate Rule (CAIR). Accordingly, we request that EPA remove the Pittsylvania facility from its list of units potentially subject to the Transport Rule. In doing so, however, the Virginia SO2 and NOx state budgets should not be reduced since emissions from the Pittsylvania facility were not included in the initial determination of those budgets. [EPA-HQ-OAR-2009-0491-3987[1].1, p.6]
Should EPA decide to now include biomass units as affected units under the Transport Rule, the state budgets must be recalculated (and increased) to account for the emissions from these units. In addition, to the extent EPA were to now consider including biomass units, it should issue a supplemental notice and seek comment on this matter. [EPA-HQ-OAR-2009-0491-3987[1].1, p.7]
Florida Department of Environmental Protection
  We have several units in the state that are currently not operating or retired, but operated within the period 2005-2009. These units are left out of the proposed allocations for either option 1 or 2. Should allocations be made to these units? In accordance with the non-operating provisions of the proposed rule, a unit whose first non-operation year is 2007 or later would qualify for allocations. It should be noted that most of these units operated so little that they would receive very few allowances. See attached spreadsheet.   [EPA-HQ-OAR-2009-0491-3879[1].1, p.1] [[See Docket Number EPA-HQ-OAR-2009-0491-3879[2].2 for the spreadsheet.]]
 Several units in the state did not operate during the 2005-2009 period, but retain valid permits and may operate at any time. These units are not included on the allocation list. Since the list contains other units with zero allocations, we assume the list is supposed to represent all units subject to the program. If these units otherwise meet the applicability requirements, and retain valid permits, should they be included on the allowance list? See attached spreadsheet.   [EPA-HQ-OAR-2009-0491-3879[1].1, p.2] [[See Docket Number EPA-HQ-OAR-2009-0491-3879[2].2 for the spreadsheet.]]
It appears that a unit in the allocation list, Reedy Creek (ORIS code 7254, unit ID 32432), is the same unit as Central Energy Plant (ORIS code 7294, unit ID CTG). We have no record of the latter unit in the state database. Both were allocated allowances, but not the same amounts.  [EPA-HQ-OAR-2009-0491-3879[1].1, p.2]
Two units listed on the allocation tables (Ridge Generating Station, ORIS code 54529 and Okeelanta Cogeneration, ORIS code 54627) were each determined by their owners to not be subject to the CAIR program. The Ridge Generating Station was not allocated allowances, but Okeelanta was. Unless EPA has reason to believe otherwise, these sources should not be listed on the allocation table.   [EPA-HQ-OAR-2009-0491-3879[1].1, p.2]
Mississippi Department of Environmental Quality
The NODA request comment on any units listed in the allocation tables that should not be included. For Mississippi, one of the listed units, Leaf River Cellulose LLC (Oris ID 10233), should not be included. This unit is a Power Boiler at a pulp mill that only uses fossil fuel for start-up and otherwise uses wood-waste and should be exempted. [EPA-HQ-OAR-2009-0491-3917[1].1, p.1]
Response: 
As suggested by commenter, these units have been removed from the final Transport Rule list of potential existing TR units.  EPA has removed these units based on information received from the commenter that suggests, given the best data currently available to EPA, that they would not be subject to the final Transport Rule.  However, EPA notes that the units presented in this list of potential existing Transport Rule units reflect only a preliminary assessment of the applicability of the proposed Transport Rule and in no way suggest that EPA has made a determination about the applicability of the proposed Transport Rule to any specific unit. Additionally, the SEMASS unit was removed from the list regardless of any comment received as it is located in the state of Massachusetts which is not subject to the final Transport Rule.
Organization: NextEra Energy, Inc.
Comment: 
NextEra Energy, Inc.
For purposes of the NODA, EPA indicates that a potential existing unit is assumed to be a unit that would potentially meet the proposed applicability criteria (i.e., the criteria in proposed §§ 97.404,97.504, 97.604, and 97.704 in the proposed Transport Rule) for covered units and that commenced commercial operation prior to January 1, 2009. According to EPA, this cutoff date was chosen for existing units because it assured that at least 1 full year of historic data would be available to determine each existing unit's allocation. NextEra Energy recommends that the cutoff date for existing units be revised to January 1, 2010, or possibly even January 1, 2011, since data for 2009 and 2010 are now available to the Agency. This will allow emissions from clean and efficient units that commenced operation in 2009 or 2010 to be covered under the Transport Rule S02 and NOx caps and not have to rely on allowances from the new unit set-aside to cover their emissions. [EPA-HQ-OAR-2009-0491-3962[1].1, p.5]
Response: 
EPA agrees that the existing unit cut-off date should be changed to January 1, 2010.  The Rule has been finalized to reflect this change and the allocation tables have been updated accordingly.  EPA was able to make this change due between the January 7, 2011 NODA and the Rule's finalization because the 2010 data was reported and verified during that time period.  Having the complete 2010 data, allowed EPA to use January 1, 2010 as a cut-off date for existing units because the 2010 data afforded at least one full year of historic data on which to base a unit's allocation.  See Section VII.D of the Preamble for further discussion.
Organization: Northshore Mining Company
Comment: 
Northshore Units 1 and 2 should be removed from EPA's list of potential existing units for the CATR.          
Northshore has two existing cogeneration units at its Silver Bay, Minnesota facility (Northshore Units 1 and 2) that provide process steam and electricity for Northshore's taconite production facility in Northeastern Minnesota.  These units are among a small group of industrial boilers that are subject to the CATR because they have produced small amounts of electricity for sale to the grid.  These units have been exempt from the Acid Rain program as cogeneration units but do not appear to meet the new cogeneration exemption criteria in the CATR due to the addition of an efficiency standard that these older units cannot meet.  EPA expressly requests comment in NODA III on units that owners believe should not be included on the list of potential existing units subject to the CATR (76 Fed. Reg. at 1113).  For the reasons set forth below and in the Cliffs Natural Resources Northshore Mining Comment Letter dated October 1, 2010 submitted in response to the proposed CATR, Northshore believes that its two cogeneration units should not be on this list and that they should be excluded from CATR like other legitimate cogeneration units.  [EPA-HQ-OAR-2009-0491-3957[1].1, p.2]
EPA has long distinguished between industrial cogeneration units and utility units when applying regulations under the Clean Air Act.   The Northshore units have qualified as cogeneration units under all previous Clean Air Act programs, including those targeting new sources (see e.g., 40 CFR 60.41a), hazardous air pollutants (see 40 CFR 63.41) and acid rain reductions (see 40 CFR 72.2).  EPA has consistently drawn a distinction between "electric utility steam generating units and industrial boilers because there are significant differences between the economic structure of utilities and the industrial sector."  See e.g., 44 Fed. Reg. 33580, 33589 (June 11, 1979).  Whereas a utility may pass on the costs of a rule such as the CATR to its retail electricity customers, an industrial facility like Northshore, which sells a wholesale product in a globally-competitive market, may not.  The amount of electricity generated for sale by Northshore and other industrial cogeneration units is relatively small and often produced inconsistently because the primary driver for operation is the industrial process, and electricity is a secondary product generated from excess steam to improve the energy efficiency of the system.  [EPA-HQ-OAR-2009-0491-3957[1].1 p.2]  
EPA has recognized the environmental benefits that arise from adding cogeneration to an industrial steam system. Generating electricity from excess steam can significantly improve energy efficiency and provide a corresponding reduction in emissions from the reduced demand for electricity from off-site sources.  EPA appropriately seeks ways to encourage the development and operation of cogeneration systems and to avoid disincentives.  In the CATR, like its predecessor Acid Rain program, EPA appropriately exempts most industrial cogeneration units.  This exemption removes a disincentive to cogeneration that may otherwise exist if an industrial boiler operator had to comply with an entirely new and burdensome regulatory program like CATR just because it generates more electricity than it may need on a given day and sells that electricity to the grid.  Northshore supports the cogeneration exemption in the CATR, but we ask that EPA broaden the exemption to excuse from the CATR all legitimate cogeneration systems. [EPA-HQ-OAR-2009-0491-3957[1].1, p.2]
EPA recently narrowed the cogeneration exemption to remove a potential loophole.  In drafting the Clean Air Interstate Rule (CAIR), EPA added a requirement not found in the Acid Rain program that requires cogeneration units to meet specified efficiency standards to qualify for the cogeneration exemption.  As EPA explained,
The purpose of this efficiency standard in the cogeneration unit definition is to prevent a potential loophole where a unit might send only a nominal or insignificant amount of thermal energy to a process and not achieve significant efficiency gains through cogeneration, but still qualify as a cogeneration unit and potentially qualify for the cogeneration unit exemption.  [EPA-HQ-OAR-2009-0491-3957[1].1, pp.2-3]
Final Rule Revising the Definition of Cogeneration, 72 Fed. Reg. 59190, 59194 (October 19, 2007).  This same efficiency standard was also incorporated into the CATR to ensure that the cogeneration exemption only excludes legitimate cogeneration systems from the CATR.    [EPA-HQ-OAR-2009-0491-3957[1].1, p.3]
Unfortunately, the efficiency standards used in the CATR exclude legitimate cogeneration units as well, including the Northshore Units, from eligibility for the cogeneration exemption.  The efficiency standards are derived from the Public Utility Regulatory Policies Act ("PURPA") and were intended to apply to newer units where "installation began on or after March 13, 1980."  18 CFR 292.205(a)(2)(i).  The Northshore Units were constructed in 1955 and 1963 respectively, and are not units that would be covered by these PURPA efficiency standards.  In fact, it is unlikely that any coal-fired cogeneration system installed in the 1950s or 1960s would be capable of meeting the efficiency standards included in PURPA for post-1980 units.  In recent years the Northshore Units have achieved 25-30% efficiency, which is well below the 42.5-45% efficiency derived from PURPA and used in the cogeneration definition in the CATR. [EPA-HQ-OAR-2009-0491-3957[1].1,p.3]
EPA did not appear to anticipate that its adoption of the PURPA definition would result in cogeneration units, such as those at Northshore, becoming subject to this rulemaking.  When developing the CAIR, EPA concluded that all cogeneration units would meet the PURPA efficiency standard: 
The EPA analyzed a range of solid fuel-fired cogeneration units and calculated their efficiencies to see if they would meet the proposed minimum efficiency standard.  All of the units selected satisfied the proposed efficiency standard.  As a result, EPA believes that most solid fuel-fired cogeneration units will meet the proposed efficiency standard.  [EPA-HQ-OAR-2009-0491-3957[1].1, p.3]
70 Fed. Reg. 25162, 25277 (May 12, 2005).  EPA failed to consider the impact on the older cogeneration systems, like the Northshore Units, which have historic efficiency rates that are well below the efficiency standard developed by PURPA for post-1980 cogeneration systems.  The historic cogeneration systems that had the foresight in the 1950s and 1960s to add electric generators to industrial steam systems appear to have been inadvertently caught in an overly-broad attempt to close a loophole.  These are not units that use a nominal or insignificant amount of thermal energy to qualify for the cogeneration exemption.  These are legitimate cogeneration systems by any measure.  EPA should exercise its discretion to allow these legitimate historic cogeneration units to qualify for the cogeneration unit exemption without meeting the PURPA efficiency criteria.  The Northshore units must be removed from the database now to ensure that the list of sources subject to CATR is accurate before applying the final allowance allocation methodology at issue in NODA III. [EPA-HQ-OAR-2009-0491-3957[1].1, pp.3-4]
To avoid an arbitrary and unreasonable result, EPA should allow the Northshore Units and other historic cogeneration systems that were built prior to 1980 and previously excluded from the Acid Rain program to qualify for the cogeneration exemption without meeting the PURPA efficiency standard.  If necessary to close the loophole, pre-1980 cogeneration systems should be able to meet a lower efficiency standard of 25% on an annual basis to sustain the exemption.  While legitimate cogeneration systems have every incentive to maximize efficiency without a regulatory obligation, we acknowledge that EPA may want some assurance that historic cogeneration systems continue to operate as legitimate cogeneration units to retain the exemption. EPA requested comment in NODA III on which units should be added or removed from the database of potentially affected units so that the final allowance allocation options can be applied accurately.  Northshore Units 1 and 2 should be removed from the CATR database as exempt cogeneration units.   [EPA-HQ-OAR-2009-0491-3957[1].1, pp.4-5]
Response: 

EPA identified, and finalized TR FIP allocations for, potential existing Transport Rule units.  The methodology used to develop this inventory of units is described in Section VII.D of the Transport Rule Preamble and the TSD for Allowance Allocation.  This list was updated based on input provided by commenters on the proposed Transport Rule and the Transport Rule NODAs. However, EPA notes that the units presented in this list of potential existing Transport Rule units reflect only a preliminary assessment of the applicability of the proposed Transport Rule and in no way suggest that EPA has made a determination about the applicability of the proposed Transport Rule to any specific unit.  See section VII.B of the TR preamble for more information on applicability.
Organization: Occidental Chemical Corporation (OCC)
Comment: 
Occidental Chemical Corporation (OCC)
We would again like to reiterate our position that the OCC-operated Ingleside Cogeneration facility should be exempt from the CATR. First, this facility meets the definition of 'cogeneration system' as defined in the August 2, 2010, proposal (75 Fed. Reg. 45210, 45393). Cogeneration system means 'an integrated group, at a source, of equipment (including a boiler, or combustion turbine, and a steam turbine generator) designed to produce useful thermal energy for industrial, commercial, heating, or cooling purposes and electricity through the sequential use of energy.' The Ingleside Cogeneration facility is commonly referred to as a '2 on1' configuration, which consists of two combustion turbines and associated heat recovery steam generators (HRSGs) and a steam turbine. Second, each of the units in the cogeneration system meet the definition of a cogeneration unit. (ld.) The specific requirements for topping-cycle units include the following:

:: Useful thermal energy not less than 5 percent of total energy output; and,

:: Useful power that, when added to one-half of useful thermal energy produced, is not less than 42.5 percent of total energy input, if useful thermal energy produced is 15 percent or more of total energy output, or not less than 45 percent of total energy input, if useful thermal energy produced is less than 15 percent of total energy output. [EPA-HQ-OAR-2009-0491-3951[1].1, p.2-3]

For Ingleside, since 1999 (the year in which the facility was brought on-line) the percentage of useful thermal energy compared to total energy output has always exceeded 5 percent (the lowest year being 2000 when this value was 22.7 percent), and the useful power, when added to one-half of the useful thermal energy always exceeded 42.5 percent (the lowest year being 2000 when this value was 51.6 percent}. Consequently, the Ingleside facility units qualify as cogeneration units. [EPA-HQ-OAR-2009-0491-3951[1].1, p.3]

In addition, the Ingleside facility is eligible for the cogeneration exemption proposed at 40 CFR § 97.504(b)(1)(i} (75 Fed. Reg. 45397). In order to qualify for the exemption, a cogeneration unit would need to supply in any calendar year - starting the later of November 15, 990 or the start-up of the unit's combustion chamber - no more than one-third of its potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale. Our data, as reported to the Department of Energy, shows that the percentage of power sold to the grid did not exceed 20 percent.  [EPA-HQ-OAR-2009-0491-3951[1].1, p.3]

Respectfully, we request that EPA expressly acknowledge in its response to comments that the Ingleside facility is exempt from the proposed rule.
Response: 
EPA identified, and finalized TR FIP allocations for, potential existing Transport Rule units.  The methodology used to develop this inventory of units is described in Section VII of the Transport Rule Preamble and the Allowance Allocation Final Rule TSD.  This list was updated based on input provided by commenters on the proposed Transport Rule and the Transport Rule NODAs. However, EPA notes that the units presented in this list of potential existing Transport Rule units reflect only a preliminary assessment of the applicability of the proposed Transport Rule and in no way suggest that EPA has made a determination about the applicability of the proposed Transport Rule to any specific unit.  The facility listed above is not on EPA's final list of potential existing Transport Rule units.
Organization: PPG Industries, Inc.
Louisiana Chemical Association (LCA)
State of Louisiana, Department of Environmental Quality
Comment: 
Louisiana Chemical Association (LCA)
6. LCA urges EPA to delete units from the CATR and from corresponding allocations where such units have submitted information to demonstrate they meet a proposed exemption under CATR. LCA believes that the following facilities are not subject to CATR and should be deleted, for the reasons stated in LCA's initial comments on October i, 2010 in this docket: Dow St. Charles Operations ; Georgia Gulf; Formosa; PPG Powerhouse C; Shell Chemical. [EPA-HQ-OAR-2009-0491-4027, p. 6]
PPG Industries, Inc.
In its prior comments on CATR, PPG provided information to demonstrate that the five combined cycle units in PPG's Powerhouse C (50489) should not be included under the scope of the proposed CATR/FIP. These five units are both owned and operated by PPG Industries at its Lake Charles Chemical Manufacturing Complex. These units are exempt cogeneration units that do not sell sufficient power to the grid to be within the applicability requirements of the proposed CATR/FIP. EPA is continuing to list these five PPG Powerhouse C units in this NODA despite PPG's prior comments that these units meet the exemption provisions of the proposed CATR/FIP. PPG Powerhouse C Units C 1 and C2 are similar units consisting of gas turbines with supplementally fired heat recovery steam generators (HRSGs). Units C4 and C5 are similar units consisting of gas turbines and unfired Heat Recovery Steam Generators ('HRSGs'). These units do not meet the applicability criteria under the Acid Rain program, CAIR, or the proposed CATR. All four units meet the exemption for cogeneration units that do not provide more than 1I3rd of their potential electrical output or 219,000 MWhs to the electrical grid for sale. Under the proposed CATR, with respect to the Annual NOx program, this exemption is found in proposed in 40 C.F.R. §97.404(b)(1)(i). For these reasons, PPG Powerhouse C1, C2, C4 and CS units are not subject to the proposed CATR and are not TR NOx Annual Units, TR NOx Ozone Units, or TR S02 Units. [EPA-HQ-OAR-2009-0491-3911[1].1, pp.3-4]
The Powerhouse C unit C3 is a steam turbine that does not, by itself fall within the definition of TR NOx Annual unit, the definition of TR NOx Ozone unit, or the definition ·of TR S02 unit under the proposed CATR because it is not a fossil-fuel fired limit. As Unit C3 is a steam turbine that does not fire any fossil fuel, the unit does not fall within these proposed definitions. Therefore, the PPG Powerhouse C3 steam turbine is not by itself subject to CATR. However, the definition of 'combustion turbine' in proposed §§ 97.402, 97.S02, and 97.602 states that 'If the device is combined cycle, the equipment described in paragraph (1) of this definition and any associated duct burner, heat recovery steam generator, and steam turbine.' (Emphasis added). The C3 steam turbine is only associated with combustion turbines which are part of a combined cycle unit that is exempt from CATR. As such, the C3 unit is also exempt. [EPA-HQ-OAR-2009-0491-3911[1].1, p.4]
Because none of the PPG Powerhouse C units (C1, C2, C3, C4 or C5) are subject to CATR, PPG requests that these units be removed from the allocation tables and all other technical support documents of the rule that would suggest that they are applicable units. [EPA-HQ-OAR-2009-0491-3911[1].1, p.4]
State of Louisiana, Department of Environmental Quality
Several cogenerations units that should be exempt from the transport rule were given allocations. These units include:
- Dow St. Charles Operations
- Formosa Plastics
- PPG Powerhouse C
- Shell Chemical
- Georgia Gulf [EPA-HQ-OAR-2009-0491-3977[1].1, p.2]
Response: 
These units have been removed from the final Transport Rule list of potentially covered existing units and do not receive allocations.  EPA has removed the units based on information received from commenters that suggests, given the best data currently available to EPA, that they would not be subject to the final Transport Rule.  However, EPA notes that the units presented in this list of potential existing Transport Rule units reflect only a preliminary assessment of the applicability of the proposed Transport Rule and in no way suggest that EPA has made a determination about the applicability of the proposed Transport Rule to any specific unit.
Organization: Prairie State Generating Company, LLC
Comment: 
Prairie State Generating Company, LLC
The alternative allocation methodologies presented also do not address issues with the size of the NUSA pools and in fact, by changing the defining date to January 1,2009 for existing versus new units, the problem of underfunding in the NUSA budget in Illinois is exacerbated. PSGC's two 800 MW pulverized coal units are well under construction, with the first unit scheduled to commence commercial operation in mid-July 2011 and the second unit following shortly thereafter. Under the proposed Transport Rule, although it was not issued allowances as an existing unit in the proposed Transport Rule, Unit 1 would be considered an existing unit, while Unit 2 would clearly meet the definition of a new unit. Under the current NODA with the existing unit definition adjusted to January 1,2009, both PSGC units would be treated as new units. New units still under construction and planning to commence commercial operations near the proposed rule January 1, 2012 deadline of new versus existing have the additional uncertainty of potentially being issued allowances as an existing unit and having those allowances revoked if they experience construction delays and no longer meet the deadline with no assurance the number of NUS A allowances will be adjusted accordingly. Not knowing whether one or both units will be in the new unit set side pool, leaves PSGC extremely concerned since the current NUSA pool leaves PSGC drastically short of the allowances needed to operate a one unit base-loaded operation, let alone a two unit base-loaded operation which would also include 'sharing' the NUSA allowances with another base-loaded 230 MW coal-fired unit which was recently constructed in Illinois under either of the alternatives in this latest NODA. [EPA-HQ-OAR-2009-0491-3897[1].1, p.3-4]
Furthermore, while new units are 'short-changed' allowances needed to operate, under this NODA gas turbine facilities are allocated permanent S02 allowances which they do not need to operate. PSGC cannot support a proposal which offers unneeded allowances to certain facilities simply because they are arbitrarily defined as 'existing' while a new, just as real facility, is not given allowances needed to operate simply because it is arbitrarily defined as 'new.' [EPA-HQ-OAR-2009-0491-3897[1].1, pp.4-5]
Response: 
EPA has modified its final allowance allocation methodology in the final Transport Rule and has also modified the size of new source set-aside accounts (see section VII.D of the preamble).  The adjustment to the new source set aside was meant to reflect those scenarios identified by Prairie State Generating Co. and shift the budget portion based on emissions from planned-committed units from the existing unit budget to the new source set-aside account.  This gives new units access to a wider pool of allowances in a manner that would likely fully cover their future emissions.
Organization: Pratt & Whitney
Comment: 
Pratt & Whitney
Pratt & Whitney notes that the Pratt & Whitney Cogeneration unit (Cogen), ORIS 54605, located in East Hartford, CT, is still included in the Alternative Allocation Tables, which are listed in the Technical Support Documents for the proposed Transport Rule. As communicated on 9/29/10 (comment 80b6357a), this unit should not be included in the documentation for the Transport Rule as it meets the cogeneration exemption of not 'supplying in any calendar year more than one-third of the unit's potential electric output capacity [104,292 Mwe-hrs] or 219,000 MWh, whichever is greater'. [EPA-HQ-OAR-2009-0491-3876[1].1, p.1]
The Pratt & Whitney Cogen permit was upgraded to allow a 32 MW unit at the end of 2002. The cogeneration unit provides a portion of the electrical power required by the facility and also provides steam for process and building heating and cooling. If at any time the cogeneration unit creates more power than the facility is using at the moment, the excess power is sold to the grid. The annual data since 2003 clearly indicates that Pratt & Whitney has consistently sold below the 219,000 MWh cogeneration exemption threshold: [EPA-HQ-OAR-2009-0491-3876[1].1, p.1] [[See Docket Number EPA-HQ-OAR-2009-0491-3876[1].1, p.1 for table.]]
Pratt & Whitney requests that our cogeneration unit, ORIS 54605, be removed from the proposed Transport Rule Allocation Tables and that the EPA confirms that this regulation will not apply to the Pratt & Whitney Cogen. [EPA-HQ-OAR-2009-0491-3876[1].1, p.1]
Response: 
Connecticut is not subject to the final Transport Rule.  Consequently, neither are the Pratt  & Whitney units discussed above because they are located in Connecticut.  They have been removed from the list of potential existing Transport Rule units.
Organization: Public Power Generation Agency
Comment: 
Public Power Generation Agency
EPA's NODA III proposes and seeks comment on two alternative allowance allocation methodologies, both of which are based on sources' historic heat input. In addition, and of particular relevance to WEC Unit 2, both alternatives would redefine the applicability criteria for an "existing unit." Under the NODA III, an "existing" unit must "meet the applicability criteria in the Transport Rule NPR (proposed §§ 97.404, 97.504, 97.604, and 97.704) and began commercial operation prior to January 1, 2009." 76 Fed. Reg. at 1111/2. Consequently, if EPA were to adopt either of the alternative allocation methodologies suggested in the NODA III, WEC Unit 2's status would change from that of an "existing unit" under the PTR to a "new unit" under the NODA III because it did not commence commercial operation before January 1, 2009. [EPA-HQ-OAR-2009-0491-3960[1].1, p.2]
PPGA thus finds itself in a fundamentally unfair position. PPGA is being asked to choose between two scenarios, both of which involve uncertainty and variability that, in combination, reflect arbitrary agency action due to the lack of adequate public notice. [EPA-HQ-OAR-2009-0491-3960[1].1, pp.2-3]
Conversely, under either of the alternatives proposed in the NODA III, WEC Unit 2 would be characterized as a new unit and would be subject to considerable uncertainty from year to year in terms of the numbers of allowances it would be allocated. Those numbers could vary greatly depending on a range of extraneous factors, including the number of new units competing for the allowances from the new unit set-aside for Nebraska in any given year, the size of that new unit set-aside both initially and in succeeding years, and the timing of retirements of existing units in the state and the number of allowances associated with those units that will be deposited at various times in the new unit set-aside (assuming that this new unit set-aside methodology as proposed in the PTR in fact is adopted by EPA in the final rule).2 [EPA-HQ-OAR-2009-0491-3960[1].1, p.3]
On the other hand, under the alternative allocation methodologies in the NODA III, WEC Unit 2 would be treated as a new unit and would, for the reasons discussed above, be subject to substantial uncertainty as to its allowance allocations from year to year, a circumstance that would make compliance planning exceedingly difficult. Unlike the child who said the bad word, PPGA has done nothing wrong and should not be forced to choose between two unpalatable alternatives. [EPA-HQ-OAR-2009-0491-3960[1].1, p.4]
EPA staff has made informal representations to counsel for PPGA that, under the PTR's original allocation methodology (assuming that that methodology, rather than, for example, either of the NODA III methodologies, is used in the final rule), EPA will make corrections to the IPM modeling such that WEC Unit 2 will receive allowance allocations based on a revised IPM run that will account for projected 2012 emissions from WEC Unit 2. Based on EPA staff's informal representations  -  and assuming that EPA properly implements and finalizes the corrections as they have been described by EPA staff to PPGA's counsel  -  PPGA would prefer the allocation methodology in the PTR, under which WEC Unit 2 would qualify as an existing source and be allocated allowances based on revised IPM modeling accounting for projected 2012 emissions from WEC Unit 2, as opposed to either of the NODA III allocation methodologies. [EPA-HQ-OAR-2009-0491-3960[1].1, pp.4-5]

2 The discussion in the text above assumes that the size of the new unit set-aside would be established based on the methodology described in the PTR, since there is no description in the NODA III of how the new unit set-aside would be established or administered if the allowance allocation methodology is based on heat input under either of the NODA III alternatives. PPGA questions whether it would be appropriate, under the NODA III alternatives, to establish the new unit set-aside based on an allocation methodology that primarily reflects historical and projected future emissions (i.e., the PTR's methodology) if the methodology used to allocate allowances to existing units is based on heat input as described in the NODA III. In any event, EPA has an obligation to explain, and to provide public notice on, how the new unit set-aside would be established and calculated if the allowance allocation methodology used for existing units is based on heat input, as proposed in the NODA III. The NODA III is unaccountably silent on this critical issue.
Response: 
See section VII.D of the preamble for an explanation of the final Transport Rule allocation methodology.  EPA agrees that WEC 2's status would change from being considered an "existing unit" under the proposed methodology to a "new unit" under the final methodology.  However, in response to concerns about the uncertainty in allocation due to the size of the new source set-aside, EPA has modified the size of new source set-aside accounts in the final rule to appropriately reflect emissions from "new units".  This includes units, such as WEC Unit 2 that are under construction but that do not commence operation prior to January 1, 2010.  States that have planned units such as WEC 2, have large set-aside accounts that are intended to provide these units with access to a more reasonable size pool of allowances.  The additional allowances added to the new source set-aside to account for planned units being reclassified as "new" instead of "existing" is equal to their projected emission levels.
Organization: Weyerhaeuser Company
Comment: 
Weyerhaeuser Company
Weyerhaeuser Company ("Weyerhaeuser") is filing this request to remove a unit belonging to the Weyerhaeuser - Flint River mill located in Oglethorpe, Georgia, from the analyses and allocations tables included in the support materials for this rulemaking. This filing is similar to one made during the comment period on the original proposed rulemaking to make the same request. See Docket ID EPA-HQ-OAR-2009-0491-2602.1 That earlier filing apparently was not acted upon by EPA as the subsequent alternative allocation NODA was developed. [EPA-HQ-OAR-2009-0491-3880[1].1, p.1]
The facility continues to be listed, this time in a key technical support document to the proposed NODA made available at http://www.epa.gov/airtransport/actions.html#jan11 and titled "Alternative allocation tables and underlying data (Excel File)" [Docket ID: EPA-HQ-OAR-2009-0491-3875]. In this support document the facility has the identifiers:
Weyerhaeuser Company  -  Flint River  
ORIS ID: 50465  
Unit ID: U500 [EPA-HQ-OAR-2009-0491-3880[1].1, p.1]
The listing and inclusion of this facility in the proposed Clean Air Transport rule (CATR) is an error, presumably due to residual records of the unit stemming from initial listings and preparation work prior to October 2007, due to its potential, but ultimately exempted, applicability under the Clean Air Interstate Transport Rule (CAIR). Amendments to CAIR in October 2007, modified how biomass fuel heat input is evaluated to qualify cogeneration units. Consequently, Weyerhaeuser determined this unit to meet the cogeneration definition and to be exempt from the current CAIR (see Exhibit 1). [EPA-HQ-OAR-2009-0491-3880[1].1, pp.1-2] [[See Docket Number EPA-HQ-OAR-2009-0491-3880[1].1, p.3 for Exhibit 1.]]
This unit is a pulp mill recovery furnace. Based on the definitions and applicability sections of proposed Subparts AAAAA -- TR NOX Annual Trading Program, BBBBB -- TR NOX Ozone Season Trading Program, CCCCC -- TR SO2 Group 1 Trading Program, and DDDDD -- TR SO2 Group 2 Trading Program, this unit will be exempt from the CATR for the same reason, which is that the unit meets the requirements to be an exempt cogeneration unit. That is: (a) it predominantly burns biomass (> 99.5 % on an annual average heat input basis) and therefore easily meets the criteria in the proposed definition for a topping cycle cogeneration unit, and; (b) per the applicability provisions it "...does not serve at any time, since the later of November 15, 1990 or the startup of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe supplying in any calendar year more than one-third of the unit's potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale." [EPA-HQ-OAR-2009-0491-3880[1].1, p.2]
The unit therefore will not be subject to the CATR, and we request EPA eliminate the unit from further CATR analyses and actions under this rulemaking. [EPA-HQ-OAR-2009-0491-3880[1].1, p.2]
Response: 
These units have been removed from the final Transport Rule list of potentially covered existing units and do not receive allocations.  EPA has removed these units based on information received from the commenter that suggests, given the best data currently available to EPA, that they would not be subject to the final Transport Rule.  However, EPA notes that the units presented in this list of potential existing Transport Rule units reflects only a preliminary assessment of the applicability of the proposed Transport Rule and in no way suggests that EPA has made a determination about the applicability of the proposed Transport Rule to any specific unit.

 

XX.B. Calculating Assurance Provision Surrender Requirement on Designated Representative (DR) Basis

Organization: Ameren Services Company
Comment: 
Ameren Services Company
On page 1117 EPA requests comments on 'Whether the Assurance Provision Allowance Surrender Requirement Should be Calculated on a Designated Representative Basis.' The text in the description of this section is not totally clear. Ameren believes that using the Designated Representative for the surrender of allowances makes some sense if it is handled in the manner described below:
a) Assume that the sum of emissions from all affected sources in a state have exceeded the states' allocation of allowances (allocated allowances plus new unit set aside) plus the states variability limit. [EPA-HQ-OAR-2009-0491-3894[1].1, p.2]
b) In determining whether the DR's units would be subject to a surrender requirement: [EPA-HQ-OAR-2009-0491-3894[1].1, p.2]
1. For the units under the DR's control sum their respective allocations and their portion of the state's variability limit
2. Compare this sum in #1 above to the total emissions for all units under the DR's common control for that control period (i.e. annual or ozone season)
3. If the total emissions in #2 exceed those in #1 above the DR would be subject to surrender requirements.
4. If the total emissions in #2 are less than those in #1 above the DR would not be subject to surrender requirements.
c) If the calculation (b) above shows an excess emission as stated in b(3) above the DR's units in total would only be required to surrender allowances that exceed that calculated in b(1) above. [EPA-HQ-OAR-2009-0491-3894[1].1, p.2]
If it is EPA's intention to implement the surrender requirement on a DR basis as described above Ameren supports this change. [EPA-HQ-OAR-2009-0491-3894[1].1, p.2]
Response: 
See sections VII.E and XI of the preamble.
Organization: American Electric Power
Comment: 
American Electric Power
EPA has solicited comments regarding the proposed compliance demonstration and assurance provisions, proposing to allow compliance to be demonstrated based on groups of units that share a common designated representative within a single state, instead of requiting compliance demonstrations to be based on ownership. EPA notes the administrative convenience of this option, and its practical utility, and solicited comments on alternative assurance mechanisms that could accompany such a change. [EPA-HQ-OAR-2009-0491-3934[1].1, p.6]
AEP supports the alternative compliance demonstration proposal, and recommends expanding and refining the assurance provisions to remove arbitrary restrictions on allowance trading and promote economic solutions. Examination of each of the emissions trading programs adopted by Congress or EPA has demonstrated that the programs are cost-effective, and the stringency of the trading schemes has assured that regional air quality concerns are addressed. Indeed, the modeling performed by MOG confirms that simply relying on the existing CAIR program, with the substantial existing allowance banks and unlimited interstate trading currently authorized, will achieve the air quality goals identified by the agency. Therefore, the extremely restrictive assurance measures in the Proposed Transport Rule are unnecessary and will substantially increase the cost of compliance, and prevent the development of any viable emissions trading market. [EPA-HQ-OAR-2009-0491-3934[1].1, p.6]
If EPA chooses to use the assurance provisions as a means of responding to the concerns outlined by the court in the North Carolina decision, a much more limited and practicable alternative is available. Under no circumstances should the assurance provisions be expanded for use in 2012-2013. During this time the state budgets and unit allocations themselves are so stringent that only limited trading (if any) will occur. Moreover, by wiping the slate clean, and depriving operators of the allowance banks created under CAIR, operators have no ability to address excess emissions caused by the inherent variability in electricity markets. EPA needs to provide an alternative mechanism that accommodates the inherent variability in emissions even in these initial years, since the electricity markets are demand driven and weather dependent. Unlimited interstate trading as recommended by EPA is the only mechanism through which the region as a whole can comply, but some additional flexibility should be provided to recognize the inherently variable nature of the electricity system. AEP suggests that a compliance supplement pool be created for compliance years 2012 and 20l3, similar to the compliance supplement pool created initially under CAIR, in order to provide a more reasonable transition to the reduced budgets in the Proposed Transport Rule. Alternatively, sources should be authorized to borrow allowances from future years in 2012 and 2013, up to the proposed single year assurance levels without penalty, in order to offset the inherent variability in the electricity markets. [EPA-HQ-OAR-2009-0491-3934[1].1, pp.6-7]
In 2014 and beyond, EPA has acknowledged the substantial variability that has historically occurred in electricity demand and emissions, but has severely limited trading based on political borders. A simpler system could be fashioned that would allow owners and operators to achieve compliance in a manner that accounts for the way in which utility systems have developed and takes advantage of the existing reporting mechanisms. There are many multi-state utility systems like AEP, some having as few as two facilities, and others having many more facilities. Most of these systems provide service in adjoining states, but represent only a portion of the total capacity affected by the Proposed Transport Rule in any single state. Many of these systems have a single designated representative, in order to centralize their compliance obligations and achieve efficiencies in compliance planning and implementation. Accordingly, an assurance provision that would allow units located in adjacent states that have the same designated representative to demonstrate compliance by limiting emissions to the allocated level plus an assurance margin of ten percent on an annual basis would assure that all states are contributing reductions, would facilitate cost-effective compliance planning within utility systems, but would not arbitrarily limit trading based on political boundaries. Emissions reductions would be achieved across adjoining states, and often in closer geographic proximity than if trading is limited to the borders of a single state. So long as total emissions in the region affected by the Proposed Transport Rule also remain below the regional cap and the assurance percentage, utilities should be able to bank and trade allowances throughout the region. If emissions rise above the cap by more than the assurance percentage, only utility systems whose emissions also exceed their allocation plus the assurance provisions would be subject to an excess emissions penalty. Penalty assessments should be payable from banked or future year allowances. [EPA-HQ-OAR-2009-0491-3934[1].1, p.7]
Such an assurance mechanism preserves the cost-effectiveness of an interstate trading scheme throughout the program. A plant on one side of the liver that otherwise might be severely impacted by the assurance provisions in one state, forcing uneconomic reductions based on its unit-level budget, will be able to take advantage of the cost-effective reductions made at a unit on the other side of the river and have the same beneficial impact on air quality. Substituting an assurance scheme based on systems with the same designated representatives thus achieves the air quality goals of the Proposed Transport Rule without the uncertainties and inefficiencies associated with separate statewide assurance requirements. [EPA-HQ-OAR-2009-0491-3934[1].1, p.8]
In addition, there is no need for multiple layers of assurance, as originally proposed. Allowing a limited margin each year for the entire Transport Region, and allowing affected facilities to certify compliance based on a common designated representative will accommodate variability without compromising the air quality goals of the proposed rule. Inserting a three-year average assurance requirement merely introduces additional uncertainties into an already fragile market system. [EPA-HQ-OAR-2009-0491-3934[1].1, p.8]
Response: 
See sections VII.E and XI of the preamble to the final Transport Rule.  The final rule adopts the assurance provisions, and applies them starting in 2012, in order to meet the requirements of North Carolina. 
EPA rejects the commenter's position that sources should be allocated extra allowances (i.e., a compliance supplement pool) beyond the state trading budgets, or that owners and operators should be allowed to "borrow", i.e., use for compliance in a given year, allowances allocated for future years.  Both of these suggestions would result in covered sources having more allowances to use to cover emissions in a control period than the total state trading budget for that control period.  The commenter failed to state what should be the size of the suggested compliance supplement pool, much less any rationale for adopting any specific size.  EPA believes that the required reductions in 2012 are achievable (see section VII.C of the preamble) and therefore there is no need for any size of compliance supplement pool to make a " more reasonable transition" to the Transport Rule 2012 state trading budgets.  EPA therefore rejects these suggestions as vague and unsupported.  Moreover, EPA notes that the assurance provisions, coupled with other elements (such as the state trading budgets) of the Transport Rule trading programs, ensure that states' significant contribution and interference with maintenance, as identified in the final rule, are eliminated as required by CAA section 110(a)(2)(D)(i)(I) and North Carolina.  In particular, each state budget reflects projected emissions for covered sources in the state after achievement of emission reductions eliminating the state's significant contribution and interference with maintenance.  To the extent that covered sources in a state were allocated for a control period a total amount of allowances exceeding the state budget for that control period or were allowed to use for a control period part of the state budget for future years, this would increase the likelihood that the total state covered-source emissions would exceed the state budget plus variability limit for the control period and thus would threaten the state's elimination of significant contribution and interference with maintenance.  In short, either compliance supplement pool allocations or use of future-year allowances would undermine compliance with North Carolina.
The commenter also stated that the assurance provisions should be implemented based on utility systems (which often are multi-state), rather than on a state-by-state basis, and suggested that CAA requirements would be met so long as region-wide emissions were reduced so that a region-wide cap was met.  However, the Court in North Carolina stressed that CAA section 110(a)(2)(D)(i)(I) requires prohibition, within each state, of significant contribution and interference with maintenance and essentially rejected the commenter's approach of evaluating the amount of emission reductions on a region-wide basis.  See North Carolina, 531 F.3d 896, 907 (D.C.Cir. July 11, 2008).
Organization: Buckeye Power, Inc.
Comment: 
Buckeye Power, Inc.
EPA requested comment on whether CATR's assurance provision's emissions surrender. requirement should be imposed on owners/operators of units, but calculated on a 'Designated Representative' -by-'Designated Representative' basis. Without further clarification, Buckeye opposes EPA's Designated Representative ('DR') approach. First, the DR approach fails to explain how such an approach would be implemented where a particular DR is responsible for facilities in separate states. For instance, if one state triggers surrender, it is unclear whether or not a DR's units in another state may be required to surrender allocations. Further complicating a DR approach, many power plants have percentage shares of ownership divided between various owners. Buckeye prefers a unit-by-unit approach to CATR's assurance/surrender provisions, with the ability for full trading within any particular state and limited interstate trading, so that adequate offsets can be purchased if required. [EPA-HQ-OAR-2009-0491-3900[1].1, p.5]
This approach is consistent both with CATR reduction and Congress' preference to allow an allocation market and market participants to determine where emission reductions should occur. This approach has proven itself time and time again under the Clean Air Act to be the shortest and most efficient approach to clean air. [EPA-HQ-OAR-2009-0491-3900[1].1, p.5]
Response: 
See sections VII.E and XI of the preamble.  Under the assurance provisions in the final rule, if a state triggers the assurance provisions, responsibility for the assurance penalty will be divided up among the groups of units and sources in that state (not outside the state) with a common designated representative.  The owners and operators of each such group where the common designated representative's share of emissions exceeds the common designated representative's share of the state budget plus variability must surrender allowances to meet their share of the assurance penalty.  This means that the group's total emissions are compared to the group's total allocations plus share of variability, and units with fewer emissions than allocations plus variability can offset units with greater emissions than allocations plus variability.  No penalty is imposed on the owners and operators of any units and sources located in another state and having the same individual for a designated representative as a group of units and sources in the state where the assurance provisions are triggered (unless, of course, the second state also triggers the assurance provisions).  
EPA recognizes that units at sources (plants) may have multiple owners and, in fact, the identity and percentage shares of the multiple owners may vary from unit to unit at the same source and can change during the year.  For this reason, the final rule requires that each source have one designated representative for all of the owners and operators and implements the requirement to hold allowances covering emissions on a source (i.e., designated representative) basis.  Similarly, because owners and operators (and not EPA) have access to information on an ongoing basis on the identity and percentage shares of multiple owners and already make decisions about the shares of emissions and allowances to be attributed among multiple owners with regard to the requirement to hold allowances covering emissions, the final rule implements the assurance provisions on a common-designated-representative basis.  Even under the commenter's suggested unit-by-unit approach, owners and operators would have to handle, in many cases, issues concerning the attribution of emissions and allowances among multiple owners of the unit. This approach also provides more flexibility for owners and operators of only one or a few units in a state -- as compared to implementation on a unit-by-unit basis -- because such owners and operators can use their grouping with any other units at their source (which necessarily have the same, i.e., common, designated representative) and can also decide to group their units with units at other sources in the state by selecting, in coordination with owners and operators of such other units, a common designated representative.  
Organization: Cleco Corporation
Comment: 
Cleco Corporation
B. Cleco supports a designated representative approach for assurance provision accounting.
Cleco supports EPA's proposed change with respect to assurance provision accounting at the designated representative level. Cleco, however, requests that EPA provide for comment the regulatory language EPA proposes to accomplish that change. It is imperative that EPA not, in its haste, undermine private agreements between owners with respect to allowance ownership and surrender obligations. It also must be clear that owners have a regulatory obligation to surrender through their designated representative. [EPA-HQ-OAR-2009-0491-4007[1].1, p.7]
Response: 
See sections VII.E and XI of the preamble.  The commenter asserted that, but failed to explain how, the assurance provisions might "undermine" private agreements among owners.  The assurance provisions provide owners and operators of units and sources in a state flexibility to group their units under a common designated representative.  Independent of the assurance provisions, every covered source is required to have a designated representative.  The selection of a designated representative -- whether the one required for a source or a common designated representative for a group of units and sources in a state -- is always based on private agreements among owners and operators, as reflected in the certificate of representation where any designated representative must certify that he or she was selected "by an agreement binding on the owners and operators."  Also, independent of the assurance provisions, multiple owners and operators of a source generally use private agreements to determine ownership of allowances and responsibilities for surrendering allowances to cover emissions.  Multiple owners and operators of a source will be able similarly to use private agreements to determine responsibilities for surrendering allowances in the event that they are subject to an assurance provision penalty.  In short, the assurance provisions do not undermine the use of private agreements, but rather preserve the ability of owners and operators to use private agreements to select designated representatives and to determine allowance ownership and surrender.  Owners and operators, of course, have the option of amending their private agreements to address specifically the assurance provisions.  
The commenter also asserted, without explanation or support, that the assurance provisions must required allowance surrender "through" the designated representative.  As with the requirement to hold allowances to cover emissions, the requirement to hold allowances for the assurance provision penalty is imposed on the owners and operators, not the designated representative.  Under both requirements, the surrendered allowances must be held in a specified account (the appropriate compliance account under the requirement to hold allowances covering emissions and the appropriate assurance account under the assurance provisions).  Any transfers of allowances to the assurance account, of course, will be made by the authorized account representative for the allowance account from which the allowances are transferred, and, if that allowance account is a source's compliance account, the designated representative is the authorized account representative for that allowance account.   
Organization: Constellation Energy
Comment: 
Constellation Energy
Constellation Energy supports the ownership method of assurance provisions.
Under the proposed Transport Rule, the assurance provisions would be triggered for a state for a given year if total emissions for covered units In the state for the year exceed the state assurance level (i.e., the state budget plus the state's variability limit). As proposed, if this level were exceeded, the assurance provision allowance surrender requirement would be imposed on certain owners of covered units in the state and calculated on an owner-by--owner basis. Specifically, each owner whose share of the state's total covered-unlit emissions exceeded the owner's share of the state assurance level would have to surrender a proportionate share of the state's exceedance, [EPA-HQ-OAR-2009-0491-4031, p.3]
While this approach may be somewhat more complicated in the case of multiple owners of the same facility, it is has the least inherent legal liability, an important consideration in the timely implementation of the Rule. While the umbrella of a common Designated Representative may afford additional compliance flexibility, it is easy to imagine potential exploitation of this flexibility and resultant unintended consequences, such as the formation of trading blocs under the guise of a common Designated Representative. The Ownership method of assurance provisions is ultimately the most straightforward approach. [EPA-HQ-OAR-2009-0491-4031, p.3]
Response: 
See section VII.E of the preamble.  EPA rejects the commenter's claim that implementation of the assurance provisions on a common-designated-representative basis has more "inherent legal liability" as vague, speculative, and unsupported.   The commenter vaguely speculates that the flexibility provided by the common-designated-representative approach could result in "potential exploitation" and "unintended consequences", such as the "formation of trading blocs".  The commenter failed to explain, even using hypothetical scenarios, what such "exploitation" and "unintended consequences" could be, what is meant by "trading blocs", what would be the likelihood of such phenomenon occurring, and what would be the adverse effects if such phenomenon were to occur. 
Organization: Exelon
Comment: 
Exelon
EPA'S PROPOSED COMPLIANCE ASSURANCE MECHANISM, IF BASED ON EITHER AN OWNER SHARE OR A DESIGNATED REPRESENTATIVE SHARE,WILL BE DIFFICULT TO IMPLEMENT AND UNNECESSARILY COSTLY.
EPA's reliance on either an owner share or a designated representative share in its compliance assurance mechanism is problematic, in that these mechanisms will be difficult to implement and make compliance unnecessarily costly. As discussed in the following section, the problems with either approach could be solved by adoption of the compliance assurance mechanism suggested by Exelon in its Original Comments. See, Original Comments at 24-26, 30-42. Exelon's proposed compliance assurance mechanism would allow EPA to move to a compliance assurance mechanism based on individual facilities while not only providing for intrastate and interstate trading, but facilitating more robust and efficient trading. [EPA-HQ-OAR-2009-0491-3919[1].1, p.7]
Compliance assurance based on either an owner's share or a designated representative share departs from the structure of the Clean Air Act, which focuses enforcement and compliance at the permitted facility level, with the designated representative being the unit of compliance for the facility. If compliance is focused on the "owner's share," EPA and states will often need to negotiate a tangled web of ownership and operational arrangements, where many of the largest facilities have multiple owners and a different operator, and ownership shares frequently change. This will make the determination of compliance on a year to year basis difficult for EPA, the states and regulated entities alike and could make enforcement for noncompliance problematic. [EPA-HQ-OAR-2009-0491-3919[1].1, p.7]
Although EPA's proposal to base its compliance assurance mechanism upon a designated representative share may solve the foregoing problems, it will impede free trading and make compliance more costly for the regulated community. Single owners often use multiple designated representatives in a particular state. Moving from an owner compliance scheme to one based on designated representatives will impede the ability of owners to take advantage of pooling units' allowance allocations. This could have the negative effects of reducing trading, causing uneconomic decisions regarding whether to install or operate control equipment, and creating administrative burdens. As discussed below, Exelon's alternative compliance mechanism will avoid both of these problems, by allowing EPA to base compliance on a facility's share, but by still allowing the flexibility of pooling and trading, which is lost in the currently proposed designated representative approach. [EPA-HQ-OAR-2009-0491-3919[1].1, p.8]
Exelon Generation's situation in Pennsylvania exemplifies the problems with either approach. The majority of allowances to which Exelon, as an owner, would be entitled derive from its co-ownership of the Keystone and Conemaugh facilities. Exelon shares ownership in these baseload electric generating facilities with seven other companies. The facilities are operated by yet another company, which also serves as the designated representative, and is an affiliate of one of the eight owners. Exelon owns and operates a number of other fossil fuel fired intermediate electric generating units and peaker units in Pennsylvania, itself, and has two designated representatives in Pennsylvania, one for its Peaking Division units and a second for its other EGUs in Pennsylvania. [EPA-HQ-OAR-2009-0491-3919[1].1, p.8]
Determining Exelon's owners' share would require EPA and the Pennsylvania Department of Environmental Protection to develop information about ownership structure and percentages and to track that information over time, greatly complicating administration and enforcement. On the other hand, switching the compliance assurance mechanism to a designated representative share would undermine operational flexibility. In the event of increased market demand in any given year (e.g., due to weather or forced outages), Exelon's intermediate and peaking units in Pennsylvania could be called on to operate at higher capacity factors than normal. With an owner's share approach, Exelon would have a much larger pool of allowances from its co-ownership in the Keystone and Conemaugh Facilities, so that it could safely increase its emissions at the intermediate and peaking units by the full variability limit of 10% of the total emissions of all of its facilities in Pennsylvania, without being concerned about needing to surrender additional allowances if Pennsylvania exceeded its statewide share plus variability limit. However, with a designated representative approach, Exelon's operational flexibility would be limited to 10% of the far smaller number of allowances allocated to its intermediate and peaker units. Given the number of owners and the existence of a separate operator, Exelon could not solve this problem by using a single designated representative for all of its facilities, since there cannot be more than one designated representative at either Keystone or Conemaugh. Moreover, pooling under a single designated representative with little information or control of multiple facilities would undermine the primary purpose of the designated representative - - the creation of individual responsibility to ensure environmental compliance. [EPA-HQ-OAR-2009-0491-3919[1].1, pp.8-9]
As discussed in the next section, with Exelon's proposed alternative compliance assurance mechanism, EPA could avoid both of these problems. Exelon would be able to transfer some of the Pennsylvania-specific allowances allocated to its co-owned Keystone and Conemaugh facilities to its peakers and intermediate units, and use banked or out-of-state allowances to assure that none of its facilities use more than 10% non-Pennsylvania, non-current year allowances. It could also go into the market to acquire Pennsylvania, current year allowances, and market signals would give all market participants the price signals necessary to assure that Pennsylvania stays within its state budget plus variability limit. [EPA-HQ-OAR-2009-0491-3919[1].1, pp.9-10]
EXELON'S PROPOSED REVISION TO THE COMPLIANCE ASSURANCE MECHANISM WILL PROVIDE A BETTER MEANS TO ASSURE COST EFFECTIVE COMPLIANCE WITH ADMINISTRATIVE SIMPLICITY.5
The various revisions that EPA has proposed affecting allowance allocation mechanisms or compliance assurance militate strongly towards adoption of the improvement to the compliance assurance mechanism suggested by Exelon in its Original Comments. See, Original Comments at 24-26, 30-42. [EPA-HQ-OAR-2009-0491-3919[1].1, p.10]
Exelon has suggested that an owner's share (or designated representative's share) be based on the type of allowances that a source owner (or designated representative) surrenders for compliance, rather than the number of allowances that it initially receives for free. The "share" or "budget" will be equal to the number of surrendered allowances that were initially allocated to a source located in the same state during the current compliance year, i.e. the surrendered allowances are in-state and in-year, as indicated by the allowance registration number. Owners can freely trade allowances between the initial allocation and ultimate surrender, so that the assurance provision calculation will be independent of the allocation scheme. As a result, regulated entities will readily be able to secure rights to in-state, in-year allowances before running units and to make the appropriate decision of whether to buy allowances or to control emissions. This method will, therefore, better assure that EPA meets the mandate of North Carolina v. EPA, 531 F.3d 896, 929 (D.C. Cir. 2008), remedy modified on reh. 550 F.3d 1176 (D.C. Cir. 2008) ("North Carolina"). [EPA-HQ-OAR-2009-0491-3919[1].1, p.11]
While Exelon supports a heat input based allocation method, the allocation of allowances under that method is unrelated to a judgment regarding which facility should reduce its emissions in order to avoid incurring requirements for the surrender of excess allowances. The most economically efficient mechanism for a state to meet its emissions budget may be for a newer, more efficient facility (or a facility with a cleaner fuel such as gas) to run for more hours or to run its control equipment for more hours, thereby taking advantage of pollution reduction due to both efficiency and control equipment. Under the heat input allocation scheme, a facility might uneconomically decide to install and run unnecessary control equipment to avoid the surrender of double allowances, unless the owner's share calculation is revised. [EPA-HQ-OAR-2009-0491-3919[1].1, pp.11-12]
The problem of the lack of an appropriate budget becomes even clearer when one considers what might happen if a state submits an alternative allocation program calling for use of an auction. If allowances are allocated by auction, an owner (or designated representative) will have no basis whatsoever upon which to determine whether it should buy allowances or install or run control equipment. With an auction, what will be the metric upon which the "owner's share" will be based? There will be no owner, designated representative or unit share or budget that can be used in the compliance assurance system. States clearly have the right to propose alternative allocation programs in their SIPs. However, combining alternative allocation methods with EPA's original assurance provision is even more likely to produce an outcome with states that exceed their budgets or meet their budgets at unnecessarily high costs. [EPA-HQ-OAR-2009-0491-3919[1].1, p.12]
The compliance assurance mechanism proposed by Exelon will provide an administratively simple mechanism to assure that emissions will not exceed State budgets. Exelon's method will not require a plethora of separate state trading programs for each pollutant, but a single trading program where the allowance certificates will simply include an identifier for the state to which they pertain and year in which they are issued. This is administratively simple to achieve because each allowance will require a certificate with a unique identifier in any case. [EPA-HQ-OAR-2009-0491-3919[1].1, pp.12-13]
An owner's, a designated representative's or even, if EPA desires, a facility's budget for purposes of compliance assurance, would be equal to the number of allowances that it surrenders that are specific for that year and the state in which the facility is located or the facilities are located, rather than being set equal to the number of free allowances allocated to that entity. The owner/designated representative/facility could surrender out-of-state or banked allowances (identified by registration number) to meet its compliance obligations, but would become subject to the requirement for the surrender of excess allowances if the state exceeds its budget plus variability limit and the percentage of out-of-state, out-of-year allowances surrendered by the regulated entity (or entities) for that year exceeds the percentage of the variability limit. [EPA-HQ-OAR-2009-0491-3919[1].1, p.13]
If, therefore, the state's variability factor is 10% of its budget, each regulated party has a strong incentive to assure that ten out of every 11 allowances it surrenders are in-state, current-year allowances, or risk having to surrender excess allowances if the state exceeds its budget plus variability limit. In this case, the number of banked or out-of-state allowances that an owner/designated representative /facility used to satisfy its compliance obligation would not exceed the variability limit. The market for the current-year, in-state allowances would give facility owners the correct signals regarding whether to install or run control equipment or purchase allowances. Futures markets and bilateral agreements would allow facility owners or designated representatives to know the number of in-state, current year allowances that will be available and their cost. Based on that knowledge, the regulated parties will be able to make informed judgments as to whether it would be most economical to install control equipment, to close facilities, or to run control equipment. Moreover, when prices of a state's current-year allowances increase as a state approaches its budget, the price signals will affect the dispatch markets, encouraging dispatch from cleaner facilities or facilities located in states that are not at or near their budgets for the year. A further benefit is that Exelon's proposal will create greater incentives for emissions to remain within state budgets and provide an additional safeguard that EPA's Transport Rule will, indeed, result in the elimination of significant contribution as required by the Court in North Carolina v. EPA. [EPA-HQ-OAR-2009-0491-3919[1].1, pp.13-14]
Exelon's proposal will neither create separate trading programs nor create a program that is difficult to administer. For example, if the NOx budgets for Illinois and Pennsylvania are 100,000 tons each for 2013, EPA would issue 100,000 2012 Illinois NOx allowance certificates and 100,000 Pennsylvania 2012 NOx allowance certificates, which will be readily identifiable by their certificate numbers. An owner with a single Pennsylvania facility emitting 1,100 tons of NOx in 2012 would need to assure that it has at least 1,000 Pennsylvania 2012 certificates, but could use 100 banked or out-of-state allowances to meet its compliance obligation. If it decided to utilize more than 100 banked or out-of-state allowances, it would face the risk of being required to surrender excess allowances if Pennsylvania exceeded its budget plus variability limit. However, this would only be a consideration in states with projected emissions in excess of state budgets plus the state variability limit; generating units in states with emissions expected to be well within budgets would have more leeway to consider inter-state allowance purchases if needed at the inter-state market price. EPA and the states could readily determine compliance and enforcement of this program would be no more complex than EPA's original proposal. In fact, enforcement and compliance will be simplified under Exelon's proposal. [EPA-HQ-OAR-2009-0491-3919[1].1, p.14]
The practical advantages of the Exelon compliance assurance mechanism are exemplified by Exelon Generation's situation in Pennsylvania, described above. In the event of increased market demand in any given year (e.g., due to weather or forced outages) resulting in Exelon's intermediate and peaking units in Pennsylvania being called on to operate at higher capacity factors than normal, Exelon could go into the market for current year allowances and buy additional current year Pennsylvania allowances for each affected facility rather than trying to determine where and how it should shift allowances between units under an owner's share or designated representative share approach. More importantly, in that case, the price of Pennsylvania, current year allowances would increase, affecting the price at which plants would bid their electricity into the PJM market, so that an appropriate price signal would be introduced into the market. This would more efficiently and effectively drive dispatch of lower emission electricity on the system, so that all states would remain within their respective budgets. Because compliance could be based on a facility's emissions, EPA and states would also be relieved of the need to negotiate the tangled web of ownership and operational arrangements that an owner's share approach would entail, while avoiding the restrictions on free trading and pooling that a designated owner's share approach would entail. [EPA-HQ-OAR-2009-0491-3919[1].1, p.14-15] 

5 Exhibit 1 presents additional materials prepared by the Northbridge Group for Exelon, entitled "EPA Transport Rule Assurance Provision Comments," that are intended to provide additional discussion and examples to support Exelon's proposed modifications to EPA's Assurance Provision methodology.  [[See Docket Number EPA-HQ-OAR-2009-0491-3919[1].1, pp.17-36 for Exhibit 1.]]
Response: 
See sections VII.E and XI of the preamble.  The commenter expressed concern that implementing the assurance provisions on a common-designated-representative basis would limit the commenter's flexibility because of difficulties with selecting a single designated representative for all of its sources and the problem of having a single designated representative with little information about or control of the various sources.  However, a designated representative can be changed simply through submission of a superseding certificate of representation, and EPA has found that designated representatives for many sources are changed relatively frequently.  In light of this and other factors discussed in the preamble, the final rule bases the identification of groups of one or more units and sources with a common designated representative based on the identity of the designated representatives as of a specific date, i.e., April 1 after the control period for which a state triggers the assurance provisions.  This approach provides flexibility for owners and operators to continue to use the different individuals as the designated representatives for most purposes under the trading programs and to select a common designated representative for purposes of the implementation of the assurance provisions. 
Under the common-designated-representative approach in the assurance provisions in the final rule, the common designated representative's assurance level is the common designated representative's share of the state budget with variability (which is defined as the total allocations and auctioned allowances for the group of units and sources having the common designated representative plus the group's share of the variability) and is compared with the common designated representative's share of emissions (which is defined as the total emissions of the units in the group).  Although the commenter asserted that allowances that are auctioned, rather than allocated, would not be considered in this comparison, the final rule expressly includes any auctioned allowances.  Specifically, in the final rule, the common designated representative's assurance level (i.e., share of the state budget with variability) includes, in addition to allocated allowances, any auctioned allowances submitted to the state or permitting authority for recordation by the Administrator in the compliance account of a unit in the group of units and sources having the common designated representative.  
The commenter suggested an alternative approach to the assurance provisions under which emissions would be compared to the amount of allowances surrendered by a facility (or owner or designated representative, depending on whether the provisions were implemented on a source-by-source, owner-by-owner, or designated- representative-by-designated- representative basis) that were originally issued for the state in which the facility (or facilities) involved are located.  According to the commenter, this approach would not require the creation of independent "assurance" allowances because the same allowances would be used to meet the requirement to hold allowances covering emissions as to meet the alternative assurance provisions.  However, the alternative assurance provisions would still result in segregated allowance markets in that, for each state, the in-state allowances could be used to avoid or reduce the amount of allowances a facility was required to surrender if the assurance provisions were triggered and the out-of-state allowances could not be used in this way.  Consequently, these alternative assurance provisions resemble the intrastate trading option described in the proposal, which faced market concentration problems.  In many states, a single large utility controls a majority of the generation and would have control of the majority of allowances issued for that state, i.e., the majority of the in-state allowances.  While auctioning of in-state allowances in each state might address this problem, the final rule adopts allocation, rather than auctioning, of allowances in the Transport Rule trading programs because of, among other things, the complexity of administration and complexity and cost of participation in separate state auctions covering multiple pollutants in a large number of states.   Moreover, assurance provisions that would be dependent on the use of auctions could not be used because, once states (rather than EPA) start distributing allowances through full or abbreviated SIPs, those SIP revisions may or may not include auctions.  In the CAIR trading programs, only a few states used any auctions to distribute allowances.  Because the alternative assurance provisions would lead to serious market liquidity and allowance pricing concerns, EPA is not adopting these alternative assurance provisions. 
Organization: Independence Power & Light (IPL)
Comment: 
Independence Power & Light (IPL)
DESIGNATED REPRESENTATIVE
The NODA presents an alternative methodology for calculating the assurance provision allowance surrender requirement when total emissions for covered units in the state exceed the state assurance level. Under this alternative, the 'calculation of shares of covered-unit emissions and of the state budget plus variability would be performed for each group of covered units having a common [Designated Representative]' ('DR'), rather than on, as the Rule proposed, an owner-by-owner basis. 76 FR 1117/1-2. The owners and operators represented by a common DR whose collective share of state covered-unit emissions exceeded the DR's collective share of the State's assurance level would be jointly and individually liable for the DR's proportionate share of the State's exceedance allowance surrender requirement. Id. EPA offers that there is a benefit to units within a DR group of being able to balance excess emissions of some units against the excess allowances from other units within the group, and that the DR approach is 'more straightforward' and 'potentially provides owners and operators with more flexibility' than the owner-by-owner approach. Id. at 1117/3. Another claimed benefit is that the DR approach would 'eliminate the need to collect detailed ownership information and would also avoid the complications arising from having to divide up units' emissions and allocations among partial owners of the units.' Id. [EPA-HQ-OAR-2009-0491-3949[1].1, p.9]
IPL is in favor of the Rule providing as much flexibility and control as possible to states and to owners whose units would be subject to the Rule. However, IPL has concerns that the DR proposal allows EPA to delegate management of the assurance program to the unit owners and operators without consideration of some issues of fairness and implementation. For example, while switching to the DR program might well eliminate the need for EPA to collect ownership data and would allow EPA to avoid the complications of dividing emissions and allocations, switching to a DR program will not allow unit owners to avoid either difficulty. The DR proposal appears to shift the burdens of implementation to unit owners to allocate the loss of allowances. The loss of allowances has the potential to be the most difficult ramification of the proposed Rule and EPA's proposal leaves it to unit owners to deal with this difficulty. [EPA-HQ-OAR-2009-0491-3949[1].1, p.10]
EPA does not provide information as to whether and how units that choose not to join a DR will be assigned allowance surrender requirements. IPL is concerned that owners and units that choose not to join a DR might find themselves at an immediate disadvantage. For example, a DR member has less incentive to sell allowances to non-members (or, indeed, a DR could restrict such sales or trading) because it would be to the DR's advantage to hoard potential excess allowances as a hedge against triggering assurance provisions for the DR as a whole. The NODA does not raise, let alone address, whether such a result would be consistent with the objective of the Rule, which also raises the issue of whether adopting a DR approach constitutes an improper delegation of EPA's authority. IPL also is concerned that there will not be equal bargaining power within DR groups because larger, more efficient units might have the most bargaining power. This inequality could lead to private agreements that undermine the policy goals behind the allowance surrender requirements. [EPA-HQ-OAR-2009-0491-3949[1].1, p.10]
If EPA wishes to shift responsibility for compliance with the FIP assurance program from EPA to DRs EPA must reconsider the DR program as outlined and address issues of fairness and implementation. Although IPL is generally in favor of any opportunity to allow the private sector or regulated community more options and control over their own destiny, the DR proposal requires considerable refinement and IPL urges EPA not to adopt the DR alternative as presently described. [EPA-HQ-OAR-2009-0491-3949[1].1, p.11]
IPL further requests that EPA revisit the proposed DR and owner methodologies for allowance surrenders and propose a methodology that presents a level playing field and that has the requisite checks and balances and due process opportunities under the law. [EPA-HQ-OAR-2009-0491-3949[1].1, p.12]
Response: 
See sections VII.E and XI of the final Transport Rule preamble.  
The commenter expressed concern that EPA was "delegating" to designated representatives the ability to "allocate loss of allowances" through allowance surrender under the assurance provisions.  However, EPA is not delegating any authority.  Instead, the final rule makes the owners and operators of a group of units and sources responsible, as a group, for surrendering allowances under the assurance provisions when the state triggers the assurance provisions.  The owners and operators must decide, generally through private agreements, who will actually provide the necessary allowances, but all the owners and operators remain responsible regardless of how they internally divide up the actual provision of allowances.  This is analogous to the implementation of the requirement to hold allowance covering emissions, which has been implemented under the Acid Rain Program and CAIR trading programs and is implemented under the Transport Rule trading programs, on a source-by-source basis.  The owners and operators of the units at each source, as a group, are responsible for holding for surrender allowances covering the total emissions of these units and decide, generally through private agreements, who will actually provide the necessary allowances.  There is no delegation by EPA: all the owners and operators remain responsible regardless of how they internally divide up the actual provision of  allowances.  Consequently, EPA rejects the commenter's claims of "improper delegation" of authority.  
The commenter also expressed concern about how units that "choose not to join a DR" will be assigned allowance surrender requirements under the assurance provisions.  Under the Transport Rule trading programs, like under the Acid Rain Program and the CAIR trading programs, every source must have a designated representative representing all the owners and operators of unts at the source.  Thus, all units at each source have the same designated representative (i.e., a common designated representative), but the owners and operators of multiple sources have the option to choose a common designated representative for the group of sources.  In short, every unit has a common designated representative, either at the source level or, if the option is taken by the owners and operators of multiple sources, at the group-of-sources level. 
The commenter expressed concern that the common-designated-representative approach puts the burden on owners and operators to determine the identity and percentage shares of multiple owners and operators.  However, for purposes of dividing up ownership of allowance allocations and meeting the requirement to hold allowances covering the source's emissions, owners and operators already have to determine the identity and shares of multiple owners and operators of units at the same source.  Owners and operators have handled these situations under the Acid Rain Program and the CAIR trading programs through private agreements and can continue to do so under the Transport Rule trading programs.  Because, in addition, unit owners and operators (but not EPA)  have ongoing access to information on the identity and shares of multiple owners and operators of the units, EPA maintains that it is reasonable to implement the assurance provisions on a common-designated-representative basis, rather than on an owner-by-owner basis. 
The commenter made vague claims about incentives for a common designated representative to "hoard" allowances "as a hedge against triggering the assurance provisions and about there not being "equal bargaining power" among units with a common designated representative.  However, the commenter failed to explain how "hoarding" allowances would create such a hedge.  In the final rule, for each group of units and sources with a common designated representative, total emissions are compared to total allocations plus share of variability, and whether the allocations continue to be held or are sold does not affect the determination of whether the owners and operators of the group are subject to the assurance surrender requirement if the state triggers the assurance provisions.  Further, the commenter speculated that "unequal bargaining power" could result in private agreements that would "undermine the policy goals behind the allowance surrender requirements", but failed to explain, even using hypothetical examples, how this could occur or what policy goals would be undermined.  The assurance provisions impose a penalty, if the state emissions exceed the state budget with variability, by making all owners and operators of the group subject to the surrender requirement regardless of their "bargaining power".   EPA rejects the commenter's claims about hoarding and bargaining power as vague, speculative, and unsupported.
Organization: Kansas City Board of Public Utilities (BPU)
Comment: 	
Kansas City Board of Public Utilities (BPU)
The claimed benefits are not ones, however, that inures to the benefit of unit owners, but, rather, allow EPA to delegate management of the assurance program to the unit owners and operators. For example, while switching to the DR program might well eliminate the need for EPA to collect ownership data and would allow EPA to avoid the complications of dividing emissions and allocations, switching to a DR program will not allow unit owners to avoid either difficulty. Switching merely means they do it among themselves in what could be relatively contentious negotiations involving how to allocate within each group a finite number of allowances among owners who likely compete against each other.[EPA-HQ-OAR-2009-0491-3978[1].1, p.10]
As the DR process is apparently voluntary, EPA offers no guidance as to whether an appeals process for disputes is available, or under whose aegis units that chose not to join a DR will be assigned allowance surrender requirements. Those owners and units that choose not to join a DR would likely find themselves at an immediate disadvantage. For example, a DR member has less incentive to sell allowances to non-members (or, indeed, a DR could restrict such sales or trading) because it would be to the DR's advantage to hoard potential excess allowances as a hedge against triggering assurance provisions for the DR as a whole. The NODA does not raise, let alone address, whether such a result would be consistent with the objective of the Air Transport Rule, which also raises the issue of whether adopting a DR approach constitutes an improper delegation of EPA's authority. It is also likely that parties will have unequal bargaining power within DR groups with larger, more efficient units likely having the most bargaining power. This inequality could lead to private agreements that undermine the policy goals behind the allowance surrender requirements. [EPA-HQ-OAR-2009-0491-3978[1].1, pp.10-11]
The NODA presents an alternative methodology for calculating the assurance provision allowance surrender requirement when total emissions for covered units in the state exceed the state assurance level. Under this alternative, the 'calculation of shares of covered-unit emissions and of the state budget plus variability would be performed for each group of covered units having a common [Designated Representative]' ('DR'), rather than on, as the Rule proposed, an owner-by-owner basis. 76 FR 1117/1-2. The owners and operators represented by a common DR whose collective share of state covered-unit emissions exceeded the DR's collective share of the state's assurance level would be jointly and individually liable for the DR's proportionate share of the state's exceedance allowance surrender requirement. Id. Despite the obvious benefit to units within a DR group of being able to balance excess emissions of some units against the excess allowances from other units within the group, EPA offers as additional benefits that the DR approach is 'more straightforward' and 'potentially provides owners and operators with more flexibility' than the owner-by-owner approach. Id. at 1117/3. Another claimed benefit is that the DR approach would 'eliminate the need to collect detailed ownership information and would also avoid the complications arising from having to divide up units' emissions and allocations among partial owners of the units.' Id. [EPA-HQ-OAR-2009-0491-3978[1].1, pp.9-10]The NODA fails to present a compelling case to shift responsibility for compliance with the FIP assurance program from EPA to DRs. By retaining control, EPA can assure that the program follows uniform guidelines for all participants based on fulfilling the stated objective of the Transport Rule, rather than a hodge-podge of differing allocation surrender schemes that are determined by the relative bargaining power of the parties to the various DRs. BPU submits that uniform treatment promotes a level playing field for all participants with a large degree of transparency. Such a program will give clear signals as to what is or is not acceptable practices and the consequences for not meeting allocated emissions levels. Those goals are much more important in establishing a sound program than the supposed flexibility and reduced complications claimed for DRs. BPU urges EPA not to adopt the DR alternative. [EPA-HQ-OAR-2009-0491-3978[1].1, p.11]
3. That the Designated Representative option for handling allowance surrenders be eliminated from further consideration. [EPA-HQ-OAR-2009-0491-3978[1].1, p.11]
Response: 
See sections VII.E and XI of the preamble.  The commenter expressed concern that EPA was "delegating" to designated representatives the ability to "allocate loss of allowances" through allowance surrender under the assurance provisions.  However, EPA is not delegating any authority.  Instead, the final rule makes the owners and operators of a group of units and sources responsible, as a group, for surrendering allowances under the assurance provisions when the state triggers the assurance provisions.  The owners and operators must decide, generally through private agreements, who will actually provide the necessary allowances, but all the owners and operators remain responsible regardless of how they internally divide up the actual provision of allowances.  This is analogous to the implementation of the requirement to hold allowance covering emissions, which has been implemented under the Acid Rain Program and CAIR trading programs and is implemented under the Transport Rule trading programs, on a source-by-source basis.  The owners and operators of the units at each source, as a group, are responsible for holding for surrender allowances covering the total emissions of these units and decide, generally through private agreements, who will actually provide the necessary allowances.  There is no delegation by EPA: all the owners and operators remain responsible regardless of how they internally divide up the actual provision of  allowances.  Consequently, EPA rejects the commenter's claims of "improper delegation" of authority.  
The commenter also expressed concern about how units that "choose not to join a DR" will be assigned allowance surrender requirements under the assurance provisions.  Under the Transport Rule trading programs, like under the Acid Rain Program and the CAIR trading programs, every source must have a designated representative representing all the owners and operators of unts at the source.  Thus, all units at each source have the same designated representative (i.e., a common designated representative), but the owners and operators of multiple sources have the option to choose a common designated representative for the group of sources.  In short, every unit has a common designated representative, either at the source level or, if the option is taken by the owners and operators of multiple sources, at the group-of-sources level. 
The commenter expressed concern that the common-designated-representative approach puts the burden on owners and operators to determine the identity and percentage shares of multiple owners and operators.  However, for purposes of dividing up ownership of allowance allocations and meeting the requirement to hold allowances covering the source's emissions, owners and operators already have to determine the identity and shares of multiple owners and operators of units at the same source.  Owners and operators have handled these situations under the Acid Rain Program and the CAIR trading programs through private agreements and can continue to do so under the Transport Rule trading programs.  Because, in addition, unit owners and operators (but not EPA)  have ongoing access to information on the identity and shares of multiple owners and operators of the units, EPA maintains that it is reasonable to implement the assurance provisions on a common-designated-representative basis, rather than on an owner-by-owner basis. 
The commenter made vague claims about incentives for a common designated representative to "hoard" allowances "as a hedge against triggering the assurance provisions and about there not being "equal bargaining power" among units with a common designated representative.  However, the commenter failed to explain how "hoarding" allowances would create such a hedge.  In the final rule, for each group of units and sources with a common designated representative, total emissions are compared to total allocations plus share of variability, and whether the allocations continue to be held or are sold does not affect the determination of whether the owners and operators of the group are subject to the assurance surrender requirement if the state triggers the assurance provisions.  Further, the commenter speculated that "unequal bargaining power" could result in private agreements that would "undermine the policy goals behind the allowance surrender requirements", but failed to explain, even using hypothetical examples, how this could occur or what policy goals would be undermined.  The assurance provisions impose a penalty, if the state emissions exceed the state budget with variability, by making all owners and operators of the group subject to the surrender requirement regardless of their "bargaining power".   EPA rejects the commenter's claims about hoarding and bargaining power as vague, speculative, and unsupported.
Organization: National Rural Electric Cooperative Association (NRECA)
Comment: 
National Rural Electric Cooperative Association (NRECA)
The proposed   assurance provision allowance  surrender  requirement holding unit owners and operators collectively and    individually  liable  for   emissions exceedances  for  units under  a  common DR  imposes  broader  liabilities than exists under the existing acid rain program.   NRECA believes owner and operator liability under a common DR should be limited to unit exceedances at the source only, following the current acid rain program provisions.   [EPA-HQ-OAR-2009-0491-3943[1].2, p.1]
Third, NRECA believes the proposed assurance provision allowance surrender requirement imposing liabilities on all unit owners and operators under a common DR is a significant departure from the current owner and operator requirements under the acid rain program that limits such liabilities to unit owners and operators under a common DR at a source where the unit exceedance occurred.  There is no apparent overriding rationale to alter the existing liability apportionment between units under a common DR, and thus the current acid rain liability apportionment should be applied to the CATR allowance provisions.   [EPA-HQ-OAR-2009-0491-3943[1].2, p.4]
EPA proposes to broaden unit owner and operator collective and individual liabilities for unit allowance shortfalls to include unit owners and operators of all units within a state under a common DR. NRECA is opposed to extending joint and several liabilities for allowance  shortfalls beyond liability limits currently imposed within the existing acid rain program.  As EPA notes, acid rain allowance shortfall liabilities are limited to units at the source where the allowance shortfall occurs. The acid rain program has been ongoing for well over a decade with this current liability apportionment system in place. NRECA is not aware of any problems with this system.  Just as importantly, joint unit owners, source operators and DRs are all functioning under existing contractual relationships that comprehend the existing acid rain liability system.  NRECA fears that expanding and altering the current system now could present negative and unintended consequences.  EPA has offered no compelling rationale to expand the liability umbrella in this NODA III beyond that existing under the acid rain program, and thus NRECA opposes such expansion. [EPA-HQ-OAR-2009-0491-3943[1].2, pp.9-10]
Response: 
See sections VII.E and XI of the preamble.  The commenter claimed that the common-designated-representative approach in the assurance provisions is a "significant departure" from the approach under the Acid Rain program because owners and operators of multiple units and sources with a common designated representative could be liable for an assurance penalty if the state involved triggers the assurance provisions.  However, in the final rule, the choice of what specific individual will be the designated representative for a source is made by the owners and operators, and thus the decision of whether to select someone who is also the designated representative for other sources and becomes a common designated representative for the group of sources under the assurance provisions is left entirely to the owners and operators.  If the commenter prefers to limit its unit's potential liability for assurance penalties to the owners and operators of units at the source where its units are located, the commenter can decide not to use the option of selecting a common designated representative with other sources. 
Further, many units under the Acid Rain Program have multiple owners and, as the commenter noted, multiple owners of units at a single source have been successfully using private agreements to govern the selection of a designated representative for the source and for other matters, such as responsibility of individual owners to actually provide allowances necessary to cover the source's emissions or to meet excess emissions penalties.  The comment vaguely speculated that use of common designated representatives under the assurance provisions could have "negative and unintended consequences".  The commenter failed to explain, even using hypothetical scenarios, what such "negative and unintended consequences" could be, what would be the likelihood of such consequences being realized, and what would be the extent of the adverse effects.  Moreover, the commenter failed to explain why, if compliance issues among multiple owners of units at a single source have been successfully handled through private agreements, private agreements cannot similarly be used among multiple owners of multiple sources under the assurance provisions.  Moreover, common designated representatives have been, and still being used, in the NOx emission reduction program that is part of the Acid Rain Program.  Under this part of the Acid Rain Program, owners and operators have the option of grouping their units and sources into NOx Averaging Plans and meeting the NOx emission rate limitations of the Acid Rain Program as a group.  See 40 CFR 76.11.  In order to be included in a single group, the units must be "under the control of the same owner or operator" (but may have minority owners) and have the "same designated representative:"  40 CFR 76.11(a).  Each group must submit, and obtain EPA approval of, a NOx averaging plan for the group, and EPA has approved, and owners and operators (including minority owners) have operated under such approved plans, in some cases for many years.  See "Acid Rain Program NOX Averaging Plans Final Rule TSD".  While NOx averaging plans, obviously, impose different requirements than the assurance provisions in the final rule, the use of these plans demonstrates that owners and operators can successfully use the same designated representative for groups comprising multiple units and sources to meet regulatory requirements involving emission limitations and holding of allowances.  For all these reasons, EPA rejects the commenter's claims of "negative and unintended consequences" as vague, speculative, and unsupported. 
Organization: NextEra Energy, Inc.
Comment: 
NextEra Energy, Inc.
With respect to the issue of how the allowance surrender requirement should be calculated, NextEra Energy does not support the alternative approach to calculate the assurance provision allowance surrender requirements at the DR level. Rather, we support EPA's original proposal to determine assurance provisions' surrender requirements at the owner level. NextEra Energy has concerns about using the DR level because it could complicate a (non-DR) joint owner's ability to hedge against the two-for-one penalty associated with the assurance provision. For example, if the combined sources under one DR exceed that DR's allocation plus the variability limit, non-DR co-owners who otherwise would not have triggered the assurance provision (because their sources were below the assurance level) would potentially have to pay a portion of the two-for-one penalty. Alternately, if a source is long on allowances, a non-DR owner would not be able to use those additional allowances as a way to balance under-allocated sources. Thus, while the DR-based calculation may provide additional flexibility to some owners and operators (particularly majority owners of co-owned units), it may provide less flexibility to other owners and operators (particularly minority owners of co-owned units). [EPA-HQ-OAR-2009-0491-3962[1].1, p.4]
As an example, assume that Unit A is owned by two companies, Company 1 and Company 2. Company 1 owns 75% of Unit A and Company 2 owns 25% of Unit A. A representative from Company 1 is assigned as the DR of Unit A. If, during a particular control period, Unit A's emissions are less than its allowance allocation, Company 2 would not be able to use the surplus allowances from Unit A to offset allowance shortages at Units Band C, also owned by Company 2 that, without the surplus from Units A, would trigger assurance proviSions and 2: 1 compliance at Units Band C. Conversely, if facility A's emissions exceed its allocation but does not exceed its share of the state variability limit, it could still trigger assurance provisions for Owner 2 if total emissions from all of Company 1 's facilities exceed their share of the state variability limit. [EPA-HQ-OAR-2009-0491-3962[1].1, pp.4-5]
While the risks to a minority owner outlined above could be addressed and mitigated to a certain degree by contractual provisions in an owner's agreement, this is not as straightforward as it may sound. Co-owners agreements are complicated documents that are carefully crafted to protected each co-owners' interests. For this reason, the parties to these agreements are often reluctant to re-open these agreements unless absolutely necessary. [EPA-HQ-OAR-2009-0491-3962[1].1, p.5]
For the reasons above, NextEra Energy opposes the alternate DR-level approach to calculate the assurance provision allowance surrender requirements that EPA requests comment on in the NODA and urges EPA to retain the owner-level approach reflected in the August 2,2010 proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3962[1].1, p.5]
Response: 
See sections VII.E and XI of the preamble to the final Transport Rule .  The commenter expressed concerns about the role of minority owners when the assurance provisions are implemented on a common-designated representative basis.  However, many units and sources under the Acid Rain Program and CAIR trading programs (as will also be the case under the Transport Rule trading programs) have multiple owners, including minority owners.  For this reason, all these programs require each source to have one designated representative for all of the units at the source.  Under the Acid Rain Program and CAIR trading programs, multiple owners and operators of units at a single source have been successfully using private agreements to govern the selection of a designated representative for the source and the distribution of allowance allocations and for other matters, such as responsibility of individual owners to actually provide allowances necessary to cover the source's emissions or to meet excess emissions penalties.  The commenter stated that private agreements can also address the commenter's concerns about "risks" to minority owners under the assurance provisions.  However, the commenter speculated, without providing any support, that owners and operators may be "reluctant to re-open these agreements unless absolutely necessary".  Moreover, because owners and operators of units and sources with a common designated representative will be responsible, as a group, for surrendering allowances under the assurance provisions if the state triggers the provisions, there is no basis for assuming that owners and operators will not re-open private agreements to address the new surrender requirement. 
The commenter discussed two hypothetical scenarios, one where the unit with a majority owner and a minority owner at a source has fewer emissions than allocated allowances and one where such  unit has more emissions than allocated allowances but less than allocated allowances plus share of variability.  According to the commenter, under the first scenario the minority owner cannot use the excess allocation to offset an excess of emissions over allocations plus variability that the minority owner has at two other sources owned by the minority owner.  However, this ignores the flexibility that the majority and minority owners have of agreeing to a common designated representative for all three sources so that the sources' total emissions will be compared to the sources' total allocations plus share of variability in determining the assurance penalty.  In fact,  this option will be available even if the owner of the second and third sources in this scenario was not a minority owner of the first source.  One could undoubtedly hypothesize some specific fact patterns where it would be more advantageous for an owner to have the assurance provisions implemented on an owner-by-owner basis rather than a common-designated-representative basis.  However, the common-designated-representative approach generally provides more flexibility by allowing owners and operators to combine their units and sources into groups with common designated representatives and thereby providing for their total emissions and total allocations plus share of variability to be compared.  For this reason, and the other reasons discussed in sections VII.E and XI of the preamble, EPA maintains that the implementation of the assurance provisions on a common-designated-representative basis is reasonable.  
According to the commenter, under the second scenario where the multiple-owner unit has more emissions than allocated allowances but less than allocated allowances plus share of variability, the unit can "still trigger assurance provisions" for the minority owner if the majority owner's other sources have emissions exceeding allocations plus share of variability. This is the same type of issue that multiple owners and operators of a source already address in private agreements in connection with the requirement to hold allowances covering total source. For example, some sources have three or more units, with ownership varying among the units.  See "Acid Rain Program NOX Averaging Plans Final Rule TSD" (NOX averaging plan for San Juan plant showing four units with ownership varying among the units).  Since these units are subject to the Acid Rain SO2 trading program (as well as the Acid Rain NOX  Program in which the averaging plan is used), the owners and operators must to determine who will actually provide extra allowances to cover SO2 emissions if, for example, one unit's emissions exceed that unit's allocations but another unit has emissions equal to or less than allocations.  The commenter provided no basis for assuming that owners and operators cannot successfully address in private agreements similar issues with regard to to the assurance surrender requirements.
Organization: Northern Indiana Public Service Company (NIPSCO)
Comment: 
Northern Indiana Public Service Company (NIPSCO)
USING DESIGNATED REPRESENTATIVES AS THE BASIS FOR DETERMINING SURRENDER AMOUNTS FOR EXCEEDING VARIABILITY LIMITS
NIPSCO believes that basing surrender amounts on a designated representative ('DR') by DR basis is an improvement over basing the amounts on an owner by owner basis as originally proposed. However, there are potential pitfalls in this new approach as well. Theoretically, a DR could represent more than one company within a state, which could have the effect under EPA's proposal to skew the prorating of the surrender amounts. [EPA-HQ-OAR-2009-0491-3995[1].1, p. 3]
NIPSCO believes a better approach is to determine the number of allowances to be surrendered on an EGU by EGU basis or source by source basis, leaving the responsibility for surrendering the requisite number of allowances to the DRs for the emitting EGUs or sources. This approach is the simplest and most straight-forward. EPA retains its ability to enforce against owners or operators of EGUs for which allowances were not timely surrendered, as owners and operators remain liable for the EGUs for which they are responsible. [EPA-HQ-OAR-2009-0491-3995[1].1, p. 3]
Response: 
See sections VII.E and XI of the preamble.  The commenter suggested that the assurance provisions should be implemented on a source-by-source basis, rather than on the basis of a group of sources with a common designated representative who may represent more than one company in the state.  However, the choice of grouping sources together through a common designated representative is an option that the commenter is not required to select.  The option, which owners and operators are not required to use, provides the potential flexibility of grouping units and sources so that their total emissions does not exceed, or exceeds by less, their total allocations plus share of variability.  Units with greater emissions than allocations plus share of variability can be grouped with units with fewer emissions than allocations plus share of variability. The commenter alternatively suggested that the assurance provisions should be implemented on a unit-by-unit basis.  However, this approach would still involve multiple company-owners since many units have multiple owners, which would have to use private agreements to determine which owners must actually provide allowances for surrender under the assurance provisions.  Under the common-designated representative approach, multiple company-owners can similarly use private agreements to determine which owners must actually provide allowances for surrender.  In addition, the unit-by-unit approach would be inconsistent with the source-by-source approach used for the requirement to hold allowances covering emissions and would provide significantly less flexibility to owners and operators than the common-designated-representative approach in the final rule providing for compliance with the assurance provisions on a source-by-source basis or on the basis of a group of units and sources.  In summary, EPA maintains that implementation of the assurance provisions using common designated representatives (whether the common designated representative for the units at one source or the common designated representative for a group of units and sources) is reasonable. 
Organization: Oglethorpe Power
Comment: 
Oglethorpe Power
Under the proposed CATR, the assurance provisions would be triggered for a state in a given year if total emissions for covered units in the state for the year exceed the state assurance level (i.e., the state budget plus its variability limit). If this level were exceeded, the assurance provision allowance surrender requirement would be imposed on certain owners of covered units in the state (as we understand it, those EGU owners within the state that exceeded their share of the state budget, including variability, regardless of whether the unit had enough allowances to cover its emissions), and would be calculated on an owner-by-owner basis. In NODA 3, EPA requests comment on whether the surrender requirement should be imposed on certain owners and operators of covered units in the state but apportioned on a designated representative ('DR')-by-DR basis, rather than on an owner-by-owner basis. Under this alternative approach, the calculation of shares of covered-unit emissions and of the state budget plus variability would be performed for each group of covered units having a common DR. [EPA-HQ-OAR-2009-0491-3896[1].1, pp.4-5]
Assuming that some type of assurance provisions will become part of the final CATR, EPA must recognize that regardless of the method used by it for assurance apportionment (termed 'calculation' in NODA 3), the basis for liability in law or equity must be based on unit ownership. Here, EPA, states that:
The DR's share of the surrender requírement would equal the amount by which the DR's share of the state's total covered-unit emissions exceeded the DR's share of the state assurance level, divided by the sum of all such exceedances þr all DRs þr covered units in the state. The owners and operators would be collectively and individually liable þr making this allowance surrender and would determine themselves how to dívíde up the actual surrender. 76 Fed. Reg. at l l 17. Given this, it appears that EPA would use the DR as the basis for unit liability, not unit ownership. That approach ignores, however, the basis for liability. Only those covered units that have exceeded their share (i.e., their allocation) of the state budget (plus variability), independent of whom is their DR, can possibly be responsible for an exceedance of the state budget under the assurance provisions. Thus, any approach EPA might use for assurance must, at the outset, recognize which units exceeded their individual budgets. Once that determination is made, EPA could then apportion liability through the DRs for the offending units, and not merely the DR himself (who could also be the DR for units that have not exceeded their allowance budgets). Provided that the CATR requires that DRs for all units reach an agreement with all unit owners prior to assuming the representation, then perhaps EPA could implement its assurance provisions through the DR hierarchy. Under that approach, the provisions governing liability between the various units owners would be controlled by the agreements struck for the appointment of the DR and would not need to be addressed by EPA. [EPA-HQ-OAR-2009-0491-3896[1].1, p.5]
Response: 
See sections VII.E and XI of the preamble.  The commenter stated that EPA must determine liability for assurance penalties on a unit-by-unit basis.  However, under the Acid Rain Program, the CAIR trading programs, and the final Transport Rule trading programs, liability for allowance surrender to cover emissions and for excess emissions penalties are determined on a source-by-source basis, not unit-by-unit basis, and multiple owners of units at a source use private agreements to select the designated representative for the source and to determine which owners must provide the necessary allowances for surrender.  In a similar fashion, the assurance provisions determine liability for allowance surrender under the assurance provisions on a group basis, where the group comprises one or more units and sources with a common designated representative.  Multiple owners of units and sources in such a group will use private agreements to select the designated representative who is common to the units and sources in the group and to determine which owners and operators must provide the necessary allowances for surrender.  
Organization: Prairie State Generating Company, LLC
Comment: 
Prairie State Generating Company, LLC
Allowance surrender determination process which is improved but not ideal [EPA-HQ-OAR-2009-0491-3897[1].1, p.1]
PSGC believes that EPA's recommendation to determine allowance surrender obligations on a designated representative ('DR') by DR basis, in the event of exceedance of the statewide assurance levels, is an improvement over the original proposal. However, theoretically, a DR could represent more than one company, thus implicating companies not responsible for the exceedance of the statewide assurance level unnecessarily and unfairly. Even if a DR represents only a single company, implicating units or sources not responsible for the exceedance of the statewide assurance level is equally unnecessary and unfair. PSGC suggests that the surrender obligation should be determined on a unit by unit or source by source basis, with the surrender of the additional allowances the responsibility of the DR (rather than individual owners). [EPA-HQ-OAR-2009-0491-3897[1].1, p.5]
This same concept has been applied in previous and existing trading programs. EP A is complicating a task which has precedence established in previous and existing programs and should be simple and straightforward. Each facility is required to maintain a compliance account and any exceedance of a state's assurance level should be based on the proportion a unit or facility has contributed to the exceedance of the variability limit. PSGC does not understand the benefit of adding the complicating factor of grouping facilities with a common DR. Although the DR may be the same for a group of facilities, the ownership for those facilities may differ. The assurance provision surrender requirements for variability exceedance should simply be made on a unit by unit or facility by facility basis with notification to the facility's DR as it occurs under previous and existing trading programs. The DR will then ensure allowances are surrendered accordingly. Including owners only complicates the matter and may even cause such confusion that allowances are not surrendered on time as required through no fault of the DR. As the EPA acknowledges, under the Transport Rule the owners and operators will be collectively and individually liable no matter how the allowance surrender requirements are calculated. [EPA-HQ-OAR-2009-0491-3897[1].1, pp.5-6]
Response: 
See sections VII.E and XI of the preamble.  The commenter stated that, if a common designated representative represents multiple sources with multiple company-owners, implementation of the assurance provisions on a common-designated-representative basis may result in "implicating companies...unnecessarily and unfairly".  However, the assurance provisions leave the selection of each source's designated representative entirely up to the source owners and operators, and so having a common designated representative with other companies' sources is entirely optional.  The commenter also stated that there could be a similarly "unnecessary and unfair" result if a common designated representative represents only one source with multiple-company owners.  However, owners and operators already handle situations like this in the context of the requirement to hold allowances to cover emissions, which requirement is imposed in the final rule (and has also been in the Acid Rain Program and the CAIR trading programs) on source-by-source basis.  In fact, multiple owners and operators of units at a source generally use private agreements to determine who will actually provide the allowances that the group of owners and operators are required to surrender in order to meet the requirement to cover the units' emissions.  Similarly, multiple owners and operators of units at a source -- or of a group of units and sources that use the option of having a common designated representative -- can use private agreements to determine who will actually provide the allowances that the group of owners and operators are required to surrender in order to meet the assurance provision penalty.  In short, owners and operators have successfully addressed situations where liability is imposed on a group of multiple owners and operators in connection with the requirement to hold allowances covering emissions, and EPA maintains that there is no reason to assume that they cannot successfully handle these types of situations in connection with the assurance provisions.
The commenter stated that it saw no reason why the assurance provisions could not be implemented on a source-by-source basis rather than on the basis of a group of sources with a common designated representative.  However, the choice of grouping sources together through a common designated representative is an option that the commenter is not required to select.  The option, which owners and operators are not required to use, provides the potential flexibility of grouping units and sources so that their total emissions does not exceed, or exceeds by less, their total allocations plus share of variability.  The commenter also suggested that the assurance provisions could be implemented on a unit-by-unit basis.  However, this approach would still involve multiple owners since many units have multiple owners, would be inconsistent with the source-by-source approach used for the requirement to hold allowances covering emissions, and would provide significantly less flexibility to owners and operators than the approaches provided in the final rule of compliance with the assurance provisions on a source-by-source basis or on the basis of a group of units and sources.  In summary, EPA maintains that implementation of the assurance provisions using common designated representatives (whether the common designated representative for the units at one source or the common designated representative for a group of units and sources) is reasonable. 
Organization: PSEG Services Corporation
Comment: 
PSEG Services Corporation
PSEG recognizes that EPA is looking for opportunities to make the assurance provision allowance surrender requirement more straightforward and the NODA proposes to impose the requirement at the designated representative (DR) level. One reason EPA outlines for switching to the DR-basis is that it would be more consistent with other requirements under the proposed Transport Rule trading programs that are on a unit-by-unit or source-by-source basis. However, EPA designed the assurance provision to provide owners and operators more flexibility than the unit-by-unit or source-by-source compliance requirements. While the PSEG fossil remains in agreement with the intent of the assurance provisions, we caution EPA that the relative benefits of calculating assurance provisions at the DR level would minimize our flexibility. At PSEG, and perhaps other companies, we assign the DR responsibility consistent with direct control of plant operations - the plant manager. Assignment of DR to the plant manager is important to us for accountability and on-site operational availability. [EPA-HQ-OAR-2009-0491-3936[1].1, p.3]
PSEG Fossil recommends maintaining the assurance calculation at the owner level. [EPA-HQ-OAR-2009-0491-3936[1].1, p.3]
Response: 
See sections VII.E and XI of the preamble.  The commenter expressed concern that implementing the assurance provisions on a common-designated-representative basis would minimize flexibility because the commenter assigns plant managers as the designated representatives.  However, a designated representative can be changed simply through submission of a superseding certificate of representation, and EPA has found that designated representatives for many sources are changed relatively frequently.  In light of this and other factors discussed in the preamble, the final rule bases the identification of the groups of one or more units and sources with a common designated representative on the identity of the designated representatives as of a specific date, i.e., April 1 after the control period for which a state triggers the assurance provisions.  This approach will provide flexibility for owners and operators to continue generally to select the plant manager as the designated representative and to select a common designated representative for purposes of the implementation of the assurance provisions.
Organization: Utility Air Regulatory Group (UARG)
Clean Energy Group
Santee Cooper
Tri-State Generation and Transmission Association, Inc.
First Energy
Gainesville Regional Utilities (GRU)
National Grid
Tennessee Valley Authority (TVA)
Florida Municipal Power Agency, Gainesville Regional Utilities, JEA, Orlando Utilities Commission, and City of Tallahassee
Kansas City Power and Light Company (KCP&L)
Great River Energy
Duke Energy
Dominion
Entergy Services, Inc.
Empire District Electric Company (Empire District)
Exxon Mobil Corporation
America's Natural Gas Alliance
West Virginia Department of Environmental Protection
NRG Energy
Xcel Energy Inc.
Maryland Department of Environment (MDE)
Dayton Power and Light Company (DP&L)
American Petroleum Institute (API)
Southern Company
Comment: 
America's Natural Gas Alliance
With respect to the issue of the manner in which the Agency calculates the assurance provision allowance surrender requirements (in the event total emissions from a state in a given year exceed the state assurance level), ANGA believes that it is critically important that the calculation be done in such a way as to enhance both administrative ease (for both covered units and for the Agency) and flexibility. To the extent that the alternative approach outlined in the NODA - calculating it on a Designated Representative (DR) basis rather than on an owner/operator basis - would be simpler to understand and implement, and would provide owners and operators more flexibility than the initially proposed method, ANGA supports such an alternative. [EPA-HQ-OAR-2009-0491-3939[1].1, p.4-5]
American Petroleum Institute (API)
C. API supports the option for an owner to identify a Designated Representative as an alternate the owner-by-owner approach suggested in the proposed CATR. [EPA-HQ-OAR-2009-0491-3982[1].1, p.2]
C. Designated Representative option for allowance surrender
On page 1,117-8 in this NODA, EPA proposes to allow a Designated Representative (DR) as an alternate to the owner-by-owner approach suggested in the proposed CATR. We support the Designated Representative approach which we agree should provide owners with more flexibility to deal with allowance surrender if needed. [EPA-HQ-OAR-2009-0491-3982[1].1, p.4]
API also supports the option for an owner to identify a Designated Representative as an alternate to the owner-by-owner approach. [EPA-HQ-OAR-2009-0491-3982[1].1, p.5]
Clean Energy Group
The Clean Energy Group recognizes that EPA is looking for opportunities to make the assurance provision allowance surrender requirement more straightforward and the NODA proposes to impose the requirement at the designated representative (DR) level. One reason EPA outlines for switching to the DR basis is that it would be more consistent with other requirements under the proposed Transport Rule trading programs that are on a unit-by-unit or source-by-source basis. However, EPA designed the assurance provision to provide owners and operators more flexibility than the unit-by-unit or source-by-source compliance requirements. While the Clean Energy Group remains in agreement with the intent of the assurance provisions, we caution EPA that the relative benefits of calculating assurance provisions at the owner level or the DR level vary from company to company and depend on existing contractual relationships and ownership agreements. While the DR-based calculation provides additional flexibility to some owners and operators, it provides less flexibility to other owners and operators. Given the different ownership structures within the electric sector, individual Clean Energy Group companies will submit specific comments on EPA's proposal to change the basis for the calculation of assurance provision allowance surrender requirements. [EPA-HQ-OAR-2009-0491-4002[1].1, p.3]
Dayton Power and Light Company (DP&L)
E. Should the Assurance Provision Allowance Surrender Requirement be Calculated on a Designated Representative ('DR') Basis?
DP&L agrees with EPA that imposing the proposed assurance provision allowance surrender requirement at the DR level, rather than owner level, is more straightforward and consistent with information already provided to EPA. It also potentially provides owners and operators more flexibility than under the approach in the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3973[1].1, p.3]
A new program of providing and updating ownership share information to EPA would only increase administrative complexity for both utilities and EPA, without providing any additional compliance assurance. [EPA-HQ-OAR-2009-0491-3973[1].1, p.3]
Dominion
Assurance Provisions
EPA is considering applying the allowance surrender requirement for the proposed CATR 'assurance provisions' on a designated representative-by-designated representative (DR-by-DR) basis rather than on an owner-by-owner basis. Since this is more consistent with the approach taken in other aspects of the proposed CATR (such as reporting requirements) as well as other interstate trading programs (such as CAIR and the Acid Rain Title IV programs), we believe this approach is more straightforward. We support this change being incorporated into the final rule. [EPA-HQ-OAR-2009-0491-3987[1].1, p.7]
Duke Energy
EPA requested comments on whether the PTR assurance provision allowance surrender requirements should be calculated on a Designated Representative ("DR") basis rather than on an owner-by-owner basis. Duke Energy agrees with EPA that imposing the assurance provision allowance surrender requirements in the PTR at the DR level would be more straightforward than using owner level, and would be more consistent with information already provided to EPA. It would also be more consistent with other requirements of the PTR that would be imposed on a unit-by-unit basis. Another advantage of applying the assurance provisions at the DR level rather than owner level is it will allow the owners of co-owned units to determine amongst themselves how any potential allowance surrender requirements should be divided up rather than having EPA make this determination. [EPA-HQ-OAR-2009-0491-3965[1].1, p.11]
Empire District Electric Company (Empire District)
An Alternative Approach to Calculation of Assurance Provision Allowance Surrender  
Empire District supports the EPA's proposed alternative calculation of the assurance provision surrender on a DR-by-DR basis rather than an owner-by-owner basis. This would help alleviate the problems caused where an owner, who is not the operator, is located in a G1 state and the joint-owned unit is located in a G2 state, or vice-a-versa. [EPA-HQ-OAR-2009-0491-3883[1].1, p.2]
Entergy Services, Inc.
Calculation Of Assurance Provision Allowance Surrender Requirements
Entergy supports the calculation of assurance provision allowance surrender requirements on a Designated Representative (DR) basis.  As the EPA has mentioned in the NODA, imposing the proposed assurance provision allowance surrender requirement at the DR level, rather than owner level, potentially provides owners and operators with more flexibility than under the approach in the proposed Transport Rule while ensuring that the issue of interstate transport is addressed. [EPA-HQ-OAR-2009-0491-3986[1].1, p.2]
Exxon Mobil Corporation
8. Designated Representative - At 76 Federal Register 1117-1118 in Section VI. EPA proposes to allow a Designated Representative (DR) as an alternate the owner-by-owner approach suggested in the proposed CATR. We support the Designated Representative approach which we agree should provide owners with more flexibility to deal with allowance surrender if needed. [EPA-HQ-OAR-2009-0491-3999[1].1, p.3]
First Energy
FirstEnergy supports the EPA's alternative approach to the assurance provisions on an Owner by Owner basis instead of the Designated Representative ("DR") by DR basis. The DR by DR assurance provision simplifies the responsibility of a utility to manage and track CATR allocations. [EPA-HQ-OAR-2009-0491-3904[1].1, p.3]
Florida Municipal Power Agency, Gainesville Regional Utilities, JEA, Orlando Utilities Commission, and City of Tallahassee
Assurance and Allowance Surrender Responsibilities: Several of our utilities currently have partial ownership or co-ownership in fossil-fuel units. We believe that having the DR for the facility or group of facilities, instead of potentially multiple owners, responsible for both assurance and allowance surrender requirements make the most sense from an administrative standpoint. [EPA-HQ-OAR-2009-0491-3907[1].1, p.2]
Gainesville Regional Utilities (GRU)
While GRU does not currently have partial ownership in any fossil-fuel units, it may be the case in the future. We believe that having the DR for the facility as opposed to multiple owners responsible for both assurance and allowance surrender requirements make sense from an administrative standpoint. [EPA-HQ-OAR-2009-0491-3922[1].1, p.2]
Great River Energy
Great River Energy supports the surrender requirement for exceedence of the state assurance level on a designated representative level.  [EPA-HQ-OAR-2009-0491-3898[1].1, p.5]
In its January 7, 2011 NODA, EPA seeks comment on allocation surrender requirements. GRE generally supports keeping the surrender requirements at a designated representative level, which is consistent with the Acid Rain program. [EPA-HQ-OAR-2009-0491-3898[1].1, p.5]
Kansas City Power and Light Company (KCP&L)
An alternative approach to calculation of assurance provision allowance surrender requirements at the designated representative (DR) level:
KCP&L supports applying the allowance surrender requirement for the Proposed Transport Rule's assurance provisions on a DR basis rather than on an owner-by-owner basis. A DR-based requirement is more in line with the approach taken not only in other aspects of the Proposed Transport Rule but also in other interstate emissions allowance trading programs. Applying the surrender requirements on a DR basis would avoid the need for EPA to obtain detailed ownership information for individual units. It would also avoid the complications arising from dividing up units' emissions and allocations among partial owners of the regulated units. Calculation at the DR level would be more straightforward and more consistent with information already provided to the EPA. [EPA-HQ-OAR-2009-0491-3893[1].1, p.3]
Maryland Department of Environment (MDE)
3. Whether, the assurance provision allowance surrender requirement should be calculated on a designated representative basis
ARMA supports EPA's proposed approach of calculating the allowance surrender requirement on a designated representative basis, and we agree with EPA's assessment that it is more straightforward and should provide greater flexibility to owners and operators of Transport Rule units compared with EPA conducting this calculation on an owner-by-owner basis. [EPA-HQ-OAR-2009-0491-3972[1].1, p.3]
National Grid
National Grid supports the NODA proposal to impose the requirements of the assurance provision at the designated representative (DR) level rather that the owner level. Though initial compliance is determined at the facility level, the EPA designed the assurance provision to provide owners and operators more flexibility than the unit-by-unit or source-by-source compliance requirements. For National Grid, this flexibility is best achieved at the Designated Representative level rather that the owner level since several units may be under different corporate ownership but all units have the same Designated Representative. [EPA-HQ-OAR-2009-0491-3921[1].1, pp.1-2]
NRG Energy
 EPA Question  -  Should the Assurance Provision be calculated on a Designated Representative Basis or an Owner Basis?  
While NRG is indifferent to this option, the Designated Representative approach is more efficient and consistent with practices for other programs.  [EPA-HQ-OAR-2009-0491-3933[1].1, p.8]  
Santee Cooper
Santee Cooper also supports EPA's proposal to require compliance with assurance provisions on a DR basis, as explained further below. [EPA-HQ-OAR-2009-0491-3913[1].1, p.2]
Santee Cooper supports EPA's proposal to determine compliance with the Transport Rule's assurance provisions at the DR level, rather than on an owner-by-owner basis.7 We agree with EPA that DR-level compliance will afford owners of EGUs an additional measure of flexibility to comply with the assurance provisions, by allowing owners. to group high and low-emitting units together under common DRs. This flexibility will ensure that total state emissions remain within the variability limit, while avoiding the imposition of unreasonable penalties on utilities that experience increases in emissions at one EGU and compensating decreases in emissions at other EGUs. [EPA-HQ-OAR-2009-0491-3913[1].1, p.4]
As EPA indicates in the NODA, DR-level compliance with the assurance provisions will also promote administrative efficiency. With DR-level compliance, regulated entities (and EPA) will be spared the complex task of determining the ownership of individual EGUs and properly attributing the emissions of those EGUs to their owners. In addition, the DR is the principal entity responsible for compliance with other EPA regulatory programs. Vesting responsibility for compliance with the assurance provisions with the DR is consistent with tins long-standing practice. [EPA-HQ-OAR-2009-0491-3913[1].1, pp.4-5]
In light of these benefits, Santee Cooper sees no compelling reason to preserve the owner-level compliance mechanism of the proposed Transport Rule, and recommends that EPA adopt the NODA's DR-level compliance proposal. [EPA-HQ-OAR-2009-0491-3913[1].1, p.5] 

7 Santee Cooper's comments on this aspect of the NODA do not reflect a change from our earlier comments on the proposed Transport Rule. In particular, Santee Cooper continues to believe that the 3- year variability limit is unnecessary and unworkable and should be omitted from the final rule.
Southern Company
In the NODA3, EPA requests comment on two issues relating to the assurance provisions of the proposed Transport Rule. Specifically, EPA requests comment on implementing the proposed assurance provisions on a designated representative-by-designated representative basis, rather than owner-by-owner basis. [EPA-HQ-OAR-2009-0491-3946[1].1, p.10]
First, Southern Company agrees with EPA's decision to consider applying the allowance surrender requirement of the proposed assurance provisions on a DR-by-DR basis, rather than an owner-by-owner basis. This approach appears to be more straight-forward and more in line with the approach taken in other aspects of the proposed Transport Rule and other interstate trading programs. However, EPA should be cautious not to include language that would undermine any agreements between joint owners or otherwise set expectations that the actual penalty allowance obligations should not be tied to ownership. [EPA-HQ-OAR-2009-0491-3946[1].1, p.10]
Tennessee Valley Authority (TVA)
In response to EPA's request for comments concerning the Calculation of Assurance Provision Allowance Surrender Requirements, TVA agrees with EPA's decision to consider applying the allowance surrender requirement on a designated-representative-by-designated-representative basis rather than on an owner-by-owner basis. This will more correctly place the responsibility of making emission reduction decisions on those responsible for operating the plants, and avoid the complication caused by having multiple owners of individual units divide up the units' emissions and allocations. Further, a designated representative-based approach is consistent with the approach taken by EPA in other interstate trading programs. [EPA-HQ-OAR-2009-0491-3983[1].1,p.2]
Tri-State Generation and Transmission Association, Inc.
Tri-State supports the proposed alternative provisions in the NODA to impose the assurance provision allowance surrender requirements on a designated-representative-by-designated- representative basis. Many of the generating units that Tri-State operates have multiple owners, and Tri-State retains ownership in units that are operated by other organizations. Tri-State agrees with EPA that imposing the assurance provision allowance surrender requirements at the designated-representative level rather than the owner level is more straightforward and consistent with information already provided to EPA, and potentially provides owners and operators with more flexibility than under the approach in the proposed Transport Rule. Tri-State appreciates EPAs willingness to consider and promote this alternative. [EPA-HQ-OAR-2009-0491-3902[1].1, p.3]
Utility Air Regulatory Group (UARG)
Finally, UARG agrees with EPA's decision to consider applying the allowance surrender requirement for the Proposed Transport Rule's "assurance provisions" on a designated-representative- by-designated-representative basis rather than on an owner-by-owner basis. See 76 Fed. Reg. at 1117. As EPA suggests, a DR-based requirement is more in line with the approach taken not only in other aspects of the Proposed Transport Rule but also in other interstate emission allowance trading programs. Applying any assurance provision allowance surrender requirements on a DR-by-DR basis should avoid any need by EPA to "obtain detailed ownership information (such as [information on] percentage ownership in individual units)." Id. In addition, adopting a DR-by-DR basis for these requirements would "avoid the complications arising from having to divide up units' emissions and allocations among partial owners of the units." Id. Thus, it seems likely that a DR-by-DR approach to applying these requirements would prove to be both "more straightforward" than an owner-by-owner approach and more "consistent with information already provided to EPA." Id. [EPA-HQ-OAR-2009-0491-3979[1].1, pp.3-4]
West Virginia Department of Environmental Protection
Alternative of implementing the proposed assurance provisions on a DR-by-DR basis, rather than owner-by-owner basis
The WVDAQ supports the implementation of the assurance provisions on a DR-by-DR (Designated Representative) basis, with the inclusion of the proposed alternative calculation method for variability. As we commented in our September 30, 2010 letter, we generally support the variability and assurance provisions, with the inclusion of the proposed alternative calculation method for variability. Since each unit can have only one DR, but may have multiple owners, the WVDAQ believes that implementation on a DR-by-DR basis simplifies the application of the assurance provisions, and is straight forward and transparent. [EPA-HQ-OAR-2009-0491-4000[1].1, p.2]
Xcel Energy Inc.
We support maintaining the assurance provision irrespective of the allocation methodology, with an allowance surrender requirement calculated on a Designated Representative basis. [EPA-HQ-OAR-2009-0491-3948[1].1, p.2]
EPA asked for comment on whether the assurance provision surrender requirement should be calculated on a Designated Representative basis. Xcel Energy supports this provision for the simple reason that it makes the program more similar to EPA's highly successful Acid Rain Program in terms of allowance surrender provisions. We further support requiring the generator(s) that trigger the assurance provision to surrender allowances proportional to their respective contribution to any exceedence of the variability limit over the state budget. [EPA-HQ-OAR-2009-0491-3948[1].1, pp.3-4]
Response: 
See sections VII.E and XI of the preamble. 
Organization: Westar Energy, Inc.
Comment: 
Westar Energy, Inc.
The NODA seeks to replace the owner-by-owner approach to allowance surrenders with a designated representative ("DR") approach under which the "calculation of shares of covered-unit emissions and of the state budget plus variability would be performed for each group of covered units having a common DR." 76 FR 1117/-2. Each group having a common DR ('DR Group') would agree as to how to split the DR Group's allowance surrender among themselves, though they would be all jointly and individually liable for the DR Group's allowance surrender requirement. Id. The NODA proffers that the DR approach offers potentially more flexibility, is 'more straightforward' and consistent with information already reported to EPA, would 'eliminate the need to collect detailed ownership information and would also avoid the complications arising from having to divide up units' emissions and allocations among partial owners of the units.' Id. at 1117/3/ Westar doubts that any of those so-called benefits will be realized under a DR Group's approach. [EPA-HQ-OAR-2009-0491-3952[1].1, pp.5-6]
Initially, the benefits appear to ease EPA's administrative burden of the allowance surrender program, rather than reduce the burden for owners. Under a DR Group approach, owners will still be required to negotiate the allowance surrenders within the group and to enforce their agreement. EPA says the change will "eliminate the need to collect detailed ownership information and would also avoid the complications arising from having to divide up units' emissions and allocations among partial owners of the units." Id. While that may be true for EPA, it is not true for owners: detailed information will still have to be collected and complications of partial ownership will still have to be solved in the DR Group negotiations. Using the DR Group's approach simply shifts those problems to the owners within a DR Group, and may actually prove even more problematic in that context because owners must spend time, effort, and expense negotiating these matters within the DR Groups. The negotiations process seems likely to produce, at best, marginal differences from EPA-established unit allowances as the basis for sharing allowance surrenders, and thus offer little flexibility beyond what the Transport Rule and NODA establish. [EPA-HQ-OAR-2009-0491-3952[1].1, p.6]
Further, as the DR Group process is voluntary, there will likely be a patchwork of responses, with some units subject to a DR Group agreement and others that are not in a DR Group subject presumably to EPA's owner-by-owner rules. Also of concern is whether the DR Group approach limits allowance trading to only those owners within the same DR Group due to explicit or implicit pressure to assure the group has adequately protected its position against a possible allowance surrender. The NODA fails to explore whether these potential effects of a NODA approach are consistent with the stated objectives of the Transport Rule to offer interstate trading within group 1 or group 2 States. Aside from that, the DR Group agreements might foster policies in a particular region that are inconsistent with the Rule's objectives. [EPA-HQ-OAR-2009-0491-3952[1].1, pp.6-7]
Nothing in the NODA demonstrates that a DR Group approach provides an appropriate means to carry out the Rule's plan. Nor has EPA provided a means by which it would oversee DR Groups to assure that they do so. That stands in sharp contrast to how EPA has limited States to full or abbreviated SIPs if they want to benefit from the trading programs. Not only does this raise issues of whether a DR Group approach constitutes an improper delegation of authority, but also it fails to offer transparency and assurances of uniform treatment under the allowance surrender program. While the owner-by-owner approach has defects, it does offer transparency and uniform treatment to all units in similar circumstances. Those factors outweigh any supposed benefits claimed for a DR Group program. [EPA-HQ-OAR-2009-0491-3952[1].1, p.7]
Response: 
See sections VII.E and XI of the preamble to the final Transport Rule.  The commenter claimed that the common-designated-representative approach in the assurance provisions simply "shifts" the "problems" of collecting ownership information and addressing partial ownership from EPA to the owners and operators.   EPA recognizes that units at sources (plants) may have multiple owners and, in fact, the identity and percentage shares of the multiple owners may vary from unit to unit at the same source and can change during the year.  For this reason, the final rule requires that each source have one designated representative for all of the owners and operators and implements the requirement to hold allowances covering emissions on a source (i.e., designated representative) basis. For purposes of dividing up ownership of allowance allocations and meeting the requirement to hold allowances covering the source's emissions, owners and operators already have to determine the identity and shares of multiple owners and operators of units at the same source.  Owners and operators have handled these situations under the Acid Rain Program and the CAIR trading programs through private agreements and can continue to do so under the Transport Rule trading programs.  Similarly, because owners and operators (and not EPA) have access to information on an ongoing basis on the identity and percentage shares of multiple owners and already make decisions about the shares of emissions and allowances to be attributed to the various owners, EPA maintains that it is reasonable to implement the assurance provisions on a common-designated-representative basis, rather than on an owner-by-owner basis.  This approach also provides more flexibility for owners and operators of only one or a few units in a state -- as compared to implementation on a unit-by-unit basis -- because such owners and operators can use their grouping with any other units at their source (which necessarily have the same, i.e., common, designated representative) and can also decide to group their units with units at other sources in the state by selecting, in coordination with owners and operators of such other units, a common designated representative. 
The commenter expressed concern that the common-designated-representative approach will result in a "patchwork" with some units subject to a "DR Group agreement" and some units not in a "DR Group" and subject to an "owner-by-owner" approach.  Under the Transport Rule trading programs, like under the Acid Rain Program and the CAIR trading programs, every source must have a designated representative representing all the owners and operators of units at the source.  Thus, all units at each source have the same designated representative (i.e., a common designated representative), but the owners and operators of multiple sources have the option to choose a common designated representative for the group of sources.  In short, every unit has a common designated representative, either at the source level or, if the option is taken by the owners and operators of multiple sources, at the group-of-sources level.  A source, or group of sources, having multiple owners and operators can use private agreements to address the distribution of responsibilities for actually providing allowances for the assurance penalty in the event that the state triggers the assurance provisions and the owners and operators of the source or the group are subject to the assurance penalty.  The assurance provisions in the final rule adopt a common-designated-representative approach and not an owner-by-owner approach.
The commenter made vague claims that there would be "explicit or implicit pressure" on units in a "DR Group" to limit allowance trading to members of the group in order to protect against a possible assurance surrender and that "DR Group agreements might foster policies inconsistent with" the Transport Rule's objectives.  However, the commenter failed to identify the source of such "pressure" and failed to explain why retaining allowances within the group of sources and units with a common designated representative would "protect" against a possible assurance surrender requirement.  In the final rule, for each group of units and sources with a common designated representative, total emissions are compared to total allocations plus share of variability, and whether the allocations continue to be held or are sold does not affect the determination of whether the owners and operators of the group are subject to the assurance surrender requirement if the state triggers the assurance provisions. Further, the commenter failed to explain, even with hypothetical examples, how private agreements among owners and operators to select a common designated representative and to address who will actually provide allowances necessary to meet any assurance surrender requirement would have results inconsistent with the elimination of states' significant contribution and interference with maintenance or any other aspect of the Transport Rule.  EPA rejects the commenter's claims as vague, speculative, and unsupported.
Organization: Wolverine Power Supply Cooperative
Comment: 
Wolverine Power Supply Cooperative
ASSURANCE PROVISIONS ON A DR BY DR BASIS
Regarding the USEPA's request for comment on implementing the compliance assurance provisions on a Designated Representative (DR) by DR basis rather than an Owner by Owner basis, Wolverine supports  this concept as being more consistent with past practice and simpler to implement because of multiple owner arrangements on many affected units. This change does not, however, resolve our concern expressed in our October 1, 2010, comments that large generating systems are at a great advantage over stranded units and small systems, and that the proposed assurance provisions will structurally provide market concentration as well as incentive for large generating systems to hoard allowances and potentially manipulate allowance markets. The DR by DR change would in no way remedy this defect in the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-4014[1].1, pp. 4-5]
Response: 
See section VII.E of the preamble.  The commenter expressed concern over "stranded units and small systems" being disadvantages under the assurance provisions.  The approach in the final rule of implementing the assurance provisions on a common-designated-representative basis provides flexibility for such units and systems in a state to group together under a common designated representative and thereby potentially reduce or eliminate the group's excess of total emissions over total allocations plus share of variability and thus the group's  share of any assurance provision penalty in the event the state triggers the assurance provisions.  The commenter also stated, without explanation or support, that the assurance provisions will "structurally provide market concentration" and incentives for allowance hoarding  and market manipulation.  In particular, the commenter failed to explain what "structure" of the assurance provisions will cause "market concentration" or what the commenter means by "market concentration".  Further, the commenter failed to explain what the commenter means by "manipulation" and how the assurance provisions encourage hoarding and manipulation.  EPA therefore rejects the commenter's claim as vague, speculative, and unsupported.

XX.C. Whether Assurance Provision Approach Should Be Maintained if Allocation Approach is Changed

Organization: Ameren Services Company
Comment: 
Ameren Services Company
EPA asks 'Whether the Overall Assurance Provision Approach Should Be Maintained if One of the Alternative Allocation Methodologies Is Used in the Final Transport Rule' (Page 1118). Ameren believes that the Assurance Provisions as described in the proposed Transport Rule have merit and should be maintained. [EPA-HQ-OAR-2009-0491-3894[1].1, p.3]
Response: 
EPA is maintaining the overall assurance provision approach in the final Transport Rule, except that, if the assurance provisions are triggered in a state, the determination of which owners and operators of units in the state must surrender allowances for the assurance penalty is determined at the common designated representative level, rather than the owner level.  See section VII.E of the preamble. 
Organization: America's Natural Gas Alliance
Comment: 
America's Natural Gas Alliance
ANGA also suggests that the Agency ensure that whatever method the Agency ultimately adopts for calculating the allowance surrender requirements does not impact the overall goal of the assurance provision - ensuring that statewide emissions meet the assurance level cap (essentially the state budget plus the variability allowance). [EPA-HQ-OAR-2009-0491-3939[1].1, p.5]
Response: 
EPA is maintaining the overall assurance provision approach in the final Transport Rule, except that, if the assurance provisions are triggered in a state, the determination of which owners and operators of units in the state must surrender allowances for the assurance penalty is determined at the common designated representative level, rather than the owner level.  See section VII.E of the preamble. 
Organization: Clean Energy Group
Comment: 
Clean Energy Group
The Clean Energy Group agrees with EPA's conclusion that changing the allocation methodology does not require a change in the proposed assurance provisions. The assurance provisions would create a powerful incentive to operate pollution control equipment rather than buy allowances. With a sufficient allowance price, the requirement that an owner surrender an additional allowance for every ton it contributes to a state exceeding its variability limit will likely result in companies limiting their reliance upon purchased allowances. Instead, companies will look to achieve further emissions reductions. This would ensure reductions occur in the necessary states so as to meet the requirements of section 110, clarified in the D.C. Circuit decision. Some Clean Energy Group companies' individual comments will suggest additional opportunities to further strengthen the assurance provisions. [EPA-HQ-OAR-2009-0491-4002[1].1, pp.2-3]
Response: 
EPA is maintaining the overall assurance provision approach in the final Transport Rule, except that, if the assurance provisions are triggered in a state, the determination of which owners and operators of units in the state must surrender allowances for the assurance penalty is determined at the common designated representative level, rather than the owner level.  See section VII.E of the preamble. 
Organization: Cleco Corporation
Comment: 
Cleco Corporation
A. Assurance provisions (i.e., penalty provisions) exacerbate the windfall problem; to the extent the windfall is not removed.
EPA proposes to determine an owner or operator's obligation to surrender a penalty allowance based on a comparison of emissions to allocations. If the allocations are unrealistically high for some units (e.g., because EPA does not correct windfall) then those units would almost certainly never trigger penalty provisions. The units that are correspondingly under-allocated allowances, on the other hand, would bear the full brunt of the penalty provisions if a state exceeded its variability limit. [EPA-HQ-OAR-2009-0491-4007[1].1, pp.6-7]
Response: 
EPA is maintaining the overall assurance provision approach in the final Transport Rule, except that, if the assurance provisions are triggered in a state, the determination of which owners and operators of units in the state must surrender allowances for the assurance penalty is determined at the common designated representative level, rather than the owner level.  This approach will allow owners and operators of individual units greater flexibility in meeting the assurance provisions.  For example, owners and operators will have the ability to select a common designated representative for a group of units reflecting different unit types, technologies, fuel types, and types of emissions controls and, in this way, address any potential disadvantages that individual units might otherwise have under the assurance provisions.   See section VII.E of the preamble.  Further, EPA is finalizing an allowance allocation approach that is based on historic heat input and limits each unit's allocation to its maximum historic emissions.  See section VII.D of the preamble.
Organization: Constellation Energy
Comment: 
Constellation Energy
Constellation Energy suggests changing the proposed assurance provisions if Option 1 or Option 2 allocations are Implemented.
Combined with Option 1 or Option 2 allocations, the current assurance provisions are too onerous for some generators and may be technically unachievable. We are concerned that, as proposed, even very well controlled units could invoke the assurance penalties. Constellation Energy suggests that EPA incorporate an engineering analysis into the assurance provisions to ensure that they are technically achievable by existing facilities. [EPA-HQ-OAR-2009-0491-4031, p.3]
Response: 
EPA is maintaining the overall assurance provision approach in the final Transport Rule, except that, if the assurance provisions are triggered in a state, the determination of which owners and operators of units in the state must surrender allowances for the assurance penalty is determined at the common designated representative level, rather than the owner level.  This approach will allow owners and operators of individual units greater flexibility in meeting the assurance provisions.  For example, owners and operators will have the ability to select a common designated representative for a group of units reflecting different unit types, technologies, fuel types, and types of emissions controls and, in this way, address any potential disadvantages that individual units might otherwise have under the assurance provisions.   See section VII.E of the preamble.  Consequently, it is difficult to understand the basis for the commenter's vague and unsupported concern about whether the assurance provisions are "technically achievable".  Further, EPA is finalizing an allowance allocation approach based on historic heat input and which limits each unit's allocation to its maximum historic emissions.  See section VII.D of the preamble.
Organization: Dynegy, Inc.
Comment: 
Dynegy, Inc.
To avoid the inequity inherent in punishing EGU systems that have installed and operated air pollution controls, EPA should in the first instance apply the assurance provision penalties to those owners (or, as proposed in the NODA. units with the same designated representative) that have not installed and/or do not operate emissions control technology. Because owners of well-controlled units have already made substantial investments in and installed air pollution control technologies, they should not be the primary target of the assurance pro vision penalties for contributing to downwind nonattainment. Simply put, it would be more appropriate and reasonable for the uncontrolled (or under-controlled) units to bear the brunt of the assurance provision penalties. Thus, EPA should delink the assurance provisions and allocations and instead focus the assurance provision penalties on uncontrolled units. [EPA-HQ-OAR-2009-0491-3944[1].1, p.4]
Response: 
EPA is maintaining the overall assurance provision approach in the final Transport Rule, except that, if the assurance provisions are triggered in a state, the determination of which owners and operators of units in the state must surrender allowances for the assurance penalty is determined at the common designated representative level, rather than the owner level.  EPA believes that this approach does not disadvantage "well-controlled" units because the allowance allocation methodology for existing units is fuel and emission control neutral, with the result that "well-controlled" units, as a group, are not disadvantaged by allowance allocations and by the assurance provisions requiring allowance surrender when emissions exceed allocations plus a share of the state variability limit.  See section VII.D of the preamble.  In addition, the final assurance provisions provide owners and operators of individual units flexibility in complying with assurance requirements.  For example, owners and operators will have the ability to select a common designated representative for a group of units reflecting different unit types, technologies, fuel types, and types of emissions controls and, in this way, address any potential disadvantages that individual units might otherwise have under the assurance provisions.   See section VII.E of the preamble. 
Organization: GenOn Energy, Inc.
Comment: 
GenOn Energy, Inc.
IV. The compliance assurance provisions in the Proposed Transport Rule will no longer be workable if EPA chooses either of the options in NODA 3.
In the current NODA, EPA specifically asks for comments on 'whether the overall assurance provision approach should be maintained if one of the alternative allocations methodologies is used in the final Transport Rule.' 76 Fed. Reg. at 1118. For the reasons discussed below, the proposed compliance assurance provisions simply will not work if the Agency adopts either of the allocation schemes in NODA 3. [EPA-HQ-OAR-2009-0491-3996[1].1, p. 9]
Response: 
EPA is maintaining the overall assurance provision approach in the final Transport Rule, except that, if the assurance provisions are triggered in a state, the determination of which owners and operators of units in the state must surrender allowances for the assurance penalty is determined at the common designated representative level, rather than the owner level.  This approach will allow owners and operators of individual units greater flexibility in meeting the assurance provisions.  For example, owners and operators will have the ability to select a common designated representative for a group of units reflecting different unit types, technologies, fuel types, and types of emissions controls and, in this way, address any potential disadvantages that individual units might otherwise have under the assurance provisions.   See section VII.E of the preamble.  Consequently, it is difficult to understand the basis for the commenter's vague and unsupported claim that the assurance provisions will not be "workable".  Further, EPA is finalizing an allowance allocation approach based on historic heat input and which limits each unit's allocation to its maximum historic emissions.  See section VII.D of the preamble.
Organization: Maryland Department of Environment (MDE)
Comment: 
Maryland Department of Environment (MDE)
4. Whether the overall assurance provision approach should be maintained if one of the alternative allocation methodologies is used in the final Transport Rule
In the NODA, EPA states that it does not believe that the assurance provision approach needs to be changed in response to a change in the allocation methodology, but that EPA may reevaluate some of the details of the assurance provisions (76 FR 1118). ARMA strongly supports EPA reevaluating some details of the assurance provisions, such as the proposed variability limits for each state and the allowance surrender levels. [EPA-HQ-OAR-2009-0491-3972[1].1, p.3]
Response: 
EPA is maintaining the overall assurance provision approach in the final Transport Rule, except that, if the assurance provisions are triggered in a state, the determination of which owners and operators of units in the state must surrender allowances for the assurance penalty is determined at the common designated representative level, rather than the owner level.  See section VII.E of the preamble. 
Organization: Michigan Municipal Electric Association (MMEA)
Comment: 
Michigan Municipal Electric Association (MMEA)
EPA suggests in the 3rd NODA that "those groups of units with total emissions exceeding their total allowance allocations plus their share of state variability . . . would reasonably be viewed as accounting for the state's exceedance and thus should be subject to proportionate shares of the allowance surrender penalty." 76 Fed. Reg. at 1118. However, small municipal units will be part of the group that "exceed[s] their total allowance allocations plus their share of state variability", but they will not be the ones to cause state assurance exceedances. EPA does not consider that this assumption will particularly harm small municipal utility units in Michigan that have relied on EPA-approved hardship allowances, and that have no time or ability to start from scratch now to apply cost-prohibitive controls. [EPA-HQ-OAR-2009-0491-4020[1].1, p.7]
Response: 
EPA is maintaining the overall assurance provision approach in the final Transport Rule, except that, if the assurance provisions are triggered in a state, the determination of which owners and operators of units in the state must surrender allowances for the assurance penalty is determined at the common designated representative level, rather than the owner level.  This approach will allow owners and operators of individual units greater flexibility in meeting the assurance provisions.  For example, owners and operators will have the ability to select a common designated representative for a group of units (such as a group that combines small municipal utility units with other units)  reflecting different unit types, technologies, fuel types, and types of emissions controls and, in this way, address any potential disadvantages that individual units might otherwise have under the assurance provisions.  See section VII.E of the preamble.  Further, if a state triggers the assurance provisions by having total emissions exceeding the state budget plus variability, it is difficult to see how the commenter can dispute the fact that any unit that purchases and uses allowances issued in a different states to cover its emissions will be contributing to the state's triggering of the assurance provisions.  Moreover, EPA is finalizing an allowance allocation approach under the FIPs based on historic heat input and which limits each unit's allocation to its maximum historic emissions and finalizing provisions under which states can replace FIP existing unit allocations starting with 2013 and existing and new unit allocations starting with 2014.  See sections VII.D and X of the preamble.
Organization: National Mining Association (NMA)
Comment: 
National Mining Association (NMA)
The adverse financial impact to coal of the heat-input methodologies is not limited to just the allocations. That impact is magnified by EPA's method for determining which units owe penalty allowances under the assurance provisions. [EPA-HQ-OAR-2009-0491-4013[1].1, p.6]
Under the assurance provisions, EPA proposes to require one additional penalty allowance for each ton of emissions in excess of the state budget plus the variability limit. EPA has proposed attributing the penalty based on a comparison of emissions to allocations at the owner level or at the designated representative level. In either case, whether a penalty is owed is based on the extent to which emissions exceed allocations. Thus, under-allocated units, owners or designated representatives have much greater exposure to the penalties than properly allocated units, owners or designated representatives. [EPA-HQ-OAR-2009-0491-4013[1].1, p.6]
The penalty is likely to be triggered in a particularly hot summer where there is unusually high energy demand. In such an event, a unit like the Fairless Energy Center in Pennsylvania, a natural gas-fired unit, which under the heat-input methodology is allocated allowances equal to over 600 times its historical maximum annual SO2 emissions, would never trigger a penalty no matter how much it ran. An under-allocated coal unit on the other hand may far exceed its allocation in a hot summer and incur the full brunt of the rule's penalty provision. Where allocations are based on emissions, this penalty burden  -  again, likely triggered in a particularly hot summer  -  is born more evenly. Coal-fired generation is still likely to incur more penalties than natural gas, but would not likely share the burden alone. [EPA-HQ-OAR-2009-0491-4013[1].1, pp.6-7]
Response: 
EPA is maintaining the overall assurance provision approach in the final Transport Rule, except that, if the assurance provisions are triggered in a state, the determination of which owners and operators of units in the state must surrender allowances for the assurance penalty is determined at the common designated representative level, rather than the owner level.  This approach will allow owners and operators of individual units greater flexibility in meeting the assurance provisions.  For example, owners and operators will have the ability to select a common designated representative for a group of units reflecting different unit types, technologies, fuel types, and types of emissions controls and, in this way, address any potential disadvantages that individual units might otherwise have under the assurance provisions.   See section VII.E of the preamble. 
Further, EPA is finalizing an allowance allocation approach based on historic heat input and which limits each unit's allocation to its maximum historic emissions.  This will prevent natural gas units from receiving SO2 allowances equal to multiple times their potential emissions.  See section VII.D of the preamble.
Organization: NextEra Energy, Inc.
Comment: 
NextEra Energy, Inc.
First of all, NextEra Energy agrees with EPA's conclusion that changing the allowance allocation methodology does not require a change in the proposed compliance assurance provisions. As explained in the proposed Transport Rule, in the event that a state's total emissions exceeds the state budget plus variability, those groups of units (whether grouped by owner as in the proposal or by common DR as discussed in the NODA) with an analogous exceedance (i.e., those groups of units with total emissions exceeding their total allowance allocations plus their shares of state variability) would reasonably be viewed as accounting for the state's exceedance and, thus, should be subject to proportionate shares of the allowance surrender penalty. Even under a different allowance allocation methodology than the allocation methodology proposed in the Transport Rule, it would continue to be the case that groups of units with greater emissions than their allocations plus share of state variability would reasonably be held responsible for the state's excess of emissions over the state assurance level. EPA believes that any state that would exceed its state assurance level would likely do so because not all units would have made the reductions necessary to eliminate the state's contribution to nonattainment or interference with maintenance. Moreover, the groups of units with emissions exceeding their allocations plus share of variability would be the units that were most likely to have contributed to the state's exceedance of its state assurance level and, thus, to the state's triggering of the assurance provisions. Consequently, it would be reasonable to penalize those groups of units (whether grouped by owner or by common DR)-through application of the assurance provision allowance surrender requirement-for the state's exceedance. [EPA-HQ-OAR-2009-0491-3962[1].1, p.4]
Response: 
EPA is maintaining the overall assurance provision approach in the final Transport Rule, except that, if the assurance provisions are triggered in a state, the determination of which owners and operators of units in the state must surrender allowances for the assurance penalty is determined at the common designated representative level, rather than the owner level.  See section VII.E of the preamble. 
Organization: NRG Energy
Comment: 
NRG Energy
Assurance Provision and Variability  -  We endorse EPA's assurance provision and inclusion of a variability penalty. This provision provides incentive for participating units and states to achieve the modeled reductions. We are concerned that under the current proposals for Option 1 and 2, the plant and state allocations are out of sync and could challenge severely under allocated facilities. [EPA-HQ-OAR-2009-0491-3933[1].1, p.6]
Response: 
EPA is maintaining the overall assurance provision approach in the final Transport Rule, except that, if the assurance provisions are triggered in a state, the determination of which owners and operators of units in the state must surrender allowances for the assurance penalty is determined at the common designated representative level, rather than the owner level.  This approach will allow owners and operators of individual units greater flexibility in meeting the assurance provisions.  For example, owners and operators will have the ability to select a common designated representative for a group of units reflecting different unit types, technologies, fuel types, and types of emissions controls and, in this way, address any potential disadvantages that individual units might otherwise have under the assurance provisions.   See section VII.E of the preamble.  Further, EPA is finalizing an allowance allocation approach that is based on historic heat input and limits each unit's allocation to its maximum historic emissions.  See section VII.D of the preamble.
Organization: Prairie State Generating Company, LLC
Comment: 
Prairie State Generating Company, LLC
Variability limits in Illinois which need reconsideration to accommodate newly constructed units [EPA-HQ-OAR-2009-0491-3897[1].1, p.1]
As long as the variability limits are necessary and have been calculated correctly, PSGC agrees with EPA's assessment that a change in allocation methodology would not necessitate any changes in the assurance provisions. [EPA-HQ-OAR-2009-0491-3897[1].1, p.6]
Response: 
With regard to the variability limits, see sections E and F of the preamble.
With regard to the assurance provisions, see section VII.E of the preamble.  EPA is maintaining the overall assurance provision approach in the final Transport Rule, except that, if the assurance provisions are triggered in a state, the determination of which owners and operators of units in the state must surrender allowances for the assurance penalty is determined at the common designated representative level, rather than the owner level. 
Organization: PSEG Services Corporation
Comment: 
PSEG Services Corporation
PSEG Fossil agrees with EPA's conclusion that changing the allocation methodology does not require a change in the proposed assurance provisions. The assurance provisions would create a powerful incentive to operate pollution control equipment rather than buy allowances. With a sufficient allowance price, the requirement that an owner surrender two allowances for every ton it contributes to a state exceeding its variability limit will likely result in companies limiting their reliance upon purchased allowances. Instead, companies will look to achieve further emissions reductions. This would ensure reductions occur in the necessary states so as to meet the requirements of Section 110, clarified in the D.C. Circuit decision. [EPA-HQ-OAR-2009-0491-3936[1].1, p.3]
Response: 
EPA is maintaining the overall assurance provision approach in the final Transport Rule, except that, if the assurance provisions are triggered in a state, the determination of which owners and operators of units in the state must surrender allowances for the assurance penalty is determined at the common designated representative level, rather than the owner level.  See section VII.E of the preamble. 
Organization: Southern Company
Comment: 
Southern Company
EPA also asks for comment on the implications that the alternative allocation methodologies might have on the proposed assurance provisions and the reasonableness of using the proposed assurance provisions with the alternative allocation methodologies. [EPA-HQ-OAR-2009-0491-3946[1].1, p.10]
Lastly, it appears that the assurance provisions under either of the heat-input allocation schemes would be disproportionately shared by the higher emission-rate units. As discussed in Section III of these comments, the heat-input methods yield a windfall of allowances to lower emission rate units (e.g., natural gas). In many cases, these units are allocated well over 500 times what they could possibly emit (e.g., SO2). Higher emission-rate units (e.g., coal) are significantly under allocated. The assurance provisions come into play when a state exceeds its budget plus variability. Therefore, if a state experiences an unusually high demand year and exceeds its budget plus variability, a significant portion of the penalty allowances will be owed by the under-allocated units. As noted earlier, the heat-input allocation method--without more consideration of actual emissions--leads to absurd results and disproportionately applies the assurance provision penalties on the higher-emitting units. [EPA-HQ-OAR-2009-0491-3946[1].1, p.10]
Response: 
EPA is maintaining the overall assurance provision approach in the final Transport Rule, except that, if the assurance provisions are triggered in a state, the determination of which owners and operators of units in the state must surrender allowances for the assurance penalty is determined at the common designated representative level, rather than the owner level.  This approach will allow owners and operators of individual units greater flexibility in meeting the assurance provisions.  For example, owners and operators will have the ability to select a common designated representative for a group of units reflecting different unit types, technologies, fuel types, and types of emissions controls and, in this way, address any potential disadvantages that individual units might otherwise have under the assurance provisions.   See section VII.E of the preamble.  Further, EPA is finalizing an allowance allocation approach that is based on historic heat input and limits each unit's allocation to its maximum historic emissions.  See section VII.D of the preamble.
Organization: Wolverine Power Supply Cooperative
Comment: 
Wolverine Power Supply Cooperative
IMPLICATIONS THAT OPTIONS 1 AND/OR 2 MIGHT HAVE ON IMPLEMENTATION AND REASONABLENESS OF THE ASSURANCE PROVISIONS OF THE PROPOSED TRANSPORT RULE
Regarding the USEPA's request for comment on this subject, Wolverine does not see that the heat-input based Options 1 and/or 2 materially impact the structure or implementation of the assurance provisions. Although they give a small amount of relief to the concerns of stranded units and small systems that they will be essentially shut out of the program, it does not relieve the great uncertainty that will exist with the future-year true-up system that the assurance proposal creates. The assurance provisions remain unreasonable in that they create a high level of risk to stranded and small systems, such as Wolverine's Sumpter plant, that they will incur [EPA-HQ-OAR-2009-0491-4014[1].1, p. 5]
Response: 
EPA is maintaining the overall assurance provision approach in the final Transport Rule, except that, if the assurance provisions are triggered in a state, the determination of which owners and operators of units in the state must surrender allowances for the assurance penalty is determined at the common designated representative level, rather than the owner level.  This approach will allow owners and operators of individual units greater flexibility in meeting the assurance provisions.  For example, owners and operators will have the ability to select a common designated representative for a group of units (such as a group that combines includes a "stranded and small" system with other) units) reflecting different unit types, technologies, fuel types, and types of emissions controls and, in this way, address any potential disadvantages that individual units might otherwise have under the assurance provisions.   See section VII.E of the preamble. 
Organization: Xcel Energy Inc.
Comment: 
Xcel Energy Inc.
EPA also requested comment on whether the overall assurance provision approach should be maintained if one of the alternative allocation methodologies is used in the final Transport Rule. Xcel Energy supports the continued use of the overall assurance provision approach, regardless of whether the original allocation method, the alternative allocation method, or our recommended allocation is used. [EPA-HQ-OAR-2009-0491-3948[1].1, p.4]
Response: 
EPA is maintaining the overall assurance provision approach in the final Transport Rule, except that, if the assurance provisions are triggered in a state, the determination of which owners and operators of units in the state must surrender allowances for the assurance penalty is determined at the common designated representative level, rather than the owner level.  See section VII.E of the preamble. 

XX.D. Allocations to New Units in Indian Country

Organization: Connecticut Department of Environmental Protection
Comment: 
Connecticut Department of Environmental Protection
Allocations to New Covered Units in Indian Country in the Future
At 76 FR 1118, EPA states that presently there are no covered sources located in Indian country in the region covered by the proposed Transport Rule. At 76 FR 1119, EPA suggests that the owner or operator of units in Indian country in the proposed Transport Rule region could request allocations from the EPA administered new unit set-aside by a specified deadline each year. EPA requests comment on all aspects of how allowances for covered units locating on tribal lands should be allocated. [EPA-HQ-OAR-2009-0491-3884[1].1, p.2]
Any provisions to accommodate units locating in Indian country in the proposed Transport Rule region in the future should not be detrimental to state programs, especially where there are limited state budgets. Removing allowances from new unit set-asides removes allowances available for newer, cleaner units in individual states. [EPA-HQ-OAR-2009-0491-3884[1].1, p.2]
Response: 
EPA is designating a new unit set-aside for each state with federally recognized tribes and Indian country for any future EGUs constructed in Indian country in the Transport Rule region as part of the final rule.  EPA will maintain control of the new unit set-aside accounts, even when states submit their own SIPs.  Unallocated allowances from these new unit set-asides will be made available to new units in the rest of the state and then, if still unallocated, to existing units in the rest of the state.  See the preamble for more details.
Organization: Empire District Electric Company (Empire District)
Comment: 
Empire District Electric Company (Empire District)
New units that chose to locate within Indian country should be allocated allowances from the State budget of the State in which the unit is located. This assures the prevention of significant impact on downwind States and Indian Territories. [EPA-HQ-OAR-2009-0491-3883[1].1, p.2]
Response: 
EPA is designating a new unit set-aside for each state with federally recognized tribes and Indian country for any future EGUs constructed in Indian country in the Transport Rule region as part of the final rule.  EPA will maintain control of the new unit set-aside accounts, even when states submit their own SIPs.  See the preamble for more details.
Organization: Fond du Lac Reservation
Comment: 
Fond du Lac Reservation
Moving on to new source allocations of credits, in the NODA it was suggested that tribes 'could go to the states' and ask for allocations from the 3% that states would be given for new source points of pollution. Under no circumstances is it believed that this is an acceptable solution. It is our stance that, like with existing source allocations, tribal allocations should be set aside for tribes. If a tribe has a need for the allocations, then they are available, if there is not a need, then the state could purchase these allocations from the tribe if needed or, again they aren't used and the environment wins. Furthermore, it is our belief that tribal allocations should not come from a percentage of the total allocations for new sources, but should be a percentage of that year's total allocation. One scenario that the Band would support, being a member of the Lake Superior Chippewa, (whose ceded territories, includes much of Michigan, the northern half of Wisconsin, much of Minnesota) has strong objection to asking the 'states' for new allocations. We believe that rights reserved. by us, in treaties entitle us to utilize these allocations as we see fit. It is our understanding, from the NODA dated 1-7-2011 that each state will be given 3% of total allocations for new source development. We believe that the signatory tribes should be given I% of each of the states of Minnesota, Michigan and Wisconsin allocations for new sources. This would offer us our rightful seat at the table in protecting our planet and its environment, in which our reservations and ceded territories lie. Secondly, it would give us a platform in which to 'retire' or trade these allocations with industry and the 'states' that surround our reservation land and reserved hunting, fishing and gathering territories. [EPA-HQ-OAR-2009-0491-4021, pp.2-3]
Another example that the band could likely support and an example of how the Agency got it right is the Western Regional Air Partnership ('WRAP'), a partnership between Indian tribes, states and federal agencies (including the EPA) and with participation from such entities as environmental organizations and industry, advocated for a tribal set-aside during the late 1990s that was eventually adopted as part of the Annex to the Regional Haze Rule ('RHR'). The Annex established declining SO2 emission milestones for major sources. If the milestones were exceeded, then a cap-and-trade program would be initiated to ensure continued SO2 reductions. As part of the Annex, an annual SO2 tribal set-aside of 20,000 tons was made available to tribes within a nine-state region, regardless if such tribes had major industrial sources emitting SO2. This set-aside was to be distributed as determined by the region's tribes (e.g., for future industrial sources, other economic development purposes, tribal scholarships, etc} This annual tribal set-aside also grew out of multiple discussions among the WRAP's partners and participants where issues of equity and economic development kept coming up during conversations with respect to the tribes that had hardly contributed to visibility impairment in the West but whose environment and health had been adversely affected by neighboring jurisdictions with sources emitting significant amounts of SO2. At that time, neither the WRAP partners or participants had sufficient information about future EGUs in Indian country but they felt it imperative to address equity issues properly before and not after the Annex was implemented. [EPA-HQ-OAR-2009-0491-4021, p.3]
In regards to new allocations, it is our stance that tribes should not be 'requesting,' the states that surround their lands, for allocations for new sources. We should receive a percentage of the proposed allocations; we look forward to working out the details that would be acceptable to all parties. [EPA-HQ-OAR-2009-0491-4021, p.3]
Response: 
EPA is designating a new unit set-aside for each state with federally recognized tribes and Indian country for any future EGUs constructed in Indian country in the Transport Rule region as part of the final rule.  EPA will maintain control of the new unit set-aside accounts, even when states submit their own SIPs.  Allowances are allocated from the Indian country new unit set-aside if and when a covered EGU is constructed in Indian country and otherwise are returned to the state budget for allocation to existing or new units (or other uses in accordance with a state's SIP).  Unallocated allowances are not provided to the tribes. See the preamble section VII.D for more details.
Organization: Forest County Potawatomi Community
Comment: 
Forest County Potawatomi Community
III. In order for EPA to meet its trust responsibility, EPA must consider and address the effects of upwind sources on tribal areas and create a set-aside of emissions allowances dedicated to tribes.
A. EPA's trust responsibility requires it to consider and address the effects of upwind sources on Tribal areas.
EPA has requested comment on 'all aspects of how allowances for covered units locating on tribal lands should be allocated.' 76 Fed. Reg. 1119. FCPC appreciates EPA's current invitation to comment on this important issue, but the Tribe is troubled by EPA's failure to consider the issue in its initial Transport Rule proposal. This failure highlights broader shortcomings in EPA's overall approach in this rulemaking: the lack of analysis on the overall effects of upwind sources on Indian Country, and the effect of the proposed rule on Indian tribes. [EPA-HQ-OAR-2009-0491-3882[1].1, p.4]
By failing to consider the impacts of upwind sources and of the proposed Transport Rule on Tribal lands, EPA has not lived up to its legal trust responsibility to Tribes. Under the federal trust responsibility, established by the Supreme Court in the 1830s in the historic Cherokee cases, the federal government is obligated to protect Indian tribes' lands, waters, natural resources and rights of self-government as a trustee would protect the interests of a beneficiary. This obligation is heightened by the Environmental Justice Doctrine. Pursuant to Executive Order 12,898, the federal government has bound itself to ensuring the fair treatment and environmental protection of all minority communities, including Indian tribes. [EPA-HQ-OAR-2009-0491-3882[1].1, p.4]
In 2009 the EPA reaffirmed its Indian Policy. First adopted in 1984, the Policy mandates that EPA 'recognize that a trust responsibility derives from the historical relationship between the Federal Government and Indian Tribes as expressed in certain treaties and Federal Indian law.' The Policy continues: 'In keeping with that trust responsibility, the Agency will endeavor to protect the environmental interests of Indian Tribes when carrying out its responsibilities that may affect the reservations.' [EPA-HQ-OAR-2009-0491-3882[1].1, p.4]
The Policy also confirms that the EPA will stand ready to 'work directly with Indian tribal governments on a one-to-one basis (the 'government-to-government' relationship), rather than as subdivisions of other governments.' Finally, in circumstances where EPA has not transferred regulatory and program management responsibilities to tribes (though the Policy expresses a preference for such transfers), the Policy requires that EPA 'encourage [tribes] to participate in policy-making' and other appropriate roles in the management of reservation programs. [EPA-HQ-OAR-2009-0491-3882[1].1, pp.4-5]
In reaffirming this Policy, the EPA Administrator concluded:
The United States has a unique legal relationship with Tribal Governments based on the Constitution, treaties, statutes, Executive Orders, and court decisions. This relationship includes a recognition of the right of tribes as sovereign governments to self-determination, and an acknowledgment of the Federal government's trust responsibility to the Tribes.  [EPA-HQ-OAR-2009-0491-3882[1].1, p.5]
Accordingly, it is critical that EPA work closely with FCPC and other impacted tribes to ensure that EPA's trust responsibility is met in addressing the impacts of upwind sources on Tribal lands and resources. This trust responsibility and EPA's own Indian Policy require EPA to work with tribal governments on a government-to-government basis to analyze the impacts of upwind sources on tribal lands and resources. [EPA-HQ-OAR-2009-0491-3882[1].1, p.5]
For purposes of this analysis, upwind sources include those in the state or states that directly border tribal lands. For example, in the case of FCPC, upwind sources include those sources located in the state of Wisconsin, since Wisconsin borders FCPC's trust land. EPA must consider the impact of Wisconsin emissions sources on the air quality on FCPC's reservation lands in Forest County, as well as its trust lands in Milwaukee County. The same holds true for every tribe's lands in every state covered by the Transport Rule. [EPA-HQ-OAR-2009-0491-3882[1].1, p.5]
In essence, EPA should treat tribal lands in the same manner as it treats states for purposes of the proposed Transport Rule. Such treatment is consistent with EPA's appropriate recognition of tribes as sovereign entities and with EPA's stated approach to dealing with tribes on a 'government-to-government' basis and not as subdivisions of other governments. Moreover, while FCPC does have Treatment as State ('TAS'), it notes that for purposes of the Transport Rule, tribes should not be required to seek TAS in order to receive the same consideration as states under Clean Air Act section 110. The TAS process is designed to ensure that tribes have the capability to administer certain provisions of the Clean Air Act. But administrative capability is of no consequence with respect to the downwind recipients of pollution under section 110(a)(2)(D)(i)(I). Downwind areas are simply the passive recipients of pollution from upwind sources, and it is EPA's duty to determine whether the upwind pollution significantly contributes to nonattainment in those downwind areas, whether the downwind areas are governed by states or by tribes. [EPA-HQ-OAR-2009-0491-3882[1].1, p.5]
At the very least, EPA should undertake the required analysis concerning effects on tribal lands during the rulemaking process for the 'Transport Rule II,' which FCPC understands will apply basic Transport Rule principles to the pending revision of the ozone NAAQS. A stricter ozone NAAQS will likely result in many more tribal areas being in nonattainment, heightening the need for EPA to explicitly consider the effects of upwind sources on tribal areas. [EPA-HQ-OAR-2009-0491-3882[1].1, pp.5-6]
B. EPA's trust responsibility requires it to create a set-aside of emissions allowances dedicated to tribes.
To fulfill its trust responsibility to tribes, EPA must create a set-aside of emissions allowances dedicated to tribes. This tribal set-aside must be calculated as a percentage of allowances for both new and existing units, because otherwise tribes are at risk of being shut out from receiving a distribution of any allowances. There are at least two compelling reasons for creating such a tribal set-aside. [EPA-HQ-OAR-2009-0491-3882[1].1, p.6]
First, failing to allocate allowances for new and existing units to tribes would cause EPA to fail to meet its obligation to work with tribes on a government-to-government basis and not as subdivisions of states or other governments. Under EPA's presently proposed allocation methodology, tribes would be treated as subdivisions of states and shut out from directly receiving any initial distribution of allowances. Moreover, if any state receives SIP authority to implement the Transport Rule, that state would directly control the distribution of allowances. This would require tribes to ask states for emissions allowances. Such a requirement would not only offend basic tribal sovereignty principles but would also raise difficult political situations for tribes, as states might be unwilling to allocate valuable emissions credits to sources locating on tribal lands (outside the jurisdiction of the states with respect to the Clean Air Act and taxing authority of the state). While some states may decline to seek to implement a SIP for purposes of section 110(a)(2)(D)(i)(I), tribes which anticipate obtaining and using emissions credits cannot simply hope that this is the case. To prevent such a situation from arising, EPA should at the outset create a tribal set-aside of emissions allowances. [EPA-HQ-OAR-2009-0491-3882[1].1, p.6]
Second, while tribes have been significantly impacted by emissions from upwind sources such as EGUs, they have not been the source of these emissions. The impacts to tribes are enhanced because of their significant reliance on the environment for their subsistence lifestyles and their traditional cultures. Moreover, energy development in Indian country has typically lagged behind the rest of the country - a reflection of the economic depression which plagues many tribes. And those tribes which do have resources for energy development often choose to implement green energy projects producing little pollution. For example, FCPC is currently pursuing biofuel projects on its reservation and trust land. This combination of historic economic depression and an environmental ethic that avoids high-polluting energy sources means that tribes - which of course bear the effects of pollution from EGUs - are effectively shut out from receiving any of the benefits of emissions allowances. Ironically, EPA's proposed allowance distribution methodology, rather than trying to rectify this disparity, enhances it by providing allowances to the sources that impact Indian Country, rather than to tribes themselves. EPA should rectify this inequitable situation by creating an explicit set-aside for tribes. [EPA-HQ-OAR-2009-0491-3882[1].1, p.6]
At a minimum, the tribal set-aside should be based on the ratio of tribal lands, including reservation lands and other trust lands, to the total area of a particular state covered by the Transport Rule. For example, if tribal areas make up 5% of the land area within a particular state's boundaries. EPA should set aside for tribes 5% of the total emissions allowances for that state. This approach would retain the state-specific character of the 'significant contribution' analysis required by the courts, while ensuring an equitable portion of allowances is reserved for tribes. [EPA-HQ-OAR-2009-0491-3882[1].1, p.7]
In addition, EPA should set aside an additional amount of allowances for tribes based on culturally important and historically significant lands used by tribes. These lands could include ceded territories, or in the case of FCPC, areas recognized as eligible for the National Historic Registry, as well as other critical cultural and historic lands. These lands are of critical importance to tribes and have been significantly impacted by emissions from EGUs. Accordingly, in addition to allocations to tribes based on their reservation lands, EPA should also allocate allowances to tribes based upon their interests and rights in these additional culturally critical lands. EPA should consult with tribes, including FCPC, regarding the extent of these additional lands and the appropriate amounts of credits to allocate to tribes based on these lands. [EPA-HQ-OAR-2009-0491-3882[1].1, p.7]
Response: 
EPA is designating a new unit set-aside for each state with federally recognized tribes and Indian country for any future EGUs constructed in Indian country in the Transport Rule region as part of the final rule.  EPA will maintain control of the new unit set-aside accounts, even when states submit their own SIPs.  The allowances would only be allocated to new sources covered under the Transport Rule once they are constructed.  See the preamble for more details.
With respect to the impact of upwind sources in Indian country within Wisconsin, our analysis shows that after implementation of the Transport Rule, when the emission reductions required of the state of Wisconsin have been made, all areas encompassed within the borders of the state of Wisconsin, including Indian country, will be free of nonattainment and maintenance problems.  Moreover, there will be few nonattainment or maintenance areas in any states covered by the Transport Rule after its implementation, and none of those areas are projected to include Indian country.  For the annual PM2.5 standard, the Transport Rule fully addresses all upwind states' transport obligations to downwind areas.  For the 24-hour PM2.5 standard, only the Liberty-Clairton area in Pennsylvania is expected to be nonattainment and only Chicago, Illinois, Detroit, Michigan, and Lancaster, Pennsylvania, are expected to have maintenance problems.  Only one area (Houston, Texas) is projected to remain in nonattainment, and one area (Baton Rouge, Louisiana) to have a remaining maintenance concern for the 1997 ozone standard.  Where there are no nonattainment or maintenance problems, there can be no significant contribution to nonattainment or interference with maintenance.  Thus, as there are no nonattainment or maintenance problems projected in Indian country after implementation of this rule, it is clear that any and all emissions which significantly contribute to nonattainment and interference with maintenance have been prohibited. 
 EPA also notes that, since the state of Wisconsin is already included in the Transport Rule region for significantly contributing to downwind receptors in other states, even though there are no receptors in Indian country in Wisconsin, sources in the state of Wisconsin are already required to reduce emissions and comply with the Transport Rule requirements.  Further, Wisconsin is a Group 1 SO2 state in the final rule and is already required to make all reductions available at the maximum cost thresholds used to set state budgets.  Therefore, the identification of additional "linkages" for Wisconsin would not have changed the emission reduction requirements applicable to the state.  
The commenter also notes that EPA should treat Indian country the same as states for purposes of the Transport Rule and that tribes should not be required to obtain Treatment as a State (TAS) status for purposes of being considered relevant downwind recipients of pollution under CAA section 110(a)(2)(D)(i)(I).  Because implementation of the Transport Rule will avoid nonattainment and maintenance problems in Indian country  -  and thus will necessarily prohibit any emissions which significantly contribute to nonattainment and interference with maintenance in such areas  -  EPA does not need to address in this action the question whether CAA section 110(a)(2)(D)(i)(I) requires that a SIP address impacts on Indian country geographically located within the submitting State or how the TAS status of a potentially-affected downwind tribe may be relevant to that issue.
Organization: Mille Lacs Band of Ojibwe
Comment: 
Mille Lacs Band of Ojibwe
The Band recommends allowance allocation be set not strictly based on existing units, but rather be set by combination of existing units together with anticipated future units and sovereign entity's total acreage bases. By setting allowance allocation strictly based on existing units, USEPA will force majority of the Tribes to miss out on the commodification of allowances afforded to States. Due to past policies of the United States which excluded Tribes from actively participating in self-determination, which lead to social, economic and political oppression geared towards extinction of Tribes and assimilate into the general public, today, energy development in Indian Country either far lags development in surrounding areas or is used to actively exploit for the benefit of surrounding areas. In addition, having allowance allocation be set strictly based on existing units would significantly hinder Tribes from developing new sources, and curtailing any possible competition with EGUs in buying allowances. [EPA-HQ-OAR-2009-0491-4019[1].1, p.3]

There are several reasons on our part to suggest factoring in allocation of allowances based on total acre basis of the sovereign entity, whether a Tribe or a State. It is inappropriate for Tribes, as sovereign nations, to be given allowances from another sovereign entity, such as the States. However, since all Tribes hold some level of interest on State lands, we propose that each of the States affected by the Air Transport Rule meet with all the appropriate Tribes holding interest on State lands-whether as simple as preservation interest per Native American Graves Protection and Repatriation Act (NAGPRA) (Pub.L. 101-601, 104 Stat. 3048), National Historic Preservation Act (NHPA) (Pub.L. 89-665; 16 U.S.C. 470 et seq.), Archaeological Resources Protection Act of 1979 (ARPA) (Pub.L. 96-95 as amended, 93 Stat. 721) or National Environmental Policy Act (NEPA) (pub.L. 91-190, 83 Stat. 852), or as extensive as usufruct rights-and have the State and Tribes together determine an equitable methodology for managing distribution and implementations of State allocation of allowances that would aid in safeguarding the interests of the Tribes on State lands. We recommend USEPA to serve as facilitator and moderator between the States and the Tribes. Once the States and Tribes have made the determination, the determination will be incorporated into the State Implementation Plans (SIPs). This allows for Tribes with little or no land base, or have no future plans on energy development upon their lands, to still have a small allocation to any unanticipated energy development, while still influencing any developments on State lands that may greatly affect the interests of the Tribes. In addition, setting allowance allocation strictly on existing units will exclude majority of Tribes who do not have existing units or have existing units that are not under the Tribes jurisdiction; these allowances are form of social credit that can be monetized, and excluding Tribes will continue to foster energy development lags or keep existing units in Indian Country not under the Tribe's authority stay out of the reach of Tribe's authority. [EPA-HQ-OAR-2009-0491-4019[1].1, p.3]
Response: 
EPA has decided to base allocations for existing units made under the FIPs on historic heat input, subject to a maximum allocation limit to any individual unit based on that unit's maximum historic emissions. This limit should help prevent over-allocation of allowances to units. Further detail on the implementation of this approach, rationale, and response to comments on the allocation method is provided in Preamble Section VII.D as well as in the Allowance Allocation Final Rule TSD in the docket for this rulemaking.
 EPA is designating a new unit set-aside for each state with federally recognized tribes and Indian country for any future EGUs constructed in Indian country in the Transport Rule region as part of the final rule.  EPA will maintain control of the new unit set-aside accounts, even when states submit their own SIPs.  Allowances are allocated from the Indian country new unit set-aside if and when a covered EGU is constructed in Indian country and otherwise are returned to the state budget for allocation to existing or new units (or other uses in accordance with a state's SIP).  Unallocated allowances are not provided to the tribes.  See the preamble section VII.D for more details.
Organization: National Tribal Air Association (NTAA)
Comment: 
National Tribal Air Association (NTAA)
Although the organization always seeks to represent consensus perspectives on any given issue, it is important to note that the views expressed by the NTAA may not be agreed upon by all Tribes. Furthermore, it is also important the EPA understands that interactions with the organization do not substitute for government-to-government consultation which can only be achieved through direct communication between the federal government and Indian Tribes. [EPA-HQ-OAR-2009-0491-3993[1].1, p. 2]
Construction of New Sources on Tribal Lands
Forcing Indian Tribes to secure allowances for new sources constructed on their lands from state allocations, through the EPA or from states themselves, is problematic in at least two ways. [EPA-HQ-OAR-2009-0491-3993[1].1, p. 2]
First, states have a vested interest in making a sufficient number of allowances available for new sources locating in their jurisdictions so as to enhance economic development and to provide greater access to energy by their residents. Hence, these states would likely be less than enthusiastic in passing on some of these allowances to Tribes, particularly if they foresaw a shortage of allowances to distribute to their own sources. This, in turn, could lead to some states litigating the issue with EPA for which a decision by the court might not be forthcoming for many years. This, in turn, could hold implementation of the Transport Rule hostage, a rule that promises to greatly improve air quality in the eastern part of the nation in which so many Tribes live. [EPA-HQ-OAR-2009-0491-3993[1].1, p. 2]
Second, a Tribe's sovereignty could be perceived as being compromised if new units locating on its land would be required to rely on the allowances already set aside for units locating in the surrounding state. Federally-recognized Indian Tribes, however, are sovereign nations with certain rights ensured by the U.S. Constitution, treaties and legal precedence, and should be treated as such by the EPA and other federal agencies. One such right is the federal government's obligation to consult with Tribes on a government-to-government basis, and in the case at hand, the Agency should be dealing directly with such Tribes regarding the allocation of allowances. Unfortunately, the EPA is proposing to pass on this obligation to states which do not share a similar obligation of consulting with Tribes, nor do they have any regulatory authority over Tribal lands. [EPA-HQ-OAR-2009-0491-3993[1].1, pp. 2-3]
Hence, the EPA should be dealing directly with Indian Tribes in the case of allocating allowances for sources being constructed on Tribal lands. Among other things, more than 100 of the nation's 565 federally-recognized Tribes reside in the region covered by the Transport Rule, with these Tribes occupying a large amount of the four percent or 95 million acres of the U.S. land base that consists of Tribal lands. In addition, Tribes have never been apportioned allowances under any of existing cap-and-trade programs for which states have received innumerable allowances. Finally, the Agency has failed to satisfactorily answer the following questions in recent consultations with Tribes: [EPA-HQ-OAR-2009-0491-3993[1].1, p. 2]
-How to identify a basis for treating new units locating in Indian Country without having initial sulfur dioxide (SO2) or nitrogen oxide (NOx) allowance allocations provided to Indian Tribes (e.g., states in which new units would locate that have already received allowance allocations as part of the Transport Rule's allowance budget); and [EPA-HQ-OAR-2009-0491-3993[1].1, p. 3]
-How allowance allocations for Indian Country should be addressed in a state that has submitted a state implementation plan providing for the state's allocation of allowances (e.g., new unit set-aside would be maintained by the state and not EPA). [EPA-HQ-OAR-2009-0491-3993[1].1, p. 3]
As such, the NTAA recommends that five percent of the total number of allowances allocated to states or an appropriate portion thereof should be made available as a Tribal set-aside for the sole purpose of providing such allowances for new sources established on Tribal lands within the region covered by the Transport Rule. Distribution of any allowances would also necessitate government-to-government consultation between the EPA and any Tribe seeking such allowances, thereby eliminating any involvement of states that do not have a similar obligation to consult with Tribes. [EPA-HQ-OAR-2009-0491-3993[1].1, p. 3]
It is imperative that the EPA address these comments and recommendations as Indian Tribes should be provided with allocations immediately based on such existing sources unlike those larger sources (e.g., coal-fired power plants) that could be constructed in the future. [EPA-HQ-OAR-2009-0491-3993[1].1, p. 4]
Response: 
EPA is designating a new unit set-aside for each state with federally recognized tribes and Indian country for any future EGUs constructed in Indian country in the Transport Rule region as part of the final rule.  EPA will maintain control of the new unit set-aside accounts, even when states submit their own SIPs.  Allowances are allocated from the Indian country new unit set-aside if and when a covered EGU is constructed in Indian country and otherwise are returned to the state budget for allocation to existing or new units (or other uses in accordance with a state's SIP).  Unallocated allowances are not provided to the tribes.  See the preamble section VII.D for more details.
XX.E. Provisions for States to Submit Full or Abbreviated SIPs Providing for State Allowance Allocations

Organization: Alabama Department of Environmental Management
Comment: 
Alabama Department of Environmental Management
ADEM strongly encourages EPA to allow States to choose which type of SIP submittal, a full or abbreviated SIP, is most appropriate for their needs, as was allowed in CAIR. Submission of either a full or abbreviated SIP should meet the transport requirement under section 110(a)(2)(D)(i)(I) of the Clean Air Act. [EPA-HQ-OAR-2009-0491-3887-cp, p.1]
Further, ADEM requests that EPA reconsider the SIP submission timeline in order for States to develop their own SIPs for distribution of allowances. With the uncertainty of the timing of the final release of the Transport Rule, States may have 5 months or less to accomplish this by November, 2011. This timeframe is inadequate for our agency to complete the rulemaking process and thus makes it impossible to have input into the 2014 allocation process. [EPA-HQ-OAR-2009-0491-3887-cp, p.1]
Response: 
In the final Transport Rule, EPA revises the deadlines for submission of SIP revisions to replace EPA-determined allocations by state-determined allocations.  The first deadline for submission of SIP revisions with replacement, state-determined allocations is April 1, 2012 for allocations for 2013.  See section X of the preamble. 
Organization: Ameren Services Company
Comment: 
Ameren Services Company
In Tables III and IV (page 1121) EPA lists the deadlines for states to submit SIPs (either abbreviated or full) replacing EPA's FIP. The timelines for 2012, 2013 and 2014 are either nonexistent or extremely short. This affectively eliminates most if not all states included in the Transport Rule from developing their own SIPs at least for 2014. This scheduling is flawed. [EPA-HQ-OAR-2009-0491-3894[1].1, p.2]
a) Based on EPA's current schedule no state can develop a SIP for the 2012·13 portion of the Transport Rule. This is unacceptable and severely limits the states inalienable rights as described above in comment #5.
b) As described in this Transport Rule NODA states are only allowed to develop SIPs for 2014 and beyond. According to EPAs schedule a SIP would be due November 1, 2011 for the year 2014. [EPA-HQ-OAR-2009-0491-3894[1].1, p.2]
Considering that EPA plans on finalizing the Transport Rule in June 2011 that would allow only 4 months for the states to develop a SIP. This timeframe is impossible to meet considering some states need up to 2 years to complete a rule making. [EPA-HQ-OAR-2009-0491-3894[1].1, p.3]
Response: 
In the final Transport Rule, EPA revises the deadlines for submission of SIP revisions to replace EPA-determined allocations by state-determined allocations.  The first deadline for submission of SIP revisions with replacement, state-determined allocations is April 1, 2012 for allocations for 2013.  See section X of the preamble.
Organization: American Electric Power
Comment: 
American Electric Power
The Proposed Schedule Fails to Recognize the Primacy of States
NODA-3 admits a fatal flaw in the Proposed Transport Rule - the primacy of states in developing and implementing the substantive requirements of their state implementation plans (SIPs). But rather than provide the minimum time required to allow states to perform these Congressionally-mandated tasks, NODA-3 ignores that authority and simply assumes that states will follow the federal plan in 2012. While such a proposal appears to provide a practical alternative, it is not what the Clean Air Act demands. [EPA-HQ-OAR-2009-0491-3934[1].1, p.3] 
Response: 
EPA has the authority to promulgate the FIPs in the final Transport Rule.  See section IV.C of the preamble.   
Organization: ARIPPA
Wisconsin Public Service Corporation (WPSC)
Comment: 
ARIPPA
ARIPPA also supports EPA's proposal to allow states to develop partial State Implementation Plans ("SIPs") to replace the Federal Implementation Plan ("FIP"), initially with respect only to proposed allocations, rather than simultaneously addressing all regulatory aspects of the FIP.  [EPA-HQ-OAR-2009-0491-3903[1].1, p.3]
ARIPPA supports EPA's proposal through the Second NODA to authorize individual states to pursue partial SIPs in order to accelerate state-specific allocation approaches.  [EPA-HQ-OAR-2009-0491-3903[1].1, p.13]
For these reasons, ARIPPA strongly endorses EPA's proposal through the Second NODA  to allow states to develop partial SIPs that would address state-specific allowance allocation methodologies, while postponing or foregoing state-specific revisions to other elements of the FIP.  This approach would reduce the time necessary for states to develop state-specific allocation schemes and satisfy the procedural requirements for SIP approval.  [EPA-HQ-OAR-2009-0491-3903[1].1, p.15]
In order to ensure individual states maximum flexibility in implementation of the program, ARIPPA also endorses EPA's efforts to increase the tools available to individual states to pursue timely, efficient and effective revisions to state implementation plans to replace the FIP.  In this context, states should be afforded the option of proposing partial SIPs to allow substitution of state-specific allowance allocation methodologies without simultaneous promulgation of a comprehensive SIP-based substitution for the FIP.  However, even with such additional flexibility and opportunity for more accelerated partial SIP revision, the timeframes proposed by EPA through the Proposed Transport Rule are insufficient to allow both states and affected sources to adequately prepare for implementation.   [EPA-HQ-OAR-2009-0491-3903[1].1, p.15]
Wisconsin Public Service Corporation (WPSC)
2. Require that State Transport Rule SIPs Adopt the Transport Rule FIP Allowance Allocations
EPA is taking comment on all aspects of how a state could replace the Transport Rule Federal Implementation Plant (FIP) with a State Implementation Plan (SIP) and on what the SIP approval criteria should be. [EPA-HQ-OAR-2009-0491-3994[1].1, p. 3]
Two difficult complications for utility compliance planning and implementation are uncertainty and short timelines. Deferring Transport Rule allowance allocations to yet to be developed and state approved SIPs introduces both these complications into utility compliance planning and implementation. [EPA-HQ-OAR-2009-0491-3994[1].1, p. 3]
First, deferral of unit allowance allocation methods to the State blurs a utility's compliance plan target and implementation approaches. Planning becomes uncertain as to what unit allocations will be and how SIPs in trading group states will combine to affect the pool and availability of tradable allowances. Include the possibility of auctions for some or all allowances, in yet to be established state auction rules, and utility compliance planning become unnecessarily complicated with no additional benefit to the goals of the Transport Rule. [EPA-HQ-OAR-2009-0491-3994[1].1, p. 3]
Second, with compliance scheduled to begin in 2012 and changing in 2014, the timeliness of the SIP development process compresses the planning and implementation timeline. The SIP development, passage, and approval process has historically been slow. Time consumed by the SIP process is time taken from compliance planning and implementation. The earlier allowance allocations are determined, the more time utilities have to prepare for compliance with the Transport Rule. [EPA-HQ-OAR-2009-0491-3994[1].1, p. 3]
Response: 
In the final Transport Rule, EPA revises the deadlines for submission of SIP revisions to replace EPA-determined allocations by state-determined allocations.  The first deadline for submission of SIP revisions with replacement, state-determined allocations is April 1, 2012 for allocations for 2013.  See section X of the preamble.
See section VII.C, concerning compliance deadlines under the final Transport Rule. 
Organization: Associated Electric Cooperative, Inc. (AECI)
Comment: 
Associated Electric Cooperative, Inc. (AECI)
AECI supports the inclusion of the both the abbreviated and full SIP options proposed in the NODA III.  The compressed timeline of 2012 for the CATR first compliance period, however, presents insufficient time to allow states the opportunity to distribute allowances under a SIP to reflect individual state needs and concerns. [EPA-HQ-OAR-2009-0491-3989[1].1, p.2]
AECI's comments to the CATR NODA III are directed exclusively at the proposed state implementation plan options and allowance allocation methods.  First, AECI supports the proposal to include the two State Implementation Plan (SIP) options. AECI is disappointed however that the timelines EPA has proposed for CATR implementation, beginning in 2012, does not allow adequate time for states to submit and obtain SIP approvals incorporating allowance allocation methodologies better suited to meeting state or local concerns as compared the chosen methodology in the generic FIP.  EPA's hurry up compliance timeline of 2012 again presents another problem with the CATR, that of the ability of a state to craft its own allowance policies to best suit its needs during the first two years of CATR implementation. [EPA-HQ-OAR-2009-0491-3989[1].1, p.3]
I. State Implementation Plan (SIP) Options:
AECI supports the CATR NODA III proposal incorporating the full and abbreviated SIP options into the final CATR regulation.  AECI is disappointed, however, that the agency has not addressed the problematic timing of the CATR 2012 and 2014 compliance periods as AECI and others have identified in earlier comments to the August 2, 2010 CATR.  EPA's failure to extend the CAIR beyond 2011 and its proposed imposition of the 2012 and the 2014 timelines continue to plague this rulemaking.  Regarding the proposed SIP options, as EPA notes in the NODA III proposal, considering the time to submit and approved a SIP and record allowances, a SIP could not be applicable before the 2014 compliance period.   As AECI has noted in our earlier comments, there is no legal prohibition in the North Carolina decision against keeping CAIR in effect beyond 2011, and EPA's failure to do so would create yet another problem in so far as effectively prohibiting states from implementing SIPs addressing Clean Air Act Section 110(a)(2)(D)(i) deficiencies during the early stages of CATR implementation. [EPA-HQ-OAR-2009-0491-3989[1].1, pp.3-4]
Response: 
In the final Transport Rule, EPA revises the deadlines for submission of SIP revisions to replace EPA-determined allocations by state-determined allocations.  The first deadline for submission of SIP revisions with replacement, state-determined allocations is April 1, 2012 for allocations for 2013.  See section X of the preamble.
See section IV.C of the preamble, concerning EPA's authority to issue the final Transport Rule FIPs, and section VII.C of the preamble, concerning the compliance deadlines under the final Transport Rule.
Organization: Buckeye Power, Inc.
Comment: 
Buckeye Power, Inc.
EPA's suggestion of an abbreviated SIP, which limits participation in interstate trading and allows states to submit abbreviated SIPs regarding certain aspects of the CATR, but only in years after 2012, does not go far enough. First, allowing only limited interstate trading does not further the goal of utilizing the market to the greatest extent possible to ensure reduction of emissions at the least cost. Second, EPA is proposing a Federal Implementation Plan for compliance year 2012. That FIP most likely would not maximize emission reductions. Congress recognized that the states are in the best position to adopt programs that will yield necessary reductions. [EPA-HQ-OAR-2009-0491-3900[1].1, p.6]
Similarly, EPA's suggestion of a full SIP for years after 2012 is likewise deficient insofar as it proposes to implement a FIP at least for year 2012, without giving states adequate time to impose a SIP. Allowing states the initial opportunity to address allocation and other issues, and thereby reducing impacts to downwind states, is in accordance with the judgment of Congress and the history of the Clean Air Act. States, as the entities in the best position to make judgments about allocations and emissions reductions, should be granted the role of primary decision-maker until and unless the states choose not to act. [EPA-HQ-OAR-2009-0491-3900[1].1, p.7]
Response: 
In the final Transport Rule, EPA revises the deadlines for submission of SIP revisions to replace EPA-determined allocations by state-determined allocations.  The first deadline for submission of SIP revisions with replacement, state-determined allocations is April 1, 2012 for allocations for 2013.  See section X of the preamble.
See section IV.C of the preamble, concerning EPA's authority to issue the final Transport Rule FIPs, and section VII.C of the preamble, concerning the compliance deadlines under the final Transport Rule.
Organization: Cleco Corporation
Comment: 
Cleco Corporation
In NODA-3, EPA proposes to allow states an opportunity to submit abbreviated SIPs to address the limited issue of how allowances are allocated to the unit-level. While we encourage EPA to afford the states flexibility, the abbreviated SIP process simply does not meet the Clean Air Act requirement that states have primary responsibility for controlling sources within their borders. As an initial matter, EPA proposes to require states seeking alternative allocation approaches to submit proposed allocation SIPs this fall  -  just a few months after the rule is scheduled to be finalized. This would essentially mean that states would have to begin the state rulemaking process before a final Transport Rule is finalized. States, such as Louisiana, are likely to be reluctant to do so, since at this point it is unclear whether Louisiana will be in the Transport Rule and if so, whether trading will be a part of the final rule. Additionally, even if Louisiana were to meet this accelerated timeline, its allocation method would not take effect until the third year of the program  -  2014. Put simply, the abbreviated SIP process does not cure EPA's unlawful attempt to deny states an initial opportunity to develop a SIP before EPA imposes a FIP. The abbreviated SIP process is too little, too late. [EPA-HQ-OAR-2009-0491-4007[1].1, pp.2-3]
VI. EPA Should Afford States Flexibility in Determining the Best Allocation Method Given Local Conditions.
As noted above, EPA is legally required to give states the opportunity to develop SIPs and should delay implementation of the FIP to allow that process to move forward. If, however, EPA insists on by passing the states, it should consider giving states additional flexibility in determining allocations. There is simply no reason why EPA must promulgate a single approved allocation method. In addition to allowing for abbreviated allocation SIPs, EPA could promulgate two or three EPA-approved allocation methods and let states opt into the allocation method that works best for their local conditions. By way of example, EPA could promulgate the improved proposed Transport Rule allocation method (discussed above) and, at the same time, promulgate an improved Option 2 method (e.g., with a more precise emission constraint) as an alternative allocation method that states could opt-in and adopt. Like the abbreviated SIP process, this would not cure EPA's unlawful bypassing of the state SIP process, but it could help mitigate the adverse impacts of potential state-specific injustices resulting from a single allocation method. [EPA-HQ-OAR-2009-0491-4007[1].1, p.7]
Response: 
In the final Transport Rule, EPA revises the deadlines for submission of SIP revisions to replace EPA-determined allocations by state-determined allocations.  The first deadline for submission of SIP revisions with replacement, state-determined allocations is April 1, 2012 for allocations for 2013.  See section X of the preamble.

Further, EPA rejects the commenter's suggestion that EPA provide several pre-approved model allocation methods that states choose to adopt.  As indicated by any commenters and as confirmed by EPA's experience in reviewing the variety of allowance allocation methods adopted by states in CAIR SIPs, states have a broad range of views on how allowances should be allocated within their borders, with states having different views concerning, for example, the establishment of allowance set-asides for specific purposes such as for encouraging efficiency or renewable energy, for cases of hardship, or for new units.  Consequently, EPA believes that, rather than trying to develop alternative model allocation methods that would attempt to capture the wide variety of state-preferred allocation methods, it is reasonable to provide general requirements for allowance allocations (such as the requirement not to exceed the available amount of the state budget and certain timing requirements for submission of allocations for recordation by EPA) and allow individual states to develop and submit their preferred allocation methods in SIP revisions for approval by EPA.    

See section IV.C of the preamble, concerning EPA's authority to issue the final Transport Rule FIPs, and section VII.C of the preamble, concerning the compliance deadlines under the final Transport Rule.
Organization: Connecticut Department of Environmental Protection
Southern IL Power Cooperative
Exelon
Business Council for Sustainable Energy (BCSE)
Michigan Department of Natural Resources and Environment
New Jersey Department of Environmental Protection (NJDEP)
Alliance to Save Energy
Prairie State Generating Company, LLC
South Carolina Department of Health and Environmental Control 
Wolverine Power Supply Cooperative
Constellation Energy
Western Farmers Electric Cooperative (WFEC)
America's Natural Gas Alliance
West Virginia Department of Environmental Protection
PowerSouth Energy Cooperative
National Rural Electric Cooperative Association (NRECA)
State of Louisiana, Department of Environmental Quality
Comment: 
Alliance to Save Energy
The current NODA acknowledges that '... of course, each state would still have the ability to submit other types of SIPs using emissions reduction approaches other than the proposed Transport Rule trading programs...'  The Alliance supports allowing states flexibility to allocate allowances and establish emissions reduction approaches that recognize and provide incentives for enhancing energy efficiency. [EPA-HQ-OAR-2009-0491-3926[1].1, p.2]
Some states may wish to include set-asides for energy efficiency and renewable energy (EERE) measures, as a number of states did under the Clean Air Interstate Rule (CAIR). The Alliance believes that states following their own procedures, including inclusion of EERE set-asides, should not affect the approvability of SIPs because the distribution of allowances within a state does not affect overall emissions in the state. [EPA-HQ-OAR-2009-0491-3926[1].1, p.2]
However, the NOPR and the NODA do not provide guidance to states on what EPA would accept as allowance distribution approaches or mechanisms. The Alliance urges EPA to:
:: indicate to states that it will duly consider state SIPs that incorporate FIP components but only differ in terms of allowance allocation mechanisms;
:: provide guidance on what allowance distribution approaches or mechanisms it will accept; and
:: provide guidance on criteria that state SIPs would have to meet to allow applicable emission sources in a state to participate in an emissions trading program. [EPA-HQ-OAR-2009-0491-3926[1].1, p.2]
Thus, the Alliance urges the EPA to provide more specific guidance and technical assistance to states on incorporating EERE set-asides or other energy efficiency provisions into a SIP, including:
:: model rules; and
:: advice on measure eligibility, M&V, and other parameters that must be met for EPA acceptance of a SIP. [EPA-HQ-OAR-2009-0491-3926[1].1, p.3]
We note that the Commonwealth of Massachusetts implemented a successful EERE NOx allowance set-aside program under CAIR in which EERE set-asides have been oversubscribed and such allowances have been sold in the market. Thus, Massachusetts may serve as a good case for guidance and assistance to other states. We also recognize that some states may opt for an alternative EERE set-aside program in which emissions allowances attributed to EERE are retired as creditable NOx reductions under the SIP rather than sold into the market. [EPA-HQ-OAR-2009-0491-3926[1].1, p.3]
The EPA may find useful resources on energy efficiency options, programs, deployment, M&V, and other pertinent issues in the work conducted through the National Action Plan for Energy Efficiency (NAPEE) and the ongoing State Energy Efficiency (SEE) Action Network.  Further, a number of states affected by CA TR have existing electric utility energy efficiency programs and requirements that have addressed questions of defining and determining energy savings, M&V, additionality, and other issues that may be useful in the development of SIPs acceptable to the EPA. The SEE Action Network also could serve as a vehicle for providing guidance and technical assistance to the states on EERE set-asides. [EPA-HQ-OAR-2009-0491-3926[1].1, p.3] 
America's Natural Gas Alliance
If the Agency decides to modify the proposed Transport Rule to allow states to replace the allocation methodology adopted by EPA in the FIP with an allocation program adopted by the state and approved by EPA, either as a full SIP or as a partial SIP revision, ANGA believes that EPA must do so in a way that preserves and maintains certainty for the regulated community to the greatest extent possible. [EPA-HQ-OAR-2009-0491-3939[1].1, p.5]
As the Agency is aware, owners and operators of units covered by the CATR are continually engaged in short- and long-term planning for these units, planning that necessarily includes CAA compliance strategies and timelines that will be affected directly by the final CATR, including the critical issue of allocation methodologies. Owners and operators need maximum certainty in terms of how allowances will be allocated in order to evaluate short and long term compliance strategies, including such basic but critical strategic decisions as installing controls \IS. fuel switching vs. purchasing allowances to meet CATR obligations. [EPA-HQ-OAR-2009-0491-3939[1].1, p.5]
ANGA acknowledges that Section 1l0(a)(2)(D)(i)(l) gives states flexibility in designing their SIP programs to abate significant contribution to nonattainment or interference with maintenance in another state. However, regardless of whether the program that applies to covered units is the FIP or a SIP, in either case the program must ensure that allocations are issued/auctioned/otherwise distributed in a timely fashion such that existing units are fully able to develop and implement their CATR compliance strategies. [EPA-HQ-OAR-2009-0491-3939[1].1, p.5]
In addition, any timeline that is prescribed for submittal of full or partial SIPs to EPA for approval must be sufficient to allow EPA time for review, public comment, and approval, and it cannot result in a situation where existing covered units are subject to both a state allocation methodology pursuant to validly promulgated state regulations and the EPA's FIP allocation methodology because EPA has not been able to approve the SIP in a timely fashion. Such a scenario would inject unacceptable uncertainty into owner/operators long term planning processes. [EPA-HQ-OAR-2009-0491-3939[1].1, p.5]
In addition, if EPA allows state-created alternative allocation methodologies, those methodologies must contain adequate safeguards to ensure that the program results in the abatement of emissions necessary to meet the Section 110(a)(2)(D)(i)(I) obligations, and states cannot be authorized to modify other program elements of the Transport Rule, including but not limited to state budgets or variability allowances. [EPA-HQ-OAR-2009-0491-3939[1].1, p.5]
Business Council for Sustainable Energy (BCSE)
The BCSE has also long supported state set-aside programs that advance energy efficiency and renewable energy deployment and development. States should be free and encouraged to submit State Implementation Plans (SIPs) that include emission reduction approaches that recognize and provide incentives for energy efficiency (including CHP and WHP) and renewable energy development. Such set-aside programs would not increase a state's emissions because the total number of allowances would remain unchanged and, therefore, should not affect the approvability of any SIPs. [EPA-HQ-OAR-2009-0491-3985[1].1, p.1]
As the NODA acknowledges, EPA will need to provide guidance to the states on what EPA would accept as allowance distribution approaches or mechanisms. The BCSE encourages EPA to make it as clear as possible that it will look favorably upon SIPs that incorporate Federal Implementation Plan (FIP) elements but that adopt allowance allocation mechanisms that include set-aside programs for energy efficiency and renewable energy. [EPA-HQ-OAR-2009-0491-3985[1].1, pp.1-2]
Connecticut Department of Environmental Protection
Provisions for states to submit SIPs or abbreviated SIPs providing for state allocation of allowances CTDEP supports EPA's provisions for states to submit SIPs or abbreviated SIPs providing for State allocation of allowances in the proposed Transport Rule trading programs. CTDEP agrees with the concept of providing the opportunity for states to allocate allowances in order to address state-specific needs or policies. [EPA-HQ-OAR-2009-0491-3884[1].1, p.2]
Constellation Energy
Constellation Energy supports an abbreviated SIP addressing only allocations.
Regarding provisions for a state in the proposed Transport Rule region to participate in the Transport Rule trading programs through submission of a full SIP or to determine the unit-level allocations under a FIP through submission of an abbreviated SIP addressing only allocations, Constellation Energy reiterates our position that implementation of a Transport Rule on a timely basis is important for human health, environmental and economic concerns. Hobbling implementation through a lengthy and unnecessary SIP process would be counterproductive. Constellation Energy supports a FIP through submission of an abbreviated SIP addressing only allocations. [EPA-HQ-OAR-2009-0491-4031, p.3]
Exelon
Exelon also supports EPA's proposal to establish an expedited SIP approval process for states that wish to adopt a different allocation methodology, provided that allocation methodology does not undermine compliance or create perverse incentives. [EPA-HQ-OAR-2009-0491-3919[1].1, p.3]
Michigan Department of Natural Resources and Environment
The current TR is expected to be finalized in 2011 with immediate EPA implementation of 2012. This latest NODA allows for states to submit full or abbreviated SIPs and implement them at the earliest in 2014, meanwhile keeping the EPA implementation in effect. The DNRE agrees with the EPA's proposal to allow for state submittals of full or abbreviated SIPs to implement the program. [EPA-HQ-OAR-2009-0491-3890[1].1, p.1] [[This comment can also be found in Section XX.]]
As indicated by Tables III and IV within the NODA, the earliest that Michigan could take over allocations through an approved full or abbreviated SIP is November 1, 2011 for 2014 allocations and November 1, 2012 for 2015 allowances. The DNRE needs at least 18 months to generate a full or abbreviated SIP. This process cannot start until the TR is final, which is predicted to be spring of 2011. Thus the SIP would not be done until fall of 2012. Even if Michigan started now, without a final rule, the earliest we could have a complete rule package submitted to the EPA is June 2012 and the first time the states can allocate under a SIP would be for the annual and ozone season of 2014. [EPA-HQ-OAR-2009-0491-3890[1].1, pp.1-2]
National Rural Electric Cooperative Association (NRECA)
First, NRECA supports the proposal to include the two State Implementation Plan (SIP) options. [EPA-HQ-OAR-2009-0491-3943[1].2, p.3]
NRECA supports the CATR NODA III proposal incorporating the full and abbreviated SIP options into the final CATR regulation.   [EPA-HQ-OAR-2009-0491-3943[1].2, p.4]
Regarding the proposed SIP options, as EPA notes in the NODA III proposal, considering the time to submit and approve a SIP and record allowances, a SIP could not be applicable before the 2014 compliance period. [EPA-HQ-OAR-2009-0491-3943[1].2, pp.4-5]
New Jersey Department of Environmental Protection (NJDEP)
The Department is very supportive of US EPA's proposal to retain states' right to allocate the allowances from the state budget to the affected sources for the Transport Rule trading programs. It is very important that states retain this right because states work closely with the sources and would better understand how to fairly allocate the allowances. Also, if the USEPA does not use a dynamic allocation method like the three-year rolling average recommendation, states like New Jersey should have the right to use such a method for allocating allowances. New Jersey's NOx Budget Program and CAIR NOx Trading Programs are examples of states' success with allocations that are fair and better address new units. [EPA-HQ-OAR-2009-0491-3891[1].1, pp.2-3]
PowerSouth Energy Cooperative
PowerSouth also offers comments on the importance of facilitating State Implementation Plans (SIP) revisions which would allow the State of Alabama to set and administer unit allocations based on the state's budgets. [EPA-HQ-OAR-2009-0491-3956[1].1, p.1]
Prairie State Generating Company, LLC
An implementation schedule which should allow state authorities to develop SIPs [EPA-HQ-OAR-2009-0491-3897[1].1, p.1]
As noted above, PSGC supports provisions which allow states to develop their own Transport Rule SIPs. The states are in the best position to understand critical factors surrounding existing, new, and potential electric generating units locating within their boundaries. [EPA-HQ-OAR-2009-0491-3897[1].1, p.6]
South Carolina Department of Health and Environmental Control 
The EPA also proposed additional SIP provisions in the NODA. Under the Clean Air Act, states have the primary responsibility for air quality, and DHEC takes its responsibility as co-regulator with the EPA seriously. The EPA proposed two SIP options in the NODA, a 'full SIP' option and an 'abbreviated SIP' option, in which states would superintend various parts of the Transport Rule program. DHEC prefers both options over the abstract discussion in the August 2,2010 Proposal, and in general would support flexibility on SIP implementation in the final Transport Rule. [EPA-HQ-OAR-2009-0491-3961[1].1, p.2]
Again, DHEC generally supports the EPA's options on allocations and SIPS as proposed in the NODA. [EPA-HQ-OAR-2009-0491-3961[1].1, p.2] [[This comment can also be found in Section XX.A.1.]]
Southern IL Power Cooperative
Southern Illinois Power Cooperative supports the proposal to include the two State Implementation Plan (SIP) options. [EPA-HQ-OAR-2009-0491-3901[1].1, p.2]
State of Louisiana, Department of Environmental Quality
Louisiana requests that EPA extend the same FIP/SIP alternatives that were available in the CAIR to those states affected by the proposed Transport Rule. [EPA-HQ-OAR-2009-0491-3977[1].1, p.2]
West Virginia Department of Environmental Protection
Information regarding provisions for state participation in the Trading Rule trading program through submission of a full or abbreviated SIP
EPA has requested comment on two approaches, which are analogous to the approaches adopted under the CAIR trading programs. WVDAQ supports the first approach, wherein EPA would adopt new provisions, as part of the proposed Transport Rule FIP that would allow a state to submit an abbreviated SIP modifying specified provisions of the proposed trading programs. Specifically, the abbreviated SIP would substitute state allocation provisions (for entities other than opt-in units) for controls periods in years after 2012. The abbreviated SIP could provide for the substitution of state allocations in one or more of the proposed Transport Rule trading programs. [EPA-HQ-OAR-2009-0491-4000[1].1, p.3]
Western Farmers Electric Cooperative (WFEC)
Regarding the proposed SIP options, as EPA notes in the NODA III proposal, considering the time to submit and approved a SIP and record allowances, a SIP could not be applicable before the 2014 compliance period.  [EPA-HQ-OAR-2009-0491-3945[1].1, p.2] 
WFEC supports the CATR NODA III proposal incorporating the full and abbreviated SIP options into the final CATR regulation.   [EPA-HQ-OAR-2009-0491-3945[1].1, p.4]
Wolverine Power Supply Cooperative
Regarding the USEPA's request for comment on adding an abbreviated State Implementation Plan (SIP) process to the proposed Transport Rule that would allow states the authorization to develop their own allocation schemes for the state's budget, while otherwise accepting the FIP, Wolverine supports this concept as adding additional flexibility to the process. [EPA-HQ-OAR-2009-0491-4014[1].1, p. 5]
Response: 
In the final Transport Rule, EPA revises the deadlines for submission of SIP revisions to replace EPA-determined allocations by state-determined allocations.  The first deadline for submission of SIP revisions with replacement, state-determined allocations is April 1, 2012 for allocations for 2013.  See section X of the preamble.
Organization: Dayton Power and Light Company (DP&L)
Comment: 
Dayton Power and Light Company (DP&L)
F. Provisions for States to Submit Transport Rule SIPs or Abbreviated SIPS Providing for State Allocation of Allowances in Proposed Transport Rule Trading Programs.
DP&L supports the opportunity of the State of Ohio to create a SIP and allocate allowances at the earliest possible time. DP&L does not support 'the auction of some or all of the allowances' by Ohio or the EPA. DP&L believes that it is an inappropriate additional cost to the utilities and auctioning allowances will interfere with the market incentive to reduce emissions inherent in an allocated allowance system. [EPA-HQ-OAR-2009-0491-3973[1].1, p.4]
:: State SIPS are warranted at the earliest possible time. [EPA-HQ-OAR-2009-0491-3973[1].1, p.4]
:: States should be discouraged from auctioning SO2 or NOx allowances. [EPA-HQ-OAR-2009-0491-3973[1].1, p.4]
Response: 
In the final Transport Rule, EPA revises the deadlines for submission of SIP revisions to replace EPA-determined allocations by state-determined allocations.  The first deadline for submission of SIP revisions with replacement, state-determined allocations is April 1, 2012 for allocations for 2013.  See section X of the preamble.
In the final Transport Rule, EPA does not establish auctioning of allowances in the Transport Rule FIP trading programs.  Further, EPA does not see -- and the commenter's unsupported, general assertions failed to provide -- any basis for barring states from considering whether to provide for allowance auctions in SIP revisions modifying or replacing the FIP trading program allocation provisions.  In order to provide states the flexibility to consider, and decide whether to adopt, allowance auctions in SIP revisions, the final rule neither encourages nor discourages state adoption of such auctions.  Instead, the final rule allows states to determine whether auctioning of any allowances is appropriate, and interested parties (such as the commenter) will have an opportunity to comment -- consistent with states' SIP development and adoption procedures -- on the appropriateness of allowance auctions. 
Organization: Edison Mission Energy (EME)
Comment: 
Edison Mission Energy (EME)
While EME agrees that a re-evaluation of the methodology used to determine unit level allocations is needed and believes that states should implement the emission limitation goals of the Transport Rule through State Implementation Plans ("SIPs"), EME does not believe that the allocation methodology or the SIP provisions proposed in the Transport Rule NODA adequately address the flaws it has identified with EPA's approach to the Transport Rule. [EPA-HQ-OAR-2009-0491-3953[1].1, p.2] [[This comment can also be found in Section XX.A.1.]]
EPA should allow states to implement the Transport Rule through SIPs because states are best positioned to collect the information needed to make informed decisions on unit level allocations. [EPA-HQ-OAR-2009-0491-3953[1].1, p.3]
The Transport Rule NODA provisions regarding SIPs still violate the cooperative federalism dictates of Title I of the CAA.
While EPA proposes that states may submit SIPs for Phase II of the Transport Rule, EPA's proposal still requires the implementation of the Transport Rule directly through FIPs in Phase I and likely during part of Phase II. [EPA-HQ-OAR-2009-0491-3953[1].1, p.3]
EME submits that EPA should allow states to implement the Transport Rule through SIPs because EPA does not have the authority to directly implement FIPs (see section V below) and because states are best positioned to collect the emissions data, information on the status of controls and generation mix, and other information needed to make informed decisions on unit level allocations (in many states, such as those with delegated air programs, EGUs report data directly to the states). Furthermore, allowing states to implement the Transport Rule through SIPs will allow states to take into account important state-specific consideration. As an example, states that currently have output-based allocation systems in place, may choose to proceed with an output-based allocation approach for the Transport Rule. This would be the most logical and efficient mechanism in these states because EGUs will have already made control technology investments based upon output-based allocations. [EPA-HQ-OAR-2009-0491-3953[1].1, pp.14-15]
Despite EPA's Proposal, The Agency Will Still be Improperly Imposing Emission Reductions on States by Directly Implementing FIPs.
EPA's Proposal seeks comment on two approaches (which it describes as analogous to approaches adopted under CAIR trading programs) that would purportedly allow states to allocate allowances and participate in the Transport Rule trading programs. The first approach would allow states to submit an abbreviated SIP substituting state developed unit level allocation provisions for EPA's unit level allocations. The abbreviated SIP could not change any other aspect of the Transport Rule trading program and the allocation allowances could not exceed the applicable state budget. The second approach would allow states to submit a full SIP if it adopts Transport Rule trading program regulations. If approved, EPA proposes in the Transport Rule NODA that the full SIP would correct the deficiency under CAA § 110(a)(2)(D)(i)(I) that EPA claims is the basis for issuance of the Transport Rule FIP. EPA's proposed second approach would significantly limit the differences that the state could adopt in its SIP. A state would only be allowed to adopt its own unit level allocation provisions, and they would have to meet the same requirements as EPA's first approach. [EPA-HQ-OAR-2009-0491-3953[1].1, pp.15-16]
Importantly, under both approaches, EPA would require that the final allocations for existing units be issued by May 1 (or January 1 for ozone season NOx) two years before the control period in which the allowances would be distributed. Furthermore, EPA would require a certain amount of time for its review and approval of the SIPS. Consequently, EPA's Proposal does not even allow for implementation of SIPs at any point during Phase I of the Transport Rule -- in either 2012 or 2013. EPA concedes that it "assume[s] that the first year for which state allocations might be used, in lieu of EPA allocation, would be 2014." [EPA-HQ-OAR-2009-0491-3953[1].1, p.16]
However, EME submits that even though EPA's proposal theoretically allows for implementation of SIPs in 2014 during Phase II of the Transport Rule, states will not likely be able to submit alternative allocations until the deadline for the 2015 control year at the earliest. It would be nearly impossible for states to meet the 2014 deadline because the SIP would be due to EPA by November 1, 2011. This is less than nine months away and EPA has not even finalized the Transport Rule yet. States must either promulgate a SIP through notice and comment rulemaking or through the enactment of legislation. It is highly unlikely that either of these actions could occur in that timeframe. [EPA-HQ-OAR-2009-0491-3953[1].1, p.16]
Therefore, even under EPA's Transport Rule NODA, the Transport Rule would be implemented by FIPs for at least the first three years of its operation, including the entirety of Phase I of the Transport Rule. As explained below, since the approaches proposed in the Transport Rule NODA still require implementation of the Transport Rule through FIPs, they are contrary to law. [EPA-HQ-OAR-2009-0491-3953[1].1,p.17]
The Transport Rule NODA provisions regarding SIPs still violate the cooperative federalism dictates of Title I of the CAA. [EPA-HQ-OAR-2009-0491-3953[1].1, p.24]
Response: 
In the final Transport Rule, EPA revises the deadlines for submission of SIP revisions to replace EPA-determined allocations by state-determined allocations.  The first deadline for submission of SIP revisions with replacement, state-determined allocations is April 1, 2012 for allocations for 2013.  See section X of the preamble.
See section IV.C of the preamble, concerning EPA's authority to issue the final Transport Rule FIPs, and section VII.C of the preamble, concerning the compliance deadlines under the final Transport Rule.
Organization: EquiPower Resources Corp.
Comment: 
EquiPower Resources Corp.
EPA should allow states to implement the Transport Rule through SIPs.
o The Transport Rule NODA's proposal regarding SIPs will not allow states to adopt SIPs to implement the Rule until 2014 at the very earliest and, for many states, likely later. Therefore, the Transport Rule NODA, like the Transport Rule, directly implements the regulations through FIPs.[EPA-HQ-OAR-2009-0491-3928[1].1, pp.2-3]
EPA Should Allow States to Implement the Transport Rule Through SIPs
State regulators are in the best position to craft SIPs and decide unit-level allocations as they have a detailed understanding about the generation mix in their state, the status of controls on those EGUs, and the performance of individual EGUs or groups of EGUs. They are also best-situated to compile data and perform the necessary analyses because the universe of affected sources in an individual state is much smaller than the total number of sources covered by the Transport Rule. Additionally, in states with delegated air programs, individual EGUs are obligated to report data directly to them. If states were allowed to establish the allocations, they would likely select allocation approaches tailored to the specific circumstances in a given state, as opposed to the one-size-fits-all approach employed by EPA under the Transport Rule's FIP. More importantly, in contrast to EPA's proposals, states typically do regular re-allocations to adjust for changes in the source mix, capacity, etc. Therefore, a state approach would be less likely to lead to supply disruptions and inefficient use of capital. [EPA-HQ-OAR-2009-0491-3928[1].1, pp.12-13]
However, EPA's Proposal is flawed for two reasons: (1) it does not allow states to implement SIPs until years after the Transport Rule goes into effect; and (2) even when states would be allowed, under EPA's Proposal, to promulgate SIPs to allocate allowances and participate in the Transport Rule trading programs, EPA's Proposal limits states' flexibility to determine how best to achieve the Transport Rule NAAQS. [EPA-HQ-OAR-2009-0491-3928[1].1, p.15]
EPA's proposal regarding SIPs in the Transport Rule NODA does nothing to correct the Transport Rule's failure to comply with the cooperative federalism structure that is established under Title I of the CAA. [EPA-HQ-OAR-2009-0491-3928[1].1, p.20]
Response: 
In the final Transport Rule, EPA revises the deadlines for submission of SIP revisions to replace EPA-determined allocations by state-determined allocations.  The first deadline for submission of SIP revisions with replacement, state-determined allocations is April 1, 2012 for allocations for 2013.  See section X of the preamble.
The commenter's objection that, in allowing states to adopt SIP revisions for allowance allocations, the Transport Rule "limits states' flexibility to determine how best to achieve the Transport Rule NAAQS" is unclear.  If the commenter is claiming that EPA lacks the authority to issue FIPs in the Transport Rule, see section IV.C of the preamble.  If the commenter is claiming that EPA is not allowing states to adopt approaches -- other than the approaches in the Transport Rule trading programs -- to eliminate states' significant contribution and interference with maintenance determined in the Transport Rule, states continue to have the option of submitting SIP revisions that do not use the Transport Rule trading programs and that cure the deficiency in the state's SIPs under CAA section 110(a)(2)(D(i)(I), and EPA will review such SIP revisions on a case-by-case basis.   See section X of the preamble.
Organization: Exxon Mobil Corporation
American Petroleum Institute (API)
Comment: 
American Petroleum Institute (API)
D. Provision to allow States to submit Transport Rule SIPs
On page 1,119 of this NODA, EPA notes that comments on the proposed CATR suggested that EPA provide state options similar to the two alternatives provided to states by EPA in the CAIR trading programs where: (1) EPA adopted a rule and model trading regulations under which states that adopted, as state SIP trading programs, the model regulations (with only certain limited changes allowed, e.g., in the allocation provisions) could participate in the EPA-administered CAIR trading programs; and (2) EPA adopted a rule allowing states to adopt in SIPs provisions replacing only certain provisions in the CAIR FIPs (e.g., the allocation provisions) and to remain in the CAIR trading programs under the CAIR FIPs. Under both approaches, the covered units in the state participated in the CAIR trading programs, albeit with state, rather than EPA, determined allocations. [EPA-HQ-OAR-2009-0491-3982[1].1, p.4]
EPA is taking comment on two approaches. These approaches would allow states to, and would provide the only ways that states could, allocate allowances and participate in the proposed Transport Rule trading programs. We support EPA providing States the flexibility to choose if needed, how to participate. In general, our experience indicates that state agencies can work well with covered units to determine allocations that may result in improved allocation methods. A state can also better address special economic, historic operations, and electric reliability and distribution circumstances via a state allocation program. [EPA-HQ-OAR-2009-0491-3982[1].1, pp.4-5]
API provides the following comments on the "third approach" as we read at FR 1120. EPA notes as a third approach that each state would still have the ability to submit other types of SIPs using emissions reduction approaches other than the proposed Transport Rule trading programs to correct the deficiency under CAA section 110(a)(2)(D)(i)(I) in the state's SIP that was the basis for the proposed Transport Rule FIPs. The EPA would review such SIP submissions on a case-by-case basis and intends to provide guidance to states that want to develop and submit such SIPs. [EPA-HQ-OAR-2009-0491-3982[1].1, p.5]
We support EPA providing this guidance to states as rapidly as possible to allow them to be best equipped to choose among options and make fully informed decisions. In our view the guidance should cover how a state can demonstrate that its emissions DO NOT contribute to downwind non-attainment or interfere with maintenance and recognize the current Air Quality Data. For example, it appears that at year end 2010 only 2 non-attainment areas (Tarrant County, TX Ozone design value of 0.084 ppm and Harford County, MD with an Ozone design value of 0.089 ppm) have an Ozone design value exceeding the 1997 8-Hour ozone NAAQS of 0.08 ppm. We suggest that many states which EPA CATR proposal shows as contributing to downwind non-attainment should be removed from this program based on an evaluation current air quality data. We strongly recommend and support EPA providing guidance that will provide clarity about the use of current air quality data in the determination of whether a state has a downwind impact.
And finally, API supports flexibly for the states to allocate allowances and participate in the proposed CATR trading programs. [EPA-HQ-OAR-2009-0491-3982[1].1, p.6]
Exxon Mobil Corporation
2. SIP alternates to the CATR approach - At FR 1120, EPA notes as a third approach that each state would still have the ability to submit other types of SIPs using emissions reduction approaches other than the proposed Transport Rule trading programs to correct the deficiency under CAA section 110(a)(2)(D)(i)(I) in the state's SIP that was the basis for the proposed Transport Rule Federal Implementation Plans. The EPA would review such SIP submissions on a case-by-case basis and intends to provide guidance to states that want to develop and submit such SIPs. We support EPA providing this guidance to states as rapidly as possible to allow them to be best equipped to choose among options and make fully informed decisions. In our view the guidance should cover how a state can demonstrate that its emissions DO NOT contribute to downwind non-attainment or interfere with maintenance and recognize the current Air Quality Data in this demonstration. [EPA-HQ-OAR-2009-0491-3999[1].1, p.2]
Comment
We support EPA providing States the flexibility to choose, if needed, how to participate. In general, our experience indicates that state agencies can work well with covered units to determine allocations that may result in improved allocation methods. A state can also better address special economic, historic operations, and electric reliability and distribution circumstances via a state allocation program. [EPA-HQ-OAR-2009-0491-3999[1].1, p.8]
Comment
We support EPA providing this guidance to states as rapidly as possible to allow them to be best equipped to choose among options and make fully informed decisions. In our view the guidance should cover how a state can demonstrate that it's emissions DO NOT contribute to downwind non-attainment or interfere with maintenance and recognize the current Air Quality Data. For example, it appears that at year end 2010 only 2 nonattainment areas (Tarrant County, TX Ozone design value of 0.084 ppm and Harford County, MD with an Ozone design value of 0.089 ppm) have an Ozone design value exceeding the 1997 8-Hour ozone NAAQS of 0.08 ppm. We suggest that many states which EPA CATR proposal shows as contributing to downwind non-attainment should be removed from this program based on an evaluation current air quality data. We strongly recommend and support EPA providing guidance that will provide clarity about the use of current air quality data in the determination of whether a state has a downwind impact. [EPA-HQ-OAR-2009-0491-3999[1].1, p.8]
Response: 
See section X of the preamble. 
EPA rejects the commenter's claim that EPA should provide guidance for states covered by the final Transport Rule to demonstrate that they do not significantly contribute to nonattainment or interfere with maintenance.  In the final Transport Rule, EPA determines that certain states significantly contribute to nonattainment and interfere with maintenance, finds that these states failed to submit SIP revisions to eliminate such significant contribution and interference with maintenance as required by CAA section 110(a)(2)(D)(i)I(I), and therefore makes these states subject to the Transport Rule FIP trading programs.  While states may submit SIP revisions that will eliminate such significant contribution and interference with maintenance, parties (including the states involved) already had a full opportunity in this rulemaking to comment on these determinations, which are final determinations subject to judicial review. 
Organization: Giarmarco, Mullins & Horton, P.C.
Comment: 
Giarmarco, Mullins & Horton, P.C.
The January 7,2011 NODA also requests comments on the provisions for states to submit their own SIPs to implement the TR. This issue has been of some concern to MCV and the State of Michigan as reflected in its previous comments to the TR. By letter dated February 7,2011, the State of Michigan further points out the adverse impact on the states and affected sources due to the shortened timeline for implementation. EPA should provide sufficient time so the states can adequately address the requirements of the TR and submit an approvable SIP. Only after a designated time period (18 months following issuance of final TR), should a FIP then be issued by EPA for states that have not complied. In this regard, MCV supports and endorses the comments submitted by the State of Michigan. [EPA-HQ-OAR-2009-0491-4015[1].1, p. 2]
Response: 
In the final Transport Rule, EPA revises the deadlines for submission of SIP revisions to replace EPA-determined allocations by state-determined allocations.  The first deadline for submission of SIP revisions with replacement, state-determined allocations is April 1, 2012 for allocations for 2013.  See section X of the preamble.
See section IV.C of the preamble, concerning EPA's authority to issue the final Transport Rule FIPs, and section VII.C of the preamble, concerning the compliance deadlines under the final Transport Rule.
Organization: Gulf Coast Lignite Coalition
Comment: 
Gulf Coast Lignite Coalition
GCLC supports EPA's proposal that States be able to propose and implement their own allowance allocation methodologies through State Implementation Plan (SIP) revisions, however GCLC finds the revision periods for the states to be unrealistic and incredibly short given the complexity involved. [EPA-HQ-OAR-2009-0491-3963[1].1, p.2]
In the NODA, EPA proposes new SIP revision timelines, by which date the states would submit their plans and be able to substitute state allocation provisions instead of EPA's allocation provisions under the Transport Rule FIP. EPA acknowledges that the SIP revision timeline is insufficient for States to develop and submit either abbreviated or full SIPs with allowance allocation provisions. EPA states that the final Transport Rule would be proposed in mid-2011, which could be late Spring or Summer, and that States in return would have until November 1, 2011 to submit abbreviated or full-SIPs with the state allocation provisions. If successful in submitting a SIP by this incredibly quick deadline, the State could then begin allocating or auctioning allowances in 2014. [EPA-HQ-OAR-2009-0491-3963[1].1, pp.3-4]
EPA would then be allotting approximately three months or so for a state to revise its SIP and to undergo its own approval process, but affording the EPA almost double the amount of time to review the review the SIP revision.  With the increasing workload and under-staffing of state agencies, the EPA should grant some leeway and flexibility for the state to submit proper SIP revisions and to better assess allocation methodologies appropriate for the state.[EPA-HQ-OAR-2009-0491-3963[1].1, p.4]
EP A should afford a more flexible SIP revision timelines so that states may appropriately examine allowance allocations appropriate for the state, particularly since EPA is given a more lengthy time to review the SIP revision.  [EPA-HQ-OAR-2009-0491-3963[1].1, p.4]
Response: 
In the final Transport Rule, EPA revises the deadlines for submission of SIP revisions to replace EPA-determined allocations by state-determined allocations.  The first deadline for submission of SIP revisions with replacement, state-determined allocations is April 1, 2012 for allocations for 2013.  See section X of the preamble.
Organization: Hoosier Rural Electric Cooperative
Comment: 
Hoosier Rural Electric Cooperative
Hoosier Energy REC, Inc. is in agreement with the inclusion of both the abbreviated and full SIP options proposed in the NODA III.  However, the timeframe prescribed will not allow States sufficient time to allocate allowances in a fair and equitable manner and to address State's individual needs and concerns.  [EPA-HQ-OAR-2009-0491-3927[1].1, p.2]
Response: 
In the final Transport Rule, EPA revises the deadlines for submission of SIP revisions to replace EPA-determined allocations by state-determined allocations.  The first deadline for submission of SIP revisions with replacement, state-determined allocations is April 1, 2012 for allocations for 2013.  See section X of the preamble.
Organization: Independence Power & Light (IPL)
Kansas City Board of Public Utilities (BPU)
Comment: 
Independence Power & Light (IPL)
IPL supports EPA's proposal to allow states to adopt a full SIP under which a state 'could allocate allowances to Transport Rule units . . . or could auction allowances.' 76 FR at 1120/1 and supports the proposal to allow States to adopt an 'abbreviated SIP [that] would substitute state allocation provisions . . . in lieu of the current [FIP] allocations provisions,' Id at 1119/2. IPL believes that states should have the full range of options available for SIPs to implement any and all transport rule elements and that each state should have the ability to specify the option that the state wishes to exercise. The proposed full or abbreviated SIP options are subject to a condition that they include 'only limited differences from the provisions of the proposed Transport Rule FIP trading program.' Id. While States could submit other SIPs for approval on a case-by-case basis, only those States submitting SIPs complying with the requirements of the 'full SIP' described above would be allowed 'to use the proposed Transport Rule trading programs' as a means to cure any allowance deficiencies that would otherwise cause the State to exceed its annual emissions budget under the Air Transport Rule. Id. [EPA-HQ-OAR-2009-0491-3949[1].1, p.11]
IPL is in favor of the full and abbreviated SIPs as providing additional flexibility for states to modify unit allowances on an annual basis as circumstances change. To the extent this approach offers a fast, efficient means for SIP approvals that allows new unit allowances to align concurrently with changing local conditions, it would be a welcome addition to the process. On the other hand, this proposal, for all practical purposes, restricts a state's ability to formulate in the first instance an appropriate SIP by requiring that a SIP either adopt the identified federal conditions or not be eligible for the proposed trading programs. Such a restriction raises a question whether in reviewing SIPs, EPA 'will not be open to considering approaches other than those prescribed' in the Rule. General Electric Co. v. EPA, 290 F.3d 377, 384 (D.C. Cir. 2002). That would impermissibly limit states' options to formulate SIPs in the first instance in violation of the Clean Air Act's scheme. Consequently, the final rule should carefully consider the extent to which the statute allows EPA to rein in the States' role in these matters. [EPA-HQ-OAR-2009-0491-3949[1].1, pp.11-12]
Finally, IPL requests that EPA provide the states with unrestricted SIP options for implementation of any Transport Rule that may be placed into effect without danger of losing their ability to participate in the trading programs. [EPA-HQ-OAR-2009-0491-3949[1].1, pp.12-13]
Kansas City Board of Public Utilities (BPU)
III. SIP OPTION
BPU supports EPA's proposal to allow states to adopt an 'abbreviated SIP [that] would substitute state allocation provisions . . . in lieu of the current [FIP] allocations provisions,' 76 FR at 1119/2, or a full SIP under which a state 'could allocate allowances to Transport Rule units . . . or could auction allowances.' Id. at 1120/1. These proposed full or abbreviated SIPs are subject to a condition that they include 'only limited differences from the provisions of the proposed Transport Rule FIP trading program.' Id. While states could submit other SIPs for approval on a case-by-case basis, only those states submitting SIPs complying with the requirements of the 'full SIP' described above would be allowed 'to use the proposed Transport Rule trading programs' as a means to cure any allowance deficiencies that would otherwise cause the state to exceed its annual emissions budget under the Air Transport Rule. Id. [EPA-HQ-OAR-2009-0491-3978[1].1, p.8]
BPU applauds the proposal to make available these 'safe harbor' full and abbreviated SIPs as providing additional flexibility for states to modify unit allowances on an annual basis as circumstances change. To the extent this approach offers a fast, efficient means for SIP approvals that allows new unit allowances to align concurrently with changing local conditions, it would be a welcome addition to the process. On the other hand, this proposal, for all practical purposes, restricts a state's ability to formulate in the first instance an appropriate SIP by requiring that a SIP either adopt the identified federal conditions or not be eligible for the proposed trading programs. Such a restriction raises a question whether in reviewing SIPs, EPA 'will not be open to considering approaches other than those prescribed' in the Rule. General Electric Co. v. EPA, 290 F.3d 377, 384 (D.C. Cir. 2002). That would impermissibly limit states' options to formulate SIPs in the first instance in violation of the Clean Air Act's scheme. Consequently, the final rule should carefully consider the extent to which the statute allows EPA to rein in the states' role in these matters. [EPA-HQ-OAR-2009-0491-3978[1].1, pp.8-9]
Response: 
In the final Transport Rule, EPA revises the deadlines for submission of SIP revisions to replace EPA-determined allocations by state-determined allocations.  The first deadline for submission of SIP revisions with replacement, state-determined allocations is April 1, 2012 for allocations for 2013.  See section X of the preamble.
EPA rejects the commenters' objection to the requirement that, in order to participate in the Transport Rule trading programs, States must submit full or abbreviated SIPs that may replace and change the methodologies -- set forth in the Transport Rule FIPs -- for distributing allowances but may not change any other elements of the Transport Rule trading programs.  The commenters failed to identify any specific element (other that the allowance distribution methodologies, which can be changed) of the Transport Rule trading programs that the commenters believe states should be allowed to change and still participate in these trading programs.  The final Transport Rule reasonably limits, for the following reasons, the changes that can be made where a state wants to participate in these trading programs.  First, many provisions of the trading programs have been developed and adopted in order for the trading programs to meet legal requirements.  For example, the specific state budgets, requirement to hold allowances to cover emissions, and assurance provisions are necessary in order to eliminate significant contribution and interference with maintenance in accordance with CAA section 110(a)(2)(D)(i)(I) and North Carolina.  See sections VI.D, F, and G and VII.E and J of the preamble.  The commenters failed to identify any alternatives to these provisions, much less show how alternatives would meet the requirements of the CAA as interpreted in North Carolina.  Second, many provisions must be uniform for all participating sources in order for the trading programs to operate successfully and meet the programs' environmental goals.  For example, in order for allowances to be fungible and therefore tradable in the allowance market with minimum transactions costs, each allowance must authorize the same amount (i.e., one ton) of emissions.  This means that all sources that may use an allowance to cover its emissions must meet uniform emission monitoring and reporting requirements that yield quality-assured emission data.  If monitoring and reporting were not uniform and accurate, then "one ton" of emissions reported by one unit and covered by one allowance might not be the same as "one ton" reported by another unit and covered by one allowance, and required emission reductions might not be achieved.  The commenters failed to identify any alternatives to the monitoring and reporting requirements in the trading programs, much less provide any basis for such alternatives.  Third, many provisions must be uniform in order for the Administrator to be able, as a practical matter, to operate trading programs in multiple states in an efficient manner and for participating parties to understand and comply with program requirements.  For example, for this reason, allowance management system requirements concerning selection of designated representatives, establishment of accounts, recordation of allowance distribution, and transfer of allowances are uniform.  The commenters failed to identify any alternatives  to these allowance management system requirements, much less provide any basis for such alternatives.  Moreover, the Transport Rule provides that EPA will review, case-by-case, states' SIP revisions that do not use the Transport Rule trading programs, but use other approaches (including state-administered intrastate or interstate trading approaches) to remedy the SIPs' deficiency under CAA section 110(a)(2)(D)(i)(I).  In short, the commenters provided no basis for their vague objection to the requirements for full and abbreviated SIPs for states that want to participate in the Transport Rule trading programs.
Organization: Kansas City Power and Light Company (KCP&L)
Comment: 
Kansas City Power and Light Company (KCP&L)
Even under the abbreviated SIP process proposed in NODA 3, this is contrary to the Act, in that the opportunity to replace federal requirements with a state plan at some time in the future does not satisfy the requirement that EPA allow the states an opportunity to develop their own plans at the outset of the program. [EPA-HQ-OAR-2009-0491-3893[1].1, p.2]
Possible options for states wishing to submit State Implementation Plans (SIPs) providing for state allocation of allowances in the proposed Transport Rule trading programs:
KCP&L is generally supportive of any provisions that provide greater autonomy to the states with regard to allowance allocations. The proposed option for states to submit abbreviated SIPs to address allowance allocations only would streamline the process for state involvement. [EPA-HQ-OAR-2009-0491-3893[1].1, p.4]
Response: 
In the final Transport Rule, EPA revises the deadlines for submission of SIP revisions to replace EPA-determined allocations by state-determined allocations.  The first deadline for submission of SIP revisions with replacement, state-determined allocations is April 1, 2012 for allocations for 2013.  See section X of the preamble.
See section IV.C of the preamble, concerning EPA's authority to issue the final Transport Rule FIPs, and section VII.C of the preamble, concerning the compliance deadlines under the final Transport Rule.
Organization: Maryland Department of Environment (MDE)
Comment: 
Maryland Department of Environment (MDE)
Overall, ARMA commends EPA for their approach to allocations and state implementation plans as reflected in the Transport Rule NODA. We strongly support EPA's use of historic heat input for the two alternative allocation methodologies and EPA's proposal for an abbreviated SIP and full SIP allowing states to take control of allocation to our sources. [This comment can also be found in section XX.A.1.] [EPA-HQ-OAR-2009-0491-3972[1].1, p.1]
a. Clean Air Interstate Rule (CAIR) full SIP and abbreviated SIP
We are pleased that EPA responded positively to Maryland's comment on the Transport Rule proposal regarding a FIP-SIP framework for the proposed Transport Rule. Maryland strongly recommended that EPA provide a FIP-SIP mechanism that allows a state to have its own discretion in the design of some aspects of the remedy, such as allocation of the state's allowance budget to sources. Maryland also recommended that EPA allow a state to submit an abbreviated SIP following the example under the Clean Air Interstate Rule (CAIR), where the state would design certain elements such as allocation of the allowance budget. In the Transport Rule NODA, EPA has provided options for a full SIP and an abbreviated SIP following the CAIR model. [EPA-HQ-OAR-2009-0491-3972[1].1, p.2]
b. SIP to help with achieving a full remedy on time
ARMA urges EPA to strengthen the proposed Federal Implementation Plan (FIP) by mandating that upwind states' State Implementation Plans (SIPs) contribute to development of a full remedy if the federal remedy does not achieve elimination of significant contribution and interference with maintenance within the required CAA timeframe. ARMA recommends that EPA revise the proposed full SIP and abbreviated SIP provisions of the NODA to address this issue. [EPA-HQ-OAR-2009-0491-3972[1].1, p.2]
c. Schedule for submitting SIPs
We have some concerns with EPA's schedule for submitting abbreviated SIPs. The earliest year for which Maryland could use its own allocation  [EPA-HQ-OAR-2009-0491-3972[1].1, p.2]scheme for allowances is 2014. EPA's schedules in Tables III and IV (76 FR 1120-1121) provide that a state must submit either an abbreviated or full SIP by November 1,2011, in order for a state allowance allocation scheme to possibly apply for year 2014 allowances. Our understanding is that the Transport Rule will not be finalized until July 2011, giving us at most four months to write a SIP, hold public hearings on the SIP and follow other administrative procedures for SIP approvals. It would be very difficult for Maryland to be able to meet this deadline for 2014 allocations. [EPA-HQ-OAR-2009-0491-3972[1].1, pp.2-3]
ARMA strongly recommends that EPA reconsider the submittal deadlines for both abbreviated and full SIPs. For example, under CAIR, EPA recognized that it took less time to approve an abbreviated SIP than a full SIP. EPA took the approach of allowing states to submit abbreviated SIPs six months later than the date for full SIPs and only one month before the date by which states were to have submitted allocations or auction results for existing units. We strongly encourage EPA to follow this example for the Transport Rule NODA, allowing states to submit abbreviated SIPs by as late as April 1, 2012, for year 2014 allocations. Likewise, EPA should also consider a later date for abbreviated SIP submittals for future year allocations. [EPA-HQ-OAR-2009-0491-3972[1].1, p.3]
d. Auctions
In the Transport Rule NODA's provisions for full and abbreviated SIPs, EPA included the option for states to auction some or all of their allowances, besides states having the option of allocating their allowances. ARMA strongly supports inclusion of the auction option. [EPA-HQ-OAR-2009-0491-3972[1].1, p.1]
Response: 
In the final Transport Rule, EPA revises the deadlines for submission of SIP revisions to replace EPA-determined allocations by state-determined allocations.  The first deadline for submission of SIP revisions with replacement, state-determined allocations is April 1, 2012 for allocations for 2013.  See section X of the preamble.  Based on its experience with reviewing full and abbreviated SIPs under CAIR, EPA has found that review of abbreviated SIPs and review of full SIPs take about the same amount of time.  In fact, the changes that each type of SIP revision (whether abbreviated or full SIPs) can make in the Transport Rule trading program provisions are the same and require about the same period for review and for providing notice and opportunity for public comment.   Also based on this experience, EPA found that the review and notice and comment processes in each case take about 6 months.   For these reasons, EPA rejects the commenter's claim that a shorter time than 6 months should be provided for review and approval of abbreviated SIPs. 
With regard to the commenter's claim that EPA should require that SIPs fully eliminate significant contribution and interference with maintenance to the extent the Transport Rule FIPs provide for full elimination, EPA notes that CAA section 110(a)(2)(D)(i)(I) already requires SIPs to prohibit emissions in the state from significantly contributing to nonattainment or interfering with maintenance and that the Transport Rule, of course, cannot and does not change that statutory requirement.  With regard to the commenter's claim that EPA should require that the particular types of SIP revisions that will allow states to replace and change allowance allocation provisions of, and still participate in, the Transport Rule trading programs, see sections VI.A and B of the preamble.  
Organization: National Association of Clean of Air Agencies (NACAA)
Massachusetts Department of Environmental Protection
Comment: 
Massachusetts Department of Environmental Protection
We are very pleased that the third NODA proposes to allow states to adopt their own allocation methods in a full or abbreviated SIP beginning with the 2014 control period. This would allow  Massachusetts to retain the output-based allocation method that it adopted in the CAIR program, should it choose to do so. We strongly support inclusion of the state allocation option through a full or abbreviated SIP in the final Transport Rule. We also reiterate our recommendation that EPA should grant states the flexibility to adopt a Transport Rule SIP annual or ozone season trading program that covers smaller EGUs and non-EGUs covered under the state's CAIR program. [EPA-HQ-OAR-2009-0491-4017[1].1, pp.1-2]
Under the SIP timelines EPA has proposed (third NODA - Tables III and IV), allocations would be based on the FIP methodology for the 2012 and 2013 control periods. We agree that states would not have time to submit SIPs that would allow for state allocations for the 2012 and 2013 periods. However, we are concerned that EPA's schedule for submission of SIPs for the 2014 period may be unrealistic. EPA proposes that a state must submit either an abbreviated or full SIP by November 1, 2011, in order for a state allowance allocation method to apply for 2014. If the Transport Rule is not finalized until June 2011, as EPA anticipates, states will have less than five months to write a SIP, hold public hearings, respond to comments on the proposed SIP, and submit the final SIP to EPA. Massachusetts would try to meet this schedule but it would be difficult to do so. [EPA-HQ-OAR-2009-0491-4017[1].1, p.2]
As an alternative, we suggest that EPA allow states to submit an abbreviated SIP at a later date than a full SIP. This was the approach EPA took in CAIR, recognizing that it required less time to approve an abbreviated SIP than a full SIP. Under CAIR, states could submit abbreviated SIPs six months later than the date for full SIPs and only one month before the date by which states were required to submit allocations for existing units. Consistent with the CAIR approach, EPA should allow states to submit abbreviated SIPs by as late as April 1, 2012, for year 2014 allocations. [EPA-HQ-OAR-2009-0491-4017[1].1, p.2]
Finally, we note in Table III, column 2, that the deadline for submitting abbreviated or full SIPs is listed as November 1,2012, for the 2016 control period. We believe that EPA may have intended this date to be November 1, 2013, which would be consistent with the other listed deadlines. [EPA-HQ-OAR-2009-0491-4017[1].1, p.2]
National Association of Clean of Air Agencies (NACAA)
We are pleased that EPA responded favorably to NACAA's comments on the Transport Rule proposal (75 Federal Register 45210), in which the association requested that the agency provide additional guidance to states that wish to submit abbreviated or full SIPs that contain provisions providing for state allocations or auctions of the Transport Rule allowances. As we noted in our comments, a number of NACAA members would prefer to allocate emissions allowances to in-state sources using their own procedures, rather than EPA's. For example, some states may wish to distribute their allowances to in-state sources in a manner that encourages renewable energy and energy efficiency. We believe that this should not affect the approvability of the SIP, since the distribution of allowances within the state does not affect the overall emissions in the state or a source's decision to control or not to control emissions. [EPA-HQ-OAR-2009-0491-3964[1].1, p.1]
We are also pleased that the Transport Rule NODA indicates specifically to what extent an abbreviated or full SIP may differ from the Transport Rule FIP provisions (pp. 1119-1120). We appreciate the clarity provided by the agency. [EPA-HQ-OAR-2009-0491-3964[1].1, p.2]
However, we do have some concerns with EPA's schedule for submitting abbreviated SIPs for states that wish to use their own allocation or auction procedures. The earliest year for which a state could use its own allocation scheme for allowances is 2014. EPA's schedules in Tables III and IV provide that a state must submit either an abbreviated or full SIP by November 1, 2011, in order for a state allowance allocation scheme to possibly apply for year 2014 allowances. Our understanding is that the Transport Rule will not be finalized until June 2011, giving states at most five months to write a SIP, hold public hearings on the SIP and otherwise follow its established administrative procedures for SIP approvals. It is unlikely any states would be able to meet this deadline for 2014 allocations. [EPA-HQ-OAR-2009-0491-3964[1].1, p.2]
We suggest an alternative: allowing states to submit an abbreviated SIP at a later date than a full SIP. This was the approach EPA took in the Clean Air Interstate Rule (CAIR), where the agency recognized that it required less time to approve an abbreviated SIP than a full SIP. Under CAIR, states could submit abbreviated SIPs six months later than the date for full SIPs and only one month before the date by which states were to have submitted allocations or auction results for existing units. Thus, EPA should allow states to submit abbreviated SIPs by as late as April 1, 2012, for year 2014 allocations.3 Likewise, EPA should also consider a later date for abbreviated SIP submittals for future year allocations. [EPA-HQ-OAR-2009-0491-3964[1].1, p.2] 

3 The deadline for states to submit allocation or auction results for 2014 allowances for existing units is May 1, 2012, so April 1, 2012, is consistent with CAIR's approach of allowing abbreviated SIPs to be submitted up to a month before this date.
Response: 
In the final Transport Rule, EPA revises the deadlines for submission of SIP revisions to replace EPA-determined allocations by state-determined allocations.  The first deadline for submission of SIP revisions with replacement, state-determined allocations is April 1, 2012 for allocations for 2013.  See section X of the preamble.  Based on its experience with reviewing full and abbreviated SIPs under CAIR, EPA has found that review of abbreviated SIPs and review of full SIPs take about the same amount of time.  In fact, the changes that each type of SIP revision (whether abbreviated or full SIPs) can make in the Transport Rule trading program provisions are the same and require about the same period for review and for providing notice and opportunity for public comment.   Also based on this experience, EPA found that the review and notice and comment processes in each case take about 6 months.   For these reasons, EPA rejects the commenters' claim that a shorter time than 6 months should be provided for review and approval of abbreviated SIPs. 
Organization: National Mining Association (NMA)
Comment: 
National Mining Association (NMA)
EPA in NODA-3 proposes to allow states to submit abbreviated allocation SIPs. To take advantage of this at the earliest available opportunity, states would need to submit proposed allocation SIPs by November 1, 2011, a few months after EPA proposes to finalize the rule. [EPA-HQ-OAR-2009-0491-4013[1].1, p.13]
Such a timeline is a practical impossibility. For most states this would require starting the state rulemaking process before the Transport Rule is even finalized and, therefore, before states even know which programs (if any) they are a part of, whether there will be state budgets and trading, or what the state budgets would be. In fact, many states would have to begin the abbreviated SIP process before knowing whether the rule will even allow for abbreviated SIPs. If a state meets this impossible timeline, its preferred state allocation method would not take effect until the third year of the program. [EPA-HQ-OAR-2009-0491-4013[1].1, pp.13-14]
This abbreviated SIP process therefore is too little and too late. States must be afforded an opportunity to determine how best to obtain necessary reductions, including where reductions should come from (e.g., EGUs, Non-EGUs, or other sources). The abbreviated SIP process does not allow this. Further, states would have no opportunity to influence the 2012 and 2013 allocations. EPA must allow states a full and complete opportunity to develop a full and complete SIP, and EPA's proposed abbreviated SIP process does not cure its unlawful usurpation of state authority. [EPA-HQ-OAR-2009-0491-4013[1].1, p.14]
Response: 
In the final Transport Rule, EPA revises the deadlines for submission of SIP revisions to replace EPA-determined allocations by state-determined allocations.  The first deadline for submission of SIP revisions with replacement, state-determined allocations is April 1, 2012 for allocations for 2013.  See section X of the preamble.
See section IV.C of the preamble, concerning EPA's authority to issue the final Transport Rule FIPs, and section VII.C of the preamble, concerning the compliance deadlines under the final Transport Rule.
Organization: NRG Energy
Comment: 
NRG Energy
 FIP Allocation and STATE SIP Options  -  Similar to the very successful Acid Rain Program, EPA should retain allocation jurisdiction. In order to promote a robust liquid market, allowances should be allocated to operational facilities for the duration of this program and for units that retire, retained for six years (as proposed). Changes to market rules can leave good faith participants with stranded investments as we have seen from the Clean Air Interstate Rule ("CAIR").   [EPA-HQ-OAR-2009-0491-3933[1].1, p.2]
FIP Allocation and STATE SIP Options  -  EPA had asked for comments on provisions for state participation in CATR by submitting full or partial SIPs. NRG appreciates EPA's approach to transition the CATR program from federal FIP implementation to State SIP operation. We believe the SIP process is fair and in alignment with the CCA and traditional SIP planning from a procedural perspective. However, we believe reallocation by the states is problematic and that similar to the Acid Rain Program, EPA should retain allocation jurisdiction and that allowances be allocated for an undefined duration to operational facilities and six years (as proposed) for affected units that will retire. [EPA-HQ-OAR-2009-0491-3933[1].1, p.7]
This transition as proposed can add greater compliance risk and planning uncertainty as many states will opt to establish alternate allocations to align with state initiatives or perhaps implement an auction process rather than grant full allocation as intended by this program. We present this caution as a generator in the Northeast where in 2009 the Regional Greenhouse Gas Initiative ("RGGI") was implemented. During the creation of this program, the RGGI developers had proposed a CO2 allowance allocation which in turn was promulgated as a "proposed auction up to 25%" to subsidize energy efficiency programs and offset predicted cost increases to rate payers with the expectation that the remainder of allowances would be issues to generators. However, because the regional program granted states the opportunity to govern allocation, as a result, most states opted for full auction to gain access to the proceeds. Whether new environmental programs are beneficial or detrimental, generating companies require certainty to plan investments and compliance strategies. In the event states have the ability to alter allocations, this can impact and impede generator planning and compliance implementation. For this reason, we strongly recommend EPA retain full governance on allocation and that the program mandate continuity of the full allocation as intended. [EPA-HQ-OAR-2009-0491-3933[1].1, p.8]
Response: 
EPA rejects commenter's claim that EPA should not allow states, through abbreviated or full SIPs, to replace and change the allowance allocation provisions in the Transport Rule trading programs.  First, the commenter pointed to the Acid Rain Program as providing a basis for not allowing states to change the allocation methodologies adopted in the Transport Rule.  However, the Acid Rain Program was a federal program created by CAA title IV, which specified the allocation methodologies to be used for all phases of the program.  In contrast, the Transport Rule trading programs are FIPs issued under CAA section 110(c) because states failed to submit SIPs meeting the requirements of CAA section 110(a)(2)(d)(i)(I), and FIPS can be replaced by SIP revisions that remedy that deficiency of the SIPs.  Further, EPA believes that, if SIP revisions meet certain requirements concerning allocations (such as the requirement that allocations meet certain timing requirements and not exceed state budgets) and retain unchanged the other provisions of the Transport Rule trading programs (except for the option of expanding applicability in the NOx ozone season program to small EGUs), the Agency can operate the Transport Rule trading programs, as modified by such SIP revisions, in a manner that will achieve the environmental goals of the programs (i.e., the elimination of significant contribution and interference with maintenance identified in the Transport Rule).  Therefore, EPA maintains that allowing states, with certain conditions, to replace and change the allowance allocation provisions in the Transport Rule trading programs and participate in these programs is consistent with its authority under CAA section 110(a)(2)(d)(i)(I) and (c). 
The commenter claimed that allowing states to change units' allocations from the allocations provided under the FIPs could "leave good faith participants with stranded investments" and "impact and impede generator planning and compliance implementation".   However, any allowance (whether allocated without cost to, or purchased by, the recipient) has a value on the allowance market and so the use (in lieu sale) of any allowance has an opportunity cost.  Consequently, EPA maintains that, although knowing a unit's allocations in advance facilitates the use of the allowance market in achieving compliance with the requirement to hold allowances covering emissions, owners'  and operators' decisions on overall compliance strategies and on investments to reduce emissions are not based on whether or to what extent the unit will be allocated allowances.  In fact, the commenter failed to explain why or how owners' and operators' overall compliance and investment decisions would be altered by the amounts of unit allocations, much less how a change in units' allocations would result in "stranded" investments in emission reductions.  For example, if a unit that had an allowance allocation under the FIPs received a reduced, or even no, allocation under an abbreviated or full SIP revision, any investment made in the unit to reduce emissions would still save the unit the cost of using allowances, whether the allowances that otherwise would have been used would have been allocated to or purchased by the unit.  It is difficult to see how the investment would be "stranded" by the change in the unit's allocation. 
With regard to allocations for retired units, see section D of the preamble.
Organization: San Miguel Electric Cooperative, Inc.
Old Dominion Electric Cooperative
Comment: 
Old Dominion Electric Cooperative
First, ODEC supports the proposal to include the two State Implementation Plan (SIP) options. ODEC is disappointed, however, that the timelines EPA has proposed for CATR implementation, beginning in 2012, do not allow adequate time for states to submit and obtain SIP approvals incorporating allowance allocation methodologies better suited to meeting state or local concerns as compared the chosen methodology in the generic FIP. [EPA-HQ-OAR-2009-0491-4004[1].1, p.2]
ODEC supports the inclusion of the both the abbreviated and full SIP options proposed in the NODA III. The compressed timeline of 2012 for the CATR first compliance period, however, does not provide sufficient time to allow states the opportunity to distribute allowances under a SIP to reflect Individual state needs and concerns. [EPA-HQ-OAR-2009-0491-4004[1].1, p.5]
San Miguel Electric Cooperative, Inc.
San Miguel supports the provision to allow States to submit Transport Rule SIPs, however the timeline is insufficient for States to design and implement a SIP. San Miguel recommends additional time be given to the States to properly design and implement a SIP. [EPA-HQ-OAR-2009-0491-3997[1].1, p.4]
Response: 
In the final Transport Rule, EPA revises the deadlines for submission of SIP revisions to replace EPA-determined allocations by state-determined allocations.  The first deadline for submission of SIP revisions with replacement, state-determined allocations is April 1, 2012 for allocations for 2013.  See section X of the preamble.
Organization: Southern Company
Comment: 
Southern Company
As explained more fully in Southern Company's and UARG's comments on the proposed Transport Rule, the Clean Air Act (CAA) does not give EPA the authority to promulgate a FIP before allowing the states to submit a SIP. The opportunity to replace a FIP with a SIP at some point in the future does not satisfy EPA's obligation to provide states an opportunity to craft their own plans at the outset of the program. In the NODA3, EPA proposes an opportunity for states to submit abbreviated allocation SIPs. We support EPA allowing states the opportunity to develop SIPs  -  as required by the CAA. But the abbreviated SIP concept falls well short of what the CAA requires. Additionally, under the abbreviated SIP process, states would be required to submit proposed allocation SIPs by November 2011  -  only a few months after EPA plans to issue the final rule  -  a virtually impossible task. Even more egregious is the fact that these SIPs would not impact the allocations until 2014, which means that states will be forced to use EPA's FIP allocation scheme in 2012 and 2013. [EPA-HQ-OAR-2009-0491-3946[1].1, p.7]
Southern Company reiterates the point made in the proposed Transport Rule comments, that the 2012 compliance date is unreasonable and unjustified. However, if EPA insists on a near-term compliance date, it must give states an opportunity to develop an allocation scheme, at the outset of the program, that reflects each states own "sensitive . . . choices" on how to implement section 110(a)(2)(D)(i)(I). States are better suited to developing fair and consistent allocations that take into consideration the unique aspects of electric generating units (EGUs) (e.g., fuel mixes or anticipated new unit construction) and economic concerns in the state. The one-size-fits-all scheme of an EPA FIP will unnecessarily penalize many units leaving some with little to no compliance alternatives given the unreasonable proposed deadlines. The CAA envisions allowing regulated sources a reasonable time to implement compliance plans, which EPA is not doing in this rulemaking. At a minimum, EPA should offer several approved model allocation methods, any one of which could be adopted by a state. [EPA-HQ-OAR-2009-0491-3946[1].1, p.7]
In every aspect of responding to any findings in the final rule, states must be afforded ample opportunity to make their "sensitive ... choices" at the outset of the rule. This includes, among other things, broad discretion to determine which units will be covered, where reductions will come from, and how to address new units. For example, states should not be forced to have a new unit set aside; rather they should be afforded the discretion to determine whether, and to what extent, a new unit set aside is warranted.[EPA-HQ-OAR-2009-0491-3946[1].1, p.7]
Response: 
In the final Transport Rule, EPA revises the deadlines for submission of SIP revisions to replace EPA-determined allocations by state-determined allocations.  The first deadline for submission of SIP revisions with replacement, state-determined allocations is April 1, 2012 for allocations for 2013.  See section X of the preamble. 
Further, EPA rejects the commenter's suggestion that EPA provide several pre-approved model allocation methods that states choose to adopt.  As indicated by any commenters and as confirmed by EPA's experience in reviewing the variety of allowance allocation methods adopted by states in CAIR SIPs, states have a broad range of views on how allowances should be allocated within their borders, with states having different views concerning, for example, the establishment of allowance set-asides for specific purposes such as for encouraging efficiency or renewable energy, for cases of hardship, or for new units.  Consequently, EPA believes that, rather than trying to develop alternative model allocation methods that would attempt to capture the wide variety of state-preferred allocation methods, it is reasonable to provide general requirements for allowance allocations (such as the requirement not to exceed the available amount of the state budget and certain timing requirements for submission of allocations for recordation by EPA) and allow individual states to develop and submit their preferred allocation methods for approval by EPA.    
See section IV.C of the preamble, concerning EPA's authority to issue the final Transport Rule FIPs, and section VII.C of the preamble, concerning the compliance deadlines under the final Transport Rule.
Organization: State of Ohio Environmental Protection Agency (Ohio EPA)
Sunbury Generation LP
Louisiana Chemical Association (LCA)
Comment: 
Louisiana Chemical Association (LCA)
Again, without waiver of any of its prior comments, LCA supports provisions that would allow a state to submit an abbreviated SIP that would substitute for the EPA FIP allocations. However, LCA believes the time period provided by EPA is insufficient for states to do this as a practical measure. [EPA-HQ-OAR-2009-0491-4027, p. 7]
EPA also proposed a second approach, which would require states to submit a full SIP rather than an abbreviated SIP, in order to integrate their program with the FIP and to be able to administer a trading program in lieu of the FIP. EPA. indicated that if the state adopted a trading program regulations meeting certain requirements for the control period in years after 2012, then EPA would approve the full SIP as correcting the deficiency under CAA Section 110(a)(2)(D)(i)(I) in the state's SIP that was the basis for issuance of the comparable proposed Transport Rule FIP. While LCA believes that the abbreviated SIP method is preferable, LCA supports giving states the flexibility to use this option as well. [EPA-HQ-OAR-2009-0491-4027, pp. 7-8]
LCA fully supports EPA's statement in the 2011 NODA that 'of course, each state would still have the ability to submit other types of SIPs using emissions reduction approaches other than the proposed Transport Rule trading programs to correct the deficiency under CAA section 110(a)(2)(D)(i)(I) in the state's SIP that was the basis for the proposed Transport Rule FIP.' LCA believes that giving states maximum flexibility will result in the fastest improvement in air quality, should a state need to reduce downwind emissions in order to satisfy its CAA good neighbor requirements. LCA urges EPA to promptly develop guidance concerning how EPA would review such SIP submissions on a case-by-case basis and what such submissions should contain. [EPA-HQ-OAR-2009-0491-4027, p. 7]
State of Ohio Environmental Protection Agency (Ohio EPA)
Lastly, in addition to the comments and concerns regarding the new allocation methods, Ohio EPA is providing comment on U.S.EPA's proposed provisions for States to submit SIPs. Ohio EPA appreciates U.S.EPA's attempt to address our, and others, comments regarding U.S.EPA's initial proposal of a 'FIP first' approach that usurps the fundamental right of the States to develop their own SIP. However, Ohio EPA believes the deadlines established in this proposal are unreasonable. U.S.EPA's proposal assumes the first year for which State allocations might be used in lieu of U.S.EPA allocations would be the 2014 control period, and only then if States submit a SIP by November 1, 2011. This would provide States approximately four months to prepare and submit SIPs if U.S.EPA finalizes this rule in June 2011 and provides guidance to States on SIP expectations. Yet U.S. EPA states in the proposal that these deadlines are needed so U.S.EPA has sufficient time to review the SIPs before recording of the allocations3 would be required and U.S. EPA determined at least 6 months is necessary for their review. It appears that again States and the regulated community are being subject to unreasonable deadlines as a means of rectifying the federal government's failure to produce a timely regulation. Four months is not sufficient time for Ohio to prepare a SIP considering rulemaking will be necessary. Under this proposal, if the SIP is not submitted by this date, a State will be required to wait until the next control period, 2015. U.S.EPA must find a flexible method for providing reasonably sufficient time for States to prepare a SIP and equally reasonable time for U.S.EPA review and approval allowing for State allocations before the 2014 control period. Ohio EPA suggests U.S.EPA evaluate other methods for providing this time, such as flexibility in changes to the time needed for recording of allocations when SIPs are under review by U.S.EPA. [EPA-HQ-OAR-2009-0491-3915[1].1, pp.5-6]   

3 Allocations are recorded in May and January of the year that is two years prior to the control period.   
Sunbury Generation LP
Sunbury supports EPA's proposal in the Second NODA to allow individual states to pursue partial SIPs in order to accelerate state-specific allocation approaches; however, this proposal is not sufficient to address the unduly stringent timeline for demonstrating compliance with the Transport Rule. [EPA-HQ-OAR-2009-0491-3920[1].1, pp.4-5]
For these reasons, Sunbury supports EPA's proposal though the Second NODA to allow states to develop abbreviated SIPs that would address state-specific allowance allocation methodologies, while postponing or foregoing state-specific revisions to other elements of the FIP. This approach would reduce the time necessary for states to develop state-specific allocation schemes and satisfy the procedural requirements for SIP approval. However, for the reasons discussed below, this potential for increased manageability at the state-level is not sufficient to provide affected source owners adequate time to complete the steps necessary to demonstrate compliance with the final Transport Rule requirements before the rule's proposed January 1, 2012 effective date. [EPA-HQ-OAR-2009-0491-3920[1].1, p.5]
Response: 
In the final Transport Rule, EPA revises the deadlines for submission of SIP revisions to replace EPA-determined allocations by state-determined allocations.  The first deadline for submission of SIP revisions with replacement, state-determined allocations is April 1, 2012 for allocations for 2013.  See section X of the preamble.
Organization: Texas Commission on Environmental Quality
Comment: 
Texas Commission on Environmental Quality
The TCEQ appreciates the EPA providing mechanisms for SIP revisions to replace the Transport Rule FIP prior to rule finalization, but is concerned that the EPA's implementation timeframe does not allow states to assume control of allocations prior to program implementation. [EPA-HQ-OAR-2009-0491-4030, p.6]
In comments regarding the original Transport Rule proposal submitted to the EPA on October 1, 2010, the TCEQ requested that the EPA allow public comment prior to finalization on any specific SIP criteria states might follow in replacing Transport Rule FIPs with state plans. The TCEQ appreciates the inclusion of these potential SIP criteria in the January 7, 2011, NODA. [EPA-HQ-OAR-2009-0491-4030, p.6]
The EPA's January 7, 2011 NODA states, "Because EPA anticipates issuing the final Transport Rule around mid-2011., there would not be sufficient time for states to develop and submit abbreviated or full SIPs with allowance allocation provisions, and for EPA to review and approve such SIP submissions, before September 2011 when EPA would record allocations to existing units for 2012 and 2013. Consequently, the tables assume that the first year for which state allocations might be used, in lieu of EPA allocation, would be 2014.' (76 FR 1120) Because changes to allocation methodologies occurring after program implementation could result in difficulties for stakeholders, the TCEQ suggests that the EPA's Transport Rule program provide a mechanism by which states could assume control of allocations prior to program implementation, if requested. [EPA-HQ-OAR-2009-0491-4030, p.6]
The EPA indicates that states may submit full or abbreviated SIP revisions to address allocations and/or Transport Rule trading for the 2014 control period but would require these SIP revisions due by November 1, 2011. (76 FR 1121). Because this initial submittal timeline is unrealistic, the EPA should either delay the deadline for SIP submittals for the 2014 control period or eliminate the disingenuous option for state-directed allocation and/or trading in 2014. [EPA-HQ-OAR-2009-0491-4030, p.6]
The Transport Rule is expected to be finalized in mid-2011. If states intended to assume control of Transport Rule allocations (abbreviated SIP revisions) or the Transport Rule trading program (full SIP revisions) starting with the 2014 control period, SIP revisions would be due to the EPA by November 1, 2011. Because the FCAA. and EPA guidance mandates that reasonable notice and public hearing be provided for such SIP revisions, states would he unable to develop, propose, provide notice and public hearing, and adopt a SIP revision after the Transport Rule is finalized but prior to the November 1, 2011 submittal deadline. [EPA-HQ-OAR-2009-0491-4030, p.6]
If the EPA actually believes state control of allocations and/or trading to be plausible for the 2014 control period, then providing a November 1, 2011, SIP submittal date for such an option would result in states having to expend staff time and resources based on an unfinalized rule. While few states would choose to develop SIP revisions based on options provided in a proposed rule without some clear assurance that such options would not change at rule finalization, some states may in fact choose to do so in order to attempt to meet the short submittal deadline. Given that, it is troubling that the EPA did not originally identify the mechanisms by which states may submit SIP revisions to assume certain control of their Transport Rule participation when it proposed the Transport Rule on July 6, 2010, instead of providing these proposed mechanisms a full six months later in the process. The EPA has demonstrated a repeated pattern of forcing states to accelerate SIP and rule development processes to meet unrealistic deadlines created by the EPA's own failures to act in a timely manner. [EPA-HQ-OAR-2009-0491-4030, pp.6-7]
The EPA should either delay the SIP submittal deadline for states seeking to assume control of allocations and/or the trading program for the 2014 control period, or the EPA should eliminate this disingenuous option. [EPA-HQ-OAR-2009-0491-4030, p.7]
Request for Date Clarification
In describing the approach for allowing abbreviated SIP revisions providing for state allocation of allowances in the proposed Transport Rule trading programs, the EPA specifies that states would issue final allocations by January 1 "of the year two years before the year of the control period for which the allowances would be distributed, 'for the NOx ozone season program (76 FR 1119). However, Table IV of the NODA, 'Deadlines for Submission of Abbreviated or Full SIPs and Unit-By-Unit Allocations or Auction Results and for Recordation: Ozone Season Trading Programs,' specifies May 1 of the year two years before the year of the control period for submittal of such allocations. [EPA-HQ-OAR-2009-0491-4030, p.7]
The TCEQ requests clarification of the submittal date for state allocations and further requests clarification of SIP revision submittal due dates associated with state allocations. The EPA stated that it needed approximately six months to review a SIP revision prior to allocations being issued; if January 1 is the correct date for final issuance of allocations for the NOx ozone season program, would SIP revisions identifying this allocation methodology be due the July 1st prior to the allocation? If so, the TCEQ again notes that the 2014 control period is not realistically available for state allocation. [EPA-HQ-OAR-2009-0491-4030, p.7]
Response: 
See section VII.C of the preamble, concerning the compliance deadlines for the Transport Rule trading programs.     
In the final Transport Rule, EPA revises the deadlines for submission of SIP revisions to replace EPA-determined allocations by state-determined allocations.  The first deadline for submission of SIP revisions with replacement, state-determined allocations is April 1, 2012 for allocations for 2013.  See section X of the preamble, concerning deadlines for SIP revision submissions.    
Organization: we energies
Comment: 
we energies
As we discussed in our previous comments, the Transport Rule should allow states to modify EPA's default allowance allocations. The abbreviated and full state implementation plan (SIP) options offered by the EPA are both acceptable means to allow states this flexibility. However, the proposed timelines in the NODA for state preparation and approval of either full or abbreviated SIPs are not realistic, and therefore the flexibility contained in these SIP options are not available to states or affected sources. [EPA-HQ-OAR-2009-0491-3976[1].1, p.2]
If EPA finalizes the Transport Rule in July 2011, it is not logistically possible for state agencies to prepare a submittal to EPA by November 2011. Instead, if the EPA were to allow states approximately 18 months to prepare full or abbreviated SIPs, these could be completed by the end of 2012. Allowing a three year compliance schedule after this date would result in a 2015 compliance date, and consequently a revised rule that is in alignment with the current Clean Air Interstate Rule (CAIR) Phase II schedule. Instead of the proposed timeline, it makes sense to instead retain the existing CAIR, including its current SIP-approved allocations, until 2015, at which time it would be replaced by the new Transport Rule. This timeline would allow for a realistic transition from CAIR to the Transport Rule, and allow a meaningful opportunity for states to develop and implement an abbreviated or full SIP. [EPA-HQ-OAR-2009-0491-3976[1].1, p.3]
Finally, we continue to have concerns that EPA has not provided adequate flexibility for utilities that have generation facilities in multiple states. The final Transport Rule should allow state SIPs to include utility-specific emissions averaging plans that would allow interstate transactions across units and state lines where a utility's generation fleet is located in multiple states. We provided more detail on this important point in our original comments. [EPA-HQ-OAR-2009-0491-3976[1].1, p.3]
Response: 
In the final Transport Rule, EPA revises the deadlines for submission of SIP revisions to replace EPA-determined allocations by state-determined allocations.  The first deadline for submission of SIP revisions with replacement, state-determined allocations is April 1, 2012 for allocations for 2013.  See section X of the preamble. 
The commenter claimed that the Transport Rule should allow "emissions averaging plans" that would allow interstate allowance trading among units owned by a utility with facilities in multiple states.  The commenter failed to explain how such "averaging plans" would operate and what provisions of the Transport Rule the commenter believes should be changed by allowing such "averaging plans".  The Transport Rule trading programs already allow interstate allowance trading in that they do not bar any allowance transactions and allow, with certain limitations, the use of  allowances issued for a different state for compliance with the allowance-holding requirements of the trading programs.  Specifically, with regard to the use of out-of-state allowances for compliance, the final Transport Rule establishes two separate SO2 Group 1 and Group 2 trading programs under which only the allowances issued under the respective trading programs can be used for compliance in the trading programs and adopts state-by-state assurance provisions limiting the use of out-of-state allowances for compliance with the requirement to hold allowances to cover emissions.  EPA rejects the commenter's claim concerning "averaging plans" as vague and unsupported and as inconsistent with the reasons for adopting two separate SO2 trading programs (see sections VI.B, C, and D of the preamble) and for adopting state-by-state assurance provisions (see sections VI.F and VII.E and J of the preamble).
Organization: Westar Energy, Inc.
Comment: 
Westar Energy, Inc.
Westar agrees that States should have flexibility to implement the Air Transport Rule in their own ways which are more reflective of local conditions and needs than are available from the FIP. The abbreviated and full SIPs also offer the opportunity for annual changes to in-State unit allowances as opposed to the effectively permanent FIP allowances. This, too, would be a means to adapt the Transport Rule's limitations as conditions evolve. In addition, it seems useful for EPA now to set out standards under which it would routinely and timely approve full or abbreviated SIPs, to speed the process and offer a degree of certainty on which affected parties could rely for planning and operations purposes. [EPA-HQ-OAR-2009-0491-3952[1].1, p.4]
Notwithstanding these salutary efforts, EPA's refusal to allow States that implement a SIP other than a full or abbreviated SIP without being shut out of the proposed Transport Rule trading programs (76 FR at 1120/2) appears to be designed as a means to force States into a particular implementation path. Because the total number of allowances allocated to a State equal the allowances in the State's budget, a proposal that would limit a State to intrastate trading would lack the capability of to provide allowance credits where the yearly emissions exceed the State budget, absent in-State banking. The potential penalties in that scenario will almost certainly preclude any State from choosing anything but a full or abbreviated SIPs. In effect, EPA is adopting a per se rule that SIPs other than a full or abbreviated SIP can never fulfill the goals of the Transport Rules, and therefore are not entitled to participate in its trading programs. This approach is inconsistent with the statutory intent that States make the initial judgment as to how the federal rule is to be implemented. Courts have stricken down similar EPA pronouncements that signal EPA "will not be open to considering approaches other than those prescribed" in a rule. General Electric Co. v. EPA, 290 F.3d 377, 384 (D.C. Cir. 2002). [EPA-HQ-OAR-2009-0491-3952[1].1, pp.4-5]
Response: 
EPA rejects the commenter's objection to the requirement that, in order to participate in the Transport Rule trading programs, States must submit full or abbreviated SIPs that may replace and change the methodologies -- set forth in the Transport Rule FIPs -- for distributing allowances but may not change any other elements of the Transport Rule trading programs.  The commenter failed to identify any specific element (other that the allowance distribution methodologies, which can be changed) of the Transport Rule trading programs that the commenter believes states should be allowed to change and still participate in these trading programs.  The final Transport Rule reasonably limits, for the following reasons, the changes that can be made where a state wants to participate in these trading programs.  First, many provisions of the trading programs have been developed and adopted in order for the trading programs to meet legal requirements.  For example, the specific state budgets, requirement to hold allowances to cover emissions, and assurance provisions are necessary in order to eliminate significant contribution and interference with maintenance in accordance with CAA section 110(a)(2)(D)(i)(I) and North Carolina.  See sections VI.D, F, and G and VII.E and J of the preamble.  The commenter failed to identify any alternatives to these provisions, much less show how alternatives would meet the requirements of the CAA as interpreted in North Carolina.  Second, many provisions must be uniform for all participating sources in order for the trading programs to operate successfully and meet the program's environmental goals.  For example, in order for allowances to be fungible and therefore tradable in the allowance market with minimum transactions costs, each allowance must authorize the same amount (i.e., one ton) of emissions.  This means that all sources that may use an allowance to cover its emissions must meet uniform emission monitoring and reporting requirements that yield quality-assured emission data.  If monitoring and reporting were not uniform and accurate, then "one ton" of emissions reported by one unit and covered by one allowance might not be the same as "one ton" reported by another unit and covered by one allowance, and required emission reductions might not be achieved.  The commenter failed to identify any alternatives to the monitoring and reporting requirements in the trading programs, much less provide any basis for such alternatives.  Third, many provisions must be uniform in order for the Administrator to be able, as a practical matter, to operate trading programs in multiple states in an efficient manner and for participating parties to understand and comply with program requirements.  For example, for this reason, allowance management system requirements concerning selection of designated representatives, establishment of accounts, recordation of allowance distribution, and transfer of allowances are uniform.  The commenter failed to identify any alternatives  to these allowance management system requirements, much less provide any basis for such alternatives.  Moreover, the Transport Rule provides that EPA will review, case-by-case, states' SIP revisions that do not use the Transport Rule trading programs, but use other approaches (including state-administered intrastate or interstate trading approaches) to remedy the SIPs' deficiency under CAA section 110(a)(2)(D)(i)(I).  In short, the commenter provided no basis for its objection to the requirements for full and abbreviated SIPs for states that want to participate in the Transport Rule trading programs.    

XX.F. Other Comments on NODA 3

Organization: Alliance for Industrial Efficiency
Comment: 
Alliance for Industrial Efficiency
We were very pleased to see EPA's recognition of the importance of energy efficiency in the NOPR. EPA acknowledged that "[p]olicies that will promote efficient use of electric power can be an integral, highly cost-effective component of power companies' compliance strategies." EPA further recognized that while the Transport Rule directly regulates utilities, reductions from industrial users will help lower electricity demand and associated emissions:  
[A]chievement of energy efficiency improvements in homes, buildings, and industry is an important component of achieving emissions reductions from the power sector while minimizing associated compliance costs. By reducing electricity demand, energy efficiency avoids emissions of all pollutants associated with electricity generation, including emissions of NOx and SO2 targeted by this rule. [EPA-HQ-OAR-2009-0491-3941[1].1, p.1] 
As organizations that work intimately with the industrial community, we couldn't agree more. Indeed, energy efficiency  -  by both regulated utilities and industrial sources  -  should be a key component of EPA's implementation strategy. [EPA-HQ-OAR-2009-0491-3941[1].1, p.1]
Response: 
EPA believes that achievement of energy efficiency improvements in homes, buildings, and industry is an important component of achieving emission reductions from the power sector while minimizing associated compliance costs.
Organization: Exelon
Comment: 
Exelon
Exelon urges EPA to implement the Transport Rule with the improvements suggested in the NODA and Exelon's comments as quickly as possible. [EPA-HQ-OAR-2009-0491-3919[1].1, p.2]
Response: 
EPA has worked quickly to finalize the Transport Rule.
Organization: First Energy
Minnesota Pollution Control Agency (MPCA)
Vectren Corporation 
South Carolina Department of Health and Environmental Control 
Birchwood Power Partners, L.P.
Louisiana Chemical Association (LCA)
Ohio Utility Group (OUG)
Dow Chemical Company
Comment: 
Birchwood Power Partners, L.P.
Birchwood Power agrees with EPA that providing adequate allowances to cleaner units is consistent with both the CAA's goals, as well as Administrator's stated goal in the preamble to the Proposed Transport Rule of fostering investment In a 'clean, efficient, and completely modem power sector.' 75 Fed. Reg. at 45227. [EPA-HQ-OAR-2009-0491-3940[1].1, p.2-3]
Dow Chemical Company
We have reviewed the 2011 NODA and recognize that EPA has expended a significant effort in developing the proposal. [EPA-HQ-OAR-2009-0491-4018[1].1, p.1]
First Energy
The NODA III supporting the proposed Clean Air Transport Rule was very easy to understand. [EPA-HQ-OAR-2009-0491-3904[1].1, p.4]
Louisiana Chemical Association (LCA)
LCA appreciates the opportunity to submit comments on the proposed 2011 NODA and recognizes that a significant amount of effort has been expended by EPA in developing this proposal_ [EPA-HQ-OAR-2009-0491-4027, p. 2]
Minnesota Pollution Control Agency (MPCA)
The MPCA therefore appreciates the issuance of this NODA providing detail on potential allocation methods.  [EPA-HQ-OAR-2009-0491-3889-cp, p.1]
Ohio Utility Group (OUG)
With the advent of NODA 3, EPA has taken a significant step forward. [EPA-HQ-OAR-2009-0491-4005[1].1, p.2]
South Carolina Department of Health and Environmental Control 
DHEC appreciates that the U.S. Environmental Protection Agency ('EPA') is responding to stakeholder comments on the proposed Transport Rule ('August 2, 2010, Proposal) in the NODA. DHEC further appreciates the outreach efforts from the EPA on this NODA, particularly a January 12, 2011, conference call with states.  [EPA-HQ-OAR-2009-0491-3961[1].1, p.1]
Vectren Corporation 
We appreciate the opportunity to comment on the items presented in the latest Notice of Data Availability (NODA), as the NODA successfully addresses many of the concerns highlighted in Vectren's original comments. [EPA-HQ-OAR-2009-0491-3923[1].1, p.2]
Response: 
EPA appreciates the commenters' support.
Organization: Mississippi Department of Environmental Quality
ARIPPA
we energies
Prairie State Generating Company, LLC
Empire District Electric Company (Empire District)
Cleco Corporation
Texas Commission on Environmental Quality
Consumers Energy
Minnesota Power 
Northern Indiana Public Service Company (NIPSCO)
National Mining Association (NMA)
Comment: 
ARIPPA
In the foregoing respects, ARIPPA endorses key concepts identified by EPA through the Second NODA for the Proposed Transport Rule.  However, in reviewing specific aspects of the Second NODA, notably including EPA's preliminary allocations reflective of the two allocation methodologies, ARIPPA cannot concur that EPA has fully implemented these concepts as articulated in the Second NODA.  Importantly, the Second NODA includes insufficient information to enable the regulated community to analyze EPA's specific implementation of the allocation methodologies discussed in that document, and therefore does not afford adequate review and comment by affected sources.  Further, in reviewing EPA's preliminary allocations, it appears that EPA has not, in fact, fully implemented the conceptual approaches described in the Second NODA in calculating preliminary allowance allocations for affected sources.  ARIPPA believes that EPA should provide sufficient information to allow effective review and comment by all affected sources and should ensure that implementation of the Proposed Transport Rule is fully consistent with the concepts identified by EPA in the Second NODA, as endorsed by ARIPPA above. [EPA-HQ-OAR-2009-0491-3903[1].1, p.16]
Cleco Corporation
We appreciate the opportunity to comment on alternative allocation methods and other matters covered by NODA-3. However, we are being asked to comment on these methods and other aspects of the proposed rule in isolation. It is imperative that EPA not piecemeal the public comment process and that the public be afforded the opportunity to comment on a comprehensive and comprehendible regulatory proposal. [EPA-HQ-OAR-2009-0491-4007, p.1]
Consumers Energy
As was the case for the Proposed Transport Rule, NODA 1 and NODA 2, the comment period for NODA 3 is arbitrarily and unreasonably short. [EPA-HQ-OAR-2009-0491-4008[1].1, p.5]
Empire District Electric Company (Empire District)
As is the case with NODA 1 and NODA 2, this NODA 3 has placed additional information in the docket for this rulemaking. The EPA states in this NODA that "final State budgets may differ from the proposed budgets because EPA is still in the process of updating its emissions inventories and modeling in response to public comments". The EPA goes on to state that "final budgets will be based on the updated inventories and modeling". Not having the completed emissions inventories and updated modeling makes development of meaningful comments difficult. [EPA-HQ-OAR-2009-0491-3883[1].1, pp.2-3]
Minnesota Power 
EPA also notes in the NODA that they are in the process of updating the State budgets for the final rule. While regulated entities might presume that they will continue to receive comparable allocations as would be determined from EPA's earlier State budget estimates, EPA should provide another opportunity for comments if there are significant changes in budget allocations in the final rule. [EPA-HQ-OAR-2009-0491-4009[1].1, p.5]
Mississippi Department of Environmental Quality
In a conference call with EPA, it was also indicated that the states would not have the opportunity to see or comment on the allocations before they are finalized. We believe that the states should also have a period to review and approve the proposed allowances before they are made final. [EPA-HQ-OAR-2009-0491-3917[1].1, p.1]
National Mining Association (NMA)
II. NODA-3 Continues EPA's Failure to Provide Notice of and a Fair Opportunity to Comment on the Proposed Rule. [EPA-HQ-OAR-2009-0491-4013[1].1, p.11]
Moreover, as with the previous two NODAs, NODA-3 is not really a notice of data availability. It proposes significant potential changes to the proposed rule. In this respect, NODA-3 is, or ought to be, a supplemental proposal for a rulemaking, which clearly requires a 60-day comment period under Executive Order 13563. [EPA-HQ-OAR-2009-0491-4013[1].1, p.14]
VI. NODA-3 Also Violates Executive Order 13563 Because It Fails to Provide the Needed Cumulative Impact Analysis [EPA-HQ-OAR-2009-0491-4013[1].1, p.14]
Northern Indiana Public Service Company (NIPSCO)
NIPSCO notes that the January 2011 NODA is more than merely a notice of data availability. In actuality, the January 2011 NODA is an amendment to the original proposal of the Transport Rule. The January 2011 NODA does, indeed, provide additional data, but it also proposes alternative allocation methodologies, a different means of calculating assurance provision allowance surrenders, alternative provisions for state implementation plans, and the source of allocations for new units located in Indian Country, all of which are substantive proposals. While these substantive proposals suggest different ways of dividing the statewide budgets and, thereby, technically involve the manipulation of data, the data themselves play no greater role in the January 2011 NODA than they did in the original proposal. Moreover, the U.S. Environmental Protection Agency ('EPA') even acknowledges that the allocations identified in this NODA are not final and are only approximations. 76 Fed.Reg. 1109, 1111. Therefore, the 'data' that are 'available' are not final and do not really provide a basis for more than approximate comments on that data, since the data are only approximations. [EPA-HQ-OAR-2009-0491-3995[1].1, p. 1]
Prairie State Generating Company, LLC
A NODA which does not simply provide additional data but substantially amends the original proposed Transport Rule while affording comment on data which is only approximate [EPA-HQ-OAR-2009-0491-3897[1].1, p.1]
The Transport Rule as initially proposed does not sufficiently accommodate new, more efficient generation, and the NODA clearly exacerbates the situation. [EPA-HQ-OAR-2009-0491-3897[1].1, p.5] [[This comment can also be found in Section XX.]]
Lastly, a note on the NODA - PSGC notes that the NODA is more than merely a notice of data availability. In actuality, the NODA is an amendment to the original proposal of the Transport Rule. The NODA does, indeed, provide additional data, but it also proposes alternative allocation methodologies, a different means of calculating assurance provision allowance surrenders, alternative provisions for state implementation plans, and the source of allocations for new units located in Indian Country, all of which are substantive proposals. While these substantive proposals suggest different ways of dividing the statewide budgets, and thereby, technically involve the manipulation of data, the data themselves play no greater role in the NODA than they did in the original proposal. [EPA-HQ-OAR-2009-0491-3897[1].1, p.7]
Texas Commission on Environmental Quality
The EPA's request for comment on its proposed use of the revised data identified in the NODA to make changes to the final Transport Rule is unreasonable and does not provide adequate notice to the public of the potential changes to the final Transport Rule. The NODA does not provide adequate information or time for the public to comment on the potential changes to the final Transport Rule.
The mere provision of data or policy alternatives without an explanation of the potential changes that could be made by the EPA in the final Transport Rule is inadequate for the public to assess and comment on the potential future rule changes or the implications of using revised data and alternatives. The EPA has stated that it intends to rely on new data and alternatives for inclusion in computer modeling to determine applicability for the final Transport Rule, but the public cannot reasonably provide meaningful comments without some understanding of the final modeling results. Placing the burden on the public to comment on changes to the final Transport Rule that will result from complex computer modeling not yet completed nor available to the public does not allow the public to ascertain whether they have a specific interest at stake. [EPA-HQ-OAR-2009-0491-4030, p.2]
The TCEQ appreciates the removal allocations from units that do not intend to operate in the future and reallocation to existing units in the proposed alternative allocation methodologies; however, the TCEQ is concerned with the EPA's apparent intent to apply allowance-holding requirements in perpetuity to existing sources that may not currently be included in the list of potential existing Transport Rule units, regardless of whether such units are ever allocated allowances (76 FR 1113). [EPA-HQ-OAR-2009-0491-4030, p.3]
The EPA intends to define 'existing units' for the Transport Rule solely by the existence of such units on the (presumably finalized) list of potential existing units. The EPA states that 'If owners and operators believe that their units should. be, but are not, treated as potential existing Transport Rule units and included in the list of such units provided by this NODA, these owners and operators should submit comments on this NODA...' but goes on to state that 'A unit that would not be allocated allowances as an existing unit because of the unit's exclusion, from the list of potential existing Transport Rule units could ultimately be determined to be a Transport Rule unlit...subject to the allowance-holding requirements of the Transport Rule regardless of whether the unit would be allocated any allowances as an existing unit." It would seem that the EPA has simply created a sub-class of units, possibly defined as existing (and therefore not able to receive new unit allocations) but without providing any existing unit allocations to said units, apparently in perpetuity. The criteria for inclusion in this sub-class is the mere inability to rapidly respond to the EPA's continued 'updating' of the existing sources list in the repeatedly limited Transport Rule-related comment periods. This policy could be challenging at a minimum and likely inequitable for these sources. If the EPA truly intends to 'define' existing units by their inclusion (which relies at least partly on sources knowing they need to request their inclusion) on a list) the EPA should provide a mechanism for existing sources left off of that list to eventually be allocated allowances. [EPA-HQ-OAR-2009-0491-4030, p.3]
The EPA notes that 'final State budgets may differ from the proposed budgets because EPA is still in the process of updating its emissions inventories and modeling...' (76 FR 1111) Because the EPA acknowledges that the Integrated Planning Model (IPM) results may alter unit-level allocations, state budgets and even the states subject to the Transport Rule, the TCEQ requests that states and other stakeholders have the opportunity to review and comment on final IPM results. [EPA-HQ-OAR-2009-0491-4030, p.5]
In addressing unit-level allocations in the NODA and the state emissions budgets, the EPA explicitly acknowledges that the budgets in question are not finalized. To the extent that sources' or states' comments to the EPA would be significantly influenced by actual knowledge of final allocations, final state budgets, or final state inclusion in the Transport Rule trading programs, the TCEQ requests that such information be made publicly available, and the opportunity for comment provided prior to rule finalization.[EPA-HQ-OAR-2009-0491-4030, p.5]
we energies
  The January NODA states that the final unit allocations will appear within the final rule. No distribution or review of these updated results is being proposed. We do not support the EPA's approach. [EPA-HQ-OAR-2009-0491-3976[1].1, pp.1-2]
Response: 
As discussed further in section XVII of this Response to Comments document (RTC), EPA provided adequate time for the public to review and comment on the proposed Transport Rule, the September 2010 NODA ("NODA 1"), the October 2010 NODA ("NODA 2"), and the January 2011 NODA ("NODA 3").
The final Transport Rule is, in all respects, a logical outgrowth of the proposal and the NODAs and thus it was not necessary for EPA to issue a supplemental proposal. EPA is not prohibited from making any changes to a proposal based on comments received during the public comment period without publishing a supplemental proposal. Instead the final rule qualifies as a logical outgrowth of the proposed rule if interested parties should have anticipated that the change was possible. It is permissible for an agency to finalize an approach different from the one proposed so long as the agency gives some indication that a different approach was being considered.
EPA disagrees with ARIPPA's comment on the allowance allocation NODA. EPA provided a complete description of each allowance allocation methodology being considered and explained how it would be applied to determine unit-specific allowance allocations based on the state budgets to be finalized in the final rule. It also, for illustrative purposes, provided information regarding what unit level allocations would be under the state budgets in the proposed rule, noting that these budgets would change between proposal and final.
Regarding NMA's comment about Executive Order 13563 in relation to NODA 3, EPA believes it did provide a meaningful opportunity for the public to comment through the Internet on all aspects of the NODA.  The Agency complied with Executive Order 13563 in developing the final Transport Rule as discussed in section XII.A of the preamble.
Regarding TCEQ's comment about existing unit allocations, the final rule does provide a mechanism for covered existing units not included in the list of potential existing Transport Rule units to receive allowance allocations.  Such units are eligible for allocations as "new units" from the new unit set-asides for the state where the units are located.  Section VII.D of the preamble to the final Transport Rule discusses the approach used in the final rule to allocate allowances from the new unit set-asides.
Organization: PPL Corporation
Comment: 
PPL Corporation
The proposed alternatives serve to highlight the unacceptable uncertainty facing utility companies and regulatory agencies under the rulemaking process and the need to extend the compliance deadlines. Comparing the original allocation proposal with the alternatives illustrates the magnitude of uncertainty regarding the number of allowances that units and companies might receive. In some cases, companies will be in compliance, will curtail or retire unit operations, or will need to install additional controls, depending on the allocation method selected. EPA has stated that it expects to finalize the rule and the accompanying allocations in mid-2011. This schedule is totally unacceptable since it allows only six months for companies to develop compliance plans, apply for and receive approvals from environmental agencies, public utility commissions (for regulated utilities), obtain financing, and construct required equipment. This is clearly unreasonable for affected companies and for regulatory agencies. It has been suggested that companies plan for the worst case and install equipment to comply. The rationale is that if a company receives more allowances than planned for, it will have surplus allowances that can be sold. However, structuring a program to maximize the risk of "over-compliance" is fundamentally inconsistent with utilization of a cap and trade mechanism which is aimed at optimizing the allocation of societal resources to achieve a targeted environmental outcome. The problem is easily solved by adopting more reasonable compliance schedules. It is simply unreasonable to put generators and utilities and the public utility commissions (in the case of regulated utilities) that approve their compliance investments in the position of being forced to undertake action without knowing the final targets. [EPA-HQ-OAR-2009-0491-3935[1].1, p.4-5]
Response: 
Issues raised in this comment regarding the feasibility of the Transport Rule compliance deadlines are outside the scope of NODA 3.  Section VII.C in the preamble to the final rule, and the Transport Rule Engineering Feasibility Response to Comments document (available in the docket), address feasibility of the compliance deadlines.
Regarding the allocation of allowances, EPA believes (and general economic theory suggests) that for owners and operators of units covered by the Transport Rule limited interstate trading programs, the determination regarding what will be the lowest cost compliance methods (e.g., installation of emission control technology, fuel switching, or allowance purchases) should not be impacted by the amount of allowances a source is allocated for a given compliance period.  EPA believes that such decisions will be made based on evaluating the cost of reducing emissions at a covered unit compared to the price of emissions allowances in the allowance market.  For a particular covered unit, if the cost to control a ton of emissions is lower than the allowance price for the regulated pollutant, then the choice will likely be made to reduce emissions.  This is the case regardless of the amount of allowances allocated to the unit since using an allocated allowance to cover emissions has an opportunity cost (i.e., the value of that allowance if it were sold in the allowance market) just as using a purchased allowance to cover emissions has a cost (i.e., the price of purchasing that allowance in the allowance market).
Organization: Rochester Public Utilities (RPU)
Edison Mission Energy (EME)
Comment: 
Edison Mission Energy (EME)
EPA's analysis of necessary emission reductions combined economic and air quality considerations and EPA used this information to establish state budgets. Thus, EPA determined that for 2012 state budgets, EPA could require emission reductions based upon what was achievable with existing controls. While the Transport Rule NODA explains that the final unit level allocations under the Transport Rule may vary because of updates EPA is making to the emissions inventories and modeling, EPA notes that it was not proposing any changes to the approach used to identify each state's emissions budget. [EPA-HQ-OAR-2009-0491-3953[1].1, p.11]
Rochester Public Utilities (RPU)
After reviewing the NODA and evaluating those issues, RPU is only providing comments with regard to the first issue, Alternative allocation methodologies. On the other issues, RPU does not have any comments to make in those areas. In addition, these comments only pertain to the January 7, 2011 NODA and in no way abrogates RPU's earlier comments submitted on October 1 and October 15, 2010. [EPA-HQ-OAR-2009-0491-3998[1].1, p.2]
Response: 
[No response needed.]